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December 8, 2025

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MISO Eschews Latest Data to Limit CONE Increase for 2026

Inflation and higher borrowing costs pushed MISO’s cost of new entry up by about 5% heading into the 2026/27 planning year, but stakeholders are questioning the RTO’s use of 2020 data in calculations in order to keep prices lower.

This year, MISO’s cost of new entry (CONE) varies from $142,970/MW-year in Missouri’s Zone 5 to $123,250/MW-year in Mississippi’s Zone 10. On average, the 2026/27 CONE is almost $359/MW-day, higher than the roughly $341/MW-day used in the 2025/26 capacity auction and the $330/MW-day used during the 2024/25 planning year.

CONE is the annualized, capital cost of building a power plant. In MISO’s case, the RTO calculates values per local resource zone and uses them to establish price caps in its capacity market.

MISO used data from the U.S. Energy Information Administration’s (EIA) 2020 Capital Costs Report for its hypothetical, advanced combustion turbine example instead of relying on the agency’s new figures from the 2024 report.

The RTO said it wanted to stick with its usual, theoretical 240-MW simple cycle plant instead of the EIA’s new norm, which would more than double the size of the example plant. The RTO upped the cost of the 2020 plant to reflect inflation.

Joshua Schabla, senior market design economist at MISO, said the RTO didn’t meaningfully alter its CONE calculations this year but probablywould change them by the time it crunches numbers again in 2026.

MISO said it plans to change the reference technology used for its power plant example for the 2027/28 planning year. Schabla said MISO plans to begin discussing its new CONE resource reference beginning in November. (See Transition Spurs Power Producers to Ask for Fresh Look at MISO Cost of New Entry.)

Some stakeholders attending an Oct. 1 Resource Adequacy Subcommittee meeting said MISO should have used more up-to-date information to inform CONE. By not upping its reference prices to reflect the true state of the industry, MISO could risk its reliability, they said.

Representing the Coalition of Midwest Power Producers, Travis Stewart expressed concern that MISO’s reliance on 2020 data is “inconsistent with market signals that we’re hoping to create.”

“New gas turbines are two to three times more expensive than they were a year ago. That information should report back to the market. The objectivity of this is important,” Stewart said. He added that he worried that consumer advocates could draw on MISO CONE values to argue against cost recovery proposals for new generation in public service commission proceedings, since prices would not match.

Pelican Power’s Tia Elliott said MISO possibly was setting itself up for a “wide spread” between it and other grid operators.

However, Anna Sommer, principal at the Energy Futures Group, said she appreciated MISO being cautious before making “major” changes to CONE. She said because MISO’s capacity auction is a prompt-year auction and most member utilities are vertically integrated, the capacity auction should not be considered a source for long-term planning signals.

Schabla said MISO didn’t want to impose “supply shocks” on the market if they’re not going to last, adding that the RTO wanted to avoid publishing high prices only to have to downgrade them in ensuing years. He said there have been questions over the legality and the longevity of the tariffs imposed by the Trump administration. Had MISO incorporated all variables, CONE might have risen by a factor of two or three, Schabla said.

“It’s a little too early for us to make a decision like that and factor that into the price caps,” he said.

Werner Roth, economist with the Public Utility Commission of Texas, said had MISO produced numbers as much as three times higher than in 2024, governors of MISO states would have reacted poorly and made PJM’s continuing fallout over record-high capacity prices look like a “pillow fight.”

Schabla said he thought wildly volatile numbers year-over-year would be worse than not drawing on the freshest data available.

“Stability matters,” he said.

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FERC Identifies 53 Regulations to Sunset in Response to Trump E.O.

FERC issued a final rule and related Notice of Proposed Rulemaking on Oct. 1 to start “sunsetting” 53 outdated, seldomly used and duplicative regulations in response to an executive order from President Donald Trump (RM25-14).

Issued in April, the executive order, “Zero-Based Regulatory Budgeting to Unleash American Energy,” directed FERC and other energy-associated agencies to conditionally sunset regulations in an effort to trim the Code of Federal Regulations, which approaches 200,000 pages and “has imposed particularly severe costs on energy production.” (See FERC Faces Challenge in Balancing Executive Order and Legal Requirements.)

“Today’s steps are a common-sense commitment to a fast and fair regulatory process,” FERC Chair David Rosner said in a statement. “Periodically reviewing, updating and streamlining the commission’s regulations helps ensure that they continue to align with our statutory mandates and are focused on high-value activities that strengthen our nation’s energy system.”

The final rule gives parties a chance to comment on each of the 53 identified regulations, and if parties file “significant adverse comments” against sunsetting any of them, they would go into the NOPR proceeding, in which FERC can respond to those concerns.

A direct final rule is a way to expedite rulemakings and is used for noncontroversial regulatory amendments, allowing an agency to issue a rule without having to go through the review process twice (a NOPR first, then a final rule). The public still gets a chance to challenge the agency’s view that its proposed changes are not controversial.

“Because the commission does not anticipate significant public comments on this rulemaking and considers it to be noncontroversial, the commission is using the ‘direct final rule procedure’ for this rule,” FERC said.

