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December 7, 2025

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NV Energy to Withdraw from WRAP

NV Energy has notified the Public Utilities Commission of Nevada that it plans to leave the Western Power Pool’s Western Resource Adequacy Program (WRAP), citing five critical issues with the program’s design.

Lindsey Schlekeway, market policy director at NV Energy, said in written testimony filed with the Nevada PUC on Aug. 29 that Nevada Power Co. and Sierra Pacific Power Co. — both doing business as NV Energy — are leaving the WRAP “due to inherent risks that outweigh the program’s current benefits for both the companies and their customers.”

The document containing the testimony had not been publicly available because of issues with the PUC’s website.

“While the companies continue to recognize the value of regional collaboration in resource adequacy planning to ensure reliability across the West, there are five critical issues within WRAP’s existing framework that significantly elevate risk exposure,” Schlekeway wrote. “These concerns must be addressed before the companies can consider rejoining the program.”

WPP Chief Strategy Officer Rebecca Sexton told RTO Insider on Oct. 2 that WPP is aware of NV Energy’s filing but noted that WPP has not received formal notice the utility is exiting WRAP.

“The deadline for notice is Oct. 31, in order to provide two years’ notice before the first binding season,” Sexton said. “We do expect some participants will exit the program. We understand this and respect it, and the door is always open for them to return. As we announced earlier this week, with the commitments we have in place, there is a critical mass of participants to move forward with our first binding season in winter 2027/28.” (See WRAP ‘Binding’ Phase Set for Winter 2027/28 After Utilities Affirm Commitment.)

“Meanwhile, participants and stakeholders are able to suggest changes or updates to the WRAP, through our open and transparent governance process and task forces,” Sexton added. “In fact, we currently have task forces and discussions with participants addressing some of the concerns being raised. We continue working hand in hand with participants and stakeholders to refine and optimize the program.”

The first issue highlighted in NV Energy’s testimony concerns deficiency charge penalties. Schlekeway noted penalties could range from $16 million to $22 million for a 100-MW deficiency if it occurred during every month of the summer season.

“This makes joining the program troublesome for load-serving entities that are planning to catch up and meet increasing loads in an unprecedented time,” according to the testimony.

‘High Financial Risk’

Schlekeway also said that the electricity industry is grappling with a host of challenges, including supply chain issues and load growth that could cause projects to delay or miss commercial operational dates, potentially exposing NV Energy to deficiency penalties.

The Planning Reserve Margin policy also is subject to volatility, with year-over-year changes ranging from “minor adjustments to swings as large as 10%,” Schlekeway contended.

“The combination of the high deficiency charges and the volatile PRM requirements creates high financial risk and planning challenges, especially amid supply chain disruptions and rapid load growth,” according to the testimony.

The second issue relates to the emergence of day-ahead markets in the West. SPP requires all load-serving entities in its Markets+ day-ahead market offering to participate in WRAP. This potentially could disadvantage those WRAP members that choose to remain in CAISO’s Western Energy Imbalance Market or opt to join the competing and soon-to-be-launched Extended Day-Ahead Market (EDAM), Schlekeway argued.

“Essentially, the WRAP voting model may dilute the influence of non-Markets+ participants leading to potential harm prior to the ability for the participant to exit the program, which occurs two years following a notification,” Schlekeway wrote. “The WEIM and EDAM WRAP members may lose their veto power with the addition of participants that participate in Markets+.”

The other issues include what Schlekeway called a “lack of market oversight and procurement mechanisms,” as well as underuse of transmission and uncertainty around operational holdback availability.

“The companies will continue to monitor the program’s development and remain open to future participation should WRAP evolve to address these five critical issues,” she wrote. “Until then, the companies will pursue alternative avenues to ensure regional reliability and resource adequacy for their customers.”

The news extends a string of developments related to WRAP as the participation deadline looms.

On Sept. 29, 11 members reaffirmed their commitment to the program, saying they would begin participating during WRAP’s first binding period in winter 2027/28. All but one of those members also have committed to joining Markets+.

The following day, PacifiCorp issued a letter asking the WPP’s Board of Directors to allow WRAP participants to defer their decision to commit to the program’s binding phase by at least one year, citing issues related to the development of Western day-ahead markets and other challenges. (See PacifiCorp Asks WPP to Delay WRAP ‘Binding’ Phase Commitment Date.)

