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December 10, 2025

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FERC Report Urges West to Address Looming Market Seams Issues

A new FERC report adds to the growing body of work showing the complexity of confronting the seams issues likely to arise between the West’s two day-ahead markets when compared with challenges at the borders between RTOs and ISOs in the Eastern U.S.

In their white paper “Seams Coordination in the Western Interconnection,” released Nov. 21, FERC staff urge Western electricity industry stakeholders to get ahead of seams issues before CAISO’s Extended Day-Ahead Market (EDAM) and SPP’s Markets+ both go live, scheduled to occur in 2026 and 2027, respectively.

And the authors recommend steps the two market operators can take to manage the myriad challenges — mostly unique to the West — related to the existence of seams between the markets.

The authors acknowledge the analyses already published on the issue, saying their report is intended “to support the ongoing discussions among stakeholders and highlight the importance of collaboration by relevant parties to address these complex issues.” (See ‘Islanded’ BAs Face Tough Choices in Western Market Future, Experts Say and Western Market Seams Issues to Differ from East, Study Finds.)

“These seams can create operational and reliability hurdles that arise from several related issues: overlapping transmission ownership and rights, differences in transmission modeling, and congestion caused by loop flow,” they said. “The same issues could diminish the economic benefits of EDAM, [CAISO’s Western Energy Imbalance Market], and Markets+ by limiting the ability to trade across markets.”

The paper outlines the history of seams coordination in the Eastern Interconnection, including the development of congestion management processes and market-to-market agreements typically wrapped into the joint operating agreements among RTOs such as PJM, MISO and SPP, and their neighboring non-market areas. Those JOAs include provisions for handling emergency energy flows between balancing authorities and managing trades across boundaries, such as through coordinated transaction scheduling (CTS), FERC staff noted.

The paper points to two efforts already underway to address seams issues in the West.

The first, not directly related to the two markets, is the joint work by CAISO’s RC West and SPP RC to propose improvements to the Western Interconnection Unscheduled Flow Mitigation Plan to the North American Energy Standards Board.

In April 2024, NAESB’s Enhanced Curtailment Calculator (ECC) Task Force — which includes members from both reliability coordinators — issued a white paper describing the problems with current unscheduled flow mitigation practices in the West. It explained that the region’s BAs and transmission operators largely rely on their own individual methods to resolve unscheduled flows, meaning that transmission customers on one system might experience curtailments for different reasons than similarly situated customers on a different system. To remedy the problem, the task force recommended expanded use of the ECC tool to bring more uniformity.

The second seams effort underway is the Markets+ Seams Working Group (MSWG), as well as work undertaken by other working groups helping to develop that market.

“From its inception, the MSWG was charged with supporting the development of seams coordination frameworks and identifying potential seams-related tariff content; early discussions on the working group’s scope included import/export and wheel-through issues and congestion management topics,” the paper says.

At the direction of the Markets+ Participant Executive Committee, the MSWG in 2024 began developing the Seams Strategy and Roadmap, designed to identify focus areas for policies and governing documents related to seams issues with neighboring areas.

Going to Flow-based Modeling

In the paper, FERC staff called out “three primary categories of issues that Western entities should consider addressing through seams coordination agreements,” including:

    • use of flow-based modeling rather than contract path modeling;
    • coordinating interchange between market areas to prioritize maintaining reliability and managing congestion; and
    • coordinating electricity flows to maximize economic efficiency.

On the modeling issue, the authors note that transmission availability in the West is mostly modeled on contract path-based models that assume flows on contracted paths between generation sources and load sinks, compared with the flow-based approach in the East that relies on a flowgate methodology to calculate available transfer capability (ATC).

“Because flow-based modeling uses actual power flows to model the transmission system, it is generally considered to be more efficient and robust than the contract-path based methodology,” FERC staff wrote, adding that use of the two methods is “inconsistent” across the West.

“The continued use of contract path-based modeling and the use of different modeling methodologies may complicate efforts to maintain reliability, mitigate congestion and enhance economic benefits in the Western Interconnection. Thus, before discussing more specific approaches to coordinating operations in the West, it is important to ensure that the transmission availability and usage metrics these markets rely on be modeled as consistently and accurately as possible,” they wrote.

Adoption of flowgate modeling would have two benefits, they said: more accurate estimation of ATC and “better coordination across seams during day-ahead and real-time operations by market operators and BAs.”

Given that EDAM and Markets+ will rely on transmission capacity being made available by market participants rather than transmission owners handing over control of their systems as in a full RTO, FERC staff said, “flow-based modeling of ATC could provide a more accurate view of how much transmission is actually available to allocate between the markets compared to the results of contract path-based modeling prior to the actual day-ahead and real-time market runs.

“Western entities could investigate whether this would ease longer-term transmission expansion needs and make more transmission available for day-ahead and real-time market optimization.”

Managing Reliability, Congestion

On the subject of coordinating interchange between markets, FERC staff called the process a “key tool” in maintaining reliability and managing congestion.

“Agreements that formalize interchange procedures during critical system conditions between markets, as well as those between markets and non-markets, have generally provided greater certainty to system operators and improved cooperation between BAs. These include agreements such as emergency energy agreements, reserve sharing arrangements and JOAs,” they wrote.

The paper recommends that Western entities consider how reliability agreements across seams address data and model coordination, emergency event protocols, and loop flow management.

FERC staff wrote that the expansion of centralized markets in the West “introduces new challenges and opportunities for managing congestion between markets areas as well as between markets and non-markets,” with EDAM and Markets+ schedules potentially causing loop flows that extend beyond their borders.

To limit the effects of congestion, the paper recommends the adoption of M2M coordination, which seeks to reduce congestion at the lowest cost through the sharing of market pricing data between two RTOs/ISOs to bring about the most efficient redispatch.

Economic Trading Across Seams

The paper says cross-seam coordination of electricity transfers for cost savings likely will take on different forms in the West than in the East.

Part of that has to do with the differences between how EDAM and Markets+ deal with bidding at their interties with non-participating BAs.

Under existing WEIM and EDAM rules, participating BAs can decide whether to allow non-resource specific bidding at their interties with non-participating BAs. In Markets+, intertie economic trading will be implemented uniformly along its seams, allowing participants to submit buy and sell offers for imports and exports as long as they have the necessary transmission rights — an approach the authors say “could facilitate more economically efficient trading across its seams.”

