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November 26, 2025

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ISO-NE Introduces Approach to Modeling Gas Constraints

ISO-NE outlined its planned approach for accounting for resources’ gas supply limitations in its new capacity accreditation framework at the NEPOOL Markets Committee meeting Nov. 13.

The incorporation of regional gas constraints into the RTO’s accreditation process is an important part of the RTO’s capacity auction reform (CAR) project, as the current accreditation process does not account for these limitations.

Gas resources make up the largest group of generators in the region, accounting for 55% of generation in 2024 and 44% of capacity awards in the most recent forward capacity auction. Changes to the accreditation methodology for gas-only resources could have significant implications for overall capacity prices in the region, capacity revenues available to gas-only resources and incentives for gas generators to sign firm fuel contracts.

Under the CAR accreditation framework, ISO-NE plans to deploy a gas capacity demand curve reflecting “the diminishing reliability impact of non-firm capacity due to the system-wide gas constraint.”

Steven Otto, manager of economic analysis at ISO-NE, said the downward-sloping gas capacity demand curve would be “analogous to the existing export-constrained capacity demand curve design.”

In the winter, when gas resources face limited access to gas, the resources would be compensated at a lower price than other capacity resources, he said.

“In conjunction with the simultaneous clearing of the system-wide demand curve, the intersection of the gas capacity supply and demand curves determines how much non-firm gas-only CSO [capacity supply obligation] will be awarded and how much less that CSO will be paid,” Otto said.

Gas generation backed by firm fuel arrangements would earn the full capacity price paid to all other resources and would decrease the estimated amount of gas available to resources without firm contracts.

This approach differs from the marginal-reliability-impact approach ISO-NE plans to take for other resource limitations.

The RTO’s basic accreditation approach is intended to quantify each resource’s ability to reduce the amount of expected unserved energy during forecasted periods of energy shortfall. Factors such as outage rate, intermittency or fuel storage capabilities would be reflected in the amount of capacity that resources are allowed to sell in the market.

The gas constraint would be calculated separately from the accreditation values assigned to gas resources. ISO-NE plans to use an accreditation methodology similar to that of other non-energy limited thermal resources. Accreditation values would be based largely on resources’ forced outage rates and maximum capabilities, Otto said.

ISO-NE will rely on modeling by the Analysis Group to estimate how much gas is available to all resources. Todd Schatzki, principal at the Analysis Group, presented the firm’s methodology for modeling gas availability.

The consulting firm plans to calculate total pipeline gas availability based on the 50 highest-inflow days since 2021, which marks the last time there was a significant increase in pipeline capacity into the region.

To estimate available supply from LNG terminals, Analysis Group will use an economic model that accounts for weather and temporal variables, which incorporate effects related to the day of the week and time of the year.

Schatzki noted that decisions about LNG releases are dictated by opportunity costs, because LNG terminals typically have a fixed amount of seasonal supply to sell over the course of the winter season.

“Total winter sendout from LNG terminals varies annually based largely on pre-season contractual commitments and to a lesser degree in-season spot cargoes,” he noted, adding that total seasonal LNG procurements affect the amount of gas available from LNG injections on a given day.

While it is difficult to predict total seasonal LNG supply, it is “important to control for annual variation in total LNG sendout,” he said.

To calculate how much of the total LNG and pipeline gas supply is available to generators, Analysis Group will subtract daily non-generator gas demand. It will calculate non-generator gas demand based on a regression model that includes similar weather and temporal variables as are used for the LNG supply calculation.

For ISO-NE resource adequacy analyses, Analysis Group will account for uncertainty in its forecast of total gas supply by calculating the total amount of gas available to generators using 24 simulated load winters. For each winter, the firm will “develop 10 profiles of available gas electric supply representing distribution of uncertainty in estimated available electric supply,” Schatzki said.

Also at the MC meeting, Otto presented ISO-NE’s proposed accreditation framework for energy limited resources, a category that includes oil, jet fuel, kerosene and dual fuel generators.

ISO-NE would determine energy limited status for these resources “seasonally based on their usable fuel inventory levels over the last three seasons,” he said, adding that resources unable to run at their maximum capability for 24 straight hours would be considered limited.

“ISO estimates suggest less than 900 MW of the region’s roughly 12,000 MW of oil, jet fuel, kerosene or dual fuel resources will be considered energy limited in the winter and around 500 MW will be modeled as energy limited in the summer,” he said.

The main accreditation factors for these resources would be maximum capability, forced outage rate and daily energy limit.

