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December 13, 2025

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PG&E Data Center Proposals Nearly Double in 2025 to 10 GW

Data center applications are piling up in Pacific Gas and Electric’s territory with some of the new load projected to come online in 2027.

PG&E now has applications for about 10 GW of new data center load, up from about 5.5 GW at the end of 2024 and 8.7 GW in May.

“Once people found out that PG&E was ready to serve, the applications came rolling in,” CEO Patricia Poppe said during the company’s July 31 earnings call.

Poppe called the volume of data center demand growth “Goldilocks growth: not so much to be a problem, and yet enough to be beneficial for all of our customers.”

Of the proposed 10 GW, about 8.4 GW are in the application and preliminary stage, 1.5 GW in final engineering and 0.5 GW under construction.

Data center load growth could allow PG&E to use more of its existing power infrastructure, which would spread the fixed costs of operating and maintaining the grid over more units of energy and allow the utility to increase its average grid utilization rate, PG&E said in a July 31 press release.

Ten gigawatts of data center load could lead to lowering customer electric bills by 10% or more and generate $1.25 billion to $1.75 billion in increased property tax revenue, the utility claimed in the release. That volume of load is enough energy to power about 7.5 million homes, PG&E said. There are currently about 14.8 million housing units in California, according to the U.S. Census Bureau.

During the call, a participant asked Poppe to provide more information about proposed data center projects in San Jose. Poppe said PG&E has worked with city officials to accelerate permitting and construction.

“Construction and preparation will take most of 2026, then we see that pipeline both in San Jose and throughout the rest of the [PG&E] service area taking shape 2027, 2028 [and] 2029,” Poppe said. “We would see the rate benefits starting in probably 2027.”

PG&E’s new data center demand numbers are dramatically higher than what the California Energy Commission forecasted in its 2024 Integrated Energy Policy Report, which showed data center peak demand of about 2.8 GW in PG&E’s territory under the “high” case in 2040.

Last week, the California Public Utilities Commission partially approved a new electric rule that will make it easier for data centers and other large customers to complete transmission connection projects in PG&E’s territory. The new rule, Electric Rule 30, will help address the increase in PG&E’s retail customer transmission interconnection demand. PG&E has received 40 transmission connection applications since 2023. (See CPUC OKs New PG&E Rule to Speed Tx Connections for AI Data Centers, Others.)

PG&E earned $521 million in the third quarter ($0.24/share), up $1 million from the same period a year earlier.

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AEP, Xcel ‘Navigate Rapidly Evolving Energy Policy’

Two of the electric utility industry’s leading companies, American Electric Power and Xcel Energy, say clean energy projects are still a part of their plans, despite the hurdles placed in front of them by the federal government’s budget reconciliation law. 

Xcel CEO Bob Frenzel told financial analysts during the company’s quarterly earnings call July 31 that with renewable tax credits “front and center” during the debate on the legislation, “we expected limitations to credit.” He said the company expects to need between 15 and 29 GW of new generation before 2031, with a “significant amount” that could be sourced from wind and solar. 

“We’re navigating rapidly evolving energy policy landscape while we predominantly navigate resource plans and transition initiatives at a state level,” he said. “We’ve been working with our state commissions and other stakeholders on the substantial generation required in our operating regions. 

“Accordingly, we’ve already invested substantial capital and/or physically commenced construction of the clean energy resources included in our base capital plan as well as enough to execute on our incremental investment pipeline. … We’ll continue to monitor executive orders, agency rulemakings and trade and tariff actions, and make adjustments as needed as we continue to develop the energy assets that we need in our region.” 

AEP CEO Bill Fehrman had the same message during his company’s second-quarter earnings call July 30. He said the legislation “currently supports” all of the company’s $9.9 billion, five-year capital plan for wind and solar generation and maintains the “required criteria to capture the full tax credits.” 

Still, the company is “closely monitoring” and will assess the potential effect on tax qualification of President Donald Trump’s July 7 executive order implementing the law that further curtailed federal subsidies on wind and solar. (See U.S. Clean Energy Sector Faces Cuts and Limitations.) 

“Even if the U.S. Department of the Treasury issues new guidance under the order that redefines the beginning of construction criteria, we currently expect that only a few projects at the back end of the plan may need to be reassessed for tax-credit eligibility,” Fehrman said. 