FERC staff suggest that Western market operators could implement coordinated economic trading between their two areas. That might entail a practice such as CTS, which allows market participants to use a single portal to submit bids based on spreads between delivery points on either side of market seam.

The market operators also could implement “some form of interchange optimization” that gives them visibility into each other’s system and pricing for each trading interval. That approach would allow market participants to submit bids within their own markets, with the operators then using that information to determine whether they can meet their needs most economically from their own resources or from transfers out of a neighboring area based on transmission constraints and other factors.

The FERC paper did not explore another complicating factor for the Western markets compared with the East: the highly fractured boundaries between EDAM and Markets+ that likely will effectively island some participants — particularly in Markets+.

During a meeting of CAISO’s Western Energy Markets Regional Issues Forum in April, Richard Doying of Grid Strategies, one of the designers of the MISO market, noted that non-contiguous market zones “will require drive-out, drive-through and drive-in transmission service and schedules,” an arrangement that will require new types of transmission service and coordination to avoid diminishing the value the markets are intended to bring.

“The complex seams arising in the West from the expansion of Western markets presents challenges to operations, reliability and the efficiency of the markets,” FERC staff wrote in the conclusion of their paper. “To address these challenges, FERC staff believe it is important that Western entities continue their work coordinating operations to ensure the reliability and efficiency of their markets and BAs as Western markets proceed toward implementation and in advance of live operations.”

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Collaboration Key to Energy Affordability, Say U.S. and Canadian Officials

BOSTON — Energy affordability and regional collaboration dominated talks at the New England-Canada Business Council’s annual Executive Energy Conference on Nov. 19-20.

While the event featured similar themes and rallying cries as the 2024 conference, calls for collaboration have taken on a different tone amid heightened tensions between Washington and Ottawa. (See US, Canadian Leaders Discuss Affordability of Energy Transition.)

Massachusetts Gov. Maura Healey (D) and Nova Scotia Premier Tim Houston both attended the event and emphasized the strong ties between the people and economies of the Northeast states and provinces.

“Our energy future is inextricably tied to Canada’s,” Healey said, noting that states and provinces are in regular communication on energy policy and planning through the Northeast International Committee on Energy, which reconvened in 2024.

She highlighted a resolution passed at the Annual Conference of New England Governors and Eastern Canadian Premiers during the prior weekend reaffirming “the importance of continued regional collaboration, including interregional information sharing, planning and analysis on energy matters.”

“We look forward to continuing to build on that and to strengthen the ties that bind us, especially on energy transmission,” she said.

Healey directly criticized the tariffs imposed by President Donald Trump for creating “needless friction” between the countries and driving up costs throughout energy infrastructure supply chains.

Massachusetts Gov. Maura Healey | © RTO Insider 

“Higher infrastructure costs ultimately make higher energy costs for our people, and it’s our businesses, our consumers and our residents who lose out,” Healey said. “Lift these tariffs, Mr. President, and lower housing costs and lower energy costs for the American people.”

Houston also touted the strength of cross-border relationships in the Northeast while emphasizing his commitment to transforming Nova Scotia into an “energy superpower.” The province has outlined plans to scale up offshore wind and offshore oil and gas drilling, with an eye toward ramping up its exports.

“Nova Scotia is the next frontier in generation,” Houston said. “As long as I’m in this chair, I will do everything I can to grow this industry.”

Several presenters spoke about the massive potential for wind generation in the province. According to the strategic plan for the province’s Wind West project, “Nova Scotia’s already studied and identified sites alone [that] have the capacity to generate 62 GW of new electricity supply, with capacity factors of up to 60%,” equal to about a quarter of Canada’s total energy capacity.

The Canada-Nova Scotia Offshore Energy Regulator has initiated a process of issuing licenses to develop up to 3,000 MW across three areas, while leaving the door open for licenses up to 5,000 MW.

Houston said he is confident about the viability of the sites, ports, workforce and matureness of the technology to support a large-scale wind buildout but acknowledged that questions remain about how to transport the power to markets in Canada and the U.S.

Dave MacGregor, associate deputy minister for the Nova Scotia Department of Energy, said he is “struck by the fact that we were talking about the exact same things 25 years ago — and I’m referring specifically to transmission.”

But despite the challenges of the past, he expressed hope that renewed collaboration efforts finally could make transmission projects a reality.

“For the first time in close to three decades, the staff are coming to Nova Scotia to figure this out,” MacGregor said. “I really have seen marked improvement, and I do see a path where New England can benefit and Canada can benefit.”

Transmission paths to New England or Quebec could follow either submarine or overland routes. Several panelists at the conference advocated for a subsea path.

“We would say submarine cable all day long,” said Donald Jessome, CEO of Transmission Developers Inc. “There’s no engineering issues; the technology is there today.”

Stuart Nachmias, CEO of Con Edison Transmission, agreed that the technology is available to support a submarine line but said there are challenges related to siting, permitting and offtake.

“Who’s going to pay? That’s always the issue,” Nachmias said.

Phil Bartlett, chair of the Maine Public Utilities Commission, concurred, emphasizing the importance of understanding what the costs would be and how they would be shared.

“It’s going to take regional collaboration. I think you would need multiple states interested in a project to move forward,” Bartlett said.

He expressed optimism about the recent increase in collaboration between the states on transmission issues, pointing to the ongoing ISO-NE Longer-term Transmission Planning (LTTP) procurement, which aims to reduce transmission constraints in Maine and help support the connection of 1,200 MW of onshore wind. (See ISO-NE Provides More Detail on Responses to LTTP Procurement.)

The newly established LTTP process includes a cost allocation framework, in which the costs of a solution selected by ISO-NE will, by default, be allocated by load share. The states have the option to submit an alternate cost allocation method or terminate the process.

In coordination with the LTTP solicitation, Maine has initiated a separate process to procure onshore wind in northern Maine and a transmission line connecting the generation to a new substation that would be created through the LTTP process.

Bartlett said he expects at least five of the six New England states to participate in this separate procurement, adding that “having the states working together on these procurement issues really helps to get it done.”