Fuel inventory evaluations would be based on an average of the median seasonal inventory levels over the past three years. The RTO plans to allow certain exemptions or special treatment for newly commercial resources or resources that experienced extended forced outages that affected their fuel inventory levels in past winters.

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Pennsylvania Withdraws from RGGI as Part of Budget Compromise

Pennsylvania has withdrawn from the Regional Greenhouse Gas Initiative as part of an overdue budget compromise signed by Gov. Josh Shapiro.

The commonwealth’s participation in the initiative never was established fully, as legal issues delayed implementation. Previous Gov. Tom Wolf signed an executive order putting Pennsylvania on a path to joining RGGI. But the plans were stymied by a lawsuit arguing that legislative approval would be required.

Commonwealth Court Judge Michael Wojcik issued an injunction in 2022, and the case remains before the Supreme Court of Pennsylvania. (See Court Blocks Pennsylvania from Joining RGGI.)

House Minority Leader Jesse Topper (R) criticized RGGI as the most significant issue holding back economic growth.

“Being a part of the Regional Greenhouse Gas Initiative is truly what was keeping energy development out of Pennsylvania, as we were losing jobs to West Virginia and Ohio,” he said in floor comments Nov. 12. “After today, that specter will be gone, and I believe this is a moment we can look to in time that we will say Pennsylvania started to meet its full potential when it came to developing energy.”

Rep. Greg Vitali (D) voted against the budget compromise because of the RGGI rider, saying climate change is one of the most significant long-term threats to the planet. Given the divided legislature, he said climate change bills have little chance of passing.

“RGGI is a tried-and-true program, it is market-based, it has been in effect since 2009. … Since that time, there has been a 46% decline in carbon emissions from the power facilities in those (participating) states and there has been a $9 million investment in clean energy projects for those states,” he said, citing statistics from RGGI. “It’s very disappointing that our governor does not support RGGI, and that is why it is on the chopping block today.”

Environmental groups criticized the agreement. PennFuture called it a “stunning betrayal” of the environment and an initiative that could have brought hundreds of millions of dollars to the state to lower energy bills and promote clean energy.

“Pennsylvania was on the goal line of making meaningful progress toward cleaner air, lower energy costs and reduced pollution,” PennFuture CEO Patrick McDonnell said in a statement. “Instead of finishing the drive, the governor and house Democrats didn’t just fumble the ball, they picked it up and ran it into the opponents’ end zone.”

NRDC Policy Director for Pennsylvania Robert Routh said the state’s participation would have been significant given the scale of its carbon dioxide emissions, which amount to roughly all of the other states participating in RGGI combined. He cited EPA figures finding Pennsylvania fossil fuel generation released just under 78 million tons of carbon dioxide in 2024.

Shapiro proposed an alternative cap-and-trade market limited to the state as part of his Pennsylvania Climate Emissions Reduction Act (PACER) bill. It failed to advance in the 2024 legislative session and was reintroduced in 2025. Given how heavily the language leans on the framework the Pennsylvania Public Utility Commission established for participating in RGGI, Routh said PACER likely would need rewriting to be implemented on its own.

If the state had a binding carbon cap-and-trade price on emissions from power plants, Routh said it would have enabled historic investment opportunities to strengthen local economies and battle climate change effects. He estimated the auction for the third quarter of 2025 would have created as much as $300 million in revenue for the state. The impact could have been even more significant, as data center load growth is expected to accelerate.

“RGGI would have been an incredibly effective tool at both keeping pollution and cost down in the face of anticipated large load growth,” he said.

Advanced Energy United Director of Wholesale Markets Jon Gordon said high capacity prices in PJM likely will spur development in Pennsylvania regardless of its participation in RGGI. The largest barrier for renewables is the amount of time it takes to get through the RTO’s interconnection process.

“As a practical matter, Pennsylvania participation in RGGI has been tied up in court for years, so this shouldn’t have a meaningful impact on project development, particularly given PJM’s high capacity prices, which reflect a significant supply shortfall relative to surging demand for energy,” he told RTO Insider. “With the ‘Lightning Plan,’ Gov. Shapiro has proposed legislation that would help get these projects built faster by speeding deployment and reducing barriers to clean energy investment. Pennsylvania should seize that opportunity.”

Virginia’s beleaguered participation in RGGI is a mirror image of Pennsylvania’s. It joined the initiative legislatively in 2020 and participated in auctions until 2023, when Gov. Glenn Youngkin (R) sought to withdraw through executive order. In November 2024, a judge found Youngkin’s action unlawful, stating that the authority to withdraw was held by lawmakers. That ruling was frozen temporarily in March 2025 when the administration appealed.

