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February 7, 2025

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

WASHINGTON, D.C. ― “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The Office of Management and Budget issued and then quickly rescinded a funding freeze days before the NASEO event, followed by a restraining order issued by the U.S. District Court in D.C. Still, ongoing uncertainty provided the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 January 7, 2025,” 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 is still 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 said also 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 over 14,000 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 is also 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 already 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 has also 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.

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NERC Updates FERC on IBR Registration Progress

More than 850 inverter-based resources that are not currently registered with NERC likely will have to be so under the ERO’s proposed IBR registration criteria, the organization told FERC in a filing Feb. 5 (RD22-4). 

NERC submitted the estimate in its quarterly progress update on the registration initiative, which the ERO is required to perform under FERC’s June 2024 order approving changes to NERC’s Rules of Procedure. (See FERC Accepts NERC ROP Changes, Drops Assessment Proposal.) The ROP changes allowed the organization to register owners and operators of IBRs that currently are not required to register but that are connected to the grid and, “in the aggregate, have a material impact” on reliable operation.  

They did so by creating a new category of generator owners called “Category 2 GOs,” comprising entities that own or maintain IBRs that “either have or contribute to an aggregate nameplate capacity of greater than or equal to 20 MVA, connected through a system designed primarily for delivering such capacity to a common point of connection at a voltage greater than or equal to 60 kV.”  

According to NERC’s filing, there are 863 IBRs meeting the Category 2 criteria with a total nameplate capacity of 38,785 MVA, distributed as follows among the regional entities: 

    • MRO — 149 IBRs with a total nameplate capacity of 6,614 MVA. 
    • NPCC — 75 IBRs; capacity of 2,422 MVA. 
    • ReliabilityFirst — 100 IBRs; capacity of 4,194 MVA. 
    • SERC — 175 IBRs; capacity of 10,473 MVA. 
    • Texas RE — 41 IBRs; capacity of 2,167 MVA. 
    • WECC — 323 IBRs; capacity of 12,915 MVA. 

NERC developed the estimate after issuing a request for information to balancing authorities and transmission owners on July 9, 2024, for “relevant information on those entities within their footprints that could meet the … registry criteria.” The estimates for both the number of IBRs and their capacity were calculated as of Jan. 24 and may change as more information is gathered. 

In addition, the ERO said the “numbers do not necessarily reflect the total number of GOs or GOPs that will be registered based on the Category 2 criteria, as the Functional Entity assignment will be determined once the ERO Enterprise receives more information about the entities.” NERC said it will provide updated numbers in future quarterly reports. 

NERC is nearing the end of the second year of its IBR registration work plan, which FERC approved in May 2023. (See FERC Approves NERC’s IBR Work Plan.) The plan laid out a three-year process for completing the registration: revise the ROP to create an appropriate registered entity function within 12 months of the plan’s approval; identify candidates for registration within 24 months; and register appropriate entities within 36 months. 

The ERO said it already has “initiated communications with newly identified entities that may be candidates for registration as Category 2 GO/GOPs.” Training for the Centralized Organization Registration ERO Systems (CORES) will be provided to newly registered entities in months 25 and 26 of the work plan, or June and July 2025. NERC plans to complete registration by May 2026. 

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FERC’s Christie Discusses Making Electricity More Affordable at NASEO

WASHINGTON, D.C. — FERC Chair Mark Christie wants to help bring down consumers’ power bills by addressing what has driven them up most in recent years: spending on the transmission and distribution system, he said at the National Association of State Energy Officials’ Energy Policy Outlook Conference. 

“The last four years [have] seen the highest rate of inflation in people’s monthly power bills over the last 25 years,” Christie said Feb. 6. “That’s a fact. People are struggling depending on the power bills.” 

Christie is accustomed to people complaining about their utility bills after 17 years as a state regulator in Virginia and since joining FERC in 2020. Natural gas prices shot up after Russia invaded Ukraine but have fallen back from that high. 