Bartlett said that 1,200 MW of onshore wind “is just the “tip of the iceberg of what’s available in Maine,” and that “we consider this Phase 1 of that buildout, recognizing there’s a lot more to do.”

‘Build, Baby, Build’

Some speakers called for increased efforts to address the infrastructure constraints that limit the flow of gas into New England.

Toby Rice, CEO of the EQT, praised the Trump administration’s energy policy approach and stressed the need to build more gas infrastructure to “win this AI race.”

“I don’t want to find out what happens if we don’t win this race,” Rice said.

It will be won, he said, by the country that can scale up generation most quickly. He noted that China is adding power at a far faster pace than the U.S.

“It’s no longer about ‘drill, baby, drill’; it’s about build, baby, build, and we’re hopeful that permitting reform will be a priority over the next 12 months,” Rice said.

He said the growth of intermittent renewables has caused gas resource capacity factors to decline, putting strain on the economics supporting gas generation in some areas. To address the issue, he advocated for increased incentives for gas resources to be available on standby.

At the same time, he opposed capping capacity prices, saying, “We have to experience a little bit of pain for the market signals to be there.”

John O’Brien, CEO of JERA Americas, said industry leaders should do more to advocate for adding gas pipeline capacity into the Northeast.

Business groups, such as the Associated Industries of Massachusetts and regional chambers of commerce, “have to be re-energized to actually take on those issues,” O’Brien said. “You should take on an agenda, and the agenda might be controversial, but that’s why you pay the big dues.”

He said New England “should recognize that we need this infrastructure to continue to have our key industries” and pushed back on the idea that it is a foregone conclusion that the gas constraint will prevent the region from hosting data centers.

“Are we going to say, ‘We’re going to forgo that opportunity because we would have to expand the gas system?’” O’Brien asked.

Other speakers focused their comments on the importance of demand-side actions and reining in spending on upgrades to existing assets.

Weezie Nuara, Massachusetts’ deputy secretary for federal and regional energy affairs, emphasized the “need to add transparency and scrutiny” to local transmission spending. She said ISO-NE’s recent work to establish a new in-house asset condition reviewer should “help us get our hands around the largest component of [transmission] spending.” (See More Oversight Needed on Local Transmission Spending in NE, Panel Says.)

From left: Sarah Tracy, Pierce Atwood; Liz Anderson, Massachusetts Department of Public Utilities; Christine Bonnell-Eisnor, Canada-Nova Scotia Offshore Energy Regulator; Phil Bartlett, Maine Public Utilities Commission; and Joshua Walters, Connecticut Department of Energy and Environmental Protection | © RTO Insider 

Massachusetts Department of Public Utilities Commissioner Liz Anderson noted that, under state law, electric utilities cannot charge ratepayers for long-term gas pipeline contracts. She said the DPU is focused on addressing affordability through the means within its jurisdiction, including demand-side actions and scrutiny on infrastructure spending.

In recent years, the DPU has pursued an ambitious strategy promoting a phased electrification of the state’s gas distribution network. (See Outgoing Mass. DPU Chair Van Nostrand Discusses Gas Transition.)

Advocates of this strategy argue that, without a focus on strategic electrification and pipe decommissioning, gas customers will be saddled with a rapidly increasing share of the gas network’s fixed costs as electrification customers exit the system.

In an op-ed published in the Boston Globe on Nov. 17, former DPU Chair Jamie Van Nostrand wrote that gas supply, which accounted for about two-thirds of customer costs a decade ago, now makes up less than a third. Meanwhile, “roughly 70% of the bill pays for infrastructure, profits and taxes,” he argued.

Anderson emphasized the importance of investment in energy efficiency and advanced metering infrastructure (AMI). The Massachusetts electric utilities aim to complete their deployment of AMI infrastructure by 2029. Once in place, the meters likely would enable development of time-varying rates that incentivize customers to reduce demand during peak periods.

“That’s a huge untapped resource, and I think that’s something we can do at the state level,” Anderson said.

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FERC Mostly Accepts Calif. IOUs’ Order 2023 Compliance Filings

FERC largely approved filings by California’s three major investor-owned utilities to comply with interconnection queue requirements under Order 2023 (ER24-2776, ER10-1391-003 and ER24-3032).

In three separate orders Nov. 20, FERC mostly accepted Southern California Edison, San Diego Gas & Electric and Pacific Gas and Electric’s tariff revisions, but the utilities must clarify some issues within 60 days.

In SCE’s case, FERC ordered the utility to file revisions related to storage operating assumptions, network upgrade cost allocation requirements, site control, the definition of regulatory limits and cluster study provisions.

On the operating assumptions, SCE argued it did not need to include those because it already offered similar provisions for electric storage resources under a commission-approved settlement agreement.

FERC rejected this argument, siding instead with renewable energy company Terra-Gen and the California Energy Storage Alliance (CESA), which contented the settlement agreement “is expressly conditioned on future compliance with commission orders.”

“Terra-Gen and CESA explain that while the settlement agreement has a moratorium prohibiting revisions to SoCal Edison’s tariff, there is also an exception allowing changes to be made if directed by a commission order or a final rule, such as Order No. 2023,” FERC said.

The two protesters asked FERC to reject SCE’s proposed revisions and direct the utility to revise its tariff to allow interconnection customers to provide operating assumptions for storage resources, according to the order.

FERC agreed, stating that “SoCal Edison has failed to adequately justify excluding the requirement for transmission providers to use operating assumptions, at the request of the interconnection customer, in interconnection studies that reflect the proposed charging behavior of an electric storage resource.”

“We are evaluating the order and are pleased to see much of our proposal approved,” Jeff Monford, spokesperson for SCE, told RTO Insider.

Meanwhile, in the SDG&E docket, CESA, along with the Clean Energy Alliance, San Diego Community Power and the Clean Coalition, also filed objections.

In one matter, CESA objected to SDG&E’s proposed rules regarding affected systems, arguing that they “are insufficiently detailed and could give rise to discriminatory practices.” FERC said it was “unpersuaded” by CESA’s arguments, finding that the utility included “requirements for circumstances where SDG&E is the host service provider.”

But the commission did order SDG&E to file revisions related to network upgrade cost allocations, commercial readiness and regulatory limits.

