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December 14, 2025

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NRG to Buy 13 GW of Generation Capacity from LS Power

NRG Energy will acquire 13 GW of gas-fired power plants and virtual power plant operator CPower from LS Power.

NRG and LS announced the agreement May 12 and said the cash and stock transaction is valued at about $12 billion, or roughly half of new-build cost for the assets.

NRG said the 18 natural gas facilities would roughly double its generation capacity. They are spread across nine states but are concentrated in areas where most of NRG’s existing load is located.

CPower, meanwhile, is an LS Power subsidiary that offers 6 GW of VPP capacity to more than 2,000 commercial and industrial customers in all of the deregulated U.S. energy markets.

NRG also reported solid first-quarter financials on May 12. Its stock price soared after the announcements, reaching a new all-time high in heavy trading and closing 26.2% higher than the previous close May 9.

In a joint news release, NRG and LS pitched the advantages the deal would offer NRG:

    • New quick-start capacity in the Northeast and Texas, simplifying risk management and lowering costs.
    • An immediate and strong value proposition, even without factoring price increases in tightening markets or large load prospects such as data centers.
    • Better ability to service rapidly growing demand for tailored long-term supply solutions, particularly data centers.
    • Potential for more than 1 GW of uprates, sites for possible development or co-location, and a differentiated commercial and industrial VPP platform.

NRG CEO Larry Coben said in the news release: “We are in the early stages of a power demand supercycle, and we are excited to lead the way with reliable energy solutions that will drive considerable value for NRG and all of our stakeholders.”

The acquisition is expected to close in the first quarter of 2026. It is subject to FERC and New York State Public Service Commission approval as well as federal antitrust review.

The sale would leave LS with about 10 GW of storage and natural gas and renewable generation capacity, as well as about 800 miles of existing transmission assets and 350-plus miles under construction.

LS CEO Paul Segal said the portfolio is uniquely suited for growing demand in the markets it serves and is being placed in capable hands. “LS Power will continue to invest in and develop secure and reliable energy infrastructure across the U.S.,” he said.

NRG reported GAAP net income of $750 million for the first quarter of 2025, or $531 million after adjustments, up from $511 million and $305 million in the same period a year earlier. The adjusted EBITDA set a first-quarter record for the company.

First-quarter 2025 earnings per share were $3.70 (GAAP) or $2.68 (adjusted), compared with $2.36 or $1.46 a year earlier.

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NYISO to Include Empire Wind in Q2 STAR Base Case

NYISO is modeling the Empire Wind offshore wind project as in-service despite federal orders to cease construction, staff said in presenting updated assumptions for the second-quarter Short Term Assessment of Reliability (STAR) to the Transmission Planning Advisory Subcommittee meeting May 6.

Alison Stuart, NYISO manager of reliability studies, explained that a scenario would be included in the modeling that would factor Empire Wind as out of service, but it was included in the base case.

Stakeholders questioned why the Empire Wind project was still assumed under the base case rules, citing the Trump administration’s targeting of the project. (See Feds Move to Halt Construction of Empire Wind 1.)

“Can you explain why? It’s clearly on hold,” a stakeholder asked.

“We don’t have any information from the developers regarding a delay of service date,” said Ross Altman, senior manager of reliability planning.

“You might not have anything from the developer, but there’s an executive order signed by the president of the country,” the stakeholder replied.

Altman responded that NYISO is tracking the news regarding Empire Wind closely, but that the project still met their base case inclusion rules.

The first-quarter STAR reaffirmed that New York City needed the Gowanus and Narrows peaker plants to maintain summer reliability into 2027. (See NYISO Reaffirms Need for NYC Peakers in Summer.) Stuart explained that the second-quarter STAR would include the deactivation of three generator units at Gowanus and Narrows, representing 64 MW of nameplate capacity. The deactivations do not include the plants’ other units at Gowanus and Narrows that the ISO designated to remain in service after their scheduled retirement under the state Department of Environmental Conservation’s peaker rule.

Stuart went on to explain that in terms of load forecast assumptions, the ISO was using the 2024 Gold Book’s projections, as the 2025 edition is not coming out in time for the study. In response to stakeholder questions, Altman said that the Gold Book was usually out in time for the third-quarter STAR.

“It just seems like you’re using very old load data, especially for New York City,” responded Chris Casey of the Natural Resources Defense Council. “There were conversations about whether we should be using that forecast in the Q1 STAR, and here we are using it for the Q2.”

The ISO is also still modeling cryptocurrency mining and hydrogen production loads as “flexible” and able to turn off during peak conditions. A stakeholder asked why this was the case, given that several interconnection studies the ISO had presented to TPAS earlier in the meeting were going to be so inflexible. Altman said that those projects were data centers and not cryptomining or hydrogen facilities and that data centers were already modeled as inflexible load.

NYISO staff also presented updates on the biennial Comprehensive Reliability Plan (CRP) in development.

Last year the CRP found a reliability need in New York City by 2033, but the ISO determined this year that the need had been resolved after updating its forecasts. (See NYISO Cancels 2033 Reliability Need for NYC.)

Altman said NYISO is still extremely worried about uncertainties and diminishing reliability margins for the city, particularly in transmission security.

The CRP, Altman said, will focus on identifying and quantifying looming uncertainties on the planning horizon. This would include load growth, system updates, generation project delays, winter risks, and generation retirements and failures.

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CEC Approves 3 IRPs, Decreases Battery Storage Project Size

The California Energy Commission (CEC) approved three integrated resource plans or publicly owned utilities as the state prepares the grid to meet peak loads this summer.

The first IRP approval went to Burbank Water and Power (BWP), which has more than 105,000 residents and is expecting electricity demand to increase in coming years due additional commercial development and electric vehicle chargers, the CEC’s report says. BWP’s peak demand is estimated to increase from 277 MW in 2023 to 323 MW in 2030 — or about 2.7% per year, CEC staff said.

From 2025 to 2027, Burbank will fall short of meeting its own capacity requirements, but it has an agreement with the Los Angeles Department of Water and Power allowing it to purchase reserve resources from LADWP. A critical project for the utility is a 3-MW solar plus storage project located at the Burbank Airport, scheduled to turn on in 2027.

