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December 7, 2025

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FERC Ends Show-cause over SPP FTR Changes

FERC has terminated a show-cause proceeding against SPP and accepted the RTO’s proposal to revise its mark-to-auction (MTA) collateral requirement for financial transmission rights by including an additional re-marking mechanism for seasonal products.

The commission said in its Sept. 30 order that SPP’s tariff “now fully addresses” its concerns in the proceeding, saying the mark-to-auction mechanism “sufficiently requires collateral to address the risk that a [transmission congestion rights] portfolio may decline in value over time” (ER25-2261, EL22-65).

“SPP’s approach ‘take[s] auction-clearing prices [ACPs] into consideration and thus incorporate[s] market expectations of the future values of the TCRs,’” FERC said, referring to a March order accepting the grid operator’s MTA proposal. That order stopped short of terminating the show-cause proceeding that dated back to 2022. (See FERC Accepts SPP Revisions to TCR Market, Maintains Show Cause.)

“Specifically, SPP’s proposal will apply ACPs from monthly auctions within the relevant season to re-mark the collateral requirements of seasonal TCRs, thereby ensuring that all TCR products are subject to a forward-looking pricing mechanism that reflects current market conditions,” the commission said.

FERC said SPP’s proposal to update collateral based on the most recent auction price for seasonal and monthly TCRs “provides sufficient protection when considered alongside other features of SPP’s TCR collateral requirements and market design.”

The commission disagreed with DC Energy’s arguments that the show-cause proceeding should remain open to consider broader reforms to SPP’s TCR market design. It found further reforms are unnecessary to address its concerns regarding the increased risk of default that results from a TCR portfolio that declines in value.

It also rejected the SPP Market Monitoring Unit’s call to strengthen tariff language regarding ad hoc collateral adjustments. FERC agreed with SPP that under its tariff, the RTO already possesses “sufficient authority” through its existing credit policy to conduct ongoing credit assessments, revise customer credit limits and issue collateral calls in response to material changes in credit risk.

The commission granted SPP’s request for waiver of the commission’s 120-day prior notice requirement for good cause and accepted the proposal effective May 1, 2026, to allow the RTO to prepare for the TCR annual auction in 2026.

FERC Penalizes NorthWestern

FERC approved a consent agreement between its Office of Enforcement and Regulatory Accounting and NorthWestern Energy, completing an investigation into whether the utility violated SPP’s tariff over a wind farm’s operation (IN25-14).

The Enforcement investigation found that NorthWestern failed to meet a deadline to convert its Beethoven wind farm project from a non-dispatchable variable energy resource (NDVER) to a dispatchable variable energy resource (DVER). NorthWestern acquired the 80-MW facility in South Dakota from BayWa Wind in July 2015, several months after it began commercial operation.

The utility, Beethoven’s market participant, told SPP several times over a seven-month period before the acquisition that Beethoven was a qualifying facility (QF) and registered it as an NDVER. Beethoven was merged into NorthWestern, and in September 2015, BayWa Wind relinquished the facility’s QF status.

As a wind-powered VER, the wind farm should have been registered as a DVER in 2015, according to SPP’s tariff. However, it wasn’t until February 2025 that NorthWestern completed the registration and conversion of Beethoven to DVER status.

NorthWestern neither admitted or denied the violation but agreed to: 1) pay a civil penalty of $40,000 to the U.S. Treasury; 2) disgorge $32,000, inclusive of interest, to SPP; and 3) provide compliance monitoring reports to Enforcement.

Enforcement opened the investigation after receiving a referral from SPP’s MMU.

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CPUC Judge Proposes Ordering 6 GW of New Resources as Tax Credits Fade

A California Public Utilities Commission judge has proposed that the commission order an additional 6 GW of capacity for the state between 2029 and 2032 to get ahead of disappearing federal tax credits and loans for renewable energy resources.

Under the proposal, 3 GW of additional procurement would be required by 2029, 4.5 GW by 2031 and 6 GW by 2032.

While ordering an additional 6 GW of resources now might be “premature,” the extra capacity likely would be needed “to achieve long-term goals,” CPUC Administrative Law Judge Julie Fitch said in a Sept. 30 ruling.

The additional resources are needed in light of the California Energy Commission’s 2024 Integrated Energy Policy Report (IEPR) demand forecast, which shows significant load growth between 2028 and 2032. Compared with the 2023 IEPR, the 2024 IEPR shows an additional 2 GW of load needed by 2030 and 5.8 GW by 2040.

The bump in future load is caused by forecasts for new data centers, increased electric vehicle charging and expanded building electrification, the ruling says. Additionally, a decreased amount of behind-the-meter solar and storage will be installed in the coming years, the CEC’s load forecast showed.

Current tax policies that make renewables more cost competitive are assumed to last only through 2029, CPUC staff said in a presentation associated with the ruling. If the federal investment tax credit and production tax credit are eliminated, ratepayers would experience “negative cost impacts” related to procurement of renewable resources, the ruling says.

“Ordering procurement now may help load-serving entities take advantage of any projects eligible for expiring federal tax credits or other incentives, such as grants or loans, that may be at risk at the federal level,” the ruling says.

However, some stakeholders are concerned a new procurement order could increase ratepayer costs due to a “frenzy of procurement by a large number of LSEs in an already tight market,” it says.

