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April 9, 2025

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MISO Fields Divergent Calls for Stronger South Planning, IRA Reversal in Tx Futures

NEW ORLEANS — Calls to consider a dissolved or weakened Inflation Reduction Act alongside appeals for stronger MISO South planning epitomized the tough situation and unsteady political climate MISO finds itself in as it tries to establish transmission planning expectations.  

In a transmission planning futures teleconference March 19, MISO revealed it plans to proceed in its modeling as if tax credits from the Inflation Reduction Act are a safe bet. However, MISO staff said they would consider performing sensitivities on the side if that federal funding is eliminated or diminished.  

MISO is revising the trio of 20-year futures scenarios it uses to plan transmission. The RTO has said it must incorporate more aggressive load growth and would create a fourth scenario specially designed to study the footprint if frayed supply chains continue to present an obstacle to new generation construction.  

WPPI Energy’s Steve Leovy asked whether MISO is considering creating a separate resource expansion model should the IRA fall. 

MISO Senior Manager of Policy and Regulatory Planning RaeLynn Asah said the sensitivities would produce “modified” and “miniature” resource expansion directions that wouldn’t be tested for resource adequacy. But she stressed that MISO hasn’t decided whether it will add the additional study step.  

Asah said MISO typically uses sensitivities to “test the durability” of its resource expansion assumptions.  

“There are a lot of rules and laws that appear to be rolling back this year,” said Kavita Maini, representing MISO industrial customers.  

“As of right now, as of March 1, the IRA is in place, so we’re incorporating it into the model,” Asah said, explaining that MISO’s future modeling relies on a “snapshot” in time. MISO began building the futures models on March 1.  

Asah said MISO “has no idea” how the IRA will hold up or how funding cancellations or claw backs might be challenged in court.  

Multiple stakeholders pointed out the IRA’s demise is not as improbable as it was last year.  

Mississippi Public Service Commission consultant Bill Booth asked if MISO could include an IRA downfall in its new, fourth future that’s meant to contemplate long-term supply chain delays and sluggish generation construction.  

“I think this will have a major impact on the generation that’s sited,” Booth said. “You have to question which variables MISO wants to include and which variables MISO wants to ignore.”  

MISO Director of Strategic Initiatives and Assessments Jordan Bakke said MISO is confronted with uncertainties at every turn in its futures planning. He said that’s why MISO’s futures include a range of possible realities. Bakke also said MISO wants to capture what it knows today, which includes an intact IRA.  

“We have not decided which of the futures we will use in expansion planning,” Executive Director of Transmission Planning Laura Rauch added.  

MISO plans to focus on its new, fourth future in an upcoming April workshop. Another May workshop will focus on resource expansion assumptions and how resources would be dispersed across the footprint.  

Asah asked members to submit their most up-to-date information on planned generation retirements to MISO. The RTO will incorporate those dates in its futures. 

Spotlight on MISO South Planning

Stakeholders’ advice to MISO to rethink the IRA’s place in the futures comes as the RTO and its board are fielding calls to action for a long-term transmission plan in MISO South. The two bids appear to come from opposing sides of the political spectrum.  

After MISO completes a futures revamp over 2025, it will use them to plan another long-range transmission plan (LRTP) portfolio for MISO Midwest, making a MISO South LRTP portfolio years away while the Midwest region would be the focus of three, multibillion-dollar portfolios within six years.  

At MISO’s March Board Week, Windy Beck, of the Deep South Center for Environmental Justice, made a plea for in-depth MISO South planning. She said the region deserves the same planning attention paid to the Midwest. Beck said she’s seen no evidence from MISO that Entergy and other South transmission owners’ billions in annual Transmission Expansion Plan (MTEP) projects are the most cost-effective and efficient projects for the grid.  

During the March 13 board meeting in New Orleans, CEO John Bear pushed back on the perception that the RTO is not doing anything on the planning front for MISO South and focusing all planning attention on MISO Midwest.  

Bear said planners have “rolled up their sleeves” to ensure the transmission solutions put forward in the South as part of the MTEPs are “efficient, reliable and at the lowest cost.”  

However, the Union of Concerned Scientists’ Sam Gomberg said the member-submitted project ideas of MISO South are no substitute for the broad analysis completed under a long-term planning exercise. 

He said MISO South desperately needs the added resiliency, reliability, cost savings and delivered clean energy like the billions in Midwestern long-range lines will provide.  

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FERC OKs Incentives on $1B Minn. HVDC Modernization, Debates Procedure

FERC granted rate incentives for the priciest project to come out of MISO’s 2024 Transmission Expansion Plan (MTEP 24), setting off friction between commissioners.

