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December 7, 2025

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CAISO Board Approves 2 Key RA Program Proposals

CAISO’s Board of Governors approved two proposals intended to improve how the ISO calculates resource adequacy values and tracks RA supply.

Some stakeholders asked the ISO to delay implementing the proposals while the California Public Utilities Commission works on similar RA updates.

The approved RA proposals are part of CAISO’s Resource Adequacy Modeling and Program Design initiative, which began in 2023 to reform RA rules, requirements and processes. The ISO board approved both proposals at its Oct. 30 general session.

The first proposal — known as Track 1 — updates CAISO’s default qualifying capacity (QC) and planning reserve margin calculation methods. Under existing practice, energy capacity portfolios must meet the industry standard reliability statistics of a 0.1 loss of load expectation, which is equal to one loss-of-load event every 10 years.

The new QC calculation method more accurately reflects the “reliability contribution of each resource type” and is “well suited to account for the ISO balancing authority area’s diverse resource mix, historical reliability risks and anticipated future trends,” CAISO Vice President of Market Design and Analysis Anna McKenna said in an Oct. 22 memo.

Under the new method, wind and solar resource QCs will be calculated using a resource’s average effective load-carrying capability (ELCC) during net peak periods. ELCC shows the reliability contribution of a resource as a percentage of its maximum capacity. Under CAISO’s existing rules, wind and solar QCs are calculated based on a resource’s average monthly historic performance from noon to 6 p.m. over three years.

For nuclear, dispatchable thermal and hydroelectric resources, the new QC calculation will be based on an unforced capacity approach, which calculates QC using historic forced outage rates during the at-risk hours for the system over the past three years. The previous QC method for these resources was based on “net dependable capacity” defined by NERC‘s Generating Availability Data System information (GADS).

The CPUC is also developing its own UCAP design for storage and thermal resource QC purposes, CAISO staff said in a document. CAISO management “remains committed to collaboration and will seek opportunities to align inputs and assumptions where appropriate,” the ISO said.

The Alliance for Retail Energy Markets (AreM) wants CAISO to wait one year to implement the Track 1 proposal to allow coordination between the CPUC and the ISO, AreM representatives said in the document.

The new QC and PRM methods apply only where Local Regulatory Authorities (LRAs) have not established their own methods for CAISO’s RA program. Currently, when an LRA has not defined its own QC and PRM criteria, CAISO applies a default PRM of 15% and a default QC, McKenna said in her memo.

CAISO’s Department of Market Monitoring (DMM) supported the Track 1 proposal but cautioned that the new QC method does not change certain aspects of existing RA calculation methods. Those methods can still “lead to capacity accounting differences across LRAs,” DMM Executive Director Eric Hildebrandt said in an Oct. 22 memo.

There are also “several unaddressed issues” that need to be revisited for default values and modeling processes, Hildebrandt said. These include the seasonality of default values and unforced capacity, the resource adequacy availability incentive mechanism and the capacity procurement mechanism, he said in the memo.

RA Data Requirements

The second RA program change, Track 3, updates RA reporting policies to require all RA-eligible capacity in CAISO’s territory to submit annual and monthly reports.

The revision will improve grid reliability by giving the ISO a “more complete view of the status of all RA-eligible capacity and identifying capacity that may be available for backstop procurement,” McKenna said in an Oct. 22 memo.

In addition to strengthening reliability, the increased data visibility can “improve policy and modeling for the CAISO system,” Hildebrandt said.

“Additional visibility into RA resources internal to the CAISO balancing authority area would improve a systemwide understanding of recent trends in the capacity procurement mechanism and competitive solicitation process,” Hildebrandt said.

WEIM Q3 Benefits

Separately, the Western Energy Imbalance Market produced about $412 million in benefits for market participants in Q3 2025. WEIM has produced about $7.82 billion since beginning operations in 2014.

NV Energy received the most of all participants — about $104 million for the quarter.

“These numbers are another reminder of the tremendous economic and reliability value of the Western Energy Imbalance Market,” CAISO CEO Elliot Mainzer said in a press release. “Now, more than ever, we should be looking for ways to come together to preserve and enhance these benefits for Western electricity ratepayers.”

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Pathways Initiative Exploring Funding Options, Issues RFP to Staff ROWE

The West-Wide Governance Pathways Initiative’s Launch Committee will hire an executive staffing firm and is considering funding sources as it advances to the next phases of building the independent organization that will govern CAISO’s energy markets.

The committee is seeking $7 million to $8 million in start-up costs for the Regional Organization for Western Energy (ROWE). The money will cover costs from 2026 to 2027, Jim Shetler, general manager of the Balancing Authority of Northern California, said at Pathways’ monthly stakeholder meeting Oct. 31.

“We’re in the process of refining and making sure we covered the necessary costs,” Shetler said. “We currently are looking at three main tranches of funding.”

The funding alternatives include stakeholder contributions, grants and debt financing.

