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February 20, 2025

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The 2025 Sustainable Energy Factbook in 7 Charts

Page 50 of the 2025 Sustainable Energy Factbook absolutely nails the unevenness of electricity demand growth across the U.S. The two charts on the page show that demand growth in ERCOT is concentrated in the far west and northern parts of Texas, while in PJM, the spike is almost exclusively in Northern Virginia.

The jump in demand in Texas is due to “the electrification of the oil and gas sector in the far west predominantly; also, bitcoin mining has contributed,” said Tom Rowlands-Rees, head of research for North America at BloombergNEF, which compiles the annual report. “In PJM, it’s data centers.”

“A lot of people’s expectations of power are that it is growing … [but] this load growth is concentrated in certain regions typically,” Rowlands-Rees said, during an advance media briefing on the report, released Feb. 20 by the Business Council for Sustainable Energy. “That nuance is important. It’s not everywhere.”

The 13th edition of the BCSE Factbook comes, as always, packed with charts, figures and industry insights, many of which stand in sharp contrast to President Donald Trump’s focus on fossil fuels and U.S. energy dominance. Rowlands-Rees called it “a snapshot of where things were at the end of the previous administration; so, that as we talk about what’s going to be happening in the future with a new administration, we actually have a benchmark against which to compare, a true picture of where things were and where they weren’t.”

With demand growth forming the backdrop for the U.S. clean energy industry at this point, BCSE President Lisa Jacobson stressed the need for a broad, all-of-the-above portfolio. “Energy efficiency, natural gas and renewable energy are the growth sectors of the U.S. economy, and as we move into a phase of anticipated increased energy demand, this portfolio is ready to meet this demand. We need more energy now.”

The key federal policies that are needed include maintaining energy tax credits and strong funding levels for technology research, development, demonstration and deployment, Jacobson said. Congress and the Trump administration also should “enact federal permitting and siting reforms, and … work with states and localities to provide the resources that they need at the community level to expand and modernize energy infrastructure,” she said.

As federal energy policies and agencies remain in flux — with Trump even challenging the independence of FERC and similar regulatory commissions — RTO Insider dug into other major trends reflected in charts across the Factbook.

US energy overview: Electricity generation mix | Bloomberg NEF

Electricity Generation Mix

The U.S. already appears to be enjoying some level of energy abundance, generating a record amount of electricity in 2024 ― 4,393 TWh — a 3.3% jump over 2023. At first glance, it looks like natural gas is the dominant source of power, accounting for 43% of generation. But with renewables growing to 24% and nuclear holding steady at 18%, carbon-free power is neck-and-neck at 42%.

BNEF also notes that as coal plants have closed, natural gas and renewables together are filling the gaps, generating “67.1% of the generation mix by the end of 2024, compared with 41.1% just a decade ago.”

Even the American Gas Association is calling for all-of-the-above energy policies.

“We need a robust energy portfolio, inclusive of not just natural gas, but of all the different technologies and supply sources and demand-side management approaches,” said Richard Meyer, AGA vice president for energy markets, analysis and standards. “We’re going to need that to ensure affordable and reliable energy for Americans.”

Policy: US progress toward emissions goals | Bloomberg NEF

US Progress Toward Emissions Goals

However, the growth in carbon-free power has not translated into major cuts in greenhouse gas emissions. Even before Trump ordered the U.S. withdrawal from the United Nations Paris Climate Accords, the U.S. had veered off course in its efforts to cut greenhouse gas emissions 50-52% by 2030, a goal set by former President Joe Biden.

The country’s modest drop in emissions overall has been driven primarily by the power industry’s switch from coal to natural gas, BNEF said. Emissions from all other sectors in the economy have fallen only 4% since 2007, and non-power emissions grew 0.24% in the past decade.

As Energy Secretary Chris Wright bluntly discounts Biden’s target for emissions cuts, it is unlikely the U.S. could meet the 2030 goals. According to BNEF, power sector emissions would have to fall 11% per year and economy-wide emissions would have to drop 6% per year.

US energy overview: Retail and wholesale power prices | Bloomberg NEF

Wholesale and Retail Power Prices

Power prices have been another component in Trump’s plans for U.S. energy dominance and abundance, with campaign promises to cut electricity bills in half.

The challenge here is that a sharp divide has opened between wholesale and retail electricity prices, according to BNEF. Spiking capacity auction prices in PJM notwithstanding, wholesale power prices rose only 0.1% in 2024. But “beneath this calm, regional shifts tell a more complex story,” the Factbook says. “California and Texas saw wholesale prices plummet by 45.9% and 51.4%, thanks to high renewable output, while New York and New England experienced increases of 11.1% and 6.1%, driven by reliance on natural gas and constrained supply.”

Similar regional differences were seen in retail electricity prices, which fell modestly by 0.68% on average in 2024. Retail prices dropped 2.5% and 2.4%, respectively, in Texas and New England, while California and New York saw increases of 7.6% and 4.8%, reflecting higher transmission and distribution costs.