If FERC gets any significant adverse comments on any part of the direct final rule, then it will publish a document removing any such part of the action and address them via the NOPR process.

The commission defines an adverse comment as one where a party explains why the action, or part of it, would be inappropriate, including challenges to its underlying premise, or how it would be ineffective or unacceptable without a change. Comments would have to provide a reason sufficient to require FERC’s substantive response in the notice-and-comment process.

FERC will have to respond if a comment causes it to re-evaluate or reconsider its position and to conduct additional analysis; if it raises an issue serious enough to warrant substantive response or to clarify/complete the record; or if it raises a relevant issue the commission had not previously addressed.

The sunsetting of each of the 53 regulations works independently so if any are moved into the NOPR proceeding, FERC can go ahead and sunset the noncontroversial rules.

The executive order gave FERC an independent justification for starting the rulemaking, but FERC noted that it did not direct the commission to rescind or reissue any particular regulation, nor alter its statutory responsibility to issue, alter or rescind rules in line with its core mission of ensuring reliability in an economically efficient manner.

“The commission has further determined, based on its independent policy judgment, that the sunset rule adopted herein is appropriate,” FERC said in the final rule. “Regulatory housekeeping, including streamlining and updating our regulations, helps ensure that they align with our statutory mandates, thus alleviating regulatory burdens and allowing regulated industries to focus more deliberately on the types of high-value projects that will augment and strengthen the nation’s energy supplies.”

The actual regulations proposed for sunset run the gamut of FERC’s authority, and many of them have not been used in decades.

One covers “regional transmission groups,” which have long since been replaced by ISOs and RTOs, FERC said. The commission proposed to remove “ratemaking treatment of the cost of emissions allowances” because most generators recover those costs through market-based rates.

One rule up for sunset implements the Powerplant and Industrial Fuel Use Act of 1978, which required power plants to switch from oil and natural gas to coal but was repealed in 1987. Gas-fired power plants have been the largest source of generation for years.

FERC also proposed to sunset rules on obsolete procedural and filing requirements such as requiring paper filings, which are no longer in general use at the commission.

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D.C. Circuit Upholds FERC Approval of TVA’s Cumberland Switch to Gas

The Tennessee Valley Authority is closing in on a gas-for-coal swap at its Cumberland plant after the D.C. Circuit Court of Appeals rejected environmental groups’ arguments against FERC’s environmental review (24-1099).

The court concluded that FERC met its due diligence under the National Environmental Policy Act and the Natural Gas Act and denied the Sierra Club and Appalachian Voices’ petition.

TVA plans to retire the pair of coal units at its 2,470-MW Cumberland Fossil Plant and replace one with a 1,450-MW natural gas turbine, which would draw on a new 32-mile pipeline built by Tennessee Gas Pipeline.

Sierra, joined by Appalachian Voices, filed a lawsuit over FERC’s assessment of the project, arguing the commission incorrectly credited the pipeline with aiding emissions reductions, conducted a flawed “no-action alternative” analysis, and should have evaluated the plant and pipeline as connected elements (CP22-493). (See TVA’s Cumberland Coal-to-gas Plans Press on over Resistance.)

The group argued that TVA would retire coal generation regardless of the gas turbine construction. But the D.C. Circuit drew on TVA’s wording that absent a replacement generation source, it “would need to continue operating the coal-fired units.”

The court said FERC did not slip up when it grouped the coal unit retirement and emissions from the new gas turbine in its downstream emissions analysis. It also said FERC properly considered the pipeline essential to the project.

Sierra also contended FERC should not have attributed the gas unit with emissions offsets beyond 2035 because that is the latest year Cumberland coal units would operate. It said FERC incorrectly used a decade of emissions comparison from 2036 through 2045.

The court responded that TVA’s plans “do not exist in a vacuum.”

“Without a replacement generation source with requisite fuel, the TVA might instead upgrade and operate the coal-fired unit well into the future, as the TVA’s no-action alternative contemplated. So even though the TVA hopes to replace its coal-fired units by 2035, FERC made the reasonable choice to credit the pipeline with a net emissions reduction covering the entire forecast period,” the D.C. Circuit said.

“Could FERC have taken a different approach? Perhaps. But we must ‘defer to agencies’ decisions about where to draw the line’ in their analyses of ‘indirect environmental effects,’” the court said, citing previous case law.

The court likewise brushed aside Sierra’s concerns that FERC estimated emissions annually rather than cumulatively. It said “anyone with a calculator — or the ability to perform basic addition” — could perform the conversions and characterized the omission as a “harmless error” at worst.

The court also said the group could not have it both ways by arguing that the pipeline would cause downstream emissions while simultaneously claiming it would not help ease emissions by making a coal retirement possible. It added that it could not criticize FERC for “reasonably” assuming that the gas turbine would be built even if the 32-mile pipeline were rejected.

The D.C. Circuit said FERC properly decided there was a market need for the project because of TVA’s 20-year agreement with Tennessee Gas to purchase all pipeline capacity. The court pointed out that TVA and Tennessee Gas are not affiliated, and Sierra did not allege self-dealing.

The court disagreed that FERC should have better scrutinized the market need for the pipeline because TVA is not state-regulated.