Pathways received a commitment under former President Joe Biden’s administration to underwrite the committee’s efforts to establish ROWE to oversee CAISO’s Western Energy Imbalance Market (WEIM) and Extended Day-Ahead Market (EDAM). (See Feds Pause $1M Pathways Initiative Funding, Group Leader Says.)

However, Shetler said, “it’s rather doubtful that we will get that federal grant.”

“We are starting to outreach to other entities, to look at private sector entities who may be willing to provide grant funds for this effort, and [we] have had some initial conversations around that,” Shetler added.

On Oct. 29, the Launch Committee issued a request for proposals to pay $420,000 for an executive staffing firm to assist in seating ROWE’s independent board and hiring of initial key staff.

The RFP notes that because of “funding limitations,” the committee is considering two options for support: basic support, including assisting in scheduling candidate interviews and preparing agendas; or routine support, which would include tasks such as vetting potential candidates and coordinating interviews.

The independent board will initially have five members, with two additional members to be added after tariff changes are approved by FERC.

“The board selection process will begin in January, so the nominating committee will begin to really meet in earnest the beginning of next year. The goal is to find five board members to be seated by or around July of 2026,” said Kathleen Staks, executive director of Western Freedom and co-chair of the Launch Committee.

California Gov. Gavin Newsom signed AB 825 into law on Sept. 19, allowing CAISO and investor-owned utilities to participate in ROWE. (See Newsom Signs Calif. Pathways Bill into Law.)

One goal in establishing the organization was to remove what some see as a barrier to wider participation in CAISO-run markets by ensuring they are not governed solely by officials and stakeholders in California. Another goal is to continue to “add additional market services that are voluntary for any Western stakeholders who want them,” Staks said.

“So being able to go from just overseeing the EIM and EDAM to adding additional services as Western stakeholders demand them is a really critical function,” Staks said. “This is not just independent governance over these energy markets. It is independent governance over all of the functions and offerings that go beyond that.”

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NIPSCO’s 1st GenCo Endeavor will Feature Gas, Cost $6B or More

Northern Indiana Public Service Co.’s leadership plan to test their new GenCo spinoff business with a $6 billion to $7 billion grid investment from a large, yet unnamed customer.

NIPSCO secured approval in September from the Indiana Utility Regulatory Commission (IURC) to launch its business model dedicated to building generation quickly to serve data centers and other large loads.

Lloyd Yates, CEO of parent company NiSource, said NIPSCO in September struck its first GenCo agreement with a “large, investment-grade data center customer” that would require two 1,300-MW GE Vernova natural gas turbines, 400 MW of new battery storage and transmission upgrades in northern Indiana.

NIPSCO’s contract with the customer stipulates an initial 15-year term. The utility plans to start constructing generation in 2027 and be able to meet the project’s full demand by 2032.

Yates said GenCo’s first, potential $7 billion investment will allow $1 billion in savings to flow back to existing customers. He said NiSource has “capitalized on emerging data center opportunities” in Indiana.

“The IURC’s approval of GenCo unlocks a unique business model designed to protect existing customers, serve new customers with speed and flexibility and maintain the financial integrity of NIPSCO,” Yates told shareholders at an Oct. 29 earnings call. “The GenCo strategy goes beyond simply providing power. It establishes a framework that strengthens our system, supports local communities and drives long-term sustainable growth for all stakeholders,”

NiSource reported $1.27 billion ($0.19/share) in revenue for the third quarter of 2025.

Yates emphasized NiSource is committed to keeping energy costs “reasonable and predictable” for the rest of its ratepayers.

NiSource Executive Vice President Michael Luhrs said NiSource plans to submit a special contract agreement to the IURC for review before the end of 2025. He said the utility expects a decision in the first half of 2026.

GenCo is exempt from many regulatory reviews typically required to build new generation in Indiana. Instead of the usual public proceeding, IURC would review the proposed contracts and power purchase agreements between NIPSCO and large loads on a case-by-case basis.

Multiple groups argue GenCo’s framework is flawed and is ripe for misconduct.

Clean Grid Alliance said GenCo would enjoy regulatory shortcuts while essentially maintaining the status of an unregulated independent power producer backed by a regulated monopoly. That one-sidedness would distort market competition and also could impede the clean energy transition, the nonprofit argued. It asked why NIPSCO didn’t simply create a new pricing tariff for data center load.

Watchdog group Citizens Action Coalition similarly argued GenCo would benefit shareholders over the public. It also said GenCo’s setup can’t fully isolate large-load investments because if the spinoff business were to lose money, it could affect NiSource’s credit rating.

The Citizens Action Coalition and the Indiana Office of Utility Consumer Counselor have alerted the IURC they plan to appeal its authorization of GenCo.

NIPSCO continues to claim GenCo will sequester investments stemming from large loads from being rolled into its rate base.

On the earnings call, Luhrs said NiSource is limited in the details it can share and called the deal a “breakthrough infrastructure agreement.”

Luhrs said the agreement will require consistent capacity payments of the customer, the “pass-through treatment of certain costs” and termination protections to mitigate risks posed by an early exit of the customer. He said NIPSCO’s proposed generation project and transmission upgrades were “carefully structured” to prioritize affordability “so that growth does not come at the expense of existing customers.”

