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December 11, 2025

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ISO-NE Talks CAR Gas Constraints, Seasonal Risk Split, Impact Analysis

ISO-NE continued work on the second phase of its Capacity Auction Reform (CAR) project with NEPOOL members Dec. 9 and 10, discussing modeling of the region’s gas constraints, seasonal auction design and its approach to evaluating the impacts of the auction changes.

Discussions around the CAR project are poised to take up a large portion of NEPOOL technical committee meetings throughout 2026. The second phase of CAR centers around resource accreditation changes and splitting annual capacity commitment periods (CCPs) into six-month winter and summer seasons.

The accreditation changes will likely be the most controversial aspect of the project, as the changes would directly affect how much capacity each resource can sell in the market. ISO-NE is aiming to complete the seasonal and accreditation design by the end of 2026.

Steven Otto, manager of economic analysis at ISO-NE, discussed the RTO’s current thinking regarding the development of a gas capacity demand curve, which would be intended to account for the “shared physical constraints” limiting gas resources’ ability to access gas during cold periods.

As envisioned by ISO-NE, the gas demand curve would reduce how much gas resources are paid for their capacity relative to other resources during the winter season. Gas capacity backed by firm supply contracts would not be subject to the curve but would likely affect the amount of gas available to remaining non-firm capacity.

The RTO “will construct a non-firm gas capacity MRI [marginal reliability impact] curve by measuring the reliability impact of substituting incremental megawatts of non-firm gas capacity with other capacity in the system,” Otto explained.

He added that, “in conjunction with the simultaneous clearing of the systemwide demand curve, the intersection of the gas capacity supply and demand curves determines how much non-firm gas-only [capacity supply obligations] will be awarded and how much less that CSO will be paid.”

The gas demand curve process would be separate from the accreditation process for gas resources; gas accreditation values would be determined largely by forced outage rate, maximum capacity and deliverability.

To determine how much gas is available to gas-only generators, ISO-NE plans to rely on modeling by the Analysis Group, which presented the initial results of its study of the region’s winter gas constraints at the meeting. The consulting firm estimated the hourly energy supply for gas resources based on 10 modeled winters intended to represent the full range of supply scenarios.

On cold days, defined as heating degree days (HDDs) at or above 45 — which equates to temperatures at or below 20 degrees Fahrenheit — the amount of available gas-only capacity averaged 4,516 MW, with a minimum of 469 MW and a median of 4,416 MW. On warmer days, available capacity averaged 6,794 MW, with a minimum of 776 MW and a median of 7,013 MW.

Gas resources did not face constraints during most days with an HDD below 45. Generation capacity equaled 8,384 MW during these days.

Responding to stakeholder questions, Todd Schatzki, principal at the Analysis Group, said the company did not find major geographic differences in access to fuel, noting there is a complex array of supply inputs to the gas system during tight system conditions.

He said it is difficult to accurately quantify local constraints, adding that constraints on the Algonquin G-Lateral appear to affect just two gas-only plants and about 5% of gas-only capacity.

ISO-NE’s proposed gas demand curve would apply equally to all non-firm gas capacity, but some stakeholders have argued that some resources are better situated geographically to access pipeline gas during tight days and should not be treated as equal to more constrained gas capacity.

The RTO plans to update the gas constraint modeling annually to account for changes in the amount of gas available to generators.

Seasonal Market

In the shift to a seasonal capacity market, ISO-NE is proposing to “employ a similar approach to setting seasonal NICR [net installed capacity requirement] values and the corresponding demand curves” to the approach it uses in the current annual capacity auction format, said Chris Geissler, director of economic analysis at ISO-NE.

ISO-NE plans to split its loss-of-load expectation (LOLE) of 0.1 days per year into seasonal LOLEs set at 0.05 days per year. This is intended to maintain the one-day-in-10-years standard.

The RTO would calculate the seasonal NICR based on the amount of capacity needed to meet the LOLE requirement.

“This means, at the corresponding NICR values, the resource adequacy model predicts the same number of expected loss-of-load events in summer and winter,” Geissler said. Although the frequency of events would be the same, the severity and duration of events would likely differ, he noted.

Several stakeholders expressed concern that evenly splitting LOLE between winter and summer seasons could cause the region to under-procure capacity in the summer and over-procure in winter.

