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December 26, 2025

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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.

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PacifiCorp Contests Amazon Data Center Service Complaint

PacifiCorp filed a partial motion to dismiss a complaint Amazon Data Services submitted to Oregon regulators alleging the utility had breached agreements to provide electric service to four data centers in its service territory.

Portland-based PacifiCorp filed the motion with the Oregon Public Utility Commission on Dec. 19, along with a nearly 40-page answer to the complaint contending the utility has “at all times … negotiated in good faith with ADS and diligently worked to discharge its obligations under the parties’ agreements.”

Amazon’s complaint (UM 2410), filed Oct. 30, said the company has been working since 2021 to develop four data center campuses in PacifiCorp’s territory in Eastern Oregon. (See Amazon Files Complaint Against PacifiCorp for Lack of Data Center Power.)

Amazon contended that, for the first campus, called Specialized, PacifiCorp has been “supplying significantly less power than promised,” while the second campus, Litespeed, has received no power.

For two other campuses, called Pivot and Gray, PacifiCorp has “refused to even complete its own standard contracting process,” Amazon alleged.

The company said it had exhausted “all reasonable efforts” to work with PacifiCorp to comply with the agreements and asked the PUC to either require the utility to provide the contracted volumes of power or shift the data centers into the territory of another utility willing to supply electricity — effectively shifting utility boundaries.

PacifiCorp’s partial motion for dismissal focuses on that latter request, arguing that, contrary to Amazon’s argument, there is no basis under Oregon law for the PUC to reallocate a service territory or electric customers “without the agreement of the affected utilities.”

“There is no legal basis for the commission to remove portions of PacifiCorp’s exclusive service territory so that the territory can be served by a different utility. Such a process is prohibited by the Territory Allocation Laws, which set forth the exclusive process for allocating and reallocating service territory and do not recognize the process ADS requests,” the utility argued.

‘Intervening Events’

PacifiCorp’s broader answer drills down into the specifics of Amazon’s complaint.

The utility said that under the terms of the master electric service and facilities improvements agreement (MESA) it entered with Amazon to serve Specialized, it paid nearly $100 million for transmission system upgrades and obtained transmission service from the Bonneville Power Administration, Umatilla Electric Cooperative and PacifiCorp Transmission.

PacifiCorp said it began serving the Specialized campus on a date that was redacted from the public version of the document and since that time has “provided all power required by ADS’ current operations” at the facility.

“Contrary to ADS’ allegations in the complaint, ADS has consistently requested PacifiCorp to deliver far less power than the amounts it is entitled to under the Specialized MESA. But if ADS were to increase its load to the full amount to which ADS is contractually entitled, PacifiCorp would be prepared to serve the full amount,” the utility wrote.

Regarding Litespeed, PacifiCorp wrote that, after “extended negotiations” with the property owner, it has acquired necessary easements for the “significant upgrades” required to power the facility and has begun their construction.

The utility said it has been supplying “bridging power” to the Litespeed site since a date also redacted from the document. It noted that Litespeed’s projected in-service date — also redacted — is later than the target completion date set out in the facility’s MESA, signed in 2023, but attributed the delay to “factors outside PacifiCorp’s control.”

“ADS has contributed to the delay by failing to timely complete required steps in the project construction and energization schedule, and the current projected in-service date is driven by the construction schedule for necessary upgrades that Portland General Electric is completing at one of its substations,” PacifiCorp added.

PacifiCorp said that meeting the full contracted future demand at Specialized and providing desired redundancy would require additional system upgrades, including building a new substation and 230-kV line — the cost estimates for which were redacted. The utility said it likely would incur similar costs to serve Pivot.

PacifiCorp argued that Amazon had failed to pay all “actual costs” required to serve Specialized and Litespeed, pointing to the company’s refusal to pay “gross-up” charges that reflect the amount of income tax the utility incurred from ADS’ financial contributions to construction.

“Cost responsibility for these upgrades is not discussed in the Specialized MESA because the upgrades were necessitated by intervening events and therefore were identified after the MESA was executed. However, ADS has been aware of the need for these upgrades since 2023, and PacifiCorp understood that ADS was willing to pay for these upgrades,” the utility said.

