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December 15, 2025

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Clean Hydrogen Future Dimming Nationwide

Clean hydrogen is losing momentum in the U.S. because of higher costs, new tariffs and policy uncertainty, BloombergNEF analyst Payal Kaur said at a California Energy Commission workshop on firm zero-carbon resources July 29.

The U.S. has approved tax credits and grants for hydrogen production, but it’s taking longer for those incentives to come to fruition, Kaur said. There also has not been much progress in creating pipelines and storage for clean hydrogen, she said.

“It’s harder to get final investment decisions for these projects because of the uncertainty in the policy environment and lack of demand,” Kaur said.

Kaur said she expects the One Big Beautiful Bill Act to boost the production of blue hydrogen — splitting hydrogen from methane and capturing the carbon — but that the law “takes a jab at green hydrogen” — split from water using renewable energy.

President Donald Trump’s tariffs could also increase the cost to produce green hydrogen in the U.S. by 14%, Kaur said.

“Having tariffs is going to increase your levelized cost of green hydrogen. You’ll see additional costs in your electrolyzer equipment, solar and wind equipment, and other factors,” Kaur said.

The U.S. has announced plans to supply about 15 million metric tons of clean hydrogen per year, amounting to 1.2% of global supply, Kaur said. About 11.7 MMT will be blue and 3.8 MMT green. Currently, blue hydrogen is about 50% cheaper to produce than green, Kaur said.

In California, officials have announced plans to build infrastructure to produce about 1.1 MMT of green hydrogen per year, the fourth most out of all states. Louisiana has announced the most green hydrogen production, about 4.5 MMT per year.

The dim outlook for hydrogen fuel also applies to California’s transportation sector, where the price of hydrogen increased from about $15/kg in 2022 to more than $35/kg in 2024. (See Report: Hydrogen Transportation Future Down Significantly in California.)

Data Center Power Requests

At the CEC’s workshop, commissioners also heard from city and energy company representatives about the state’s integrated energy policy report, specifically how data centers are impacting future procurement plans.

Mandip Samra, general manager of Burbank Water and Power, told commissioners that data center developers are suddenly interested in building projects in the city because of its reliable, low-cost supply of electricity.

The utility did not include data centers in its load forecasts in 2023, but since then, “we’ve had a lot of data centers come to us because Burbank has a lot of reliability. We’re actually one of the highest reliability areas in the state and top 5% in the nation,” Samra said.

Sustainability was ranked last in importance in surveys submitted from stakeholder groups to the utility, Samra said.

Kent Leacock, senior director of public affairs for Mainspring Energy, told commissioners that his company is working with a rural community in the Midwest to help bring a new data center online there. The project is in development and is a combination of providing immediate power and allowing for data center load growth in the region.

The rural community could not meet the load demand of the new data center, so it decided to hire Mainspring to supply about 30 MW, Leacock said. The company builds linear generators, which supply power by releasing electrons out of copper coils.

“As you are all probably aware, with data centers, time is of the essence,” Leacock said. “You’re falling behind if you’re a month behind energizing your data center.”

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MISO Prepares for More Projects than Study Slots in 1st Queue Express Lane

MISO expects to exceed its quarterly project maximum when it begins accepting the first generation project proposals under its interconnection queue express lane.

The grid operator will officially open its new, expedited queue study process to hopefuls at 8 a.m. EDT on Aug. 6. It will accept generation proposals through Aug. 11.

“We’re suspecting we get more than 10 in the first cycle,” MISO Director of Resource Utilization Andy Witmeier said at a July 29 Entergy Regional State Committee meeting.

Witmeier said excess project submissions would roll over into the next quarterly study window. MISO is limited to studying 10 projects per quarter under the expedited treatment FERC approved July 21. (See FERC Approves MISO Interconnection Queue Fast Lane.)

MISO plans to study no more than 68 projects, at a pace of 10 per quarter, until the process sunsets on Aug. 31, 2027. It pledged to begin studying the first batch by Sept. 2. MISO plans to open a second application window in early November and kick off studies in early December.

MISO said in an emailed statement that the process is “only intended for highly certain projects that respond to a specific resource adequacy or reliability need.” In response to criticism that the fast lane will favor load-serving entities’ projects, MISO has stressed that independent power producers need only a legally binding agreement with an off-taker to compete for the limited slots. (See CGA Says New MISO Info Guide on Queue Fast Lane Shows Plan is Unfair.)

To qualify for the expedited studies, projects are required to address “a specific load addition or resource adequacy deficiency and be commercially operable within three to six years” of submission. MISO said interconnection service for projects will be capped at 150% of the identified need and must be situated in the project’s local resource zone. Relevant regulatory authorities must certify there’s a resource adequacy or reliability need for each project.

