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February 6, 2025

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Senate Confirms Trump’s Energy, Interior Secretaries

The U.S. Senate on Feb. 3 voted to confirm President Donald Trump’s nominee to be secretary of energy, Chris Wright, 59-38, days after confirming Doug Burgum as secretary of the interior.

Senate Energy and Natural Resources Committee Chair Mike Lee (R-Utah) said Wright, CEO of Liberty Energy, would reverse the climate policies championed by the Biden administration’s Department of Energy.

“For the last four years, when Americans opened their energy bills, they didn’t see ‘climate plans’; they saw costs piling up and questions they couldn’t answer,” Lee said. “With Chris Wright as secretary of energy, I am confident that we can reverse the irresponsible policies of the Biden administration and prioritize affordable and reliable energy.”

Lee’s counterpart in the House, Energy and Commerce Committee Chair Brett Guthrie (R-Ky.), also welcomed Wright’s confirmation.

“Maintaining affordable and reliable energy will be key to both our economic success and national security in the years ahead,” Guthrie said. “Secretary Wright understands the importance of utilizing our domestic energy resources to secure the grid, lower prices and create family-sustaining jobs.”

Burgum, former governor of North Dakota, was confirmed 78-19 on Jan. 30. Both he and Wright cleared the floor within two weeks of making it out of the Energy and Natural Resources Committee, which approved them both Jan. 23. (See Trump Energy, Interior Cabinet Picks Easily Pass Committee Votes.)

“Gov. Burgum’s confirmation today is a win for our public lands and a win for American energy,” Lee said. “He has spent his career bringing people together to solve problems and earned the trust of tribes, businesses, conservationists and working families alike. He understands that we cannot regulate our way into prosperity.”

Advanced Energy United welcomed the two new secretaries with statements arguing that its members’ technologies — such as solar, wind, storage and advanced transmission — are part of an affordable, reliable grid.

“Our industry shares with Secretaries Burgum and Wright their ambition to lower energy costs, strengthen the electric grid and make America energy abundant,” CEO Heather O’Neill said. “We urge the incoming administration to embrace and enable the market forces and investments that are allowing states to leverage advanced energy solutions to meet their energy needs. Advanced energy technologies provided 96% of all new electricity added to America’s power grid in 2024 and remain the lowest-cost way to reliably meet growing electricity demand.”

Electric Power Supply Association CEO Todd Snitchler argued that Wright and Burgum should support competitive markets as the power industry seeks to meet higher demand from data centers.

“Properly functioning competitive wholesale electricity markets have a proven track record of delivering the reliable power needed to fuel this growth while adapting to new technologies and market conditions and shielding consumers and taxpayers from investment risks,” Snitchler said. “These benefits are made all the more salient as recent news about DeepSeek and other AI tools has underscored the likely quickly changing dynamics of the industry as it develops.”

American Clean Power CEO Jason Grumet congratulated Burgum on his new role and said the clean energy industry wanted to work with the new administration.

“We are eager to support the administration’s efforts to make American energy dominance a reality,” Grumet said. “This whole-of-government approach will be crucial to aligning agencies to advance an ‘all-of-the-above’ energy strategy which is essential to achieving these goals.”

National Rural Electric Cooperative Association CEO Jim Matheson said his members often have to deal with Interior, as they operate on federal lands.

“Electric cooperatives serve 56% of the nation’s landmass and operate on more public lands than any other type of utility,” Matheson said. “We look forward to partnering with Secretary Burgum and his team to alleviate the layers of bureaucratic red tape in our land and species management agencies that so often stand in the way of electric system operations, reliability and affordability. By doing so, cooperatives can more effectively operate and maintain their systems, harden the electric grid against wildfire and other threats and meet surging electricity demand.”

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Uncertainty Remains Around Energy Tariffs amid Last-minute Deals

As the Trump administration forged last-minute agreements with Canada and Mexico to postpone steep new tariffs, the energy industry fretted about potential fallout for cross-border supply chains and wholesale electricity markets. 

President Donald Trump signed a series of executive orders Feb. 1 creating new tariffs on Mexico, Canada and China, purportedly a response to the countries’ failure to control drug trafficking and — in the case of the U.S. neighbors — illegal immigration. 

The tariffs would include a 10% duty on Canadian energy, a 25% tariff on other Canadian goods and a 25% fee for all Mexican imports. On Feb. 3, the day before the tariffs were set to take effect, the U.S. announced a month-long pause on the tariffs on both countries, following agreements to increase security at both borders. 

However, the administration is set to proceed with a new 10% tariff on all imports from China, which comes on top of steep tariffs imposed by the Biden administration on battery components, electric vehicles and solar cells from the country. (See Biden’s New Tariffs Target China’s Dominance in Solar, EV Markets.) 

Much of the uncertainty around the tariffs stemmed from vague language in the executive order regarding the lower tariffs for “energy or energy resources.” 

The definition referenced by the order classifies energy and energy resources as “crude oil, natural gas, lease condensates, natural gas liquids, refined petroleum products, uranium, coal, biofuels, geothermal heat, the kinetic movement of flowing water and critical minerals.” 

Electricity is not explicitly mentioned in the order or the definition of energy or energy resources, and uncertainty remains regarding how the administration would levy a fee on electricity imports from Canada. 

Responding to the order, energy executives representing a wide range of interests expressed concerns about potential cost impacts. 