Both companies told analysts that they plan to increase their capital expenditures in the face of electricity demand that is projected to surge as much as 35 to 50% by 2040. 

Xcel said it will likely need an additional $15 billion capital investment in addition to the $45 billion, five-year plan it outlined in fall 2024 to strengthen its infrastructure. It filed a generation plan in June for its Southwestern Public Service Co. subsidiary for 5.2 GW of generation and storage, much of it company owned and operated. 

AEP said it plans to announce about a 30% increase in its five-year capital plan, from $54 billion to approximately $70 billion, during its third-quarter conference call this fall. Fehrman said the company will allocate the incremental capital to transmission (50%), generation (40%) and distribution (10%). 

“Demand for power is growing at a pace I have not seen in my 45-year energy career,” Fehrman said. 

“We believe that we’re in the early stages of an infrastructure investment cycle in the United States that will define many industries for decades,” Frenzel said. “Not just the often-discussed AI boom; we see potential investment in onshoring and reshoring of manufacturing and other energy-intensive industries.” 

Earnings Results

Columbus, Ohio-based AEP reported earnings of $1.23 billion ($2.29/share), compared to $340 million ($0.64/share) for the same period a year ago. 

Fehrman said the company’s operating earnings of $1.43/share were the company’s “strongest ever” for a second quarter in its 100-year history. It also beat the Zacks Consensus Estimate of $1.28 by 11.7%. AEP’s stock price closed July 31 at $113.14, up $3.89 (3.6%) from its July 29 close. 

Xcel reported second-quarter earnings of $444 million ($0.75/share), reflecting increased recovery of infrastructure investments that were partly offset by higher interest charges, depreciation, and operations and maintenance expenses. 

The company beat the Zacks Consensus Estimate of $0.63/share by 19.05%. Xcel’s stock price closed July 31 at $73.44, up $1.05 on the day. 

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WEIM Q2 Benefits Exceed $420M, as Total Tops $7.4B

CAISO’s Western Energy Imbalance Market (WEIM) provided participants with $422.44 million in economic benefits during the second quarter of 2025, up 15% compared with the same period year earlier despite no change in membership. 

Cumulative benefits since the 2014 launch of the market reached $7.41 billion, according to the benefits report released by the ISO on July 31. The WEIM has over time expanded to include 22 participating balancing authority areas — including CAISO — representing more than 80% of load in the Western Interconnection. 

“The quarterly benefits have grown over time as a result of the participation of new BAAs, which results in benefits for both the individual BAA but also compounds the benefits to adjacent BAAs through additional transfers,” CAISO said in the report. 

NV Energy raked in the largest share of benefits, at $84.12 million, followed by Public Service Company of New Mexico ($48.96 million), Balancing Authority of Northern California ($35.86 million), PacifiCorp ($33.02 million), Los Angeles Department of Water and Power ($32.17 million) and Salt River Project (SRP) ($30.01 million). Nearly all those participants have committed to joining CAISO’s Extended Day-Ahead Market, except for SRP, which plans to join SPP’s Markets+. 

Maintaining a pattern of second-quarter market performance, solar-heavy CAISO was by far the largest net exporter of energy, with about 2.55 million MWh, down nearly 11% from a year earlier. PacifiCorp was the next largest next exporter at 931,263 MWh from both its East and West BAAs, followed by NV Energy (648,995 MWh), SRP (347,571 MWh), Puget Sound Energy (256,891 MWh) and the small Avangrid BAA in the Pacific Northwest (213,961 MWh). 

PacifiCorp was the largest net importer at 659,549 MWh, followed by CAISO (641,660 MWh), Powerex (611,111 MWh) and SRP (603,028 MWh). 

In the WEIM, a net export represents the difference between total exports and total imports for a BAA during a particular real-time interval, while a net import represents the inverse, meaning that a BAA can be both a heavy exporter and importer over an extended period based on varying momentary needs and trading positions over that period. 

CAISO was also the site of the greatest volume of wheel-through transfers during the quarter at 581,943 MWh. The next largest amount of such transfers went through Arizona Public Service (413,625 MWh), NV Energy (388,671 MWh), PacifiCorp-West (384,732 MWh) and Idaho Power (233,497 MWh). 

