The Massachusetts Department of Public Utilities has directed the state’s gas distribution companies to revise their line extension policies and require new customers to cover the cost of new hookups, with limited exceptions.
Issued on Aug. 8, the order is poised to end the longstanding utility practice of charging to the rate base the costs of connecting new gas customers. The practice assumes the new customers eventually will pay back these costs through distribution fees (20-80-E).
The ruling likely will significantly increase the upfront costs associated with new natural gas hookups in the state and reflects the DPU’s increased focus on phasing out natural gas use for heating. In 2023, the DPU required the utilities to consider gas alternatives, and in 2024 state lawmakers required the department to consider the state’s emissions limits and risks of stranded assets when authorizing requests for gas system expansion.
The DPU first proposed the change in February, expressing concern that existing line extension policies are misaligned with the state’s efforts to decarbonize and do not account for risks of stranded assets as customers transition to electric heat pumps. (See Mass. DPU Proposes Major Shift in Gas Line Extension Policies.)
The proposal was supported in comments submitted by climate advocacy groups, the Department of Energy Resources and the Massachusetts Attorney General’s Office. Investor-owned gas utilities pushed back, arguing that ending line extension allowances may push some customers to higher-emitting heating methods like oil and propane.
In its ruling Aug. 8, the DPU agreed with the AGO that the gas utilities assume “unrealistically long” payback periods for new customers and do not account for declining gas usage because of decarbonization.
The DPU also wrote that the gas companies’ existing formulas for calculating upfront payments for new customers fail to account for “the environmental impact of the additional gas combustion facilitated by the expansion of the gas distribution system through line extensions.”
The department rejected arguments that the policy change will push customers toward fuel oil or propane heating systems, writing that “no evidence is offered to suggest that such a situation is anything more than a rare or isolated circumstance.”
Responding to utility concerns about cost barriers to electrification, the DPU referenced a 2024 report sponsored by environmental groups that found all-electric new construction has reached near-cost parity with fossil construction. (See Report Outlines Cost Savings of All-electric Buildings in Mass.)
“It is a better course of action to address in other proceedings the claimed barriers to electrification than to maintain a line extension policy that locks in continued growth in the natural gas distribution system that is contrary both to the commonwealth’s climate goals and to the minimization of potentially stranded costs,” the DPU added.
The department stressed that the policy change does not deny customers the ability to connect to the gas network but requires customers to assume the costs and stranded-asset risks associated with these connections.
“Eliminating line extension allowances neither incentivizes nor disincentivizes new gas extensions,” the DPU wrote, citing AGO testimony that the change “only removes an unwarranted incentive.”
Under the proposal, the department would allow utilities to socialize the costs of new gas connections only if a customer “can demonstrate that it has no technically feasible alternative to the use of natural gas, including electrification.”
The DPU wrote that exceptions likely will be limited to “hard-to-electrify” commercial and industrial customers. It said gas utilities will be responsible for demonstrating the need for any exception.
The department required the utilities to file revisions within 30 days in the dockets for their climate compliance plans (CCPs). It noted that stakeholders will have the opportunity to file briefs and evidence within the CCP dockets on the DPU’s revised proposal and the utilities’ compliance proposals (25-40 through 25-45).
“This order is another great step in the right direction toward an orderly transition off of the natural gas system,” said Kyle Murray, Massachusetts program director at the Acadia Center. “It also shows that the natural gas system has traditionally only been able to expand thanks to massive subsidies from existing ratepayers. This order is simply removing that subsidy and requiring natural gas to compete on an even playing field.”
Stakeholders requested that the NYISO Market Monitoring Unit provide a comprehensive explanation of the difficulties in obtaining data from the ISO and market participants on supplemental commitments after it presented its State of the Market report for the first quarter Aug. 5.
Supplemental commitments to satisfy reserve requirements occurred on 75 days in the first quarter in the North Country load pocket — near the border with Canada — and 28 days in New York City load pockets, according to the MMU’s presentation to the Installed Capacity Working Group. Nearly half of these commitments could not be verified by the MMU.
“These are instances where we weren’t able to get information to substantiate the need for the commitment,” said Pallas LeeVanSchaick, vice president of Potomac Economics.
A supplemental commitment is an out-of-market action in which a generator is not committed economically in the day-ahead market but is needed for reliability. Transmission owners and NYISO operators may dispatch generators “out of merit order” to maintain lower-voltage reliability and manage constraints in high-voltage transmission that are not represented in the market model.
