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March 11, 2026

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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.

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Emerald AI, InfraPartners Team up to Deploy Flexible Data Centers

Digital infrastructure firm InfraPartners and Emerald AI announced a new partnership to construct data centers designed to be flexible grid assets.

The Flex-Ready Data Centers combine Emerald’s energy management software solutions with InfraPartners’ off-site manufacturing approach to constructing and upgrading data centers, the companies announced March 10.

“The innovation here is to put together the data center design with the needs of the software from the beginning, so that the data center is delivered as a flex-ready data center, so there is no retrofitting later,” Emerald’s chief scientist, Ayse Coskun, said. “There are no additional components needed later.”

The software needs telemetry from all aspects of data centers, which includes computing, cooling, any behind-the-meter generation or storage, and other uses of electricity at the facility, she said.

The main attraction for data centers to become flexible grid assets is speed-to-power, but flexibility offers clear benefits to the operation of the grid, InfraPartners Chief Technology Officer Harqs Singh said.

The Electric Power Research Institute has “a data center flex program with all the utilities in it, and so they’re very interested in being able to have data centers become assets, rather than just consumers,” Singh said. (See EPRI Launches DCFlex Initiative to Help Integrate Data Centers on the Grid.)

With Emerald’s management services, data centers can respond to energy availability, match up with intermittent renewables or just respond to prices, Coskun said.

“So, this interface enables not just speed to power, but more broadly a more amicable relationship between the large data center loads and the grid,” she added.

Compared to “traditional” data centers — those used for cloud computing and data storage — AI data centers have a very high “power density,” which is why they have made headlines about massive loads ranging from the hundreds of megawatts to gigawatts.

“The power density of a rack — a cabinet of servers — is increasing like 10 times compared to a typical cloud rack,” Coskun said. “The AI data centers are running a mix of training, inference and other AI loads, and there are differences. For instance, training loads tend to be more spiky, changing the power up and down more rapidly compared to cloud loads.”

Cloud computing data centers must respond to consumer requests, such as when someone accesses a database or streams video, while AI data centers have more batch processing, long-running training and heavily use their computer hardware, she added. Using energy management techniques can help smooth out their highly variable demand.

“I consider this a welcome side effect of controlling power that the spikes are reduced,” Coskun said. “Because essentially, it’s not only necessarily just reducing the power during a high demand time, but also you can set up overall power limits to gently curb the power without adversely impacting performance, at least beyond the performance constraints, and then reduce these spikes.”

The grid does not respond well to major, fast fluctuations in demand or supply, so flexibility can make AI data centers much easier to handle on the bulk power system, she said. Energy management can also smooth out ramps from spiking energy during training and as they are responding to signals from the grid itself.

“In our work so far with power grid operators and utilities, we received both requests — ‘can you reduce the power over a gradual window of 10 to 15, minutes? We don’t want to see this sharp drop,’” Coskun said, and “‘can you respond within seconds in an emergency, if needed?’ And we demonstrated both. So, there’s flexibility on how quickly we can tune power as needed, depending on the needs of the grid.”

InfraPartners can build it all from the start with its approach of building data center infrastructure at a central manufacturing site and then deploying it where needed, Singh said. That can help with initial construction, but also as new chips constantly improve and existing chips wear out and need to be replaced.

“We are going to have to be a lot more agile,” Singh said. “We’re going to have to adapt a lot more.”

The biggest constraint the industry faces now is power supply, and one way of handling that will be to install more efficient chips as they become available, he said.

“That means that the data center needs to evolve to deploy the latest chips all the time,” Singh said, “and being really good grid partners, working with the grid, showcasing to them how are the loads changing. How do we manage our assets on the data center side with grid assets, such that we’re good partners and be able to power the performance improvements that are coming? … It’s what we call ‘the upgradeable data center’: having a data center that upgrades with different chip technologies that are coming.”

A lot of the contracts for chips last about five years, but how often the chips are going to be swapped out is somewhat uncertain at this point, he added.

