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January 30, 2025

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What is and isn’t in Trump’s National Energy Emergency Order

President Donald Trump’s executive order declaring a National Energy Emergency talks a lot about energy and energy resources ― referring to different fuels, fossil and otherwise ― but relatively little about generation, defined as the use of those fuels to produce electricity, according to Keith Martin, co-head of projects for Norton Rose Fulbright.

Electricity is “not the operative part of the executive order,” despite the fact that an alleged shortage of electric power across the U.S. is the ostensible reason for its issuance, Martin said in an interview Jan. 21. The order is inconsistent in that respect, he said, “promoting energy defined to exclude electricity. … A more careful draftsman would have connected all the dots.”

Signed just after Trump’s inauguration on Jan. 20, the emergency declaration and some of the other energy-related orders are essentially policy statements aimed at “messaging,” Martin said. “They are press releases on fancier paper … directions to the agencies, but they’re not specific legal actions.”

What’s left out of the order is as significant as what’s included. While calling for “a reliable, diversified and affordable supply of energy,” it omits any mention of solar, wind or storage and makes only passing reference to transmission as part of its definition of generation.

So, what impact, if any, might the declaration and Trump’s other energy-related executive orders have? It varies, Martin said.

Trump’s order on “Unleashing American Energy” calls for an immediate pause on “the disbursement of funds appropriated through the Inflation Reduction Act of 2022 … or the Infrastructure Investment and Jobs Act.”

The wording calls for agencies to “review their processes, policies and programs for issuing grants, loans, contracts or other financial disbursements of such appropriated funds for consistency with the law” and Trump’s own fossil fuel-leaning energy policies spelled out in the order.

“The Biden administration had been rushing to get to legal commitments for these types of things,” Martin said, referring to the Department of Energy’s efforts to finalize contracts with a range of grant and loan recipients in the first weeks of January.

According to a final report from the White House, 90% of IRA and IIJA funds available through the end of 2024 have finalized contracts. But, Martin said, “the choice of words ― pausing disbursements ― suggests that Trump intends to ignore the legal commitments and just block any further disbursements.”

Industry analysts ClearView Energy Partners agreed, saying the wording could be interpreted “expansively so that it applies to obligated undisbursed monies as well as those which have yet to be obligated.”

The emergency declaration, on the other hand, calls on department and agency heads to “identify and exercise any lawful emergency authorities available to them, as well as all other lawful authorities they may possess to facilitate the identification, leasing, siting, production, transportation, refining and generation of domestic energy sources.”

DOE’s emergency powers are limited, under the Federal Power Act Section 202(c), to temporary actions in response to emergency-related power shortages. For example, DOE issued an emergency order on Oct. 9, 2024, for Duke Energy Florida to operate some generating plants at low output because of the impacts of Hurricane Milton.

Other sections of the order call for streamlining and accelerating the Fish and Wildlife Service’s emergency consultations on projects that might raise concerns about endangered species or critical habitat “in order to ensure an initial determination within 20 days of receipt” and to get to a final decision within 140 days.

Tom Falcone, president of the Large Public Power Council, does not expect immediate changes. “It’s early days on a lot of these things,” he said, noting that the energy emergency order calls for reviews, assessments and recommendations, as do some of the provisions of the “Unleashing” order. “We read them as general direction with an awful lot of process to come, because each one of those things calls for administrative processes and other processes that are still to come.”

‘A Period of Power Politics’

Karen Wayland, CEO of the GridWise Alliance, is similarly skeptical of Trump’s claims of an energy emergency. “I think managing our energy system requires constant attention, but I don’t see anything that constitutes an emergency,” she said.

Wayland framed Trump’s rhetoric as overreach. “We know where infrastructure constraints are. We know both on the transmission [side] and the pipelines. We know where they are. There’s nothing in the presidential authorities that allows him to just say, ‘OK, everything has been approved. You can go ahead and go build that.’”

ClearView Energy Partners took a broader view of the current political context for Trump and his executive orders and how they might be implemented. The U.S. and other countries “have entered a period of power politics” in which American presidents first “learn from, and build upon, their predecessors’ actions” and appear “increasingly willing to test the outer peripheries of regular order, established norms and American political traditions.”

ClearView anticipates legal challenges to Trump’s more controversial orders, but should federal courts overturn an order, Trump “might iteratively pursue new tactics to achieve his original objectives.”

Like Martin, ClearView sees the emergency declaration as setting direction; “however, it does not appear to immediately change policies that might directly impact supply, demand or price.”

Lisa Jacobson, president of the Business Council for Sustainable Energy, sees Trump’s orders as an opportunity for bipartisan action in support of clean energy.

The U.S. may not have an energy emergency, “but we clearly have challenges,” Jacobson said. “We need to understand and respect them, and if this creates an opportunity to really amplify the urgency of moving us into a better position to modernize and expand our energy infrastructure, I’m going to take that moment.”

But Jacobson also argued that the way forward requires “durable” bipartisan legislative action, especially on permitting. “We know there’s an appetite for that. Hopefully raising it to the level that the president has done on Day 1 will yet again underscore the fact that for our economy, for our security, for the environment, we need to be able to move much faster with energy infrastructure, and energy infrastructure of all kinds.”

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Powerex Commits to Funding, Joining SPP’s Markets+

Powerex said Jan. 21 that it will fund the next phase of SPP’s Markets+ and “re-affirmed” its commitment to joining the Western real-time and day-ahead offering, a move the company signaled as early as November 2023 — before the start of the extensive stakeholder process to develop the market. 

The announcement by Powerex, the marketing and trading arm of Vancouver, British Columbia-based BC Hydro, comes on the heels of another positive development for SPP in its competition for participants with CAISO’s Extended Day-Ahead Market (EDAM)/Western Energy Imbalance Market (WEIM): FERC’s approval of the Markets+ tariff. (See SPP Markets+ Tariff Wins FERC Approval.) 

“Powerex has greatly appreciated the collaboration of a diverse group of stakeholders who have invested countless hours over multiple years, with SPP providing facilitation and market expertise to aid in this effort,” Powerex CEO Tom Bechard said in a statement. “The end result is a fair, robust and durable initial market design built upon an inclusive and independent governance structure from the outset.” 

The announcement also follows by two months the first formal commitments to Markets+ by Arizona’s four largest utilities, including Arizona Public Service, Salt River Project, Tucson Electric Power and UniSource Energy Services. (See 4 Arizona Utilities Commit to Joining Markets.) 

