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December 10, 2025

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Goulding Hasn’t Drunk the ‘Energy Dominance’ Kool-Aid

TORONTO — The Ontario government’s ambitious energy plan could prove costly to ratepayers if load growth stalls or new nuclear plants produce cost overruns, A.J. Goulding, president of London Economics International, said at the Ontario Energy Conference in a keynote speech Sept. 29.

“I worry a bit when words like ‘superpower’ or ‘energy dominance’ are used,” said Goulding, referring to the goals laid out in the Ministry of Energy and Mines’ Integrated Energy Plan (IEP) in June. “They suggest a shift of focus from cost/benefit, risk and reward.”

The IEP calls for expanding natural gas and nuclear generation, including four small modular nuclear reactors totaling 1,200 MW and a new 4,800-MW nuclear plant at the Bruce Nuclear Generating Station. The plan is based on a projected 75% increase in electric demand by 2050. (See Ontario Integrated Energy Plan Boosts Gas, Nukes.)

Despite its name, Goulding said, the ministry’s IEP is a “political document” rather than the investment blueprint that utilities file with regulators. “This is not a criticism. The IEP is a helpful statement of the government’s intent and informs the deliberation of Ontario’s quasi-independent agencies,” said Goulding, whose speech was titled “Skating fast enough or over our skis?”

Goulding praised the IEP’s “all-of-the-above” approach to generation as a way to balance affordability and environmental impact and said the province’s proposed expansion of nuclear power “makes sense from a reliability and emissions perspective, not to mention jobs and land use.”

Load Growth Projections

But he questioned the ministry’s projection that load growth will increase by three-quarters — 3% per year — over the next 25 years.

“Looking at successive 25-year periods since 1960, we find the most recent that averaged 3% load growth ended in 1995,” he said. “Only two individual years since 1997 have exceeded 3% lower growth.

“Per capita electricity consumption in Ontario peaked in 1988 and has fallen 36% since,” he continued. “We keep finding new ways to not use electricity, and it’s not clear that electrification will fully reverse these trends.”

A recession, or the impact of the U.S. government’s tariffs, also could dampen load growth. If growth falls short of projections, customers could face steep rate hikes to pay for infrastructure additions, he said.

New Nuclear Plants

Goulding raised concern over Ontario’s plan to build the first SMRs in the Group of Seven. The province hopes they will be a boon for economic development as other jurisdictions seek to tap its experience.

“While Ontario’s bet on first-mover advantages on small modular nuclear reactors … may pay off, it also carries with it first-of-a-kind” risk, he said, citing research showing nuclear projects have averaged cost overruns of over 120%.

Although he acknowledged that “recent experience in Ontario has been more positive with refurbishment of legacy designs,” he said it will take more than three SMRs to reach “N-of-a-kind” cost reductions.

“Ontario is not large enough to absorb sufficient reactors to reach that point on its own. Arguably, all of Canada may not be [large enough], making global partnerships critical,” he said.

The magnitude of Ontario’s planned spending on energy infrastructure leaves it vulnerable to “continuity risk” — the possibility that a large capital project is suspended following a change in government.

“Around the world, governments appear increasingly inclined to pivot from their predecessors’ policies, regardless of underlying merit,” he said. “This increases costs for projects that ultimately proceed and decreases investor confidence. Continuity risk is difficult to hedge. … and increases with project size. Large-scale nuclear investments could be particularly vulnerable to this risk.”

Granular Additions

Goulding said scenario analysis and maintaining optionality are central to addressing forecast risk.

“New-build plans need to be tested against multiple outcomes. The optimal plan should perform well across several resources that can be added in more granular increments,” he said. “An [Ontario Energy Board] process in which regulated entities detail IEP rate impacts and the extent of engagement with First Nations would provide both transparency and discipline as the province considers next steps.”

He also called for increased use of demand response to reduce the need for peaking plants. “Now, the challenge with demand response,” he joked, “is that it doesn’t make for a nice ribbon cutting.”

