ERCOT’s Board of Directors on Feb. 25 approved staff’s recommendation to pursue use of 15 mobile generators as an alternative to extending the life of two aging gas-fired units slated for retirement in South Texas.
Staff said during a special board meeting that, based on current cost estimates, LifeCycle Power’s generators and their combined capacity of 450 MW will be more cost effective in mitigating the “relevant reliability risks” in the San Antonio area posed by CPS Energy’s planned retirement of the three units at its V.H. Braunig plant.
Nathan Bigbee, ERCOT’s chief regulatory counsel, said continuing to operate Braunig Units 1 and 2 for two more years beyond their 2025 retirement date is budgeted to cost $59 million, including expected fuel costs and incentive factors or adders. The two units went into service in 1966 and 1968 and have a combined summer maximum rating of 392 MW, according to a CPS update.
In contrast, LifeCycle’s generators are projected to cost $54 million, including fuel costs and incentives. They can reach full output in 10 minutes, faster start times than the three Braunig units. ERCOT and CPS signed an RMR contract on Feb. 24 for Braunig Unit 3, which has a summer max rating of 400 MW.
The age of units 1 and 2 creates additional risks in extending them RMR contracts, Bigbee said. He said the budgets for the two units have increased 8% since November.
“These are both 60-year-old units, so they’re very old generators,” he said. “CPS Energy has told us that these are going to need lengthy outages and expensive inspections and repairs to ensure that they can be safely operated.”
The two units would have to be inspected consecutively, potentially pushing the inspections past the high-demand summer season. They would also have to wait until CPS completes its 60-day inspection of Braunig Unit 3, which begins March 3.
“That just shows you that this is subject to a lot of variability,” ERCOT General Counsel Chad Seely said.
The generators are leased by Houston utility CenterPoint Energy, which has agreed to release its obligation to LifeCycle for two years without compensation. CenterPoint leased the generators and several smaller ones after the deadly 2021 winter storm, but the large generators have sat unused ever since. (The utility says it plans to resize its generator fleet to address future hurricane outages.)
CPS has said it can interconnect the generators in batches to its substations, starting in June and ending by September. The generators will be registered as generation resources and would be the last resources deployed by ERCOT during actual or anticipated emergency conditions, as are RMR units.
One sticking point is the diesel-fired generators’ emissions permitting. Bigbee said the resources might not meet nitrogen oxide gas emissions limits. Staff are working with LifeCycle and the Texas Commission on Environmental Quality to “identify an appropriate solution under the current regulatory framework.”
The board’s decision also begins a 90-day clock for ERCOT to come up with an exit strategy from operating Braunig and the mobile generators. Staff said that involves accelerating three transmission projects south of San Antonio to alleviate the constraint causing the congestion. Two of the projects are scheduled to come into service in 2027 and a third in 2029.
In the meantime, ERCOT and the market are on the hook for $45.85 million under the terms of Braunig 3’s RMR contract. That is the budgeted amount, which ERCOT said is a 33% increase since the first submission from CPS in November.
The RMR contract is ERCOT’s first since 2016, when it entered into an agreement with NRG Texas Power over a previously mothballed gas unit near Houston. The RMR contract ended in 2017, thanks partly to transmission facilities that increased imports into the region. (See ERCOT Ending Greens Bayou RMR May 29.)
CPS told ERCOT in 2024 that it planned to retire the Braunig units in March 2025. However, ERCOT said the plant’s retirement would lead to reliability issues in the San Antonio area until the transmission constraint is resolved. (See ERCOT Evaluating RMR, MRA Options for CPS Plant.)
The Bonneville Power Administration will be on the hook for nearly $27 million in funding for the next phase of SPP’s Markets+ — and potentially more depending on the market’s final footprint, according to a document the RTO filed with FERC on Feb. 21 (ER25-1372).
BPA’s funding obligation — and that of other Markets+ funders — appears in a table appended to the end of the Markets+ Phase 2 Funding Agreement, which SPP submitted to FERC to gain approval for its plan to obtain third-party financing to cover the $150 million needed for the Phase 2 implementation process for Markets+.
The agreement details the purpose, terms and timelines of the financing and outlines how Markets+ funders will collateralize the loan up front and then ultimately fund its repayment through future market transactions. Funders who back out before the market goes live would still be liable for paying their share.
The agreement contains a few provisions that seem specifically tailored for BPA. For instance, BPA’s status as a federal agency prohibits it from posting collateral, so the SPP will instead require BPA to submit a “letter of assurances” committing the agency to cover its obligation.
Another apparent accommodation for BPA is the carve-out Feb. 13 to Aug. 12 as “Stage 1” of Phase 2. During that stage, Markets+ funders will only be obligated to commit to two-thirds of the total spending for Phase 2 — or $100 million. That will allow a funding entity to withdraw from Phase 2 before incurring full charges, a potentially important option for BPA, given that it has committed to funding the market before issuing an official decision on whether to actually join it.
Unclear Liability
But regardless of whether BPA will ultimately be liable for its full share of Phase 2 or only a portion, the Markets+ agreement indicates the agency will likely be obligated to cover more than the $25 million that BPA staff had previously estimated.
The table at the end of the agreement lists the eight entities that have so far publicly committed to funding Phase 2, including BPA, Powerex, Arizona Public Service, Tacoma Power, Grant County Public Utility District (PUD), Chelan County PUD, Salt River Project and Tucson Electric Power.
Absent from the table are two investor-owned utilities known to be leaning in favor of Markets+ — Puget Sound Energy (PSE) and Xcel Energy’s Public Service Company of Colorado (PSCo), as well as El Paso Electric (EPE), which last month committed to join the SPP market despite not having participated in its Phase 1 development process. (See El Paso Electric to Join SPP’s Markets+ in 2028.)
The table shows BPA’s “Stage 1” obligation comes to about $26.8 million in a market footprint consisting of the eight committed funders, slightly above — but in line with — BPA’s previous estimate for its Phase 2 implementation costs.
But another column for full “Phase 2” obligations, which are calculated off the $150 million Phase 2 total, shows BPA’s share increasing to nearly $40.2 million, a figure agency staff did not broach during funding discussions at its most recent day-ahead market stakeholder workshop in late January. (See BPA Considers Impact of Fees in Day-ahead Market Choice.)
