On June 18, 2026, the Federal Energy Regulatory Commission (“FERC” or the “Commission”) took long-awaited steps to address the impacts of large loads, including data centers, on the transmission grid. First, the Commission issued an order on rehearing in the ongoing co-located load proceedings involving PJM Interconnection, L.L.C. (“PJM”) and PJM transmission owners, which addressed issues arising from FERC’s December 2025 Order, previously summarized here.[1] Second, the Commission instituted new proceedings requiring each FERC-jurisdictional regional transmission organization (“RTO”) or independent system operator (“ISO”) to either demonstrate their tariffs adequately address the integration and impacts of large loads or to alternatively propose tariff reforms.

PJM Rehearing Order

The December 2025 Order paired with the Commission’s June 2026 Rehearing Order in the ongoing PJM proceedings may serve as a harbinger of how the Commission intends to address large load interconnection across the other five grid operators within its jurisdiction.

The PJM Rehearing Order addresses three separate procedures that followed the Commission’s December 2025 Order. First, it addresses requests for rehearing and clarification filed by various parties. Second, it accepts in part and rejects in part PJM’s proposed tariff revisions filed in compliance with the December 2025 Order. Third, it responds to the paper hearing record developed through briefings submitted following the December 2025 Order.[2]

Requests for Rehearing and Clarification of December 2025 Order

On rehearing, the Commission largely upheld its findings from the December 2025 Order. FERC maintained that PJM’s existing tariff is unjust and unreasonable, and that PJM must establish new transmission service options (i.e., interim non-firm transmission service (“Interim NITS”), firm contract demand (“FCD”) service, or non-firm contract demand (“NFCD”) service) in addition to PJM’s existing network integration transmission service (“NITS”) to serve customers who are willing and able to take service on behalf of a Co-Located Load and limit energy withdrawals from the transmission system under certain conditions.[3] Co-Located Load encompasses customer load, such as a data center or a large manufacturing facility, physically connected to a generation resource that is in turn interconnected with the PJM transmission system.

The PJM Rehearing Order set aside two aspects of the December 2025 Order relevant to customers who have behind-the-meter generation (“BTMG”), as defined in the PJM tariff.[4] The Commission first clarified that Eligible Customers taking transmission service on behalf of load with BTMG (that are willing and able to limit energy withdrawals from the transmission system under certain conditions) may take any of the new transmission services, and are not required to take only NITS.[5] In addition, the Commission carved out an exemption for certain cogeneration Qualifying Facilities (“QFs”) from the new 50 MW materiality threshold applicable to PJM’s BTMG netting rules. For cogeneration QFs that can demonstrate that “they are integrated with load such that, when their generating facility trips offline, the load follows,” the 50 MW netting threshold does not apply and the exempt facilities may net by using BTMG.[6] This exemption would apply, for example, to a large manufacturing facility with a BTMG cogeneration QF arrangement where the manufacturing process requires steam produced by the QF. If the QF stopped functioning, the manufacturing process would also stop, and the facility would not withdraw energy from the transmission system.

Apart from these two changes, the Commission upheld its findings from the December 2025 Order. Any further challenges to the December 2025 Order, as modified by the PJM Rehearing Order, may be subject to judicial review.

PJM’s Proposed Tariff Revisions for Large Load Interconnections

The Commission’s December 2025 Order directed PJM to propose tariff revisions to revise its BTMG netting rules, establish new transmission services, and clarify interconnection procedures and agreements. In response, PJM submitted a compliance filing. The Commission’s determinations are summarized below.

1. BTMG Rules

Netting Materiality Threshold. PJM’s existing retail BTMG rules allow Network Customers to reduce transmission charges by netting an unlimited amount of load at a particular electrical location using BTMG.[7] The Commission accepted PJM’s proposal to set the materiality threshold at 50 MW and to exclude on-site backup power from the threshold.[8] FERC found a 50 MW threshold just and reasonable because it addresses the resource adequacy concerns identified in the December 2025 Order without being overly restrictive.[9] The Commission acknowledged that new netting limitations may result in economic consequences, but stated that economic concerns must be balanced against reliability, resource adequacy, and cost-shifting risks.[10]

The Commission rejected PJM’s proposal to apply the 50 MW threshold to cumulative nameplate capacity of generation, rather than to the total load that can be netted at an electrical location.[11] The Commission clarified that its directive was not intended to prohibit netting when a Network Customer exceeds the threshold, but rather to limit how much load a Network Customer may net using BTMG at a single electrical location.[12]

