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February 28, 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, 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/share. This compares with $1.62 billion and $5.01/share for 2023. 

Adjusted (non-GAAP) income was $2.74 billion, or $8.67/share in 2024. During the year, Constellation twice bumped its full-year guidance for adjusted earnings higher, but results still exceeded the final $8 to $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 to $9.60/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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Energy Innovation: US Needs New Approach to Grid Reliability

To build a reliable, affordable and clean electric power system that can meet the challenges of unprecedented demand growth, the U.S. energy industry and the customers it serves will need to shift their thinking about what a reliable system looks like, according to a new study from nonprofit think tank Energy Innovation Policy & Technology. 

“Grid operators, reliability authorities and utilities are ringing reliability alarm bells, and outdated views on grid reliability are colliding with slow-moving institutions,” the report says. New concepts of reliability are needed so that “utilities and grid operators can build new generation faster and more efficiently, while simultaneously deploying strategic demand-side solutions at scale.” 

In opposition to President Donald Trump’s call to ensure reliability by building new fossil fuel-fired plants, Energy Innovation argues that “reliability is a characteristic of the whole electric system, to which individual resources contribute. Every source of electricity has different characteristics that should complement each other in a balanced portfolio.” 

Examples include the increasing number of grids around the world that provide reliable service with major amounts of solar, wind and storage online, it says. 

“For instance, large grids in the Midwest, Texas and California regularly operate using more than 70% renewable energy, and … Iowa and South Dakota generated roughly 60% of all their electricity in 2023 from wind power,” the report says. “In Hawaii, South Australia and Denmark, grids are already operating using 100% renewable power for days at a time. 

“Notably, though, these jurisdictions have adjusted their planning and operating practices to integrate higher penetrations of renewable energy and battery storage without compromising reliability.” 

The Energy Innovation report is intended to be a primer for U.S. regulators and policymakers to demystify the often-daunting technical details of “grounding reliability discussions in meaningful solutions … while also discussing the challenges in achieving a 100% clean electricity grid.” 

Caught between the high speed of data center buildout and the much slower regulatory speed of project permitting and interconnection, the industry is at “an inflection point where the pressures are growing,” Sara Baldwin, Energy Innovation’s senior director of electrification policy and co-author of the report, said in an interview with RTO Insider. “So, the lag that is created in slow decision-making is actually exacerbating the challenges. It’s creating more of an energy emergency. … Excuses are standing in the way. 

“We’re actually not confronting technical challenges as much as we’re confronting human challenges,” Baldwin said. “And in some ways, human challenges are harder because human beings want to have full control over all the decision-making that falls underneath their jurisdiction and in their purview.” 

An example is the traditional thinking about the need for system inertia, provided by spinning turbines and typically powered by fossil fuels or hydropower, often cited by industry leaders arguing for more baseload power. 

Specifically, they say, inertia can help to keep frequency levels on the grid stable in the event of stress on the system or disturbances caused by extreme weather. 

Report co-author Michelle Solomon, Energy Innovation’s manager for electricity policy, countered that “traditional inertia isn’t actually something that you need to run the grid. Traditional inertia is part of this broader frequency response set of services, and actually, in many cases, inverter-based resources can respond faster … and provide what’s called synthetic inertia.” 

Grid services provided by inverter-based and synchronous resources | Milligan Grid Solutions

The report notes that “while inertia slows frequency decline, it is not capable of restoring frequency back to its nominal level. Instead, services like fast frequency response, which can both slow the rate of frequency decline and help restore frequency are needed. … 

“Inverter-based resources (IBRs) can ramp up and down much more quickly than a conventional power plant, making them more responsive to changing grid conditions,” the report says. “IBRs can provide nearly instantaneous fast frequency response.” 

Can IBRs Deliver?

But the report also acknowledges that a significant gap exists between what IBRs are technically capable of doing and industry confidence in their ability to deliver when needed in real-life situations. 

“Developers must be disciplined to program their resources to ride through a voltage event [even] if such a setting should compromise their asset or their operating revenues,” the report says. Similarly, utilities and grid operators need to “quantify and understand how IBRs respond during a grid emergency” and ensure appropriate compensation in cases where they “provide a superior response.” 

For Mark Lauby, senior vice president and chief engineer at NERC, such recommendations contain a lot of “ifs” and potential threats to reliability. While he agreed that the future of the U.S. grid lies in a portfolio of diverse resources, including IBRs, “they haven’t been proven. We haven’t got a lot of them on the system.” 

New and traditional technologies have “got to work together, not against each other,” Lauby said in an interview with RTO Insider. 

“Batteries can move very quickly as long as they are charged … and inverter-based resources can mimic some of the things like inertia on the system, but they have got to be able to run on the battery,” he said. “The battery better be charged, and if you have long-term events, where you’ve kind of exhausted your battery storage, now you don’t have energy and, by the way, you don’t have essential livelihood services.” 

