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February 11, 2025

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SPP Board/Regional State Committee Briefs: Feb. 3-4, 2025

RSC, Directors Approve One-time Study to Meet PRM Requirements

SPP’s Board of Directors has approved a one-time process to quickly add generation so load-responsible entities (LRE) can meet their resource adequacy needs under the grid operator’s planning reserve margin (PRM) requirements.

During its virtual Feb. 4 quarterly meeting, the board endorsed the Resource and Energy Adequacy Leadership Team’s proposal for an expedited resource adequacy study (ERAS) to ease the interconnection of new resources. The process, separate from the RTO’s existing generator interconnection (GI) process and its definitive interconnection system impact study of proposed generation, is designed to address resource adequacy concerns created by increased load projections, generation retirements and the current GI queue backlog.

While cautioning that stakeholders fall on both sides of the recommendation, CEO Barbara Sugg said, “I believe we have to do everything we can to get generation online as quickly as we can and meet our reliability needs, and I think this is a big step toward that.”

“This provides an additional optionality for those trying to meet the additional PRM requirements, so I think this is a positive step forward,” director Stuart Solomon, a former utility CEO, said.

Under the proposal, LREs will be able to select any generation and fuel type, based on their needs, for a special one-time study conducted outside the regular GI study queue. Requests accepted into the study will have priority over all GI requests without signed agreements. The requests must have a commercial operation date within two years.

The Regional State Committee (RSC), which unanimously approved the proposal during its Feb. 3 meeting, also will be required to approve the one-time ERAS.

While LREs generally supported the recommendation, developers said that existing GI requests might suffer financial harm from ERAS projects “jumping the line.” They also expressed concerns about FERC’s acceptance of an eventual tariff change, saying that it appears contrary to longstanding policy.

However, that policy could change. U.S. lawmakers have introduced legislation requiring the commission to craft rules so transmission providers can set up special queues for reliability needs and dispatchable generation. (See Bills Introduced in Congress to Speed up Queues for Dispatchable Power Plants.)

“We also understand the desire to add more generation, but we really still echo some concerns about the potential harm that this could have on projects in the existing queue and getting to our goals of getting through the backlog,” NextEra Energy Resources’ Jennifer Solomon said. “One of the problems that we see with moving this to FERC is that currently, the proposal is only open to projects that are selected by an LRE. There a number of issues that we will look at as the [tariff revision] develops, but I echo that it’s important that we stay kind of focused on how, if this moves forward, [it does so] in a way that ensures that it’s targeted, that it’s looking at how the [commercial operation dates] are going to be met.”

“We’re in a very unusual time. We have unprecedented load growth. We have these increases in PRMs, but it’s really challenging load-responsible entities,” Oklahoma Municipal Power Authority’s Dave Osburn said. “We’re the entities that are responsible for serving load. What SPP put forward is a bold plan, but this is the time for bold plans.”

The Members Committee approved the measure with its advisory vote, 16-4, with two abstentions. The Advanced Power Alliance, EDP Renewables, the Natural Resources Defense Council and Pine Gate Renewables opposed the proposal.

RA, Congestion-hedging Recs Pass

The board also approved several other recommendations related to resource adequacy and congestion hedging that previously were endorsed by the RSC:

    • A long-term PRM policy paper outlining the framework for establishing planning horizon PRM requirements and providing LREs with adequate advance notice leading up to the applicable operating seasons. Stakeholders approved a Year 4, Year 7 and Year 10 cadence for the loss-of-load expectation studies and switching the LOLE study from a biennial analysis to annually.
    • Implementing a 2029 PRM for the summer and winter seasons of 17% and 38%, respectively, based on submitted forecasts for the resource and load mix using the 2023 LOLE study.
    • Two policies stemming from the Holistic Integrated Tariff Team’s work on congestion hedging. One increases opportunities for all market participants to receive long-term congestion rights (LTCRs) awards and the other coordinates with planning to review firm transmission assumptions used in planning processes. The LTCR proposal allows the netting of flows in their allocation. Eligible participants can nominate up to 50% of each path, with all current awarded LTCR paths over 50% grandfathered. The awarded LTCRs can be held for five years.

SPP staff said the increase in LTCRs would improve their allocation while also maintaining participants’ ability to retain current allocations by grandfathering those rights. That would result in more awards with no entity losing their current positions there, they said.

However, stakeholders pushed back, as they have since firm transmission service customers first asked in 2016 for improvements in determining the amount of auction revenue rights awarded in the annual and monthly ARR allocations. The Market Working Group and Cost Allocation Working Group both voted against the proposals, expressing a desire to wait until the 2025/26 LTCR period to evaluate other changes. Concerns also arose that allowing more LTCRs to be allocated could lead to underfunding issues.

“I think we have a responsibility to think about the public interest, and expanding the size of the pie is a way to create value for customers across the SPP region,” director Steve Wright said. “A 50% increase in LTCRs seems like a very big deal to me. There’s a lot of value that’s created and therefore, a lot of benefit that can flow through to members in the SPP region. I think we have a responsibility to go try and make that happen and continue to work with those who are concerned that their existing rights may be impacted in some way.”

EDP Renewables’ David Mindham was among those protesting the congestion-hedging recommendation over what he said was a lack of equity in allocating LTCRs.