The CEC also approved an IRP for Vernon Public Utilities (VPU), which has about 1,900 customers and a peak load of about 189 MW. In 2022, VPU terminated all three of its transmission contracts with Southern California Edison and LADWP, saying these contacts were not economical for its ratepayers, the CEC report says. VPU’s peak load occurs between 10 a.m. and 2 p.m. Monday through Friday, and during these hours CAISO has recorded some of the lowest emission intensity values, including zero, as increasing amounts of solar generation are connected to the system, according to the report.

The final IRP approval went to Redding Electric Utility (REU), which has about 45,000 customers. REU’s forecast peak demand in 2030 is 227 MW — down from 241 MW in 2018 and 253 MW in 2006. Redding utilities connect to California’s transmission grid through two substation facilities owned by the Western Area Power Administration. In August 1995, REU signed a 40-year transmission agreement with WAPA. REU plans to procure 60 MW of energy from a solar project beginning in 2026.

The commission also has amended a $30 million grant with Form Energy, reducing the grant to $25 million, decreasing the project’s energy storage system size from 5 MW to 1.5 MW and increasing match share from $6 million to $25 million.

The project size was adjusted to better align with the charging capacity of the Mendocino substation, a Form Energy spokesperson told RTO Insider. An original study of the project indicated the site could support a discharge capacity of 5 MW and charge capacity of 4 MW, but a secondary study completed in 2024 found the interconnection charging capacity was closer to 1.5 MW on average, the spokesperson said. The project initially was estimated to come online by 2025 but now is expected to come online in 2026, the spokesperson said.

If completed, the project will be the first multiday energy storage project in California. The project grant is funded by the CEC’s Long Duration Energy Storage program, which is for non-lithium technologies with more than eight hours of energy storage.

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StakeholderForum: The Unseen Costs of Subsidized Solar

Policymakers and advocates often hail solar energy as the future of electricity generation. Yet behind the glowing headlines and government incentives lies an overlooked economic risk — one that threatens both grid stability and long-term affordability. 

If one were to assess solar power’s true cost, a simple thought experiment proves instructive. Imagine a U.S. region rich in both natural gas and sunlight, where a hypothetical grid relies entirely on newly built generation. Based on 2024 gas prices and capital costs, at a baseline, a 100% gas-fired system would break even at approximately $50 to $55/MWh.  

However, as solar capacity is added, the system’s breakeven cost of generation rises by $3.25 to $3.50/MWh for every 10 percentage points of demand captured by solar. At 50% solar penetration, system generation costs would rise to $65 to $73/MWh. This is before considering the costs of additional large-scale battery storage, system balancing and monitoring, and transmission assets inevitably needed to make solar work well enough to achieve and maintain such a market share. 

Doug Sheridan

Yet the situation on today’s real-world grids is even more precarious. In many cases, new solar farms are being added to systems otherwise dominated by legacy gas-fired power plants. These assets were built under the assumption they would have a fair opportunity to generate returns over their lifespan. Instead, heavily subsidized solar generation — boosted further by both national and state regulatory favoritism — is driving wholesale electricity prices down while pushing older, gas-fired plants to the financial brink. 

For many power producers, this shift has created a brutal economic reality — legacy gas-fired plants being forced into an uneconomical position, unable to justify reinvestment or sustain profitability. This dynamic keeps power prices artificially low in the short term but lays the groundwork for rising costs over time — as dispatchable gas-fired units retire and grids become dangerously reliant on intermittent solar. 

No grid exemplifies this trend more starkly than ERCOT, which supplies power to millions of people across the state. Rapidly growing solar penetration has eroded developer confidence in the profitability of gas-fired projects on the system — as evidenced by the lukewarm enthusiasm for the $5 billion Texas Energy Fund designed to incentivize new gas-fired capacity. (See 2 More Projects Fall out of TEF Loan Program.) Developers continue to refuse its offers, no doubt concerned over the lack of regulatory and economic safeguards against the eroding effects of subsidized renewables. 

Texas is at an inflection point. The systematic erosion of its time-tested dispatchable gas-fired generation threatens grid reliability, while the economic uncertainty deters investors from stepping in to stabilize the system. 

If history is any indication, officials may attempt to downplay the consequences of solar’s effects on the system or blame external factors like rising demand. But in reality, Texas — and states following similar paths — are setting themselves up for long-term risks in both pricing and power security. The risk of higher residential rates and more frequent blackouts cannot be ignored. 

Subsidized solar may look economically attractive today, but its distortive impacts on energy markets tell a different story. Without course correction, states like Texas risk facing an electricity crisis not in spite of solar’s success — but because of it. 

Doug Sheridan is president of EnergyPoint Research in Houston. 

See Stakeholder Soapbox guidelines to learn how to make a submission for publication. 

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BPA Chooses Markets+ over EDAM

The Bonneville Power Administration on May 9 issued its long-awaited decision on joining a day-ahead market, confirming its choice of SPP’s Markets+ over CAISO’s Extended Day-Ahead Market, marking a major milestone for Little Rock, Ark.-based SPP’s push to expand into the Western Interconnection.  

BPA’s final record of decision (ROD) will come as little surprise to those who’ve been following market developments in the West. In March, the agency released a draft “policy direction” stating that the SPP market “is the best long-term strategic direction for Bonneville, its customers and the Northwest,” which followed by a year a staff “leaning” expressing similar determination. (See BPA Selects SPP Markets+ in Draft Policy.) 

“Day-ahead market participation, specifically in Markets+, is in the best interest of our customers and the region, as it offers the opportunity to ensure a reliable, abundant and affordable energy supply for consumers in the Northwest,” BPA Administrator John Hairston wrote in a letter announcing release of the decision. 

“BPA’s final policy direction toward participation in Markets+ represents significant effort by BPA staff and stakeholders to evaluate market options that support the region’s ability to share affordable and reliable energy,” said Carrie Simpson, SPP vice president of markets. “SPP thanks BPA for their engagement during Phase 1 of Markets+ development, and we look forward to their continued collaboration as we work together to implement a Western market that improves grid efficiency and values the needs of all participants.” 

The ROD represents a big win for SPP and is likely a key to the viability of Markets+, given that BPA manages the output from 31 hydroelectric dams in the Federal Columbia River Power System with a combined capacity of about 22,440 MW, while also operating more than 15,000 miles of transmission lines — about 75% of the Northwest grid.  

