{"document":{"slug":"e-8-miso-el26-70-000","title":"MISO show cause order","issued":"2026-06-18","docket":"EL26-70-000","filer":"FERC","group":"June 18 orders","kind":"order","file":"docs/orders/e-8-miso-el26-70-000.pdf","url":"https://www.ferc.gov/media/e-8-el26-70-000","sha256":"3946eea46ef8014cd75a1ecde6d3d9b1c555c7bf7ad23fbf503ec252de7facc8","pages":115,"tokens":43221,"emptyPages":[]},"pages":[{"page":1,"startToken":0,"endToken":156,"text":"195 FERC ¶ 61,212 \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 \nMidcontinent Independent System Operator, Inc. \nAEP Indiana Michigan Transmission Company, Inc. \nALLETE, Inc. \nAmeren Illinois Company \nAmeren Transmission Company of Illinois \nAmerican Transmission Company, LLC \nCleco Power LLC \nDuke Energy Indiana, LLC \nEntergy Arkansas, LLC \nEntergy Louisiana, LLC \nEntergy Mississippi, LLC \nEntergy New Orleans, LLC \nEntergy Texas, Inc. \nGridLiance Heartland LLC \nIndianapolis Power & Light Company \nInternational Transmission Company \nITC Midwest LLC \nMichigan Electric Transmission Company, LLC \nMidAmerican Energy Company \nMontana-Dakota Utilities Company \nNorthern Indiana Public Service Company LLC \nNorthern States Power Company, a Minnesota \nCorporation \nNorthern States Power Company, a Wisconsin \nCorporation \nNorthwestern Wisconsin Electric Company \nOtter Tail Power Company \nPioneer Transmission, LLC \nRepublic Transmission, LLC \nSouthern Indiana Gas & Electric Company \nUnion Electric Company \nWabash Valley Power Association, Inc. \nWolverine Power Supply Cooperative, Inc. \nDocket No.\n \n EL26-70-000"},{"page":2,"startToken":156,"endToken":357,"text":"Docket No. EL26-70-000 \n- 2 - \nORDER INSTITUTING PROCEEDING \nUNDER SECTION 206 OF THE FEDERAL POWER ACT \n \n(Issued June 18, 2026) \n \n \nParagraph Numbers \nI. Background ..................................................................................................................... 6. \nA. Growth of Large and Co-Located Loads and ANOPR ............................................. 6. \nB. Recent Proceedings Addressing Large and Co-Located Loads .............................. 13. \n1. PJM Co-Location Proceedings ............................................................................ 14. \n2. SPP High Impact Large Load and High Impact Large Load Generation \nAssessment Processes .............................................................................................. 17. \n3. SPP Conditional High Impact Large Load Service ............................................. 19. \nII. MISO’s Existing Processes .......................................................................................... 21. \nA. Existing Tariff Processes ......................................................................................... 21. \nB. Recent Stakeholder Proceedings in MISO .............................................................. 29. \nIII. Discussion ................................................................................................................... 33. \nA. Transmission Service to Eligible Customers on Behalf of Large Loads ................ 39. \n1. Jurisdiction ........................................................................................................... 42. \n2. Tariff Provisions .................................................................................................. 48. \nB. Cost Shifting Risk Among Transmission Customers .............................................. 66. \n1. Jurisdiction ........................................................................................................... 68. \n2. Additional Cost Transparency ............................................................................. 71. \n3. Cost Recovery Agreements ................................................................................. 78. \nC. Co-Location Arrangements and Load with Behind the Meter Generation ............. 86. \n1. Definition ............................................................................................................. 88. \n2. Jurisdiction ........................................................................................................... 92. \n3. Tariff Provisions .................................................................................................. 94. \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. \n1. Jurisdiction ......................................................................................................... 110. \n2. Definitions ......................................................................................................... 112. \n3. Tariff Provisions ................................................................................................ 113. \nF. Informational Report .............................................................................................. 120. \nIV. Briefing Questions .................................................................................................... 123."},{"page":3,"startToken":357,"endToken":831,"text":"Docket No. EL26-70-000 \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) \n(PJM Show Cause Order); PJM Interconnection, L.L.C., 193 FERC ¶ 61,217 (2025) \n(PJM Co-Location Order); Sw. Power Pool, Inc., 194 FERC ¶ 61,031 (2026) (SPP HILL \nOrder); Sw. Power Pool, Inc., 195 FERC ¶ 61,196 (2026) (SPP CHILLS Order); see also, \ne.g., Duke Energy Carolinas, LLC, 193 FERC ¶ 61,237 (2025); Commonwealth Edison \nCo., 194 FERC ¶ 61,181 (2026). \n2 As explained below, it appears that it would be reasonable to define a large \nload as (1) a new commercial or industrial customer, (2) located at a single site behind \none or more points of interconnection, (3) that has a peak load of 50 MW or greater, \n(4) interconnects to the transmission system at a voltage level of greater than 69 kV, and \n(5) is not part of a co-location arrangement. See infra P 58. \n3 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 89. \n4 42 U.S.C. § 7173. \n5 See Interconnection of Large Loads to the Interstate Transmission System, \nAdvance Notice of Proposed Rulemaking, Docket No. RM26-4-000 (Oct. 23, 2025) \n(ANOPR); see also Letter from Chris Wright, Sec’y, U.S. Dep’t of Energy, Docket \nNo. RM26-4-000 (Oct. 23, 2025). The ANOPR uses the term “hybrid facilities,” which \nit explains 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":831,"endToken":1311,"text":"Docket No. EL26-70-000 \n- 4 - \nnumber of unique challenges that large load integration poses for the reliable operation \nof that system; and have debated how best to ensure that the rates, terms, and conditions \nof transmission service remain just and reasonable as more and more large loads are \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 \nrates, terms, 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 \nfoundations of a just and reasonable framework for addressing these concerns and \nensuring the timely, efficient, and reliable integration of large and co-located loads onto \nthe transmission system. For example, Southwest Power Pool, Inc. (SPP) has recently \ntaken a number of innovative and proactive steps to address the challenges of integrating \nlarge loads, co-located loads, and/or generation and electrically proximate large load onto \nthe transmission system while ensuring that its tariff remains just and reasonable, and \nPJM Interconnection, L.L.C. (PJM) has likewise taken steps toward that goal in response \nto this Commission’s directives.8 By contrast, Midcontinent Independent System \nOperator, Inc. (MISO) has not yet proposed tariff revisions to address the challenges \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 \nof participation in the ANOPR proceeding or NARUC Collaborative, should file to \nintervene in Docket No. EL26-70-000. \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":1311,"endToken":1739,"text":"Docket No. EL26-70-000 \n- 5 - \nassociated with the integration of large and co-located loads, despite the facts that large \nand co-located loads are increasingly common in the MISO region and MISO itself has \nrecognized that its tariff currently does not “provide a consistent or transparent \nframework to evaluate” such large loads.9 \n \nAs discussed below, we find that MISO’s existing Open Access Transmission, \nEnergy, and Operating Reserve Markets Tariff (Tariff) appears to be unjust, unreasonable, \nor unduly discriminatory or preferential. We thus institute a show cause proceeding \npursuant to section 206 of the Federal Power Act (FPA),10 and we direct MISO and the \nTransmission Owners,11 within 60 days of the date of this order, to either: \n \n9 MISO, Issue Submission Report (Apr. 15, 2026), \nhttps://cdn.misoenergy.org/New%20Issue%20-\n%20Large%20Load%20Interconnection%20Reliability%20Requirements748710.pdf \n(MISO Issue Submission Report). \n10 16 U.S.C. § 824e. \n11 Transmission Owners refers to the entities listed in the caption of this order. We \nrecognize that MISO’s transmission owners include entities that are not subject to the \nCommission’s jurisdiction because they are not public utilities pursuant to section 201(f) of \nthe FPA. See 16 U.S.C. § 824(f); Sw. Power Pool, Inc., 180 FERC ¶ 61,022, at PP 44-45 \n(2022). Accordingly, the Commission has not included 1803 Electric Cooperative, Inc.; \nAmes Municipal Electric System; Arkansas Electric Cooperative Corporation; Big Rivers \nElectric Corporation; Board of Water, Electric and Communications Trustees of the \nCity of Muscatine, Iowa; Central Minnesota Municipal Power Agency; Citizens Electric \nCorporation; City of Alexandria, Louisiana; City of Columbia, Missouri, Water & Light \nDepartment; City of Henderson, Kentucky, Utility Commission; City Water, Light and \nPower - City of Springfield, Illinois City Water and Light Plant of the City of Jonesboro; \nCooperative Energy; Dairyland Power Cooperative; East Texas Electric Cooperative, Inc.; \nGreat River Energy; Hoosier Energy Rural Electric Cooperative, Inc.; Indiana Municipal \nPower Agency; Lafayette City-Parish Consolidated Government; Michigan Public Power \nAgency; Michigan South Central Power Agency; Minnesota Municipal Power Agency; \nMissouri Joint Municipal Electric Utility Commission; Missouri River Energy Services; \nMunicipal Electric Utility of the City of Cedar Falls, Iowa; Municipal Energy Agency of \nNebraska; Prairie Power, Inc.; Rochester Public Utilities; Sam Houston Electric \nCooperative, Inc.; Southern Illinois Power Cooperative; Southern Minnesota Municipal \nPower Agency; Willmar Municipal Utilities; and WPPI Energy here as Transmission \nOwners that must respond to this order to show cause. Nonetheless, the Commission \nretains the authority to review each entity’s formula rates as a component of MISO’s Tariff \nin an order to show cause directed towards MISO, and MISO must respond to this order"},{"page":6,"startToken":1739,"endToken":2051,"text":"Docket No. EL26-70-000 \n- 6 - \n(1) show cause as to why the Tariff remains just and reasonable and not unduly \ndiscriminatory or preferential without provisions addressing: \n(a) the application process, study procedures, and ongoing operational \nrequirements that apply to Eligible Customers12 seeking transmission \nservice on behalf of large loads; \n(b) additional transparency concerning the Network Upgrade13 costs to \nprovide transmission service to Eligible Customers on behalf of large \nloads, a pro forma cost recovery agreement between MISO, the relevant \ntransmission owner, and Eligible Customer taking transmission service \non behalf 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 \nregarding the non-public utilities’ MISO Tariff provisions on file with the Commission. \nSee Sw. Power Pool, Inc., 180 FERC ¶ 61,022 at P 40. \n12 MISO defines an Eligible Customer, in relevant part, as: \n(i) Any electric utility (including the Transmission Owner(s), \nITC Participants(s), and any power marketer), Market \nParticipant, Federal Power Marketing Agency, or any person \ngenerating electric Energy for sale or for resale is an Eligible \nCustomer . . . ; or (ii) Any retail customer taking unbundled \ntransmission service pursuant to a state requirement that a \nTransmission Owner or ITC Participant offer the transmission \nservice, or pursuant to a voluntary offer of such service by a \nTransmission Owner or ITC Participant, that is an Eligible \nCustomer under this Tariff. Unbundled retail customers that \nseek to take local distribution service cannot be Eligible \nCustomers under this Tariff with respect to that service. \nMISO, FERC Elec. Tariff, Module A, § 1.E (Definitions E) (93.0.0), Eligible Customer \n(MISO Tariff). \n13 Capitalized terms not otherwise defined herein have the meanings ascribed to \nthem in the Tariff."},{"page":7,"startToken":2051,"endToken":2479,"text":"Docket No. EL26-70-000 \n- 7 - \n(d) transmission services that reflect Eligible Customers taking \ntransmission service on behalf of co-located loads, load with behind the \nmeter generation, and flexible large loads that are willing and able to limit \ntheir use of the transmission system under certain conditions;14 and \n(e) the rates, terms, and conditions of service applicable to interconnection \ncustomers serving electrically proximate large load or co-located load; or \n(2) explain what changes to the Tariff would remedy the identified concerns if the \nCommission were to determine that the Tariff has in fact become unjust and \nunreasonable or unduly discriminatory or preferential and, therefore, proceeds to \nestablish a replacement Tariff. \n \nWe are also concerned with MISO’s need to ensure adequate generation to serve \nnew large loads.15 We therefore direct MISO to submit, within 30 days of the date of \nissuance of this order, an informational report on how MISO 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 \nat different 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 MISO and/or the Transmission \nOwners in response to this proceeding should (a) propose a reasonable implementation \nperiod to ensure minimal disruption to such existing commercial arrangements, and \n(b) allow a reasonable amount of time to finalize ongoing agreements that are nearing \ncompletion as of the date such Tariff provisions are filed with the Commission. Such \n \n14 As explained below, for purpose of this order, “flexible” large loads are a subset \nof large loads, as used in this order, that are not co-located with generation, but are \nwilling and able to limit their energy withdrawals from the transmission system under \ncertain conditions. See infra note 217. \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":2479,"endToken":2881,"text":"Docket No. EL26-70-000 \n- 8 - \nproposed Tariff revisions should include a reasonable effective date that accommodates \nsuch considerations regarding these existing commercial arrangements. \nI. \nBackground \nA. \nGrowth of Large and Co-Located Loads and ANOPR \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 \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 ¶ \n61,045 (2026) (Order Regarding Intent to Act)."},{"page":9,"startToken":2881,"endToken":3254,"text":"Docket No. EL26-70-000 \n- 9 - \nlarge loads’ such as data centers, there is an urgent need for thoughtful reforms to ensure \nthat large loads are ‘able to connect to the transmission system in a timely, orderly, and \nnon-discriminatory manner.’”20 After recognizing the Commission’s recent actions in \nproceedings involving issues associated with large loads,21 the Commission concluded \nthat it was clear that additional “action is warranted to support further progress where it is \nneeded.”22 \n \nMISO’s comments in response to the ANOPR recognize the growth of large loads23 \nand 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.24 Other comments on the ANOPR identify a number of \nlarge load projects that are underway across the MISO footprint.25 The Commission’s \n2025 State of the Market Report found that MISO had the fastest data center growth of \nany region in the country, with data center capacity increasing at a 43% compound annual \ngrowth rate since 2020.26 \n \nThe MISO TOs stated in their ANOPR comments that, to date, MISO has \napproved transmission enhancements to support approximately 14.4 gigawatts (GW) of \n \n20 Id. P 2. \n21 Id. (citing PJM Co-Location Order, 193 FERC ¶ 61,217; SPP HILL Order, \n194 FERC ¶ 61,031; Commonwealth Edison Co., 194 FERC ¶ 61,181; Tri-State \nGeneration & Transmission Ass’n, 193 FERC ¶ 61,070 (2025); Duke Energy Carolinas, \nLLC, 193 FERC ¶ 61,237). \n22 Id. PP 3-4. \n23 MISO November 21 ANOPR Comments at 10-11 (noting that MISO has \napproved approximately 17 GW of large load additions since the 2022 MISO \nTransmission Expansion Plan cycle and that data centers are, in part, materially \nincreasing the outlook for load growth over coming years). \n24 See id. at 30-33 (describing NERC’s findings related to large loads); \nsee also MISO, Large Load Additions Workshop 7-8 (Jan. 30, 2026), \nhttps://cdn.misoenergy.org/20260130%20Large%20Load%20Workshop%20Presentation\n738349.pdf (MISO Large Load Workshop Presentation). \n25 EEI March 12 ANOPR Comments, attach. 1 at 1-8 (listing publicly announced \nlarge load projects, including in the MISO footprint). \n26 Commission Staff, 2025 State of the Market Report 7 (Mar. 2026) (FERC 2025 \nState of the Market Report)."},{"page":10,"startToken":3254,"endToken":3683,"text":"Docket No. EL26-70-000 \n- 10 - \nlarge load additions.27 AES states that they are experiencing unprecedented load growth \ndriven by data center additions in their respective territories and that AES Indiana \nforecasted to MISO nearly 1.9 GW of new load by 2029, which represents a 75% \nincrease to its existing peak.28 Alliant states that the Alliant Energy Operating \nCompanies are coordinating with their respective transmission owners and MISO to \ninterconnect four large loads totaling approximately 3 GW.29 Wisconsin Electric \nhighlights that Microsoft committed to invest over $7 billion to construct a data center in \nWisconsin Electric’s service territory and that Vantage Data Centers is also investing in a \n$15 billion data center that will be powered by Wisconsin Electric.30 Entergy states that \nit plans to construct more than 8 GW of additional dispatchable generation over the next \nfive years to meet the needs of customers, including 7 to 12 GW of data centers.31 \n \nWhile some commenters in the ANOPR proceeding assert that MISO’s existing \nprocesses effectively facilitate the interconnection of large loads,32 the MISO TOs argue \nthat more can and should be done to address the growth of large loads,33 and a number of \nentities in the MISO footprint generally agree there is a need for clear rules in MISO’s \nTariff governing how large loads are added to the transmission system.34 The Illinois AG \n \n27 MISO TOs November 21 ANOPR Comments at 3. \n28 AES November 21 ANOPR Comments at 4. \n29 Alliant November 21 ANOPR Comments at 2. \n30 Wisconsin Electric November 21 ANOPR Comments at 4-5. \n31 Entergy November 21 ANOPR Comments at 3. \n32 See, e.g., Arkansas Commission November 21 ANOPR Comments at 3; \nDTE November 21 ANOPR Comments at 13; Entergy November 21 ANOPR Comments \nat 18; Louisiana and Mississippi Commissions November 21 ANOPR Comments at 6; \nMISO November 21 ANOPR Comments at 2; MISO TOs November 21 ANOPR \nComments at 4; North Dakota Commission November 21 ANOPR Comments at 5; \nOMS November 21 ANOPR Comments at 2-3; South Dakota Commission November 13 \nANOPR Comments at 5-6; Wisconsin Electric November 21 ANOPR Comments at 7-8. \n33 MISO TOs April 3 ANOPR Comments at 2-3. \n34 AES November 21 ANOPR Comments at 4-5 (“AES shares the view that \ntransparency and regulatory certainty are necessary elements for effective market \nparticipation and investment, whether such investment involves generation, transmission \nand distribution, or load.”); Alliant November 21 ANOPR Comments at 3 (“Establishing \nclear, transparent, and fair rules will enable straightforward compliance and reduce \nadministrative burdens, fostering a more efficient regulatory environment.”);"},{"page":11,"startToken":3683,"endToken":4070,"text":"Docket No. EL26-70-000 \n- 11 - \nstates that the MISO market monitor has identified large increases in “federal energy \nmarket prices and transmission charges” and argues that adopting clear rules in MISO’s \nTariff for the interconnection of large loads to the transmission system is necessary both \nto address the effect that these outsized loads have on the wholesale electricity markets \nand the transmission system, and to prevent practices that will lead to unjust and \nunreasonable cost shifts and prices.35 Commenters also support reforms that capture \nthe efficiencies of generation paired with electrically proximate large load.36 \n \nIn addition, various entities in the MISO footprint recognize that large loads \npresent unique operational and reliability challenges. For example, ATC states that large \nloads require detailed study to understand how grid providers can best serve them and \nthat their operating characteristics, such as large and rapid ramping, make them even \nmore challenging to analyze and serve.37 Similarly, DTE asserts that, operationally, the \nlargest loads pose distinct planning and reliability challenges, including abrupt ramps, \nconcentrated nodal demand, and sensitivity to upstream contingencies.38 AES states that \neach new large load interconnection is unique depending on the site, cost of facilities \nnecessary to provide transmission service, and load type.39 \n \nMoreover, many commenters in the ANOPR proceeding filed persuasive \ncomments documenting, generally, the need for clear and consistent tariff provisions to \nensure regulatory and process certainty, fairness and consistency, and efficiency as large \n \nITC November 21 ANOPR Comments at 2 (“ITC is committed to working with FERC \nand stakeholders to achieve a regulatory framework that is efficient, transparent, and \nequitable for the interconnection of large loads.”); Industrial Customers November 21 \nANOPR Comments at 6 (“Require transparency improvements and clear standards for \nload studies and system impact studies pertaining to the FERC-jurisdictional transmission \nsystem.”). \n35 Illinois AG November 21 ANOPR Comments at 5-6 (citing Potomac \nEconomics, IMM Quarterly Report: Spring 2025, at 2 (July 10, 2025), \nhttps://www.potomaceconomics.com/wp-content/uploads/2025/06/IMM-Quarterly-\nReport_Spring-2025-MSC.pdf). \n36 E.g., Alliant November 21 ANOPR Comments at 6; ENGIE November 21 \nANOPR Comments at 14; MISO November 21 ANOPR Comments at 13; OMS \nNovember 21 ANOPR Comments at 13. \n37 ATC November 21 ANOPR Comments at 3. \n38 DTE November 21 ANOPR Comments at 18. \n39 AES November 21 ANOPR Comments at 9."},{"page":12,"startToken":4070,"endToken":4468,"text":"Docket No. EL26-70-000 \n- 12 - \nand co-located loads are added to the transmission system in increasing numbers.40 There \nis also broad support for rules that help to ensure that other transmission customers are \nnot unfairly burdened with additional costs or reliability impacts as large and co-located \nloads interconnect to the transmission system.41 In addition, many ANOPR commenters \nhighlighted the need to efficiently integrate large loads, particularly data centers, to \nsupport national security priorities and economic development.42 \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 20543 filings, the growing use of co-location \n \n \n40 See, e.g., AI Supply Chain Alliance November 21 ANOPR Comments at 2; \nCalibrant November 21 ANOPR Comments at 1-3; CEBA November 21 ANOPR \nComments at 9-11; Constellation November 21 ANOPR Comments at 6; DCC November \n21 ANOPR Comments at 3-4; ECA November 21 ANOPR Comments at 7-11; EPSA \nNovember 21 ANOPR Comments at 4-6; Infrastructure Masons December 5 ANOPR \nComments at 4-7; Microsoft November 21 ANOPR Comments at 9-10; National Grid \nNovember 21 ANOPR Comments at 7; ODEC December 5 ANOPR Comments at 2-4; \nR Street November 21 ANOPR Comments at 3; Switch December 5 ANOPR Comments \nat 3; Tract November 21 ANOPR Comments at 5; Vantage November 21 ANOPR \nComments at 5-6; Vistra December 5 ANOPR Comments at 1-2. \n41 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. \n42 See, e.g., AI Supply Chain Alliance November 21 ANOPR Comments at 2; \nDCC November 21 ANOPR Comments at 3; ECA November 21 ANOPR Comments \nat 6; Geronimo November 21 ANOPR Comments at 1-2; Google November 21 ANOPR \nComments at 2-3; Verrus December 5 ANOPR Comments at 2. \n43 16 U.S.C. § 824d."},{"page":13,"startToken":4468,"endToken":4892,"text":"Docket No. EL26-70-000 \n- 13 - \narrangements.44 The Commission’s orders in those proceedings have addressed the need \nfor clear and consistent tariff provisions regarding the rates, terms, and conditions of \nservice that apply to co-location arrangements and for transmission services that reflect \nEligible Customers taking transmission service on behalf of co-located loads and load \nwith behind the meter generation that are willing and able to limit their energy \nwithdrawals from the transmission system under certain conditions. Several other \nCommission proceedings have addressed the challenges of integrating large loads onto \nthe transmission system, including the need for clear and consistent tariff provisions \nregarding the provision of transmission service to Eligible Customers on behalf of large \nloads and for interconnection customers serving electrically proximate large load. As \nexplained below, these proceedings provide examples that will help to ensure that \njurisdictional transmission service is provided in a manner that is just and reasonable \nand maintains reliability as large loads are integrated onto the transmission system \nand co-location arrangements become more common. It is in this context that the \nCommission now considers whether MISO’s Tariff remains just and reasonable without \nsimilar 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 \napply to co-location arrangements.45 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.46 On \nDecember 18, 2025, the Commission found that PJM’s tariff was indeed unjust and \nunreasonable because it does not contain provisions addressing with sufficient clarity \nor consistency the rates, terms, and conditions of service that apply to interconnection \n \n44 See PJM Show Cause Order, 190 FERC ¶ 61,115; PJM Co-Location Order, \n193 FERC ¶ 61,217, PJM Co-Location Rehearing Order, 195 FERC ¶ 61,209; SPP HILL \nOrder, 194 FERC ¶ 61,031; SPP CHILLS Order, 195 FERC ¶ 61,196. \n45 See PJM Show Cause Order, 190 FERC ¶ 61,115. \n46 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 n.4."