Stakeholders pointed out that this was a repeat issue for the MMU and asked whether there was a provision in the tariff or a technical issue that was preventing the MMU from obtaining the information. LeeVanSchaick said the data from the ISO are not detailed enough to make a determination in all cases.
Stakeholders also asked whether the MMU was able to ask transmission owners and generators for information. LeeVanSchaick said that while it can ask any market participant for information, the kind of information is different depending on what kind of participant it is.
“I don’t think it’s a matter of asking the MMU to identify who the bad guy is, so much as … providing more information about the … different rules and responsibilities for information requested from generators, the NYISO, TOs and other parties,” a stakeholder who did not identify themselves said. “Understanding that at a general level could show what the barrier to receiving information might be.”
Competitive and Congested
The NYISO markets otherwise performed competitively, the MMU said. Prices in each region were up year-over-year this quarter, ranging from 59 to 119%, mostly driven by higher natural gas prices, which rose 67% in Western New York and 188% along the border with Vermont. LeeVanSchaick said that this was from the extremely cold weather in January and February.
Load levels were higher across the state compared to 2024. The average daily load increased 4.5%, and the peak load increased by 3.4%. At the same time, congestion rose within the state and across the PJM-NYISO interface. This was partially because of transmission outages in New York but also from high demand.
Thirty percent of the congestion occurred in New York City, increasing 450% year over year. The Gowanus-Greenwood line was out of service throughout the quarter, and a parallel line was out of service in February.
Many generators were curtailed or out of service. During the coldest part of January, roughly 1.75 GW of oil generation was out of service because of planned outages. “As NYISO implements firm-fuel capacity accreditation in 2026/27 and designs a seasonal capacity market, it will be important to consider reasonable limits on planned outage scheduling under peak conditions and incentives for availability,” the MMU said.
NYISO and local TOs issued 28 GWh of wind curtailments manually because of unmodeled transmission constraints or generators not responding to economic curtailment instructions. The MMU found that TO-controlled communication equipment was not maintained well enough to send signals from NYISO to the control centers of many wind plants. It suggested implementing stronger penalties for failure to comply with curtailment instructions.
SPP’s Board of Directors has agreed to defer action on a 765-kV transmission project with a ballooning cost estimate and on staff’s large load integration policy, both the source of much stakeholder discussion.
The 765-kV project, the first in SPP history, was awarded to Southwestern Public Service in February with an estimated cost of $1.69 billion. SPS filed a revised cost estimate of $3.62 billion in June, more than double the earlier projection and easily outside the variance bandwidth of +/‑30% that can lead to a re-evaluation.
However, SPP said the 765-kV project remains “the most cost-effective and strategically sound option” to address Eastern New Mexico’s “critical needs.” The grid operator has seen a 32% increase in summer peak load for the 2023 and 2024 transmission planning assessments, driven by rapid electrification of the oil and gas industry. It said “significant” growth is continuing into the 2025 and 2026 assessments.
The board deferred a decision on the project during its Aug. 5 quarterly meeting until it meets again in November, at the latest.
The directors also delayed action on SPP’s proposed large load integration policy, agreeing to wait until after a special Markets and Operations Policy Committee call Aug. 21. That will allow for additional stakeholder input and technical review. The board plans to hold a joint meeting with state regulators less than two weeks after the MOPC call to discuss the issue further. Both bodies will vote on the proposal during their October and November quarterly meetings.
MOPC rejected the proposal during its July meeting, giving it only 53.7% approval. (See “Members Shoot down Staff’s Proposal for Integrating High-impact Large Loads,” SPP MOPC Briefs: July 15-16, 2025.)
SPP says high-impact large loads (HILLs), generally defined as anything equal to or larger than 50 MW, are investments requiring short-term costs to integrate and operate that are balanced with long-term benefits (jobs and revenue). The proposal would complete system impact studies within 90 days for the load and its supporting generation together, leading into the normal firm-service interconnection queue. Study costs would be directly assigned to the cost-causers (the requesting transmission customer), staff said.
SPS 765-kV Project Deferred
The RTO gave the Potter County-Crossroads-Phantom project a notification to construct with conditions (NTC-C); SPS could not order materials or begin construction until it provided a refined project estimate within the study’s variance bandwidth.
