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March 12, 2025

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NJ Pushes Ahead with EVs as Washington Pulls Back

New Jersey is forging ahead with programs that promote electric vehicle adoption, announcing incentive opportunities totaling $185 million already this year, as officials await the impact of President Donald Trump’s frequently expressed opposition to EVs. 

The New Jersey Economic Development Authority on Feb. 24 approved a new phase of the New Jersey Zero Emission Incentive program (NJ ZIP), with $75 million available for incentive grants, and launched a new program, called New Jersey Zero Emission Vehicle Financing program (NJ ZEV), with $25 million allocated. The program will provide loans of $50,000 to $500,000 for commercial or industrial enterprises purchasing one or more EVs. 

Both are supported by funding from the Regional Greenhouse Gas Initiative, as is the allocation announced in January by the New Jersey Department of Environmental Protection of $35 million to fund local government projects that replace medium- and heavy-duty (MHD) diesel trucks with electric models. 

In his budget released Feb. 25, Gov. Phil Murphy also allocated $50 million to the sixth year of the state’s Charge Up New Jersey program, funding it at the same level as last year. The program awards incentives of up to $4,000 for the purchase of lower-priced EVs. 

Even in a good environment, it is not clear whether the funding would be enough to ensure the uptake of EVs continues at pace in the state. And Trump’s frequent criticism of EVs on the campaign trail suggests that he could take significant measures to slow the adoption of EV purchases — most notably the elimination of the $7,500 tax credit for an EV purchase. 

Murphy cited the expenditure of $135 million on NJ ZIP, NJ ZEV and the MHD program in a speech announcing the budget Feb. 25, saying that “with each and every investment, like these, into New Jersey’s clean energy future, we are not only meeting our responsibility to combat climate change” but also creating jobs and boosting the economy. 

But stakeholders close to the EV sector are skeptical that the state’s efforts so far will be enough. 

Laura Perrotta, president of the New Jersey Coalition of Automotive Retailers (NJ CAR), said she believes the Murphy administration’s recent announcements are a “direct response to the uncertainty around EV policy on the federal level.” 

She noted that New Jersey EV sales are already affected by new laws and regulations enacted in 2024 that pushed up the cost of buying an EV. “Add in the uncertainty around the federal EV tax credit and tariffs on China, Canada and Mexico, which could add as much as $12,000 to an EV, and it seems both federal and state-level economic policies are making it harder for customers to purchase an EV,” she said. 

Added Purchase Expense

New Jersey’s commitment to EV adoption was highlighted March 10 by a NESCAUM announcement reporting that the state and nine others had fulfilled their 2018 pledge to put 3.3 million EVs on their roads by 2025. 

The report said that when the 10 governors made their commitment, there were only 16 EV models on the market, compared to 150 today. 

“State leadership in electric vehicles has produced incredible results in the past decade, exceeding many expectations,” Elaine O’Grady, clean transportation director for NESCAUM, said in a release. The far larger variety of EVs available is because of states’ commitment and “their market-enabling programs that helped to build the EV market that exists in the U.S. today.” 

With a goal of registering 330,000 EVs by 2025, New Jersey has more than 215,000 EVs on the road, according to recent state budget documents. The state gained momentum in 2023, adding about 62,500 vehicles for a 68% jump over the year before. 

Pam Frank, CEO of ChargEVC-NJ, which promotes the sustainable growth of the EV market, said figures released this month for 2024 are expected to show that the state added fewer EVs than in 2023. She expects the numbers to be impacted by three “unforced errors” the state imposed on the sector in 2024: the elimination of a rule that allowed EV buyers to avoid sales tax on the purchase; a four-year, $250/year fee to pay for road repairs and upgrades (a fundraising measure that for non-EVs is done by a gas tax); and the introduction in July of a new rule in the Charge Up program, which has historically been a key driver of EV adoption in the state. 

The program previously offered a maximum purchase incentive of $4,000, providing it was priced less than $45,000 — an effort to focus the incentive on lower-income buyers. In July, the state started offering the $4,000 incentive only to low- and –moderate-income buyers, and a $2,000 incentive to everyone else. (See NJ EV Incentives Target Low-income Buyers.)  

Frank said that although the recently announced dollar figures look large, most of the programs announced by New Jersey this year are a continuation of past programs, and they don’t make up for the obstacles enacted last year. 

“It’s sort of like, the left hand giveth and the right hand taketh away,” Frank said. That makes it especially hard for New Jersey’s EV sector to advance if Trump takes measures to remove federal incentives, she said.  

The state is at a delicate moment, an “inflection point,” with the era of “early adopters” coming to an end and the general market buyers getting more interested and poised to become the main purchase driving force, she said. And the state needs to give them all the encouragement it can, she said. 

Federal Support Uncertain

The state is also facing the potential loss of federal support for electric charger installations under the National Electric Vehicle Infrastructure (NEVI) program, which was enacted in November 2021, Frank said. 

The U.S. Department of Transportation on Feb. 6 sent a memo to state DOTs saying it was reviewing the program and “suspending the approval” of all planned charger installations.  

The state applied for funds late, Franks said. It was awarded $104 million to identify alternative fuel corridors, the major state and interstate highways where EV charging stations would be located every 50 miles. However, none of the charging installations have been built, she said. And the state did not move on the project’s main contract until December, when it awarded $20.96 million to Joseph M. Sanzari Inc. to build charging stations at 19 locations along state highways. 

Steve Schapiro, a spokesperson for the New Jersey Department of Transportation, said it is “reviewing whether there is any impact to the funding to” the department. 