},{"page":14,"startToken":4892,"endToken":5234,"text":"Docket No. EL26-70-000 \n- 14 - \ncustomers serving co-located load and Eligible Customers taking transmission service on \nbehalf of co-located load.47 \n \nSpecifically, the Commission found that the PJM tariff was unjust and unreasonable \nbecause there is a lack of sufficient clarity or consistency as to the rates, terms, and \nconditions of service that apply to interconnection customers serving co-located load.48 \nThe Commission also found that PJM’s tariff was unjust and unreasonable because it \ndoes not include transmission services that reflect Eligible Customers taking transmission \nservice on behalf of co-located loads that are willing and able to limit their energy \nwithdrawals from the transmission system under certain conditions.49 Additionally, \nthe Commission found that PJM’s behind the meter generation rules were no longer just \nand reasonable.50 The Commission directed PJM to file a compliance filing to revise its \ntariff: (1) to set forth specific terms and conditions that an interconnection customer in \nPJM seeking to serve co-located load must follow in order to effectuate a co-location \narrangement;51 (2) to require that the Eligible Customer taking transmission service \non behalf of co-located load takes one of three transmission services: (a) network \nintegration transmission service (NITS) or a new interim, non-firm transmission service \nwhile Network Upgrades to provide full NITS service are constructed (interim NITS); \n(b) a new firm contract demand transmission service; or (c) a new non-firm contract \ndemand transmission service;52 (3) to revise the behind the meter generation rules and \nimplement a transition process for existing behind the meter generation participants;53 \nand (4) to make several clarifications on how certain aspects of PJM’s generator \ninterconnection process apply to interconnection customers seeking to serve co-located \nload.54 \n \n47 PJM Co-Location Order, 193 FERC ¶ 61,217. \n48 Id. P 176. \n49 Id. P 177. \n50 Id. P 179. \n51 Id. PP 187-192, 225-230. \n52 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. \n53 Id. PP 221-224. \n54 Id. PP 161, 231-236."},{"page":15,"startToken":5234,"endToken":5639,"text":"Docket No. EL26-70-000 \n- 15 - \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).55 \n2. \nSPP High Impact Large Load and High Impact Large Load \nGeneration Assessment Processes \n \nOn January 14, 2026, the Commission accepted revisions to SPP’s tariff to add a \nhigh impact large load (HILL) study process and High Impact Large Load Generation \nAssessment (HILLGA) process.56 SPP’s tariff revisions established HILLs as a new \ncategory of load;57 imposed enhanced study requirements to enable SPP to assess the \nHILL’s reliability impacts on the transmission system;58 and created additional, ongoing \n \n55 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). \n56 SPP HILL Order, 194 FERC ¶ 61,031 at PP 61, 64. \n57 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 H) \n(1.0.0). \n58 SPP HILL Order, 194 FERC ¶ 61,031 at PP 13-17 (explaining that the HILL \nprocess requires up to three additional studies beyond those required of all transmission \nservice requests for transmission customers requesting to add or modify a delivery point \nassociated with a HILL, including a HILL delivery point study, HILL supplemental load \nconnection study, and potential supplemental Electromagnetic Transient study)."},{"page":16,"startToken":5639,"endToken":6040,"text":"Docket No. EL26-70-000 \n- 16 - \noperational requirements for transmission customers serving HILLs to ensure continued \nreliability of the transmission system.59 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.60 \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.”61 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.62 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 \n59 Id. P 18 (explaining that market participants registering a HILL must \n(1) follow all nonconforming load requirements (e.g., additional load forecast \nrequirements); (2) provide load data via telemetry in real time; (3) have remote capability \nto disconnect the load from the transmission system made available to the transmission \noperator; (4) have an up/down ramp rate not exceeding 20 MW per minute unless \notherwise directed; (5) include additional information with registration; and (6) not have \nwithdrawals from the transmission system without appropriate transmission service); id. \nP 19 (explaining that the transmission owner, at the transmission customer’s expense, \nmust install a phasor measurement unit or similar equipment); id. PP 20-21 (explaining \nthat the transmission customer will be required to comply with ride-through requirement \nguidelines). \n60 Id. P 27 (explaining that, under the HILLGA process, SPP proposes to \nstudy HILLGA 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). \n61 Id. P 60. \n62 Id. P 61."},{"page":17,"startToken":6040,"endToken":6358,"text":"Docket No. EL26-70-000 \n- 17 - \npoint of interconnection.63 In addition, the Commission found that the proposed study \ndeposits would discourage speculative HILL study requests.64 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.65 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.”66 \n3. \nSPP Conditional High Impact Large Load Service \n \nOn June 5, 2026, the Commission accepted revisions to SPP’s tariff to add a \nnew type of non-firm transmission service, conditional high impact large load service \n(CHILLS).67 CHILLS allows transmission customers serving HILLs to reliably receive \ntransfers of energy until sufficient designated resources and/or network upgrades are \nin place to support long-term, firm transmission service.68 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.69 \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 \n63 Id. P 62. \n64 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 \nif an 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. \n65 Id. P 63. \n66 Id. P 64. \n67 SPP CHILLS Order, 195 FERC ¶ 61,196 at P 1. \n68 Id. P 7. \n69 Id. PP 9-10."},{"page":18,"startToken":6358,"endToken":6697,"text":"Docket No. EL26-70-000 \n- 18 - \ncomplete the network upgrades needed to procure long-term firm transmission service \nthrough existing tariff processes.70 \n \nThe Commission found that SPP had shown that unprecedented growth in \nlarge loads presents significant and unique operational and planning challenges.71 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.72 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.73 \nII. \nMISO’s Existing Processes \nA. \nExisting Tariff Processes \n \nIn MISO, transmission owners play the lead role in managing and connecting \nload and have their own study processes and requirements, and MISO plays a supporting \nrole by conducting its own studies.74 With the exception of ATC’s local planning \nprocedures,75 transmission owners’ processes with respect to planning for and studying \nload additions within the MISO territory are not detailed in the MISO Tariff.76 Some \n \n70 Id. P 9. \n71 Id. P 84. \n72 Id. \n73 Id. \n74 See, e.g., MISO TOs November 21 ANOPR Comments at 5-7; ATC November 21 \nANOPR Comments at 7-8; Wisconsin Electric November 21 ANOPR Comments at 6-7. \n75 MISO Tariff, attach. FF-ATCLLC (31.0.0). Although Attachment FF-ATCLLC \nincludes ATC’s distribution-to-transmission interconnection request process and load \ninterconnection procedure, Attachment FF-ATCLLC does not include provisions specific \nto large loads. \n76 As a result, two of Xcel Energy Services Inc.’s affiliate transmission owners \nhave, for example, filed with the Commission numerous stand-alone system impact study \nagreements for requests by load to interconnect to their transmission assets within MISO, \nbut such agreements are not standard practice among transmission owners within MISO. \nSee, e.g., N. States Power Co., a Minn. Corp., Docket No. ER26-1174-000 (Mar. 17, 2026)"},{"page":19,"startToken":6697,"endToken":7093,"text":"Docket No. EL26-70-000 \n- 19 - \ntransmission owners have established specific procedures and requirements outside of \nCommission-jurisdictional tariffs for interconnecting large loads.77 MISO performs a \nsupplemental role in this process by evaluating transmission system enhancements \nnecessary to accommodate load additions once the transmission owner has already \nfollowed its own study procedures.78 Specifically, MISO’s role primarily consists of \nstudying new Network Load—i.e., load designated by an Eligible Customer to receive \nNITS—to identify upgrades to its transmission system necessary to accommodate the \nnew load and maintain reliability. MISO’s processes for new Network Load additions \nare set out in Module B of the Tariff, through which MISO may conduct system impact \nstudies and facilities studies to determine what transmission facilities are required for the \nrequested transmission service.79 MISO’s Tariff does not distinguish based on the size of \nload seeking to be added to the transmission system,80 and the process for studying new \nload additions is separate from MISO’s process for studying generator interconnection.81 \n \nEligible Customers in MISO may take either NITS or Point-to-Point Transmission \nService.82 Point-to-Point Transmission Service may be firm transmission service (which \nmay only be curtailed in limited circumstances for reliability purposes) or non-firm \nservice (which may be curtailed or interrupted for both economic and reliability reasons \nto accommodate firm Point-to-Point Transmission Service and NITS customers).83 These \ntransmission services require the Eligible Customer to request transmission service to \n \n(delegated order); N. States Power Co., a Wis. Corp., Docket No. ER25-863-000 (Feb. 12, \n2025) (delegated order). \n77 Wisconsin Electric November 21 ANOPR Comments at 6 (citing ATC, \nTransmission System Planning Criteria (Aug. 28, 2025), \nhttps://www.atc10yearplan.com/wp-content/uploads/2025/09/PLG-CR-0001-4.pdf). \n78 MISO TOs November 21 ANOPR Comments at 6-7. \n79 See MISO Tariff, Module B, §§ 32.3 (31.0.0), 32.4 (30.0.0). \n80 MISO, Load Interconnection Whitepaper 4-5 (July 2023), \nhttps://cdn.misoenergy.org/MISO%20Load%20Interconnection%20Whitepaper629693.pdf. \n81 See, e.g., MISO November 21 ANOPR Comments at 23; MISO TOs \nNovember 21 ANOPR Comments at 22; ATC November 21 ANOPR Comments at 10. \n82 MISO Tariff, Module B, § I (Introduction) (30.0.0); see also id. Module A, § 1.T \n(Definitions T) (43.0.0), Transmission Service. \n83 Id. Module B, §§ 13.6 (Curtailment of Firm Transmission Service) (31.0.0), \n14.7 (Curtailment or Interruption of Service) (31.0.0)."},{"page":20,"startToken":7093,"endToken":7511,"text":"Docket No. EL26-70-000 \n- 20 - \nmeet the load’s maximum demand, regardless of the load’s operational capabilities or \nwillingness to be curtailed. \n \nCosts for Network Upgrades needed to provide transmission service to \nEligible Customers to serve new load are allocated in several ways. As noted, MISO \nmay conduct a facilities study, in coordination with the affected transmission owner(s), \nto estimate the costs of Direct Assignment Facilities and Network Upgrades needed to \nsupply an Eligible Customer’s request for new NITS, new long-term firm Point-to-Point \nTransmission Service, or designation of new Network Load(s).84 Direct Assignment \nFacilities are facilities constructed by a transmission owner for the sole use and \nbenefit of a transmission customer,85 and their costs are directly assigned to the \nEligible Customer.86 Network Upgrades, on the other hand, are included in the MISO \nTransmission Expansion Plan (MTEP) as Transmission Delivery Service Projects, the \ncosts of which may be rolled into the relevant transmission owner’s base zonal rates in \naccordance with Attachment N of the Tariff.87 As such, these costs are shared among the \ntransmission owner’s wholesale transmission customers based on usage.88 \n \nNetwork Upgrades needed to provide requested transmission service to \nEligible Customers may also be planned for and constructed under local transmission \nplanning processes within MISO. Under Attachment FF to the Tariff, the Transmission \nExpansion Planning Protocol, transmission owners may propose Network Upgrades for \ninclusion in the MTEP that qualify as Other Projects, which address local reliability \nissues and/or provide local economic benefit and do not otherwise qualify as another type \nof project.89 Other Projects may include transmission projects needed to connect new \nloads, among other purposes, and costs for approved Other Projects are assigned to the \napplicable transmission owner and may be recovered under the transmission owner’s \n \n84 Id. Module B, §§ 19.4 (Facilities Study Procedures) (30.0.0), 32.4 (Facilities \nStudy Procedures) (30.0.0). \n85 Id. Module A, § 1.D (Definitions D) (71.0.0), Direct Assignment Facilities. \n86 Id. attach. N (Recovery of Costs Associated with New Facilities) (30.0.0), § A. \n87 Id. attach. FF (Transmission Expansion Planning Protocol) (93.0.0), §§ II.A.2.b, \nIII.A.2.e; MISO, Transmission Planning Business Practice Manual (BPM-020), § 2.3.2.6; \nsee also MISO Tariff, attach. N, § B. \n88 MISO Tariff, attach. N, § B; see also id. Schedule 7 (Long-Term and Short-Term \nFirm Point-To-Point Service) (93.0.0); id. Schedule 9 (Network Integration Transmission \nService) (98.0.0). \n89 Id. attach. FF, § III.A.2.k."},{"page":21,"startToken":7511,"endToken":7916,"text":"Docket No. EL26-70-000 \n- 21 - \nformula rate in Attachment O of the Tariff through base zonal rates.90 As such, the costs \nof the Network Upgrades needed to provide the requested transmission service are shared \namong the transmission owner’s wholesale transmission customers based on usage within \nthe transmission pricing zone(s) in which the facilities are located. \n \nMISO also uses its Expedited Project Review (EPR) process91 to perform \nstreamlined consideration and approval of local transmission projects, including some \nprojects that are associated with large load additions.92 The details governing the study \nprocess and cost allocation for EPR requests are included in MISO’s Transmission \nPlanning Business Practices Manual.93 While not all EPR projects are associated with \nlarge loads, MISO explains that it has seen an increase in EPR applications, which \nreflects the increased proliferation of data centers and large loads.94 According to MISO \nand MISO TOs, the EPR process allows for an expedited review for transmission owners \nwho need to start construction on transmission projects to support large load additions \nmore quickly than would be enabled under normal MTEP timelines.95 \n \nFinally, in addition to the local transmission projects described above, MISO plans \nregional transmission projects through its Long Range Transmission Planning (LRTP) \nprocess that focuses on a long-term (i.e., 20 to 40 years) planning horizon and results in \nprojects that are “regional backbone facilities needed to move bulk power between \n \n90 Id.; MISO, BPM-020, § 2.3.2.1. \n91 Attachment FF of MISO’s Tariff provides the basis for the EPR process by \nallowing MISO to perform a streamlined review outside of the MTEP cycle of a \ntransmission owner’s transmission project in the event that a transmission owner \ndetermines that system conditions warrant the urgent development of system \nenhancements that would be jeopardized unless MISO performs an expedited review of \nthe impacts of the project. MISO Tariff, attach. FF, § I.D.1.c. \n92 MISO November 21 ANOPR Comments at 9-10; MISO, MTEP25 Report 36 \n(2025), https://cdn.misoenergy.org/MTEP25%20Report731648.pdf (MISO MTEP 25 \nReport); MISO Tariff, attach. FF, § I.D.1.c; MISO, BPM-020, § 4.1.4. \n93 MISO, BPM-020, § 4.1.4. \n94 MISO November 21 ANOPR Comments at 9-10. \n95 Id.; Alliant November 21 ANOPR Comments at 10; Entergy November 21 \nANOPR Comments at 18-19; MISO TOs November 21 ANOPR Comments at 8; \nOMS November 21 ANOPR Comments at 9; Wisconsin Electric November 21 ANOPR \nComments at 7."},{"page":22,"startToken":7916,"endToken":8324,"text":"Docket No. EL26-70-000 \n- 22 - \ngeographically dispersed areas within MISO.”96 The costs of LRTP projects are \nallocated on a regional or sub-regional basis. Anticipated load growth is one of several \nfactors MISO considers when developing LRTP portfolios.97 \n \nMISO processes generator interconnection requests under Attachment X \n(Generator Interconnection Procedures) of its Tariff.98 MISO administers a three-phase \nDefinitive Planning Phase (DPP) process that facilitates the structured study and restudy, \nin clusters, of interconnection requests for proposed generating facilities.99 MISO \nconducts one system impact study in each of the three DPP phases that will evaluate the \nimpact of an interconnection request on the reliability of the transmission system (i.e., a \npreliminary system impact study in DPP Phase I, a revised system impact study in DPP \nPhase II, and a final system impact study in DPP Phase III) and account for withdrawn \ninterconnection requests in the same study cluster to refine the analysis.100 During DPP \nPhases II and III, MISO also conducts a two-part facilities study to estimate the cost and \ntime required to construct necessary interconnection facilities and Network Upgrades to \nfacilitate the interconnection of a proposed generating facility.101 \n \nPursuant to the Tariff, an interconnection customer may request, and MISO \nmay provide, provisional interconnection service for limited operation of a proposed \ngenerating facility at MISO’s discretion based on the results of available studies that \nindicate that there is a level of interconnection that can occur without any additional \nNetwork Upgrades.102 The scope of the provisional interconnection study “will consist \nof stability, short circuit, and voltage analysis to identify issues that would result if the \n \n96 See MISO, MTEP2024 Report 11, 21 (Dec. 12, 2024), \nhttps://www.misoenergy.org/planning/transmission-planning/mtep/ (scroll down to and \nclick “MTEP Reports”; then download “MTEP24.zip” to access “MTEP24 Chapter 1 – \nTransmission Planning Overview” PDF) (MISO MTEP 2024 Report). \n97 See id. at 28-29, 88. \n98 MISO Tariff, attach. X (Generator Interconnection Procedures) (185.0.0). \n99 An interconnection request for a proposed generating facility to be studied through \nthe Expedited Resource Addition Study process is subject to separate rules and study \nprocedures pursuant to section 3.9.2 of Attachment X. Id. § 2 (Scope and Application). \n100 Id. §§ 7.3.1 (Definitive Planning Phase I), 7.3.2 (Definitive Planning Phase II), \n7.3.3 (Definitive Planning Phase III). \n101 Id. §§ 7.3.2.5, 7.3.3.4. \n102 Id. § 7.9 (Provisional Generator Interconnection Agreement)."},{"page":23,"startToken":8324,"endToken":8667,"text":"Docket No. EL26-70-000 \n- 23 - \nGenerating Facility were interconnected without project modifications or system \nmodifications.”103 Under the Tariff, an interconnection customer may also request \nsurplus interconnection service to increase the gross generating capability at the same \npoint of interconnection of an existing generating facility without increasing the total \namount of interconnection service at the point of interconnection.104 The surplus \ninterconnection study for surplus interconnection service consists of reactive power, \nshort circuit/fault duty, stability analyses, and any other appropriate studies, and \nsteady-state (thermal/voltage) analyses may be performed as necessary to ensure \nthat all required reliability conditions are studied.105 \nB. \nRecent Stakeholder Proceedings in MISO \n \nThe Commission is aware that MISO has begun considering potential revisions \nand enhancements to its Tariff that may help address the recent growth of large and \nco-located loads. MISO explained in its ANOPR comments that it engages in regular \noutreach to its members and that it is working to enhance its processes related to large \nload additions, including by launching a survey to obtain more granular information on \nlarge loads and anticipated future buildouts.106 MISO incorporated the results of that \nsurvey into its 2026 Long Term Load Forecast, which MISO will use to inform its \nlong-term transmission planning efforts.107 MISO also recently convened a stakeholder \nworkshop to address the integration of large loads, including consideration of a set of \nguidelines and requirements needed to support reliability as a result of large load \nintegration.108 Moreover, MISO established the Large Load Working Group, a new \nstakeholder group that will provide input and policy guidance on processes and policies \n \n103 Id. § 10.2 (Provisional Interconnection Study Procedures). \n104 Id. §§ 3.2.3 (Surplus Interconnection Service), 3.2.3.1. \n105 Id. § 3.2.3.2. \n106 MISO November 21 ANOPR Comments at 12. \n107 See MISO, 2026 Long-Term Load Forecasting (LTLF) Results Summary \n(Apr. 13, 2026), \nhttps://cdn.misoenergy.org/20260413%20LTLF%20Workshop%202026%20Long%20Te\nrm%20Load%20Forecast%20Summary_UPDATED750524.pdf (MISO Long-Term Load \nForecasting Results Presentation). \n108 MISO Large Load Workshop Presentation at 18-25."},{"page":24,"startToken":8667,"endToken":9018,"text":"Docket No. EL26-70-000 \n- 24 - \nthat facilitate the integration and enablement of large loads in the MISO footprint.109 \nMISO recently recognized that its existing Tariff provisions “do not provide a consistent \nor transparent framework to evaluate” large loads and that interested parties “face \nuncertainty regarding applicable criteria, study assumptions, data requirements, and \npost-interconnection obligations.”110 MISO TOs also explain that MISO is developing \na definition of large load and reliability requirements for large load additions.111 \n \nMISO notes that it is working with stakeholders on issues related to co-location \narrangements,112 including developing a zero-injection generator interconnection \nagreement process for generation that is co-located with load.113 That process would \nallow a generating facility to serve load directly, but would not grant interconnection \nservice, and would prevent the generating facility from injecting onto the transmission \nsystem.114 MISO explains that, under this proposal, it would process a zero-injection \ngenerator interconnection request outside the standard generator interconnection queue \nprocess.115 In the context of its stakeholder process, MISO has also explained that this \nproposal will create a path for generating facilities that are co-located with load to \ninterconnect more quickly, with potentially reduced Network Upgrade costs.116 \n \n109 MISO, Large Load Working Group (LLWG), \nhttps://www.misoenergy.org/engage/committees/large-load-working-group/ (last visited \nApr. 27, 2026). \n110 MISO Issue Submission Report. \n111 MISO TOs April 3 ANOPR Comments at 13. \n112 We note that we have defined the terms co-location arrangement and co-located \nload for purposes of this order, and we recognize that MISO’s usage of this term in its \nproposal or any planned Tariff revisions may not necessarily or ultimately match the \nusage of those terms here. However, we continue to use these defined terms here and \nthroughout this order. \n113 MISO November 21 ANOPR Comments at 13. \n114 Id.; see also MISO TOs April 3 ANOPR Comments at 13-14. \n115 MISO November 21 ANOPR Comments at 13. \n116 MISO, Consideration of Zero-Injection GIA 2 (Jan. 21, 2026), \nhttps://cdn.misoenergy.org/20260121%20PAC%20Item%2009%20Market%20Participati\non%20and%20Registration%20of%20Co-\nLocated%20Load%20and%20Generation%20(PAC-2024-4)736238.pdf."},{"page":25,"startToken":9018,"endToken":9371,"text":"Docket No. EL26-70-000 \n- 25 - \n \nFinally, MISO is also considering through the stakeholder process the potential \nneed for new transmission services as part of its efforts to address large load additions, \nsuch as incremental service until Network Upgrades are completed and other interim or \nnon-firm service options.117 \n \nWhile we are encouraged by MISO’s stakeholder efforts, and by its initial \nattention to the pressing concerns associated with large and co-located loads118 and to the \nSecretary’s interest in these issues,119 we are initiating this FPA section 206 proceeding \nin order to ensure that MISO’s ongoing processes generate reforms that are sufficiently \ntimely and comprehensive to address the concerns we today identify. As such, and as \nthe Commission explained in the April Order Regarding Intent to Act, we find that the \nCommission must now take further action to ensure that MISO promptly proposes \nrevisions to ensure that its Tariff remains just and reasonable. \nIII. \nDiscussion \n \nBased on the discussion below, pursuant section 206 of the FPA, we direct MISO \nand the Transmission Owners, within 60 days of the date of this order, to either: \n(1) show cause as to why the Tariff remains just and reasonable and not unduly \ndiscriminatory or preferential without provisions addressing: \n(a) the application process, study procedures, and ongoing operational \nrequirements that apply to Eligible Customers seeking transmission service \non behalf of large loads; \n(b) additional transparency concerning the Network Upgrade costs to \nprovide transmission service to Eligible Customers on behalf of large loads, \n \n117 See MISO, Large Load Additions (Apr. 8, 2026), \nhttps://www.misoenergy.org/planning/large-loads---container-page/large-load-additions/; \nMISO, Response to Feedback: Large Load Workshop19 (Jan. 30, 2026), \nhttps://cdn.misoenergy.org/MISO%20Response%20to%20Large%20Load%20Workshop\n%20Considerations%20and%20Outcomes%20of%20Large%20Load%20Additions74606\n9.pdf. \n118 See generally MISO November 21 ANOPR Comments; see also Post-Technical \nConference Remarks of Aubrey Johnson on behalf of MISO, Docket No. AD24-11-000, \nat 1, 5-6 (filed Dec. 9, 2024) (noting need to consider the impacts of co-location from a \nreliability, system operations, resource adequacy, planning, and cost-equity standpoint; \nand potential reforms related to co-location arrangements). \n119 See supra PP 6-7."},{"page":26,"startToken":9371,"endToken":9780,"text":"Docket No. EL26-70-000 \n- 26 - \na pro forma cost recovery agreement between MISO, the relevant \ntransmission owner and Eligible Customer taking transmission service \non behalf of the large load to mitigate the risk of cost shifting among \ntransmission customers, and a mechanism to ensure such payments are \nappropriately credited towards transmission owners’ transmission revenue \nrequirements consistent with the Commission’s cost-of-service regulations; \n(c) the rates, terms, and conditions of service that apply to co-location \narrangements; \n(d) transmission services that reflect Eligible Customers taking \ntransmission service on behalf of co-located loads, load with behind the \nmeter generation, and flexible large loads that are willing and able to limit \ntheir use of the transmission system under certain conditions; and \n(e) the rates, terms, and conditions of service applicable to interconnection \ncustomers serving electrically proximate large load or co-located load; or \n(2) explain what changes to the Tariff would remedy the identified concerns if \nthe Commission were to determine that the Tariff has in fact become unjust and \nunreasonable or unduly discriminatory or preferential and, therefore, proceeds to \nestablish a replacement Tariff. \n \nWe also direct MISO to submit, within 30 days of the date of issuance of this \norder, an informational report on how MISO 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 MISO’s and the Transmission \nOwners’ filings, addressing either or both of: (1) whether the existing Tariff remains just \nand reasonable and not unduly discriminatory or preferential; and (2) if not, what changes \nto the Tariff should be implemented as replacement rates. \n \nWe recognize that MISO and/or the Transmission Owners (to the extent the \nmatters addressed herein implicate aspects of the Tariff over which they have the filing \nrights) may elect to address some or all of the issues discussed in this order by proposing \nrevisions to the Tariff pursuant to their applicable FPA section 205 filing rights. We \nstrongly encourage this. Although both the Secretary’s ANOPR and our own Order \nRegarding Intent to Act expressly recognized (and indeed encouraged) that possibility,120 \nno such filings were received from MISO by the Commission prior to the issuance of this \norder. Should MISO and/or the Transmission Owners elect to make such filings in \nresponse to this order, those filings should state explicitly that the proposals are being \n \n120 See ANOPR at P 32; Order Regarding Intent to Act, 195 FERC ¶ 61,045 at P 5."