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December 7, 2025

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NEPOOL Committees Support ISO-NE Prompt Capacity Auctions

WESTBOROUGH, Mass. — NEPOOL technical committees voted in favor of ISO-NE’s proposal to adopt a prompt capacity auction and update the RTO’s resource retirement process, indicating broad stakeholder support for the first phase of ISO-NE’s capacity market overhaul.

In a joint meeting Nov. 12, the NEPOOL Markets Committee voted 97.9% in favor of the proposal and approved one of three amendments proposed by stakeholders. The NEPOOL Transmission Committee voted to support the associated transmission-related changes.

The proposal encompasses the first phase of work in ISO-NE’s Capacity Auction Reform (CAR) project. The RTO began stakeholder discussions in September on the second phase of the project, which centers around accreditation changes and shifting to a seasonal capacity market. (See ISO-NE Kicks off Talks on Accreditation, Seasonal Capacity Changes.)

While ISO-NE plans to file the two phases separately, both are intended to take effect for the 2028/29 capacity commitment period (CCP).

Under the proposed changes, ISO-NE would hold capacity auctions about a month prior to the start of each CCP, compared to the more than three years that historically have separated Forward Capacity Auctions and CCPs.

The proposal also would decouple resource deactivation from the auction process. ISO-NE has said processing resource deactivations in the immediate leadup to prompt auctions would not give it enough time to address any issues triggered by retirements. In the Forward Capacity Market, resources submit delist bids more than four years before the relevant CCP.

ISO-NE proposes to require resources to submit deactivation notifications one year before the start of the relevant CCP. It has said the one-year deadline balances the tradeoffs between a longer timeline, which would give ISO-NE and market participants enough time to respond to retirements, and a shorter timeline, which would enable resources considering retirement to make a better informed decision.

While the changes received widespread support from NEPOOL members, several stakeholders outlined lingering concerns about the risk that ISO-NE will not be able to obtain FERC approval of the second phase of CAR changes in time for the 2028/29 CCP, leaving the Phase 1 changes to stand alone for the first prompt auction.

Stakeholders also expressed concern that the shorter retirement notification period will increase the risk of out-of-market resource retentions. They emphasized the need to encourage bilateral transactions to protect against price volatility.

The MC also voted 83.3% to adopt an amendment by the New England Power Generators Association (NEPGA) to maintain ISO-NE’s current rules allowing capacity supply offers to reflect resources’ physical limitations in high ambient temperatures.

ISO-NE had proposed to eliminate its option for resources to submit ambient air delist bids associated with capacity it would not be able to provide when ambient temperatures exceed 90 degrees Fahrenheit. These delist bids are not subject to cost review by the Internal Market Monitor.

NEPGA made the case that, without the amendment, market participants would “unnecessarily be required to submit a cost workbook for megawatts it is physically unable to produce at those high ambient temperatures.” It proposed “technical conforming language” extending the existing exemption to the new design. ISO-NE indicated it would adopt the changes into its proposal.

The MC rejected a pair of proposals related to the competitive offer price threshold (COPT), which sets the price above which offers are subject to Monitor review.

Under ISO-NE’s proposal, the RTO would continue to calculate the threshold based on the previous capacity auction clearing price and forecasting for the upcoming auction.

Several stakeholders have expressed concern that relying on four-year-old prices to set the threshold in the transition to a prompt auction could create issues related to stale data, pointing to higher prices in recent annual reconfiguration auctions and a recent increase in Pay-for-Performance penalties.

Calpine and LS Power each offered amendments to the threshold methodology. Calpine proposed basing the threshold on a calculation of the opportunity cost associated with scarcity revenues, while LS Power proposed a one-year fixed price for the 2028/29 CCP based on the outcomes of recent reconfiguration auctions.

Both proposals fell short of the 60% voting threshold for MC support. Calpine’s proposal received 53.8% support, and LS Power’s received 56.7%.

ISO-NE acknowledged the concerns about stale data and said it plans to take a more in-depth look at the threshold in the second phase of the CAR project.

If the second phase of CAR is not approved prior to the 2028/29 CCP, “the ISO anticipates that it would make further updates to the [Phase 1] design, which would include an assessment of the COPT given the latest information available,” the RTO noted in a memo published prior to the meeting.

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Top Mass. House Members Seeking Major Rollback of Climate Laws

Top Massachusetts House members are pushing an expansive energy bill that would scale back several major climate initiatives and programs and give the state immunity from legal challenges that result from missing its 2030 climate targets.