“What we’re saying in SPP right now is the only way you can get value from paying for transmission is if you’re already getting that value, so that discourages new entry into willingly paying for transmission on the SPP system,” he said. “EDP has paid for a lot of transmission service throughout the years. We’re not going to do that anymore. We’re not going to willingly pay for transmission because we weren’t here long enough to derive value from the existing long-term congestion process. We’ve been run out of the market.”

The Members Committee voted against the motion with their advisory ballot, 6-10, with six abstentions.

Nickell, Sugg Share CEO Report

Lanny Nickell, who doesn’t officially take the CEO’s reins at the RTO until April 1, shared his initial thoughts with stakeholders while sharing the president’s report to the board with Sugg.

“I made a commitment to the board to help SPP succeed by placing an emphasis on operational excellence, ambitious strategy and high visibility,” he said. “Those are the three pillars that I believe will allow us to be successful, if built upon a foundation of SPP’s world-class culture and stakeholder experience.” (See Nickell: SPP’s Culture Paves Way for its 2025 Success.)

Nickell listed SPP’s three corporate goals for 2025, down from five the year before:

    • Continuing to mitigate resource adequacy risks (he sits on the Resource Energy and Adequacy Leadership Team).
    • Accelerating generator and load interconnection while planning for the load of the future.
    • Continuing SPP’s Western expansion.

“Just because there’s three and not five doesn’t mean there’s less work,” he said. “These do not represent all the work and initiatives that will be undertaken throughout the year. They just simply represent the objectives that need to be most visible within our member community and within the organization and need a higher degree of focus and attention to ensure successful completion.”

Sugg, who announced her retirement last year, said, “I’ve worked with Lanny for a long time, and I have every confidence that he’s the best choice.

“As I look forward, I’m excited about where SPP is headed,” she added. “There’s no shortage of challenges, but we’ve proven time and time again that we always rise to the challenge. Lanny has got a lot on his plate and very high expectations that he set for himself, never mind the expectations that you all set for him. Certainly, I’m going to be watching SPP from the front row with my pompoms and whatever else I need to cheer on the organization as a whole.”

Ellis Retires, Evergy Exec Hired

Sugg also said Sam Ellis had retired Feb. 3 as vice president of IT after 22 years with SPP. He joined the organization in 2003 from member company Empire District Electric Co.

“It’s particularly noteworthy that I tried to hire Sam, and he rejected my offers prior to 2003, not that I’m holding a grudge against Sam or anything,” Sugg said. “He finally did come to SPP, and he did finally come and work directly for me. Anyway, we’re going to miss Sam, his sense of humor, his love for this company, and for our people.”

Sam Ellis (left), Kevin Bryant | SPP

Ellis received a round of virtual applause from the board and stakeholders.

Nickell tag-teamed Sugg by announcing Kevin Bryant’s hire as the RTO’s first executive vice president of stakeholder affairs and chief strategy officer. Bryant will oversee the development and execution of SPP’s corporate strategy; lead the administration of its stakeholder process; and direct the management of the organization’s relationships and communications with internal and external stakeholders, including member companies and market participants in the Eastern and Western Interconnections.

Bryant comes to SPP after 22 years at Evergy, where he most recently was the company’s COO and its CFO before that. He will join the staff April 1.

RTO Western Expansion Progressing

COO Antoine Lucas said during the quarterly update to stakeholders that while SPP has received tariff approval for Markets+, it also is waiting on FERC’s go-ahead for its Western RTO expansion. The RTO filed a response to the commission’s deficiency filing in November.

“I hope that we will get that approval toward the middle of this month,” he said.

Lucas said in the meantime, staff is working with its vendor to build out the market systems. He said there have been a “few challenges” with software delays, but that staff is working to ensure the RTO expansion meets its April 2026 go-live target.

Casey Cathey, vice president of engineering, said SPP signed 108 generator interconnection agreements for more than 18 GW of capacity in 2024, three times more than the 10-year average for GIAs. He said the RTO expects to execute another 150 GIAs for 6.7 GW this year, when four study clusters are expected to enter negotiations for GI agreements.

The GI backlog effort continues, Cathey said, with clusters through 2022 resolved this year. The 2025 study cluster closes March 1, leaving the 2026 cluster as potentially the first study group under SPP’s consolidated planning process. Staff plans to bring a revision request for stakeholder approval in the second quarter this year and file a tariff change at FERC in the third quarter.

RSC OKs Order 1920 Extension

The RSC unanimously approved staff’s recommendation to request an extension of a six-month engagement period under FERC Order 1920 until Nov. 3.

The order requires transmission operators to produce a 20-year regional transmission plan to identify long-term needs at least every five years. SPP has produced 20-year plans for at least a decade. However, it still is subject to a six-month engagement period to allow state entities to negotiate a cost allocation method and/or a state agreement process.

“It really appears FERC wants to model other regions after what SPP does, and that is to have states involved in cost-allocation decisions provided to transmission upgrades,” SPP General Counsel Paul Suskie told the regulators.

SPP’s engagement period was to end May 5, but several RSC members expressed a desire for an extension. The committee is responsible for determining cost allocation issues, financial transmission rights allocations and the regional resource adequacy approach.