Luhrs stressed that the contract ensures NIPSCO retail customers won’t be responsible for the infrastructure costs associated with serving the large load. He added NIPSCO would complete the project with “minimal interruption” to existing operations.

“We continue to see strong momentum from large-load customers,” Luhrs said, indicating GenCo will attract more customers.

Minutes after announcing the gas generation additions under GenCo, Yates said NIPSCO remains committed to the energy transition and would close its R.M. Schahfer and Michigan City coal plants by the end of 2025 and at the end of 2028, respectively. NIPSCO has announced plans to build a $644 million natural gas peaker plant at the Schahfer site to supply more demand tied to data center growth.

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MISO Members Grapple with Large Load Implications

MISO members debated how their system could change under the weight of large load additions and scheduled a future discussion in front of the RTO’s board of directors.

MISO Advisory Committee members considered the co-location of large loads at generating facilities at their Oct. 28 teleconference and planned a discussion slot on large loads at the Dec. 10 meeting to be held in front of the MISO Board of Directors.

Union of Concerned Scientists’ Sam Gomberg said there’s a “timing mismatch” between the rapid development of data centers and the slower-moving processes to “responsibly” get generation and transmission online. On top of that, Gomberg said vacillating federal policy is worsening uncertainty in planning for rising demand.

“People know they should be running, but they’re not exactly sure which direction to be running in,” Gomberg said.

Clean Grid Alliance Executive Director Beth Soholt said in MISO, load forecasts, generation planning, interconnection queues and transmission planning “aren’t totally synced up.” Soholt added there’s an “opaqueness” regarding how much large load customers are required to pay, with each state outlining its own cost responsibilities.

Illinois Commerce Commissioner Michael Carrigan joked that no one can get through a day without debating “AI, data centers, shifting load or increasing load from manufacturing.” He said he’s particularly concerned about an undersized grid expansion.

“We’re going to grow into practically anything you build,” Carrigan said.

But Kavita Maini, representing MISO industrial customers, asked what would happen to all newly built generation if AI processing became more efficient and didn’t need as much generation as anticipated.

“In my head, that’s one of the biggest challenges,” Maini said.

Maini said large loads should cover the costs they incur. Gomberg agreed he was concerned consumers could end up financing grid upgrades through increased power bills.

“The minute we start talking about subsidies and discounts, the whole system becomes inefficient,” Maini said.

Wisconsin Public Service Commissioner Marcus Hawkins said the timing of when cost recovery begins on large loads is vital because existing customers typically are the only ones paying leading up to energizing the large load facility.

Gomberg said it’s probably worth it for MISO to expand participation rules for energy storage and hybrid resources to get online quickly and reliably handle new load. He said storage can absorb or transmit power in a “matter of milliseconds” to keep load and energy balanced.

Gomberg and Soholt said it’s probably time to dust off NextEra Energy’s 2024 proposal that MISO create a dedicated study and registration process for new generation contingent on large loads. (See “NextEra Makes 2nd Overture for Bundled Studies,” MISO Previews Future Projects to Improve System Planning.)

Soholt called for more consolidated planning across MISO in general that ties together load estimates, annual and long-term transmission planning, and the interconnection queue and associated fast lane.

“We still have very siloed planning,” Soholt said.

Gomberg said he is “very curious” what happens when concentrated large loads cause congestion issues on the MISO system. Xcel Energy’s Susan Rossi, representing MISO Transmission Owners, said she likewise has questions around the potential for added reliability costs and uplift payments that could be induced by large loads.

John Wolfram, also representing MISO TOs, said he wondered what ensues when a co-located power plant goes offline but the large load it was built to serve tries to keep humming. Wolfram said that kind of “post-contingency thinking” could be helpful.

NextEra’s Erin Murphy said members’ conversations are especially germane since the Department of Energy recently directed FERC to initiate a rulemaking to speed up the interconnection of large load additions, including data centers and manufacturing facilities. Also, FERC in 2024 initiated proceedings to explore the upshots of co-locating large loads near generating facilities (AD24-11).

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Wanted: N.Y. Community Eager to Host Nuclear Reactor

Here’s something you don’t see every day: a state asking communities to raise their hand and explain why they should be the site of a next-generation nuclear reactor.

The New York Power Authority has begun to sound out developers on how they would go about building a gigawatt or more of advanced nuclear generating capacity and sound out communities on why they would be the right place to do it.

The requests for information NYPA issued Oct. 30 will not result in a contract award or siting designation, but they will help shape the process by which those decisions are made.

Faced with the prospect of increasing power demand in New York state, the statutory requirement to reduce emissions and the slow pace of renewable energy development, Gov. Kathy Hochul (D) in June ordered NYPA to develop at least 1 GW of advanced nuclear capacity. (See N.Y. Pursuing Development of 1-GW Advanced Nuclear Facility.)

Caveats: It must be sited in a community that welcomes it and must be developed in partnership with the private sector.