Industry sources have told RTO Insider that the $40.2 million figure is likely an outlier and that its Phase 2 funding exposure should decline once entities such as PSE, PSCo and EPE commit to funding, although those commitments are not guaranteed and the agency’s final obligation isn’t clear.
BPA expressed confidence that its funding obligation will decrease as other parties sign on to Markets+.
“The $40.19 million represents BPA’s total share of the Phase 2 development costs based on the current list of funding participants,” agency spokesperson Nick Quinata said in an email. “BPA believes, based on discussions with other Phase 1 participants, that other entities will commit to Phase 2 funding, which will lower each entity’s liability.”
“Each entity’s pro rata share will be recalculated to account for any additional entities that execute funding agreements once their internal and/or regulatory processes are complete,” SPP COO Antoine Lucas said.
Michael Linn, director of market analytics at the Public Power Council (PPC), which represents the publicly owned utilities comprising BPA’s “preference customers,” said his group isn’t concerned about the $40 million figure.
“PPC expects additional entities will announce their intention to fund Phase 2 over the coming months and BPA’s costs will be close to the original anticipated costs,” said Linn, whose group has advocated for the agency to choose Markets+ over CAISO’s competing Extended Day-Ahead Market (EDAM). (BPA staff have estimated EDAM will require lower startup costs than Markets+ but potentially higher annual costs.)
At least one of those announcements appears to be pending. Earlier in February, PSCo filed with the Colorado Public Utilities Commission for permission to join Markets+. The Colorado utility is expected to pay about $20 million to help fund Phase 2. (See related story, PSCo Seeks to Join Markets+.)
‘Mousetrap Situation’
Both Linn and Quinata said the staged funding approach outlined in the Markets+ funding agreement should work to BPA’s advantage.
Linn said it would contain the agency’s costs as uncommitted entities “work through their internal processes prior to executing the agreement,” while Quinata noted it “limits each party’s liability should Phase 2 discontinue for any reason.”
But Fred Heutte — senior policy associate with the Northwest Energy Coalition, which has urged BPA to join EDAM — cautioned that the timelines established in the agreement effectively bind the agency to joining Markets+ before it issues its draft market decision in early March and its final “letter to the region” on the choice in May.
Speaking with RTO Insider, Heutte pointed out that timelines in the agreement require BPA to provide its “letter of assurances” committing to Phase 2 funding by Feb. 28, a week before it issues the draft letter March 6.
“So the timing on this is what’s really interesting, because by the time that Bonneville issues the draft letter to the region, they’ll already have put the financial commitment on the table. It’s not just something they’re considering —they’re already in the game,” making them liable for their full obligation if they pull out after Stage 1, he said.
Heutte laid out a potentially complex scenario in which SPP begins investing in and staffing up for Phase 2 after securing financing this spring, creating an “immediate contingent liability” for the RTO and Markets+ funders such as BPA. Launch of the market in the first half of 2027 would create yet another contingent liability for BPA as it works through its next rate case, because it would then be obligated to begin repaying its portion of the loan whether or not it chooses to participate in the market.
“This is a mousetrap situation. Bonneville’s going to say, ‘Well, you know, we did what we were asked to do, and now we’re kind of in, so we have to stay in,’” he said. “And I have a feeling that, while they are still under a tremendous amount of pressure to have a letter [to the region] say, ‘Well, we’re not going to decide right now; we’re just not going to make a market choice,’ which is what we [NWEC] strongly prefer. The financial hook on this letter of assurances is a pretty big one.”
Marissa Gillett, the top regulator at the Connecticut Public Utilities Regulatory Authority (PURA), is poised to be reappointed amid utility lawsuits and outcry about the state’s regulatory environment.
Tensions between utilities and regulators have escalated during Gillett’s tenure. The utilities have argued that the agency has demonstrated a lack of transparency and threatened their ability to receive a fair return on investments, while Gillett has argued that she is simply holding them accountable to existing laws. (See The Rocky Road to Performance-based Regulation in Connecticut.)
In January, Eversource Energy and Avangrid, which own gas and electric utilities in the state, sued the agency in Hartford Superior Court, alleging that Gillett has illegally issued unilateral decisions on “scores of substantive rulings across a wide range of contested and uncontested dockets conducted by PURA over the past five years.”
“Certain actors at PURA have undertaken a number of unlawful procedures that have the effect of reducing what the legislature intentionally designed as a multi-member agency to the province of one commissioner,” the companies wrote.
Gov. Ned Lamont (D) has stood by Gillett and helped craft a deal to ensure her reappointment on the eve of her confirmation hearing Feb. 20. The administration agreed to appoint state Sen. John Fonfara (D) and former state Rep. Holly Cheeseman (R) to fill the vacancies on PURA’s board, which would return the agency to a full complement of five members.
The deal would also transition PURA from a subsidiary of the Department of Energy and Environmental Protection to a quasi-public agency, enabling the administration to circumvent rules preventing it from appointing sitting legislators to executive-level positions.
At a nearly six-hour confirmation hearing with the legislature’s Executive and Legislative Nominations Committee, Gillett fielded a wide range of questions about her leadership at the agency, energy affordability in the state and utility decarbonization efforts.
She defended PURA against the utilities’ allegations in their lawsuit and said she has not made any final rulings without holding a vote with her fellow commissioners.
“We have votes recorded on every final decision of the agency in accordance with law,” Gillett said. She pointed to PURA’s record in recent court challenges to agency decisions, noting that it has “consistently and repeatedly won when challenged in court — four times at the [Connecticut] Supreme Court.”
Responding to questions about the regulatory environment for the state’s investor-owned utilities, Gillett said PURA has continued to apply “traditional ratemaking principles” and emphasized that its statute makes clear that the burden of proof in regulatory dockets is on the utilities.
In May 2024, Eversource announced its plans to cut $500 million in planned investments in the state because of the state’s “negative regulatory environment.” (See Eversource Announces $500M Cut in Connecticut Investments.) More recently, Eversource and PURA have disagreed over a potential expedited cost recovery mechanism for deploying advanced metering infrastructure, putting the estimated $766 million investment on hold.
