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December 14, 2025

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Feds Pile on More Barriers to Wind and Solar

The Trump administration has taken further steps to thwart renewable energy development, adding new directives limiting wind and solar development on federal land and at sea. 

Most notably, an Aug. 1 order (SO 3438) from Interior Secretary Doug Burgum prioritizes efficient use of federal land for energy generation — an impossible challenge for sprawling solar and wind farms, which need square miles to generate as much power as a fossil or nuclear plant covering just a few acres. 

In other recent moves, the Department of the Interior’s Bureau of Ocean Energy Management on Aug. 4 rescinded the schedule of seabed leases for offshore wind power development, one of President Donald Trump’s regular targets. 

On July 30, BOEM rescinded designation of all wind energy areas on the outer continental shelf along the East, West and Gulf coasts — more than 3.5 million acres determined to hold the best potential for wind farms. 

A July 29 order (SO 3437) from Burgum ended “preferential treatment” for wind projects and placed new potential hurdles to its development. (See Trump Administration Takes Another Swing at Wind Power.) 

A July 15 internal directive required any and all decisions and actions pertaining to wind and solar at Interior to be reviewed and signed in succession by two high-level deputies and then Burgum himself. (See Interior Dept. Places Solar, Wind Under Close Review.) 

The steady stream of directives is becoming increasingly redundant in their intended effect if not their specified actions. 

There are likely multiple reasons for this, Ted Kelly, lead counsel for U.S. clean energy at the Environmental Defense Fund, told NetZero Insider. If one strategy falls to a court challenge, the others might stand. Also, the administration is very message-oriented: Serial announcements make Interior look good to Trump’s inner circle and make Trump look good to his core constituency, he added. 

The number and tenor of the directives also can create paralyzing uncertainty within the profit-driven private sector. 

“I think we’ve seen it in different areas; they kind of have a dual strategy of, create the uncertainty as much as they can, and then also get to the aggressive attacks when they can,” Kelly said. 

EDF saw this two-track approach with the stop-work order on Empire Wind 1 and revocation of a loan guarantee for the Grain Belt Express transmission line, he added. 

Kelly said EDF is challenging some actions in court, but others are not actionable yet. 

Burgum offered a robust justification with his Aug. 1 order, announcing it as an effort to “Rein in Environmentally Damaging Wind and Solar Projects.” He said the order would better manage federal lands and minimize environmental impact on them: “Gargantuan, unreliable, intermittent energy projects hold America back from achieving U.S. energy dominance while weighing heavily on the American taxpayer and environment.” 

Federal law requires Interior to make judicious decisions about use of federal land and seabed, the news release continued. “These laws ultimately raise the question of whether the use of federal lands for wind and solar projects is permissible, given these projects’ encroachment on other land uses and their disproportionate land requirements, especially when reasonable project alternatives with higher capacity densities are technically and economically feasible.” 

Interior can do only so much to thwart onshore renewables development: It holds sway over public land, but plenty of private land is available. 

Offshore wind energy development, however, is entirely within federal purview, unless the turbines are placed close to shore in state waters — a politically and technically challenging step that has not been proposed. 

On his first day in office, Trump directed a halt to all new offshore wind power leasing and directed an ominous-sounding review of existing leases for potential modification or termination. In the wake of that memorandum, federal permitting reviews and other regulatory work essential to planning an offshore wind farm slowed or halted. 

But notwithstanding the weekslong Empire Wind stop-work order — which actually may have been an attempt to twist the arm of the governor of New York state over natural gas pipeline permitting, rather than a true attempt to stop the wind project — the Trump administration has allowed construction to continue on the five active projects: Coastal Virginia Offshore Wind, Vineyard Wind 1, Revolution Wind, Empire Wind 1 and Sunrise Wind. 

The administration has moved to prevent any steel from being placed in the water on other projects, however, including a revocation of the EPA air permit for Atlantic Shores Offshore Wind and a challenge of the Maryland construction permit for US Wind. 

Wind opponents are suing the federal government (1:2025cv00152 and 1:2024cv03111) for approving construction of US Wind’s Maryland proposals. The government told the U.S. District Court for Delaware on July 28 that it plans to move for a voluntary remand of US Wind’s construction and operations plan. 

If granted, this would send the massive 90-part blueprint approved by the wind-friendly Biden administration back for review by the Trump administration, potentially dooming it. 

Boosting fossil fuel production and sidelining the renewables sector is exactly the turnabout from the Biden years that Trump promised on the campaign trail. 

But it is not good policy, Kelly said, given that major increases in generation capacity are at least five years away for natural gas and 10 for nuclear. 

“There’s the real contradiction and hypocrisy of their insistence, on the one hand, that there’s an energy emergency and that we need to get all generation online as quickly as possible,” he said. “But on the other hand, these clean energy types of projects don’t count as energy, and we’re going to throw up roadblocks in the middle of them, when really they’re the only things, other than some gas plants that are already under construction or under order, we can build in the next five to 10 years.” 