So NYPA is looking for a site and is trying to line up potential private-sector partners with a track record of developing, constructing, operating and/or servicing nuclear energy facilities.

It defines advanced nuclear as large-scale or small modular reactors employing Gen III+ or Gen IV technologies. Microreactors are not under consideration.

NYPA requires that the project start construction before 2033 and enter operation by 2040.

NYPA is steering clear of first-of-a-kind projects, which can carry elevated risk of delay, technical hurdles and cost overrun, but it is not being strict about this — it asks merely that the first concrete have been poured for at least one similar project somewhere else in North America by early 2030.

Host Community

The host communities RFI defines “community” as anything from a village to a county to a multicounty region.

New York City, Long Island and all but one Hudson Valley county are excluded from consideration — NYPA is looking toward the less densely populated parts of upstate, and away from the crowded downstate areas where many viewed the now-closed Indian Point nuclear plant unfavorably.

NYPA seeks a site that has a clear path toward construction of nuclear generation, is large enough, has water access, is protected from hazards and has demonstrated support from key stakeholders within the community.

Respondents should describe their community’s high-level vision for nuclear and how it would advance the community’s goals.

NYPA wants to know about factors including the area workforce and workforce development programs; local supply chain; supportive institutions such as labor unions and community leaders; infrastructure; power-intensive industries the community hosts or is trying to attract; framework for local approvals; and development incentives that would attract and retain nuclear supply chain businesses.

Also important are details such as interconnection potential, transportation access suitable for heavy cargo, environmental issues and any efforts taken to gauge popular support.

Interest has been expressed already. Officials in Oswego County, home to three of the state’s four operating commercial reactors, say additional reactors would be a nice fit there. Many in the lakeside city of Dunkirk, which suffered economically with the shutdown of NRG Energy’s coal-fired power plant, are lobbying for that site to host the state’s next reactor.

Development Partner

In the RFI issued to developers, NYPA seeks details about the technology they would use, siting considerations, cost and timeline assumptions, and potential ownership/partnership structures they see with NYPA.

And of course NYPA is looking for a demonstrated credible path to adding at least 1 GW of fission generation to New York’s grid as soon as possible.

NYPA asks respondents what experience they have with nuclear or other large-scale capital project construction and operation, details about those projects, their track record in securing state and federal funding, partnerships they would develop, what manufacturer and technology they would use in New York, supply chain considerations, fuel and waste management, design modularity and anticipated challenges.

NYPA also wants to know which site the respondents would propose for their project or know how they would identify a site if they have not already.

And it asks some questions that point to the central challenges of nuclear power development: describe your licensing strategy; provide your anticipated timeline up to commercial operation date; detail high-level levelized cost of electricity and overnight costs assumption; and give a directional level of maturity on those cost and time estimates, and on the assumptions underlying them.

Then there are the questions of equity, which New York retains as a guiding principle: Discuss your approach to workforce development; highlight your partnerships with labor unions and community organizations; and describe how your strategy supports job quality, equitable access for workers from disadvantaged communities and a skilled regional workforce.

The response deadline for both RFIs is Dec. 11. Participation is not a prerequisite for consideration in the future solicitation process.

Underlying Need

New York is likely to miss its statutory goal of 70% renewable energy in 2030, perhaps by a wide margin. As of 2023, its power mix was only 23.2% renewables, and increasing that percentage is only going to get more difficult during Trump 2.0.

Meanwhile, the existing fossil generation is aging, and new fossil generation may be needed to replace it if emissions-free resources cannot be brought online in time. So the state has embraced nuclear as a firm resource to complement intermittent wind and solar.

New York’s four commercial reactors are a crucial piece of the state energy portfolio, providing 22.2% of the electricity generated in the state in 2023 and nearly half of its emissions-free electricity. Despite their age, they are running at a capacity factor in the mid-90% range.

They have received $3.69 billion in the first seven years of New York’s zero emissions credit program, begun in 2017 to prevent their retirement for economic reasons.

The state is considering extending the ZEC program to 2049 to prevent retirement of the three oldest reactors, which began operating in 1960, 1970 and 1975 and are coming up on license renewals. (See N.Y. Makes Case for Extending Nuclear Subsidies to 2049.)

All four reactors are owned by Constellation Energy. In January, New York state joined Constellation in a proposal for a federal grant to support Constellation’s early site permit request for one or more advanced nuclear reactors to be co-located with two of the existing reactors in Oswego County.

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Dominion Reports on CVOW Progress, Data Center Growth in Q3 Earnings

Dominion Energy reported $1 billion in net income in the third quarter, which saw it remain on track with its offshore wind project while its pipeline of data center customers grew yet again.

The Coastal Virginia Offshore Wind (CVOW) project should see its first turbine installed later in November, with the first power delivery expected in the first quarter of 2026, Dominion CEO Robert Blue told analysts during a conference call held Oct. 31. Additional strings of turbines will be installed until the project’s completion target near the end of 2026.

“The project is now two-thirds complete and just a few months away from delivering much needed electricity to our customers,” Blue said.

