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December 7, 2025

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Renewable Construction Slump Starts in 2028, Forecast Shows

U.S. construction of new wind, solar and energy storage facilities will decrease significantly over the next five years, with a cliff dive projected to take place in 2028, a BloombergNEF analyst said in an Oct. 8 presentation to the California Energy Commission. 

About 81 GW of new wind, solar and energy storage capacity is projected to be installed in the U.S. in 2027, falling to around 48 GW the following year, the analyst said. In total, the wind, solar and storage resource buildout by 2030 will be 23% below forecasts prior to the Trump administration’s One Big Beautiful Bill Act. 

The large drop in 2028 will stem from the effects of recent federal policies that will be seen more broadly by that time, Derrick Flakoll, policy expert at BloombergNEF, said at the CEC’s Oct. 8 business meeting. Renewable energy projects are, on the contrary, forecast to increase in the next two years as developers “rush to qualify for federal subsidies,” he said. 

But when the decline happens, it will be due in part to new restrictions placed on countries designated as foreign entities of concern, Flakoll said. 

“For both clean energy manufacturing and clean energy deployment, there are penalizations for … supply chains that are tied to China,” Flakoll said. “For projects beginning in 2026, anything other than energy storage needs to be at least 40% non-Chinese … or non-Foreign Entity of Concern.” 

Although construction of renewable energy projects will drop in the coming years, the impact could have been much harder, he said. 

“One reason we only see that 23% decrease is that renewables are generally the fastest thing to get on the grid,” Flakoll said. 

Wind, solar and storage are on average faster to connect to the grid than gas turbine facilities in all markets, except MISO, he said. 

Offshore wind projects are expected to see the sharpest decline in construction. 

“We don’t really see a lot of offshore wind [projects] coming online through 2035,” Flakoll said. “For markets like California, where floating offshore wind is in early stages, we don’t really see anything happening through 2040.” 

Even though construction of clean energy projects will slow in the U.S., domestic manufacturing of utility-scale energy storage equipment is projected to increase dramatically over the next 10 years, from about 12 GWh in 2025 to more than 60 GWh in 2035. This is due in part to battery manufacturing facilities in the U.S. shifting from making batteries for electric vehicles to building batteries for energy storage. 

“There might actually be enough [battery manufacturing] to meet U.S. demand,” Flakoll said. 

CEC Vice Chair Siva Gunda asked about the cost of EV charging in California versus other parts of the U.S.  

Prices will be different for each market, such as in California versus PJM, Flakoll said. These price differences “are ultimately political choices,” he said. 

“The way that California chooses to pay for certain [energy] programs might have an effect on electricity rates,” Flakoll said. “It is [also] based on California’s changing policy landscape. … We are seeing so much policy change in California as we speak.” 

Idaho Gas Plant Capacity Approved for Calif. Utilities

At the Oct. 8 meeting, the CEC also determined that a new, planned natural gas plant in Idaho meets California’s carbon dioxide emissions requirements. The gas plant can therefore provide capacity to Lassen Municipal Utility District and the Truckee Donner Public Utility District, the CEC said in its decision. 

The CEC specifically found that the gas plant’s emission in Idaho will be below the CEC’s Emission Performance Standard for Local Publicly Owned Electric Utilities, which limits generator facilities to 1,100 pounds of CO2 per MWh of energy. 

The planned 364-MW gas plant will be built in Power County, Idaho and owned by the Utah Associated Municipal Power Systems. It will provide about 7 MW of capacity to Lassen and 5.25 MW to Truckee, with both 30-year contracts starting on July 1, 2031. 

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NYISO Reliability Plan Calls for ‘New Dispatchable Generation’

NYISO released an updated draft of its Comprehensive Reliability Plan for 2025-2034 that calls for the acceleration of new generation development and preservation of “critical, dispatchable capability.”

“New York’s electric system faces an era of profound reliability challenges as resource retirements accelerate, economic development drives demand growth and project delays undermine confidence in future supply,” NYISO writes in the plan’s conclusion. “While this 2025-2034 CRP … identifies no actionable reliability need, this outcome should not be mistaken for long-term system adequacy. The margin for error is extremely narrow.”