Geissler said ISO-NE does not expect the proposed LOLE distribution to skew demand curves, saying the risk split should not have significant impacts on seasonal capacity costs. He said ISO-NE will work to provide more examples in future discussions on the topic.

Impact Analysis

Geissler also introduced ISO-NE’s proposed approach to evaluating the market impacts of the proposed suite of CAR changes. He said the impact analysis will focus on identifying differences between modeled results using current auction rules and CAR auction rules.

ISO-NE presented an initial impact analysis for its Resource Capacity Accreditation project in May 2024 before the RTO suspended the project, incorporating it into the broader CAR effort. (See ISO-NE: RCA Changes to Increase Capacity Market Revenues by 11%.)

ISO-NE plans to split the impact analysis into two main focuses: changes to the amount of capacity resources can sell, and changes to market clearing outcomes, he said. The RTO plans to look at metrics including clearing prices, capacity costs, cleared capacity by resource type and season, and revenues by technology type.

He noted it will be difficult for ISO-NE to predict supply offers for all resource classes amid the changing market design and broader changes in the energy landscape, including a potential increase in Pay-for-Performance risk.

To address the issue of uncertainty, the RTO plans to rely on a “consistent set of assumptions to derive offer prices,” which should “help to provide an apples-to-apples comparison between the current rules and CAR cases and reduce the impact of over- or underestimating offer prices,” he said.

ISO-NE plans to evaluate “multiple sets of offer prices to reflect the uncertainty of how resources may offer going forward and clearly articulate the basis for each to help participants develop their own expectations about market outcomes,” he added.

Geissler said ISO-NE will try to incorporate stakeholder-requested scenarios and analyses, but he noted “the considerable stakeholder interest and the resource-intensive nature of this work” may make it hard to follow through on all requests.

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SPP Board OKs Updated 2025 Transmission Plan

SPP’s Board of Directors has approved an updated assessment of the RTO’s 2025 transmission plan that corrects two minor errors and will re-evaluate a third project recently designated as a competitive upgrade.

Staff told the board during its Dec. 9 virtual meeting that two projects were inadvertently left off a list of approved construction permits: a new 345/115-kV transformer embedded in a larger Southwest Public Service project in West Texas, and a North Texas Electric Cooperative zonal planning criteria (ZPC) project that had an incorrect lead time when the assessment was drafted. (ZPC projects are not eligible for regional funding.)

The projects have been reviewed, verified for inclusion and recommended for notifications to construct (NTCs), staff said. The board agreed and approved the NTCs, along with the updated 2025 Integrated Transmission Plan.

The approval will add $48.1 million in costs to the ITP, amounting to a rounding error given its $8.6 billion price tag. The board approved the original plan in November after trimming several of its proposed 765-kV projects. SPP has said the portfolio’s regional benefit-to-cost ratios are between 12:1 and 18:1, the highest in the RTO’s planning history. (See SPP Board Approves 2025 ITP with 4 765-kV Projects.)

The board also approved staff’s recommendation to re-evaluate a 115-kV competitive upgrade out of the same ITP in the SPS service territory. Staff said SPS requested a re-termination of the project from a line tap to a substation about “2 miles down the road.”

Casey Cathey, vice president of engineering, also asked for a pause in the project’s request-for-proposals process, saying SPP has “worked through” some of the facilities through the RFP framework.

“This re-evaluation does not change the [FERC] Order 1000 classification. It doesn’t change the needs that are addressed, and it does not change the need date either,” Cathey said. “It is simply a termination refinement.”

He said SPS will submit updated cost estimates for the project’s noncompetitive portions. SPP designated portions of the project as competitive upgrades Dec. 3.

“It should be quite cost competitive compared to the original project, but we would like to go through that re-evaluation process,” Cathey said.

The Members Committee unanimously endorsed both recommendations, with two combined abstentions.

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CAISO, SPP Explore Using Existing Tools to Manage DAM Seams

CAISO and SPP have made “significant progress” on adapting existing tools to tackle seams between the two entities’ respective day-ahead markets, according to a CAISO representative.

Anna McKenna, vice president of market design and analysis at CAISO, discussed seams between SPP’s Markets+ and the ISO’s Extended Day-Ahead Market (EDAM) during a technical session at the WECC quarterly meeting on Dec. 9.