FERC likewise required PG&E to clarify or correct provisions pertaining to co-located generating facilities, operating assumptions, cluster study and site control, among other issues.

CESA contended PG&E failed to “provide interconnection customers with electric storage resources with the ability to design and charge their facilities in a manner sufficient to satisfy their proposed operating parameters,” according to FERC. The organization argued PG&E failed to explain how it would review interconnection customers’ requested operating assumptions or whether the company would allow customers to operate in accordance with those assumptions after entering service.

FERC noted that some of CESA’s concerns should be addressed by PG&E in its subsequent compliance filing but that its “concerns about PG&E not describing how it will analyze requested operating assumptions or allowing additional flexibility for interconnection customers to adopt control technologies are outside the scope of this compliance filing because these requirements were not established in Order No. 2023.”

The utilities said in their filings that they must navigate between Order 2023 requirements as well as their CAISO tariffs. FERC noted this and pointed to overlap in, for example, cluster study requirements in both CAISO and Order 2023.

PG&E spokesperson Jennifer Robison told RTO Insider that “FERC’s order will help expedite interconnection of wholesale generation on markets managed by [CAISO].”

“This is an important step in meeting CAISO’s load forecasts, which project significant electric demand growth in California driven mostly by new data centers, EV charging and building electrification,” Robison added. “We look forward to continuing to work with CAISO and other stakeholders on additional improvements to the interconnection process.”

FERC issued Order 2023 in July 2023 with the goal of clearing backlogged interconnection queues by implementing a first-ready, first-served cluster study process; increasing interconnection customers’ financial obligations; and penalizing grid operators for missing study deadlines. (See FERC Partly Accepts SPP’s Order 2023 Compliance.)

In 2024, the commission rejected challenges to the order, though it made several clarifications and minor modifications and established an extended compliance deadline with Order 2023-A. (See FERC Upholds, Clarifies Generator Interconnection Rule.)

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House Natural Resources Committee Advances Permitting Bills

The House Natural Resources Committee has passed a package of permitting legislation, which includes reforms to the National Environmental Policy Act meant to speed up the deployment of infrastructure.

The main bills, including the SPEED Act (H.R. 4776), had bipartisan co-sponsors. Committee Chair Bruce Westerman (R-Ark.) and Rep. Jared Goldman (D-Maine) cosponsored the SPEED Act, which cleared the committee 28-15.

“The committee took an important bipartisan step toward lowering energy prices for hardworking Americans and building critical projects,” Westerman said in a Nov. 20 statement. “The increasing demand for electricity and critical minerals is fueling new investments, and federal permitting laws must keep up. The SPEED Act eliminates bureaucratic delays that hinder projects and restores NEPA to its original purpose.”

The bipartisan support for NEPA reform is a victory for government efficiency, economic growth and lower energy bills, he added.

The SPEED Act seeks to speed up the processing time for permits at agencies and limit opposing litigation to parties directly affected by projects. It requires lawsuits to be filed within 150 days of a permit being issued.

Golden introduced an amendment, which was approved by the committee unanimously, that would block the executive branch from revoking permits for projects once they have been approved.

“Both parties have agreed on this problem for years, and today’s support from the committee gives me hope that Congress is finally ready to take the win,” Golden said. “I’m grateful to Chairman Westerman for his commitment to earning bipartisan support for our bill, and I’m ready to get this passed on the House floor.”

Golden and Republicans said presidents of both parties have used their authority to pull permits for projects that were underway. While that will not be possible should the package become part of a broader bill that passes Congress, many Democrats said it was not enough.

Rep. Seth Magaziner (D-R.I.) said during the mark-up hearing Nov. 20 that he was happy Golden’s amendment passed, noting that his state has faced the issue with the Revolution Wind project. (See Judge Lifts BOEM’s Stop-work Order on Revolution Wind.)

“All across the country, from solar projects in Nevada to onshore wind in Idaho, the Trump administration is indiscriminately canceling projects that have already been fully permitted and approved, showing that they care more about culture wars than lowering costs for Americans,” he said.

Magaziner submitted an amendment that would have made the language Golden submitted retroactive to Jan. 20, 2025, covering all the projects the administration has blocked since taking office.

“If we do not adopt my amendment, not only will clean energy projects already being held up by the administration not be covered, but also any other projects that they decide to block from now until final passage of the bill,” Magaziner said.

The amendment was not agreed to, meaning the prohibition against yanking approved permits would go into effect only when the SPEED Act becomes law.

The desire to address the Trump administration’s actions against clean energy projects goes well beyond Democrats on the committee: The 104-member Sustainable Energy and Environmental Coalition, the 116-member New Democrat Coalition and the nearly 100-member Congressional Progressive Caucus released a joint statement saying it was a pre-requisite for any permitting package.

“Ensuring that clean energy projects are treated fairly and can move forward where appropriate is the prerequisite for serious, practical negotiations on a reform package capable of meeting the nation’s energy needs,” the statement said. “Additionally, to be comfortable with any sort of agreement, we need to be able to trust that this administration is going to follow the law that we write.”

The committee opposition to the SPEED Act came from Democrats, with ranking member Jared Huffman (D-Calif.) saying the bill effectively guts NEPA.

“This bill is so extreme that there’s simply nothing left in a meaningful way of NEPA if this were to become law,” Huffman said. “Now, Democrats are very interested in working constructively in problem solving. We would love to have a meaningful conversation, but it has to start with ending the war on clean energy, which this bill does not do in any significant way.”

Several other bills cleared the committee, including the ePermit Act (H.R. 4503) from Reps. Dusty Johnson (R-S.D.) and Scott Peters (D-Calif.). The bill codifies how federal agencies should implement electronic permitting systems.

“The ePermit Act moves us toward a modern, efficient, fully digital permitting system that will cut red tape, and today’s passage brings us one step closer to delivering results faster,” Peters said. “As energy costs continue to rise across the country, it’s important we meet the growing demand for electrification, data centers and clean-tech manufacturing.”

Peters has backed reforms to how electric transmission is sited, which is under the Energy & Commerce Committee’s jurisdiction. That is one of the other committees, in addition to the Senate, working on permitting legislation. (See Bipartisan Transmission Permitting Reform Bill Introduced in House.)