FERC approved Allete’s request for abandoned plant and construction work in progress incentives on a $1 billion modernization of subsidiary Minnesota Power’s circa-1970 HVDC line. The March 17 order had two commissioners disagreeing with how incentives were awarded on at least some of the work (ER25-948).

The commission fully allowed the pair of incentives for the portion of the line in Minnesota — where the certificate and route permitting already are approved — and conditioned incentives for the North Dakota portion of the line on state regulators’ approval of construction. In North Dakota, work awaits an order from the Public Service Commission on certificate and route permit applications. Allete said that decision is likely in the third quarter of 2025.

Allete sought transmission rate incentives under FERC’s rebuttable presumption that the line supports reliability or reduces congestion. The company said the project being subjected to MTEP studies and its ultimate inclusion in the portfolio is evidence of its usefulness.

MISO approved most of the four-part project under a seldom-used “transmission delivery service project” category as part of MTEP 24. (See MTEP 24 Reaches $6.7B; MISO Ending Rush Island Reliability Agreement in Mid-October.)

Allete said the aging, 465-mile line stretching from west-central Minnesota to central North Dakota is experiencing more frequent outages. The company breaks down the project into four components: $828 million in converter station replacements, $112 million in AC transmission facilities upgrades, a $68 million HVDC transmission line upgrade and a new, approximately $24.5 million Nelson Lake substation.

However, FERC said the project’s MTEP status didn’t prove it was the result of a fair and open regional planning process that accounts for reliability and congestion benefits. The commission cast doubt that MISO would perform the usual, comprehensive studies on that particular category of project. It also pointed out the project’s Nelson Lake substation is categorized as an “other” reliability project and also not obliged under MISO’s more rigorous studies.

The commission instead relied on the state commission processes in Minnesota and North Dakota for the project to meet the federal standard for incentives.

FERC paused before approving incentives for the $68 million line-upgrade section of the project. The commission acknowledged there’s almost no chance the Minnesota and North Dakota commissions would explicitly evaluate the upgrade of existing line because the work wouldn’t alter the original voltage, and the project would remain within its existing right of way. Nevertheless, FERC decided the line is “integrally related to the other components” and therefore also entitled to incentives.

Commissioner Lindsay See said while she was “glad” to agree with the majority on most of the incentives, she said she would have stopped short of granting Allete incentives for the line-upgrade portion of the project. She dissented in part from the order.

Commissioner Willie Phillips wrote in a separate concurrence that while he was pleased the project ultimately won incentives, he was troubled that FERC would conduct an on-the-spot reevaluation of MISO’s transmission delivery service project classification and deem it deficient against the rebuttable presumption standard.

Phillips also said the commission deviated from precedent without explanation when it made the effective date of a portion of the incentives contingent on North Dakota’s approval of construction instead of the March 18, 2025, effective date Allete requested for the entire project.

“As such, this order represents an attempt by the current commission to modify our longstanding policy on transmission incentives on a case-by-case basis,” Phillips wrote. “Our practices are not set in stone, and I believe it is both reasonable and appropriate to continually reassess and reevaluate them based on experience, changed circumstances, and achieved wisdom.

“But to do so in the context of an uncontested application, without notice or opportunity for interested parties to comment on these changes, lacks transparency and creates regulatory uncertainty that could undermine the very purpose of FPA [the Federal Power Act].”

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ISO-NE Planning Advisory Committee Briefs: March 19, 2025

Additional Economic Study Results

At the ISO-NE Planning Advisory Committee on March 19, Richard Kornitsky and Ellie Ross presented the results of additional modeling scenarios for the RTO’s 2024 Economic Study, which aims to evaluate the effects of state and federal policies and changes to the region’s resource mix through 2050. 

Previous findings of the study have illustrated how the region’s resource needs are expected to shift in the 2040s as the power system decarbonizes, corresponding with an exponential increase in the cost of additional carbon reductions. (See “2024 Economic Study,” ISO-NE Details Evaluation Models for Transmission Solicitation.) 

Building on the prior results, ISO-NE modeled a scenario evaluating the retirement of thermal resources. The model found the region could retire “up to 5,550 MW of legacy thermal (non-nuclear) generation” by 2050 without exceeding the loss-of-load expectation (LOLE) threshold, which was set at 0.1 days per year with a loss-of-load event. 

“The retirement of 5,550 MW of legacy thermal generation has minimal impact on system operations in the 2050 production cost model,” Ross said. “In the model with retirements, this generation is easily replaced by remaining [natural gas] generators.” 

She noted that the scenario caused a decrease in generation from thermal resources that burn landfill gas, municipal solid waste and wood waste solids, which resulted in an overall increase in the emissions from natural gas and oil. 