},{"page":27,"startToken":9780,"endToken":10259,"text":"Docket No. EL26-70-000 \n- 27 - \nsubmitted under FPA section 205. Should MISO and/or the Transmission Owners submit \na filing under FPA section 205, they should also explain which of the Commission’s \nabove directives their filing addresses and how it resolves them. Additionally, any such \nfiling should provide a reasoned explanation for how the proposal will avoid disrupting \nexisting commercial arrangements and clearly identify a reasonable effective date that \naccommodates such existing commercial arrangements. \n \nThe Commission will consider requests from MISO and/or the Transmission Owners \nto hold, for up to 90 days, all or certain aspects of this FPA section 206 proceeding in \nabeyance, including the deadline to respond to this order. Any such abeyance, which will \nbegin as of the deadline to respond to this order, would be considered to provide MISO and \nthe Transmission Owners time while they work through the stakeholder processes to \ndevelop FPA section 205 filings to revise the Tariff to address the issues raised in this order. \nRequests for a full or partial abeyance121 should be submitted prior to the deadline to \nrespond to this order, specifically within 45 days of issuance of this order, to allow time for \nthe Commission to act on the abeyance request. We emphasize that we will not grant such \nabeyances reflexively, that any abeyance will be limited to 90 days, and that we will look \nwith great disfavor toward requests to extend the abeyance period. We anticipate that \nsuccessful abeyance requests, if any, will include both (1) a robust description of the \ncontent of a potential future filing under FPA section 205 and (2) a reasoned and specific \nexplanation of 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.122 That date is the date of publication of notice of initiation of this proceeding in \nthe Federal Register. \n \n121 A partial abeyance may be appropriate to the extent MISO is developing \nFPA section 205 filings in response to only a subset of the directives in this order. For \nany remaining directives, we expect a response to this order within the 60-day deadline \nset forth herein. \n122 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)."},{"page":28,"startToken":10259,"endToken":10703,"text":"Docket No. EL26-70-000 \n- 28 - \nA. \nTransmission Service to Eligible Customers on Behalf of Large Loads \n \nWe today make a preliminary finding that MISO’s Tariff appears to be unjust \nand unreasonable because it lacks provisions that address, with sufficient clarity and \nconsistency, how MISO and/or the Transmission Owners will timely study (i.e., \nwithin 60-90 days of receiving the request) the provision of transmission service to \nEligible Customers on behalf of large loads.123 \n \nThroughout this order, we use the phrase “the provision of transmission service \nto Eligible Customers on behalf of large loads” to encompass the provision of new, \nmodified, or additional jurisdictional transmission service to Eligible Customers on \nbehalf of large loads. We note that this phrase is not limited to instances where an \nEligible Customer submits an application to request new transmission service. It also \nincludes instances where an Eligible Customer requests a new or modified point of \ndelivery to serve a large load, where a large load seeks a new or modified delivery point \nas an unbundled retail transmission service customer, or where large loads are otherwise \nincluded in an Eligible Customer’s reported load growth and that Eligible Customer is \ntaking NITS. \n \nWe direct MISO and the Transmission Owners to the extent the matters addressed \nherein implicate aspects of the Tariff over which they have the filing rights, to explain \nwhether the Tariff remains just and reasonable without an application process, study \nprocedures, and ongoing operational requirements that address the unique characteristics \nand challenges of providing transmission service to Eligible Customers on behalf of large \nloads, or to propose appropriate Tariff revisions. We recognize that MISO is currently \nconsidering potential reforms to enhance its processes related to large load additions in its \nstakeholder process and we encourage MISO to consider whether these efforts would, \neither fully or in part, address the Commission’s concerns that the Tariff appears to be \nunjust and unreasonable. \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 \n \n123 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":29,"startToken":10703,"endToken":11125,"text":"Docket No. EL26-70-000 \n- 29 - \nentities. We are encouraged by efforts made at the state level to address issues related to \nlarge load additions that fall within state jurisdiction.124 \n \nAs discussed below, however, certain aspects of the process for integrating large \nloads onto the transmission system fall squarely within the Commission’s exclusive \njurisdiction. Specifically, we find that it is within the Commission’s exclusive authority \nto ensure that transmission provider and/or transmission owner tariffs include sufficiently \nclear and consistent provisions governing how transmission service to Eligible Customers \non behalf of large loads interconnecting to the transmission system will be studied, \nincluding whether new or upgraded transmission facilities are necessary to provide the \nrequested transmission service. The Commission has jurisdiction over the study process \nfor transmission service to both Eligible Customers on behalf of large loads and \nunbundled retail transmission service to end-use large load customers where, pursuant \nto state law or a public utility’s voluntary offer of such service, the large load is an \nEligible Customer under the transmission provider and/or transmission owner tariffs.125 \n \nThe Commission is a creature of statute and has jurisdiction over only those \nmatters that Congress has given it the authority to regulate.126 That authority includes \njurisdiction over the wholesale sale and transmission of electricity in interstate \ncommerce, including all facilities used for such sale and transmission.127 As relevant \nhere, the Commission must ensure that the rates, charges, and classifications for such \ntransmission of electricity—as well as the practices directly affecting such transmission \nof electricity—are just and reasonable and not unduly discriminatory or preferential.128 \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 \n \n124 See generally NARUC April 14 ANOPR Comments (highlighting action taken \nby state public utility commissions related to large loads). \n125 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 MISO Tariff, Module A, § 1.E, Eligible Customer. \n126 Atl. City Elec. Co. v. FERC, 295 F.3d 1, 8 (D.C. Cir. 2002). \n127 16 U.S.C. § 824(b)(1). \n128 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))."},{"page":30,"startToken":11125,"endToken":11569,"text":"Docket No. EL26-70-000 \n- 30 - \nover unbundled retail transmission service.129 As part of its transmission authority, \nthe Commission has exercised jurisdiction over the terms of certain interconnections \nto the transmission system as an element of transmission service,130 including the \ninterconnection of wholesale load to the transmission system.131 \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 \nconditions of interstate transmission service to Eligible Customers on behalf of large \nloads connecting to the transmission system, and the practices directly affecting the \nprovision of such interstate transmission of electricity. An essential component of \nproviding such transmission service is the process by which the transmission provider \nand/or transmission owner evaluates (1) whether it can provide the requested \ntransmission service and (2) the impact that providing such transmission service will \nhave on the jurisdictional transmission system, including determining whether any new \nor upgraded transmission facilities are needed to provide transmission service while \nmaintaining reliable operation of the transmission system. This transmission service \nstudy process determines what Network Upgrades are needed to provide transmission \nservice to Eligible Customers on behalf of large loads, the costs of which are included in \ntransmission rates. As such, this study process directly affects Commission-jurisdictional \ntransmission rates.132 The Commission has exclusive authority to ensure that the process \nto study the provision of transmission service to Eligible Customers is just and reasonable \nand not unduly discriminatory or preferential. We therefore find that we have authority \nto ensure that tariffs include provisions that clearly and consistently address the study \nprocess for the provision of transmission service to Eligible Customers on behalf of large \n \n129 New York v. FERC, 535 U.S. 1, 17, 19-20 (2002) (upholding the Commission’s \nexercise of jurisdiction over unbundled retail transmission service). \n130 Tenn. Power Co., 90 FERC ¶ 61,238, at 61,761 (2000) (Tennessee Power), order \ndenying reh’g, 91 FERC ¶ 61,271 (2000); Standardization of Generator Interconnection \nAgreements & Procs., Order No. 2003, 104 FERC ¶ 61,103, at P 9 (2003); see also \nLaguna Irrigation Dist., 91 FERC ¶ 61,340, at 62,152 (2000). \n131 Pac. Gas & Elec. Co., 109 FERC ¶ 61,392, at P 37 (2004); Pac. Gas & Elec. Co., \n115 FERC ¶ 61,193, at PP 36-38 (2006). \n132 Cf. Transmission Plan. & Cost Allocation by Transmission Owning & \nOperating Pub. Utils., Order No. 1000, 136 FERC ¶ 61,051, at P 112 (2011) (“It is \nthrough the transmission planning process that public utility transmission providers \ndetermine which transmission facilities will more efficiently or cost-effectively meet \nthe needs of the region, the development of which directly impacts the rates, terms and \nconditions of jurisdictional service.”)."},{"page":31,"startToken":11569,"endToken":12002,"text":"Docket No. EL26-70-000 \n- 31 - \nloads, including the unique impacts that providing transmission service to \nEligible Customers on behalf of large loads may have on the transmission system. \n \nAt the same time, we continue to recognize that the FPA expressly reserves \nto states the authority over any other sale of electric energy, including retail sales \nand wholesale sales not in interstate commerce (such as wholesale sales within the \nElectric Reliability Council of Texas region), as well as facilities used for the generation \nand distribution of electricity.133 As such, we recognize that states will continue to \nregulate: (1) the specific terms of retail sales to large load;134 (2) which entities may \nmake retail sales within their borders, including which entities are legally permitted to \nprovide electricity to retail large load customers;135 and (3) any siting decisions and \nconstruction associated with the large load project.136 Nothing in this order is intended to \nintrude upon state authority over retail service to large loads. \n \nIn sum, we today exercise our authority to ensure that the process by which \njurisdictional transmission providers and/or transmission owners will study the provision \nof jurisdictional transmission service to Eligible Customers on behalf of large loads \ninterconnecting to the transmission system, including where, as allowed by state law or a \npublic utility’s voluntary offer of such service, an end-use large load seeks unbundled \nretail transmission service, is just and reasonable and not unduly discriminatory or \npreferential. Pursuant to that authority, we find that MISO’s Tariff appears to be unjust \nand unreasonable or unduly discriminatory or preferential because it lacks sufficiently \nclear and consistent provisions regarding the study process related to the provision of \ntransmission service to Eligible Customers on behalf of large loads. We need not \ncomprehensively address the Commission’s jurisdiction over other aspects of the addition \nof large loads to the transmission system at this time. \n \n133 16 U.S.C. § 824(b)(1); see Dayton Power & Light Co. v. FERC, 126 F.4th 1107, \n1129 (6th Cir. 2025). \n134 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). \n135 PJM Show Cause Order, 190 FERC ¶ 61,115 at PP 68-69. \n136 See, e.g., Citizens Action Coal. of Ind., Inc. v. FERC, 125 F.4th 229, 238 \n(D.C. Cir. 2025) (citing 16 U.S.C. § 824(b)(1)) (recognizing state authority over \ngeneration resource mix, including through their siting authority); Order No. 1000, \n136 FERC ¶ 61,051 at P 107 (acknowledging state authority over siting, permitting, \nand construction of transmission facilities)."},{"page":32,"startToken":12002,"endToken":12437,"text":"Docket No. EL26-70-000 \n- 32 - \n2. \nTariff Provisions \n \nIn the following section, we begin by considering MISO’s Tariff as it relates to \nhow MISO and/or the Transmission Owners will study the provision of transmission \nservice to Eligible Customers on behalf of large loads and explain our concerns that the \nlack of sufficiently clear and consistent provisions regarding the study process for the \nprovision of transmission service to Eligible Customers on behalf of large loads is unjust \nand unreasonable or unduly discriminatory or preferential. We then consider whether \nthe Tariff is unjust and unreasonable without certain elements. First, we consider \nwhether the Tariff lacks sufficiently clear and consistent Tariff provisions establishing an \nappropriate definition of large load, as a separate category of load. Second, we consider \nwhether the Tariff lacks sufficiently clear and consistent Tariff provisions establishing an \napplication process and requirements for Eligible Customers requesting transmission \nservice on behalf of large loads and a study process that considers the unique operational \nchallenges of providing transmission service to Eligible Customers on behalf of large \nloads. Third, we consider whether the Tariff lacks sufficiently clear and consistent Tariff \nprovisions establishing ongoing operational requirements necessary to ensure that MISO \ncan reliably provide transmission service given the unique operational impacts on the \ntransmission system of providing transmission service to Eligible Customers on behalf of \nlarge loads. Finally, we consider whether the Tariff requires such ongoing operational \nrequirements for Eligible Customers taking transmission service on behalf of large loads \nto be memorialized in service agreements. \n \nWe preliminarily find that MISO’s Tariff appears to be unjust and unreasonable or \nunduly discriminatory or preferential because it does not contain provisions addressing \nwith sufficient clarity and consistency how MISO and/or the Transmission Owners will \nstudy the provision of transmission service to Eligible Customers on behalf of large \nloads. We recognize that MISO and/or the Transmission Owners may have existing load \nintegration processes, including studies that are performed in evaluating the provision of \ntransmission service to Eligible Customers on behalf of large loads.137 However, we are \nconcerned that those processes and any required studies with regard to the provision of \ntransmission service are not described in the Tariff with the degree of clarity and \nspecificity necessary to ensure that the transmission provider can mitigate operational \nrisks of providing transmission service to Eligible Customers on behalf of large loads, \ngiven their impact on the transmission system, avoid disputes regarding how studies \nare conducted, deter speculative or duplicative requests for transmission service by \nEligible Customers on behalf of large loads, and help avoid excessive and unnecessary \nNetwork Upgrades. \n \n137 See supra P 21."},{"page":33,"startToken":12437,"endToken":12849,"text":"Docket No. EL26-70-000 \n- 33 - \n \nAs noted above, Xcel Energy, Inc., on behalf of Northern States Power Company \n(NSPC), a transmission owner in MISO, has submitted to the Commission numerous \nsystem impact study agreements to evaluate the interconnection of new loads on NSPC’s \ntransmission system. Those submissions adapt Xcel Energy’s grandfathered pro forma \nsystem impact study agreement contained in its Open Access Transmission Tariff, which \nis used to evaluate the provision of NITS or firm Point-to-Point Transmission Service \nwhen an Xcel Energy subsidiary is the transmission provider (i.e., not in the MISO \nfootprint), to the study of large load additions.138 These agreements underscore our \nconcern that MISO’s Tariff lacks provisions that address with sufficient clarity and \nconsistency how MISO and/or Transmission Owners study the interconnection of large \nloads to the transmission system because they demonstrate that Xcel Energy is using an \nad hoc study process that is not reflected in MISO’s Tariff to study the addition of large \nloads. \n \nMoreover, we are concerned that the existing Tariff does not contain other \nelements akin to those described below, which we preliminarily find may be necessary to \nensure that the rates, terms, and conditions of jurisdictional transmission service are just \nand reasonable. \n \nAt the outset, we recognize that the Transmission Owners may be primarily \nresponsible for conducting the studies that (1) evaluate whether a large load may be \ninterconnected to the transmission system and served by the Eligible Customer, and \n(2) determine whether Network Upgrades are necessary to provide transmission \nservice.139 We appreciate that this role may stem from how MISO and the Transmission \nOwners allocated rights and responsibilities in the governing documents establishing \nMISO. We do not seek to alter that allocation of rights and responsibilities. \n \nWe are nonetheless concerned that MISO’s Tariff lacks a study process that \naddresses the unique operational and reliability challenges that providing transmission \nservice to Eligible Customers on behalf of large loads presents to the transmission \nsystem. Large loads can be more energy intensive and geographically concentrated than \ntraditional load, and exhibit different load profiles and operational characteristics.140 \nMISO itself has recognized in presentations to stakeholders that large loads can have a \n \n138 See supra note 76. \n139 See supra P 21. \n140 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)."},{"page":34,"startToken":12849,"endToken":13277,"text":"Docket No. EL26-70-000 \n- 34 - \ndisproportionate impact on system reliability due to their size and unique characteristics, \nand so too has MISO acknowledged that the scale, pace, and characteristics of large load \ngrowth present significant operational and planning challenges.141 As a result, providing \ntransmission service to Eligible Customers on behalf of large loads may be more complex \nand could raise greater reliability concerns for the transmission system, relative to a \nsituation where Eligible Customers seek transmission service on behalf of traditional \nload. \n \nWithout a clear and consistent process to study the provision of transmission \nservice to Eligible Customers on behalf of large loads, MISO and/or the Transmission \nOwners may not fully capture the transmission system impacts of providing such \ntransmission service, which could result in significant operational risks for the \ntransmission system. Furthermore, we are concerned that, without sufficiently clear and \nconsistent Tariff provisions, MISO 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 MISO and/or the Transmission Owners will study the provision of \ntransmission service to Eligible Customers on behalf of large loads will lead to disputes \nover a variety of issues—e.g., study timelines and delays,142 how the transmission service \nneeded on behalf of the large load is studied,143 what types of Network Upgrades are \nconsidered, and how required Network Upgrades to provide the requested transmission \nservice are determined.144 Such disputes may arise from the lack of transparency in how \n \n141 MISO Large Load Workshop Presentation at 7-8; see also MISO November 21 \nANOPR Comments at 30-33. \n142 See, e.g., CEBA November 21 ANOPR Comments at 12-13; Eolian November 21 \nANOPR Comments at 14-16; Institute for Progress November 21 ANOPR Comments \nat 7-8; Microsoft November 21 ANOPR Comments at 9; ODEC December 5 ANOPR \nComments at 4. \n143 Commenters raised concern that large loads are not studied with consideration \nof their known operating characteristics, including their willingness to be flexible or \ncurtailable. See, e.g., ClearPath November 21 ANOPR Comments at 5-6; Constellation \nNovember 21 ANOPR Comments at 23-24; Critical Loop November 21 ANOPR \nComments at 3; GridCare December 5 ANOPR Comments at 1-2; L. Lynne Kiesling \nNovember 21 ANOPR Comments at 10. \n144 Specifically, commenters raised concern that transmission providers/owners \nmay only consider traditional transmission infrastructure or that there is a lack of \nconsideration of alternative transmission solutions. See, e.g., ACORE November 21 \nANOPR Comments at 3-4, 6-7; American Terawatt November 21 ANOPR Comments"},{"page":35,"startToken":13277,"endToken":13740,"text":"Docket No. EL26-70-000 \n- 35 - \nstudies are performed and how decisions will be made.145 We are thus concerned that the \nlack of clear and consistent provisions in MISO’s Tariff related to the study process for \nthe provision of transmission service to Eligible Customers on behalf of large loads \nappears to be unjust and unreasonable or unduly discriminatory or preferential. \n \nLastly, we are concerned that MISO’s existing Tariff fails to deter speculative or \nduplicative requests for transmission service by Eligible Customers on behalf of large \nloads. Many ANOPR comments assert that clear and consistent provisions establishing \nstudy timelines and costs, readiness requirements, and/or penalties will deter speculative \nor duplicative requests related to large load additions.146 Commenters explain that \nspeculative requests may bog down and delay the study process, wasting time and \nresources for transmission providers;147 result in inaccurate study results or delays for \n \nat 4-5; Calibrant November 21 ANOPR Comments at 1-2, 3; CEBA November 21 \nANOPR Comments at 9-10; Chamber of Commerce November 21 ANOPR \nComments at 3; CTC Global Corporation November 21 ANOPR Comments at 1-3; \nDCC November 21 ANOPR Comments at 10-11; GridCARE December 5 ANOPR \nComments at 4; Industrial Customers November 21 ANOPR Comments at 27-28; \nInfrastructure Masons December 5 ANOPR Comments at 18; Iron Mountain Data \nCenters, LLC November 21 ANOPR Comments at 3-4; Land Trust Alliance November 21 \nANOPR Comments at 5-6; PIOs November 21 ANOPR Comments at 22; Southeast PIOs \nNovember 21 ANOPR Comments at 44-45; WATT and Advancing Modern Powerlines \nNovember 21 ANOPR Comments at 5-8. \n145 See, e.g., CEBA November 21 ANOPR Comments at 12; ECA December 5 \nANOPR Comments at 1-2; Eolian November 21 ANOPR Comments at 17-18; EPSA \nNovember 21 ANOPR Comments at 6; Infrastructure Masons December 5 ANOPR \nComments at 4, 6-7; Southeast PIOs November 21 ANOPR Comments at 39-40; \nSwitch December 5 ANOPR Comments at 3; Tract November 21 ANOPR Comments \nat 5; Vantage November 21 ANOPR Comments at 5-6; Verrus November 21 ANOPR \nComments at 6, 12; Vistra December 5 ANOPR Comments at 27. \n146 See, e.g., ACORE November 21 ANOPR Comments at 6; AEU November 21 \nANOPR Comments at 17-18; Amazon November 21 ANOPR Comments at 6; Crusoe \nDecember 5 ANOPR Comments at 5-6; EDF Power November 21 ANOPR Comments \nat 12-13; EEI November 21 ANOPR Comments at 20; Fervo November 21 ANOPR \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. \n147 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"},{"page":36,"startToken":13740,"endToken":14135,"text":"Docket No. EL26-70-000 \n- 36 - \nother Eligible Customers seeking transmission service on behalf of load;148 create a \nsubstantial risk of cost shifts if the large load additions do not materialize as planned;149 \nand distort load forecasts.150 Clear and consistent study procedures that include readiness \nrequirements (i.e., meaningful milestones and/or financial commitments) can help ensure \nthat Eligible Customers’ requests for transmission service on behalf of large loads are \nmore viable and more likely to materialize as planned, given that they must meet specific \nmilestones and/or pay costs to proceed. \n \nMore specifically, we preliminarily find that MISO’s Tariff appears to be \nunjust and unreasonable because it lacks sufficiently clear and consistent Tariff \nprovisions that address certain aspects of the process to provide transmission service \nto 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 Customers \non behalf of large loads and the study procedures, including readiness requirements, \nfor studying the provision of transmission service to Eligible Customers on behalf of \nlarge loads; \n \nComments at 9; Ohio FEA November 21 ANOPR Comments at 4; Vistra November 21 \nANOPR Comments at 23. \n148 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 14-15. \n149 See, e.g., Buckeye November 21 ANOPR Comments at 1-2; Exelon \nNovember 21 ANOPR Comments at 3; Kansas Commission November 21 ANOPR \nComments at 12; NRECA November 21 ANOPR Comments at 9; OCC November 21 \nANOPR Comments at 9; Southeast PIOs November 21 ANOPR Comments at 20; \nState Entities November 21 ANOPR Comments at 7-8; TAPS November 21 ANOPR \nComments at 15, 22-24; Tri-State November 21 ANOPR Comments at 6, 8; Vistra \nNovember 21 ANOPR Comments at 23. \n150 See, e.g., CEBA November 21 ANOPR Comments at 8; EEI November 21 \nANOPR Comments at 20; ELCON November 21 ANOPR Comments at 7; Invenergy \nNovember 21 ANOPR Comments at 6; GridCare December 5 ANOPR Comments at 5; \nOCC November 21 ANOPR Comments at 9; PIOs November 21 ANOPR Comments \nat 5; Southeast PIOs November 21 ANOPR Comments at 41; Talen November 21 \nANOPR Comments at 9."