The decision also is likely to influence the decisions of other entities in the region. 

“Puget Sound Energy appreciates BPA making the choice to participate in the Southwest Power Pool’s Markets+ program,” Phil Haines, the utility’s director of energy supply and trading, told RTO Insider. “As BPA’s largest transmission customer, it’s important to us to have a clear view. We expect to make a decision of our own very shortly.” 

The ROD was the culmination of a two-year stakeholder process conducted by BPA, an effort often marked by tensions between supporters of each day-ahead market, with some EDAM backers contending the process appeared to be working to a foregone conclusion. (See Rising Tensions Evident at BPA Day-ahead Markets Workshop.) 

The process even drew the attention of key Northwest political figures, including members of the Pacific Northwest’s U.S. Senate delegation, who largely were critical of the agency’s leaning in favor of the SPP market. (See In Letter to Senators, BPA Tempers Markets+ Leaning.) 

In his letter, Hairston said the federal power agency reached its decision “through thorough policy analysis, extensive input from customers and stakeholders, careful consideration of current market dynamics, and thoughtful attention to the principles that guided our assessment.” 

The ROD seems to anticipate potential complaints about how BPA conducted its day-ahead markets process, saying the agency “has held one of the most open and transparent public processes to evaluate day-ahead market participation.” 

“In comparison, electric utilities that have indicated they will or have taken steps to join EDAM did so largely without public process or transparency. They are now rapidly implementing EDAM despite serious concerns about potential unjust and unreasonable transmission OATT terms and conditions in their BAAs,” BPA wrote. 

As in the “policy direction” issued in March and staff leaning published last year, BPA’s ROD emphasized the importance of Markets+’s independent governance framework. While recognizing the “qualitative” nature of the issue, BPA reiterated its oft-stated opinion that the SPP market’s governance structure is “superior” to that of EDAM, despite ongoing efforts by the West-Wide Governance Pathways Initiative to relax the state of California’s oversight for CAISO’s EDAM and Western Energy Imbalance Market (WEIM). 

“Independent governance does not factor into a strict formula where the risk of negative governance-related outcomes is quantified or weighted against other criteria,” BPA wrote in the ROD. “There is unmeasurable uncertainty regarding what issues will confront day-ahead markets in the future. In addition to past disputes and known current challenges, there will surely be issues that arise that no one has yet fully contemplated, and governance will surely impact market decisions that impact financial outcomes. … Bonneville would be accepting great risk if the process is biased toward certain entities, does not allow issues of concern to be prioritized or is not durable enough to provide fair representation in crisis situations.” 

The ROD also rebuffed requests by EDAM supporters that BPA at least delay its decision until developments play out this year related to California legislative bill that would implement the recommendations by the Pathways Initiative to bring greater independence to the EDAM and WEIM. 

“Bonneville does not find merit in waiting for EDAM to incrementally improve its governance,” BPA wrote. “First, Bonneville has determined that the existing Markets+ governance is superior even to the Pathways Step 2 governance revisions currently proposed for EDAM, which still require legislative approval. Second, the Pathways Step 2 governance does not sufficiently address Bonneville’s concerns regarding independence and EDAM governance independence would continue to be insufficient, even under Pathways Step 2.” 

BPA also pointed to the “strategic benefit” of deciding on a market now, including “better coordination” with other agencies and establishing an “early seat at the table” for participating in Markets+.   

‘Special Problems’

In his letter, Hairston acknowledged the work that remains before BPA can begin participating in Markets+, including the agency’s own “tariff and rate proceedings to determine cost allocations and the terms and conditions for transmission service.” 

BPA — and other Markets+ participants — also can move on to deal with the market’s Phase 2 implementation stage, which begins this summer.  

Participants presumably will need to begin addressing challenges stemming from the non-contiguous nature of the Markets+ footprint, which likely will consist of three isolated pockets concentrated in the Pacific Northwest, Arizona and Colorado, as well as a smaller segment in El Paso Electric’s New Mexico service territory. Chief among those challenges will be the lack of transmission capacity connecting the market’s zones, which will require making energy transfers through the larger EDAM, where possible. 

During an April 9 meeting of CAISO’s Western Energy Markets Regional Issues Forum (RIF) in Portland, Ore., Grid Strategies’ Richard Doying, one of the architects of MISO’s market, said the situation in the West will be unique in that the Eastern Interconnection does not contain any markets where market zones are “in their own isolated zones without physical transmission connected.”  

“And that is, in fact, the case for what we have right now in the Markets+ region. It’s not clear, based on all of the announcements, whether EDAM will be contiguous. We have to see where everyone goes at the end of the day. … But it does introduce special problems,” Doying said. 

The creation of separate day-ahead markets in the West will result in more issues at the seams of the two markets, although BPA and other Markets+ participants have played down the importance of seams in their market decisions.  

During the April 9 RIF meeting, Todd Kochheiser, senior electrical engineer at BPA, noted the agency already manages a non-contiguous balancing authority area that spans six states and is adjacent to 18 other BAAs. He said BPA has more than 75 years of experience managing operations across seams, although he acknowledged day-ahead markets would add a new layer of complexity. 

“While seams present complexities, Bonneville and other utilities have successfully managed seams in the Western Interconnection for decades,” Hairston wrote. “Based on this experience, and as part of our day-ahead market implementation plan, Bonneville will reach out and collaborate with entities to mitigate seams.” 

Reactions

Reactions from across the region were mixed. 

“We respect BPA’s decision to join Markets+ and recognize the valuable contributions from diverse stakeholders across the Pacific Northwest during this evaluation process,” CAISO CEO Elliot Mainzer — BPA’s previous administrator — said in an email. “CAISO continues to focus on the success of the Western Energy Imbalance Market (WEIM) and the Extended Day-Ahead Market (EDAM) to ensure inclusive and efficient energy market solutions. Our commitment to maintaining reliability and delivering economic value to our customers in the West remains unwavering, and we look forward to continued collaboration with all parties involved.”  

