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December 5, 2025

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Xcel Seeks Extension for Comanche Coal Plant from Colorado Regulators

Xcel Energy, along with Colorado Gov. Jared Polis’ administration, wants to keep Unit 2 of the coal-fired Comanche Generating Station running a year longer than planned, mainly because of malfunctions at Unit 3.

A petition filed Nov. 10 with the Colorado Public Utilities Commission asks to keep Unit 2 available through 2026, a year past its scheduled retirement date of Dec. 31. The petition was filed by the Colorado Energy Office, the state Office of the Utility Consumer Advocate, PUC trial staff and Xcel Energy subsidiary Public Service Company of Colorado.

The request follows the unexpected outage of Unit 3 that began Aug. 12. Xcel said the unit was extensively damaged and is expected to remain offline until at least June.

“The cause of the outage, the steps necessary to repair it and the costs are unknown at this time,” according to a fact sheet on the Colorado PUC website.

With a nameplate capacity of 750 MW and accredited capacity of 415 MW, Unit 3 is the largest of Comanche’s three units. It is to retire by Jan. 1, 2031. Unit 2 has a nameplate capacity of 335 MW and an accredited capacity of 296 MW, the petition said. The 335-MW Unit 1 retired in 2022.

The coal-fueled steam units are in Pueblo, about 110 miles south of Denver.

Extended Outage

Xcel’s petition to postpone the retirement of Unit 2 “is a direct response to the unexpected outage of the Comanche Unit 3,” the PUC fact sheet said.

But other factors are contributing to the request, the petition said. The peak demand forecast in PSCo territory has increased to about 7,150 MW for summer 2026. A forecast made in 2024 predicted the summer 2026 peak would be about 6,950 MW.

Supply chain and tariff issues are hindering generation and storage projects, the petition added. An updated analysis of accredited capacity showed that PSCo needs more generation and capacity to meet demand.

“The continued operation of Comanche Unit 2 in 2026 is the most cost-effective approach to providing needed electricity for the system,” the petition said.

While market purchases would be one option for replacing the lost output of Unit 3, “such purchases are often expensive and volatile, especially during high-use times, such as winter cold spells, which can lead to gas price spikes,” the PUC fact sheet said.

If the PUC approves a yearlong extension to Unit 2 operations, PSCo would report to the commission by March 1 on the status of Unit 3. The report would discuss short-term resource options and “appropriate operational parameters” for Unit 2, especially after Unit 3 returns to service.

A more detailed report would be filed by June 1, including updated load and resource projections and loss-of-load calculations. The six-month planning period would give PSCo time to propose longer-term resource options, potentially including “consideration of updated retirement dates for Comanche Unit 2 and Comanche Unit 3,” the petition said.

Cost Concerns

Unit 3 has been plagued with problems since operations began in 2010. From mid-2010 through 2020, the unit averaged 91.5 outage days a year, according to a March 2021 report from the PUC. A 2020 outage lasted much of that year and extended into 2021.

“Plagued by failures and outages, Comanche 3 has been an albatross around the neck of Xcel ratepayers for more than a decade,” Erin Overturf, clean energy director at Western Resource Advocates, said in response to PSCo’s petition. “This request to delay the long-planned retirement of Comanche 2 will lead to increased costs for utility customers at a time when people are already economically struggling.”

The Sierra Club said in a statement that any decision to keep a coal plant running for reliability reasons “must be strictly monitored and narrowly tailored to avoid more unnecessary costs and pollution.”

“The administration and Xcel’s proposal would guarantee only one thing: Comanche 2 will run for another year, which means more air pollution in Pueblo and higher electricity bills for everyone,” said Margaret Kran-Annexstein, director of the Sierra Club’s Colorado chapter.

The PUC approved early retirement dates for Comanche Units 1 and 2 in 2018. Xcel announced in 2022 its plans to exit from coal-fired power plants by the end of 2030 as part of its clean energy transition.

The Trump administration has had other ideas about coal plants set to retire. In late May, the Department of Energy issued an emergency order to reverse the impending retirement of the J.H. Campbell coal plant in Michigan. The order directed the plant to remain ready to operate because of a shortage of electricity and capacity to generate electricity.

DOE in August ordered Campbell to remain available through Nov. 19. In an Oct. 30 filing, plant owner Consumers Energy said Campbell had racked up $80 million in net costs since late May staying online. (See J.H. Campbell Tab Rises to $80M on DOE’s Stay Open Orders.)

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UPDATED: Regulators Urge FERC to Honor State Authority over Large Load Interconnections

SEATTLE — The National Association of Regulatory Utility Commissioners passed a resolution urging FERC to resist the Department of Energy’s push to give itself jurisdiction over large loads interconnecting with the grid — an authority historically belonging to state regulators.