CAISO’s EDAM and SPP’s Markets+ are scheduled to go live in 2026 and 2027, respectively. One concern with having two separate day-ahead markets is the potential for friction at the borders of the two markets as entities join one market or the other. These seams arise from differing policies and separate dispatch between neighboring markets, which can result in additional costs for transferring energy across the boundary. (See ‘Islanded’ BAs Face Tough Choices in Western Market Future, Experts Say.)

CAISO has met with SPP, transmission owners and providers, and other partners in the West to discuss seams, according to McKenna. She said those discussions are in the early stages, noting that system reliability is the overarching principle as EDAM evolves.

Still, SPP and CAISO’s joint work as Western reliability coordinators (RCs) can help, McKenna said.

“Significant progress has been made in adapting some of the RC-based tools,” McKenna said. “And one you might have heard about is the enhanced curtailment calculator.

“This is a pretty powerful tool for us to be able to use in the Western Interconnection, so that we can ascertain what curtailments might have to happen on the system, should limits be exceeded, in a collaborative and coordinated and reliable manner. This will be foundational for some of the discussions we’ll have on the market side as to how we deal with these challenges coming up with the seams.”

The West has a history of collaboration and already has in place “a series of robust network models, real-time data sharing with each other and state estimators that we rely on,” McKenna added.

“We want to maintain and continue to use these tools as part of our engagement in the seams discussions,” McKenna said. “And of course, these things have to evolve over time. But we’re hopeful that with the work that we’ve done in the West and collaborative nature of how we do business in the interconnection will drive and will guide those discussions.”

‘Come Together and Find Solutions’

Meanwhile, SPP has launched separate efforts, including the Markets+ Seams Working Group (MSWG) and other working groups as it develops the market. 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.

SPP also is expanding its RTO into the Western Interconnection, and the plan is to optimize Markets+ with the RTO in 2028, Carrie Simpson, vice president of markets at SPP, said during the WECC meeting.

SPP is “committed to working on seams,” Simpson said. The RTO wants to help “coordinate transfers amongst different parties, whether it’s EDAM, [Western Energy Imbalance Market], CAISO, Markets+” or non-market participants, Simpson added.

SPP plans to host a symposium on Western seams in Tempe, Ariz., on Feb. 26. (See SPP Markets+ Cruising Through Early Development.)

A recent report by FERC urged Western electricity industry stakeholders to get ahead of seams before the launches of Markets+ and EDAM. The paper highlighted seams coordination in the Eastern Interconnection. (See FERC Report Urges West to Address Looming Market Seams Issues.)

McKenna noted that solutions in Eastern markets are not necessarily compatible with the reality in the West.

“We think there’s going to have to be some extraordinary and important efforts between, not just the market operator to market operator, but those who are within these markets, such as the transmission owners, the transmission providers, the balancing areas,” McKenna said. “We all have to come together and find solutions.”

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MISO Launches 2nd Review of Long-range Tx Project for Cost Overruns

INDIANAPOLIS — MISO has opened another review of a second project from its first long-range transmission plan (LRTP) portfolio, prompted again by construction cost overruns.

MISO Executive Director of Transmission Planning Laura Rauch announced that MISO is conducting a variance analysis on the 345-kV Iron Range-Benton County-Big Oaks project in Minnesota. Joint developers Minnesota Power and Great River Energy have revised costs to build the line from an originally estimated $970 million to $1.39 billion. MISO’s Board of Directors approved the project under the first LRTP portfolio in 2022.

The Minnesota project review joins MISO’s ongoing variance analysis on the planned 345-kV Morrison Ditch-Reynolds-Burr Oak-Leesburg-Hiple line in Illinois and Indiana, which has climbed from an estimated $261 million to $675 million. That project was also approved in 2022 under the first LRTP portfolio. Northern Indiana Public Service Co. is handling the upgrade.

MISO uses its variance analysis to re-evaluate transmission projects that experience significant cost increases or other obstacles. Once it completes 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.

MISO Director Mark Johnson asked what timeline the stakeholder community can expect on MISO’s most recent variance analysis. He said it seemed that the variance analysis on the Indiana project had run long and noted that MISO began it in early 2024.

