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March 12, 2026

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Northwest Lawmakers Explore Building Transmission Without BPA’s Help

Oregon and Washington lawmakers are exploring ways to build new transmission independent of the Bonneville Power Administration as electric sector stakeholders in the Pacific Northwest worry about the agency’s struggle to build transmission fast enough to keep up with aggressive clean energy laws and increased load.

BPA paused certain planning processes in 2025 to consider how to address nearly 61 GW of transmission service requests. The agency presented several proposals to reduce the queue, but concerns have been raised that many of the efforts would go into effect after the 2030 deadline for utilities in Oregon and Washington to meet strict greenhouse gas standards.

Former BPA Administrator Randy Hardy has previously argued that the issue lies with the states’ respective clean energy laws, which he said set off a “gold rush” among developers, leaving BPA to solve the issue of building enough transmission to keep up. His comments received support from utilities and other organizations during BPA meetings. (See BPA Tx Planning Overhaul Prompts Concern for Northwest Clean Energy Compliance.)

But Oregon state Rep. Mark Gamba (D) pushed back on that notion in an interview with RTO Insider.

Oregon’s House Bill 2021 directs the state’s investor-owned utilities to reduce their greenhouse gas emissions by 80% by 2030, on the path to achieving 100% GHG-free generation by 2040. (See Clean Energy, Equity Goals to Reshape Oregon IRP Process.)

For Gamba, the issue is not the law’s requirements but rather that BPA, which controls approximately 75% of the region’s high-voltage transmission, has failed to build enough transmission.

“I’m less concerned with HB 2021 and the law as I am with the fact that we are still burning fossil fuels in the state of Oregon to supply energy to a rapidly growing load. That needs to come to a screeching halt,” he said. “But the only way that’s going to happen is if we build more transmission.”

As a federal entity, BPA does not have to follow mandates imposed by the Oregon legislature. The agency has focused on its preference customers — publicly owned utilities that rely on it for generation — and failed to realize “they are the backbone of the transmission system in the whole Pacific Northwest,” Gamba contended.

The situation worsened in 2025 after approximately 200 employees accepted a “deferred resignation” buyout offer under President Donald Trump’s effort to slim down the federal government, according to Gamba.

BPA resumed hiring in September 2025. (See BPA Looks to Fill 155 Positions After Hiring Freeze.)

BPA declined to comment for this story, but the agency has previously noted its efforts to build out transmission and generation.

For example, when BPA paused its transmission planning processes to deal with the 61 GW of generation in its current interconnection study, it identified 16 GW of late-stage projects that are now being integrated at a rate of roughly 1 to 1.5 GW per year, with the goal of integrating the full 16 GW by 2035, according to the agency.

As for transmission, the agency secured $773.8 million in transmission capital for 2025 with the goal of doubling transmission capital execution by 2028. It plans to issue awards to contractors in March 2026 that will cover a 10-year period with a maximum value of $25 billion to build and modify lines.

BPA also launched its $5 billion Grid Expansion and Reinforcement Portfolio initiative in 2023 with the aim of building 23 new transmission lines and substation projects.

However, Gamba said BPA was “pretty nonresponsive” even before staffing cuts, adding that he doubts the agency will “start building significant new lines anytime soon.”

Instead, the Democratic lawmaker thinks Oregon should take matters into its own hands. Gamba presented a bill last year aimed at creating a transmission authority (TA) and intends to revive that effort this year.

“We just need some entity to act like an adult in the room and actually start developing the transmission that we need,” Gamba said.

A map over BPA’s transmission assets withing the Pacific Northwest | BPA

The TA would explore where transmission is needed and begin the siting and permitting process. It would then work with either utilities or third parties to get lines built. The approach has found success in New Mexico and Colorado, according to Gamba.

In an email to RTO Insider, JD Podlesnik, Portland General Electric’s senior director of transmission delivery, said the utility is ready to work with both BPA and other regional entities to expand transmission.

Podlesnik noted that PGE has added more than 3,000 MW of clean energy and storage to the grid and recently finalized agreements for an additional 1,000 MW of clean energy resources, “making steady progress toward customer-driven clean energy targets.”

“At the same time, transmission capacity remains a key challenge across the region, both for reliability and clean energy targets,” Podlesnik said in the email. “BPA plays an important role in expanding the transmission network and accelerating the interconnection of new generation resources. Continuing to execute on BPA’s Grid Expansion and Reinforcement Portfolio is one of the critical steps in addressing those constraints.”

Washington Issues

But Oregon entities are not alone in grappling with transmission constraints and compliance with clean energy laws. Washington utilities face a similar situation.