MISO CEO John Bear has said the “temporary mechanism allows us to address urgent needs while preserving state authority for resource adequacy and maintaining transparency and fairness.”

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NYPA Lines up More Potential Renewable Projects

The New York Power Authority has stepped up its renewable energy development efforts, offering a draft revision of its strategic plan that would more than double proposals to 6.8 GW.

The move is seen as timely, given the new hurdles to renewable energy being erected by the federal government since NYPA started down this path.

NYPA in 2023 gained new authority to develop renewable energy alone or in partnership with the private sector. A year later, it offered an initial tranche of 40 proposals totaling 3.5 GW, with the caveat that, as with most proposed renewables, there likely would be a significant attrition rate.

The final plan adopted in January contained 37 proposals rated at 3 GW, three of which have since been withdrawn from consideration because they were on an incompatible timetable.

On July 29, NYPA announced a second tranche of proposals totaling 3.8 GW.

These range from large wind and solar farms to a half-gigawatt compressed air storage cavern to dozens of storage facilities of a few megawatts each in New York City, where energy resources are most tightly stretched.

In a news release, NYPA President Justin Driscoll cited New York’s strong vision for a clean energy future but also acknowledged the escalating challenges facing it.

“There has never been a more critical time for NYPA to move expeditiously as we contend with expiring federal tax credits and associated increased competition for equipment and installers,” he said. “NYPA is committed to building a diverse portfolio of clean energy projects.”

NYPA has a long history of energy development, notably the major hydroelectric facilities that provide nearly half of the state’s emissions-free electricity.

But public power advocates had long sought a larger role for NYPA, in hopes that as a state entity it could accomplish what the private sector was failing to do: bring large amounts of new renewables online. In 2023, they succeeded in their lobbying efforts for the Build Public Renewables Act.

But in 2024, they were sorely disappointed that NYPA came out of the gate with a 3.5-GW plan rather than the bold 15-GW vision they had hoped for. NYPA said it wanted to move prudently and preserve the strong bond rating that would help it finance these efforts.

Public Power NY cheered the new gigawatts implied in the July 29 update of the strategic plan and especially welcomed the attention to the New York City area.

They also raised their goal to more than 15 GW, saying in a news release:

“New Yorkers stood up in record numbers to demand New York lead the way on building publicly owned, union-built renewable energy, and we’re winning. The rapid addition of 4 more GW of public renewables shows NYPA can build even more than the 15 GW necessary for us to meet the state’s climate goals, including 5 GW downstate.”

No Price Tag for Compressed Air Project

NYPA is facing a potentially busy few years. Along with the renewables mandate, Gov. Kathy Hochul in June directed it to lead development of at least 1 GW of advanced nuclear generation.

NYPA has attracted private sector interest in its renewables role. To date, 94 developers and investors have been pre-qualified to collaborate on generation projects, and the window for potential partners remains open through Sept. 30.

This latest tranche of renewables consists of three wind farms, 17 solar arrays and 156 energy storage systems.

NYPA and Orenda would co-develop 140 of the energy storage facilities. Almost all would be in New York City’s four outer boroughs, with the rest in the next county north. Some already have interconnection agreements.

Along with the standard battery energy storage systems, photovoltaic panels and wind towers proposed to be erected by the dozens or millions, there is one outlier among the projects: Hydrostor and NYPA would team up on a 500-MW compressed air storage facility in the northern town of Croghan and aim to bring it online in late 2031.

The draft revision of the strategic plan offers no price tag on the venture and gives no indication what level of risk would be attached to such a venture.

However, Hydrostor’s 500-MW/4,000-MWh Willow Rock compressed air energy storage proposal in California gives some hint about the price range: It received a $1.76 billion federal loan guarantee in the last days of the Biden administration.

One thing that will not be on the final renewables list is a nuclear reactor, even though NYPA is charged with seeing one built. Nuclear is not classified as a renewable energy technology.

Every proposal that does make it into the plan still must clear the full due diligence process, NYPA writes:

“The power authority is committed to building as much renewable energy as we prudently can. The inclusion of a project within this updated strategic plan, however, does not guarantee that NYPA will proceed with that project.”

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Pathways Initiative Clarifies Near-term Division of Labor with CAISO

The West-Wide Governance Pathways Initiative will run its stakeholder processes separately from CAISO’s until the effort’s “regional organization” (RO) is formally launched in 2028, even in areas of overlapping interest, an official said in a July 28 update. 

Pathways Launch Committee Co-Chair Kathleen Staks provided the update and associated slides via email after the group’s July 25 monthly online meeting was repeatedly “Zoom-bombed” by someone making offensive remarks, forcing the organizers to shut it down. 