At the DEP, spokesperson Larry Hajna said there is no impact from the memo on another project to install chargers on New Jersey highways and those of three other states, because it is not funded under the NEVI program. That project, the Clean Corridor Coalition, involves installing 450 charging ports at 24 sites along the I-95 corridor in New Jersey, Connecticut, Delaware and Maryland. (See NJ to Install 167 Heavy Truck Chargers with $250M Federal Grant.) 

Echoing Frank’s concern about changes to state incentive programs, NJ CAR’s Perrotta said Gov. Murphy should abandon the Advanced Clean Cars II rules, which require an increasing number of new car purchases to be EVs and all new light-duty vehicles sold in the state to be zero emission by 2035. (See New Jersey to Adopt Advanced Clean Cars II Rule.) 

She said the state would struggle to meet its requirements, such as one that 43% of new cars be EVs in 2026, given that only 11 to 12% of sales were EVs in 2024. 

Spurring EV Purchases

State officials believe incentive programs can help get there. The Charge Up program had by the end of January approved 49,700 incentives in New Jersey — supporting slightly less than one in four EVs registered in the state — at a total cost of $147.8 million. The program awarded 11,300 incentives in 2024, according to the Board of Public Utilities. 

NJ ZIP, which was launched in 2021, provides vouchers to support the purchase of trucks, starting at $15,000 for Class 2b vehicles and rising to $175,000 for Class 8 vehicles. It offers bonuses for low- and moderate-income buyers, applicants scrapping old diesel vehicles and school districts purchasing zero-emission buses. 

The program has committed $54.4 million in awards to 155 applications and has already supported the purchase of 134 vehicles in the state, and an additional 288 vehicle purchases are in process, according to the Economic Development Authority (EDA). 

The new NJ ZEV program is designed to complement NJ ZIP and other state incentive programs by “offering financing for vehicle costs that may not be met by NJ ZIP vouchers or other grant funding available via other sources,” EDA CEO Tim Sullivan told the agency’s board in a Feb. 24 memo. 

The program will make loans of between $50,000 and $500,000 toward the purchase of a medium- and heavy-duty vehicle that help cover the funding gap for an EV. The funds can be spent on the purchase, taxes, registration fees, operating expenses and charging or fueling equipment for EVs or hydrogen fuel cell EVs. 

Announcing the new funding for the two programs, Murphy said they would “drive us forward in our mission of decarbonizing transportation, reducing consumer costs and responding to market preferences.” 

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SERC Projects Shrinking Margins in Next Decade

Soaring electricity demand across the SERC Reliability footprint is squeezing the region’s reserve margins, with more than half of SERC’s subregions expected to fall below NERC’s 15% reference margin in the coming decade, the regional entity said in its Long-Term Reliability Assessment released March 11.

SERC publishes its LTRA each year as a companion to NERC’s LTRA — which is published the preceding December —  and as a tool for industry, regulators and policymakers “to support the decision-making necessary to ensure the reliability of the [grid] during the planning horizon.”

The RE gathered, independently validated and verified data from all SERC entities to develop the report, while also conducting a stakeholder review process in collaboration with industry experts.

This year’s report covers the years 2024-2034, based on data on generation and transmission resources, planned outages and demand projections on an hourly basis. SERC staff considered historical weather events, system outages, load levels in peak and off-peak scenarios, and generating resource levels.

Current peak demand in the region is 260 GW in summer and 251 GW in winter, according to the assessment. These figures are projected to grow by 48 GW and 41 GW over the next 10 years, respectively, representing an overall compound annual growth rate of 1.7% in the summer months and 1.5% in the winter months. This calculation is based on a 50/50 projection, meaning that there is a 50% chance the actual load will be lower or higher than the forecast.

The subregion with the highest predicted CAGR is SERC-PJM, with 5.19% and 4.63%. The subregion contains parts of Virginia, North Carolina and Kentucky.

SERC-MISO Central, which includes all or parts of Illinois, Iowa, Kentucky and Missouri, has the lowest predicted CAGR with 0.20% and 0.13%.

To meet this demand, total generating capacity for the summer months is expected to grow from 315.3 GW in 2024 to 332.1 GW in 2034. However, winter generating capacity is projected to fall over the same period from 318 GW to 312.9 GW.

The decline in winter capacity is largely due to the expected retirement of nearly 18 GW of coal generation, causing coal to fall from 20% of on-peak winter capacity to 14%. Most other generation types are projected to shrink slightly or grow; natural gas should grow from 157.3 GW in 2024 to 165.4 GW summer capacity in 2034, and solar generation is expected to nearly double, from 22.8 GW to 41.7 GW in summer across the SERC footprint.

However, SERC noted that the expansion of solar does not provide equal benefits from season to season. While solar as a share of summer generation is expected to rise from 7% to 13%, its share of winter capacity is projected to grow from 3% to just 5%. The report acknowledged that solar’s variability and “lack of essential reliability services makes it less than a one-for-one replacement for the retiring coal capacity.”

Sounding the Alarm

With demand rising faster than generating capacity, many of SERC’s subregions are expected to fall below NERC’s reference margin in the coming decade, the RE said. This represents a significant shift from last year’s LTRA, when only SERC MISO-Central was expected to show such a decline. (See SERC Highlights DERs, Extreme Weather Challenges in LTRA.)

In this year’s report, SERC MISO-South, SERC-PJM and SERC-East all show sub-15% anticipated reference margins in either summer or winter, or both, for at least part of the decade. SERC-PJM has the highest projected deficiency at -22% for winter and -12% for summer.