“Though the TVA is not subject to state supervision, it is hardly a rogue entity. The TVA must follow a statutorily prescribed ‘least-cost planning’ framework in making investment decisions; it is subject to congressional oversight and must annually notify Congress of any ‘major new energy resource’; and its investment decisions are subject to public notice and comment,” the D.C. Circuit said.

The court ruled that FERC was not obligated to contemplate evidence about clean energy subsidies accessible under the Inflation Reduction Act or weigh TVA’s choice of natural gas over a renewable alternative, as Sierra argued.

“The Sierra Club is entitled to the expansive view of NEPA … and it is free to argue for robust judicial scrutiny of environmental impact statements. But the Sierra Club’s understanding of NEPA is not shared by the Supreme Court,” the D.C. Circuit said.

The court said the Supreme Court “repudiated” similar arguments raised in 2025’s Seven County Infrastructure Coalition v. Eagle County, Colorado, a case centered on approval of an 88-mile railroad line connecting Utah’s oil-rich Uinta Basin to the national freight rail network.

“After Seven County, the era of searching NEPA review is over — or at least it should be,” the court said.

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PacifiCorp Asks WPP to Delay WRAP ‘Binding’ Phase Commitment Date

PORTLAND, Ore. — PacifiCorp has asked the Western Power Pool’s Board of Directors to allow Western Resource Adequacy Program participants to defer their decision to commit to the program’s binding phase by at least one year, saying the emergence of day-ahead markets in the West and other developments warrant reconsideration.

Following a question during a panel discussion at a Western utility conference about PacifiCorp’s position on WRAP, Michael Wilding, vice president of energy supply management at PacifiCorp, said WRAP “is an incomplete product.”

“We see the value in the regional coordination,” Wilding said at the fall joint meeting of the Committee on Regional Electric Power Cooperation and Western Interconnection Regional Advisory Body (CREPC-WIRAB) in Portland. “We want to continue to work with the region. But right now, we need … some time to evaluate where the program’s going.”

Wilding’s comments came in response to a question about a letter issued by PacifiCorp on Sept. 30 in which CEO Cindy Crane said moving forward with the current Oct. 31 commitment date “would be imprudent and not in the best interest of our customers.”

The letter came one day after WPP announced that WRAP is moving forward with the first binding season in winter 2027/28 after receiving commitments from a “critical mass” of participants. (See related story, WRAP ‘Binding’ Phase Set for Winter 2027/28 After Utilities Affirm Commitment.)

Crane noted in the letter that work by the WRAP Day-Ahead Market (DAM) and Planning Reserve Margin (PRM) task forces highlights developments that have emerged after WRAP was formed and that the program must now adapt to.

For example, the DAM Task Force is developing a proposal aimed at realigning WRAP’s “operational subregions with the footprints of CAISO’s [Extended Day-Ahead Market] and SPP’s Markets+, replacing the legacy MidC/SWEDE structure,” the letter stated.

“This would fundamentally change how capacity planning, the operational program, and the settlement of holdback and energy deployments are managed,” according to Crane.

Additionally, the PRM Task Force is considering new tools for setting planning reserve margins, which could impact participants, Crane contended.

“Active discussions are occurring relating to mechanisms to defer deficiency charges for entities making strategic investments in new resources, recognizing the need for flexibility as the region transitions to new market structures,” according to the letter.

Crane urged the board to defer the binding decision by at least one year to implement changes and allow for further stakeholder input.

WPP told RTO Insider that the organization’s board and staff are reviewing the letter.

WPP launched the WRAP in response to industry concerns about resource adequacy in the West.

Under the program’s forward showing requirement, participants must demonstrate they have secured their share of regional capacity needed for the upcoming season. Once WRAP enters its binding phase, participants with surplus capacity must help those with a deficit in the hours of highest need. (See WRAP Task Force Explores Optimization for Day-ahead Markets.)

The binding phase also includes penalties for participants that enter a binding season with capacity deficiencies compared with their forward showing of resources promised for that season.

In 2024, the binding phase was postponed by one year at the request of participants, who said they were facing challenges including supply chain issues, faster-than-expected load growth and extreme weather events that would make it difficult for them to secure enough resources and avoid penalties. WRAP members voted in September 2024 to delay the binding phase until summer 2027, but that date was pushed forward. (See WRAP Members Vote to Delay ‘Binding’ Phase to Summer 2027.)

‘Some Folks Will Leave’

Speaking on a separate Oct.1 panel at the CREPC-WIRAB conference, WPP Chief Strategy Officer Rebecca Sexton did not mention the PacifiCorp letter, but acknowledged the challenges facing the WRAP, saying the program is “living in a world of dichotomies” in which “lots of things are true at the same time.”

“We are in a resource adequacy crisis, and we also have utilities who are working really hard to close the gap, working really hard, and it feels like the goalposts keep moving with all of these challenges,” she said.

In her presentation, Sexton spelled out the top five challenges facing WRAP members — many of which had been cited by participants in their previous request for a delay, including: “significant” load growth, supply chain constraints for project developers, interconnection delays for resources, resource retirements and fuel supply issues.