“We are pleased to hear of Powerex’s commitment to join Markets+ phase two, and we look forward to continued collaboration with Powerex and other entities as we work together to build a Western market that will reduce costs for members, improve reliability and help members reach their renewable integration goals,” Antoine Lucas, SPP vice president of markets and incoming COO, said in an email to RTO Insider. 

FERC’s Jan. 16 decision approving the tariff opened the door for Markets+ backers to begin making formal participation commitments and provide the $150 million investment needed to fund the market’s Phase 2 implementation stage. 

According to an SPP spreadsheet posted to the RTO’s site Oct. 24, 2024, Powerex will be the single largest funder of Phase 2, responsible for 23.2% under the most likely market footprint scenario, equating to around $34.8 million.  

“Our share of Phase 2 is not yet finalized and will depend on who ultimately signs on,” Jeff Spires, director of power at Powerex, said in an email, adding that 23.2% “seems like a reasonable estimate based on participation in Phase 1.” 

“SPP is using a funding mechanism for Phase 2 similar to Phase 1 for determining each participant’s share of the Phase 2 implementation costs,” Lucas said. 

The Bonneville Power Administration, which has not finalized its funding commitment, would be the second-largest contributor, at about $25 million, or 17.4%. The federal power agency recently said it “is actively working with SPP and all other Markets+ participants on finalizing Phase 2 funding agreements.” 

In its statement, Powerex noted that a market footprint that includes much of the Northwest (BPA was not explicitly mentioned), the Arizona utilities and — likely — Xcel Energy-Colorado “will have substantial resource and load diversity, enhancing the benefits for all participants.” 

“This expected diversity includes an extensive hydro fleet in the Northwest, growing solar supply in the Southwest as well as expanding wind resources in the Northwest, Southwest and Rockies western subregions,” the company said. “The Markets+ footprint will also have both winter-peaking and summer-peaking utilities, further enhancing the opportunities for mutually beneficial trade.” 

Powerex said it also is “actively pursuing investments in transmission expansion efforts” to help support connectivity across Markets+. 

Markets+ Supporter, EDAM Critic

In nearly equal measure, Powerex has been one of Markets+’s most ardent supporters and one of CAISO’s harshest critics, having previously stated it had no intention of joining EDAM under any circumstances. 

The company has been a consistent critic of CAISO’s state-backed governance structure and an outspoken skeptic of the ISO’s dual roles as operator of and participant in the EDAM/WEIM, contending that CAISO market practices don’t provide equal treatment to non-California participants — all complaints CAISO and EDAM supporters in the Northwest have contested.  

In that capacity, Powerex has been a key contributor to the series of “issue alerts” Markets+ backers have been publishing since summer 2024 to compare key features of Markets+ and EDAM, covering such issues as governance, market operations, market design and market seams. 

In its Jan. 21 statement, Powerex said it “evaluated its decision to fund and join Markets+ based on three equally important pillars: independent governance, an impartial market operator and sound market design. These three pillars are critical to ensure equitable outcomes for all participants and ratepayers across the market’s footprint.”  

Powerex was one of the first entities to weigh in on the debate over CAISO’s response as WEIM operator during the January 2024 cold snap in the Northwest, which pushed a handful of the region’s balancing authority areas to the brink of rolling blackouts in the face of power supply shortages. 

The company criticized how CAISO distributed the high transmission congestion revenue rents resulting from the event, questioned California’s role in supplying its northern neighbors and even offered a recommendation that the Northwest use existing transmission to increase import capability directly from the Southwest and Rocky Mountain regions to circumvent flowing power through CAISO’s territory. (See Powerex Report Expands NW Cold Snap Debate.) 

The persistent debate around the cold snap prompted CAISO to respond eventually with its own rebuttal. (See CAISO Seeks to Dispel CRR ‘Myths’ Around January Cold Snap.) 

More recently, Powerex published its own analysis questioning the soundness of a Brattle Group comparative study that found Northwest utilities as a whole would financially benefit more from participating in EDAM than in Markets+, which elicited a response from Brattle. (See Powerex Contests Brattle’s EDAM/Markets+ Comparative Study.) 

In June 2024, clean energy industry group Renewable Northwest released a study contending that Powerex was backing Markets+ because the company would benefit more financially from a West divided into multiple markets than a single market that included California. The study was conducted by Grid Strategies. (See Group Claims Powerex Backing Markets+ to Benefit from Divided West.)  

At the time, Spires told RTO Insider the intent of the study “appears to be to distract from the essential governance and market design elements that differentiate the two day-ahead market options.” 

With Powerex’s announcement, the attention of participants in Western electricity market developments will return to BPA, which says it will issue a draft day-ahead market decision in March and a final decision in May. 

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Trump Will Need More than Executive Orders for US to Meet Rising Power Demand

President Donald Trump’s wave of executive orders issued just after he took office already have generated plenty of headlines, but on their own, they will not solve the biggest issue facing the power industry — the need to meet rising demand — sources told RTO Insider on Jan. 21.

“If we truly want to win the AI race against China, I think that merits a declaration of national emergency, but we can’t possibly build enough oil and gas infrastructure in the next couple of years to do it with fossil fuels alone,” former FERC Chair Neil Chatterjee (R) said in an interview. “What we should be focusing on is making it easier through this emergency declaration to get every available electron.”

In addition to expanding fossil generation, that would include renewable energy, storage and the transmission needed to connect new supplies and loads to the grid, he said.

Electric transmission was not mentioned in the “Unleashing American Energy” executive order, and it only came up in the “Declaring a National Energy Emergency” order as part of generation. It could benefit from Trump’s executive action, Grid Strategies President Rob Gramlich said.

The major tech firms backing AI, many of whose CEOs were in the Capitol rotunda when Trump took office Jan. 20, are going to want to expedite transmission buildout to help meet that demand, Gramlich said in an interview.

Part of the reason transmission was largely absent from the executive orders is that it became politicized in the past few years, as Democrats came to support its expansion as necessary to deliver on the goals of the Inflation Reduction Act.

“That has created this notion that transmission policy is having red states subsidize blue state policy, and it is going to take some education and experience to overcome that,” Chatterjee said.

Republicans will tackle many of their policy preferences on their own because they control the White House and both houses of Congress, Gramlich said. He expects they will push energy policy through budget reconciliation, a legislative procedure tying bills to budget measures in order to avoid the Senate filibuster. Democrats used this to pass the IRA itself without Republican support in 2022. (See Senate Passes Inflation Reduction Act.)