MISO-South is also expected to hit negative margins in both summer and winter in 2033 and 2034, while MISO-Central will have negative summer margins in 2024 and 2025 before rising above 0% in 2026. SERC noted that the MISO and PJM subregions can both draw on resources from the greater MISO and PJM footprints.

The RE called the falling margins a “marked deterioration and a trend that bears watching,” and urged grid planners to carefully coordinate the retirement of existing resources with the introduction of new ones. SERC also said regulators and policymakers “should pay close attention to whether proposed retirements shown in integrated resource plans will be replaced in time to meet projected load without falling below reference margins.”

“A key purpose of forward-looking reports like this is to sound the alarm early enough so that something can be done while there is still time to take meaningful action,” SERC said. “SERC looks forward to working with federal and state policy makers and regulators, SERC registered entities and … technical committees and working groups to continue to identify, understand and address reliability and security concerns across the SERC region.”

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Ford Suspends Ontario Electricity Tariff as Trump Huffs and Puffs

Ontario Premier Doug Ford on March 11 said he would suspend the 25% tariff on electricity exports to the U.S., issued the day before, after speaking with Commerce Secretary Howard Lutnick and receiving threats of additional tariffs by President Donald Trump. (See Ontario Premier Ford Slaps 25% Tariffs on Power Exports to US.) 

In a post on X, Ford and Lutnick said they would meet in D.C. on March 13 “to discuss a renewed” United States-Mexico-Canada Agreement. The two said they “had a productive conversation about the economic relationship between the United States and Canada.” 

The statement came several hours after Trump posted a rambling message on his own social media site, Truth Social, saying he had instructed Lutnick to impose an additional 25% tariff on steel and aluminum imports from Canada in retaliation to Ford’s action, on top of a blanket 25% tariff on all such imports set to go into effect at midnight March 12. 

Trump made a series of other threats, such as “declaring a National Emergency on electricity within the threatened area” and increasing a tariff on imported vehicles April 2. 

“The only thing that makes sense is for Canada to become our cherished 51 state,” the president wrote. “The artificial line of separation drawn many years ago will finally disappear, and we will have the safest and most beautiful nation anywhere in the world — and your brilliant anthem, ‘O Canada,’ will continue to play, but now representing a GREAT and POWERFUL STATE within the greatest nation that the world has ever seen!” 

Later, Trump posted another, shorter message, asking, “Why would our country allow another country to supply us with electricity, even for a small area? Who made these decisions, and why? And can you imagine Canada stooping so low as to use ELECTRICITY, that so affects the life of innocent people, as a bargaining chip and threat? They will pay a financial price for this so big that it will be read about in history books for many years to come!” 

Asked on MSNBC about his reaction to Trump’s threats, Ford said, “We will not back down; we will be relentless. I apologize to the American people that President Trump decided to have an unprovoked attack on our country … but we need the American people to speak up. We need those CEOs to get actually get a backbone and stand in front of him and tell him this is going to be a disaster. It’s mass chaos right now.” 

Later that day, Trump backed off his threat to up the steel and aluminum tariff for Canada, according to White House Deputy Press Secretary Kush Desai. “President Trump has once again used the leverage of the American economy, which is the best and biggest in the world, to deliver a win for the American people,” he said, adding that the blanket tariff was still scheduled to go into effect. 

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ACEEE Recommends Winter Discounts to Spur Heat Pump Adoption

Setting a lower price for power in the winter is key to ensuring that consumers’ overall energy bills do not go up when they switch to heat pumps, according to a report released March 11 by the American Council for an Energy-Efficient Economy.

“We know that heat pumps cut climate pollution and can reduce home energy costs, even in the coldest states,” ACEEE Buildings Program Director and co-author Matt Malinowski said in a statement. “Utilities, regulators and policymakers need to further reduce costs by encouraging heat pump-friendly electric rates and energy-efficiency upgrades, especially for low- and moderate-income households.”

The discounted winter rate is vital in states with high electric rates and in cold regions where the economics of heat pumps can be the most challenging. Generally, maintaining the grid is more costly in the summer than in the winter, so ACEEE said flat seasonal rates effectively overcharge in the cold months.

Other changes that can help boost heat pump adoption are efficiency upgrades like insulation, so homes need less heat, and adopting time-of-use rates, the study said.

The report modeled bills using actual utility rates under different home heating electrification scenarios, specifically picking from among the most expensive for electrification. The models in the report were based on single homes in Colorado, Connecticut, Maine and Minnesota.

“In any cold-climate U.S. state, the ongoing bills are lowest with cold-climate heat pumps when heat pump adoption is accompanied by energy efficiency home envelope improvements and a favorable electricity rate plan,” the report said. “Heat pump-specific rate plans are best for incentivizing heat pump adoption, with winter discounts being a potentially important facet of those plans. These rates are generally based on the cost of service for heat pump customers, without subsidizing other customer classes.”

In Maine, all of the options studied led to no increases in bills when the modeling added a heat pump because the increased efficiency was enough to offset higher electric rates. Electrification increases costs in some months of the year but leads to lower overall bills.

Minnesota has an even bigger gap between electricity and gas costs, but one utility offers a 35% discount winter rate for customers using electricity for heat so adopting heat pumps leads to lower costs year-round for its customers.

The Colorado utility the study looked into offers a 10% winter heating discount — not enough to make heat pumps cheaper on their own, though time-of-use rates that the utility offers would also help cut costs.

In Connecticut, the study found that fuel oil and propane customers (representing 45% of residential customers in the simulation set) can save money through electrification, but the price ratio between gas and electricity was so high that even a discount like Minnesota’s and efficiency upgrades still would not fully make up the difference in costs.

