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December 29, 2025

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Solar Power Continues to Make Gains, but Slowdown Expected in 2026

Photovoltaic solar is expected once again to account for a significant percentage of U.S. generation capacity additions in 2026, even as the number of gigawatts being installed decreases from record highs in 2023 and 2024.

The degree of risk and uncertainty springing from indifferent or outright obstructive new federal policies in 2025 has trimmed planned solar deployment, but not “bigly,” because the central argument for solar endures for now: It is a relatively quick and cheap way to add emissions-free electrons to a grid that sorely needs more electrons.

“We’ve seen a tremendous decrease in the levelized cost of solar, though that has slowed in recent years, given a lot of the supply chain and tariff effects that are out there,” said John Hensley, senior vice president of markets and policy analysis for the American Clean Power Association. “But solar in many of these markets is the least-cost new-build resource. And in some cases, you pair that with storage, which is a fairly cost-effective strategy, and that combo pack just looks very enticing in a lot of these markets.”

Solar has another advantage: Alternatives are limited.

No one is likely to build new coal or large conventional hydro generation; new nuclear is coming but not for several years; and new natural gas turbines are expensive and backlogged for a few years.

New deployment of wind power has slowed to the point that solar is poised to surpass it as the largest U.S. renewable resource by nameplate capacity.

Countering these factors is President Donald Trump. While he does not express the same hostility for solar panels as for wind turbines, he does treat solar like a rival to fossil fuels and is moving to limit solar through policy restrictions, tariffs and elimination of tax credits.

What new surprises the Trump administration holds for solar and other renewables in the new year can only be guessed.

But so far, the effect has been significant if not severe. BloombergNEF in November lowered its 2025-2035 projection of solar capacity additions by 25% but still expects to see 432 GW of new utility-scale solar.

The Solar Energy Industries Association and Wood Mackenzie in December maintained their projection of 250 GW of solar installations from 2025 through 2030, with the caveat that significant uncertainty hangs over the industry and its future.

The U.S. solar industry has the potential to build more than 250 GW, WoodMac added.

In February 2025, well before the One Big Beautiful Bill Act codified an early end to federal tax credits for solar and wind projects, the Brattle Group looked at the possible outcome of eliminating or altering clean energy credits in a report commissioned by ConservAmerica. It concluded solar additions through 2035 would drop from 550 GW to 242 GW.

Samuel Newell, who leads more than 50 electricity-focused consultants at Brattle and was a co-author of the report, told RTO Insider that solar will continue to see growth, though not unbridled.

“Solar is absolutely a proven technology and continuing, even still, to improve, and so we’ll still see more of it,” he said. “I think the headwinds are there too. There is community opposition. There is the cost relative to gas-fired [generation] in a world that’s not paying for its emissions, and it also has the challenge that … in terms of meeting resource adequacy needs, it has lower and lower marginal value the more you add, and even lower energy value the more you add.”

The drop-off is a few years away, Newell predicted.

With “wind and solar, there’s obviously a rush to build the plants currently far enough along to be able to meet the safe harbor to still get the tax credits,” he said. “After that, I would expect them to fall off quite a bit. Some states will still build them where they’re economic because there’s such good wind and solar resources. They won’t build as many as they would have if there had been the tax credits.”

Illuminate USA employees mark production of the 1 millionth solar panel at the company’s factory in Ohio. | Illuminate USA

Alexander Heil, a senior economist with The Conference Board whose work centers on renewables and the energy transition, said the numbers still support solar even if policy does not.

“If you look at some of the data, solar and storage is now cheaper than natural gas when it comes to electricity generation,” he said. “So I think it’s probably a question of how much that transition is going to slow in the U.S., [rather than] completely turn around.”

Heil added the caveats that economics and solar resources are far from equal from one region of the country to the next.

(One example: The Energy Information Administration reported that 2023 capacity-weighted average cost of new solar construction in the Northeast was $2,584/kW — 61 to 67% higher than in the South, West and Midwest. It also reported that solar capacity factors in the Northeast states are lower or much lower than in those other regions of the country.)

Coal produced 196% more U.S. electricity and natural gas produced 750% more than utility-scale solar panels in the last year of Joe Biden’s presidency. Plenty of people and interest groups would like to raise those percentages even higher, and they have the ear of policymakers in the first year of Trump’s second presidency.

SEIA in November issued a report warning that more than 500 solar and storage projects totaling 117 GW of capacity are threatened by political attacks. On Dec. 4, it sent Congress a letter signed by 143 solar companies asking it to get the Department of the Interior moving again on permitting solar projects. A near-total moratorium had been in place since an Interior memo in July that revised the review procedures, they complained.

That memo was a master work of byzantine bureaucracy and analysis paralysis. ACP and many other clean energy advocates called it an intentional effort to slow renewables. It specifies separate reviews by two high-ranking Interior officials of a 68-point checklist for wind and solar facilities on public land and then a third review by the Interior secretary himself. The 69th point is a catchall for anything not included in the first 68 points.

The policy extends beyond public land to include anything on private land that needs a permit from the Interior, requires the department to sign off on another agency’s permit or uses its resources.

Two weeks after the SEIA protest letter, Interior signed off on a 700-MW solar project proposed in western Nevada.

Whether or not this was an actual or de facto moratorium, the takeaway is the same: The momentum the U.S. solar industry carries into 2026 is shadowed by uncertainty and risk.

“I think there’s a number of officials who look at executive orders and some of the action by Interior or other parts of the administration, and the gut thinking is that, ‘Oh, this only affects projects that are on public lands or in public waters,’” Hensley said. “But when you read deeper into those documents … you realize it affects more.”

All this comes after considerable effort and expense to establish a U.S. photovoltaic manufacturing base — something that would mesh well with Trump’s stated priorities if it did not involve renewable energy.

Sixty-five solar and storage manufacturing facilities began or expanded production in the first three quarters of 2025, SEIA said, including an ingot and wafer factory that completed the supply chain. Every major component of a solar farm now can be sourced from U.S. factories.

Just in those nine months, U.S. solar cell production capacity more than tripled, and it has increased more since then.

“We’ve seen tremendous advancements in the development of solar and battery module manufacturing facilities, increasing focus and intent on bringing the cell manufacturing lines here to the U.S.,” Hensley said. “We don’t want to lose sight of that. It’s not just about bringing electrons to the system; there’s a lot of job creation and economic growth activity that’s going on in the manufacturing space as well, and it’s happening fast.”

ACP tallied 146.2 GW of utility-scale solar generation nationwide at the end of the third quarter of 2025, nearly half of which came online after 2022. EIA reported that solar was expected to account for more than half of all new U.S. generating capacity coming online in 2025.