Such regional variations could, at least in part, account for the difference between BNEF’s figures showing modest overall decreases in electricity prices and consumer perceptions of higher electricity bills. But BNEF found that energy accounted for only 3.82% of consumer spending in 2024, a 0.3% drop from 2023, and electricity accounted for only about a third of that total, while motor fuel made up 2%.

US energy overview: Jobs in select segments of the energy sector | Bloomberg NEF

Jobs in the Energy Sector

One of the strongest arguments for continued federal support for the energy industry has been its recent record of job growth, with the auto industry remaining the top job generator and energy efficiency a surprising second. But the growth in jobs for transmission, distribution and storage also has been significant, rising from 1.3 million in 2020 to 1.43 million in 2023.

When it comes to the jobs breakdown by fuel type, solar remains far ahead of the pack, with 364,544 jobs.

Finance: Energy transition investment | Bloomberg NEF

Energy Transition Investments

While Wright may not believe there is an energy transition, China committed $818 billion to its transition in 2024, a significant jump from the $684 billion it invested in 2023. By comparison, U.S. transition investments have stagnated, barely rising from $336 billion in 2023 to $338 billion in 2024.

Whether slapping tariffs on Chinese imports will improve U.S. competitiveness in global clean energy markets remains an open question.

Certainly, BNEF says the election and policy uncertainty put a dent in U.S. investments in certain sectors last year, with clean energy falling from $110 billion in 2023 to $97 billion in 2024.

But other investments signaled growth in key sectors like building electrification and grid expansion — both of which could cut consumer electric bills. Private dollars for electrified heat rose from $27 billion in 2023 to $32 billion in 2024 and investments in the power grid jumped from $85 billion in 2023 to $95 billion in 2024.

However, beyond investment, China also leads the world in installations of long-duration energy storage, a key technology for grid flexibility, with 2.5 GW in 2024 versus 625 MW in the U.S.

Economics: US levelized costs of electricity for unsubsidized new build, 2H 2023 | Bloomberg NEF

US LCOE for Unsubsidized New Energy Projects

In 2024, the levelized cost of electricity for natural gas edged below solar and wind, due largely to falling prices for natural gas. But the LCOE for new, unsubsidized generation and flexibility — what could be built to meet demand growth — presents a different picture, underlining the potential costs and benefits of a broad, diversified portfolio.

Unsubsidized solar is competitive with natural gas but will be cheaper if tax credits are maintained. Looking to new nuclear for clean, dispatchable power is going to be expensive, with a top LCOE of $523/MWh, and demand flexibility, storage and carbon capture will all come with higher costs.

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Trump Claims Authority over Independent Agencies in Executive Order

President Donald Trump on Feb. 18 issued an executive order that seeks to bring independent regulatory agencies like FERC under greater White House control. 

Trump said in “Ensuring Accountability for All Agencies” that “so-called” independent agencies’ minimal supervision from the elected president goes against the Constitution, and they “shall submit for review all proposed and final significant regulatory actions to the Office of Information and Regulatory Affairs (OIRA)” before they can be published in the Federal Register. 

It is unclear how much of an impact this, or any of Trump’s executive orders that stretch the interpretation of existing laws, are going to have on FERC. Established in 1980, OIRA reviews the regulations from cabinet agencies like EPA or the Department of Energy, but historically, it has exempted independent agencies’ decisions from substantive review, according to a report from the Congressional Research Service. 

Regardless of its actual effects, the executive order in and of itself is “an unprecedented effort” to curtail the independence of regulatory agencies, Ari Peskoe, director of Harvard Law School’s Electricity Law Initiative, said in an interview. 

“It depends on what the administration thinks it’s going to do here: whether it’s going to dictate policy, which is not quite possible for FERC since it still has a majority of Democratic commissioners; whether the administration is going to take it even further and continue firing commissioners and independent agencies, as it already did for the” National Labor Relations Board, Peskoe said. “So again, it’s just a lot of questions.” 

“My biggest fear is if the Supreme Court makes this broad determination about the separation of powers and Congress’ ability to set up independent agencies, because that would last forever, or at least until a future Supreme Court changed that, which usually takes decades to happen,” Grid Strategies President Rob Gramlich said. “So, unlike a lot of other changes right now that might last four years, that would do damage forever. And we really need independent regulatory agencies to have regulatory certainty and investor certainty about how to do business in electric power.” 

“Capital-intensive business models require a degree of certainty that independent agencies bring,” former FERC and Pennsylvania Public Utility Commissioner Nora Mead Brownell said. “When I became a PUC commissioner, I realized how critical it is for those kinds of agencies to truly be independent and base their decisions on the facts.” 

Moving away from that kind of independence, where decisions are based on a public record that lays out the facts and follows legal precedent, will at least make infrastructure investments more expensive, she said. “Why would you want to invest in something that is so subject to the whims of a leader who does not actually have a basic understanding of the economy?” 

