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December 7, 2025

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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.

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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.”