“It is the legal obligation of these entities to appropriately invest in the grid,” Gillett said. “If a regulated monopoly is not adequately investing in the grid to meet its statutory obligations of maintaining a safe, reliable and affordable grid, the consequence of that is a revocation of their franchise.”
Gillett also criticized Eversource for not yet coming in for a rate case during her tenure, noting that it “has not been in for an adjudicated rate case since 2014; there was a settlement in 2018. If there is a question of whether the utility has enough revenue to build out and invest in this state, there is a remedy for that, and that remedy is coming in for a rate case before PURA.”
“It is my opinion that it is an unacceptable amount of time for a regulated utility to stay out of receiving scrutiny from not just its regulator, but other stakeholders,” she added.
Gillett said the fight between utilities and regulators in Connecticut is being watched throughout the country and could affect utility regulation in other states.
“The work that my colleagues and staff have positioned ourselves to continue … has been viewed at times as existential threats to traditional ways and business models. I think folks should understand that this is being watched and does have larger implications,” Gillett said.
Legislators focused much of the hearing on energy affordability in the state, which has some of the most expensive electricity rates in the country.
“People are telling us that they are suffering; they are truly having to make a decision between paying their utility bill … and having to give something up in exchange for that,” state Sen. Eric Berthel (R) said.
Gillett pointed to a significant recent increase in the public benefits charge for Eversource ratepayers as a key cost driver, which she said was largely from unrecovered costs associated with the power purchase agreement for the Millstone nuclear plant. She said she voted against the 10-month increase in the charge, which will conclude at the end of April, but was overruled by her fellow commissioners.
Environmental justice advocates attending the hearing voiced their support for Gillett, while the committee voted along party lines to support her reappointment. She still must be confirmed by the General Assembly, where Democratic legislators hold large majorities.
Avangrid declined to comment on Gillett’s renomination and the agreed-upon changes to PURA’s makeup. Eversource wrote in a statement that “the planned changes provide a pathway for a constructive, predictable and transparent regulatory environment that benefits customers through investment and a focus on reliability.”
Holtec has set a 2030 target for commercial operation of two small modular reactors to be built beside the large nuclear plant it is working to restart in Michigan.
The company’s Feb. 25 announcement also laid out a roadmap for Holtec and Hyundai Engineering & Construction to build a 10-GW fleet of SMRs elsewhere in North America through the 2030s.
Both announcements build on existing plans and an existing alliance between the two companies.
They said their respective construction expertise and in-house manufacturing capabilities will be key to increasing the speed and decreasing the cost of SMR construction compared with the few recent large-scale U.S. reactor projects, which have been restrictively slow and expensive.
Holtec’s SMR-300 initiative is just one of several small modular reactor development efforts. The 2030 target date for commercial operation makes it one of the more ambitious efforts, but the concept is similar: Standardize the design, increase deployment and develop economies of scale, rather than intermittently building what amounts to a series of first-of-a-kind projects.
“The key to making SMR deployment faster and more cost effective isn’t just learning from the industry — it’s applying those lessons directly to each new project,” Rick Springman, Holtec’s president of global clean energy opportunities, said in a news release. “With Holtec’s in-house manufacturing and Hyundai E&C as our construction partner, we control most of the process, allowing us to refine and improve with every reactor we build. That’s how we scale smarter and deliver reliable energy where it’s needed most.”
The two companies held a launch ceremony Feb. 25 at Michigan’s Palisades nuclear plant, which Holtec acquired from Entergy when it shut down in 2022. Holtec initially planned to decommission it but now is preparing the 54-year-old 800-MW reactor for a first-of-its kind restart. The company received a $1.52 billion federal loan guarantee for the project in March 2024.
Holtec said it has invested more than $50 million in SMR-300 site development efforts and expects to start its formal permitting process with the Nuclear Regulatory Commission next year.
Holtec began collaborating with Hyundai E&C in 2021, and the two have now signed an expanded cooperation agreement for SMR-300 construction.
The SMR-300 is a 300-MW advanced Generation 3+ pressurized light water reactor design. Holtec’s intention is to build the plants, service them through their operational life, manage spent fuel and perform decommissioning.
Multiple other companies and consortia are pursuing SMRs, and many potential customers are keenly interested in them as a non-intermittent source of emissions-free electricity, but SMRs still must reach a long series of engineering, regulatory, financial, supply-chain and political milestones before they are deployed at scale.
Hyundai E&C CEO Han-Woo Lee said in the news release that the partners intend to do just that: “To ensure the successful completion of this project, we will work closely with the U.S. government and leading local companies to build a systematic supply chain, create and develop high-quality jobs in the U.S., and develop strategies for mutual growth with local communities, ultimately pioneering a new era in the global SMR industry.”
Xcel Energy subsidiary Public Service Company of Colorado (PSCo) has asked the Colorado Public Utilities Commission for permission to join SPP’s Markets+, saying the market option would not lock “the company into other markets which have suboptimal policies for customers and Colorado’s state goals.”
In a Feb. 14 filing, PSCo requested that the commission find it is in the public’s interest that the utility join SPP’s Markets+ while also asking for approval of modifications to the electric commodity adjustment tariff to recover costs associated with its market decision.
Specifically, PSCo seeks recovery of approximately $2 million in Phase 1 funding fees. The company also seeks recovery of costs associated with Phase 2 of Markets+, including approximately $14 million in administrative fees during the first five years of market operations and about $13 million to $15 million in technology upgrades, according to the filing.
Gerald Deaver, a commission adviser sitting in for CPUC Chair Eric Blank during a Feb. 21 Markets+ State Committee, said, “PSCo indicates in the filing that it would enter into the Phase 2 agreement as quickly as it could after a commission order approves their participation.”
PSCo “has evaluated several alternatives to Markets+, including the SPP RTO expansion and CAISO EDAM,” the filing stated. “The company’s analysis concluded that, at this time, participation in Markets+ provides the best option to retain the benefits of market participation while not prematurely locking the company into other markets which have suboptimal policies for customers and Colorado’s state goals.”