Project 2025, which was authored by Trump appointees including Office of Management and Budget Director Russell Vought and Federal Communications Commission Chair Brendan Carr, has a section on independent agencies calling them “constitutionally problematic” using the same logic in the executive order. But it focuses more on the higher-profile agencies like the FCC and Securities and Exchange Commission. 

FERC is rolled into the same chapter as the Department of Energy, which was written by former Commissioner Bernard McNamee, nominated by Trump in his first term. It calls for FERC to refocus on reliability and affordability, with more specific suggestions including ensuring “sufficient dispatchable on-demand generation” and reforming RTO markets to pay such generators “reliability pricing.” (See Plan for GOP President: Cut Climate Programs, ‘Re-examine’ RTOs.) 

While Project 2025 and Trump’s executive order are based on the logic that independent agencies are not democratically accountable because of the president’s limited oversight, Peskoe pointed out that they combine functions from across all three branches. 

“They are somewhat legislative, somewhat executive and somewhat judicial, that they sort of combine all three aspects, and that’s what kind of makes these agencies unique in our government,” Peskoe said. 

Congress would be well within its powers to set rates for utilities in interstate commerce, but it just lacks the bandwidth to do that, so it created FERC to handle those issues, he continued. 

“These types of agencies have been around for a very long time,” Peskoe said. “They don’t really cite any particular problems with these agencies. It’s just this sort of constitutional accountability issue, which, again, hasn’t really come up in generations. So, it’s just a naked power grab by this administration.” 

The White House does get to influence FERC by picking commissioners and naming the chair. Brownell said President George W. Bush picked her and former Texas Public Utility Commission Chair Pat Wood, whom Bush appointed as chair of FERC, because both had pushed forward electric competition in their respective states, and the president wanted to expand its role at the wholesale level. 

Gramlich was a staffer for Wood, and he recalled visiting the White House — but not to take directions. 

“We’d be briefing them on what’s happening so they could understand the impacts and guide legislation, but they were never telling us what to do,” Gramlich said. 

Former FERC Chair Rich Glick, appointed by President Joe Biden, took some flack from The Wall Street Journal’s editorial page for meetings with the White House, but Gramlich said those were similar to what he and Wood did 20 years earlier. (See Glick Denies Taking Directions from Biden Admin.) 

“Even if a chairman wanted to take cues from the White House, that’s always been sort of up to them,” Gramlich said. “But this would be structural. I mean, you could have the White House essentially overturning and approving actions that don’t reflect the votes of the commission.” 

If the executive order is allowed to go into effect, and the courts wind up siding with the White House, some in the utility business might think of it as a win for a while, but politics change more quickly than the lifespan of much of the infrastructure FERC oversees, Brownell said. 

“You have four years of an administration with everybody and their brother tinkering in the business without understanding it, and you create an instability that is very dangerous, particularly at a time that we desperately need new infrastructure.” 

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FERC Approves PJM 2025 Transmission Project Cost Assignments

FERC on Feb. 18 approved PJM’s annual update to its tariff’s cost responsibility assignments for transmission projects set to be completed in 2025. The approval came despite protests regarding the use of the 1% de minimis threshold and the inclusion of a project that was the subject of a $6.6 million civil penalty imposed by the commission last year (ER25-775).

The update, filed Dec. 20, allocates costs for dozens of projects in the RTO’s Regional Transmission Expansion Plan, but the one that attracted the greatest attention was Public Service Electric and Gas’ 230-kV Roseland-Pleasant Valley (RPV) line. The commission approved a settlement between its Office of Enforcement and the utility on Dec. 5, 2024, subjecting the utility to a $6.6 million civil penalty to resolve allegations of it “failing to fully and accurately provide information” to PJM staff about the project (IN21-5). (See FERC Fines PSE&G $6.6M for Inaccurate Info on Transmission Line.)

In protest of the update, Public Citizen argued that RPV included imprudently incurred expenses and requested that component of the cost assignment filing be set for evidentiary hearing. The New Jersey Division of Rate Counsel said PSE&G should be required to demonstrate that its project and the scope of work were appropriate, which it argued could not be done through formula rate proceedings that lack the opportunity for a full prudence review. The agency also asked that FERC review PJM’s process for reviewing similar projects.

The utility answered that Public Citizen was improperly attempting to transform the cost allocation process into a prudence inquiry, which it said is outside the scope of the proceeding and should be done through a separate, standalone complaint. It also argued the organization had not identified any specific costs that were improper and had not met the standard for initiating such an inquiry. The commission agreed, finding both protests out of scope.

The Long Island Power Authority (LIPA) and Neptune Regional Transmission System argued PJM’s continued use of the 1% de minimis threshold and netting provisions of its solution-based distribution factor (DFAX) is in violation of the D.C. Circuit Court of Appeals’ ruling in Consolidated Edison Company of New York v. FERC, under which they said it is unlawful to base peak loads in the DFAX analysis on the threshold. They also protested that PJM had not provided evidence of how costs align with their derived benefits and had not detailed the drivers behind significant cost allocation changes. (See Paper Hearing Opened on PJM DFAX Method.)