Grandfathering and Transition Period. In compliance with the Commission’s December 2025 Order, PJM proposed to grandfather any existing retail BTMG with a contract in place (even if not fully operational) as of December 18, 2025. Grandfathered generators would continue to use PJM’s existing retail BTMG netting rules through the term of the contract, encompassing existing renewal or extension rights and modifications within the scope of the existing contract that do not “fundamentally alter” the arrangement in effect as of December 18, 2025.[13]

The types of agreements that may qualify for grandfathering are not made explicit in the PJM Rehearing Order. PJM has stated that “utility contracts, fuel contracts, maintenance contracts, and more” could qualify, and FERC elaborated that engineering, procurement, and construction contracts may qualify.[14] PJM intends to “explore with stakeholders whether manual language should be developed” to elaborate on the types of contracts that may be grandfathered.[15]

Exemptions for QFs. PJM’s proposed tariff revisions would allow for grandfathering of all QFs over 50 MW serving as retail BTMG as of December 18, 2025.[16] The Commission rejected this approach, finding that PJM failed to meaningfully distinguish between load served by QFs that are BTMG and load served by other categories of BTMG.[17] However, as discussed above, PJM must exempt certain cogeneration QFs from the new retail BTMG netting rules, if they demonstrate that the load ceases when the integrated generating facility goes offline.[18]

2. Transmission Services

PJM’s compliance filing provided an outline of the transmission services that Eligible Customers taking service on behalf of Co-Located Load may take: (1) NITS or a new Interim NITS, (2) a new FCD service, or (3) a new NFCD service.[19] However, a number of issues regarding the rates, terms, and conditions associated with these transmission services remain subject to the ongoing paper hearing.[20] As discussed above, PJM must extend the new transmission services to Eligible Customers taking service on behalf of load with BTMG that are willing and able to limit their energy withdrawals from the transmission system under certain conditions.[21]

3. Necessary Studies

The December 2025 Order required PJM to clarify the Necessary Study process for existing Interconnection Customers to allow their generating facilities to serve Co-Located Load. PJM proposed the following clarifications:

• Existing Interconnection Customers must enter into a Necessary Study Agreement with PJM and provide all information needed to perform the Necessary Studies, as detailed in future PJM manuals;
• Project developers may not make changes to facilities until the Necessary Study process and amended interconnection agreement are effective;
• Necessary Studies will include thermal, short circuit, and stability studies under various seasonal and load conditions, and assess any necessary control technologies and protection systems required; and
• Project developers will be responsible for the cost of any modifications or necessary Network Upgrades.[22]

FERC found PJM’s proposals partially compliant. In a future filing, PJM must provide specific information on the additional study details that will be available in PJM manuals, how the revisions will apply to parties who have already executed Necessary Study Agreements and for which PJM has already completed Necessary Studies, and how PJM will ensure all prerequisites are met before an Interconnection Customer can serve Co-Located Load from an existing generator.[23] The Commission rejected PJM’s tariff revisions to the extent they require existing Interconnection Customers with effective Interconnection Service Agreements (“ISAs”) or Generation Interconnection Agreements (“GIAs”) to enter into new GIAs, finding that such customers must be able to amend their existing agreements.[24] Lastly, the Commission rejected PJM’s proposal to raise the initial deposit for Necessary Studies from $25,000 to $50,000 because PJM proposed the change “without explanation.”[25]

4. Miscellaneous Revisions to Definitions and General Rules

Definition of Co-Located Load. PJM proposed to replace “Point of Interconnection” with “Point of Change in Ownership” in its tariff definition of Co-Located Load.[26] FERC rejected this change, reasoning that PJM did not sufficiently explain how the deviation complies with the December 2025 Order.[27]

Definition of Non-Retail BTMG. While the December 2025 Order directed substantial changes for retail BTMG, it did not change PJM’s existing non-retail BTMG rules. However, PJM proposed to revise its definition of BTMG to “add clarifying language” that PJM states “preserves the status quo.”[28] FERC rejected the proposal because PJM failed to provide any justification for the revisions.[29]

Generation Interconnection Procedures, Pro Forma GIA, and Common Service Provisions. The Commission accepted various proposals by PJM to establish rules for all Interconnection Customers serving Co-Located Load, such as:

• An Interconnection Customer who will use its generator to serve Co-Located Load must specify an Eligible Customer who will take service on behalf of the Co-Located Load;
• If an Interconnection Customer does not want to identify an Eligible Customer, it may terminate its generator’s interconnection to PJM and serve the Co-Located Load fully islanded from PJM’s transmission system; and
• A new schedule in the pro forma GIA will serve as a placeholder for specifying operational procedures or data exchange requirements necessary for arrangements between Co-Located Loads and the associated generators.[30]

FERC rejected revisions to the extent that the proposed rules require existing Interconnection Customers with effective ISAs or GIAs to enter into new GIAs, as discussed above.[31] PJM must submit further revisions to clarify that existing Interconnection Customers who wish to modify their ISAs or GIAs to serve Co-Located Load must publicly notify PJM and identify the Eligible Customer who will take transmission service.[32]

5. Effective Date

PJM requested that its tariff revisions bear a placeholder effective date of 12/31/9998, because PJM cannot implement the tariff changes until the Commission rules on pending issues related to the terms and conditions of the new transmission services in the paper hearing procedures.[33] The Commission declined to rule on the request, seeking additional information in a future compliance filing.[34]

Paper Hearing Issues: Rates, Terms, and Conditions of New Transmission Services

In the December 2025 Order, the Commission established paper hearing procedures, inviting briefing to address issues regarding the appropriate rates, terms, and conditions of the new transmission services for Co-Located Load.

1. Firm Contract Demand and Non-Firm Contract Demand Service

The Commission rejected proposals by PJM to place certain limitations on FCD and NFCD services, including proposals to require Eligible Customers: to take sufficient transmission service to account for the entire gross demand of a Co-Located Load, to take FCD service at a level of contract demand reflecting the amount of load not served by a Co-Located Generator, to request NFCD transmission service equal to the MW level of a Co-Located Generating Facility dedicated to serving a Co-Located Load for any portion of the load not covered by FCD service, and to only allow NFCD service in circumstances where the Co-Located Generator is on outage.[35]

FERC directed PJM to make further revisions to remove the proposed limitations and allow Eligible Customers to select any amount, including 0 MW, for NFCD transmission service.[36] The Commission emphasized the need for FCD and NFCD transmission services to recognize the flexibility of Co-Located Loads that are willing and able to limit their energy withdrawals from the transmission system under certain circumstances.[37]

Anti-Toggling Mechanism. The Commission approved PJM’s proposal to prohibit Eligible Customers from toggling from FCD service to NFCD service for a period of five years, with a 42-month notice of termination applicable to FCD customers, to prevent changes based on expected market conditions and to recognize that PJM has procured capacity on behalf of its FCD customers.[38] FERC rejected PJM’s proposed exception that would have permitted Eligible Customers to decrease the level of FCD contract demand and increase the level of NFCD contract demand, finding the proposal inconsistent with the anti-toggling mechanism directive.[39]

Study Procedures. The Commission directed PJM to file more detailed study procedures for transmission service, stating that PJM’s current proposal is vague and unclear.[40] PJM must study requests for FCD service using the cluster study process, which is the same process PJM uses for new service requests for NITS.[41] For NFCD service, the Commission directed PJM to provide more detailed procedures akin to the study of Non-Firm PTPS, which should also include details about the term length and minimum term of NFCD service.[42] Lastly, PJM must specify how transmission owners will participate in the study process for FCD and NFCD services, including the roles and responsibilities of PJM and the transmission owners in such studies.[43]

Rates and Charges. PJM transmission owners must base rates for FCD service on the zonal NITS rates and underlying NITS revenue requirements.[44] The Commission rejected the transmission owners’ proposal to set the maximum rate for NFCD service equal to the FCD rate, finding that non-firm transmission rates should generally be priced below firm transmission service rates to incentivize efficient non-firm uses of the transmission system and to better align with cost causation.[45] PJM transmission owners must propose a lower maximum rate or non-discriminatory discounts for the NFCD transmission rate.