PacifiCorp will begin trading in EDAM in 2026, while NV Energy is leaning heavily in favor of joining that market.

NV Energy did not respond to a request for comment for this story.

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DOE Terminates $7.56B in Energy Grants for Projects in Blue States

The U.S. Department of Energy has terminated 321 grants totaling $7.56 billion for 223 projects, apparently targeting Democratic-leaning states.

The Oct. 2 DOE announcement did not specify the grants being eliminated, but later in the day, Democrats on the House Appropriations Committee posted the list. They said the projects are in 108 congressional districts represented by Democrats and 28 represented by Republicans.

Russell Vought, director of the Office of Management and Budget, posted on X on Oct. 1 that the cuts were being made to “Green New Scam funding” for projects that are part of the “Left’s climate agenda.” The 16 states he identified were won by former Vice President Kamala Harris in her losing run against President Donald Trump in 2024.

The 32 U.S. senators representing those 16 states are all Democrats and all voted against a bill that would have averted the federal government shutdown.

But the grant cancellations will have some fallout in red states as well.

MISO-SPP Portfolio

Among the terminated financial awards, the fifth largest is the $464 million grant for the MISO–SPP Joint Targeted Interconnection Queue (JTIQ) portfolio under DOE’s Grid Resilience and Innovation Partnerships (GRIP) program.

The grant was intended to offset about 25% of the projected $1.6 billion capital costs for the JTIQ portfolio’s five 345-kV projects. The funds were awarded in 2023 to the Minnesota Department of Commerce, the lead applicant in a project that also involves the Great Plains Institute and the two RTOs. (See DOE Announces $3.46B for Grid Resilience, Improvement Projects.)

A Commerce Department spokesperson said the department has not received “any formal notification” from DOE on the GRIP funding’s termination. However, it was included in the list distributed by House Democrats.

In a statement provided to RTO Insider, the Commerce Department said it was “deeply concerned” about DOE’s suggestion of an “illegal effort to rescind federally obligated energy funds targeted exclusively at blue states.”

“If true, this would represent an unprecedented and politically motivated breach of federal law and funding norms — with potentially serious consequences for families, businesses and communities across Minnesota,” it said. “Without these investments, Minnesota could face higher energy prices, slower infrastructure development, and increased burdens on low- and middle-income households — all while demand for clean, affordable energy continues to grow.”

While Minnesota has been coordinating the application process and is responsible for the granted funds, the JTIQ’s proposed projects are sited in the Dakotas, Iowa, Kansas, Missouri and Nebraska, all of which lean heavily Republican.

The grid operators have said the “backbone” projects will unlock 28 GW of capacity and reduce curtailments in the highly congested region along their seam. FERC has approved and reaffirmed the RTOs’ proposal to fully allocate the costs of the JTIQ portfolio to interconnecting generation assessed per megawatt. (See FERC Upholds MISO and SPP’s JTIQ Cost Allocation over Criticism.)

“Federal energy funding plays a vital role in expanding clean energy generation, providing reliable energy transmission [and] creating jobs,” Commerce said. “This kind of action directly undermines [DOE’s] stated priorities: ensuring energy abundance and maintaining affordability for Americans.”

Commerce said it is working with state and federal partners to “assess” the situation and protect Minnesota’s interests.

An SPP spokesperson said it is working with Commerce and MISO to “review the order and consider options.”

MISO said it is monitoring the “developing situation” and that it will coordinate with its project partners “to understand any potential impacts.”

The project’s partners have 30 days to appeal the termination; DOE said some award recipients already have begun that process.

DOE said in May it was reviewing the “billions of dollars that were rushed out the door” in the Biden administration’s final days. It requested additional information to evaluate 179 awards covering more than $15 billion in financial assistance. (See MISO-SPP JTIQ Fed Funds Caught Up in DOE Review of Grants.)

The largest cuts were to the Biden administration’s Hydrogen Hub initiative. California stands to lose $1.2 billion promised to its $10 billion-plus ARCHES hydrogen initiative, while the Pacific Northwest Hydrogen Hub stands to lose $1 billion.

The CEO and board chair of ARCHES called the decision short-sighted but said the initiative would go on without federal funding.

California Gov. Gavin Newsom (D) went on the attack: “In Trump’s America, energy policy is set by the highest bidder, economics and common sense be damned.”