},{"page":37,"startToken":14135,"endToken":14571,"text":"Docket No. EL26-70-000 \n- 37 - \n(3) ongoing operational requirements for transmission customers151 serving large \nloads necessary to ensure reliable operation of the transmission system; and \n(4) pro forma provisions in transmission service agreements to memorialize these \nterms. \n \nFirst, we preliminarily find that MISO’s Tariff appears to be unjust and \nunreasonable because it lacks a definition of large load, as a new category of load. As \nMISO acknowledges, integrating large loads poses specific challenges to transmission \nsystem operation given their size, operational behavior, and unique potential to impact \nthe transmission system.152 An appropriate definition, including a load size and \ninterconnection voltage threshold, should be based on the characteristics of MISO’s \ntransmission system. That said, based on the record in the ANOPR proceeding,153 it \nappears that it would be reasonable to define a large load as a new, commercial or \nindustrial customer, located at a single site behind one or more points of interconnection, \nand that has a peak load of 50 MW or greater, interconnects to the transmission system \nat a voltage level of greater than 69 kV, and is not part of a co-location arrangement. \nWe note that this threshold also aligns with the definition of large load that MISO has \nproposed in its Large Load Working Group.154 In its response to this order, MISO should \n \n151 We note that such ongoing operational requirements should apply to \ntransmission customers, rather than Eligible Customers, as these requirements apply \nafter the Eligible Customer has an executed (or a filed unexecuted) service agreement \nfor transmission service and have become transmission customers under the Tariff. \n152 MISO Large Load Workshop Presentation at 7-8; see also MISO November 21 \nANOPR Comments at 30-33. \n153 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). \n154 See MISO, Large Load Interconnection Reliability Requirements (LLWG) 8 \n(May 14, 2026), \nhttps://cdn.misoenergy.org/20260514%20LLWG%20Item%2004%20Large%20Load%2\n0Interconnection%20Reliability%20Requirements757718.pdf."},{"page":38,"startToken":14571,"endToken":15017,"text":"Docket No. EL26-70-000 \n- 38 - \nexplain whether the Tariff remains just and reasonable without such a definition, or \npropose Tariff revisions establishing its own definition of large load. \n \nSecond, we preliminarily find that MISO’s Tariff appears to be unjust and \nunreasonable because it lacks sufficiently clear and consistent Tariff provisions \nestablishing the application process and study procedures that will be used when MISO \nand/or the Transmission Owners evaluate the provision of transmission service to \nEligible Customers on behalf of large loads. MISO should explain whether the Tariff \nremains just and reasonable, for example, without: (1) an application process that accepts \nEligible Customers’ applications for transmission service on behalf of large loads on a \nrolling basis; (2) a non-refundable application fee and sufficient readiness requirements \nthat escalate at distinct phases of the study process to deter duplicative or speculative \nrequests for transmission service (e.g., meaningful milestones and/or financial \ncommitments); and (3) information and data requirements that Eligible Customers must \nsubmit to MISO and/or the Transmission Owners regarding the characteristics of the \nlarge load on behalf of which the Eligible Customer is taking transmission service, \nincluding disclosure to MISO of any substantially similar pending transmission service \nrequests on behalf of the same large load customer.155 MISO may also elect to propose \nTariff revisions establishing such an application process, fee, and requirements. \n \nFurther, MISO’s Tariff appears to lack sufficiently clear and consistent provisions \nestablishing a study process for evaluating the provision of transmission service to \nEligible Customers on behalf of large loads that considers the unique characteristics and \nimpacts of large loads on the transmission system. For example, we are concerned that \nMISO’s Tariff may not clearly and consistently require MISO or the Transmission \nOwners to conduct studies that evaluate the transmission system’s ability to withstand \nrisks observed from analyzed large load behavior created by the large load at the point \nof interconnection, or any other necessary supplemental studies to evaluate the impact \nof providing transmission service to Eligible Customers on behalf of large loads.156 \nAdditionally, we preliminarily find that MISO’s Tariff appears unjust and unreasonable \nbecause it lacks appropriate provisions recognizing within the transmission service \nrequest study process the unique operational characteristics of large loads that are willing \n \n155 The Electric Reliability Council of Texas (ERCOT) has proposed a similar \ndisclosure requirement in its Batch Zero process for large load interconnections. ERCOT \nPlanning Guide, § 9.7.1(1)(b) (proposed Mar. 4, 2026). \n156 See generally NERC, Industry Recommendation: Large Load Interconnection, \nStudy, Commissioning, and Operations (Sep. 2025), \nhttps://www.nerc.com/globalassets/programs/bpsa/alerts/2025/nerc-alert-level-2--large-\nloads.pdf (finding that unique operational characteristics of large loads necessitate \nenhancements to studies)."},{"page":39,"startToken":15017,"endToken":15403,"text":"Docket No. EL26-70-000 \n- 39 - \nand able to limit their energy withdrawals under certain conditions, which may \nthereby lessen or potentially avoid the need for certain Network Upgrades. While \nflexible large loads can reduce the demand on the transmission system, and therefore \npotentially reduce the need for additional transmission capacity, additional informational \nand study requirements may be necessary to account for the dynamic nature of these \ntypes of loads while maintaining reliability.157 Additionally, we note that accurate \nmodels using Electromagnetic Transient studies may help to ensure that transmission \nservice needed on behalf of large loads can be provided without compromising \nreliability.158 \n \nAdditionally, we preliminarily find that MISO’s Tariff appears to be unjust and \nunreasonable because it lacks clear and consistent provisions requiring the evaluation \nof alternative transmission technologies159 as potential solutions to accommodate \nan Eligible Customer’s request for transmission service on behalf of a large load. \nAlternative transmission technologies can add more capacity on existing transmission \nlines quickly, often within one to three years.160 Unlike with traditional load growth,161 \n \n157 See, e.g., AEMA November 21 ANOPR Comments at 6; Thermal Battery \nAlliance November 21 ANOPR Comments at 7; Verrus November 21 ANOPR \nComments at 10. \n158 See, e.g., NERC, Draft Reliability Guideline: Risk Mitigation for Emerging \nLarge Loads 6-7 (May 2026), https://www.nerc.com/globalassets/who-we-are/standing-\ncommittees/rstc/reliabilityguideline_riskmitigationforemerginglargeloads.pdf; NERC, \nAssessment of Gaps in Existing Practices, Requirements, and Reliability Standards for \nEmerging Large Loads 31 (Mar. 2026), https://www.nerc.com/globalassets/our-\nwork/guidelines/reliability/white-paper---assessment-of-gaps.pdf; see also SPP HILL \nOrder, 194 FERC ¶ 61,031 at P 62. \n159 For purposes of this order, alternative transmission technologies include static \nsynchronous compensators, static VAR compensators, advanced power flow control \ndevices, transmission switching, synchronous condensers, voltage source converters, \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). \n160 WATT and Advancing Modern Powerlines November 21 ANOPR Comments \nat 5-6. \n161 See, e.g., SPP HILL Order, 194 FERC ¶ 61,031 at P 7 (explaining that the \nHILL proposal was needed in part due to large load customers frequently requesting \ntransmission service within months rather than years of their intended commercial \noperation, straining legacy regulatory frameworks and planning processes originally"},{"page":40,"startToken":15403,"endToken":15856,"text":"Docket No. EL26-70-000 \n- 40 - \nlarge load customers often have development timelines requiring interconnection to the \ntransmission system faster than traditional Network Upgrades can be built, necessitating \na sufficient evaluation of alternative transmission technologies that can more quickly \naccommodate transmission service requests from Eligible Customers on behalf of large \nloads.162 The Commission has previously recognized that alternative transmission \ntechnologies have the potential to mitigate or defer the need for traditional Network \nUpgrades and often can be deployed both more quickly and at lower cost than traditional \nNetwork Upgrades, and therefore failing to consider whether alternative transmission \ntechnologies can meet transmission needs more efficiently or cost-effectively than \ntraditional Network Upgrades has the potential to render Commission-jurisdictional \nrates unjust and unreasonable.163 Further, to the extent Network Upgrade costs to \naccommodate an Eligible Customer’s request for transmission service on behalf of a large \n \ndesigned for slow, incremental, and predictable load growth); see also FERC 2025 State \nof the Markets Report at 8 (“[D]ata centers have characteristics unlike more traditional \nloads [including] size, strong desire for faster interconnection, and potential flexibility.”). \n162 Exec. Off. of the President, Winning the Race: America’s AI Action Plan 1-2, \n15 (July 2025), https://www.whitehouse.gov/wp-content/uploads/2025/07/Americas-AI-\nAction-Plan.pdf (explaining that accelerated deployment of AI data centers is a \ncritical matter of national security and international economic competitiveness, and \nrecommending federal policy action to optimize the existing grid through advanced \ngrid technologies); 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 \n1-2 years to construct.”); Industrial Customers November 21 ANOPR Comments at 28 \n(“Achieving speed-to-power in the near-term, while also protecting customers, will \nrequire the use of GETs, advanced reconductoring, and unlocking all available system \ncapacity.”); Energy Systems Integration Group, Historical and Modern Large Loads: \nCharacteristics, Context, and Industry Action to Meet Grid and Customer Needs 4 \n(Mar. 2026), https://www.esig.energy/wp-content/uploads/2026/03/ESIG-Historical-vs-\nModern-Large-Loads-white-paper-2026.pdf (describing the timing mismatch between \nhow long it takes to build a new data center and how long it takes to plan, permit, and \nbuild transmission). \n163 Improvements to Generator Interconnection Procs. & Agreements, Order \nNo. 2023, 184 FERC ¶ 61,054 at P 1583, order on reh’g, 185 FERC ¶ 61,063 (2023), \norder on reh’g, Order No. 2023-A, 186 FERC ¶ 61,199, errata notice, 188 FERC ¶ \n61,134 (2024); see also Bldg. for the Future Through Elec. Reg’l Transmission Plan. & \nCost Allocation, Order No. 1920, 187 FERC ¶ 61,068 at P 1201, order on reh’g, Order \nNo. 1920-A, 189 FERC ¶ 61,126 (2024), order on reh’g, Order No. 1920-B, 191 FERC ¶ \n61,026 (2025)."},{"page":41,"startToken":15856,"endToken":16332,"text":"Docket No. EL26-70-000 \n- 41 - \nload are rolled into a transmission owner’s transmission revenue requirement, \ntransmission customers other than the Eligible Customer may bear a portion of those \nNetwork Upgrade costs, highlighting the need for clear and consistent provisions \nrequiring the evaluation of least-cost options like alternative transmission technologies \nto mitigate the rate impact on all transmission customers. \n \nMISO should explain whether the Tariff remains just and reasonable without \nprovisions that (1) require the evaluation of alternative transmission technologies in \ntransmission service request studies, using models that are capable of evaluating the \ntransmission system to accurately account for advanced transmission technologies, in all \ninstances, without the need for a request from the Eligible Customer seeking transmission \nservice on behalf of a large load; and (2) if traditional Network Upgrades are selected \ninstead of alternative transmission technologies, inclusion in the study report to the \nEligible Customer seeking transmission service on behalf of a large load of a sufficiently \nclear demonstration of why alternative transmission technologies are not feasible \n(i.e., would not resolve reliability violations identified or meet the relevant planning \ncriteria) or would not result in lower costs or a faster timeline for accommodating the \ntransmission service request; or propose Tariff revisions establishing such provisions. \nThis transparency and informational requirement is warranted for the regulatory scheme \nwe are establishing for transmission service requests by Eligible Customers on behalf of \nlarge loads given demand from and the expedited development timelines for large load \ncustomers. We underscore that we are not mandating the use of alternative transmission \ntechnologies. To the extent stakeholders believe that specific characteristics of providing \ntransmission service to Eligible Customers on behalf of large loads warrant requirements \nbeyond those contemplated here, we seek further briefing. \n \nFinally, based on the record, it appears reasonable that such study processes, \nculminating in a report to the Eligible Customer with the results of the studies, including \nany Direct Assignment Facilities and Network Upgrades necessary to accommodate the \ntransmission service request as well as a non-binding good-faith estimate of the cost and \nthe time to construct such facilities, should take no more than 60-90 days calendar days \nto complete.164 To the extent MISO or the Transmission Owners already have such \nprocedures and conduct such studies, but those processes are not included in the Tariff, \n \n164 Several commenters support a 60-day timeline. See, e.g., Constellation \nNovember 21 ANOPR Comments at 26; Critical Loop December 5 ANOPR Comments \nat 8; EDF Power November 21 ANOPR Comments at 16; Tract November 21 ANOPR \nComments at 9. Other commenters note that SPP’s HILL process has a 90-day timeline, \nor otherwise support a 90-day timeline. See, e.g., AEMA November 21 ANOPR \nComments at 3; Eolian December 5 ANOPR Comments at 27; Industrial Customers \nNovember 21 ANOPR Comments at 20; PJM November 21 ANOPR Comments at 7; \nSPP November 21 ANOPR Comments at 16-17."},{"page":42,"startToken":16332,"endToken":16818,"text":"Docket No. EL26-70-000 \n- 42 - \nMISO and the Transmission Owners should explain their existing processes and \nconsider whether amendments are necessary to the Tariff to memorialize those processes \nand also address the concerns expressed herein. Otherwise, MISO should explain \nwhether the Tariff remains just and reasonable without: (1) sufficiently clear and \nconsistent provisions to evaluate the impact of providing the requested transmission \nservice to Eligible Customers on behalf of large loads, including identifying the Direct \nAssignment Facilities and Network Upgrades necessary to provide such service reliably; \n(2) provisions to appropriately recognize within the transmission service study process \nthe unique operational characteristics of large loads; (3) a study deadline of no more than \n60-90 calendar days; or propose Tariff revisions establishing them. \n \nThird, we preliminarily find that MISO’s Tariff appears to be unjust and \nunreasonable because it lacks provisions addressing ongoing operational requirements \nfor transmission customers taking transmission service on behalf of large loads. We are \nconcerned that without such requirements the rates, terms, and conditions of transmission \nservice may be unjust and unreasonable. The unique nature of these large loads creates \nchallenges for operation of the transmission system and necessitates greater visibility and \noperational control when providing transmission service to transmission customers on \nbehalf of large loads, without which the reliability of the transmission system could be at \nrisk.165 For example, we are concerned that MISO’s Tariff does not require transmission \ncustomers to provide MISO hourly forecasts, telemetry data, and other data to ensure \nsufficient visibility or specify requirements for maintaining communication channels \nbetween MISO and the transmission customer on behalf of the large load. Additionally, \nwe are concerned that the Tariff does not require transmission owners to install, and \ntransmission customers to pay for, equipment to enable MISO to monitor large loads for \nimpacts of, for example, fast-ramping load that may impact the transmission system too \nquickly to be captured by conventional data acquisition systems (e.g., the need for phasor \nmeasurement units or similar equipment). We are also concerned that the Tariff does not \nrequire the transmission customer to enable MISO to remotely disconnect large loads \nwhen necessary to maintain reliability of the transmission system, with the costs of such \nequipment directly assigned to the transmission customer, as well as the terms and \nconditions under which MISO may remotely disconnect the large load (e.g., emergency \nconditions, so that transmission equipment is not harmed). Further, we are concerned \nthat the Tariff does not specify ramp rate or ride-through requirements with which the \ntransmission customer taking transmission service on behalf of the large load must \ncomply. Lastly, we are concerned that the Tariff does not specify requirements for \nnecessary control technologies and/or protection systems that may be necessary to limit a \n \n165 E.g., ATC November 21 ANOPR Comments at 14; CAISO November 21 \nANOPR Comments at 10 (citing NERC Characteristics and Risks of Large Loads); \nHerb Schrayshuen November 21 ANOPR Comments at 2-5."},{"page":43,"startToken":16818,"endToken":17232,"text":"Docket No. EL26-70-000 \n- 43 - \ntransmission customer’s withdrawals from the transmission system as appropriate.166 \nMISO should explain whether the Tariff remains just and reasonable without these or \nother ongoing operational requirements as part of the rates, terms, and conditions of \ntransmission service or propose Tariff revisions establishing necessary ongoing \noperational requirements. \n \nFourth, we preliminarily find that MISO’s Tariff appears to be unjust and \nunreasonable because it lacks pro forma provisions in a transmission service agreement \nbetween MISO and the transmission customer taking transmission service on behalf \nof a large load to memorialize the above terms (e.g., equipment requirements, data \nrequirements, remote disconnect capability). We are concerned that, without such \npro forma provisions in a transmission service agreement between MISO and the \ntransmission customer, MISO may be unable to enforce ongoing operational \nrequirements for transmission customers taking transmission service on behalf of large \nloads. MISO should explain whether the Tariff remains just and reasonable without \nsuch pro forma provisions in a transmission service agreement, or propose revisions to \ninclude pro forma provisions memorializing the ongoing operational requirements in a \ntransmission service agreement between MISO and the transmission customer. \nB. \nCost Shifting Risk Among Transmission Customers \n \nWe next preliminarily find that MISO’s Tariff appears to be unjust and \nunreasonable because it lacks adequate mechanisms to mitigate the risk of cost shifting \namong transmission customers, which may result in unjust and unreasonable rates \nfor 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 \nof large loads; and (2) a pro forma cost recovery agreement between MISO, the relevant \ntransmission owner, and the Eligible Customer taking transmission service on behalf of \nlarge loads that help ensure that Eligible Customers bear the risk and are ultimately \nresponsible for costs incurred to provide transmission service, including the cost of \nNetwork Upgrades. \n \nWe direct MISO and the Transmission Owners, to the extent the matters addressed \nherein implicate aspects of the Tariff over which they have the filing rights, to explain \nwhether the Tariff remains just and reasonable without (1) robust, accurate, and \nsystematic provision of data on MISO’s website in a single location, and in an easily \n \n166 Specifically, as discussed below, the Commission has found that such \nnecessary control technologies and/or protection schemes may be appropriate where \nEligible Customers are taking one of the new transmission services. See infra \nPP102,105."},{"page":44,"startToken":17232,"endToken":17662,"text":"Docket No. EL26-70-000 \n- 44 - \naccessible format that is searchable and allows users to filter the data, regarding the cost \nfor Network Upgrades needed to provide transmission service to Eligible Customers on \nbehalf of large loads; and (2) a pro forma cost recovery agreement between MISO, the \nrelevant transmission owner, and the Eligible Customer taking transmission service on \nbehalf of a large load, or to propose Tariff revisions to provide additional transparency \nand establish such a pro forma cost recovery agreement. We encourage state regulators \nresponsible for setting retail rates to provide input to MISO regarding their transparency \nneeds. \n1. \nJurisdiction \n \nThe Commission has a duty to address the risk of cost shifting among transmission \ncustomers that may result in unjust and unreasonable transmission rates. As explained \nabove, the Commission is obligated to ensure that the rates charged for jurisdictional \ntransmission service—as well as any practice directly affecting such rates—are just and \nreasonable and not unduly discriminatory or preferential. With respect to the addition of \nlarge loads to the transmission system, the Commission has exclusive authority to ensure \nthat transmission rates are just and reasonable. The costs of those upgrades to the \ntransmission system (i.e., Network Upgrades) necessary to provide transmission service \nto Eligible Customers on behalf of large loads are inputs to jurisdictional transmission \nrates, and thus directly affect the Commission-jurisdictional rates paid by transmission \ncustomers. To fulfill its responsibility to ensure that transmission rates are just and \nreasonable, the Commission must act to address the risk of cost shifting among \ntransmission customers due to (1) the process transmission providers and/or transmission \nowners use to evaluate the facilities needed, and the associated costs, for the provision of \ntransmission service to Eligible Customers on behalf of large loads and (2) speculative \ntransmission service requests by Eligible Customers on behalf of large loads that could \nresult in unjust and unreasonable transmission rates. \n \nIn response to the ANOPR, many commenters raise concerns about the impact that \nlarge load additions can have on retail ratepayers, particularly the concern that other retail \nratepayers may be forced to subsidize Network Upgrades needed to add large loads to \nthe transmission system.167 While we appreciate and are similarly concerned about this \nissue, the Commission is limited to addressing jurisdictional transmission rates and as \nsuch, we do so herein. As the Commission has explained, states determine how \nCommission-approved rates are collected among the relevant retail consumers along \n \n167 See, e.g., Illinois AG November 21 ANOPR Comments at 11-12; Missouri \nCommission November 21 ANOPR Comments at 11; OMS November 21 ANOPR \nComments at 4."},{"page":45,"startToken":17662,"endToken":18077,"text":"Docket No. EL26-70-000 \n- 45 - \nwith the rates for state-jurisdictional matters.168 Specifically, states have authority \nover how the wholesale costs of providing electricity, including transmission of such \nelectricity, to those retail customers are recovered through retail rates.169 We are \nencouraged by efforts taken by states to reform retail tariffs to address the potential \nfor retail cost shifting as large loads come online,170 as well as voluntary efforts by \ntransmission owners to protect retail ratepayers through cost recovery agreements with \nlarge loads.171 We are also encouraged by the execution of the President’s Ratepayer \nProtection Pledge, through which data center developers have committed to shield retail \nratepayers from increased electricity prices.172 \n \nWe expect that the additional cost transparency measures proposed in the \nfollowing section will give state public utility commissions and other state regulators \nthe information necessary to allow them to understand which transmission costs are \ncaused by which transmission customers, so that they can sub-allocate these costs to the \nappropriate retail customers. Indeed, the Commission’s objective in this proceeding is to \nrespect the cooperative federalism approach established under the FPA. Specifically, one \nof the benefits of providing transparency on the costs of Network Upgrades necessary to \nprovide transmission service to Eligible Customers on behalf of large loads is so that state \nregulators can use that information to protect residential and small commercial customers \nby incorporating those costs into the retail rates as they see fit given their authority to \nset rates for different classes of retail customers. We encourage state public utility \ncommissions, state regulators, and state consumer advocates to submit comments \nexplaining whether this information is sufficient and granular enough or to submit \ncomments explaining precisely which additional information on transmission cost \nallocation may be needed to inform proper state-jurisdictional cost allocation. \n \n168 PJM Show Cause Order, 190 FERC ¶ 61,115 at P 167. \n169 Id. P 68. \n170 See, e.g., Arkansas Commission November 21 ANOPR Comments at 2; \nLouisiana and Mississippi Commissions November 21 ANOPR Comments at 6-8; \nWisconsin Electric November 21 ANOPR Comments at 5-6. \n171 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 ¶ \n61,103 (2025); Dayton Power & Light Co., 189 FERC ¶ 61,220 (2024). \n172 Proclamation No. 11014, 91 Fed. Reg. 11439 (Mar. 4, 2026)."