A study by Energy and Environmental Economics predicts that accelerated load growth and aging power plant retirements will create a resource gap in the Northwest starting at about 1.3 GW in 2026 and expanding to almost 9 GW by 2030. That is approximately the load of the state of Oregon.

For context, BPA’s White Book released in May 2025 projected the Northwest would have about 27.9 aMW of total (not just federal) generation available in 2026.

As is the case nationwide, data centers and electric vehicles are the primary drivers behind the expected load growth.

And just as in Oregon, Washington’s Clean Energy Transformation Act (CETA) requires all electric utilities in the state to become greenhouse gas-neutral by 2030 (allowing for use of offsets and other programs) on the way to generating all power from emissions-free resources by 2045. It also prohibits utilities from serving their Washington customers with any coal-fired generation after 2025. (See Washington Agencies Adopt New Rules to Implement CETA.)

But again, lack of transmission poses challenges for utilities to meet the law’s requirements.

There is collaboration across state lines to build more transmission independent of BPA, according to Washington Rep. Alex Ramel (D).

Washington lawmakers are also seeking to create a transmission authority under Senate Bill 6355.

“There is this sort of federal government monopoly in the space,” Ramel said.

Relying too much on the federal government as BPA struggles with staffing shortages “is a real concern,” according to Ramel.

“That, to me, is part of the reason why we need to be more expeditious about how we think about putting together these kinds of projects,” Ramel said in referring to a potential Washington TA. “Because if [BPA] is losing staff, that can only … impact negatively our need to be able to increase clean energy transmission opportunities.”

As for CETA, Ramel said he is not ready to “pull the plug on it.” He acknowledged the law was passed when the region did not have the same electricity use that comes with the development of AI and electric vehicles.

“I could be persuaded to have reasonable extensions or extenuating circumstances for utilities that really can’t meet those goals,” Ramel said. “But right now, I haven’t seen anything that persuades me that those goals can’t be met. We could revisit that in the future if we need to. Right now, I think we should stay full steam and let’s build out clean energy and let’s accelerate transmission.”

Puget Sound Energy, which is one of BPA’s largest transmission customers, has removed coal from its energy portfolio in accordance with CETA and is focused on providing 80% of its electricity from renewable or non-emitting resources by 2030-2033, according to Matt Steuerwalt, PSE’s vice president of external affairs.

Still, BPA’s ability to expand transmission capacity and allow new resources to come online “will have a major impact on our progress toward Washington clean energy laws,” Steuerwalt told RTO Insider.

“We also have to consider permitting and siting for energy infrastructure development undertaken by entities other than BPA, which is a major challenge to building any project,” he added. “We have been following the current legislation closely to see the extent to which it can address these and other issues.”

‘Morass of People’

But for Scott Simms, executive director of the Public Power Council, there are risks with creating separate TAs.

“I think that once you create an additional apparatus to try to do the exact same thing that other organizations are statutorily obligated to do, it’s going to create a morass of people trying to all do the same things,” Simms said.

Instead of solving the transmission challenges, the risk is that additional TAs would “exacerbate the very problem you’re trying to solve,” he added.

Rather, Oregon and Washington should fix the challenging operating environments they have created for consumer-owned and investor-owned utilities alike, Simms contended.

“There’s a variety of things on both the energy policy side with regards to resources and there are fixes on the transmission side when it comes to permitting and the planning process,” he said. “If the states were just to focus on how to best facilitate and streamline the transmission permitting and siting elements, that would be a huge help.”

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AI’s Rapid Growth Increases Risks to U.S. Grid

Artificial intelligence has been framed by the Trump administration as ushering in a “new golden age of human flourishing, economic competitiveness and national security” for the U.S. should it win the race for computing systems that perform tasks normally requiring human intelligence.

But with the country’s drive to build up its AI ecosystem comes increased risks, both digital and physical.

Faruk Dziho, the business intelligence analyst and data solutions lead for the Texas Reliability Entity, says that while AI can strengthen grid reliability, it also creates risks if it is not managed properly.

“At the end of the day, it’s just a tool, and it’s not a replacement for engineers or operators. It excels at pattern recognition and forecasting when there is clean data,” he said during a Talk with Texas RE webinar March 10. “When it comes to some risk-mitigation strategies, there needs to be a robust data governance in building high-quality data pipelines with clear ownership, extensive validation model transparency and oversight.”

Texas RE added AI integration as a “moderate” risk in its 2024 Reliability Performance and Regional Risk Assessment, released in June 2025, saying the risks are “currently relatively unlikely to manifest themselves.”

“As AI increases in scale and integration, however, associated risks may increase in both likelihood and impact,” the regional entity wrote.