Jason Grumet, CEO of American Clean Power, said in a statement that the organization “is concerned that increasing the costs of energy production inputs will put upward pressure on consumer energy costs and diminish our capacity to unleash energy abundance.” 

He noted that components needed for solar panels, wind turbines and batteries are manufactured in Mexico and Canada and said the United States-Mexico-Canada Agreement has “been a positive factor in lowering American energy costs.” 

Connor Teskey, CEO of Brookfield Renewable, told investors Jan. 31 that added costs from tariffs on the renewable components ultimately will be passed on to ratepayers via more expensive power purchase agreements. 

“The demand is stronger than ever before. … Should these things change the economics of a project, we will very simply push it through the PPA price,” Teskey said. 

Fossil fuel industry representatives also expressed concern about the tariffs. American Petroleum Institute CEO Mike Sommers noted that American refineries rely on crude imports from Canada, adding that Mexico is the top destination for exports of refinery products, while fossil fuel exports to China totaled over $14.4 billion in 2023. 

“Energy markets are highly integrated, and free and fair trade across our borders is critical for delivering affordable, reliable energy to U.S. consumers,” Sommers said. 

Electrical Uncertainty

Significant uncertainty remains regarding how the tariffs would affect wholesale electricity markets, and whether the administration could even put a tariff on electricity imports. 

A representative of the U.S. International Trade Commission declined to comment on the executive order, but highlighted a provision in the Harmonized Tariff Schedule that states electricity “shall not be subject to the entry requirements for imported merchandise set forth in section 484 of the Tariff Act of 1930.” 

They also linked a 2021 report by the ITC that noted “imports of electrical energy are not considered to be subject to the tariff laws of the United States.” 

From the standpoint of electricity trading, Canadian provinces are more plugged into U.S. markets than to each other, according to the Canada Energy Regulator (CER), which regulates electricity exported from Canada. 

“Most of Canada’s electricity trade is with the U.S., as opposed to between provinces,” the CER notes on its website.

The latest figures from the CER show Canada exported 32,750,232 MWh of electricity to the U.S. over January-November 2024 at an average price of $CAN61.45/MWh, while importing 21,471,172 MWh. The country’s exports, largely produced by hydroelectric dams, were valued at nearly CAN$2.82 billion over that period, with imports estimated at about CAN$1.25 billion. 

Ontario was the largest exporter, at 10,975,316 MWh, followed by British Columbia (5,895,148 MWh), Manitoba (5,682,762 MWh) and Québec (5,330,654 MWh). 

But the relationship has long been symbiotic, with the U.S. receiving significant economic — and reliability — benefits from Canada’s surpluses. 

In New England, imports from Canada are an important part of the resource mix, even as a major drought has caused decreased hydropower generation in Québec over the past two years.

Net imports across tie lines with Canada were used to meet about 5% of the New England’s total electricity demand in 2024. As recently as 2022, net imports across these lines covered over 13% of the region’s total electricity use. (See New England Gas Generation Hit a Record High in 2024.) 

Even in a down year for hydropower in 2024, imports played a major role in preserving grid reliability during a pair of capacity scarcity events in the summer. Imports earned a combined $29 million in credits for performing during these periods, far more than any other resource type. (See NEPOOL Markets Committee Briefs: Dec. 10, 2024.)

A 10% increase in the cost of Canadian electricity would raise the market price paid to all participating resources when the imports are setting the market price. According to the ISO-NE Internal Market Monitor, external transactions — which include imports from both Canada and New York — were marginal 27% of the time in the day-ahead market in 2023. 

“With the caveat that we are entering uncharted waters, at this time I do not expect this to have a major impact on electricity imports into New England,” said Dan Dolan, president of the New England Power Generators Association. “NEPGA’s observations are that those north-to-south flows tend to be less economically driven and more about what raw availability is available in excess of native load.”

However, the tariffs could create challenges for long-term state contracts for power from Canada, he noted. Hydro-Québec has a long-term contract with Vermont, supplying the state with about a quarter of its total electricity needs. 

The company also has signed long-term contracts with Massachusetts for the New England Clean Energy Connect (NECEC) transmission line, slated to come online at the end of 2025, and with New York for the Champlain Hudson Power Express, which is projected to finish construction in 2026. These projects could significantly increase the amount of power imported into the Northeast U.S. from Canada. 

“Contracted electricity associated with a fixed cost may require regulatory or contractual adjustments,” Dolan said. He also expressed concern that hydropower would be the only type of generation eligible for the lower 10% tariff, while other sources of power may face the full 25% duty because of the vague language in the executive order. 

Larry Chretien, executive director of the Green Energy Consumers Alliance, noted that NECEC will provide about 15 to 20% of Massachusetts’ electricity. A 10% tariff on these imports “makes the deal far less attractive,” he said.

A representative of Hydro-Québec said the company is “closely monitoring” the situation, including potential impacts on short-term energy sales and long-term contracts, adding that it “will adjust our activities to limit impacts in Quebec.” 

Joe LaRusso, manager of the Clean Grid Program at the Acadia Center, a New England-based climate advocacy group, said he does not think tariffs would have a major effect on New England resource mix, but said they likely would lead to an overall increase in electricity prices.

“It’s not good for a region that is already feeling the pinch of a significant energy burden,” LaRusso said, adding that the cost increases likely would be the most pronounced in the winter, when the region relies most heavily on imported electricity. 

ISO-NE said it is reviewing the proposed tariffs, as well as potential responses from Canadian officials. 