Among those intervening events was this year’s passage of Oregon House Bill 3546, which requires that utility contracts with data centers avoid shifting network upgrade costs to other retail electricity customers.

PacifiCorp said it and ADS recognized this past summer that negotiations over a contract to cover all four sites “had become protracted” but that ADS rejected the utility’s “last, best and final” offer that would be consistent with rules under HB 3546.

“While PacifiCorp remains ready and willing to serve all four data center campuses, it cannot agree to terms for electric service to ADS that contravene Oregon law or policy or otherwise shift costs or risks to PacifiCorp’s other customers,” the utility said.

Reached for comment on PacifiCorp’s answer, Amazon spokesperson Lisa Levandowski said the company has paid more than $100 million for PacifiCorp over the past four years “to build and upgrade its electrical infrastructure” to “ensure it can deliver the power we’ve agreed on for our data centers … without passing additional infrastructure costs to its other customers.”

“Despite these investments and our compliance with all commission-approved policies, PacifiCorp has delivered only a fraction of its contractual obligations, forcing us to file with the Oregon Public Utility Commission,” Levandowski said in an email.

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MISO, Minn. Say Federal Funds for JTIQ in Play

Federal funding for MISO and SPP’s Joint Targeted Interconnection Queue (JTIQ) portfolio is still intact nearly three months after the U.S. Department of Energy said it was revoking its grant for the transmission projects.

“The federal grant for the JTIQ portfolio has not changed since the award was issued, and projects are proceeding as planned,” the Minnesota Department of Commerce said in a statement to RTO Insider.

The $464.5 million in federal funding for the $1.7 billion portfolio was among the 321 grants DOE said it was canceling in early October. (See DOE Terminates $7.56B in Energy Grants for Projects in Blue States.) The state Commerce Department led the application for federal funding with assistance from the Great Plains Institute.

When asked about the JTIQ funding status, MISO issued an identical statement to the Minnesota agency. Neither organization offered any details on the possible reconsideration of the projects by DOE, nor whether they were notified that the funding no longer was in jeopardy.

MISO said it is “not in a position to speak on the DOE’s processes.” CEO John Bear mentioned that JTIQ’s federal funding was restored at the RTO’s Board of Directors meeting Dec. 11.

DOE did not respond to RTO Insider’s request for comment on the JTIQ portfolio’s funding status.

MISO and Minnesota’s implication that the funds are not in doubt doesn’t quite square with congressional record.

Earlier in 2025, the chopping block appeared to be the most likely outcome for the $464.5 million from the department’s Grid Resilience and Innovation Partnerships (GRIP) program awarded to the JTIQ portfolio in 2023. While the department did not specifically name the portfolio in its announcement, it was on a list of projects slated for cancellation that was posted by Democrats on the House Appropriations Committee.

MISO, Minnesota and the Great Plains Institute have said they have never been formally notified that GRIP funding for the JTIQ projects is rescinded. However, regulators publicly appeared nervous about the status of the funding.

“I wish all the people who spent many thousands of hours on those projects strength in these trying times,” Wisconsin Public Service Commissioner Marcus Hawkins said at the Organization of MISO States’ annual meeting in October.

Brattle Group Praises JTIQ, Calls for More Interregional Transmission

Brattle Group Principal Johannes Pfeifenberger issued an appeal for more interregional transmission planning during the Midwestern Governors Association’s webinar on transmission benefits Dec. 15.

He praised the JTIQ portfolio in particular. By spending a couple of billion dollars, MISO and SPP “can create interconnection headroom more cheaply than in individual interconnection queues.”

“Doing something more proactive on both sides of the seams can really save some money,” he said.

Pfeifenberger said upgrade costs for generation developers under the JTIQ should be about half as expensive as the upgrades identified in MISO and SPP’s separate interconnection queues.

He also expressed hope that the 765-kV projects under MISO’s $22 billion long-range transmission portfolio eventually could be “interconnected into a macro grid.”