The company said it favors Markets+ for several reasons, including its governance structure, benefits “overall and in relation to costs relative to the other markets studied, including EDAM,” and Markets+’s greenhouse gas emissions tracking and accounting system.
PSCo also said “Markets+ is the only organized day-ahead market proposal for the West that will have a fully impartial and independent market operator, providing confidence that all market operator actions will be for the benefit of all participants and stakeholders.”
Markets+ supporters have repeatedly touted the benefits of the market’s independent governance in comparison with CAISO’s state-backed governance, an issue supporters of the ISO’s EDAM and Western Energy Imbalance Market have been attempting to address through the West-Wide Governance Pathways Initiative. (See Pathways ‘Step 2’ Bill Sets Conditions for EDAM Governance.)
“Over the past 10 years, through the successful implementation of the Western Energy Imbalance Market, regional coordination has proven an essential tool in maintaining grid reliability and lowering costs for electricity consumers in California and across the West,” CAISO spokesperson Jayme Ackemann said. “We look forward to continuing that work as we move [toward] the launch of the Extended Day-Ahead Market in 2026, which will build upon the benefits of the WEIM for all participants.”
In an email, Xcel spokesperson Tyler Bryant told RTO Insider that the company has been involved in the development of Markets+ since 2022. Bryant said the company believes joining Markets+ is in the public interest based on CPUC’s criteria.
Antoine Lucas, SPP vice president of Markets, said the RTO is pleased with the application and the company’s continued participation in Markets+.
“SPP values their unique voice as an entity representing the Mountain West region and the specific needs of Xcel customers, and we look forward to their engagement in phase two of Markets+ development,” Lucas said.
‘Thoroughly Intermeshed’
But not everyone is thrilled with the decision.
In an interview with RTO Insider, Brian Turner, director of Advanced Energy United, contended that the application lacked sufficient analysis of climate change impacts and the purported costs and benefits to Colorado ratepayers.
Turner also said the decision will create market seams within Colorado. He noted that Colorado-based Tri-State Generation and Transmission — which sells energy to utilities all around the Centennial State — has indicated it will join SPP’s full RTO as that entity expands into the West.
Meanwhile, the utilities that buy power from Tri-State have each indicated they will join different markets, some going with Markets+, others committing to SPP RTO, and others joining no market, Turner said.
The transmission systems of Xcel and Tri-State “are thoroughly intermeshed,” according to Turner.
“The seams between Xcel, going with Markets+, and Tri-State, going with SPP RTO and [Tri-State] having its own issue with seams with individual co-ops, is going to be a very major issue here, and one that should be raised to Colorado policy makers and is not,” Turner said.
“I fear the Colorado utilities, and therefore, policymakers, and therefore, rate makers, are headed down a road to a very limited market with lots of costs and reliability risks from the seams and the limited market that they’ve set themselves up with, basically driving down a dead-end road,” Turner said.
Public Service Enterprise Group saw an “over-12-fold” increase in mature leads and inquiries from customers exploring “large load and data center projects” over the past year, CEO Ralph LaRossa said in the utility’s fourth-quarter earnings call Feb. 25.
The suggestion of a potentially expensive surge in demand comes after several quarters in which LaRossa has touted the utility’s South Jersey nuclear generators — Hope Creek and Salem — as primed to accommodate the needs of data centers and artificial intelligence developers. Company officials have suggested they are an important part of the utility’s future expansion and of helping the state boost its economy. (See Data Center Opportunity is Strong, Expanding, PSEG CEO Says.)
The volume of inquiries totaled 4,700 MW in the last year, compared to about 400 MW in 2023, LaRossa said. The average size of the leads in 2024 was 100 MW, and the customer inquiries even included some “large electric vehicle interconnections,” he said.
“Approximately 25% of the 4,700 MW of new business leads have been incorporated into PJM’s 2025 system peak load forecast,” he noted.
NJ Wind Port
Responding to an analyst’s question, utility executives rebuffed suggestions that the utility’s ability to develop such projects would be affected by recent FERC rulings.
The ruling gave PJM and its transmission owners 30 days to answer a series of questions about whether the RTO’s tariff needs updating to accommodate co-location arrangements.
“We continue to have discussions with multiple parties for various elements of what we’re talking about, and that interest remains strong,” CFO Daniel Cregg said.
“It would have been great to have complete answers throughout everything from what FERC said,” Cregg added. “I don’t know that we necessarily expected that, and we’ve got to wait for some [details]. But I think directionally, what they said was favorable for the flexibility to do what you want to do, and those details have yet to be written, so we’ll continue to see what happens there.”
LaRossa said he hoped for more “clarity” from FERC on the issue in the future but added that “it’s not stopping anything.”
New Jersey has spent more than $500 million to develop the New Jersey Wind Port adjacent to PSEG’s nuclear plants, off the Delaware River, with a goal of serving the state’s nascent offshore wind sector. However, state wind projects have largely stalled amid economic and supply chain difficulties, as well as opposition from the Trump administration. (See NJ Abandons 4th OSW Solicitation.)
LaRossa noted that the New Jersey Economic Development Authority announced recently that it is looking for alternative uses for the port.
“That’s one thing that we just want to point out,” he said. “And we know that there’s some interest, from the governor’s standpoint and from New Jersey’s standpoint, to continue for us to look to pursue these opportunities.”
The sheer volume of inquiries shows that “there’s interest from the industry in New Jersey” and that the state’s effort to market itself to large load clients “has been working,” LaRossa said.
Fall in Earnings
Cregg said the utility plans to invest $3.8 billion in 2025 in regulated investments on “infrastructure modernization, energy efficiency and meeting growing demand and electrification initiatives.”
That expenditure is part of an expanded five-year regulated capital investment plan of $21 billion to $24 billion between 2025 and 2029, an increase from the previous planned $18 billion to $21 billion, he said.
PSEG’s fourth-quarter results for 2024 fell from $546 million ($1.10/share) in 2023 to $286 million ($0.57/share). Non-GAAP operating earnings for the quarter were $421 million ($0.84/share), compared with $271 million ($0.54/share) in the same period last year.