ITC Holdings is one of hundreds of firms and interest groups that endorsed the SPEED Act. RTO Insider interviewed its director of federal affairs, Devin McMackin, on the prospects for legislation passing the full Congress in 2025.

“The real limit on when things can get done this Congress is as we get closer to the midterms,” McMackin said. “So, there will come a point when, certainly it will be harder to make a bipartisan deal. But I think there’s time now for Congress to do that, and it’ll depend on a lot of things. But we are cautiously optimistic that there’s a window of time right now that kind of goes into the beginning part of next year where something could actually get done.”

The SPEED Act would help the major transmission upgrades being planned in the MISO and SPP, he added.

“I think it’s reasonable to foresee that there are some number of these projects, especially the greenfield ones, that are going to need to traverse some sort of federal land or some sort of protected area,” McMackin said. “And then that, of course, triggers federal reviews under NEPA and other environmental laws, and the potential for there to be litigation, because there usually is whenever there’s sort of federal permitting processes happening.”

The SPEED Act does not render NEPA toothless environmentally. Rather, it provides better clarity for how agencies can review projects and places limits on litigation.

“Litigation is kind of the thing that can really hold up projects when you have sort of injunctions and starts and stops and things like that, and that can also really raise the cost of projects, which we’re very conscious about as well,” McMackin said.

The American Clean Power Association also supported the SPEED Act. CEO Jason Grumet said it would create key milestones throughout the permitting process that provide greater certainty for developers.

“The SPEED Act reforms are necessary to develop all forms of American energy infrastructure enabling a comprehensive response to soaring energy demand,” Grumet said in a statement. “Absent these improvements and additional efforts to support pipeline and transmission infrastructure, energy prices will spike and system reliability will be threatened.”

The Sierra Club, Earthjustice and the Union of Concerned Scientists all signed onto a letter, along with about 100 other environmental groups from around the country, in opposition to the SPEED Act.

“The urgency many feel to accelerate this buildout [of better transportation systems, more affordable housing, semiconductor fabrication facilities, transmission lines, renewable energy and more] is well founded, but the SPEED Act takes exactly the wrong approach,” the letter said. “We cannot simply deregulate our way to a smarter, more efficient permitting system. Stripping away safeguards does not create better processes or stronger projects. It only invites more mistakes, conflict and harmful development.”

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CPUC Approves PG&E Cancellation of University Electrification Project

The California Public Utilities Commission approved a request to cancel Pacific Gas and Electric’s contract with California State University, Monterey Bay to convert hundreds of the university’s residential units from gas and electric service to all-electric service.

The project between PG&E and CSU Monterey Bay included retirement of about eight miles of existing natural gas piping and installing electric-only service and equipment at about 1,200 dwellings. As part of the project, the university would have waived its right to receive gas service in the future, said the decision, approved at a Nov. 20 voting meeting.

The project would have addressed customer safety needs, long-term rate affordability and customer energy preference, and would have aligned with California’s climate goals, PG&E said in its application.

PG&E originally introduced the project as a case study in “how a utility can use building decarbonization as a tool to both reduce emissions and promote long-term gas ratepayer affordability,” the decision says.

The company’s original application showed that electrification instead of new gas infrastructure would have resulted in “net present value of approximately $1 million to benefit utility customers,” the Natural Resources Defense Council said in a filing.

“This is in addition to the climate and air quality benefits of these investments, and the avoided risk of future stranded assets,” the NRDC said in the filing.

But in January, PG&E requested to withdraw the project application due to safety concerns, specifically around plastic fusion failures on the existing gas piping system. These failures needed to be repaired or replaced by Dec. 15, 2026.

However, PG&E said 2026 was the earliest year the regulatory approval process for the project would have concluded. This timeline would be too late to safely remediate the piping issues, the decision notes.

The NRDC disagreed with PG&E’s request, saying the investor-owned utility did not prove the timing of the project was infeasible.

CPUC ruled that it is “reasonable and in the public interest” to grant PG&E’s motion to withdraw the project application: The terms agreed to by PG&E and CSU Monterey Bay allow either entity the option not to pursue the project at any point, the decision says.

CPUC ordered PG&E to submit a lessons-learned report that summarized ratepayer impacts and operational experiences associated with the canceled project, the decision says.

SCE Reliability Contracts Approved

At the meeting, CPUC approved eight Southern California Edison contracts with energy storage and solar generation facilities as part of SCE’s midterm reliability request for offers to cover the agency’s 2023-2028 resource procurement compliance requirements.

The battery storage and solar facilities have capacities between 20 MW and 238 MW and are expected to start providing energy in 2026 and 2027, according to the resolution.

The contracts are part of CPUC’s Decision 21-06-035, which required load-serving entities to procure 11,500 MW of midterm reliability capacity.

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MISO TOs Oppose Tx Cost Containment Suggestions

Multiple transmission owners have questioned the need behind a suggestion that MISO work more checks into its process for reviewing troubled transmission projects.

MISO transmission customers have asked MISO to use a 20% cost overrun on transmission projects in progress to trigger the RTO’s variance analyses. That would take the place of the RTO’s existing 25% over-budget threshold. MISO uses its variance analysis to reassess transmission projects that experience significant cost increases or other obstacles.

The group of transmission customers asked MISO to involve its Board of Directors with project reviews and decisions on transmission projects. They’ve also suggested MISO draw on third-party experts to decide projects’ fate.

After it wraps up a variance analysis, MISO can decide either to let projects stand as-is, develop a mitigation plan for them, cancel projects or assign them to different developers if possible.

At a Nov. 18 stakeholder cost allocation meeting, Ken Stark, with the Coalition of MISO Transmission Customers, said that although transmission construction is needed, it must be done in an affordable manner. Stark has advocated for tighter rules around the variance analysis since late 2024. (See End Users Push MISO for More Intensive Cost Overrun Evals on Tx Projects.)

“It’s top of mind for regulators right now,” Stark reasoned. He pointed out that SPP uses a 20% cost overrun to trigger reviews.

ITC’s Cynthia Crane criticized the proposal for borrowing some of SPP’s transmission cost containment process while ignoring key components. For instance, she said the 20% threshold SPP uses to re-examine projects is applied later, only after cost estimates are much more concrete than MISO’s preliminary estimates.