STEP Report Approved

The board’s unanimously approved consent agenda included:

    • Approval of the 2025 SPP Transmission Expansion Plan report, which indicates 43 transmission upgrades, valued at $161.8 million, have been completed since the 2024 report. Another 290 upgrades were issued notices to construct, valued at $3.2 billion, and 20 upgrades worth $195.4 million were withdrawn.
    • A revision request (RR650) to develop HVDC planning criteria for SPP’s governing documents.
    • Endorsement of the Oversight Committee’s recommendation that the 17 members of the 2024 industry expert pool be renewed for 2025 and that five new members be added: former SPP exec Michael Desselle and Carolyn Barbash, Adrienne Bradley, Susan Thomas and Stanley Krause.
    • Adding an independent director to the 24-person Strategic Planning Committee, giving the board between three and five seats.
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MISO Members to Explore Ways to Rev Up Stalled Generation Builds

MISO members teed up a discussion on the approximately 57 GW of approved but unfinished generation in the footprint that will be a focal point of MISO’s quarterly Board Week in March.  

MISO’s Advisory Committee plans to host a discussion titled “Stalled GIAs: Challenges, Inefficiencies, Impacts” at its all-day meeting March 12 in New Orleans. Members will probe the footprint’s growing number of generation projects that have signed generation interconnection agreements (GIAs) but have yet to reach commercial operation.  

MISO has said its resource adequacy standing would be less precarious if some of the 57 GW would come online. It has pinned the delay mostly on blocked supply chains. 

“While we appreciate the work MISO has done to track the status of projects, there are some other elements that warrant discussion to get a full picture of this topic,” NextEra Energy’s Erin Murphy said.  

MISO first reported in 2023 that it was sitting on about 50 GW in generation projects that have earned stamps of approval to connect to the system but weren’t completed. (See MISO: Reliability Risk Upped by 49 GW in Approved but Unbuilt Generation.) That number has grown.  

MISO and members circulated a list of draft questions for sectors, including naming the leading factors for so many GIAs to become stationary and suggesting improvements for how to get projects unstuck and prevent that from happening in the future. The list also asked members to evaluate to what extent MISO’s proposed, fast-tracked interconnection queue lane might help. 

Advisory Committee leadership will take members’ suggestions on the draft discussion starters through Feb. 19.  

MISO surveyed generation developers over the delays and found they consistently cited supply chain issues on the part of transmission owners as a source of the holdup. Illinois and Indiana lead MISO with the most megawatts signed for but not online. 

MISO in late 2024 concluded its members need to bring projects online at an “unprecedented” 17-GW-per-year clip to achieve resource adequacy while decarbonizing the grid. That’s triple the rate members have added per year over the past few years. (See MISO Assessment Calls for 17 GW in New Resources Annually.) However, RTO staff have warned that the generator interconnection queue isn’t the source of guaranteed resource additions that it used to be and that projects could face anywhere from three- to seven-year delays before megawatts materialize on the system after signing their interconnection agreements.  

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MISO TOs Take ROE Battle to DC Circuit Court Again

MISO transmission owners again have taken arguments against FERC’s most recent return on equity decision to the D.C. Circuit Court of Appeals. 

The transmission owners on Feb. 4 submitted a petition for review of FERC’s October order that set their base ROE at 9.98%, down from the previous 10.02% (25-1045). They said the commission impermissibly and retroactively backdated ROE to “an earlier order that FERC abandoned” while including eight years of interest as part of the excessive refunds ordered. 

FERC most recently settled on MISO transmission owners’ ROE by once again eradicating the risk premium model from the calculation. (See FERC Sets MISO TOs’ ROE at 9.98%, Again Eliminates Risk Premium Model.) The commission reasoned there was no evidence investors use the model. FERC stuck to the remaining two models — the discounted cash flow and the capital asset pricing — to establish a zone of reasonableness and set the ROE at its midpoint.  

At the time, FERC’s decision appeared to settle a more than 10-year-old back-and-forth over which rate inputs are appropriate.  

MISO TOs’ rehearing request of the October decision was denied Dec. 19, 2024, because FERC failed to act on it within the statutorily prescribed 30-day period (EL14-12, et al). In their request, MISO TOs said they shouldn’t be subjected to “punitive interest for multiyear delays far outside of the MISO transmission owners’ control” because of FERC’s delay in addressing complaints filed more than a decade ago. 

The transmission owners also argued to the D.C. Circuit that the latest ROE decision lends legitimacy to “an underlying unlawful complaint” made in 2015. 

MISO transmission customers in late 2013 first complained that the 12.38% ROE in use since 2002 was excessive. A second complaint challenging the ROE followed in 2015; that complaint was dismissed as FERC set and reset ROEs from 2016 onward (10.32% beginning in 2016, 9.88% in 2019, 10.02% in 2020).  

MISO TOs said since the second, 2015 complaint made no new allegations and presented no new facts or analyses on ROE, only the first, 2013 complaint should be considered for FERC’s 15-month limit on refunds per the Federal Power Act. The TOs said the 2015 complaint included identical analysis and identical allegations as the 2013 version. They argued it amounted to a “transparent attempted end-run around” to roll another 15-month period into the assorted ROE refunds and ultimately had FERC backdating refunds with interest to 2016. TOs said FERC should have dismissed the 2015 ROE complaint as an “unlawful successive complaint” instead of referring to it as a point in time for refunds.  