Full-year 2024 earnings were also lower than those of 2023. The company reported net income of $1.772 billion ($3.54/share), compared with $2.563 billion ($5.13/share). Non-GAAP operating earnings were $1.839 billion ($3.68/share), compared with $1.742 billion ($3.48/share).
When geothermal startup Fervo Energy went out for its first round of venture capital funding in 2018, it pulled in $500,000, co-founder and CEO Tim Latimer recalled. “It’s just not a sector that the investment community was excited about.”
Fast forward to 2024, and investments in the company — which uses fracking technology to tap into hard-to-reach geothermal reservoirs — totaled just under $500 million, Latimer told the audience at a panel discussion hosted by the Atlantic Council on Feb. 20 in D.C.
The company’s roster of investors now includes cleantech leaders like Bill Gates’ Breakthrough Energy Ventures, as well as Devon Energy, a major oil and gas producer based in Oklahoma.
“I think this is a perfect example of the oil and gas industry getting into [geothermal],” he said. “People are viewing this as a bankable, mature technology for the first time. … It just has all these solutions that the world needs right now in terms of an energy resource, and so there’s enormous momentum to widen the aperture for what geothermal can do, and the technology to get it done.”
High-tech companies are looking for 24/7, carbon-free electricity to power their massive artificial intelligence data centers, and the “enhanced” geothermal systems developed by Fervo and others are increasingly seen as an essential part of the portfolio of resources that will be needed.
Fervo’s first demonstration project in Nevada is now providing power to Google data centers under an innovative “clean transition” tariff. The company is building its first utility-scale plant in Utah, with Southern California Edison signed up for two 15-year contracts for 320 MW.
Building on oil and gas industry buy-in, enhanced geothermal also has broad bipartisan support at the federal and state level.
The U.S. only has about 3 GW of geothermal energy online, most of it in California. But the Biden administration saw enhanced geothermal systems adding as much as 300 GW of new capacity to the grid by 2050, according to a report issued by the Department of Energy in March 2024.
New Energy Secretary Chris Wright is also a fan. Liberty Energy, the fracking company he led prior to being tapped to lead the department, is another one of Fervo’s investors, and in his first order as secretary, Wright listed geothermal as one of the advanced technologies the Trump administration will continue to develop and support.
Colorado Gov. Jared Polis (D) launched a regional effort, the Heat Beneath Our Feet Initiative, during his term as chair of the Western Governors’ Association from 2023 to 2024.
“If you look at a map of natural geothermal resources in the United States, you’ll see the West is a hot spot — pardon the pun, but it really is,” Polis said in an onstage interview with Jeremy Harrell, CEO of ClearPath, an energy policy nonprofit. “That’s where it is likely to be, and is, most economical, most deployable, [with] the highest levels of heat subsurface.”
Polis worked to restructure his state’s oil and gas commission into the Energy and Carbon Management Commission. While continuing to permit oil and gas projects, the renamed commission is now permitting geothermal in “an analogous way,” he said.
“They’ve done their rules around that in consultation with the industry and set up what I think is one of the most expedited, reliable permitting regimes for geothermal in the country,” he said.
The final report on the Heat Beneath Our Feet Initiative similarly calls for geothermal exploration to receive the same tax incentives as oil and gas exploration, a proposal that “has big bipartisan support in Congress,” Harrell said.
The Oil and Gas Connection
Traditional geothermal power plants draw superheated liquids from naturally occurring underground reservoirs to the surface to create steam to run turbines. These plants are typically located near underground tectonic rifts, meaning they are geographically limited.
For example, Iceland sits on the Mid-Atlantic Ridge, where the North American and Eurasian tectonic plates meet, allowing the island country to run its heat and electricity largely on geothermal energy.
The enhanced geothermal technology developed by Fervo and others uses the fracking and horizontal drilling technologies developed by the natural gas industry to tap into dry “hot rocks.” With horizontal, or directional, drilling, Fervo can drill multiple wells from a single site on the surface, according to the company.
Increased efficiencies in drilling are bringing down prices, according to the 2024 DOE report. The national average cost of enhanced geothermal could fall to $60 to $70/MWh by 2030 and drop still further to a highly competitive $45/MWh by 2035.
The quick movement down the price curve is drawing more investment to Colorado, according to Polis. Mt. Princeton Geothermal and Western Geothermal, both Colorado-based geothermal companies, are partnering with Iceland’s Reykjavik Geothermal on developing wells in the state.
But enhanced geothermal can also leverage other lessons learned from the oil and gas industry, said Morgan D. Bazilian, professor of public policy at the Colorado School of Mines. Geothermal researchers are looking at “what the oil and gas industry learned about community engagement, what the industry learned about project management, what the industry learned about finance and … what the industry learned about permitting and how to deal with mineral rights.”
The transferability of workforce skills between oil and gas and geothermal is another strong selling point.
Talking geothermal at the Atlantic Council on Feb. 20 are (from left) Reed Blakemore, Atlantic Council (moderator); Morgan Bazilian, Colorado School of Mines; Brian George, Google; Ravi I. Chaudhary, former assistant secretary of the Air Force; Fervo Energy CEO Tim Latimer; and Jack Waldorf, Western Governors’ Association. | Atlantic Council
Fervo’s Latimer noted that crews working on his company’s Utah project came from North Dakota, where they were drilling oil wells. While the U.S. has lost leadership in solar and storage manufacturing to China, “we have never lost the lead in drilling. Nobody in the world has the skilled workforce out there that the United States does when it comes to drilling.”
“We can easily transition those skills directly” to geothermal, he said. “There’s no retraining required. If you’re drilling an oil well one day, you can do geothermal the next.”
In the same way, coal plant operators can transition to operating geothermal plants, Latimer said. “You look at a geothermal power plant: You have rotating equipment and turbines and heat exchangers and pressure control equipment. It’s the exact same skills” as for coal.
Bazilian cautioned, however, that attracting and keeping a skilled workforce for geothermal could be difficult. Graduates from the Colorado School of Mines typically field multiple high-paying job offers, and not only in the energy sector.
“They’re going to where there’s excitement, or there’s some kind of value-add for them, or where they’re making the best salaries,” he said. “If we don’t find ways to make [geothermal] exciting … then we will fail to train the workforce of the future we need.”