While the project’s progress is on schedule now, analysts wondered if the upcoming gubernatorial election could throw it off. Gov. Glenn Youngkin (R) is term limited, and U.S. Rep. Abigail Spanberger (D) is leading in polls ahead of Election Day on Nov. 4.

All the candidates running for statewide office support CVOW, but one analyst asked what risk the project faced with a Democrat likely to become governor given how the Trump administration has treated offshore wind and other energy projects in Democratic-led states.

“It’s the fastest way to get 2.6 GW on the grid that’s going to serve AI and technology companies, defense security installations,” Blue said. “It’s critical to important infrastructure upgrades at the Oceana Naval Air Station. And if you stop it now, it causes energy inflation. So, it’s not surprising that we’re seeing bipartisan support at all levels of government, and we expect that to continue after the election.”

Dominion is also facing some delays in getting the ship it had built to install many of the wind plant’s components — the Charybdis — to work. The vessel is compliant with the Jones Act, which requires U.S.-owned and crewed vessels when sailing domestically, and was meant to “derisk” construction.

“This is the first Jones Act-compliant wind turbine insulation vessel to be built in the U.S. and subject to U.S. regulatory oversight,” Blue said. “It’s a big ship. It’s 472 feet long. It’s 184 feet wide. It weighs 27,000 tons. It’s got some complex systems on it. It’s got a 2,200-ton capacity crane. It’s got a jacking system that’s capable of creating a 40-meter air gap under the hull when the ship is jacked up.”

It was delivered to Portsmouth, Va., in October. Regulators there identified some issues that needed to be fixed before it can get to work. Regulators had concerns with the electrical systems, which Dominion’s workers are painstakingly reviewing, and some documentation issues, Blue said.

“To date, we’ve done over 4,000 inspections across 69 electrical systems, including 1,400 cable inspections,” Blue said. “We’ve got 200 people working around the clock. Of that original 200 punch-list items, we’ve closed out about 120, so it’s important to know not all those items are created equal. Some punch-list items are a little more complex and will take longer to resolve, but the progress has been really good.”

While for now Dominion expects CVOW to be fully installed by the end of 2026, the Charybdis’ issues could push that back to early 2027, Blue said.

Dominion now has 47 GW of data centers at various levels of development in its pipeline, which is up from 40 GW at the end of 2024, Blue said. The biggest chunk of those, 28.2 GW, is in the least-certain category, defined as only asking for an engineering study from the utility.

An additional 9 GW have signed a construction letter of authorization, which means Dominion can start work on upgrading infrastructure and the data center has to pay even if it walks away. And 9.8 GW have signed an electric service agreement, which defines how the data center will take service and lays out cost recovery.

“We welcome these customers to our system and recognize the vital contribution data centers make to national, state and community success,” Blue said. “We’re developing resources across distribution, transmission and generation to ensure we meet this critical need on a timely basis, while also taking active steps to safeguard all of our customers from the risk of paying more than their fair share for reliable and affordable electric service.”

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WRAP Wins Commitments from 16 Entities

Sixteen entities have committed to participating in the Western Resource Adequacy Program’s first financially “binding” season covering winter 2027/28, the Western Power Pool said Oct. 31 — the deadline for participants to commit to the program.

“As of the deadline, there are 16 current participants that will remain in the program for binding operations, including five in addition to the 11 who sent a commitment letter last month, and we expect more companies to join in the future,” WPP said in a notice posted on its website.

The committed participants include:

    • Arizona Public Service
    • Avista Corp.
    • Bonneville Power Administration
    • PUD No. 1 of Chelan County
    • Clatskanie People’s Utility District
    • Constellation
    • PUD No. 2 of Grant County
    • Idaho Power
    • NorthWestern Energy
    • Powerex Corp.
    • Puget Sound Energy
    • Salt River Project Agricultural Improvement and Power District
    • Seattle City Light
    • Tacoma Power
    • The Energy Authority
    • Tucson Electric Power

WPP said the participants “bring significant load (over 58,000 MW in peak load) and resources and a large, diverse geographic footprint, making WRAP one of the largest RA programs in the country and giving us critical mass for a binding program.”

New commitments after the initial 11 include Constellation, Grant County, Idaho Power, Seattle City Light and The Energy Authority. WPP noted the full group “includes members committed to or leaning toward” either CAISO’s Extended Day-Ahead Market (EDAM) or SPP’s Markets+, “as well as some who have not indicated they will join a day-ahead market.” SPP is operating the WRAP on behalf of the WPP and its Markets+ day-ahead platform, which requires members to participate in the program.

The Oct. 31 announcement marks the conclusion of a tumultuous October for the WRAP. The month began with PacifiCorp asking the WPP’s board of directors to delay the program’s binding phase by at least one year to deal with uncertainties around the program, followed by a similar request from Portland General Electric (PGE). (See PacifiCorp Asks WPP to Delay WRAP ‘Binding’ Phase Commitment Date.)