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Federal Briefs

NRC Approves TerraPower Nuclear Reactor

The Nuclear Regulatory Commission unanimously voted to grant a construction permit to TerraPower to build its new smaller, advanced nuclear reactors.

The permit allows TerraPower to begin pouring concrete and building the components of its proposed nuclear plant in Kemmerer, Wyo. The plant is currently expected to come online in 2031.

The 345-MW reactor is the first new U.S. commercial reactor in nearly a decade to receive clearance to begin construction.

More: The New York Times

Lawmakers Introduce Bill to Keep Colorado Uranium Disposal Site Running

A group of lawmakers introduced a bill that would extend the operations of the Grand Junction uranium disposal site.

The bill would amend the Uranium Mill Tailings Radiation Control Act of 1978 to extend operations at the site until it reaches capacity. The 1978 legislation currently lists Sept. 30, 2031, as a deadline to shut down the site. The site currently has room for 200,000 more cubic yards of radioactive material.

More: The Daily Sentinel

Oil Prices Soar Past $100/Barrel

Oil prices on March 9 soared above $100/barrel as the conflict between the U.S. and Iran escalates.

Gasoline prices neared $3.50/gallon on average and were up nearly 50 cents from a week ago. Compared to a month ago, before the conflict began, gas prices were up about 58 cents on average. Diesel prices were $4.66/gallon on average, up about 23% over the course of a week.

More: The Hill; The New York Times

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State Briefs

KENTUCKY

House Committee Approves Bill to Create Carbon Storage Framework

The House Natural Resources and Energy Committee unanimously approved a bill that would create a regulatory framework for carbon storage wells.

The bill would require permits from the Energy and Environment Cabinet before constructing or operating carbon sequestration injection wells, with the goal of having the state government receive permission from EPA to be the primary regulator of the wells.

The bill now heads to the full House.

More: Kentucky Lantern

MAINE

Bill Would Place Temporary Moratorium on Data Centers

The Energy, Utilities and Technology Committee advanced a measure that would place a moratorium on data centers.

The bill would pause the development and permitting of new data centers larger than 20 MW until at least October 2027. The measure would also require the Department of Energy Resources to create a new Data Center Coordination Council, which would submit policy recommendations by the winter of 2027.

The measure now goes to the full legislature.

More: Maine Public Radio

MARYLAND

DOA to Reduce Fee for EV Charger Inspections

The Department of Agriculture said it plans to reduce the inspection fee for EV chargers.

Secretary of Agriculture Kevin Atticks told the House Environment and Transportation Committee his agency will tap into the Strategic Energy Investment Fund to help pay for the charger inspection program, which should lower the fee for each charging port from $150 to $75.

More: Maryland Matters

MASSACHUSETTS

EFSB Approves Construction of Storage Facility

The Energy Facilities Siting Board approved Jupiter Power’s plan to construct a 700-MW battery storage facility, which will be the largest in New England. 

The facility, which will consist of lithium-ion batteries, will be built on a former Exxon Mobil oil tank farm and will occupy about 16.5 of 20.75 acres.

More: WCVB

MICHIGAN

House Bills Seek to Put PSC Seats up for Election

A group of 13 House Democrats introduced proposals that would require Public Service Commission members to be elected by voters.

Under the plan, the PSC would expand to five members. The state’s political parties would nominate candidates while voters would pick commissioners beginning in 2028. They would serve staggered four-year terms and be capped at 12 years. Currently, the three-member panel is appointed by the governor to six-year terms, and all three current members are appointees of Gov. Gretchen Whitmer.

The bills were sent to the Government Operations Committee.

More: The Detroit News

OKLAHOMA

Corporation Commission Rejects OG&E’s Charge Plan for Natural Gas Units

The Corporation Commission voted to reject Oklahoma Gas and Electric’s request to apply a cost recovery mechanism for two natural gas units at its Horseshoe Lake Power Plant.