National Security
The panel also touched on a less obvious but essential application for geothermal: providing emergency power and reliability at U.S. military bases.
“We’re in the midst of a decade of consequence in which potential adversaries are looking at ways to gain a strategic advantage against our nation,” said Ravi I. Chaudhary, former assistant secretary of the Air Force for energy, installations and environment.
“We’ve got to bring up our game in innovation over the next decade; otherwise our adversaries will; our global competitors will,” Chaudhary said. “Geothermal is a natural methodology by which we can build redundancy and ruggedize our installations against potential threats.”
He pointed to pilot projects at Air Force bases in San Antonio, Texas and Mountain Home, Idaho, where geothermal systems under development would be able to disconnect from the grid and keep operations going at the bases in case of a disturbance or other emergency on the grid.
At Mountain Home, for example, should a “civil disruption” affect the electric grid, an islanded geothermal system would allow the Air Force to “get the jets out of town quickly … and then plug back into the grid so we can distribute that energy to prevent more civil disruption,” Chaudhary said.
“We can ill afford to move at the speed of government these days,” he said. “We have to move at the speed of the threat … and when it comes to national security and across the board, the speed of innovation.”
The challenges for enhanced geothermal include transmission, permitting, and market and regulatory structures. Project and transmission permitting can be especially difficult in some Western states, which have millions of acres of public land under federal jurisdiction. In Colorado, public lands cover 36% of the state, Polis said, while in Nevada, the figure is more than 85%.
Google and the Grid
Brian George, the U.S. federal policy lead at Google, sees enhanced geothermal and partnerships with companies like Fervo as key components of the portfolio of clean energy resources his company is looking at to power its data centers.
“I tend to think a lot about what are the regulatory structures that we need to have in place to be able to bring on these types of new resources that are in stages where they require significant capital investment, right?” George said. “It’s going to require a little bit of a nudge from companies like Google … to bring on the resources that do provide that 24/7 baseload power in a way that all grid customers can benefit from the reliability and clean benefits of these resources.”
At the same time, he said, transmission must become a bipartisan issue, rather than being seen as “an enabler of wind and solar.”
“Transmission is a tool to unlock economic and national security. It is a tool for us to bring more loads onto the grid, for new manufacturing entities to bring new plants onto the grid, for new resource developers to bring new generators on the grid,” he said.
“There’s a ton of demand; there’s a ton of capital ready to go,” but it’s waiting to see if transmission will be built to connect new energy to the grid, George said. Federal, state and local governments will all have a role to play, he said.
“The last thing we need to do is come in with a very heavy-handed approach, and say, ‘This is the line that shall be built,’ without consulting governors and county councils and local entities. It has to be a collaborative process. …
“Our view is that the grid should be planned in close partnership with developers and off-takers and utilities in a way that enables that grid to grow and work for everybody,” he said.
Co-locating new data centers with generation could help “to accelerate the addition of new loads and new generation to the grid,” George said. “But I would just underscore that the reliability, resilience and economic points that the grid provides are difficult to match.”
The policies of the Biden administration will continue to shape the U.S. power portfolio a while longer, even as the Trump administration tries to make a hard right turn from renewables back to fossil fuel.
The U.S. Energy Information Administration on Feb. 24 said solar and battery storage dominate planned electric generation capacity additions to the U.S. grid in 2025, with natural gas providing only 7% of the 63 GW total.
Even the wind turbines that Trump wants to halt are expected to outstrip natural gas, with 7.7 GW of new wind capacity vs 4.4 GW of new gas-fired generation. EIA noted, however, that the data behind its projections was generated in December 2024, a month before Trump began a rapid-fire attempt to limit renewables and boost fossil fuel development.
In total, EIA projects 2025 additions of 32.5 GW of solar, 18.2 GW of storage, 7.7 GW of wind, 4.4 GW of gas and 0.2 GW of all other forms of generation.
That is nearly 63 GW — about 29% higher than the 48.6 GW installed in 2024, which itself was the largest single-year addition since 2002.
The 30 GW of solar added to the grid in 2024 was a record, and EIA expects solar installation to set another record in 2025, with Texas once again accounting for the lion’s share of projected new photovoltaic capacity: 11.6 GW.
Likewise, the 10.3 GW of battery storage installed nationwide in 2024 was a record, and EIA expects 2025 installations to far surpass that total. (EIA includes batteries in the generation capacity tally as a secondary source of stored electricity, not as a primary source of electrical generation.)
Wind is expected to bounce back from a slump: The 5.1 GW added in 2024 was the least since 2014. But EIA’s 2025 projection of 7.7 GW of new wind power is off by more than 9%, as it includes 715 MW from Revolution Wind, an offshore wind farm that has pushed its completion date back to 2026.
EIA also assumes Vineyard Wind 1 will come online in 2025. The 800-MW facility began construction off the Massachusetts coast in late 2022, with an anticipated 2024 in-service date. But it experienced significant delays and component failures in 2024, and in early 2025, it is well behind schedule, with no anticipated completion date listed on the project website.
Simple-cycle combustion turbines account for about half of the 4.4 GW of new natural gas-fired capacity projected to come online in 2025, and combined-cycle units account for about a third.
EIA said five states — Utah, Louisiana, Nebraska, North Dakota and Tennessee — account for about three-quarters of the expected gas additions, the largest of which are the 840-MW Intermountain Power Project in Utah (where 1,800 MW of coal-fired capacity is being retired) and the 679-MW Magnolia Power in Louisiana.
EIA reports that in 2023, 4.18 trillion kWh of electricity was generated at utility-scale facilities in the United States — 60% fossil, 21.4% renewable and 18.6% nuclear.
The largest components were natural gas (43.1%), atomic fission (18.6%), coal (16.2%), wind (10.2%), hydropower (5.7%) and photovoltaic solar (3.9%).
The Eastern Interconnection Planning Collaborative on Feb. 24 urged FERC to not use NERC’s Interregional Transfer Capability Study (ITCS) “as a metric for determining prudent additions” to transfer capability on the grid (AD24-5).