“We are seeking guidance from the administration on what, if any, role [ISO-NE] will be required to have in implementing these tariffs,” the RTO said. “We cannot speculate on what, if any, impact these actions will have on wholesale electricity prices or the level of imports into the region.” 

NYISO wrote in a statement that it “is actively pursuing guidance pertaining to the impact on electricity markets and which Canadian energy resources qualify.” 

Both Northeastern RTOs emphasized the close collaboration and ties between the power systems on both sides of the border. 

BC Retaliation?

Western electricity markets faced a similar state of unease around the treatment of energy supplies from British Columbia, whose provincially owned utility, BC Hydro, shares control of hydroelectric output from the Columbia River system with its U.S. counterparts, the Bonneville Power Administration and the Army Corps of Engineers. 

BC Hydro is closely integrated with the Western U.S. market through the operations of its marketing arm, Powerex, a sophisticated trader that markets the province’s ample surpluses of hydro generation and engages in arbitrage trades throughout the Western Interconnection. 

Powerex accounts for nearly all the province’s exports into the U.S. and currently participates in CAISO’s Western Energy Imbalance Market (WEIM), although it recently said it eventually will leave that market to join SPP’s Markets+, for which it has been a key backer and the top funder. (See SPP Markets+ Tariff Wins FERC Approval.) 

Asked what measures CAISO might have to take to account for the tariffs in its markets, ISO spokesperson Anne Gonzales told RTO Insider: “It’s too early to tell what kind of direct impacts the energy tariffs might have on our market and operations. We are monitoring developments closely as these policies become more defined.” 

Powerex did not respond to a request for comment about the potential impact of the tariffs on its operations. 

In December, Victoria News reported that British Columbia Premier David Eby said he would not rule out cutting the province’s electricity flows to the U.S. in retaliation to tariffs on Canada. 

“We are prepared to support retaliatory tariffs and response to the United States that gets their attention to help them understand what the consequences would be for British Columbians and what the consequence would be for Americans,” Eby said during a Dec. 12 press conference, echoing a similar statement by Ontario Premier Doug Ford. 

While Eby noted that British Columbia generally is a net importer of electricity, he also pointed to Powerex’s strategy of importing electricity from other parts of the West at a “much lower” cost during times of surplus, then selling back into U.S. states such as Washington, Oregon and California during critical periods of peak demand. 

Evidence of the value of that relationship could be seen in January 2024, with Powerex counted among suppliers from across the West that helped prevent multiple utilities in the U.S. Northwest from resorting to rolling blackouts during an extended deep freeze accompanied by low hydro supplies and a fault in the region’s natural gas pipeline system. (See Powerex Report Expands NW Cold Snap Debate.) 

Eby’s office did not respond to a question about whether he still might follow through on the threat to withhold electricity supplies from the U.S. in the face of tariffs. 

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FERC, NERC Praise Grid Performance in Cold Snap

FERC and NERC applauded the performance of the North American electric grid during recent periods of extreme cold weather that deposited snow and ice across much of the Southeastern U.S. this January while promising a deeper review of the events to see what worked in the energy system and what didn’t. 

Low temperatures blanketed the South on Jan. 19, fueled by what the National Oceanic and Atmospheric Administration described as an “Arctic blast” and a “deep trough” of Arctic air. (See NERC Pushes Cold Weather Prep as ‘Trough’ Approaches.) Cities as far south as Louisiana reported extreme low temperatures, with New Orleans hitting 26 degrees Fahrenheit on Jan. 22, the same day that Lafayette saw 4 F and New Iberia reported 2 F — record lows for all three. 

Cities across the South also broke snowfall records: Mobile, Ala., received 7.5 inches and Pensacola recorded 10 inches on Jan. 21, and Fernandina Beach, Fla., had 4 inches on Jan. 22. NOAA said some “sites have recorded more snow so far this winter season than many locations far to the north, including Chicago.” 

However, despite the severe cold, NERC and FERC said in a press release that the grid “operated without any major incidents [and] with no major fuel system disruptions impacting electric generation.” Before the icy weather arrived, the ERO had called on utilities to take necessary steps “to ensure the highest levels of reliability,” expressing particular concern about the supply of natural gas for electric generation. 

NERC and FERC will join with the regional entities to review the grid’s performance during January’s cold weather, the release said. Areas of focus will include winter preparation activities by the electric and gas industries, any changes since the winter storms of 2021 and 2022 that impacted grid performance, and “additional opportunities to enhance winter operations.” The commission and the ERO undertook a similar review following last year’s Arctic storms. (See FERC, NERC Review January Winter Storm Performance.) 

FERC Chair Mark Christie said he looked forward “to learning more about what worked well during very challenging winter conditions,” while NERC CEO Jim Robb said he hoped the review would “help inform both gas and electric industry actions in anticipation of future cold weather events, which are occurring with alarming frequency even during otherwise-mild winters.” 

The ERO said it expects to discuss a summary of the review at a FERC open meeting this spring, prior to the release of a full report. 

NERC warned in its 2024-2025 Winter Reliability Assessment that multiple regions face elevated risk of energy shortfalls during extreme winter conditions extending over a wide area, including parts of Texas and SERC Reliability that were hit by January’s storms. The ERO cited rising demand and retirements of thermal generation capacity as contributing to slimmer reserve margins across the continent. 