ISO-NE also modeled scenarios featuring increased capital costs for offshore wind resources and no OSW buildout. 

Adopting the National Renewable Energy Laboratory’s conservative cost estimates for OSW — instead of the moderate estimates used in the model’s base case — increased total annualized build costs by about $17 billion, or 10.8%. 

This cost estimate still was cheaper than the no-OSW scenario, which increased build costs by about $26 billion, or 16.6%, compared to the base case. 

“New England needs new OSW resources to meet state emission goals at the lowest cost,” Ross said. “The buildouts with less or no OSW must rely more on emitting generation, [small modular reactors] and new [solar] resources.” 

“Even if OSW capital costs are higher than current estimates, the system will economically benefit from new OSW resources, although the ideal time frame for building OSW shifts to after 2040,” she said. 

Asset Condition Projects

Rafael Panos of National Grid introduced an asset condition project (ACP) to replace wooden structures, insulation, conductor and shield wire on a 115-kV line in Massachusetts.  

The wooden poles set to be replaced, which have an average age of 30 years, have significant woodpecker damage, Panos said. He said the population of woodpeckers in New England has grown in recent years, causing significant damage to wooden transmission structures. 

The company plans to replace the wooden poles with steel structures; Panos said he has observed woodpeckers pecking at steel structures, “but fortunately, they were not able to get through.” 

The project’s projected cost is $19 million, and the expected in-service date is the second quarter of 2026. Stakeholder comments are due April 2.  

Panos also presented a cost update on a project overhauling a substation in Tewksbury, Mass. The company has increased its cost estimate on the project to about $67 million, compared to the $36 million estimate presented in 2022.  

The increase was driven by additional issues found at the substation and rising costs of labor, equipment, materials and permitting, Panos said. 

Project List Update

New England transmission owners have added 10 ACPs to ISO-NE’s tracking list since the previous update in fall 2024, said Brent Oberlin, executive director of transmission planning at ISO-NE. (See New England Transmission Owners Issue Draft Asset Condition Forecast Database.) The TOs estimate the projects collectively will cost about $730 million.  

ACPs categorized in the database as proposed, planned or under construction total $5.97 billion, while the total cost of in-service ACPs is $5.36 billion.  

This estimate does not include a series of projects proposed by Eversource to replace its network of underground high-pressure, fluid-filled transmission lines in Eastern Massachusetts. The company estimates the first phase of these replacements will cost between $1.5 billion and $2 billion and plans to provide more detailed cost estimates to the PAC in the summer. (See Eversource Outlines Billions in New Boston-area Asset-condition Needs.) 

ACP costs in New England have ballooned in recent years, spurring calls from some consumer advocates for more transparency and oversight to ensure projects are cost efficient and right sized to account for future transmission needs. 

“Despite the eye-watering sums being spent on ACP upgrades, they are not being designed to maximize the amount of power that can be carried via transmission lines in existing rights of way,” the Acadia Center wrote in a recent blog post. “Each ACP that fails to maximize the capacity of existing transmission represents a lost opportunity to prepare New England to meet the projected doubling of the region’s peak demand.” 

Connecticut 2034 Needs Assessment

Sarah Lamotte, transmission planning engineer at ISO-NE, presented the results from ISO-NE’s Connecticut 2034 Needs Assessment, which is intended to “identify the time-sensitive and non-time-sensitive needs in the study area.” 

The study identified time-sensitive minimum load needs at 21 of the 115-kV buses and 27 of the 345-kV buses in the region. 

Lamotte said the study considered non-transmission solutions and found they would not alleviate the time-sensitive issues. She said ISO-NE plans to initiate a solutions study in the second quarter of 2025 to address the identified needs. 

Boston 2033 Solutions Study

Aqeel Ahmed, associate engineer at ISO-NE, presented the preliminary results of the RTO’s Boston 2033 Solution Study, which is intended to address time-sensitive, minimum-load, high-voltage needs.  

The preferred solution identified includes the installation of a 115-kV reactor and protection systems upgrades at five substations. The projected cost is $26 million.  

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FERC Approves Tariff for SPP RTO West

FERC has accepted SPP’s proposed revisions to its tariff that will incorporate seven Western Interconnection entities as transmission-owning members of the RTO, making the grid operator the first to provide full market services in the grid’s two major interconnections.

The commission on March 20 directed SPP to make a compliance filing within 30 days. It also required the RTO to provide a notification of the RTO West’s go-live date no later than six months prior (ER24-2184).