},{"page":46,"startToken":18077,"endToken":18515,"text":"Docket No. EL26-70-000 \n- 46 - \n2. \nAdditional Cost Transparency \n \nWe preliminarily find that MISO’s Tariff appears to be unjust and unreasonable \nor unduly discriminatory or preferential because it does not contain provisions requiring \nthe provision of data on MISO’s website in a single location, and in an easily accessible \nformat that is searchable and allows users to filter the data, on transmission service \nrequested by Eligible Customers on behalf of large loads, for Network Upgrades \nevaluated in the local transmission planning process that are needed to provide \ntransmission service to Eligible Customers on behalf of those large loads, and the costs \nfor those Network Upgrades. We preliminarily find that cost transparency measures are \nneeded to provide stakeholders with sufficient information and visibility regarding the \nNetwork Upgrades, and their associated costs, needed to provide transmission service to \nEligible Customers on behalf of large loads. \n \nAs an initial matter, we note that the MISO Tariff contains several methods \nfor identifying Network Upgrades needed to provide transmission service to Eligible \nCustomers, including for Eligible Customers requesting transmission service on behalf \nof large loads. As discussed above, Network Upgrades triggered by a new NITS request \nor designation of new Network Load, such as to serve a large load, may be designated \nas Transmission Delivery Service Projects within the MTEP or included in local \ntransmission planning processes. Moreover, in its comments, MISO asserts that its load \nforecasting approach accounts for data centers and manufacturing as two key drivers of \nload growth.173 We also acknowledge that MISO recently conducted a survey to gather \nmore granular data on large loads to improve its load forecasting.174 \n \nHowever, MISO’s Tariff does not appear to require that information identifying \nthe Network Upgrades needed to provide transmission service to Eligible Customers on \nbehalf of large loads and the costs of those Network Upgrades determined through local \ntransmission planning processes be readily available on MISO’s website in a single \nlocation, and in an easily accessible format that is searchable and allows users to filter \nthe data. The speed and scale with which Eligible Customers are seeking transmission \nservice on behalf of large loads makes it difficult for interested parties, including \ntransmission customers and state regulators, to accurately assess which transmission \ncosts are driven by requests for transmission service by Eligible Customers to serve large \nloads. Further, MISO itself projects load growth to be three times higher than previously \nforecasted.175 We are concerned that the potentially speculative nature of requests for \n \n173 MISO November 21 ANOPR Comments at 11. \n174 Id. at 12; see MISO, MISO Long-Term Load Forecasting Results Presentation. \n175 MISO November 21 ANOPR Comments at 10-11."},{"page":47,"startToken":18515,"endToken":18970,"text":"Docket No. EL26-70-000 \n- 47 - \ntransmission service by Eligible Customers on behalf of large loads,176 the speed and \nscale with which large loads are seeking to be added to the transmission system, the \nprojected need for significant Network Upgrades to provide transmission service to \nEligible Customers on behalf of large loads, and the lack of centralized information on \nthe associated transmission costs in MISO hamper the ability of the Commission and \nstakeholders (including transmission customers and state regulators177) to understand and \naccurately assess the relationship between the addition of large loads to the transmission \nsystem and wholesale transmission costs. \n \nFor local transmission planning processes, we note that, for example, MISO’s \nEPR Technical Study Task Force presents high-level study results and cost estimates for \nEPR projects that have been recently approved or are currently being studied at publicly \nnoticed, monthly regional stakeholder meetings.178 However, MISO’s Tariff does not \ncontain provisions that require MISO to publicly post cost estimates of EPR requests \nnecessary to provide transmission service to Eligible Customers on behalf of large loads. \nSimilarly, while MISO regularly updates a list of locally planned transmission projects \nthat will be included in Appendix A of the next MTEP as Other Projects,179 the Tariff \n \n176 See supra P 56. \n177 See Transcript, NARUC Collaborative, Docket No. AD24-7-000, at 16-17 \n(Feb. 11, 2026) (Chair Bagot, Virginia) (asserting that additional transparency at the RTO \nlevel would help the states get the information they need to “identify . . . that bucket of \ncosts” related to large load-driven transmission costs), 19 (Commissioner Chattopadhyay, \nNew Hampshire) (noting the need for “all parties to be able to see things transparently” \nwith respect to wholesale transmission costs), 35-37 (Chair Martz, Iowa) (raising concern \nthat currently RTOs/ISOs do not have to clearly explain when a “bucket of costs is \nspecifically for this large load” and noting that “if we, at the state level, can’t see the \ndriver [of transmission costs], we can’t assign the cost to the causer[,] [a]nd so we need \nthat clarity”), 69-70 (Chair Myers, Arizona) (“[B]eing able to allocate the large load costs \nto the correct bucket when it gets to the states is kind of a top priority.”). \n178 MISO, BPM-020, § 4.1.4.2; see also, e.g., MISO, Expedited Project Review \nTechnical Study Taskforce (EPR-TSTF) (Jan. 6, 2026), \nhttps://www.misoenergy.org/events/2026/expedited-project-review-technical-study-\ntaskforce-epr-tstf---january-6-2026/; MISO, Expedited Project Review Results and \nRecommendation 4 (Jan. 6, 2026), https://cdn.misoenergy.org/20260106%20EPR-\nTSTF%20Item%2002%20EPR%20Results%20and%20MISO%20Recommendation7341\n23.pdf (estimating the Network Upgrades to serve a 620 MW load addition will cost \n$11.26 million). \n179 MISO, MTEP Appendix A Status Report, \nhttps://www.misoenergy.org/planning/transmission-planning/mtep/ (scroll down and"},{"page":48,"startToken":18970,"endToken":19417,"text":"Docket No. EL26-70-000 \n- 48 - \ndoes not require public posting of cost estimates for Other Projects necessary to provide \ntransmission service to Eligible Customers on behalf of large loads. \n \nWe are concerned that without sufficient transparency regarding the \nNetwork Upgrades, and their associated costs, needed to provide transmission service \nto Eligible Customers on behalf of large loads, stakeholders may lack information and \nvisibility regarding the costs driven by large load additions. We preliminarily find that, \nfor Network Upgrades evaluated in the local transmission planning process180 that are \nneeded to provide transmission service to Eligible Customers on behalf of large loads, \nMISO must provide clear, timely, and detailed information regarding the extent to \nwhich requests for transmission service by Eligible Customers on behalf of large loads \nnecessitate Network Upgrades to accommodate the transmission service to Eligible \nCustomers on behalf of large loads, as well as the costs of those Network Upgrades. \n \nWe note that centralized information regarding Network Upgrades needed to \naccommodate requests for transmission service by Eligible Customers on behalf of \nlarge loads would also help inform stakeholders at the state and local level to address \naffordability and other challenges posed by the integration of large loads. Indeed, \ncommenters state that the opaque nature of requests for transmission service by \nEligible Customers on behalf of large loads, and the associated Network Upgrades \nrequired to provide that transmission service, prevent wholesale and retail customers, \nstates, and other stakeholders from understanding such costs.181 \n \nclick “Project Tracking and Monitoring,” then click the link to “MTEP Appendix A \nStatus Report”) (last visited Apr. 30, 2026). \n180 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. \n181 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-"},{"page":49,"startToken":19417,"endToken":19864,"text":"Docket No. EL26-70-000 \n- 49 - \n \nAccordingly, we preliminarily find that MISO’s Tariff appears to be unjust and \nunreasonable because it does not require the provision of data on MISO’s website in a \nsingle location, and in an easily accessible format that is searchable and allows users to \nfilter the data, that identifies the Network Upgrades that are needed to accommodate \nrequests for transmission service by Eligible Customers on behalf of large loads, and \nthe costs of those Network Upgrades. MISO should explain whether the Tariff remains \njust and reasonable without provisions that would require MISO and the Transmission \nOwners to publicly post and regularly update data that details: (1) the aggregate amounts \nof proposed large load additions in MISO’s footprint, including the aggregate amounts \nin each transmission pricing zone; (2) the planned Network Upgrades needed to provide \ntransmission service to Eligible Customers on behalf of large loads, identified by \ntype of equipment and Network Upgrade (e.g., new substation, reconductoring, a new \nhigh-voltage transmission line) for each transmission service request; and (3) cost \nestimates for those Network Upgrades; or propose such Tariff revisions. MISO and the \nTransmission Owners should also consider what other data related to transmission costs \nresulting from the provision of transmission service to Eligible Customers on behalf of \nlarge loads would be useful to include on MISO’s website. To the extent there are \nconcerns about data confidentiality, MISO and the Transmission Owners should consider \nwhether there are ways to mitigate those concerns while still providing the necessary \ntransparency. \n3. \nCost Recovery Agreements \n \nWe next preliminarily find that MISO’s Tariff appears to be unjust and \nunreasonable because it lacks adequate mechanisms to mitigate the risk of cost shifting \namong transmission customers, which may result in unjust and unreasonable rates \nfor transmission service. In particular, we are concerned about the apparent lack of a \npro forma cost recovery agreement between MISO, 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 \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":50,"startToken":19864,"endToken":20306,"text":"Docket No. EL26-70-000 \n- 50 - \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.182 Commenters also argue that retail-level large load tariffs do not \nprotect wholesale transmission customers from cost shifting.183 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.184 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, \nit cannot protect against cost shifting associated with regional transmission buildout \nwhere “the large loads that formed the basis for the [regional] transmission plans do \nnot materialize, leaving only existing customers to pay for generational expansions \nof the transmission grid.”185 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.186 \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 \n \n182 See, e.g., Buckeye November 21 ANOPR Comments at 8-13; APPA November 21 \nANOPR Comments at 6 (“Wholesale transmission customers in particular could be left \nshouldering massive costs if new large loads do not ultimately attain or maintain the level \nof electricity demand that is being forecasted.”); NRECA November 21 ANOPR Comments \nat 21 (noting the risk that other transmission customers could bear stranded upgrade costs \ncaused by large loads that they cannot absorb); TAPS November 21 ANOPR Comments \nat 22-24; California DWR November 21 ANOPR Comments at 8. \n183 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. \n184 Buckeye November 21 ANOPR Comments at 14-15; see TAPS November 21 \nANOPR Comments at 26-27 & nn.50-51. \n185 Kansas Commission November 21 ANOPR Comments at 11-12. \n186 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,” \nin a Construction Service Agreement with Amazon)."},{"page":51,"startToken":20306,"endToken":20797,"text":"Docket No. EL26-70-000 \n- 51 - \namong transmission customers, which may lead to unjust and unreasonable increases \nin jurisdictional transmission rates. When a transmission owner constructs Network \nUpgrades to accommodate an Eligible Customer’s request for transmission service on \nbehalf of a large load, those transmission costs will be included in the transmission \nowner’s transmission revenue requirement. If, however, the Eligible Customer takes less \ntransmission service than anticipated because the large load operates at a lower demand \nthan anticipated or fails to materialize at all, other transmission customers may see an \nincrease in transmission rates. In such a situation, those other transmission customers \nmay have to pay for potentially unnecessary Network Upgrades that they neither caused \nthe need for nor benefit commensurately from. In other words, this introduces the risk \nthat costs may be unfairly shifted to other transmission customers, which may result in \nthose costs then being passed through to residential customers, among others. \n \nMISO’s Tariff does not require cost recovery agreements between MISO, the \nrelevant transmission owner, and the Eligible Customer taking transmission service on \nbehalf of a large load. Such agreements would help ensure that the Eligible Customer \nmakes a minimum contribution to the transmission owner’s transmission revenue \nrequirement commensurate with the costs incurred to provide the requested transmission \nservice, including the costs of any needed Network Upgrades. Absent such cost \nrecovery agreements, we are concerned that there is no mechanism to help ensure that \nEligible Customers taking transmission service on behalf of large loads (as opposed to \nother transmission customers) bear the risk of, and are ultimately responsible for, the \ncosts incurred to provide them with the requested transmission service, including the \ncosts of any needed Network Upgrades. \n \nAccordingly, we preliminarily find that, in order to prevent unjust and unreasonable \ncost shifting among transmission customers, it appears necessary for MISO, the relevant \ntransmission owner, and the Eligible Customer taking transmission service on behalf of a \nlarge load to enter into a cost recovery agreement that requires the Eligible Customer to \nmake a minimum contribution toward the transmission owner’s transmission revenue \nrequirement, if the Eligible Customer ultimately takes less transmission service than \nanticipated because the large load does not materialize as planned or is not developed at \nall. We preliminarily find that such cost recovery agreements are necessary to help ensure \nthat the Eligible Customer is responsible for timely paying the costs of large load-driven \ntransmission (i.e., the costs incurred to provide them with the requested transmission \nservice, including the costs of any needed Network Upgrades), rather than having those \ncosts paid by other transmission customers that neither caused the need for nor benefit \ncommensurately from those Network Upgrades.187 Our preliminary finding is not \nintended to alter or call into question existing regional cost allocation methods for \n \n187 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":20797,"endToken":21235,"text":"Docket No. EL26-70-000 \n- 52 - \nNetwork Upgrades, but instead is focused on helping to prevent cost shifting among \ntransmission customers. \n \nWe note that several transmission owners and large load customers have filed \ncost recovery agreements (Transmission Security Agreements or Construction Service \nAgreements) with the Commission that guarantee minimum contributions from a large \nload customer (rather than from the Eligible Customer taking transmission service on \nbehalf of the large load customer) to the transmission owner’s transmission revenue \nrequirement.188 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.189 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 MISO’s Tariff is unjust and \nunreasonable because it lacks a pro forma cost recovery agreement of this type, we also \npreliminarily find that the minimum contribution required pursuant to such an agreement \nshould be based on the level of jurisdictional transmission service (in MW) requested by \nthe Eligible Customer on behalf of the large load. That figure is in turn tied to how \nMISO and/or Transmission Owners will study the requested transmission service and \ndetermine any necessary Network Upgrades that must be developed to provide the \nrequested transmission service. We note, however, that there may be other just and \nreasonable methods for determining this minimum contribution, including methods that \naccount for potential timing differences between when costs are incurred to develop \nneeded Network Upgrades and the pace at which the large load ramps toward energizing \n \n188 See supra note 171. \n189 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":21235,"endToken":21672,"text":"Docket No. EL26-70-000 \n- 53 - \nat its full level of requested service. We further preliminarily find that the cost recovery \nagreement should include a credit support (or other financial security) requirement \nsufficient to secure the obligations of the Eligible Customer taking transmission service \non behalf of a large load to pay the amounts owed pursuant to the cost recovery \nagreement. We find that a cost recovery agreement with a specified minimum financial \ncontribution and financial security sufficient to secure such contribution is necessary to \nmitigate cost shifting if the Eligible Customer ultimately takes less transmission service \nthan anticipated because the large load does not materialize as planned or is not \ndeveloped at all. We preliminarily find that an Eligible Customer may include a credit \nsupport or other financial security posted by a large load as part of a retail agreement to \navoid creating duplicative credit support requirements. MISO should explain why such a \npro forma 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.190 \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.191 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 Customer \ntaking transmission service on behalf of Eligible Load192 that is willing and able to limit \nits energy withdrawals from the transmission system under certain conditions.193 As \n \n190 See infra P 125. \n191 See 18 C.F.R. pt. 101 (2025). \n192 As discussed below, for purposes of this order, we will use the term \nEligible Load to refer to co-located load and/or load with behind the meter generation. \nSee infra P 91. \n193 PJM Co-Location Order, 193 FERC ¶ 61,217 at P 2; PJM Co-Location \nRehearing Order, 195 FERC ¶ 61,209 at PP 91, 102."},{"page":54,"startToken":21672,"endToken":22048,"text":"Docket No. EL26-70-000 \n- 54 - \ndiscussed below, MISO’s Tariff appears to be unjust and unreasonable because it lacks \nsuch provisions.194 \n \nWe direct MISO and the Transmission Owners, to the extent the matters addressed \nherein implicate aspects of the Tariff over which they have the filing rights, to explain \nwhether the Tariff remains just and reasonable without provisions addressing the rates, \nterms and conditions that apply to interconnection customers serving co-located load and \nfor Eligible 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. We recognize that MISO is currently considering reforms related to \nco-location arrangements in its stakeholder process, and we again encourage MISO to \nconsider whether these efforts would, either fully or in part, address the Commission’s \nconcerns 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.”195 The PJM \nCo-Location Order used the term co-location arrangement when referring to both the \nco-located load and the associated generator.196 \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 \nMISO’s Tariff defines Behind the Meter Generation (BTMG) as: \n \n194 We note that MISO does not allow Eligible Customers taking transmission \nservice on behalf of loads with behind the meter generation to reduce their transmission \nservice charges by netting output from the behind the meter generation in determining \nNITS charges. We therefore need not address behind the meter generation netting rules \nin this order. \n195 PJM Co-Location Order, 193 FERC ¶ 61,217 at P 164 (alterations in original). \n196 Id. P 3."},{"page":55,"startToken":22048,"endToken":22372,"text":"Docket No. EL26-70-000 \n- 55 - \nGeneration resources used to serve wholesale or retail \nload located behind a CPNode that are not included in the \nTransmission Provider’s Setpoint Instructions and in some \ncases can also be deliverable to Load located within the \nTransmission Provider Region using either Network \nIntegration, Point-To-Point Transmission Service or \ntransmission service pursuant to a Grandfathered \nAgreement.197 \n \nFor purposes of this order, we will use the term Eligible Load to refer to co-located \nload and/or load with BTMG.198 \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.199 The \nCommission retains exclusive authority to regulate the procedures and agreements that \napply to the interconnection of a generator that will make wholesale sales, both where \nthe generator interconnects directly to the interstate transmission system and where a \ngenerator interconnects to dual-use distribution facilities.200 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.201 As the Commission found in the PJM Co-Location Order, we continue to \n \n197 MISO Tariff, Module A, § 1.B (Definitions B) (3.0.0). While we believe this \ndefinition is sufficient for purposes of this order, responses may explain whether changes \nto the definition of BTMG may be needed in order to comply with any future directives, \nshould the Commission find that the Tariff has in fact become unjust and unreasonable. \n198 PJM Co-Location Rehearing Order, 195 FERC ¶ 61,209 at P 91. \n199 PJM Co-Location Order, 193 FERC ¶ 61,217 at P 171 (citing 16 U.S.C. \n§§ 824d, 824e; EPSA, 577 U.S. at 278). \n200 Id. P 172 (citing Nat’l Ass’n of Regul. Util. Comm’rs v. FERC, 475 F.3d 1277, \n1282 (D.C. Cir. 2007)). \n201 Id. P 173."},{"page":56,"startToken":22372,"endToken":22758,"text":"Docket No. EL26-70-000 \n- 56 - \nacknowledge that the application of these principles depends on the specific facts and \ncircumstances presented in particular situations.202 \n \nAdditionally, we reiterate that certain other aspects of co-location arrangements fall \nsquarely within the jurisdiction of the states. As we explained in the PJM Co-Location \nOrder, states retain exclusive authority over the specific terms of retail sales and retail rate \ndesign, including retail cost allocation to the co-located load; which entities are legally \npermitted to provide electricity to retail customers in co-location arrangements; and which \ngenerating facilities are sited and allowed to serve co-located load.203 \n3. \nTariff Provisions \n \nWe preliminarily find that MISO’s Tariff appears to be unjust and unreasonable or \nunduly discriminatory or preferential because it does not contain provisions addressing \nwith sufficient clarity and consistency the rates, terms, and conditions of service that \napply to interconnection customers serving co-located load. We also preliminarily find \nthat MISO’s Tariff appears to be unjust and unreasonable or unduly discriminatory or \npreferential because it does not contain provisions addressing with sufficient clarity \nand consistency 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 \nload may use generator interconnection processes in MISO’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 \non behalf of the co-located load under the Tariff for purposes of assessing charges, \nincluding the appropriate charges for wholesale services that should apply to such \nEligible Customers. 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,204 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 \n202 Id. P 174. \n203 Id. PP 167-169. \n204 Hecate Energy Greene Cnty. 3 LLC v. FERC, 72 F.4th 1307, 1312 \n(D.C. Cir. 2023)."},{"page":57,"startToken":22758,"endToken":23212,"text":"Docket No. EL26-70-000 \n- 57 - \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 \nfor them,”205 and that costs must be allocated in a manner that is at least roughly \ncommensurate with the benefits that entity receives.206 \n \nWe preliminarily find that MISO’s Tariff appears to be unjust and unreasonable \nbecause it lacks sufficient clarity and consistency as to the rates, terms, and conditions \nof service that apply to interconnection customers serving co-located load, including \nthe scope of the analyses MISO performs as part of its existing study process to evaluate \nthe impacts of co-location arrangements, which may need to account for any potential \ndynamic impacts of co-located load and any potential impacts of requests to modify \nan existing generating facility’s interconnection service level to serve co-located load \non transmission system reliability. Additionally, in the PJM Co-Location Order, the \nCommission found that it was necessary to clarify that interconnection customers seeking \nto use new generating facilities to serve co-located load may (1) request interconnection \nservice at a level below the generating facility’s maximum facility output; (2) use \nexisting procedures to accelerate interconnection requests that satisfy certain tariff \ncriteria; and (3) request provisional interconnection service and surplus interconnection \nservice.207 As such, interconnection customers seeking to use their generating facilities to \nserve co-located load have no means of knowing the appropriate mechanism for setting \nforth the terms and conditions of co-location arrangements. We recognize that MISO is \ndeveloping a zero-injection generator interconnection agreement process for generation \nthat is co-located with load in its stakeholder process.208 However, MISO’s Tariff \ncurrently does not include any standard interconnection procedures for these zero-\ninjection arrangements, nor does the Tariff specify how MISO studies the reliability \nimpacts that such arrangements may have on the transmission system. We are concerned \n \n205 Midwest ISO Transmission Owners v. FERC, 373 F.3d at 1368. \n206 See, e.g., Ill. Com. Comm’n v. FERC, 576 F.3d at 476. \n207 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 \npart on April 16, 2026. PJM Interconnection, L.L.C., 195 FERC ¶ 61,030. \n208 MISO November 21 ANOPR Comments at 13; see also MISO TOs April 3 \nANOPR Comments at 13-14."},{"page":58,"startToken":23212,"endToken":23663,"text":"Docket No. EL26-70-000 \n- 58 - \nthat the details of such a process—including the existing rules and studies applicable to \nsuch generator interconnection arrangements—are not sufficiently detailed in the Tariff \nto ensure 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 MISO to address situations in \nwhich a co-located load withdraws energy from the transmission system. \n \nTherefore, we preliminarily find that MISO’s Tariff appears to be unjust and \nunreasonable because it does not contain provisions addressing with sufficient clarity \nand consistency the rates, terms, and conditions of service that apply to interconnection \ncustomers serving co-located load. MISO should explain whether the Tariff remains just \nand reasonable without such provisions, or propose Tariff revisions. \n \nWe have similar concerns regarding MISO’s existing rate designs for transmission \nand ancillary services that are used by Eligible Customers taking transmission service \non behalf of Eligible Load. The Commission has previously found that co-located loads \nthat are synchronized with the transmission system use and benefit from at least some \nancillary services and may be reasonably charged for such benefits.209 Specifically, the \nCommission has found that, regardless of whether a co-located load withdraws energy \nfrom the transmission system, co-located load relies on and benefits from regulation \nservice and black start service, and concluded that Eligible Customers taking one of the \nnew transmission services (discussed below) on behalf of co-located load must pay for \nthese ancillary services on a gross demand basis.210 In the PJM Co-Location Rehearing \nOrder, the Commission applied these findings to Eligible Customers taking transmission \nservice on behalf of load with BTMG.211 However, MISO’s Tariff does not appear to \ninclude a mechanism by which an Eligible Customer, on behalf of Eligible Load, would \nbe charged for ancillary services commensurate with its usage of such services, \nparticularly if such customer did not withdraw energy from the transmission system. \n Therefore, we preliminarily find that MISO’s Tariff appears to be unjust and \nunreasonable because it does not address whether and how Eligible Customers taking one \nof the new transmission services on behalf of Eligible Loads will be charged for their use \nof regulation and black start services, which introduces the risk that Eligible Load may \nbenefit from regulation and black start services without contributing to cost recovery for \nsuch services. As noted in the PJM Co-Location Order, this introduces the risk that costs \nmay be allocated entirely to other transmission customers and passed through to \n \n209 PJM Co-Location Order, 193 FERC ¶ 61,217 at P 183. \n210 Id. PP 184-185. \n211 See PJM Co-Location Rehearing Order, 195 FERC ¶ 61,209 at P 400."