Winter weather has been a growing concern for NERC after several severe storms in recent years caused widespread generation outages. FERC and NERC’s final report on Winter Storm Elliott of December 2022 said the bomb cyclone caused an “unprecedented” amount of generation failures, reaching more than 90 GW in coincident unplanned outages, with most of the entities that shed load located in the Southeast. (See FERC-NERC Elliott Report Calls Winter Outages ‘Unacceptable’.) 

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NYISO CEO Lays out 2025 Priorities

NYISO CEO Rich Dewey opened the Management Committee on Jan. 29 with a congratulations on getting through 2024 before looking ahead to the rest of 2025.  

“We had a lot on our plate, very complicated matters that needed to be navigated through the stakeholder process. Sometimes contentious. Sometimes not,” Dewey said. “I do want to express my appreciation to stakeholders for continuing to work through the issues and tee us up for, I think, an equally challenging 2025.” 

Dewey said his “first priority” is maintaining grid reliability. Load forecasting and managing uncertainties are going to be paramount as large loads continue to come online. 

“Specific to this are the large loads that we’ve seen based on economic development, or some of the AI-driven, business-centric data center applications that can pop up pretty quickly,” Dewey said. “Managing that and making sure we’ve got a good, reliable system to deal with those uncertainties is going to be a big part of our forecasting team’s priorities.” 

He went on to say the 2024 Reliability Needs Assessment would “transition forward” to the Comprehensive Reliability Plan this year. In all its reliability, planning and forecasting, NYISO faces challenging levels of uncertainty, and new, innovative methods will be needed to address it, he said. 

Dewey said meeting the needs of the system would require looking at the market structures, rules and planning processes in place to ensure they continue to provide reliability through appropriate market signals. He pointed to the complexities of 2024’s Demand Curve Reset, saying the ISO had heard the feedback from stakeholders and was committed to examining the design principles of the capacity market. (See related story, FERC Accepts NYISO Demand Curve Reset.) 

This will occur alongside the monumental shift in transmission planning required by FERC Order 1920. NYISO is going to have to balance this new long-term regional transmission planning regime while working through the inaugural state Coordinated Grid Planning Process. Dewey said this would require a “tremendous amount of work” in 2025 to meet the needs of stakeholders and position the ISO for an uncertain future.

“I believe we’ve got some of the leading markets, if not the leading markets, in the nation,” Dewey said. But with all the new technologies and transitions occurring industry wide, “we need to continue to stay out ahead of that.” 

Operations Report and Winter Reliability

The committee also heard COO Emilie Nelson’s report on December 2024’s market performance. The average locational-based marginal price was $73.20/MWh, which was higher than the $35.26/MWh for November 2024 and $33.67/MWh for December 2023.  

Both the day-ahead and real-time load-weighted LBMPs were higher than in the previous month. The average year-to-date monthly cost was $44.67/MWh, up 14.2% over December 2023. This correlates with higher sendouts, 432 GWh/day on average compared to 377 GWh/day in November. Natural gas prices also were higher.  

“I’d like to call out that, of course, we had some pretty significant cold temperatures last week, spanning [Jan. 20 to 22],” Nelson said. The peak load was 23,521 MW and occurred Jan. 22, a Wednesday. 

She expressed her gratitude for the communication across the cold-stressed system. 

“Although the neighboring control areas were also operating through tight system conditions, all areas were projected [to achieve,] and then realized, reliable operation,” Nelson said. “It was a situation where the coordination of power flows provided greater regional reliability.” 

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FERC Accepts NYISO Demand Curve Reset

FERC on Jan. 28 accepted NYISO’s proposed tariff revisions that were submitted as part of the Demand Curve Reset, including setting a two-hour lithium-ion battery energy storage system (BESS) as the proxy peaking plant for use in determining the curve for the next four years (ER25-596).

In doing so, the commission dismissed protests from the Independent Power Producers of New York, the Market Monitoring Unit, the Electric Power Supply Association and Ravenswood Operations, among others, finding that NYISO and its consultants had identified the lowest-cost option for a hypothetical peaker plant.

The DCR is a quadrennial process that examines the cost of new entry for a hypothetical peaking plant and the likely revenue the plant would earn from participating in the capacity market. The difference between the likely cost and likely revenue illustrates what the hypothetical plant would need to earn from the capacity market to support market entry.

The latest reset was contentious, frequently driving meetings of the Installed Capacity Working Group past their allotted times with stakeholder discussion, feedback and arguments.

Some of these arguments continued in the FERC filing process with opponents’ protests. IPPNY and the MMU told FERC the two-hour BESS was ill considered from a capacity accreditation factor perspective in that such units would experience price volatility. IPPNY and EPSA asserted that NYISO did not account for the financial risks adequately in BESS development. And IPPNY, the MMU and Ravenswood argued that two-hour BESS units were unable to meet transmission security needs.

FERC rejected these arguments, finding many of them to be speculative and that NYISO’s proposed cost of equity and debt for a BESS peaker was “justified.”

“Based on the record before us, we disagree with protesters that the two-hour BESS technology option will not provide adequate price signals to support the construction of new resources, and the retention of existing resources, to maintain NYISO’s system reliability,” FERC said. “For example, [the New York Transmission Owners’] analysis suggests that capacity costs could increase by 37% due to NYISO’s selection of the two-hour BESS.”

The commission also found that arguments about transmission security were “misplaced,” as NYISO’s service tariff does not require the ISO to consider a peaking plants contribution to transmission security.