The PJM Rehearing Order directs that Eligible Customers taking FCD and NFCD service on behalf of Co-Located Loads or load with BTMG will also be charged for:

• Regulation and black start services based on gross demand;
• Ancillary services based on contract demand (for FCD) or as-reserved contract demand (for NFCD); and
• Administrative charges and redispatch costs to cover congestion-related costs.[46]

The Commission concluded that the paper hearing record does not adequately justify an additional charge for Eligible Customers that reserve 0 MW or a de minimis amount of transmission service but still depend on the system for synchronization support services.[47] However, the Commission recognized that once implemented, the new transmission services may raise novel cost causation questions, and invited parties to submit filings under Federal Power Act (“FPA”) section 205 or complaints under FPA section 206 to address any resulting issues.[48]

2. Interim NITS

Interim NITS customers will receive non-firm transmission service to Co-Located Load or load with BTMG and automatically convert to a Network Customer when Network Upgrades are complete.[49] Generally, the same non-rate terms and conditions will apply to Interim NITS and NITS customers.[50] Interim NITS customers will also be assessed administrative service charges, ancillary service charges, black start service charges, regulation charges, and any redispatch costs.[51] The Commission found that PJM should have greater discretion regarding studies of Interim NITS requests because the service is temporary and only available to the extent that PJM determines that it can be provided reliably.[52]

3. Curtailment for Interim NITS and NFCD

FERC agreed that FCD service should be treated comparably to NITS for purposes of developing a curtailment hierarchy. PJM will curtail Interim NITS and NFCD comparably to Non-Firm PTPS (i.e., prior to firm transmission services and prior to deployment of PJM’s Pre-Emergency Load Response Program or in response to a transfer capability shortage as a result of system reliability conditions).[53] However, the Commission found that PJM has not adequately explained its curtailment hierarchy among non-firm transmission services: Non-Firm PTPS, Interim NITS, and NFCD transmission service.[54]

PJM’s tariff will specify curtailment priorities for the new transmission services, and implementation details will be provided in PJM manuals and individual service agreements to allow operational flexibility during emergency procedures.[55]

4. Necessary Control Technologies and Protection Systems

FERC found that Eligible Customers taking any of the new transmission services must have necessary control technologies and/or protection systems in place to limit energy withdrawals to contract demand levels.[56] The Commission explained that penalties alone may not be sufficient to ensure compliance with load shedding and curtailment procedures or to deter unreserved excess energy withdrawals from the PJM system.[57]

The Commission provided guidance on implementing necessary control technologies and/or protection systems, stating that (1) Eligible Customers should pay for any studies necessary to evaluate and design the systems, (2) the systems must be subject to approval by PJM and the transmission owners, and (3) the systems must fully meet PJM and transmission owner technical criteria and NERC reliability standards.[58] If a special protection scheme is employed, it must be fully redundant.[59]

The Commission directed PJM to propose further tariff revisions to ensure that Eligible Customers taking service on behalf of Co-Located Load or load with BTMG have adequate telemetry, data exchange, and metering requirements so that PJM may monitor the Eligible Load’s use of the transmission system, limit withdrawals, and ensure relay settings are consistent with necessary control technologies and/or protection systems.

5. Penalty Charges and Remedial Actions

Operational Penalties. The Commission acknowledged that significant reliability risks exist if Eligible Customers taking service on behalf of Co-Located Loads or loads with BTMG fail to limit withdrawals from the transmission system when required.[60] However, the Commission rejected PJM’s “one strike and you’re out” approach to addressing failures to follow curtailment or load shedding directives and misoperations of necessary control technologies and/or protection systems. Instead, FERC directed PJM to establish a penalty scheme whereby after a second instance of failure to follow directives or misoperation of systems, the non-compliant Eligible Load’s service will be terminated under the three new transmission services.[61] However, NITS will remain a service option (once any necessary Network Upgrades are completed).[62]

Financial Penalties. Where Eligible Customers use transmission service that has not been reserved, the Commission found it just and reasonable to impose financial penalties. PJM transmission owners must submit a framework proposal for financial penalties tied to unreserved use of the transmission system.[63] The framework includes a penalty rate that is twice the rate for FCD transmission service, a base penalty charge for each hour in which an Eligible Customer’s reserved service limit is exceeded during at least one five-minute interval, and a penalty ratchet when exceedances occur repeatedly within the same day, week, month, or year.[64] The Commission directed that unreserved use penalties be distributed to all non-offending transmission customers.[65]

6. Annual Report

The Commission directed PJM to propose a tariff provision requiring annual reporting on the use of the new transmission services. Suggested information includes data on transmission service requests by zone, total MW of each service type taken each year by zone, transmission revenues paid by Eligible Customers, frequency and magnitude of curtailment for NFCD and Interim NITS by zone, and frequency and magnitude of denials of NFCD service reservation requests by zone.[66]