MISO Director Mark Johnson | © RTO Insider 

“At the end of the day, I don’t think this is a good look for any of us if this drags on,” Vice President of System Planning Aubrey Johnson told MISO leadership during a Dec. 9 meeting of the System Planning Committee. Johnson said MISO plans to accelerate the process overall and deliver more timely outcomes.

“We expect to do that at a faster rate next year than we have with the current project,” Johnson said. He added that MISO’s review on the Indiana project was out for “executive review” and that MISO would deliver a verdict publicly before the end of 2025.

Industrial customers across MISO have repeatedly asked MISO to enact stronger cost containment boundaries on transmission projects. They’ve said MISO’s variance analysis should have a 20% overbudget threshold to trigger the study (instead of 25%) and that MISO should consult with third-party experts and its Board of Directors on projects’ fate.

MISO staff have said they don’t see a need to alter the process but that the RTO will create more public notices when it must conduct a variance analysis. (See MISO to Make Transmission Re-evaluation Process More Public and MISO TOs Oppose Tx Cost Containment Suggestions.)

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Louisiana Gen Co. First to Lodge Complaint Over MISO Auction Error and Price Corrections

Louisiana-based power generator Pelican Power is the first to register a complaint over MISO’s yearslong miscalculation in its capacity auctions in an effort to stop the RTO’s retroactive pricing corrections.

Pelican Power filed the complaint with FERC in mid-November regarding MISO’s settlement adjustments to the 2025/26 Planning Resource Auction (PRA) (EL26-26).

The utility said MISO’s retroactive pricing corrections run “directly counter to the commission’s longstanding policy of not disturbing auction outcomes.” It called the “after-the-fact tinkering with auction outcomes” unlawful and in violation of the filed rate doctrine. It asked FERC to order MISO to cease resettlements.

Comments and interventions are due in the complaint Dec. 15. MISO leadership during its Dec. 9 Markets Committee meeting acknowledged they may have to undo the pricing adjustments if the complaint is successful.

Pelican argued that nothing in MISO’s tariff allows it to make wide-ranging changes to capacity prices in the 2025/26 auction. It said MISO “has taken a series of ad hoc actions not authorized by, or consistent with, the terms of the MISO tariff and applied rules never reviewed or approved by the commission.” Pelican said MISO appeared to be attempting to expand its remedial authority beyond “straightforward corrective measures” and its duty to enforce a filed rate.

“MISO’s desire to right its wrong does not excuse its further violations of the filed rate, any more than a bank robber’s heartfelt remorse excuses his breaking back into the bank to replace the money he stole,” Pelican wrote.

Pelican added that MISO began taking steps to remedy the error in mid-August, with most of summer 2025 — and therefore the planning year’s highest capacity prices — behind it.

“While it may have been difficult, if not impossible, for MISO to actually re-run the 2025/26 PRA, particularly with the 2025/2026 planning year already underway, the fact remains that the MISO tariff does not authorize any, much less all, of the foregoing steps, and that MISO has simply invented and applied a whole new set of settlement rules to be found nowhere in the MISO tariff,” Pelican said.

For eight years, MISO used a technically incorrect “all hours” approach to calculate its loss of load expectation (LOLE), which according to MISO’s tariff, theoretically should occur only on a day’s peak hour. The error caused the auction to function as if a loss of load event could strike at any non-peak hour, raising the supply MISO secured for nearly a decade. The grid operator discovered in summer that an unnamed vendor since 2017 miscalculated the RTO’s LOLE. The coding error caused a $280 million impact on market participants in the 2025/26 auction, with some owing more money and some getting refunds. (See MISO IMM: Capacity Prices Efficient Despite Yearslong Error and MISO Discloses $280M Error, Over-procurement in 2025/26 Capacity Auction.)

As previously defined, a day with a loss-of-load event is counted in MISO’s LOLE calculations only if the event happens during the hour with daily peak load. MISO received FERC permission to officially use an “all-hours” loss of load approach in its capacity auctions beginning with the 2026/27 planning year.

The Independent Market Monitor has said the error was a good thing and made MISO more reliable as it traded thermal baseload generation for renewable generation.