NARUC’s Board of Directors approved the measure (EL-1) in a Nov. 11 vote at the organization’s Annual Meeting.

The vote comes just over two weeks after Energy Secretary Chris Wright issued an Advance Notice of Proposed Rulemaking (ANOPR) pressing for FERC to extend its jurisdictional authority to include the interconnection of large loads — including hyperscale data centers. (See Energy Secretary Asks FERC to Assert Jurisdiction over Large Load Interconnections.)

DOE argued the new rules would be in the public interest and align with the Trump administration’s goals of reviving U.S. manufacturing and dominating the development of artificial intelligence.

But through the NARUC resolution, state regulators are asking FERC to “preserve and affirm states’ retail regulatory authority under the Federal Power Act” and “ensure that large load interconnections do not compromise grid reliability or impose undue costs on retail customers, and respect state tools for promoting system flexibility and equitable cost allocation.”

The resolution provides NARUC a foundation for developing initial comments on the ANOPR, Idaho Public Utilities Commissioner John R. Hammond Jr., chair of the group’s Committee on Electricity, told RTO Insider at the conference.

“We know the resolution is broad. We wanted it to be nimble,” said Virginia State Corporation Commission Judge Kelsey Bagot, who guided the document through the committee to gain consensus ahead of the board vote.

“We did get a lot of collaboration among NARUC members” on the resolution, Bagot said.

Hammond agreed that the group found a lot of “commonality” on the issue.

Comments on the ANOPR are due Nov. 21, which Bagot acknowledged is a “tight deadline.”

‘Unprecedented Expansion’

In an Oct. 23 letter to FERC accompanying the ANOPR, Wright contended that “the interconnection of large loads directly to the interstate transmission system to access the transmission system and the electricity transmitted over it falls squarely within the commission’s jurisdiction.”

The ANOPR offered a handful of legal justifications for the change, saying that:

    • large load interconnections are a critical component of open access transmission service that require minimum terms and conditions to ensure non-discriminatory transmission service;
    • interconnection of large loads directly affects FERC-jurisdictional wholesale rates, over which the FPA has granted the commission exclusive authority; and
    • the rule change would not violate state jurisdiction over retail sales.

The ANOPR also said that any views controverting the changes would conflict with the FPA’s core requirement that FERC have exclusive jurisdiction over transmission in interstate commerce.

But with the NARUC resolution, state regulators are clearly disputing those points.

A draft of the resolution said the proposed rulemaking “represents an unprecedented expansion of federal jurisdiction and potential intrusion on the states’ historic retail regulatory authority under the Federal Power Act, introducing potential confusion, unintended customer consequences and/or legal uncertainty where none currently exists.”

But the final resolution removed that language — and toned down other statements, instead saying “it is imperative that FERC, in any final rulemaking, make clear that it is affirmatively not asserting jurisdiction over end-use sales, which falls squarely within the exclusive jurisdiction of state retail energy regulatory authorities.”

The resolution goes on to explain that state regulators exercise oversight over resource adequacy, grid reliability and maintaining affordability for retail customers. It says their authority over integrated resource planning stems from their “reserved jurisdiction” under Section 201(b) of the FPA, “enabling states to oversee utilities’ long-term forecasting of electricity demand and evaluation of supply- and demand-side resources to meet that demand in a cost-effective, reliable and sustainable manner.”

The resolution notes also that NERC’s most recent Long-Term Reliability Assessment shows electricity demand is growing at the fastest rate in two decades, with especially steep increases expected for winter peaks. It cautions that “large load interconnections without sufficient available generation capacity could threaten reliable power service to existing retail customers,” with grid operators potentially lacking sufficient resources to maintain system stability during peak demand and extreme weather events.

The regulators warn also that the costs for large load interconnections, presumably mandated by FERC — including needed transmission upgrades — could unfairly fall to retail ratepayers “if not properly allocated.”

The resolution points out that at least “at least 20 states have approved or have pending large load tariffs or similar measures, which may include financial commitments, curtailment protocols and minimum contract terms to allow for the rapid interconnection of large loads without compromising grid reliability or unduly burdening existing retail customers.”

Drawing a Line

Judge Bagot expressed confidence that FERC can “find a solution states can be comfortable with,” noting the commission’s recent decision on Tri-State Generation and Transmission Association’s High Impact Load Tariff (HILT) could offer perspective on where the commission will stand.

In that order, FERC rejected the HILT, saying “certain aspects” of the proposed tariff “appear to present an impermissible intrusion on retail rate regulation” by state commissions. (See FERC Rejects Tri-State’s ‘High Impact Load Tariff’ Aimed at Data Centers.)

State regulators think “a line can be drawn” that preserves state authority but “allows the feds to be involved” with large load interconnections, Bagot said.

An earlier version of this article contained language from a draft version of the resolution. The story has been updated to reflect the wording in the final document. 