PJM responded that the issues raised by Neptune and LIPA are the subject of other pending FERC litigation, and in the meantime, it is obligated to apply the effective tariff language. The commission wrote that PJM had applied its tariff properly and adequately provided detail regarding DFAX and its cost allocation methodology, which it noted permits challenges to the inputs.

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BPA Close to Issuing New Long-term Power Contract

The Bonneville Power Administration on Feb. 18 kicked off the last public contract development workshop series under its “Provider of Choice” initiative, allowing stakeholders to provide input on the agency’s long-term power contracts that it will issue later in 2025. 

BPA will hold three workshops this week, with the last one scheduled for Feb. 20. The final workshops indicate BPA is wrapping up development of the draft long-term contract that will go into effect in 2028 and set the conditions under which the agency sells federal power to customers. Following a public comment period, the goal is to have final templates ready by June 18 and signed contracts by December 2025, according to BPA presentation material. 

Michelle Lichtenfels, program manager of the Provider of Choice initiative, noted that BPA has hosted dozens of workshops on the issue, saying “this feels like a big week.” 

Lichtenfels thanked the participants, adding, “This is really a momentous time for being our last contract workshop series, but also the last chance we get to engage before we get into that public comment period.” 

The Feb. 18 meeting focused on ironing out details on several topics related to the contracts, including day-ahead markets, planning reserve margins and charges related to the Western Resource Adequacy Program, among other issues. 

Bonneville delivers power to regional public power customers under contracts executed in 2008. The agreements provided approximately 76% of BPA’s power services’ revenue requirement in 2022, according to a Provider of Choice concept paper. 

The long-term contracts by statute cannot exceed a 20-year term, and BPA launched the provider of choice initiative to begin contract discussions with stakeholders before the current agreements expire in 2028, according to the paper.

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Struggling NJ Solar Sector Evaluates Net-metering Reform

A more than 40% decline in New Jersey solar installation capacity from 2023 to 2024 has added to the debate over how to retool the state’s net-metering system to help advance the solar sector.

The state reached a milestone of 5 GW of installed capacity late last year but installed only 241.4 MW of projects in 2024, according to figures released this month by the New Jersey Board of Public Utilities (BPU). That was a drop from 453.2 MW in 2023 and was the lowest level of new installations since 2015.

The decline became a focal point in a four-hour public hearing the BPU held Feb. 10 as part of its yearlong effort to determine whether the state’s net-metering system should be modified, left as is, or dramatically restructured.

The sector has enjoyed solid growth for 15 years, driven by an initial incentive program of solar renewable energy certificates — which some critics said was too generous — in addition to net-metering benefits. The state’s 206,000 net-metered projects account for more than 95% of solar projects in the state, which ranks it among the biggest in the nation. Questions as to whether the system is sustainable or equitable and fair to non-solar utility customers emerged repeatedly at the hearing.

State law allows energy suppliers to stop offering net metering when the total capacity generated by net-metering customers reaches 5.8% of the total annual kilowatt-hours sold in the state. New Jersey reached that threshold in May 2024, triggering the board’s initiative to solicit stakeholder input on what comes next. (See NJ Scrutinizes Solar Net Metering Strategy.)

Solar developers ― who made up about half of the more than 80 attendees at the online hearing ― say any change to the current net-metering system should consider the challenges already facing the sector.

“Right now, we are in a very fragile market,” said Fred DeSanti, executive director of the New Jersey Solar Energy Coalition. He cited as an example the state’s offshore wind sector, which has yet to build a turbine and largely has ground to a halt. “We’re seeing what’s going on with the offshore wind, and that makes this almost paramount to make sure that this [solar] renewable energy resource is something that still continues to be in play in New Jersey.”

The sector’s difficulties include the extensive backlog of interconnections at PJM and the difficulty of connecting solar projects to the grid controlled by some utilities because the infrastructure is aging or insufficient, DeSanti said. Also challenging are high interest rates, material shortages, a 10% tariff levied by President Trump on Chinese goods, which developers fear will raise solar panel prices, and the possible disappearance of the federal 30% income tax credit for solar projects, DeSanti said.

Residential installations were 33% lower in 2024 than 2023, DeSanti said. But most worrying was the “abysmal” performance in the commercial solar sector ― largely due to interconnection problems ― with installations of 71 MW, about 37% of the state’s approved capacity in 2024, he said.

DeSanti said that to thrive, the solar sector needs a bill enacted, S2816, that would require each utility in the state to submit an infrastructure improvement plan. If the federal tax credit “goes away,” he added, the solar program “probably will as well.”

Net-metering Adjustments

Net metering allows solar homeowners or business project operators to draw electricity from the grid when the weather or sundown curtails generation, and to send power to the grid when their solar systems generate more electricity than they need. The incoming and outgoing electricity volumes are balanced out, or “netted,” at the end of the month and the utility pays the solar project for the net volume of electricity they generate.