This is from the broad range of scenarios for load growth, generation retirement and new generation construction. The majority of NYISO’s scenarios forecast statewide reserve margin declines. (See NYISO Dogged by Uncertainty in Comprehensive Reliability Plan.)

“In the best-case scenario we might have a reliability margin of 2,000 MW,” Ross Altman, senior manager of reliability planning for NYISO, told the Electric System Planning Working Group on Oct. 7. “Worst case, we could be deficient by 10,000 MW.”

The ISO is calling for “several thousand megawatts of new dispatchable generation” by the 2030s.

“Depending on the load and the way that demand grows, the projected [amount] of green generation may not be enough,” Altman said. “Storage and renewables help, but they don’t get us all the way there.”

Environmental stakeholders at the meeting said this amounts to a call for new fossil fuel generation without outright saying it. But Matt Schwall, director of regulatory affairs for Alpha Generation, noted that NYISO did not “parse words” in its comments on New York’s draft State Energy Plan. “They clearly indicate there’s a need for fossil fuel-based generation: retention of existing and installation of new.”

He went on to say that if the word “dispatchable” was an issue, then maybe the term that should be used is “fossil fuel generation.”

“Well, I would ask for the empirical basis of that as well,” replied Michael Lenoff, an attorney representing Earthjustice.

Another stakeholder asked whether the ISO could highlight a “maybe not probable,” but possible, scenario where the reserve margin slips as soon as 2028. The stakeholder said that such a scenario was critical for evaluating the risks to the grid over the next five years.

NYISO recommends that reliability planning move away from a “reactive posture” toward a more proactive approach. The ISO’s preliminary recommendations include:

    • accounting for a wider range of outcomes in reliability planning rather than relying on a single “expected future”;
    • strengthening reliability planning beyond reliance on emergency measures;
    • including more approaches to address resource shortfalls beyond additional transmission planning; and
    • addressing system voltage performance issues from changes in flow patterns caused by distributed generation and large upstate loads.

NYISO said these recommendations may require changes to its planning process manual and tariff, which it plans to discuss with stakeholders in upcoming meetings.

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WPP Board Declines to Delay WRAP ‘Binding’ Phase Commitment Deadline

The Western Power Pool’s Board of Directors has denied PacifiCorp’s request to postpone the deadline by which Western Resource Adequacy Program (WRAP) participants must commit to the first “binding” phase of the program, scheduled for winter 2027/28. 

The board’s rejection comes just three weeks before the Oct. 31 commitment deadline and likely adds to the uncertainty building around how many participants could abandon the WRAP before it enters its penalty phase. NV Energy has already notified the Public Utilities Commission of Nevada of its intent to withdraw from the program. (See NV Energy to Withdraw from WRAP.) 

PacifiCorp CEO Cindy Crane requested a one-year postponement of the deadline in a letter to the board Sept. 30. She contended that the WRAP’s Day-Ahead Markets and Planning Reserve Margin task forces have identified critical issues that have emerged since the program was launched in 2020 — including challenges stemming from the split between participants choosing to join either CAISO’s Extended Day-Ahead Market or SPP’s Markets+. (See PacifiCorp Asks WPP to Delay WRAP ‘Binding’ Phase Commitment Date.) 

In rejecting PacifiCorp’s request, WPP board Chair Bill Drummond said the board determined a delay would have a “detrimental effect” on the WRAP and its participants. 

“Delaying the participant decision deadline or the start of binding operations adds uncertainty, undermines confidence in our data and modeling, limits program compliance and stifles unlocking the full benefits of the program, which can only come with the certainty of binding operations,” Drummond said Oct. 8 in a letter addressed to Crane. 

Drummond added that the board “does not believe that the unilateral board action requested by PacifiCorp aligns with the tenets or the spirit of the established governance process, and driving such a request through the process contemplated by the [WRAP] tariff is not feasible with so little time before the decision deadline.” 

He said the voluntary nature of the WRAP “necessitates a bottom-up, member-driven process to make changes that will affect all participants in the program.” 

Drummond also noted that in September, 11 WRAP members “with substantial load, resources and geographic diversity” affirmed their commitment to the winter 2027/28 binding phase, a development that created “critical mass to move forward with confidence.” (See WRAP ‘Binding’ Phase Set for Winter 2027/28 After Utilities Affirm Commitment.) 

“Any further delay would jeopardize this critical progress,” Drummond wrote. 

