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December 31, 2025

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Will Batteries Remain a Clean Energy Bright Spot in 2026?

Energy storage is the great enabler of the clean energy revolution, moving electricity in time, much like transmission moves it in space. In 2026, utility-scale energy storage projects in the United States will face headwinds that could slow the pace of a technology that is fast becoming a global grid staple.

The question is whether the challenges the energy storage industry faces will outweigh the strong demand for its services. And if they do, what implications will it have for the grid?

Battery energy storage systems (BESS) provide a vital service for clean energy that is generated with a side of intermittency — solar and wind — by taking electricity generated at one time of day and storing it until it’s needed. The obvious benefits of smoothing supply and limiting wasteful curtailment are just the start.

BESS can provide stability, resilience and resource adequacy services to the grid, even when wind and solar aren’t involved, supporting baseload reliability. And at a time when interconnection queues are measured in years, integrating BESS can enable developers to build larger renewable projects than the interconnection point otherwise would allow.

These benefits provide real, measurable value. For example, a recent report found that solar and battery storage growth could reduce New England wholesale energy costs by more than two-thirds of a billion dollars a year by 2030. (See Report Shows Cost Savings from New Solar, Storage in New England.)

Emerging Stability After a Year of Uncertainty

2025 was a doozy: on-again-off-again tariffs, supply chains redirected to avoid foreign entities of concern (FEOC) restrictions, political standoffs over critical minerals, massive renewables projects suspended on a whim and U.S. battery manufacturing rushing to fill the gap. Yet despite everything, growth in the onshore manufacturing base and deployment of utility-scale BESS grew throughout the year.

Dej Knuckey

The energy storage market, which law firm Troutman Pepper Locke called “bruised but buoyant,” largely was spared in President Donald Trump’s tax bill (One Big Beautiful Bill Act, or OBBBA) because of batteries’ role in providing baseload power. “However, the battery storage industry faces significant constraints from the OBBBA, most notably, the FEOC rules. These restrictions — which vary depending on the tax credit and tax year in question — prevent entities linked to adversarial nations, particularly China, from accessing, directly or indirectly, the benefits of U.S. energy tax incentives,” its report said.

Wood Mackenzie and the American Clean Power Association attributed the year’s strength to rising demand and the need for grid reliability. “These installations deliver the flexible, reliable grid support America needs today, boosting reliability and keeping power bills in check,” said John Hensley, ACP senior vice president of markets and policy analysis.

So, what lies ahead for our versatile friends in 2026?

Trend 1: Market Solid as Global Supply Chain Concerns Fade

2026 should see a solid, but not stellar, market.

The good news: The volatility of early 2025 has settled. Early 2025 saw so much regulatory whiplash that analysts resorted to issuing high and low predictions. One thing the market hates more than new regulations is uncertainty, and the return to single-scenario forecasts shows a return to confidence.

Analysts are mixed about 2026. The most optimistic expect only a modest rise, while others expect a modest pullback. There’s no concern about demand; supply constraints and interconnection queues will dictate how the year will unfold.

The often-conservative EIA estimates that U.S. utility-scale BESS will grow from 45.6 GW at the end of 2025 to 65.6 GW at the end of 2026, more than doubling total installed capacity since the end of 2024. The 20 GW addition is only a slight increase from 2025’s 18.6 GW capacity addition, according to its December 2025 Short-Term Energy Outlook.

On the other end of predictions, Wood Mackenzie forecasts that supply chain issues in the near term will drive an 11% contraction in the U.S. utility-scale storage market in 2026, followed by an 8% decline in 2027. Despite the expected pullback in the coming year, the medium-term outlook is rosier than earlier in 2025. “Notably, the utility-scale five-year forecast has increased 15%” compared to pre-OBBBA projections.

Materials and manufacturing constraints will continue to throttle the market.

The U.S. may have some of the not-so-rare-earth materials needed to build batteries, but even when they can be mined, there’s often no way in the U.S. to refine them to battery-grade purity. It hasn’t been economically viable in the past, and building out those capabilities won’t happen overnight.