CCUS Utility

Goulding noted that the government’s continued commitment to natural gas generation is tied to development of carbon capture, utilization and storage (CCUS). “If we believe carbon capture and storage requires scale, perhaps we need a carbon capture utility to catalyze CCUS investment,” he said. “CCUS helps to legitimize the all-of-the-above strategy. It is also an area worthy of federal government support.”

Conclusion

“We can best manage the risks in the IEP through appropriate time-limited consultation, thoughtful scenario analysis, diversification of ownership and resource type, expanding the role of demand response and creating a foundation for CCUS, while maintaining a focus on affordability,” he concluded. “Policymakers need to take willingness to pay into account first as plans are being formulated, rather than after the fact, while also acknowledging that some rate increases are unavoidable.”

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MISO IMM Recommends Changes to Handling of Midwest-South Tx Constraint

MISO’s Independent Market Monitor has called for the RTO to change how it manages its Midwest-South transfer limit in ways he contends will open line capacity and reduce costs for Midwest market participants.

IMM David Patton asked MISO to create more steps on the limit’s transmission constraint demand curves to use more megawatt space on the transmission path and create headroom for deviations.

At a Sept. 30 MISO Market Subcommittee meeting, Patton said the Midwest-South limit has been binding more frequently since 2022 and contributed to $41 million in congestion over summer 2025, a 121% increase over 2024.

He said the regional transfer constraint has been used more in recent years due to solar additions in the South, a prolonged drought in Manitoba that has the Midwest exporting more power than usual and a drop in natural gas prices that has made MISO South’s plentiful gas generation more attractive.

Patton said reformulated demand curves on the transfer limit would allow greater energy transfer capability, increased use of MISO South generation and reduced costs to loads in MISO Midwest. He said adjusted curves could allow the RTO to tap into more than 200 MW on average in the South and increase flows by 50-60 MW.

Patton contended that adopting his demand curve recommendations would have reduced Midwest average energy prices by $3.48/MWh and driven down the region’s market costs by $515 million just over summer 2025.

Patton said that he’s long advocated MISO renegotiating its contracts with SPP and other neighbors to stipulate how MISO is allowed to use the transfer limit. He said because the transfer limit is a “contractual constraint that does not reflect any physical limits,” MISO should work to get more out of it.

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ISO-NE Publishes Draft 2026 Work Plan

Capacity auction alterations, a new asset condition reviewer role, parallel transmission planning efforts, new reserve products, Pay-for-Performance changes and interconnection modifications are likely to be on the docket for ISO-NE in 2026.

The RTO’s draft 2026 annual work plan, published in advance of the NEPOOL Participants Committee’s meeting Oct. 9, includes continued work on several major ongoing projects and outlines potential new initiatives related to dynamic operating reserves, PFP adjustments and surplus interconnection service.

The Capacity Auction Reform (CAR) project will continue to be the RTO’s main market development focus. The second phase of CAR, which is scheduled to run throughout 2026, will focus on overhauling the RTO’s capacity accreditation methodology and splitting annual capacity commitment periods into distinct summer and winter seasons. (See ISO-NE Kicks off Talks on Accreditation, Seasonal Capacity Changes.)

ISO-NE plans to seek technical committee votes in November on the first phase of the project, centered around the transition to a prompt market, followed by a PC vote in December. (See Stakeholders Mixed on ISO-NE Prompt Capacity Market Proposal.)

Other projects for 2026 include ISO-NE’s effort to stand up a new “asset condition reviewer” role. The role is intended to provide increased transparency around pooled costs associated with upgrades to aging and degrading transmission infrastructure, which have ballooned in recent years. (See ISO-NE Open to Asset Condition Review Role amid Rising Costs.)

As ISO-NE works to develop its in-house review capabilities over the next year, “the ISO plans to use a consultant to begin reviewing some [asset condition] proposals in an interim phase and facilitate stakeholder review and discussion of the consultant’s feedback,” the RTO wrote in its work plan.