Ten of those 11 members have already committed to joining Markets+, which requires its participants to join the WRAP. Starting in 2026, PacifiCorp will be the first participant in the EDAM, which has no RA program requirement. 

Addressing a second request by Crane, Drummond said WPP will continue to work with stakeholders to refine the design of the WRAP, pointing to “work underway to optimize the program in response to suggestions from participants, including task forces addressing some of the challenges you raised in your letter. These efforts are following the same governance process I referenced earlier.” 

Drummond acknowledged that his response might not satisfy PacifiCorp’s concerns about the WRAP and that the utility “may need to provide notice this month of intent to exit the program” before the first binding season. He said the program’s two-year exit notice means exiting participants continue to comply with the WRAP and remain able to engage in the stakeholder process. 

Asked to comment on Drummond’s letter and on whether the board’s response would mean PacifiCorp will not commit to the WRAP binding phase by the end of October, company spokesperson Omar Granados told RTO Insider: “PacifiCorp appreciates the Western Power Pool and its leadership in addressing resource adequacy in the West. We understand the constraints under which WPP is operating. 

“PacifiCorp remains committed to resolving resource adequacy challenges and engaging with regional partners to identify the best long-term solutions for our customers. With this in mind, we will use the time between now and the deadline to determine the best course of action.” 

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ISO-NE Reveals 1st Details of Long-term Transmission Proposals

ISO-NE received six proposals from four different companies in response to its request for proposals to address transmission constraints and interconnect onshore wind in Maine, COO Vamsi Chadalavada told the NEPOOL Participants Committee on Oct. 9.

The costs of the proposals range from about $960 million to $4.04 billion, Chadalavada said. Three of the proposals primarily rely on AC transmission, and three rely on HVDC, he added.

Despite ISO-NE’s attempts to standardize the cost calculation requirements, some of the proposals include the cost of corollary upgrades in their price estimates, Chadalavada said. The RTO will attempt to “create an even playing field” between proposals that included corollary upgrade costs and those that did not, he added.

The Longer-Term Transmission Planning procurement requires proposals to increase the capacity of the Maine-New Hampshire interface to 3,000 MW and the Surowiec-South interface to 3,200 MW, and support the interconnection of at least 1,200 MW of onshore wind in Northern Maine. (See ISO-NE Releases Longer-term Transmission Planning RFP.)

Chadalavada said all proposals claim to meet these basic requirements and that ISO-NE received proposals to increase the Maine-New Hampshire interface to 3,600 MW and Surowiec-South to 3,800 MW.

The Maine-New Hampshire interface currently is limited to 2,000 MW, while Surowiec-South is limited to 1,800 MW. When the New England Clean Energy Connect (NECEC) line comes online — potentially around the end of 2025 — ISO-NE plans to increase the transfer limit of Maine-New Hampshire to 2,200 MW and Surowiec-South to 2,800 because of the upgrades associated with NECEC.

Also at the PC meeting, Chadalavada discussed market operations and performance, noting that energy market costs totaled $358 million in September (based on data through Sept. 30), an increase from $321 million in September 2024.

He said a planned transmission outage from mid-October to mid-November will limit flows from New York to New England to about 1,000 MW and flows from New England to New York to between 500 and 600 MW.

Responding to a stakeholder question about expected power imports from Québec in the coming winter, Chadalavada said ISO-NE’s “expectation is that we are going to see a reduced volume of imports, consistent with the past few years, but when we face really cold conditions, we expect the ties to be fully utilized.”

Imports from Québec have dropped significantly since early 2023, largely because of prolonged drought conditions in the province. Despite the significant reduction in total import volume, Hydro-Québec has continued to send large amounts of power during high-price periods in New England and has earned significant Pay-for-Performance credits in recent capacity scarcity events. (See Drought, Climate Drive Uncertainty on New England Imports from Québec.)

The PC also voted to approve planning procedure and operating procedure changes, including changes that set the load power factor ranges throughout the region. The revisions are “designed to address growing concerns around light-load and high-voltage conditions as the quantity of distributed energy resources on the New England system continues to increase.”

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European Regulator Issues ‘Factual Report’ on Iberian Outages

A new report from Europe’s electric grid regulator has revealed new details about the continent’s power system during April’s mass outages in Spain and Portugal, but insight into the causes of the blackout will have to wait for a follow-up report to be issued in 2026. 