Many LSEs said they already are procuring as many resources as possible. Ordering them to find more resources would “not assist in the areas where procurement is delayed because of interconnection and permitting issues or supply chain issues,” the ruling says.

The ruling does not specify which types of energy resources are needed or in what amounts for the proposed 6 GW. As more energy storage is added to the grid, there might be “a question about the need for energy resources to generate sufficient additional electricity to charge the storage,” the ruling says.

In the ruling, Fitch also asked stakeholders to provide feedback about whether repowering existing energy facilities should be eligible to count toward “new” resources.

In most past decisions, the commission did not allow procurement to include repowering facilities or tapping into existing clean energy or natural gas resources, but in the late 2020s and early 2030s, certain resources will be of retirement age, Fitch said in the ruling.

Fitch also asked stakeholders to respond to certain questions related to new procurement, such as:

    • Should the new procurement be for generic capacity, or should there also be an energy component due to the declining effective load-carrying capability of battery storage?
    • Should a procurement order specify particular types of resources, such as clean long-duration energy storage, or should the order be for generic capacity resources?

Stakeholder comments on the proposal are due Oct. 22.

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Texas PUC Approves Permian, Outside ERCOT Transmission Projects

Texas regulators have approved the first transmission project in the Permian Basin Reliability Plan, Oncor’s proposed 23-mile, 345-kV double-circuit line east of El Paso in far West Texas (57828).

The Public Utility Commission endorsed the project, along with several others also out of ERCOT’s territory in West and East Texas, during its Oct. 2 open meeting. The project, which includes substation work, is expected to cost $216.1 million. It previously was approved by ERCOT.

The commission added language to the order requiring Oncor to make quarterly progress reports. The utility told the PUC it expects the facilities to be energized by December 2027.

The Permian Basin plan is a result of House Bill 5066, passed by the Texas Legislature in 2023 and signed into law by Gov. Greg Abbott (R). It required the PUC to approve a reliability plan for the Permian Basin that supports oil and gas electrification and growing community demand.

The commission approved the plan in September 2024. It comprises local projects such as Oncor’s. It also includes ERCOT’s first 765-kV transmission lines, with three import paths into the petroleum-rich basin. (See Texas PUC Approves Permian Reliability Plan.)

Outside ERCOT TEF Selections

The PUC accepted staff’s recommendation to select six projects eligible for $387.1 million under the Texas Energy Fund’s Outside ERCOT Grant Program (OEGP) after their analysis of completed applications.

The order delegates authority to Executive Director Connie Corona to enter into grant agreements with the applicants, contingent upon a final review (58492).

The applications, all for reliability and resilience projects, belong to:

    • Entergy: $199.7 million for transmission and distribution infrastructure hardening, pole replacement and flood-fortification projects.
    • Sam Houston Electric Cooperative: $87 million to bolster its distribution system in hurricane-prone regions of its East Texas service territory by replacing wooden utility poles with high-strength, corrosion-resistant steel or ductile iron poles.
    • East Texas Electric Cooperative: $51.5 million for undergrounding, pole upgrading, and transmission and distribution infrastructure projects.
    • El Paso Electric: $43.5 million for continuous online monitoring, an energy storage system project, underground hardening in Downtown El Paso and restoration work at its Newman gas plant, among other initiatives.

The OEGP is one of four programs under the TEF and has been given $1 billion by Texas lawmakers to dispense to projects that make reliability and resilience improvements, modernize infrastructure, improve weatherization or address vegetation management outside of ERCOT’s territory. The PUC selected the first four projects under the program in August, making them eligible for more than $240 million in grants. (See Texas PUC Approves $240M in Energy Fund Grants.)

Texas voters approved the TEF in November 2023 after legislation passed earlier in the year.

“The outside, or OEGP, piece of the bill maybe didn’t get as much attention as the inside-ERCOT piece, but it’s just as important,” commission Chair Thomas Gleeson said. “I think it signals and shows that we’re making significant progress towards achieving the goals of the entire bill.”

Entergy Transmission Project OK’d

The commission approved Entergy Texas’ proposed SETEX Area Reliability Project, a 500-kV single-circuit transmission line in northeastern Texas that has drawn opposition from local landowners (57648).

The commissioners settled on the same 145-mile route that had been before them in the two previous open meetings that had the project on the agenda. The project has estimated costs between $1.33 billion and $1.52 billion. (See “SETEX Reliability Project,” Texas PUC Releases Rulemakings for Large Loads.)

MISO identified the project as a baseline reliability project needed to comply with NERC’s federal reliability standards and to address demand growth in the region.

In other actions, the PUC:

    • Signed off on CenterPoint Energy’s settlement with Houston and other cities to recover nearly $1.1 billion in system restoration costs eligible for recovery and securitization after Hurricane Beryl and other storms in 2024. The PUC stripped $2.2 million in legal expenses and consulting fees from the agreement, deferring them until CenterPoint’s next ratemaking proceeding (58028).
    • Endorsed the suspension of $20.1 million in annual funding through 2030 for nuclear decommissioning costs related to Comanche Peak Power’s ownership interest in the Comanche Peak Nuclear Power Plant’s two units. The order also reduces the decommissioning costs to zero through 2030 (58193).
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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.