Sexton said part of the program’s “value proposition” is its binding forward showing, which tells participants how much capacity they must bring to the table to meet regional needs. The binding operational program is the other part, enabling participants with surpluses to assist those with deficits in the hours of highest need.

“So when the operating time horizon is similar, we motivate the participants to deliver to each other. If you’re having a better day than planned, then you might get an obligation to deliver to someone who’s having a worse day than planned,” Sexton said.

She pointed out that while participation in the WRAP is voluntary, once committed, participants are expected to meet their obligations to avoid a “tragedy of the commons situation” in which some participants lean too heavily on others to meet their own needs.

Sexton noted that WRAP participants are working “to evolve the program to make sure that it’s one they want to stay in” and “that they think is really solving this regional need.”

She pointed to various WRAP efforts, including stabilizing planning reserve margins to make them more predictable and working to “best integrate” with day-ahead markets to optimize delivery, which she called a “real opportunity” for the program.

But Sexton acknowledged yet another “dichotomy” facing WRAP: that “the reason why we need the resource adequacy program is also increasing, and it’s really challenging to subject yourself to this voluntary compliance program and get the resources in place to meet the metrics.”

“So we are having conversations [with participants]. We expect that some folks may not stay in the program. We know some folks will leave,” she said.

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Solar Dominates CPUC Tx Plan Recommendations Despite Cost Increases

The California Public Utilities Commission is recommending the state build another 68.5 GW of new solar generation resources by 2045, despite new tariffs on imported goods and the planned elimination of certain federal tax credits that will increase the cost of renewables.

The CPUC’s new order instituting rulemaking (R 25-06-019) issued Sept. 30 includes the agency’s 2026/27 Transmission Planning Process (TPP) base case energy resource portfolio, which CAISO will use to help decide what new transmission infrastructure is needed in the state.

Build rates for solar resources in California have averaged between 1 and 3 GW/year, but the base case portfolio calls for build rates between 4 and 7 GW/year going forward.

The largest amount of new solar generation in the base case — about 19 GW — would be built in San Diego Gas & Electric’s and Southern California Edison’s “Arizona” region.

The additional energy resources and accelerated build rates stem from the California Energy Commission’s 2024 Integrated Energy Policy Report (IEPR), which showed higher demand and peak load than the 2023 IEPR, the ruling says. The state now needs up to 30 GW more capacity than estimated in the 2025/26 TPP.

In the ruling, stakeholders told the CPUC that the elimination of certain tax credits associated with renewables will have “negative cost impacts on ratepayers.”

Utility-scale solar is expected to see a levelized cost increase of 73 to 90% due to the elimination of the federal investment tax credit and production tax credit, while levelized costs for onshore wind are expected to rise 14 to 150%, the order says.

The CPUC’s model assumed that wind and solar tax credits will end, specifically for projects that are not under construction by July 4, 2026. Energy storage and clean firm technologies retain tax credit eligibility through 2032, the order says.

RTO Insider asked the CPUC why its resource model recommended such a significant amount of additional solar generation despite the increasing costs.

“Though [the model] now accounts for the large increasing cost of solar due to new tariffs and tax credit eliminations, there are also increases in cost for other candidate resources,” the CPUC responded. “Overall, the cost of the energy transition has increased due to the loss of the tax credits. Despite recent cost increases, solar energy remains a competitive avenue for reaching the state’s clean energy goals and steadily growing demand.”

As for tariff impacts, solar generation and lithium-ion battery storage will see the largest cost increases because most of their components are built in China and Southeast Asia, the order notes. The model’s resulting weighted average tariff is 29% for onshore wind, 70% for utility-scale solar and 122% for lithium-ion battery storage, the ruling says.

The battery storage supply chain is uniquely dependent on imports from China, which is subject to some of the highest tariffs overall under current federal policy, the ruling says. The CPUC’s resource model assumes that the current tariff policy will last through 2029. However, the model does not consider the fact that China has been flagged as a foreign entity of concern.

Wind and Other Portfolios

In the base case portfolio, out-of-state wind capacity needed by 2045 came in at 19 GW — the second largest volume of new resources, behind solar. In-state wind finished in third place for needed generation resources, totaling 7.7 GW by 2045.

Additional battery storage resources came in at about 25 GW in the base case portfolio.

The rulemaking also included a “least-cost” resource portfolio, which recommended slightly more solar generation — 71.5 GW.

And the ruling included a “limited wind” sensitivity portfolio, which the CPUC built due to the “recent lack of wind development in California, the recent increased difficulty of permitting wind in California and the recent changes in federal policy toward wind projects,” the rulemaking says.

The limited wind portfolio is not intended as a policy preference but rather is meant to show transmission capacity needs if less wind capacity is built in the coming years, the ruling says. Offshore wind shows 0 GW in this portfolio, whereas in the base case portfolio, California is projected to have 4.5 GW of offshore wind by 2045.

Solar needs soar to 83.2 GW by 2045 in the limited wind portfolio.

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N.Y. Working on Ecosystem to Support Advanced Nuclear Generation

A state-sponsored summit sought to position New York to benefit from next-generation nuclear power and design the ecosystem to support it.