Wind and solar provided 14% of utility-scale generation in the U.S. in 2023 and accounted for 78% of capacity additions in 2024. 

In January 2025, shortly before President Joe Biden left office, the National Renewable Energy Laboratory released an analysis showing federal lands hold the potential for 5,750 GW of utility-scale photovoltaics, 975 GW of geothermal and 875 GW of wind generation. 

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Calif. Fights to Maintain ZEV Momentum

In the face of federal attacks on California’s landmark zero-emission vehicle regulations, the state is “doubling down” on efforts to spur ZEV adoption. 

The California Air Resources Board (CARB) in July completed a series of four public sessions seeking feedback on ways to encourage ZEV adoption — part of an initiative called ZEV Forward. Input from the sessions will help shape recommendations CARB will send to Gov. Gavin Newsom in August. 

“Across the country, people are looking to California to fill that void that now exists at a federal level,” California Transportation Secretary Toks Omishakin said during a session in Sacramento.  

And CARB on July 24 approved amendments to its Advanced Clean Trucks (ACT) regulation to give truck manufacturers more flexibility in complying with the rules. ACT requires truck makers to deliver for sale in the state an increasing percentage of ZEVs over time. 

ACT is a complement to CARB’s Advanced Clean Cars II regulation, under which car manufacturers must provide an increasing percentage of ZEVs through 2035, when all new cars sold in the state must be zero-emission or plug-in hybrid. 

The federal government is now trying to overturn those regulations. 

But CARB has prepared for challenges to ACT. In July 2023, the agency entered into the Clean Truck Partnership with truck makers, promising to provide more compliance flexibility to manufacturers in exchange for a pledge to comply with the regulations regardless of the outcome of litigation or changes to CARB’s authority to enforce them. (See CARB, Manufacturers Partner to Support Clean Truck Rules.)  

“One of the reasons that we were really interested in this Clean Truck Partnership is to provide both certainty to the state and to manufacturers going forward, where there might be a potential for a change in the federal posture around clean energy and clean technology,” CARB Executive Officer Steven Cliff said during the July board meeting. 

The ACT amendments the board approved July 24 include a pooling provision, in which a manufacturer may transfer surplus ZEV credits generated in one state to another state that has adopted ACT.  

Amendments adopted in October 2024 gave manufacturers three years, rather than one, to make up a ZEV credit deficit from a particular year. The amendments also allow manufacturers to use credits from near-zero-emission trucks to make up part of a deficit. (See Calif. Revises Clean Truck Rules to Ease Compliance.) 

The Waiver Battle

In May, Congress adopted three resolutions to roll back EPA waivers that allowed California to enforce three of its clean vehicle regulations: ACT, ACC II and an omnibus rule that sets emission standards for internal combustion heavy-duty trucks sold in the state. 

On June 12, the day President Trump signed the resolutions, California filed a lawsuit in U.S. District Court calling the overturn of the EPA waivers unlawful.  

To rescind the waivers, Congress used the Congressional Review Act, which was designed for overturning federal rather than state rules, according to the complaint. In addition, the EPA waivers are not rules and thus aren’t subject to the CRA, the lawsuit said. 

In addition to California, plaintiffs include 10 other states: Colorado, Delaware, Massachusetts, New Jersey, New Mexico, New York, Oregon, Rhode Island, Vermont and Washington. 

Also on June 12, Gov. Gavin Newsom fired off an executive order “doubling down” on the state’s commitment to clean cars and trucks. 

“We won’t let this illegal action by Trump and Republicans in the pockets of polluters stand in the way of commonsense policy to clean our air, protect the health of our kids and compete on the global stage,” Newsom said in a statement. 

The order directs state agencies, including CARB and the California Energy Commission (CEC), to make recommendations to the governor within 60 days on ways to spur ZEV adoption in the state.  

It also directs CARB to develop an Advanced Clean Cars III regulation “consistent with state and federal law” that would build on existing regulations or provide an alternative if California doesn’t prevail in the court on its regulations. 

Ideas to surface at the July public meetings included offering more incentives and loan programs for ZEV buyers, expanding hydrogen-vehicle infrastructure or offering pooled insurance programs for car share fleet operators. 

Others emphasized the need for approaches that don’t require a federal waiver. 

ZEV Sales Growth

In the second quarter of 2025, 21.6% of new vehicles sold in California were ZEVs, amounting to 100,670 vehicles, the California Energy Commission (CEC) reported. That number is lower than sales in the second quarter of 2024. 

The dip in sales was driven by lower Tesla sales, while non-Tesla ZEV sales remained strong, the CEC said. 

At the national level, EV sales in the first half of 2025 were up 1.5% year-over-year, with 607,089 vehicles sold, according to a report from Cox Automotive’s Kelley Blue Book. Second-quarter figures were down 6.3% year-over-year. 