Protest and Praise

“Following a thorough, individualized financial review, DOE determined that these projects did not adequately advance the nation’s energy needs, were not economically viable and would not provide a positive return on investment of taxpayer dollars,” the department said in a news release.

OMB’s Vought identified the states hosting targeted projects as California, Colorado, Connecticut, Delaware, Hawaii, Illinois, Maryland, Massachusetts, Minnesota, New Hampshire, New Jersey, New Mexico, New York, Oregon, Vermont and Washington.

DOE said the grants being terminated had been awarded by its offices of Clean Energy Demonstrations, Energy Efficiency and Renewable Energy, Grid Deployment, Manufacturing and Energy Supply Chains, Advanced Research Projects Agency-Energy and Fossil Energy.

It said 26% of the terminated grants and 41% of the money were awarded between Election Day 2024 and Inauguration Day 2025.

Reaction to the announcement was swift.

U.S. Sen. Adam Schiff (D-Calif.), a frequent critic of Trump, posted: “Our democracy is badly broken when a president can illegally suspend projects for blue states in order to punish his political enemies.”

U.S. Rep. Troy Nehls (R-Texas) posted: “Terrific news. Terminate the Green New SCAM.”

U.S. Sen. Patty Murray (D-Wash.), vice chair of the Appropriations Committee, said: “President Trump has spent the year hurting families, killing jobs and raising people’s costs, and now he and Russ Vought are gleefully using the shutdown they have caused as a pretext to inflict even more pain. … This administration has had plans in the works for months to cancel critical energy projects, and now, they are illegally taking action to kill jobs and raise people’s energy bills.”

In a Truth Social post, Trump suggested there is more to come: “I have a meeting today with Russ Vought, he of Project 2025 fame, to determine which of the many [Democratic] agencies, most of which are a political SCAM, he recommends to be cut, and whether or not those cuts will be temporary or permanent.”

U.S. Rep. Rosa DeLauro (D-Conn.), ranking member on the House Appropriations Committee, said: “This was obviously designed as a political attack by the White House targeting Democrats. But the sad reality is that Americans — the middle class, working class and vulnerable — who voted for both Democrats and Republicans will be hurt by this. This is divisive, it is petty, and unfortunately it is exactly what we have come to expect from President Trump and Russ Vought.”

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Xcel Battles Colo. Counties over Transmission Project

Xcel Energy is fighting two counties that are blocking a segment of the company’s Colorado’s Power Pathway transmission project.

Elbert and El Paso counties denied siting permits for the Power Pathway project in July.

Now, Public Service Company of Colorado (PSCo), an Xcel subsidiary, has appealed the permit denials to the Colorado Public Utilities Commission. PSCo is asking the commission to use its backstop siting authority to allow the project to move forward.

“While Public Service acknowledges that counties … have certain regulatory siting authority, they cannot and should not use such authority to preclude infrastructure projects that are necessary for Colorado’s statewide interest,” PSCo said in its application to the PUC.

During its Oct. 1 meeting, the commission set an Oct. 22 pre-hearing date for the Elbert County and El Paso County cases.

$1.7B Project

Colorado’s Power Pathway is a $1.7 billion project that aims to transport wind and solar energy from the state’s Eastern Plains to the Front Range region, which includes Denver and other cities. Plans call for 550 miles of new double-circuit, 345-kV transmission line along with four new substations and upgrades to four existing substations.

The project is being built in five segments. Segments 2 and 3 went into service in 2025, and construction is underway on segments 1 and 4. But the 130-mile-long Segment 5 has stalled due to permitting issues.

PSCo said the project is needed to meet the state’s clean energy targets, including an 80% reduction in greenhouse gas emissions by 2030. The project will encourage development of new wind and solar generation in Eastern Colorado, PSCo said, in part by reducing the need for long gen-tie lines to connect resources.

The PUC approved a Certificate of Public Convenience and Necessity for the Power Pathway project in 2021, calling it “one of the most expansive and significant transmission proposals to be considered by the commission.”

“This proposal comes at a critical time for Public Service, Colorado’s largest utility, to transform its system and the ways in which it reliably generates and delivers energy for its customers in advance of clean energy targets,” the commission said in an order granting the CPCN.

But in Elbert County, the board of county commissioners denied siting permits for a 48-mile section of the project. County commissioners said the company hadn’t addressed wildfire risks, and residents’ requests to move the line farther east “were dismissed.” In addition, the transmission line would hurt ranching and farming in the county, reduce residential property values and create an “industrial scar” that would impact the rural aesthetic, the county commission said in a resolution.