MISO TOs argued that FERC only may establish new rates prospectively and cannot claim that it “simply granted rehearing in the more than eight years” that passed since it set the 10.32% ROE, especially since new ROE orders have come and gone since then. TOs said FERC only should have used the original, 15-month span between 2013 and 2015 for refunds when it set the current, 9.98% value.  

This isn’t the first time the D.C. Circuit has been asked to weigh in on the long-running ROE question.  

FERC found the ROE case back on its docket last year because the D.C. Circuit in 2022 vacated the commission’s 10.02% value due to the risk premium model’s inclusion since 2020. On a petition for review from transmission customers, the court said it didn’t understand why FERC would dedicate pages to describing the risk premium model’s shortcomings, circular nature and scarce use only to reinstate its application a few years later in 2020. (See DC Circuit Sends FERC Back to Drawing Board on MISO ROE.) 

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Bills Introduced in Congress to Speed up Queues for Dispatchable Power Plants

Rep. Troy Balderson (R-Ohio) introduced legislation on Feb. 6 that would speed up the nation’s interconnection queues for “dispatchable generation,” with a companion bill introduced in the Senate by Sens. John Hoeven (R-N.D.) and Todd Young (R-Ind.).

The Guaranteeing Reliability through the Interconnection of Dispatchable (GRID) Power Act would allow certain projects, at the request of grid operators, to bypass overwhelmed queues. It would require FERC to craft rules to that effect for transmission providers to set up a special queue for such projects needed for reliability.

Grid operators would have to show a reliability need and how such a project would address it and provide a process for public comment and stakeholder engagement before taking a proposal to FERC. Any proposal to speed a project through the queue would have to go to FERC for approval and be open for comments from all parties.

“Our interconnection queue is buckling under its own weight,” Rep. Balderson said in a statement. “Transmission providers are tasked with ensuring we have enough electricity to keep the lights on, but the growing backlog of projects is adding years to an already time-consuming process. This legislation would give grid operators the authority to identify and expedite the consideration of essential projects that will protect our grid’s reliability and provide the power needed to meet America’s growing demand.”

The bill, a version of which Balderson introduced late in 2024 as well, is supported by the Electric Power Supply Association, a trade group of independent power producers that build many of the power plants that would benefit from a quicker path through the queue.

“EPSA is a staunch supporter of the benefits of competitive markets. However, no economic model or structure can overcome inefficiencies in the interconnection process that can significantly delay critical investment in new dispatchable generation,” said EPSA CEO Todd Snitchler. “This legislation appropriately creates a process that recognizes when reliability concerns require that certain investments be prioritized in the interconnection queue. The proposal is designed to recognize when reliability may be at risk and respond in a prudent and targeted manner.”

EPSA said natural gas power plants will continue to be needed for decades even as more intermittent resources are added to the grid.

The legislation comes as artificial intelligence is driving a spike in data center demand and leading to demand growth for the first time in decades. New investment and rapid development of dispatchable generation resources is needed to meet that, with EPSA pointing to the recent PJM capacity auction and its resulting price spike as signaling the need for more investment.

The RTO has made several filings at FERC that would seek to speed up new capacity through the queue, though the closest change to the legislation — the Reliability Resource Initiative — would only be for Transition Cycle No. 2, not permanent like the legislative proposal.

“Bureaucratic delays are slowing critical power projects and threatening the reliability of our electric grid,” said Sen. Young. “We need to cut through red tape to get more power online faster. This bill will strengthen our grid to promote American energy independence and drive economic growth — especially in states like Indiana, where reliable energy is vital to jobs and Hoosier workers.”

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Oregon Utilities Enter 2025 With Ambitious Wildfire Plans

Increased wildfire risk in the Pacific Northwest has spurred utilities to adjust their operations to account for climate change and other contributing factors to better predict and fight fires going into 2025, utilities told the Oregon Public Utility Commission on Feb. 6.

There were 64,897 reported wildfires in 2024 that burned approximately 8.9 million acres nationwide, compared to 2.7 million acres in 2023. Oregon saw nearly 1.8 million acres burned due to wildfires, according to the National Interagency Coordination Center.

The “rapidly increasing impacts of climate change” are the predominant drivers behind the approximately 55% increase in wildfire risk in 2025 compared to 2024 risk models, Kellie Cloud, senior director of wildfire and operational compliance at Portland General Electric, said during OPUC’s wildfire workshop.

“Extreme weather events, drought and tree mortality all increase the potential for smaller fires to grow into destructive wildfires,” Cloud said.

The utility’s 2025 risk model also confirmed the importance of increased investment in system hardening and the effectiveness of PGE’s vegetation management, according to PGE’s presentation.

Some of PGE’s efforts already have paid off as it has reduced the size of certain high-risk zones by, for example, converting 8.7 overhead line miles to go underground and improving risk methodologies, Cloud said.

These efforts will continue into 2025, with PGE — which serves about 900,000 customers — planning to convert 26 line miles of overhead to underground, reducing ignition likelihood by addressing tree mortality and installing more wildfire detection cameras, among other things.

Similar efforts are underway by Idaho Power, which serves 20,000 customers in Oregon and another 650,000 across Idaho.

2024 marked an intense fire season for Idaho Power, said Jon Axtman, the company’s wildfire mitigation and transmission and distribution engineering director.

The utility saw 1,509,455 acres burned across its service area, which is about 175% above normal for the fire season in terms of acres burned, according to Idaho Power’s presentation.