The ISO also noted that avoided renewable energy curtailments from WEIM operations reduced greenhouse gas emissions by 112,712 MWh over the quarter, displacing an estimated 48,241 metric tons of CO2 emissions from thermal sources that would have otherwise been needed to produce energy. Since 2015, the market has helped reduce CO2 emissions by more than 1.12 MT, the ISO said. 

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IMM: MISO Should Penalize Gen that Falls Flat on Emergency Output

The MISO Independent Market Monitor has called on the RTO to develop a penalty system for generation that doesn’t rev up into emergency ranges as promised to assist a maxed-out grid.

The Monitor said it noticed some generators didn’t attempt to depart their economic output for emergency output during the May 25 load shed event in Greater New Orleans. (See MISO Says Public Communication Needs Work After NOLA Load Shed.)

MISO generation resources keep emergency maximums on file that are higher than their stated economic ranges. The RTO is allowed to access units’ emergency dispatch ranges after it has declared an emergency.

IMM Carrie Milton said that on May 25 in MISO South, 140 MW worth of emergency ranges were offered as available, but half of it ultimately didn’t show up.

At an Entergy Regional State Committee meeting July 29, Milton said MISO should create consequences for generation “not moving into the emergency ranges when they’re instructed to do so.”

MISO Executive Director of Market and Grid Strategy Zak Joundi said the RTO is tracking nonperformance of units and is pondering solutions to incentivize resources to dip into emergency ranges. He said MISO also may decide it needs to provide clearer notifications to units when red-alert-level output is necessary.

“We’re finding that there are gaps,” Joundi said of a MISO analysis of past emergency range performance.

Joundi said MISO will bring “a full narrative” to the Market Subcommittee soon. In response to MISO South regulatory staff questions, Joundi said he couldn’t offer a timeline on when the RTO might develop a process to correct generators’ behavior.

Ultimately, resources that get paid for capacity must deliver megawatts, Joundi said. “If not, there have to be consequences.”

Louisiana Public Service Commissioner Eric Skrmetta said it seemed like some resources “need a stick instead of a carrot.”

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DOE Extension of Michigan Coal Plant Cost $29M in 1st Month

The Michigan coal plant kept online by an emergency order from the U.S. Department of Energy cost $29 million to run in a little over a month. 

That’s according to Consumers Energy’s recent Securities and Exchange Commission filing, where the company notes a $29 million “net financial impact” of extending operations of the J.H. Campbell plant from May 23 to June 30. 

In May, Energy Secretary Chris Wright issued an emergency order under the Federal Power Act requiring J.H. Campbell to continue operating for 90 days through Aug. 20. The plant has about two more months — and it appears, several more millions of dollars — before Consumers can retire it as planned. 

DOE’s order did not include federal funding to keep the Campbell plant operational. Consumer advocates and environmental nonprofits expect that costs associated with the extension will be passed on to consumers in Michigan and neighboring areas in MISO Midwest. 

Consumers said in its filing that it has “continued to make J.H. Campbell available in the MISO market,” consistent with the department’s order. The utility also noted its pending complaint with FERC that seeks to alter the MISO tariff to develop a means to recover plant costs while the order is in effect. 

MISO declined to comment on whether it has dispatched J.H. Campbell in its markets since late May. The RTO said individual unit dispatch data is not available to the public. 

“MISO, Consumers and the joint owners [of the plant] are taking all appropriate action to comply with the DOE order,” spokesperson Brandon Morris said in a statement to RTO Insider. 

Consumers did not respond to RTO Insider’s questions on how often the plant has been used since the DOE order or how it is planning to recoup costs.  

Earthjustice, one of the organizations suing the DOE over its order along with Michigan Attorney General Dana Nessel, said ratepayers are poised to fund the utility’s expenses for the plant “plus a return on any capital investments.” (See Opponents Take DOE to Court over J.H. Campbell Retirement Delay.)  

