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February 23, 2025

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Struggling NJ Solar Sector Evaluates Net-metering Reform

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

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

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

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

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

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

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

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

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

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

Net-metering Adjustments

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

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

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

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

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

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

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

Balance of Benefits

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

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

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

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

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

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

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

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

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

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

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West Coast Truck Charging Network Advancing Despite Uncertainty

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

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

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

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

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

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

The project status also varies among the three states.

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

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

Solicitation Planned

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

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

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

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

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

What About NEVI?

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

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

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

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

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

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

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

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

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Utilities Say Procurement Challenges Growing Since Pandemic

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Corrosion monitoring must continue for the life of the project.  

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

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2 Companies Withdraw Texas Energy Fund Projects from Consideration

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

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

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

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

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

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

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

PUC Approves Non-ERCOT Program

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

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

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

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

ADER Project Moved to ERCOT

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

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

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

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Constellation Reports Solid 2024 Financials, Expects Better in 2025

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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FERC OKs Changes to PJM Capacity Market to Cushion Consumer Impacts

FERC approved a set of wide-ranging changes to PJM’s capacity market, including setting a new reference resource, recognizing the resource adequacy contribution of reliability must-run (RMR) units and establishing an RTO-wide non-performance charge rate (ER25-682). 

The rule changes came after the capacity prices spiked in the 2025/26 base residual auctions last year, due to the tightening supply and demand balance in the RTO. It also comes as the capacity auctions have been delayed so new generation can be built in time to participate. 

Two major fossil fuel power plants outside of Baltimore — the 1,289-MW Brandon Shores coal plant and the 843-MW H.A. Wagner oil-fired plant — are slated to retire but have entered into RMR deals with PJM to stay open until the grid is reinforced. Both of those RMR deals are pending at FERC. 

PJM proposed reflecting the resource adequacy contributions of any RMR deals in its next capacity auction for 2026/27 that is set for July 2025, and the one after that for 2027/28. They will bid $0 into the auction, effectively serving as price takers and giving the RTO more time to develop a fulsome proposal. 

Brandon Shores and H.A. Wagner are the only two plants that could qualify for the temporary rule, but Brandon Shores might require an emergency order from the U.S. Department of Energy under the Federal Power Act’s Section 202 (c). 

FERC found the proposal to reflect RMR units in the capacity auction just and reasonable, which includes crediting back the load paying for the RMR deal with any capacity revenues. 

“We agree with PJM that taking into consideration the resource adequacy contributions of RMR resources that meet certain criteria, such that they can be reasonably expected to perform, similar to capacity resources, will reflect the actual availability of resources in the PJM region for the 2026/2027 and 2027/2028 delivery years and avoid the risk that load will pay twice for the same capacity,” the order said. 

Requiring them to be price takers in the auction is in line with rules in New York and New England and will avoid customers paying for the same megawatts twice, FERC said. 

Previously, PJM was set to use a combined cycle natural gas unit for the 2026/27 auction. Given the realities of the auction, that would have led to a too-steep demand curve that left the auction price too sensitive to small changes in supply and demand. Instead, the auction will be run with a curve based on a combustion turbine natural gas plant, which will help ease the rate impacts of tight market conditions while maintaining reliability. 

PJM reviews such basic inputs to its capacity market every four years, but the market conditions have changed so much since 2022 moving to a combined cycle reference unit no longer makes sense for the next auctions, FERC said. 

Another major change is setting up a marketwide non-performance rate because some of the local delivery areas (LDA) have market conditions with a near-zero net cost of new entry (CONE), which means the non-performance penalties also were near zero. Keeping the non-performance rates above zero everywhere will help the RTO maintain reliability in an emergency. 

“We agree with PJM that its proposed uniform Non-Performance Charge rate recognizes the fact that capacity emergencies often extend beyond a single LDA, particularly given PJM’s recently revised definition of Emergency Action, which is structured such that PAIs [performance assessment intervals] are triggered across an entire Reserve Zone or Reserve Sub-zone,” FERC said. 

PJM also proposed a clarification that even if resources get out of a must-offer requirement, that does not provide a defense against market power abuse, like withholding capacity. That led to protests from market participants that the change would lead to them having the burden of proving their decisions to bid into the market are legitimate. 

FERC noted that it’s impossible to write rules that explicitly ban every kind of fraudulent behavior because “the methods and techniques of manipulation are limited only by the ingenuity of man.” 