Key among the topics that were to be discussed: how Pathways and CAISO will proceed over the next couple years as they engage in parallel stakeholder initiatives covering similar subjects. 

“We have received several questions about whether and if so, how, the various stakeholder processes underway may overlap and how stakeholders are supposed to engage,” wrote Staks, the executive director of Western Freedom. “It is important to note that … CAISO will continue to run its own stakeholder processes for the WEIM [Western Energy Imbalance Market] and EDAM [Extended Day-Ahead Market] and any other initiatives until the RO is fully functional and the tariff changes are in place that give the RO authority over the WEIM and EDAM ([around] January 2028).” 

Staks said the Western Energy Markets (WEM) Regional Issues Forum (RIF), the WEIM’s key stakeholder body, will continue with its work, including evaluating recommendations coming out of Pathways’ final “Step 2” proposal. (See Pathways Initiative Approves ‘Step 2’ Plan, Wins $1M in Federal Funding.) 

“For the RO implementation work, the Launch Committee will continue to manage the stakeholder process the same way it has since the beginning of the Pathways Initiative — through public meetings and written comment opportunities,” she wrote. “This work includes development of the corporate documents, organizational policies and procedures, including the scope of work of the Office of Public Participation and job descriptions for key RO roles, and refinement of the RO stakeholder process.” 

Once it is seated and selected, the RO’s “initial” board of directors will be making final decisions on those, while the Launch Committee likely will continue to manage related stakeholder processes until launch of the RO, she said. The committee hopes to seat the board by July 2026 and no later than January 2027, Staks said during the group’s May meeting. (See Pathways Initiative Seeks $7.1M to Fund RO.) 

In her update, Staks also clarified that the membership of the RO board’s Nominating Committee will reflect new sectors described in the Pathways proposal, and not those in the RIF, despite some overlap. 

“Each sector will need to organize itself to participate in the RO Nominating Committee process separate from the past/current engagement in the RIF or the CAISO-WEM Nominating Committee,” she wrote. 

Staks noted that CAISO will be running the stakeholder process for the tariff revisions needed to implement the Pathways proposal, given that it’s the ISO’s tariff that will be changing. 

Additionally, she wrote, the RO’s Stakeholder Representatives Committee (SRC) is unlikely to be “fully functional” until the RO is operating. 

“Having the right staff in place at the RO to manage the independent stakeholder process will be a priority for the RO, but the timing will depend on funding through the RO implementation phase,” she said. 

Staks recommended that sectors begin organizing to select their Nominating Committee representatives by this fall and to participate in RO stakeholder work ahead of formation of the SRC. 

Nominating Committee Revisions

The Launch Committee has revised the appendix of the Pathways final proposal related to the Nominating Committee, following recommendations from the Bonneville Power Administration and California Large Energy Consumers Association, Staks said. 

“In response to these comments, the Launch Committee made some significant changes to streamline and better organize the document and make it less prescriptive. In several places, there was language removed because the Launch Committee determined that it would be better to leave procedural details to the sectors and Nominating Committee to ensure flexibility and independence,” she wrote. 

The revisions remove the ability of the RO’s corporate secretary to appoint sector representatives to the Nominating Committee, clarify that the WEM Body of State Regulators representative is a voting member of the committee while the RO board representative is a non-voting member and specify that Launch Committee alternates will not vote on the initial board slate, among other changes. 

Updated Timelines

A chart in the slide presentation shows the Pathways Formation Committee has updated timelines for “key” deliverables, including extending the time allotted for developing corporate documents and defining the scope of the work of the Office of Public Participation. 

The chart also shows that Pathways will begin its Phase 2 fundraising in August. The group, which has estimated a $7.1 million budget for all three of its phases, hit a financing snare early in 2025 when the Trump administration paused nearly $1 million in funding as part of a larger spending freeze on projects previously promised support by the Biden administration. 

Online Meeting Restrictions

In response to the Zoom-bombing July 25, the Launch Committee will enact more restrictive practices for its online public meetings, including preventing participants from turning on cameras or microphones until they make a request using the “raise hand” feature. Staks said the committee also is considering disabling the chat feature because other entities have reported problems with “inappropriate content” being shared through that function as well. 

“These features do limit the ease of participation, but after our experience on Friday, we feel implementing these changes will prevent this situation from occurring again but still leave room for participation,” she said. 

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MISO Skirts Max Gen Emergency in July Heat

MISO issued a slew of warning notices and operating instructions — especially in its South region — to help deal with oppressive July heat, forced generation outages and strained transmission.

But the grid operator managed to avoid calling a maximum generation emergency on July 29, although it circulated a maximum generation warning that was in effect from 3 p.m. to 10 p.m. ET.