Independent Market Monitor David Patton said it’s “disturbing” that MISO essentially must resettle the 2025/26 auction to reflect a reliability standard lower than one day in 10 years. “From our perspective, we think these resettlements … are extremely destructive to the integrity of the market,” Patton said during MISO’s September Market Subcommittee meeting.

MISO has been resettling the 2025/26 auction at estimated prices under its continuing error procedure. It’s the only auction where MISO has made pricing corrections. MISO has claimed it’s “not rerunning or resettling the [Planning Resource Auction], taking new bids or establishing a new auction clearing price.”

MISO made the first of three rounds of settlement adjustments Sept. 18. The first set of corrections totaled nearly $77 million. MISO warned market participants that if the adjustment should exceed their credit limit, it would trigger a margin call to cover losses within two business days.

Following discovery of the mistake, MISO Director of Resource Adequacy Neil Shah has said MISO will attempt to make its loss of load expectation calculations more transparent. MISO is working to develop a “masked” model for stakeholders to review, Shah said at the October Resource Adequacy Subcommittee.

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Judge Tosses Trump’s Halt on Wind Projects

A federal judge ruled that President Donald Trump’s executive order halting onshore and offshore wind power leasing and permitting was unlawful, finding that it violated the Administrative Procedure Act.

Judge Patti B. Saris, of the U.S. District Court for Massachusetts, found that both Trump and the executive agencies charged with carrying out the order failed to provide a reasoned explanation for the change, as required by the APA.

“Even assuming … that the [order] itself could be characterized as the [agencies’] own explanation for their manner of implementing it, the [order] does not provide adequate explanation: It merely includes a single sentence citing ‘various alleged legal deficiencies underlying’ wind permitting, ‘potential inadequacies in various environmental reviews’ and the possibility that these vaguely defined issues ‘may lead to grave harm,’” Saris wrote in a ruling issued Dec. 8.

“Whatever level of explanation is required when deviating from longstanding agency practice, this is not it.”

In ruling against the administration, Saris sided with 18 Democratic state attorneys general who challenged the order in May. (See State Attorneys General Sue Trump for Executive Order Halting Wind Approvals.)

Along with the halt, Trump had ordered a review of the government’s permitting processes for both types of wind resources. The states argued this also violated the APA, as the president did not set a deadline for the review, and there was no indication that the relevant agencies were even working on it. Saris agreed.

“More than 10 months after the wind order instituted a ‘temporary’ pause on the issuance of wind energy authorizations, no end to the comprehensive assessment appears to be in sight,” she wrote. “The agency defendants neither included a timeline for that assessment in the administrative record nor provided an anticipated end date during the course of this litigation.”

Trump’s order effectively halted development of the U.S. offshore wind industry: Multiple projects were canceled, and international companies such as Ørsted have shifted their focus to building in more favorable regulatory environments. (See Ørsted to Slash Workforce, Refocus on European OSW.)

“Overturning the unlawful blanket halt to offshore wind permitting activities is needed to achieve our nation’s energy and economic priorities of bringing more power online quickly, improving grid reliability, and driving billions of new American steel manufacturing and shipbuilding investments,” Oceantic Network CEO Liz Burdock said in a statement.

But while stocks for Ørsted and other energy companies with offshore wind holdings rose on news of the ruling, ClearView Energy Partners said it was skeptical new offshore wind projects would proceed, at least while Trump is still in office.

“We view the ruling as positive for offshore wind proponents, but we are not convinced the decision sufficiently supplants the actions the Trump administration has taken to constrain offshore wind,” ClearView said in a note Dec. 9. “We are skeptical that this loss in court can inspire the administration to change its oppositional posture.”

“The court expresses no view on whether the agency defendants should issue or withhold any particular permit,” Saris wrote. “But, while a president may direct a reappraisal of permitting practices after a change of administration, the agency defendants may not, as they have done here, decline to adjudicate applications altogether, for an unspecified time, pending the completion of a wide-ranging assessment with no anticipated end date.”

Saris’ ruling, if upheld, may be a boon to projects that have already been approved. In a filing with the U.S. District Court for D.C. on Dec. 2, the Bureau of Ocean Energy Management asked for a voluntary remand of its approval of New England Wind, off the coast of Massachusetts. It cited Trump’s executive order and its ongoing “re-evaluation” of its permitting process.