“I think most permitting reform will need to go through Congress, and I think only a tiny bit could be done through reconciliation, leaving most of it for what would need to be a bipartisan bill,” Gramlich said.

He warned not to expect negotiations on permitting reform to pick up immediately where they left off last session because Republicans will need time to push through whatever policies they can without Democrats’ votes. Either later this year or next year, momentum could pick up for another attempt at a bipartisan permitting bill. (See Lame Duck Permitting Push Fails; Manchin Blames House GOP Leaders.)

The big issue facing infrastructure advancement is bipartisan: Americans of all political persuasions can exhibit “NIMBYism” when it comes to infrastructure, whether it is a pipeline for natural gas or a transmission line for clean energy, Chatterjee said. But the country will need all the electrons possible to meet the rising demand and maintain reliability.

Neither party has wrapped its mind around the surge in demand the electric industry is facing and how important serving it is to win the AI race, which is a national security issue, he said.

“When everyone gets situated, and we start to recognize that electric power is essential to winning the AI race, some of the political obstacles of the last decade and a half, in my view, will start to wear away,” Chatterjee said. “And you’ll see Democrats recognizing we cannot possibly win the AI race without fossil fuels. And you’ll see Republicans recognizing that we cannot possibly win the AI race with fossil fuels alone.”

Gramlich agreed with that assessment, adding that many policymakers are stuck on where the grid was a few years ago when the expansion of renewables was the main driver for its expansion.

“But now there’s a lot of other generation, and there’s a lot of different types of loads, including manufacturing and data centers that are also trying to connect to the grid,” Gramlich said. “So, the interests in support of grid expansion have expanded dramatically, and I think we’ll see, over the course of this year, the politics come around and incorporate that fact.”

Mark Brownstein, the Environmental Defense Fund’s senior vice president for the energy transition, took issue with the idea of an “energy emergency” altogether, saying in a statement that the U.S. is already the largest oil and gas producer, with export capacity on pace to double.

“The first-day wave of executive orders does nothing to lower energy costs or improve reliability,” Brownstein said. “Instead of rolling back cost-effective, common-sense safeguards that have broad public support, a forward-looking administration would be focused on modernizing our aging electricity grid to meet the growing demand from AI data centers and an increasingly digital economy, prioritizing efficiency and clean electricity.”

Erasing Biden’s EV Targets

While the industry deals with the growth of data center demand now, Trump’s executive orders will have some impact on longer-term demand trends, such as for electric vehicles.

Trump’s “Unleashing” order states that “it is the policy of the United States … to eliminate the ‘electric vehicle mandate’ and promote true consumer choice.” There is not any law or rule requiring consumers to purchase EVs, but Republicans branded former President Joe Biden’s policies to encourage EV adoption as such.

The order lists several “regulatory barriers” to be removed, such as state emissions waivers and “unfair subsidies and other ill-conceived government-imposed market distortions that favor EVs over other technologies and effectively mandate their purchase by individuals, private businesses and government entities alike by rendering other types of vehicles unaffordable.”

R Street Resident Senior Fellow Josiah Neeley said that the order could wind up being a blessing in disguise for the industry.

“It seemed unlikely based on the ability of the [Biden] administration to build out necessary accompanying infrastructure, like charging stations,” that getting EVs to 50% of national sales by 2030 “was going to be feasible,” Neeley said in an interview. “And, so, I think realistically, the administration had set itself on a collision course where it was going to have to do something to alter” its goal.

EVs are going to make up a growing share of new vehicles going forward, but it will be driven by customer demand and that will help turn down the political back and forth around them.

“I think unfortunately in America, everything tends to get very easily politicized, where if one party tries to push EVs, that makes EVs seem uncool,” Neeley said. “By contrast, you have [Tesla CEO] Elon [Musk] endorse Trump, and suddenly a bunch of people who used to like Tesla don’t like Tesla anymore.”

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Prior to Trump Inauguration, Feds Lift Suspension on Vineyard Wind 1

The U.S. Bureau of Ocean Energy Management (BOEM) on Jan. 17 approved Vineyard Wind 1’s plan to remove additional installed blades in the wake of a major blade failure in the summer, while the Bureau of Safety and Environmental Enforcement (BSEE) lifted its suspension of blade installations and power production.  

BSEE’s suspension was triggered by an incident July 13, when one of the Vineyard Wind’s 350-foot blades began to collapse during testing, raining debris into the Atlantic Ocean. 

GE Vernova, parent company of blade manufacturer LM Wind Power, initially signaled that the issue was an isolated manufacturing defect. (See GE Vernova Finds Defect in Vineyard Wind Blade.) However, Vineyard Wind noted in its revised Construction and Operations Plan (COP) that a root cause analysis helped identify defects in other blades. 

Vineyard Wind attributed the issue to “insufficient bonding at certain locations within the blade, which should have been detected at the manufacturing plant through inspection and quality control procedures.” BOEM has mandated the removal of all blades manufactured at a factory in Gaspé, Quebec. 

Vineyard Wind said it plans to replace the blades installed at up to 22 locations. The company also may need to remove or repair additional blades, manufactured in France, at two other locations.  

BOEM determined these two blades can remain in place if Vineyard Wind demonstrates that anomalies in the blades do not affect their structural integrity and that “the difficulty of the repair will likely cause more damage than the anomaly.” 

BOEM also has required supervision of all new blades manufactured at the factory in France.  

“Following months of extensive work and collaboration with the federal interagency, GE Vernova and Vineyard Wind developed a detailed and rigorous approach to safely resume the construction and operation of the project,” said Vineyard Wind spokesperson Craig Gilvarg in a statement. “Friday’s action cements this plan as a modification to the COP, which strengthens the project’s construction program, ensuring that this rigorous approach will guide all project activities in perpetuity.” 

The approval allows Vineyard Wind to resume full construction on the project; BSEE had updated its suspension order in August to allow Vineyard Wind to resume installing towers and nacelles. 

While the COP approval is a necessary step for Vineyard Wind, the need to replace more blades is a significant setback for the project, coming after a six-month delay to power production and blade installation. The project previously aimed to be fully operational by the end of 2024. 

The costs of replacing the blades will be substantial — GE Vernova told investors in October that the blade failure and associated delays will cost the company about $700 million. (See GE Vernova Gives Update on Offshore Wind Woes.) 