The “Grid Incident in Spain and Portugal on 28 April 2025” document, issued Oct. 3 by the European Network of Transmission System Operators (ENTSO-E), constitutes “a factual record to transparently inform stakeholders and governance bodies” and not an assignment of blame for the mass outages. ENTSO-E is an association of 40 transmission system operators (TSO) spanning 36 European countries. 

The outage began the afternoon of April 28 and left the entire population of Spain and Portugal, as well as parts of France, without power for up to 18 hours. Spain’s government and grid operator Red Electrica released separate reports in June concluding the blackouts occurred because traditional synchronous generation could not provide adequate control of high voltage resulting from frequency oscillations exacerbated by a faulty power plant controller.  

Reviewing those reports, U.S. experts — including NERC Chief Engineer Mark Lauby — said the U.S. grid was unlikely to suffer similar challenges because of reliability requirements put in place by FERC and NERC. Lauby said NERC would have to wait for ENTSO-E’s report “to gain any [further] insights into the incident. (See Lauby Says U.S. ‘On the Right Track’ After Iberian Blackout.) 

An expert panel comprising representatives of affected and non-affected transmission system operators (TSOs), national regulatory authorities, regional coordination centers (RCCs) and the European Union’s Agency for the Cooperation of Energy Regulators wrote the report. ENTSO-E set up the panel May 12 to review the outages as required by the EU’s Incident Classification Scale methodology after an event is classified as a Scale 3 incident, meaning termination of operation of part or all of a TSO’s transmission system. 

Red Electrica, Redes Elétrica Nacional and Réseau de Transport d’Électricité — the TSOs for Spain, Portugal and France, respectively — provided input and suggestions for specific chapters but did not act as primary authors for the chapters on their regions. The report’s authors wrote that this was “to ensure the neutrality of the reports delivered by the expert panel.” 

‘Systems Collapsed’

According to ENTSO-E’s report, at 9 a.m. the day of the incident, Spain’s electric grid began to display increasing variability in voltage. These variations were not significant until shortly after 10:30 a.m., when voltage briefly exceeded 430 kV in part of the 400-kV transmission network. 

When the outages began at 12:32 p.m., the voltage of the 400-kV network was below 420 kV and no oscillations with amplitude higher than 20 MHz were observed. Between 12:32:00 and 12:32:57, 208 MW worth of distributed wind and solar generators in southern Spain tripped offline, while distribution grids experienced a rise in net load of about 317 MW. The report’s authors did not identify a cause of this increase but theorized it “might be due to the disconnection of small embedded generators [of less than] 1 MW or to an actual increase in load,” or both. 

Major disconnection events occurred from 12:32:57 to 12:33:18 in the Granada, Badajoz, Sevilla, Segovia, Huelva and Cáceres regions, leading to an additional loss of at least 2 GW of generation. The reason for most of these trips is not known, though the report attributed an unspecified amount to over-voltage protection.  

No generation trips had been observed in Portugal or France up to this point. That changed between 12:33:18 and 12:33:21, when a sharp voltage increase in southern Spain bled over into Portugal, triggering “a cascade of generation losses that caused the frequency of the Spanish and Portuguese power system to decline.” Both countries’ grids began to lose synchronism with the rest of the European power system at 12:33:19.  

At that point, the automatic load shedding and system defense plans of Spain and Portugal were activated but could not prevent the ongoing collapse of the Iberian grid. At 12:33:20, the AC interconnection to Morocco tripped due to underfrequency, and a second later, protection devices disabled the AC overhead lines between France and Spain. Finally, the HVDC lines transmitting power from Spain to France tripped at 12:33:23 and “all system parameters of the Spanish and Portuguese electricity systems collapsed.” 

The French grid was “marginally affected,” according to the report. France experienced load loss of about 7 MW, and one nuclear power plant tripped offline during the incident. 

A review of RCC data indicated the grid was considered secure at the time of the event and no major issues were known. No congestion had been detected on the Iberian transmission network, and the available production capacity was believed to be sufficient for expected consumption. 