“I have repeatedly stressed that BPA should take its time to get this decision right, which will impact Oregonians for decades,” Sen. Jeff Merkley (D-Ore.) said in an email. “Despite concerns from my fellow senators and the governors of Oregon and Washington, BPA has made a rushed decision. BPA still needs to go through a ratemaking process, and I remain laser-focused on prioritizing the needs of Oregon families to have affordable and reliable energy.” 

“It’s disappointing BPA has chosen this route now, when evidence suggests waiting for both day-ahead market options to mature could provide the most benefits to ratepayers,” Sen. Ron Wyden (D-Ore.) said. “I’ll keep pressing BPA to make decisions that prioritize affordable, reliable and clean electricity in the Northwest.”

Leah Rubin Shen, managing director at Advanced Energy United, called BPA’s decision “premature,” contending it could “entrench costly market seams and inefficiencies.” Rubin Shen pointed to the production cost study commissioned by BPA in 2024 that showed Markets+ would deliver the agency fewer economic benefits than EDAM. (See BPA Sticks to Markets+ Leaning Despite Study Showing EDAM Benefits.) 

“The West has the potential to come together and build a broad, unified market for the whole region,” she said. “Unfortunately, this decision takes us away from that vision, cementing a narrower path that could lock us into a fragmented market structure and undermine the immense reliability and cost-savings benefits of sharing resources across the region.”

“BPA’s participation in Markets+ is a win for the Northwest,” said Scott Simms, executive director of the Public Power Council. “This market was designed with BPA’s unique role in mind, and the result reflects a strong, collaborative effort among public power, SPP and other Western entities. We support BPA’s timely decision which comes at the end of a rigorous public process. Making this decision now will allow the agency to pursue participation in a day ahead market that has the confidence of its customers.” 

The Northwest Energy Coalition (NWEC), a strong EDAM supporter in the region, expressed disappointment over BPA’s decision and also pointed to the BPA analysis showing the greater financial benefits stemming from the larger footprint of the CAISO market.  

“Yet BPA has chosen Markets+, a smaller market footprint. When BPA joins Markets+, it will decrease net benefits to customers by $108 million each year. If BPA joins EDAM, it will increase net benefits to customers by $57 million each year,” NWEC wrote. “BPA’s decision to pursue a market with less economic benefits for customers and less direct interconnection with other utilities across the West will reduce the potential for all electricity users in the region to benefit from a unified day-ahead market. This decision is not in the best interest of the region.” 

“We greatly appreciate Bonneville’s continued leadership during this pivotal moment in the evolution of western energy markets,” said Jeff Spires, managing director of power at Powerex. “Bonneville’s choice to participate in Markets+ is the result of an extensive and comprehensive evaluation process in which Bonneville prioritized the foundational governance and market design elements that will provide benefits for Bonneville, its customers, and the broader Northwest region for years to come.” 

“BPA’s decision to join Markets + is a significant milestone in providing confidence for other Northwest utilities to join,” said Laura Trolese of The Energy Authority, chair of the Markets+ Participants Executive Committee. “I expect other announcements to follow.”  

Seattle City Light said it is “deeply disappointed” in the decision. “BPA’s decision to join Markets+ is inconsistent with its responsibility to maximize customer benefits in accordance with sound business principles. BPA’s own record and analysis shows that Markets+ will increase costs for BPA and its customers.” The decision “will negatively impact the utility in two significant ways — as a market participant and as one of BPA’s largest customers. Our ratepayers will bear the burden of this decision as we spend $20 [million to] $40 million more every year on energy. This is especially burdensome with the rising costs to meet growing energy needs.”

“As BPA’s largest individual customer, Snohomish PUD appreciates the administration’s thorough and transparent evaluation of a complex decision with significant regional impact,” said Adam Cornelius, power analyst at the PUD. “We expect that BPA’s participation in a day-ahead market to result in more efficient usage of the Northwest’s hydropower resources and transmission system, driving improved reliability and cost savings. Snohomish values the independent governance and market design of Markets+ and believes it strikes the right balance for our customers and the region.”

“We continue to work collaboratively with other Markets+ members and look forward to providing APS customers more savings opportunities and continued reliable service through a larger market footprint,” said Kent Walter, Arizona Public Service, director of Western market affairs. “Bonneville Power Administration joins a group of diverse utilities and generation providers who benefit from the regional diversity of the northwest and southwest participants. Together, we are developing a market structure that enables market choice for future participants.”

Tom Kleckner contributed to this article. 

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Collateral Benefits of OSW Transmission Projects Can be Key

VIRGINIA BEACH, Va. — States looking to upgrade the grid to interconnect wind power off their coasts should look for secondary benefits to lure support, speakers said at Oceantic Network’s 2025 International Partnering Forum on April 28 to May 1.

Reaping multiple benefits from a grid project can help soften the uncertainty that faces many transmission projects, reducing the risk and perhaps opposition, speakers said.

The challenge is “to advance grid improvements that would be beneficial for offshore wind integration and also provide other benefits to reliability,” John Bernecker, director of the Transmission Center of Excellence at the New York State Energy Research and Development Authority, said in the April 29 panel “Strategies for Cross-value Benefits.” Such initiatives can “cost-effectively integrate other resources as well,” he said.

The strategy reflected a view running through several panels at the conference that offshore wind projects could be made more acceptable to a broader community by downplaying the climate benefits and highlighting other positives.

One such example is the planned Propel New York project to improve the grid across parts of Long Island, New York City and Westchester County. Initially designed to connect 3 GW of offshore wind, the final project also improved the city’s connection with upstate New York and Long Island, said Girish Behal, a vice president at New York Power Authority, one of the project developers.

“That’s where the value conversation comes into place,” he said. “Long Island being a constrained area has a high cost of generation, [and] connecting it to the rest of the grid adds resiliency in being able to bring in what I would call ‘off-location’ power.”

Christian Lindeen, commercial lead of offshore wind for consultant DNV, outlined several examples in which the multibenefit strategy has worked in Europe. In the U.K., he said, a study showed how to use submarine cable bootstraps to bypass the onshore grid with HVDC offshore connections. The system bypasses the “constraints that are onshore, alleviating the grid,” he said.

The message, Bernecker said, is that “it’s important that we’re continuing to advance what we can in a mindful way as we navigate the uncertain times.”