When fully operational, Vineyard Wind 1 will have an 800-MW nameplate capacity, and is a key component of Massachusetts’ decarbonization plans. It is under contract with Massachusetts’ electric utilities to provide power at an average annual cost of $89/MWh for 20 years (DPU 18-76, et al.).  

The project’s potential benefits include increased winter grid reliability, reduced wholesale market costs, cheaper renewable energy certificates to meet state electricity standards and an estimated reduction in annual carbon dioxide emissions by 1.68 million metric tons. 

The COP approval on Jan. 17 came just days before the inauguration of President Donald Trump, who has halted approvals, permits, loans and new leases for offshore wind projects.  

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Critics Slam Trump’s Freeze on New OSW Leases

President Trump’s executive order freezes future offshore wind leasing, but its impact on existing leases remains to be determined. 

Trump has a longstanding animosity toward wind turbines, particularly in the ocean, and he had said repeatedly he would issue a ban. On Jan. 20, just hours after his inauguration, he halted onshore and offshore wind power leasing and permitting and ordered a review of the government’s processes for both. 

The order does not affect existing wind leases, but it sets up potential challenges by directing “a comprehensive review of the ecological, economic and environmental necessity of terminating or amending any existing wind energy leases, identifying any legal bases for such removal.” 

The wind power industry and its advocates were left with more questions than answers Jan. 21. 

“It is too soon in the process to determine what impact, if any, federal actions might have on New York reaching its ambitious renewable energy targets,” a spokesperson for the New York State Energy Research and Development Authority said. 

Offshore wind is a key part of New York’s decarbonization strategy, and NYSERDA is charged with contracting 9 GW of capacity to be online by 2035. 

Empire Wind 1 is among the state’s contracted projects, and Equinor is ramping up preparations to build the project. 

A spokesperson on Jan. 21 took the same tack as the renewable energy industry has taken since Nov. 5, emphasizing the economic and energy benefits of offshore wind: 

“We will continue to assess all policy developments and work with the Trump administration as we deliver long-term energy solutions for the growing American economy.” 

The Oceantic Network juxtaposed the contradictory aspects of Trump’s various first-day actions, declaring a national energy emergency and trying to curtail a source of electricity. 

“Today’s actions threaten to strand $25 billion already flowing into new ports, vessels and manufacturing centers, and curtail future investments across our country,” CEO Liz Burdock said. “We urge the administration to reverse this sweeping action and keep America working in offshore energy as part of its commitment to an ‘all-of-the-above’ energy strategy.” 

Trump’s executive order targets the Lava Ridge onshore wind project in Idaho specifically and onshore wind in general. 

But it seems more focused on offshore wind, where the federal government can have more impact — few projects are planned close enough to shore that they would be subject to state review. 

Projects in federal portions of the Outer Continental Shelf face review by a host of federal agencies, any of which might move more slowly or less cooperatively than they did under the Biden administration, which was highly supportive of offshore wind development. 

Still, the executive order stopped well short of the existential threat to offshore wind Trump voiced on the campaign trail, with implications of a halt to construction or operation of fully permitted projects. 

“The actual executive order is more cautious than feared,” research and strategy firm Jeffries wrote in a Jan. 21 update. 

But what does the order mean — will it scare away investors, or derail the yearlong commitments needed to build a domestic supply chain and supporting ecosystem? Might that also limit the industry, with the added bonus of making it appear too weak to stand on its own? 

It is too soon to tell, said Oceantic, which represents more than 400 companies working in the offshore wind sector. 

Danish wind power leader Ørsted, which has had perhaps the rockiest ride in the early years of U.S. offshore wind development, offered no insight during a conference call Jan. 21 as to what impact the order might have on its operations. 

Massachusetts Gov. Maura Healey (D) spoke resolutely Jan. 21 of the state’s support and need for offshore wind development. 

But she acknowledged she was concerned about the executive order and said: “We’ll see what else comes on this.” 

Healey emphasized the electrical generation capacity, economic benefits and job creation that offshore wind would offer, rather than the ecological benefits. 

In short, she followed the same script most of the U.S. renewable energy sector has followed since the election in November of an avowed climate skeptic and fossil fuel fan. 

Trump apparently was not swayed by that line of reasoning over the past two months, but advocates remain hopeful that members of his slim Republican majority in Congress will want to protect the new jobs created in their districts by green energy manufacturing. 

“The offshore wind industry’s supply chain alone spans 40 states and $25 billion … in investments, powering economic development and job creation,” Advanced Energy United CEO Heather O’Neill said. “Pausing offshore wind projects puts livelihoods at risk and will make it harder and more expensive for states to meet their energy needs.” 

The order goes beyond a freeze on permitting and leasing. It blocks issuance of rights of way and loans until an assessment is completed on the environmental impact of onshore and offshore wind, the economic costs of intermittent generation of electricity, and the effects of subsidies on the viability of the wind industry. 

American Clean Power Association CEO Jason Grumet assailed the provisions as being at odds with the nation’s character and interests. 

“For too long, we have witnessed careening policy restrictions on the development of energy resources on our nation’s vast federal lands,” he said in a news release. “Regardless of administration, ‘some of the above’ strategies are not good energy policy. No nation can achieve energy dominance absent consistent policy that moves beyond the idea that energy systems have partisan character.” 

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Appeals Court Rules FERC Improperly Awarded RTO Membership Adder

The 6th U.S. Circuit Court of Appeals has ruled that FERC improperly allowed Duke Energy Ohio and FirstEnergy to include the RTO adder in their rates despite participation in an RTO being mandated by Ohio law.

In a December 2022 order, the commission removed the adder from the rates filed by two of American Electric Power’s subsidiaries but left it in place for Duke and FirstEnergy (EL22-34). The commission differentiated between the three by stating that it previously approved AEP’s application for the adder as an independent element, but that Duke’s and FirstEnergy’s rates were the culmination of settlements that formed the entirety of their rates. (See FERC Orders Two Ohio Utilities Ineligible for RTO Adder.)

While FERC argued it could not disentangle the RTO adder from the negotiated rates Duke and FirstEnergy reached in separate proceedings with consumer groups, the 6th Circuit said that in both instances it could be determined that a 50-basis-point adder was included. The commission said it cannot know how the inclusion of the adder interacted with the “precise trade-offs and concessions” in other elements of the settlement.

The court asserted that FERC practice at that time was to grant the adder regardless of the circumstances of a utility, such as whether it was in a state that mandates RTO participation, so the adder likely was not to be a significant factor in negotiations.

