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December 31, 2025

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EDAM Implementation to Remain CAISO’s Focus in 2026

The Extended Day-Ahead Market took center stage at CAISO in 2025 as the ISO tabled other long-term initiatives to ensure the market’s timely launch in May 2026 with PacifiCorp as its first participant.

And EDAM preparations will continue to be the primary focus for the ISO and its stakeholders heading into the new year.

According to a December report from CAISO CEO Elliot Mainzer, 2025 saw thousands of stakeholders from California and throughout the West tune in to EDAM implementation workshops that enlightened and sometimes perplexed stakeholders, with the ISO trying to quickly address new critical problems to keep EDAM’s schedule intact.

The year started with a bang: In February, Powerex — which has committed to joining SPP’s competing day-ahead market Markets+ — published a paper contending that EDAM contained a “design flaw” that could result in $1 billion in unjustifiable charges for non-CAISO participants.

The paper said EDAM’s treatment of firm transmission rights and congestion would leave the market’s non-CAISO participants exposed to charges for constraints occurring outside their systems while not providing them adequate ability to recover or hedge against those costs. (See Powerex Paper Sparks Dispute over EDAM ‘Design Flaw’.)

About a month later, CAISO began an “expedited” initiative to decide how to allocate congestion revenues when a transmission constraint in one EDAM balancing authority area causes congestion in a neighboring BAA. (See Fast-paced Effort will Address EDAM Congestion Revenue Issue.)

In late summer, FERC approved CAISO’s new EDAM congestion revenue allocation design. The approved design is a short-term solution, and the ISO said it would propose a long-term design within the next two years. (See CAISO’s EDAM Scores Simultaneous Wins at FERC.)

Top EDAM Challenges

RTO Insider asked CAISO and a few of its stakeholders their views on EDAM’s top challenges in 2025.

CAISO Vice President of External Affairs Stacey Crowley said the ISO worked with vendors to deliver timely functionality for market simulation, supported participating entities in developing tariffs through the FERC process, and established a transitional congestion revenue allocation design informed by stakeholder input — all critical steps to enable EDAM launch.

PacifiCorp, which will join EDAM in May 2026 as the first participant, said it faced several key challenges while preparing for EDAM’s 2026 launch.

“Building and testing interconnected IT systems for PacifiCorp and CAISO required extensive coordination and design adjustments that had to be integrated into the development plans of both organizations,” PacifiCorp spokesperson Omar Granados told RTO Insider. “Additionally, managing communication and testing across numerous transmission customers and 14 neighboring utilities added significant logistical challenges.”

EDAM Priorities Going into 2026

The coming months in 2026 will see heightened activities around EDAM implementation, with stakeholders anticipating several challenges to ensure the market opens as planned in May.

PacifiCorp remains confident in the EDAM go-live timeline, but it must resolve issues that have never been encountered before, Granados said.

For example, starting in February, PacifiCorp and CAISO will begin parallel operations for their respective market systems, staff and support processes. While the ongoing market simulations have suggested that the utility is ready for EDAM, parallel testing will “likely reveal adjustments needed before launch,” the spokesperson said.

To address this concern, PacifiCorp is working closely with software partners and has established an internal issue-resolution team to quickly identify and resolve problems, Granados said. After starting in the market, further refinements and process optimizations are expected, he said.

CAISO’s Department of Market Monitoring (DMM) will be “closely watching and reporting on” critical areas as EDAM is implemented, DMM Executive Director Eric Hildebrandt said. One area is market efficiency and performance, such as pricing and volumes of self-scheduling versus supply/demand that is bid into and clears EDAM. DMM will watch also how EDAM affects the broader real-time Western Energy Imbalance Market.

DMM will monitor congestion withing EDAM, specifically how much transmission is available in the day-ahead market for transfers between BAAs; the amount of “unscheduled flows” and congestion revenues created by schedules in one BAA on other BAAs; and how these congestion costs and revenues are allocated among BAAs, Hildebrandt said.

Two other focuses for EDAM: the day-ahead resource sufficiency requirement and evaluation, and the day-ahead imbalance reserve product, including the impact it has on EDAM prices, he said.

As for CAISO, Crowley said the ISO will work with vendors to test systems and procedures, and to ensure market participants have the training and practices needed to fully engage at launch.

Working Across Agency Lines

RTO Insider asked CAISO how it plans to work with the California Energy Commission and the California Public Utilities Commission as EDAM launches.

Crowley noted that EDAM is regulated under FERC, but “we have worked collaboratively with California agencies such as the CEC and CPUC — as well as regulators across the West — to ensure they are informed and able to provide input into the market design.”