The Sept. 30-Oct. 1 event in Syracuse reflects the state’s growing interest in advanced nuclear technology and its promise of emissions-free baseload power.

The event was a follow-up to 2024’s Future Energy Economy Summit, and one need only look at the title of this year’s edition — Advanced Nuclear NY Summit — to see the state’s evolving focus.

It is a focus that would have seemed unlikely in the Democratic-led state just a few years ago. Even now, there remains significant opposition to extending the operating life of existing nuclear plants in New York or building new ones. A contingent of protesters parked itself outside the 2025 summit, just as in 2024.

But with construction of other emissions-free power generation lagging behind state goals, the aging of existing fossil generation and expectations for steadily increasing load on the New York grid, Gov. Kathy Hochul (D) and her regulatory/policymaking agencies are emphasizing new nuclear power more as part of the solution.

Earlier in 2025, Hochul directed the New York Power Authority to develop at least 1 GW of new nuclear generation. And the state is setting the stage for continued subsidies to prevent retirement of four aging commercial reactors that supply about one-fifth of the state’s power and two-fifths of its carbon-free power.

The New York State Energy Research and Development Authority was created in 1975 when the state reconstituted its Atomic and Space Development Authority; 50 years later, NYSERDA remains the state’s liaison to the U.S. Nuclear Regulatory Commission, and it is leading the state’s advanced nuclear initiative.

On the eve of the summit, NYSERDA President Doreen Harris spoke with NetZero Insider about the state’s goals and progress. The interview has been edited for brevity.

Q: What is NYSERDA’s role in moving New York forward with nuclear energy?

A: All state agencies are involved, but NYSERDA’s major directive is to advance the master plan and take the lead as the coordinator. “Our job is to really look at the broader needs, not just the outcome of a project, or projects, but also the broader ecosystem necessary to get from here to there.” That includes everything from community acceptance to workforce development to technology advancement.

Q: Will NYSERDA take a direct role in technology development?

A: Not supporting prototype development — that is usually through the national laboratories. NYSERDA’s role is more to assess the technologies being developed, then help push to standardize and scale them. Toward this end, New York is a co-lead in the Advanced Nuclear First Mover Initiative of the National Association of State Energy Officials. NYSERDA does have an innovation portfolio that can assist with some aspects of technology development.

Q: New York is pursuing an early role with advanced nuclear; does that carry a high technological or financial risk?

A: Not if the state pursues it correctly. “That’s exactly the whole point of this, the First Movers Initiative being a great example.” The goal is to lead efforts toward standardization and scaling while not being on the bleeding edge.

Q: Do you see a particularly stubborn obstacle to new nuclear generation in New York?

A: Community acceptance is important. “We’ve been quite clear, as has the governor, that we are looking for communities that are not only accepting, but welcoming of the projects that would ensue.” Also important: “The question of not just how to pay for these projects, but who pays and how are those costs recovered? I think it will add a level of complexity to advanced projects in this market.” For that reason, the state’s economic development arm and its power utility cohosted the 2025 summit.

Q: What is your takeaway on progress in the year since the 2024 summit?

A: “Really, we’ve made extraordinary progress as a state, not just the actual master plan that is now fully underway, but also the governor’s 1 GW-plus NYPA directive. … The focus of this summit is on economic development, on supply chain and on workforce opportunities. These are both challenges and opportunities for the state of New York to meet the moment.”

Q: Some observers worry that the Trump administration’s rush to deploy advanced nuclear designs will lead to compromises in regulatory oversight. Do you?

A: New York wants to see the federal government put full effort into advancing nuclear technology and helping states get it off the ground, but not at the expense of safety. It will continue to assess that checks and balances are preserved as it does this. “We need this to move from concept to application, but in a measured way, and that balance will continue to need to be refined.”

Q: What about you personally? What do you see in all this as an engineer?

A: Harris is excited about the technological capabilities and safety mechanisms of advanced nuclear. “It’s a far cry from the reactors that I worked on as a young engineer and … it’s reflective of really how central innovation is to the energy transition.”

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R Street Scorecard Ranks All 50 States on Electric Competition Policies

The R Street Institute has ranked the states on their embrace of policies related to competition, which includes retail power markets, RTO membership, smart metering policies and friendliness to distributed resources.

The scorecard gives the best grade to Texas, with most customers in ERCOT’s territory shopping for their electricity providers, but even it was left at an “A-” because the retail market does not extend to municipal utilities, co-ops or the utilities outside the grid operator’s territory.

On the other end of the scale is unranked Nebraska, where consumers are completely served by public utilities and the report’s authors lacked access to data to give it a ranking. Alabama was given the lowest grade — the only “F” — as no real competition exists at any level. It also scored low on other metrics like smart meter data and consumer engagement.

“What we want to accomplish with the release of this report and the scorecard is to help policymakers at the state level better understand what are the policy opportunities and what are some of the challenges in given jurisdictions regarding the enablement of more competitive practices in a given jurisdiction,” Chris Villarreal, R Street associate fellow and report co-author, said during a webinar presenting the report Sept. 30.

The report explains every state’s grade, including areas where they can improve, which is possible for even the best-ranked states, Villarreal said.