Northern Opportunity

The premier of Nova Scotia, Tim Houston, happened to take the stage at IPF a day after the Liberal Party candidate in the Canadian election for prime minister, Mark Carney, was announced as the winner.

Carney is committed to both clean and traditional generation.

“Interesting results,” Houston said. “It’s probably a helpful result for this sector. So I’m excited.”

Nova Scotia Premier Tim Houston | © RTO Insider

Houston was billed to speak about “Cross-Border Energy Collaboration,” but he spent time pitching the benefits of his province for offshore wind, and he urged the assembled developers, vendors and other stakeholders to consider partnering with him.

“We have incredible wind speeds. It blows a lot. We have good, good bottom; we have ports. We have a lot to offer,” he said.

Nova Scotia will solicit bids for 2.5 GW of power in 2025 and will follow that with additional solicitations every two years to meet demand, of which there is a lot, he said.

Canada at present has “zero offshore wind,” the premier said, but he believes that “from Nova Scotia, we could power most of Canada.” He said that he hopes wind power can boost the economy of his province, which is ranked lowest by GDP per capita out of the 50 U.S. states and 10 Canadian provinces.

With OSW halted in the U.S., industry players could ply their trade in Canada, he suggested, adding that his government is committed to the cause.

“I actually think that timing couldn’t be better,” he said. “Because as things settle down in the United States over the next little while, we can be getting to work in Nova Scotia and building up those supply chains and building the infrastructure and creating the energy that is so much in demand.”

Diversity Makes a Good Hub

Developing a wind port hub is considered essential to the supply chain infrastructure. So what makes a good hub? What can be gleaned from the short history of U.S. offshore wind to help inform the development of future hubs?

To answer the questions, a panel focused on hubs in Virginia, Rhode Island, New Orleans and Maryland on April 30.

The hub status of the Port of Providence, which serves the Block Island Wind Farm off Rhode Island, largely grew out of the area geography: It’s located in a key area of offshore wind activity, said John O’Keeffe, vice president of business development at Waterson Terminal Services, which manages the port.

“We are located in a key area of the majority of the offshore wind activity that’s happened in the past 10 years,” he said.

The Virginia hub, which includes the Fairwinds Landing logistics center, emerged from the area’s strong marine tradition, building upon the benefits of the Port of Virginia, the East Coast’s second largest port.

So when the need for an OSW infrastructure emerged, the state could “simply pivot some of our existing facilities, our existing supply chains, our existing workforce,” said Will Fediw, senior vice president of the Virginia Maritime Association. “We weren’t building anything from scratch.”

The New Orleans wind hub is in large part focused on Port Fourchon, which is the base of 99% of offshore oil and gas service operations in the area, said Cameron Poole, energy and innovation associate for Greater New Orleans. Those sectors have helped the hub grow, and wind has in turn provided them with support during industry slowdowns, he said.

In Maryland, the former site of Bethlehem Steel has been transformed into Sparrows Point, a trade and logistics hub, with an offshore wind component that includes a steelmaking and monopile manufacturing operation. Other OSW elements include the Crystal Steel Fabricators facility in Federalsburg and the Hellenic Cables factory under construction in Baltimore, Maryland Del. Lorig Charkoudian said.

Fediw said a key lesson is the importance of embracing a breadth of industry sectors.

It’s “the idea of administration-proofing your hubs by thinking about more of a diversified portfolio,” he said. “So many projects were wanting to be like, [‘We’ll be] all-in on offshore wind where we’re going to build a pure offshore wind terminal.’ And that created a lot of risk.”

Instead, with Fairwinds Landing, it was, “‘We’re going to buy a terminal; we’re going to develop it; and we’re going to have several business lines here,’” he said. “‘We’re going to do some offshore wind; we’re going to do some shipbuilding, ship repair; we’re going to do some project cargo, and really spread that risk across so that they’re making money.’

“That drives investment and gives the market more confidence, because they see that risk has been bought down,” he said, adding that that approach may have helped wind ports and hubs that are now struggling. “Maybe at other ports and hubs, if they had looked at that approach a little bit, it might have helped de-risk and speed up investment by having more multipurpose terminals.”

Paulina O’Connor, executive director of the New Jersey Offshore Wind Alliance, echoed the sentiment after listening to a separate panel on procurement. She said she liked some of the comments she heard, such as “the pivot to working more collaboratively with other states.” Having completed the first phase of its wind port, New Jersey has no wind project under construction and is looking at alternative ways to use the hub.

“It was very competitive in the beginning: Who’s going to get the turbine manufacturer? Who’s going to get the cable manufactured to their state?” she recalled. “I think we’ve grown and gotten smarter, and now we realize that it is better to be collaborative. And I’m really pleased to see that, and hope that New Jersey takes a step forward to implement that and works more collaboratively with New York and Delaware and Maryland, not only in the supply chain, but transmission development as well.”

Vendors Anxious but Holding Faith

Uncertainty pervaded virtually all aspects of the IPF25 conference, and vendors offering their goods and services in the exhibition hall were no exception.

Several said the conference was markedly smaller than last year, with fewer attendees and vendors. But some also held out hope the sector would rebound.

Melissa Wood, TDI-Brooks International | © RTO Insider

Melissa Wood, director of sales and marketing at TDI-Brooks International, which operates a fleet of ships that do analog mapping of the sea floor, said she had not been sure she would come to IPF. She has attended the conference for several years and was so bullish when she signed up for the 2025 conference a year ago that she took two booth spaces.

Then President Donald Trump moved against the industry, and the future looked far less upbeat.

“I’ll be honest, we did say, ‘Should we be here?’” she said. “Our owner was like, ‘I don’t think it’s going to be worth my time.’ I said, ‘We’ve already paid for the booth space.’

“We all kind of had the rug pulled out and have to figure out what to do next,” she said. “So it’s obviously slower than it has been in the past.”

TDI has pivoted and found work in the oil and gas industry, the company’s main business for 29 years, she said. But she expects the wind sector to rebound.

“I think within the next 12 months, we’ll see a change,” Woods said. “Maybe things have reset a little bit. … A lot of these developers have had to lay off folks, but they still have kept their permitting strong and their procurement people strong to be able to still trudge forward with the government to try to see if they can turn things around. I think the people here want clean energy. They’ll educate the current administration, and we’ll see a change.”