Overall, much remains to be done on the interregional front, Pfeifenberger said. He said RTOs’ interregional planning processes come last and that grid operators often will focus on local needs at the expense of more beneficial interregional links.

Pfeifenberger said spending on transmission has increased tenfold over the past 30 years, from $3 billion per year in the mid-1990s to $30 billion annually today. However, he said most of the investment is spent to refurbish local infrastructure.

“MISO is the exception,” Pfeifenberger said. But overall, he criticized transmission planning as “too siloed and reliability-focused.”

Pfeifenberger said the simulations RTOs use to plan transmission tend to underestimate the savings projects can deliver.

He said simulations use normal weather conditions that don’t test heat waves or cold snaps. He also said they don’t account for fuel price spikes or unusual generation or transmission outages.

Pfeifenberger said on Dec. 15, Henry Hub in the MISO footprint was trading at $5/MMBtu, up from the average $3/MMBtu, while gas in Boston was valued at $25/MMBtu. But if RTOs always experienced normal weather, outages and fuel prices, “we wouldn’t need half the grid we have.”

“Sometimes you have to spend money to save money,” he said.

MISO and SPP are considering a FERC filing to amend their joint operating agreement to be able to consider more types of benefits to justify future interregional transmission projects.

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Governors’ Workshop Focuses on Energy Demand, Collaboration

PHOENIX, Ariz. — Arizona Gov. Katie Hobbs and panelists discussed efforts to meet rising energy demand at a Western Governors’ Association workshop, with some noting opportunities and challenges navigating state-level permitting and regulation.

Hobbs delivered the keynote at the association’s two-day workshop — Energy Superabundance: Unlocking Prosperity in the West — Dec. 17. The governor said while innovation in chip manufacturing and artificial intelligence is “booming” in the U.S., more energy is needed to support those efforts.

Hobbs touted recent Arizona initiatives, including a $15.6 million investment for grid resiliency projects and an executive order to streamline energy development. She urged Western states to collaborate, saying, “The fact is that America’s energy future runs through Arizona and other Western states.

“We stand on the frontier of energy innovation and generation, and our collective power has the ability to support and promote American advancement for generations.”

In a separate panel on the relationship between energy and economic development, Jake Dubbs, lead adviser for external affairs and tribal relations at SPP, discussed increasing electricity demand and the need for regional cooperation to bring new generation online more quickly.

SPP projects “an increase of almost 35%” in electricity demand by 2030, according to Dubbs.

“The West requires so much attention, and it requires a lot of different groups coming together,” Dubbs said. “And I think that’s one thing that we are really working hard towards at SPP, making sure that all the different groups, unique perspectives, are coming together to talk.”

He said SPP’s RTO expansion and development of the day-ahead market, Markets+, are part of efforts to increase partnerships in the West and take advantage of the region’s resources. (See SPP Markets+ Cruising Through Early Development.)

Navigating state agencies remains a challenge for developers, said Ashley Bunch, manager of government relations and stakeholder engagement at BluEarth Renewables.

Some places, like Arizona, are easier to navigate because agencies are aligned and “understand what our goal is,” Bunch said. “And they really are all kind of working together.

“We sometimes see in other states that a game and fish department may not be as on board as, say, another state land entity, and it makes things … more difficult. … If the state agencies can come together and … put forth the guidelines very clearly … that would be very helpful to us. And I do think Arizona does a very good job of that.”

Long interconnection queues also pose obstacles to new generation, said Chris Pasterz, economic development director in Navajo County.

Developers and large energy users look for favorable governments “that have pathways for development,” Pasterz said. Expanding the use of private land is one part of the solution, he noted.

“That’s one thing that we’ve done in Navajo County to promote the private landowners’ utilization of their lands, their resources,” Pasterz said.

The agreements between private landowners and developers must ensure that local communities reap the benefits from new projects, he added.

Policymakers “can really help with that speed of development by finding your areas where there is a pathway for private land development,” Pasterz argued. “But also supporting those private elected officials who are negotiating those deals locally to make sure that those benefits are retained into the future for their community.”