The company’s engineers revised the line costs from about $4.2 million/mile to $5.9 million/mile, comparable to what MISO and ERCOT are projecting in their 765-kV projects. They also increased SPP’s original estimate of 244 miles for the project’s two legs to 354 miles to account for their actual paths. The modifications accounted for more than $661 million of the increased cost estimate.
Reactor costs also increased $180 million between the two estimates, SPS said. It will incur additional expenses for two new 765/345-kV substations, necessitating three additional 20-mile 345-kV line segments, because of “land challenges.”
SPS’ Jarred Cooley, the utility’s director of strategic planning, told the board and stakeholders that the 765-kV lines’ right of way of up to 250 feet forced it to “skirt around” communities, oil and gas infrastructure, irrigation systems, archeological sites and environmental species habitats, such as the endangered lesser prairie-chicken.
“This is something that we, as an entire company, are digging into deeply across multiple fronts,” Cooley said during SPP’s joint stakeholder briefing Aug. 4. “We’ve spent a lot of time on this. We definitely understand the sticker shock of the comparison between the initial SPP estimates and what SPS is providing today.”
American Electric Power’s Stacey Burbure, vice president of FERC and RTO policy and strategy, said SPS’ cost estimates are in line “across the board” with what her company is seeing. AEP has been awarded one of three 765-kV projects in ERCOT and owns 2,110 miles of 765-kV transmission, more than any other transmission company in North America.
“When I think about why we are here, it’s because the initial cost estimate is wrong,” she said.
“There’s a need for improvement,” Oklahoma Municipal Power Authority’s Dave Osburn said, “but when I looked at what the future projections and the load increases that are being projected, I’m not sure how we can really efficiently do that without 765.
“Yes, they are more expensive than others, but there’s a lot of other benefits that come with the 765 overlay,” he added. “As we go through this particular project, let’s learn from this, and let’s figure out the true cost of building out the 765, because I do think it’s something we’re going to have to be addressing going forward.”
As a short-term reliability project, Potter County-Crossroads-Phantom is not eligible for the competitive process. It currently has an in-service date of 2031.
“Back in February when we addressed short-term reliability projects, I raised concerns about this particular project because it was so large. Now that the costs are more than double, my concerns are intensified, but I’m very sensitive to the fact that this is a reliability project,” Director Irene Dimitry said. Alluding to the in-service date, she added, “The solution that has been identified for this near-term need is not a near-term solution.”
Dimitry said she wanted to see more time taken to find the right balance between reliability and affordability by considering competitively bidding the project. She offered a motion that would rescind the board’s prior approval of the project and direct staff to facilitate an expedited competitive selection process. Dimitry, who has been tasked with assembling a task force to refine SPP’s competitive selection process, suggested a recommendation be made to the board at its May 2026 meeting.
The motion failed both the Members Committee’s advisory vote (7-8, with seven abstentions) and the board’s vote. SPP does not disclose the board’s vote beyond “pass” or “fail.”
SPS President Adrian Rodriguez defended the project’s reliability status, saying that had it been in place in March, the utility would not have had to drop 122 MW of load for almost three hours. He welcomed the board’s attention, saying, “We need to get this right.” (See SPP Addresses 3rd Load Shed Since March 31.)
“The scrutiny is justified, and we’re committed to being part of our early engagement in assessing costs with the SPP staff and bringing this before the board,” he told directors. “It’s clear that the costs, I acknowledge, are different from the original estimate, but that comes with validation of uses. We’re excited about setting a strong precedent.”
Rodriguez promised SPS would continue to update the board and work with staff before November. He said the company has focused on keeping costs as low as possible, from competitively procuring engineering and construction services to holding slots for equipment in an uncertain supply chain.
Any further delays would only increase the project’s costs, Rodriguez said.
“The tradeoff that we’re always sensitive to is, in this case, delayed dollars. Every day that passes, these costs can increase,” he said. “I am very sensitive to moving quickly … but very concerned about any type of lengthy delay that could result in increased costs” for major transmission and distribution supplies.
“What I don’t want to do is to have a self-fulfilling prophecy that we come a couple of months later [and] there are some cost increases because of the additional delays, and then we are back in the same boat,” Rodriguez added. “At the end of the day, ultimately, it’s our customers that are impacted.”