“PJM’s proposal accurately states that an exception or exemption does not provide a defense to potential claims of withholding, market manipulation, or the exercise of market power,” FERC said. “PJM’s proposed language does not prohibit or limit an entity from providing evidence of the facts and circumstances relevant to defending against market power claims.” 

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Federal Briefs

IEA Raises Energy Consumption Predictions

The International Energy Agency last week raised its predictions for the world’s rising electricity demand, pegging the growth at almost 4% a year until 2027, up from its previous forecast of 3.4% a year. 

The consuming of more electricity will be led by China, where demand grew by 7% last year and could grow by 6% a year over the next three years. Rising demand in the U.S. is expected to add the equivalent of California’s current power consumption to the national total by 2027. 

More: The Guardian 

SEC Moves to Kill Climate Disclosure Rule

Mark Uyeda, the acting chair of the Securities and Exchange Commission, last week announced he was directing the commission’s legal team to inform a federal appellate court that the regulator was pausing a rule that requires publicly traded companies to provide investors with information about the impact of their businesses on climate and the environment. 

The decision to tell the U.S. Court of Appeals for the Eighth Circuit to pause any further proceedings in the matter is an indication the regulator may eventually move to rescind the rule or modify it. 

More: The New York Times 

Separate from DOGE, TVA Offers Buyout to Workers

The Tennessee Valley Authority is offering a voluntary buyout program that will give qualifying employees five days of pay for every full year of service to reduce the utility’s workforce and cut costs. 

The offer was announced internally last year and applies across the company, TVA spokesperson Scott Brooks said. It is unrelated to the buyout offered to federal employees by the Trump administration. 

TVA had 11,312 employees in 2024, up from 10,901 the year before, according to its latest annual financial report. 

More: Knoxville News Sentinel 

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State Briefs

REGIONAL 

$3B Natural Gas Pipeline Expansion Planned for Southeast

Kinder Morgan and Southern Natural Gas last week announced their proposed $3 billion natural gas expansion project called the South System Expansion 4 Project. 

The project, which would deliver over a billion cubic feet of natural gas daily, would stretch nearly 300 miles across Georgia, Alabama and Mississippi. The companies are splitting the cost. 

Construction is expected to start in 2027. 

More: WJCL 

CALIFORNIA 

Edison International Faces Shareholder Lawsuit over LA Wildfires

Edison International, the parent company of Southern California Edison, has been sued for allegedly defrauding shareholders before the recent Los Angeles-area wildfires by assuring them it could shut down power lines to reduce the risk of catastrophic damage. 

Shareholders said Edison made materially false and misleading statements for nearly four years before the fire by assuring its utility unit used a power shutoff program to “proactively de-energize power lines” to reduce wildfire risks during “extreme weather events.” The shareholders said reports claim Edison had not de-energized the lines, while lawsuits blamed the company’s equipment for starting the Eaton fire. 

The lawsuit seeks unspecified damages for shareholders. 

More: Reuters 

Lawmaker Proposes Law to Limit Rate Increases for Investor-owned Utilities

Sen. Aisha Wahab last week introduced a bill that would prohibit investor-owned utilities from proposing more than one rate increase per year. 

The bill would also cap any rate increase to no more than the Consumer Price Index, which is a measure of the average change over time in the prices consumers generally pay for goods and services. 

The Public Utilities Commission approved six rate increases for PG&E in 2024, which later announced it made a record $2.47 billion in profits. 

More: KCRA 

ILLINOIS 

Madigan Convicted of Bribery Conspiracy

Former House Speaker Michael Madigan was convicted last week on 10 counts relating to a nearly decadelong bribery conspiracy involving ComEd. 

The jury also convicted Madigan of a plot to install ex-Ald. Danny Solis on a state board in exchange for Solis’ help securing private business for Madigan’s law firm. However, the jury acquitted Madigan of attempted extortion and other crimes involving Solis and an apartment project, as well as failing to agree on finding Madigan guilty of a broad racketeering conspiracy. 

The most serious counts carry a maximum of 20 years in prison for the 82-year-old. No sentencing hearing has been set. 

More: Chicago Sun-Times 

IOWA 

House Advances Bills Aimed Against CO2 Pipelines

A House subcommittee last week advanced bills aimed at curtailing carbon sequestration pipelines. 

One bill would allow landowners to seek declaratory judgment, or a legally binding explanation of their rights, from a district court if their property were subject to an eminent domain claim in an application before the Utilities Commission. Another bill would limit permits to liquified CO2 pipelines to 25 years and prohibit the UC from renewing those permits. 