“Contrary to FERC’s assertion, whether it approved the RTO adder explicitly on a ‘single-issue’ basis or impliedly as part of a settlement makes little difference to how the three utilities approached rate negotiations,” the ruling said.

Judge Karen Nelson Moore partially dissented from the ruling, arguing that modifying elements of a settlement could undermine the preference both FERC and the courts have adopted for resolving issues through agreements over potentially intensive and costly litigation. She said the commission’s original solution of eliminating the AEP adders while leaving the Duke and FirstEnergy agreements in place would advance valid policy goals around consumers’ rates and promote dispute resolution through settlements.

“If FERC had accepted OCC’s [Ohio Consumers’ Counsel] invitation ‘to change unilaterally a single aspect of such a comprehensive settlement’ … the commission could have signaled to parties that their settlements could become unsettled as a result of later legal developments in which the parties had little say. This in turn would rob the settlement process of the certainty and predictability that incentivize settlements and thereby enhance administrative efficiency in support of the public good,” Moore wrote.

Both AEP and the OCC appealed FERC’s order to the court, the former requesting that the adder be reinstated and the latter seeking its removal from Duke and FirstEnergy’s rates.

The court consolidated that appeal with a separate proceeding Dayton Light and Power (DPL) initiated after FERC rejected its application for the adder in 2021 (ER20-1068). The commission determined that DPL was ineligible for the adder on the grounds that Ohio law requires its membership in PJM.

Dayton argued that Section 219 of the Federal Power Act does not condition eligibility for the adder on whether a state makes that decision mandatory and posited that FERC’s awarding of the adder preempts state law.

The court disagreed, stating that the adder is an incentive for taking a voluntary act.

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ERCOT Forecasts Highest March Risk of EEAs in Early Evening

ERCOT‘s Monthly Outlook for Resource Adequacy (MORA) report for March predicts the highest risk of an energy emergency alert (EEA) in the month will occur around 7 p.m. Central time, an ERCOT representative said in a webinar hosted by the Texas Reliability Entity on Jan. 21. 

However, the overall likelihood of an emergency in the month is likely to remain low. 

Pete Warnken, ERCOT’s resource adequacy manager, shared the report during the regional entity’s monthly Talk with Texas RE webinar, as part of a presentation on the grid operator’s reliability assessments for the winter months. NERC Manager of Reliability Assessment Mark Olson also took part in the call to discuss the ERO’s Winter Reliability Assessment and Long-Term Reliability Assessment, with a focus on their implications for the Texas energy grid. 

ERCOT develops each MORA two months ahead of the month covered, based on data provided by ERCOT, its market participants and the grid operator’s consultants. MORA releases are targeted for the first Friday of the month; the March outlook was published Jan. 9. 

The MORA evaluates resource adequacy in two ways: first, by determining the risk ERCOT may need to issue an EEA or begin to order controlled outages for the monthly peak load day; and second, by evaluating the extent to which resource capacity can provide sufficient operating reserves for the hour with the highest risk of a reserve shortage. ERCOT does not specify a date for the peak load day. 

According to the March MORA, the chance of an EEA — defined as the probability of capacity available for operating reserves (CAFOR) being less than 2,500 MW — on March’s peak load day will be 6.31% at 7 p.m. Central time, the highest likelihood of the day. The chance of ordering controlled outages, which matches the probability of CAFOR being less than 1,500 MW, also will be highest at that time, around 5.42%. 

Warnken observed that while this level does not rise to what ERCOT would consider an elevated risk — which would mean a 10% or greater probability of issuing an EEA — it is higher than what the operator has seen in previous years for the same time period. This also was true of the February MORA, which he shared for comparison’s sake. 

“You’ll notice that for … almost every hour, you do see a probability greater than zero,” Warnken said. “This is something that we weren’t seeing last year for a monthly report. And what explains this is, there’s been a lot of new loads being added to the system … things like data centers [and] AI computing facilities that run basically around the clock. And because they’re high loads for every hour, that risk [of having insufficient reserves] increases for the hours beyond what you typically see.” 

Warnken also discussed ERCOT’s upcoming Capacity, Demand and Reserves (CDR) report, which the ISO normally publishes twice a year. Because of “significant methodology changes” introduced since the last CDR in May 2024, ERCOT delayed the planned December release to the middle of February to ensure the report’s quality. (See Texas PUC Shelves PCM Design Over Lack of Benefits.) 

The biggest change to the report’s methodology is the use of effective load carrying capability (ELCC), defined as the expected reliability benefits of inverter-based resources during the hours with the highest risk of loss-of-load events, rather than using the historic availability of wind and solar facilities during peak load hours as in previous reports. Warnken said this approach will provide greater granularity into the effect of individual wind and solar facilities on the system, as well as battery energy storage systems. 

Additional updates include revising the criteria for including planned resources in the CDR. Previous iterations of the report previously required material such as a signed interconnection agreement, adequate water supplies, and air permits; on top of these, the CDR now will require notification to ERCOT that a project developer has provided financial security for facility construction to the transmission provider, and that the transmission provider has received a notice to proceed with interconnection construction. 

“One of the issues that we’ve had is that we’ve overestimated the amount of planned capacity forecasted,” Warnken said, noting that construction often is canceled or delayed on generation projects. “What we wanted to do is, add a couple of additional criteria to make sure that [we’re] less likely [to go] off the mark because of all these postponed projects.” 

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Ørsted Takes $1.7B Impairment on US Offshore Wind

Ørsted has announced new problems and an additional $1.7 billion in impairments for its U.S. offshore wind portfolio. 

And that was before President Trump took office and fired off an executive order creating a whole new world of hurt for the struggling U.S. offshore wind sector. 

The world’s leading offshore wind developer said Jan. 20 that increases in long-dated U.S. interest rates, decreases in the value of seabed leases, and delays and cost escalations expected with the Sunrise Wind project will cost 4.3 billion, 3.5 billion and 4.3 billion Danish Krone, respectively, or $1.69 billion (U.S.) total. 

During a conference call with financial analysts Jan. 21, CEO Mads Nipper said he would not speculate on the impact of Trump’s Jan. 20 executive order but it did not contribute to the impairments. 

The news is the latest in a series of financial blows in the U.S. market for the Danish wind power developer, which has seen its stock value crater as one problem after another carries impacts sometimes ranging in the hundreds of millions of dollars. 