“There is an important role for state regulators through the [Western Energy Markets] Body of State Regulators and the public stakeholder process,” she said. “While state agencies do not have direct oversight of EDAM, they have also been actively engaged in the development of legislation like Assembly Bill 825, which will establish an independent governance board, committee of state regulators and other public processes similar to what occurs at … CAISO now.”

DMM will publish quarterly, annual and other special reports on the performance of CAISO markets, with state regulators and policy makers being a primary audience for those documents and the recommendations they contain.

“We do outreach to key regulatory agencies in all the EDAM/WEIM states in order to highlight our reports and recommendations, answer questions and get any input state agencies have on what types of analysis and reporting they would find most useful,” Hildebrandt said.

While DMM’s recommendations often play a role in shaping market design, “we do not have any role in the actual implementation,” Hildebrandt added. Instead, the Monitor “will be focusing on quickly identifying and helping address any problems or unexpected issues that arise” with EDAM implementation, he said.

Batteries Provide Sneaky Reliability, Kinks to Work Out

While EDAM implementation demanded much of the ISO’s and stakeholders’ attention in 2025, CAISO weathered yet another year without needing to issue a flex alert or call for rolling blackouts. CAISO leaders repeated highlighted the addition of massive volumes of battery storage resources as a critical contributor to grid reliability.

By April 2025, more than 12,000 MW of battery storage capacity was online in the ISO — up from about 500 MW in 2020. An additional 15,000 MW of storage resources are expected by 2028, accounting for the majority of the 20,000 MW of new resources expected in that time.

The increase in batteries has kept CAISO focused on technical issues throughout the year, such as outage management enhancements, battery nonlinearity guidance and state of charge clarifications. The ISO also started an initiative to improve the visibility of distributed batteries, especially when they are needed for resource adequacy purposes.

CAISO will continue to lean on batteries in the coming year, specifically in the ISO’s resource adequacy program and qualifying capacity (QC) process. Stakeholders asked CAISO to provide more clarity on how battery durations will be counted in CAISO’s default QC counting rules, asking the ISO to avoid lumping all battery capacity together, including eight-hour batteries and four-hour batteries.

CAISO’s DMM early in 2025 raised concerns about the potential gaming and inefficient bidding behavior in CAISO’s bid cost recovery (BCR) process for battery storage resources. In an August report, DMM said the current BCR design creates gaming opportunities for battery storage units, “especially through manipulation of various biddable parameters used to manage state-of-charge. (See CAISO Monitor Sees ‘Gaming’ Potential in Battery Storage Bid Cost Recovery.)

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NYISO’s 2026 to be Dominated by Reliability Concerns

At the final Management Committee meeting of 2025, NYISO CEO Rich Dewey addressed stakeholders and staff, thanking them for their cooperation and work during a full, “challenging” year.

“When we started the year, we talked a lot about our concerns we had with respect to reliability,” said Dewey, who went on to list aging generation and explosive load growth as key drivers of reliability concerns. “Some tough decisions were made through the course of the year. … I am really happy and confident where we landed thinking about the planning process.”

Dewey warned stakeholders and staff that 2026 would be just as full, if not fuller, than 2026.

“If I told you 2026 was going to be easier, you should not believe me,” he said. “We have a lot of continued work ahead of us, and so it’s going to be a challenge to address the issues that we have on our plate already.”

Chief among those challenges are the upcoming discussions on changes to the reliability planning process. Stakeholders recently approved a Comprehensive Reliability Plan that calls for structural changes to the process. (See NYISO Reliability Plan Calls for ‘New Dispatchable Generation’.) NYISO wants to move planning from a “reactive posture” to a more proactive approach accounting for a wider range of outcomes in reliability planning rather than a single expected future. The ISO also called for new dispatchable generation. This angered environmental stakeholders, who accused the ISO of endorsing fossil fuel-fired development in all but name.

Most of the specifics of how the reliability planning process would determine needs were left open to discussion. During an Operating Committee meeting Oct. 16, Ross Altman, NYISO senior manager of reliability planning, said discussions with stakeholders would need to happen in order to determine which range of forecasts would be considered actionable. (See NYISO Notes ‘Fluctuation’ of Outlooks for Grid Reliability.)

New York City Reliability Need

The third-quarter Short-Term Assessment of Reliability (STAR) found there was a reliability need in New York City. This is the second year in a row a reliability need was found for the city. (See NYISO Again Identifies Reliability Need for NYC.) The city could be 650 MW short by the summer of 2026 if the Champlain Hudson Power Express (CHPE) does not come online on time.