“Wildfires in 2024 impacted the reliability of our customers as well, and we had 46 outages across the entire service territory that were either caused by fires burning into our lines, threatening or damaging equipment, or at the request of fire agencies to deenergize for safety purposes,” Axtman said.

He added that the utility also initiated its first ever full public safety power shutoff (PSPS) in 2024, which impacted thousands of customers.

The event led Idaho Power to reassess some of its operations, according to Axtman. For example, the utility installed more weather stations to gather wind speed data quickly instead of relying on publicly available data. Weather stations also could reduce the utility’s reliance on field observers in remote areas, he said.

Similar to PGE, Idaho Power will focus on system hardening in 2025, installing fire resistant wrap around transmission poles and building out its network of wildfire cameras, according to Axtman.

Representatives from PacifiCorp also participated in the wildfire workshop to discuss its mitigation plans in Oregon. The utility serves 623,000 customers in the state across nearly 21,000 square miles, about 14% of which is in high-fire risk areas, according to Melissa Swenson, director of PacifiCorp’s wildfire mitigation program.

Among the initiatives PacifiCorp has launched include expanding its fire risk model to cover its entire service territory, not just high-risk areas, and it has implemented a new PSPS forecast editor “to be more targeted about when a PSPS can happen,” Swenson said.

The utility also has increased its distribution hardening target from 125 miles in 2024 to 175 miles in 2025, and increased the number of fire season safety patrols, according to Swenson.

“Grid hardening is really the way to reduce the operational costs of the work, but also to improve the reliability,” Swenson said. “Because I think, you know, over time, if we have more hardening, maybe we don’t have to do the PSPS events.”

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DOE Official to NASEO: ‘There is not an Energy Transition’

WASHINGTON ― “The Trump administration will have a 180-degree opposite view of energy and climate issues than the previous administration,” Lou Hrkman, acting assistant secretary at the U.S. Department of Energy, told the opening session at the National Association of State Energy Officials’ Energy Policy Outlook Conference on Feb. 5.  

And he added, “From my standpoint, thank goodness!” 

Hrkman served as DOE deputy assistant secretary for advanced energy systems and carbon management in the first Trump administration, and this time around is heading the Office of Energy Efficiency and Renewable Energy. Facing a ballroom full of state energy officials, he outlined what that policy U-turn will mean with newly confirmed Energy Secretary Chris Wright, a fossil fuel executive, leading the department. 

Hrkman agrees with his new boss’s much-publicized view that “there is not an energy transition.” Citing figures from the U.S. Energy Information Administration, Hrkman said that by 2050, “fossil fuels will continue to provide 80 to 85% of energy use worldwide, just about the same percentage as it is now. Renewables are additive; they are not replacing fossil fuels.” 

He also endorsed Wright’s belief that “climate change [is] a challenge, but ending world energy poverty is a more important goal.” 

Hrkman’s remarks received respectful, if not enthusiastic applause from an audience of state officials who are now waiting to see if they will receive the billions in federal dollars they were awarded for a range of clean energy projects funded through the Inflation Reduction Act and Infrastructure Investment and Jobs Act.  

The Office of Management and Budget issued and then quickly rescinded a funding freeze days before the NASEO event, followed by a restraining order issued by the U.S. District Court in D.C. Still, ongoing uncertainty provided the background buzz at the conference. (See Judge Issues Restraining Order on Trump Admin over Funding Pause.) 

“There’s a lot of angst at the state level, and that’s red, blue and purple across the board,” said California Energy Commissioner Andrew McAllister, a past president of NASEO. “These monies, many of them, have been contracted already. They’re obligated. We have contractors ready to spend the money, in some cases, already spending the money and putting programs together and pushing out rebates to American citizens. And so, I think it’s a shame if that stops.” 

While not mentioning solar, wind or storage, Hrkman called for a “best-of-the-above” approach, which puts fossil fuels first as critical to “American civilization. … There is no analysis by any credible source or government organization that concludes net zero will be achieved by 2050; not here in the U.S., not in your states, not anywhere in the world.” 

“Net zero can only be achieved when technology advances,” he said. “Over time it is accepted by the public. The new technology is affordable, and market forces, not government mandates lead the way.” A similar time-and-technology approach will eventually bring down greenhouse gas emissions, he said. 

The technologies DOE will prioritize going forward, besides fossil fuels, will be nuclear, geothermal and fusion energy, he said, while building out supply chains for critical mineral mining and refining.  

He also signaled a rollback of energy efficiency standards for home appliances set by Biden’s DOE, arguing that consumer choice and commonsense goals would provide “real energy savings, [and] dollars in real pockets for real consumers.” 

On permitting reform, Hrkman said it is “desperately” needed but should not be used “as a smoke screen to allow socialized costs of new transmission for renewable energy sources. Ratepayers in the states and cities that use that energy should pay the full cost for transmission, just like it is today.”  

Political Rhetoric, Physical Reality

On his first day in office on Feb. 5, Wright backed up Hrkman with a series of orders aimed at implementing President Donald Trump’s Jan. 20 executive order on Unleashing American Energy, beginning with a blanket refutation of cutting greenhouse gas emissions to net zero as a long-term U.S. goal.  

