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April 18, 2025

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Company Briefs

Occidental Petroleum Awarded Permit for Direct Carbon Capture Project

EPA has approved Occidental Petroleum’s application to capture carbon dioxide from the atmosphere and inject it underground. Occidental, a Houston-based oil firm, will start storing 500,000 metric tons of carbon dioxide in deep, non-permeable rock formations 4,400 feet underground as soon as this year. The facility will be located 20 miles southwest of Odessa. 

More: Texas Tribune 

Chevron Ordered to Pay More than $740M to Restore Louisiana Coast

Oil company Chevron must pay $744.6 million to restore damage it caused to southeast Louisiana’s coastal wetlands, a jury ruled following a trial more than a decade in the making. 

Jurors found that Texaco, acquired by Chevron in 2001, had violated Louisiana regulations governing coastal resources for decades by failing to restore wetlands impacted by dredging canals, drilling wells and billions of gallons of wastewater dumped into the marsh. The jury awarded $575 million to compensate for land loss, $161 million for contamination and $8.6 million for abandoned equipment. 

The case was the first of dozens of pending lawsuits to reach trial in Louisiana against the leading oil companies for their role in accelerating land loss along the state’s rapidly disappearing coast. The verdict, which Chevron said it will appeal, could set a precedent leaving other oil and gas firms on the hook for billions of dollars in damages tied to land loss and environmental degradation. 

More: The Associated Press 

EVelution Energy to Break Ground on Cobalt Processing Facility

EVelution Energy  said it plans to begin construction of its cobalt processing facility in Arizona later this year. It would be the only cobalt processing facility in the U.S. Cobalt is a mineral in high demand for its use in EV batteries, aerospace products and defense technologies.  

More: Arizona Republic 

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Md. Consumer Advocate Seeks Price Cut in PJM 2024 Capacity Auction

The Maryland Office of People’s Counsel has filed a complaint against PJM alleging the rules used in the 2025/26 Base Residual Auction would require consumers to pay twice for capacity provided by generators operating on reliability-must-run agreements.

The auction conducted in July 2024 resulted in a nearly 10-fold increase in capacity prices. (See PJM Capacity Prices Spike 10-fold in 2025/26 Auction.)

“PJM ran a flawed auction resulting in prices that — unless corrected — will cost Maryland residential electric customers hundreds of dollars per year in unreasonable and unnecessary capacity costs,” People’s Counsel David Lapp said in an announcement of the complaint April 14. “We are asking FERC to undo those unjust results and direct PJM to reset the prices for the 2024 auction by correcting the same flawed rules that FERC has already accepted the need to fix for future auctions.”

Pointing to a Synapse Energy Economics report commissioned by the OPC, the complaint said excluding RMR units from the supply stack would inflate costs by more than $5 billion. That report found that the 2025/26 BRA design would increase monthly costs by as much as 24% for some Maryland ratepayers. (See Maryland Report Details PJM Cost Increases for Ratepayers.)

OPC also contends the auction allowed market manipulation, improperly exempted 1,600 MW of generation from being required to submit offers and produced prices incapable of incentivizing new entry because of the confluence of long development timelines and a compressed auction schedule. It notes the auction was conducted within a year of the start of the corresponding delivery year on June 1.

“The [FERC] and the courts have made clear that high prices are unjust and unreasonable if they do not reflect market fundamentals or cannot induce a market response. The 2025/2026 BRA results fall short on both grounds,” the complaint says.

The complaint argues that revising the auction results would not violate the filed rate doctrine as they are “intended to govern future performance” that has yet to begin. It pointed to a 2021 remand from the D.C. Circuit Court of Appeals directing FERC to reopen an investigation into MISO’s 2015/16 capacity auction, which set a $150/MW-day clearing price in its Zone 4. (See FERC to Take 2nd Look at 2015 MISO Capacity Auction.)

The complaint effectively would expedite implementation of a change the commission approved in February, granting a PJM request to model the output of RMR units as capacity as long as the resources could meet certain criteria, including being available to RTO dispatchers when called upon.

The proposal is set to go into effect for the 2026/27 and 2027/28 delivery years, with PJM intending to develop a long-term solution with stakeholders. Comments on the docket centered around two Talen Energy resources: the 1,289-MW Brandon Shores coal-fired generator and 843-MW H.A. Wagner oil-fired plant. Both facilities are located near Baltimore and are slated to deactivate after operating on RMR agreements through Dec. 31, 2028 (ER25-682, ER24-1787, ER24-1790). (See FERC OKs Changes to PJM Capacity Market to Cushion Consumer Impacts.)