More: Iowa Capital Dispatch 

MARYLAND 

Constellation to Upgrade Calvert Cliffs Nuclear Plant

Constellation Energy last week said it will spend $100 million to upgrade equipment and electrical systems at its Calvert Cliffs nuclear power plant. 

The company is upgrading the plant with the hopes of renewing its operating licenses. The current licenses for its two reactors expire in 2034 and 2036. The upgrades are expected to increase production by 10%. 

More: The Baltimore Banner 

MICHIGAN 

PSC Approves DTE’s Application for Cold Creek Solar Project

The Public Service Commission has approved DTE Electric’s application for its 100-MW Cold Creek Solar Park Project. 

The project will provide power to Ford Motor Co. through DTE’s voluntary green pricing program. 

Commercial operation is expected in late 2026. 

More: WTVB 

MINNESOTA 

PUC Approves Xcel Gas Rate Increase

The Public Utilities Commission last week approved an 8.17% rate increase for Xcel Energy natural gas customers, effective July 1. 

The PUC approved the deal between Xcel and officials, which was down from an original request of 9.6%. The increase will add about $4.20/month to the average household. 

More: The Minnesota Star Tribune 

PENNSYLVANIA 

Senate Votes to Pull State from RGGI

The state Senate has passed a bill that would pull the state out of the Regional Greenhouse Gas Initiative. 

The bill formally repeals Pennsylvania’s participation in RGGI, ensuring that any decision to impose electricity taxes or emissions programs must go through the legislative process rather than being enacted unilaterally by the executive branch. 

The bill now moves to the House of Representatives. 

More: PA Senate Republicans 

SOUTH CAROLINA

Santee Cooper OKs VC Summer Settlement

The Santee Cooper Board of Directors last week unanimously approved a settlement that will enable the company to raise rates for the second time this year to recover $550 million in costs it incurred during a nearly five-year freeze on its electric rates. 

The increase is expected to start at about 3% ($5/month) for the average household and gradually decline to less than 2%. The collection period will last 14½ years starting in July. 

The resolution follows years of negotiations with Central Electric Power Cooperative and lawyers who filed a class-action lawsuit on behalf of ratepayers in 2017. The litigation followed the utility’s decision to abandon the expansion of the V.C. Summer nuclear plant after sinking billions of dollars into the doomed project. 

More: The Post and Courier 

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Company Briefs

Energy Transfer, CloudBurst Sign Natural Gas Supply Agreement

U.S. pipeline operator Energy Transfer announced it has entered into a long-term natural gas supply agreement with CloudBurst Data Centers for its development in Central Texas. 

Energy Transfer will provide up to 450,000 MMBtu/day of natural gas through its Oasis Pipeline to CloudBurst’s campus outside of San Marcos, Texas. The supply will generate up to nearly 1.2 GW of power for at least 10 years. 

More: Reuters 

Toyota EV Battery Factory Ready to Begin Production

Toyota announced that Toyota Battery Manufacturing North Carolina, the automaker’s first in-house battery manufacturing plant outside Japan, is ready to begin production and will start shipping batteries for North American EVs in April. 

The nearly $14 billion battery facility will produce batteries for hybrid electric vehicles, plug-in hybrid electric vehicles and battery electric vehicles. Production will be increased in phases, with line launches planned through 2030. 

More: Assembly Magazine 

Denbury Fined for Menacing Federal Inspectors

The Pipeline and Hazardous Materials Safety Administration has proposed a $2.4 million fine against pipeline company Denbury and its contractor, Republic Testing Laboratories, for taunting, pushing and blocking inspectors from doing their jobs while examining a carbon dioxide pipeline in Texas. 

PHMSA’s report details six incidents from Aug. 30 to Dec. 7, 2023, that it says violated federal law at the facility. The report also says Denbury refused to provide data and prevented inspectors from photographing readings on equipment. 

More: Louisiana Illuminator 

Clean Hydrogen Startup Syzygy Announces Layoffs

Syzygy Plasmonics said it would slash more than half of its staff by the end of March. 

The company, which has raised more than $100 million in funding and received backing from Mitsubishi Heavy Industries America, notified the state of Texas that it plans to lay off 68 employees beginning March 31. The layoffs are “a result of the company’s current financial outlook,” CEO Trevor Best said. 

Syzygy develops photoreactors that use light rather than combustion to power chemical reactions. 

More: Houston Chronicle