“Here, as in other states where electricity is much more expensive than gas, the state should consider deep public investment (not ratepayer-funded) in making electric power more affordable to its residents,” the paper said. “This could include taking on some costs of grid maintenance and upgrades, putting a price on carbon or implementing clean heat standards that place performance requirements on all heating market actors. Fortunately, this type of electricity-gas price ratio is rare, and gas prices are expected to naturally increase in the coming years relative to electricity.”

Rates are not the only thing presenting roadblocks to heat pump adoption, with the report saying the biggest barrier is still lack of awareness, which means that ongoing marketing/educational campaigns are needed.

Another challenge is that some HVAC contractors have misperceptions about the technology’s efficiency and costs. The report recommends better training around heat pumps in the HVAC industry, providing incentives to contractors and encouraging them to focus on maximizing homeowner satisfaction over getting jobs done quickly.

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OSW Critics Petition US Supreme Court for Vineyard Wind 1 Review

Commercial fishing advocates who have been fighting Vineyard Wind 1 for years are asking the nation’s highest court to do what lower courts have not: Rule that federal regulators improperly authorized construction of the 800-MW wind farm off the Massachusetts coast. 

The Responsible Offshore Development Alliance’s petition was docketed by the U.S. Supreme Court on March 10. Statistically, it is a long shot — the justices hear fewer than 100 of the thousands of appeals submitted each year. 

But if the petition is successful, defense of the regulatory decisions (which were made under President Biden, a strong offshore wind supporter) would fall to the Trump administration, which has taken firm steps to limit or block offshore wind development. 

The Texas Public Policy Foundation filed a similar petition to the Supreme Court on March 11 in a similar case that had been consolidated in U.S. District Court with RODA’s challenge. 

The shift from strong support to strong opposition between the two administrations has created a new element of risk and uncertainty for an industry that already was struggling to maintain momentum in the United States.  

Interior Secretary Doug Burgum offered some clarity March 6, when he told Bloomberg that while all offshore wind projects would be reviewed, in accordance with the executive order, advanced projects would be reviewed differently than early stage projects. 

Burgum also echoed Trump’s criticisms that offshore wind is too expensive and cannot serve as a baseload. 

In the challenge it began in January 2022, RODA asserts that the U.S. Interior Department under Biden reinterpreted Section 1337 of the Outer Continental Shelf Lands Act to “consider” the impacts of offshore wind projects rather than “ensure” they do not interfere with reasonable uses such as use of the sea or seabed for a fishery. 

Vineyard Wind 1 in 2021 became the first offshore wind proposal green-lighted in federal waters, and RODA said it set the precedent for the 10 other records of decision that followed, all of which were favorable. 

A district court rejected that line of attack (1:22-cv-11172). In December 2024, the U.S. Court of Appeals for the First Circuit denied RODA’s request to appeal the District Court’s ruling. 

“Petitioning the SCOTUS is the only option left to ensure American seafood harvesters, and the US wild-caught sustainable seafood industry, are not put out of business at the hands of those who want to turn our oceans into a massive web of industrial power plants,” RODA said March 10 in announcing its petition to the Supreme Court. 

The petition seems to acknowledge that the opportunity to block Vineyard Wind 1 has passed, as roughly three-quarters of its planned turbines are at least partly built. But it seeks to inform future projects: 

“Petitioner asks this court to grant review of this issue of vital importance to the fishing industry and to provide guidance to the secretary [of the Interior] regarding the correct statutory interpretation of ‘shall ensure’ in Section 1337(p)(4) so that future ocean energy projects are reviewed according to the criteria provided by Congress.” 

Texas Public Policy Foundation senior attorney Ted Hadzi-Antich said in a March 11 news release: “This is a stark example of federal administrative agencies shirking their responsibilities to follow the law. When that happens, we are here to hold their feet to the fire.” 

Even without a Supreme Court ruling, the U.S. offshore wind sector is struggling, both from the effects of Trump’s directives and from an array of financial and supply chain problems that set in long before the 2024 presidential election. 

Some recent examples: 

    • Major offshore wind developer RWE, which in November announced a two-year pause in its U.S. efforts, filed notice March 7 that it would lay off 73 employees in Massachusetts. 
    • RWE’s vice president of East Coast offshore development, Amanda Lefton, departed the company to become the acting commissioner of New York’s Department of Environmental Conservation. 
    • SouthCoast Wind’s developers are preparing for a potential delay of up to four years on the project off the Massachusetts coast. 
    • New Jersey canceled its next offshore wind solicitation in February after two bidders pulled out and a third lost one of its project partners. 
    • New Jersey stepped up its review of potential alternative uses for the wind port it has invested more than a half-billion dollars to build but has yet to use for offshore wind construction. 
    • Developers booked new impairments on projects planned along the East Coast. 

There are bright spots: 

    • New York state told NetZero Insider recently that work continues on its most recent offshore wind solicitation, which targeted the first quarter of 2025 for finalization of contracts. 
    • Massachusetts did not provide NetZero Insider with an update on its most recent solicitation, but power purchase agreements are due to be finalized by March 31.  
    • Coastal Virginia Offshore Wind is under construction, albeit at a higher cost. 
    • Revolution Wind is under construction off the Massachusetts coast, albeit at a higher cost and with a delayed commercial operation date. 
    • Onshore construction is underway for Empire Offshore Wind in New York, where developer Equinor is building an offshore wind port for over $850 million. On March 11, Empire submitted its request to the state Public Service Commission to proceed with the next phase of its onshore substation construction. 
    • And, of course, construction of Vineyard Wind 1 is far along, though well behind its original schedule after some problems with components. 
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CARB Work Seeks to Surmount Challenges to Calif. Hydrogen Goals

Consultants are evaluating four primary pathways for hydrogen production in California, and they say it’s too soon to eliminate any of them from a long-term strategy for the state’s green hydrogen industry. 