Other highly ranked states are retail restructured jurisdictions in the Northeast and Midwest, with D.C., Illinois, Ohio and Pennsylvania all getting a “B+.” Delaware, Maine and Rhode Island each received a “B,” and Massachusetts, New Hampshire and New Jersey a “B-.”

The “C” states include a mix of retail restructured states, including some like Maryland or New York that would have ranked higher in years past but have fallen because of policy changes. Maryland recently shut down its retail market for residential consumers, while New York has for years capped retail prices based on a backward-looking, 12-month rolling average of utility rates.

One issue with Maryland is that while the Public Service Commission has started to more actively police bad actors in the retail market in recent years, for a long time it took a light approach to ensuring the market ran fairly, which is one of the metrics the report card uses to rank restructured states, R Street Senior Fellow Kent Chandler said in the webinar.

“Maybe it was too little too late … holding some of those bad actors accountable really did contribute to the ultimate public policy shift there in the legislature,” he added.

NRG Energy Vice President of Regulatory Affairs Travis Kavulla agreed with that assessment. (His company serves about 8 million customers in competitive markets around the country, and as a Maryland resident, he has a grandfathered long-term contract from the market.)

Another issue is that the more successful states try to keep their consumers actively informed, such as by requiring multiple notices that a long-term, fixed contract is expiring and customers need to pick another option or they could automatically be shifted to a provider of last resort with more volatile prices, Kavulla said. Some other state commissions, like Pennsylvania’s, issue notices to consumers that utility rates are about to go up and consumers can shop for a better deal.

“So now, ironically, basically all residential customers in Maryland, except for people like me, who have grandfathered long-term contracts, are basically strapped to the roller coaster of volatile wholesale energy market pricing, which interestingly, is giving Maryland legislators heartburn that they could have prevented by encouraging more active shopping and more long-term contracting,” Kavulla said.

Other states with mixed grades do not have any experience with retail markets, but they have taken moves to join an RTO like some western states, or they have very good policies around distributed energy resources, such as Hawaii.

Just before the report was finalized, Utah was about to join Alabama at the bottom of the pack, but its legislature passed Senate Bill 132, which allows more competitive options for large loads, noted Josh Smith, energy policy lead for the Abundance Institute. The law shifts the uncertainties around the future of large loads from data centers looking around for quick and affordable access to the grid away from captive ratepayers.

“There’s this kind of uncertainty that ratepayers should not be on the hook for,” Smith said. “Instead, that should be something that Google or Meta, or anyone else can check up with a company. … There are lots of these guys who can provide that. And that’s the first step that Utah took … in addition to enabling some very niche, I think, but exciting private grid options within the legislation.”

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U.S. Energy Agencies Lay out Plans for Federal Government Shutdown

The federal government officially shut down as the clock turned to midnight Oct. 1 after the two parties failed to agree on a spending package to keep it open at the start of fiscal year 2026.

While Democrats and Republicans both blamed each other for the impasse, federal agencies released plans to keep vital employees working and to furlough others, at least once any existing funds are exhausted. For now, both FERC and the Department of Energy have some leftover funds from the previous fiscal year, so they can operate normally, but they will wind down most operations if the shutdown lasts too long.

FERC’s plan allows it to use leftover funds and will keep it running with all 1,478 employees working. Once that runs out, however, just 60 employees and 18 contractors who are needed to “protect life and property” will remain working, it said.

“It is anticipated that there would be no disruption to FERC operations during a short lapse in appropriations of one to five days,” the plan says. “FERC has historically had sufficient previously appropriated funds that remain available to support operations during a short-term lapse. In the event of a lapse extending beyond one to five days, FERC will continue operations using balances from prior years until exhausted.”

If the funding is exhausted in a lengthy shutdown, FERC will continue to inspect hydropower dams and LNG projects under construction for safety. It will monitor the reliability of the bulk power system and threats to energy infrastructure. Some remaining employees will monitor jurisdictional energy markets and offer legal advice to commissioners.

The commissioners are presidentially appointed and Senate-confirmed, so they will continue working, and the office of the secretary of the commission will remain open to release any formal actions publicly.

“Federal employees in offices with funding for salaries continue to report for work as scheduled,” DOE’s plan says. “A prolonged lapse in appropriations may require subsequent employee furloughs. If there is an imminent threat to human life or protection of property, a limited number of employees may be recalled from furlough status.”

Like FERC, DOE has historically remained fully open during short lapses of funding that last just one to five days, and if the money runs out, it has been able to wind down operations in half a day.

The department has 15,523 employees, though that was already scheduled to fall to 13,812 at the start of FY26 on Oct. 1 because of the buyouts the Trump administration offered federal workers early in 2025. An additional 1,409 employees are taking the buyout effective Dec. 31, and 71 others have already left.

The Bonneville Power Administration is self-funded, and its 3,266 employees can keep working with regular pay, though 192 were scheduled to leave on Oct. 1 because of the buyout.

“The other power marketing administrations (Southeastern Power Administration, Southwestern Power Administration [and] Western Area Power Administration) will perform functions related to the safety of human life and the protection of property by engaging in controlling and directing power to utilities, transmission of power and repair of the power transmission system,” DOE says in its plan.