Similarly, building a battery factory requires a significant amount of time, as well as massive amounts of capital, which is flighty in a time of political intermittency. Battery manufacturing had a head start as factories already were under construction. In 2026, we’ll see several of those plants come online and others expand production, increasing the supply of cells and batteries made in the U.S. LG Energy Solution’s plant in Arizona should come online, and its Michigan plant should increase production. SK On’s Georgia plant should begin production in the second half of the year after pivoting from automotive to stationary energy storage.

Trend 2: Energy Storage Everywhere

In the past five years, BESS has begun to be decoupled from renewables. Its versatility means it’s solving problems throughout the increasingly overburdened grid. While many solar farms have BESS on site, 2026 will see an increase in the use of BESS to provide resilience, stability and reliability. A couple of examples: In Oregon, backup systems sited at substations provide resilience, while in California, a whole-town backup system with BESS and hydrogen fuel cells has been installed in Calistoga to power the town during public safety power shutoffs on high-fire risk days.

While most of the new utility-scale energy storage capacity will be in California and Texas, the need for resilience knows no borders. With the rise in extreme weather events that can knock the grid offline, there’s increased demand for grid-tied microgrids that support critical infrastructure such as hospitals.

Energy Storage and the Growth of AI

The rise in AI data centers has upended forecasts from just a few years ago and is driving creative ways to meet demand without yearslong delays. This need to move quickly in an industry slowed by regulation and the need for so many rounds of community engagement is bringing forth creative ways to slip energy projects in with AI data centers that are being fast-tracked.

One potential solution is what RMI calls “Power Couples,” which leverage batteries so AI data centers can be built out without impacting local electricity reliability and cost. RMI defines a Power Couple as the “pairing of a large electricity consumer with new-build solar, wind and battery resources sized to meet the on-site load, all located near an existing generator with an approved interconnection.”

This would mean the customer who benefits could bear the costs and take advantage of fast-track approval for connecting the new generation resources to the grid, and strict physical safeguards would ensure that the new load cannot affect grid reliability.

Trend 3: Community Resistance will Go Pro

While most other headwinds will die down in the coming year, community resistance will be an increasingly significant problem in 2026. Concern about BESS’ safety has grown following the high-profile January 2025 fire at Moss Landing, Calif., at the time the world’s largest lithium-ion battery system. It raised awareness of the potential risks of having BESS sited nearby, and armed community opposition groups around the country with a vivid example.

When they occur (which is not that often), lithium battery fires are difficult to extinguish and can produce toxic substances such as hydrogen fluoride, phosphorus pentafluoride and phosphoryl fluoride. Community groups can draw on a growing body of evidence that the risk persists beyond the initial fire, such as the recent report on toxic residue in the Elkhorn Slough wetland near Moss Landing.

Some lithium battery chemistries are safer than others; for example, lithium iron phosphate (LFP) batteries are less likely to have thermal runaway than lithium nickel manganese cobalt (NMC), the battery chemistry used at Moss Landing. For that reason, LFP will take an ever-larger share of the market — estimates put LPF at about 80% of the utility-scale market in the U.S. But once a developer is educating the public about the nuances of battery chemistries, it’s already losing the public relations battle.

NIMBY, Meet BESS

The forces that don’t want renewables to flourish (I’m looking at you, oil and gas) have taken a leaf from the misinformation campaigns used by the tobacco industry (if you haven’t seen Thank You for Smoking, it’s a must watch). So far, solar and wind farms have been their primary targets, but if they haven’t already, these “astroturf” campaigns will set their sights on BESS.

Astroturf is the tongue-in-cheek term for non-local organizations that are trying their darndest to look like grassroots efforts. Of course, some of the opposition is grassroots, but astroturf groups supercharge them, supplying ready-to-execute playbooks that savvy political insiders have tested and refined.

How to tell if they’re behind community opposition campaigns? Look for overly wholesome names (Patriotic Americans for Energy Freedom, anyone?) and search their materials for language that been used to stonewall projects throughout the country. For example, NIMBY groups protesting solar farms consistently described them as “industrial solar,” a negative term that proved effective in early anti-solar fights.