“That assessment itself is not set in stone. As adoption expands across the industry, both the probability and severity of those risks may rise,” Dziho said. “We’ll continue to monitor developments and adjust the assessments as the technology evolves.”

The Texas Interconnection grew faster than any other region in 2025, with demand increasing 5% through September when compared to the same period in 2024, according to the U.S. Energy Information Administration. The agency has said it expects demand to increase by more than 9% in 2026.

Dziho told his online audience that AI carries risks that demand robust mitigation strategies. AI-driven load growth could lead to cybersecurity vulnerabilities that can be exploited faster with AI-powered tools and systems, adaptive malicious code that bypasses security controls, and data poisoning.

“Artificial intelligence basically makes it easier for attackers to generate phishing attacks by generating thousands of personalized emails instantly or scanning for vulnerabilities faster,” he said.

Because AI systems use massive amounts of data collection and typically include confidential and/or sensitive information, data privacy controls must be effective in reducing the risk of breaches, Dziho said.

“We need to secure artificial intelligence workflows,” he said. “The field is changing constantly. There are new threats that we find out daily.”

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FERC Opens Show Cause Proceeding into ISO-NE Rules for Improper Payments

FERC has initiated a show cause proceeding based on concerns about the lack of provisions in ISO-NE‘s tariff enabling fixes to incorrect payments to or from market participants.

The order, issued March 10, comes following multiple recent requests from participants for waivers to return improperly accrued funds to the RTO.

The commission wrote the ISO-NE tariff “appears to be unjust and unreasonable because it lacks provisions that would enable ISO-NE to return amounts that it erroneously charged to market participants and to accept payments from market participants that were erroneously or improperly received in ISO-NE’s markets.”

FERC established settlement procedures in 2024 for a waiver request by Canal Marketing to return improperly accrued funds from the RTO’s Inventoried Energy Program. The commission approved a settlement between ISO-NE and Canal in early 2025. (See FERC Establishes Settlement Procedures for ISO-NE IEP Exit Request.)

In fall 2025, Brookfield Renewable Trading and Marketing requested a waiver to refund ISO-NE for four months of improperly received capacity market revenues. FERC established settlement proceedings for this waiver request on the same date as its show cause order.

ISO-NE has 60 days to justify its existing tariff rules or explain what changes it would make if FERC requires it to make tariff changes addressing the issue.

“If ISO-NE prefers to propose revisions to the tariff on the subject of this order, then it may do so pursuant to its applicable [Federal Power Act] Section 205 filing rights,” FERC added.

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SEIA, WoodMac Chart Whiplash in U.S. Solar Industry

Nearly 40% fewer U.S. solar power projects reached completion in the fourth quarter than in the third quarter as developers pivoted to start new projects in time to qualify for tax credits.

But while the 43.2 GW of solar capacity installed in 2025 was 14% less than in 2024, it nevertheless made up 54% of all new capacity added to the U.S. grid in 2025, the Solar Energy Industries Association (SEIA) and Wood Mackenzie said in a new report March 10.

2025 was the fifth straight year solar was the top source of new U.S. power generation capacity.

Looking ahead, the analysis predicts nearly 500 GW of additional photovoltaic capacity will be installed nationwide through 2036, even with the headwinds created by a president hostile to renewable energy. The costs of alternatives are high enough that solar remains a value proposition even without the lucrative investment and production tax credits that are being sunsetted sooner than originally planned.

“It’s clear that solar will continue to be the dominant source of new power capacity in the United States, even as gas generation continues to grow,” said Michelle Davis, head of solar at Wood Mackenzie and lead author of the report. “Strong demand growth combined with escalating costs of new gas plants will allow solar to remain competitive, even without tax credits.”

The “U.S. Solar Market Insight 2025 Year in Review” acknowledges the many uncertainties facing solar power. The baseline prediction of 490 GW more solar capacity by 2036 could be 11% higher or lower due to a series of factors, but the projected variation for utility-scale solar (6-7%) is much less than for distributed solar (23-28%).

Distributed solar is more sensitive to changes in retail rates and cost-impacting policies such as tariffs and import guidance, the authors state, while utility-scale projects are more likely to be affected by interconnection bottlenecks, supply chain constraints and power demand growth.

Another unknown factor is President Donald Trump.

Trump’s signature on the One Big Beautiful Bill Act in July 2025 moved forward the expiration of tax credits in the Inflation Reduction Act.

Projects now must start construction before July 4, 2026, or be placed into service by Dec. 31, 2027, to qualify for full tax credits. This led to significantly fewer completed projects in 2025 than expected — the value of completing them was outweighed by the imperative of beginning work on the next projects in the pipeline in order to safe harbor their tax credits.