7. Proposed Effective Date

PJM proposed a June 1, 2029 effective date for the three new transmission services based on timelines to integrate the new services into PJM’s capacity market to procure capacity for FCD customers and to modify PJM’s core markets and operations software.[67] The Commission urged PJM to reconsider, noting that “the issues raised in this proceeding, including those pertaining to Co-Located Load, are urgent in nature and, therefore, merit serious consideration of an earlier effective date.”[68] PJM must explain in its next compliance filing whether it can make any of the new transmission services available at an earlier date.

What Comes Next?

PJM must submit further compliance filings within 60 days, by August 17, 2026. The December 2025 Order, as modified by the PJM Rehearing Order, is eligible for judicial review. However, many aspects of PJM’s new transmission service offerings remain unresolved and will continue to develop through future compliance filings.

New Large Load Interconnection Proceedings

On the same day it released the PJM Rehearing Order, the Commission launched “aggressive targeted action” to speed up large load integration by opening six show cause proceedings under section 206 of the FPA, targeting the six regional grid operators (PJM; Midcontinent Independent System Operator, Inc.; Southwest Power Pool, Inc.; California Independent System Operator Corporation; ISO New England Inc.; and New York Independent System Operator, Inc.) and their transmission owners.[69]

The Commission has highlighted five key categories of reform:

1. Developing efficient application and study processes applicable to customers seeking transmission service requests on behalf of large loads;[70]
2. Preventing cost shifting and requiring cost transparency;
3. Accommodating co-location agreements and BTMG, including addressing the rates, terms and conditions of service applying to co-location agreements;[71]
4. Providing new transmission services associated with co-located loads, load with behind-the-meter generation, and flexible large loads (i.e., loads that are willing to limit use of the transmission system under certain conditions); and
5. Developing a process to study generating facilities that serve electrically proximate and co-located large loads.

The Commission set a 60-day response deadline for grid operators and transmission owners to explain why their current tariffs remain just and reasonable, or to file tariff changes to address issues related to large load interconnection.[72] In addition, each RTO/ISO must file an informational report by July 20, 2026 explaining how it intends to ensure adequate generation will be available to serve new and existing large loads.[73] Chairman Swett explained that individual show cause proceedings will allow the Commission to enact large load reforms more quickly than through a rulemaking process, while noting that a future rulemaking is a possibility.[74]

[1] PJM Interconnection, L.L.C., 193 FERC ¶ 61,217 (2025) (“December 2025 Order”), aff’d in part and set aside in part on reh’g, 195 FERC ¶ 61,209 (2026) (“PJM Rehearing Order”).

[2] PJM Interconnection, L.L.C., 195 FERC ¶ 61,209 (2026).

[3] PJM Rehearing Order at P 31.

[4] PJM’s Tariff, as proposed in its February 23, 2026 compliance filing, defines “Behind The Meter Generation” as “either Retail Behind the Meter Generation or Non-Retail Behind The Meter Generation and refers to a generation unit that delivers energy to load without using the Transmission System or any distribution facilities (unless the entity that owns or leases the distribution facilities has consented to such use of the distribution facilities and such consent has been demonstrated to the satisfaction of the Office of the Interconnection); provided, however, that Behind The Meter Generation does not include (i) at any time, any portion of such generating unit’s capacity that is designated as a Generation Capacity Resource or DER Capacity Aggregation Resource; or (ii) in an hour, any portion of the output of such generating unit that is sold to another entity for consumption at another electrical location or into the PJM Interchange Energy Market.” See PJM Interconnection, L.L.C. Co-Located Tariff Revisions, Docket No. ER26-1479-000, Proposed PJM Open Access Transmission Tariff, Definitions A-B (filed Feb. 23, 2026).

[5] PJM Rehearing Order at PP 32, 91, 101-03.

[6] Id. at PP 33, 141-42.

[7] Id. at P 181. In contrast, PJM’s current tariff provides for a 3,000 MW regional netting cap for non-retail BTMG, which is defined to include BTMG “that is used by municipal electric systems, electric cooperatives, or electric distribution companies to serve load.” See PJM Interconnection, L.L.C. Co-Located Tariff Revisions, Docket No. ER26-1479-000, Proposed PJM Open Access Transmission Tariff, Definitions L-M-N; § 34.3 (filed Feb. 23, 2026).