SPP has targeted April 2026 as when the entities will begin participating in its Integrated Marketplace, transmission planning, reliability coordination and other RTO services. They all are members of the Western Energy Imbalance Service market, which SPP has administered since 2021:

    • Basin Electric Power Cooperative
    • Colorado Springs Utilities
    • Deseret Power Electric Cooperative
    • Municipal Energy Agency of Nebraska
    • Platte River Power Authority
    • Tri-State Generation and Transmission Association
    • Western Area Power Administration’s Colorado River Storage Project, Rocky Mountain and Upper Great Plains regions

FERC agreed with the grid operator that its proposal to integrate the expansion members into its RTO likely will improve grid reliability and operational efficiency, benefiting existing members and new ones. SPP has said RTO West will provide more than $200 million in annual benefits to its members, primarily through the optimization of DC ties with the Eastern Interconnection. (See SPP Files to Incorporate Western Entities into RTO.)

“The RTO West proposal will consolidate the management of transmission facilities under a single, centrally cleared market and allow SPP to dispatch resources more efficiently across a broader geographic area,” FERC said.

“Expanding the RTO into the Western Interconnection is an exciting step in SPP’s growth, bringing value to new and existing members while enhancing reliability in both interconnections,” CEO Barbara Sugg said in a news release.

The commission filed a deficiency letter in October after SPP’s first tariff filing and asked for further clarifications on six issues, including the optimization of DC ties. (See FERC Issues Deficiency Letter for SPP’s RTO West Tariff.)

It said the RTO’s proposed DC tie access and incremental market efficiency use charges are reasonable given the “unique role that the West DC ties will play” in connecting SPP’s Western and Eastern balancing area authorities and the increased costs that will result from the ties’ use in market dispatch.

“Absent these charges, these increased costs would be borne fully by customers in the West DC ties’ transmission pricing zones because the [annual transmission revenue requirement] for each West DC tie will continue to be recovered from its respective transmission owner’s zone,” the commissioners wrote.

SPP said it is working with additional Western utilities that have expressed interest in becoming RTO members once this initial expansion is complete.

The grid operator is developing a second Western market in Markets+, a day-ahead offering centered primarily on the Pacific Northwest that secured FERC approval in January. It also serves as the program administrator for the Western Power Pool’s Western Resource Adequacy Program. (See SPP Markets+ Tariff Wins FERC Approval.)

“Multiple markets maximize value for all participants,” Sugg said.

The grid operator has expanded its footprint in the Eastern Interconnection from eight to 14 states since it became an RTO in 2004. The Western expansion will increase its service territory to all or part of 17 states.

The RTO’s expansion is part of the grid operator’s five-year strategic plan, Aspire 2026.

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ACP: Storage Set Installation Record for 2024

The storage industry set a record of 12.3 GW in installations in 2024, according to the U.S. Energy Storage Monitor report that was written for the American Clean Power Association by Wood Mackenzie.

Developers installed a total of 12,314 MW, or 37,143 MWh, increases of 33% and 34%, respectively, over 2023.

“After another year of record deployment, energy storage is solidifying its place as a leading solution for strengthening American energy security and grid reliability in a time of historic rising demand for electricity,” ACP Vice President of Energy Storage Noah Roberts said in a statement. “The energy storage industry has quickly scaled to meet the moment and deliver reliability and cost savings for American communities, serving a critical role firming and balancing low-cost renewables and enhancing the efficiency of thermal power plants.”

Texas and California led the way with installations, representing 61% of the total with the other 39% being spread across 13 states. Most of the installations in the fourth quarter were utility-scale, with Texas seeing 1,185 MW installed, California 857 MW, New Mexico 400 MW, Oregon 292 MW, Arizona 185 MW and North Carolina 115 MW.

Overall, fourth-quarter installations were down 20% from the fourth quarter of 2023, which the report said was caused by the delay of 2 GW of projects in late-stage development that should be installed this year.

Distributed storage saw high levels of installation as well, with 1,250 MW installed for the residential sector — a new record. Residential installations set a fourth-quarter record as well at 380 MW, a 6% increase over the previous quarter. Installers across the country are working to install more storage at consumer homes, with Arizona seeing a spike in activity as more firms sought to combine solar with storage.

Storage for the community-scale, commercial and industrial (CCI) sectors was up 22% on the year to hit 145 MW in 2024, with California, Massachusetts and New York accounting for 88% of that capacity.

The report forecasts 13.3 GW, or 43.2 GWh, of installations this year, a 22% increase from 2024, with the forecast going up by 11% from the last quarterly report because of the 2 GW of delays.

“Over the next five years, utility-scale installs will total 68.2 GW/256 GWh, a very similar total buildout to last quarter,” the report said. “This sustained outlook is due to political uncertainty impacting the midterm forecast being offset by storage’s role in meeting unprecedented load growth.”