MISO declared two maximum generation alerts for July 28 and 29 for its entire footprint and a transmission advisory for the South region on July 29 because of limited transfer capability. MISO debuted transmission advisory notifications following load shed in greater New Orleans on May 25 that could be traced to transmission insufficiency, not a lack of capacity. (See MISO Debates What-ifs, Vows Improvements in Front of La. PSC After Load Shed.)

“Today is probably the fifth day or so of a streak of hot weather across most of the Eastern Interconnect,” MISO Senior Director of Reliability Coordination John Harmon said during a July 29 meeting of the Entergy Regional State Committee (ERSC), held a few hours after MISO issued the maximum generation warning. Harmon said MISO and other grid operators were conducting a flurry of analyses and collaborative actions to cope with the heat.

He said an Arkansas transmission line was forced offline late on July 28, impacting MISO’s ability to move power in the South, which prompted the transmission advisory. He also noted MISO’s July 29 demand forecast was higher than originally anticipated.

At the time, Harmon said MISO would act as it saw fit to combat risk.

Public Utility Commission of Texas economist Werner Roth said he appreciated the addition of MISO’s transmission position warnings, noting he’d rather have more notices from the RTO than too few.

MISO prepped for a possible 126-GW peak demand on July 28 but ultimately served nearly 121 GW. In the moment, the RTO said it was contending with forced generation outages and a loss of its import interchange schedules in addition to heat-driven demand.

At one point on July 29, MISO forecast a nearly 124-GW peak and said it had about 130 GW in committed capacity on peak. It reported more than 9 GW in imports near its 121.5-GW peak.

MISO spokesperson Brandon Morris said neighboring grid operators dialed back exports on July 29 because of the widespread heat.

“However, the MISO grid remains stable at this time, and we will continue to work with our member utilities to navigate this prolonged heat wave impacting almost half of the country,” Morris said in an email to RTO Insider at about 4 p.m. ET, when real-time demand passed 120 GW.

‘Very Resilient’

The RTO enacted conservative operations instructions four days in advance for July 28-29, when the extreme heat was expected to pose the most risk.

Additionally, MISO declared a severe weather alert for those days in its Midwest region as it prepared for thunderstorms with winds up to 75 mph and possible tornadoes.

The grid operator has called a string of capacity advisories and conservative operations throughout July, making 17 separate capacity advisories and three conservative operations calls. All told, MISO published 47 notifications to caution members, update them or cancel instructions and alerts.

MISO initiated a series of capacity advisories for MISO South on July 10, 14-17 and 21-24 due to significant forced generation outages. By July 23, the advisory extended to the entire footprint as the grid operator contended with more widespread hot weather and offline generation.

The RTO also instituted conservative operations July 21-25 for the entire footprint due to soaring temperatures.

Meanwhile, MISO rounded out June with a 120-GW peak on June 23 during its sole maximum generation emergency declaration of the summer. (See MISO Declares Max Gen Emergency in Heat Wave.)

MISO Independent Market Monitor Carrie Milton said MISO “successfully managed the situation” without resorting to relying on operating reserves despite the emergency declaration. She added that other grid operators were forced to dispatch and nearly exhaust their operating reserves.

Milton said MISO’s handling of the challenges borne by the heat is further evidence that it doesn’t deserve the high-risk status it was assigned in NERC’s revised Long-Term Reliability Assessment. (See IMM: NERC Reliability Assessment Still Overstating MISO Risk.)

“MISO showed itself to be very resilient,” Milton said at the ERSC meeting.

Beyond the maximum generation event, load averaged 83.7 GW over June, the highest in the past four years. The day before the emergency, solar output peaked for the month at 13.1 GW.

Real-time prices in June rose to an average of $42/MWh, compared with the $28/MWh average in the two previous Junes. Daily generation outages also were up in June, averaging 51 GW — far from June 2024’s 35-GW average.

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DOE Lifts Run Hour Restrictions on Maryland Generator

The U.S. Department of Energy has issued an emergency order to lift annual run-hour restrictions on the H.A. Wagner Generating Station Unit 4 located outside of Baltimore to address a shortage of generation in PJM. 

The 397-MW generator is limited to operating at a maximum of 438 hours when operating on oil fuel by a consent order that Raven Power, a Talen Energy subsidiary, entered with the Maryland Department of the Environment (MDE). In a July 21 request for the emergency order, PJM stated that the unit had 80 hours remaining before hitting the limit. 

The RTO anticipates a need to run the unit throughout the year, particularly when temperatures exceed 82 degrees and loads rise above 151 GW, or to mitigate the impact of transmission or generation outages. In particular, the request stated that if a heat wave similar to the high temperatures seen in late June were to occur again, Wagner would exhaust its remaining run hours. (See PJM Reviews June Heat Wave.) 