The decision blocks OG&E from using Construction Work in Progress (CWIP) for units 13 and 14, a financing method authorized under a new state law that allows utilities to charge customers for infrastructure projects before they are completed. In November, the commission approved OG&E’s request to build the two units but didn’t grant CWIP treatment. 

OG&E said it plans to file an appeal with the state Supreme Court.

More: The Oklahoman; KGOU

SOUTH CAROLINA

Santee Cooper to Buy Nuclear Power from JEA

Santee Cooper has agreed to buy $83 million of electricity from JEA’s Plant Vogtle in Georgia. It will purchase 206 MW in 2027 and 103 MW in 2028.

Two of the plant’s four reactors were completed in 2023 and 2024, and the agreement requires all power to come from the new units.

JEA’s board was told it could expect $203 million in revenue from the agreement. JEA pays $250 million annually to buy electricity from Vogtle. The company is offsetting the energy it’s selling with new purchase agreements with Florida Power & Light.

More: The Post and Courier

SOUTH DAKOTA

Senate Nixes Carbon Enviro Studies, Eminent Domain Restrictions

The Senate voted against bills related to carbon dioxide pipelines and eminent domain restrictions.

The Senate Commerce and Energy Committee voted 5-3 to reject a bill passed by the House that would have required environmental impact studies for carbon dioxide pipelines, saying it was unnecessary. Rep. John Hughes (R-Sioux Falls) argued that an impact statement is a more accessible way to learn how a project might affect the environment than other public filings.

Elsewhere, the Senate voted 19-14 not to put a resolution on the fall ballot that would have asked voters to narrow the use of eminent domain and place those restrictions in the state constitution.

More: South Dakota Searchlight; South Dakota Searchlight

VIRGINIA

General Assembly Nixes Bills Requiring Data Centers to Get SCC Certificate

Two bills that sought to give the State Corporation Commission the authority to review how proposed high-load users — mainly data centers and manufacturing facilities — would impact the environment and energy reliability were tabled for the year.

A bill in each house would have directed the SCC to review if a proposed project that would need more than 25 MW would have an impact on rates, affect grid reliability or hinder the utility’s ability to follow environmental regulations. The bills also would have allowed the SCC to examine the environmental and health impacts a project could have on communities.

Opponents said the bills would have unnecessarily extended the building process and lengthened generation queues.

More: Virginia Mercury

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Company Briefs

Hope Gas Announces $250M Pipeline Expansion

Hope Gas said it is proceeding with a $250 million pipeline expansion in Mason County, W.V.

The first phase of the project will be the construction of a 30-mile, 24-inch natural gas pipeline. Construction is slated to begin in April 2026, with a completion date slated for the end of 2026.

More: West Virginia Public Broadcasting

Qcells Resumes U.S. Solar Panel Production After Customs Furlough

Qcells, the U.S. solar manufacturing arm of South Korea’s Hanwha Solutions, said it has returned to normal solar panel production at its Georgia manufacturing facilities.

The increased production volume closes a chapter for the manufacturer’s U.S. operations. In November 2025, the company announced a furlough of 1,000 workers due to a temporary pause in production caused by lengthy customs clearance processes.

At full capacity, the two facilities will produce a combined 8.4 GW of solar panels and components annually.

More: pv magazine

SK Lays off Nearly 1,000 Workers at Georgia Plant

Battery company SK Battery America laid off nearly 1,000 workers at a manufacturing plant in Georgia amid automakers’ changing electrification plans and uncertain consumer demand for EVs.

The company said March 6 marked the last working day for 958 employees, about 37% of its workforce, according to a Worker Adjustment and Retraining Notification.

More: The Associated Press

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PJM Plans to Release Reliability Backstop Design in April

VALLEY FORGE, Pa. — PJM has updated its thinking on the design of its reliability backstop procurement to meet rising data center load, gravitating toward a model in which the RTO would determine the amount of capacity to be purchased and act as the administrator and counterparty to the resulting agreements.