While the bill appears to have almost no chance of passing in the Senate, the legislation marks a significant change in the House’s approach to climate and energy policy. The bill has drawn immediate outcry from climate and consumer advocates. And it sets the stage for a high-profile clash between environmental advocates and industry groups that historically have opposed climate policy.

“This bill is a major attack on the climate policy that we’ve had since 2008,” Larry Chretien, executive director of the Green Energy Consumers Alliance, told RTO Insider.

The legislation, sponsored by Rep. Mark Cusack (D), responds to a wide-sweeping energy bill introduced by Gov. Maura Healey (D) in May. (See Mass. Gov. Healey Introduces Energy Affordability Bill and Stakeholders Mixed on Massachusetts Energy Affordability Bill.) Cusack is the top House member on the legislature’s powerful Joint Committee on Telecommunications, Utilities and Energy.

While Cusack’s and Healey’s bills both claim to take aim at energy affordability challenges in the state, their approaches vary significantly. While Healey’s bill takes a more technocratic approach to cutting energy costs and largely avoids cuts to climate and clean energy initiatives, the House bill would seek to cut costs by taking aim at a myriad of decarbonization programs and requirements.

“This is a bill that saves significant money, real hard dollars, that people will see the impact of,” Cusack said in a recent interview with the CommonWealth Beacon. He added that the Trump administration has significantly set back the state’s ability to meet its near-term climate targets and that changes to the climate targets are necessary to protect the state from lawsuits.

The bill includes several proposals favored by industry groups, including the changes to the state’s decarbonization targets and regulatory changes that could make it easier to finance new pipeline projects. (See Gas Industry Sees Political Opportunity in New England.)

“It’s a pro-utility bill, it’s a pro-natural gas bill,” Chretien said, adding that he was surprised by the extent of the proposed policy rollbacks. “I don’t think it’s a foregone conclusion that this passes the House.”

Key Components

The bill’s proposals include significant changes to the Mass Save energy efficiency program, which has become an important vehicle for incentivizing heating electrification in recent years.

It would reduce the budget for the 2025-27 Mass Save plan from $4.5 billion to $4.17 billion, after the Department of Public Utilities already reduced the proposed plan from $5 billion to $4.5 billion in February. For future three-year plans, the bill would cap Mass Save budgets at $4 billion.

The bill would allow customers to receive Mass Save rebates for gas furnaces and would undercut a demonstration project in the state that authorizes 10 municipalities to ban fossil fuels in new buildings and major renovations. Under the proposal, customers in municipalities participating in the demonstration project would be prohibited from receiving heating electrification incentives from Mass Save.

It also would remove the social cost of carbon from DPU and Mass Save calculations of cost effectiveness and would prohibit state entities from promulgating any regulations or programs that have “unreasonable adverse impacts” on energy costs or the “the operating costs or economic competitiveness of Massachusetts businesses.”

The House proposes authorizing the state’s electric utilities to enter long-term gas contracts, which could lift a major barrier to the development of new pipeline infrastructure into the region. (See Pipeline Expansion Highlights Key Questions About Gas in New England.)

Cusack’s bill would scale back the state’s Renewable Portfolio Standard, decreasing the required annual increase in the RPS from 3 to 1%. It would require the state to return to ratepayers 70% of alternative compliance payments made under the RPS.

Some aspects of the bill are aligned with clean energy priorities, including several provisions promoting surplus interconnection service and flexible interconnection. The bill would give the Department of Energy Resources increased procurement authority and set targets to procure 10,000 MW of solar and 10,000 MW of offshore wind by 2040.

Emissions Limits

Regarding the state’s five-year decarbonization targets, the bill includes language intended to prohibit any legal action against the state if the state fails to meet its 2030 emissions limit.

A 2021 law set the 2030 emissions limit at 50% below 1990 emissions levels. If emissions exceed the limit, the law requires the state to “describe remedial steps that might be taken to offset the excess emissions and ensure compliance with the next upcoming limit.”

While environmental advocates have strongly opposed efforts to undermine the state’s climate targets, interpretations vary regarding the extent to which the state is vulnerable to lawsuits for failing to meet its emissions limits, and limited legal precedent exists on the issue.

Sen. Mike Barrett, the top senator on the joint TUE committee, has stressed that the 2030 limit is “not a rigid five-year requirement, and no one has ever pointed to legal language that suggests otherwise.”