Ørsted has canceled offtake contracts for New York and Maryland offshore wind farms and canceled a New Jersey project outright amid inflation and supply chain pressures. 

It’s running into cost increases and delays on its Revolution Wind project, now under construction off the New England coast, as well as for Sunrise Wind, which has begun onshore construction in New York. 

Ørsted had a landmark success in 2024 when its South Fork Wind project became the first utility-scale offshore wind farm to come online in U.S. waters. It, too, ran into cost escalations, but it’s a very small facility, rated at only 132 MW. 

During the conference call, an analyst noted that Ørsted had a stellar track record in Europe and Taiwan. “So can you in any way try to help us” understand, he asked, “why it is that in the U.S., execution just seems to continue to go wrong almost quarter by quarter?” 

Nipper replied: “It is very disappointing that we are running into these, but it is simply the immature and nascent industry of both the supply chain and the execution setup of the U.S. practice compared to any other place we operate in the world, most notably Europe.” 

Nipper told analysts he would take questions only on the impairment, but was asked nonetheless about Trump’s executive order. 

“Because it was issued late last night, we are in the process of reviewing it to assess the impact of our portfolio,” Nipper said. “That’s all we have to say at this stage.” 

The impairment resulting from interest rates is fairly straightforward — it is a capital-intensive business and capital became more expensive, Nipper explained. 

The impairment on the value of Ørsted’s seabed leases off the New Jersey, Delaware and Maryland coasts is the result of the company looking at market uncertainties and deciding to mark down the value. 

The election of a president determined to halt offshore wind development might seem to have played some factor in that loss of value, but Nipper made no such connection. 

“I want to highlight that we believe the leases continue to hold strategic optionality and value based on the long-term potential of the U.S. offshore market,” he said. 

The Sunrise impairment is less straightforward, more entangled in the challenges of standing up a new industry on a continent without an ecosystem to support it. 

Nipper explained: 

Completion of the first U.S.-built wind turbine installation vessel was delayed, forcing Ørsted to shuttle components of Revolution and Sunrise around on barges to remain compliant with the Jones Act.  

The barge model is slower and less efficient because it is more vulnerable to foul weather, especially in winter. The construction of Sunrise is expected to span two winters. 

Based on experiences so far this winter with Revolution, Sunrise likely will take longer than expected to build and therefore require a longer charter of vessels and crews, which come with a high daily cost. 

Finally, the HVDC export cable was found to be defective and needed to be remanufactured — leading to a delay in load-out and installation, and therefore another escalation of vessel and crew costs. 

All of this has depleted the Sunrise contingency budget, necessitating the new impairment. 

Despite all that, Sunrise remains a money-making proposition, with an expected internal rate of return in the mid-single digits over its lifetime, Nipper said. 

He cautioned, however, that this could change: “This assessment does not take into account any potential initiatives of the incoming U.S. administration.” 

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Trump to Declare ‘National Energy Emergency’ to Ramp up Oil, Gas Production

Minutes after he was sworn in as 47th president of the United States, Donald Trump pledged to bring down energy prices by immediately declaring a “National Energy Emergency” and signaled his intention to rapidly increase production of oil and gas to underpin both economic growth and national security.

“We will drill baby, drill,” Trump said in his 30-minute inaugural address. “America will be a manufacturing nation once again, and we have something that no other manufacturing nation will ever have: the largest amount of oil and gas of any country on Earth. And we are going to use it. … We will bring prices down, fill our strategic reserves up again, right to the top, and export American energy all over the world. We will be a rich nation again, and it is that liquid gold under our feet that will help to do it.”

Trump also pledged to end the “Green New Deal” and “electric vehicle mandate,” terms which he and Republican lawmakers have used as negative labels for former President Joe Biden’s clean energy policies and the EV tax credits and other incentives in the Inflation Reduction Act.

Following the inauguration, the White House provided an outline of the energy emergency declaration and other expected executive actions on energy policy.

The apparent intent of the emergency declaration would be to “use all necessary resources to build critical infrastructure.” Other actions would be focused on streamlining permitting and reviewing for potential rollback all regulations resulting in “undue burdens” on energy production and use, as well as on mining for “non-fuel” minerals.

The White House did not specifically state whether the declaration would lift any of the Biden administration’s restrictions on LNG export facilities or oil and gas leasing on federal lands, or whether Trump’s definition of critical infrastructure will include high-voltage interregional transmission.

EPA’s finalized limits on power plant and vehicle tailpipe emissions likely will fall into the regulations considered undue burdens.

As expected, Trump also once again will withdraw the U.S. from the 2015 U.N. Paris Agreement on climate change, aimed at limiting the increase in global average temperature to 1.5 degrees Celsius by 2050. (See Trump Pulling U.S. Out of Paris Climate Accord.)

A long-time opponent of wind power, he also intends to end leasing for wind farms on federal land, which could include both on- and offshore leasing.

Finally, the president will “empower consumer choice” in EVs and a range of household appliances, including washing machines, dishwashers, showerheads and toilets, likely through potential rollbacks of federal energy-efficiency standards.

The White House had yet to announce the signing of any executive orders as of press time.

Appointments

The White House did announce a series of presidential appointments and nominations for acting leaders and subcabinet positions, respectively.

At DOE, Ingrid Kolb will be acting secretary of energy, pending confirmation of Trump’s nominee, Chris Wright, CEO of Liberty Energy. A career administrator, Kolb has directed DOE’s Office of Management since 2005.

Another career administrator, Walter Cruickshank, will become acting secretary of the interior, pending the confirmation of former North Dakota Gov. Doug Burgum. Cruickshank currently is deputy director of the Bureau of Ocean Energy Management.

Preston Wells Griffith, who served as a special adviser on energy and acting assistant secretary of energy during the first Trump administration, has been nominated to be DOE’s undersecretary for infrastructure, replacing David Crane.

And Dario Gil, senior vice president and director of research at IBM, has been tapped as DOE’s undersecretary for science, replacing Geraldine Richmond.

LPO’s Last Hurrah

Trump may have limited ability to claw back IRA tax credits and incentives. According to a final “Investing in America” report from the Biden administration, about $100 billion, or 90%, of IRA funding available through the end of 2024 has been “obligated” with signed contracts, which will make any claw back attempts difficult.

The report also noted that EPA had obligated all of the $27 billion it received for the Greenhouse Gas Reduction Fund, with $20 billion going to a national clean energy funding network of community development banks and $7 billion going to the Solar for All program, aimed at funding solar projects for low-income communities.