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FERC Denies CAISO OATT Interconnection Rehearing Request

FERC has denied rehearing requests regarding approved revisions to CAISO’s Open Access Transmission Tariff generator interconnection procedures, which contesting parties said rely partly on “subjective and discriminatory criteria.”

Calpine, Clean Energy Associations, Dynegy Marketing and Trade, and Vistra filed the rehearing requests in October 2024. On Nov. 7, FERC denied the requests and clarified the discussion in its queue reform order.

CAISO proposed the OATT interconnection revisions because of an “unprecedented numbers of interconnection requests” resulting from California state regulatory requirements and policies, the order said.

The revisions included a zonal approach that prioritizes interconnection projects in areas with existing or planned transmission capacity. The approach provided four cluster study criteria, including a “commercial interest” score, which is up to 30% of a project’s overall score.

The rehearing parties claimed that commercial interest points create opportunities for potential undue discrimination or preference, specifically by allowing load-serving entities (LSE) to allocate commercial interest points to affiliates. That allows for the disparate treatment of LSEs vs. non-LSEs and creates an impact on small LSEs, the parties argued.

The commission found these claims “unpersuasive” because CAISO’s revisions “balance LSEs’ role in resource procurement with appropriate tariff limitations on LSEs’ ability to award points, including limitations on points that may be awarded to affiliates,” the order says.

FERC disagreed with the rehearing parties’ claim that LSEs would be able to control access to the grid by using “subjective and discriminatory criteria to assign commercial interest points in an anticompetitive manner.”

The rehearing parties said allowing LSEs to award commercial interest points violates the Federal Power Act, which prohibits undue discrimination. The parties also said the commercial interest points process erodes “two longstanding commission policies that provide non-discriminatory and comparable access to all wholesale users and ensure interconnection rules are not unduly discriminatory or preferential.”

FERC pointed out the Federal Power Act does not prohibit all discrimination, only “undue discrimination.”

“Discrimination is undue when similarly situated customers are treated differently,” the commission said in the order. “Here, no party on rehearing has provided any persuasive explanation that similarly situated interconnection customers will be treated differently under the revised tariff.”

CAISO said rejecting commercial interest points would “significantly diminish the value of its proposal and result in more ties,” the order says.

The approved OATT revisions will allow CAISO to select and move forward with proposed generating facilities for reliability and public policy purposes, the order says.

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MISO States Call NERC’s Planned RA Standard Inappropriate

The Organization of MISO States is warning NERC that its possible new resource adequacy standard would tread on states’ planning authority.

In draft comments, OMS said NERC’s potential standard positions it “for the first time beyond resource adequacy assessments, which Congress clearly mandated NERC produce, into enforceable resource adequacy standards” with corrective action plans.

NERC is developing a possible new approach to resource adequacy standards that may set new, actionable instructions to maintain reliability.

The organization opened a comment period through Dec. 10 on its plan, which would have planning coordinators conducting their own Long-Term Energy Reliability Assessments using an unserved energy basis and reporting the results to NERC. The plan would take a step beyond the customary one-day-in-10-years loss-of-load expectation metric.

NERC’s outline calls for resource planners and transmission planners to prove they have developed corrective action plans — enforced by the ERO — to address “unacceptable” levels of reliability risks in long-term assessments.

Speaking at the OMS Board of Directors’ meeting Nov. 10, Wisconsin Public Service Commissioner Marcus Hawkins told fellow regulators that states and RTOs already conduct the analyses NERC is advising and make their own resource adequacy plans.

‘Reinforce Rather than Override’

Hawkins said NERC “does not have the authority to issue the standard in its current form.” He called NERC’s effort a “renamed resource adequacy standard” that usurps authority from the states and transfers it to a planning coordinator.

“The draft appears to expand NERC oversight into areas reserved for state authority under the Federal Power Act,” OMS wrote in draft comments, adding that it could “shift state regulators from decision-makers to reviewers of federally enforceable actions.” The group of states said NERC should stay out of policymaking and stick to reliability assessments that “reinforce rather than override” state resource planning.

“It is essential that NERC’s standards not create de facto resource planning or procurement mandates that bypass the processes established under state and federal law,” OMS said.

Hawkins said OMS’ view is NERC is taking on new responsibilities that it doesn’t have permission to assume.

OMS wrote that utilities would be put in the “untenable position of being subject to conflicting obligations,” referring to enforcement risk at the federal level from NERC creating friction with state laws that govern least-cost planning, rate recovery and resource approvals. OMS said a utility could propose binding resource additions in a corrective action plan outside a state review process.

OMS Legal and Regulatory Director Brad Pope said that although there are varying interpretations of the draft standard, MISO states generally construe it to be “federal overreach into state jurisdiction.”