“The only hard and fast goal in Massachusetts law is net zero by 2050,” Barrett said in a conversation with RTO Insider in October. “The language is carefully written; if we fail to meet a limit or sublimit by 2030, we’re supposed to try extra hard to get us back on track by 2035 or 2040. I wrote that language, so I know what I’m talking about.”

Reactions

Environmental and consumer groups panned the bill, arguing it would gut the state’s climate laws while providing minimal cost benefits for ratepayers.

“This bill represents an attempt to undo decades of good climate policy in our commonwealth — policies and programs that many House members who serve with Chair Cusack spent blood, sweat and tears on,” said Vick Mohanka, director of Sierra Club Massachusetts.

Caitlin Peale Sloan, the Conservation Law Foundation’s vice president for Massachusetts, called the bill “nothing short of betrayal,” adding that “rolling back the state’s commitments to affordable, clean energy is a gift to polluters and a slap in the face to every resident who deserves better.”

Kyle Murray, the Acadia Center’s Massachusetts program director, said the bill fails to “meaningfully address many of the largest real underlying energy cost drivers,” including gas volatility, spending on gas distribution pipe replacements, electric transmission costs and utility profits.

Meanwhile, the Associated Industries of Massachusetts (AIM), the largest business association in the state, praised the bill.

“We applaud Chair Cusack and the House for boldly protecting Massachusetts consumers by offering meaningful reforms that will generate real energy cost savings at a time when everything is expensive,” said AIM CEO Brooke Thomson in a statement. “This legislation confronts the harsh realities of our climate policy decisions and ensures the commonwealth is set up for long-term success in meeting these climate goals.”

Cusack did not respond to multiple requests for comment.

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MISO Interconnection Queue Dips Below 175 GW

MISO’s generator interconnection queue now totals 174 GW across 944 projects, a result of several developers dropping out of the line in recent months.

MISO Vice President of System Planning Aubrey Johnson told a Nov. 11 meetup of the Entergy Regional State Committee that MISO expects even more withdrawals as its planners begin processing studies. Johnson said many developers left the queue after the Trump administration announced it would abolish tax incentives for renewable energy development.

MISO’s queue has dropped steadily since the news. At the beginning of 2025, MISO said it had 312 GW to study; by September, that number had fallen to 215 GW. (See MISO Interconnection Queue Drops to 215 GW on Tax Incentive Phaseout.)

Johnson said MISO now expects to be able to sign 25 GW of interconnection agreements annually.

“We are moving projects through the interconnection queue; we are getting projects ready to come online,” Johnson said. He said MISO will work on the 2022, 2023 and 2025 cycles of projects; the RTO skipped the 2024 cycle while it designed a queue megawatt cap and put stricter rules in place to discourage developer speculation.

Between now and the second half of 2026, MISO estimates its members will add 8 GW of nameplate capacity (5 GW on an accredited basis) to the system.

Johnson said if achieved, those additions will exceed the 3.1 GW of capacity additions that MISO and the Organization of MISO States said were needed to meet the summer 2026 planning reserve margin. The shortfall prediction came from the MISO-OMS annual resource adequacy survey.

Johnson said as of November, MISO has 61 GW of projects with signed generator interconnection agreements that have permission to connect to the system.

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Texas PUC Hints at Revisiting ERCOT Conservative Operations

Texas regulators have approved ERCOT’s methodologies for determining minimum ancillary services for 2026 while hinting at the same time that they are considering discontinuing the use of conservative operations (54445).

Potomac Economics, which serves as ERCOT’s Independent Market Monitor, has said the grid operator’s practice of setting aside large amounts of operating reserves leads to inefficient scarcity prices that the energy-only market relies on to attract investment. (See Patton Calls on ERCOT to Operate its System Less Conservatively.)

“I think we do need to look at moving away potentially from how conservatively we’ve been operating the grid,” Thomas Gleeson, chair of the Public Utility Commission, said during its Nov. 6 open meeting. “I think we need to talk through all that because we’ve committed to kind of having a refocus on affordability and costs. Every season we get away from [February 2021’s] Winter Storm Uri, I think we need to be asking ourselves, given where we are today, ‘Does our methodology, does our procurement practice, really match what we think we need?’ I think we need to start asking those questions.”

The PUC directed ERCOT to use conservative operations in 2023 after a flurry of conservation calls.