While the president relentlessly boosts fossil fuels over renewables, he does not show the same level of hostility to solar panels as to wind turbines. There even have been a few hints in early 2026 of solar opposition softening among some MAGA influencers.

solar

Solar power’s growth as a U.S. power generation technology is shown. | Wood Mackenzie

Whatever the motive for this turnaround, solar has some effective selling points in 2026: It is faster and less expensive to deploy than gas or nuclear; U.S. solar component manufacturing has expanded greatly; and battery energy storage systems to smooth out its intermittent performance are proliferating in number while decreasing in price.

SEIA interim President Darren Van’t Hof indicated that while the federal uncertainty has not gone unnoticed, it is not insurmountable: “Solar and storage continue to dominate new capacity additions to the grid despite policy headwinds. American households and businesses of all sizes are demanding solar + storage because they deliver fast, affordable power to help meet rapidly rising demand,” he said.

“Washington must deliver policy certainty for the market to work and to keep pace with growing energy demands. Without this certainty, less solar will get built and Americans will pay the price with higher energy bills.”

Even with this churn, all of Wood Mackenzie’s U.S. power projections show solar constituting nearly half of all U.S. capacity additions each year through 2060.

The 2025 outlook calls for an average annual addition of 44 GW through 2036, which is an increase over previous projections based on the increase in the near-term utility-scale pipeline and continued growth in energy demand expectations.

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SERC Speakers Warn of Rapidly Evolving Security Threats

Speakers at a SERC Reliability-hosted webinar praised the commitment by utilities and other stakeholders to address the grid’s ongoing and emerging risks but warned that their adversaries also remain inventive and committed.

“There’s this saying, ‘A rising tide lifts all boats,’” Chad Kitchens, senior lead analyst at Entergy, said at the regional entity’s 2026 Regional Risk Webinar on March 10. “It seems every year the tide is coming in higher, and we have to keep our head above water, [which] requires a greater investment in newer technologies [and] newer control measures.”

The webinar focused on risks identified in SERC’s biennial Regional Risk Report, last released in 2025 and covering the years 2024 to 2026, with a focus on extreme physical events including sabotage and attacks, and exploitation of cybersecurity vulnerabilities. (See Weather, Supply Chain Top SERC Risk Rankings.) Participants included security specialists from electric utilities, law enforcement and consulting firms.

In the first panel, Kitchens joined Jon Carstensen, utilities vertical manager at security firm IQSIGHT, and Mike Hazell, private sector coordinator for the Florida Fusion Center, an information-sharing program managed by the Florida Department of Law Enforcement, to discuss the industry’s response to physical threats. Hazell warned listeners that recent news about attempts by violent extremists to target electric infrastructure showed “the age of security through obscurity is over for us.”

“As the industry adapts and starts to invest in [security], our adversaries are also adapting, and they’re adapting to the point where they’re doing deliberate targeting,” Hazell said. “They are doing the research to understand what … a critical asset is for, not only the energy sector, but the sectors that have interdependencies with the energy sector.”

Hazell pointed to a worrying trend of extremists borrowing tactics and even motivations from each other in what he called “a salad bar approach to rhetoric and ideologies.” He said the attack in February by a New York man against a substation in Boulder City, Nev., was an example of this development.

After Dawson Maloney of Albany, N.Y., drove his rented car, loaded with weapons, through the substation fence and killed himself with a shotgun, authorities found several documents in a hotel room he rented, including military pamphlets on improvised weapons, books on magic from the 17th century and novels promoting white supremacy and terrorism. (See Police, FBI Seeking Motive in Nevada Grid Attack.)

Hazell said the incident shows the need for collaboration among utilities, law enforcement and the cybersecurity community “to outpace our adversaries” by sharing threat intelligence while protecting sensitive information that adversaries could use for their attacks.

Kitchens agreed that “we have to up our game,” suggesting that utilities consider machine learning and artificial intelligence technology to help keep up with threats. As an example, he mentioned video monitoring systems with analytic functions that can classify observed objects and notify operators to anything out of the ordinary.

“I think the biggest thing that I’m excited about is just being able to [use] those analytic and AI capabilities to filter out the noise that traditionally you get when you do that,” Kitchens said. “It’s making more efficient use of the people you have, which allows you the potential to ingest more sites into your [security operations center] and provide a larger sense of protection.”

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ISO-NE Proposes Cut to Performance Payment Rate

ISO-NE has proposed to reduce its performance payment rate (PPR) by more than 60% in response to concerns that excessive penalties will have unintended consequences for the capacity market.