But the transmission and distribution parts of consumer bills have been climbing. State regulators oversee the distribution system, and they also have some oversight of transmission. But FERC sets rates for the interstate commerce lines. 

FERC regulates the RTOs, which have taken over the planning of transmission. But they often only lightly oversee smaller, “local projects,” as opposed to the more in-depth reviews the organized markets carry out in their regional planning efforts. RTOs, especially the large multistate markets, lack the resources to properly oversee all the local lines that come before them, Christie said.  

“We have to build transmission to serve consumers, not to serve special interests,” he said. 

Even if an RTO says a local line is needed, it is a healthy process to have a state regulator examine the project and what’s driving the need for it, he added. 

“Go back and check your state laws — you need a strong, robust permitting process,” Christie told the room full of state officials. 

State officials should pay attention to what their RTOs are doing and that involves working with state utility regulators, who already are engaged with the organized markets, Christie said. 

Christie gave the standard disclaimer that he was talking about issues generally, and he did not mention any specific cases. But just before the holiday break, a major complaint seeking greater FERC oversight of local transmission was filed with the commission. (See Consumer Groups Seek Independent Oversight of Local Tx Planning.) 

National Rural Electric Cooperative Association CEO Jim Matheson wrote Christie a letter Feb. 5 congratulating him on his elevation to chair and urging him to focus on affordability, among other issues. The co-op trade group supports Christie’s efforts to give states a bigger role in the planning of the grid on Order 1920-A and agreed that state regulators, and co-ops (that set their own rates for consumer-members), are the first line of defense from excessive transmission costs. 

“Under Order 1920-A, there are significant holes in that line of defense where cooperative consumer-members are concerned, and we urge you to address this inequity in the future so that all consumers receive the protection they deserve,” Matheson said. 

Christie Addresses Other Issues

An attendee asked about natural gas and electric coordination. Christie noted that while the power increasingly relies on the fuel as part of its baseload supply, gas generators still largely rely on just-in-time fuel delivery. One rule change that should be examined is whether they should be required to store fuel. 

FERC has been working with the electric industry and the pipeline industry on improving gas coordination for years, and that work has seen progress, but Christie said that work could be expanded to bring in more entities. 

“What about everyone else that needs gas?” Christie said. “We have manufacturers that need gas. And, of course, the LDC [local distribution companies] still need gas.” 

Responding to another question on the rise of data centers and co-location with generation, Christie said every customer who uses power effectively is a cost-causer, whether it is a new residential account, or a massive data center with demand in the hundreds of gigawatts. 

“We have gotten a bunch of cases regarding what’s called co-location,” Christie said. “I’ve said this publicly several times and I’ll say it again — we’re going to address it; we’re going to address it soon.” 

FERC will handle the issues around data centers on the federal side, but ultimately, the facilities are customers of utilities, so states have a major role to play in the process of meeting their demand affordably, he added. 

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SPP Board Approves 8 Urgent Short-term Projects

SPP’s Board of Directors approved eight short-term reliability projects (STRPs), a $3.15 billion package with immediate needs for this year through 2028, that were identified in the 2024 Integrated Transmission Planning assessment.

They include the first 765-kV project in SPP’s history, a $1.69 billion, 293-mile circuit in Southwestern Public Service Co.’s Texas and New Mexico service territory. An attempt to pull the project from the list because of its price tag and make it subject to competitive bidding under FERC Order 1000 failed.

The directors followed the language in SPP’s tariff, which defines STRPs as upgrades that meet the criteria for competitive projects but that are needed in three years or less to address “identified reliability violations.” In that case, STRPs are not considered competitive upgrades under the tariff.

The board’s Feb. 4 approval means the incumbent transmission owners will receive notifications to construct for the projects.