Transmission Planning

Also in 2026, ISO-NE plans to evaluate and select a preferred transmission solution for the first Longer-Term Transmission Planning (LTTP) solicitation, which is intended to increase transmission capacity in Maine and help interconnect new onshore wind generation in the state. (See ISO-NE Releases Longer-term Transmission Planning RFP.)

According to ISO-NE spokesperson Randy Burlingame, the RTO received six qualified responses prior to the Sept. 30 deadline. Burlingame declined to comment which companies submitted proposals, but said ISO-NE will publish summaries of the proposals within 60 days.

ISO-NE wrote in the work plan that it plans to select a preferred solution “as early as September 2026.”

“Upon completing, reviewing and adjusting for any lessons learned from the 2025 cycle, the LTTP process could then proceed with a subsequent cycle, which would seek stakeholder input,” the RTO added.

In the third quarter of 2026, ISO-NE plans to begin work to comply with FERC Order 1920, which establishes long-term planning requirements for grid operators. In February, FERC accepted ISO-NE’s request to push back the compliance deadline for the order by two years, extending it to June 2027. The RTO has said the delay will enable it to “implement and gain experience from conducting the first LTTP” request for proposals.

“While New England’s new LTTP framework accepted by FERC in July 2024 went far in complying with [Order 1920], notable differences must be addressed,” ISO-NE noted.

The RTO said Order 1920 compliance discussions likely will include a focus on “further including [grid-enhancing technologies] into transmission planning assessments,” along with the development of a process for right-sizing asset condition upgrades “as a way to address long-term needs.”

Dynamic Operating Reserves

To prepare the system for increasing variability in generation and demand, ISO-NE “is assessing and commencing development of dynamic, operating reserve demand curves for incremental quantities of existing real-time reserve products (10- and 30-minute reserves), in amounts that vary during the operating day based on the system’s near-term potential ramping needs,” it wrote.

The RTO is considering adding a 60- or 90-minute reserve product, which could include “dynamically determined demand quantities,” to prepare the system for “unanticipated supply and demand changes.”

In a memo published in March, ISO-NE wrote that, to address increasing uncertainty and ramping requirements, it plans to develop “a dynamic, real-time probabilistic forecast of the system’s energy ramping needs,” which could inform these new reserve products. (See “Flexible Response Services,” ISO-NE Gives Updates on Prompt, Seasonal Capacity Market Changes.)

The RTO plans to begin stakeholder discussions on these potential changes in the fourth quarter of 2026.

Pay-for-Performance

ISO-NE also wrote that changes may be needed to its PFP rules following a recent New England Power Generators Association (NEPGA) complaint to FERC about “serious flaws” in the construct’s design.

In response to the complaint, ISO-NE has said it is open to capping the PFP balancing ratio but opposed NEPGA’s proposed changes to the stop-loss mechanism. (See ISO-NE Open to PFP Changes Following NEPGA Complaint.)

“The ISO may assess and discuss with stakeholders possible cost-allocation related revisions to the stop-loss mechanism and balancing ratio, depending on FERC action on NEPGA’s filing,” ISO-NE wrote in its work plan.

Surplus Interconnection Service

Prior to the publication of the work plan, some stakeholders pushed ISO-NE to pursue updates to surplus interconnection service rules, arguing that the RTO should allow increased flexibility for interconnecting resources that are willing to accept limitations based on the existing capacity resources at an interconnection point. (See Stakeholder Forum: Surplus Interconnection Can Maximize Capacity in ISO-NE.)

ISO-NE wrote that it plans to initiate discussions with stakeholders in the first quarter of 2026 “to identify the objectives, issues and scenarios driving stakeholders’ inquiries around existing and future access and use of assigned interconnection service rules.”