Capacity resources in New England have incurred significant performance penalties during scarcity events over the past two years. These penalties have been particularly consequential for slower-start fossil units. Over two events in 2024, net penalties for combined cycle gas and oil generators totaled $44.3 million, while penalties for steam turbine residual-oil units totaled $25.8 million.

Some participants have argued the risk of these penalties could drive up capacity prices in future auctions and push resources out of the market.

The performance rate determines penalties and credits during scarcity events. The RTO’s Pay-for-Performance (PFP) construct is designed to insulate ratepayers, with underperforming resources paying for the incentives for overperforming resources.

The RTO’s per-megawatt-hour performance rate has grown in recent years, increasing from $2,000 to $3,500 in 2021, to $5,455 in 2024, and to $9,337 in 2025.

ISO-NE announced at the NEPOOL Markets Committee meeting March 10 that it plans to cut the rate back to $3,500. It also plans to move forward on an expedited schedule to implement the changes as quickly as possible, targeting a technical committee vote in May.

“Some resources may find the increased PPR, and the volatility associated with it, makes the risks and potential costs of selling capacity too high,” said Chris Geissler, director of economic analysis at ISO-NE. “This could result in retirements from resources that can still make meaningful contributions to system reliability.”

He added that a high performance rate increases the risk that individual resources hit their stop-loss limits, which cap the total penalties each resource can accrue per month. When resources hit this limit, ISO-NE charges unrecovered penalties to all capacity resources that have not hit the stop-loss limit.

The reduced PPR still should provide adequate incentives for performance, Geissler said, estimating that incentives from PFP and elevated energy market prices likely would total around $6,000/MWh.

“History suggests that resources make investments and perform strongly at this rate,” he said.

Stakeholders generally reacted favorably to the proposal, while some expressed concern that a $3,500 rate may be too low to adequately incent performance during scarcity conditions.

Treatment of Exports

Also at the MC meeting, ISO-NE detailed its plans to subject certain exports to the performance rate.

This change, recommended by both of the RTO’s market monitors, is intended to prevent a market loophole that could allow participants to earn performance credits without sending any power.

Under the current rules, during a capacity scarcity event, if a participant schedules exports that equal imports scheduled by a different participant, the export would not be charged performance penalties, but the import would earn performance credits.

“These two transactions collectively result in no power flowing but do not net in settlement because they are submitted by different market participants,” said Enrico De Magistris, economist at ISO-NE. “The market participants could transact outside the ISO-NE system to share the PFP credits.”

He noted that ISO-NE is not aware of any instances in which a participant has exploited this loophole.

To fix the issue, the RTO proposes to charge the performance rate during scarcity conditions to all exports “not associated with a specific generator in the ISO-NE system.”

Unlike “system-backed exports,” exports associated with a specific generator would not be charged the performance rate. These exports would reduce the amount of performance revenues the associated generator could earn or subject it to performance penalties for not meeting its capacity supply obligation (CSO).

De Magistris said ISO-NE likely will remove system-backed exports from the calculation of its balancing ratio, which it uses to determine capacity resources’ obligations during scarcity events.

ISO-NE calculates the systemwide balancing ratio by dividing load and reserve requirements by total CSO. System-backed exports are currently included in the calculation as load, while generator-backed exports are excluded.

Balancing Ratio Cap

ISO-NE also discussed its proposal to cap the PPR balancing ratio in compliance with an order issued by FERC in January.

The ruling stemmed from a complaint by the New England Power Generators Association after the balancing ratio exceeded 1.0 for the first time ever during an event in June (EL25-106). (See FERC Directs ISO-NE to Cap Pay-for-Performance Balancing Ratio at 1.0.)

In designing the tariff changes, ISO-NE has tried to “keep the ‘effective’ payment rate for overperformance as close to the tariff-specified [PPR] as possible,” said Megan Sweitzer, lead analyst at ISO-NE.

Under the proposal, if the cap on the balancing ratio leads to the under-collection of performance charges, this deficit would cut into the performance credits allocated to overperforming resources.

“This change ensures resources performing at their CSO megawattage are not charged” and “lowers the ‘effective’ PPR for overperformance when a deficiency exists,” Sweitzer said.

Notably, the treatment of deficits caused by the balancing ratio cap would differ from the treatment of deficiencies caused by the stop-loss mechanism, which will still be charged to all capacity resources.

While NEPGA argued against ISO-NE’s allocation of stopped losses in its complaint, FERC sided with ISO-NE’s argument that the stop-loss mechanism benefits all capacity resources and therefore it is fair to charge capacity resources for the costs of its implementation.