“The Trump administration is raising people’s electricity bills with its promotion of coal at all costs. The illegal abuse of emergency powers to force an aging coal plant to keep burning coal has real costs for consumers, who the administration suggests should be forced to pay millions for this unnecessary dirty power plant that is polluting their air,” Earthjustice attorney Shannon Fisk said in a statement to RTO Insider. “Meanwhile, clean electricity sources that have almost zero operating costs, such as solar and wind, can get pushed out of the market when aging coal plants are forced to stay online.” 

The Institute for Energy Economics and Financial Analysis has pointed out that operation and maintenance for Units 1 and 2 at the plant totaled $45.80/MWh over 2023, higher than energy prices nearly all the time at the Michigan hub. The units are 63 and 58 years old, respectively. 

MISO’s Independent Market Monitor has repeatedly said the coal plant is not necessary for reliable summer operations in the footprint. 

At MISO’s Market Subcommittee meeting in July, IMM Carrie Milton explained that this year’s capacity auction — the first to feature a sloped demand curve — cleared more capacity than necessary to satisfy the RTO’s reserve margin requirement, making J.H. Campbell’s federal operating extension “absolutely unnecessary.” Milton said going forward, the sloped curve should send all the signals necessary for MISO members to plan new generation or decide whether to hang on to existing generation longer through retirement deferrals. 

MISO itself studied the retirement of J.H. Campbell three years ago and determined in March 2022 that it could shut down as planned without the RTO needing it to stay online as system support resource. 

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PPL Briefs Analysts on Efforts to Serve Data Centers in Pa., Ky.

PPL expects that the current surplus of generation in its Pennsylvania territory will be lost to demand growth from data centers in the next five years and said it has plans to help meet that growing demand with new generation. 

“We have made it a strategic priority at PPL to serve data centers across our service territories, as AI will be critical to America’s continued competitiveness and national security, as well as the execution of our utility-of-the-future strategy,” CEO Vincent Sorgi said on the company’s second-quarter earnings call July 31. “We are enabling speed to market for the data centers by being able to connect them to the grid faster than they can get the data centers built.” 

PPL sees about 14.5 GW of data centers in advanced stages of development that could come online by the early 2030s. Assuming those all come online, the net long position in PPL’s territory would disappear, and an additional 7.5 GW of supply would be needed. Sorgi said that while the numbers outside its territory are fuzzier for the firm, Pennsylvania could need an additional 12 GW. 

“Our current capital plan includes another $7 billion through 2028. That means we can connect data centers as quickly as developers can build them,” Sorgi said. 

Once the existing long generation is used up, PPL would shift to building out more generation, and it is backing a few horses there. The company has entered a joint venture with Blackstone to supply data centers using “energy services agreements” (ESAs), which was announced at a high-profile event in July. (See $92B in Power, Data Center Infrastructure Planned in Pa.) 

“Those ESAs will have regulated-like risk profiles that do not expose the companies to merchant energy and capacity price volatility as PPL is not getting back into the merchant generation business,” Sorgi said. “Therefore, construction of any new generation will require the successful execution of ESAs with hyperscalers. The joint venture is actively engaged with hyperscalers, landowners, natural gas pipeline companies, turbine manufacturers and land parcels to enable this new generation buildout.” 

Sorgi did not want to get into much more detail about the ESAs, as negotiations are ongoing, but he anticipated placing orders for new natural gas-fired turbines by next year. 

PPL is also still backing legislation that would let the utility rate-base new generation in Pennsylvania, which would represent a major shift in policy for an early and once enthusiastic adopter of restructuring and wholesale markets. (See Utilities Pushing for Return to Owning Generation in Pennsylvania.) 

A pair of bills that would authorize utility-owned generation are pending in the relevant committees in the Pennsylvania General Assembly: SB 897 and HB 1272. 

“Both the House and Senate bills would allow regulated utilities, like PPL Electric Utilities, to build and own generation again to solve a resource adequacy need,” Sorgi said. “And both pieces of legislation would also encourage utilities to enter into agreements with [independent power producers] to help de-risk their new generation investment. As a company, we are primed to act quickly once this proposed legislation becomes law.” 

A key difference between the deal with Blackstone and building its own generation is that the former would require PPL Electric Utilities to run an open request for proposals to get around affiliate rules, while the latter could happen without any competition. 