“The 2024 auction results ignore the significant ratepayer-funded reliability contributions of the Brandon Shores and Wagner plants — with devastating consequences to customers from the resulting extraordinarily higher capacity market costs,” Lapp said. “The Federal Power Act prohibits requiring captive utility customers to pay twice for the same service.”

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GCPA Conference Examines the Biggest Change to ERCOT Market in 15 Years

HOUSTON — ERCOT this December will begin implementing a market design change that has been debated for more than a decade, experts said at the Gulf Coast Power Association’s Annual Spring Conference on April 14.

The real-time co-optimization (RTC) of energy and ancillary services means that ERCOT’s security-constrained economic dispatch will solve for both at the same time. Vice President of Commercial Operations Keith Collins said it could save billions of dollars a year in operating the grid, with a study finding RTC plus batteries (RTC+B) could save between $2.5 billion and $6.4 billion annually.

“Ultimately, there’s a lot of benefit this is going to derive to the market, to the ratepayers and consumers,” Collins said. “And you see that this is something that, while it’s been in the works for a long time, we are essentially at the dawn of the RTC location.”

The big difference in the potential benefits has to do with the years the market change was “back cast” for testing, which included the summer of 2023, when conditions in ERCOT were tight and prices were high, Collins said.

R Street Senior Fellow Beth Garza was a big supporter of the move when she was ERCOT’s Independent Market Monitor, saying she got the grid operator and the Texas Public Utility Commission on board with the market change in 2018. The biggest change since that time has been the growth of storage, with 11 GW now competing in the markets.

“This idea of ‘RTC plus B,’ in my mind, has become ‘RTC because of B,’” Garza said. “For storage to be able to easily move into and out of providing energy versus capacity for ancillary services needed something different. And here it is.”

The change will save money by dispatching a plant that had reserved some capacity for ancillary services in the energy market and then shifting the ancillary service to a more expensive plant, lowering the overall cost of power, according to ERCOT.

“We are getting more expensive ancillary services,” ERCOT Principal of Market Design and Development Dave Maggio said. “So that can be a question of, is that necessarily a good thing? And the answer in this case is, yes, it is worth getting more expensive ancillary services because of the overall decreasing energy price.”

The change also comes with a new offer cap in the energy markets, at just $2,000/MWh, down from the current $5,000/MWh. Prices can still go above $2,000/MWh, but as in the FERC-regulated markets, that will only happen when the market is running short. Scarcity pricing will be handled through the “ancillary services demand curve,” which will replace the operating reserves demand curve (ORDC), Maggio said.

While RTC is set to go live Dec. 5, ERCOT is going to be spending the next seven months getting ready for it with market trials starting May 5, and a market notice explaining them is due soon, said Matt Mereness, the grid operator’s senior director of market operations and implementation.

The training will involve weekly calls with market participants and, starting in September, trial runs of the new market design that will cover the morning ramps, Mereness said. ERCOT ran similar tests 15 years ago when it transitioned to a nodal design from zonal.

“Who was here for the nodal go-live 15 years ago?” Mereness asked the audience. “Now raise your hand if you did that. Well, the good news is it’s not that big, but this is still the biggest paradigm shift we’ve had in 15 years.”

The move to RTC is going to mean more efficient energy and ancillary services markets, which means that to drive more resource investments, the market will need to have more scarcity events that drive prices high and send price signals for investments, said NRG Senior Director of Regulatory Affairs Bill Barnes.

“We are becoming more dependent on the demand curve for price elevation,” Barnes said. “I think that’s a good thing. … When we first started, there wasn’t an ORDC. We were solely dependent on submitting high offers. As we’ve evolved over the past 20 years, we’ve moved more towards a demand curve approach, which to me more aligns the price formation with the actual fundamentals of the market, versus one participant deciding to submit the price of the cap on a random day, which can be not a good thing.”

While the move to RTC+B will influence price formation in ERCOT’s markets, consultant Eric Goff said generation investments in the near future are going to be driven by large loads like data centers coming to Texas.

“The reason, among others, that large loads are attracted here is because you can transact in this market,” Goff said. “You can get what you want without having to ask for too much permission, and if those large loads contribute to higher prices because of their demand, which they have been, in the long run, then you get to a price that reflects the cost of entry.”

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FERC Authorizes NYISO, ISO-NE to Collect Tariffs on Electricity

FERC on April 14 approved filings by NYISO and ISO-NE authorizing them to collect tariffs on electricity imports from Canada, if the “relevant federal authorities” deem them responsible for doing so (ER25-1462, ER25-1445).