“With government-backed incentives set to end in September and economic pressures mounting, the second half of the year will be a critical test of EV demand,” Stephanie Valdez Streaty, senior analyst at Cox Automotive, said in a statement. “Q3 will likely be a record, followed by a collapse in Q4, as the electric vehicle market adjusts to its new reality.” 

For medium- and heavy-duty trucks in California, manufacturers sold 131,552 vehicles from model year 2024. Of those, 30,026 were ZEVs, or 22.8%. Cliff provided the figures during CARB’s July board meeting. 

And manufacturers have accumulated about 26,000 more ZEV credits than are needed to comply with ACT, he said. 

Coalition Formed

California is not alone in its ZEV efforts. 

In May, Newsom and governors of 10 other states launched the Affordable Clean Cars Coalition, an initiative organized by the U.S. Climate Alliance. The goal is to make cleaner vehicles more affordable and accessible by reducing costs, increasing options and expanding infrastructure. 

Participants are California, Colorado, Delaware, Maryland, Massachusetts, New Jersey, New Mexico, New York, Oregon, Rhode Island and Washington. 

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Exelon Continues to Explore Getting Back into Generation

Exelon reported earnings of 39 cents/share for the second quarter as it deals with a large pipeline of new data centers and rising wholesale prices that are costing its customers across its six utilities, all in PJM.

“We have remained very active across a variety of federal and state proceedings to solve an ever-evolving set of opportunities to better serve our customers and advance our state’s energy and economic goals,” CEO Calvin Butler said on an earnings call held July 31.

The Illinois legislature examined a broad omnibus energy bill this session that would have affected transmission, energy storage, efficiency and resource planning efforts but ultimately did not pass it.

“The process offered us and other stakeholders the opportunity to discuss critical issues, and we remain optimistic that Illinois will continue to lead the nation in advancing progressive, constructive legislation that enables effective partnership across private and public entities,” Butler said.

Other states like Pennsylvania and New Jersey are looking into ways to expand their power generation supplies as PJM’s market is increasingly tight, which could allow Exelon and other utilities to own generation. Butler indicated Exelon was interested in utility-owned generation in an earlier earnings call, but he offered more details this time. (See Utilities Pushing for Return to Owning Generation in Pennsylvania.)

Through the recently enacted Next Generation Energy Act, Maryland is seeking over 3,000 MW in new supply through a competitive process beginning in October. COO Michael Innocenzo told analysts if that falls short, it could present an opportunity for utility-owned generation.

“It’s clearer now than ever that states should be thinking broadly about how to secure the energy futures for our citizens,” Butler said. “Exclusive reliance on PJM enabled low and relatively steady supply costs for its customers in a period of low demand growth, and when states weren’t yet facing significant turnover in their generation-supply driven by economics, policy and technology.

“But the volatility and unpredictability we are seeing in supply costs, along with a steady increase in warnings from institutions like NERC and [the U.S. Department of Energy] is undermining the faith in the status quo. Despite higher prices, we are not seeing the market respond fast enough. We saw some new generation entry, but demand growth was double that amount.”

Demand response is one of the quickest to market supply options, but despite the tightening supply-demand balance in PJM, the number of megawatts bid into the market fell this past auction, Butler said.

“Bigger, longer-term fixes are available with legislative action, and we stand ready to be part of that solution,” Butler said. “We look forward to continuing the dialogue with our states to be a part of the solutions to ensure energy is delivered reliably and cost-effectively, in a manner that best suits their goals. Time remains of the essence in adding supply to the grid.”

Exelon has 17 GW of large loads in its pipeline looking to connect to the grid (with deposits already paid), and an additional 16 GW are in advanced planning stages but not quite as far. Its Commonwealth Edison subsidiary in Chicago is holding another cluster study window in August, in which several gigawatts of additional projects have shown interest.

Exelon used to be a major player in the power markets with the country’s largest nuclear fleet and a large retail business, but all of that was spun off into Constellation Energy in 2022. If Exelon and other utilities are successful in directly owning generation, Butler said the market would still have a role to play.

“We will continue to partner with PJM, but we do see it as an ‘and’: The competitive markets and regulated generation being part of the solution,” he said.

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Gov. Newsom Proposes Additional $18B for Calif. Wildfire Fund

California Gov. Gavin Newsom is promoting legislation that would add billions of dollars to California’s utility wildfire fund after deadly fires destroyed more than 18,000 homes in the Los Angeles area in January.  

Of the proposed $18 billion, $9 billion would be paid for by utility customers and the other $9 billion by shareholders of each participating utility in the fund. Customer contributions would come from a 10-year extension of an existing non-bypassable charge on customer electric bills that currently expires in 2035, the governor’s office told RTO Insider. 

“This is an existing charge, so customers will not experience an increase in their bills from this proposal, while shareholders will be required to immediately commit to collectively contribute an additional $9 billion,” Newsom’s office said. 