[8] PJM Rehearing Order at P 207.

[9] Id. at P 208.

[10] Id. at P 209.

[11] Id. at PP 207, 215-17.

[12] Id. at P 216.

[13] Id. at PP 222, 233.

[14] Id.

[15] Id. at P 222.

[16] Id. at P 234.

[17] Id. at PP 240-242.

[18] Id. at P 240.

[19] Id. at P 252.

[20] Id. at P 263.

[21] Id.

[22] Id. at P 271.

[23] Id. at PP 280, 283, 285.

[24] Id. at PP 282, 284.

[25] Id. at P 288 n.681.

[26] Id. at P 293. FERC previously directed PJM to adopt the definition of Co-Located Load specified in the December 2025 Order: “a configuration that refers to end-use customer load that is physically connected to the facilities of an existing or planned Customer Facility on the Interconnection Customer's side of the Point of Interconnection to the PJM Transmission System.” December 2025 Order at P 164 (2025).

[27] PJM Rehearing Order at P 307.

[28] Id. at P 296.

[29] Id. at P 314.

[30] Id. at P 309.

[31] Id. at P 310.

[32] Id. at P 311.

[33] Id. at P 316.

[34] Id. at P 318.

[35] Id. at P 348.

[36] Id. at PP 342, 348.

[37] Id. at P 343.

[38] Id. at P 535.

[39] Id. at P 536.

[40] Id. at P 370.

[41] Id. at PP 370-72.

[42] Id. at P 373.

[43] Id. at P 374.

[44] Id. at P 398.

[45] Id. at PP 402-408.

[46] Id. at PP 399-401.

[47] Id. at PP 454-55.

[48] Id. at P 456.

[49] Id. at P 571.

[50] Id.

[51] Id. at P 573.

[52] Id. at PP 574-75.

[53] Id. at P 551.

[54] Id. at PP 553, 555.

[55] Id. at P 552.

[56] Id. at P 480.

[57] Id. at P 481.

[58] Id. at PP 484, 486-87.

[59] Id. at P 485.

[60] Id. at P 515.

[61] Id. at PP 515-16. The first instance of misoperation of necessary control technologies and/or protection systems will result in a suspension in service for up to 120 days. Id. at P 523.

[62] Id. at PP 519, 528.

[63] Id. at P 529.

[64] Id.

[65] Id.

[66] Id. at PP 579-80.

[67] Id. at PP 581-83.

[68] Id. at P 597.

[69] FERC News Release, FERC Launches Aggressive Targeted Action to Speed Large Load Interconnection, available at https://www.ferc.gov/news-events/news/ferc-launches-aggressive-targeted-action-speed-large-load-integration; see PJM Interconnection, L.L.C., 195 FERC ¶ 61,211 (2026); Midcontinent Independent System Operator, Inc., 195 FERC ¶ 61,212 (2026); Southwest Power Pool, Inc., 195 FERC ¶ 61,213 (2026); California Independent System Operator Corp., 195 FERC ¶ 61,214 (2026); ISO New England Inc., 195 FERC ¶ 61,215 (2026); New York Independent System Operator, Inc., 195 FERC ¶ 61,216 (2026).

[70] This particular area of reform does not apply to Southwest Power Pool, Inc. (“SPP”) and SPP transmission owners. The Commission commended SPP for its “leadership” and “bold and proactive steps” taken to address large loads, including SPP’s enhanced study process for requests for transmission service to serve large loads. Southwest Power Pool, Inc., 195 FERC ¶ 61,213 at P 2 (2026).

[71] Because the issue of co-located loads in PJM is already addressed in the ongoing show cause proceedings, the new show cause order issued to PJM on June 18, 2026, addresses only issues relating to integrating large loads that are not co-located with generation. See PJM Interconnection, L.L.C., 195 FERC ¶ 61,211 at P 2 (2026).

[72] See, e.g., PJM Interconnection, L.L.C., 195 FERC ¶ 61,211 at P 3 (2026). The Commission provided RTO/ISOs and associated transmission owners the opportunity to request to hold all or portions of the proceedings in abeyance for up to 90 days. See, e.g., id. at P 39.

[73] See, e.g., id. at PP 4, 104.

[74] Id. at PP 9-10 (Swett, Chairman, concurring).