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.)
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.”
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.”
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.
“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.”
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.”
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.
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.
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.”
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.
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.
WASHINGTON — 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.