But because solar owners are paying only utility delivery charges on their net consumption and not the full amount of electricity they use from the grid, critics argue they typically don’t pay enough to cover their share of the fixed or overhead costs of the utility. That includes maintaining and improving the grid, funding electric vehicle charging programs, providing subsidies for low-income customers and energy efficiency programs. Critics say that by not paying the overhead, solar project owners leave those costs to be spread among the rest of the customers, pushing up their bills.

Adjustments to net meter billing that other states have used or studied include changing the time over which the net-metering balance is calculated, for example, to daily rather than monthly. Under another proposal, known as “buy all, sell all,” the customer buys all the electricity they use as though they don’t generate any, and sells all the energy they generate. Some states have considered a per-kilowatt fee to pay for overheads. Another factor to be addressed once a plan is adopted is whether it affects new customers or existing customers only.

Lyle Rawlings, a solar developer and president of Mid-Atlantic Solar and Storage Industries Association, said the future of net metering is central to the sector’s future.

The system “works especially well for residential system owners,” he said, urging the BPU to “keep net metering.” But the state can “benefit greatly from alternatives” tried by other states, he said.

His organization favors the Massachusetts SMART program, under which the state calculates the revenue needed to support a solar project and the size of incentive is calculated by subtracting the energy compensation generated by the project from the revenue figure, he said. The system can work for behind-the-meter projects, which are net-metered, or those in front of the meter that are tied directly to the grid.

In both, “the solar developer or investor or the homeowner knows what their total revenue is going to be, and that’s a really good kind of security to have,” he said.

Balance of Benefits

New Jersey faces an issue that California has wrestled with on a much larger scale. With 31% of its electricity generated by solar, California has sought to cut the credits paid to new net-metering users and focus more on promoting investment in solar systems paired with storage. That has angered owners of existing solar panels who fear they will see their credits cut. (See California PUC Adopts Contested Net Metering Plan.)

The Solar Energy Industries Association last year ranked New Jersey 10th among states by total solar installed. The state’s maturing solar market ― its nearly 211,000 solar projects together generate 7% of the electricity generated in state ― in part triggered this scrutiny of net metering.

“There’s a lot of benefits associated with this, and I think that’s what makes the net-metering debate so difficult,” said Abe Silverman, a former BPU executive who now is a researcher at the Ralph O’Connor Sustainable Energy Institute at Johns Hopkins University.

“We know very clearly about what the [net-metering] rate we are paying for that electricity production is, and it’s relatively high,” he said in an interview with Net Zero Insider. But it becomes a “lot harder to tally up all the benefits” that the system reaps from net-metered solar projects, which include enabling the utility to buy less power from the grid, reducing the investment necessary in the distribution grid and cutting pollution, he said.

“So, the question becomes, where’s that trade-off? Where’s the right place to draw the line between the benefits and the costs?” he said. “At what point do you start saying: ‘OK, this was an incentive that needed to be there in the sort of dawn of the rooftop solar age. Maybe now that incentive needs to start getting shrunk!’”

David E. Dismukes, a consultant for the New Jersey Division of Rate Counsel, said at the hearing that New Jersey ranks among the top five states for net-metering capacity. The 22,500 net-metering projects added in 2023 were the state’s highest annual figure ever, according to slides shown by Dismukes.

“But that continued growth that we’ve seen has put a lot of pressure” on New Jersey, as it has elsewhere, he said.

“A lot of other states are questioning some of the continued policies,” he said. That includes “whether they need to be updated and whether they need to be reformed in light of these large levels of participation that is increasing the cost associated with the buyback rates and some of the costs associated with maintaining the distribution system through a cost-service perspective,” he said.

Andy Wall, a board member of the Mid-Atlantic Solar and Storage Industries Association, said net metering should be continued in part because it is simple to understand.

“Net metering is the simplest model we know to get residential customers to take the decision to host solar,” he said, adding that the incentive helps drive up the volume of solar generated energy. “By keeping it simple, we will keep overall ratepayer costs at a minimum.”

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West Coast Truck Charging Network Advancing Despite Uncertainty

Despite federal funding uncertainties, West Coast state officials said they’re moving forward with plans for a tri-state truck charging network that was previously awarded $102 million from the Federal Highway Administration.

The West Coast Truck Charging and Fueling Corridor project will stretch across California, Oregon and Washington, with charging stations and hydrogen fueling sites for medium- and heavy-duty trucks, mainly along Interstate 5. The project is a joint effort of the California, Oregon and Washington departments of transportation and the California Energy Commission (CEC).

The CEC and California Department of Transportation (Caltrans) held a joint workshop Feb. 13 to gather feedback on a future solicitation for development of the charging and fueling stations.

“We do have an executed agreement with FHWA for this project,” Sarah Sweet from the CEC’s Fuels and Transportation Division said during the workshop. “So right now, we’re moving forward with what we have in our agreement and the federal guidance we have today.”

Still, Jimmy O’Dea, assistant deputy director for transportation electrification at Caltrans, acknowledged there’s been a lot of “news and commotion at the federal level” since the start of the Trump administration.

“All we can say at this point is that it’s a fluid situation that we are continuing to monitor very closely,” O’Dea said.