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The Year the Humble Electron Becomes Politicized

As we turn the page from 2025 to 2026, the trends of the past year are not just continuing, they are accelerating. The defining story of the coming year will be the widening chasm between electricity supply and demand, a dynamic driven by a slow-moving supply side, coupled with the explosive growth of energy-hungry data centers.

Physical bottlenecks: Access to hardware, whether for generation or transmission, is becoming a big problem. Transformers, switchgears and turbines are in short supply and increasingly expensive. Even when equipment is available and developers can put steel in the ground, the existing interconnection process is far too sluggish to meet projected demand. While some grids are working to fast-track these issues, and even employing AI to assist with the process, it’s not fast enough.

Even if we could access equipment and resolve the interconnection issue, there’s simply not enough existing transmission to accommodate new supply. That barrier exists largely because the permitting process is agonizingly slow — where transmission facilities traverse multiple states. The SunZia and Grain Belt Express projects are strong examples: Each took well over a decade to get approvals lined up.

Peter Kelly-Detwiler

Software and applied intelligence augment the existing system’s capabilities to do more, with applications such as dynamic line rating, topology optimization and power flow management. They, as well as reconductoring of existing transmission lines, can provide some relief but cannot meet the magnitude of the challenge.

These infrastructure timelines are simply incompatible with the “I-want-it-yesterday” urgency of the data center industry — the modern-day equivalent of Rumpelstiltskin that no longer spins straw into gold, but rather converts data, silicon chips and power into enormous digital wealth.

Financial and National Security: There’s also a pressing national security imperative. Those countries that dominate the data also will dominate the future economy and military battlefields. The Russia-Ukraine conflict, rapidly shifting from a people-centered struggle to one driven by software, fiber optics and lethal drones, clearly demonstrates how swiftly AI is transforming modern warfare and how urgently the global AI race must be won.

The Astonishing Accelerating Pace of Change: Three short years ago, AI had a relatively minimal profile. The launch of ChatGPT 3.0 catalyzed a rapid shift in that industry, and a race to feed chips and machines with power. Here, though, the virtual world collides with the physical reality and complexity of the electric grid. That collision creates significant uncertainties because of the speed and the magnitude of the projected growth in demand.

In this new world, billions of dollars now seem trivial, AI companies make circular investments in each other, and chip technologies and AI modeling approaches constantly evolve. It’s also a world in which few AI companies are demonstrating profitability. We may well look back at 2026 as the start of a golden age, or as a repeat of the dotcom bubble — leaving behind enormous, stranded assets if the promised returns fail to materialize.

The Federal vs. States’ Rights Collision: In 2026, the electron will sit square in the middle of the centuries-old tug-of-war between state sovereignty and federal oversight. This is epitomized by the Department of Energy-mandated FERC rulemaking to standardize large load interconnection processes.

The related debate is contentious. By the recent comment deadline, approximately 150 comments had been filed. State entities such as the National Association of Regulatory Commissioners (NARUC) and the National Conference of State Legislatures pushed back, with NARUC commenting: “The commission should avoid any action that would circumvent or negate state decisions governing the provision of retail service.” Similarly, the NCSL stated: “This new proposed rule would bring under federal jurisdiction an issue that is currently handled by the states and has been for decades. … Such actions should also not remove decision-making powers that have historically been left to the states.”

FERC must publish its determination by April 2026. Given the size of the prize at stake, it’s likely to be controversial and spark ongoing debate regarding states’ rights.

As big as that issue is, it may be eclipsed by legislation related to permitting of new energy infrastructure. Construction of such infrastructure inevitably raises questions about states’ rights, eminent domain and property rights. States have been quite successful in either delaying or terminating many infrastructure projects proposed over recent decades. That’s one critical reason so little energy infrastructure has been built recently. But it’s also not a sustainable model for the future, given the pressures on today’s fragile grid that are further exacerbated by data loads.

When Elephants Fight, Grass Gets Trampled: With obvious shortfalls in capacity to meet new large loads, we already are seeing the impacts on other customers’ wallets. The past three capacity auctions in PJM have resulted in punishingly high prices for load. In the first two auctions, the revenues associated with existing and forecast data center load were estimated to exceed $16.6 billion, representing more than half of the entire revenues paid to capacity. The second auction, for 2026/27, would have gone higher had a negotiated cap not been in place.

The most recent auction in mid-December for 2027/28 saw prices hit the cap again, clearing at $333.44 per MW-day, and likely adding an additional $8 billion of data-related costs to the data center-related tab. Worse yet, when PJM ran a simulated auction absent the cap, prices catapulted to $529.80.

This burden falls squarely on other ratepayers, with capacity costs now representing well over 25% of the wholesale power bill. Absent political or regulatory intervention, the effects may get much worse, since the June 2026 auction for 2028/29 no longer is capped.

The Rise of Flexible Load: To mitigate these effects, many PJM members insist that new large loads must bring their own capacity or agree to be interrupted. They maintain this is the only way to ensure that other ratepayers are not affected. Clarity is hard to come by: A dozen proposals related to large load interconnections recently were considered by PJM stakeholders, but none were approved, leaving lack of clarity as to what to do next.

Meanwhile, a FERC ruling told PJM to develop a clear set of rules (and report back by Jan. 19, 2026) for co-located data centers siting next to generation to speed access to power, and their associated impacts on transmission.

Meanwhile, in Texas, Senate Bill 6 was signed into law in 2025, authorizing ERCOT to use the so-called “kill switch” to cut power to data centers during grid emergencies. Details as to how that will work in practice are being resolved. Just to the West, SPP has approved an expedited interconnection process of just 90 days if data loads commit to being interrupted when necessary.

2026 a Volatile Mix: With electricity bills rising, data-related loads have become a lightning rod. The coming year promises a heated political environment. Already House Democrats have floated the “Protecting Families from AI Data Center Energy Costs Act,” urging FERC to examine ways to manage rising power costs associated with data centers.

Add to that President Trump’s Dec. 11 executive order “Ensuring a National Policy Framework for Artificial Intelligence.” Between massive AI loads and the infrastructure permitting debate, the stage is set for a collision between the fast-moving culture of Silicon Valley and the regulated and risk-averse power sector. Then throw in the centuries-old tension between states and federal power just to spice up the mix. In 2026, electricity no longer will be just a commodity; it will become a political flashpoint.

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WRAP Builds Momentum, Faces Challenges Heading into 2026

With 16 binding participants and 58 GW worth of load committed, the Western Power Pool’s Western Resource Adequacy Program aims to build on the momentum in 2026 and prepare for more members.

Sixteen participants decided to remain in the WRAP before the Oct. 31 deadline to either exit or commit to the program’s first “binding” — or penalty phase — season in winter 2027/28. (See WRAP Wins Commitments from 16 Entities.)

WRAP now has critical mass and will continue refining the initiative, WRAP Director David Zvareck and WPP Chief Strategy Officer Rebecca Sexton told RTO Insider in an interview.