The grid operators have said President Donald Trump’s tariffs on energy imports do not appear to apply to electricity. However, to prevent potential financial consequences, both saw the need to establish a framework for collecting them.

The commission accepted both grid operators’ proposed open access transmission tariff revisions for allocating Trump’s tariffs. NYISO proposed to charge the “financially responsible party,” while ISO-NE proposed to charge “the entities selling the assessed electricity into the ISO-administered market.” (See ISO-NE Braces for Tariffs on Canadian Electricity and NYISO Preparing to Collect Duties on Canadian Electricity Imports.)

Both grid operators wrote that their cost collection methods would allow importers to include the costs of the duties in market offers. The mechanisms could change if the federal government gives clear instructions to them to collect the tariffs differently. ISO-NE included in its proposal a provision allowing it to collect the duties “in accordance with any federal regulations or guidance,” while FERC directed NYISO to add a similar provision in an additional filing.

FERC emphasized that it makes “no finding regarding whether import duties imposed pursuant to the Canadian tariff executive order apply to Canadian electricity or whether [the grid operators are] required to pay them,” and similarly declined to rule on whether it is legal to apply the import duties to electricity.

Because of the “exigent circumstances present,” FERC directed both grid operators to file “any legal and/or technical guidance and related documentation from the relevant federal authorities showing that a federal agency has assessed an import duty on Canadian electricity imports” that triggers the grid operator’s collection authority, “as soon as practicable after receiving such invoice.”

If they do start collecting the tariffs, the grid operators must provide informational filings to FERC every six months for three years about the costs of the duties.

ISO-NE’s proposal is intended to be a temporary mechanism; if the RTO anticipates tariffs lasting longer than 120 days, it must file a permanent cost collection method within 120 days of the first import duty invoice.

ISO-NE responded: “We still believe the tariffs do not apply to electricity, and that if they do, ISO-NE would not be the entity responsible for implementing them. There is a lot of uncertainty around the situation, and the proposal is a proactive move covering one possible outcome.” They also published a press release, saying ” the ISO is committed to maintaining ongoing dialogue with our stakeholders, state officials, and the federal government.”

NYISO said it had no further comments.

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Report Estimates Billions in Savings from More Interregional Transmission

The authors of a new report released April 4 say better market integration and reduced interregional constraints in the U.S. transmission network would have saved as much as $12 billion in 2022 and 2023.

They note the importance of achieving better grid integration in an era when increasing amounts of renewable generation is coming online but flag the difficulty of achieving it, given the financial incentive existing generators have to delay or block such integration.

The working paper, “Power Flows, Part 2: Transmission Lowers US Generation Costs, But Generator Incentives Are Not Aligned,” was written by Dasom Ham, Owen Kay and Catherine Hausman as part of Resources for the Future’s Obstacles to Energy Infrastructure research project.

They write that geographic constraints and mismatched supply and demand are growing as intermittent wind and solar capacity come online, often far removed from high-demand areas.

Better integration of electricity markets could allow systemwide cost savings and therefore lower consumer costs, the paper says. Integration of existing supply across regions could have saved $5.8 billion to $7.1 billion under 2022 conditions (which included higher natural gas prices) and $3.4 billion to $5 billion under 2023 conditions.

Other savings that could be created by intraregional integration were not estimated, nor does the report offer a full cost-benefit analysis of building new transmission or look at the cost versus societal benefit of building renewables.

But such integration would also create winners and losers, as existing generators in high-demand markets see their net profits drop and renewables in high-supply markets avoid curtailment.

The structure and processes of markets give those incumbents many opportunities to delay or block transmission construction projects that would run counter to their interests, and the report highlights case studies in multiple regions where they appear to have done just that.

This opposition can be hidden within workings of RTOs or it can be publicly visible, such as NextEra Energy’s long-running but unsuccessful fight to thwart Avangrid’s construction of the New England Clean Energy Connect, which will bring up to 1.2 GW of cheap Canadian hydropower to a region where NextEra operates multiple power plants.

The analysis showed these dynamics vary substantially by region: Greater market integration would benefit existing power producers in the Great Lakes, Great Plains and Rocky Mountain regions but hurt producers in the Northeast and Southeast.

The barriers to siting, planning, permitting and construction of transmission are well known, and include cost allocation, land rights and environmental clearance. Importantly, transmission planning and changes to market structure for interregional electricity trade depends largely on the consensus of incumbent generation companies, who hold greater sway than stakeholders who would see cost savings.