PSCo said it provided documentation showing the transmission line would operate safely and that it was in a low wildfire risk area. And commissioner comments during public hearings revealed their real concerns, PSCo alleged.

According to PSCo, the commission chair stated that the line “serves no purpose here for Elbert County. And frankly, I don’t care about Denver and Aurora. I really don’t.”

PSCo is not the local electric service provider for either Elbert County or El Paso County.

El Paso County Concerns

In El Paso County, where about 45 miles of transmission line would be built, the board of county commissioners expressed similar concerns. One commissioner wanted to know why the solar and wind farms couldn’t be built closer to Denver, PSCo said in its application, while a resident pleaded to not turn their area into a “green energy dumping grounds of Denver.”

PSCo also filed complaints against Elbert and El Paso counties in district court but said that’s a separate matter from its application with the PUC.

PSCo asked the PUC to process its request on an expedited timeline so the company can stick to its construction schedule and avoid increased costs. In addition, “delayed availability of these resources also raises resource adequacy concerns as the Pathway project is necessary to deliver generation to meet increasing demand throughout Colorado,” the company argued.

PSCo wanted a commission decision by January, but the PUC on Oct. 1 denied its request for expedited treatment. Instead, commissioners said they’d do their best to move the matter along quickly.

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Duke Asks for More Gas and Batteries, Delayed Coal Retirements to Meet Demand

Duke Energy on Oct. 1 filed its long-range plan for its system in the Carolinas with the North Carolina Utilities Commission, calling for more natural gas-fired generation and batteries while keeping existing coal plants online to meet accelerated demand for electricity.

The 2025 Carolinas Resource Plan reflects the $19 billion in investments, representing 25,000 jobs, the states have attracted so far this year, most of which are from new manufacturing plants.

“North Carolina is the top state for business, and our focus is on ensuring Duke Energy’s low energy rates continue to support this region’s economic success,” Duke Energy North Carolina President Kendal Bowman said in prepared remarks. “By expanding our diverse generation portfolio and maximizing our existing power plants to meet growth needs, we will ensure reliable energy while saving all our customers money.”

Duke said its plan should lead to average power bills growing by 2.1% over the next decade, which is below expected inflation and lower than the previously approved resources plan filed in 2023.

Customer energy needs over the next 15 years are forecast to grow at eight times that of the last decade-and-a-half, double the rate Duke was expecting in 2023.

Duke has a 22% reserve margin target that it plans to meet by 2031, but it said it is continuing to re-evaluate that in light of growing demand, declining imports from neighboring systems and the risk of extreme temperatures going forward.

“To meet the 22% reserve margin necessary for system operators to have the resources they need in real time, the companies must continue their immediate buildout of available resources to meet the increasing need for capacity driven by growing loads and retiring coal generation,” Duke said in testimony at the NCUC. “New gas combustion turbines and combined cycle units, battery storage and solar are the resource types that are executable over the near term to put flexible megawatts into the hands of our system operators.”

As in 2023, Duke plans to build five combined cycle natural gas power plants, but it now also plans to build seven combustion turbine gas plants, up from five in the last plan. It also wants to build more LNG storage to cut fuel costs and hedge against price volatility.

The target for battery storage was also expanded in the plan — 5,600 MW by 2034, up from 2,900 MW in the 2023 iteration — which will help meet near-term growth and use federal tax credits, the company said.

The plan calls for 4,000 MW of new solar power by 2034, to be deployed in a way that maximizes customer benefits from the remaining federal energy tax credits.

Expanding nuclear power is being considered, with Duke evaluating the potential for new light-water reactors in addition to small modular reactors. New nuclear capacity could be up and running by 2037 at its Belews Creek plant in North Carolina or its Cherokee County plant in South Carolina.

Wind is not an economically viable resource for the Carolinas through 2040, though Duke said it would reassess that in 2027.

With the federal government easing regulations on coal, Duke said it is targeting two- to four-year extensions of its units that have dual-fuel capability (the Belews Creek, Cliffside and Marshall plants), as it said a few more years of operation would help deal with load growth. Over the long term, Duke said it was maintaining “an orderly exit from coal as approved by state regulators.”