“I think it’s important that we come out strong in these comments,” Pope said.

Hawkins put other MISO state commissioners on notice at the OMS Annual Meeting in late October that the rollout of the new NERC standard could be problematic. At the time, Hawkins said his reading is that potential “binding corrective action plans” issued by NERC would entail some level of investment to bolster resource adequacy. He said he worried about the potential jurisdictional implications of the ERO essentially mandating certain entities to open their pocketbooks to bring more resources online.

“I think that is one potential negative outcome,” Hawkins said at the time.

On Nov. 10, NERC Manager of State Government and Regulatory Affairs William McCurry said the ERO recognizes that states are in charge of what is built within their borders.

McCurry also said NERC wants to engage more with stakeholders on the organization’s upcoming Long-Term Reliability Assessment and would take comments on the draft report.

“We realize there were data inaccuracies with the 2024 report,” McCurry told regulators and staff. “We’re trying to be thoughtful and collaborative in how we approach this year’s assessment.”

McCurry was referencing an apparent mix-up in NERC’s 2024 assessment where unforced capacity values for MISO were used when calculating a margin that NERC ultimately compared to an installed capacity requirement. (See IMM: NERC Reliability Assessment Still Overstating MISO Risk.) NERC fixed the mistake, and MISO was subsequently downgraded from “high risk” in the assessment to “elevated risk.”

At the MISO Market Subcommittee’s meeting in October, Independent Market Monitor David Patton again said the RTO is in a better place than NERC assumes in its long-term assessments, even without the errata.

“MISO was in a more reliable state than other control areas in the Eastern Interconnection,” Patton said of the slew of energy emergencies that occurred on June 24. He noted that PJM entered a weeklong string of emergencies June 23-30.

At the OMS Annual Meeting, Bryan Clark, director of reliability analysis for the Midwest Reliability Organization, said the regional entity is working to beef up its regulatory staff to prepare for more complex assessment work. He acknowledged reliability assessments are a “projection, not a prediction” and said MRO is open to working together with MISO and its stakeholder community on reliability initiatives.

During the American Council on Renewable Energy’s annual Grid Forum in late October, NERC Senior Vice President Camilo Serna said the industry needs to plan and operate the bulk power system from an energy adequacy perspective rather than a resource adequacy perspective. He said grid operators need to capture not only frequency of outage events, but also the magnitude and duration to find out what’s acceptable.

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IESO Board OKs Rule Changes Ahead of Capacity Auction

The changes, approved by the IESO Board of Directors on Oct. 24 and effective Nov. 17, include a multistep tie-break process to optimize the capacity auction clearing process (MR-00488-R00) and an amendment to make it easier for participants to transfer capacity obligations and harder to buy them out (MR-00483-R00).

The board acted following favorable reviews by its Technical Panel. (See IESO Capacity Market Rule Changes Advance.)

Resources selected in the annual capacity auction are expected to participate in the energy market unless they buy out or transfer their obligations. But some resources fail to fulfill their obligations because, for example, they did not complete the registration requirements. (See IESO Seeks to Shore up Capacity Market.)

Unfulfilled obligations reduce the capacity available and distort clearing price signals, the ISO says.

With the changes, suppliers who fail to complete the registration process no longer will have the option of simply forfeiting their deposits and will be required to buy out their obligations. In addition, the buyout charge is increasing from 33 to 50% of the obligation value.

The revisions also will remove the requirement that obligations can be transferred between resources only with the same attributes.

The board said the changes, recommended unanimously by the Technical Panel, will improve reliability.

Tie-break Methodology

A tie occurs when two or more participants offer the same price for the last available quantity of capacity in a zone.

Under the previous rules, the ISO used time stamps to select the bid submitted first to break the tie. The new rules created a three-step process to award an equal share in step 1 and apply a proportional allocation in step 2, based on what’s left over from step 1. Capacity remaining after step 2 will be allocated by time stamp rank.

In its approval, the board said the changes will result in a “more equitable” tie-break solution.

Auction

The Nov. 26-27 auction, which will seek capacity for the periods beginning May 1 and Nov. 1, 2026, is open to existing and non-committed demand response, generation, energy storage and import resources. Results will be posted Dec. 4.

The 2024 auction for summer 2025 (May 1-Oct. 31) procured 1,987.9 MW at $332.39/MW-day in all zones except the Northeast and Northwest, which priced at $195/MW-day. For the winter obligation period (Nov. 1, 2025, to April 30, 2026), IESO procured 1,478.4 MW at $139/MW-day in all zones.

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OMS: MISO Contains Almost 17 GW of DERs

The Organization of MISO States (OMS) estimates the RTO is up to approximately 16.6 GW of distributed energy resources across its footprint, up 3 GW from 2024.

That’s according to the 2025 OMS DER Survey, released before the Nov. 10 meeting of the MISO DER Task Force.