Energy and Environmental Economics (E3) is studying the hydrogen production pathways as part of a California Air Resources Board report. The consultants presented initial findings from their analysis during a Feb. 25 CARB workshop. 

E3’s analysis focuses on four hydrogen production methods: electrolysis of water using zero-carbon power, steam reformation of methane, methane pyrolysis and biomass gasification. The pathways were chosen based on their relatively high level of technology readiness, according to Vignesh Venugopal, senior managing consultant at E3. 

The steam reformation and pyrolysis pathways use methane as a feedstock: either fossil-gas methane or biomethane, which may come from landfill gas, dairy production, organic waste or wastewater treatment. Carbon capture and storage is also evaluated for methods that produce carbon emissions. 

E3 found that electrolysis using solar power could theoretically meet California’s 2045 hydrogen demand, which is estimated at 1.6 million metric tons (MT) in CARB’s 2022 climate change scoping plan. 

But the resources required for doing so could be a constraint, Venugopal said. About 812 square kilometers of land would be needed for alkaline electrolysis, mainly for solar installations, E3 estimated. That’s more than six times the land area of San Francisco County, which measures 120 square kilometers.  

About 72 billion liters of water would be required to meet the 2045 hydrogen demand with alkaline electrolysis, as well as 85 TWh of electricity, which is 28% of California’s current total electricity demand of about 300 TWh. 

The land use impacts of electrolysis along with other factors “warrant consideration of other pathways,” according to E3. 

“An optimal [hydrogen production] strategy may involve multiple pathways to mitigate impacts and bring benefits to the state,” Venugopal said. 

E3’s final analysis will include more details on resource requirements for other hydrogen production pathways.  

Meeting Climate Goals

CARB is developing the hydrogen report in response to Senate Bill 1075 of 2022, which states that the legislature’s intent is to develop “a leading green hydrogen industry in California” to realize energy benefits and help meet the state’s climate goals. California has set a goal of net-zero greenhouse gas emissions by 2045. 

SB 1075 notes that technological advances may be needed — in addition to scaling up production — to produce hydrogen from renewable feedstock for $1 per kilogram. That’s a target set by the U.S. Department of Energy in its Hydrogen Energy Earthshot, an initiative launched during the Biden administration. 

The E3 analysis looked at the cost of producing hydrogen using different pathways and making various assumptions. 

With electrolysis, the hydrogen production cost in 2045 could be as low as $1 per kilogram, according to E3. That assumes less expensive electrolyzers from China are paired with low-cost solar energy. 

The cost of electrolytic hydrogen rises to over $4 per kg with the use of more expensive, American-made electrolyzers powered by a new nuclear reactor. 

For hydrogen produced using steam methane reformation, projected 2045 costs range from $2 to $10 per kg based on the price of natural gas or renewable natural gas (RNG) used. RNG can be costly, depending on its source. Venugopal noted. The high end of the cost range also assumes carbon capture is part of the process. 

The cost of natural gas or RNG is also a key factor for hydrogen produced through pyrolysis, which has a cost range of $2 to $14 per kg. In pyrolysis, methane is heated in the absence of oxygen to produce hydrogen and solid carbon. The lower production cost figures in the E3 study assume that the solid carbon byproduct can be sold. 

Gasification uses heat, steam and oxygen to convert biomass to hydrogen and other products without combustion. E3 estimated the cost to produce hydrogen by this method as ranging from $1.7 to $5 per kg, based on the cost of biomass used and whether carbon capture is deployed. Sources of biomass include forest residue, crop residue and urban wood waste. 

Venugopal noted that “a wide range of uncertainty exists” regarding the cost to produce hydrogen in the different pathways. 

“There is meaningful overlap between the cost from each pathway, which suggests it is too soon to pick one single pathway based on cost alone,” he said. 

Report Timeline

CARB is accepting comments on the hydrogen workshop through March 18. 

E3 will continue its analysis, addressing additional topics including the impacts on clean air objectives, barriers to hydrogen use and policy recommendations. The consultant expects to complete the analysis in the third quarter of 2025. 

CARB expects to release a draft version of its hydrogen report by the end of this year, accept public comments and then issue a final report in early 2026. 

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Federal Briefs

GAO Blocks Vote to Repeal California EV Rules

The Government Accountability Office last week said the Biden administration’s approval of California’s plan to end the sale of gasoline-only vehicles by 2035 is not subject to review and potential repeal by Congress. 

Last month, the EPA sent the approval to Congress saying it was considered a rule under the Congressional Review Act. The GAO said the decision should be considered an order and is not reviewable. 

California’s rules require 35% of vehicles in the 2026 model year to be a zero-emission model before rising to 68% by 2030. 

More: Reuters 

US to Withdraw from Coal Transition Partnership

The United States is withdrawing from the Just Energy Transition Partnership, a collaboration between richer nations to help developing countries transition from coal to cleaner energy, sources in participating countries said. 

The coalition, which consists of 10 donor nations, was first unveiled at the U.N. climate talks in Glasgow, Scotland in 2021. 

The U.S. state department did not respond to a request for comment. 

More: Reuters 

BLM Approves Newcastle Geothermal Development Project

The Bureau of Land Management last week approved the Newcastle Geothermal Development project in Utah. 