“We’ve still got two more nonbinding forward showings ahead of us,” Zvareck said. “Those are really the final opportunities for our participants to learn more about the program, get things dialed in and work on curing any deficiencies that they might have had.”

Addressing deficiencies refers to members ensuring they are resource adequate ahead of the first binding season, Sexton noted.

“We’re offering an RA program in the midst of a resource adequacy crisis,” she said. “And in the time it’s taken to get this program off the ground over the last six years, the crisis of resource adequacy has just gotten worse.”

Interconnection requests from large load customers, such as data centers, coupled with supply chain issues make it difficult to keep up and build new generation, Sexton said.

“This makes the program more important but also means that participants have had to work really hard to close the gap so that they can be resource adequate when they go through the first binding season,” she said.

With the WRAP being a requirement to participate in SPP’s Markets+ day-ahead market, Sexton and Zvareck anticipate more entities to join the RA program in 2026.

“The notion of getting a whole group of new participants that could be larger than any we’ve seen so far is a new kind of challenge for us,” Sexton said.

Zvareck and Sexton could not disclose the number of potential new members, but Sexton said there is “a lot of opportunity there to increase the diversity of the footprint … but it certainly could be quite a bit more work to onboard a larger group of folks than we have previously.”

Day-ahead Market Impacts

Most of the 16 participants that committed to the WRAP plan to join Markets+. Meanwhile, five utilities withdrew from the program before the Oct. 31 deadline, including four that plan to participate in CAISO’s Extended Day-Ahead Market (EDAM): NV Energy, PacifiCorp, Portland General Electric and Public Service Company of New Mexico.

Markets+ and EDAM are set to launch in 2026 and 2027, respectively.

Exiting EDAM members cited high deficiency charges, concerns about Markets+ gaining more voting power in the WRAP and challenges operating under a divided Markets+ and EDAM footprint, among other issues. While WPP administers the WRAP, the technical platform is managed by SPP, prompting some participants to question whether EDAM participants can get equal treatment under the program.

Those concerns led some future EDAM participants to launch discussions in April 2025 about developing an alternative RA program for non-CAISO EDAM members, according to a Dec. 18 filing NV Energy submitted to the Public Utilities Commission of Nevada in response to questions about its decision to withdraw from the WRAP. (See NV Energy Filing Reveals Extensive Talks Around EDAM RA Program.)

The West-Wide Governance Pathways Initiative’s Regional Organization for Western Energy has been floated as a potential overseer of an EDAM-aligned RA program. (See Pathways’ ROWE Could Offer Western RA Program, PGE Says.)

Though the WRAP was conceived before the day-ahead markets, Sexton sees opportunities in leveraging them for the program’s purposes. The program’s Day-Ahead Market Task Force is exploring how it can adapt and ensure that both Markets+ and EDAM participants can reap its benefits. (See WRAP Day-Ahead Market Task Force Looks to Future After Commitments, Withdrawals.)

“The thing that’s wonderful about the advancement of the day-ahead market existence — the paradigm that is about to be introduced here — is that they can start leveraging what connectivity does exist in a way that WRAP was never scoped to do,” Sexton said.

For example, the task force is looking into how WRAP can use the day-ahead markets to share the resource diversity between the Northwest and Southwest, Sexton noted.

“It was clearly a priority of the Day-Ahead Market Task Force participants to continue to remain inclusive of a broader footprint and broader participation in WRAP,” Sexton said. “So, it’ll be important to us to be watching how we can not only lean into the Markets+ opportunities presented but also ensure that anyone not in Markets+ can still access the diversity and the benefits of WRAP and be a participant in the WRAP value proposition.”

Seams Issues?

Zvareck said participants in both market camps are eager to collaborate and make the program work.

One concern with having two separate day-ahead markets is the potential for friction at their borders as entities join one market or the other. These seams arise from differing policies and separate dispatch between neighboring markets, which can result in additional costs for transferring energy across the boundary. (See CAISO, SPP Explore Using Existing Tools to Manage DAM Seams.)

The WRAP team will pay “close attention to the seams coordination discussions going on between CAISO and SPP because … there’s an opportunity for that to better inform us how those will work,” Zvareck said. He noted it is still too early to tell exactly how the seams will impact the WRAP.

When asked how much the exits from the WRAP impacted RA efforts and connectivity in the West, Spencer Gray, executive director of the Northwest & Intermountain Power Producers Coalition, said a single RA program would be ideal.

“Over time, harmonization or at least liquidity for RA products with what’s required in California would be even better,” Gray said. “I have hoped that WRAP could provide that, and perhaps it will still evolve in that direction. The region certainly spent a lot of brainpower and effort to launch WRAP, and from NIPPC’s membership, there are competitive retailers both in and out of WRAP.

“But setting aside some of the design challenges of WRAP for many load-serving entities, my overall perception is that while WRAP has predated both the EDAM and Markets+ tariffs and go-live dates, the financial importance in terms of trading volume and the organizational impact of a day-ahead market on participating entities have overwhelmed the value proposition of WRAP for some LSEs,” Gray said. “Some kind of regional RA program and requirement remains highly valuable — to lower the planning reserve margins of individual LSEs and to avoid a dangerous game of musical chairs — but it can take several forms.”

Fred Heutte, senior policy associate at the NW Energy Coalition, said WRAP participants are working to address the concerns of utilities that provided exit notices.

“Those utilities in turn continue to be involved in the WRAP for the next two years, and a lot can happen in that time,” Heutte said.

For Heutte, one of the key RA questions going into 2026 will be how much demand from data centers and other new large loads will materialize. Already, there have been indications of a market correction on some of the higher forecast estimates, he said.

“Transmission facilitates resource adequacy,” Heutte said. “A lot of effort is going into bringing advanced transmission technologies and new power lines onto the grid.”

Heutte pointed to the Western Transmission Expansion Coalition study plan, which is set for public release Feb. 4. The WestTEC effort, jointly facilitated by the WPP and WECC, will address long-term interregional transmission needs across the Western Interconnection. The goal is to produce transmission portfolios for 10- and 20-year planning horizons. (See WestTEC Targets Early 2026 for Release of 10-year Tx Outlook.)

WestTEC is just one example. Efforts are underway in California and Oregon, and Portland General Electric has struck a deal with a data center to bring behind-the-meter batteries to address local RA concerns. The Bonneville Power Administration has launched initiatives to accelerate onboarding of new resources, Heutte noted. (See Utilities Back Some BPA Transmission Updates, Hesitate on Others.)

“And there are many, many other examples throughout the West,” Heutte said.

A recent study by Energy and Environmental Economics predicts that accelerated load growth and aging power plant retirements will create a resource gap starting around 1.3 GW in 2026 and expanding to almost 9 GW by 2030. (See 9-GW Power Gap Looms over Northwest, Co-op Warns.)