In comments filed with the commission on the study, EIPC — an association of 18 planning authorities from the Eastern and Central U.S., including PJM, ISO-NE, NYISO, Duke Energy, Dominion Energy and the Tennessee Valley Authority — also commended NERC for the “enormous task” carried out by the ERO in a short time frame, and thanked the organization for working with industry stakeholders during the study.
NERC submitted the final installments of the ITCS to FERC in November, ahead of the December deadline set by Congress in the Fiscal Responsibility Act of 2023. (See NERC Files ITCS to FERC, Meeting Congress’ Deadline.) In the FRA, Congress directed NERC to submit to FERC a study detailing current transfer capabilities across the North American grid, recommendations for prudent additions to transfer capability that could strengthen grid reliability, and recommendations to meet and maintain total transfer capability.
The ERO’s final report, submitted in three parts — with a fourth component focused on Canada planned for release this year — recommended a total of 35 GW of additional transfer capability across FERC’s transmission planning regions. NERC Director of Reliability Assessments and Performance Analysis John Moura said the ERO had to use its discretion to narrow the FRA’s broad requirements to a workable framework; for example, NERC’s definition for “prudent” additions focuses on reliability rather than economic factors.
EIPC’s comments acknowledged that NERC had “relatively little time to develop a study methodology, gather the required data, consult stakeholders, execute the study and validate results” and that the limited time required the ERO to “change and reduce the scope of its study.” EIPC also said it appreciated that NERC went out of its way to coordinate with grid stakeholders through the ITCS Advisory Group.
However, the collaborative did express concerns about the study — partly regarding its methodology, but mainly that large transfer capability studies like the ITCS are inherently unsuitable “to drive transmission upgrades on the power system.” EIPC pointed out that transmission service providers (TSPs) and transmission planners “have a more in-depth understanding of the current and planned transfer capability on their system” than NERC.
“Decisions on the value of specific transmission improvements are complex, and they must consider all the factors regularly evaluated by TSPs, transmission planners and resource planners,” EIPC said. “This goes beyond the factors considered for transfer capability in [large transfer capability studies]. For example, available capacity, the feasibility of upgrades, the potential for excess generation and cost allocation must be considered to ensure investments are prudent and aligned with a beneficiary-pays methodology.”
EIPC emphasized that it “shares the same goals as FERC, NERC and the rest of the industry” regarding improving grid reliability through interregional transfer capability, and that it also believes investments in transfer capability can add value to the grid “at appropriate costs.” However, it also cautioned that despite providing “interesting insights,” large-scale “snapshot-in-time” studies like the ITCS lack “the appropriate granularity” to make useful recommendations.
Calling the ITCS “not directly actionable,” EIPC suggested that federal and state regulators and policymakers seek input from “planning entities responsible for analyzing transmission security and resource adequacy needs” when determining interregional transfer capability needs. In addition, EIPC said that prudent additions should be assessed in terms of cost, not just their reliability benefits.
EIPC also recommended that FERC work with state regulators on metrics to guide decision-making on increasing interregional transfer capability. The collaborative stopped short of defining the metrics itself but suggested that they include factors such as specific needs that a proposed expansion could address, whether the potential reliability benefits exceed the projected cost of the project, and the feasibility of the proposed project to meet the identified need.
In a separate statement, EIPC said its members “stand ready to provide technical assistance” for the Eastern Interconnection if FERC decides to pursue such a metrics project.
Voting on Site Control Requirement Manual Revisions Deferred Pending Settlement
VALLEY FORGE, Pa. — Stakeholders in the Markets and Reliability Committee (MRC) voted for a third consecutive meeting to delay acting on revisions to Manual 14H intended to clarify when developers may add or remove parcels from their project footprint. PJM and EDF Renewables stated they’re working toward resolving a complaint filed on the matter (EL25-22). (See “Other Committee Business,” PJM MRC/MC Briefs: Jan. 23, 2025.)
The complaint from the American Clean Power Association, Solar Energy Industries Association and Advanced Energy United alleges PJM is violating its tariff and Manual 14H in guidance it has issued to developers around when they can change the parcels included in their projects. In past stakeholder meetings, PJM said the proposed manual revisions would codify that guidance, which renewable developers have argued is overly burdensome and would require them to retain land they have determined is unneeded.
A motion to defer voting on the manual revisions initially was rejected by stakeholders, with the 60% in support falling shy of the two-thirds sector-weighted threshold. Emma Nix, of EDF Renewables, told the committee that settlement discussions are making progress and passing the proposal would frustrate that process. The second vote passed with 82% support.
“I expect that we will have a settlement that we can share with stakeholders within the next month … things are going very smoothly,” she said.
PJM attorney Chris Holt said the RTO is limited in what it can say due to settlement confidentiality. But he confirmed discussions are progressing toward a resolution. He noted that FERC has granted an abeyance on the complaint that ends on March 10 and stated that PJM is hopeful an agreement can be reached by then. General Counsel Chris O’Hara said settlements often result in PJM committing to propose revisions to its governing documents in the FERC docket in which the settlement is made. If such an agreement is reached, those changes might not come back to the stakeholder process for consideration next month. Interested parties instead could comment on that docket.
The proposed changes would allow parcels to be added to a project at Decision Point 1, so long as the land is adjacent to the site or evidence of connecting easements is provided. Parcels also could be removed at this point, so long as the project continues to meet the minimum acreage and energy output defined in the project application. (See “Vote on Site Control Requirements Deferred,” PJM MRC/MC Briefs: Dec. 18, 2024.)
The revisions would seek to clarify language stating there are no specific site control evidentiary requirements associated with Decision Point 2 by specifying that “site control must be maintained throughout the cycle process.” A note also would be added stating that parcels similarly can be added to DP1, with the caveat that a one-year term would be imposed from the end of Phase 2 of the relevant study cycle.
No additions would be permitted at the final Decision Point 3, but reductions would be allowed so long as the acreage-per-megawatt and evidentiary requirements continue to be met. Once a generator interconnection agreement is signed, any site control changes would require a necessary study agreement to determine permissibility.