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Duke Files Settlements in Carolinas on Proposed Utility Combination

Duke Energy has entered a pair of settlements in North and South Carolina on its proposal to combine Duke Energy Carolinas and Duke Energy Progress, which still needs approval from both states’ regulators.

Duke said combining its Carolina subsidies would help it meet the states’ growing energy needs at a lower cost. (See Duke Energy Says Combining Carolina Utilities Would Save Billions.)

The deal before the North Carolina Utilities Commission was filed in late February and signed by North Carolina Public Staff, the North Carolina Attorney General’s Office, Google, Nucor, Walmart and others.

“We’re pleased that public staff and the attorney general’s office agree our customers will see significant future cost savings and other meaningful benefits from combining our two utilities,” Duke Energy North Carolina President Kendal Bowman said in a statement on March 10. “It reduces customer costs, simplifies operations, promotes regulatory efficiencies and supports economic growth across the Carolinas.”

The deal pending before the Public Service Commission of South Carolina was filed on March 6 and was endorsed by the state’s Office of Regulatory Staff, Nucor, Walmart, Vote Solar, the Sierra Club and others.

“Our engagement has been laser-focused on consumer protections and affordability for South Carolina families and small businesses, and one of the best ways to do that is by investing in alternatives to building new costly and polluting resources,” Sierra Club’s Paul Black said in a statement. “Duke’s regulators at the Public Service Commission must turn their attention to establishing strong consumer protections that require tech companies, not families, to pay for all of the energy and infrastructure costs for new data centers, and the Sierra Club has laid the groundwork to make that happen.”

Duke Energy Carolinas owns 20.8 GW of generation and serves 2.9 million customers across a 24,000-square-mile territory, while Duke Energy Progress owns 13.8 GW to supply 1.8 million customers across a 28,000-square-mile territory.

The filings with both states include commitments from the utility to save hundreds of millions of dollars through lower production costs from more efficient operations and lower capital costs from more efficient planning.

The proposal already has been approved by FERC. Assuming the two states approve the settlements, Duke expects to combine the subsidiaries effective Jan. 1, 2027. (See FERC Approves Duke Proposal to Combine Carolinas Subsidiaries.)

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EIA Expects No Impact on Domestic Natural Gas Prices from Iran Conflict

The war in Iran is not expected to lead to higher domestic natural gas prices in part because higher oil prices tied to the closure of the Strait of Hormuz mean more oil production and related gas supply from the Permian Basin, the U.S. Energy Information Administration said.

In its monthly Short-Term Energy Outlook, released March 10, EIA explained how Iran’s closure of the strait in response to a bombing campaign by the U.S. and Israel raised global oil and LNG prices.

The Brent crude oil spot price was up sharply since the start of military action in the Middle East, settling at $94/barrel March 9, a 50% boost since the start of the year and the highest since September 2023.

“We make the assumption in our modeling that the effective closure of the Strait of Hormuz will cause oil production in the Middle East to fall further in the coming weeks,” EIA said. “We assume this shut-in production will gradually ease as transit through the strait resumes.”

Nearly 20% of global oil trade flows through the strait, which is between Iran and the Arabian Peninsula, along with about 20% of global LNG, mainly from Qatar to East Asia. Global LNG prices have shot up, but U.S. export capability was already operating near capacity before the bombing began.

In the short term, EIA predicts national average natural gas prices of $3.80/MMBtu, 13% lower than last month’s figure, as more of the fuel was left in storage than it had expected.

“The Henry Hub spot price averages nearly $3.90/MMBtu in 2027, 12% lower than our forecast last month,” EIA said. “Lower prices in 2027 mostly reflect more associated natural gas production as a result of the recent increase in oil prices and the related increase in production later in the forecast.”

Higher crude production results in more associated natural gas production, and EIA expects the latter to rise 2% from 2025 to 121 Bcfd this year and an additional 3% in 2027 to 124 Bcfd. The 2027 figure is 2 Bcfd higher than EIA forecast a month ago.

“Elevated oil prices will drive more oil-directed drilling in the Permian, which will contribute to greater volumes of associated natural gas production,” EIA said.

National average residential electricity prices are expected to rise slightly this year and next, going from 16.5 cents/kWh in 2025 to 17.3 cents/kWh in 2026 and 18 cents/kWh in 2027.

“We expect U.S. electricity generation will grow by 1.2% in 2026 and by 3.1% in 2027, which follows recent upward trends in generation to meet growing electricity demand,” EIA said. “Between 2010 and 2019, electricity generation was essentially unchanged, as electricity demand from a growing population was offset by the use of more efficient appliances and heating and cooling equipment. But since 2021, U.S. generation has been growing [at] an average of about 2% per year.”