PPL’s subsidiaries in Kentucky — Louisville Gas & Electric and Kentucky Utilities — are also seeing load growth. The utilities have entered a deal in a pending certificate of public convenience and necessity proceeding to build new gas plants, among other investments. 

“The stipulation strikes the right balance between building new generation needed to support economic development in the state, including supporting anticipated data center load, and ensuring we maintain affordability for our customers,” Sorgi said. 

The utilities will build two new 645-MW combined-cycle natural gas plants, add selective catalytic reduction to Ghent Generating Station Unit 2 and extend the 300-MW Mill Creek coal plant Unit 2’s life from 2027 to at least 2031, with analysis required in their next integrated resource plan to consider keeping the plant open even longer. They also withdrew a request to build a new battery storage plant in the state, but without prejudice so that project could still be developed in the future, Sorgi said. 

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Industry, Regulators Grapple with AI Demand at NARUC Policy Summit

BOSTON — Growing power demand from data centers dominated conversations at the NARUC Summer Policy Summit, where industry members and Trump administration officials advocated for the rapid addition of fossil fuel resources and infrastructure to meet anticipated load growth.  

Speakers at the event framed the AI industry in terms of a global arms race and argued that regulators must be hyper-focused on enabling new resources to come online at a faster pace. 

“I think there is a definite need for the regulatory framework to become more reflective of the world that we live in,” said Corey Hessen, CEO of Homer City Redevelopment, which is developing a campus of gas-powered data centers on the site of a recently retired coal plant in Pennsylvania.  

“The world that we live in means that new load and new generation has a demand to come online faster than ever before, and that will mean that the utilities and regulators must work together to come up with a framework that’s representative of what those needs are,” he said. 

The NARUC meeting, July 27-30, featured noticeably little talk of decarbonization, reflective of rising power demand across the country and the dramatic shift in federal energy policy under the Trump administration. 

Pablo Koziner, chief commercial and operations officer of GE Vernova, said the company has seen a massive surge in orders for gas equipment in recent months.  

GE Vernova has reported a 55-GW backlog of industrial gas turbine bookings and under-reservation agreements, which it expects to continue to grow over the coming years. (See GE Vernova’s Gas Power Equipment Surge Continues.) The company also has a major backlog on electrical equipment orders, including switchgear and transformers. 

“We’re just experiencing a huge amount of this demand,” Koziner said, adding that data center demand outpaces supplier expectations, with data center developers willing to pay high costs for their power needs.  

“The question is: How much new capacity do you need to install to keep up versus how much you can unlock from existing infrastructure? And I think it’s a combination of both,” he said. “There are efficiencies that we can unlock, but there’s certainly a need for a lot more capacity to keep up.” 

In a recent report, Wood Mackenzie said it is tracking 134 GW of proposed data center demand across the country, with new data center proposals concentrated in Texas, Virginia, Pennsylvania and other states in the middle of the country.  

The research and consulting firm says constrained gas supply chains and rapidly rising costs of combined cycle gas plants will pose a significant barrier to scaling up power production over the next few years, with high costs likely exacerbated by the effects of the Trump tariffs. 

Meanwhile, the renewable energy industry is facing major headwinds associated with the One Big Beautiful Bill Act and Trump’s executive orders. Renewables could face significant cuts and project cancellations across the country despite rising demand and power costs. (See U.S. Clean Energy Sector Faces Cuts and Limitations.) 

While coastal states with higher energy costs have seen lower data center demand growth, these areas are unlikely to be immune to the effects of AI. Kim Harriman, deputy CEO at Avangrid, which owns electric utilities in Connecticut, Maine and New York, told RTO Insider that AI demand growth “is here, and we see it.” 

She noted that, over the long term, electrification of heating and transportation, the reshoring of manufacturing and housing development also likely will be significant drivers of demand in the region.  

Fossil Fuel Infrastructure

Representatives of the natural gas industry argued that rising power demand will require new gas infrastructure throughout the country, while Trump administration officials said it is essential to retain the nation’s coal fleet. (See Trump Officials Talk Regulatory Rollbacks at NARUC Meeting.) 

“The existing system alone is not going to be enough to meet this demand. We’re going to have to build out more infrastructure,” said Amy Andryszak, CEO of the Interstate Natural Gas Association of America. 