The plant is expected to generate up to 20 MW near Newcastle in Iron County. 

More: BLM 

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State Briefs

ALABAMA 

Alabama Power to Install BESS

Alabama Power has announced plans to develop the first utility-scale battery energy storage system (BESS) project in the state. 

The 150-MW Gorgas BESS will be installed at the site of the retired Plant Gorgas power station in Walker County and will cover 7 acres. 

Construction is set to begin this year, with commercial operations planned by 2027. 

More: Renewables Now 

CALIFORNIA 

LA County to Sue SCE over Eaton Fire

Los Angeles County last week said it will sue Southern California Edison, alleging the utility’s equipment sparked the Eaton Fire. 

The lawsuit seeks to recover costs and damages sustained from the fire. Costs and damage estimates were expected to total hundreds of millions of dollars, the county said, adding that assessments were ongoing. The blaze destroyed more than 9,400 structures and killed 17 people in the Altadena area. 

More: The Associated Press 

IOWA 

House Committee Advances Bill to Block CO2 Pipelines from Eminent Domain

The House Judiciary Committee last week advanced bills to block liquid pipelines carrying carbon dioxide from the use of eminent domain. 

One bill specifies that the “construction of hazardous liquid pipelines for the transportation or transmission of liquefied carbon dioxide” does not constitute a public use for the purpose of condemning agricultural land. The bill would apply to any condemnation proceedings made on or after its enactment. Another bill would restrict liquid pipelines from the right of eminent domain. 

A companion bill in the Senate has not had any scheduled hearings and will likely be dead. 

More: Iowa Capital Dispatch 

KENTUCKY 

Utilities Request Approval for Natural Gas, BESS

Louisville Gas & Electric and Kentucky Utilities have requested approval for a Certificate of Convenience and Necessity from the Public Service Commission for two natural gas plants and a battery energy storage system (BESS). 

The two 645-MW natural gas plants would supply additional generation at the E.W. Brown Generating Station. The companies expect to have the units available in 2030 and 2031. 

The companies also plan to install 400 MW of BESS at the Cane Run Generating Station and a selective catalytic reduction facility to reduce nitrogen oxide emissions for Ghent Unit 2. These are expected to be operational in 2028. 

More: Energy Storage News 

MINNESOTA 

Xcel Energy Proposes $318M in Refunds to Customers

Xcel Energy officials said they are proposing returning $318 million to customers. 

According to a news release, more than half of the refund ($176 million) comes from federal tax credits for nuclear energy generation, with the remainder would come from lower fuel costs and a 2011 outage at the Sherco coal plant. 

The refunds, which would total $81 for the average residential customer, must be approved by the Public Utilities Commission. 

More: KARE 

MONTANA 

Bill to Allow Community Solar Projects Clears Senate

The Senate has passed a proposal that would establish a legal framework for community solar power projects. 

If the proposal passes the Legislature, it will allow a solar developer to build a solar array between 50 kW and 5 MW and sell shares of the generation to subscribers. It would also require the Public Service Commission to come up with a framework for pricing the electricity generated. 

More: Montana Free Press 

PENNSYLVANIA 

Canada Bitcoin Miner Acquiring 2 Coal Plants

Canada-based crypto mining company Bitfarms last week announced it is acquiring two coal-fired power plants to power its bitcoin mining operations. 

Bitfarms is set to buy Stronghold Digital Mining in a deal expected to close this month. Stronghold owns the 85-MW Scrubgrass waste plant in Venango County and the 80-MW Panther Creek waste facility in Carbon County. 

Bitfarms already has a presence in the state, having purchased a data center in Mercer County last year. 

More: POWER Magazine 

RHODE ISLAND

Carrier to Credit Ratepayers in Fraud Case Settlement

The Public Utilities Commission last week approved a settlement that will have Rhode Island Energy credit ratepayers $7.9 million for an alleged fraud scheme by its predecessor, National Grid. 

In December 2021, the PUC discovered that National Grid knowingly misfiled invoices for its energy efficiency program over an eight-year period to make more money, overcharging customers as much as $2.2 million. National Grid acknowledged in a 2023 report that company employees “acted inappropriately” by deliberately delaying invoices. 

Under the settlement, Rhode Island Energy will credit customers using its storm contingency fund, reducing future storm-related costs. 

More: Rhode Island Current 

SOUTH DAKOTA

Gov. Rhoden Signs Eminent Domain Ban for Carbon Pipelines

Gov. Larry Rhoden last week signed a bill banning the use of eminent domain for carbon dioxide pipelines. 

The issue has been at the center of a contentious debate over Summit Carbon Solutions’ proposed $9 billion carbon capture pipeline. The project would transport carbon dioxide from ethanol plants in five states, including South Dakota, to an underground storage site in North Dakota. 

In a letter explaining his decision, Rhoden emphasized his commitment to property rights and framed the bill as a way to restore trust between landowners and developers. 

More: South Dakota Searchlight 

VIRGINIA 

Dominion Seeks SCC Approval for Chesterfield Gas-fired Units

Dominion Energy last week said it is seeking State Corporation Commission approval of its $1.47 billion project to install four natural gas-fired generating units at its Chesterfield Power Station. 

The four units would generate 944 MW and would run at times of peak demand. 

The project would add an average of $1.36 to the residential monthly bill and would vary year-to-year. 

More: Richmond Times-Dispatch 

WEST VIRGINIA

FirstEnergy Planning to Replace Coal Plants with Natural Gas

FirstEnergy announced during its fourth quarter earnings call that there are plans to shut down two Mon Power coal plants in favor of natural gas. 