Calling net zero too expensive and ineffective in cutting emissions, Wright said, “going forward, the department’s goal will be to unleash the great abundance of American energy required to power modern life and to achieve a durable state of American energy dominance.” 

He also pledged a thorough review of DOE’s research and development activities to prioritize “true technological breakthroughs ― such as nuclear fusion, high-performance computing, quantum computing and AI ― to maintain America’s global competitiveness. … 

“The long-awaited American nuclear renaissance must launch during President Trump’s administration,” he said. “The department will work diligently and creatively to enable the rapid deployment and export of next-generation nuclear technology.”  

Other priorities include refilling the U.S. Strategic Petroleum Reserve; developing more baseload, dispatchable resources to improve grid security; and, of course, permitting reform. 

Arguing against Trump’s attack on clean energy and climate action, Rep. Doris Matsui (D-Calif.) countered that “our energy system and climate change are inextricably linked. Many people want to pretend climate change isn’t happening. The physical reality doesn’t bend to political rhetoric.  

Rep. Doris Matsui (D-Calif.) | © RTO Insider LLC

“We must reduce emissions as quickly and rapidly as possible while still improving grid reliability, reducing energy costs and meeting increasing energy demands.” 

Matsui called the challenges ahead “a perfect storm, unlike anything we faced before,” urging state officials to “get serious about working together.” 

“We must chart a path forward that is both forward-looking and feasible,” she said. “We are not on that path. Banning wind energy, blocking solar on federal lands, tariffs on energy imports and critical grid equipment, this is not going to make energy cheaper. This is not going to make energy more abundant or more reliable.” 

Grid-enhancing technologies and demand flexibility provided by distributed energy technologies such as virtual power plants should not be partisan issues, she said. 

“It’s common sense that we need more capacity to transfer energy where it’s needed most,” she said. “We should embrace a more flexible, more dynamic energy paradigm.” 

Echoing Matsui, McAllister said states will have to work with the federal government and compromise will be key.  

Hrkman’s speech provided some clarity for state officials at the conference, McAllister said. “We’re just hearing exactly what we needed to hear and to understand the directions the new administration is proposing.” 

While California has the resources to ride out a funding pause and keep some of its IRA-funded clean energy projects “on life support” at least for a while, McAllister acknowledged that other states might not have the same options. 

He sees the federal focus on reliability, affordability, jobs and economic development as a starting point where federal and state energy officials might work together. “There’s plenty of palette for us to paint with,” he said. 

“When the smoke clears and we figure out what the actual, sort of substantive daily priorities are going to be for the staff at the Department of Energy, and what initiatives they’re actually going to be working on — I don’t really want to speculate — but I feel like there’s a lot that we can do together, and I hope that we do.” 

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Equinor, Ørsted, Vestas Say US OSW Market in Trouble

Three companies closely involved in offshore wind power development offered a glum assessment of the sector’s prospects in the U.S.

Developer Equinor and turbine manufacturer Vestas reported their year-end results Feb. 5, and developer Ørsted on Feb. 6.

Equinor and Ørsted, who are behind three of the five U.S. projects now under construction, said they expect to continue with those projects even as the Trump administration has moved to strangle a sector that enjoyed strong support during the Biden administration.

Vestas CEO Henrik Andersen offered the opinion that the industry had set itself up for trouble in the U.S. over the past 18 to 24 months, a period when most advanced projects in the Northeast canceled their offtake contracts and sought more money or were paused.

Equinor and Ørsted both said they would scale back their investments and their expected buildout of renewables through the end of the decade. Vestas, which booked its first U.S. offshore order in 2024, said it expected a steep learning curve with negative financial impacts in early deliveries of its new V-236 15-MW offshore turbine.

“We will not take unnecessary risks by entering a revitalized arms race or being swayed by unrealistic political aspirations,” Andersen wrote in an introduction to the annual report.

Financial analysts asked executives of all three Scandinavian companies for their thoughts on the U.S. market.

Ørsted

2024 was another costly year for Ørsted’s U.S. operations.

“We have recorded total impairments of [$2.16 billion] for the year, with the majority relating to the adverse developments within our U.S. offshore wind portfolio,” newly appointed CEO Rasmus Errboe said.

CFO Trond Westlie said the company expects a further ramp up in costs as its Revolution Wind and Sunrise Wind projects move closer to completion. Revolution began offshore construction in 2024 while Sunrise will begin in 2025; both are behind schedule, causing some of the cost impairment Errboe cited.

Errboe said the company will invest in fewer offshore projects and reduce its 2030 capacity goals as it cuts its investment plans by 25% through the 2020s, but said it remains fundamentally confident in the long-term attractiveness of offshore wind as a means of energy generation.

Revolution and Sunrise are not affected by President Donald Trump’s freeze on new offshore wind leasing but potentially could be impacted by the review of existing leases that Trump also ordered, or by new tariffs on what is a heavily European supply chain.

An analyst asked if Ørsted had given itself enough of a buffer. Errboe said he thought it had, but added: “There is no doubt that we have seen increased pressure on our metrics, and obviously, in particular, due to the recent events in the U.S.”

Equinor

Equinor said it expects to increase its oil and gas production by more than 10% over 2024 levels by 2027. It also expects to reduce its renewables and decarbonization investments to about $5 billion from 2025 through 2027. And it is lowering its target for renewables capacity to 10 to 12 GW by 2030.