Mary Landrieu, co-chair of Natural Allies and a former Democratic senator from Louisiana, made the case for new gas pipelines while urging attendees to “drop our political ideologies.” 

Natural Allies is a group backed by gas pipeline companies, focused on promoting “the great asset of natural gas” to “Democrats primarily,” Landrieu said.  

Landrieu praised recent statements from Connecticut Gov. Ned Lamont (D) indicating he is open to new gas infrastructure, and she repeatedly emphasized the importance of an “all-of-the-above approach” to energy policy. 

Andryszak said opposition from “certain states” has been an impediment to building out gas infrastructure, and added she hopes “conversations around demand for more energy of all forms” will cause states that have opposed gas infrastructure to “rethink some of their policies.” 

Efforts to expand gas pipeline capacity into the Northeast have faced strong opposition from climate activists and Democratic politicians in recent years, while proponents of natural gas hope regulatory rollbacks and increased federal support for pipelines will help facilitate projects in the Northeast.  

In Massachusetts, where much of New England’s gas demand is concentrated, Gov. Maura Healey (D) has been relatively quiet on the issue of gas expansion but has not shut down the possibility of new gas infrastructure. 

Natural gas combustion and methane leaks from gas networks are key drivers of climate change. Leaked methane has a strong short-term warming effect on the climate, and scientists warn that an expanded reliance on natural gas is not compatible with efforts to decarbonize the economy and stabilize the climate. 

Even in the absence of regulatory hurdles, proposals to build new natural gas pipelines into New England face questions about funding, and industry experts have expressed skepticism about the likelihood of new gas infrastructure in the region due to a lack of counterparties to pay for the infrastructure. (See New Pipelines Unlikely for New England, Experts Say.) 

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FERC Approves NPCC’s $102K Penalty Against ORU

Consolidated Edison subsidiary Orange and Rockland Utilities (ORU) will pay $102,000 to the Northeast Power Coordinating Council for violations of NERC reliability standards as the result of a settlement approved by FERC. 

NERC submitted the settlement to FERC on June 30 in its monthly spreadsheet Notice of Penalty; it was the only settlement for the month. The commission said in a July 30 filing that it would not further review the settlement, leaving the penalty intact (NP25-12).  

ORU, with its subsidiary Rockland Electric, serves about 300,000 electric customers in New York and New Jersey. Two of the three violations in the settlement involved both companies and covered a period of almost 17 years, from 2007 to 2024. They all stemmed from NERC’s FAC family of facility ratings standards. 

The utility reported to NPCC on Oct. 9, 2020, that it had discovered potential violations of FAC-008-1 (Facility ratings methodology) and FAC-008-3 (Facility ratings), along with FAC-014-2 (Establish and communicate system operating limits). Because ORU and Rockland are in coordinated oversight with each other, the first two issues applied to both companies. 

For the FAC-008-1 violation, ORU said that its facility ratings methodology (FRM) “failed to include consideration for operating limitations, such as a topology change.” ORU conducted an extent-of-condition assessment and found no additional issues; however, when NPCC and ReliabilityFirst later completed a joint self-certification review in March 2023, they found that ORU and Rockland had failed to include several topics in the FRM, including: 

    • using a wind speed assumption that does not match ORU’s existing FRM; 
    • a mismatch of ambient temperatures used to establish normal, long-term emergency and short-term emergency ratings of copper tubular bus sections; 
    • insufficient summer and winter ambient temperature information; and 
    • a mismatch of substation configuration data. 

Regarding the infringement of FAC-008-3, ORU and Rockland determined from an internal compliance review that 17 facilities had ratings that were inconsistent with the FRM: four 345/138-kV transformers and 13 138-kV transmission lines. The changes resulted in derates of up to 40%, though 75% of the derates were less than 13%, and increased ratings of up to 17%. As for the FAC-014-2 violation, ORU reported that the system operating limits of 14 facilities had been incorrectly calculated during 64 breaker outages. 

All of the violations posed a moderate risk, according to NPCC, and no harm is known to have occurred. To mitigate the infringements, ORU and Rockland have updated their main FRM document with language addressing the use of operating limits when calculating facility ratings, provided training to responsible staff on FAC-008 compliance and created a new spreadsheet to organize ratings data.  