Lauby also said that while management of demand-side resources can be effective for shaving peak demand, which can be predicted and prepared for, stress on the grid is now coming at less predictable times and locations. 

IBRs could build more uncertainty into electric systems, on top of the essential variability of wind and solar, he said. For example, a dayslong drop in wind could take thousands of megawatts off the grid. 

NERC is working on a range of standards intended to build industry confidence in the reliability of IBRs and other new technologies, he said. 

Natural Gas Won’t

The Energy Innovation report comes at a pivotal moment in industry and public debates over the most effective short-term strategies for meeting data centers’ ravenous appetite for electricity, which could make up 12% of U.S. energy demand by 2028. (See Berkeley Lab: Data Centers Could Need 12% of US Power by 2028.) 

The Trump administration and congressional Republicans are advocating for regulatory changes to allow faster permitting, interconnection and construction of natural gas plants, which they are promoting as baseload power that will keep the lights on and cut consumers’ bills. 

For example, in a speech on the House floor Feb. 13, Rep. Julie Fedorchak (R-N.D.) announced her plans to form an AI and Energy Working Group that would target increasing baseload power on the grid. 

“The rapid, forced transition to intermittent power sources — paired with the retirement of reliable baseload generators — has left our electric grid increasingly vulnerable to outages,” Fedorchak said. 

On Feb. 11, FERC approved PJM’s Reliability Resource Initiative, a one-time measure aimed at adding extra capacity to the RTO’s system by allowing generation that meets certain criteria to essentially jump its notoriously backlogged interconnection queue. (See FERC Approves PJM’s One-time Fast-track Interconnection Process.) 

Renewable developers opposed the initiative, saying it is designed to allow large natural gas plants to get online ahead of the approximately 286 GW of projects, mostly wind, solar and storage, that have been waiting for years for PJM to work through its queue backlog. 

An illustrative example of grid services working together to stabilize frequency | Milligan Grid Solutions

On the other side, the Solar Energy Industries Association has been attempting to pivot the public dialogue on demand growth to include solar, storage and other renewables as “the fastest technologies to develop and deploy. Not only are they much simpler to engineer, their supply chains are more robust than natural gas (which currently faces a bottleneck in gas turbine blades),” SEIA said in a Feb. 4 blog post. Natural gas plants can also be 2.5 times more expensive to build, it said.  

The Energy Innovation report joins a recent study from Duke University in arguing for aggressive deployment of demand-side resources that can open up capacity on the grid versus inherently slow and costly fossil fuel generation. (See US Grid Has Flexible ‘Headroom’ for Data Center Demand Growth.)  

“While strategic new generation and transmission solutions are needed to meet growing demand, these large investments will show up on customers’ electric bills for decades to come and could increase emissions without helping affordability or sufficiently improving reliability,” the report says.  

“But aggressive investments in demand-side solutions are a cost-effective, least-regrets way to manage growth in the near term, while unlocking their full potential over the long term.” Similarly, getting solar, wind and storage online quickly will buy time for the development of dispatchable, zero-carbon generation that could replace fossil fuels, the report says. 

Pointing to the 2,600 GW of mostly renewable projects in RTO and ISO interconnection queues, Solomon said, “Because wind and solar and batteries are already in the process of being built, [they] can come online in a matter of a year and a half. … The gas plants they are looking at building are not coming online until 2030. Natural gas isn’t the solution that’s going to deliver.” 

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Ore. Senators Ask Trump to Justify ‘Reckless’ Job Cuts at BPA

Oregon Sens. Jeff Merkley and Ron Wyden have demanded the Trump administration explain and justify recent actions that could drastically cut staff at the Bonneville Power Administration and compromise the federal power agency’s ability to maintain grid reliability in the Pacific Northwest.

In a letter dated Feb. 14, the state’s two Democratic U.S. senators warned President Donald Trump that moves by his newly created Department of Government Efficiency (DOGE) could result in the “imminent departure” of 20% of BPA’s workforce and pose “a direct and immediate threat to the reliability of the electrical grid that serves millions of American families and businesses” in the region.

The 20% figure appears to have its origin in a Feb. 13 Oregon Public Broadcasting article that said BPA could see the firing of an additional 350 to 400 “probationary” employees on top of the 200 staffers who agreed to accept DOGE’s “deferred resignation” buyout offer made to the entire federal workforce last month. (See BPA Committed to Trump’s Energy Goals, Hairston Says.)

BPA staff were offered the buyout despite the fact that its operations are self-funded through its power sales, made primarily to the Northwest’s large number of publicly owned utilities that rely on the agency for low-cost power generated by the region’s extensive network of federally owned hydroelectric dams.

BPA also has rescinded 90 job offers following the federal hiring freeze Trump imposed after his inauguration Jan. 20.