“We continue to work with the Legislature on policy that will stabilize California’s Wildfire Fund to support the recovery of wildfire survivors and to protect California utility consumers — even as wildfires become bigger and more destructive due to climate change,” Newsom’s office added in a separate statement. 

The L.A. wildfires created significant uncertainty regarding the adequacy of the wildfire fund “to protect against electrical corporation bankruptcy risks and undermined confidence in the financial stability of the state’s electrical corporations,” the draft legislation says. 

“The prospect that electrical corporations and their customers could be required to bear, on an ongoing basis, losses of the magnitude of those wildfires is unsustainable,” the draft says. 

Financial markets are demanding higher costs for capital to account for the increased risk of investing in or lending to California’s electric companies, which increase electricity rates, the draft says. The wildfire fund’s durability is “being further compromised by hedge funds and other speculators seeking to profit from the fund,” the draft says.  

After the January 2025 wildfires, some insurance companies sold their subrogation rights to private equity and hedge funds, which “profit by demanding even higher recovery than the insurance companies, draining the wildfire fund’s resources and capacity to pay fire victim claims,” the draft legislation says. 

The draft legislation is supposed to stop hedge fund speculation by capping insurance subrogation claims at 40%, the governor’s office said. 

The state’s wildfire fund began in 2019 after years of deadly fires ignited by Pacific Gas and Electric’s equipment sent the utility into bankruptcy court. The wildfire fund is financed by PG&E, Southern California Edison (SCE), San Diego Gas & Electric and California electricity ratepayers. 

Of the L.A. fires, the Eaton Fire and the Palisades fire were the two most destructive. The L.A. County Fire Department and the California Department of Forestry and Fire Protection (Cal Fire) are still investigating the cause of the Eaton fire, but videos of the fire’s early stages suggest a possible link to SCE’s equipment, SCE representatives said in February. (See SCE Probes Link Between Equipment and Eaton Fire.) 

On July 23, SCE announced a new wildfire recovery compensation program for victims of the Eaton Fire. The program is expected to operate through 2026, a company press release said. 

Separately, the California Public Utilities Commission (CPUC) on July 28 issued a proposed decision that approves SCE’s 2025 general rate case to increase customer bills by $16.15 per month on average. A significant portion of the rate case is for capital expenditures for wildfire reduction risk purposes — about $5.1 billion for wildfire mitigation work from 2025-2028, the proposed decision says.  

The CPUC decision approved about $3.1 billion of the request, “reflecting our judgment that the long-term benefits of these investments justify the costs,” said CPUC administrative law judges Colin Rizzo and Ehren Seybert, who co-wrote the proposed decision. 

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NYISO Drops Seasonal CAFs from Winter Reliability Project

ALBANY, N.Y. — NYISO surprised stakeholders July 29 when, as part of an update on where it was with the Winter Reliability Capacity Enhancements project, it revealed it was no longer considering seasonal capacity accreditation factors (CAFs) because it found they would disincentivize participation in the capacity market.

“We are pretty set on retaining annual CAFs for this project,” Alexis Drake, a senior market design specialist for NYISO, told the Installed Capacity Working Group.

The Winter Reliability project is an initiative by the ISO to consider changes to the capacity market to reflect New York’s transition from a summer-peaking system to a winter-peaking one, and resource adequacy becomes more of a concern in the latter season.

CAFs — which represent the reliability contribution of different resource types, expressed in percentages — are set annually for each capability year. NYISO had considered setting them biannually instead, with winter and summer figures, as part of a broader move toward a seasonal capacity market. Because CAFs historically hinge on the annual loss-of-load expectation, and New York has historically been a summer-peaking system, the figures are more representative of resource adequacy contributions during the summer.

But Drake’s presentation did not contain NYISO’s reasoning for maintaining annual CAFs, leading to attendees expressing frustration and demanding an explanation.

Mike Cadwalader, president of Atlantic Economics, said that working groups are supposed to be the forum where market design, rules and policy are discussed in the open and that he did not appreciate that, according to him, NYISO has been presenting “take it or leave it” proposals.

“This is the first time the ISO has presented its proposal not to do seasonal CAFs, and it’s a pretty compressed discussion,” Cadwalader said. “What you have done is you’ve gone off for the last few months to think about it among yourselves. You have not been discussing with market participants.”

Other stakeholders said they would appreciate a presentation of NYISO’s thinking and internal discussions on seasonal CAFs. Cadwalader and Doreen Saia, chair of Greenberg Traurig’s natural resource practice, asked NYISO to present its thinking quickly so that stakeholders could understand where the ISO was coming from before discussions of tariff revisions occur. Cadwalader said that rushing to tariff revisions before conceptual agreement was “putting the cart before the horse.”

Drake said that from the ISO’s perspective, implementing seasonal CAFs might cause price volatility and disincentivize certain kinds of generators from participating in the market all year. If a resource, like a non-firm gas generator, received a 0% value for a seasonal CAF, there would be no incentive for it to participate in that season.