Astroturf is not the only resistance strategy. Other opposition will grow through under-funded local media, which spreads misinformation on a pay-to-play basis, and local codes or guidelines written to limit certain development.

Are they succeeding? In part. In the past year, significant projects were shelved due to community pressure, including a 650-MW project on Staten Island that was canceled. Others, like the 320-MW Seguro project in San Diego, are mired in hearings. Some of these projects are large enough to materially affect regional storage deployment, and all will cause developers to think twice about planning projects anywhere near communities.

Batteries Withstanding Market Battering

Taking all the positives and negatives together, 2026 should be a solid, though not soaring, year. Batteries will continue to be the bright spot in the clean energy landscape in the United States, and their ability to support the grid and delay costly transmission projects makes them critical.

To help the market grow, developers will need to get ahead of community resistance or focus on projects away from residential areas or rural idylls rather than risk being mired in endless permit fights. Groups like American Clean Power need to continue educating and lobbying critical audiences to ensure BESS projects aren’t unduly harmed.

And the industry needs to differentiate types of lithium-ion batteries to end-run community and fire service objections. LFP, despite its lower energy density, will continue to take an ever-larger share of the market, at least until new chemistry batteries are widely available.

Project developers and the grid their projects connect to operate in time frames well beyond any single administration. BESS projects are fortunate to have avoided the Trump administration’s crosshairs, which harmed other clean energy sectors. My hope for 2026 is that it will continue to work its magic, quietly installing reliability and avoiding controversy.

Power Play columnist Dej Knuckey is a climate and energy writer with decades of industry experience.

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Trump Scoring Victories as he Goes Tilting at Wind Turbines

As 2025 opened, there was no uncertainty surrounding Donald Trump’s opinion of the wind power industry. The question was how soon the opinion would turn to action and how damaging it would be.

The answer: “immediate and significant.”

As 2026 opens, we have a clearer view: Every onshore wind project that falls within federal purview is delayed, and the U.S. offshore wind pipeline is a shadow of its former self, reeling from a blanket stop-work order on all remaining projects in late December. (See All U.S. Offshore Wind Construction Halted.)

Onshore wind is an established sector of the U.S. energy market, unlike offshore wind, and seems better able to ride out the hostile policy changes of Trump 2.0. Land-based wind turbines for years have been the leading U.S. source of renewable energy. The pace of construction slowed in recent years, and photovoltaic solar was poised to surpass it as the leader in installed renewable capacity.

But with its higher capacity factor, wind still produces far more electricity: 451,904 GWh, compared to 219,834 GWh from utility-scale solar arrays in 2024, according to the U.S. Energy Information Administration.

This compares with 232,896 GWh from conventional hydropower, 652,156 GWh from coal combustion, 718,865 GWh from nuclear reactors and 1,869,892 GWh from natural gas combustion.

John Hensley, senior vice president of markets and policy analysis at the American Clean Power Association, said U.S. onshore wind experienced a marked regulatory slowdown in 2025. The restrictions on wind and solar projects on public land included multilayered review processes that extend to projects on private land for things such as incidental eagle take permits and U.S. Army Corps of Engineers permits. Approvals essentially halted as a result.

“To date, we have not heard of any [wind] project that’s actually received any approval to move forward,” Hensley told RTO Insider.

The slowdown for onshore wind in the early 2020s came despite the Biden administration’s support for renewables and has several underlying factors, Hensley said.

The extensive buildout from 2005 to 2020 saturated some markets; filled up some of the prime locations; and left utilities and large offtakers wanting some diversity in their generation mix.

Solar construction took off synergistically: Solar typically is strongest at midday, when onshore wind often is weakest, and interest was growing in renewables in regions with good solar irradiance but weak wind speeds, including the Southeast and Mid-Atlantic.

Importantly, the cost of solar components plummeted, Hensley said.

As a result of all this, installed capacity grew 90.5% for solar and just 8.3% for wind from the first quarter of 2023 to the third quarter of 2025, by ACP’s count.

But there was a rebound for onshore wind in 2025, which ACP expects will end with 36% more additions than in 2024.