“As a transmission-dependent utility and representing many transmission-dependent utilities, there’s always been a lot of concern over … circumventing the Order 1000 process,” the Oklahoma Municipal Power Authority’s Dave Osburn said during the discussion preceding the vote. “We’re saying all these projects are required this year, and we know they’re not going to be done. Bringing $3 billion worth of lines with a need date of this year, something about that doesn’t sit well.”

Renewable interests and developers and cooperatives made their opposition known during a 30-day comment period earlier this year after staff’s designation of the STRPs. They said the projects would not be subject to the cost controls and schedule guarantees that competitive projects face, leading to a risk of delays. Previous directly assigned projects have been delayed without current means of holding the assignees accountable, they also said.

Transmission owners supported the designated projects, saying they complied with the tariff and FERC precedent, that they would address persistent operational needs and eliminate the need for load shed during future winter storms.

“I don’t believe that this is circumventing Order 1000,” Evergy’s Denise Buffington said, responding to Osburn. “I think Order 1000 and the compliance filings that were in front of FERC contemplated the scenario that there would be times when there are projects that are immediate needs and that need to be done soon for reliability reasons. Load shedding is not a mitigation … I don’t think any incumbent transmission owner that has customers potentially going in the dark are going to wait on these projects. These projects are going to be the highest priority, and we are going to get them done as soon as is possible.”

Director Ray Hepper thanked members for their comments and said the board had an “incredibly important and challenging discretion” to determine whether the projects should be competitive or directly assigned.

“For me, this creates a real challenge. What criteria should I use to guide my vote?” Hepper said. “On one hand, I can simply say all these projects are needed within three years and therefore, they meet the terms of the tariff. On the other hand, I can argue that FERC has concluded that competition is good and therefore all these projects should go out for bids. These are the relatively more straightforward bookends of the discussion.”

Board Chair John Cupparo advocated the directors consider establishing clear mechanisms to avoid a similar situation in the future. He said should the board agree, it will engage staff and stakeholders to gather necessary input before the 2025 ITP is released in October.

“It’s my understanding that the board has full discretion over how to treat the short-term reliability project list, and it’s our role to determine how we want to treat it each time it comes before us,” Cupparo said. “In my opinion, we are obligated to evaluate and understand all reasonable options and the benefits and impacts on the entire SPP footprint and its 18 million residents.”

The Members Committee’s advisory vote rejected the motion to designate the 765-kV project as a competitive project, 7-11, with three abstentions. It approved the designation for all eight STRPs, 14-6, with one abstention. The board sided with both votes.

The STRPs were culled from the 89 potential projects in the 2024 ITP. The board in December approved 12 of those as winter-weather projects, with 11 staged on or before Dec. 1, 2025, to resolve the remaining winter reliability needs.

The eight STRPs are:

    • Holcomb-Sidney (Kansas), new 345-kV line, 135 miles.
    • Delaware-Monett (Oklahoma and Missouri), new 345-kV line, 114.5 miles.
    • Monett-North Branson (Missouri), new 345-kV line, 47.2 miles.
    • Phantom-Crossroads-Potter (New Mexico, Texas), new 765-kV line, 293 miles.
    • Iron House-Texaco (New Mexico), new 115-kV line, 2.3 miles.
    • Grapevine-Kingsmill (Texas), new 115-kV line, 10.7 miles.
    • Moore County-XIT (Texas), new 230-kV line, 46.2 miles.
    • Buffalo Flats-Delaware, new 345-kV line, 154.6 miles.

Three of the projects — Phantom–Crossroads–Potter, Grapevine–Kingsmill and Moore County–XIT — have been assigned to SPS, which is facing unprecedented demand from new manufacturing, oil and gas growth, and its communities.

Xcel Energy, the parent company of SPS, said all three lines are “crucial” for maintaining a reliable electricity supply. It said the Phantom-Crossroads-Potter line is “especially important” in supporting load growth.