“We felt it would disincentivize participation, which is not what we are trying to achieve,” Drake said.

The other elements of NYISO’s update did not draw as much attention. The ISO is considering requiring External-to-Rest-of-State Deliverability Rights and Unforced Capacity Deliverability Rights holders to submit distinct seasonal elections for the winter and summer capability periods. These seasonal elections would be subject to a must-offer requirement. To participate in the capacity market during that capability period, the holders would need to offer capacity during the periods they are participating in.

NYISO is also proposing to expand the existing New York Control Area minimum ICAP requirement to develop seasonal requirements. These would still be based on the Installed Reserve Margin study. Seasonal transmission security limits and winter locational minimum installed capacity requirements would also need to be implemented.

With seasonal minimum ICAP requirements, the current seasonal capacity adjustments on the demand curve would not be required because the seasonal requirements directly represent the capacity needed to maintain reliability. NYISO will review the demand curve parameters again to see if any additional adjustments are needed.

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Dominion Reports Continued Demand Growth, CVOW 60% Complete

Dominion Energy reported earnings of $760 million for the second quarter as executives reported continued growth in data center developments in its territory and continued progress on its Coastal Virginia Offshore Wind (CVOW) project. 

“We’re continuing to see strong sales in our service areas, driven by continued data center expansion and economic growth,” CFO Steven Ridge told analysts on an Aug. 1 earnings call. “Notably, nine of our top 10 all-time peak days in Virginia have occurred this year, including six in the last six weeks, and our all-time peak in South Carolina was set just a few days ago.” 

Dominion will release its standard disclosures on data centers later in 2025, which will show continued growth in its contract backlog. Interest in new data centers is as robust as the utility has ever seen, Ridge said. 

The CVOW project is 60% complete, is poised to begin delivering electricity to customers in January 2026 and will be completed later in 2026, CEO Robert Blue said on the call. Construction has continued steadily since the first quarter earnings call, despite tariff uncertainty. (See Coastal Virginia Offshore Wind Sees Costs Increase from Trump Tariffs.) 

“It represents the fastest and most economical way to deliver almost 3 GW of electricity to Virginia’s grid to support America’s AI and cyber pre-eminence in the largest data center market in the world, support U.S. shipbuilding including Huntington Ingalls (the largest naval ship building company in the United States and one of our largest customers), and support some of the country’s largest and most important military and defense installations,” Blue said. 

The project has widespread support among political and economic interests in Virginia and has been fully permitted and approved by federal and state agencies, he added. 

As of the call, Dominion had installed 134 out of 176 monopiles and in July set a record for installing 26 in a month. There are just 42 left and three months of the installation season remaining. Most of the monopiles already have been delivered to the staging area for the project in Portsmouth, Va., with two more barge loads of deliveries needed. 

“Commissioning of the first offshore substation, which was installed on March 10, is now complete,” Blue said. “The remaining two offshore substations are 99% and 70% complete, respectively, and on track to be delivered this fall, with installation to be completed by Q1 2026, as planned.” 

Siemens Gamesa is producing turbines for the project with sections for 58 full towers completed and 12 already delivered to Portsmouth. Unlike the monopiles, turbines can be installed at any point during the year, Blue said. 

The Jones Act-compliant vessel, Charybdis, is nearing completion, with a few final tests required before it can start sea trials that will last a couple of weeks. Once those trials are over, it will take 10 days to get to Virginia from Brownsville, Texas.

“We will install our first turbine in September, which is in line with our original schedule,” Blue said. “We had expected the vessel to complete sea trials last month, which would have enabled us to begin turbine installation ahead of schedule. However, the electric cable terminations that connect much of the ship’s internal communication technology simply took longer to complete than expected. That work has now been complete for several days.” 

The vessel is being delivered a little behind schedule, but its completion in the coming weeks will be a major milestone for CVOW, Blue said. 

Tariffs are impacting CVOW, which is being built with imported material from the E.U. and Mexico. 

“We estimate that the total impact of tariffs as they exist today, through project completion at the end of 2026, would be $506 million,” Blue said. “This is slightly lower relative to our disclosure last quarter, despite a doubling of the steel tariff due to both working with vendors to identify cost mitigation strategies as well as completing our analysis of the final trade regulations and appendices.” 

That number could grow as the Trump administration reportedly is considering 5% higher tariffs for both the EU and Mexico, which would raise project costs by an additional $134 million, though Blue cautioned that was just an estimate and tariffs might not go up at all. 

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ERCOT Technical Advisory Committee Briefs: July 30, 2025

Real-time Co-optimization Project Sailing Through Market Trials

ERCOT says all systems are go — or more specifically, green — and early market trials have been successful as the Real-time Co-optimization plus Batteries (RTC+B) project barrels to its Dec. 5 go-live date. 

Matt Mereness, RTC+B’s project manager, told the Technical Advisory Committee on July 30 that market trials conducted in May and June were successful. Every resource was able to establish connectivity with ERCOT systems and submit at least one bid, and qualified scheduling entities added 99.5% of about 26,000 telemetry points to the current model. 