The project status also varies among the three states.

California and Oregon were able to get funding for the charging corridor project obligated before a federal funding freeze was ordered, but Washington did not, according to Tonia Buell with the Washington State Department of Transportation.

“Although the project was awarded and funding authorized, it wasn’t fully obligated and fully contracted,” Buell said during the workshop. “So we are kind of in a pause status until further guidance.”

Solicitation Planned

The project received a $102 million award from the FHWA in August from the Charging and Fueling Infrastructure (CFI) competitive grant program. (See West Coast Truck Charging Corridor Wins $102M in Federal Funds.)

Of the total funds, Washington and Oregon will each receive $21 million, which is expected to grow to $26 million with private sector money. The funds will go toward two charging sites for battery electric trucks and one hydrogen fueling station in each state.

California expects to have $67 million from the CFI award plus matching funds to cover 16 charging sites and one hydrogen fueling station. The stations will be located along I-5 and on certain other freight routes.

California has proposed inviting private entities, excluding investor-owned utilities, to apply for funding to develop the stations. The total award per applicant would be capped at $18 million, and applicants would be required to provide at least 50% in matching funds.

The CEC is accepting comments on the proposed solicitation through Feb. 27. The agency plans to release the solicitation in April, with applications due in August and funds awarded in early 2026.

What About NEVI?

The CFI program funding the West Coast charging corridor is separate from the National Electric Vehicle Infrastructure (NEVI) program, which aims to establish EV charging networks throughout the U.S. Both programs are funded through the Infrastructure Investment and Jobs Act.

The NEVI program requires states to submit EV charger deployment plans annually, which must receive approval from the federal transportation secretary before funding is obligated each year.

On Feb. 6, the FHWA issued a letter to state transportation department directors suspending approval of their NEVI deployment plans.

The agency said it’s updating its NEVI program guidance to align with U.S. Department of Transportation policy and priorities, including a recent order called “Ensuring Reliance Upon Sound Economic Analysis in Department of Transportation Policies, Programs and Activities.” The updated NEVI guidance is scheduled to be released this spring.

“Therefore, effective immediately, no new obligations may occur under the NEVI formula program until the updated final NEVI formula program guidance is issued and new state plans are submitted and approved,” the letter stated.

However, reimbursement of existing obligations will be allowed “in order to not disrupt current financial commitments,” FHWA said.

Regarding the CFI program, Sweet with the CEC said the agency has not received any updated guidance.

“Right now, we have an agreement and we’re moving forward, and we have not received any guidance or direction about pauses or freezes or anything like that for CFI,” she said.

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Utilities Say Procurement Challenges Growing Since Pandemic

MIAMI — For Dan Beans, CEO of Roseville Electric Utility in California, the disruptions brought by the COVID-19 pandemic taught some hard truths about the resiliency of the global supply chains on which companies like his rely for essential materials. 

“We have learned several lessons. One of them is: No one’s coming to save you,” Beans said during a panel on supply chain issues at NERC’s quarterly technical session during the Board of Trustees and Member Representatives Committee meetings in Miami. 

“And what I mean by that is mutual aid. We’ve always done a really good job with that, but when it comes down to what do I have to hold back from my customers during the supply chain crisis, and what can I give to [neighbors], it makes it hard. So mutual aid is definitely at risk with a supply chain situation as dire as this,” he said. 

Beans said the pandemic-induced supply issues caused Roseville Electric’s inventory practices and project timelines to go “out the window” and that even after switching from a one-year procurement cycle to three years, the utility still has not been able to rebuild its inventory of spare parts, with more than 200 transformers on order since 2022. The city’s growing population has added to the pressure by creating demand for housing. 

Roseville Electric has been able to address the transformer shortage by finding a supplier based in South Korea, which Beans said has provided good equipment. But he worried that trade tensions might create new problems for his utility and others. 

“I don’t know that the policymakers understand this,” Beans said. “Transformers aren’t toilet paper; this is not going to be at Costco next week. This is going to take a lot of time, [and there are] a lot of different knobs to turn. We need some immediate action, and some long-term action.” 

The electric sector is not the only industry experiencing supply chain issues in recent years, according to Betsy Soehren Jones, executive director of the Critical Infrastructure Security Consortium, which works on behalf of electric, gas, oil, transportation, water asset owners and business organizations to protect supply chains and suppliers from cybersecurity and other risks.  

Focusing on the challenge of software provenance and cyber vulnerabilities, she suggested utilities could learn from the experiences of peers in the automotive industry. 

“What they did was, they pulled all of their major suppliers into a room, and they sat down and said, ‘These are our expectations, these are the threats, these are the risks that we see as an industry,’” Soehren Jones said. “‘We need to figure out a better way, between all of us, to get the software bill of materials standardized. … We need to know what’s inside of things. We need to understand where are you sourcing your materials? … Because at the end of the day, we are the ones that are responsible for selling that product to the market.’” 