The biggest growth is in ERCOT, where EIA said generation is expected to grow by 7.3%, leading to increases across all technology types. The rest of the country is expected to see less generation from natural gas plants, as the delivered price of the fuel for generators is up 8%.

Higher gas prices tend to favor generation from coal plants as a substitute, but with operators currently planning to retire 4% of coal capacity and the growth of renewables, EIA forecasts coal generation will drop 7% this year, mostly in the Midwest and Southeast. Plans to retire coal plants are subject to change, the agency noted.

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Utilize the Grid Better to Save $100B+, New Coalition Urges

A new industry coalition calling itself Utilize has begun a campaign to make electricity less expensive and quicker to connect by unlocking underused grid capacity.

Utilize announced its launch March 10 and said it soon will release a Brattle Group research report showing that better use of existing grid infrastructure could save more than $100 billion over 10 years.

The coalition’s charter members are a cross-section of energy providers and users including Carrier, Google, Renew Home, SPAN, Sparkfund, Tesla and Verrus.

Utilize is designed as a nonpartisan campaign focused on influencing state-level regulators, elected officials, utilities and stakeholders.

In its announcement, Utilize emphasized one of the salient themes of the 2026 campaign season: consumer costs. It said the $100 billion in savings would accrue to consumers on their electric bills and allow consumers to connect to the grid more quickly. But it also said better utilization would help states meet the growing power demands created by data centers, manufacturing and electrification without delay or excess cost.

The power grid is built for peak demand, and the excess capacity in non-peak periods has been cited repeatedly as a potential resource to meet new non-peak demand, particularly if more users were more flexible in their peak demand.

Utilize cited an influential 2025 Duke University study showing the existing grid could handle 126 GW of new demand with no additional generation if data centers cut their power use as little as 1% in peak periods. (See US Grid Has Flexible ‘Headroom’ for Data Center Demand Growth.)

In the 13 months since the study was released, many other people have reached the same conclusion, and Duke issued a follow-up report that drilled down on the benefits. (See Duke University Study Quantifies Benefits of Data Center Flexibility.)

The Federal Reserve Bank of St. Louis recently charted U.S. grid capacity utilization dropping from just over 100% in July 1999 to just over 68% in August 2025. It averaged 71.27% in January 2026, the most recent month charted.

Now Utilize wants to translate research into action.

“For decades, we’ve built the grid to meet peak demand, even though large portions of it sit unused for most hours of the year,” Executive Director Ian Magruder said.

“It’s like building an airplane that only flies with full passengers a few times a year. That excess capacity is hiding in plain sight, and new technologies give us the opportunity to unlock it. Better grid utilization is one of the fastest, most practical levers states can pull to reduce power bills while supporting economic growth.”

Utilize said it will support technology-neutral policies that align planning, incentives and regulatory framework to meet the objectives of affordability, reliability and speed.

The goal is to make better grid utilization a core principle of U.S. grid planning.

Utilize cited the 2025 Duke study’s finding that the 22 regional power systems examined operated at just 53% of capacity on average.

Utilize also pointed to a 2025 Stanford University study showing that even during peaks, most Western U.S. transmission lines were carrying only 18 to 52% of their available capacity, with most clustered around 30% of capacity. But the excess capacity is not consistently accessible due to operational and planning constraints; Utilize said better utilization would allow for more demand to be served and would spread the fixed grid costs across more electricity sales.

The new Utilize coalition adds some prominent names to the push to better utilize the existing grid. Some other recent efforts:

A new partnership announced the same day as Utilize announced itself will design flexible data centers. (See Emerald AI, InfraPartners Team up to Deploy Flexible Data Centers.)

Google has funded analyses on flexible data center models and signed some flexibility agreements of its own. (See Analysis Offers Blueprint for Faster Data Center Interconnection and Google Strikes Demand Response Deals with I&M, TVA.)

A blueprint is being created for placing smaller data centers near stranded power to speed their deployment. Research has shown flexibility would be part of a suite of tools that could limit the financial impacts of data center buildout. Other research has highlighted the value of demand management and energy efficiency.

If “flexibility” seems like a buzzword lately, that’s because it is. RTO Insider columnist K Kaufmann recently explained the phenomenon. (See Why 2026 will be the Year of Flexibility.)

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MISO’s 3rd Expedited Queue: 8 GW of Gas and Batteries

MISO announced a third, 8-GW cycle of generation projects to enter its fast-tracked interconnection process, its largest cluster yet.