Residential storage is expected to grow by 47% this year and 223% by 2029. The national attachment rate (linking solar with storage) is expected to flatten in 2025 and 2026 and then drop in future years. Attachment rates are expected to rise in every state, but solar will grow in net metering states like Florida faster than in high-attachment states like California and Puerto Rico.

CCI storage is a high-cost business, where sales and development can be more challenging than other market segments. State policy could create significant upside to the sectors by 2030s, but that is too far out to influence the forecast.

The report includes several sensitivity cases for the next five years, with a high growth one adding 10 GW over that period, which would require federal tax incentives to stay in place, avoiding additional tariffs under President Donald Trump, renewables firmed with storage deployed to meet load growth, and barriers to finance and interconnection eased.

The low case would cut installations by 22% over the rest of the decade, which assumes no more tax credits, higher tariffs on Chinese batteries, an expanded supply chain for natural gas generation and favorable treatment for it in queues, while financing and interconnection issues for storage are not addressed.

“It’s still too early to determine the final form of IRA tax incentives over the coming year,” Wood Mackenzie Global Head of Storage Allison Weis said in a statement. “The combination of new tariffs on China and other countries with continued [Section] 45X and domestic content bonus adder incentives would make U.S.-based systems more competitively priced. However, many domestic providers are not set up to meet quick demand. If higher pricing is combined with ITC tax incentives phasing out beginning in 2028, it could lower our five-year deployment outlook by as much as 19%.”

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Fate of Wind Tower Manufacturing Site in Albany Uncertain

At last year’s Alliance for Clean Energy New York conference, the Port of Albany hosted a tour of its new Beacon Island facility, which was slated to develop into a wind tower manufacturing facility. The facility could produce up to 150 towers per year and support 3,178 jobs, according to the Center for Economic Growth.

But when the port announced getting $18.8 million in funding from New York in February to install a substation, sanitary wastewater plant and fire protection system, there was no mention of the wind tower site.

“This is great news and will provide a critical boost enabling additional maritime commerce,” port CEO Richard Hendrick said in a statement. “The port will be able to move forward with the electrification infrastructure, including critical long-lead items needed in expanding the port for manufacturing opportunities.”

New York Gov. Kathy Hochul’s statement on the award referenced that the site was a “unique asset to manufacturers of a variety of large-scale components” but made no mention of building towers for offshore wind.

Penny Vavura, spokesperson for the Port of Albany, told NetZero Insider that under the current administration, the port was open to other industries on the site.

“We’re still talking to Marmen,” Vavura said, referring to the developer of the proposed site. “But if things don’t come together, we’ll still look for something that offers similar community benefits as far as employment opportunities.”

The Trump administration chilled the market for offshore wind with a first-day executive order ordering a halt to new offshore wind permitting and a review of existing leases. (See Trump Executive Orders Put 43 GW of Wind Projects at Risk.) EPA also recently pulled the permit for the Atlantic Shores project off New Jersey. (See EPA Puts Hold on Atlantic Shores OSW Permit.) Many projects have been put on pause, and industry-wide layoffs have occurred. (See OSW Critics Petition US Supreme Court for Vineyard Wind 1 Review.)

Vavura said she had “no clue” what industry, other than offshore wind, might be interested in the site.

“It’s a challenging thing to try to forecast,” Vavura said. “The next best step is to start having conversations to see what’s out there.”

A spokesperson for Marmen confirmed it was still in discussions with the port about developing the site but otherwise declined to comment. The company’s website features an Albany office “coming soon” among its divisions.

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NERC: Cold Weather Standards Now Expected in April

NERC’s Board of Trustees expects to submit the ERO’s latest cold weather standard to FERC by April 7, several days after the March 27 deadline the commission set for the standard in 2024, staff said at the monthly meeting of NERC’s Standards Committee on March 19. 

Director of Standards Development Jamie Calderon told attendees the board plans an open meeting April 4 to discuss the standard and that the ERO already has informed FERC the filing would come after the deadline. 

The standard has had an unusual path to passage, with the board ordering the SC in January to take over writing it after it failed to garner enough favorable votes from industry stakeholders to pass. Trustees exercised their authority under Section 321 of the ERO’s Rules of Procedure to sidestep the normal stakeholder approval process because they were concerned about missing FERC’s deadline. 

A team of volunteers completed work on EOP-012-3 (Extreme cold weather preparedness and operations) in January, and the SC posted it for a 45-day formal comment period that began Jan. 27 and ended March 12. (See NERC Cold Weather Standard Commenters Say More Work Needed.) Calderon said the delayed submission date was necessary because a “number of comments came in at the last minute” and the team needed more time to review them all. The SC plans to submit any relevant comments to the board along with the standard at its open meeting next month. 