OMS Legal and Regulatory Director Brad Pope said the annual survey recorded a “big jump” in DER deployment from 2024 to 2025. In 2024, the survey uncovered nearly 13.6 GW of DERs. For the previous three years, OMS typically has tallied an approximate 1-GW increase in DERs year over year. (See OMS Survey: Another 1-GW Jump in DERs in MISO Footprint.)

Pope said solar generation continues to dominate among reported DERs. Erik Hanser, a staffer with the Michigan Public Service Commission, said 75% of the megawatts represented in the 2025 survey originate from either solar or demand response.

Pope said some increases this year probably are due to underreporting in previous years. He said OMS is looking to improve its data collection method to get the fullest picture it can of DERs in MISO.

MISO utilities responding to the survey “still see a need for regulatory direction” on DERs, from MISO and “especially from state commissions,” Pope said. He said respondents agreed that a “comprehensive and secure data registry of some form” would be useful to share DER data. Many utilities expect to encounter challenges around data sharing and secure communication when FERC Order 2222 — which will allow DER aggregators to compete in MISO’s wholesale markets — takes effect in 2030.

Hanser said that in this version of the survey, OMS logged “a lot more serious talk” about DER management systems, with more utilities considering them. But Hanser said survey responses indicated DERs are still too small in size and number to materially affect the MISO transmission system or inspire planning changes. Hanser said utilities in high DER penetration areas reported a small number of backflow issues on circuits or at substations, some of which were addressed by line upgrades.

Hanser said some utilities thought MISO should lead on creating protocols to set up communication between utilities and DER aggregators. Other utilities are in the early stages of addressing communication and awaiting more information from the RTO, he said.

“Overall, we got the sense that it’s too early. … Utilities are waiting for guidance both from MISO and their state regulators,” Hanser said. “Utilities are wary [of acting] before fully understanding how DERs will eventually operate in MISO. Utilities want to build systems they believe will interact easily with MISO rules.”

During the OMS Annual Meeting in October, Executive Director Tricia DeBleeckere urged MISO and members to do more to prepare for the 2029 deadline for the RTO to comply with Order 2222.

For the first year of the survey’s history, utilities reported electric vehicles as DERs, Pope said, with slightly more than 1 GW hailing mostly from Michigan’s Zone 7. Pope said OMS is investigating how utilities quantify the resource capability of EVs and if the ones that showed up in the survey are capable of bidirectional services. Hanser said OMS must examine if the reported EVs are in fact being used as distributed resources and aiding the grid.

Overall, Zone 7 contains the most DERs, at a little more than 4 GW. The zone is home to a few large, behind-the-meter generators that put it beyond other MISO zones. Minnesota, Wisconsin and the Dakotas’ Zone 1 holds the second-most DERs, at nearly 3.4 GW.

OMS gathers data on DER assets both registered and unregistered with MISO. Pope noted that the organization collects information only on DERs connected at the distribution level and therefore doesn’t include all of MISO’s load-modifying resources in its survey.

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IESO Implementing ‘True-up’ on Renewed Market Rules

After seven months of operations under its Market Renewal Program, IESO is doing some housekeeping, implementing “non-substantive” changes that it said will “improve clarity” and “better align the market rules with the correct functioning” of the nodal market.

The changes, approved by the IESO Board of Directors on Oct. 24, are effective Dec. 3.

The Renewed Market, which launched May 1, created a financially binding day-ahead market (DAM) and about 1,000 generation, load and intertie pricing nodes to replace its provincewide price. (See Ontario Nodal Market Nearing ‘Steady State’ After Nearly 4 Months.)

Some of the changes remove transitory provisions that allowed both the Renewed Market rules and the legacy market rules to be in effect concurrently. “They do not reflect changes in design principles and are limited to typographical, cleanup, clarifications or computational corrections,” IESO said.

In addition to general cleanup items, the changes affect sections on settlements, market power mitigation, and market and system operations.

Market Power Mitigation

The changes (MR-00484-R00) reduce the default value for maximum starts per day from 10,000 to one; remove the “unnecessary administrative burden” on market participants to disclose affiliated entities that have limited or no ability to control or influence a market participant; and codify IESO’s obligation to publish potential constrained areas.

Market and System Operations

The changes to Chapter 7 of the market rules (MR-00484-R01):

    • prohibit generator offer guarantee-eligible resources from increasing offer prices for energy and operating reserves (OR) during the first 30 minutes of a dispatch hour of the real-time market unrestricted window;
    • require market participants to revise single-cycle mode status to align with the requirements and duration of commitments that span across midnight; and
    • add a limit for electricity storage resources offering OR in the opposite direction of OR supply during the subsequent dispatch hour in the energy market. The limit was inadvertently omitted.