Rebecca Carroll, executive director of market design and economics, repeatedly stressed during a workshop March 4 that PJM does not have a proposal yet and will be working on its final design through at least April 10. The RTO aims to file a proposal with FERC by late May.

PJM is considering allowing data centers that procure capacity through the procurement to avoid being enrolled in its proposed Connect and Manage system, which would require them to curtail ahead of demand response resources during strained system conditions. While the amount of capacity purchased in the backstop would be determined by PJM, Carroll said the buyers may be able to submit their own preferred amount to purchase.

The procurement is intended to be a one-time measure that awards 15-year capacity commitments, possibly starting in 2030.

Core questions Carroll said PJM’s package must answer include how the RTO should balance reliability and over-procurement risks; whether changes to credit and collateral rules would be required to account for the greater risks associated with 15-year commitments; and when resources would need to be capable of coming online to participate in the backstop — with 2029 or 2030 being possible requirements.

A model in which PJM is the counterparty could pose substantial risks if either the data center or generation default, which could force the RTO to pick up the remainder of the multiyear commitment or to suddenly procure capacity for the data center. PJM presented examples of how securitization could be used to shift the risk to investors in a model similar to the bonds issued in the wake of February 2021’s Winter Storm Uri.

PJM Chief Risk Officer Carl Coscia said such a high collateral requirement would likely make any project unviable; however, the threshold should be high enough to prevent backstop participants from walking away from their commitments. The RTO’s risk provisions were designed around a three-year advance capacity auction awarding one-year commitments and are not well positioned to account for the uncertainty with 15-year obligations, he said.

Gwen Kelly, PJM senior director of credit risk and collateral management, said if the current credit policy was applied to a 15-year, 1-GW unforced capacity commitment at $400/MW-day, there would be a $662 million pre-auction credit requirement, $224 million of which would be returnable. Coscia said this accounts for deficiency charges over the 15 years.

PJM CFO Lisa Drauschak repeated that staff still do not have a proposal, and the presentation only illustrates possible pathways and outcomes.

Several stakeholders have presented their own perspectives and proposals during several workshop meetings held over the past month. (See PJM Stakeholders Begin Discussions on Reliability Backstop Design.) The workshops will be on hiatus over the next month until PJM has a complete package to present.

Many of the same sticking points dominated the discussions: how to define the amount of capacity to be procured; whether the procurement should be one-time; which resources are eligible to offer; and whether PJM, utilities or the data centers should be the counterparties to backstop commitments.

Independent Market Monitor Proposal

The Independent Market Monitor proposed a separate backstop procurement auction awarding 15-year commitments to new resources that reach agreement to serve data centers in the same locational deliverability area (LDA).

Bowring stated the key goal of any acceptable backstop auction design is to ensure that the data centers pay for the costs they impose on the system. Bowring stated that the Monitor’s proposal is the only that does not attempt to shift costs and risks to other customers and therefore the only proposal consistent with the statement of principles from the White House Office of Energy Dominance and the PJM governors.

The backstop auction would use the basic Base Residual Auction (BRA) design, modeling capacity transfer capability and limits between LDAs and providing a single clearing price up to a maximum based on the net cost of new entry (CONE) for the reference resource. Unlike the BRA, the backstop maximum price would be based on an assumed 15-year lifespan for the reference resource to match the commitment term. The contracts would cover the full cost of energy, ancillary services and capacity.

The Monitor’s backstop would not be a one-time measure and would be run after each BRA to procure capacity for data center load, which would be excluded from the standard capacity auctions. Bowring said limiting the number of backstop auctions is desirable, artificially limiting the number to one auction would counter the goal of the White House and governors to ensure that data centers pay for the costs they impose rather than shifting those costs to others. In the absence of future backstop auctions the increased demand by additional data centers would be borne by other customers, but just delayed by a year.

Seller eligibility would be limited to new generation, with no allowance for uprates, DR or resources which canceled deactivations or did not clear in the capacity market.  Bowring said this is the only way to counter the strong incentives to game the process and attempt to be designated as new.  Consumers could offer varying bids into the auction, with the highest winning if there is insufficient supply offered.