“I understand the concern about one project being a significant cost in the portfolio. The alternative could have been multiple other lines in which this discussion may not be revolving around a single project, but it could have been multiple other projects,” SPS’ Jarred Cooley said during the board discussion. “SPS has a very strong track record of building projects on time and under budget. The last eight 345-kV projects in our footprint have done that, and we definitely would be ready, willing and able to build this line as soon as given the go-ahead.”

The eight projects completed over the past seven years added 318 miles to a high-voltage transmission network that now exceeds 8,000 miles.

Adrian Rodriguez, president of Xcel Energy – Texas and New Mexico, said in an emailed statement Feb. 5 to RTO Insider that the utility is “honored to be entrusted with these critical projects.”

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NYPA Argues Clean Path Potential Benefits Outweigh Cost

The New York Power Authority has updated its petition to the Department of Public Service to get priority status for the transmission portion of the Clean Path project.  

The update includes cost estimates for the project, as well as an attachment forecasting the potential financial benefits to New York consumers. The total estimated cost for this version of Clean Path is about $5.2 billion. Most of the expense comes from the $3.8 billion cost of equipment, materials and labor.  

Industry watchers told RTO Insider on background that the estimates generally seemed reasonable for a project of its scope but wouldn’t speculate on the specifics.  

Clean Path originally was an $11 billion portfolio of projects between the developers and the New York State Energy and Research and Development Authority. The package would include 178 miles of HVDC line between upstate New York and Queens, and 23 renewable energy facilities. The public-private collaboration between NYPA and Forward Power was believed by many industry watchers to be dead when the original contract was canceled in November 2024. (See $11B Transmission + Generation Plan Canceled in NY.) 

The original petition to save the transmission portions of Clean Path did not include cost estimates or a cost/benefit analysis. (See NYPA Files Petition with New York PSC to Save Clean Path Project.) 

Cost/Benefit

NYPA projected two scenarios for assessing the benefits of Clean Path: one where the state does not achieve a 100% emissions-free electrical system by 2052, and another where the state achieves 100% zero-emission generation by 2040. Both scenarios assumed the Climate Leadership and Community Protection Act goal of 70% renewable generation will be achieved by 2033.  

Both scenarios evaluated the project’s impact on the “locational minimum installed capacity requirements” in New York City. NYPA evaluated the benefits of Clean Path in terms of the cost of energy production, locational capacity requirements, renewable energy and zero emissions credits, and congestion prices. Secondary market effects were not considered. 

In the less optimistic scenario, Clean Path would accrue $6.2 billion of benefits, roughly $4 billion of which comes from projected reductions in locational capacity requirements. This means the primary benefit would be felt in terms of reduced capacity prices, specifically by importing cheaper renewables to New York City.  

In the more optimistic scenario, Clean Path would accrue $21.5 billion in benefits. The difference between the less optimistic and more optimistic scenarios’ forecasts is driven primarily by dramatically increased “load payment savings.” In other words, NYPA predicts that if New York were to build Clean Path and transition to 100% emissions-free renewables, the market would spend about $11 billion less on load. Spending on the production of energy and congestion also would save about $5.8 billion combined. 

The Department of Public Service (DPS) has not yet solicited public comment on the updated petition. Sources consulted on background said comment probably would be solicited within a week or so. Comment periods typically are open for 60 days. It’s likely DPS already is assessing the findings put forward in the petition, but it’s unclear how long after the comment period DPS will announce a decision.  

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SEIA: US Now Manufacturing More Solar Panels Than It Installs

The U.S. now can manufacture enough solar panels to meet domestic demand but still must import most of the core components ― the solar cells and the silicon wafers used to make them ― according to the latest figures from the Solar Energy Industries Association. 

The U.S. has enough solar panel manufacturing capacity to produce more than 51 GW of panels per year, with an additional 17.5 GW under construction and 23.5 GW of additional capacity announced. The industry installed 40.5 GW of solar in 2024, according to a separate year-end report from SEIA.  