In an email to ERO Insider, Lauby wrote that NERC is reviewing ENTSO-E’s factual report and waiting for the regulator to issue its final report on the root causes of the outage, which is being developed by the same panel and expected in the first quarter of 2026. Lauby called this timeline “typical” for detailed system studies. 

“Overall, the lessons learned have not yet changed — that is, to ensure the actions taken to manage oscillations do not exacerbate the ability [to] manage voltage on the system [and] that generating resources should be enabled to provide dynamic voltage support,” Lauby wrote.  

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N.J. Seeks to Promote Energy-efficient Construction

The New Jersey Board of Public Utilities is looking to stimulate energy-efficient construction with a new program launched Oct. 7 that offers a simpler incentive application process and incentives of up to $2.50/square foot. 

The New Construction Program (NCP) provides builders, developers and project stakeholders with a “single point of entry” through which they can access a portfolio of financial incentives, the BPU said in a release. It replaces several old programs that were accessed independently with a consolidated system that offers “three distinct pathways” designed to meet the needs of different projects. 

Incentives under the new program start at $1/square foot for buildings that are ENERGY STAR certified or meet LEED V4.1 standards, rising to $2.50 for projects that achieve PHIUS certification, the board said. Projects can earn more incentives if they offer greenhouse gas reduction, develop affordable housing, or create industrial and high-energy intensity buildings in priority zones. 

BPU President Christine Guhl-Sadovy called the NCP a “pivotal step forward in making high-performance buildings more affordable and comfortable for New Jersey residents and businesses.” 

“By consolidating our previous programs and offering enhanced incentives, we’re creating clear pathways for builders to deliver energy-efficient buildings that reduce utility costs, improve indoor comfort and support those who choose to pursue clean energy options,” she said. 

Emphasis on Decarbonization

Creating energy-efficient buildings, mainly by electrifying heat and water heating systems, is a key plank of Gov. Phil Murphy’s effort to cut emissions and reach the state’s goal of having 100% clean electricity by 2035.  

The BPU is refining a new Energy Master Plan, a follow-up to the 2019 version, both of which lean heavily on building electrification. (See N.J. Releases Electrification-focused Energy Master Plan.) In December 2023, Murphy signed an executive order setting a goal of electrifying 400,000 additional dwelling units and 20,000 additional commercial spaces or public facilities by December 2030. (See N.J. Advances Multifaceted Building Decarbonization Strategy.) 

The NCP “strongly emphasizes decarbonization technologies, offering bonus incentives for projects incorporating all-electric systems such as heat pumps, helping support builders or homeowners who choose to pursue highly efficient and decarbonized air and water heating systems,” according to the BPU. 

In one of the options, a so-called “bundled pathway” combines several energy conservation measures that can be used on commercial and industrial buildings. A second, “streamlined” pathway offers a much simpler process for projects that harness only energy conservation measures. And a third, “high-performance” pathway allows the developer to obtain the most generous incentives by meeting “nationally recognized certifications.” 

DEP Seeks to Make Electrification Funding Easier

The BPU’s launch of NCP coincided with the announcement by the New Jersey Department of Environmental Protection of a new online tool that seeks to help residents, local governments, nonprofits and businesses find incentives for building electrification and other climate mitigation projects. 

The New Jersey Funding One Stop Shop can help reduce project costs by estimating which incentives are available and what percentage of a project is funded. It asks users about the project and provides information on possible grants, rebates, financing options and a technical assistance program, according to a DEP release. 

Among the target categories for the website are “building energy efficiency” and “energy generation.” The possible funding sources include the state’s $15 million NJ Cool pilot program, which opened in May and provides financial assistance to commercial, industrial and institutional building owners and tenants undertaking retrofit projects that reduce operating emissions from existing buildings. 

Another program reached through the site is one offered by Jersey Central Power & Light, one of four utilities that serve the state, which offers commercial and industrial customers up to $4 million for a “tailored, non-standard energy efficiency project.” 

“The One Stop Shop database is an easy-to-use tool that can help residents, local governments and nonprofits pursue critical green projects, like homeowners installing a heat pump [and] a government transitioning to an all-electric vehicle fleet,” DEP Commissioner Shawn M. LaTourette said. 

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FERC Ends Rule Pausing Pipeline Construction Pending Rehearing

FERC issued a final rule Oct. 7 that removes regulations that paused natural gas pipeline and LNG export facility construction pending appeals in order to encourage the development of plentiful gas at reasonable prices (RM25-9).