Settlements

Settlement provisions of the market rules were revised (MR-00484-R02) to:

    • amend the hourly operating reserve settlement amount by dividing the quantities by 12;
    • clarify the eligibility for the DAM balancing credit based on day-ahead schedules;
    • delete the offer/bid substitution for DAM make-whole payments (MWPs), which is not applicable;
    • modify the language of the DAM MWP ineligibility for called capacity exports with the same language in the real-time MWP provisions;
    • insert the “dispatchable load” resource type within a provision for the real-time MWP reversal charge;
    • amend the formula for the hourly uplift settlement amount to add a missing variable; and
    • amend the formula for the DAM reliability scheduling uplift by inserting brackets to clarify the summation function.

Miscellaneous Cleanup Items

MR-00484-R03 deletes the obligation for IESO to review the capacity prudential requirements at least once every three years.

MR-00484-R04 corrects typographical and grammatical errors, adds cross-references and italicizes defined terms.

MR-00484-R05 removes transitory provisions to reflect the switch from the legacy market to the Renewed Market, including:

    • “Section A” rules at the beginning of each chapter, which allowed both the renewed market rules and the legacy market rules to be in effect concurrently;
    • sections A.1 and B.1.1 in each chapter of the market rules (where applicable); and
    • the defined term “market transition error,” which is no longer required.

It also modified the definitions of the terms “market transition,” “market transition completion” and “Renewed Market rules.”

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PJM Monitor Presents Spin Event Performance

The PJM Independent Market Monitor found that modeling issues were the largest cause of synchronized reserve underperformance during a July 22 spin event, in which about 80% of assigned reserves responded.

The Monitor has been reaching out to resource owners whose units underperform during reserve deployments, focusing on events longer than 10 minutes. It also has inquired with the owners of overperforming resources, but the small sample size limited the amount that could be shared.

The effort has become more important since PJM instituted a 30% adder on the synchronized and primary reserve requirement in May 2023 to counteract a low response rate.

The 10-minute-32-second event had 2,764 MW of generation and 548 MW of demand response assigned, with a 78.8% response rate. (See “July Operating Metrics,” July Heat Wave Update, PJM OC Briefs: Aug. 7, 2025.)

Joel Romero Luna, Monitoring Analytics | © RTO Insider LLC

Joel Romero Luna, a market analyst with the Monitor, said PJM’s modeling of the amount of time needed to bring equipment into service or change output is accounting for a rising share of reserve underperformance. That constituted the largest cause July 22, at 178.8 MW of the 523 MW for which a cause was attributed.

Issues with software and hardware, such as mechanical failures or errors in programs that dispatch units, were the second-highest rationale for underperformance, followed by outdated or inaccurate resource parameters.

Luna told the Operating Committee on Nov. 3 that communication between PJM and resource operators has improved significantly. However, operators sometimes still do not know what is required of them during a spin event.

Personnel error and communications issues accounted for 12% of the shortfall for which a cause could be attributed. PJM has reworked how reserve deployments are sent to resource operators to convey instructions through unit basepoints. (See “Stakeholders Endorse Reserve Rework, Reject Procurement Flexibility,” PJM MRC Briefs: July 24, 2024.)

October Operating Metrics

PJM’s load forecast accuracy improved for a fourth consecutive month, PJM’s Marcus Smith said while presenting the monthly operating metrics. The average hourly forecast error was 1.02%, while the rate for peak hours was 1.30%.

Three days exceeded the RTO’s 3% peak-hour error benchmark due to unpredicted weather conditions. The peak Oct. 4 was 3.05% under forecast due to high temperatures in the east causing increased load. Oct. 7 was over forecast by 3.12% due to storms across the footprint pushing temperatures down, and Oct. 8 was over forecast by 3.59% due to lower temperatures and variations in cloud coverage.

There was one shared reserve event and one geomagnetic disturbance warning, and there were 24 post-contingency local load relief warnings. Two shortage cases were approved Oct. 3 due to low generation during the afternoon ramp; another was issued Oct. 17 at 10:20 a.m. due to a unit tripping offline.

A spin event was declared Oct. 15 at 4:52 p.m.; it lasted 5 minutes and 21 seconds. There was 2,804 MW of generation assigned, of which 57% responded.

Another event Oct. 17 was initiated at 8:13 p.m. and lasted 11 minutes and 7 seconds. There was 1,743 MW of generation assigned, of which 74% responded, and 644 MW of demand response assigned, of which 92% responded.

The Oct. 17 deployment is the second in PJM’s three-event rolling average used to determine whether it will reduce a 30% adder on the synchronized and primary reserve requirement. Paired with an event Sept. 25 with 77% performance, the average is 78%. Performance across three consecutive events must be above 75% for the adder to be reduced by 10%, and a larger reduction is possible if performance is higher. (See PJM OC Briefs: March 6, 2025.)