CEO Anders Opedal noted the uneven nature of the energy transition globally and pointed to pressures such as inflation, supply chain bottlenecks and regulatory uncertainty. “In our view, the energy transition must be balanced and financially sustainable,” he said.

Equinor is developing the 810-MW Empire Wind 1 off the New York coast. Onshore work has begun, and the company hopes to bring the $7 billion project online in 2027.

An analyst asked what would happen if Empire lost the $2 billion in federal investment tax credits that make up a key part of its financing.

Opedal thought that scenario unlikely — but not impossible, given the nature of politics. “We advocate to all governments that we talk to that predictability and stability and regulatory framework, it’s important, otherwise energy companies like us and others cannot invest in those countries.”

There is a long U.S. history of grandfathering projects affected by policy changes, Opedal said. That does not remove the uncertainty facing Empire Wind 1, but Equinor is pushing forward with it, he added.

“And altogether it has been a challenging project, but, you know, close to 10% equity return. So this is not great. It is OK.”

Cancellation at this late point would carry substantial costs of its own.

Vestas

Vestas in 2024 received its first-ever U.S. offshore wind turbine order: 54 of the V-236 turbines to power Empire Wind 1.

CEO Andersen seemed pessimistic about a second order coming anytime soon.

“I think the offshore has come to a stop more or less, with immediate effect,” he said, referring to Trump’s executive order.

“And of course, I can only regret that. But on the other hand, I think also it’s an appreciation of that the actual and factual things happening in the U.S. East Coast over the last two to three years probably stopped that themselves some time ago, because it wasn’t transparent and it didn’t give a [line of sight] how to build a pipeline there.”

Andersen clarified for another analyst:

“I think the offshore U.S. [wind industry] probably stopped themselves 18, 24 months ago, because it didn’t give the visibility and it didn’t get the traction on auctions coming out on a frequent basis between the six states. And of course, somebody has taken a bit of an advantage of that and probably stopped most of it. I feel strongly for the people that have spent now three, five, six years in working on offshore projects.”

Vestas cooled on the idea of building U.S. factories for offshore wind components 18 to 24 months ago, Andersen said. Its main offshore wind infrastructure in the U.S. now is human knowledge, he said, and the company will try to transfer key personnel to other parts of the company.

U.S. onshore wind is an entirely different situation for Vestas.

It has a factory, a domestic supply chain and more than 5,000 employees in this country, plus a large book of orders and a much stronger position from which to roll with the Trump administration’s policy changes.

“We see the onshore and the offshore very differently,” Andersen said. “When it comes to the onshore backlog, we are well covered for ‘25, we are well covered a long distance into ‘26, and right now, I will say, the dialog with customers are really, really well.

“I will confirm, many people are still sticking to their projects, the pipeline. And also, not to forget, the states generally appreciate the buildout and also need the electricity generation.”

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SCE Probes Link Between Equipment and Eaton Fire

Southern California Edison told the California Public Utilities Commission on Feb. 6 that it is reviewing videos suggesting a link between its equipment and the devastating Eaton Fire in Los Angeles, while also acknowledging its equipment may have sparked the smaller Hurst Fire. 

SCE said in a letter to the CPUC that a video published by the New York Times “appears to show two flashes of light in the Eaton Canyon area” on the evening of Jan. 7, around the time the Eaton Fire started. The video led the utility to launch an internal investigation into whether there is a connection between the flashes and SCE’s equipment, according to the letter. 

“Information and data have come to light, such as videos from external parties of the fire’s early stages, suggesting a possible link to SCE’s equipment, which the company takes seriously,” the utility said in a news release. “SCE has not identified typical or obvious indications that would support this association, such as broken conductors, fresh arc marks in the preliminary origin area or evidence of faults on the energized lines running through that area.” 

However, SCE acknowledged in a separate letter that its equipment may have sparked the Hurst Fire, which burned roughly 799 acres and damaged two homes. There were no reports of fatalities or injuries associated with the fire. The Los Angeles Fire Department still is investigating, and SCE said it is cooperating with the probe. 

Eaton Fire

SCE has three transmission towers, which collectively carry four active transmission lines, in the area where the Eaton Fire started. The lines were reenergized briefly Jan. 19, but field workers deenergized them again after noticing small flashes of white light upon each reenergization, according to SCE’s letter to CPUC. 

Before-and-after photos of one of the towers show no “obvious signs of arcing or material changes.” SCE said it expects to learn more after it can thoroughly inspect the structure.  

Photos from a different structure approximately “five circuit miles from the preliminary origin area” did find “signs of potential arcing and other damage on the grounding equipment for two of the three idle conductors,” SCE wrote in the letter to CPUC. 

“SCE does not know when this damage occurred, and a comparison between pre- and post-fire photographs is underway,” the letter stated. “SCE continues to assess these facilities, including any potential relation to the cause of the fire.” 

The utility also said it had not found any faults with the four energized transmission lines that run through the Eaton Canyon in the 12 hours before the reported start time of the fire. 

The Eaton Fire began shortly after 6 p.m. Jan. 7 and burned more than14,000 acres. The deadly fire engulfed parts of the Altadena community, with thousands of structures either damaged or destroyed. The flames claimed at least 17 lives, according to Cal Fire.  

SCE filed an incident report related to the Eaton Fire on Jan. 9 after receiving “significant media attention” and preservation notices from counsel representing insurance companies.  