While the administration had issued stop-work orders on two projects, they were later lifted. Five projects are still under construction in the U.S.: Vineyard Wind 1, off Massachusetts; Revolution Wind, off Rhode Island; Coastal Virginia Offshore Wind, off Virginia; and Sunrise Wind and Empire Wind 1, off New York.

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NERC Standards Committee Pushes Projects Forward

Members of NERC’s Standards Committee dealt with multiple action items in what Chair Todd Bennett, of Associated Electric Cooperative Inc., called a “healthy agenda,” despite agreeing to delay action on one item until its next meeting in January.

In the Dec. 9 teleconference, Bennett told the SC he was “proud of what this committee has been able to accomplish over the past year,” reminding members that more than 50 outstanding FERC directives were being resolved through the standards development process as of mid-2025. Trustee Sue Kelly, the committee’s liaison to NERC’s Board of Trustees, echoed Bennett’s remarks, praising the SC, along with NERC’s standards development staff, for working hard “to shovel the work out the door and yet maintain high quality.”

The action items for the committee’s final meeting of the year were relatively simple and approved with little debate, with the exception of a proposal to add four members to the standard drafting team for Project 2022-05 (Modifications to CIP-008 reporting threshold).

The SC authorized soliciting nominees from industry to replace four departing members of the project team at its Aug. 20 meeting, receiving 10 nominations. (See NERC Standards Committee Tackles Final Order 901 Tranche.) NERC staff recommended four of these candidates to join the team.

However, during the meeting, several SC members expressed confusion that the background material they were given about at least two of the candidates — who were not identified by name, in accordance with NERC’s policies — did not match their oral description by Alison Oswald, a manager of standards development. Oswald examined the material and determined that NERC staff had copied the wrong information into the file.

Rather than try to sort out the confusion during the meeting, Oswald suggested removing the item from the meeting’s agenda and returning to it at the committee’s January meeting. Asked by Terri Pyle of Oklahoma Gas and Electric how this decision would impact NERC’s standards development schedule, Oswald said the project was low priority and delaying action would only cause the new members to miss one SDT meeting. After Bennett endorsed the proposal, the rest of the committee agreed to delay action.

The next item similarly concerned appointing the chair, vice chair and eight other members to the SDT for Project 2025-06 (Supply chain risk management). This project is intended to address FERC’s September order directing NERC to develop standards addressing registered entities’ SCRM plans within 18 months. (See FERC Tackles Cybersecurity in Multiple Orders.)

NERC received 14 nominations in the 14-day solicitation period, Manager of Standards Development Sandhya Madan said, and it recommended 10 for SDT membership. Committee members approved all members without objection.

Members then turned to a proposal to authorize drafting new reliability standards for Project 2021-03 (CIP-002), a necessary step to moving forward with a standards development project. The committee again approved the proposal without opposition, along with subsequent authorizations of standards development for Project 2025-03 (Order No. 901 operational studies) and Project 2025-04 (Order No. 901 planning studies).

The latter two projects address the final milestone of FERC Order 901, covering operational and planning studies for inverter-based resources. Members also approved a proposal to reassign two standards authorization requests to update TPL-001-5.1 (Transmission system planning performance requirements) from Project 2022-02 (Uniform modeling framework for IBR) to Project 2025-04.

Aside from the action items, Oswald also shared with members a planned change to NERC’s SDT reference manual that would allow staff to remove team members for lack of attendance at meetings. The new language would specify that if a team member missed three consecutive meetings without notifying staff, the developer assigned to the project would reach out to the member to see if they would like to continue to serve.

If no response was received and the member missed two additional meetings, the developer would email asking again if they wished to continue serving. Continued lack of response after an additional three weeks would cause the member to be reassigned as an observer. The changes would take effect in 2026, Oswald said.

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CEC Approves EV Fast Chargers Along Calif. Highway Corridors

The California Energy Commission granted about $15 million to companies to install more than 100 electric vehicle fast charger stations in the Golden State.

The CEC on Dec. 8 voted to approve about $11.2 million for San Francisco-based Electric Era to install 72 direct current faster chargers (DCFCs) at 16 locations along some of the state’s major highways, including Interstate 80, from Auburn to Grass Valley, and U.S. 101, from San Francisco to Los Angeles.