A third October spin event was declared Oct. 28, but the data had not been processed before the Operating Committee meeting.

Manual 14D Revisions Endorsed

Stakeholders endorsed by acclamation a slate of revisions to Manual 14D: Generation Operational Requirements drafted through the document’s periodic review.

The changes require that generation owners notify PJM of start-up issues that may affect their units during a cold weather advisory and added sections detailing cold weather operating limit data requests and the cold weather advisory drill. They also detail how data about resources is used in PJM’s Gen Model to produce load flow, short circuit and dynamics modeling for planning staff.

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Modernization Task Force Leaders Update NERC Members on Progress

Industry stakeholders will have a chance to weigh in on the proposals of NERC’s Modernization of Standards Processes and Procedures Task Force in the coming weeks, task force leaders said at the Nov. 10 meeting of the Member Representatives Committee.

NERC has been seeking comments on the MSPPTF’s draft recommendations since Oct. 21, task force Chair Greg Ford reminded attendees, observing that the comment period actually closed earlier that day. (See NERC Seeks Feedback on Standards Modernization Recommendations.) The ERO’s Board of Trustees created the MSPPTF in February in light of the rapidly evolving risk environment, which has made it increasingly difficult to keep up with new threats to reliability.

While the online comment submissions are closed, Ford said stakeholders can share their views on the recommendations at two upcoming stakeholder forums, to be held Nov. 13 in Salt Lake City and Nov. 19 in Atlanta. These forums were intended to be to be held in person, but because of uncertainties around flight availability arising from the ongoing federal government shutdown, Ford reminded listeners that an online option is available.

“We really encourage everyone to come participate in this,” Ford said. “This is where we, as the task force, can learn a little bit more about what your comments were intended to address, but it’s also more for you to hear from the task force members on where our recommendations were headed. We’ll take all of that input and get ready for our December workshop.”

The MSPPTF’s recommendations apply across the standards development process. They include organizing a biannual period for requesting, reviewing and initiating new standards projects; implementing a subcommittee under the Reliability Issues Steering Committee to drive standards drafting; and revamping the standards balloting process to provide more accountability and encourage stakeholder participation.

The task force will revise its proposals based on feedback submitted online and at the forums, and present its final recommendations to the board at its February 2026 meeting in Savannah, Ga.

Leadership Elections and Plan Update

Ford took over running the MRC meeting briefly while Chair John Haarlow, CEO of Snohomish County Public Utility District, and Vice Chair Matt Fischesser, of ACES Power, excused themselves so members could vote on a proposal to grant them another term in their positions.

Haarlow and Fischesser were the only nominees received during the nomination period, which lasted from Sept. 11 to Oct. 9, and as a result were unanimously confirmed to remain.

Camilo Serna, NERC’s senior vice president for strategy and external engagement, then gave members an overview of the ERO’s progress on its next three-year strategic plan. NERC’s current three-year plan will conclude at the end of 2025; the organization had planned to create a new plan to begin in 2026 but concluded earlier this year that long-term planning would be a “fool’s errand” because of the uncertainty introduced since President Donald Trump’s return to office. Instead, 2026 will be treated as a “bridge year” before the new plan begins in 2027.

Serna said NERC is defining the priorities, goals and initiatives to be addressed in the plan and how it will measure progress. The organization will provide a draft of the priorities to the MRC in January so that members can provide feedback ahead of the February board and MRC meetings; this list will be finalized by March.

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SPP State Regulators Affirm Use of Highway/Byway Cost Allocation

LITTLE ROCK, Ark. — SPP state regulators have approved several motions related to FERC Order 1920’s mandate for long-term, scenario-based planning to ensure the system can meet future needs and be fairly compensated.

The Regional State Committee endorsed the continued use of SPP’s highway/byway cost allocation for long-term regional projects during its Nov. 3 quarterly meeting. It also approved the Cost Allocation Working Group’s recommendation to allocate long-term projects with public policy benefits to the state they benefit.

Under the grid operator’s highway/byway methodology, one-third of the cost of byway projects — lines rated at 100 to 300 kV — are allocated to the RTO’s full footprint, with customers in the transmission pricing zone in which the project is built being allocated the rest. “Highway” projects, those larger than 300 kV, are allocated RTO-wide.

The RSC offered several amendments to the motions brought forward by a CAWG sub-group, but both failed. Both would have established a $150 million threshold for projects to be cost allocated, provided that a simple majority of affected committee members vote to initiate the process.

However, separate votes to require alternative ex post cost allocation methodology be approved by either a two-thirds or simple majority both failed with deadlocked ballots.

John Krajewski, a consultant for the Nebraska Power Review Board who led the CAWG sub-group, said SPP has never identified a project or issued a notification to construct (NTC) out of a 20-year study.