Heutte cautioned against interpreting the study as an emergency. He said reports from WECC and the Northwest Power and Conservation Council show the region can meet needs if resource efforts pick up.

“It is important over the next year to focus on the basics and not fall into complacency or panic,” Heutte contended. “And it’s not a matter of reliability versus affordability; both are essential. Everyone wins when the lights stay on and everyone can afford their energy bills. When it comes to resource adequacy in the West, we are surrounded by opportunity, but we have to make the effort now.”

When discussions about launching the WRAP began in 2019, few could have predicted the resource crisis to reach the point it is at now, WPP’s Sexton said.

“I don’t think anyone could have imagined back in 2019 how much harder the resource adequacy problem would have become in the six years since then, or how much commitment we would have to this binding version of a program: more than 58 GW of load and great regional diversity,” Sexton said.

“Our participants are solving that problem,” she added. “They are the ones actually acquiring the resources, making the resource decisions, working on supply chain issues, and then working with us on the metric side and the program side to figure out how to properly stand up the program that they’re committed to.”

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U.S. Hydropower Faces Prospects for Growth, Contraction in 2026

The U.S. hydroelectric sector is approaching a bit of an inflection point as 2026 begins: The demand for energy storage capacity is driving a flurry of proposals for new pumped storage hydropower (PSH) capacity, but proposals for new conventional hydro facilities are limited to small-scale projects.

Moreover, much of the U.S. conventional fleet is aging, and many operators must decide whether to begin the often-long and potentially costly federal relicensing process.

The kinetic energy of moving water has been harnessed for so many centuries and is so integrated into the landscape that it can be easy for people outside the electric industry to forget it is there.

But nationwide as of 2024, there were 2,250 conventional plants rated at a combined 80.6 GW and 42 PSH facilities rated at 22.2 GW, the Oak Ridge National Laboratory reported September in its 2025 Market Update. These accounted for 5.9% of all U.S. power generation and 27.4% of U.S. renewable electricity generation.

Just as important in the era of intermittent generation, hydro offers the grid a dispatchable backstop when demand spikes up or supply spikes down. The National Hydropower Association (NHA) calculates hydro accounts for about 40% of the U.S. black-start capacity.

But there is no new Hoover Dam or Niagara Power Project on the drawing board, nor is there likely to be, NHA President Malcolm Woolf told RTO Insider.

“We’re not building those kind of massive hydropower facilities anymore,” he said. “The real challenge is, how do we not go backwards? How do we not lose that critical infrastructure?”

NHA’s dashboard provides the context for his point: In most years from 2003 to 2021, no more than five federal licenses expired, and in several years, none did. In the next three years combined, 120 expired. 2025 saw 20 expirations, and 59 licenses will expire in 2026. After a relative lull with 20 to 30 expirations per year, 301 licenses will expire from 2033 through 2037.

As of June 2025, 211 of the roughly 2,300 U.S. hydropower and pumped storage hydro projects were in the federal relicensing process and 33 were in the license surrender process. | Oak Ridge National Laboratory

“We’ve got, I believe, 16,000 or 17,000 MW that are up for relicensing in the next decade, and it often takes a decade or longer to relicense these facilities,” Woolf said.

“So I do think that, frankly, this administration, the remaining three years are going to be decisive, because these facilities are going to have to make a decision now on whether they want to go through the lengthy and expensive relicensing process, or whether they want to just run their facility until their existing license ends, and then turn off the powerhouse.”

Individual dams may be controversial, but as a whole, the hydro sector enjoys bipartisan support, Woolf said.

Hydropower is one of the Trump administration’s preferred technologies as it pursues a “Golden Era of American Energy Dominance”; the One Big Beautiful Bill Act preserved enhanced tax credits for repowering existing hydro facilities even as it pinched the other major renewables, wind and solar.

But what the hydro industry still is waiting for, Woolf said, is streamlined permitting. Not knowing how long licensing will take or how the costs will change over that period is a barrier to investment.

“So we are working with this administration, both legislatively and regulatorily, to try to streamline the regulations — not cut out state agencies or others, but just try to create some process discipline, so that if everyone’s going to need to do their own NEPA review, how about you do the NEPA reviews all at once, instead of four different times in series?”

The tax credits and greater clarity on licensing or relicensing would help revitalize the industry, Woolf said, but there are other speed bumps.

There is not, for example, much of a domestic manufacturing base for hydropower equipment — few facilities have been built in recent decades, and those that exist tend to last for decades, so the demand does not exist to support a supply chain. Imported gear could face supply chain constraints or tariff costs.

There also is the unknown impact of climate change on the precipitation that conventional hydro relies on.

The Energy Information Administration reports wind and solar generation increasing in 19 of the past 20 years as installed capacity increases but shows hydro up and down from one year to the next, often significantly, despite minimal changes in installed capacity.

The U.S. hydropower fleet is mapped as it existed in 2024. | Oak Ridge National Laboratory

The 242 TWh net generation of the U.S. hydro fleet in 2024 was the least in 20 years.

But infrastructure can be adjusted to match changing precipitation patters, Woolf said: “As we’re adapting to climate change, we may need more reservoirs, more dams, and then hydropower is a great way to offset the costs of those facilities.”

A hydro sector snapshot drawn from the 2025 Market Update:

    • There were 78 non-powered dams, 23 conduits and eight new stream-reach development projects in various stages of the development pipeline in 2024, with a combined capacity of 1.12 GW.
    • Seventy PSH projects were in the development pipeline in 2024, with a combined storage power capacity of 60.6 GW; additions of 2.5 GW to existing facilities were in the planning or construction stages.
    • As of June 9, 2025, 211 conventional hydropower and PSH projects were in the relicensing process and 33 conventional projects were in the license surrender process.
    • Economic infeasibility or restoration of aquatic ecosystems are the most often cited reasons for surrendering a license​.

Woolf is excited about the prospects for PSH.

He said there is the desire to get things built fast, which points to battery storage rather than PSH, which is a conundrum for the hydro industry to overcome. But he also sees a national shift in thinking that favors long-duration assets such as hydropower.

A significant percentage of those 70 PSH proposals in the FERC pipeline will never reach construction, Woolf said, for the same reasons many proposals for other generation technologies will die in the interconnection queue.

“So I’m not suggesting we’re going to get 60 gigawatts built, but we haven’t built any for 25 years in this country,” he said. “But something seems to have changed. It does seem like there’s a whole lot more need for long-duration, eight-plus hours of energy storage to back up and firm up increasing variable generation on the grid. Pumped storage is really an established technology that’s really perfect for this moment.”

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Coal’s Decline Slows Amid Demand Growth in 2026, Trump’s Support

Don’t call it a comeback.

After a long decline in the U.S., coal-fired generation is enjoying strong policy support in the second Trump administration.