There is more to come in 2026 and beyond, Hensley said, reiterating what ACP and other clean energy advocates have been saying for the past year: The U.S. demand for electrons is too great to sideline the fastest, least-expensive source of new generation — solar and wind — at a time when gas turbine orders are backlogged for years, no one is building coal or large conventional hydro, and new nuclear will not come online until the 2030s at best.

In their fourth-quarter wind report, ACP and Wood Mackenzie predict 46 GW of new wind installations through 2029, plus 2.5 GW of capacity additions via upgrades through 2028, thanks to a strong repowering market.

BloombergNEF, meanwhile, has reduced its 2025-2035 U.S. onshore wind projection by 46% but still expects 74 GW of new capacity in that period.

“We’re in this interesting moment in the market where, because of a lot of the electricity growth that we’re seeing and the resource adequacy concerns that a lot of these markets are showing, there’s just a voracious appetite for new power plants across the entire technology stack,” Hensley said.

The demand exists for additional onshore wind, and the industry can meet it, he added, but this is subject to external influence.

“I think it becomes a question of how long [the hostile policies] stay in place, and how much of the project pipeline is impacted,” Hensley said. “Even though wind has been growing slower than solar and storage, it is still a very large and mature industry in the U.S., with a substantial manufacturing base.”

He conceded that a large enough regulatory burden and high enough costs could slow the onshore wind industry.

Just look at offshore wind.

Whatever chance the industry had of meeting President Joe Biden’s aspirational 2030 goal of 30 GW of wind capacity in U.S. waters was gone well before Trump was elected to his second term, because of cost, logistical and other factors.

But 2025 saw a series of policy crackdowns by the Trump administration aimed at fulfilling his campaign promise to block offshore wind development. Amid this, a series of developers put their projects on hold or quit the U.S. market altogether.

NextEra Energy Resources’ Callahan Divide wind farm in Texas | NextEra Energy Resources

There were a few bright spots. In September, a federal judge threw out a stop work order the Department of the Interior slapped on Revolution Wind. In early December, a different federal judge threw out Trump’s Day 1 pause on wind power permits in a case brought by the attorneys general of New York and 17 other states.

The Alliance for Clean Energy New York joined that lawsuit as a plaintiff intervenor. Alicia Gené Artessa, director of ACE NY’s New York Offshore Wind Alliance (NYOWA), told RTO insider a week later that the ruling was a sign of hope for the offshore wind industry in its battles with Trump, providing a foothold for states and the industry to take the federal government to court over permit denials.

That conversation was a week before Interior ordered a halt to all U.S. offshore wind construction activity — five projects with 5.5 GW of combined nameplate capacity costing tens of billions of dollars, some of them are very close to completion.

The latest stop-work order is a dramatic escalation of Trump’s war on wind. As of press time, the order’s full impacts are still unclear, and the next steps by the government and industry has not been announced.

But Gené Artessa’s takeaway message on the offshore wind sector is relevant regardless of the blow-by-blow with Trump and its ultimate outcome: The industry and its partners in state government need to fix the problems that afflicted U.S. offshore wind before Trump returned to office, and they need to prepare for the next tranche of projects to follow his departure from office — particularly in a state like New York, which is counting on offshore wind to decarbonize its grid.

“That’s one thing that I think the state recognizes, we have to protect this industry,” Gené Artessa said. “So to get through the next few years of federal hostility, we need to look inward, because we had attrition before Trump took office. We had issues with our procurement process that needed to be solved. That’s what we are hyper-focused on for 2026.”

The Trump administration already has scared away investors critical to future offshore wind projects in U.S. waters. The question remains whether they will come back during the future administration of a wind-friendly president, because even the fastest project could extend beyond a single four-year presidential term.

Gené Artessa acknowledged that some developers will quit the U.S. offshore wind market and others will struggle mightily, which she said directly contradicts Trump’s stated desire to boost jobs and increase power generation. But there is the opportunity to fight back in court, she said, and the opportunity for states to improve their own processes.

“To me, it doesn’t make any sense,” she said, “but we are alive for another day, and we’re keeping the good fight going over here at NYOWA.”