Following initial discussions, the RTO plans to “conduct a gap analysis of the use cases against the existing interconnection rules to determine the scope of potential solutions,” which would inform additional stakeholder discussions on potential rule changes.

ISO-NE is scheduled to complete its first cluster interconnection study under transitional Order 2023 rules in August 2026. The next cluster study will begin in October 2026.

Other Initiatives

The work plan includes initiatives intended to improve ISO-NE’s modeling of inverter-based resources, boost cybersecurity and deploy a new market clearing platform. The RTO also plans to publish a report on the performance of its new day-ahead ancillary services market that will include “any potential recommendations for enhancements.” The ISO will discuss the draft work plan with NEPOOL members at the PC meeting in West Hartford, Conn., on Oct. 9.

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N.Y. Build-ready Renewables Program to be Redirected

New York is planning a step back and a change of focus for a renewables program that never gained traction in the five years after it was launched.

The New York State Energy Research and Development Authority on Oct. 1 proposed to the Department of Public Service (15-E-0302) that the Build-Ready Program be terminated as a ratepayer-funded program and changed to an economic development model funded through other means.

Build-Ready was launched in October 2020 to develop a roster of turn-key plans that would place renewable generation on sites such as landfills, abandoned industrial areas and dormant generation facilities that could be sold to developers. Proceed from the sales would fund the next developments, and the program would become self-sustaining.

NYSERDA did an initial review of 16,400 parcels, narrowed that down to 3,400 sites and then identified 480 potential locations. But for a variety of reasons, all 480 were unworkable.

After nearly five years of effort at a cost of $15.6 million, Build-Ready’s one tangible result was a 12-MW solar project on the tailings pile of a defunct mine, sold to a developer in early 2025. (See Results Elusive in N.Y. Build-Ready Renewables Program.)

But in its five-year report to the DPS, NYSERDA identified some other results of Build-Ready: an interactive geographic information system and standardized database of all the sites it reviewed; a team that has developed expertise in photovoltaic solar project origination and development; and a template for partnership with other agencies, governments and organizations.

NYSERDA said the institutional knowledge gained through Build-Ready on interconnection, economics, leasing schemes and permitting is proving useful to other programs it and other agencies are pursuing. The agency proposes to meet Build-Ready’s statutory requirements by encouraging siting and development of renewable energy and storage on challenging sites.

Asked for clarification, a NYSERDA spokesperson said the program would continue to accept and evaluate site suggestions but focus on economic development opportunities, a shift it anticipates will give projects a better chance of coming to fruition.

This will include work with outside economic agencies: A memorandum of understanding is in place with the state’s economic development arm, Empire State Development, for Build-Ready to support its POWER UP and FAST NY programs.

The role now proposed for Build-Ready is to support economic development by optimizing siting and development of new loads; expanding existing loads; and helping investigate incorporation of clean energy technologies into economic development projects, the spokesperson said.

In a 2020 order, the Public Service Commission gave Build-Ready a $71.8 million budget, most of it from the ratepayer-financed Clean Energy Fund. NYSERDA spent only $15.6 million through Aug. 31, 2025, and in its Oct. 1 proposal, it said it would repay the CEF money through other funding streams and move forward without ratepayer money.

Build-Ready’s problems sprang from its central mission: design an inherently challenging and expensive project in a financially sustainable manner, then get it fully permitted and sell it.

“Build-Ready has determined that very few sites in New York state both meet the program’s numerous requirements (e.g. previously developed site, no agricultural land, no competition with the private sector) and also support economically viable large-scale renewable energy projects,” NYSERDA wrote.

Along the way, state leaders created in-house competition in 2023 by directing the New York Power Authority to take on a role as a renewable energy developer. And federal leaders in 2025 have made renewables much more expensive by adding tariffs and eliminating tax credits.

“Given this new policy paradigm in which Build-Ready must operate,” NYSERDA wrote, “developing economically viable Build-Ready solar PV projects going forward will be even more difficult.”

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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.