Attending his fifth IPF conference, James Gura, of the Moran Shipping Agency, a logistics and compliance company in New Haven, Conn., that is working on offshore wind projects, said he expects the sector to make a comeback.

“This convention, I would say, is a little bit slower than conventions in the past. And I think people are concerned about the stability of the market and offshore wind,” he said. But he added: “There is a need for energy diversification in the United States, and I think this is an option to fulfill those needs. We are cautiously optimistic on the future of the industry.”

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NERC Offered to Help with Iberia Outage Investigation, Robb Says

NERC CEO Jim Robb told the ERO’s trustees the organization has offered to assist its European counterparts as they investigate the recent mass blackout in the Iberian peninsula, while warning that it is “way too early” to draw any conclusions about the cause of the issues. 

Robb’s comments at the May 8 meeting of NERC’s Board of Trustees in Washington, D.C., echoed those he made at a joint meeting of FERC and the National Association of Regulatory Utility Commissioners on April 30. (See FERC-NARUC Collaborative Examines Ongoing Issues with Gas-electric Coordination.)  

They were similar to the remarks of Teresa Ribera, European Commission executive vice president for a clean, just and competitive transition, who on May 5 criticized what she called a “trigger-happy attitude” blaming renewable energy for the outages.  

Nearly the entire population of Spain and Portugal, along with parts of France, lost power on the afternoon of April 28, with electricity restored for most of the peninsula only the following day. Spain’s grid operator said the same week that the outages began with two separate generation loss incidents in the country’s southwest, but it has not identified their exact location. 

Robb drew parallels between the Iberia outages and the Northeast blackout of August 2003, which “changed so much about how we approach reliability of the [power grid] here in North America.” He also compared the incident to “some of the things we’ve seen in West Texas, California and Utah,” an apparent reference to previous grid disturbances including the Odessa disturbances of 2021 and 2022 when multiple renewable generation resources tripped offline. (See NERC Repeats IBR Warnings After Second Odessa Event.) 

While Robb advised listeners that “it’s probably best to … let [investigators] do their work,” he named a few areas in which NERC is particularly interested, such as the relative lack of inertial generation on the peninsula and the “frequency loss and voltage control that comes along with that.” He also mentioned the use of natural gas to restart the Iberian grid, which touches on questions that NERC has been studying about the North American grid’s black start capability.  

In addition to offering to help the European Energy Information Sharing and Analysis Centre with its investigation, Robb said the ERO plans to give a full briefing at FERC’s open meeting in June about the Iberian outage and its implications for North American customers. 

FERC Chairman Mark Christie, who also attended the meeting, assured Robb he was looking forward to NERC’s report and urged the ERO to “keep telling the truth.” He also expressed his hope that FERC’s upcoming technical conference on resource adequacy June 4-5, which will feature presentations from Robb as well as CEOs of the RTOs, would be “critically important” and “a seminal moment in American energy policy.” 

Kim Shares Section 321 Analysis

The board meeting featured a presentation from Soo Jin Kim, NERC’s vice president of engineering and standards, on the ERO’s use of its special powers under Section 321 of NERC’s Rules of Procedure to streamline the standards development process. 

NERC’s board has invoked its Section 321 powers twice so far: in August 2024 to move forward with standards on inverter-based resources (IBRs), and in January 2025 for a proposed cold weather standard. In both cases the ERO was facing a FERC-imposed deadline that trustees feared they could not meet through the normal stakeholder process, with standards having failed to garner enough votes in formal ballot periods. 

Kim acknowledged that the Section 321 process had been “very time consuming” and “a strain on resources” for both industry and NERC, even though both uses resulted in standards being submitted to FERC. She said the ERO staff has been working to identify the contributing factors in the development of the cold weather standard that required the board to invoke the special authority. 

So far, NERC has identified several common elements, Kim said. First, many of the comments received during the ballot period were not helpful and in some cases “contradicting … the original FERC order and the directives that were issued,” leaving the standard development team unsure how they could address industry concerns while still satisfying the commission’s mandate.

“Process inefficiencies” also contributed to the ERO’s inability to finish the standard in time, Kim said, naming the difficulty of assembling a standards development team given the limited availability of industry stakeholders as an example. In addition, she said miscommunication between NERC and industry at key moments kept the project from meeting its goals. 

NERC staff members are working on recommendations for both the ERO and industry to address these issues, Kim said. For industry, these include working out ways for interested employees to participate in NERC’s drafting teams, work groups and task forces; improving metrics for measuring the progress of standards development projects; and revising the process and timing for FERC engagement.  

Recommendations for NERC include figuring out how new participants can get involved in the standards process and enhancing the process for holding technical conferences, which formed an important part of the Section 321 cycle for both the IBR and the cold weather standards. 

RDA Updates, IBR Alert Approved

Trustees also approved changes to NERC’s regional delegation agreements at the meeting, ahead of their expiration at the end of the year. The RDAs set out NERC’s relationships with the regional entities, including their authority to engage in compliance monitoring and perform reliability assessments. They now will be filed with FERC, to take effect Jan. 1, 2026. 

In addition, the board approved a Level 3 alert setting out essential actions for registered entities to take regarding IBR performance and modeling. These include enhancing the generator interconnection and planning policies, performing a review of IBRs currently on the system to determine the accuracy of their models, and implementing process to verify the accuracy of models used in the interconnection and planning processes. 

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SPP Approves 6th Competitive Transmission Project

OMAHA, Neb. — SPP has approved its sixth competitive project under FERC Order 1000, a 345-kV transmission line in Oklahoma bringing “needed congestion relief” north of Oklahoma City.

There’s more to come. SPP also said it has classified two more transmission projects as meeting the criteria for being considered competitive upgrades.

SPP’s Board of Directors on May 6 endorsed an industry expert panel’s (IEP) recommendation to select Transource Oklahoma, with Transource Energy, to build the proposed 38.4-mile, 345-kV transmission line. Transource expects the Mathewson-Redbud project to cost $72 million and plans to energize the line in 2027.

The board also approved a bid from incumbent transmission owner OG&E Transmission, with ITC Great Plains, as the alternate builder. Their bid, the only other one submitted, had an estimated cost of $84 million. That proved to be the deciding factor.