It has seen an uptick in output amid rising power demand and higher natural gas prices. And planned retirements of aging facilities are being delayed in some cases to preserve generation capacity.

But no large coal-burning plant has been built in the U.S. in more than a decade, and most objective observers do not expect any future construction — natural gas plants are more economical and less likely to face policy friction during a future Democratic presidency.

DTE Energy’s coal-fired Trenton Channel Power Plant in Michigan is shown before demolition in June 2024. | Shutterstock

The U.S. Energy Information Administration (EIA) in its December 2025 Short Term Energy Outlook reported that coal provided 16% of U.S. electricity in 2024. It predicted coal would total 17% in 2025, then drop back to 16% in 2026 as the total number of gigawatt hours generated through all technologies increased by 1.7%.

Brattle Group Principal Samuel Newell told RTO Insider that the business case for new coal generation does not work.

Samuel Newell, Brattle Group | Brattle Group

“If you’re going to burn fossil, natural gas-fired combined cycle generation is just — you’re not going to beat the economics with new coal, even before accounting for the really high exposure to future regulatory risk,” he said.

Existing plants are a different matter.

“Certainly, there’s a lot of discussion about existing coal and how long it makes sense for existing plants to stay online,” said Newell, who leads more than 50 electricity-focused consultants at Brattle. “And there have been many plans, projections for fairly rapid retirement of the coal fleet, but with that likely slowing down a bit with the high load growth we have now. Not new coal.”

EIA records show U.S. coal-fired generation declined in each of the four years of President Donald Trump’s first term, despite Trump declaring his predecessor’s war on coal to be over. In his second term, Trump has called for construction of new coal plants, including as co-located power for large loads, but so far, he has had a bigger impact by supporting existing coal facilities.

Trump laid the groundwork for this in April 2025 with an executive order “Reinvigorating America’s Beautiful Clean Coal Industry,” and Energy Secretary Chris Wright has reaffirmed the vision repeatedly since then.

In late May, eight days short of the planned retirement of Consumers Energy’s 1,560-MW J.H. Campbell coal plant in Michigan, Wright issued an emergency directive under the seldom-used Section 202(c) of the Federal Power Act to keep it operating, saying it was needed to avoid capacity shortfalls in the Midwest. He subsequently renewed that order twice.

In September, Wright said the Department of Energy is working with utilities around the country to avert other retirements, although he conceded that planned retirements of coal plants that are smaller, older or inefficient are likely to go forward. (See Wright: DOE Working to Stop More Coal Plants from Retiring.)

On Dec. 16, Wright issued a 202(c) order blocking the imminent retirement of TransAlta Centralia’s 730-MW coal-fired generator in Washington, again citing resource adequacy.

Some plant operators are pushing back retirements without DOE telling them to do so. Count on Coal cheered the trend in an August post, saying more than 40 retirements had been averted in the past three years.

However, coal-fired generation comes with considerations beyond dollars and watts, such as its impact on the climate of the planet and the health of people who live near such facilities.

Alexander Heil, a senior economist with The Conference Board whose work centers on renewables and the energy transition, cited this impact in arguing against coal.

Alexander Heil, The Conference Board | The Conference Board

“There’s no such thing as clean coal … that’s a total misnomer,” he told RTO Insider. “I mean, there are 9 million people worldwide, I believe, that die every year from air pollution, particulate matter and such. That’s not priced … there’s tons of social costs, all kinds of externalities with coal.”

He added: “I don’t really think people are seriously going to be considering coal as an alternative here in the U.S.”

Environmental advocates have blasted the J.H. Campbell and Centralia orders, saying they are costly, dirty and unnecessary, as well as a liability, given their age and condition.

“Actions by the Trump administration to force jalopy coal plants to continue burning coal are an unprecedented power grab that cost communities in their wallets and their health,” Earthjustice said.

But coal still has its fans.

America’s Power, a trade organization advocating for coal-fired generation, says coal is “critical to maintaining affordable electricity prices, and a reliable and resilient electricity grid.” The organization notes the U.S. has the largest coal reserves in the world — enough for 440 years at current production and consumption levels.

America’s Power recently commissioned a study that concluded the cost of replacing U.S. coal with various configurations of renewables and other generation would run $3 billion to $54 billion a year, plus unquantified loss of reliability attributes.

“Fortunately for consumers, utilities in 19 states have reversed decisions to retire coal plants, but more than 50,000 megawatts of coal generation are still scheduled to retire over the next five years,” CEO Michelle Bloodworth said as she announced the report Dec. 10. “This amount of coal generation could power at least 50 hyperscale data centers, which are in desperate need of power. The new study shows that it would be a big economic mistake to allow these coal retirements to continue.”

But the other side offers cost estimates that go in the opposite direction.

The Environmental Defense Fund said a study it and other advocates commissioned showed the federal stop-retirement orders could cost ratepayers $3 billion to $6 billion a year. (See New Report: Consumers Could Pay $3B More Annually if DOE Stay-open Orders Persist.)

EIA statistics quantify coal’s decline:

    • U.S. coal production has come nearly full circle in the past 75 years, rising from 481 million short tons in 1949 to 1.17 billion in 2008 and dropping to 513 million in 2024.
    • From 2015 through 2024, U.S. coal-fired generation dropped from 1,352 TWh to 652 TWh per year, with every year but one lower than the year before.
    • Natural gas generation increased 40% from 2015 through 2024 and surpassed coal as the leading U.S. generation technology in 2016. (Solar generation by comparison jumped 678% over the same period but still provided only 47% as much electricity as coal in 2024.)
    • The number of U.S. coal-fired plants dropped from 491 in 2014 to 219 in 2024.
    • From 2015 through 2024, the time-adjusted capacity of the U.S. coal fleet dropped from 286 GW to 176 GW, and its capacity factor fell from 54.3% to 42.6%.
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Nuclear Power Retains Great Potential in 2026

Commercial nuclear energy begins 2026 with strong momentum toward future expansion in the United States — “future” being the key word.

Restarts and uprates of existing nuclear plants notwithstanding, it will be years before new-build capacity comes online and possibly a decade or more before a significant amount of new gigawatts is added to the grid.

But 2025 was marked by a continual stream of announcements of technological advances and new offtake agreements for the power to be produced by future reactors employing those new technologies.

President Donald Trump jumped in with both feet as well, ordering regulatory streamlining to get new reactors built faster and setting aspirational goals for a nuclear generation buildout the likes of which the world has never seen.

The limited amount of nuclear construction attempted in the U.S. over the past three decades has been a train wreck of delays and cost overruns, but that has been due in no small measure to how few civilian reactors were being built in this country.

The expectation and hope now is that enough new reactors will be built that economies of scale and standardization can develop, bringing the levelized cost of nuclear power down to a point where it is a viable option for helping meet the expected surge in demand for electricity.