The STAR also found reliability needs for Long Island and the Lower Hudson Valley in 2027 and 2030, respectively, but neither are as large as New York City’s.

The findings triggered a formal process in which the ISO will seek solutions to the issue, including transmission, generation and energy efficiency, either alone or in combination. The process is sure to dominate stakeholder discussions for months in 2026.

The shortfall is driven primarily by the impending retirements of the Gowanus and Narrows gas generators in the city. These generators are being kept online by an ISO reliability designation under New York state’s peaker rule. If CHPE and Empire Wind complete on time, they would, according to the ISO, solve the deficiency.

The previous year’s reliability need was “solved” by considering certain large loads, including cryptocurrency mines and hydrogen electrolysis plants, “flexible,” meaning that they would not operate during peak hours for economic reasons. (See NYISO: Large Load Flexibility Eliminates 2034 Shortfall Concern.)

With the rapid proliferation of inflexible, “always on” data centers in the interconnection queue and this year’s reliability shortfall coming from a lack of generation, it is less likely that a similar solution will present itself to NYISO. Until CHPE and Empire Wind are completed, the ISO is in an awkward position of trying to solicit solutions for a problem that may solve itself.

Resetting the Demand Curve Reset

Late in 2025, NYISO began discussion with stakeholders about how the demand curve reset process would be reformed. It is highly likely that this will continue to dominate stakeholder meetings in 2026. The DCR sets capacity prices every four years based on the capital costs of a new generator on the market. DCRs are time and resource intensive and contentious between stakeholder sectors.

Even though both stakeholders and NYISO staff identified the DCR as a priority during the Capacity Market Structure Review project, it is likely that any changes to the process will also be controversial between stakeholder sectors.

An issue discovery report was supposed to be presented to stakeholders at the final Installed Capacity Working Group meeting of the year, but it was not on the agenda. (See NYISO Begins to Discuss Demand Curve Reset Process Changes.) It is unclear when this report will be presented.

A Possible Hudson Valley Power Authority?

Late in the year, a coalition of environmental groups, local activists, politicians and electricity consumers released the results of a feasibility study that found that the Hudson Valley Power Authority Act, which was introduced in the state legislature in 2025, could save the Central Hudson Gas & Electric system, including ratepayers, $15.2 million after its first year of passage. By Year 30, these savings would climb to $210.5 million annually, a 12.7% difference in rates and saving $2.9 billion cumulatively.

The bill would allow the state to acquire Central Hudson’s assets and convert the utility to a nonprofit utility. The purchase price would be roughly $3.5 billion.

“This is a common step in municipalization and other public ownership campaigns,” said Sandeep Vaheesan, legal director of the Open Markets Institute. “At a minimum, the purpose is to show that this is a practical choice in terms of dollars and cents.”

NewGen Strategies and Solutions, a management and consulting firm, conducted the study on behalf of the coalition. The firm said that the savings would be realized primarily by not paying profits to shareholders, issuing cheaper debt and being exempt from state and federal taxes.

“The question is, could they acquire and operate the utility at a lower cost to ratepayers?” said Scott Burnham, a partner at NewGen. “One of the critical elements of the analysis is that we did not conduct an appraisal of these assets. … We looked purely at publicly available information.”

Central Hudson has come under political fire for requesting double-digit rate hikes in 2024, followed by another rate case in 2025. In response to rising energy bills, lawmakers passed a bill that requires utilities seeking rate increases to “fully and publicly explain all capital expenditures included in the request.” The bill passed after the Public Service Commission approved a three-year rate hike package over the summer.

“There’s a lot of discontent with Central Hudson in the Mid-Hudson Valley, specifically over rates,” Vaheesan said. “There’s a widespread view that Central Hudson has been seeking and obtaining aggressive rate increases and that their service record is mediocre.”

The New York Times reported that Fortis, the owner of Central Hudson, had no interest in selling. A spokesperson for Central Hudson told the Times Union that any attempt to purchase the company would only result in a drawn-out and costly legal battle.

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MISO Vows Greater Generation Totals for Big Tech in 2026

MISO has indicated that new generation to serve data centers and other large loads will be mission critical over 2026 and said it will take pains to interconnect units.

The grid operator also will plan accordingly for fewer renewables in the footprint in the future and will embark on long-range transmission planning for its Southern load pockets.

‘Speed to Power’ + Fast Pass Gen Projects

MISO CEO John Bear said speed to power will be MISO’s theme in 2026, as it is nationally. He said MISO’s interconnection queue fast lane is working as intended to sate demand.