3 Packages Advancing from ELCC Task Force
PJM presented a slate of proposals aimed at adding new generation categories to the effective load carrying capability (ELCC) framework and how analysis of changes in the resource mix and risk modeling affect class accreditation. They are the first recommendations made by the ELCC Senior Task Force (ELCCSTF), which was formed last year to consider changes in the functionality and transparency of the methodology.
Two of the proposals focus on how changes in ELCC inputs can affect resource class ratings between the completion of a Base Residual Auction (BRA) and the associated delivery year, as well as how that might interact with any capacity shortfalls that could be caused if a resource sees its accreditation reduced between a BRA and incremental auction (IA).
The main motion advancing to the MRC, Package B, would lock resources’ ELCC ratings and accreditation in at their values used in the BRA, though any changes in risk modeling still would affect the Reserve Requirement Study values used in the IAs and could cause PJM to revise the amount of capacity it procures in those auctions. The alternative, Package C, would follow the status quo of updating ratings between IAs, but would lower the penalty rate for any deficiency associated with reduced accreditation to 100% of its clearing price, down from the 120% penalty rate. The two proposals were nearly tied in an ELCCSTF poll, with Package B holding 66.5158% support and 68% preference over the status quo, while Package C received 66.5025% and 74.9% preference.
Package A was introduced by Vistra and would have capped the deficiency charge at the lesser of any change in accreditation or the equivalent demand forced outage rate (EFORd).
PJM’s Pat Bruno said Package B would remove the uncertainty associated with shifting accreditation from market sellers while retaining penalties for any shortfall in installed capacity (ICAP). He gave the example of a unit experiencing a catastrophic failure or a planned resource not entering commercial service on time still being subject to deficiency charges. Package C would retain some incentive for market sellers to mitigate any lost AUCAP.
Susan Bruce, representing the PJM Industrial Customer Coalition, argued that Package B would shift all risk to load and require load to buy shortfall capacity twice, in the BRA and IA.
“The main motion addresses a concern, and I certainly am sympathetic to the concern, but it shifts the risk to load … so I think some fundamental question should be answered here,” she said.
Adrien Ford, of Constellation, said the main motion would handle the unhedgeable risk of changing ELCC ratings more effectively than the other two options considered.
The third proposal advancing from the ELCCSTF would add two new resource classes: a waste-to-energy subset of the steam generation category and oil-fired combustion turbines (CTs). The former has an estimated ELCC rating of 83% based on the parameters used in the 2025/26 third IA, while oil CTs would have an 85% rating.
1st Read on CIFP Manual Revisions
PJM’s Joseph Tutino provided a first read on a set of manual revisions to conform with FERC’s order granting PJM’s capacity market changes drafted through the Critical Issue Fast Path (CIFP) process in 2023. The package is the second set of conforming revisions, this time focusing on generation testing requirements and adding a requirement that dual-fuel resources must offer schedules with both fuels into the energy market. (See “1st Read on 2nd Phase of CIFP Manual Revisions,” PJM MIC Briefs: Jan. 8, 2025.)
The summer and winter capability testing detailed in Manual 18 would be changed to focus on whether capacity resources are able to output their daily ICAP minus the 95th percentile hourly seasonal net output. A resource that has a daily ICAP value exceeding the tested capability during that season would be subject to shortfall charges until it is able to test to a greater capability. The addition of generation operational testing to Manuals 14, 18 and 28 would allow PJM to test a resource twice per season, plus any additional retests if a unit fails to perform. The dual-fuel must-offer requirement would be codified in Manual 11.
Ford said Constellation has worked with PJM on changes to the language to reflect permit requirements. PJM’s Skyler Marzewski said the RTO views those changes as a clarification rather than substantive change to the proposal.
Members Committee
Manual Revisions Seek to Reimagine Role of MC Webinar
PJM’s Michele Greening presented revisions to Manual 34 that would restructure the MC Webinar in an effort to shift substantive discussions to be held instead at the MC. The proposal includes a single change to revise the manual to state that “reports, briefing and non-decisional business will be conducted” to instead read as “may be conducted,” allowing for more flexibility.
Vistra’s Erik Heinle said the webinar is a useful venue and should continue. But some stakeholders have grown concerned that topics discussed there are more appropriately addressed before the broader attendance that the full committee sees. In particular, he said the monthly reports the Independent Market Monitor provides should be moved to the MC.
Tom Hyzinski, of the GT Power Group, provided an example from the March 18 MC Webinar to highlight the concern raised by Heinle. Hyzinski said that although it was not covered or even noticed in the Market Monitoring Report that was posted, the Monitor mentioned at the webinar that PJM had unilaterally increased the amount of reserves they carry some time ago. That increase needs to be addressed, he said, suggesting the additional reserves PJM procures are inappropriately increasing consumer costs. Hyzinski said PJM staff were not present to refute those claims or offer alternative perspectives. (See “Stakeholders Reject PJM Synch Reserve Manual Change; RTO Overrides,” PJM MRC/MC Briefs: May 31, 2023.)
Monitor Joe Bowring responded that the argument he voiced during the webinar was that there are communication issues between PJM dispatchers and generation owners that have led to reserves underperforming and that resolving that issue would obviate the need for the higher reserve requirement. Rather than moving the reports to the MC, Bowring suggested it may be more effective for webinar participants to request that discussion of materials presented be added to the MC agenda when warranted.
Stakeholders Discuss Synchronized Reserves
PJM’s Mike Bryson said PJM may lower its synchronized reserve requirement if a trend of increased performance holds up. The RTO increased the requirement by 30% in May 2023 to address low performance. That change may be reversed if five consecutive spin events see 100% or higher performance. In response to stakeholder questions as to whether PJM will continue to monitor reserve deployment and consider ongoing changes to the requirement, Bryson said the focus is getting back to the standard procurement target before considering next steps.
Bowring said he’s glad to hear PJM is considering the change and he’s hopeful changes to how reserves are deployed will improve performance to where the baseline requirement is sufficient for PJM. (See “Stakeholders Endorse Reserve Rework, Reject Procurement Flexibility,” PJM MRC Briefs: July 24, 2024.)
Both Bowring and Bryson said the dialogue they had with generation owners whose units underperformed yielded helpful insight into what was driving the issue, and ongoing coordination would be beneficial.