And there is even some hope of harnessing a unicorn that has eluded so many scientists and engineers for so long: commercially viable fusion power.

But much progress still needs to be made, particularly with the first wave of small modular reactors (SMRs) that are not merely next-generation versions of the large light-water reactors that make up the present-day U.S. fleet.

The manufacturing team surrounds a toroidal magnet in the testing chamber at Commonwealth Fusion Systems, a leading company in the chase to develop commercially viable nuclear fusion power. | Commonwealth Fusion Systems

“2026 is too early for things to fully come to fruition,” said utility consultant Yavuz Arik of energytools. “I mean, we have still a long way to go to deployment of some of the new SMR technologies.”

But Arik said progress will be steady and significant in 2026.

“I think President Trump has set a lot of interesting things, great movements, in place. The regulatory oversight part has been expedited now. In my opinion, that doesn’t mean that we’re foregoing safety.”

He agrees with the urgency Trump has attached to new nuclear.

“Right now, we have a national priority that we need power and we need clean power. We can go dig for more coal and gas, but we need to get ahead of the curve, and we’re running behind both the Chinese and the Russians in many ways.”

Exhibit A in any discussion of slow and expensive nuclear construction is the expansion of Plant Vogtle in Georgia, but what often is overshadowed by the stunning price tag is the fact the project was in some ways a first of a kind, which almost always is more complicated and/or expensive than follow-up efforts.

Brattle Group principal Samuel Newell said the potential exists for the U.S. to move forward from Vogtle at lower cost and higher speed with subsequent projects using the same Westinghouse AP1000 reactor, eventually reaching Nth of a kind speed and economy.

Samuel Newell | Brattle Group

“You can build on what we learned from Vogtle with an AP1000,” he said. “That has basically a complete design that now would be done before starting construction, which was one of the problems with Vogtle. We know how those plants work; there’s very little risk that it wouldn’t operate. … So we’re a little further along with that.”

Next-generation SMRs present a different set of issues. Designs such as the GE Vernova Hitachi BWRX-300 — the first SMR being deployed in North America — are smaller, more advanced versions of large-scale boiling water reactors. This could reduce the number of “first of a kind” factors.

But other SMR designs are starting with more unknowns and greater risks.

“They have even less developed supply chains, and really less developed supply chains for fuel,” Newell said, but added that he’s optimistic some of the dozens of SMR designs being pursued will reach widespread adoption.

“I hope this country pursues several of them and learns if some of them eventually make the most sense,” said Newell, who leads more than 50 electricity-focused consultants at Brattle. “But even if we do, Nth of a kind would still be the 2040s before we have them at any really substantial scale.”

Alexander Heil, a senior economist with The Conference Board, said there is some urgency to the effort: The existing fleet is decades old. The wave of retirements of functional but not economic reactors has halted, and the Nuclear Regulatory Commission signed off repeatedly in 2025 on extensions of operating licenses, but nothing lasts forever.

Alexander Heil | The Conference Board

“On average they’re 40 years old,” Heil said. “You can probably stretch into 60 in terms of permit and design life. But that also means we do the math on this stuff, that in the next generation, without any serious additions, the U.S. is going to be out of the nuclear business. What currently still makes up 20% of the grid is going to be rapidly declining.”

Heil believes in the statistical safety of nuclear power, even having lived through a three-month stay-at-home order after the Chernobyl disaster. What concerns him more is the prospect of hundreds of new nuclear waste dumps around a nation that lacks a central repository for material that will remain dangerous for millennia to come.

Heil also is skeptical that nuclear generation will reach a point of speedy and economical construction and achieve a true renaissance.

“I just don’t see, in practical terms, how this is really going to happen at the scale that we would want this to happen if it’s supposed to be replacing what’s currently on the grid,” he said.

The “modular” in “small modular reactor” is the reason why many people are pinning such high expectations on SMRs: If they can be constructed on-site in serial fashion, or even factory-built and shipped to the site in containers, they should be able to achieve great economy of scale.

That does not address other potential stumbling blocks facing SMRs, notably fuel supply, but it should help reduce the cost and increase the speed of nuclear buildout.

But which SMRs?

The third edition of the Nuclear Energy Agency’s SMR Dashboard in July analyzed 74 SMR designs; 27 of the companies behind them are headquartered in the U.S. — more than in the next four countries combined.

Arik flagged X-energy’s Xe-100 design as one to watch in the crowded landscape. Along with electricity, it can produce industrial heat, and it has a high burn-up fuel cycle with less waste generated than earlier technologies.

“It’s probably going to go maybe 700 Celsius,” he said. “When you go that high, you can do a lot of industrial use heat as heat, and that provides a big advantage, too, because you’re not converting heat to electricity and then using electricity, you’re using heat as heat. And for X-energy’s design, it’s an 80-MW electric but 200-MW heat for each reactor.”

X-energy in November announced the start of above-ground construction of the nation’s first advanced nuclear fuel fabrication facility. The company is pursuing construction of a four-reactor complex that will provide electricity and industrial steam to a Dow plant in Texas and up to a dozen reactors in Washington state through an agreement with Amazon, an investor in X-energy.

Arik also is watching TerraPower. At 345 MW, its Natrium reactor is too big to meet the classic definition of an SMR — 300 MW or less per unit.

It instead is a small advanced reactor. It is sodium-cooled, which Arik noted has been proved to work, and it doubles as energy storage: The molten salt can provide gigawatt-scale backup to grids with a high percentage of intermittent renewable generation.

Advanced nuclear technology company Oklo holds a groundbreaking ceremony for its first Aurora powerhouse at Idaho National Laboratory in September 2025. | Oklo

In March 2024, TerraPower was the first developer to submit a construction permit application for a commercial advanced reactor to the NRC. Later that year, it began site work for a Natrium demonstration project in Wyoming.

NRC in December 2025 completed its safety review, concluding there were no safety concerns that would preclude issuance of the construction permit. Further deliberations and review are needed, but NRC is trying to expedite such processes.

Arik expects it to come together.

“Now, there have been trials when you try to do [sodium cooling] bigger and bigger, then you get into different problems,” he said. “But TerraPower is trying to do it at this right size, this 345 MW, which I think they’re going to succeed at.”

Then comes the important part, not just for TerraPower and X-energy but the nuclear industry as a whole: Getting the first of a kind built, fine-tuning it and moving toward Nth of a kind.

“Once we get to mass production, we’re going to be able to turn out things much, much faster, and the U.S. is great at that,” Arik said. “So, I’m confident that things are going to get really faster, like we’re going to wrap this up within three years, once that design is set in stone.”

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Geothermal Picks up in the West but Hurdles Remain, WGA Panelists Say

PHOENIX, Ariz. — There is growing excitement about geothermal energy in the Western U.S., with billions of dollars invested in the industry, but panelists at a Western Governors’ Association workshop said supply chain issues and permitting complexity remain significant challenges.