Soehren Jones said manufacturers and their suppliers set up a “standardized library of information” that allowed suppliers to continue innovating in their products while manufacturers could stay abreast of major updates, and suggested that a similar approach could keep utilities from stifling innovation among their vendors.  

She added that the U.S. Defense Department’s Defense Innovation Unit (DIU) could serve as a model for the electric industry. DIUs were created in 2015 to help technology startups enter the DOD market and adapt to the department’s procurement regulations. 

Jeremy Rand, vice president of procurement at Arevon Energy, joked that product sourcing has given him his “first five gray hairs” over the past three years. He admitted that utilities “don’t understand … where our products are sourced from” as well as they should.   

Rand said the silver lining of the pandemic and other trade disruptions was that it forced the industry to take a hard look at these issues and start to identify areas for improvement. However, he emphasized that utilities are still in the process of fully understanding the problems they face. 

“We definitely are learning much more in depth, and there is much better communication with those vendors than there ever has been to get down to those suppliers and understand how [they] are affected [by] tariffs [and other] disruptions … and how that synergy between all of them comes together so we can understand the risk profile of our projects,” Rand said. 

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EPA Gives W.Va. Primacy for Permitting CCS Injection Wells

With West Virginia lawmakers looking on, U.S. EPA Administrator Lee Zeldin on Feb. 18 signed an approval granting the state primary authority for permitting carbon dioxide injection wells in the state, which could be used in carbon capture and sequestration projects. 

Under the approval, West Virginia will have “primacy” for permitting the wells — called Class VI wells — that are supposed to permanently sequester carbon dioxide in deep underground caverns, while also ensuring no CO2 leakage or other negative impacts affecting drinking water. 

Zeldin hailed the approval as an example of “the spirit of cooperative federalism that is alive and well in the Trump administration. … We here at EPA respect the talent that’s out there [in] the states, the understanding of how to do it better and faster.” 

Interior Secretary Doug Burgum spoke of North Dakota’s experience when he was governor, after it because the first state to be granted primacy for Class VI permitting in 2018, during the first Trump administration. 

“We’ve permitted some of the largest CO2 storage areas in the country. We’ve done all that in time frames that have been as short as six months from the beginning of the permit application, and we’ve done that without any risk to the environment,” Burgum said. Permitting primacy also drew “a record amount of capital investment coming into our state,” used in part for the development of low-carbon fuels such as ethanol. 

West Virginia is the fourth state to be granted primacy, following North Dakota in 2018, Wyoming in 2020 and Louisiana in 2023. The approval will go into effect 30 days after it is published in the Federal Register, according to the EPA announcement.

Sen. Shelley Moore Capito (R-W.Va.), chair of the Senate Environment and Public Works Committee, cited the state’s long history of energy production and ongoing work on carbon sequestration at the National Energy Technology Laboratory in Morgantown, W.Va. 

“EPA [should] be the overarching responsible agent to give us guidelines and give us expertise and make sure we’re within the guidelines,” Moore Capito said. “But really, let us work together to make sure that we get not just the best results, the quickest results [but] probably the most economic results and probably the most long-lasting results.” 

Under the Safe Drinking Water Act, EPA has jurisdiction over six classes of injection wells, from Class I, used to “inject hazardous and non-hazardous wastes into deep, underground rock formations,” to Class VI, used for long-term storage or sequestration of CO2 in “subsurface rock formations.” 

Many states have primacy for Class II wells, which are used to sequester fluids used in oil and gas production. Only six states ― Arizona, Iowa, Minnesota, New York, Pennsylvania and Virginia ― and the District of Columbia still are under federal jurisdiction for all classes, according to an EPA map. 

Class VI permitting requires the injections wells to be designed “in a manner that will prevent any CO2 or formation fluids from leaking outside of the injection zone.” Well construction will depend on “site-specific conditions,” and materials used should be “corrosion resistant and compatible with the conditions and fluids to which they may be exposed.”   

Corrosion monitoring must continue for the life of the project.  

According to EPA’s Class VI permit tracker, the agency has 161 applications under review and targets completing individual reviews within 24 months of receiving an application. West Virginia appears to have two projects in the queue, one received in April 2024, and one received in September 2024. 

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2 Companies Withdraw Texas Energy Fund Projects from Consideration

Two energy companies, citing equipment procurement constraints, have withdrawn projects from the Texas Energy Fund’s (TEF) In-ERCOT Load Program. The withdrawals leave 16 projects that have advanced to a due diligence phase (56896).

ENGIE Flexible Generation NA filed Feb. 17 at the PUC to withdraw its Perseus project, a 930-MW peaking facility, from consideration. The company said it has “become evident” supply chain issues would delay the project’s schedule, making it impossible to meet a December 2025 deadline for statutorily mandated initial loan disbursements.

ENGIE also withdrew its Spenser project from further consideration. The project, a 483-MW peaker, did not advance to the due diligence phase.

In January, Howard Energy Partners withdrew its co-generation facility at its Javelina processing plant in Corpus Christi, attributing it to similar “equipment procurement constraints.” The company said the delays would prevent it from meeting the same December timelines as ENGIE.

