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December 5, 2025

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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.

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MISO Draft Tx Planning Futures Envision 400-GW Supply or More by 2045

MISO predicts it will have anywhere from 383 GW to 454 GW of installed capacity in its footprint by 2045, according to a preliminary version of its 20-year planning futures.

MISO charted resource totals at 383 GW, 403 GW, 446 GW and 454 GW for its Futures 1-4, respectively. The grid operator makes capacity expansion predictions under its 20-year planning scenarios, which help decide which long-range transmission projects are useful. This time around, MISO’s predictions contain more natural gas generation and fewer renewable energy resources.

At a Nov. 18 stakeholder teleconference to debate the futures, Director of Economic and Policy Planning Christina Drake said they “limit all-in costs to members” while respecting states’ and utilities’ decarbonization goals and still being able to serve peak demand and meet planning reserve margin targets.

MISO has been constructing its planning futures for more than a year. It paused in mid-2025 to recalibrate the generation expansion assumptions in its futures after the Trump administration revoked tax credits for renewable generation. (See MISO Seeking Realistic Gen Buildout for Tx Planning Futures.)

Drake said MISO will perform more sensitivity analyses to test whether the four futures are “broad enough.” MISO plans to use sensitivities to test other assumptions, like more load hyperscalers than MISO anticipates in its updated load forecast, a drop in cost for small modular reactors or long-duration storage, the reinstatement of renewable tax credits or natural gas prices that rise faster than expected.

Drake said MISO would not adjust members’ stated resource plans to test assumptions, considering those plans set in stone. She has said “MISO will not be putting its finger on the scale” by changing planned units.

MISO Independent Market Monitor David Patton has suggested MISO introduce a sensitivity that contemplates cost caps on members’ decarbonization goals. Patton reasoned that utilities would not spend infinite amounts of money to meet their clean energy goals when they have shareholders to answer to.

Drake said MISO will share its chosen sensitivities in December.

MISO said it will incorporate its growing load into the futures and plans to include data from its long-term load forecasting pilot program. (See MISO Rationalizes Load Forecasting Pilot Program.) According to early results, MISO could have an additional 64 GW to serve within 20 years.

Sustainable FERC Project’s Natalie McIntire asked how MISO would capture the “uncertainty” behind the rise in large loads, where some may not materialize.

Clayton Mayfield, manager of MISO’s economic planning team, said MISO would evaluate its stakeholder sources of data to figure out which large-scale load projects plan to minimize their needs. He also said MISO would use a project certainty ranking for loads, with a “high” classification for publicly known load projects in development with known locations, a “medium” ranking for loads under study and included in MISO’s long-term forecast and “low” for loads still in talks and unreported in the long-term forecast.

MISO’s first, most conservative future would include only high-certainty loads, while the second, middle-of-the-road future would include high- and medium-certainty projects. MISO’s most aggressive fleet change scenario would include all potential load growth.

Mayfield said MISO is using a siting process for load additions similar to its capacity expansion process to depict load locations.

Bryn Baker, senior director at the Clean Energy Buyers Association, requested MISO consider that some large loads bring their own co-located or behind-the-meter generation to the table to aid their needs.

WPPI Energy’s Steve Leovy similarly asked MISO to consider that some loads might be interruptible or construct on-site generation.

Finally, MISO won’t include Louisiana’s previous goal to reach net-zero greenhouse gas emissions by 2050 in its futures. At a late October workshop, Drake said MISO had “active discussions” with Louisiana officials and was told the Louisiana goals have been discontinued.

“Probably for the entire expansion, it’s not going to move the needle much,” Drake said.

MISO will hold more futures stakeholder workshops Dec. 17, Jan. 29 and Feb. 26.

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PJM Stakeholders Reject All CIFP Proposals on Large Loads

The PJM Members Committee voted against each of the dozen proposals brought to address rising data center load as part of the RTO’s Critical Issue Fast Path (CIFP) process. (See PJM Stakeholders to Vote on Large Load CIFP Proposals.)