OG&E and ITC both voted against the recommendation in the Members Committee’s advisory vote to the board. Five other members abstained from the 12-2 vote.

The IEP, comprising industry experts independent from SPP, unanimously recommended the Transource proposal. It said that while both bids were “capable” of financing, constructing, operating and maintaining the project, Transource’s bid “presented an advantage primarily based on lower costs.”

“Because there were only two proposals, the determining factor was the cost of the project,” it said.

“We felt good with that result,” Steve Strickland, the IEP’s chair, told the board and members. “We believed either respondent was capable of producing the project.”

The panel determined the project’s lifetime cost, as measured by the present value revenue requirement, would provide more than $14 million in savings to SPP customers. It said the OG&E-ITC bid provided a “more robust” engineering design that added costs and risks that “negated most, if not all, of those benefits.”

The five-person IEP met virtually and in-person after the Mathewson-Redbud project reached the criteria to be classified as a competitive upgrade. The project first was identified in the 2023 Integrated Transmission Planning (ITP) assessment as an economic project with projected costs of $110 million; it was pulled from the portfolio because some of its upgrades would qualify as a competitive upgrade. (See “MEAN Appeal of ITP Fails,” SPP ‘All Over’ Addressing Resource Adequacy.)

Mathewson-Redbud transmission project | SPP

The panel evaluated the two bids through SPP’s competitive TO selection process, required under Order 1000. It scored the bids based on engineering design, project management, operations, rate analysis and finance.

SPP Director Irene Dimitry said OG&E, the incumbent TO, will handle the substation upgrades. That lowered the initial estimate.

Transource said it was “excited to get to work building this new transmission line” and support Oklahoma’s growing economy.

The developer is a partnership between American Electric Power and Evergy, focused on developing and investing in competitive projects nationwide. AEP owns 86.5% of the company.

SPP’s board annually forms a pool of industry experts that might be called upon to review, rank and score the competitive proposals. The grid operator already has solicited candidates for this year’s IEPs.

The panels will evaluate two projects that were part of the 2024 ITP:

  • the 345-kV Belfield-Maurine-Underwood-Laramie River project, a 438-mile line that runs from the Laramie River in Wyoming up into the Dakotas and has an estimated cost of $1.1 billion; and
  • the 345-kV Elm Creek-Tobias project on the western side of SPP’s footprint, an 85-mile segment valued at $887 million.

According to a report by consulting firm Concentric Energy Advisors critical of Order 1000’s success, MISO and CAISO have considered nearly 40 competitive projects between them. SPP has considered the third most (10) and approved of six:

  • North Liberal-Walkemeyer
  • Sooner-Wekiwa 345 kV
  • Wolf Creek-Blackberry 345 kV
  • Minco-Pleasant Valley-Draper 345 kV
  • Crossroads-Hobbs-Roadrunner 345 kV
  • Mathewson-Redbud 345 kV

The North Liberal-Walkemeyer project later was withdrawn.

The 2024 ITP was SPP’s largest portfolio in both size and value in its 20 years as a transmission planning coordinator. The plan includes 89 transmission projects, representing 2,333 miles of new transmission and 495 miles of rebuilds — including 1,900 miles of the RTO’s first 765-kV lines — to address increasing load growth and changes in the region’s generating fleet. SPP expects the portfolio’s benefits to exceed costs by a ratio of at least 8-to-1. (See SPP Stakeholders Endorse Record $7.65B Tx Plan.)

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ISO-NE Discusses Details of New Prompt Capacity Market

ISO-NE and NEPOOL members discussed how to address market power, tie benefits and resource qualification in a prompt capacity market during a three-day meeting May 6 to 8.

The RTO is working to transition its Forward Capacity Market — which features auctions held three years prior to each capacity commitment period (CCP) — to a prompt market, with auctions held one month before each CCP.

The move to a prompt market is intended to increase the accuracy of available information prior to each auction and eliminate the phenomenon of in-development resources receiving capacity supply obligations (CSOs) but not coming online quickly enough to meet them.

The RTO plans to file its prompt market proposal in late 2025. Once it completes the prompt market design, ISO-NE plans to begin working on the details of a separate proposal for seasonal capacity market changes, which would split CCPs into separate six-month winter and summer periods.

Market Power Mitigation and Resource Retirements

Responding to feedback from NEPOOL members at the Markets Committee in April, ISO-NE has walked back a proposal for a penalty to prevent the abuse of market power in the new auction format.

The market power charge would have applied to retiring resources that fail a pair of ISO-NE tests to determine whether the resource is economically viable and whether its retirement would provide net benefits to the resource owner’s generation portfolio. (See ISO-NE Outlines Market Power Mitigation Measures for CAR Project.)

“Multiple sectors shared concerns on potential issues associated with an imposition of the market power charge,” said Kevin Coopey, principal analyst at ISO-NE. He said the feedback included concerns about the “individualized nature” of market power penalties on participants found to be exercising market power, compared to the “potential regional harm.”

He said ISO-NE “continues to believe that there could be benefits to a [market power charge] and may further assess such a framework after CAR [the Capacity Auction Reform initiative] is completed.”

In place of a penalty, ISO-NE plans to adapt its existing process of proxy supply offers. Proxy offers would apply only to resources that fail both the conduct test and the net-portfolio benefits test and would last for one year after a resource’s retirement.

Stakeholders at the MC generally expressed appreciation for the elimination of the proposed market power charge, while some continued to advocate for more flexibility around retirement submissions. ISO-NE still proposes to require retirement notifications to be submitted two years in advance and would not allow participants to withdraw submissions.

ISO-NE also adopted a proposal made to the MC in April by LS Power to allow accelerated retirements for requests that pass reliability and market power tests. Once a resource is approved for accelerated retirement, it would be able to retire as soon as its first month without a CSO.

Buyer-side Market Power Mitigation

ISO-NE also plans to largely maintain its existing format for mitigating buyer-side market power, economist Andrew Copland said.

Buyer-side market power occurs “when a participant with a large load-side interest attempts to lower its total capacity market costs through the uneconomic entry of a resource,” he noted.

New passive demand response resources and resources smaller than 5 MW are exempt from buyer-side market power mitigation, along with new resources supported by federal or state governments to support decarbonization and resources “that do not receive out-of-market revenues from [a load-serving entity], state or political subdivision of a state.”