Compromise Includes Review of Utility Load Forecasting

The Pennsylvania budget legislation includes a section granting the Public Utility Commission “the ability to investigate methodologies, data and assumptions used by utilities when developing load forecasts submitted to PJM.”

PJM has encouraged state regulators to take a more proactive role in reviewing utilities’ load forecasts, particularly large load adjustments (LLAs), which often include data center projects not captured in the standard economic modeling. PJM’s Critical Issue Fast Path proposal, one of a dozen to be voted on Nov. 19, would add a review to its load forecast process for state commissions to review LLAs.

Routh said there has been a sharp increase in efforts to address the effect large load growth is having on constituents’ bills, with the accuracy of forecasts central to ensuring consumers don’t pay for transmission and capacity that will go unused. He said the language on reviewing utility forecasts rapidly moved from legislative committees into the budget legislation.

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NARUC Report Seeks to Make Headway on Gas-electric Challenges

SEATTLE — A new report from the National Association of Regulatory Utility Commissioners offers state regulators an extensive set of recommendations intended to address risks stemming from the ever evolving interdependence of the natural gas and electric sectors in the U.S.

The release of the 40-page paper by NARUC’s Gas-Electric Alignment for Reliability (GEAR) Task Force was a showpiece at the organization’s annual meeting. The report highlights an issue that has dogged the two industries for over a decade: how to get them to better coordinate their actions to maintain grid reliability.

But progress has been halting, as NARUC Executive Director Tony Clark indicated at the start of a Nov. 11 panel discussion at the meeting.

“Ronald Reagan said the closest thing to eternal life on this earth was a government program, but I’m not so sure. For regulatory offices, the closest thing to eternal life is the gas-electric conversation,” Clark said.

The report’s authors, which included state regulators and executives from gas and electric companies, wrote that “the goal of GEAR was to provide a venue for key regulatory and industry stakeholders to discuss and develop solutions to the reliability problems caused by the misalignment of the gas and electric industries.”

They compared “achieving the highest level of reliability” to obtaining an insurance policy.

“It must be planned and purchased ahead of time; you hope you never need it; and if it is not used, it will invariably look expensive,” they wrote. “It is important for regulators and industry experts to help the public understand that those characteristics do not mean the cost to assure reliability are not prudent investments.”

The report draws on source materials and presentations by a wide swath of energy organizations, such as the North American Energy Standards Board, NERC and its regional entities, FERC, RTOs/ISOs, the Electric Power Supply Association and the Interstate Natural Gas Association of America, as well as BP.

The report outlines nine recommendations for state officials:

    • the creation of a voluntary, ongoing Natural Gas Readiness Forum intended to improve natural gas “value chain reliability via the promotion of communication, peer-to-peer connections, situational awareness and education among its participants.” The task force advised that the American Gas Association lead this effort.
    • support for federal permitting changes to encourage the construction of new natural gas pipeline infrastructure.
    • have states and organized power markets examine ways to increase investment in and development of “storage of all types” to support the grid in times of high demand.
    • encourage regulators to contact their RTOs/ISOs and utilities and review NERC information regarding load shedding practices, and evaluate whether changes are needed given the current electricity consumption landscape.
    • ensure greater liquidity and transparency in natural gas markets around winter weekends, when trading is limited.
    • “in lieu of direct winterization regulations for natural gas production,” examine the “need and feasibility of a market-driven process” that allows utilities and generators to recover costs for premiums they pay for improved winter performance.
    • encourage state regulators and policymakers to support “market-based solutions” to incentivize gas procurement and “provide economic certainty, consistent with recommendations to improve natural gas unit scheduling and dispatch.”
    • consider development of “robust” demand response programs to shift energy use during periods of high demand or system stress.
    • support or adopt measures “that facilitate more timely and frequent use of interstate capacity release or asset management arrangements” by utilities.

“The GEAR Task Force expects the alignment of the gas and electric systems to remain an ongoing challenge for NARUC, its members and industry in the years and decades to come,” the report says. “These recommendations should serve as a backdrop and ongoing point of discussion to assist regulatory agencies and their partners in serving the needs of the natural gas system, the electric grid and utility customers.”

‘An Education’

During the Nov. 11 panel, Clark asked GEAR participants what state regulators should take away from the report.

Georgia Public Service Commissioner, GEAR Chair and outgoing NARUC President Tricia Pridemore said her state already allows electric utilities to roll firm gas transportation and storage costs into their rate base.

“It’s just a part of our customer expectations and how we operate,” Pridemore said. “Developing a path within your state to do the same provides liability assurances and insurance that’s not matched, and that is a path that I think regulators, who fully understand the systems more than our friends in the legislature do, should be communicating now.”