The upstream supply chain, however, lags far behind. The nation has only 2 GW of solar cell manufacturing online versus 42.6 GW announced and 11.8 GW under construction. Production of silicon ingots and wafers has yet to go online, with only 3.3 GW under construction.  

SEIA is putting a positive spin on the disconnect, noting that it originally set a 50 GW target for panel manufacturing in 2020, expecting to hit that goal by 2030. Reaching and exceeding the benchmark five years ahead of schedule “is a testament to what we can achieve with smart, business-friendly public policies in place,” CEO Abigail Ross Hopper said in a Feb. 4 press release.  

“The U.S. is now the third-largest module producer in the world because of these policy actions,” Hopper said. “This milestone not only marks progress for the solar industry but reinforces the essential role energy policies play in building up the domestic manufacturing industry that American workers and their families rely on.”  

Without actually naming the law, Hopper is referring to the clean energy tax credits and incentives contained in former President Joe Biden’s Inflation Reduction Act. SEIA specifically advocated for the law’s advanced manufacturing production tax credit, applicable to solar manufacturing, and bonus incentives for solar projects that use products made in the U.S., according to the press release. 

The organization also successfully pushed for a 25% investment tax credit for domestic production of solar wafers and ingots, contained in the CHIPS and Science Act, which like the IRA was passed in 2022. 

SEIA frames the lag in cell and wafer manufacturing as the result of “sequencing the build-out of a domestic solar supply chain. Establishing production of downstream components like modules ensures there is sufficient demand for upstream manufacturing,” according to the press release.  

Tariff-proof Chinese Wafers?

Since President Donald Trump won the election in November, SEIA has been focused on protecting solar’s federal tax credits by positioning the industry as a critical part of Trump’s vision for U.S. energy dominance and independence, as well as a major source of the clean, affordable power needed to meet growing demand from data centers. 

The organization also continues to tout the private investment and jobs that solar manufacturing has brought to Republican states and congressional districts. By SEIA’s count, new or planned solar manufacturing facilities are located in 23 states with Republican governors and 122 districts with Republican representatives in Congress, versus 20 states and 90 districts with Democratic leaders and lawmakers.  

The industry’s weak spot, however, could be its continued dependence on imported cells and wafers. Private investments in new U.S. facilities could be at risk if congressional Republicans take steps to reduce or roll back clean energy tax credits and other incentives as part of their plans to extend the 2017 Tax Cuts and Jobs Act.  

First published by Politico, a recently circulated short list of potential budget cuts Republicans are considering includes discontinuing $300 billion in clean energy funding from the Infrastructure Investment and Jobs Act and an additional $56 billion in grants from the IRA.  

In an email to NetZero Insider, Elissa Pierce, a research analyst at Wood Mackenzie, notes that in 2024, “62.5% of US cell imports came from Cambodia, Malaysia, Thailand and Vietnam,” the four nations subject to antidumping and countervailing duty tariffs imposed by the Commerce Department in 2024. 

An investigation by the International Trade Commission found that companies in those countries were using Chinese components in their products, while seeking to circumvent existing U.S. tariffs on Chinese solar cells and panels.  

Pierce expects the percentage of solar cell imports from the four nations will decrease in 2025, with imports from Indonesia, Laos and South Korea rising.  

More to the point, she said, prospective cell manufacturers in the U.S. could still import wafers and ingots from China — even with increased tariffs — because “Chinese wafers are so cheap that this isn’t very impactful. Some of the cell manufacturers coming online this year have stated that they will get wafers from Southeast Asia.” 

The industry recently celebrated the opening of a new U.S.-owned cell manufacturer, ES Foundry, in South Carolina, Christian Roselund, senior policy analyst at Clean Energy Associates, wrote on LinkedIn. But he cautioned that “U.S. solar manufacturing is a long way from being able to meet the demands of our internal market at the cell level.” 

Erecting trade barriers and cutting federal incentives “will set back U.S. solar manufacturing, not advance it,” he said.