Resources also could avoid mitigation by passing a conduct test or providing evidence showing that their sponsoring LSE “is unlikely to realize a material net financial benefit.”

If a market entrant does not meet any of these criteria, it would be subject to an offer floor price imposed by the ISO-NE Internal Market Monitor.

Tie Benefits

Also at the MC, members debated how ISO-NE accounts for tie benefits in the capacity market.

Tie benefits describe the level of support the RTO expects to receive from neighboring control areas during grid emergencies. ISO-NE assumes about 2,000 MW of tie benefits, which reduces the amount of capacity it needs to procure in its capacity auction.

In recent months, New England generators have pushed back against this assumption and have argued the RTO should not treat tie benefits as equivalent to resources with CSOs.

Bruce Anderson, general counsel for the New England Power Generators Association (NEPGA), said that because tie benefits are not supported by CSOs or subject to Pay-for-Performance penalties, ISO-NE should not reduce its installed capacity requirement to account for them.

“Rather than reduce the capacity market demand quantity based on a probabilistic estimate of the amount of energy ISO-NE can rely on during capacity deficiencies, the value of import megawatts should be grounded in actual, firm offer and delivery requirements,” Anderson said.

He argued that the current approach “compromises system reliability” and “displaces resources willing to assume a capacity supply obligation, including those both within New England and in neighboring control areas.”

Ben Griffiths of LS Power expressed particular concern about Hydro-Quebec interconnection capability credits (HQICCs) on the Phase II transmission line between New England and Quebec. HQICCs reduce the capacity charges for interconnection rights holders that financially support the line.

Griffiths argued the current methodology gives HQICCs “preferential treatment compared to capacity,” while non-interconnection-rights-holding participants are effectively “compelled to purchase HQICCs at above-market rates even when true performance-backed capacity is available at the same price.”

He said ISO-NE should conform its treatment of HQICCs “with either PTF [pool transmission facilities] or capacity obligations” to boost market equity and improve reliability.

He also emphasized the uncertain emergency benefits associated with the lines, noting that Hydro-Quebec has not given emergency assistance to New England over at least the last seven years.

“We have no idea how much, if any, emergency assistance [Hydro-Quebec] could provide New England when needed,” Griffiths said.

Other stakeholders pushed back on NEPGA and LS Power’s arguments, saying that tie benefits are an important input into the ICR and are supported by agreements between neighboring regions.

At the April MC meeting, Matthew Ide, of the Massachusetts Municipal Wholesale Electric Co., said that “network load customers pay for all the tie benefits that come from the PTF ties through regional transmission rates. In return, load receives the benefit of a lower ICR and less need to procure capacity to meet the ICR.” (See NEPOOL Markets Committee Briefs: April 8-9, 2025.)

Resource Qualification

Jennifer Engelson, supervisor of resource qualification at ISO-NE, detailed the RTO’s current thinking on resource qualification in a prompt auction.

New resources that have not achieved commercial operations will be allowed to participate in auction qualification activities but must come online prior to a “capacity demonstration deadline” in early April prior to the auction in May, she said. ISO-NE plans to issue preliminary qualified capacity (QC) values in February but would not finalize these values until after the demonstration deadline and a period for participants to challenge their QC values.

For intermittent resources, QC will be based on “the average of the median of the resource’s net output in reliability hours for the most recent five seasonal periods,” Engelson said.

For non-intermittent resources, QC will be based on the median seasonal claimed capability for the past five years. QC for non-intermittent imports and distributed energy capacity resources will be based on seasonal audit values.

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Panel Explores How Western Markets Have ‘Played off’ Each Other

SACRAMENTO — In the competition between two Western day-ahead markets — CAISO’s Extended Day Ahead Market (EDAM) and SPP’s Markets+ — the two market operators have “sort of played off one another,” an industry observer said. 

Kris Raper, vice president of strategic engagement and external affairs at WECC, offered her views on the developing Western markets May 6 during a California Energy Transition Summit hosted by Infocast. 

For a while, it seemed like CAISO’s Western Energy Imbalance Market (WEIM) and EDAM “were really the only game,” Raper said during a panel discussion on Western markets. 

But then “SPP sort of came in the room and they had to create a space for themselves,” Raper said. 

“My personal observation is that SPP has sort of stood back a bit and seen within … CAISO, within the EIM and the EDAM formation, what has worked for them and what has not,” Raper said. “And they have taken a script from that.” 

“It’s a good thing, right?” she added. “If it makes them all better and utilizes more stakeholder input.” 

Raper’s comments came in response to an audience member question on what California can learn from SPP’s Western market expansion. 

Another panelist, Western Freedom Executive Director Kathleen Staks, also responded. 

“California has learned that … the hatred for California is real,” Staks said. “That is part of why SPP saw that moment. California was not responding to the needs of the West in an adequate way.” 

Staks is Launch Committee co-chair for the West-Wide Governance Pathways Initiative, which is developing a new independent Western “regional organization” (RO) to oversee CAISO’s WEIM and EDAM. Some potential market participants are uncomfortable with markets led by CAISO, whose Board of Governors members are appointed by the California governor. 

The Pathways effort now hinges on Senate Bill 540 in the California legislature, which would allow an independent RO to oversee CAISO energy markets. (See California Lawmakers Seek to Trump-proof Pathways Initiative Bill.) 

Affordability, Reliability

Raper described many of her comments as “personal observations” and noted that WECC has a neutral view on energy markets.  

“If it adds to reliability, then that’s something we would support,” Raper said. 

The market developments are occurring as lawmakers in several states are responding to constituent concerns by taking back power that was delegated to utility commissions, Raper said. That means a new group of stakeholders who must be educated on the issues. 

“A lot of the reason that legislators are hearing from their constituents is because costs are so high,” Staks said. 

If SB 540 doesn’t pass, Staks said, utilities that haven’t yet committed to a day-ahead market may choose a non-CAISO option and leave CAISO’s WEIM. 

“That is not good from an affordability standpoint for California,” Staks said. “It is not good from a reliability standpoint, because it makes it harder to trade with our neighbors, and it’s not as good from an emissions standpoint.”