Early October also brought news of NV Energy’s intent to withdraw from the WRAP, a move the utility explained to the Public Utilities Commission of Nevada in an Aug. 29 filing that didn’t come to light until the regulator resolved issues with its website. (See NV Energy to Withdraw from WRAP.)

Then came the development, revealed by NV Energy, that future EDAM participants already have begun discussions about developing an alternative to WRAP. (See EDAM Participants Exploring Potential New Western RA Program.)

Just ahead of the deadline, NV Energy, PacifiCorp and PGE issued letters notifying WPP of their withdrawal, along with Calpine, Eugene Water & Electric Board (EWEB) and Public Service Company of New Mexico (PNM). (See 4 Entities Join NV Energy in Exiting WRAP, While Idaho Power Commits and PacifiCorp Next to Leave WRAP After Raising Concerns.)

Among the five utilities withdrawing from the WRAP, four (NV Energy, PacifiCorp, PGE and PNM) have committed to joining the EDAM, while EWEB will be participating in Markets+ by virtue of its location with the Bonneville Power Administration’s balancing authority area.

Of the 16 committing to the first binding season, just two — Idaho Power and Seattle City Light (SCL) — have expressed leanings in favor of EDAM, although SCL’s geographic position adjacent to future Markets+ members — including BPA — could make participation in the CAISO market a challenge.

In an Oct. 30 letter affirming SCL’s commitment to WRAP, utility Power Supply Officer Siobhan Doherty called the program “a cornerstone for enhancing reliability and coordination across the Western Interconnection” and said the SCL’s participation already has “provided tangible benefits for Seattle and the broader region.”

But Doherty raised a concern shared by some withdrawing participants, saying SCL “continues to closely monitor developments related to planning reserve margin (PRM) volatility in the shoulder months, particularly June and September. We recognize this as an area that could materially affect program outcomes and merits continued refinement.”

California Dreamin’?

The WRAP withdrawals have generated speculation in the Western electric sector about what kind of RA alternative could take shape in the region, including the potential for a program that might include California utilities — and CAISO.

In an email to RTO Insider, the ISO said it recognized that some EDAM participants are exploring WRAP alternatives and acknowledged that “several have approached CAISO with preliminary questions regarding our technical capabilities in this area, and we remain open to those discussions as stakeholder needs evolve.

“Ultimately, decisions about participation in WRAP and any alternative approaches rest with the utilities, their regulators and stakeholders. As with WRAP, any new resource adequacy program will not alter the CAISO Balancing Authority’s existing resource adequacy requirements.”

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Advocates in Massachusetts Continue Push for All-electric Construction

A coalition of municipal officials and climate advocates in Massachusetts are renewing a push for the expansion of a state program allowing a select number of municipalities to ban fossil fuel hookups in new building construction and renovation projects.

The current program, established by a 2022 omnibus climate bill passed in the state, authorizes 10 municipalities to “require new building construction or major renovation projects to be fossil fuel-free,” with exceptions for scientific research and medical facilities.

Prior to the bill’s passage, the demonstration project faced significant opposition from real estate and business groups, who argued it would increase the costs of new construction.

Activists lobbied for an expansion of the program during the 2023-2024 legislative session, facing pushback from energy and real estate companies and groups including National Grid, the Massachusetts Energy Marketers Association and the real estate association NAIOP. (See Massachusetts Considers Legislation to Ban Gas in New Buildings.)

Ultimately, an expansion of the program was not included in a wide-ranging energy bill passed by the state in 2024. Disagreements over gas utility reforms were one of the key points of contention during negotiations between the House of Representatives and Senate, with the latter supporting a more ambitious approach to transitioning away from natural gas.

While an expansion of the demonstration program was not included in the 2024 bill, the legislation included a series of gas regulation reforms intended to rein in spending on pipe replacements and amend gas utilities’ legal obligation to provide gas service to customers. (See Mass. Clean Energy Permitting, Gas Reform Bill Back on Track.)

At a hearing held by the legislature’s Joint Committee on Telecommunications, Utilities and Energy (TUE) on Oct. 29, advocates urged lawmakers to expand the cap on the demonstration program from 10 to 20 municipalities.

Proponents’ case for expanding the demonstration project was simple: The cost of all-electric buildings is generally on par with fossil buildings, and building all-electric would avoid costly retrofits in the future. Advocates also highlighted the climate and health benefits of electrifying buildings.

Several advocates cited a 2022 study by the Massachusetts Department of Energy Resources — conducted during the administration of Gov. Charlie Baker (R) — which projected the costs of all-electric homes to be cheaper than the cost of gas homes in most cases.

In 2024, a report commissioned by climate group ZeroCarbonMA found construction costs for all-electric buildings to be within 1% of fossil buildings, and forecast energy costs “to quickly become much more cost-effective than gas under expected emissions regulations and increasing average gas delivery costs.” (See Report Outlines Cost Savings of All-electric Buildings in Mass.)

Recent steps taken by the Massachusetts Department of Public Utilities could also shift the cost calculation in favor of electrification; the DPU has moved to prevent utilities from socializing the costs of new gas hookups across their rate base and has approved a new winter heat pump rate reducing winter costs for heat pump owners. (See Mass. DPU Requires Revisions to Gas Line Extension Policies and Report Details Cost Savings of Heat Pump Rates for Mass. Consumers.)