Asked by Barry Lawson of Georgia Transmission whether NERC might consider pursuing “informal” extensions or arrangements with FERC in similar situations in the future, Calderon emphasized that the ERO took this route because of the “exigent circumstances” arising from the exercise of the Section 321 authority. 

“This is not the preferred operation,” Calderon said. “We do intend to file in the future, on time, every time. This was a truncated project with nine months [to finish], and the teams worked diligently over the winter holidays as well. We’re considering this to be extraordinary circumstances, due to the comments, that we will just be filing after that deadline. So it is not an extension or any agreement.” 

Trustee Sue Kelly, the board’s liaison to the SC, said that as a board member, she decided to support the delayed filing after thinking “really long and very hard.” Despite the FERC deadline, Kelly said adhering to the original date would not have provided enough time to “give full faith and credit to the last round of comments.” Chief Engineer Mark Lauby agreed that “there were some very good [comments] in there [that] helped a great deal.” 

Review of Section 321 Planned

With Section 321 now having been invoked twice by the board in the past year, the SC has begun work on a guidance document to formalize its approach the next time the board uses its special authority. 

“None of us wants [Section 321] to come up again, but in the instance that it does, we just want to make sure we can walk through the process in a really efficient manner,” said Vice Chair Troy Brumfield of American Transmission Co., who has been organizing the effort. 

Brumfield said a group of volunteers from the SC will examine both uses of Section 321. The board first invoked the rule in August 2024 to meet a FERC-imposed deadline for standards regarding inverter-based resource performance. (See “Board Invokes Standards Authority to Meet IBR Deadline,” NERC Board of Trustees/MRC Briefs: Aug. 15, 2024.) 

That decision involved Section 321.2-321.4, which called for a technical conference to resolve issues with the standard and a final ballot round with 60% stakeholder approval needed for passage. The board used a different part of Section 321 for the cold weather standard, dispensing with a conference and ballot altogether and putting authority in the SC to revise the standard. 

Calderon suggested that drawing on the SC’s experience could help prevent future delays like the one that affected EOP-012-3. 

“This was the first instance we issued 321.5,” the section used for the cold weather standard, Calderon said. “There’s going to be ample discussion on ensuring that that process is allotting sufficient time, should that be taken in the future.” 

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NYISO Business Issues Committee OKs Firm Fuel Accreditation Concept

The NYISO Business Issues Committee has approved, in concept, implementation of the ISO’s new firm fuel election process and requirements as part of its changes to capacity accreditation. 

The March 18 vote passed unanimously, with only the Market Monitoring Unit and Natural Resources Defense Council abstaining. The Installed Capacity Working Group will vote on revised tariff language before the Management Committee’s March 26 meeting. The ISO aims for a FERC filing in mid-April. 

For several weeks and across multiple working group meetings, NYISO stakeholders have been hammering out the details of the ISO’s firm fuel accreditation improvement project. The project aims to ensure generators that say they have guaranteed (firm) sources of fuel deliver on their promises during winter months. 

The ISO and the New York State Reliability Council are concerned about future fuel supply constraints in the winter. As New York transitions to a winter-peaking system, the downstate gas turbine fleet will find itself competing with home heating for fuel during peak periods. 

FERC accepted NYISO’s capacity accreditation changes in July 2024, but it delayed implementation until 2026 after generators complained of the limited amount of time to make their firm fuel elections: The changes required them to tell the ISO by Aug. 1 prior to each capability year how much of their capacity was covered by firm fuel supply. (See FERC Accepts NYISO Capacity Accreditation Changes, with 1-Year Delay.) 

Other requirements include that resources with firm fuel have supply, transportation and replenishment strategies in place by Dec. 1 of the capability year through the end of winter, and have fuel available to run 56 hours over any consecutive seven-day period in December through February. 

Firm suppliers would not have to submit additional attestation that they have secured fuel, and those downstate and in Long Island would get their own capacity accreditation factor. Failure to meet firm fuel performance obligations by being unavailable because of fuel supply issues on the day-ahead or real-time markets could result in audit and financial sanction. The MMU also may examine suppliers if it identifies concerns with bidding or operational behavior. 

Generators would be sanctioned based on the reason that the firm supply was unavailable, with a 1.5 multiplier added to violators who otherwise could have prevented it; NYISO would use NERC’s guidance for “outside management control” events for the base “1.0” sanction. 

During the ICAP Working Group’s meeting the day before the BIC’s vote, stakeholders wondered whether firm generators could be subject to sanctions if they were told by the ISO they were not being scheduled on the day-ahead market, sold their fuel and then were called on as part of the supplemental resource evaluation program but were unable to respond.  