“This order reduces the threat of power outages during peak demand conditions for millions of Americans,” U.S. Secretary of Energy Chris Wright said in an announcement of the order. 

The July 28 emergency order allows the unit to be dispatched beyond the run-hour limit when PJM determines the unit is needed to meet demand during a maximum generation alert or transmission security emergency. It is effective for 90 days, which is the maximum allowed under DOE’s Federal Power Act (FPA) Section 202(c) authority. 

The unit’s operation would continue to follow emissions limits. If Wagner is operated “in reliance on this order,” PJM is required to notify the DOE and provide a summary of the hours exceeding the operating limit. 

“The inability to run Wagner Unit 4 could result in adverse reliability impacts to service in the Baltimore Gas and Electric (BG&E) territory, and within PJM’s service territory more broadly,” the emergency order states. “For the remainder of 2025, PJM anticipates the continued need to schedule Wagner Unit 4 in order to maintain reliable system operations during projected peak demand and/or increased flows on transmission facilities that are required to serve the BG&E zone.” 

In its request, PJM wrote that it has been dispatching Wagner Unit 4 more often in 2025 than the year prior, including during the winter storm that set a new seasonal peak on Jan. 22 and for 100 hours during the five-day heat wave in June. PJM wrote that it was told by the MDE that the consent order could not be modified without changes to the larger state implementation plan, which would not be possible before the end of the year. The plan limited Wagner’s run hours in order to meet the one-hour sulfur dioxide national ambient air quality standards. 

Wagner and the co-located 1,289-MW Brandon Shores generator are operating on reliability-must-run (RMR) agreements with PJM to keep the units operational between their desired June 1 deactivation date and May 31, 2029. (See FERC Approves $180M Annually for RMR Deals with Brandon Shores and Wagner Plants.) 

The DOE also has used Section 202(c) emergency orders to delay the deactivation of two generators in PJM and MISO: Consumers Energy’s 1,560-MW J.H. Campbell coal plant in West Olive, Mich., and Constellation’s 760-MW Eddystone Units 3 and 4 near Philadelphia. Those orders focused on broader resource adequacy shortfalls the RTOs have discussed. (See DOE Orders PJM, Constellation to Keep 760-MW Eddystone Generators Online.) 

NRDC Director of RTO Advocacy Casey Roberts said PJM was urged by organizations like the Sierra Club to consider alternatives to an RMR agreement for Brandon Shores and Wagner, including the feasibility of battery storage at the site. The situation shows that relying on inflexible fossil generation vulnerable to issues with environmental standards and permits is not a good solution, she said. PJM’s Deactivation Enhancement Senior Task Force is in the early stages of considering alternatives to retaining deactivating resources on RMR agreements, she added. 

While avoiding RMRs outright would provide a more long-term solution, Roberts said PJM also has not been clear enough on the operational alternatives it may have to avoid dispatching Wagner above its maximum run hours, such as how Wagner would be dispatched relative to demand response. 

Roberts said Section 202(c) orders have been sought by PJM in the past to allow resources to exceed environmental permits during acute needs, including allowing units to exceed run hours during Winter Storm Elliott. The Wagner order is more theoretical in the needs it aims to resolve, she said. Unlike the Campbell and Eddystone orders — which she said were based on sweeping resource adequacy claims — the Wagner order is more rooted in an evidentiary basis, but there remains insufficient detail on how the generator may be deployed.  

“PJM is not being very transparent about the circumstances in which it is dispatching Wagner, or Eddystone for that matter,” she said.

In response to Roberts’ comments, PJM spokesperson Jeff Shields said the RTO sought an order from the Secretary of Energy to allow the H.A. Wagner generator to continue operating beyond its run-time limitation to preserve grid reliability in specific circumstances over the next 90 days. PJM will dispatch Wagner Unit 4, a 397-MW fuel-oil generator in the BG&E territory, only under limited emergency conditions, Shields said. He emphasized that Wagner 4 already is operating under a FERC-approved RMR agreement to operate beyond its intended deactivation date through 2029.

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EPA Proposes Rescission of Endangerment Finding that Underpins All GHG Rules

EPA is proposing to rescind its 2009 endangerment finding, which qualifies greenhouse gases as pollutants and has been used by Democratic presidential administrations to regulate emissions from power plants and other sources.

The rescission, if finalized, would repeal regulations on greenhouse gas emissions from all motor vehicles and engines, the agency said. “However, EPA intends to retain, without modification, regulations necessary for criteria pollutant and air toxic measurement and standards, Corporate Average Fuel Economy testing and associated fuel economy labeling requirements,” it said.