Investment patterns in recent years show the result of these dynamics: Only 2% of new circuit miles installed from 2011 to 2020 were for interregional transmission lines, and the majority of all transmission investments were for local reliability concerns rather than generation cost savings.

The new report builds on “Power Flows: Transmission Lines, Allocative Efficiency and Corporate Profits,” a working paper written by Hausman and issued by the National Bureau of Economic Research in January 2024.

The earlier report focused on the MISO and SPP regions, but the new report looks at the entire continental U.S. The dynamics are similar and can be generalized, but MISO and SPP do have some distinctive features, and there were some limitations in extending the research design to the rest of the country.

Data was obtained primarily from the Energy Information Administration and EPA’s Continuous Emissions Monitors Systems datasets.

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PJM CEO Manu Asthana Announces Year-end Resignation

PJM CEO Manu Asthana on April 14 said he will resign from his position at the end of 2025 after more than five years of leading the RTO.

“My five-plus years at the helm of PJM have been some of the most fulfilling of my career,” Asthana said in a statement. “I am especially appreciative of the opportunity to have led PJM’s remarkably talented, diligent and committed people, who work hard every day to keep the power flowing for 67 million people.

“The time has now come for my wife and me to move back to be closer to our family and friends in Texas. I look forward to continuing to lead the organization through the end of the year and to helping facilitate an orderly transition to my successor.”

Asthana relocated to Pennsylvania when he took over as the head of PJM on Jan. 1, 2020, in the wake of the GreenHat Energy default, which led to the resignation of several PJM executives. (See PJM Taps Ex-Direct Energy Exec as New CEO.)

Mark Takahashi, chair of the PJM Board of Managers, said Asthana guided the RTO through several significant changes, including the shift to studying interconnection requests with a cluster-based approach and an overhaul of capacity market rules following Winter Storm Elliott in December 2022. (See FERC Approves 1st PJM Proposal out of CIFP.)

“The PJM board is grateful to Manu for his strong leadership during a time of tremendous change in the electricity industry,” Takahashi said in a statement. “Under his leadership, PJM successfully navigated the COVID-19 pandemic, significant market reforms, interconnection process enhancements, the buildout of a robust risk management function and the delivery of world-class grid reliability through a variety of extreme weather events.”

Takahashi said Asthana has worked with the board to develop “PJM’s internal succession pipeline.”

“We have a strong executive team, including internal succession candidates. We will also consider external candidates for this role,” Takahashi said.

The board has formed a search committee to identify a replacement in the next year. That process will be aided by consulting firm Korn Ferry with input from the RTO’s membership and stakeholders. Asthana is set to stay on as a senior adviser until June 2026.

Electric Power Supply Association CEO Todd Snitchler said Asthana led PJM through a time of rapid change.

“We have appreciated working with him and his willingness to listen to the input of the generator community as he navigated how to deliver reliable power while addressing the challenges posed by varying state and federal policy preferences; a rapid rise in energy demand; and external factors like supply chain hurdles and onerous permitting policies that impede infrastructure development,” Snitchler said.

He said EPSA hopes to see PJM continue to address planning and interconnection queue issues, and “strongly support” a market that balances input from stakeholders and market participants and “provides reasonable certainty and a fair opportunity for a return on investment for resource developers.”

Glen Thomas, president of GT Power Group, said “leading PJM is a challenging job, and Manu led PJM through some very challenging times, from COVID to the data center demand boom. He remained calm, accessible and diligent no matter what the challenge. We look forward to working with PJM to find a successor that can lead PJM to meet its mission to deliver reliability through markets.”

D.C. Public Service Commission Chair Emile Thompson, current president of the Organization of PJM States Inc. (OPSI), pointed to several capacity market changes PJM pursued in recent months that consumer advocates have argued would ward off inappropriately high prices. (See PJM, Shapiro Reach Agreement on Capacity Price Cap and Floor.)

“CEO Asthana has been a tremendous partner to work with during my tenure as the president of OPSI,” he said. “Together, we worked to implement a number of reforms in response to the most recent Base Residual Auction. I look forward to continuing to work with him through the remainder of his tenure as we tackle issues such as resource adequacy, sub-annual capacity markets, transmission planning and issues surrounding co-location.”

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SEEM Members File Market Agreement Update

Alabama Power, on behalf of other members of the Southeast Energy Exchange Market (SEEM), has submitted a FERC-ordered filing detailing changes to the market’s agreement intended to comply with a March 14 order from the commission (ER21-1111).