“So, in some respects, this was an academic exercise,” he said, “but I also think it was important because we’re required to do it under Order 1920, and it’s possible in the future this may be an issue.”

Order 1920 requires transmission providers to plan for at least 20 years, create at least three different long-term scenarios to identify future needs and evaluate potential solutions for cost-effectiveness. The order also incorporates a landowner bill of rights, tribal impact reports and engagement plans with environmental justice communities. The compliance filing is due in June.

Nickell Recaps ‘Transformational’ Year

SPP CEO Lanny Nickell thanked the RSC for the “key role” it played in helping the grid operator move initiatives related to resource adequacy and cost allocation that made 2025 a “transformational” year.

Nickell name-checked the one-time expedited resource adequacy study (ERAS) to fast-track qualified projects and a provisional load process, both approved recently by FERC. He also mentioned the Consolidated Planning Process that would combine transmission planning and generator interconnection studies; it was filed with FERC on Nov. 3.

“That, in and of itself, is going to be revolutionary,” he said of the CPP.

Nickell said SPP received 36 submissions as part of the ERAS process, totaling 13.2 GW of capacity. About 73% of that is gas generation, with solar and batteries accounting for the rest. Generator interconnection agreements will be made during the first quarter of 2026, he said.

“That’s the kind of generation we’re going to need to help us with our accreditation and to help load-serving entities meet their requirements,” he said.

The RTO expansion into the Western Interconnection remains on track, Nickell said, with a Dec. 2 go/no go date fast approaching to determine whether to open the transmission congestion rights market in the West on Jan. 1, 2026. The next key decision comes Feb. 2, he said, when SPP will decide whether or not to stick with the April 1 go-live date.

The grid operator’s other Western market, Markets+, has 41 entities that have committed to fund the development of the market’s systems development and hardware. SPP is targeting a go-live date in late 2027.

“We’re in a time of change, and I think it’s just important to realize and to show and to demonstrate what can be done when you put your heart to it and put your mind to it,” Nickell said.

JTIQ Funds Remain in Limbo

General Counsel Paul Suskie told the committee that SPP has yet to receive “official word” about the status of the U.S. Department of Energy’s $464 million grant for the grid operator’s Joint Targeted Interconnection Queue initiative with MISO.

“Fingers are crossed that the funds will still be there,” Suskie said. “I’m personally an optimistic person. I’m optimistic the current administration will see the value that JTIQ will have for the region to get new generation online.”

The DOE loan under its Grid Resilience and Innovation Partnerships (GRIP) program would account for more than 27% of the $1.7 billion portfolio, comprising five 345-kV projects along SPP’s northern seam with MISO. Each grid operator is responsible for two projects in its footprint, and they share the fifth.

The funds were awarded in 2023 to the Minnesota Department of Commerce, the lead applicant in the JTIQ initiative that also involves the Great Plains Institute and the two RTOs. However, the department in early October included the $464 million grant on a list of projects that it intended to terminate. (See DOE Terminates $7.56B in Energy Grants for Projects in Blue States.)

Suskie said conversations continue between DOE and parties to the initiative. NTCs have been awarded to Omaha Public Power District and Evergy for the JITQ projects, he said, giving them the obligation to move forward with their portions of the projects and making them eligible for cost recovery.

FERC has approved the RTOs’ request to allocate the portfolio’s costs 100% to interconnecting generation assessed on a per-megawatt basis. In doing so, it cited the GRIP funding as one of the “unique set of facts and circumstances of the proposed JTIQ framework.” (See FERC Upholds MISO and SPP’s JTIQ Cost Allocation over Criticism.)

RSC Selects New Leadership

The RSC approved the Nominating Committee’s slate of officers for the 2026 term, with Nebraska’s Chuck Hutchinson succeeding New Mexico’s Patrick O’Connell as president.

Oklahoma’s Kim David will serve as the RSC’s vice president, while Arkansas’ Justin Tate and Missouri’s Kayla Hahn will take the secretary and treasurer positions, respectively.

Randy Pinocci, Montana PSC | © RTO Insider 

O’Connell said it was an honor to have led the committee and its differing points of view.

“We work together to try to get to consensus and focus on the region first,” he said. “That’s not always true in daily life in general, especially these days. This isn’t just professionally a great experience; it’s also kind of a respite from the real world sometimes. I really, on a personal level, really appreciate how the RSC works together, and then I appreciate that SPP allows us to work together in that way.

“So, thank you all for that,” O’Connell said. “Dry your eyes, OK?”

The RSC’s roster grew to 13 with the addition of Montana’s Randy Pinocci. Observing from the audience were Wyoming Public Service Commission Chair Mike Robinson, another potential new member, and New Mexico’s Greg Nibert, who will replace O’Connell on the RSC in 2026.