Kansas Corporation Commissioner Dwight Keen said he thinks state governments should take a role in ensuring that the gas and electric industries “provide continuity of attention to the nuances, the methods and the means by which we continually re-evaluate and reassess … the kinds of techniques we can use to really enhance reliability going forward.”

Rhode Island Public Utilities Commissioner Ron Gerwatowski expressed regret that the report contained many recommendations his agency doesn’t have the authority to implement, but he appreciated that it provides “an education.”

“There’s a lot of information that’s confirming things, some of which we know already, but other things that are new,” Gerwatowski said, adding that the report gives regulators additional information to bring into federal proceedings or conversations at RTOs, allowing them to “act as advocates to try to move things along” when gas and electric entities come into conflict.

Arizona Corporation Commissioner Lea Marquez Peterson said the effort offered “a clear realization how different every state is. In Arizona, we don’t have natural gas supply; we’re dependent on neighbors and distribution lines that come through our state.” She said developing the report revealed the level of interdependence among states on gas issues.

Michigan Public Service Commissioner Dan Scripps recommended that fellow regulators take time to understand their utilities’ load shed procedures because it’s “way, way too late” once a state is in an emergency.

Scripps advised also that regulators in organized electricity markets work with RTOs “around scheduling and dispatch as well as the incentives for things like out-of-market support for natural gas purchases.”

Iowa Utilities Commissioner Josh Byrnes said the report is “a script” for having conversations with utilities.

“Sometimes I struggle with what can we do as regulators when it comes to some of these topics — like, some of them feel like they’re beyond our scope, [or] sometimes it feels like it’s more federal level, or it’s just like, where do I fit into the conversation?” Byrnes said. “So I feel like this report is going to help me to start those conversations and try to find that purpose moving forward as a regulator in this issue.”

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Brattle Study Finds Similar PRMs Under Alternative Western RA Footprint

As entities explore alternatives to the Western Resource Adequacy Program (WRAP), a new Brattle Group study examines the impact on planning reserve margins of an RA program encompassing expected participants in CAISO’s Extended Day-Ahead Market.

Brattle prepared the report for the Balancing Authority of Northern California, Idaho Power, the Los Angeles Department of Water and Power, NV Energy, PacifiCorp, Portland General Electric (PGE), Public Service Company of New Mexico (PNM), the Sacramento Municipal Utility District and Seattle City Light.

Those nine entities form a “non-CAISO EDAM” footprint that is the focus of the study. Some of the entities have signed agreements to join EDAM, while others are awaiting regulatory approval to do so or have said they are leaning toward EDAM.

The study simulated winter 2027/28 and summer 2028 planning reserve margins for an RA program covering the non-CAISO EDAM footprint, compared with footprints for WRAP’s Northwest and Southwest subregions.

For summer, Brattle found the PRM was similar among the three footprints, with each falling between 14 and 15%. The authors said summer reliability risks are comparable for the three footprints.

More variability was seen in winter PRMs: from almost 17% for WRAP’s Northwest region to nearly 12% for WRAP’s Southwest region and about 9% for the non-CAISO EDAM region. The authors attributed the non-CAISO EDAM footprint’s lower PRM to higher regional resource diversity.

“The non-CAISO EDAM footprint offers significant resource adequacy benefits, on par with and possibly exceeding the resource adequacy benefit of the current WRAP footprint,” the report authors said.

Planning reserve margin volatility was one concern utilities cited in deciding whether to commit to Western Power Pool’s WRAP or to withdraw from the program.

With an Oct. 31 deadline to commit to the program’s first binding phase in winter 2027/28, WRAP won commitments from 16 entities, while five entities withdrew. (See WRAP Wins Commitments from 16 Entities and 4 Entities Join NV Energy in Exiting WRAP, While Idaho Power Commits.)

Many of those that committed to WRAP plan to join SPP’s Markets+, which requires WRAP participation. But there were exceptions: Idaho Power has committed to WRAP despite saying it is leaning toward EDAM.

NV Energy, PGE and PNM are expected to join EDAM; each announced their withdrawal from WRAP. And in October, NV Energy representatives revealed that talks are underway regarding an alternative resource adequacy program. (See EDAM Participants Exploring Potential New Western RA Program.)

Western Power Pool (WPP) wasn’t involved in the study and hasn’t fully reviewed the results, according to WPP Chief Strategy Officer Rebecca Sexton.

“In our initial review, the study seems to support WRAP’s foundational premise that there is significant benefit to customers from participation in a broad, WRAP-wide footprint,” Sexton said in an email.