Michael O’Connor, director of the Mountain West Geothermal Consortium, said during the Dec. 18 workshop that the U.S. leads the world in geothermal power with 4 GW of capacity and enjoys support from the Trump administration.

There has been about $2 billion in investment in the industry over the past few years. Fervo Energy announced Dec. 10 it has raised $462 million toward geothermal development, and other developers are expanding operations, according to O’Connor.

Despite this momentum, commercial lenders remain cautious because of project risks and the difficulty developers face in proving their models are accurate, making it challenging to scale the industry.

“There are some places where we can really see the West leading,” O’Connor said. “Getting to scale is going to require several different projects in several different environments. We need to get over that risk curve … in a lot of different places, and the West has all of that geological variability that you need to demonstrate it.”

Another key to ensuring geothermal success involves knowledge-sharing across state lines, O’Connor said.

“Each of these states should not have to learn how to permit this technology separately,” he said. “This is something that a lot of regional collaboration can be helpful for.”

Developers are testing several types of geothermal technology. The most mature approach is called a hydrothermal system and accounts for roughly 16 GW worldwide. The approach includes looking for naturally occurring conditions that allow hot fluids from underground to spin turbines, O’Connor said.

One of the most commercially viable approaches is called an enhanced geothermal system (EGS). The approach includes leveraging hydraulic fracking between wells in reservoirs to extract heat, O’Connor explained.

Fervo operates an EGS called Project Red in Nevada. One of the company’s main concerns is finding geologic conditions for its systems. Another is transmission availability, according to Marc Reyes, director of interconnection and transmission at Fervo.

“That is a key concern,” Reyes said. “As we all know, the grid is not built to have a lot of excess capacity. Ultimately, cost-causation drives the rates that we all see and pay in our electric bills and by and large, the grid is not built to accommodate very large projects. So that is one of the factors that comes into play … not just identifying perhaps incrementally available capacity on the transmission grid, but where the transmission grid might be suitable for expansion.”

Tim Kowalchik, research director at the Utah Office of Energy Development, said geothermal is “maybe the ideal co-location resource.”

“At its heart, you’re getting heat from the ground, maybe digging some holes, putting pipes in the ground and circulating a fluid,” Kowalchik said. “That really basic system is the same thing that can do district heating; it is the same thing that can give you process heat. That is not true of other generating technologies. There is a larger lift to being able to do sort of multi-use cascades.”

While there are a lot of “exciting” initiatives in the geothermal space, “none of that establishes you a supply chain,” Kowalchik said.

No single company or laboratory can reduce costs enough for utilities to choose geothermal as the least-cost option, he added.

“That takes building at scale, multiple regions to multiple ownership structures … to who is your offtake is going to be incredibly important,” Kowalchik said. “We need all of that to get fleshed out to make a healthy ecosystem for geothermal, and that takes building at scale. And I do not know if the industry has the scale capability for enhanced geothermal.”

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DOE Orders Two Indiana Coal Plants to Stay Open Through Winter

U.S. Secretary of Energy Chris Wright issued more emergency orders under Section 202 (c) of the Federal Power Act to keep a pair of Indiana coal plants, F.B. Culley and R.M. Schahfer, running past their previously scheduled retirement at year’s end.

CenterPoint Energy owns the F.B. Culley generating station in Warrick County, Ind., which is made up of two coal-fired units — the 103.7-MW Unit 2 and the 265.2-MW Unit 3, said the order issued Dec. 23. Unit 2 was poised to retire in December 2025, and the order keeps it open until March 23, 2026.

Northern Indiana Public Service Co. (NIPSCO) owns the Schahfer plant, which is made up of two gas-fired units and two coal-fired units at 423.5 MW apiece, the latter of which were going to retire in December. The order keeps the plant open at least until March 23, 2026.

DOE has issued multiple successive orders to keep the Campbell plant in Michigan and the Eddystone plant in Pennsylvania running since this summer. (See State AGs, Enviros Argue Campbell Plant Orders Exceed DOE’s Authority.)

“The Trump administration remains committed to swiftly deploying all available tools and authorities to safeguard the reliability, affordability and security of the nation’s energy system,” Wright said in a statement. “Keeping these coal plants online has the potential to save lives and is just common sense. Americans deserve reliable power regardless of whether the wind is blowing or the sun is shining during extreme winter conditions.”

Both orders cite declining reserve margins in MISO as the reason for keeping the power plants running past their intended retirement dates. The most recent Organization of MISO States and MISO survey of resource adequacy shows a risk of falling short of planned reserve margins later this decade. (See MISO, OMS Report Stronger Possibility for Spare Capacity in Annual RA Survey.)

The orders also note that MISO is trying to address the situation, especially with its Expedited Resource Adequacy Study (ERAS) proposal, which FERC approved this summer. (See FERC Approves MISO Interconnection Queue Fast Lane.)

“The ERAS process should help expedite the construction of needed new capacity,” DOE said in the order. “However, resources studied under the ERAS will have commercial operation dates that are at least three years away and are provided an additional three-year grace period to commence commercial operations.”

Earthjustice called the latest two 202 (c) orders a “power grab to override the decisions made in the interest of customers by power companies, grid operators and state utility regulators.”

“The plants at issue here were marked for retirement because coal is expensive and unreliable,” Earthjustice senior attorney Sameer Doshi said in a statement. “These aging power plants emit deadly air pollution, contaminate water with toxic metals, harm our climate and increasingly break down when we need them most — and the Trump administration is now asking ratepayers to pay more to keep burning coal. What’s more, the Federal Power Act should be applied based on its plain text. An event carefully planned for years is not an ‘emergency.’”

Citizens Action Coalition of Indiana Program Director Ben Inskeep said keeping the two coal plants running would add to affordability worries for the state’s ratepayers.

“The federal government’s order to force extremely expensive and unreliable coal units to stay open will result in higher bills for Hoosiers who are already reeling from record-high rate increases in 2025,” Inskeep said in a statement. “We can’t afford this costly and unfounded federal overreach.”

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Natural Gas Generation in Demand, and Priced Accordingly

With support from the Trump administration and demand from data centers, 2025 and now 2026 are high times for the U.S. natural gas sector.

But the picture is not uniformly rosy: Large gas turbines are hard to come by and increasingly expensive, gas transmission pipelines are constrained in some regions, and rising LNG exports further weld the U.S. market to global price volatility.

Natural gas accounted for 43.4% of U.S. utility-scale generation in 2024, more than nuclear (18%) and renewables (17%) combined, according to the U.S. Energy Information Administration. Net generation from natural gas was 3.5% higher in 2024 than 2023, while renewables jumped 12.8% and nuclear held steady.

Renewable energy, particularly solar, is likely to carry this momentum well into President Donald Trump’s second term, despite his efforts to boost fossil fuels, but a large pipeline of natural gas projects awaits.