“Moreover, NYISO states that it has commenced a multiyear collaborative process with its stakeholders to evaluate potential enhancements to its current capacity market to value resource contributions to transmission security,” it said. “We believe that the separate stakeholder process is the appropriate forum to address any potential transmission security concerns.”

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Ørsted Replaces CEO Mads Nipper

Ørsted CEO Mads Nipper has been replaced by Deputy CEO Rasmus Errboe.

The Danish renewable energy developer announced Jan. 31 that Nipper would leave immediately and Errboe would assume leadership Feb. 1. Errboe, a 13-year Ørsted veteran, formerly was CFO of its global offshore wind business.

Nipper’s four years as CEO were tumultuous for the leading offshore wind developer. The company shed more than 80% of its market capitalization as its investments in the new U.S. offshore wind sector ran into headwinds.

Most recently, the company on Jan. 20 reported $1.7 billion in new impairments on its U.S. offshore wind portfolio. (See Ørsted Takes $1.7B Impairment on US Offshore Wind.)

And that setback did not even reflect the other news that day: the inauguration of President Donald Trump, and his Day 1 executive order targeting offshore wind. (See Critics Slam Trump’s Freeze on New OSW Leases.)

It was a striking juxtaposition for Nipper. He became Ørsted’s CEO in January 2021, just as a strong supporter of wind power was inaugurated as U.S. president, and he departed in January 2025, right after a strong opponent took over.

Former Ørsted CEO Mads Nipper | Ørsted

Lene Skole, chair of Ørsted’s board of directors, alluded to the sea change in the company’s Jan. 31 announcement.

“The renewable energy market has fundamentally changed since January 2021,” she said. “The impacts on our business of the increasingly challenging situation in the offshore wind industry, ranging from supply chain bottlenecks, interest rate increases, to a changing regulatory landscape, mean that our focus has shifted. Therefore, the board has today agreed with Mads Nipper that it’s the right time for him to step down.”

Skole complimented Nipper’s achievements: The company’s installed renewable capacity rose from 11.3 GW to 18.2 GW, and it consistently met its EBITDA projections during his tenure.

The U.S. offshore wind sector, which still has a very significant European component, ran head-on into supply chain shortages, logistics challenges and soaring costs in 2022, just as it was gaining momentum under a supportive federal administration. Most projects, from Maryland to Massachusetts, suffered delays and cost increases, many of them severe enough to cause developers to cancel offtake contracts or ask for more money.

Ørsted went a step further and canceled a mature project outright. (See Ørsted Cancels Ocean Wind, Suspends Skipjack.) That move alone caused a $2.83 billion impairment.

The company did enjoy a milestone achievement under Nipper: completion of the first utility-scale offshore wind project in U.S. waters, South Fork Wind, in March 2024. (See First Large US Offshore Wind Farm Complete.) South Fork had its challenges, but it totals only 12 turbines, and the challenges apparently were surmountable.

And Ørsted was not alone in its struggles; its erstwhile development partner was losing money as well.

In September 2024, after a two-year effort, Eversource Energy extracted itself from its joint venture with Ørsted on South Fork and other projects off the Northeast coast. The New England utility took a $1.95 billion impairment in 2023 on its offshore wind ventures, and it projected its 2024 loss attributable to offshore wind will be in the half-billion-dollar range. (See Eversource Finds OSW Buyer, Takes $1.95B Hit for 2023 and Eversource Takes Another Financial Hit with OSW Exit.)

New Ørsted CEO Rasmus Errboe | Ørsted

Ørsted has begun offshore construction of Revolution Wind, which holds offtake contracts in Connecticut and Rhode Island, and onshore construction of Sunrise Wind, which holds a New York contract. Both projects have seen increasing costs and lengthening schedules in the past several months. And both face the potentially serious threat posed by Trump’s Jan. 20 executive order, which directs “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.”

In a Jan. 21 call with financial analysts, Nipper insisted that Sunrise still could be a profitable project, and he declined to speculate on the impact of the executive order. Further information would come with the company’s annual report on Feb. 6, he said.

An analyst asked how Ørsted could do so well in Europe and Taiwan but keep stumbling quarter after quarter in the U.S.

“It is simply the immature and nascent industry of both the supply chain and the execution setup of the U.S. practice,” Nipper replied.

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Stakeholder Soapbox: Preparing for NERC Registration and Compliance with New IBR Rules

By Terry Brinker

As a former manager of registration for NERC and president and CEO of Reliable Energy Advisors, I have written articles about the risks and challenges of NERC regulations.

In my article “Your Audit Report May Be Worthless,” I warned of falling into the trap of thinking your organization has a strong compliance program because you passed an audit.

Today, I am sounding the alarm about potentially hundreds of facilities being swept up into the NERC regulatory world where fines and penalties can be as high as $1 million a day per violation.

Recently, NERC unveiled updated rules for inverter-based resources (IBRs), which are reshaping the landscape for utilities and energy producers. These new standards aim to enhance grid reliability and security in light of the increasing integration of renewable energy sources, such as solar and wind, into the electric grid.

NERC

Terry Brinker |

For utilities not currently registered with NERC, these changes bring unique challenges and obligations. For entities that are registered and have additional facilities that will meet the new thresholds, more documentation will be needed.

To ensure a smooth transition, nonregistered entities must prepare proactively for NERC registration and adherence to NERC standards. This is no small feat, particularly for newcomers to NERC. In addition, unlike in the past where registration was a voluntary process, NERC has coordinated with reliability coordinators and transmission operators to identify entities that meet this new threshold.