Katjana Ballantyne, mayor of the city of Somerville, said the city has “has overwhelmingly supported” joining the demonstration project and noted that the City Council in 2023 unanimously voted in favor of adopting a fossil-free building ordinance, though the city ultimately was not included in the program.

“All-electric new construction offers the easiest and most effective opportunity to begin decarbonizing buildings,” Ballantyne said. “The cost of all-electric new construction is level or even less than fossil fuel construction.”

Mark Sandeen, a member of the Lexington Select Board, said the town’s participation in the demonstration program “has been a huge win for affordable housing developers, and perhaps more importantly, for the eventual residents of those homes.”

Jonathan Kantar, manager of a design and construction company and a volunteer member of the city of Newton’s Design Review Committee and Energy Commission, said the city has found that “energy-efficient and all-electric buildings don’t cost any more than fossil fuel alternatives, and sometimes cost less.”

Representatives of groups that typically have opposed electrification requirements did not speak at the TUE hearing, though this does not mean they are not active on the issue.

A 2021 Brown University report on lobbying in the state noted that “major energy and utilities corporations and their trade groups only rarely submit public testimony in opposition to legislation advancing climate action,” but they have found significant success blocking legislation through behind-the-scenes lobbying.

According to state disclosures, over the first half of 2025, National Grid spent about $128,000 on lobbying; Eversource Energy spent $135,000; NAIOP spent $126,000; and the Home Builders and Remodelers Association of Massachusetts spent $61,000.

Sen. Mike Barrett (D), the top senator on the TUE Committee, said he is “starting to see significant indication” that building developers have “begun to move against” fossil fuel-free requirements and stricter building energy codes.

Massachusetts has three building codes available to municipalities: the base code; the stretch code, which includes increased energy efficiency requirements; and the specialized code, which incorporates even stricter requirements, including that buildings be pre-wired for electrification. Municipalities in the state can opt into either the stretch or specialized codes.

Barrett said that “early reports from participating communities I represent are that costs of installing heat pumps in new construction are equal to or lower than the costs of installing gas furnaces in new construction,” but he pressed advocates to provide clear data comparing the costs of all-electric construction and fossil construction.

“It seems to me that that proof point is going to be crucial in the next several months as people begin to hunt, as we must, for the real sources of the housing problem,” Barrett said.

In comments made to NetZero Insider following the hearing, representatives of real estate and building development groups argued that all-electric buildings are costlier to build.

“NAIOP is strongly opposed to the expansion of the fossil fuel-free demonstration program at this time,” said Anastasia Daou, vice president of policy at NAIOP Massachusetts. “The existing program dissuades investment, creates significant safety concerns with inconsistent applications of standards and empowers communities to block desperately needed housing in the commonwealth.”

A representative of the Home Builders and Remodelers Association of Massachusetts said the organization “absolutely opposes this expansion” and cited a 2023 industry-sponsored report that forecast Massachusetts’ specialized energy code to increase the construction costs of single-family homes by 1.8 to 3.8%.

A representative of Eversource said the company has “not provided testimony on this legislation and [does] not have anything to provide at this time.”

Representatives of National Grid and the office of Gov. Maura Healey (D) had not responded to requests for comment as of press time. Healey’s administration has not taken an official stance on the potential expansion of the program.

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PacifiCorp Next to Leave WRAP After Raising Concerns

PacifiCorp joins other utilities leaving the Western Power Pool’s Western Resource Adequacy Program just before the deadline to commit to the program’s first binding phase.

PacifiCorp submitted its withdrawal notice on Oct. 30. Michael Wilding, the utility’s vice president of energy supply management, signed the letter and addressed it to WPP Chief Strategy Officer Rebecca Sexton.

WRAP participants have until Oct. 31 to commit to WRAP’s first financially binding phase in winter 2027/28.

PacifiCorp’s withdrawal goes into effect before Nov. 1, 2027, and the utility will be subject to the requirements of WRAP’s tariff during the two-year withdrawal period, according to the letter.

Wilding did not shut the door entirely on rejoining the program, saying PacifiCorp “will continue to engage with the program for the duration of the withdrawal period.”

“Should circumstances change, the company can reenter the program by September 2026 to join other participants in the first financially binding program season in November 2027,” he added.

In an email to RTO Insider, PacifiCorp spokesperson Omar Granados said, “We appreciate the Western Power Pool and its leadership in addressing resource adequacy across the region. PacifiCorp remains committed to providing safe, reliable power, and we believe collaborating with our regional partners is the best way to develop long-term solutions for our customers.”

WRAP has stated it secured enough participants for the program to enter the first binding phase after 11 utilities reaffirmed their commitment in late September. (See WRAP ‘Binding’ Phase Set for Winter 2027/28 After Utilities Affirm Commitment.)