“With this proposal, the Trump EPA is proposing to end 16 years of uncertainty for automakers and American consumers,” EPA Administrator Lee Zeldin said in a statement. “In our work so far, many stakeholders have told me that the Obama and Biden EPAs twisted the law, ignored precedent and warped science to achieve their preferred ends and stick American families with hundreds of billions of dollars in hidden taxes every single year.”

The endangerment finding came from the Supreme Court’s decision in 2007’s Massachusetts v. EPA, in which the court sided with the state when it sued the agency to regulate GHGs under the Clean Air Act. Prior to the ruling, carbon dioxide was not considered a pollutant under the law.

EPA’s latest proposal calls the endangerment finding “unprecedented,” saying it interpreted the CAA as authorizing the regulation of domestic emissions from new motor vehicles and engines based on global climate change concerns “rather than air pollution that endangers public health or welfare through local or regional exposure.” The agency has already proposed repealing the Biden administration’s attempt to regulate power plant greenhouse gas emissions. (See EPA Proposes Repealing Limits on Power Plant Greenhouse Gas Emissions.)

The proposal also says the Supreme Court “did not require the agency to find that GHGs are subject to regulation under CAA Section 202(a) and does not support our implementation of the statute since 2009.”

The agency says the proposal would save $54 billion annually by repealing all of the GHG standards.

Recent Supreme Court decisions like West Virginia v. EPA — which found the agency could not regulate power plant emissions through generation-shifting mechanisms, as was proposed by the Obama administration in its Clean Power Plan — and Loper Bright v. Raimondo — which ended the doctrine of deference to agencies in statute interpretations, known as Chevron deference — provided the basis for EPA’s proposal.

But the courts have upheld Massachusetts in the 18 years since it was issued, National Wildlife Federation Director for Legal Advocacy Jim Murphy said on a call with reporters.

“I think that EPA is on very shaky ground here, on both the science and the law,” Murphy said. “It would remove the obligation for EPA to take action to curb greenhouse gasses, and that’s just not efforts like the Clean Power Plan or other attempts to regulate emissions from power plants, but it could affect things like methane emissions from oil and gas production and a whole host of other efforts that EPA has taken.”

The move is certainly going to be challenged in court, assuming EPA concludes its rulemaking and finalizes its proposal, and Murphy said he hoped it would be overturned.

The Department of Energy was involved in the EPA action, producing a report called “A Critical Review of Impacts on Greenhouse Gas Emissions on the U.S. Climate” that reviewed literature and government data on the climate impacts of greenhouse gas emissions.

“The rise of human flourishing over the past two centuries is a story worth celebrating. Yet we are told — relentlessly — that the very energy systems that enabled this progress now pose an existential threat,” Energy Secretary Chris Wright said in a statement. “Climate change is real, and it deserves attention. But it is not the greatest threat facing humanity. As someone who values data, I know that improving the human condition depends on expanding access to reliable, affordable energy.”

The House Sustainable Energy & Environment Coalition, a group of Democratic representatives who support climate policies, criticized EPA in a statement, saying the scientific consensus is overwhelming.

“Climate change is already wreaking havoc across America,” the SEEC said. “By ignoring the overwhelming scientific consensus, contradicting the clear statutory language in the Clean Air Act and overriding repeated Supreme Court rulings, EPA has revealed today just how far it will go to be every polluter’s ally.”

Posting on X, LS Power CEO Paul Segal argued that EPA’s effort to withdraw the endangerment finding should not matter to his sector.

“I don’t think this matters for the power generation industry,” Segal said. “Investors need to expect political volatility (We’re living it!) and plan for the worst case — whatever that might be for the investment you are making.”

Union of Concerned Scientists President Gretchen Goldman said the administration is using the “kitchen sink approach” to avoid complying with the law.

“But getting around the Clean Air Act won’t be easy,” she said. “The science establishing climate harms to human health was unequivocally clear back in 2009, and more than 15 years later, the evidence has only accumulated. Communities across the nation are having to cope with deadly heat waves, accelerating sea level rise, worsening wildfires and floods, increased heavy rainfall, and more intense and damaging storms. Burning fossil fuels has made the climate increasingly unstable and dangerous for people.”

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Stakeholder Forum: PJM Is Flailing, but There’s a Solution

By Brad Viator and Alison Williams

These days, partisan alignment on public policy issues is as rare as a vegetarian in southeastern Texas.

Alison Williams

But in early July, nine governors, Republicans and Democrats alike, sent a letter to the PJM Board of Managers, whose energy market is responsible for shockingly high rate increases across 13 states and D.C. The governors say that “market participants, consumers and the states” that participate in PJM are having a “crisis in confidence” in the beleaguered grid operator. PJM likely has never been the recipient of such organized, cross-party discontent in its 100-year history.