The proposed changes to the agreement detail the ability of utilities to participate in SEEM via pseudo-ties, which are used to represent interconnections between two balancing authorities where no physical connection exists between the load or generation and the power system network. SEEM members proposed the changes take effect April 15.

FERC directed SEEM to update the agreement after members argued in an earlier filing that pseudo-ties offered a means for loads and resources outside the SEEM territory to participate in the market. (See SEEM Members Respond to FERC Briefing Request.) This claim came in response to the commission’s request for briefings after an order from the D.C. Circuit Court of Appeals remanded the commission’s approval of the market in 2021.

One of FERC’s questions concerned whether entities with a source or sink outside SEEM’s territory could meet the technical requirements of the market’s matching platform. SEEM’s supporters have argued the territorial requirement was needed to implement the market platform that matches excess supply with free transmission every 15 minutes. But the court claimed the limitation resembled “discriminatory practices against third-party competitors by monopoly utilities.” (See DC Circuit Sends SEEM Back to FERC.)

FERC’s March 14 order acknowledged “an external source or sink could be a participant in SEEM if it used a pseudo-tie,” but observed that such a practice would significantly affect “rates, terms or conditions of service” to such an extent that it should be included in the market agreement rather than a business practice manual. In their response, SEEM members agreed “there is not a SEEM entity that … would have the authority to evaluate and approve or reject creation of a pseudo-tie” under the current market agreement.

To address this, members proposed amending the agreement in several places. First, the new agreement adds the words “including through the use of a pseudo-tie” to language in the market rules that says a participant must own or control a source, and/or “be contractually obligated to serve a sink,” within the SEEM territory. A new footnote in the same section specifies that a prospective participant seeking to establish a pseudo-tie must coordinate with relevant BAs, transmission providers and reliability coordinators, along with the SEEM Operating Committee.

Members said that “a pseudo-tied resource or load, once established, would appear no differently from any other resource or load registered as a valid source or sink” participating in SEEM.

A change to Article 5 would establish the Operating Committee’s obligation to coordinate with efforts to participate via pseudo-tie. The language of the new section 5.11 requires the committee not to reject a pseudo-tie that has been accepted by the relevant TP, BAs and RCs.

Similar language is found in proposed changes to section 3.4, adding that TPs “shall have a duty to coordinate and act in good faith in interactions with any prospective participant … utilizing a pseudo-tie,” and with all relevant BAs and RCs. Such good-faith interaction must include transparency about the reason for any denial of participation.

The updates also added definitions of the terms “pseudo-tie” and “reliability coordinator” to be consistent with definitions in the SEEM market rules.

“These changes appropriately commit SEEM to working with potential participants on pseudo-ties, including coordinating with the other identified entities necessary to the establishment of any such pseudo-tie,” members said.

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Corrected. Electric, Hydrogen Trucks Promoted for Port NY-NJ

(Editor’s note: An earlier version of this article contained information about a company, Zeem, that’s unconnected to the Kearny Point project.)

New Jersey is investing up to $13 million in a pilot project to put six hydrogen-fueled trucks to work in the Port of New York and New Jersey as the port authority prepares to launch an unrelated initiative to cut trucking emissions by opening the first publicly accessible heavy-duty truck chargers at the port. 

The New Jersey Economic Development Authority (EDA) on April 9 agreed to pay Rutgers University to develop the hydrogen project with money from the Regional Greenhouse Gas Initiative (RGGI). Rutgers researchers will buy six Class 8 hydrogen fuel-cell trucks, as well as fueling facilities and fuel, and partner with one or two logistics companies to operate the trucks at the port. 

The project will add to the ongoing effort to cut emissions in and around the largest port on the East Coast. Pollution from the port has attracted attention because of its location in a densely populated area already burdened with fossil fuel electricity generators and highways. Much of the port is in Newark, the state’s largest city, and the marine terminals contributed about 8.5% of the greenhouse gas emissions in the area, according to the EDA’s memorandum of understanding for the hydrogen project.  

The 15-month-long hydrogen project, with the option to extend by a year, will be carried out at Port Newark and Port Elizabeth marine terminals and aims to “position New Jersey as a leader in clean hydrogen innovation,” according to a memo outlining the project that was submitted to the board by EDA CEO Tim Sullivan. 

Rutgers researchers will “gather raw data to assess the vehicle’s feasibility” and will submit quarterly reports to the EDA that address issues including “procurement, health and safety, equipment operations, vehicle mileage, fuel consumption and maintenance,” the memo says. “This data will emphasize economic and environmental factors, including but not limited to total cost of ownership and tailpipe emission,” the memo adds. 