DOE’s Loan Programs Office pushed through a final surge of deals, announcing three loans with final contracts totaling more than $16.5 billion on Jan. 17, including:

    • $15 billion to Pacific Gas and Electric for its Project Polaris, which will upgrade transmission with grid-enhancing technologies, increase hydropower and energy storage, and deploy virtual power plants;
    • $996 million to Ioneer to develop its Rhyolite Ridge project in Nevada, which will produce lithium carbonate to be used in EV batteries; and
    • $584.5 million to Convergent Energy and Power for utility-scale solar and storage projects to improve grid resilience in Puerto Rico.

In one of his final reports as LPO director, Jigar Shah said the office has a pipeline of more than 160 applications seeking more than $200 billion in loan guarantees for a range of projects.

Reactions

New York Gov. Kathy Hochul (D) and New Mexico Gov. Michelle Lujan Grisham (D), co-chairs of the U.S. Climate Alliance, stated that “we will continue America’s work to achieve the goals of the Paris Agreement and slash climate pollution.”

Formed after the first withdrawal in 2017, the Climate Alliance is a bipartisan organization of U.S. governors from states that have committed to reducing emissions in line with the agreement.

“Our states and territories continue to have broad authority under the U.S. Constitution to protect our progress and advance the climate solutions we need. This does not change with a shift in federal administration,” Hochul and Grisham wrote in a Jan. 20 letter to the U.N. Framework Convention on Climate Change.

Andrew deLaski, executive director of the Appliance Standards Awareness Project, said Trump’s plans to roll back appliance efficiency standards “would not help families and would only raise their total costs.”

“Test after test has found that efficient new dishwashers, washing machines and showerheads perform far better than old models,” deLaski said.

Heather O’Neill, CEO of Advanced Energy United, called on Trump to recognize that his “promise to achieve greater energy abundance in America must include leveraging the incredible, proven power of advanced energy technologies.”

“Our power grid faces real challenges, and at a moment when wildfires and extreme temperatures threaten lives across the country, it’s clearer than ever that we need to deepen our investments in advanced energy solutions that increase resilience and lower costs,” O’Neill said. “We urge the administration to embrace the market forces and tax cuts that are empowering states to meet their energy needs and goals.”

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SPP MOPC Briefs: Jan. 15, 2025

Real-time Dispatchable Transactions

The SPP Markets and Operations Policy Committee on Jan. 15 approved tariff revisions that would implement dispatchable transactions in the real-time energy market.

Dispatchable transactions, already instituted in the RTO’s day-ahead market, allow market participants to submit dynamic schedules, which SPP evaluates and dispatches economically. RR653, passed with 95.56% stakeholder approval, essentially would extend the existing dynamic interchange transaction framework to the Real-Time Balancing Market.

The goal, said Yasser Bahbaz, SPP senior director of market development, is to increase market participation, especially at the seams. Market participants could change their bids and offers up to 30 minutes prior to the operating hour. “The advantage here is that now we would have a transaction product in real time that we could economically assess and dispatch in real time, and we’d determine whether it’s economically favorable to serve our market,” Bahbaz said.

“Because it is a dispatchable transaction, the market will have every opportunity to assess that transaction,” Bahbaz said in addressing some stakeholder concerns. “So we think this is better than having fixed schedules, in some ways, because we would be able to assess ramp, and to the extent that we can take in imports or have exports, it would be co-optimized with what we have. … The nice thing about this product is that it is fully flexible.”

Steve Sanders, strategic adviser for the Western Area Power Administration, said that while the organization was supportive of the product’s concept, “this proposal is not there yet. It lacks the effectiveness of market-to-market seams coordination and zonal resource optimization, with several risks to both product manipulation, effects to internal market optimization, and reliability during abnormal or emergency operating conditions.”

“I think we are committed to solving these issues together with staff” and the Market Monitoring Unit before the proposal is filed with FERC, Sanders continued. “Our goal would be that, to the extent that we have a product that would pass the FERC hurdle and provide benefits to the market and not create issues, that would be a desirable outcome.”

American Electric Power’s Richard Ross — chair of the Market Working Group, which recommended approval of the revisions — asked Bahbaz whether any of WAPA’s concerns gave SPP pause in moving forward with them. “Do you think we need to do additional work as a group before this is approved, or can we overcome these concerns during the FERC filing?”

“From SPP’s standpoint here, I think it’s important for us to move this forward,” Bahbaz answered.

Jodi Woods, SPP director of market monitoring, said the RTO addressed many of the MMU’s concerns with the proposal, “but we do still have some outstanding ones that we’re continuing to monitor. … We’re going to follow it through implementation … including potentially recommending additional tariff language.”

Extension for FERC Order 881 Implementation

The MOPC approved asking FERC for an extension to comply with certain requirements of Order 881, from July 12 this year to Sept. 1, 2026.

Issued in 2022, Order 881 directs transmission owners and providers to end the use of static line ratings, and to use ambient-adjusted ratings (AARs) and seasonal ratings instead. FERC allowed three years to implement the requirements.

In December 2023, FERC found that SPP’s plan was mostly in compliance but that it had not properly explained whether and, if so, how the use of AARs would affect existing market processes (ER22-2339).

Since then, the RTO’s Ambient Adjusted Ratings Implementation Task Force has worked to develop the timelines and other requirements for the calculation and implementation of AARs. But members of the task force recommended to the Operations Reliability Working Group (ORWG) that based on TO readiness, staff should request an extension to comply with the AAR requirements.

Based on a survey conducted Dec. 20, 2024, only 24% of members said they would be ready on SPP’s targeted go-live date of July 1. According to the ORWG, a minimum of 67% of impacted members, and a minimum of 90% of impacted lines and flowgates (“critical mass”), are needed for implementation.

It also wants more time for testing, preferably not while SPP works to integrate RTO West, and avoiding a peak season for implementation.

Responding to COO Lanny Nickell on how the Sept. 1 date was chosen, SPP’s Charles Cates said staff were confident that implementation could not be achieved any earlier than April 1, 2026. “But they also don’t want us to take too much time.”

Advanced Power Alliance’s Steve Gaw asked if SPP had any idea how much delaying implementation of AARs, which he noted can reduce transmission congestion, would cost.

Cates answered that it would be “minimal to none. The budget that we have accounted for the project, we are not anticipating to change at this time. There may be some additional staff costs as we implement this, but those will be embedded.”