Escaping NERC registration will be unlikely.

Understanding the New NERC Rules for Inverter-based Resources

NERC’s updated rules focus on addressing the operational and cybersecurity challenges posed by IBRs. The new requirements emphasize:

Performance Validation: ensuring that IBRs can withstand and recover from disturbances without jeopardizing grid stability.

Data Sharing: mandating detailed operational data submissions for elective grid planning and operations.

Cybersecurity: strengthening the security framework to safeguard inverter-based systems against cyber threats.

These requirements reflect NERC’s commitment to integrating renewable energy resources while maintaining the reliability and resilience of the Bulk Electric System.

Steps for Utilities Preparing for NERC Registration

For utilities not currently registered with NERC, the prospect of registration and compliance can be daunting. However, following a structured approach can streamline this transition:

Assess Applicability: Not all utilities are subject to NERC’s rules. Entities must determine whether their operations meet NERC’s criteria for registration. This includes evaluating the size, capacity and operational impact of their resources on the BES. If you have a facility (or facilities) with a 20-MVA nameplate rating and connected at 60 kV or higher, the countdown is on for you to register.

Conduct a Gap Analysis: Perform a thorough gap analysis to identify areas where your operations diverge from NERC standards. This involves:

    • reviewing the new IBR requirements.
    • identifying which NERC standards apply to your organization.
    • assessing current operational, cybersecurity and data management practices.
    • identifying deficiencies and areas needing improvement.

Develop a Compliance Program: A robust compliance program is critical for meeting NERC standards. Key components include:

    • Policies and Procedures: develop clear and comprehensive documentation of processes.
    • Training: educate staff on NERC compliance obligations and the new IBR rules.
    • Monitoring: implement tools for continuous monitoring and reporting of compliance metrics.

Engage with Industry Experts: Collaborate with NERC-registered utilities or consulting firms specializing in regulatory compliance. Their expertise can provide valuable insights into best practices and help navigate complex requirements.

Prepare for Audits and Registration: Mock audits and readiness assessments are essential for ensuring compliance. These activities simulate NERC’s evaluation processes and allow utilities to address gaps before official audits.

Key Considerations for NERC Compliance

Documentation: maintain meticulous records of all compliance-related activities, including testing, training and incident responses.

Technology Investments: upgrade existing systems to meet performance and cybersecurity standards for IBRs.

Stakeholder Engagement: work closely with regulatory bodies, industry peers and technology providers to ensure alignment with NERC expectations.

Conclusion

The new NERC rules for IBRs signify a pivotal moment for utilities, especially those not yet registered with NERC. By proactively assessing their readiness, addressing operational gaps and implementing robust compliance programs, these entities can position themselves to meet NERC’s standards effectively.

Early preparation not only ensures compliance but also fosters a more resilient and secure grid as renewable energy continues to grow in prominence. As the energy industry evolves, adhering to NERC’s regulations is not merely a regulatory obligation — it is a critical step toward supporting a sustainable and reliable energy future.

Did I mention not adhering to NERC’s regulations can result in fines and penalties up to $1 million a day per violation?

Terry Brinker is a 30-year industry professional with experience leading, facilitating and implementing improvements in power plant operations, control room operations, compliance and regulatory matters.

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ACORE Presses Congress to Order Improvements in TVA Planning, Oversight

The American Council on Renewable Energy (ACORE) says Congress could take steps to establish more comprehensive transmission and generation planning within the Tennessee Valley Authority. 

ACORE published a new report ahead of a Jan. 30 webinar, suggesting Congress ensure the TVA board of directors has access to outside expertise; order TVA to engage in comprehensive transmission planning; bring the utility under FERC jurisdiction; require more transparency; and investigate how best it could plan resources, transmission and interconnection. 

ACORE said projections of increasing load in the Tennessee Valley and TVA relying on imports to manage peak load mean it is time for Congress to consider modernizing the utility’s management. 

Jonathan Geldof, lead author of the report and senior manager of government affairs for ACORE’s Macro Grid Initiative, said that with TVA’s draft integrated resource plan laying out 30 possible portfolios, its board members — who are not required to have experience in the electric industry — seem ill equipped to determine the most realistic path. Geldof said Congress should ensure the board can access independent staff, like at a state public service commission, or use an Independent Market Monitor, akin to those in RTOs, to get advice. 

The webinar occurred a day before TVA CEO Jeff Lyash announced his retirement after about six years with the federal utility. (See related story, TVA CEO Jeff Lyash Announces Plans to Retire.) 

TVA is conducting integrated resource planning through 2035. The draft IRP estimates it will need 9 to 26 GW in new firm capacity, resulting in a 75 to 90% reduction in carbon emissions from a 2005 peak. 

In its report, ACORE said the draft IRP is so broad it could “serve to justify whatever action TVA chooses to take.” It also said the utility’s board is “woefully ill equipped to provide the kind of feedback [that] would serve as a check on TVA.

“ACORE noted that with TVA set to reach its borrowing limit in the coming years, it’s an opportune time for Congress to condition funding increases on administrative improvements. 

Geldof said the valley is poised for data centers, including an expansion of Colossus, a supercomputer built by Elon Musk’s artificial intelligence startup, xAI. On the other hand, he said, TVA faces 7 GW of retirements over the next few years. 

“What all those scenarios have in common is that TVA is going to need a lot more generation in the coming years,” Geldof said. 