The Harrison plant in Harrison County and the Fort Martin plant in Monongalia County are scheduled to shut down within the next 15 years, while the replacement natural gas facilities are expected to begin construction within the next five years. 

More: WDTV 

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Company Briefs

Sunnova Names Mathews President, CEO

Sunnova Energy International last week announced that former COO Paul Mathews has been appointed president and CEO, effective immediately. 

Mathews joined Sunnova in January 2023. Prior to that, he spent nearly two decades serving in a variety of leadership roles at UPS. 

Mathews succeeds William Berger, who is stepping down as chairman, president and CEO. 

More: Sunnova 

Alliant Energy Appoints New Board Chair

Alliant Energy last week announced the appointment of Patrick Allen as the new independent board chair, effective following the company’s Annual Meeting of Shareowners in May. 

Allen has been a member of Alliant’s board since 2011. 

He will succeed John Larsen, who will retire. 

More: Investing.com 

RWE to Lay off Some of Boston Workforce

German energy company RWE Offshore Wind Services plans to lay off 73 employees from its Boston-based U.S. offshore wind arm, according to state filings. 

Company spokesperson Ryan Ferguson said the layoffs, which will come by May 6, will affect workers supporting the long-term development of offshore wind projects across the country. 

More: Boston Globe 

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PJM PC/TEAC Briefs: March 4, 2025

Planning Committee

PJM Presents Changes to DESTF Issue Charge

PJM’s Chen Lu on March 4 presented the Planning Committee with a draft amendment to the Deactivation Enhancement Senior Task Force’s (DESTF) issue charge to add a key work activity (KWA) focused on creating pro forma language for reliability-must-run agreements with generation owners seeking to deactivate a unit identified as being necessary for reliability.

The new language seeks a proposal that would be effective for the 2028/29 delivery year, which is the tail end for a temporary measure allowing some resources operating on RMR agreements to be counted as capacity if they meet certain requirements (ER25-682). Approved by FERC in February, the temporary change allows resources that PJM believes can act as capacity to be counted in the supply stack for the 2026/27 and subsequent Base Residual Auction. (See FERC OKs Changes to PJM Capacity Market to Cushion Consumer Impacts.)

While PJM will ask the Markets and Reliability Committee to vote on the changes during its March 19 meeting, Lu brought the language to the PC, Market Implementation Committee and Operating Committee during their March meetings to provide stakeholders with advance notice.

Paul Sotkiewicz, president of E-Cubed Policy Associates, asked Lu why PJM had reversed its earlier position that RMR agreements should be out-of-scope for the DESTF. He stated that RMR agreements are different from other areas the task force has focused on because they are specific to transmission security, not market design.

Lu responded that there are relevant issues around RMR agreements, such as the operational parameters needed to maintain reliability and on the markets side what is needed to count those resources as capacity. PJM believed a senior task force was the best forum rather than a standing committee.

Speaking during the MIC meeting March 5, Philip Sussler, of the Maryland Office of People’s Counsel, and Clara Summers, of the Illinois Citizens Utility Board, questioned whether the added work item would impact the ability for the task force to proceed with KWAs exploring alternatives to RMRs, an addition to the issue charge the two consumer advocates sought to have included in 2024. (See “Stakeholders Approve Generation Deactivation Issue Charge,” PJM MRC/MC Briefs: Sept. 20, 2023.)

Other work areas include education on alternatives to rebuilding transmission assets when generation deactivations would trigger reliability violations, such as reconductoring or the deployment of grid-enhancing technologies; developing alternatives to RMR agreements; and accounting for any changes stakeholders and the RTO may make to its capacity interconnection rights transfer process.

Transmission Expansion Advisory Committee

Market Efficiency

PJM’s Nicolae Dumitriu presented the Transmission Expansion Advisory Committee with an update on the RTO’s 2024/25 long-term market efficiency window.

The congestion drivers behind the analysis were identified through base cases pairing the 2024 load forecast with the expected grid topology in 2029 and 2032. An additional sensitivity was included examining how increased load identified in the 2025 forecast could impact the 2029 case to allow PJM to right-size the solutions built on the two base cases.

The inclusion of the 2024 Regional Transmission Expansion Plan (RTEP) Window 1 slate of grid updates mitigated 13 constraint overloads that prevented the market efficiency analysis from being able to calculate interface limits, in addition to reducing congestion on several lines. The remaining congestion is largely located along the PJM/MISO border. PJM also included planned resources sorted into the fast-track study queue and those with suspended interconnection service agreements (ISAs) to the analysis to allow it to meet the expected 17.8% reserve requirement.

The preliminary congestion drivers identified include the 138-kV Museville-Smith Mountain line in the AEP zone, which has $39.7 million of congestion in the 2029 base case and $51.5 million in the 2032 case; the 115-kV West Point-Lanexa line in the Dominion zone, which has $1.2 million of congestion in 2029 and $1.3 million in 2032; and the 115-kV Garrett-Garrett Tap line in the APS zone, which has $1.8 million in 2029 and $2.4 million in 2032.

PJM’s Nicholas Rodak said the next step is finalizing additional sensitivities and the models for the 2025, 2029, 2032 and 2035 simulated years.

Tightening Supply and Demand Impacting RTEP Planning

PJM’s Wenzheng Qiu presented stakeholders with an update on the assumptions being developed for the 2025 RTEP analysis, which includes an expectation that existing generation and planned resources with signed ISAs will not be sufficient to meet loads in 2030.

Window 1 will include the 2025 load forecast, which includes 16 GW of growth in 2030 above the prior year’s forecast.