Monitor Joe Bowring said the core goal is to avoid shifting risk and costs to general load by using the auction structure to directly pair resources and data centers. Any model in which PJM or utilities would be the counterparty would risk requiring other customers to pick up the commitment if the data center defaults. He referenced the ratepayer protection pledge large tech companies signed on March 4, which states they will avoid shifting the costs of their interconnection and service onto other customers. (See Trump Gets Tech Execs to Sign ‘Ratepayer Protection Pledge’.) Bowring stated that the pledge is a good model for all data centers.

Data centers larger than 5 MW would be required to participate in the backstop or be subject to curtailment similarly to PJM’s Connect and Manage proposal. PJM would work with electric distribution companies (EDCs) to identify the data center customers behind large load adjustments (LLA) the utilities submit for inclusion in PJM’s load forecast. The purpose of the comparatively cutoff for data centers is to prevent gaming by adding incremental load to a data center in order to avoid the rules.

GQS New Energy Strategies Principal Pamela Quinlan, representing the Data Center Coalition, said it would be a difficult task to tie LLAs to specific customers and seeking to allocate costs to a class of consumers based on how the electricity is used would be undue discrimination.

Bowring responded by saying the capacity shortfall PJM is facing is due to data center load growth, so the costs to mitigate those reliability risks should be assigned to those customers. Bowring said that costs must be directly assigned to data centers in order to prevent costs from being shifted to other customers.

“This is not an allocation to a class of customers. It is a direct assignment via a bilateral contract between willing participants that covers all the mutual risks in the contract. The concept of allocation means that the costs could be reallocated to other customers if a data center fails,” he said in an email to RTO Insider. “The idea that it is difficult for large corporations to reach a bilateral deal is far fetched.”

She argued the Monitor’s analysis assumes available capacity would remain the same in the absence of data center load growth, ignoring the likelihood of resources deactivating without that growth.

Quinlan said using a 15-year net CONE to set the maximum price, on the grounds that the commitment term would be 15 years, misses that resources could participate in PJM’s other markets after the commitment has expired.

Bowring responded that the basic BRA would have higher prices and would continue to attract the capacity needed to meet the needs of other customers. “As our analysis has shown, the current crisis in the capacity market is a result of data centers and not the organic growth of other customers.” It is fine that data centers participate in PJM markets at the end of the 15 year contracts.

“The proposal from the Data Center Coalition would have PJM serve as the counterparty. This means that the data center risk would be imposed on other PJM members. That is inappropriate and inconsistent with the basic goal of a backstop auction to address the costs imposed by data centers. It is not a general concern to be put off to the uncertain future but must be a core element of any backstop proposal,”he said in an email.

Data Center Coalition

Quinlan presented a set of priorities the Data Center Coalition believes should be incorporated into PJM’s design, centering around the position that the RTO should not make substantial changes to the capacity market while designing a one-time procurement structure.

The coalition recommended a backstop design in which PJM would be the counterparty and limited to participants which could be in service for the 2028/29 delivery year, with some allowance for the following year. The RTO’s design should not seek to determine resource adequacy for specific load-serving entities or use “uncertain” long-term forecasts to determine the need for capacity.

Concurrent with the procurement, the RTO should initiate a comprehensive review of the capacity market design, including improvements to load forecasting and consideration of “LSE-based frameworks,” Quinlan said.

Responding to questions on how the risk of a data center default could be managed, Quinlan said risk allocation is an important question to consider, but one that should be part of a long-term discussion. The ideal way to manage the risk associated with multiyear commitments is to ensure that the backstop is a short-term measure that buys time for more substantial market changes, she said.

Quinlan said the coalition considered ways of allocating costs that did not fall to LSEs, but there are practical questions on implementation and whether that can be accomplished in time for a May filing.