The utilities also revised all applicable facility ratings, implemented a new process checklist to be completed prior to energizing grid additions and modifications, and created a requirement for annual validation of all changes to or affecting facilities within the previous 12 months. 

Because ORU and Rockland are in RF’s footprint as well as NPCC’s, the REs will split the penalty payment based on relative net energy for load, with RF receiving $59,177. 

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Trump Officials Talk Regulatory Rollbacks at NARUC Meeting

BOSTON — The Trump administration’s proposed rescission of EPA’s 2009 endangerment finding classifying greenhouse gases as pollutants would be the “largest deregulatory action in the history of the country,” EPA Administrator Lee Zeldin said July 30.

Speaking at the Summer Policy Summit of the National Association of Regulatory Utility Commissioners, Zeldin touted the Trump administration’s “energy dominance agenda” and said deregulating the fossil fuel industry will help the U.S. compete with China and serve growing demand from artificial intelligence.

EPA’s endangerment finding is the legal basis of a range of federal regulations targeting climate-warming emissions, and its elimination could have major effects on emission-reduction efforts throughout the country. The agency issued the endangerment finding under the Obama administration after the Supreme Court ruled in 2007 that it has the authority under the Clean Air Act to regulate GHGs. (See related story, EPA Proposes Rescission of Endangerment Finding that Underpins All GHG Rules.)

Zeldin said the Obama administration took a “creative approach” when issuing the endangerment finding and said the finding has been undercut by recent Supreme Court cases, including the elimination of the Chevron doctrine, which gave deference to agencies in their interpretations of laws.

“We’re living in a bit of a different world in 2025 than 2009 because of all the Supreme Court cases,” Zeldin said. “The Supreme Court has made it pretty clear that agencies like the EPA shouldn’t just be filling in any vague language in the statute.”

Deregulating the oil, gas and coal industries will be essential “if you want to make America the AI capital world [and] if you want to unleash energy dominance,” Zeldin said.

He argued that regulatory rollbacks will help the country’s economy and national security, and added that “if you care about our environment, it improves our environment, because in the United States, we tap into our energy supply so much better than so many other countries do.”

In June, the administration proposed to repeal GHG emissions standards for new power plants and Biden-era updates to the Mercury and Air Toxic Standards. (See EPA Proposes Repealing Limits on Power Plant Greenhouse Gas Emissions.)

“We will actually have more deregulation in one year at EPA than the entire federal governments, across all agencies, across entire presidencies, primarily because of the stuff that was done in 2023 and 2024,” Zeldin added.

The Trump administration’s actions to deregulate the fossil fuel industry have drawn strong criticism from climate scientists and activists. Emissions from fossil fuel combustion are one of the core drivers of human-caused climate change.

Other Trump administration officials speaking at the NARUC event also emphasized the importance of bringing new generation and transmission infrastructure online to meet AI demand.

Peter Lake, senior director of power at the National Energy Dominance Council, said the U.S. is facing “an inflection point in the history of industrial technologies,” adding that “we’ve all heard about the amazing things that AI can do — the incredible benefits to health care; technology; communication; picking wine at dinner; … optimizing shopping for my girlfriend.”

Nick Elliot, director of the Grid Deployment Office at the Department of Energy, said the U.S. needs to rapidly scale up the development of gas resources to balance the system as load grows, adding that supply chain backlogs must be addressed to achieve this buildout.

He said DOE’s recent changes to National Environmental Policy Act procedures should help reduce development timelines throughout the U.S.

“We are looking specifically to try and streamline regulation as much as we can, to give developers as much visibility on timelines and process to get things online,” Elliot said.

Deputy Energy Secretary James Danly said market reforms are needed to incentivize new resources to come online at the necessary rate to meet anticipated demand. He noted that the PJM capacity auction clearing at the price cap earlier in the month indicates prices “probably should have been higher” and criticized “subsidy regimes that warp the price signals” and hurt development. (See PJM Capacity Prices Hit $329/MW-day Price Cap.)

He expressed optimism about the changes to federal tax credits made by the One Big Beautiful Bill Act, calling the bill “an important part of getting energy policy correct.” (See U.S. Clean Energy Sector Faces Cuts and Limitations.)