The source of the grants is the $5 billion Biden-era National Electric Vehicle Infrastructure (NEVI) program, which was funded by the federal Infrastructure Investment and Jobs Act. The Trump administration halted NEVI payments early in 2025 but resumed the program in August after a court ruling. (See DOT Issues Guidance to Resume NEVI Funding.)

Under the terms of the grants, the Federal Highway Administration (FHWA) must authorize funding for the projects before reimbursable expenditures can be incurred, the CEC’s application says. Even where funds have already been obligated or work to be performed will not be reimbursable or will be done with matching funds, FHWA and California Department of Transportation (Caltrans) approval may still be required prior to commencing work, the application says.

Rivian, an EV truck manufacturer, received four grant awards, totaling about $1.7 million, to install DCFCs in Long Beach, Temecula, Tulare and Cabazon. As part of the grant, Rivian must sign a data-sharing agreement with a charging network provider, which will collect and send to the CEC charging data from each charging port, the application says.

The CEC approved also the commission’s 2025-2026 investment plan update for the clean transportation program, which included a significant drop in funding for EV light-duty chargers, from $98.5 million in 2025/26 to $34.2 million in 2026/27. EV heavy-duty vehicle charger funding will increase from $15 million in 2025/26 to $44 million in 2026/27.

In total, the transportation investment plan includes about $327 million for fiscals 2025/26 through 2027/28.

“[We are] targeting the expansion of charging in multifamily housing properties,” Commissioner Nancy Skinner said at the agency’s voting meeting. “Because in the analysis we’ve done, multifamily residents have the least access to charging at home. And so, since charging at home is one of the most convenient ways to have an EV, we really want to expand multifamily charging installations so that it is much more convenient for folks.”

POU IRPs Approved

The CEC also approved the integrated resource plans (IRPs) for the City of Palo Alto Utilities and Hetch Hetchy Power (HHP).

The approved IRP requires a publicly owned utility (POU) to meet greenhouse gas emission reduction requirements, renewable energy resource procurement amounts, and carbon neutrality and reliability requirements, the CEC’s Palo Alto order notes.

Palo Alto’s IRP shows that the utility will increase its investments in geothermal power generation, renew a hydroelectric generation contract with the Western Area Power Administration, and see an increased reliability risk during years with low hydroelectric generation availability.

Most of Palo Alto’s capacity — about 230 MW out of 340 MW — is provided by hydroelectric generation facilities, and about 80 MW from solar power generators.

HHP, which is operated by the San Francisco Public Utilities Commission (SFPUC), has 380 MW of existing resources. The utility anticipates low growth over the coming years, mostly driven by the San Francisco International Airport expansion, public transit electrification and new developments, CEC staff member Bryan Neff said at the meeting.

HHP transmits power across 167 miles of transmission infrastructure that is owned and operated by SFPUC, Neff said.

HHP’s load growth will require additional resources by 2033, so the utility plans to procure 75 MW of battery storage capacity starting in 2027, 100 MW of solar generation starting in 2033 and 50 MW of geothermal starting in 2035, the CEC’s staff review says.

“I think we’re seeing this in all the IRPs from the POUs: There is significant load growth in the upcoming years,” CEC Vice Chair Siva Gunda said at the meeting. “I think that’s consistent with the demand forecast of the CEC.

“When we think about California as a whole, we generally think about CPUC as a significant part of the work, and about 75 to 80% of the load does fall under the CPUC jurisdiction. But there’s almost a quarter, depending on the time of the year, that is planned through the POU work. … There’s also a lot of transmission work that is being taken up by the POUs, and [this is] something that we need to closely track.”

There is significant uncertainty in the load in the West and significant uncertainty in what resources are online, Gunda said.

“It’s important for us to track through our dependence on imports and just really be careful of planning that.”

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Analysis: OSW and Gas Together Help NYISO, ISO-NE Grid Reliability

Northeastern power systems cannot afford to drop offshore wind if they are to maintain reliability, reduce emissions and lower electricity prices, according to a new analysis from Charles River Associates.

The analysis, released Dec. 2, examined both NYISO and ISO-NE and found that retaining existing natural gas while completing queued OSW projects were necessary to maintain reliability and affordability.