Google

Google recommended PJM adopt a backstop in which it procures capacity on behalf of load and allocates the costs across the region, leaving it to states to develop end-user rates. While the company shared several design components it prefers, it stated it does not have a complete proposal.

The company expressed support for one-time solution targeting a specific delivery year with well defined needs, leaving long-term capacity commitments as a separate issue. The backstop should focus on a fuel-neutral framework for incentivizing high-accreditation resources, with the capacity to be purchased defined by the deficiency in a particular auction — rather than targeting individual customers or a class of end-users.

Joint Stakeholders

A cohort of generation owners presented a backstop focused on meeting the shortfall expected for the 2028/29 BRA, scheduled to open in June 2026. The proposal was signed onto by Constellation Energy, Vistra, AlphaGen and Earthrise.

The one-time auction would be conducted in September and mirror the 2028/29 BRA clearing price for commitments up to 15 years. Resource offers would clear first based on the delivery year in which the project can come online, then by the length of the commitment term the offer requested. Procurement would be capped at the reliability requirement for the 2028/29 delivery year.

Seller eligibility includes new resources, uprates, DR, reactivated resources and existing resources that cleared above the maximum price in the 2028/29 auction.

Constellation’s Erik Heinle said the proposal is agnostic on how costs would be allocated, though it specifies that it would respect bilateral contracts. The risk of over-procurement and large loads not coming online would be managed by restricting procurement to load that is already accounted for in the capacity auction through capping the amount purchased at the reliability requirement for the 2028/29 delivery year.

Voltus

Voltus advocated for PJM allowing behind-the-meter capacity to participate in the backstop, arguing behind-the-meter resources have some of the quickest development times — making them well suited to a process intended to rapidly bring on new capacity.

Senior Manager of Regulatory Affairs Kimaya Abreu said PJM should be focused on procuring new capacity from resources not receiving a sufficient price signal from BRAs. That effort would be best served by taking a tech-agnostic approach which allows behind-the-meter capacity to participate. Not allowing DR, behind-the-meter storage, and other DERs’ participation would run afoul of requirements that BTM resources be treated comparably to generation, outlined by FERC in orders 719, 745, 841, and 2222.

Voltus argued including behind-the-meter resources in the backstop is consistent with proposals stakeholders made throughout the 2025 Critical Issue Fast Path process focused on meeting large load growth, as well as the statement PJM’s Board of Managers released at the conclusion of the process. (See PJM Board of Managers Selects CIFP Proposal to Address Large Load Growth.)

The company also endorsed a proposal by the Natural Resources Defense Council to define new capacity, which would allow resources that have completed the third phase of the interconnection process, or are in the surplus interconnection service process, to qualify so long as they are not already subject to the capacity must-offer requirement. For DR, resources that did not offer into the capacity market between the 2025/26 and 2027/28 auctions would be permitted, as well as those seeking to increase the amount of capacity offered.

NRDC

The NRDC’s proposal included an auction design in which capacity would be procured for a pool of buyers that would share the costs and risks, while sellers would receive 10- to 15-year commitments. If participating consumers default or do not come into service, either the capacity payments would be reduced, or the remaining load would pay more. The auction would be a permanent addition to the capacity market, conducted during each queue cycle’s final agreement phase. For Transition Cycle 2, this would be December 2026 or the following month.

Participating resources would be required to offer into BRAs during their commitment terms, with the revenues flowing to load with long-term commitments, which would also be responsible for capacity deficiency penalties. The auction would be open to large loads as well as LSEs seeking to offer long-term firm service to new customers.

The maximum procurement would be set at the amount bid into the auction, and any load that does not receive a commitment would be required to go through PJM’s proposed Connect and Manage system.

Eligibility would be limited to projects that have already cleared the interconnection queue but not yet entered service, as well as DR. The NRDC said the backstop should not be allowed to become another expedited interconnection queue following the example of the Reliability Resource Initiative, which allowed 51 projects to be inserted into TC2. Several of those projects have dropped out of the queue after running into high network upgrade costs.