“The first cycle of GIAs is signing within days, not years,” Bear reported at MISO’s Dec. 11 board meeting.

MISO created a temporary queue express lane to get necessary generation online faster. Throughout 2026, MISO will welcome four more 15-project cycles into its interconnection queue express lane.

The first two cycles of projects are composed overwhelmingly of gas generation. MISO expects the 11 GW of new natural gas generation from the first two classes of its fast lane to begin coming online in 2028. (See MISO Accepts 6 GW of Mostly Gas Gen in 2nd Queue Fast Lane Class.)

Bear said MISO is working to condense timelines in the ordinary interconnection queue. He said regular queue phases are “shrinking dramatically” and can now be measured in days, not years.

“We have to be faster, and we have to be better,” Bear told stakeholders, members and board members.

MISO has vowed to ease the process to bring co-located generation and load online sooner, trying to move as fast as new large loads demand. The RTO said it may create interconnection agreements where generation is barred from injecting into the MISO system. The design work would take place over 2026. (See MISO Floats ‘Zero Injection’ Agreements to Bring Co-located Gen Online.)

MISO Senior Vice President Andre Porter | © RTO Insider LLC

MISO Senior Vice President Andre Porter said MISO today has 180 GW of installed capacity, 138 GW of that accredited. He said though MISO contains more gigawatts than it did a decade ago, its accredited capacity values have remained flat. However, he said members are making demonstrable progress on the RTO’s supply.

MISO reported that its three-year historical supply additions increased over 2025 from 4.7 GW to an estimated 6.7 GW annually. But Porter added that incremental load growth by 2030 also increased over 2025, up to 23 GW from an 18-GW estimate just months earlier.

“Members are making real progress in terms of additions they’re making. There’s significant momentum in the MISO region that’s going to allow us to rise above the noise,” Porter said, referring to the daily headlines on growing demand.

Porter said MISO has a goal to complete 25 generator interconnections per quarter over 2026 and 2027. He said MISO likely will need to sign on 8 GW of accredited capacity per year to continue to meet resource adequacy targets.

“You’re going to see much more speed within the generator interconnection queue,” Porter promised members a Dec. 10 Advisory Committee meeting. He said MISO understands that the queue “can no longer be an impediment” to generation development.

MISO’s regular generator interconnection queue contains 910 projects at 169 GW, much lower than the more than 300 GW MISO began 2025 with. Developers have withdrawn 129 GW worth of projects over 2025 since the Trump administration announced a phaseout of tax credits for renewable energy. MISO has yet to factor in the projects that queued up for the 2025 cycle. The RTO warned that the regular queue will fluctuate over the first half of 2026 as more developers remove projects and as it adds 2025 projects.

MISO, by its estimate, will field expedited transmission requests to support 13.1 GW in load growth throughout 2026. MISO approved expedited transmission projects to support 9.7 GW of large load additions in 2025.

“Since we’ve closed our [Transmission Expansion Plan] process in September, we’ve had more requests for expedited review than in all of 2025. And last year was multitudes of the year before,” MISO Executive Director of Transmission Planning Laura Rauch reported at the MISO Board of Directors’ System Planning Committee meeting Dec. 9.

Load Grows Where Data Centers Go

MISO Senior Vice President Todd Ramey said MISO members’ load forecasts show an uptick in load around 2027, when the net coincident peak could pass 130 GW.

MISO members’ combined load forecasts. MISO’s range of load forecasts predictions are represented by the shaded region. | MISO

“We’re pretty tight on surplus capacity here, so I think this shows a need to focus on getting accredited capacity online as load growth continues to pick up,” Ramey said during the RTO’s June Board Week.

MISO’s 2025/26 Planning Resource Auction showed capacity is at a premium in the footprint — at least during summer when prices soared to $666.50/MW-day. (See MISO Summer Capacity Prices Shoot to $666.50 in 2025/26 Auction.)

Fewer Future Renewables

The RTO reported that it noticed a drop in members’ plans for standalone renewable energy and increasing plans for dispatchable resources.

Rauch said MISO clocked a sizable difference between the future generation plans its members submit now versus what they submitted a few years ago. She said members foresee more thermal, dispatchable energy within 20 years. MISO has said more on-call energy will prove useful to combat load growth.

MISO has reported that since 2024, its members’ plans for new, dispatchable resources jumped from 32 GW to 50 GW by 2043. Plans for standalone renewable energy, on the other hand, dropped from 103 GW to 55 GW. MISO said it noticed the sea change from surveying its members about their plans for its 2024 Regional Resource Assessment and again in 2025 as part of the OMS-MISO Resource Adequacy Survey.