Responding to this concern during the BIC meeting, Zach Smith, senior manager of capacity and new resource integration for NYISO, clarified that gas-only firm units called in for SREs that don’t respond would be evaluated only to see if fuel was available or if they made efforts to procure fuel.  

“If there was no fuel available and they made those efforts to try and find it, they will not be subject to any penalty for the firm fuel,” Smith said. “If our investigation finds that the fuel was procurable at a price and the entity did not try to get it, they will be subject to the 1.5 penalty.” 

Other stakeholders brought up the 16-month period between the firm fuel election (Aug. 1 prior to the capability year) and the deadline for having supply arrangements in place (Dec. 1 of the capability year). They argued this could lead to situations where a generator elects as firm but its fuel supplier “goes bankrupt” or experiences some other disruption and no longer can meet a firm fuel obligation. Stakeholders asked whether the eventual tariff revisions would include making generators tell the ISO if this occurred by the Dec. 1 deadline. 

Nikolai Tubbs, a market design specialist for NYISO, said the ISO was going include that provision in the procedures manual, not the tariff. 

Doreen Saia, chair of Greenburg Traurig’s energy and natural resources practice, asked whether every financial penalty should be called a sanction. She said the effect of the 1.0 modifier was to put the generator in the position of not having the financial benefit of being a firm supplier, which wasn’t really a sanction.  

“That’s not a sanction to me; that’s an adjustment,” Saia said. “I think we have to step back from calling it a sanction because [issues outside of a generator’s control are treated] no different than the EFORd [equivalent forced outage rate on demand] rules we have today. I don’t get an EFORd hit if the transmission line to my facility goes down.” 

Saia said she agreed with penalizing poor performers but that clarifying the punitive sanction from the non-punitive was necessary so future tariff revisions would be legible. “I guarantee you, six months from now when someone else is looking at this who has not been part of these conversations, they’re not going to get it.” 

Smith said NYISO still was considering whether to use the word “adjustment” or something else. He said the ISO understood her concern and was working on it. 

Market Monitor Proposes Future Firm Fuel Election Changes

Dovetailing off the firm fuel discussion at the ICAP Working Group meeting, MMU Potomac Economics proposed changes it said would better coordinate the capacity market with firm fuel elections. 

The Monitor argued there were several issues with the current structure of firm fuel elections and how they interact with the Installed Reserve Margin study and fuel constraints. At the heart of its concerns is that generators make firm fuel elections roughly 15 months before the winter performance period they are electing for and that these elections cannot be changed. This pushes into a system where the IRM, capacity accreditation factors (CAFs) and unforced capacity prices are interrelated.  

“What we are saying is that there’s a lack of market responsiveness,” Potomac’s Joe Coscia said. “We’re setting the same price regardless of whether there’s more or less fuel relative to the IRM requirement.” 

Coscia said the current system caused problems whether or not firm fuel elections were used in future IRM studies. If they were, generators could over-elect and incur financial losses or under-elect and artificially boost prices. This could increase the volatility of prices and CAFs. If they weren’t used in the IRM, then the market and IRM might not be reflective of actual fuel arrangements.  

“The resource adequacy modeling component should consider how to coordinate these fuel elections in a way that makes sense,” Coscia said. “If you meet the requirements, consumers benefit from it.” 

Potomac proposed moving the firm election deadline to after the final CAFs are published and setting the winter UCAP requirements to satisfy the reliability criteria of the IRM study. This would mean that generators’ firm fuel elections affect the amount of UCAP supplied relative to the reliability requirements, and they would be closer to when generators are sure of having contracts in place, knowing the price of fuel and the price of CAFs. 

The Monitor said that while these changes will not be in place for the 2026/27 capability year, NYISO should discuss implementing them in the long term. 

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ISO-NE Scales Back Vehicle, Heating Electrification Forecasts

As part of a major overhaul of its annual load forecasting process, ISO-NE has significantly scaled back its electrification forecast for electric vehicles and heat pumps.

Prior forecasts relied heavily on state EV targets to estimate load growth due to a lack of data on EV adoption. ISO-NE has compiled data over the past few years, enabling it to better estimate the actual adoption rates in the region, said Victoria Rojo, supervisor of load forecasting and system planning at ISO-NE.

“Comprehensive vehicle registration data has indicated that prior forecasts have exceeded actual EV registrations,” Rojo told the Planning Advisory Committee on March 19.

ISO-NE has indicated its 2024 Capacity, Energy, Loads and Transmission (CELT) report overestimated the adoption of personal light-duty vehicles by more than 70%. As a result, the RTO is reducing its adoption forecasts for all classes of electric vehicles.