TVA recently set an all-time peak demand record of 35.3 GW on Jan. 22 during a cold snap in which systemwide temperatures averaged 11 degrees Fahrenheit. However, ACORE said TVA was able to meet demand only through 20% imported power. 

Integrated Transmission Planning

Additionally, TVA is undergoing an integrated transmission plan for the first time in its history. But Geldof said any ensuing transmission portfolio will not be as valuable as it could be unless it is planned in concert with the IRP. TVA is tackling the two under independent processes. 

“When you consider generation and transmission separately, that’s not really an integrated plan,” he said. 

Geldof said that like much of the Southeast, TVA also needs interregional transmission. He pointed out that while TVA was initiating rolling blackouts during the December 2022 winter storm, neighbor SPP was curtailing excess wind generation in its footprint. 

Congress also should order a relaxation of TVA’s “fence,” Geldof said, which suppresses competition. He was referring to a 1959 addition to the TVA Act that prohibits the utility from selling its electricity into wholesale markets outside of its territory and prohibits its local power companies from buying power from its neighbors. 

“They could open a ‘gate,’ to expand the metaphor … or they could take down the fence altogether,” Geldof said of Congress, though he added that large utilities in the valley likely would resist removal of the wheeling restriction. 

Southern Renewable Energy Association (SREA) Executive Director Simon Mahan said the group applied to be a stakeholder in TVA’s integrated transmission process but was denied and shut out of meetings. 

From what he can tell, Mahan said, TVA’s transmission planning is “radically different” than that of nearby MISO, where planners hold consistent public meetings, are available for discussion and do not gatekeep planning information. He said SREA is concerned TVA just now is “stepping into” long-term, scenario-based transmission planning but seemingly refuses help from those that have contributed to comprehensive planning in RTO footprints. 

“It’s a missed opportunity from public power to take feedback from some of the areas that have best practices and really kind of shut down those discussions before they get started,” Mahan said. 

Mahan also said the TVA board receives limited information and currently does not get the “gut check” that analysis from independent third parties provides. 

“It’s not that we’re criticizing the board for making bad decisions. It’s just that they are not given enough information to know, ‘Is this truly the best decision at the right time?’” he said.   

Maggie Shober, research director at the Southern Alliance for Clean Energy, said TVA should settle on the most probable path forward in an IRP instead of simply using its lowest-end and highest-end estimates, which have it installing anywhere between a few hundred megawatts and several gigawatts of solar capacity. 

“TVA’s past IRPs have been overly broad.” The public should reach out to the TVA and its board to urge more specific resource planning, she said. Many in TVA’s leadership come from C-suites in investor-owned utilities that are accustomed to meeting load growth with natural gas plants. Shober said it’s incumbent on her organization and others to “break them out of that.” 

Myra Sinnott, of solar developer Silicon Ranch, said more transparent oversight would make building generation in TVA easier. 

Sinnott said trying to develop in TVA is a “chaotic” process, with requirements continually changing with no clear indication. 

“It’s like Whac-A-Mole sometimes. … You feel a little hamstrung working in a black hole,” Sinnott said. “It tends to be a more complicated process working in TVA than in other regions. … It would be easier if things were a little more consistent.” 

ACORE’s panel, “TVA’s Transmission Troubles,” underway on Jan. 30 | ACORE

Finally, panelists agreed the Trump administration’s efforts to bolster fossil fuels would not grind the clean energy transition to a halt or render renewable generation an unsafe bet. 

Mahan said TVA’s resource needs are coming fast through a combination of load growth and aging generation. He said scuttling renewable energy plans in favor of fossil fuel generation does not make economic sense and would strain the supply chain for natural gas components. 

“If we’re going to be building big stuff again on the load side, we have to have as many tools in our toolbox as possible,” he said. 

“I feel like the cow is already out of the barn,” Sinnott said. “It’s going to take a lot more than four years to slow it way down.” 

Shober said she thinks TVA has an overreliance on gas already given its current generation portfolio. She argued TVA’s increasing reliance on gas will not help it become more reliable and could introduce volatility into rates through oscillating fuel prices. 

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WEIM Q4 Benefits Exceed $374M

CAISO’s Western Energy Imbalance Market (WEIM) provided participants $374.25 million in benefits during the fourth quarter of 2024, down about 4% from the same period a year earlier, according to an ISO report released Jan. 30.

Cumulative benefits since the 2014 launch of the WEIM grew by 31% in 2024, to $6.62 billion. Last year saw no new participants join the market, which includes balancing authority areas accounting for 80% of load in the Western Interconnection.

NV Energy earned the largest share of benefits at $73.08 million, followed by the Balancing Authority of Northern California ($57.99 million), PacifiCorp ($46.58 million) and Los Angeles Department of Water and Power ($34.21 million).

CAISO’s benefits fell by half to $12.65 million, and the ISO was by far the market’s largest exporter (1,060,806 MWh) and importer (877,127 MWh). PacifiCorp came in second in both categories, with its East and West BAAs exporting a combined 839,781 MWh and importing 540,163 MWh.

The ISO also was the location of the largest volume of wheel-throughs (814,970 MWh), followed by the Western Area Power Administration-Desert Southwest region (401,898 MWh) and Arizona Public Service (356,176 MWh). WEIM members gain no financial benefit from facilitating wheel-throughs, with only the sink and source benefiting.