},{"page":59,"startToken":23663,"endToken":24122,"text":"Docket No. EL26-70-000 \n- 59 - \nresidential customers, among others.212 MISO 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 \nwith the benefits received.213 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.214 We are concerned that MISO’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.215 \n Therefore, we also preliminarily find that MISO’s Tariff appears to be \nunjust and unreasonable because it does not include transmission services that reflect \nEligible Customers taking transmission service on behalf of Eligible Load that are willing \nand able to limit their use of the transmission system under certain conditions. MISO \nshould explain whether the Tariff remains just and reasonable without the transmission \nservices described by the Commission in the PJM Co-Location Order, with regional \nvariation as appropriate, being available to Eligible Customers taking transmission \nservice on behalf of Eligible Load, or propose appropriate Tariff revisions. Specifically, \nMISO should explain whether the Tariff remains just and reasonable without (1) an \ninterim non-firm network transmission service while Network Upgrades are being \nconstructed (i.e., interim NITS) and (2) permanent firm and non-firm contract demand \n \n212 See PJM Co-Location Order, 193 FERC ¶ 61,217 at P 159. \n213 Id. P 199. \n214 PJM Co-Location Rehearing Order, 195 FERC ¶ 61,209 at PP 101-103. \n215 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":24122,"endToken":24537,"text":"Docket No. EL26-70-000 \n- 60 - \ntransmission services (transmission service up to a specified MW quantity, i.e., the \ncontract level, on a firm or non-firm basis). Finally, we note that the Commission has \nfound it just and reasonable that, in order for an Eligible Customer to take interim NITS, \nfirm contract demand transmission service, and non-firm contract demand transmission \nservice, an Eligible Customer must have necessary control technologies and/or protection \nsystems, which may include a special protection scheme, to limit its energy withdrawals \nto its approved level.216 \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 loads217 can quickly and verifiably adjust \ntheir consumption in response to system conditions or price signals.218 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 \nneed for Network Upgrades, among other potential benefits.219 In recognition of this \nflexibility, many commenters support new transmission services that reflect the \n \n216 PJM Co-Location Rehearing Order, 195 FERC ¶ 61,209 at P 480. \n217 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. \n218 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 Comments \nat 5; CEBA November 21 ANOPR Comments at 14-15; ClearPath November 21 ANOPR \nComments at 2-4; Digital Energy Council November 21 ANOPR Comments at 1; EDF \nPower November 21 ANOPR Comments at 4; Emerald November 21 ANOPR Comments \nat 2; Verrus November 21 ANOPR Comments at 4. \n219 See, e.g., AEMA November 21 ANOPR Comments at 5; ELCON November 21 \nANOPR Comments at 9; Emerald November 21 ANOPR Comments at 6-7; Institute for \nProgress November 21 ANOPR Comments at 11; Land Trust Alliance November 21 \nANOPR Comments at 10; LS Power November 21 ANOPR Comments at 5; Microsoft \nNovember 21 ANOPR Comments at 10-11; National Grid November 21 ANOPR \nComments at 19-20; OMS November 21 ANOPR Comments at 13-14; Southeast PIOs \nNovember 21 ANOPR Comments at 50."},{"page":61,"startToken":24537,"endToken":24963,"text":"Docket No. EL26-70-000 \n- 61 - \noperational capabilities of flexible large loads, including interim NITS while \nNetwork Upgrades are constructed, and non-firm transmission service.220 \n We preliminarily find that MISO’s Tariff appears to be unjust and unreasonable \nbecause it does not include transmission services that reflect Eligible Customers taking \ntransmission service on behalf of flexible large loads that are willing and able to limit \ntheir use of the transmission system under certain conditions. The transmission services \navailable to Eligible Customers, including on behalf of flexible large loads, in MISO are \nNITS and firm and non-firm Point-To-Point Transmission Service.221 While these \nremain just and reasonable options for an Eligible Customer to take on behalf of a \nflexible large load, based on the record before us, we preliminarily find that new \ntransmission services should be available to reflect the operational reality that large loads \nmay use the transmission system to differing extents and certain large loads are willing \nand able to limit their use of the transmission system under certain conditions.222 As \nexplained above, the Commission found that Eligible Customers taking transmission \nservice on behalf of Eligible Load should be allowed to choose a transmission service \nthat aligns with their use of the transmission system and therefore aligns the charges for \nservice with the benefits received.223 As the record suggests, Eligible Customers taking \ntransmission service on behalf of flexible large load also may be willing and able to limit \ntheir use of the transmission system under certain conditions. As recognized in the \nANOPR record, load flexibility can avoid inefficient and costly transmission system \nbuild-out.224 In addition, transmission services that reflect that flexible large loads are \nwilling and able to limit their withdrawals from the transmission system under certain \n \n220 See, e.g., Constellation November 21 ANOPR Comments at 24-25; \nCalibrant November 21 ANOPR Comments at 2-4; Critical Loop November 21 ANOPR \nComments at 2; Digital Power Network November 21 ANOPR Comments at 3; PIOs \nNovember 21 ANOPR Comments at 27-28; Splight November 21 ANOPR Comments \nat 3-4. \n221 See supra P 22 (describing existing transmission services in MISO). \n222 See supra P 103. \n223 PJM Co-Location Order, 193 FERC ¶ 61,217 at P 199; PJM Co-Location \nRehearing Order, 195 FERC ¶ 61,209 at P 103. \n224 See supra P 103; see also PJM Co-Location Order, 193 FERC ¶ 61,217 \nat PP 160, 177, 199 (finding that new transmission service options reflect a co-located \nload’s ability to limit withdrawals from the transmission system and potentially avoid \ncostly and inefficient transmission system buildout that may not be necessary)."},{"page":62,"startToken":24963,"endToken":25386,"text":"Docket No. EL26-70-000 \n- 62 - \nconditions could help timely interconnect flexible large loads.225 Entities in the MISO \nfootprint acknowledge the importance of facilitating load flexibility.226 \n Therefore, we are concerned that MISO’s Tariff does not include transmission \nservices that reflect the use of the transmission system by Eligible Customers on behalf \nof flexible large load, on both an interim and permanent basis. MISO 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 \nas appropriate, being available to Eligible Customers taking transmission service on \nbehalf of flexible large loads, or propose appropriate Tariff revisions. Specifically, \nMISO should explain whether the Tariff remains just and reasonable without (1) an \ninterim non-firm network transmission service while Network Upgrades are being \nconstructed (i.e., interim NITS) and (2) permanent firm and non-firm contract demand \ntransmission services (transmission service up to a specified MW quantity, i.e., the \ncontract level, on a firm or non-firm basis). Finally, we note that the Commission has \nfound it just and reasonable that, in order for an Eligible Customer to take interim NITS, \nfirm contract demand transmission service, and non-firm contract demand transmission \nservice, an Eligible Customer must have necessary control technologies and/or protection \nsystems, which may include a special protection scheme, to limit its energy withdrawals \nto its approved level.227 \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 \nstudy new load and new generation together, when physically or electrically proximate, \npresents system benefits and can help address the challenges posed by large load \n \n225 See supra P 103; see also PJM Co-Location Order, 193 FERC ¶ 61,217 \nat PP 201 (finding that the interim, non-firm transmission service will facilitate the \n“timely” provision of transmission service and that “[t]his willingness to curtail would \npotentially allow them to obtain service more quickly”), 205 (recognizing that parties \nargue that co-located loads may be able to receive transmission service faster with use \nof a new, limited transmission service product than they would if they selected NITS, to \nthe extent that providing NITS would require Network Upgrades that the limited \ntransmission service would not). \n226 See, e.g., OMS November 21 ANOPR Comments at 13 (“[E]nabling load \nflexibility is critical to accelerating the interconnection of large loads while maintaining a \nreliable and affordable grid for existing customers.”). \n227 PJM Co-Location Rehearing Order, 195 FERC ¶ 61,209 at P 480."},{"page":63,"startToken":25386,"endToken":25739,"text":"Docket No. EL26-70-000 \n- 63 - \nadditions.228 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.229 As a result, this can speed up the interconnection process for both large loads \nand generation, and shorten energization timelines,230 which commenters contend reduces \nuncertainty for both parties231 and “is necessary to match the pace of AI innovation in the \nUnited States.”232 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.233 Other benefits \nto a joint study identified by commenters include improving load forecasting and siting \ndecisions234 and reducing the need for critical supply chain components.235 \n \n228 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 21 \nANOPR Comments at 1. \n229 AEU November 21 ANOPR Comments at 13; ClearPath November 21 \nANOPR Comments at 4; DCC November 21 ANOPR Comments at 5; DTE November 21 \nANOPR Comments at 8-11; ENGIE November 21 ANOPR Comments at 6; Entergy \nNovember 21 ANOPR Comments at 5; Geronimo November 21 ANOPR Comments \nat 17-18; Information Technology Industry Council November 21 ANOPR Comments \nat 2. \n230 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. \n231 ClearPath November 21 ANOPR Comments at 4; CEBA November 21 \nANOPR Comments at 8. \n232 Microsoft November 21 ANOPR Comments at 8-9. \n233 CEBA November 21 ANOPR Comments at 8. \n234 ELCON November 21 ANOPR Comments at 5; Maryland Commission \nNovember 21 ANOPR Comments at 6-7. \n235 AEU November 21 ANOPR Comments at 13."},{"page":64,"startToken":25739,"endToken":26079,"text":"Docket No. EL26-70-000 \n- 64 - \n Commenters contend that current generator interconnection study processes \nmay not 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.236 For example, Eolian states that in its experience \ndeveloping a project in PJM, the failure of the generator interconnection study process to \nreflect reasonably expected load conditions on the grid models triggered overly costly \nNetwork Upgrades and caused the cancellation of generation project that could have \nreliably served adjacent load growth.237 \n Commenters in the ANOPR proceeding argue that the current state of the generator \ninterconnection queue is not meeting the expeditious time frame needed to match the pace \nof large load additions and ensure the safe and reliable interconnection of these loads.238 \nFor example, Oracle states that one of the most significant and widespread delays it \nencounters when siting data centers in the U.S. is access to sufficient energy.239 Similarly, \nHelion contends that more than half of U.S. developers now identify interconnection \ndelays as the single biggest barrier to adding new generation capacity.240 Commenters \ncontend that if large load interconnection proceeds more quickly than new generation can \ncome online, the result could be price increases for consumers.241 \n \n \n \n236 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. \n237 Eolian May 19 ANOPR Comments at 10. \n238 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. \n239 Oracle November 21 ANOPR Comments at 1. \n240 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)). \n241 AEP December 5 ANOPR Comments at 1-2; OPSI November 21 ANOPR \nComments at 6-7, 11."},{"page":65,"startToken":26079,"endToken":26478,"text":"Docket No. EL26-70-000 \n- 65 - \n A number of commenters support expedited interconnection studies for new \ngeneration paired with load.242 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.243 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.244 Other commenters \nsuggest reforms to expedite studies for new generation paired with large loads at existing \npoints of interconnection that have already been studied, arguing it is unjust and \nunreasonable not to fully utilize existing infrastructure and proven reliability paths while \nnew load waits for service.245 \n1. \nJurisdiction \n The Commission’s statutory authority includes jurisdiction over the wholesale \nsale and transmission of electricity in interstate commerce, including the facilities used \nfor such sale and transmission.246 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.247 In the PJM Co-Location Order, the Commission observed that a generator’s \n \n242 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. \n243 AEP December 5 ANOPR Comments at 12; AEU November 21 ANOPR \nComments at 13; Google December 5 ANOPR Comments at 15; see also \nDuke November 21 ANOPR Comments at 21-22. \n244 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. \n245 Constellation June 5 ANOPR Comments at 8-9. \n246 16 U.S.C. § 824(b)(1). \n247 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"},{"page":66,"startToken":26478,"endToken":26824,"text":"Docket No. EL26-70-000 \n- 66 - \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.”248 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.249 Nothing about our preliminary finding here, \nhowever, intrudes or is intended to intrude on that exclusive authority. Rather, we \npreliminarily find that it is necessary and appropriate to exercise our exclusive \njurisdiction over generator interconnection to ensure the availability of generator \ninterconnection processes specifically tailored to the unique operational characteristics of \ngenerating facilities dedicated to serving electrically proximate large loads and co-located \nloads, as defined below. The Commission has exercised this jurisdiction previously in \nrequiring generator interconnection services that allow certain generating facilities to \ninterconnect more quickly through the use of provisional interconnection service and \nsurplus interconnection service,250 and has approved interconnection processes that allow \ncertain generating facilities to interconnect more quickly by replacing a retiring existing \ngenerating facility.251 \n \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.”). \n248 PJM Co-Location Order, 193 FERC ¶ 61,217 at P 171. \n249 See, e.g., Citizens Action Coal. of Ind., Inc. v. FERC, 125 F.4th at 238 \n(citing 16 U.S.C. § 824(b)(1)). \n250 Reform of Generator Interconnection Procs. & Agreements, Order No. 845, \n163 FERC ¶ 61,043, at PP 438, 467 (2018), order on reh’g & clarification, Order \nNo. 845-A, 166 FERC ¶ 61,137, order on reh’g & clarification, Order No. 845-B, \n168 FERC ¶ 61,092 (2019); Order No. 2023, 184 FERC ¶ 61,054 at P 1436; \nPJM Interconnection, L.L.C., 190 FERC ¶ 61,083 (2025). \n251 See, e.g., PJM Interconnection, L.L.C., 194 FERC ¶ 61,079 (2026); \nMidcontinent Indep. Sys. Operator Inc., 167 FERC ¶ 61,146 (2019)."},{"page":67,"startToken":26824,"endToken":27249,"text":"Docket No. EL26-70-000 \n- 67 - \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,252 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 \nMISO’s transmission system. \n3. \nTariff Provisions \n We preliminarily find that MISO’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 \nthis order,253 that has a high peak load (i.e., large co-located loads that are 50 MW or \ngreater).254 Specifically, we preliminarily find that MISO’s Tariff appears to be unjust \nand unreasonable because it lacks a generator interconnection study process and/or \ngenerator interconnection service to reflect an interconnection customer’s commitment in \nan interconnection agreement to limit the generating facility’s output to minimize the \nimpact on the transmission system while serving an electrically proximate large load \nor large co-located load. We are concerned that MISO’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 \nto limit 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,255 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 \n \n252 See supra P 58. \n253 See supra P 89. \n254 We note that generator interconnection service in and of itself does not convey \ntransmission service. \n255 See PJM Co-Location Rehearing Order, 195 FERC ¶ 61,209 at P 480."},{"page":68,"startToken":27249,"endToken":27709,"text":"Docket No. EL26-70-000 \n- 68 - \ntransmission system of interconnecting the generating facility to serve that electrically \nproximate large load or large co-located load may be limited,256 thereby potentially \nreducing the need for Network Upgrades, which can accelerate the generator \ninterconnection process.257 In the absence of Tariff provisions accounting for these \noperational dynamics when an interconnection customer’s generating facility is serving \nelectrically proximate large loads or large co-located loads, new shovel-ready generating \nfacilities may face unnecessary delays in reaching commercial operation under current \ngenerator interconnection processes and will be unable to serve the immediate demand of \nnew large loads or large co-located loads.258 \n As commenters in the ANOPR proceeding have recognized, the status quo may \nresult in inefficient and unnecessary development of infrastructure, which leads to \n \n256 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. \n257 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.”). \n258 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 21 \nANOPR Comments at 6 (asserting that a clear framework to study large loads paired with \ngeneration 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”); Longroad \nNovember 21 ANOPR Comments at 8."},{"page":69,"startToken":27709,"endToken":28137,"text":"Docket No. EL26-70-000 \n- 69 - \nunnecessarily higher network upgrade costs that may result in unjust and unreasonable \nrates.259 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.260 The same result may occur in the absence of \nnew generator 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.261 \n SPP recognized this problem and submitted an FPA section 205 filing to \nimplement a new, interim, generator interconnection service and related generator \ninterconnection process, HILLGA, to facilitate the prompt interconnection of generating \nfacilities that are specifically identified for and limited to serving a HILL, which the \nCommission accepted.262 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 \nthe same local area.”263 We do not expect or propose that MISO adopt an identical \nprocess to SPP’s HILLGA process, nor do we preliminarily find that the absence of \nTariff provisions specifically mirroring SPP’s Tariff renders MISO’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 \n \n259 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. \n260 PJM Co-Location Order, 193 FERC ¶ 61,217 at P 177 (“[F]or Eligible Customers \ntaking service on behalf of Co-Located Loads that do not reserve transmission . . . requiring \nsuch Eligible Customers to take NITS on behalf of these Co-Located Loads may in some \ncircumstances result in costly and inefficient transmission system buildout that may not be \nnecessary if such Eligible Customers are willing and able to take a transmission service \nthat requires fewer Network Upgrades to provide, and therefore may result in lower \nNetwork Upgrade costs, than would NITS.”). \n261 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). \n262 SPP HILL Order, 194 FERC ¶ 61,031. \n263 Id. P 64."},{"page":70,"startToken":28137,"endToken":28583,"text":"Docket No. EL26-70-000 \n- 70 - \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 \nlarge load or large co-located load.264 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 \nprotection scheme, that ensure that the net injection does not exceed the amount in the \nexisting generator interconnection agreement.265 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.266 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 \n \n264 While, as discussed above, we view such a process that permits generation \nto serve electrically proximate loads no more than two substations away from the \ngenerators to be reasonable, we understand the unique features of MISO’s transmission \nsystem may warrant consideration of a more limited definition of electrically proximate. \nSee Duke 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. \n265 See Constellation June 5 ANOPR Comments at 1-2, 10-13. \n266 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”)."},{"page":71,"startToken":28583,"endToken":29047,"text":"Docket No. EL26-70-000 \n- 71 - \nprotection systems, which may include a special protection scheme, to ensure that there is \nno injection to the transmission system.267 It may be reasonable for such a load-limited \ngenerator interconnection service to be or not to be of an interim nature. We invite MISO \nand/or Transmission Owners, in responding to this order or in an FPA section 205 filing, \nto submit original proposals designed to address the concerns expressed herein and \ntailored to their unique circumstances. \n 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 MISO’s current \ngenerator interconnection process failing to keep pace with the new large loads seeking \nto be integrated onto MISO’s transmission system.268 We preliminarily find that this \noutcome may be unjust and unreasonable because reliance on MISO’s current generator \ninterconnection processes for generating facilities serving electrically proximate large \nloads or large co-located loads could result in unnecessary interconnection delays, \nunnecessary Network Upgrades, and an otherwise inefficient expansion of the \ntransmission system, imposing unnecessary delays and costs on transmission customers. \n MISO should explain whether the Tariff remains just and reasonable without, \nfor example, provisions that establish: (1) a new generator interconnection study process \nand new interim generator interconnection service that reflect an interconnection \ncustomer’s commitment, in a generator interconnection agreement, to limit a generating \nfacility’s output to match the hourly forecast of an electrically proximate large load or \nlarge co-located load; or (2) a generator interconnection study process that allows the \nuse of the existing ERIS or NRIS of an existing generator to connect a new generating \nfacility and a new large load behind the same point of interconnection of the existing \ngenerator with necessary control technologies and/or protection systems, which may \ninclude a special protection scheme, that ensures that the net injection does not exceed \nthe amount in the existing generator interconnection agreement; or (3) a new generator \ninterconnection service that allows a new generating facility and new large co-located \nload seeking to interconnect behind the same new point of interconnection with necessary \n \n267 See MISO November 21 ANOPR Comments at 13; see also MISO TOs April 3 \nANOPR Comments at 13-14. \n268 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":72,"startToken":29047,"endToken":29446,"text":"Docket No. EL26-70-000 \n- 72 - \ncontrol technologies and/or protection systems, which may include a special protection \nscheme, to ensure that there is no injection to the transmission system. We note that, \nwith respect to numbers (2) or (3), these approaches could be either interim or permanent. \nThese approaches may not be mutually exclusive. \n Given that generator interconnection service in and of itself does not convey \ntransmission service, we encourage MISO to consider, in responding to these concerns, \nwhat type of transmission service an Eligible Customer will need to take on behalf of \nthe electrically proximate large load or large co-located load.269 We note that, in the \nPJM Co-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.270 \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. \nAs discussed above and highlighted in the ANOPR, the growth of demand, and the speed \nof such 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.271 Indeed, the relative speed \nand concentration at which large loads are seeking to interconnect appears to be \noutpacing the addition of new generation, which in turn heightens reliability risks and \ndrives up costs to ratepayers.272 We are concerned that MISO and load serving entities \nare unable to plan adequate generation to serve all load at the pace such load seeks to \nconnect. \n \n269 See SPP HILL Order, 194 FERC ¶ 61,031 at P 34. \n270 PJM Co-Location Order, 193 FERC ¶ 61,217 at P 206. \n271 See, e.g., Entergy November 21 ANOPR Comments at 29-30; Eolian \nNovember 21 ANOPR Comments at 16-17; Industrial Customers November 21 ANOPR \nComments at 24-26; R Street November 21 ANOPR Comments at 1; South Dakota \nCommission November 13 ANOPR Comments at 5; Talen December 5 ANOPR Reply \nComments at 7. \n272 See, e.g., Eolian November 21 ANOPR Comments at 16-17; David Gardiner & \nAssociates November 21 ANOPR Comments at 1-2; Joint Consumer Advocates \nDecember 5 ANOPR Comments at 2; PSEG November 21 ANOPR Comments at 8; \nSouthern California Edison December 5 ANOPR Comments at 3."