“Employees on the ground are already warning that these actions will make it nearly impossible to strengthen and expand the grid as needed,” Merkley and Wyden wrote. “Instead, BPA will be forced into ‘damage control’ mode, struggling just to ‘keep the lights on.’ This is not speculation; it is the reality voiced by those who operate our energy infrastructure every day.”

The senators called the cuts “reckless” and “financially ludicrous,” particularly in light of BPA’s status as a self-funding entity.

“If the administration’s goal is truly to ensure reliable, secure, and affordable energy, then why are you actively dismantling the most effective and self-sustaining power system in the country?” they wrote.

The senators’ letter also demanded Trump answer a series of “critical” questions by Feb. 28, including:

    • How the administration can justify the cuts given BPA’s self-funding status.
    • How it plans to address operational and safety risks “posed by the loss of experienced linemen, engineers, and dispatchers” and avoid grid failures in the face of the expected growth in electricity demand stemming from new data centers.
    • Whether the administration will commit to lifting the hiring freeze on “mission-critical” positions at BPA that would prevent “de-stabilization” of the Northwest grid.

The letter also asks Trump to explain the role of DOGE in BPA’s staffing decisions and describe its “qualifications in managing complex energy infrastructure.”

Some of the senators’ questions overlap with those RTO Insider asked the U.S. Department of Energy last month upon learning that BPA staff had been among the federal workers offered buyouts. DOE has not responded to or acknowledged those questions. (See BPA Employees Confront Trump’s ‘Fork in the Road’.)

Politico on Feb. 17 reported that 30 “Department of Energy” employees who work on grid maintenance for BPA had been asked to return to their jobs after having been terminated.

BPA confirmed to RTO Insider that those employees are in fact BPA staff.

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NY PSC OKs Partial Implementation Plan on Energy Storage

New York’s Public Service Commission has approved an implementation plan to push for installation of 200 MW of residential energy storage and 1,500 MW of retail storage (18-E-0130).

These will make up part of the state’s 2030 goal of 6 GW of storage, which is equal to about 20% of the state’s present-day peak load. The remaining 4,300 MW is to come from bulk storage; the PSC continues to review the proposed bulk implementation plan.

The state has a way to go. As of April 2024, there was only about 400 MW of storage operational in New York. Nearly 600 MW was under contract but not yet online, and 300 MW was procured but not under contract. Construction of wind and utility-scale solar also is progressing slowly in New York.

Gov. Kathy Hochul (D) in January 2022 doubled the state’s 2030 storage target from 3 GW to 6 GW. The PSC approved the roadmap for reaching 6 GW in June 2024; the implementation plans will guide procurement efforts and set the stage for financial incentives to be allocated. (See NY Sets Strategy to Reach 6 GW of Energy Storage.)

The implementation plans are living documents, however.

They were prepared by the New York State Energy Research and Development Authority based on the June 2024 roadmap. In its approval Feb. 13, the PSC directed NYSERDA to make some modifications based on stakeholder feedback. Continued refinement may be necessary, the PSC noted, due to changes in market conditions, technology or other factors specific to retail and residential storage.

Fire safety is among those moving targets.

Battery energy storage system (BESS) fires are rare, but those that do occur have been very well publicized, with a noticeable effect on public opinion. This can become a significant hurdle to BESS development in a home-rule state like New York, where local governments have the ability to pause or block development of some energy infrastructure development.

After three unrelated BESS fires in rapid succession in 2023, New York state put together a task force that issued a series of recommendations to limit the likelihood of BESS fires. (See NY Fire Code Updates Recommended for BESS Facilities.) Those recommendations have been forwarded for consideration in the 2025 update of the New York State Uniform Fire Prevention and Building Code.

The PSC wrote in the order: “The commission directs NYSERDA to implement new fire safety requirements as necessary based on updates to the building code for fire safety, regarding energy storage systems.”

A significant buildout of energy storage is necessary if the state is to increase its reliance on intermittent renewables and decrease its use of fossil-fired energy generation, as it hopes.

PSC Chair Rory Christian noted this in a Feb. 13 news release, saying: “Energy storage is crucial as New York works to decarbonize our electric grid, manage increased energy loads, and optimize the integration and use of clean, renewable energy. Today’s decision moves forward our landmark energy storage program.”

The cost to ratepayers is unknown, again because of unknowable future energy market fluctuations.

An analysis performed as the roadmap was prepared in 2024 estimated the cost of subsidies for the 6 GW buildout at $1.3 billion to $2 billion; $200 million already had been allocated as of April 2024.

The analysis further estimated that $2 billion worth of grid upgrades could be avoided if 6 GW of storage capacity were online, and that additional benefits would accrue to society through such things as cleaner air and reduced health care costs.

New York claims its storage goal is the nation’s most ambitious, but that distinction is diminished by the fact that California and Texas already are far beyond the 6 GW the Empire State hopes to achieve by 2030. S&P Global reports that as of the second quarter of 2024, California had 10.3 GW online and Texas had 7.7 GW.