A spokesperson for the utility told RTO Insider in January that “no fire agency has suggested that SCE facilities were involved in the ignition of the [Eaton] fire, and they have not requested the removal and retention of any of our equipment.” 

In its most recent update to the CPUC, SCE contended it has performed numerous inspections from 2020 through 2024 on its transmission facilities in the Eaton Canyon. 

The utility said it is evaluating several “potential causes,” including whether one of the lines became energized through, for example, induction. SCE also is investigating “human activity near the county’s preliminary area of origin.” 

SCE said the investigation could take several months to complete. 

If SCE’s equipment is found to be at fault, the utility’s credit rating could take a hit, Moody’s Ratings cautioned in a report Jan. 16, per Reuters. The report also said the company could see financial damage if the California Wildfire Fund runs out of money. Utilities pay into the fund to receive reimbursements for some wildfire claims.  

Additionally, legal challenges are starting to trickle in. Some affected by the Eaton Fire have filed lawsuits against SCE, alleging the blaze began under one of the company’s transmission towers. SCE also has received preservation notices from counsel representing insurance companies.  

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SPP Sets Deadline for Markets+ Funding Agreements

Financial backers of Phase 2 of SPP’s Markets+ have until Feb. 14 to submit executed funding agreements, the RTO said in a monthly newsletter sent out Feb. 5.

SPP said it will distribute the agreements to “interested parties” — the key market participants — on Feb. 7. The RTO has estimated the Phase 2 implementation stage will cost about $150 million.

The Feb. 5 newsletter also said SPP is “working to finalize” Phase 2 “intent to participate” agreements and stakeholder agreements for non-funding parties, which should be distributed later this month.

Markets+ so far has received solid commitments from Powerex, Arizona Public Service, Salt River Project, Tucson Electric Power, UniSource Energy Services, El Paso Electric and Chelan County Public Utility District in Washington.

The funding agreement deadline could pose a challenge for the Bonneville Power Administration, which repeatedly has affirmed that it plans to shell out its estimated $25 million share for funding Phase 2 before making a decision to commit to the market. But BPA, which would be the second largest funder after Powerex, also recently indicated it still is working out details around the exact amount and timing of its payment. (See BPA Considers Impact of Fees in Day-ahead Market Choice.)

Speaking at a Jan. 28 workshop at BPA’s Portland, Ore., headquarters, staff told stakeholders the agency estimates it would incur $13 million to $15 million in annual operating costs to participate in Markets+, on top of the $25 million in implementation fees. By comparison, CAISO’s Extended Day-Ahead Market would cost $2.5 million to $3 million in upfront implementation costs, with annual costs in the form of ISO grid management charges estimated at $29 million.

BPA did not respond to a request for comment in time for publication of this article.

Asked whether BPA might be allowed an exception to the deadline, SPP spokesperson Meghan Sever said: “Like with Phase 1, there will be a grace period to give entities the time needed to sign and return agreements.”

Sever also pointed out that non-funding parties signing agreements to participate in Phase 2 “will have a separate timeline for those agreements, which will be sent once the funding agreement process is complete.”

At a Feb. 4 meeting of SPP’s Board of Directors, SPP COO Antoine Lucas said the funding agreements already have been distributed for review by participants, and the RTO could receive those executed “as early as the middle of this month.”

Lucas said hitting the Markets+ scheduled go-live date of 2027 is “really going to depend upon the timeliness of receiving executed agreements to move forward with the market.”

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Xcel Sees Little Effect from Executive Orders on Energy

Xcel Energy CEO Bob Frenzel told financial analysts Feb. 6 that the Trump administration’s energy-related executive orders will have little effect on the company’s operations.

Frenzel reminded analysts during the company’s fourth-quarter conference call that Xcel doesn’t have any wind projects offshore or on federal lands and that its permitting needs for wind, solar and storage assets are “relatively light.”

“I think we’ll be able to work through it all, and I’m optimistic that our capital plans for 2025 and beyond are going to remain intact,” he said. “We’ll be able to work with the administration and all the agencies to make progress here.

“We need to be able to move very quickly on building our infrastructure and making sure that we can serve our customers. Look, we support permitting reform broadly at a national and even state and local levels in order to be able to build the infrastructure we need to meet this era of growth.”

Xcel faces 30% expected load growth over the next five years. It has added $10 billion of additional capital investment to its base five-year plan, now at $45 billion. Transmission plans approved by MISO and SPP in December will require as much as $4 billion in capital investments, Frenzel said.

The company in November completed the first phase of solar installations at its Sherco plant site, where Xcel is in the process of retiring three coal units. They will be replaced by a 710-MW solar facility that Frenzel said would be the largest in the upper Midwest.

Xcel reported year-end earnings of $1.94 billion ($3.44/share), compared with $1.77 billion ($3.21/share) in 2023. It said the year-over-year earnings growth reflected increased recovery of infrastructure investments, partially offset by higher depreciation, interest charges and operations and maintenance expenses.

The company said adjusted earnings per share were $0.81 for the fourth quarter. That fell short of the analyst consensus of $0.89/share. Revenue for the quarter was $3.12 billion, also below the consensus estimate of $3.77 billion.

Xcel’s share price closed at $67.12, dropping 83 cents on the day from its previous close.