},{"page":73,"startToken":29446,"endToken":29890,"text":"Docket No. EL26-70-000 \n- 73 - \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, \nMISO’s Expedited Resource Addition Study process and Joint Targeted Interconnection \nQueue with SPP have provided pathways for more efficient interconnection for \ngeneration.273 While we are encouraged by the implementation of such processes to \nensure resource adequacy and faster interconnection, we remain concerned that these \nefforts may fall short in light of generator retirements and tightening supply conditions. \n Accordingly, we direct MISO to submit in Docket No. EL26-70-000, within \n30 days of the date of issuance of this order, a detailed informational report on any \nproposals under consideration in its stakeholder process to address the issue of resource \nadequacy to serve new large loads. We also strongly encourage new proposals to the \nextent necessary to address these concerns. The informational report must include a \ndetailed schedule of key milestones, such as stakeholder or MISO Board votes, that \nincludes the estimated date on which MISO expects to file any such proposals with the \nCommission. Additionally, as part of this informational report, we direct MISO to \nidentify any ongoing stakeholder processes that aim to increase the pace of adding \ngenerating capacity in the MISO region. The informational report must include a detailed \nschedule of such initiatives, including timing of the stakeholder process and dates of any \nanticipated 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 \nbe at varying stages of that process. We appreciate that different large loads are \ncurrently at different stages of that process. We also understand that large loads and \nEligible Customers taking transmission service on behalf of large loads are negotiating, \nentering into, 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 MISO and the Transmission Owners, in responding to the order to \nshow cause, should protect existing commercial arrangements including: (1) what would \nbe a reasonable implementation period to ensure minimal disruption to such existing \ncommercial arrangements, and (2) how to allow a reasonable amount of time to finalize \nongoing agreements that are nearing completion as of the date such Tariff provisions are \nfiled with the Commission. \n Today’s order proposes, as part of a potential replacement rate, to establish new \ntransmission services that recognize flexible large loads’ ability and willingness to limit \n \n273 MISO November 21 ANOPR Comments at 6-7."},{"page":74,"startToken":29890,"endToken":30350,"text":"Docket No. EL26-70-000 \n- 74 - \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 MISO’s \nTariff and/or processes. Specifically, what, if any, potential impacts on regional and \nlocal transmission planning would arise from the introduction of the new transmission \nservices discussed herein? For example, when planning for load growth, how would \ntransmission providers and planners account for flexible large loads’ potential preference \nto take the new transmission services, including potential uncertainties around the type, \nlocation, and quantity of such expected loads? \n Today’s order preliminarily finds that MISO’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 \nbetween the transmission owner/provider and an Eligible Customer to prevent unjust \nand unreasonable cost shifts among transmission customers related to Network Upgrade \ncosts required 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 MISO’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 MISO to explain whether the \nTariff remains just and reasonable without provisions that (1) require the evaluation of \nalternative transmission technologies in transmission service request studies, using \nmodels that are capable of evaluating the transmission system to accurately account \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 \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 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 MISO’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"},{"page":75,"startToken":30350,"endToken":30779,"text":"Docket No. EL26-70-000 \n- 75 - \nloads. Any filings or tariff changes submitted in response to this order should address the \nfollowing questions: \na. To what extent would MISO allow an interconnection customer’s \ngenerating facility serving electrically proximate large load or large \nco-located load to participate in MISO’s energy and ancillary services \nmarket, and if MISO were to allow them to participate, what restrictions \nor mitigation would MISO apply? \nb. To the extent that MISO plans for the electrically proximate large load \nor large co-located load associated with an interconnection customer’s \ngenerating facility for resource adequacy purposes, would MISO account \nfor the generating facilities serving electrically proximate large load or \nlarge co-located load in the resource adequacy construct? If applicable, \nwould MISO allow the generating facilities serving electrically proximate \nlarge load or large co-located load to participate in MISO’s capacity \nmarket? If so, would MISO accredit these generating facilities using the \nsame method as other MISO 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. EL26-70-000 as discussed in the body of this order. \n(B) \nMISO and the Transmission Owners are hereby directed, within 60 days \nof the date of the order, either: (1) to show cause as to why the Tariff remains just and \nreasonable and not unduly discriminatory or preferential; or (2) to explain what changes \nto the Tariff they believe would remedy the identified concerns if the Commission were \nto determine that the Tariff has in fact become unjust and unreasonable or unduly \ndiscriminatory or preferential and, therefore, proceeds to establish a replacement Tariff. \n(C) \nMISO 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. EL26-70-000 \nmust file a notice of intervention or motion to intervene, as appropriate, with the \nFederal Energy Regulatory Commission, 888 First Street, NE, Washington, DC 20426, \nin accordance with Rule 214 of the Commission’s Rules of Practice and Procedure, \n18 C.F.R. § 385.214 (2025), within 21 days of the date of issuance of this order. The \nCommission encourages electronic submission of interventions in lieu of paper using the"},{"page":76,"startToken":30779,"endToken":31007,"text":"Docket No. EL26-70-000 \n- 76 - \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 MISO’s and the \nTransmission Owners’ filing, addressing either or both of: (1) whether the Tariff remains \njust and reasonable and not unduly discriminatory or preferential; and (2) if not, what \nchanges to the Tariff should be implemented as a replacement rate. \n(F) \nThe Secretary shall promptly publish in the Federal Register a notice of \nthe Commission’s initiation of the proceeding under section 206 of the FPA in Docket \nNo. EL26-70-000. \n(G) \nThe refund effective date in Docket No. EL26-70-000 pursuant to \nsection 206 of the FPA shall be the date of publication in the Federal Register of the \nnotice discussed in Ordering Paragraph (F) above. \n \nBy the Commission. Chairman Swett is concurring with a separate statement attached. \nCommissioner Rosner is concurring with a separate statement \nattached. \nCommissioner See is concurring with a separate statement attached. \nCommissioner Chang is concurring with a separate statement \nattached. \nCommissioner LaCerte is concurring with a separate statement \nattached. \n \n( S E A L ) \n \n \n \n \n \n \n \n \n \n \n \nCarlos D. Clay, \nDeputy Secretary."},{"page":77,"startToken":31007,"endToken":31242,"text":"Docket No. EL26-70-000 \n- 77 - \nAppendix - Commenters in Docket No. RM26-4-000 \n \nAdvanced Energy Management Alliance (AEMA) \nAdvanced Energy United (AEU) \nAdvancing Modern Powerlines Coalition (together with Working for Advanced \nTransmission Technologies Coalition, WATT and Advancing Modern Powerlines) \nAdvocates for Consumer Regulated Electricity \nAES Corporation (AES) \nAI Supply Chain Alliance \nAlexandre Figueras, on behalf of Monza Tech \nAlliance for Tribal Clean Energy \nAlliant Energy Corporate Services, Inc. (Alliant) \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 Corporation274 \nAmerican Public Gas Association \nAmerican Public Power Association (APPA) \nAmerican Terawatt, Inc. (American Terawatt) \nAmerican Transmission Company LLC (ATC)275 \nAmericans for a Clean Energy Grid \nAntora Energy, Inc. \nArevia Power \nArizona Public Service Company \nArkansas Public Service Commission (Arkansas Commission) \nAttorney General of the State of Oklahoma \n \n274 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. \n275 ATC submitted comments on behalf of itself and its corporate manager ATC \nManagement Inc."},{"page":78,"startToken":31242,"endToken":31442,"text":"Docket No. EL26-70-000 \n- 78 - \nBase Power Company, Inc. (Base Power) \nBloom Energy Corporation \nBuckeye Power, Inc. (Buckeye) \nCalibrant Energy Holdings, LLC (Calibrant) \nCalifornia Department of Water Resources State Water Project (California DWR) \nCalifornia Independent System Operator Corporation \nCalifornia Public Utilities Commission (CPUC) \nCenter for Biological Diversity \nChevron U.S.A., Inc. \nClean Energy Buyers Association (CEBA) \nClearPath, Inc. (ClearPath) \nConfederated Tribes and Bands of the Yakama Nation \nConstellation Energy Generation, LLC (Constellation) \nConsumer Energy Alliance \nConsumers Energy Company \nCritical Loop, Inc. (Critical Loop) \nCrusoe Energy Systems, Inc. (Crusoe) \nCTC Global Corporation \nData Center Coalition (DCC) \nDavid Gardiner & Associates \nDelaware Division of the Public Advocate (together with Pennsylvania Office of \nConsumer Advocate, Joint Consumer Advocates)276 \nDigital Energy Council \nDigital Power Network \nDistributed Capacity Parties277 \nDr. Elisa Nelson \nDTE Electric Company (DTE) \nDuke Energy Corporation (Duke) \nEDF Power Solutions, Inc. (EDF Power) \nEdison Electric Institute (EEI) \nElectricity Consumers Resource Council (ELCON) \nElectricity Customers Alliance (ECA) \nElectric Power Supply Association (EPSA) \nEmerald AI (Emerald) \nEnchanted Rock, LLC \nEnergy New England, LLC \n \n276 The Illinois Attorney General joined the Joint Consumer Advocates in filing \nreply comments. \n277 Distributed Capacity Parties include: Clovereleaf Infrastructure; Spark \nCommunity Investment d/b/a Sparkfund; and Voltus, Inc."},{"page":79,"startToken":31442,"endToken":31669,"text":"Docket No. EL26-70-000 \n- 79 - \nEnergy Trading Institute \nENGIE North America, Inc. (ENGIE) \nEntergy Services, LLC (Entergy)278 \nEnvironmental Law & Policy Center \nEolian L.P. (Eolian) \nEquinix, Inc. \nesVolta, LP \nETX Upstream, LLC \nEversource Energy279 \nExelon Corporation (Exelon)280 \nFervo Energy Company (Fervo) \nFirstEnergy Service Company281 \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 \n278 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. \n279 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. \n280 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. \n281 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":80,"startToken":31669,"endToken":31980,"text":"Docket No. EL26-70-000 \n- 80 - \nHelion Energy (Helion) \nHerbert Schrayschuen \nHeron Power Electronics Company \nIndiana Energy Association \nIndicated PJM Transmission Owners282 \nIndustrial Customer Organizations (Industrial Customers)283 \nInformation Technology Industry Council \nInfrastructure Masons, Inc. (Infrastructure Masons) \nInstitute for Progress \nInternational Energy Credit Association \nInvenergy284 \n \n282 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. \n283 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 \n284 Invenergy includes: Invenergy Wind Development North America LLC, \nInvenergy Solar Development North America LLC, and Invenergy Thermal Development \nHoldings LLC."},{"page":81,"startToken":31980,"endToken":32259,"text":"Docket No. EL26-70-000 \n- 81 - \nIron Mountain Data Centers, LLC \nISO New England, Inc. \nITC Holdings Corp. (ITC) \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 Parties285 \nLong Island Power Authority \nLongroad Energy Holdings, LLC (Longroad) \nLouisiana Public Service Commission (together with the Mississippi Public Service \nCommission, Louisiana and Mississippi Commissions) \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. (MISO) \nMISO Transmission Owners (MISO TOs)286 \n \n285 Load Flexibility Parties include: Enerwise Global Technologies, LLC d/b/a \nCPower, Enel North America, Inc., and Voltus, Inc. \n286 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":82,"startToken":32259,"endToken":32568,"text":"Docket No. EL26-70-000 \n- 82 - \nMissouri Public Service Commission (Missouri 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)287 \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 Systems288 \nNew England Public Systems289 \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 \n287 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. \n288 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. \n289 New England Public Systems include: Connecticut Municipal Electric \nCooperative, Massachusetts Municipal Wholesale Electric Company, and Vermont"},{"page":83,"startToken":32568,"endToken":32803,"text":"Docket No. EL26-70-000 \n- 83 - \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 Owners290 \nNorth American Electric Reliability Corporation \nNorth Carolina Utilities Commission \nNorth Carolina Utilities Commission Public Staff \nNorth Dakota Public Service Commission (North Dakota Commission) \nNortheastern Rural Electric Membership Corporation \nNRG Energy, Inc. \nOffice of the Illinois Attorney General (Illinois AG) \nOffice of the Ohio Consumers’ Counsel (OCC) \nOklahoma Corporation Commission \nOklo Inc. (Oklo) \nOld Dominion Electric Cooperative (ODEC) \nOncor Electric Delivery Company LLC \nON Energy Storage, Inc. \nOpenAI Inc. \nOracle America, Inc. (Oracle) \nOrganization of MISO States, Inc. (OMS) \nOrganization of PJM States, Inc. (OPSI) \nPaces AI Inc. \nPacific Gas & Electric Company \nPaige Lambermont, on behalf of Competitive Enterprise Institute \nPaul Statchen \nPennsylvania Office of Consumer Advocate \nPennsylvania Public Utility Commission \nPew Charitable Trusts Energy Modernization Project \nPJM Interconnection, LLC \nPower for Tomorrow \nPPL Corporation291 \n \nPublic Power Supply Authority. \n290 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. \n291 PPL Corporation submitted comments on behalf of the PPL Companies, which"},{"page":84,"startToken":32803,"endToken":33042,"text":"Docket No. EL26-70-000 \n- 84 - \nPrime Mover Institute \nPSEG Companies (PSEG)292 \nPublic Citizen, Inc. \nPublic Interest Organizations (PIOs)293 \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)294 \nSouthern California Edison Company (Southern California Edison) \nSouthern Companies295 \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. \n292 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. \n293 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. \n294 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. \n295 Southern Companies include: Georgia Power Company, Alabama Power \nCompany, and Mississippi Power Company."},{"page":85,"startToken":33042,"endToken":33317,"text":"Docket No. EL26-70-000 \n- 85 - \nSouthwest Power Pool Transmission Owner Group296 \nSplight Inc. (Splight) \nState Entities297 \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 \nMembers298 \nU.S. Representatives299 \nU.S. Senate Committee on Energy and Natural Resources \nU.S. Senators300 \n \n296 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. \n297 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. \n298 Submitted by Frank Pallone, Jr. (Ranking Member) and Kathy Castor (Ranking \nMember, Subcommittee on Energy). \n299 The U.S. Representatives that submitted comments include: Suhas \nSubramanyam, John W. Mannion, Mike Quigley, and Donald S. Beyer Jr. \n300 The U.S. Senators that submitted comments include: Edward J. Markey, Chris \nVan Hollen, Elizabeth Warren, Peter Welch, Raphael Warnock, Richard Blumenthal, and \nAdam B. Schiff."},{"page":86,"startToken":33317,"endToken":33364,"text":"Docket No. EL26-70-000 \n- 86 - \nU.S. Senator Jon Ossoff \nUnion of Concerned Scientists (UCS) \nVantage Data Centers (Vantage) \nVerrus \nVirginia State Corporation Commission \nVistra Corp. (Vistra) \nWashington Utilities and Transportation Commission \nWIRES \nWisconsin Electric Company (together with Wisconsin Public Service Corporation, \nWisconsin Electric) \nWisconsin Public Service Corporation"},{"page":87,"startToken":33364,"endToken":33638,"text":"UNITED STATES OF AMERICA \nFEDERAL ENERGY REGULATORY COMMISSION \n \nMidcontinent Independent System Operator, Inc, AEP \nIndiana Michigan Transmission Company, Inc., \nALLETE, Inc., Ameren Illinois Company, Ameren \nTransmission Company of Illinois, American \nTransmission Company, LLC, Cleco Power LLC, Duke \nEnergy Indiana, LLC, Entergy Arkansas, LLC, Entergy \nLouisiana, LLC, Entergy Mississippi, LLC, Entergy \nNew Orleans, LLC, Entergy Texas, Inc., GridLiance \nHeartland LLC, Indianapolis Power & Light Company, \nInternational Transmission Company, ITC Midwest \nLLC, Michigan Electric Transmission Company, LLC, \nMidAmerican Energy Company, Montana-Dakota \nUtilities Company, Northern Indiana Public Service \nCompany LLC, Northern States Power Company, a \nMinnesota Corporation, Northern States Power \nCompany, a Wisconsin Corporation, Northwestern \nWisconsin Electric Company, Otter Tail Power \nCompany, Pioneer Transmission, LLC, Republic \nTransmission, LLC, Southern Indiana Gas & Electric \nCompany, Union Electric Company, Wabash Valley \nPower Association, Inc., and Wolverine Power Supply \nCooperative, Inc. \nDocket No. EL26-70-000 \n \n(Issued June 18, 2026) \n \nSWETT, Chairman, concurring: \n \n \nToday, we take historic action to push our country’s electric markets and economy \ninto the future—a future of fair cost allocation, unprecedented transparency for the \nAmerican ratepayer, respect for states’ rights, efficient markets and speed to power. Last \nOctober, Secretary Wright articulated the monumental, generational and “urgent” \nchallenge FERC must solve for our country when he directed us to develop “reforms to \nensure the timely and orderly interconnection of large loads to the transmission system.”1 \nI strongly agree. And now, through this suite of six orders, we deliver. \n \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)."},{"page":88,"startToken":33638,"endToken":34097,"text":"Docket No. EL26-70-000 \n \n- - 2 - - \n \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 \nFirst, the record the Commission collected in response to the challenges identified \nin the ANOPR and subsequent resulting developments indicate that an approach that \nhonors the ANOPR principles but accounts for widening regional variation may now be \nmore efficient than a one-size-fits-all rule.6 The world has changed a great deal since last \n \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 \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"},{"page":89,"startToken":34097,"endToken":34521,"text":"Docket No. EL26-70-000 \n \n- - 3 - - \n \nOctober. The ANOPR itself, including the articulated principles, appears to have shifted \nthe playing field and prompted great progress across several electric markets. This \nchange (and the Commission’s alignment with the Secretary) is well illustrated by a \nnumber of landmark orders approving several market new constructs that we issued since \nOctober, which together operationalize the Secretary’s principles and laid groundwork \nfor meaningful reform and today’s actions.7 While working to develop those orders, the \nCommission has simultaneously devoted significant attention to evaluating the various \nprocedural paths through which we might comprehensively deliver. \n \nIndividual show cause proceedings will allow the Commission to ensure that \nsolutions to the problems the Secretary identified are tailored to the specific, varied \ncircumstances and market constructs of each region. Indeed, a careful review of today’s \nsix orders reveals the many ways in which those orders are customized for each market’s \nunique circumstances and progress (or lack thereof) towards serving large load. To name \njust a few examples, the orders recognize ongoing stakeholder processes in various \nregions and are adapted to existing tariff provisions concerning large and co-located \nloads; account for regional variances in allocating rights and responsibilities among \nRTOs/ISOs and the transmission owners; leave room for each market to tailor operational \nrequirements for large loads that are particular to their region; and otherwise account for \nincumbent regional differences on topics such as cost allocation and cost transparency, \nstudy processes, and network upgrade procedures. \n \nProceeding via show cause proceedings will also allow the markets (and their \nrespective transmission owners) to explain, in the first instance, how to address the \nCommission’s concerns. These entities have the deepest understanding of their \nrespective regions and are best positioned to implement solutions we identified, in the \nmost expeditious manner. The Commission will promptly evaluate their responses to \ntoday’s orders, and, with input from stakeholders, swiftly establish appropriate reforms. \n \nSecond, proceeding via individual show cause orders will allow the Commission \nto act more quickly than through traditional rulemaking. Notice-and-comment \nrulemaking may not capitalize upon individual market progress prompted since October \n \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":90,"startToken":34521,"endToken":34997,"text":"Docket No. EL26-70-000 \n \n- - 4 - - \n \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 \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 \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 \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":91,"startToken":34997,"endToken":35181,"text":"Docket No. EL26-70-000 \n \n- - 5 - - \n \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"},{"page":92,"startToken":35181,"endToken":35467,"text":"UNITED STATES OF AMERICA \nFEDERAL ENERGY REGULATORY COMMISSION \n \nMidcontinent Independent System Operator, Inc, AEP \nIndiana Michigan Transmission Company, Inc., \nALLETE, Inc., Ameren Illinois Company, Ameren \nTransmission Company of Illinois, American \nTransmission Company, LLC, Cleco Power LLC, Duke \nEnergy Indiana, LLC, Entergy Arkansas, LLC, Entergy \nLouisiana, LLC, Entergy Mississippi, LLC, Entergy \nNew Orleans, LLC, Entergy Texas, Inc., GridLiance \nHeartland LLC, Indianapolis Power & Light Company, \nInternational Transmission Company, ITC Midwest \nLLC, Michigan Electric Transmission Company, LLC, \nMidAmerican Energy Company, Montana-Dakota \nUtilities Company, Northern Indiana Public Service \nCompany LLC, Northern States Power Company, a \nMinnesota Corporation, Northern States Power \nCompany, a Wisconsin Corporation, Northwestern \nWisconsin Electric Company, Otter Tail Power \nCompany, Pioneer Transmission, LLC, Republic \nTransmission, LLC, Southern Indiana Gas & Electric \nCompany, Union Electric Company, Wabash Valley \nPower Association, Inc., and Wolverine Power Supply \nCooperative, Inc. \nDocket No. EL26-70-000 \n \n(Issued June 18, 2026) \n \n \nROSNER, Commissioner, concurring: \n \n \nThe electric industry is in the midst of changes not seen in a generation. \nCompared to more traditional load growth, the large loads seeking to connect to the grid \ntoday are larger, sometimes by orders of magnitude, and more concentrated. They also \nexhibit different operational characteristics, such as the ability to quickly change their \nenergy consumption, sometimes in seconds. Often, these large loads seek to connect to \nthe grid as quickly as possible. And because of these dynamics, large loads are rapidly \ndriving the need for new transmission infrastructure and energy supply. This creates new \nchallenges that, if unaddressed, could jeopardize the reliability and affordability of the \ngrid on which we all depend. \n \nToday, we are taking an important step toward addressing these challenges. We \nare opening a dialogue with each of the six RTO/ISOs on a series of reforms that are"},{"page":93,"startToken":35467,"endToken":35939,"text":"Docket No. EL26-70-000 \n- 2 - \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 \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 \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":94,"startToken":35939,"endToken":36353,"text":"Docket No. EL26-70-000 \n- 3 - \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 \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” \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":95,"startToken":36353,"endToken":36789,"text":"Docket No. EL26-70-000 \n- 4 - \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 \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 \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":96,"startToken":36789,"endToken":37266,"text":"Docket No. EL26-70-000 \n- 5 - \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 \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 \n \n7 See Sw. Power Pool, Inc., 194 FERC ¶ 61,031 (2026)."},{"page":97,"startToken":37266,"endToken":37334,"text":"Docket No. EL26-70-000 \n- 6 - \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":98,"startToken":37334,"endToken":37336,"text":"Figure 1"},{"page":99,"startToken":37336,"endToken":37338,"text":"Figure 2"},{"page":100,"startToken":37338,"endToken":37629,"text":"UNITED STATES OF AMERICA \nFEDERAL ENERGY REGULATORY COMMISSION \n \nMidcontinent Independent System Operator, Inc, AEP \nIndiana Michigan Transmission Company, Inc., \nALLETE, Inc., Ameren Illinois Company, Ameren \nTransmission Company of Illinois, American \nTransmission Company, LLC, Cleco Power LLC, Duke \nEnergy Indiana, LLC, Entergy Arkansas, LLC, Entergy \nLouisiana, LLC, Entergy Mississippi, LLC, Entergy \nNew Orleans, LLC, Entergy Texas, Inc., GridLiance \nHeartland LLC, Indianapolis Power & Light Company, \nInternational Transmission Company, ITC Midwest \nLLC, Michigan Electric Transmission Company, LLC, \nMidAmerican Energy Company, Montana-Dakota \nUtilities Company, Northern Indiana Public Service \nCompany LLC, Northern States Power Company, a \nMinnesota Corporation, Northern States Power \nCompany, a Wisconsin Corporation, Northwestern \nWisconsin Electric Company, Otter Tail Power \nCompany, Pioneer Transmission, LLC, Republic \nTransmission, LLC, Southern Indiana Gas & Electric \nCompany, Union Electric Company, Wabash Valley \nPower Association, Inc., and Wolverine Power Supply \nCooperative, Inc. \nDocket No. EL26-70-000 \n \n \n(Issued June 18, 2026) \n \nSEE, Commissioner, concurring: \n \n \nGrowing electricity demand underscores America’s economic strength and the \nopportunities that come with it. And with new opportunities come new challenges. The \npace and scale of emerging large loads create new circumstances that require us to adapt \nin how we build and manage the grid. Large and flexible loads can materially change \nsystem operations, for instance, as well as near-term planning needs, upgrade \nrequirements, and how we allocate costs. Most existing systems were not designed to \naccommodate those changes—especially not at the pace needed to support AI growth and \nadvanced manufacturing that are central to America’s economic competitiveness. As a \nresult, uncertainty over the operative rules and delays in interconnecting large loads can \nundermine reliability and investment and add unacceptable and avoidable costs. \n \nToday, the Commission takes strong action within our jurisdictional sweep to \naddress these and other challenges that large load growth poses to the interstate"},{"page":101,"startToken":37629,"endToken":38087,"text":"Docket No. EL26-70-000 \n- 2 - \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 \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 \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":102,"startToken":38087,"endToken":38583,"text":"Docket No. EL26-70-000 \n- 3 - \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 \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."