The Trump administration believes “very much in the free market,” Danly said. He added that “capitalism is the engine by which America achieves great things, and this is the way we’re going to meet the needs that industries have for electricity, for gas [and] for energy of all types.”

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Colo. PUC Approves PSCo’s Markets+ Participation

The Colorado Public Utilities Commission voted July 30 to allow Public Service Company of Colorado to join SPP’s Markets+ day-ahead market, with commissioners split on whether the move is a step toward or away from full RTO participation. 

Commission Chair Eric Blank and Commissioner Tom Plant voted in favor of PSCo’s participation in Markets+; Commissioner Megan Gilman was opposed. The decision is the latest step in the development of the West’s two competing day-ahead markets: Markets+ and CAISO’s Extended Day-Ahead Market (EDAM). 

And the vote might not be the final word on the matter: At least one group — Advanced Energy United — said it plans to ask the commission to reconsider its decision. 

The vote follows a commission debate July 23 on the Markets+ issue. Blank made the case for allowing PSCo to join Markets+, while the other two commissioners voiced concerns. (See Colorado Commissioners Spar Over PSCo’s Markets+ Choice.) 

During the July 30 hearing, Blank argued that joining Markets+ is a step on a “continuum” moving toward full RTO participation. 

“Whether we get to a full RTO or not, as additional market services become available along the continuum, the benefits of the market increase more toward the higher end, potentially into the hundreds of millions of dollars per year of savings,” Blank said. 

He sees benefits arising mainly from better integration of Colorado’s two balancing authorities, through steps such as optimizing dispatch and unit commitment between them. PSCo operates one of the state’s balancing authorities and the Western Area Power Administration (WAPA) runs the other. WAPA’s Rocky Mountain Region plans to join SPP’s RTO West. (See WAPA, Basin Electric Commit to SPP’s RTO West.) 

Blank previously pointed to benefits related to resource adequacy, greenhouse gas accounting and wholesale market price transparency. 

Gilman said she expects PSCo to request a waiver allowing it to sidestep a state requirement to join an RTO by Jan. 1, 2030. And with the costs of joining Markets+ projected to exceed financial benefits until after 2030, Gilman said the company will be able to use those figures as an argument against joining an RTO. 

“Instead of appearing like a rational continuum or plan to progress, this appears to in some ways work against the goal of moving to a full RTO,” she said. 

Plant said after reviewing the issue for the past week, he agreed with Blank that a day-ahead market offers benefits as an interim step toward RTO participation. He highlighted the “transparency benefits of wholesale pricing, consistency of a market structure, [and] the benefits of efficiency of joining the two BAs.” 

PSCo Pleased

PSCo, an Xcel Energy subsidiary, filed its request to join Markets+ in February. (See PSCo Seeks to Join SPP’s Markets+.) 

The commission on July 30 also approved the company’s request to recover Markets+ associated costs through the electric commodity adjustment tariff. 

Xcel Energy spokesperson Michelle Aguayo said the company was pleased with the decision. 

“This milestone follows years of working with [SPP], other utilities throughout the West and interested stakeholders to build a market that provides for the efficient dispatch and commitment of our resources, helping integrate larger amounts of renewable energy to our fleet, and improve efficiency and reliability while reducing customer costs,” Aguayo said in an email to RTO Insider. 

The company plans to execute agreements to help fund and implement Markets+ “shortly” and join the market in 2027. SPP has set a deadline of Sept. 1, 2025, for balancing authorities to join Markets+ in time to participate when it goes live Oct. 1, 2027. 

Hurdles Ahead?

Others were disappointed by the commission’s vote. 

“Joining a smaller, more balkanized market undermines the very affordability and reliability of clean energy resources that the region depends on, and rushing into this decision, Colorado risks hitching its wagon to the wrong horse,” Brian Turner, regulatory director at Advanced Energy United (AEU), said in a statement.  

Other Markets+ trading partners are far from Xcel’s neighbors, Turner said, and instead of delivering benefits, the participation will just create more seams. 

Turner said PSCo’s proposal was approved without the required legal analysis. AEU plans to file an application for reconsideration within 20 days of a final decision being issued.