The proposal from the Southern Maryland Electric Cooperative (SMECO) was the highest vote-getter at a special MC meeting Nov. 19, receiving 46.66% sector-weighted support, still falling short of the two-thirds required for endorsement. It was followed by the Independent Market Monitor’s proposal at 39.88% and PJM’s at 38.66%. The voting was advisory to the RTO’s Board of Managers, which expressed its intent to file changes with FERC in December to be effective for the 2028/29 Base Residual Auction (BRA).

Addressing the committee after the vote, PJM CEO Manu Asthana said those goals stand, and more detail around timing will be forthcoming. Though there was no winner among the packages, Asthana said there was plenty of information for the board to review from the input shared during the meeting preceding the vote, the last to be held as part of the process.

The CIFP meeting, during which each of the sponsors presented their proposals to the board, lasted much of the day, beginning at 9 a.m. and stretching past its 2 p.m. scheduled end time, pushing the MC’s meeting to start at 3:45 p.m. The CIFP meeting was closed to the media, and there was no discussion on the packages themselves during the MC meeting before the vote opened.

RTO spokesperson Jeff Shields said the board plans to act in the next few weeks.

“PJM opened this conversation about the integration of large loads and greatly appreciates our stakeholders for their contributions to this effort,” he wrote in an email statement. “The stakeholder process produced many thoughtful proposals, some of which were introduced late in the process and require additional development. This vote is advisory to PJM’s independent board. The board can and does expect to act on large load additions to the system and will make its decision known in the next few weeks.”

The SMECO package adopted the changes sought by PJM, including changes to the pricing and dispatch of price-responsive demand (PRD), the addition of state reviews of large load adjustments and an expedited interconnection track (EIT) for state-sponsored projects. Both SMECO’s and PJM’s proposals would shift PRD to an energy market strike price, rather than a dynamic retail rate, but SMECO proposed a $1,000/MWh limit and PJM would set it at $1,849/MWh.

The PJM proposal also would align PRD dispatch with demand response by requiring it to respond regardless of bid price, subject it to performance assessment interval (PAI) penalties and mirror their 30-minute energy bid price caps. SMECO would subject PRD participants to Capacity Performance penalties only if the resource is dispatched when the strike price or PAI conditions have not been met and require that they have supervisory control over the load and the ability to curtail.

The EIT would create a 10-month process for resources of at least 250 MW and nonrefundable study deposits of $10,000/MW for projects paired with large loads and doubled for standalone development. They would require letters of support from the governor or utility commission for the state they are sited in, which is intended to avoid expending limited resources for studying requests on projects that will be mired in permitting and siting challenges at the state level. Only 10 projects would be allowed to proceed each year.

The RTO’s executive summary of its package included a request for the board to initiate a second phase of the CIFP process focused on changes to the reliability backstop and incentives for large loads to bring their own generation or participate in DR programs.

Board Chair David Mills said it will work to assemble a proposal that makes sense of all the information provided throughout the CIFP process.

PJM Board of Managers Chair David Mills | © RTO Insider

“It’s been an arduous journey to get to this point. I’m actually not surprised we got such disparate accounts on all of these proposals. … Just because none of these passed does not mean the board will not act,” he said.

During an open-ended discussion following the MC’s regular monthly meeting Nov. 20, Mills said he could envision changes to the CIFP process. One possible change could be adding milestones throughout the process if there are many proposals being considered.

Tom Rutigliano, senior advocate at the Natural Resources Defense Council, said the board has difficult decisions ahead of it to ensure that data center growth is not subsidized by the public.

“The growth of data centers is colliding with the reality of the power grid. PJM members weren’t able to see past their commercial interests and solve a critical reliability threat. Now the board will need to stand up and make some hard decisions. We hope they fulfill their obligation to 67 million people and commit to protecting reliability, not subsidize data centers at public expense, and treat all customers fairly,” he said in a statement.

“The public faces a $163 billion bill through 2033; and the region could suffer multiple rolling blackouts each year. If the board doesn’t step up, the region won’t be able to meet record demand and will suffer declining reliability for years to come.”