Further, Crane said the SPP board is much more directly involved with day-to-day operations, having to sign off on tariff changes before they’re submitted to FERC. The MISO board, on the other hand, takes a self-proclaimed “noses in, fingers out” governance approach, she said.

Stark said the board could have a “discreet and focused” role that doesn’t drastically expand its authority.

MISO’s Jeremiah Doner said the RTO provides frequent updates on the status of transmission projects. He said the board is not “hands off” when it comes to transmission development.

Stark said it then “makes sense” for the board to have a say in transmission projects that have hit a snag, given that the board approves MISO’s annual transmission expansion plans.

Crane said MISO’s End-Use Customer sector is “cherry picking” pieces of SPP’s process.

“I fail to see how the proposal you’re proposing is adequate,” Ameren’s Justin Stewart added.

Other stakeholders said MISO’s 25% cost overrun threshold had stakeholder backing and would be more appropriate than borrowing another RTO’s approach just for the sake of it.

The Planning Advisory Committee will take written stakeholder opinions on the proposed variance analysis edits through early December and hold a special meeting on Dec. 16 for further discussion on the topic.

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MISO South Regulators Ready to Strike Out on Their Own for Tx Cost Allocation

MISO South states have signaled their intent to strike out on their own on a cost allocation design for long-range transmission projects located exclusively in the South subregion.

South regulators proposed their own cost allocation design process under FERC’s Order 1920, which could produce a cost-sharing plan that could override MISO’s recommended allocation for new transmission projects. (See State Regulators Weigh Drafting Alternative to MISO Tx Cost Allocation.)

During a Nov. 18 MISO teleconference, New Orleans City Council attorney David Shaffer, representing MISO South states, introduced the proposal southern regulators put together.

“What’s envisioned is the state agreement process would apply to long-range transmission projects in the MISO South region,” Shaffer explained.

Shaffer emphasized that the MISO South state agreement process document is simply a framework to be used to design a cost allocation, not a cost allocation methodology itself.

According to the document, the South’s design process would last no longer than six months after the MISO Board of Directors approves a slate of long-range projects.

The document instructs MISO South states to devise cost allocations that are roughly commensurate with estimated benefits. It also stipulates that benefit estimations should meet the Entergy Regional State Committee’s criteria of “accurate, objective, measurable, quantifiable, non-duplicative, forward-looking, replicable and supported by data.”

Participation in the development of and votes on cost allocation methods would be limited to relevant state entities, Shaffer said. However, state entities could agree unanimously to designate more organizations to participate in the process.

Some MISO stakeholders said the document was ambiguous as to when the design process would start.

FERC’s Order 1920 directs RTOs to involve states when developing or amending a long-term regional transmission cost allocation. It gives states the go-ahead to meet independently to negotiate and devise cost allocation methods to offer to FERC in place of RTOs’ methods.

MISO must file the state agreed-upon allocation alongside its own suggested allocation, even if it doesn’t agree with it. MISO previously said its established, 100% postage stamp to load allocation could work for South long-range planning. The RTO changed its stance after it announced that the first MISO South long-range planning effort would be limited to Louisiana and a portion of Texas. MISO leadership said they couldn’t picture using a subregional postage stamp allocation on a load-ratio basis for projects limited to just two states.

MISO South’s Entergy Regional State Committee has said it won’t support any postage stamp aspect in MISO’s long-range transmission allocation.

Prior to Order 1920, the Entergy Regional State Committee Working Group proposed an allocation in early 2024 for upcoming MISO South long-range transmission plan portfolios. It involves assigning 90% of costs based on adjusted production cost savings and avoided reliability projects; the remaining 10% would be charged to new generation that interconnects in MISO South based on a flow-based methodology. (See Entergy States Debut Long-range Tx Cost Allocation Proposal, MISO Members Unconvinced.)

Clean energy nonprofits have said Entergy and MISO South’s preferred approach isn’t broad enough and will leave the South continuing to build expensive local projects that don’t yield regional benefits. (See Clean Energy Orgs Push Entergy Players to Consider Broader Cost Allocation.)

MISO’s Jeremiah Doner said MISO will review the South state agreement process when it’s finalized around March 2026. He said the South’s allocation process will “have to be memorialized” in MISO’s tariff as part of Order 1920 compliance.

MISO’s Order 1920 compliance filing is due to FERC in June 2026.

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FERC Winter Outlook Warns of ‘Tight’ Conditions

FERC staff expect “grid operators will have adequate generating resources to meet demand across the United States under normal conditions” during the coming winter months, presenters said at the commission’s monthly open meeting Nov. 20.

However, “difficult to predict” severe weather events “could create tight supply conditions” in some areas and require operational mitigations to avoid reliability issues, they warned.

Presenting FERC’s 2025-2026 Winter Energy Market and Electric Reliability Assessment, Eric Primosch, of the Office of Technical Reporting and Economics, told commissioners the National Oceanic and Atmospheric Administration predicts higher-than-average temperatures across most of the southern continental U.S. for the winter months of December, January and February. Only in the northernmost states are mildly lower-than-average temperatures expected.

For this reason, the U.S. Energy Information Administration predicts the number of nationwide heating degree days — a metric that measures how cold a given location is by comparing its average outdoor temperatures to a reference temperature — to drop by about 8% from the previous winter.

Multiple states in the West and Southeast U.S. also either are likely to develop drought conditions over the winter or to see current droughts continue, Primosch said. These dry conditions “could significantly reduce hydroelectric output in WECC, disrupt fuel deliveries and impair cooling for power plants in the Central U.S., and elevate wildfire risk across the country,” he said.

Despite the warmer conditions, and a slight expected increase in natural gas production from last year, Primosch said gas prices are expected to be higher at most hubs than they were last winter. Henry Hub futures averaged $4.39/MMBtu as of Nov. 4, up 26% from last winter’s settled average of $3.49/MMBtu. FERC’s report attributed the rise to growing demand for gas in the South-Central region.

In its seasonal temperature outlook, NOAA forecast higher-than-average temperatures across most of the southern continental U.S. | NOAA

Possible explanations for rising prices at other hubs include competition with other regions for LNG at the Algonquin Citygates hub, potential supply constraints at Transco Zone 6, and infrastructure constraints at both SoCal-Citygate and PG&E-Citygate in California. However, gas storage inventories stood at 3,915 Bcf at the beginning of the withdrawal season, near the top of the five-year range, and are expected to “remain relatively robust through winter,” helping to moderate price volatility.