The Nuclear Regulatory Commission has already started to wind down operations under its plan.

“The NRC has some appropriations for performing high-priority activities, such as operator licensing, time-sensitive licensing actions and activities related to recent executive orders, with a core group of employees,” the agency’s plan says. “When NRC appropriations no longer support other high-priority activities, the NRC plans to operate at a reduced level for some period of time and to begin a minimal maintenance and monitoring mode in which the NRC will continue to carry out its responsibility to protect public health and safety.”

The law firm Holland & Knight posted a summary and links to other federal agencies’ plans for the shutdown.

The Maryland Public Service Commission issued a notice saying that utility disconnections are forbidden for any federal workers in the state, noting that Gov. Wes Moore has reminded utilities of that rule.

The White House’s Office of Management and Budget and Office of Personnel Management said that federal employees can expect to be paid on time for work through Sept. 30.

The Government Employee Fair Treatment Act of 2019 requires that all employees, including those who are furloughed, get back pay for the shutdown once it ends, though POLITICO reported Sept. 24 that OMB could try to fire many federal employees during a shutdown.

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Gas Industry Sees Political Opportunity in New England

MARLBOROUGH, Mass. — Speaking at an industry conference Sept. 30, representatives of major gas pipeline companies said they are optimistic that political shifts at the federal and state levels will create opportunities for gas infrastructure expansion in New England.

Panelists at the Northeast Energy and Commerce Association’s annual Fuels Conference emphasized the importance of reducing the region’s gas constraints to alleviate affordability and reliability concerns, while downplaying climate concerns about long-term reliance on natural gas.

“After decades of disagreement, a lot of key states are coming around, and a lot of it centers around the need for electric generation,” said Rick Smead, managing director at RBN Energy. He added that data center demand growth in the Boston area has increased the urgency to address gas constraints.

Brooke Thomson, CEO of the Associated Industries of Massachusetts (AIM), the largest business association in the state, said she has “seen a shift” in the political acceptance of natural gas.

“A lot of the change that has come out of the shift in federal administration is trickling down to the local level,” Thomson said, adding that Massachusetts Gov. Maura Healey (D) has emphasized that “everything’s on the table, including natural gas.”

She said the conversation around gas in the state has shifted significantly since the Biden administration, when Massachusetts lawmakers sought to ban new natural gas hookups and succeeded in passing a pilot program allowing 10 municipalities to ban gas connections for most new buildings.

Bill Ryan, chairman of Pilgrim Strategies, a lobbying firm whose largest client is Enbridge, said Healey “has almost gone out of her way to talk about the reality of natural gas in the current energy mix and the future energy mix.”

While the industry was on the defensive in Massachusetts under the Biden administration, “I think we’re in a different arc right now,” with political leaders in the state “singing a different tune,” Ryan said.

Speakers at the event stressed that the gas industry should double down on their efforts to drive the narrative around gas in the state.

“We’ve really made some gains in having people better understand the impact of natural gas,” said Mike Dirrane, director of Northeast marketing at Enbridge. “We’ve seen a change in the narrative, even in the media.”

“I think we need to be even more aggressive in pointing out the benefits of the natural gas industry,” he added.

Earlier in September, Enbridge announced a $300 million project to expand the capacity of its Algonquin pipeline into Massachusetts by about 75,000 Dth/d. Dirrane said the company has reached agreements with seven utilities in New England to support the expansion, which Enbridge expects to be completed in 2029. The project would not require any new compression, he added.

The project would be a relatively small expansion of the pipeline, which has a peak day capacity of over 3 million Dth. It appears to be a significantly scaled-back version of Enbridge’s 2023 proposal to increase Algonquin’s capacity to Massachusetts by 250,000 Dth/d. (See Enbridge Announces Project to Increase Northeast Pipeline Capacity.)

Dirrane said the project will meet “some of the critical needs right now” but speculated that a subsequent project may be necessary “to meet additional needs further down the road.” He said Enbridge has met with “all of the administration officials in New England” and has “had some great dialog and really good education on the benefits of natural gas and its impact on affordability.”

The project will likely be met with significant resistance from climate organizations in the state, which have opposed all efforts to expand gas capacity into the region. Environmentalists argue that increasing the long-term reliance on natural gas is not compatible with reaching net-zero emissions by 2050; methane is a potent near-term greenhouse gas and a key contributor to manmade climate change.

Smead applauded the effort to increase pipeline capacity to the Northeast. While the Algonquin expansion is “not a huge project,” he expressed his hope that “there’s going to be more of these that keep ramping up capacity, rather than a big monster that gets in all the papers.”

He stressed that, despite changing political attitudes around gas expansion, key barriers to addressing New England’s gas constraints remain.

He highlighted a pair of large pipeline projects to the region that were shelved during President Donald Trump’s first term: Kinder Morgan’s Northeast Energy Direct project and Enbridge’s Access Northeast project.

“The reason stuff didn’t get built in New England was because people didn’t want to pay for it, not because environmentalists lay down in the right of way,” Smead said.