Sexton noted that participants representing more than 58 GW of Northwest and Southwest load and a broad mix of resource types have committed to WRAP. She said WPP would welcome proposals based on the study’s findings that would enable study sponsors to participate in WRAP.

Brattle modeled loads and resources for the different footprints for winter 2027/28 and summer 2028.

Looking at planning reserve margins on a monthly basis, Brattle found that PRMs for the WRAP footprints were lower than that of the non-CAISO EDAM footprint in June, and were similar or lower in July. But PRM for non-CAISO EDAM was the lowest among the three footprints in August, which along with July is considered a high-risk month.

For the winter months, the non-CAISO EDAM footprint had the lowest PRM among the three footprints in November, December, January, February and March.

The Brattle study used WRAP’s methodology to look at zonal resource adequacy needs and resource capacity accreditations. Brattle also recommended fine-tuning the WRAP methodology by including transmission limits within the footprints, temperature-dependent thermal outage rates, and improved hydro and weather modeling.

Adding these enhancements to the WRAP methodology “would likely reveal additional risks and yield a more complete assessment of regional RA needs,” the report said.

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BPA Looks to Fill 155 Positions After Hiring Freeze

The Bonneville Power Administration has resumed hiring after workforce reductions as part of President Donald Trump’s efforts to slim down the federal government, Deputy Administrator Suzanne Cooper said during the agency’s quarterly business review.

After receiving authority to fill critical functions, BPA resumed hiring in September and is looking to fill 155 positions. To date, the agency has posted 122 job openings, Cooper said during BPA’s fourth quarterly business review on Nov. 13. Cooper filled in for Administrator John Hairston, who had a scheduling conflict.

“The response has been overwhelming,” Cooper said. “So far, we’ve received more than 3,450 applications, and we’ve made 49 selections. We are ecstatic about the level of interest, especially for positions that are typically difficult to fill.”

BPA staff received a “deferred resignation” buyout offer in January from Trump’s unofficial Department of Government Efficiency, immediately setting off alarms in the electricity sector about the impact on the region’s grid reliability.

About 200 agency employees — or 6% of the workforce — accepted the buyout offer, while 90 job offers had been rescinded following a federal hiring freeze announced Jan. 20, according to BPA. (See BPA Exempted from Federal Staffing Cuts, Hairston Says.)

Despite workforce challenges, BPA continued work on 23 projects as part of a $5 billion portfolio the agency expects will add more than 6,000 MW of transmission capacity. The projects are expected to be completed by 2035, Cooper said.

“When including other planned projects designed to sustain our existing assets, BPA’s total projected grid investment for the next 10 years is approximately $15 billion,” Cooper said.

BPA has launched other initiatives aimed at boosting capacity, such as the Grid Access Transformation Project (GAT), which it launched after pausing certain transmission planning processes to consider changes in how it will tackle 65 GW of transmission service requests. (See Utilities Back Some BPA Transmission Updates, Hesitate on Others.)

“We are also benefiting from the work done in recent years to modify our large generator interconnection process,” Cooper said. “We move to a first-ready, first-served approach that will improve … interconnection queue processing and address backlog. We plan to complete our first generator interconnection cluster study in January of 2026. This cluster study represents 167 customer requests and more than 61 GW of generation.”

BPA’s entrance into SPP’s day-ahead Markets+ in October 2028 will further “optimize the use of our existing transmission and generating assets, as well as give us accurate data regarding our capacity needs, which we expect will help inform future investment,” Cooper added.

BPA hosted the quarterly business review shortly after committing to the Western Resource Adequacy Program’s first financially “binding” season covering winter 2027/28. BPA was one out of 16 entities committing to WRAP’s first binding season. Five utilities withdrew from the program. (See WRAP Wins Commitments from 16 Entities.)

“BPA continued to see the near- and long-term value of the Western Power Pool’s resource adequacy program, which remains one of the largest such programs in the country,” Cooper said. “While a few utilities opted to exit the program, WRAP remains viable and continues to provide critical tools and resources to help address current and future reliability challenges.”

Financial Outlook

Tom McDonald, BPA’s chief financial officer, provided an update during the Nov. 13 call, saying that “despite difficult hydrological conditions, BPA met its key performance indicators this year. The well below-average water supply, however, tested our financial risk mechanisms.”

In fiscal 2025, BPA achieved net revenues of $74 million, $4 million above target. The result largely was driven by transmission service revenues, which came in $22 million over target. However, this is $211 million below the rates-based forecast of $285 million, according to a news release.