To a lesser extent, the RTO also has reined in its forecast for heat pump adoption in the region, reducing its 2025 adoption expectation for Connecticut by 30% and for Massachusetts by 15%. The changes aim to account for “state policies, goals and [the] best available historical installation data.”

While ISO-NE still expects heating and transportation electrification to increase substantially long-term, the updated adoption numbers significantly decrease the energy forecast for the upcoming decade. In its draft CELT forecast, ISO-NE reduced its annual net energy projection for 2033 by 8.2%, from 140,001 GWh to 128,460 GWh.

The RTO also cut its summer peak load projection for 2033 to 26,663 MW, a 1.4% reduction, and dropped its winter peak projection to 24,440 MW, an 8.7% reduction.

This is the second straight year ISO-NE has scaled back its demand forecasts. In 2024 it reduced its 10-year summer peak load forecast by 1.8% and its winter peak by 2.5%. (See ISO-NE Decreases Its 10-year Peak Load Forecast.)

An ISO-NE study looking at 2032 — which relied on the elevated 2023 CELT forecast — found limited risk of shortfall on the New England grid, with the greatest risks coming during extreme winter weather scenarios. (See ISO-NE Sees Little Shortfall Risk for 2032.)

The electrification adoption changes are one component of a revamped forecasting methodology ISO-NE has rolled out for its 2025 CELT report. The new modeling capabilities will enable the RTO to estimate hourly power demand in each load zone more than 20 years into the future. The modeling will rely on zonal, county-level forecasts of electric vehicles, heat pumps and behind-the-meter solar.

“Each forecast component (base load, EV, HP and BTM PV) reflects coincident weather over a 70-year simulation period and are combined into forecasts of net and gross load for each zone and the region,” Rojo noted.

The new methodology also introduces “climate-adjusted weather data reflecting 70 weather years,” Rojo said. ISO-NE previously had not included the effects of climate change in its CELT forecasts.

The modeling also uses energy efficiency as an input to the model, eliminating the need for a separate energy efficiency forecast.

The RTO plans to publish its final CELT forecast in May.

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PUC Adds 2 More Projects to Texas Energy Fund

The Texas Public Utility Commission has advanced two generation projects for due diligence review as part of the Texas Energy Fund’s In-ERCOT loan program, filling a hole left by two proposals that dropped out earlier this year.

The PUC accepted staff’s recommendation during its open meeting March 13 to add NRG Energy and Vistra projects to the TEF portfolio. The companies are seeking $548 million in TEF funds for their 895 MW of potential new generation (56896).

NRG plans to add a 455-MW, quick-start natural gas peaker at its Greens Bayou facility outside Houston. Vistra has proposed a second Permian Power 440-MW natural gas peaker in the Permian Basin. Permian Power I, one of the first projects selected, would be built next to Vistra’s existing 325-MW gas unit near Monahans in West Texas.

PUC attorney Laurie Hobbs said staff prioritized applicants that meet the commission’s priorities, including speed to market, ability to relieve transmission constraints and diversity of dispatchable resource types.

“We’re really trying to still balance as many of the [commission’s] original policy priorities … but we must present you with applicants that can begin timely construction of their projects,” she told the commissioners.

ENGIE Flexible Generation NA withdrew a 930-MW peaking facility from consideration in February, and Howard Energy Partners pulled back a co-generation facility in January. Both companies said supply chain issues would delay the projects and keep them from meeting a December 2025 deadline for initial loan disbursements. (See 2 Companies Withdraw Texas Energy Fund Projects from Consideration.)

“We need to make sure as best as we can that any project we approve going forward can meet these deadlines and be online,” PUC Chair Thomas Gleeson said.

The In-ERCOT portfolio has 19 applications, totaling 9,774 MW of new gas generation, for $5.37 billion in loaned TEF funds.

Deputy Executive Director Barksdale English told the commission that Vistra generator Luminant, NRG, Constellation Energy and Calpine account for 35% of the TEF projects. He said adding more participants would increase competition.

Constellation said in January it plans to acquire Calpine, the nation’s largest operator of geothermal and natural gas power generation. (See Constellation to Acquire Calpine for $29.1B.)

The TEF was created by the Texas Legislature in 2023 to add more dispatchable generation to the grid and was approved by voters later that year. Managed by the PUC, it is designed to provide grants and loans to finance construction, maintenance, modernization and operation of electric facilities in the state.

The fund is composed of four programs: In-ERCOT Generation Loans; In-ERCOT Completion Bonus Grants; Outside-ERCOT Grants; and Texas Backup Power Package.