The five-year analysis of the balance between load and generation finds that peak loads could be met with the addition of projects with suspended ISAs, fast-lane queue projects, the Chesterfield Energy Reliability Center planned in Virginia and the Coastal Virginia Offshore Wind project, albeit with a loss-of-load expectation of 1.6 days per year. If the 2,308 MW of offshore wind planned in New Jersey and 255 MW in Delaware are not completed, the LOLE would increase to two days per year, 20 times higher than the one-in-10 benchmark.

If all those projects are included in the seven-year base case, Qiu said the 2032 LOLE would be 2.3 days per year. The seven-year case is being included in the analysis to identify projects that could be right sized for long-term needs.

PJM’s Sami Abdulsalam said resources with suspended ISAs and fast-lane projects are being included in the RTEP analysis to allow the amount of available generation to meet peak loads. The point of interconnection for those projects is being set at the nearest bus at 500-kV or higher to avoid impacts to lower-voltage facilities. The seven-year case also includes all projects being studied in Transition Cycle 1 and 2, which will also be modeled on the high-voltage backbone network.

Responding to stakeholder questions on how any network upgrades required for those generation projects will interact with the RTEP needs, Abdulsalam said the seven-year case will inform the solutions chosen to resolve the five-year needs. Not all network upgrades expected to be completed in the latter analysis will be included in the five-year case, so any such upgrades would be removed.

Supplemental Projects

FirstEnergy presented two projects in the ATSI zone to address transmission overloads and congestion identified in MISO’s Long-Range Transmission Planning process (LRTP) and support projects in the 2024 MISO Transmission Expansion Plan.

The first would construct a 20-mile optical fiber line between the Lemoyne and Toledo Edison substations and replace line relaying at Lemoyne at a $15.6 million cost. The second would install 7 miles of fiber from Toledo Edison to the Lallendorf substation, where line relaying would also be replaced, at a $5.9 million cost. The overall $40 million project is in the conceptual phase with a projected in-service date of June 1, 2032.

FirstEnergy also presented three projects to replace transformers in the JCPL zone for maintenance issues and the infrastructure approaching the end of its useful life. The 230/115-kV Whippany transformer No. 12 is about 66 years old and has had problems with leaking oil and nitrogen gas; the unit, associated relaying and substation conductor would be replaced at a $8.1 million cost, with an in-service date of March 7, 2030.

The 230/34.5-kV Chester transformer No. 4 is nearly 46 years old and has been reading elevated ethane gas in its oil. Replacing the transformer, a 230-kV circuit switcher, 34.5-kV breaker and limiting terminal components would cost $7.3 million with an in-service date of Dec. 31, 2029. The 230/34.5-kV Chester No. 1 would also be replaced, as it was installed about 60 years ago and there are signs of degrading insulation. Its replacement would cost $7.3 million, which includes a 34.5-kV breaker and limiting terminal components.

FirstEnergy presented a $12 million project to replace the control building at its Glade substation in the Penelec zone. The building is 56 years old and degrading, with rusting walls and broken windows. Several line ratings are also limited by terminal equipment. Several other components of the substation would also be replaced, including: four disconnect switches, two 230-kV breakers, and substation conductor and the line trap on the 230-kV Lewis Run-Warren line. Substation conductor and terminal equipment would also be replaced at the utility’s Warren and Lewis Run substations. The project is in the conceptual phase with a projected in-service date of Dec. 17, 2027.

American Electric Power presented a $173 million project in its zone to connect LRTP Tranche 2 projects to the PJM grid. While the full cost would be assigned to MISO customers, there could be impacts to the PJM grid, so AEP determined to submit them as supplemental projects to be studied for any transmission violations. No “large-scale issues” have been determined, AEP said.

The Sorenson substation would be reconfigured to terminal two new 765-kV lines to the Greentown and Lulu facilities, and four new 345-kV lines would be terminated at the Sullivan substation, with two running each to Fairbanks and Dresser.

Several lines would also be modified to cut into new substations:

    • the 765-kV Sullivan-Rockport line would cut into a new Pike County substation;
    • the 765-kV Jefferson-Greentown and 345-kV Tanners Creek-Hanna lines would both cut into the Gwynneville substation;
    • the planned 345-kV Gwynneville-Tanners Creek line would cut into the existing Batesville substation;
    • the 345-kV Fall Creek-Sunnyside line would cut into a new Madison County substation; and
    • the double-circuit, 345-kV Olive-University Park and Olive-Green Acres lines would cut into the 345-kV Babcock substation.

Exelon presented a $874.2 million project to extend two 765-kV lines from ComEd’s Collins substation, which would also be expanded, to interconnect with projects in MISO’s Tranche 2.1 portfolio. All costs associated with the project would be allocated to MISO.

A new 765-kV Woodford County substation would be built in the MISO grid as part of the project, which would cut into ComEd’s 345-kV Powerton-Katydid and Powerton-Nevada lines. Two 300-MVAR line reactors would be installed at Collins, along with associated circuit breakers for each new line.

Exelon also presented a $40 million project in the ComEd zone to construct a new 345-kV substation, named Eldamain, to serve a new customer bringing 600 MW to the area of its Plano substation. The new facility would be cut into the 345-kV LaSalle-Plano line with 0.4 miles of new double-circuit line. The project is in the engineering phase with a projected in-service date of June 1, 2029.

Dominion Energy presented a $30.6 million project to rebuild 10.3 miles of its 230-kV Shawboro-Elizabeth City line as it approaches its end of life, having been built with wooden H-frames in 1975. The project is in the engineering phase with an estimated in-service date on Aug. 31, 2025.