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Tribes Urge FERC to Reject Wright’s Hydropower NOPR

Tribes asked FERC to reject a proposal from Energy Secretary Chris Wright to reverse a 2024 rule change that required consultation with them over hydropower projects proposed on their lands (RM26-5).

FERC rejected some pumped hydro facility applications that were for projects in Navajo Nation territory after tribal authorities opposed them and said it would start denying other projects on native lands whenever tribes opposed them. (See FERC Rejects Pump Storage Projects Over Navajo Objections.)

Wright told the commission that eliminating the rule was needed “for America to continue dominating global energy markets.”

“The commission’s longstanding policy has been to grant applications for preliminary permits over the opposition of third parties, such as federal land managers, similarly affected agencies or tribes, as applicable,” Wright wrote in an Oct. 23 letter. “The reason is simple. The commission views preliminary permits as ‘encouraging hydroelectric development by affording its holder priority of application (i.e., guaranteed first-to-file status) with respect to the filing of development applications for the affected site.’”

The preliminary permit only lets holders investigate the feasibility of a project; it does not give them any land-disturbing or other property rights, he added.

Recent orders denying preliminary permit applications because of objections from the Navajo created “an untenable regime whereby it has effectively delegated its exclusive statutory authority to issue preliminary permits to third parties,” Wright said. The letter was accompanied by a Notice of Proposed Rulemaking the secretary filed under Section 403 of the Department of Energy Organization Act that, if approved, would return the rules to the status quo ante.

The National Hydropower Association told FERC in comments filed Nov. 12 that it supports the NOPR because it preserves the ability for developers to protect their early investment in a proposed project, while developers consult with regulators, tribes and other parties on their projects.

“Recognizing the importance of protecting a developer’s critical investments early in the project development phase, years before any revenue stream from the project is secured, the commission should adopt the proposed NOPR and return to its longstanding policy that preliminary permits should be denied only if there is a permanent legal barrier to licensing the project,” NHA said.

Objections raised early in the process lack information on the project’s design, operating parameters and environmental effects, and FERC should not defer to the sentiments of other entities, whether that is a federal land manager, another agency or a tribe, the group argued.

The Navajo urged FERC to reject the NOPR and asked for another month to file more substantive comments.

“The 2024 policy resulted in developers engaging with the Navajo Nation, its political subdivisions and the local communities where the project would be located; obtaining non-invasive access authorization and permission to survey from the Nation under Navajo law; and reapplying for preliminary permits without opposition,” it told FERC. “At least two proposed projects are in the feasibility stages of project development.”

The Choctaw Nation of Oklahoma and Chickasaw Nation filed joint comments opposing the NOPR, saying it directly implicates their sovereign authority over tribal lands, waters and other cultural resources. They also complained about the comment deadline, which gave parties just 12 days to respond to the secretary’s proposal and asked for a 60-day extension and initiation of government-to-government consultation with interested tribes before moving forward.

“Nothing in Section 403 requires the commission to undertake a rulemaking or to adopt the secretary’s suggested regulatory text,” they said.

The proposal conflicts with the Department of Energy’s own “trust responsibilities” to tribes, they argued. The federal trust responsibility applies to all executive agencies and requires that federal actions avoid harming tribal lands and waters, they said.

“By requesting rule changes that would restrict the commission’s ability to consider tribal consent or protect tribal rights in preliminary-permitting decisions, the secretary is advancing an action that is inconsistent with those responsibilities,” the tribes told FERC. “DOE should instead consult with tribes before proposing any regulatory changes that could impact tribal lands or waters.”

While the secretary argued the 2024 policy allows “third parties” to veto permits, the two tribes argued that framing ignores fundamental law.

“Tribal nations are not ‘third parties,’” they added. “They are sovereign governments with federally protected interests in land, water, cultural and other trust resources. These interests are not speculative; they are legally recognized and enforceable.”

Considering a tribe’s authority to control access to its lands or use of its waters is not an improper delegation, but rather FERC performing its duty under the Federal Power Act and other federal law, they said.

The Ute Mountain Ute Tribe also argued that tribes are not third parties, but rather sovereign governments whose lands and resources are held in trust by the U.S. The 2024 policy correctly applied the law, it said.

“DOE’s proposed rule would compel the commission to disregard that obligation by forcing the issuance of permits even when tribes have explicitly withheld consent,” the tribe said. “Tribal opposition is not a ‘veto’; it is the exercise of sovereign authority. By denying permits in those circumstances, the commission honors its trust duty and promotes orderly, cooperative energy development.”