The rule reverses Order 871, which stopped the issuance of authorizations to proceed with construction of pipelines and LNG export facilities while rehearing requests were filed in opposition to project construction, operation or need. The order also adopted a policy of presumptively staying projects when a landowner affected by eminent domain protested a project.

FERC cited President Donald Trump’s executive orders seeking to “unleash” U.S. energy and prioritizing the construction of energy infrastructure. (See What is and isn’t in Trump’s National Energy Emergency Order.)

In April, the pipeline trade group Interstate Natural Gas Association of America filed a petition for rulemaking seeking to rescind Order 871, arguing a decision from the D.C. Circuit Court of Appeals affords stakeholders the same protections. The court allowed affected landowners and others to file an injunction halting construction as soon as 30 days after a rehearing request has been filed at FERC.

INGAA also argued the order effectively presumed FERC’s approvals of pipeline are wrong, which subjects developers to unnecessary costs and construction delays. Most of the requests under Order 871 came from parties that do not own land, INGAA said, arguing it had become a tool to delay authorized projects.

FERC issued a proposal to eliminate the order and its rules pausing construction in June, saying more gas pipelines are needed to meet increasing demand for the fuel from end users and power plants, and that pipeline expansion would make both the gas and bulk power systems more reliable.

Opponents included major environmental organizations, who argued that the court decision allowing for quicker injunctions still could let developers start construction on land seized by eminent domain before a stay from the courts was issued. FERC said that those concerns are addressed by existing landowner protections.

“The commission will continue to consider stay requests from landowners on a case-by-case basis, as well as continue the presumptive stay policy established in Order No. 871-B,” FERC said in the final rule. “The presumptive stay policy specifically protects directly affected landowners who would be subject to eminent domain.”

INGAA argued that the change was needed to help meet demand growth in the electricity sector, with FERC summarizing that “additional generation capacity is critical to the nation’s energy security needs, particularly given the development of data centers to advance artificial intelligence.”

Opponents acknowledged that demand is growing, but there is a lot of uncertainty in forecasted data center demand, and much of it will be met by renewable generation.

But FERC said the rule around staying construction was procedural, only delaying projects it found to be in the public interest. “Despite comments suggesting the contrary, it is not the mechanism by which the commission determines whether there is a need for additional energy infrastructure,” FERC said. “The commission continues to evaluate proposed projects under the existing standards in [Natural Gas Act] Sections 3 and 7, as appropriate.”

Even if natural gas generation will decrease over the long term, as some reports indicate, the power grid and natural gas system will continue to be interdependent.

“Even though more renewable energy resources, such as wind and solar, are supplying electric generation, the electric power sector has relied on natural gas over the past decades and continues to do so, which leads to increased interdependence,” FERC said. “Accordingly, an increase in electricity demand, without sufficient natural gas supplies and interstate transportation infrastructure to support such demand, could impact grid reliability even if renewable energy source generation increases.”

Opponents also questioned the value of relying on Trump’s executive orders, which independent agencies are not required to follow. But FERC said that those orders were not the primary basis for its decision. It instead relied on its authority under the NGA and considered the added costs and risks a delay of up to 150 days could cause a project it had previously found to be in the public interest.

“The commission did not rely on compliance with executive policy to justify the regulation’s removal; rather it discussed the executive orders as evidence that the pressing resource adequacy and system reliability concerns have been widely recognized,” FERC said.

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Energy Grants Worth $24B Appear Poised for Cancellation

The Trump administration is gearing up — possibly — to terminate billions more in energy-related grants awarded under the Biden administration.

Media outlets covering energy and politics were abuzz Oct. 7 and 8 after a purported target list was leaked to a few journalists.

The news came on the heels of 321 grant terminations collectively announced Oct. 2 but not individually identified. (See DOE Terminates $7.56B in Energy Grants for Projects in Blue States.)

The new, larger list leaked on Oct. 7 consists of 658 grants totaling $23.88 billion, but it overlaps with the earlier list that emerged Oct. 2.

The U.S. Department of Energy would not comment Oct. 8 on the new list that has been published, but it pointed out the agency’s stated intention had been to continue its review of grants awarded before President Donald Trump began his second term.