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NV Energy’s Early IRP Filing Reflects Load, Resource Challenges in 2026

In mid-2023, NV Energy officials called the utility’s reliance on short-term market purchases “risky and costly” and asked state lawmakers to declare that its open position should be closed quickly.

A year later, the company set targets in its 2024 integrated resource plan to reduce its open position.

Now, at the start of 2026, NV Energy says it will take longer than previously planned to reach its open-position targets. “Open positions” refer to resource needs that are met through short-term market purchases rather than by the utility’s own resources or long-term contracts.

“We aren’t able to have the decrease come as quickly as our plans from the 2024 IRP,” said Janet Wells, vice president of resource planning. The delay is “in order to both consider the load needs as well as the resource availability in the short term.”

Wells’ comments came during a stakeholder briefing Dec. 18 about the company’s plans to file its next IRP in April 2026.

The 2026 resource plan is coming two years after NV Energy’s 2024 IRP, even though the company is only required to file a plan every three years. Nevada Assembly Bill 524, enacted in 2023, authorized NV Energy to file an IRP more often “if necessary.”

The company has faced criticism for following each IRP with a series of amendments, often including proposals for high-priced new resources. Resources proposed in amendments, sometimes with a claim of urgent need, don’t get the thorough review they would receive in a full IRP, critics say.

AB 524 also instructs utilities to include in their IRPs a scenario in which enough resources are acquired to close the open position. That won’t necessarily be the IRP’s preferred scenario. (See Bill Would Require NV Energy to Examine Market Reliance.)

Early IRP Filing

NV Energy did not respond to emails asking why it is filing its next IRP early. But Wells pointed to possible reasons during her presentation to stakeholders.

The utility’s projected load growth over the next 20 years is up roughly 25% compared to projections in the 2024 IRP, she said. At the same time, Wells said, the company is facing an array of challenges. Federal tax credits for solar and wind projects are soon expiring, and federal policy has shifted regarding solar and wind. Tariff impacts on imports remain uncertain.

Meanwhile, the Trump administration has emphasized the need for U.S. dominance in artificial intelligence.

And even as load is growing, NV Energy must still meet the state’s renewable portfolio standard of 34% in 2026, 42% from 2027-2029, and 50% in 2030.

One resource strategy NV Energy is adopting is to prioritize projects that reduce or remove the need for permitting on federal lands.

“This way we would provide the greatest likelihood of delivery in the remaining critical years where production tax credits remain possible,” Wells said.

Potential resources being evaluated include solar and storage — both paired and standalone — as well as geothermal and gas turbine projects.

Wells said there are potential projects that would use the utility’s clean transition tariff, in which a large load customer brings their own generation. Those proposals would be submitted in a separate filing around the same time as the IRP.

In response to a question about how many megawatts of new resources would be from renewables compared to fossil fuel-fired resources, Wells said the company would share more information in the next stakeholder briefing, scheduled for Jan. 14.

Open Position Concerns

Brian Turner, director at Advanced Energy United, said NV Energy’s delay in reducing its open position was “somewhat” concerning, given that “the overall market situation in the West is tightening.”

NV Energy’s decision in 2025 to withdraw from the Western Resource Adequacy Program was understandable, Turner said, but adds to the concerns.

“There’s less transparency and less understanding of what’s going to be available,” Turner said.

That makes an alternative resource adequacy program being explored by NV Energy and other entities planning to join CAISO’s Extended Day-Ahead Market all the more important, he added. (See NV Energy Filing Reveals Extensive Talks Around EDAM RA Program.)

Another issue, Turner said, is whether NV Energy’s requests for proposals are robust enough given the growing demand. AEU is calling for reform to the company’s procurement process.

Load Forecasts

Wells said the Jan. 14 stakeholder briefing would also include more details on NV Energy’s load forecast.

In a base case forecast, large loads are “mitigated” — meaning requested loads are reduced by half if a line-extension contract has been signed or by 85% if there’s no contract.

In addition to a base case, the company is analyzing two alternative scenarios. In one, growth from data centers and AI is removed. In the other, mitigations aren’t applied to anticipated large loads.

The alternative scenarios are primarily for use in policy decisions, Wells said, rather than producing realistic forecasts.

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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.”