EV Advances in the Ports

The EDA’s approval came as two heavy-duty electric charging initiatives are close to coming online. The Port Authority of New York and New Jersey (PANYNJ) is ready to open four EV DC fast chargers (DCFC) in the port that will be available to the owners and operators of drayage trucks, which move shipping containers in and out of the port. 

In an unrelated project, EV Edison is completing construction on Kearny Point, a heavy-duty trucking depot that will be able to handle 200 Class 8 trucks a day. “The hub is currently in its final stages of construction and will be ready in a few weeks,” said Yazan Harasis, director of engineering at the company.
Located on the edge of the Port of New York and New Jersey, the Kearny Point depot will have 30 ports, each with up to 180 kW of power, which will take about two hours to fully charge a truck, he said.

Drayage trucks make more than 14,000 trips in and out of the port each day, but the drayage sector and truck owners in New Jersey have been slow to embrace electricity or any other alternative truck fuel, as they have been in other states.  

PANYNJ in July 2024 said the use of electric trucks and container handling equipment increased by about 8% from 2022 to 2023. But that growth started from a small base. The authority’s March 2025 report shows there are 19 electric trucks serving the port, compared to 10,875 diesel trucks.  

Drayage trucks typically pick up containers imported through port terminals and deliver them to a distribution center or a warehouse, often returning the same day to the port with empty containers. As such, the distance of a typical drayage delivery is much less than, say, those made by cross-country truckers. 

A National Renewable Energy Laboratory (NREL) report in 2023 found that existing electric trucks on the market had sufficient range to replace 20% of diesel trucks in the port, because the average route they completed each day was 140 miles. (See NREL Report Sees Role for Electric Trucks at Port of NY-NJ.) 

Trucker Skepticism

Truckers, however, say electric trucks on the market are too expensive, the number of models available is limited and the range for those EV trucks on the market still is too small. A diesel truck typically costs $180,000 and an electric truck upward of $400,000, according to the American Trucking Associations. Studies have shown EV trucks can be cheaper than diesel over the life of the vehicle, due to the lower fuel and maintenance costs. (See NRDC Report Predicts a Decline in NJ’s EV Truck Costs.) 

Truckers say the hefty EV battery takes up space that otherwise would be used for carrying goods and products, making the trucks less efficient. And they say the time taken to charge the battery also reduces truck efficiency, compared to the relative speed with which a diesel truck can be filled up. 

The cost factor is particularly important because many of the trucks that serve the port are owned and operated by small businesses that operate a handful of trucks and have little capital to buy an electric truck. 

Lisa Yakomin, president of the Association of Bi-State Motor Carriers, which represents drayage truckers in the port, said she’s not familiar with the hydrogen pilot proposed by the EDA, but said the state lacks charging or fueling infrastructure for hydrogen trucks, as it does for electric trucks. 

“If you compared the two side by side, I think there are, from a charging standpoint, advantages to the hydrogen fuel cell” over electric trucks, Yakomin said. “But the challenges relating to infrastructure are the same for both, and the challenges in terms of cost are the same for both. And those are two very big issues that keep them from being taken seriously. 

“I’m not aware of any public fueling stations for hydrogen (around the port). I think there’s one private one in the entire state of New Jersey,” she said. Still, she added, “one of the advantages that hydrogen fuel cell trucks have over EVs is that they charge about as quickly as a diesel truck does. They also go twice as far as an electric truck. But when you compare it to a diesel truck, they still go a fraction of the distance of a diesel truck on a full tank of gas.” 

While a diesel truck can go about 1,300 miles on a tank of gas, and an electric vehicle can do 200 miles or so on a charge, a hydrogen truck can go about 400 miles, she said. She added that port officials have said the chargers planned for the new electric charging sites are 350 kW, which would charge a truck in about two hours — a time she suggested is too long for the rapid-turnaround needs of the drayage sector. 

The website for Phoenix-based Nikola, which makes hydrogen fuel-cell trucks, says its vehicles have a range of 500 miles and can be refueled in “20 minutes or less.”  

Hydrogen is made by electrolyzers splitting water molecules into their components of hydrogen and water. For hydrogen produced this way to be clean, or green, as it is commonly called, the electrolyzers have to be powered by zero-emissions renewable or nuclear energy. 

The EDA, in memorandum outlining the hydrogen project, said “hydrogen is most applicable to industries that are difficult to decarbonize through battery electrification. In the transportation sector, electrifying medium- and heavy-duty vehicles remains a challenge.” 