“Thank you for helping get everything green,” Mereness said as he shared data from the trials. 

The market trials are continuing in July and August, where the focus is on initial real-time market execution and verifying QSEs’ ability to follow ERCOT frequency signals. In September, the optional day-ahead market begins along with a required live-production test to ensure effective frequency dispatch and control. 

“Not perfect, but hey, this was Week 1,” Mereness said. “This is what we expected. ERCOT wasn’t perfect either.” 

The RTC+B initiative began last decade but was delayed by 2021’s Winter Storm Uri. The program will allow the market to optimize ancillary services and energy simultaneously in real time, with the goals of reducing overall costs and making it easier to dispatch energy resources more efficiently. 

NPRRs to be Categorized

The committee’s leadership has scheduled an Aug. 25 workshop to prioritize existing protocol changes and those still being developed. ERCOT’s Keith Collins, vice president of commercial operations, asked for the workshop to balance delivering RTC on time while also addressing legislative directives from the most recent session and the existing backlog. 

Collins suggested dividing Nodal Protocol revision requests (NPRRs) into tiers, with the top tier classified as those that are critical. Other NPRRs would be designated as “what’s that next batch?” 

“When you have these really complicated processes, whether it’s RTC or maybe it’s [fuel] firming … if we keep kind of piling stuff on, we’re going to end up right back where we are,” Collins said. “What we’ve got to do is solve the current problem, and then we’ll work on the other things.” 

Members discussed whether to hold the workshop annually or quarterly. Collins said the pace of workshops has yet to be determined. 

“We’ve got to manage what’s coming into the reservoir and what’s going out of the reservoir,” he said. “If we do an effective job in an orderly way, we’ll sort of move through the backlog and then the stream just flows normally and we don’t have to worry about this anymore. It’s just the backlog is, as noted, large, and it could be years.” 

Garza, Reid Join TAC

TAC welcomed two new members to its consumer segment: former Independent Market Monitor Beth Garza and Air Liquide’s Mike Reid, who will represent the residential consumer and industrial segments, respectively. Garza replaces Eric Goff, who runs Goff Policy, while Reid replaces LyondellBasell’s Eric Schubert. 

Garza led the IMM for more than five years before leaving the position in 2019. She has been a senior fellow with the R Street Institute since 2020. 

‘Penny’ 0.01-MW Bids

Committee members agreed to place all four NPRRs up for consideration on the combination ballot, which is essentially a consent agenda. The NPRRs were all unopposed at the Protocol Revision Subcommittee, responsible for reviewing and recommending protocol changes. 

Members did discuss NPRR1289, which would provide an option pricing report that would be posted following each congestion revenue rights (CRR) auction. The report would contain shadow prices for all biddable source-sink paths for each month within each time-of-use for the auction period. It also establishes a minimum CRR bid of 1 MW. 

“Today, people can use a 10th of a megawatt for price discovery or as a very small investment. So, that’s No. 1: getting rid of a lot of small noise on the quantities, and that is something that does take a system change,” Mereness said. “People have said one of the reasons for the 10th-of-a-megawatt penny bids is so they know the value of a path, and so this report that we need to develop is a source-sink pairing for all options.” 

“At the end of the day, this is a moving target. I’ve said we’re going to be right back here,” said Seth Cochran, with energy trader Vitol. “We need a total state change with our computational power, or we need to figure out other things that we can do.” 

Members agreed to have the Congestion Management Working Group continue to monitor the issue and discuss implementation details. 

The combination ballot included three other NPRRs, three revisions to the Settlement Metering Operating Guide (SMOGRRs), and single changes to the Retail Market (RMGRR) and Planning (PGRR) guides and to the Verifiable Cost Manual (VCMRR) that, if approved by the Board of Directors, will: 

    • NPRR1277: revise the minimum current exposure and estimate aggregate liability (EAL) formulas, improving the efficacy of existing credit formulas that measure credit exposures in the ERCOT market. The EAL formula revisions include applying the real-time forward adjustment factor against the respective days’ real-time liability estimated (RTLE) and then taking the max over the lookback period; and introducing seasonal variability in the lookback period as it is applied for RTLE. 
    • NPRR1281: strengthen the relationship between the settlement of firm fuel supply service (FFSS) and operations by clarifying its hourly rolling equivalent availability factor language to ensure the accurate calculation of the FFSS standby fee. 
    • NPRR1288: simplify the CRR auction by removing the ability to transact in multiple month strips that create optimization issues for ERCOT. 
    • RMGRR183: incorporate various updates that have been implemented as part of previous project improvements to transmission and/or distribution service providers’ Competitive Retailer Information Portal self-service tool. TDSPs will be able to assign weather moratoriums by county name instead of service territory. 
    • PGRR120: prevent generators from interconnecting to the ERCOT grid if they would be radial to a series capacitor under N-1 conditions. 
    • SMOGRR032: incorporate the Other Binding Document “TDSP Access to EPS Metering Facility Notification Form” to standardize the approval process. 
    • SMOGRR033: incorporate the Other Binding Document “TDSP Cutover Form for EPS Metering Points” to standardize the approval process. 
    • SMOGRR034: remove obsolete gray-box language associated with NPRR1020 (Allow Some Integrated Energy Storage Designs to Calculate Internal Loads). 
    • VCMRR044: set the variable O&M in the mitigated offer cap for hydro generation resources to the real-time systemwide offer cap and the incremental heat rate value to zero. 
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Demand Growth Accelerating in the Northeast, Eversource Says