Vancouver, British Columbia-based Powerex earned the smallest share of benefits, at $840,000, down 98% year-over year. The company’s imports fell by 73%, to 336,184 MWh, while its exports rose 25-fold to 16,902 MWh. Powerex will withdraw from the WEIM after confirming last month that it plans to join SPP’s Markets+, although no date for the changeover has been announced. (See Powerex Commits to Funding, Joining SPP’s Markets+.)

The report said WEIM operations prevented curtailment of 30,462 MWh of renewable generation during the fourth quarter, helping to avoid the emission of 13,038 metric tons of CO2. The ISO estimates the market has been responsible for reducing carbon emissions by 1,043,034 MT since tracking began in 2015.

In a press release accompanying the report, CAISO said the benefits “emphasize the value of the ISO’s Extended Day-Ahead Market (EDAM), which promises to further build upon the benefits of WEIM for participants in the day-ahead market, where the vast majority of energy trading occurs.”

The ISO expects to launch the EDAM in 2026 and noted that WEIM members PacifiCorp and Portland General Electric already have begun onboarding activities to participate in that market.

The WEIM currently has 22 participants, including the ISO, but it likely eventually will lose a portion of those to Markets+, which SPP plans to launch in 2027.

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Day-ahead Seams Issues Could Take Years to Resolve, BPA Staff Says

PORTLAND, Ore. — The Bonneville Power Administration would have to strike several types of agreements, many of which are complex and could take years to implement, to tackle seams that could arise if BPA joins a day-ahead market, agency staff said during a workshop Jan. 30. 

BPA has generation and load all over the Pacific Northwest that would be impacted by market seams irrespective of whether the agency chooses to join SPP’s Markets+ or CAISO’s Extended Day-Ahead Market (EDAM). With 38 balancing authorities and over 30 transmission service providers, the Western interconnection already is complex, Todd Kochheiser, senior electrical engineer at BPA, said during a presentation on the seams issue. 

“Anybody that’s operated in the Pacific Northwest, either commercially or [in a] more traditional sense, knows that a lot of the BAAs in the Northwest are non-contiguous,” Kochheiser said. “They’re sort of stitched together using a collection of native transmission and third-party transmission service providers. It’s a fairly messy landscape when you look at it from that perspective.” 

BPA’s own BAA is similarly non-contiguous and located in six states while adjacent to 18 BAAs, Kochheiser noted. 

The creation of day-ahead markets and associated real-time markets “will change existing market and [reliability coordinator] footprints in the [Pacific Northwest] and introduce new seams on top of those that already exist,” a BPA staff presentation stated.  

For BPA, this means ensuring seams agreements and their implementation “address concerns that are unique and specific to Bonneville,” Kochheiser said. 

But getting there is tricky. BPA must strike complex agreements with multiple parties that can take years to negotiate and implement. Agreements between RTOs can range from 200 to 400 pages, according to the presentation. 

However, staff pointed out that BPA has experience negotiating agreements that can guide the agency. For example, the agency already has a Coordinated Transmission Agreement (CTA) with CAISO, Kochheiser said. 

Still, it took a long time to get BPA and CAISO to agree on terms for the existing CTA contract, and it took even longer to implement it, according to Kochheiser.  

“It probably took twice or three times longer to implement than it did to negotiate and sign it,” he said, adding that “signing an agreement isn’t the touchdown. You’re at the 50-yard line.” 

Proponents of both Markets+ and EDAM each have argued that their respective preferred market choice provides a better solution for resolving seams.  

‘Difficult Headache’

A study published in February 2024 by the Western Power Trading Forum (WPTF) and Portland, Ore.-based Public Generating Pool found that a seam between EDAM and Markets+ likely would create challenges beyond those seen at the boundaries of the full RTOs in the Eastern U.S., given that each market still would contain operating seams within them.  

Fred Heutte, a senior policy analyst at the Northwest Energy Coalition (NWEC), has pointed to this study to argue that, given BPA’s size, the agency’s positions would be even more complicated if it joins Markets+ while many of its neighbors join EDAM because both markets effectively would be running on top of its balancing authority area.  

Heutte reiterated those concerns during the Jan. 30 workshop, saying splitting the West into two major markets would “be a permanent, expensive, difficult headache, just on the agreement side.”

Actual implementation would not be any easier, Heutte said. There’s a risk that seams agreements cannot identify unforeseen issues, “and we see distortion in the market system operation that costs a lot of money and a lot of time.” 

“There’s been a sort of free-floating thing ‘Oh, we can just deal with this with the seams agreement.’ It’s not going to be so easy, and it’s going to be expensive,” Heutte added. 

But proponents of Markets+ have a different view. For example, Jeff Spires, director of power at Powerex, argued in September that Markets+ provides a much more equitable solution to tackling market seams than EDAM. Spires warned about joining EDAM, saying participants would be subject to the whims of CAISO and its purported preference toward California. 

During the Jan. 30 workshop, Laura Trolese with The Energy Authority said she understands the concerns about BPA joining Markets+ as it “might seem like it’s creating many more seams than if BPA were to join EDAM.” However, she added it appears EDAM still has “a lot of seams that are pretty complex.” 

Libby Kirby, BPA’s market initiatives policy lead, said BPA is not solely responsible for creating seams. 

“The decision of all of us ultimately resulting in two markets creates an additional seam,” Kirby said. “It is not only BPA that has made a decision. I want to make sure that’s clear.” 

BPA has said it will issue a draft day-ahead market decision in March and a final decision in May.