The Department of Energy in 2024 allocated $750 million to fund 52 projects in 24 states across the nation, with an aim to advance electrolysis technologies and manufacturing and recycling capabilities for clean hydrogen. The goal of the projects, with funding from the Infrastructure Investment and Jobs Act, is to boost the manufacture of electrolyzers to produce up to 1.3 million tons of clean hydrogen yearly and boost the production of fuel cells, which run on the clean hydrogen, by 14 GW yearly. (See DOE Announces $750M in Clean Hydrogen Funding.) 

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Stakeholders Respond to Mass. Proposal to Limit Cost Recovery for Gas Expansion

Business groups and environmental advocates expressed divergent views on a proposal by the Massachusetts Department of Public Utilities that would require new gas customers to cover the entire cost of connecting to the system.

The department’s draft policy would end the utility practice of including the costs of connecting new customers into rate base. This is currently allowed if the utility expects to recover the costs through distribution fees from the new customers over an extended period.

The DPU, along with the state Department of Energy Resources and Attorney General’s Office, has expressed concern that the practice is not in line with the state’s climate laws and risks creating stranded costs as the state transitions away from natural gas (DPU 20-80). (See Mass. DPU Proposes Major Shift in Gas Line Extension Policies.)

The department proposed to allow exemptions to the requirement for new customers to cover their entire connection costs if they can prove the project would create a “demonstrable reduction” in carbon emissions, has no “feasible alternatives” to gas service and is consistent with the state’s statutory climate limits.

Climate and consumer advocates have supported the proposal, while the gas utilities, real estate groups and large business associations have voiced their opposition. Many of the arguments raised in the proceeding reflect significant underlying disagreements about the future of the natural gas system as the state decarbonizes. In an earlier phase of the proceeding, the DPU concluded that decarbonization of the state’s gas network should be based on electrification. (See Massachusetts Moves to Limit New Gas Infrastructure.)

In comments submitted in early April, gas distribution companies argued that the proposal would increase the cost of new gas service and push developers to use heating oil in new buildings. Eversource Energy wrote it would create “significant unintended consequences that will work directly against the commonwealth’s ability to reach its 2050 goals.”

National Grid and the Associated Industries of Massachusetts (AIM) — whose membership includes both National Grid and Eversource — both argued that the proposal would hurt economic development in the state.

“We are concerned that this proposal could impede economic growth, contribute to higher energy costs, and hinder vital housing and infrastructure development,” AIM wrote. “This change is likely to impose unreasonably high upfront costs to necessary energy infrastructure for commercial and industrial facilities.”

The Greater Boston Real Estate Board wrote that the draft policy would hurt housing development in the state and said the exemptions included in the proposal “offer no benefit.” It also argued that, in light of recent delays to offshore wind projects, “the department should reconsider the climate impact of this draft policy as more load is added to an already constrained electric grid.”

In contrast, the Massachusetts AGO — which serves as the official ratepayer advocate in the state — expressed support for ending the existing line extension policies, arguing that “such outdated policies encourage expansion of the gas system and increased gas infrastructure investment at a time when the commonwealth has made clear and decisive steps towards decarbonization through electrification by 2050.”

The AGO highlighted the emissions sub-limits in Massachusetts’ 2025-2030 Clean Energy and Climate Plan, which requires a 49% reduction in both the residential and the commercial and industrial heating and cooling sectors by 2030 (relative to 1990 levels).

“The LDCs’ [local gas distribution companies’] current policies are both antithetical to achieving the commonwealth’s climate mandates and inconsistent with the financial interests of ratepayers,” the AGO wrote.

It warned of a “price vortex,” in which customers exiting the gas system would increase distribution costs for the remaining customers. This phenomenon would likely disproportionately affect low- and moderate-income households that cannot afford the upfront costs required to convert to electrified heating, the AGO wrote.

“Line extension allowances exacerbate the price vortex because the new gas investments will become stranded costs as customers reduce natural gas consumption and possibly leave the gas distribution system before the end of the assumed repayment period,” the AGO noted.

Supporters of the DPU’s proposal highlighted a 2024 analysis by Groundwork Data, which found that the costs of all-electric construction have reached near parity with buildings that rely on fossil fuels and concluded that all-electric buildings will likely provide long-term savings for building owners. (See Report Outlines Cost Savings of All-electric Buildings in Mass.)

“Despite claims to the contrary by real estate developers and other similarly aligned industry members, there is a clear trend toward building electrification in Massachusetts and beyond,” the Conservation Law Foundation, Environmental Defense Fund and Sierra Club wrote in joint comments.