GE Vernova, which claims the title of world’s largest gas turbine manufacturer and supplier, said in early December it would end 2025 with a backlog of 80 GW of orders and manufacturing slot reservations — and need until the end of 2028 to fulfill it. The company has been raising its prices as well — CEO Scott Strazik said in October that a new combined-cycle gas plant now runs in the range of $2,500/kW of capacity.

Two large competitors, Siemens Energy and Mitsubishi Heavy Industries, report similarly strong order books.

“We continue to see high demand for gas turbines particularly in the U.S., where new electricity demand from the data center buildout and other factors are driving capital expenditures at our utility customers,” Mitsubishi CFO Hiroshi Nishio said in November.

Siemens Energy said in November it closed its 2025 fiscal year with a $162 billion backlog and with a 43% increase in transactions for its gas services division, which sold 194 gas turbines.

Natural gas-fired generation has had its ups and downs. It replaced coal as the dominant U.S. power generation fuel when advances in hydrofracking techniques made the nation the world’s leading natural gas producer.

Federal priorities quickly swung toward renewables under President Joe Biden, then swing back even more suddenly under President Donald Trump.

Natural gas-fired generation capacity will grow, Brattle Group principal Samuel Newell told RTO Insider. But that does not necessarily lock the U.S. into decades of use.

Samuel Newell | Brattle Group

“I think the next several years, the demand growth is such that the combination of using the existing gas-fired fleet more and new capacity, we’re going to be burning a lot more gas in the next several years,” he said. “But in the long run, if we go in a direction that does take climate change seriously, you’d have to increase non-emitting generation a lot, some combination of renewables and nuclear. [But] the gas-fired is still helpful to have there for reliability reasons.”

The larger problem is that load forecasts are increasing at a rate that outstrips the supply chain’s ability to produce new gas-fired generation, said Newell, who leads more than 50 electricity-focused consultants at Brattle.

“I think we’re in a position where it would really help to have everything,” he said, which is why he expects wind, solar and storage development to continue despite the policy shifts against wind and solar.

The political shifts are not the only influence on energy-sector strategies, but they can be hard to overlook.

Strazik said in December 2024 that GE Vernova had secured 9 GW of turbine manufacturing reservations just in the month after Election Day.

NextEra Energy in February 2023 boasted it was the word’s largest generator of renewable energy from the wind and sun. In January 2025, it emphasized that it had the nation’s largest natural gas fleet and recently had struck a framework agreement with GE Vernova to pair new gas generation with renewables and storage.

NextEra’s December 2025 investor presentation contains more than 200 references to “gas” and boasts of being the quintessential all-forms-of-energy company: Gas-fired generation, nuclear, electric transmission, gas pipelines, storage and renewables, in that order. The December 2023 investor presentation contains only 26 references to “gas,” and 16 of those were buried in the fine-print disclaimers at the end.

National Grid’s Northport Power Plant is shown in October 2024. It is one of the aging gas-fired power plants that help keep the lights on in New York. | © RTO Insider 

So what becomes of all this gas generation demand if the major manufacturers cannot quickly meet it?

In some cases, smaller-scale generation is a solution.

Caterpillar, Cummins, Generac, Rolls Royce, Wartsila and others all are reporting booming demand for their products as standby or prime power for data centers.

GE Vernova does not operate in this space — its offerings start at around 35 MW.

The company says its 35-MW LM2500 aeroderivative gas turbine will consume about 60% more fuel and emit 60% more carbon dioxide per megawatt hour generated than its 7HA.03 heavy duty combined-cycle gas turbine configured in a 2×1 block, while its 90-MW 7E simple-cycle gas turbine’s consumption and emissions are roughly 90% higher.

But a new 7HA.03 is taking about 24 months to reach commercial operation, compared with about six months for the 7E and about six weeks for the LM2500.

Strazik said in December 2025 that GE Vernova is not losing deals to competitors pitching small generation.

However, he said, there are projects that initially will rely on someone else’s reciprocating engine or other small generation as a bridge solution to eventual installation of his company’s heavy-duty turbines.

“But I don’t really cry in my beer over that because it’s enabling the heavy-duty to get done later,” Strazik said.

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Markets+ Stakeholders Approve Baseline Protocols

SPP Markets+ stakeholders have unanimously approved the first version of the day-ahead market’s protocols, providing a framework for market design, operations and settlements as its future participants build its systems and processes.

The grid operator said the protocols will provide additional guidance on how market rules are applied by translating policy requirements into operational procedures as stakeholders construct and implement Markets+ in its second phase.

“A big milestone for this group to be able to get that approved,” Arizona Public Service’s Kent Walter said during a Dec. 18 virtual meeting of the Markets+ Participant Executive Committee (MPEC). The committee’s vice chair, Walter led the meeting in Chair Laura Trolese’s absence.

MPEC and its working groups and task forces are well into the $150 million implementation effort to add a bundle of services that will centralize day-ahead and real-time unit commitment and dispatch. Markets+ offers Western entities an alternative to CAISO’s Extended Day-Ahead Market as the two grid operators develop regional markets where none existed before.

“What we’re contemplating here is a huge improvement over the status quo, but I’m hopeful that someday, we’ll get to the more optimal use of the transmission system,” Western Power Trading Forum Executive Director Scott Miller said. “I appreciate what SPP is doing. We believe that this is going to go relatively smoothly. … But for a lot of people, this is one of those areas where it’s like, ‘We’re going to watch to see how this operates.’”

Two working groups brought the draft protocols forward. The Markets+ Resource Advocacy Task Force incorporated four outstanding parking lot items into the protocols, including adjustments to the appropriate must-offer calculation for storage resources that are self-committed to charge.

The task force will spend 2026 working on two more parking lot items and addressing any new developments that emerge from the Western Power Pool’s Western Resource Adequacy Program. (See WRAP Wins Commitments from 16 Entities.)

The Markets+ Design Working Group (MDWG) added market transfer, balancing authority area constraints and violation relaxation limits to the protocols. They would optimize market flows between BAs, using an e-tag framework for source and sink that defines the system limits in optimizing each interval.

The work represents an “early alignment” between the MDWG and SPP staff ahead of the broader design buildout, said Xcel Energy’s Nick Detmer.

Jim Gonzalez, SPP’s senior director of seams and Western services, said the interface portion of the protocols gets into “some of the deep nuts and bolts of the technical implementation” of the approved tariff.

“Version 1 of the protocols generally covers all the business practices of the approved tariff language from [January 2025] … where we really need that starting point to fully appreciate as we move in through this implementation effort,” he said. “A lot of the structure is correct. It’s in place. It’s really not going to change what we’re talking about as all the extra work is really fine-tuning.”

The protocols now go to the Interim Markets+ Independent Panel, composed of three SPP board members, for its consideration Jan. 6.