While preliminary permits do not allow developers to disturb any land, they do block tribal governments from pursuing their own developments at sites, which has tangible economic and jurisdictional consequences, the tribe said.

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New York Suspends All-electric New Construction Law

Attorneys for the state of New York agreed in a federal court filing Nov. 12 to suspend the implementation of the All-Electric Buildings Act, which had been scheduled to go into effect in January.

The law would prohibit heating oil and natural gas from being used in new construction, including single-family homes and apartments shorter than seven stories. By 2029 the law would have applied to all buildings with limited exceptions.

The New York State Builders Association, the National Association of Home Builders and trade groups representing the propane industry along with building and plumbing trade unions sued the state in 2023, saying the law violates the federal Energy Policy and Conservation Act, which restricts states from regulating gas in appliances.

A federal court disagreed with the plaintiffs’ claims in July 2025, finding that EPCA did not pre-empt the All-Electric Buildings Act because the state law did not concern the “energy use” of products covered by the federal law. The court found that EPCA stipulated energy efficiency rules, not whether certain fuels were allowed.

The plaintiffs appealed to the 2nd U.S. Circuit Court of Appeals. The appellate court has yet to decide on the case.

New York Secretary of State Walter T. Mosley filed a stipulation agreement to suspend the effective date of the mandate “to avoid further litigation” and “uncertainty during the appellate process.” The plaintiffs in turn agreed to withdraw their motion for an injunction.

The suspension will remain in effect 120 days after the 2nd Circuit rules, if the Supreme Court does not take up the case.

Gov. Kathy Hochul (D) “remains committed to the All-Electric Buildings law and believes this action will help the state defend it, as well as reduce regulatory uncertainty for developers during this period of litigation,” wrote Ken Lovett, a spokesperson for the governor. “Gov. Hochul remains resolved to providing more affordable, reliable and sustainable energy for New Yorkers.”

The law is a key part of New York’s strategy under the 2019 Climate Leadership and Community Protection Act to reduce emissions from fossil fuels over the next 25 years. State energy officials have identified buildings as responsible for one-third of statewide greenhouse gas emissions.

The news comes within a week of the Hochul administration issuing permits for a natural gas pipeline in New York and air permits for a gas plant to power a cryptocurrency mine. (See Permits for Trump-Favored Gas Pipeline Approved by N.Y. and N.J.) Environmental groups have accused the governor of backtracking on climate issues.

“We are deeply discouraged by this unnecessary delay and look forward to this appeal being resolved in a timely manner so this cost-saving, common-sense affordability and clean energy measure can move forward,” John Lindsay, spokesperson for the Building Decarbonization Coalition, said in an emailed statement. “Every day of inaction slows progress toward safer and more affordable new homes and buildings.”

“Gov. Hochul is backsliding on one of New York’s most important affordability and climate laws,” said Michael Hernandez, New York policy director for Rewiring America. “Now, she’s using litigation as cover to delay the All-Electric Buildings Act.”

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MISO to Include Southeastern Texas in South Long-range Tx Planning

MISO announced it will honor a request from Texas regulators and include southeastern Texas in its first long-range transmission study for MISO South.

The grid operator earlier said it would start the process of drawing up planning studies for areas of Louisiana with heavy load pockets, marking the first long-range transmission plan for MISO South. (See MISO Kicks off South’s Long-range Tx Plan with More Restrained Approach.) Now a portion of Texas will be part of the equation.

MISO Executive Director of Transmission Planning Laura Rauch confirmed that Texas regulators approached MISO to request that part of the state be included in the study and that MISO agreed.

Speaking at a Nov. 11 Entergy Regional State Committee meeting, Rauch told South state regulators that MISO’s approach to South long-term system planning would differ from the planning conducted in MISO Midwest.

Rauch said MISO Midwest had several years of membership before MISO proposed the first, $10 billion long-range transmission portfolio in 2022 followed by the second, $22 billion portfolio in 2024.

“That journey took many, many years in the Midwest. … While I can’t guarantee the outcome, I know the outcome will look very, very different in the South than in the Midwest,” said Rauch, who emphasized different planning needs in MISO South.

Rauch said that over the course of 2026, MISO will assemble a study scope for Louisiana and Texas, build system models and hold discussions around potential needs in the South.

“It’s very likely that we’ll need to do additional analysis,” Rauch said. “Really, the goal is to practice the conversation around long-term needs.”

Rauch said MISO “may have to divide and conquer on” which issues to tackle first and could focus first on Louisiana before turning its attention to possible projects in southeastern Texas.

“My goal is for information at this point, not necessarily a certain amount of transmission approved,” Rauch said.