},{"page":103,"startToken":38583,"endToken":38962,"text":"Docket No. EL26-70-000 \n- 4 - \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______________________________ \nLindsay S. See \nCommissioner\n \n3 PJM Interconnection, L.L.C., 195 FERC ¶ 61,209 (2026). \n4 See id. P 456."},{"page":104,"startToken":38962,"endToken":39101,"text":"UNITED STATES OF AMERICA \nFEDERAL ENERGY REGULATORY COMMISSION \n \nMidcontinent Independent System Operator, Inc. \nAEP Indiana Michigan Transmission Company, Inc. \nALLETE, Inc. \nAmeren Illinois Company \nAmeren Transmission Company of Illinois \nAmerican Transmission Company, LLC \nCleco Power LLC \nDuke Energy Indiana, LCC \nEntergy Arkansas, LLC \nEntergy Louisiana, LLC \nEntergy Mississippi, LLC \nEntergy New Orleans, LLC \nEntergy Texas, Inc. \nGridLiance Heartland LLC \nIndianapolis Power & Light Company \nInternational Transmission Company \nITC Midwest LLC \nMichigan Electric Transmission Company, LLC \nMidAmerican Energy Company \nMontana-Dakota Utilities Company \nNorthern Indiana Public Service Company LLC \nNorthern States Power Company, a Minnesota \nCorporation \nNorthern States Power Company, a Wisconsin \nCorporation \nNorthwestern Wisconsin Electric Company \nOtter Tail Power Company \nPioneer Transmission, LLC \nRepublic Transmission, LLC \nSouthern Indiana Gas & Electric Company \nUnion Electric Company \nWabash Valley Power Association, Inc. \nWolverine Power Supply Cooperative, Inc. \nDocket Nos. EL26-70-000 \n \n \n(Issued June 18, 2026)"},{"page":105,"startToken":39101,"endToken":39533,"text":"Docket No. EL26-70-000 \n- 2 - \nCHANG, Commissioner, concurring: \n \n \nIn a series of orders today, the Commission initiates separate proceedings under \nFederal Power Act (FPA) section 206 to explore the impact of the increasing growth of \nlarge loads in Regional Transmission Organization (RTO) and Independent System \nOperator (ISO) regions. The preliminary findings in these orders, and the associated \nproposed reforms to RTO/ISO and transmission owner tariffs, could significantly change \nhow loads procure, use, and pay for transmission service, with ramifications for \nRTO/ISO operations, planning, and markets. I write separately to emphasize the \nimportance of building actionable records in these proceedings, particularly with respect \nto our consideration of customer protection, transmission service, and alternative \ntransmission technology reforms. \nI. \nOverview of Today’s Orders \n \nIn each of today’s orders to show cause, the Commission identifies a series of \nissues raised by the ongoing growth of large loads, directs briefing on whether existing \ntariffs remain just and reasonable in light of those developments, and describes possible \nsolutions to those issues if the Commission ultimately concludes that the relevant tariffs \nare unjust and unreasonable. Each order is directed to a specific RTO/ISO and relevant \ntransmission owners that play a role in interconnecting large loads to the Commission-\njurisdictional transmission system. The Commission does not pursue the broad assertion \nof jurisdictional authority contemplated in the Advanced Notice of Proposed \nRulemaking, which I hope assuages concerns raised by our state colleagues that the \nCommission ought not encroach upon matters properly left to their jurisdiction.1 \n \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 \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":106,"startToken":39533,"endToken":39987,"text":"Docket No. EL26-70-000 \n- 3 - \nAssessment concept, to facilitate a process through which a generator may temporarily \nserve a co-located or electrically proximate load until interconnection and transmission \nservice is available. The Commission also invites each region to submit FPA section 205 \nfilings that can address each issue identified in the orders, thereby resolving the \nCommission’s concerns. \nII. \nThe Commission Needs Good Records to Ensure Reasoned Decision-Making \n \nI first want to emphasize that the Commission needs active participation from \ninterested stakeholders to develop thorough records in each region. The Commission \ncannot make reasoned decisions about whether reforms might be needed without an \naccurate understanding of the existing processes, which differ by region. Because the \nCommission is acting via FPA section 206 rather than generically through a rulemaking, \nthe issues addressed by these orders will be subject to ex parte restrictions across the \nRTOs/ISO regions, including with our state colleagues whose regulation can and will \ndirectly affect the individual transmission owners that need to comply with the orders \nissued today. This will limit the Commission’s ability to engage in informal fact-finding \nand discussions with regional stakeholders, and thus, it is even more essential that the \nrecord in each region fully reflects the views of all interested parties. \n \nSecond, I highlight three issues below that will be especially important to the \nsuccess of this effort, and I hope that interested parties will take particular care in helping \nthe Commission address those issues. Importantly, I recognize that the record established \nin each RTO/ISO region will (and should) differ, which will allow the Commission to \nensure any required changes to an RTO/ISO’s tariff are appropriately tailored to that \nregion’s needs. \nIII. \nThe Commission Needs to Pursue Meaningful Customer Protection \n \nThe FPA is fundamentally a customer protection statute,2 and the Commission has \nan obligation to ensure that the rates that wholesale and transmission customers pay are \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 \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":107,"startToken":39987,"endToken":40411,"text":"Docket No. EL26-70-000 \n- 4 - \nwholesale customers against unjustified cost shifts. I am laser-focused on this issue \nbecause we should not create unjustified costs for consumers in our efforts to connect and \nserve large loads. \n \nIn today’s orders, the Commission launches an inquiry into whether existing \nRTO/ISO tariffs include adequate mechanisms to mitigate the risk of undue cost shifting \namong transmission customers. To address this risk, the Commission preliminarily \nidentifies a two-part solution: (1) that each RTO/ISO post public information about the \namount of new large loads seeking to connect to the RTO’s/ISO’s transmission system, \nany Network Upgrades identified in the local transmission planning process to serve \nthose loads, and the costs of those Network Upgrades; and (2) that each RTO/ISO adopt a \npro forma cost recovery agreement to help ensure that Eligible Customers serving large \nloads bear the risk and are ultimately responsible for costs incurred to provide \ntransmission service. I strongly support this effort to provide additional transparency \nregarding jurisdictional transmission service requests and the costs associated with \nproviding transmission service to the requesting parties, as the Commission cannot \neffectively execute its statutory responsibilities without sufficient understanding of the \ncosts that feed into jurisdictional rates. \n \nExploring how agreements between transmission owners and Eligible Customers \ncan protect wholesale customers against cost shifts is important. However, as I have \npreviously explained, bilateral agreements that simply provide transmission revenue \ncontributions untethered from any assessment of the actual cost of providing transmission \nservice induced by individual large loads may be insufficient to adequately protect other \ncustomers against unjustified cost shifts.3 It is therefore important that the resulting \nregulatory and rate design are not limited to a pre-defined solution set, and that parties \nprovide the Commission with comprehensive records outlining various and innovative \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 \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-"},{"page":108,"startToken":40411,"endToken":40841,"text":"Docket No. EL26-70-000 \n- 5 - \nand a growing body of thoughtful analyses and proposed approaches to provide customer \nprotection for costs driven by large load growth.6 Without prejudging any particular \nproposed solution, the Commission needs a robust record in each docket and each region \nto ensure we establish the right cost shift protections for wholesale customers, including \nbut not limited to the commitments outlined in the Ratepayer Protection Pledge.7 \n \nI support initiating our own review of customer protection approaches, rather than \nsimply relying on voluntary commitments that may fall short of optimal protection, \nbecause the Commission has the opportunity and obligation to get this issue right. I \ntherefore encourage interested parties to assist the Commission in that effort by clearly \nand comprehensively explaining the benefits and tradeoffs of alternative customer \nprotection approaches. How power infrastructure costs will be assigned across Eligible \nCustomers that serve large loads and other customers is at the core of the efforts we \ninitiate today. \nIV. \nThe Commission Needs to Understand the Implications of Extending New \nTransmission Services to Additional Loads and Regions \n \nThe orders also preliminarily find that the Commission should extend the \ntransmission services developed in the PJM co-location proceeding – Interim NITS, Firm \nContract Demand, and Non-Firm Contract Demand – to new types of load and new \nregions. These new transmission services represent a fundamental paradigm shift from \nthe traditional network service and point-to-point transmission service models established \nin Order No. 888 that have been used across the country for the last three decades. While \nthese services have the potential to facilitate more efficient use and build out of the \ntransmission system, they also contemplate running the system “tighter” than we have \ndone in the past, potentially with more loads on the system served by co-located or \nbehind-the-meter generation, and potentially more use of batteries, load control systems, \nand backup resources to manage demand during system peaks or other stressed \nconditions. While it is important to identify innovative solutions that can adapt to the \nneeds of the system, the Commission and grid operators must also be careful not to \n \nseeks-nevada-tariff-to-shield-ratepayers-from-data-center-costs/822250/. \n6 E.g., Travis Kavulla, How Will Data Centers Pay for Power?, American Affairs \n(may 2026), available at https://americanaffairsjournal.org/2026/05/how-will-data-\ncenters-pay-for-power/ ; Electricity Customer Alliance, A Customer-Centric Agenda for \nthe Federal Energy Reg. Comm’n (Jan. 2026), available at https://lnkd.in/em-apfuQ; \nGrid Strategies, Federal Transmission Pricing Vol. 2, Options for Ensuring Affordability \nin an Era of High Load Growth (June 2026), available at \nhttps://gridstrategiesllc.com/project/federal-transmission-pricing. \n7 Proclamation No. 11014, 91 Fed. Reg. 11439 (Mar. 4, 2026)."},{"page":109,"startToken":40841,"endToken":41271,"text":"Docket No. EL26-70-000 \n- 6 - \nimplement changes that create unforeseen reliability risks. Ultimately, we must find the \nproper balance (and I would argue we are exploring a new balance) between costs of \ninvestments versus reliability. \n \nThe Commission’s experience in the PJM co-location proceeding highlights the \ncomplexities and challenges of introducing these new transmission services, which have \nsignificant ramifications for system operations, transmission planning, grid reliability, \nmarket dispatch, resource adequacy, and cost allocation. As the Commission considers \nwhether to expand these transmission services to new types of load and new regions, I \nencourage commenters to address what impacts the introduction of new firm and non-\nfirm transmission products would have in their regions, as well as any relevant \ncharacteristics that might distinguish their regions from the Commission’s findings in the \nPJM co-location docket. Ultimately, this topic will have direct long-term impacts on how \nfuture transmission systems will be planned and configured, how efficiently future power \nmarkets will operate, and how customers will respond to prices and system needs. \nTherefore, I am specifically interested in understanding how extending the new \ntransmission services might affect individual suppliers or customers, as well as how \nexisting systems or processes might be affected by these new services. I am open to \nunderstanding how these services might be helpful to a region or that they may create \nproblems not yet anticipated. \nV. \nThe Orders Recognize the Importance of Evaluating Advanced Transmission \nTechnologies \n \nLastly, today we preliminarily find that each RTO/ISO’s tariff is unjust and \nunreasonable because the tariff lacks clear and consistent provisions requiring the \nevaluation of alternative transmission technologies as potential solutions to accommodate \nan Eligible Customer’s request for transmission service on behalf of a large load. \nSpecifically, it is important for RTO/ISOs and transmission owners to evaluate whether \nalternative transmission technologies are feasible in reducing the cost of transmission \nsystem upgrades or allow for a faster timeline for accommodating the transmission \nservice request. As many transmission owners have explored various alternative \ntechnologies in pilot projects,8 it is time to roll out all available technologies to reduce \n \n8 See, e.g., Increasing Mkt. and Planning Efficiency Through Improved Software, \nEffective Congestion Mitigation with Transmission Topology Optimization at Alliant \nEnergy and ATC, Docket No. AD10-12-016, available at \nhttps://www.ferc.gov/media/effective-congestion-mitigation-transmission-topology-\noptimization-alliant-energy-and-atc (Alliant and ATC were able to save customers \napproximately $24 million over a 12-month period through the use of topology \noptimization); Pablo Ruiz and Derek Brown, “Reliable and Efficient Congestion \nMitigation Using Transmission Reconfigurations,” NewGrid and Evergy presentation \n(Oct. 2022)¸ available at https://www.spp.org/Documents/67968/SAG%20Meeting%20"},{"page":110,"startToken":41271,"endToken":41545,"text":"Docket No. EL26-70-000 \n- 7 - \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 \nMaterials%2020221007.zip (identifying reconfigurations, had they been implemented, \nwhich could eliminate 98% of overloads and reduce congestion costs by 85% for \ncongestion patterns associated with 10 significant constraints on Evergy’s system); \nPacific Gas & Electric Press Release, PG&E and Smart Wires Enhance Grid Reliability, \nCapacity for Data Centers in San Jose (May 28, 2025), available at \nhttps://investor.pgecorp.com/news-events/press-releases/press-release-details/2025/PGE-\nand-Smart-Wires-Enhance-Grid-Reliability-Capacity-for-Data-Centers-in-San-\nJose/default.aspx (describing PG&E’s deployment of advanced power flow control \ndevices were able to mitigate thermal overloads by up to 34%, enabling an additional 100 \nMW of firm power delivery over existing lines at a congested substation)."},{"page":111,"startToken":41545,"endToken":41684,"text":"UNITED STATES OF AMERICA \nFEDERAL ENERGY REGULATORY COMMISSION \n \nMidcontinent Independent System Operator, Inc. \nAEP Indiana Michigan Transmission Company, Inc. \nALLETE, Inc. \nAmeren Illinois Company \nAmeren Transmission Company of Illinois \nAmerican Transmission Company, LLC \nCleco Power LLC \nDuke Energy Indiana, LCC \nEntergy Arkansas, LLC \nEntergy Louisiana, LLC \nEntergy Mississippi, LLC \nEntergy New Orleans, LLC \nEntergy Texas, Inc. \nGridLiance Heartland LLC \nIndianapolis Power & Light Company \nInternational Transmission Company \nITC Midwest LLC \nMichigan Electric Transmission Company, LLC \nMidAmerican Energy Company \nMontana-Dakota Utilities Company \nNorthern Indiana Public Service Company LLC \nNorthern States Power Company, a Minnesota \nCorporation \nNorthern States Power Company, a Wisconsin \nCorporation \nNorthwestern Wisconsin Electric Company \nOtter Tail Power Company \nPioneer Transmission, LLC \nRepublic Transmission, LLC \nSouthern Indiana Gas & Electric Company \nUnion Electric Company \nWabash Valley Power Association, Inc. \nWolverine Power Supply Cooperative, Inc. \nDocket No. EL26-70-000 \n \n \n \n \n \n \n \n(Issued June 18, 2026)"},{"page":112,"startToken":41684,"endToken":42146,"text":"Docket No. EL26-70-000 \n- 2 - \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 MISO’s Tariff that need to \nbe resolved to appropriately respond to this growth, as informed by careful review of the \nthousands of pages of comments received in response to the advance notice of proposed \nrulemaking (ANOPR).1 I write separately to underscore my expectation for RTOs and \nISOs, including MISO, to timely submit their robust, thoughtful, and region-specific \nproposals to address the concerns that we have preliminarily identified in their respective \ntariffs and agreements. By harnessing your region-specific expertise and creativity to \nbring tailored solutions to the table, together we can efficiently, reliably, and affordably \nintegrate large load, co-located load and generation and/or storage, as well as electrically \nproximate large load onto the transmission system. I also support the use of alternative \ntransmission technologies to unlock every megawatt of existing capacity from our current \ntransmission system. We have the technology. We should use it now to enable faster \ninterconnection of large loads, lower costs to customers, and help prevent cost shifting. \n \nTo that end, and in light of our action in today’s orders, I also ask the state public \nutility commissions—whether they have already approved large load retail tariffs, are in \nthe process of crafting large load retail tariffs, or have yet to embark on this essential \ntariff design process—to take a hard look and ensure their large load retail tariff \nprovisions insulate ratepayers from the negative impacts of data center growth. \nAdditionally, I expect MISO to design proposals in response to this show cause order that \ndovetail with the efforts on the retail side to implement the Ratepayer Protection Pledge, \nprotect customers, and ensure that large loads cover the costs they incur to integrate with \nthe grid. \n \nThe stakes here could not be higher and every gambler knows that the secret to \nsurviving is knowing what to throw away and knowing what to keep.2 Today’s orders do \nexactly that—adopting thoughtful proposals that position our nation for success, driving \nmeaningful change, and rejecting the gridlock, half-measures, and failure to plan that \nhave gone on for far too long. The data center odyssey that we embarked upon first with \n \n1 Interconnection of Large Loads to the Interstate Transmission System, Advance \nNotice of Proposed Rulemaking, Docket No. RM26-4-000, (Oct. 23, 2025) (ANOPR); \nsee also Letter from Chris Wright, Sec’y, U.S. Dep’t of Energy (Oct. 23, 2025) \n(Secretary’s Letter). \n \n2 Kenny Rogers, The Gambler (United Artists Records 1978)."},{"page":113,"startToken":42146,"endToken":42623,"text":"Docket No. EL26-70-000 \n- 3 - \nPJM, then SPP, we now aggressively extend to all the RTO/ISO regions.3 Enabling the \nswift and efficient interconnection of large loads to the transmission system while \nmaintaining affordability, reliability, commitment to open access, competitive principles \nand cooperative federalism, will only be achieved through consistent, coordinated action \nand persistence. But without that first step,4 there is no direction, no forward momentum, \nno journey, and no way to arrive at our future destination. In the show cause orders we \nissue today, the Commission takes a series of long strides towards our ultimate large load \ninterconnection destination: we make preliminary findings that the RTO/ISO tariffs, \nincluding MISO, may be unjust and unreasonable and/or unduly discriminatory or \npreferential because they lack features necessary to timely, reliably, and safely \ninterconnect and serve new large loads in a way that produces just and reasonable rates. \n \nI commend each commentor for their robust and ongoing responses to the \nconcerns that Secretary Wright and the Commission raised in the ANOPR proceeding. \nThe comments helped us identify the common issues, common solutions, and individual \ndifferences among the RTOs/ISOs. We heard a plea for broad flexibility and regionally \ntailored solutions. And we will strive to work towards those solutions, not through top-\ndown, one-size-fits-all mandates, but through consideration of region-specific proposals. \nAnd we endeavor to support an appeal for federal policies that build upon rather than \ndisrupt current and planned developments, reflecting state and local processes and \nstakeholder efforts. Through these individually tailored and region-specific show cause \norders, we are delivering to ensure that our transmission system can accommodate new \nlarge loads in a timely, safe, and reliable manner. And, importantly, in a manner that \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, MISO, and your stakeholders. We are directing you to expeditiously bring \nforward for our consideration your novel, region-specific solution(s). Time is of the \nessence. By inviting you to proceed under FPA section 205, we are giving you \nsignificant perks: the benefits of first wielder of the pen and the relatively capacious \n \n3 Interconnection of Large Loads to the Interstate Transmission System, 195 \nFERC ¶ 61,045 at P 2 (2026) (Order Regarding Intent to Act) (citing PJM Co-Location \nOrder, 193 FERC ¶ 61,217; SPP HILL Order, 194 FERC ¶ 61,031; Commonwealth \nEdison Co., 194 FERC ¶ 61,181 (2026); Tri-State Generation and Transmission Ass’n, \n193 FERC ¶ 61,070 (2025); Duke Energy Carolinas, LLC, 193 FERC ¶ 61,237 (2025)). \n4 Admittedly, we are further down the road in some regions as compared with \nothers."},{"page":114,"startToken":42623,"endToken":43120,"text":"Docket No. EL26-70-000 \n- 4 - \nstandard under FPA section 205 that allows us to accept a potentially broad range of \nproposals provided they are shown to be just and reasonable and not unduly \ndiscriminatory or preferential.5 We are even giving you flexibility to propose the \nimplementation date for your innovative proposals. But such freedom comes with great \nand concomitant responsibility. \n \nThis is not a time to be cavalier and dodge the urgent need to meet the moment. \nWhile this is a long journey, even so, we must continue to move at breakneck pace to win \nthe AI race. So let me be direct. If you choose not to submit timely, reasonable, non-\ndiscriminatory or preferential, comprehensive, and substantiated proposal(s), as directed \nand as required under our applicable statutes, your deficient response will not go \nunnoticed. I am prepared to play jurisdictional hardball, if needed.6 This Commission \nhas appropriately exercised considerable restraint in asserting the full scope of our \njurisdiction in these orders. However, the Commission has very broad jurisdiction over \ntransmission that we will not hesitate to utilize as necessary to ensure that we meet our \nobjectives in all show cause proceedings, including this MISO proceeding we initiate \nhere. If we find your Tariff is in fact unjust and unreasonable and unduly discriminatory \nor preferential, any failure on your end to provide a sufficient FPA filing or filings to \naddress the large-load-related concerns that we have identified will result in the \nCommission dictating the solutions for you. I say this not as a threat, but as a statement \nof duty. While you may not like our remedies—I have often said that the federal \ngovernment generally does not come up with the best solutions—this is an outcome we \nare prepared to pursue given the gravity of the moment and our statutory obligation. \nNotwithstanding our readiness to step in, it greatly benefits everyone for you to come up \nwith an approach tailored to your region. \n \n5 See, e.g., NRG Power Mktg, LLC v. FERC, 862 FERC 108, 105 (D.C. Cir. 2017) \n(FERC may not employ a rate design that follows “a completely different strategy” than, \nor is “methodologically distinct” from, a proposed rate) (internal quotations omitted); \nOxy USA, Inc. v. FERC, 64 F.3d 679, 692 (D.C. Cir. 1995) (stating that a proposal under \nFPA section 205 “need not be the only reasonable methodology, or even the most \naccurate”); City of Winnfield v. FERC, 744 F.2d 871, at 874-875 (D.C. Cir. 1984) \n(comparing the respective authorities of the Commission and public utilities under \nsections 205 and 206). \n \n \n6 16 U.S.C. § 824(b); New York v. FERC, 535 U.S. 17 (2002) (“There is no \nlanguage in the statute limiting FERC’s transmission jurisdiction to the wholesale \nmarket[.]”)) (emphasis in original); id. at 20 (stating that “the FPA authorizes FERC's \njurisdiction over interstate transmissions, without regard to whether the transmissions are \nsold to a reseller or directly to a consumer[.]”)."},{"page":115,"startToken":43120,"endToken":43221,"text":"Docket No. EL26-70-000 \n- 5 - \n \nI will end my concurrence where I began: We have heard your concerns, and, let \nme underscore, now is the time for you to heed ours. This is an extraordinarily \nconsequential proceeding. The stakes for reliability, for affordability, and for the \nAmerican ratepayer could not be higher. We owe it to the public to get this right. I look \nforward to reviewing and acting as expeditiously as possible on your responses to this \nshow cause order, which I expect will include an FPA section 205 proposal or proposals. \n \nFor these reasons, I respectfully concur. \n \n \n______________________________ \nDavid LaCerte \nCommissioner"}],"sections":[{"p":1,"at":0,"title":"Opening text","method":"opening text","endPage":2,"endAt":2669,"startToken":0,"endToken":309},{"p":2,"at":2669,"title":"D. Extending New Transmission Services to Eligible Customers Taking Service on","method":"printed heading","endPage":2,"endAt":2868,"startToken":309,"endToken":326},{"p":2,"at":2868,"title":"E. Interconnection Customers Serving Electrically Proximate Large Load and Co-","method":"printed heading","endPage":8,"endAt":190,"startToken":326,"endToken":2501},{"p":8,"at":190,"title":"I. 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