“We found that there are quite material resource adequacy risks in New York City,” Oliver Stover, an associate principal of Charles River, said during a webinar Dec. 4 to discuss the paper. “This is important from the perspective of offshore wind because it can have a non-trivial impact on helping reduce these risks.”

Stover went on to say that New England’s exposure to tightening natural gas and electricity markets could be mitigated by investment in OSW.

The base case in the analysis assumes that the current queue of OSW projects in both markets will be completed on time and that existing gas resources are retained. When compared to cases in which OSW is canceled without substitutes, replaced by onshore renewables or replaced by gas, the base case performed better on prices and reliability.

Developing gas alone was found to raise prices and emissions while possibly reducing overall capital costs. Onshore renewables could match base case prices and emissions but were weaker for reliability without extensive transmission upgrades. Failing to bring on new resources at all had the worst overall performance.

“This is not just a winter problem, particularly in the New York ISO,” Stover said. “We see summer challenges continuing into the nighttime hours, and offshore wind is well positioned to augment solar builds in filling in those hours.”

These findings mirror the policy preferences of major stakeholders and politicians in New York. The Independent Power Producers of New York, the Alliance for Clean Energy New York and Gov. Kathy Hochul have previously stated that they favor an “all of the above” approach to energy.

Stover said that OSW’s proximity to load pockets, particularly in New York City, made it better for reliability than onshore renewables in general. Bypassing transmission congestion to inject directly into load pockets was a major source of OSW’s reliability benefits in the analysis. Without OSW development, both Boston and Vermont were at risk of load shedding by 2036.

Gas-fired generation development is difficult in high-population areas of both New York and New England. The existing gas system is already constrained, and there is limited headroom on the gas distribution system to bring on more firm generation, Stover said.

“They are both challenging places to build. They’re expensive. They’re coastal. They’re quite dense, and there is limited fuel,” Stover said. “Those problems might be solved in the long term … but that might be challenging.”

Stover also pointed to a recurring topic of conversation at NYISO stakeholder meetings: the aging fossil fleet. If nothing new comes online, it places greater burdens on aging infrastructure, which increases the likelihood of generator failure and forced retirement. ISO-NE’s generation portfolio is a little more flexible in this respect, as the region could afford to retire units more than New York.

While reliability and energy prices fell in the base case “OSW+ NG” scenario, capital costs were slightly higher than the gas-only scenario. Stover said that this was because OSW, and renewables broadly, required more infrastructure investment to bring them online.

“You have to pay for the upfront capital cost, and then we enjoy the benefits of paid dividends on driving down the energy price,” Stover said.

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Company Briefs

Amazon Backs out of Project Blue Data Centers

Amazon Web Services has pulled out of its role as future operator of the Project Blue data center complex in the Tucson, Ariz., area, according to sources.

Amazon has left the project because its operations aren’t compatible with the project’s recently announced plans to use air cooling instead of water cooling for the data centers’ servers, the sources said. Beale Infrastructure, the project’s developer, is now negotiating with Meta to replace Amazon as the center’s operator.

Project Blue switched to plans for an air-cooled operation after the Tucson City Council voted unanimously to kill its effort to be annexed into the city and to receive city water supplies for its operations.

More: Tucson.com

Exxon Halts Plans for Low-carbon Hydrogen Facility

ExxonMobil has pulled the plug on what would have been one of the world’s largest hydrogen plants after its $332 million grant from the Biden administration was taken away by the Trump administration.

In 2022, Exxon announced plans to build a facility at its refining and petrochemical complex in Baytown, Texas, with the capacity to produce 1 Bcfd of blue hydrogen, which is made using natural gas and carbon-capture equipment.

Since blue hydrogen typically costs about one-third more than the ​“gray” version of the fuel made with unmitigated gas, Exxon CEO Darren Woods said the company could not find enough buyers willing to pay the premium.

More: Canary Media

Eurowind Energy Exits 400-MW Battery Project

Danish renewables developer Eurowind Energy last week announced the sale of a 400-MW battery storage project in California under a plan that will provide it with cash for its European activities.

The divestment is in the Potentia-Viridi battery energy storage system project, which Eurowind Energy developed under a 50/50 joint venture with Capstone Infrastructure.

The project is expected to come online in June 2028.

More: Renewables Now