“That was a great answer to a question I didn’t ask,” Gaw replied. “My question was, how much are we potentially costing the market by not implementing 881 in a timely manner?”

“We’re not sure. We have not done in a while an ambient-adjusted market study,” Cates said.

Gaw then noted the survey showed that 71% of members said they would be ready by Dec. 1, 2025, surpassing staff’s 67% threshold. “Why did you all feel like that that wasn’t a better date, at least to get us up and running sooner with this?” he asked. “I think FERC might scrutinize this fairly significantly because of the extent of the delay.”

Cates responded by saying staff expected SPP’s request to be among the shorter extensions among the RTOs, with some asking for up to 2028, “and I certainly understand why.” Specific to SPP, “we have a lot of deliveries coming for the West integration. So we need to be very careful with how we stage this and not interact with that project.”

The Natural Resources Defense Council’s Christy Walsh also noted the survey results and wondered how much of that 71% actually would be ready in October. “I understand you don’t want to implement something new in the middle of winter — that makes complete sense — but we’re constantly hearing we have a resource adequacy problem. … If we have 71% of people ready to free up some transmission constraints on the transmission system where we have more resources adequacy, that just seems like an easy win,” she said.

Evergy’s Jeremy Harris, chair of ORWG, noted that under SPP’s current timeline for implementation, its ratings database, the Limit Exchange Portal (LEP), was supposed to have begun testing Nov. 1. It still has not been delivered. “So from a TO/TOP perspective, we have little faith in SPP’s timeline, and we need this extension because we will need to connect to it, and SPP doesn’t even have the tool.”

“That still doesn’t explain to me why we have a survey that says 71% think they’ll be ready by the end of this year,” Walsh countered. “I’m hearing separately, ‘but not really.’”

Harris responded that he expected that if the survey were conducted today, there would be fewer members saying they would be ready based on the fact that the LEP tool still was not ready.

The extension request was approved with 94.44% support.

Expedited Resource Adequacy Process

In a relatively close vote, the committee endorsed developing a proposal to create a one-time process to quickly add generation to meet load-responsible entities’ resource adequacy needs outside of SPP’s generator interconnection procedures.

“Given the concerns by some stakeholders to come up with a process to meet those [RA] needs,” SPP’s Steve Purdy said.

The proposal largely is based on MISO’s Expedited Resource Adequacy Study, which it hopes to file by February. (See MISO Tells Board RA Fast Lane in Interconnection Queue is a Must.) Both essentially would create a “fast lane” for projects that are deemed necessary to maintain reliability.

In SPP’s case, the projects would be determined by the LREs themselves. And the RTO is relying on its Regional State Committee’s endorsement “to undergird and provide justification for the deviation from established FERC policy,” Purdy said. “It’s not truly a GI study; it’s a resource adequacy study that involves interconnection of new resources,” though it would follow certain procedures for studying projects.

The process would be open to any generator type, though there would be a capacity ceiling determined by SPP based on LREs’ load projections. Projects would be required to have a proposed commercial operation date within five years of its submission; if SPP’s preferred timeline is approved, that would be by 2030.

The goal is for the MOPC to approve the formal revision request in April, with RSC and Board of Directors approval in May.

“I think SPP staff has done a remarkable job in a very short time,” Golden Spread Electric Cooperative’s Mike Wise said. “I think this is a good example of SPP staff responding to stakeholders’ concerns and developing a product that really can meet their needs.”

Other stakeholders representing LREs voiced their support. But several stakeholders voiced opposition based on the ongoing work on SPP’s Consolidated Planning Process (CPP).

APA’s Gaw said, “We really don’t know what this exact proposal is going to look like when it gets into [revision request] form. We’ve got serious concerns with this proposal for a number of reasons,” among them being that stakeholders already have spent “countless hours” on the CPP, but this new proposal seemed to be taking precedence.

He also argued that MISO is letting states determine their RA needs, while “this is entirely left up to the load-responsible entities, and I don’t know how the states are going to be able to manage ensuring consumer protections.”

“CPP is something that would address a lot of the concerns that we have right now, and MISO is not in the same position as SPP is,” AES’ Shilpi Sunil Kumar said. “I would request staff to keep that in mind, that we don’t need to do exactly as MISO is doing because their concerns and problems are different.”

Invenergy’s Arash Ghodsian said that, as he told MISO with its proposal, “we need some transparency on some of the details” about the affected-system aspect. “There’s probably room for some improvement, but the details at this point are very important if we’re going to provide support.”

Purdy responded that SPP likely would need to propose revisions to its Joint Operating Agreement with MISO.

Lucas to Succeed Nickell as COO

Nickell opened what he said likely would be his last MOPC meeting as the committee’s secretary with a brief speech as he prepares to take over for SPP CEO Barbara Sugg on April 1.

“I’m super excited — really excited — to be SPP’s next CEO; to have the opportunity to lead this organization,” Nickell said. “My goal for SPP is really simple: … I want SPP to be the best. The best RTO in the country. That really shouldn’t be that hard to do because we already have the best employees, and we already have the best stakeholders.”

After his remarks, Nickell announced that Antoine Lucas, vice president of markets, will take over as COO.

“I’m really excited about this new opportunity, particularly the increased role in the stakeholder process that comes along with it,” Lucas said.

Nickell also reminded attendees of SPP’s inaugural Energy Synergy Summit, announced the previous day, to be held March 3-4 in Dallas.

In its announcement, the RTO billed the event as “a deep dive into resource adequacy, load and generation interconnection, grid modernization, and the policies and partnerships needed to support them.”

“This is going to be a tremendous opportunity for our stakeholders and anyone who’s interested in … figuring out how to add resources quicker while doing it reliably, and adding load, not only quicker but also reliably,” Nickell said. “Trying to meet both the expectations that I know a lot of our members have: ‘I need more resources, and I want to serve this load that I know is coming.’ That is what the purpose of this summit is: to talk about both those issues.”

Nickell was asked whether this would be the first in an annual series. “I suspect that we’ll need to do that,” he replied, though he seemed to imply this new event really is a continuation of the RTO’s Resource Adequacy Summit, held in 2023. “This time we thought, ‘Man, we need to combine the topics of resource adequacy and load growth, and specifically the kind of load growth that we’re seeing … with big data centers.”

The deadline for registration is Feb. 24, while the special room rate for the Dallas/Fort Worth Airport Marriott, where the conference will be held, ends Feb. 10.