The AGO and a range of environmental nonprofits called for the DPU to add language establishing strict criteria for the exemptions that would allow a project’s connection costs to be covered by ratepayers.

“The draft policy should establish a clear and consistent methodology for assessing a demonstrable reduction in GHG emissions for proposed line extensions serving new construction,” wrote a coalition of environmental groups led by Rewiring America and the Acadia Center.

The AGO said the payback periods should be cut in half, which would bring the payback period for residential projects to 10 years and the period for commercial and industrial projects to five years. It recommended that the connecting customer be required “to pay for the remaining balance of outstanding costs of the line extension if the customer leaves the gas distribution system before the end of the assumed repayment period.”

The DOER agreed that utilities’ line extension policies are inconsistent with the state’s climate mandates and fail to account for the risk that line extensions will become stranded assets. But it called on the DPU to convene technical sessions to seek consensus among stakeholders around the best way to update the policies.

The department also noted that it met with a wide range of stakeholders before submitting its comments and found “a broadly shared concern that the language of the proposed policy, specifically of the proposed exceptions, was vague and raised significant questions regarding implementation.”

It said technical sessions could help achieve “alignment and clarity” more efficiently than another round of written comments.

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Counterflow: Groove on the Rubble

The last couple weeks remind me of the 1971 comedy record by David Frye during the Nixon administration. Richard Nixon (Frye) hosts yippie Jerry Rubin (Gabe Kaplan) in the White House, trying to make a political connection.

Steve Huntoon |

And I need to stop to clarify that “yippie” back then meant members of the Youth International Party.

Nixon asks, “Tell me, Mr. Rubin, what would you do after everything was torn down?” And Rubin replies, “I don’t know, man, maybe we’ll just sit there and groove on the rubble.”

Yeah man, just groove on the rubble.

We’ll skip over everything else in the past couple weeks and ask what to make of the Trump administration’s latest executive order directing FERC, an independent agency, to sunset its regulations in no more than five years (or explain why not). In apparently unintended irony, this is “to provide certainty and order.”

The “fact sheet” for the executive order talks repeatedly about “energy production,” which suggests the Trump administration doesn’t know what FERC does. FERC has no direct role in the production of energy except for the licensing of hydroelectric plants (and arguably qualifying facilities under the Public Utility Regulatory Policies Act, which the executive order inexplicably excludes).

FERC is told to sunset all its regulations implementing the Federal Power Act of 1935 and the Natural Gas Act of 1938 in one year but no more than five years. But these statutes don’t exist in any intelligible way without the implementing regulations that have been promulgated and judicially affirmed over the last 80-some years.

Most recently we have the long-term transmission planning regulations in Order 1920. So let’s see how this works: They govern transmission planning for the next 20-plus years, but they’re terminated in one year or five years?

The executive order requires FERC to issue a “sunset rule” for each of its regulations by Sept. 30, 2025, to eliminate each of its regulations by Sept. 30, 2026, except for such regulations that FERC finds should be extended based on “costs and benefits.”

How can FERC get rid of regulations it is required by statute to have? How can FERC amend each of its regulations to add a sunset date without conducting formal rulemakings to do so? How can FERC apply a “costs and benefits” standard (whatever that might be) to its regulations rather than the statutory standards?

FERC is required to coordinate all this with its “DOGE team lead” and with the Office of Management and Budget (OMB). Does FERC have a DOGE team lead employee, as it apparently is required to have per an earlier executive order? How can the DOGE team lead, a FERC employee, coordinate with DOGE, and how can FERC coordinate with OMB, on rulemakings to sunset FERC’s regulations without violating FERC’s ex parte rules?

This comes on the heels of a February executive order regarding FERC and other “so-called independent  agencies” (note the “so-called” pejorative) that:

    • gives OMB control of FERC resources.
    • requires the FERC chairman to “regularly consult with and coordinate policies and priorities with the directors of OMB, the White House Domestic Policy Council and the White House National Economic Council.”
    • gives the attorney general control of all “questions of law” involving FERC.
    • subjects all draft FERC regulations to review by OMB.

Good luck to Chair Mark Christie, his FERC colleagues and our industries.

(P.S. And let us pray for the return of Kilmar Armando Abrego Garcia so none of us have to fear arbitrary U.S. government kidnapping to foreign gulags where we must spend the rest of our lives.)

Columnist Steve Huntoon, a former president of the Energy Bar Association, practiced energy law for more than 30 years.