The financing challenges for new pipelines in New England are often attributed to the fact that gas utilities have been reluctant to sign long-term contracts to support major projects; electric utilities are not allowed to use ratepayer funds for pipeline contracts; and gas generators typically do not sign long-term firm supply contracts. (See New Pipelines Unlikely for New England, Experts Say.)

While New England generators often struggle to access pipeline gas during the coldest days of the year, gas generation in ISO-NE has increased steadily in recent years, hitting its all-time high in 2024 amid reduced electricity imports from Canada. (See New England Gas Generation Hit a Record High in 2024.)

“It’s not necessarily in the interest of the generators to pay for it if they make their money off of volatility,” Smead added.

The Role of LNG

Multiple speakers emphasized the importance of the Everett LNG import terminal to the region and said there may not be a single solution to replace the facility when its contracts with Massachusetts gas utilities expire in 2030.

When approving the contracts, the Massachusetts Department of Public Utilities directed the utilities to develop a plan to reduce their reliance on the import terminal. (See Massachusetts DPU Approves Everett LNG Contracts.)

Everett, which is north of Boston, supports direct injection into the gas network and the dispatch of LNG trucks to other points on the system.

Jeff Tounge, development lead at Cashman Preload Cryogenics, outlined the company’s proposal to build an LNG storage tank in Northern New England that could supply 200,000 Dth of gas for winter reliability and inject enough gas to supply a 1,300-MW gas plant for 10 days during peak demand.

He said the project would provide reliability benefits during cold winter periods and that Cashman is seeking long-term utility contracts for the project.

Charlie Riedl, executive director for the Center for Liquefied Natural Gas, said he sees an important role for both LNG infrastructure and additional pipeline capacity.

“What the Northeast really needs is additional pipeline capacity to complement LNG,” Riedl said, adding that “pipelines are the most cost-effective way to meet growing demand.”

Emissions Limits

Also at the meeting, several speakers said they hope Massachusetts will re-evaluate its legally binding decarbonization targets, which require the state to cut its emissions by 50% by 2030 and at least 85% by 2050, relative to 1990 levels.

“There should be a real hard look at going back and providing some flexibility there” to account for “what’s potentially feasible right now,” AIM’s Thomson said.

“I think it’s possible that the House does this,” she added. “Do I think the Senate would do this? I don’t think they would, but I hope they consider it.”

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Stakeholders Demand Answers on Repeat MISO South Capacity Advisories

Stakeholders told MISO they need a better explanation of the every-other-day capacity advisories issued for MISO South, which have become customary since the beginning of summer.

Jim Dauphinais, an attorney for multiple industrial end-use customers, commented that there’s been an “extraordinary” number of capacity advisories in MISO South in recent months.

“We don’t know if it’s a change in MISO practices or a change in resource availability,” Dauphinais said at a Resource Adequacy Subcommittee meeting Oct. 1. He asked MISO staff to speak on its raft of declarations in the South.

“It makes people ambivalent. … I don’t know if that’s too strong of a word. The situational awareness goes down because they are happening so frequently,” Dauphinais said.

Mississippi Public Service Commission consultant Bill Booth agreed that the regularity of the alerts has made them easier to ignore.

“An alert is useful if there are instructions following it. We’re not sure what to do with these,” Booth said.

MISO Resource Adequacy Director Neil Shah said one of the drivers behind the advisories is a larger number of outages in the South. Beyond that, he said his colleagues would be better equipped to speak on the continual advisories at an upcoming stakeholder meeting.

The RTO has extended its steady stream of capacity advisories from summer into September, issuing 15 capacity advisories over the month, with a few including MISO Midwest.

At MISO’s quarterly Board Week in September, Executive Director of System Operations Jessica Lucas said the RTO is trying to indicate periods of elevated reliability risk in the South so that no one is caught off guard by potential emergency orders. (See MISO Recounts Tough Summer; Monitor Praises Lack of Emergencies and MISO on Track to Wrap Summer with 122-GW Peak, Addresses Frequent South Advisories.)

Stakeholders have speculated that advisories are the direct outcome of the RTO’s load-shed orders in Greater New Orleans during Memorial Day weekend. (See MISO Says Public Communication Needs Work After NOLA Load Shed.)

Public Utility Commission of Texas economist Werner Roth told Shah to expect similar questioning from the Entergy Regional State Committee at its Oct. 7 meeting.

“We’re going to expect some more clarity around this. We are curious to get more of a dive in this,” Roth said.

Pelican Power’s Tia Elliott said she’s been fielding questions about the advisories.

“Is MISO being more conservative because of what happened in May? More information from MISO would be useful,” she said.

WEC Energy Group’s Chris Plante also said his coworkers have been approaching him for answers.

“Was there a change to operational procedures? And if there was, would that potentially extend to MISO North? Those are questions I don’t have answers for,” Plante said.

Minnesota Power’s Tom Butz asked whether the frequent advisories would affect the resource adequacy hours MISO uses in its availability-based accreditation or have an influence on how it plans to divvy up the planning resource margin requirement among its load-serving entities. (See Stakeholders Question MISO Plan to Reassign LSEs’ MW Duties Based on Risky Periods.)

“All fair comments and questions. I hear you guys loud and clear,” Shah said. He promised to take the concerns to fellow staff members and have them address the advisories publicly.