Brad Viator

At the heart of the PJM problem is the inability of the grid operator to bring new generation online quickly enough to match skyrocketing demand for electricity. This shortfall is manifesting directly into exorbitant energy costs. The crisis of timely and affordable generation is largely attributable to a combination of factors: decreased supply because of coal and gas plant retirements, and increased demand because of electrification and data center expansion.

The governors wrote that PJM’s response to this capacity challenge “has been typified by halting, inconsistent steps and rising internal conflicts within the stakeholder community.” According to a report from Reuters, “new projects totaling about 46 GW — enough capacity to power 40 million homes — have been cleared in recent years,” but they are not being built because of PJM’s painful bureaucratic delays and market-based shortcomings.

Just how bad is PJM’s current electricity shortfall? Consider the recent capacity auction that closed July 22. (See PJM Capacity Prices Hit $329/MW-day Price Cap.) Electricity prices soared to $329.17/MW-day — and were it not for a measly price cap orchestrated by Pennsylvania Gov. Josh Shapiro (D) earlier this year, the auction price would have reached $389/MW-day. (See FERC Approves PJM-Pa. Agreement on Capacity Price Cap, Floor.) One could argue that the cap worked in practice if not in principle; the capped price still represents a 22% jump over last’s auction price and a whopping 1,100% more than the clearing price two years ago. (See PJM Capacity Prices Spike 10-fold in 2025/26 Auction.)

And let’s not lose sight of who’s paying the price — customers. The New York Times on July 23 referenced the president and chief executive of multistate electric utility Exelon, saying that “some of his customers in Maryland, for example, could pay an additional $1 to $4.50/month as a result of the auction, depending on their location.”

Fundamentally, the PJM market is broken. Higher prices are supposed to signal energy producers to bring new capacity online. But because of PJM’s deep dysfunction, new generation is not showing up, even at exorbitant prices. Yet, PJM’s capacity auction press release essentially is a humble brag that their market is functioning.

In reality, though, capacity inside PJM is about the same as it was in 2024. More alarmingly, the auction cleared its reliability requirement by the slimmest of slim margins at 139 MW over the required threshold to have a functional market. That translates to a miniscule buffer of 0.001% of the capacity total of 134,311 MW. In other words, the market was a stone’s throw away from collapse.

Everyone knows we need more electricity. It’s painfully clear PJM is not capable of responding to increased demand.

But is there a better path forward that would make the PJM markets more reliable at creating new capacity? The answer is yes.

PJM needs to look to the southeastern U.S., where states like Georgia and Louisiana are attracting new data centers by adding capacity quickly and cost-effectively. This is not occurring by happenstance but rather through sensible planning between regulated utilities and their state regulators in public service commissions, who are being mindful of costs, growth and timing. While PJM cannot become a state regulator, it can plan like one by streamlining its processes and reforming poor functions to bring new capacity in a way that balances reliability and affordability — something utilities in vertically integrated markets never lose sight of.

Further, if PJM behaved more like a PSC and prioritized proper planning and adequate power availability, this would also help solve another of the grid operator’s most pressing challenges: the interconnection queue consisting mostly of non-dispatchable renewable energy that is unlikely to materialize because of a stack of challenges, including tariffs, supply chain problems, sunsetting tax credits and the same exact megawatts of renewables existing in other interconnection queues.

If PJM actually planned to strategically locate dispatchable generation, such as natural gas, it could make some of the renewables projects more viable by allowing those two sources to operate hand-in-glove to ensure stable energy day and night.

One thing is clear: PJM cannot afford to continue to take a passive approach to capacity. The grid operator must be decisive, act quickly and be willing to make hard choices about the future of the region’s energy supply. PJM also must be prejudicial in its decisions — identifying and prioritizing the energy sources it believes are real and shovel-ready commitments and then locating them in optimal places to ensure those sources are developed and brought online efficiently.

Finally, as a first step to reforming PJM, the nine governors are urging the RTO to appoint two new members to open seats on its board through a transparent process with input from those state executives. The letter states: “They must be individuals who understand the concerns of ratepayers facing rising costs.” (See State Governors Seeking Ability to Nominate 2 Members to PJM Board.)

Adding two new board members is a good first step. But it is an insufficient change to PJM’s underlying structural flaws. PJM must revise its mentality to act more like a PSC and focus on building new, dispatchable generation capacity — such as natural gas — that can both stand on its own and aid in renewables deployment. If utility regulation can work in the Southeast to build new capacity, there is no reason PJM, with its massive footprint, can’t do the same through smarter planning.

Brad Viator and Alison Williams are energy consultants at B Strategic Solutions.

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DTE Expects to Need Gigawatts of Capacity for Data Centers

DTE Energy reported it is in various stages of discussion to supply as much as 7 GW to new data centers and is on track to reach agreement on the first project by the end of 2025.