DOE Press Secretary Ben Dietderich had the same statement for RTO Insider as for everyone else who asked:

“No determinations have been made other than what has been previously announced. As Secretary Wright made clear last week, the department continues to conduct an individualized and thorough review of financial awards made by the previous administration. Rest assured, the department is hard at work to deliver on President Trump’s promise to restore affordable, reliable and secure energy to the American people.”

Nonetheless, the news media took the ball and ran with it.

But the headline verbs they used pointed to a lack of certainty about what was happening:

Floats. Eyes. Weighing. Mulls. Said to Mull. About to Squash. Threatens to Kill. No Decision Made. Appear Poised.

The Old Gray Lady herself played it with a double caveat: The list “suggests” more cuts “may be coming.”

Advocates were a little more certain with their words, as in the Clean Air Task Force’s broadside headline: “DOE rips funding from over 600 awards.”

But the situation is not always certain with Trump, who has a deliberately unpredictable leadership style.

Could this new, expanded list be the latest in a series of attempts to intimidate or influence one side or the other or both during the government shutdown? DOE certainly isn’t saying.

Furthermore, the grant terminations may not stick. DOE noted that grant recipients have the right to challenge termination and said that some already have begun that process.

The new list of purported grant cuts stretches into Republican strongholds, while the earlier list was heavily concentrated in places that are represented by Democrats in the House and Senate and that voted for Kamala Harris in 2024.

The earlier list targeted grants for two of the seven regional hydrogen hubs that were among President Joe Biden’s signature initiatives. The new list calls for termination of all of them — total value $7 billion.

The other major grants would help fund projects on other research and development tracks that were central to the Biden administration’s clean energy vision, such as electric vehicles, industrial decarbonization and carbon capture.

But sprinkled among the large grants are small awards for efforts to address the multitude of details that crop up in such a broad and ambitious initiative — such as $2.38 million to Bat Conservation International to look for a way to reduce the number of bats killed by the wind turbines that Trump derides.

Colleges in red states and blue states alike are heavily represented on the list, as well as local and state government entities, industry groups and nonprofits.

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Report Projects $19.3B in Benefits from New England Efficiency Programs

Projected energy efficiency investments in New England over the next three years will generate an estimated $19.3 billion in lifetime benefits, returning $2.93 for every dollar spent, according to new analysis by the Acadia Center.

The report makes the case that states should not reduce efficiency spending when seeking to provide short-term rate relief, calling on lawmakers and officials to look for ways to fund programs more equitably.

Retail electric and gas rates in New England are among the highest in the country, and prolonged cold weather over the past winter created significant political pressure for lower rates.

In February, the Massachusetts Department of Public Utilities cut $500 million off the state’s three-year efficiency plan. Meanwhile, Rhode Island Energy has proposed reducing its 2026 energy efficiency budget by over $43 million.

In response to the cuts, proponents of energy efficiency are emphasizing the long-term benefits of these investments, while some have advocated for funding efficiency programs outside of gas and electric rates. (See Advocates Defend Energy Efficiency Programs in Massachusetts.)

The report, which relies on state-reported data on expected spending and benefits, found $6.6 billion in total expected spending across New England over the next three years.

The bulk of this spending — $4.5 billion — is concentrated in Massachusetts. The state also has the highest per-capita spending, followed by Maine and Rhode Island. New Hampshire has the lowest per-capita expected spending.

Different calculation methodologies make it difficult to compare program benefits among states, Acadia wrote. The group noted that calculations related to the social cost of carbon vary significantly between states, “ranging from a low of $0/short ton in New Hampshire to a high of $415 in Massachusetts.”

Despite these differences, “all states demonstrate a benefits/program budget ratio above 1.0, indicating that $1 invested in energy efficiency programs [generates] more value than the initial investment,” Acadia wrote.

The authors noted that Maine reported a particularly high benefit-to-budget ratio. They wrote that the state stands out for high reported benefits associated with electrification investments and a higher portion of the costs shared by participants in the program. While program participants are responsible for 15 to 35% of overall costs in other New England states, participants are responsible for 48% of costs in Maine.

The report also highlights ISO-NE data showing how the allocation of efficiency investments has changed in recent years. While traditional efficiency upgrades like insulation and appliance upgrades still make up most costs, the percentage of spending dedicated to electrification increased from 6% in 2020 to 30% in 2024.