The pace of load growth has picked up across Eversource Energy’s service territories in the Northeast, the company said during its second-quarter earnings call Aug. 1.

CEO Joe Nolan said demand increased by 2% during the quarter, “nearly double the rate observed during the same period last year.”

“As anticipated, electric demand continues to rise, both in the near term and throughout our 10-year forecast horizon,” Nolan said. “In several regions, demand is expected to outpace existing infrastructure capacity, underscoring the critical need for strategic upgrades and new development.”

Nolan said heating and transportation electrification is “further fueling this upward trend” and said the growing demand reinforces the company’s planned investments in grid infrastructure. He highlighted a 10% increase in Eversource’s five-year investment plan, which the company announced in February. (See Eversource to Boost Grid Investments by $1.9B After Exiting Wind, Water.)

Load growth in Eversource’s service territories is reflective of broader trends across the region: After years of relatively flat load because of energy-efficiency programs and behind-the-meter solar, demand in New England has begun to trend upward. ISO-NE experienced its highest peak load since 2013 in June and is forecasting accelerating load growth over the coming years. (See Extreme Heat Triggers Capacity Deficiency in New England.)

Nolan discussed several of the company’s major investments and regulatory proceedings, including investments in advanced metering infrastructure (AMI); a “first-of-its-kind” underground substation in Cambridge, Mass.; construction of an onshore substation for Revolution Wind; and regulatory proceedings in Connecticut and New Hampshire.

He said construction of the AMI communication network in western Massachusetts is “substantially complete” and that Eversource has started construction on its communication network in eastern Massachusetts. He said the company expects the overall deployment of AMI in the state to take about three years.

Construction on the onshore substation for Revolution Wind is “progressing well,” Nolan said, adding that it should be “substantially complete this month.”

He noted that Ørsted said in May that construction on Revolution Wind was about 75% complete. Ørsted said the project should be placed in service in the second half of 2026 and that delays associated with the onshore substation pushed back the overall in-service date for the project. (See Ørsted Remains Committed to U.S. Offshore Wind Projects.)

Nolan also applauded a recent rate case ruling by the New Hampshire Public Utilities Commission, which he called a “constructive decision” that “largely supports our investments on grid modernization, system reliability and necessary infrastructure.”

The PUC authorized an 8.2% distribution rate increase and a $6 hike in the monthly fixed residential customer charge. It also approved a performance-based ratemaking process allowing formula-based increases to rates through 2029.

Nolan praised the “very favorable” regulatory climate in New Hampshire and called the rate case “an example for other jurisdictions.”

But the PUC’s ruling has drawn criticism from New Hampshire Gov. Kelly Ayotte (R) and Consumer Advocate Donald Kreis, who both expressed concern about consumer cost increases stemming from the decision.

“Eversource distribution rates are going up by 24% — well ahead of inflation — at exactly the same time energy charges are also skyrocketing,” Kreis wrote in response to the decision. “What an awful time to be a New Hampshire electric user, especially if your utility is Eversource.”

In Connecticut, where Eversource has frequently butted heads with top utility regulator Marissa Gillett, Nolan said the company continues to have “concerns with certain core components” of the draft decision issued in July in the state Public Utilities Regulatory Authority’s docket on performance-based regulation.

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Vistra to Pay $38M to Settle Decade-old MISO Capacity Market Manipulation Case

Vistra has agreed to pay $38 million to wind down a long-running FERC inquiry into whether it manipulated prices in MISO’s 2015/16 capacity auction. 

Vistra, Dynegy at the time of the alleged manipulation, said it’s ready to pay MISO $38 million, which MISO will distribute to net buyers of Zone 4 capacity in downstate Illinois in the 2015/16 auction and to customers of Ameren Illinois that paid the capacity charge resulting from the auction (ER25-3069).  

Vistra settled with complainants Public Citizen, the Illinois Attorney General, Southwestern Electric Cooperative, Illinois Municipal Electric Agency and the Illinois Industrial Energy Consumers. The agreement was struck first at a May 15 in-person settlement conference.  

FERC in 2024 directed hearing and settlement procedures after its Office of Enforcement in 2022 concluded Dynegy took actions to make sure one of its resources set the $150/MW-day clearing price for Southern Illinois to raise profits. (See FERC Staff Finds Dynegy Manipulated 2015 MISO Capacity Auction.) Vistra purchased Dynegy in 2018.  