“The vast majority of our participants are remaining in the program,” Dave Zvareck, WRAP director, told RTO Insider. “We have received some exit notices this week, which was expected, as well as renewed commitment to the program, and we will move forward with binding operations in winter 2027/2028.”

PacifiCorp’s withdrawal comes after it asked WPP’s Board of Directors to allow WRAP participants to defer their decisions to commit to the program’s binding phase by at least one year after raising concerns about WRAP’s design, planning reserve margins, charges and its ability to adapt to the emergence of day-ahead markets in the West. (See PacifiCorp Asks WPP to Delay WRAP ‘Binding’ Phase Commitment Date.)

Other entities exiting the program have highlighted the challenges of navigating WRAP’s requirements when most of the West will be split into two day-ahead markets: SPP’s Markets+ and CAISO’s Extended Day-Ahead Market (EDAM).

All load-serving entities in Markets+ must participate in WRAP, which is being operated by SPP on behalf of WPP. By contrast, EDAM doesn’t require participation in an organized resource adequacy program, instead leaving members the option of choosing their own RA programs. But EDAM will use a resource sufficiency evaluation to ensure participants’ RA going into the day-ahead and real-time time frames.

PacifiCorp now joins Calpine, Eugene Water & Electric Board, Portland General Electric, Public Service Company of New Mexico and NV Energy in exiting WRAP. Out of those six entities, only EWEB will participate in Markets+ because it sits within the Bonneville Power Administration’s balancing authority area. (See 4 Entities Join NV Energy in Exiting WRAP, While Idaho Power Commits.)

Under WRAP’s forward-showing requirement, participants must demonstrate they have secured their share of regional capacity needed for the upcoming season. Once WRAP enters its binding phase, participants with surplus capacity must help those with a deficit in the hours of highest need.

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

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Xcel Energy, AEP Plan to Invest $132B Through 2030

Xcel Energy and American Electric Power said during their quarterly earnings calls that they have increased their capital investment spend to meet increasing demand from large loads.

Xcel told financial analysts Oct. 30 that it plans to invest $60 billion over the next five years to strengthen its infrastructure because of 11% annual rate base growth.

CEO Bob Frenzel said he expects the updated five-year plan to deliver 7,500 MW of zero-carbon renewable generation, 3,000 MW of gas-fired generation and almost 2,000 MW of energy storage to ensure system reliability, and 1,500 miles of HV transmission line miles to support demand growth. He said Xcel has safe-harbored all renewable and storage projects in the base capital plan.

The Minneapolis-based company says it has 19 turbines on order, taking advantage of its scale to meet the demand from oil and gas electrification in the Permian Basin.

“The growth you see in the Permian is probably a function of two things,” Frenzel said. “One is continued strength in mining in the Permian Basin. So just more wells, more infrastructure, more fields being open. The second is a trend toward electrification of those fields and of existing fields.”

Xcel said it recorded a $290 million ($0.36/share) charge in reaching a settlement with plaintiffs in the 2021 Marshall wildfire in Colorado. The amount has been excluded from quarterly and year-to-date ongoing earnings. The company expects to pay about $640 million related to these settlements, with about $353 million expected to be reimbursed to Public Service of Colorado by remaining insurance coverage.

“Xcel Energy does not admit any fault or wrongdoing in disputes that our equipment caused the second ignition,” CFO Brian Van Abel said. “We believe this provides a positive outcome for our communities and our investors.”

The company reported earnings of $524 million ($0.88/share) during the quarter, compared to $682 million ($1.21/share) for the same period in 2024.

Xcel reaffirmed its 2025 earnings guidance of $3.75-$3.85/share. Frenzel said he’s confident the company can deliver on earnings guidance for the 21st year in a row.

The company’s stock price closed at $81.59 Oct. 30, up 50 cents from its open.

AEP: $72B Capex Plan

AEP told financial analysts Oct. 29 that it’s revised its five-year capital plan to $72 billion and that it is supported by an expected $10% annual growth rate in its rate base. System demand is projected to surge to 65 GW by 2030, up from a current peak of 37 GW. Company executives said they will invest $30 billion in transmission, $20 billion in generation, $17 billion in distribution and $5 billion in other spending.

“Electricity demand growth is happening, and we are seeing it play out across the country in real time,” CEO Bill Fehrman told analysts. “Regions with concentrated data center and industrial development, including AEP’s footprint, are emerging as clear winners. Large annual capital budgets from hyperscalers totaling hundreds of billions of dollars reinforce the conviction, strength and staying power of this demand growth.”

The Columbus, Ohio-based company said its 28 GW of contract data center load all have financial commitments associated with them.

“That’s why we have so much confidence in the 28 GW,” CFO Trevor Mihalik said.

AEP reported third-quarter earnings of $972 million ($1.82/share), slightly above 2024’s performance of $960 million ($1.80/share) for the same period. The company reaffirmed its 2025 operating earnings guidance range of $5.75-$5.95/share, saying it expects to be in the upper half of the spread.

AEP’s stock price closed at $121.89 Oct. 30, up $6.79 (5.9%) from its Oct. 29 open.