Acadia also emphasized the climate, public health and employment benefits of efficiency investments, writing that efficiency programs “play an instrumental role in creating and sustaining the over ~161,000 energy efficiency industry jobs in the region that currently exist,” and that planned investments are expected to reduce emissions by about 25.3 million metric tons.

Efficiency improvements also lead to region-wide cost reductions in the ISO-NE wholesale markets, the authors wrote. However, quantifying these effects is made challenging by recent updates to ISO-NE’s load forecasting methodology, which “now omits reporting on annual and peak demand reductions from energy efficiency,” Acadia noted.

To ensure the longevity and maximum effectiveness of efficiency programs, “more focused attention will need to be paid toward how programs are funded, how ambition can be increased cost-effectively, who pays, and over what time period are costs incurred,” the authors wrote.

“New funding concepts and reforms in this arena will ensure that ratepayers continue to benefit greatly from efficiency as an energy resource while perhaps bearing less of a direct responsibility to invest in program budgets exclusively through electric and gas rates,” concludes the report.

Mass Save Changes?

In Massachusetts, advocates are supporting a pair of bills (H.3577, H.3529) that would provide state funding for building efficiency retrofits, efficiency upgrades and electrification.

However, advocates may face an uphill battle to overhaul the funding mechanisms for the state’s Mass Save efficiency program in the 2025/2026 legislative session.

Massachusetts Gov. Maura Healey (D) included some changes intended to “streamline program delivery and enhance the customer experience” for Mass Save in a wide-ranging energy bill filed in May, but the legislation largely shies away from major changes that would shift efficiency costs away from rates. (See Mass. Gov. Healey Introduces Energy Affordability Bill.)

Meanwhile, Sen. Mike Barrett, co-chair of the legislature’s Joint Committee on Telecommunications, Utilities and Energy, indicated at a recent hearing on efficiency legislation that a major overhaul of Mass Save funding appears unlikely in the current environment.

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MISO Moves to Increase Quarterly Project Count in Queue Express Lane

MISO wants to increase the number of generation projects it may study under its interconnection queue express lane from 10 to 15 per quarter.  

The grid operator in late September filed with FERC to increase the 10-project quarterly limit and said it wants the change to become effective Nov. 26, days before it kicks off acceptance of a second cycle of expedited generation requests (ER25-3543).  

MISO told the commission the change would allow it to study more interconnection requests in fewer cycles and would enable approved generation projects to more quickly secure generator interconnection agreements. That, in turn, would help address “near-term resource adequacy needs earlier while having a negligible impact on MISO’s workload.”  

MISO still plans to study 68 generation projects but tackle them in fewer cycles and potentially wind down the process earlier than its originally planned Aug. 31, 2027, retirement date.  

The RTO said with the first study “well underway,” it now has “a far better understanding of how [the expedited process] will work in process and has better visibility into what the next several study cycles would look like.”  

“As of today, MISO has already completed most of the initial analysis for the first 10 … projects, which demonstrates that MISO has the capacity to expand the discrete number of projects studied in each cycle,” MISO said.  

FERC in July approved MISO’s interconnection fast lane (ER25-2454). Since then, MISO has designated a 10-project, 5.3-GW first cycle for study among the 26.5 GW of applicants. In total, 47 projects lined up for the chance at an expedited queue study process. (See MISO Selects 10 Gen Proposals at 5.3 GW in 1st Expedited Queue Class and 26.5 GW of Mostly Gas Gen Compete for MISO’s Sped-up Grid Treatment.)  

WPPI Energy’s Steve Leovy said he’s concerned MISO filed for the change abruptly without holding any stakeholder discussions.  “Did it occur to MISO that it might be useful to inform stakeholders of the planned decision to make a filing?” Leovy asked at an Oct. 8 meeting of the RTO’s Planning Advisory Committee.  

Director of Resource Utilization Andy Witmeier said the RTO is aware that it communicated the existence of the filing to stakeholders only as it submitted it to FERC. Witmeier said MISO was under pressure to file in time to allow for FERC’s 60-day response time so the new limit could take effect by the Dec. 1 deadline for the second intake of projects. He said no stakeholder meetings were scheduled during that time.