The Javelina facility, consisting of a 134-MW combined cycle facility and a 192-MW simple cycle unit, would make 271 MW available for dispatch.

PUC spokesperson Ellie Breed said the PUC anticipates proposing an additional project or projects for advancement to due diligence to replace the ENGIE project.

The withdrawals leave at least 16 projects in the TEF portfolio, accounting for about 8.5 GW of capacity. Loan information is confidential.

PUC Approves Non-ERCOT Program

The PUC established another TEF program when it approved a rule during its Feb. 13 open meeting that creates a program for grants to utilities and power generators outside the ERCOT region.

The rule sets up the Outside of ERCOT Grant Program as one of four programs under the TEF, which Texans approved by constitutional amendment in 2023. The grants can be used to finance modernization, weatherization, reliability and resiliency improvements, and vegetation management (57004).

“Every corner of our state faces unique weather threats and challenges,” PUC Chair Thomas Gleeson said in a statement. “The rule approved today will ensure that the TEF improves electric reliability for all Texans, whether inside or outside the ERCOT region.”

The ERCOT region covers about 75% of Texas, except for portions of East Texas, West Texas and El Paso.

ADER Project Moved to ERCOT

The commission endorsed staff’s recommendation to move the aggregated distributed energy resources (ADER) pilot project into ERCOT’s stakeholder process to determine the best way to move the initiative forward (53911).

The action will dissolve the ADER Task Force, which was created in July 2022. Its work has resulted in three virtual power plants, or ADERs, participating in the wholesale energy market and providing certain ancillary services. The ADERs can provide 25.5 MW of energy, 111 MW of non-spin reserve service, and 8.7 MW of ERCOT contingency reserve service.

“The pilot can only benefit from the larger stakeholder group at ERCOT, and that will facilitate its coordinated growth, along with other projects within the ERCOT market system,” PUC staffer Ramya Ramaswamy told the commission. She also recommended the grid operator file progress reports every six months.

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Constellation Reports Solid 2024 Financials, Expects Better in 2025

Constellation Energy turned in better-than-projected financials for 2024 as it continued to meet the demand for emissions-free energy with the nation’s largest nuclear fleet. 

The Baltimore-based energy company said it has the lowest CO2 emissions rate among the top 20 private investor-owned U.S. power producers and that it once again was the nation’s largest producer of emissions-free energy in 2024. 

The capacity factor of its nuclear plants inched up from 94.4% in 2023 to 94.6% in 2024, which it said is about four percentage points higher than the industry average. 

Constellation CEO Joe Dominguez has spoken about U.S. energy trends presenting opportunities for the company, and he repeated the message Feb. 18 as he announced the fourth-quarter and year-end financials: “There has never been a more exciting time for our country and for the energy industry. We are privileged to be at the heart of it all.” 

Demand for electricity is such that Constellation is working to restart a 51-year-old retired reactor at Three Mile Island in Pennsylvania, which it has renamed the Crane Clean Energy Center, to supply Microsoft for 20 years. 

Constellation is also in the process of acquiring Calpine Corp., the nation’s largest operator of geothermal and natural gas power generation, a deal it said would create a leading retail supplier of power to meet growing demand. (See Constellation to Acquire Calpine for $29.1B.) 

Constellation’s stock price has been on a mostly steady and often sharp rise since the company spun off from Exelon in early 2022. That likely is based in part on the widespread (but not universal) expectation that data centers for power-intensive artificial intelligence applications will create huge demands for additional electricity — Constellation stock jumped 25% in a single day when the Calpine deal was announced. 

The price per share hit an all-time high Jan. 24, then plummeted 21% the next trading day on news that DeepSeek had developed an artificial intelligence model that needs only a fraction of the electricity that other models consume. The stock price has recovered much of that loss, however. 

In its annual 10-K filing, also released Feb. 18, Constellation said energy-intensive data centers would be a potential driver of market demand for its reliable, carbon-free electricity, as would policy support for nuclear energy and consumer preference for clean energy. 

Constellation reported 2024 GAAP net income of $3.75 billion, or $11.89 per share. This compares with $1.62 billion and $5.01 per share for 2023. 

Adjusted (non-GAAP) income was $2.74 billion, or $8.67 per share in 2024. During the year, Constellation twice bumped its full-year guidance for adjusted earnings higher, but results still exceeded the final $8-$8.40 guidance the company set. 

“Backstopped by our strong balance sheet and industry-leading generation and commercial businesses, we’re affirming our 2025 adjusted operating earnings guidance range at $8.90-$9.60 per share,” CFO Dan Eggers said in the news release. 

Constellation closed 2024 with 31,676 MW of nameplate generation capacity — 22,068 MW of nuclear, 7,045 MW of natural gas and oil, and 2,563 MW of renewables. 

2024 sales totaled 269,417 GWh, approximately the same as 2023 sales. That broke down to 67.4% nuclear; 9.9% gas, oil and renewables; and 22.6% purchased power.