Solar, Batteries Lead Capacity Additions

On the electricity side, Shannon Zaret of OTRE told commissioners that EIA predicts total electricity consumption of 1,035 TWh this winter, slightly less than the 1,041 TWh recorded the previous winter but still higher than the five-year average.

Zaret said the greatest use is expected in the residential sector, at 387 TWh, followed by commercial users at 359 TWh and industrial at 254 TWh.

Electricity usage in the commercial sector is projected at 5% above its five-year average, Zaret said, with EIA attributing the rise in part to data centers in the PJM region.

EIA forecasts the electric sector to have new generation capacity totaling 64.7 GW this winter, comprising 25.7 GW of generation completed between March and November and 39 GW expected between December and February 2026. The new generation is offset by 2.4 GW of retirements already completed by November and 6.2 GW of further retirements expected by February. Most of the retirements are coal-fired plants, while solar generation accounts for half of the capacity additions and batteries 30%.

NERC Senior Engineer Robert Tallman shared a summary of the ERO’s Winter Reliability Assessment, published Nov. 18. (See NERC Winter Reliability Assessment Finds Many Regions Facing Elevated Risk.) That report found that several subregions face elevated risk for outages this winter if they experience severe weather, with the highest risk in the WECC Northwest and Basin subregions, ERCOT, SERC Reliability’s Central and East subregions, and the Northeast Power Coordinating Council’s New England and Canadian Maritime Provinces subregions.

Asked by FERC Chair Laura Swett whether gas production in the U.S. will “keep pace” with demand this winter, Primosch said the elevated production, along with precautions taken by producers, gave cause for optimism.

“We’ve seen producers really focus on improving winterization … in terms of preventing equipment failure [and] wellhead freeze-offs, [and] really trying to maintain as much production as possible on their system during these winter weather events,” Primosch said. “This strategy was effective last winter, as we saw the collaboration of producers, pipelines [and] storage operators all work together to help meet peak record demand, [and] we expect that to be the case again this winter.”

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FERC Ends Nonpublic Investigations into Winter Storm Uri

FERC said Nov. 20 it has closed its enforcement investigations into possible unlawful activity related to 2021’s Winter Storm Uri, just a few months before the statute of limitations on the issue is to expire.

The storm knocked out power across much of Texas for days, leading to hundreds of deaths, and caused massive electricity price spikes there while driving up natural gas costs across a broad swath of the country.

FERC and NERC quickly released a report on the reliability issues in ERCOT in November 2021, which included recommended changes to winter reliability standards that since have been put in place. (See FERC, NERC Release Final Texas Storm Report.)

The commission released its fiscal 2025 Report on Enforcement at its regular meeting Nov. 20, but earlier versions of the report for 2023 and 2024 explained some of the nonpublic investigations into activity around the storm.

The 2023 version explained how FERC dropped a probe into a natural gas marketer that cited a “force majeure” clause to stop the sale of gas to one customer, which was sold to another, but the agency lacked evidence to move forward on any allegation. Then-Chair Willie Phillips said additional investigations were ongoing. (See FERC Enforcement Report Details One Closed Probe into Winter Storm Uri.)

The 2024 version of the report detailed a couple of other cases FERC opened and then closed without action. One involved market manipulation in the gas sector in which a firm contacted a price index reporter to remove a price on the lower end from their indices during the storm after learning it would have a significant positive financial effect on the company.

Another one involved a probe into a company doing business in CAISO that was alleged to have withheld physical energy during Uri and at other times to drive up prices and secure firm contracts, but it was closed due to a lack of evidence.

FERC does not name the targets of its investigations unless it decides to move forward with a settlement or other enforcement actions.

“I would not speak to any nonpublic investigations before the commission makes them official,” Chair Laura Swett said at post-meeting press conference. “There’s a reason for that regulation: It’s to protect the entities before we come up with a conclusion, and they are given appropriate due process.”

FERC has five years after an event to move forward on cases, which means it would have to do so on any Uri investigations within the next three months — but the agency confirmed that will not be happening.

The storm has sparked many civil lawsuits, and utility customers around the country still are paying for its costs, which in some areas have been securitized over many years in rates to spread out price spikes.

FERC lacks any authority over ERCOT’s market and a state court has found the Public Utility Commission of Texas followed the law in keeping prices at the $9,000/MWh cap throughout the week of outages. (See Texas Supreme Court Rules for ERCOT, PUC During Uri.)

Other lawsuits have targeted natural gas market participants, but many of them involve the intrastate markets in Texas and Oklahoma, which are important even outside those states. In 2023, the 5th U.S. Circuit Court of Appeals ruled that FERC could not fine BP for trades on the Texas gas system during a 2008 event. (See FERC Approves Smaller Fine for BP After 5th Circuit Decision.)

One lawsuit filed by CirclesX Recovery against many major natural gas firms contends that widespread withholding of gas during Uri caused its price to spike from about $2/MMBtu to $208/MMBtu at Texas’ Waha hub and to as high as $1,200/MMBtu at unregulated nodes on the intrastate natural gas system. That suit is pending at the Texas 1st Court of Appeals.

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IESO Open to Broader Range of Storage Technologies in Long Lead-time Procurement

IESO is considering a broader range of long-duration energy storage technologies in its upcoming long lead-time procurement but will not include hydroelectric redevelopments, officials told stakeholders at an engagement session Nov. 19.

ISO officials also said they are considering changes to a termination provision and additional flexibility on outages.

IESO created the long lead-time procurement (LLT RFP) because energy storage resources such as compressed air and pumped hydro require longer planning cycles than the four-year lead times for resources offering in the pending Long Term 2 (LT2) procurement. The ISO plans to seek 600 to 800 MW of capacity and up to 1 TWh of energy from resources requiring at least five years of lead time in a solicitation expected about Q4 2026.

The energy stream of the LLT RFP will be open to new build hydroelectric facilities with a nameplate capacity of at least 1 MW that do not include pumped storage. LDES projects will be eligible for the capacity stream.