Commission staff said ERCOT’s current ancillary services and the future deployment of Dispatchable Reliability Reserve Service (DRRS) “provide ERCOT sufficient” ancillary service products to comply with NERC requirements and respond to “inherent system variability and uncertainty” (55845).

Staff recommended the PUC minimize the number of significant market design changes during the first several months after the Real-time Co-optimization + Batteries project goes live in December.

RTC+B will “likely produce a fundamental shift in the procurement and deployment of AS, and the industry will be best served if the commission observes those changes and uses RTC-based data to inform subsequent changes to future AS methodologies,” staff said.

The ERCOT Board of Directors endorsed the methodologies during its September meeting. The grid operator will use a probabilistic methodology — an analytical approach incorporating randomness and uncertainty by assigning probabilities to outcomes and events — to calculate hourly ERCOT contingency reserve service (ECRS) and non-spinning reserve service quantities. The probabilistic model aligns ECRS and non-spin requirements with the risk profile, where higher risk equals a higher requirement and vice versa. (See ERCOT Board Approves AS Procurement for 2026.)

The Monitor opposed the methodology during the stakeholder process, saying it was misaligned with reliability outcomes. The IMM’s compromise position included halving the six-hour forecast horizon for determining non-spin and using a one-hour discharge horizon for storage resources rather than four hours.

LCRA Wins 2nd TEF Grant

The commission approved the Lower Colorado River Authority’s eligibility for a Completion Bonus Grant (CBG) of up to $22.56 million in performance-dependent funds over a 10-year period under the Texas Energy Fund (57937).

PUC staff and LCRA signed the agreement Nov. 10, the first under the TEF’s completion bonus program for projects that connect to the grid before June 1, 2029. LCRA’s Timmerman Power Plant Unit 1 was synchronized in August.

Two other applicants in the program are seeking loans totaling $23.06 million, staff said, for projects offering a combined 360 MW.

“I think it’s fair to say this is working well,” Gleeson said.

The unit provides ERCOT 190 MW of dispatchable generation. A second unit is expected to become operational in 2026, adding another 190 MW of capacity to the grid.

Annual payments are contingent upon the plant’s performance as measured by ERCOT during an annual “test period” and compared to the performance of a reference group of other generation resources in the region. Timmerman Unit 1’s first test period will run June 1, 2026, to May 31, 2027.

The PUC announced in October the largest loan under the TEF’s In-ERCOT Generation Loan Program, a 20-year, $1.12 billion loan for about 60% of Competitive Power Ventures’ 1,350-MW natural gas unit in West Texas. The unit has a targeted operational date in 2029.

With the fifth grant under the program, the TEF has now financed more than 3,100 MW of dispatchable power. Twelve more projects are moving through the In-ERCOT program’s due diligence review, representing nearly 6,000 MW of additional generation.

PUC Approves ERCOT Budget

The commission endorsed ERCOT’s biennial 2026-2027 budget and system administrative fee, adding large load interconnections to a list of priority performance measures that must be met (38533).

As approved by the ERCOT board during its June meeting, the grid operator is authorized to spend $485.87 million in 2026 and $585.04 million in 2027. The PUC granted the grid operator’s request to increase an existing $100 million revolving line of credit by $25 million and to reduce its administrative fee from 63 cents/MWh to 61 cents. (See “Board Approves $1.07B 2-year Budget,” ERCOT Board of Directors Briefs: June 23-24, 2025.)

The large load performance measure was added to staff’s original recommendations, all designed to support ERCOT’s implementation of the 2026 reliability standard assessment: deployment and stabilization of the RTC+B project; enactment of Senate Bill 6, the 2025 legislation overhauling several grid regulations; development of DRRS; and implementation of the ancillary services study findings.

ERCOT staff agreed to work with PUC staff to develop the performance measure targets. “We have a lot of ideas,” General Counsel Chad Seely told the commissioners.

In other actions, the PUC:

    • adopted revisions to ERCOT’s standard generation interconnection agreement (SGIA) that require generators to pay interconnection costs that exceed a “reasonable allowance” established by the commission, effective Jan. 1, 2026. Other changes include revisions adding plain language and clarity to the SGIA; requirements regarding the sharing of contact information between generators and transmission service providers; and requirements that generators comply with the Lone Star Protection Act (58211).
    • approved an amendment to established wholesale market power rules that removes the exemption currently preventing a generation entity controlling less than 5% of ERCOT’s total installed capacity from being considered to have market power, commonly referred to as the “small fish rule” (58379).
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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.