In 2024, Vistra tried unsuccessfully to get FERC to back down on some of the findings from its staff. (See Dynegy Unsuccessful in Rehearing Requests of 2015 MISO Capacity Auction Manipulation Case.)  

Vistra Energy’s Coffeen Power Station in downstate Illinois retired in 2019 | Vistra Energy

The company asked FERC to issue an order approving the settlement agreement on or before Aug. 29. The settlement amount is not subject to additional interest, considering the 10 years that have passed since MISO held the auction.  

“While this figure was determined on a black-box basis, negotiations among the settling parties concerned issues such as the passage of time since Dynegy’s alleged actions, the time-value of money and the commission’s regulations regarding interest, demonstrating the importance to certain of the settling parties of speedy approval of the settlement and disbursement of the settlement amount,” Vistra said of negotiations in its Aug. 1 filing.  

The settlement is a fraction of the $429 million in refunds the Illinois Office of the Attorney General at one point claimed were due to Illinois ratepayers. 

The settlement would release Vistra from all claims of market manipulation and attempts to exercise market power in the Zone 4 auction for the 2015/16 MISO planning year and settle all challenges relating to the clearing price. Vistra said it likewise would withdraw all its appeals stemming from the lengthy case.  

Vistra continues to deny all allegations concerning Dynegy’s conduct.  

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New Report: Battery Storage Pivotal for MISO Savings

A new report shows the MISO footprint could ring up $27 billion in additional system costs through 2050 if it and members miss the boat on developing new gigawatts of battery storage.  

The report, from Austin, Texas-based Aurora Energy Research and commissioned by American Clean Power Association, concluded that without a widespread deployment of battery storage in the Midwest, MISO risks higher costs, less robust reliability and a more drawn-out transition to clean energy. 

Aurora said an 11-GW deployment of new battery storage in the Midwest and Central U.S. by 2035 could save consumers several billion dollars in energy costs and fortify reliable operations.  

Aurora’s modeling showed that without battery storage, MISO’s peak energy prices would climb $159/MWh higher during the times of highest demand by 2035, leading to an excess of $4.5 billion spent over 10 years. It estimated MISO would rely heavily on gas peaker plants to meet a 130-GW demand by then, adding an additional $493 million in energy prices and raising the average cost of peaker-generated electricity by $1.75/MWh. The report concluded more storage resources could slash evening energy price spikes by more than 60% between now and 2035.  

Aurora used a “no battery” scenario for comparison purposes, where it anticipated that only 250 MW worth of battery storage is online in the footprint by 2027, followed by a standstill in battery development thereafter. The research firm assumed natural gas prices would rise to about the $5/MMBtu mark by 2035. It also assumed the extension of production and investment tax credits and introduction of an investment tax credit for battery storage.  

Aurora said the more than $4.5 billion that batteries could save in energy costs by 2035 could reach more than $25 billion by 2050. It said its long-term modeling showed $27 billion in savings versus the no battery scenario, with savings originating from lowered wholesale prices on peak and smaller system costs through the flexibility that batteries can provide. 

Aurora’s two study scenarios through 2035, comparing an 11-GW battery storage buildout in MISO to a ‘no battery’ case. Batteries are shaded in yellow on the bar charts. | Aurora Energy Research

Without more battery assistance soon, the report projected that MISO’s wind and solar generation could be 8 TWh lower by 2035. Aurora anticipated a spike in the RTO’s ancillary service costs, with regulating reserve prices potentially increasing 179%.  

MISO has nearly 1 GW of storage online and registered and has about 70 GW of battery capacity in its generator interconnection queue. More than 25 GW of proposed battery storage projects lined up to connect to the system in 2024 alone. Historically, only about 20% of generation proposals ever make it to interconnection agreements in MISO.  

The planning scenario that MISO based its nearly $22 billion long-range transmission portfolio on in 2024 assumed 20 GW of new four-hour lithium-ion batteries by 2024.  

“There are hundreds of energy storage projects in the MISO project queue, working through their lengthy interconnection and permitting process. These projects represent billions of dollars in economic investment, thousands of jobs and billions of dollars in energy cost savings,” the American Clean Power Association said, urging policymakers to act now to help deploy projects.  

“As power demand surges, battery storage is one of the fastest and most effective ways to strengthen reliability and lower electricity bills,” Noah Roberts, American Clean Power’s vice president of energy storage, said in a press release. “Grid batteries deliver massive cost savings for families and businesses, while ensuring that the grid delivers power when it’s needed most. With more than $25 billion in energy savings at stake, this is a generational opportunity for the Midwest to secure a more reliable and affordable energy future.” 

At a July 30 MISO stakeholder workshop to discuss reliability, Clean Grid Alliance’s David Sapper said he hoped MISO could “do better in terms of fostering” battery storage.