The utility is working to expand capacity at existing plants, adding nearly 300 MW to the grid at four nuclear stations, expanding its Bad Creek pumped storage plants by an additional 280 MW and upgrading seven other hydro facilities. It also plans to upgrade its natural gas fleet in ways that cut costs and emissions, it said.

The proposed plan came under criticism from the Southern Environmental Law Center, the Sierra Club and Vote Solar, which are active in the proceeding before the NCUC. The plan comes after a new North Carolina law that eliminated the state’s interim carbon-reduction target of 70% by 2030. The groups argue the plan risks higher bills by backing new natural gas and unproven new technologies. (See Duke Highlights Legislative Wins in Q2 Earnings Call.)

“We’re concerned that regulated monopoly Duke Energy is continuing to rely on expensive new gas power plants, leaving North Carolina families on the hook for escalating fuel costs and making it harder to reach the 2050 carbon-neutrality requirement,” SELC Senior Attorney David Neal said in a statement. “Duke yet again appears to have fallen short of taking full advantage of energy efficiency, load flexibility, renewables and storage, which remain the cheapest and fastest suite of options for meeting rising demand.”

Parties have 180 days to file comments and critiques on the plan with the NCUC, which will hold public hearings and an evidentiary hearing as it weighs the merits of Duke’s filing.

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Lawmakers Divided on CISA 2015 Reauthorization

As Democrats and Republicans in Congress struggle to pass a funding measure to reopen the federal government, leaders of one committee remain just as divided about the fate of a cyber defense law.

The Cyber Information Sharing Act of 2015 (CISA 2015) expired Sept. 30, after a last-minute attempt to bring a measure authorizing its renewal to the Senate floor failed. The law provided liability protections for entities that voluntarily share and receive cyber threat indicators and defensive measures with other entities or with the government.

It also set requirements for the departments of Homeland Security, Defense and Justice, along with the director of national intelligence, to share information on cybersecurity threats with private entities; state, local and tribal governments; and the general public. Cybersecurity professionals in the electric sector and other industries, as well as government officials, have warned that the expiration of the law would quickly erode the information-sharing environment that it fostered. (See Stakeholders Urge Cyber Info Sharing Act Renewal.)

Sen. Gary Peters (D-Mich.), ranking member of the Senate Homeland Security and Governmental Affairs Committee, took to the Senate floor Sept. 30 to urge that the Senate pass by unanimous consent a bill that he and Sen. Mike Rounds (R-S.D.) introduced in April to extend CISA 2015 another 10 years. Peters called the law “one of our most effective defenses against cyberattacks” and cited support from both parties in Congress, along with the Trump administration, to justify the emergency move.

However, Sen. Rand Paul (R-Ky.), chair of the Homeland Security Committee, blocked Peters’ request. Calling Peters’ warnings about the consequences of the law’s expiration “fake outrage,” Paul observed that the continuing resolution scheduled for a vote later that day would extend the law for two months and suggested that Democrats concerned about CISA 2015 vote for that. Peters and all but two of his fellow Democrats later voted against the resolution.

Responding to Paul, Peters said businesses needed assurance that the law would not run out again.

“Countless businesses in every industry across the country depend on these protections. Telling them they could be eliminated again in just two months … does not give them the certainty they need to work,” Peters said. “This is why they want the 10-year extension. … If my colleague doesn’t support clean authorization, well, he’s chair of the committee. He should have initiated a bipartisan process. He should have perhaps convened hearings like a chairman normally would, if they actually care about an issue.”

Paul has proposed his own bill that would renew CISA 2015 for two years while limiting protections against disclosure of cyber threat data shared with the federal government. He has also previously called for tying renewal of the law to legislation that would ban DHS’ Cybersecurity and Infrastructure Security Agency from working on cybersecurity in federal elections.

In a statement Oct. 1, NERC and the Electricity Information Sharing and Analysis Center (E-ISAC) said they “continue to follow developments” relating to CISA 2015’s expiration, while affirming that “E-ISAC information-sharing activities remain business as usual.”

“Information sharing with the E-ISAC is an essential component of the electricity sector’s cyber security posture, helping members identify and mitigate security risk, and defending against evolving threats,” NERC and E-ISAC staff wrote. “And, like many other ISACs, the E-ISAC offers significant protections to address legal and privacy concerns, having long been committed to confidentiality. … The industry should … continue sharing information across the sector and with other sectors through the E-ISAC and other trusted information-sharing partnerships.”

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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.