Eligible Technologies

IESO’s Jasdeep Kahlon | IESO

In response to stakeholder requests for greater flexibility, IESO said it is considering increasing the limit on Class II LDES technologies to 200 MW from 100 MW and lowering the minimum to 10 MW from 50 MW.

Stakeholders said the proposed 50-MW minimum project size and a 100-MW cap would limit the procurement to only one or two LDES projects. Stakeholders proposed minimum project sizes as low as 1 MW.

“Most likely, with the current setup, we would be procuring only one project,” acknowledged IESO’s Jasdeep Kahlon. “However, we maintain that the need for a cap is required to limit risk related to these less proven technologies.”

Kahlon said the ISO doesn’t see the benefit of dropping the minimum size below 10 MW, “as the minimum size requirement is intended to ensure participation from commercial-scale projects and not intended to procure less proven pilot-scale technologies.”

Hydro Redevelopments

The ISO also rejected participation by hydro redevelopments, saying it has received limited information about potential projects and noting that “historical redevelopment timelines are highly variable,” with some taking up to six years and others being completed in less than four years.

It also said there is “little evidence to justify” the 40-year contracts planned for the LLT procurement for hydro redevelopments and said such projects should seek 20-year contracts under the LT2 RFP scheduled for early 2026. (See IESO Officials Deny Favoring Gas Resources in Upcoming Procurement.)

Optional Termination

At an engagement session in October, the ISO said it would seek to reduce risks in the procurement by reserving the right to reject proposals that are too expensive and allowing the ISO and generation developers to cancel deals in the first few years. (See IESO Seeks to Manage Risks in Long Lead-time Procurement.)

The ISO said the termination option could be exercised by IESO or the project developer in the first two or three years after the contract date.

Stakeholders said the termination option would increase developers’ risk and make financing more expensive, while reducing participation levels. They also said it could discourage participation by Indigenous communities that “typically invest in projects with a high likelihood of reaching commercial operation and generating long-term revenue.”

The ISO said it would specify the circumstances that could result in a termination — such as failure to meet key milestones or obtain permits — and the date on which the optional termination right would lapse. It also is considering the termination payment that would apply when IESO or the supplier terminates and whether suppliers that terminate projects would be eligible for future procurements.

Reserve Prices

IESO proposed to use reserve prices — a confidential price threshold — to ensure it doesn’t pay too much for energy or capacity in the solicitation. The ISO said the thresholds will be based in part on prices in the first window of the LT2 procurement and differences in the obligations of LT2 and LLT resources.

Many stakeholders opposed the proposal, saying prices from recent IESO procurements are not a good comparison due to the lifespans of the technologies procured.

The ISO said reserve prices will ensure the procurement is cost effective and broadens Ontario’s supply mix while addressing the uncertainty of developing LLT resources. “The potential benefits associated with long lead-time resources, along with the longer lifetimes, will be considered in the determination of a reserve price,” it said.

Outages

IESO said it is developing a proposal to provide additional flexibility for “mid-term extended outages” and aligning them with annual planned maintenance outage requirements for LDES technologies. IESO had proposed a single outage of up to 12 months after the 20th anniversary of the contract. (See IESO Ups Capacity Target for Long Lead-Time Resources.)

Stakeholders told IESO it should consider permitting suppliers to take outages beginning after year 10 of the contract term and allow them to take multiple outages adding up to 12 months. Some said technologies using mechanical storage, such as compressed air energy storage (CAES) and pumped hydro, should be able to take an annual planned outage for up to 10 business days, similar to that for natural gas generators under the LT2(c-1) contract.

Early In-service Provisions

ISO officials said they may allow developers to begin commercial operation before the planned commercial operation date (COD). The request would have to be filed no earlier than three years after the contract date and at least one year before the expected COD. Commercial operation could be no earlier than five years after the contract date.

IESO approval would depend on deliverability and system needs (e.g., Annual Planning Outlooks showing a need for energy arising earlier than capacity).

Environmental Approvals and Permitting

Because some LDES technologies are new to Ontario, the ISO said developers should consult early with the Ministry of Environment, Conservation and Parks regarding the environmental assessments and permitting requirements that will apply.

Team Member Experience

Kahlon said IESO is considering providing more flexibility to the team member experience requirements.

Under IESO’s proposal, hydro developers must have at least two team members with experience with a hydro facility with a nameplate capacity of at least 1 MW that has achieved commercial operation in Canada or the U.S. within the past 15 years.

Stakeholders said the proposed requirement may create obstacles for mature resource types such as pumped hydro because no such projects have been commissioned within the past 15 years.

IESO may allow developers to begin commercial operation before the planned commercial operation date. The request would have to be filed no earlier than three years after the contract date and at least one year before the expected COD. Commercial operation could be no earlier than five years after the contract date. | IESO

“For pumped storage projects, the requirement to have developed a ‘same technology’ project should include conventional hydroelectric facilities, as pumped storage is a direct variant of hydroelectric generation and the relevant development expertise is transferable,” Andrew Thiele, senior director policy and government affairs for Energy Storage Canada, said in written feedback.

Jim Beamish, head of planning and analysis for Access Capital Corp., said requirements should be functional, as they were in the early 2000s when Ontario started procuring wind and solar generation.

“I recognize your concerns,” Beamish said, “but the ISO really needs to look back at that and say, ‘Well, what didn’t work?’ Because … there have been no CAES projects that reached commercialization in in the last 15 years.”

“The intent here is definitely not to limit participation through team member experience,” responded IESO’s Danielle D’Souza. “It’s really meant to just ensure that we have the best chance of these projects getting across the finish line.”

Municipal Support Resolutions

Paul Ernsting, of Peterborough Utilities, said it may be challenging for developers to obtain required support resolutions from municipalities because of 2026 elections.

“If you’ve got less than three-quarters of council coming back, then that’s a lame duck period. They don’t do any decision-making during that period,” he said.

“You’ve got your elections happening Oct. 26. Once everyone’s elected, they don’t start meeting until mid- to late November at the earliest. … That can be a tight timeline for this procurement, as well as for LT2 window two.”

D’Souza welcomed the feedback. “We’ve heard that it’s very different from municipality to municipality,” she said.

Next Steps

The IESO asked stakeholders to comment on the LLT RFP by Dec. 3 using the feedback form posted on the engagement webpage.