Despite the renewable slowdown, MISO expects to have about 40 GW of installed solar capacity at the end of 2028.

By 2045, MISO believes it could have anywhere from 383 GW to 454 GW of installed capacity, with a bigger natural gas generation buildout and fewer renewable energy resources. (See MISO Draft Tx Planning Futures Envision 400-GW Supply or More by 2045.)

“We’re expecting to see a significantly more balanced system” than before, Porter said.

But MISO’s four transmission planning scenarios, to be finalized in spring 2026, don’t allow for much energy storage, a detail MISO Director Barbara Krumsiek asked about during MISO’s quarterly Board Week in December.

Rauch said MISO’s reworked versions of the future simply don’t contain as much excess energy production from renewable energy, making storage a less compelling avenue.

At a Dec. 10 Advisory Committee meeting, Clean Grid Alliance’s Beth Soholt urged MISO not to underestimate storage expansion and consider giving it a broader use category in the markets.

“It’s like bacon. It makes everything better. Add it to a sandwich and it tastes better,” Soholt joked.

Soholt said MISO’s market rules for storage can either be a “barrier or a facilitator.”

More DOE Emergencies, More Thermal Resources

Porter said MISO expects to receive more emergency orders from the Department of Energy to keep thermal resources online. However, he said some members themselves might be considering delaying retirements on some of those units.

“The thought is that perhaps we won’t need as many of those orders moving forward,” Porter said.

Since May, there’s been no end in sight to DOE’s interventions to keep a Michigan coal plant online. The Department of Energy in fall ordered Consumers Energy’s J.H. Campbell coal plant to delay closure through the winter. But MISO and its Independent Market Monitor said J.H. Campbell did not clear the planning resource auction and was not needed for resource adequacy. (See MISO: Retirement-delayed Campbell Coal Plant not a Capacity Resource.)

According to Yes Energy data, the 1.45-GW plant had an average 70% capacity factor over June and July 2025.

Ramping Needs

With a solar fleet capable of a 14.5-GW peak and set to double over 2026, MISO will pay more attention than it ever has to its steeper ramping needs, which have risen dramatically with a growing renewable fleet.

Zak Joundi, executive director of markets and grid strategy, said MISO will design a process to dynamically set requirements for ramp capability and regulation reserves throughout 2026.

MISO must “clear the right products in the right areas,” Joundi told the MISO Board of Directors in early December. However, Joundi said while designs would be more computationally complex, MISO would stop short of clearing ancillary services on a nodal basis, like its real-time energy market.

MISO South Long-Range Tx Plan an Open Question

MISO will turn its attention to long-range transmission planning for the most constrained load pockets in its South region. The RTO has pledged to conduct a risk assessment as part of its first long-range transmission effort in MISO South in 2026, focusing on load pockets across Louisiana and southeast Texas.

But don’t expect multibillion-dollar transmission portfolios like those designed for MISO Midwest. The RTO’s planners will take a more measured approach with the South. (See MISO to Include Southeastern Texas in South Long-range Tx Planning.)

Rauch said MISO would “practice what a long-term transmission plan and risk assessment will look like” with its South stakeholders over 2026. She said MISO won’t propose solutions until it and stakeholders can review results of the risk analysis and better understand whether generation, transmission or something else might be needed.

“We don’t want to commit to anything until we see those,” Rauch said. She added that MISO could conduct more assessments after the initial risk assessment to further flesh out solution decisions.

MISO’s South planning announcement was prodded in part by a late May 2025 load shedding incident in New Orleans. Repercussions from widespread blackouts in the New Orleans area are to reverberate into 2026 as MISO has promised to launch a new transmission warning system. (See MISO to Debut Tx Warning System in 2026.)

Finally, MISO in 2026 will manage planned transmission outages related to construction of its first, $10.6 billion batch of long-range transmission projects in MISO Midwest that were approved in 2022. Executive Director of System Operations J.T. Smith said the construction is expected to alter MISO’s usual congestion patterns.

Smith said “good, solid outage coordination” will be key, alongside reflecting changes in MISO’s financial transmission.

“It is going to be impactful. There are going to be some right of ways that we lose access to for a while,” Smith told MISO directors at a Dec. 9 Markets Committee of the Board of Directors.

Bear agreed that outage coordination will be key as the first long-range transmission projects are built. MISO expects the largest disruptions from LRTP project construction in 2026, 2027 and 2028.

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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.”