Arkansas Public Service Commission consultant Keith Berry asked if MISO has considered how to divide the costs of the projects.

Rauch said cost allocation negotiations “realistically” arise only when transmission needs are named. However, she said the first MISO South long-range planning — being limited to Louisiana and Texas — likely won’t require the region-wide postage stamp to load cost allocation used in MISO’s other long-range transmission portfolios.

“I will say with a focus on two states, I don’t see a need for a multivalue project cost allocation,” Rauch said.

Rauch said she doubted that “engineering studies won’t show sufficient value spread” across the entire South region.

Texas utilities Commissioner Courtney Hjaltman previously said she intended to ask the MISO board to include Entergy’s Texas footprint when it begins work on a long-range MISO South plan.

“My request will be to include Texas, as we obviously have load growth that we need to have included in that study,” Hjaltman said at the Oct. 23 Texas Public Utility Commission meeting.

Asked by an audience member why MISO’s focus is on Louisiana, she said, “They are trying to really home in on certain areas and include Louisiana, and specifically New Orleans, which obviously had a load shed event this past summer, and that might be why, but there’s just no reason that Texas shouldn’t be included.”

At the Entergy meeting, Berry asked where MISO stands on launching a planning study aimed at increasing transfer capability between MISO South and MISO Midwest.

Rauch said at this point, MISO believes operational fixes and increased coordination on the transmission contract path are the best way forward. MISO no longer talks about a fourth long-term transmission plan portfolio, which it once said might result in an expansion of Midwest-South transmission.

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IMM Advises Better Constraint Management After MISO Tx Emergency

MISO’s Independent Market Monitor said a MISO South September transmission emergency shows the RTO needs a better handle on constraint management within its markets.

MISO declared a local transmission emergency around 1 p.m. ET on Sept. 16 after a 500-kV transmission line was forced offline in MISO South. The IMM said the sudden outage forced two constraints into violation and congestion costs rose to $12 million.

“MISO was successful in avoiding a load shed,” MISO Independent Market Monitor staffer Robert Sinclair said during a Nov. 11 Entergy Regional State Committee meeting. He said MISO “successfully utilized the available supply to maintain reliability through the event.”

MISO confirmed that a local transmission emergency occurred in MISO South on Sept. 16.

Sinclair said MISO manually dispatched some generation to manage violated constraints and made additional resource commitments that sent some resources into their emergency ranges to increase supply by more than 700 MW.

However, Sinclair said the IMM is finding in its initial investigation that MISO should improve its transmission constraint demand curves so that the market dispatches generation instead to manage constraint violations. He said while MISO’s manual dispatch actions were effective, they are more expensive than letting the market take the wheel.

Outages of 500-kV lines in MISO South “have increased in frequency in 2025 and triggered more frequent transmission emergencies,” Sinclair added.

He promised a fuller report on the events and the IMM’s recommended course of action at the upcoming MISO Board Week in December in Indianapolis. There, MISO leadership can respond to the recommendation.

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MISO Re-examining Monthlong Outage Limit for Capacity Resources

MISO has signaled an openness to alter its 31-day planned outage rule for units that signed up to be capacity resources.

MISO said it experienced significantly more outages in summer 2025 compared to recent years, “which contributed to tight system conditions.” The upsurge has MISO revisiting its generator planned outage rules.

MISO expects capacity resource owners to either procure replacement capacity or pay penalties if they are offline for more than 31 days in a season. They must notify the RTO 120 days in advance of planned outages to be exempt from capacity accreditation reductions.

Davey Lopez, manager of market design resource planning, said MISO will examine whether its outage rules are rewarding availability, as MISO intended, and determine if they need an overhaul. At a Nov. 12 Resource Adequacy Subcommittee meeting, Lopez said MISO now has three planning years of data to evaluate the impacts of its move to seasonal capacity auctions and outage rules.

The RTO’s 31-day outage rule has been in effect since FERC approval in August 2022.

WEC Energy Group’s Chris Plante said he believes generation owners aren’t as concerned about their forced outage rates anymore under MISO’s availability-based capacity accreditation. Other stakeholders agreed that unit owners are less worried about their forced outage rate and more preoccupied with being available during the predefined risky hours in a season, which MISO has placed a premium on per its availability-based accreditation.

Lopez said MISO’s evaluation would look for “unintended consequences” and assess whether the ruleset “continues to provide the proper incentives for resources to be available during the periods of highest reliability risk and prudent planned outage scheduling.” He stressed that MISO doesn’t yet have any revisions in mind.

Lopez said he would appear before the RA Subcommittee in early 2026 for more discussion.