MISO’s expedited interconnection queue continued its theme of a high proportion of thermal resources, with gas plants outnumbering storage facilities on a capacity basis 5.8 GW to 2.2 GW. Storage accounted for eight entries, while gas submittals took the remaining seven slots.

In its last 15-count queue class, gas also tipped the scales and accounted for 4.3 GW of the 6-GW group. (See MISO Accepts 6 GW of Mostly Gas Gen in 2nd Queue Fast Lane Class.)

The grid operator said it expects this collection of projects to be in service no later than 2031.

This batch of expedited interconnections includes Northern Indiana Public Services Co.’s (NIPSCO’s) coal-to-gas transition at its R.M. Schahfer Generating Station. NIPSCO submitted two combined cycle plants totaling 2,639 MW. NIPSCO cited its 2024 integrated resource plan to back up the need for the plants, which was developed before the U.S. Department of Energy stepped in to prevent the Schahfer plant from retiring as planned at the end of 2025.

The Schahfer plant is on emergency stay-open orders through March 23. So far, DOE hasn’t let any of its 90-day operating extensions lapse, issuing a chain of orders before the last has a chance to expire. Schahfer also needs expensive, time-consuming repairs before the plant’s Unit 18 can function. (See Enviros Warn NIPSCO Against Rebuilding Coal Unit on DOE Emergency Order.)

NIPSCO also put forward 500 MW of battery storage at its Mitchell site in Gary, Lake, Ind. NIPSCO said both the Schahfer gas plants and Mitchell battery storage “are necessary for resource adequacy to serve growing data center, advanced manufacturing and other economic development project load requirements.”

Xcel Energy, DTE Electric, NextEra Energy, Swift Energy Storage, Hackett Energy Storage and Brickyard Energy Storage also submitted battery facility plans ranging from 100 MW to 300 MW in Michigan, Minnesota and Indiana.

Xcel Energy’s plans included its Sherco South BESS project, part of the utility’s planned Sherco Energy Hub in central Minnesota, which reimagines the site around the coal-fired Sherburne County Generating Plant (Sherco) into a solar and storage format. Xcel closed Sherco Unit 2 in 2023 and plans to idle units 1 and 3 in 2026 and 2030, respectively.

Gas plans, on the other hand, involve one of Entergy Louisiana’s three plants to serve the sprawling Meta data center in Richland Parish, a 478-MW plan from Entergy Texas, and Basin Electric Power Cooperative’s 250-MW turbine in South Dakota.

Gas submittals from Alliant Energy subsidiaries Interstate Power and Light Co. for a 750-MW plant in north-central Iowa and Wisconsin Power and Light Co. for a 150-MW turbine addition in eastern Wisconsin also made the cut.

“The interest we continue to see reflects both the urgency and the opportunity to develop a clear, timely path to interconnection, and [the Expedited Resource Addition Study] is helping us provide that in the near term,” Vice President of System Planning Aubrey Johnson said of the batch of applicants.

MISO said that, to date, its queue fast lane has attracted 53 applicants representing almost 27 GW of nameplate capacity, which the RTO has either agreed to study or awaits approval.

The RTO said it has completed studies on more than 11 GW of proposed capacity and the developers behind the first 10 projects already have struck generator interconnection agreements.

MISO’s temporary queue express lane is capped at 68 projects, and MISO said it will entertain the last project submissions through mid-2027 before the process winds down on Aug. 31, 2027, if not sooner.

Johnson said the queue fast lane is part of MISO’s larger work to get its regular interconnection queue unstuck and pick up the pace on achieving a one-year processing timeline.

Express Lane Dropouts

Developers have withdrawn eight projects since the fast-tracked interconnection lane opened in 2025.

The most recent projects to drop off are two NextEra battery storage projects in Hoosier Energy’s territory. NextEra withdrew its 275-MW Sandcut and 400-MW Merom four-hour storage projects in mid-February. They were meant to serve a Solvenz data center.

NextEra also shelved its expedited request for its restart of the Duane Arnold nuclear plant in Iowa. The plant is set to rumble back to life by early 2029. Google signed a 25-year deal to buy power from the plant in October 2025. By November 2025, NextEra withdrew its fast-track request, though plans to restart the plant remain.

Alliant Energy’s Interstate Power and Light Co. also scrapped its request for expedited processing on a planned, 950-MW natural gas plant near Duane Arnold in November.

MISO confirmed to RTO Insider that any projects it lists as “withdrawn” were withdrawn by their respective developers.

The RTO also said it allows other developers to take the place of withdrawn projects only if it can be done quickly. The grid operator said it doesn’t backfill fast lane spots if the developer doesn’t withdraw its project before it begins its round of studies.