The news came with the Michigan utility’s second-quarter earnings report July 29, which also contained an update on the outlook for continued renewables development.

DTE President Joi Harris fielded most of the questions during an earnings call with financial analysts. CEO Jerry Norcia, whom she will succeed in September, filled in more details.

Harris said data center developers have shown interest in Michigan because there is excess generation capacity and because the state enacted tax incentives to attract them.

She noted that DTE previously had reached framework agreements for 2.1 GW of data center load but said some negotiations are now further along.

DTE will not count one of these potential large customers as part of its pipeline until it has secured land or has strong prospects of doing so and has a pathway to zoning approval.

The utility is in advanced discussions with developers who would present more than 3 GW of new demand; each has secured land, zoning approval and some degree of community support. It is in continuing discussions with developers representing 4 GW of new demand who have not progressed as far with their site planning but are on track with it.

Harris said DTE hopes to seal the first agreement — 1 GW for a hyperscaler’s project — before 2026: “Our intention is to have a really good indicator by the third quarter and have a final deal in hand by the end of the year.”

The utility has more than 1 GW of capacity available and plans to add 1 GW of storage to match the data center’s demand watt for watt, Harris said. This would come from a combination of power purchase agreements and self-build, she said, and the cost is estimated at $1 billion.

Further data center buildouts would require additional storage capacity, she said, as well as new baseload generation — such as carbon capture-ready combined cycle gas plants.

Meanwhile, DTE continues to plan coal retirements, so it plans to add new capacity beyond whatever the data centers need.

“We’re already in the MISO queue for at least one plant and potentially two, and that’s to serve our existing load,” Harris said.

DTE still plans to meet some of that demand with renewables — even as the Trump administration works to make renewables harder and more expensive to build. It has 2,500 MW of renewables in service now and plans to add 900 MW a year for the next five years.

Based on the longstanding definition of “safe harbor” and the provisions for safe-harboring in the reconciliation bill, DTE does think it can bring its projects to completion and still claim the Biden-era tax credits.

“Just as a reminder, we have to build these assets. It is required under the law,” Harris said, apparently referring to the state mandate of 50% clean energy by 2030 and 100% by 2040.

The 900 MW of annual renewable capacity is expected to have a large component of solar and storage, though some consideration is being given to repowering existing wind turbines. The economics of solar are better than wind at this point, and community acceptance of solar has proved greater than for wind.

Analysts asked for greater specificity regarding the infrastructure changes implied by the announcements, and whether DTE needs to pull forward its 2026 Integrated Resource Plan. But the details are fluid.

Harris said DTE’s next IRP will provide more insight on anticipated load growth and strategies to meet that demand, but there is no need to accelerate the timetable.

“So we don’t intend to pull forward the IRP,” she said. “What we intend to do is serve the load near term with our existing riders and tariffs and then move toward building out larger assets based on the results of the IRP.”

DTE reported operating earnings of $283 million or $1.36/share in the second quarter of 2025, down from $296 million or $1.43/share in the second quarter of 2024.

The company reaffirmed its guidance for 2025 operating earnings of $7.09 to $7.23/share. Its stock price closed 0.2% lower July 29.

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SPP ERAS GI Requests to Begin in September

With FERC approval of SPP’s expedited resource adequacy study (ERAS) process now in hand, SPP has notified stakeholders that the one-time study’s submission window for fast-track reviews will open Sept. 2. 

In a July 28 email to load-responsible entities, generator interconnection customers and other stakeholders, SPP said it has targeted March 20, 2026, to execute GI agreements. It said the target date is subject to study progress and the timely completion of all process steps. 

The ERAS submission window will close Oct. 2. At that time, the RTO will notify applicants of any deficiencies in their requests and allow them to address the issues during a certain time period. 

The study itself will begin Oct. 17, subject to execution of required agreements. Staff will work with applicants on agreement execution, study cost deposits, procedural requirements and other steps as the process continues. 

Ceiling capacity values — the maximum amount each LRE can select for inclusion in the ERAS — will be posted to their respective resource adequacy folders by Aug. 1. 

SPP proposed the one-time ERAS study outside of its normal planning process to help LREs meet their resource adequacy (RA) requirements for 2030. It said the study was necessary because there is a 16.7-GW aggregate gap between resource adequacy requirements and capacity. 

FERC agreed with a July 21 order approving the ERAS process. It found that SPP has “existing authority” under its tariff to evaluate and maintain resource adequacy and to manage its interconnection queue to provide sufficient generation to meet RA requirements. It agreed with SPP that ERAS requests will receive a GIA “significantly sooner” than those processed through the RTO’s normal study process. (See FERC Approves SPP’s ERAS Process, Accreditation.)