Members agreed there’s a need to address how large loads are added to the system but raised concerns about maintaining reliability, cost-allocation equity and transparency. Views differed on how to balance speed with planning thoroughness; how to define qualifying load types; and whether existing processes could be adapted or new pathways were needed.
The discussions have continued since then. COO Antoine Lucas surveyed the audience for the board meeting and said he could see stakeholders he has had phone conversations with in recent weeks as he worked to “try to get people comfortable as quickly as we could,” he said.
He argued that the policy will help SPP integrate the large loads and their high impact.
“The high-impact portion of it is really based on our assessment that these loads have the ability to materially impact the reliable operations of the system,” he said. “For that reason, we felt that there was a need for pretty detailed and enhanced policy proposals to ensure that we were able to identify what those differences were and some of the risks that those posed.”
Lucas said staff will continue to engage with stakeholders until an MOPC call Aug. 21. The joint board and Regional State Committee meeting that follows will give staff additional input in bringing back the policy to the October and November meetings.
Based on the feedback already received, Lucas said SPP will focus on just two of the policy’s three paths: HILLs and high-impact large load generation interconnection assessments (HILLGAs). The latter are generation and load studied on the fast track and pairing generation with a HILL or a conditional HILL (CHILL).
Lucas proposed that SPP continue to work on CHILLs, which has received most stakeholder questions. These loads would be interconnected to the grid quickly but would be expected to transition to firm service within five years.
“We would have a little more time to work through that with stakeholders and make sure that they’re all comfortable with that,” Lucas said. “We think we have a pretty good product at the end of the day to make the SPP region more attractive for entities who are looking to … connect large loads.”
Board Vice Chair Ray Hepper, leading the meeting in place of Chair John Cupparo, reminded the board and stakeholders that it was an “executive order” from the chair in May that asked for staff to return in August with a large load integration policy.
“Not only did they bring us a proposal, they brought us tariff language; that is an incredible accomplishment,” Hepper said, not mentioning that the proposal is about 500 pages long. “Everybody agrees we need to move quickly. We don’t want to slow this proposal down, but a little more time is helpful. This is an important initiative for lots of the [load-responsible entities], and it’s important for lots of the states.”
FERC has approved an SPP tariff change that allows interconnection customers without a pending request to ask for interim service when the study cluster’s window is closed (ER25-2476).
In its Aug. 7 letter order, the commission found that SPP’s proposal would meet the agency’s independent entity variation standard, used to evaluate deviations from the pro forma large generator interconnection procedures and agreements established under FERC Order 845. The standard is designed to allow IC customers to obtain interim service sooner than otherwise would be possible.
FERC said the proposed tariff revisions “will provide additional flexibility” for interconnection customers by allowing them to submit requests that would enable a timelier IC service.
“Absent SPP’s proposed tariff revisions, interconnection customers without a pending interconnection request would not be able to request interim interconnection service until the next [study] cluster window, which could occur as late as April 1, 2026, potentially delaying the connection of needed generation,” the commission said.
The tariff revision also maintains existing financial and study requirements for an interim IC, FERC said. It noted the proposal includes limits such as requiring customers to submit a request in the next open study cluster window or have their interim GIA terminated, ensuring that a customer can’t have interim service indefinitely.
SPP submitted its proposal in June, saying that revisions to its definitive integration system impact study (DISIS) process will allow customers to ask for interim IC service on the condition it submits requests to the DISIS queue during the next open cluster window. Customers with pending requests also will be required to maintain that request for its interim service to remain valid.
The PJM Board of Managers has initiated a Critical Issue Fast Path process aimed at maintaining resource adequacy in the face of rising data center load growth, asking stakeholders to draft proposals to serve 32 GW of load growth expected by 2030.
“Recent increases in large load additions, mainly from data centers, present both opportunities and challenges for the regional grid,” the board wrote in an Aug. 8 letter announcing the initiation of the CIFP process. “PJM’s location, size, market opportunities and system reliability make it an attractive area for large load customers to locate, and we continue to see significant load interconnection activity at several of our utilities.” The board cited PJM’s 2025 load forecast, which estimates the system’s peak load will grow by 32 GW between 2024 and 2030, with 30 GW of that being attributed to data centers.
The letter identifies five areas for stakeholders to focus on: resource adequacy; reliability criteria for triggering any solutions with a temporary nature; changes to interconnection rules that may support resource adequacy; coordination between PJM, those party to large load contracts, member states and impacted customers; and a timeline for implementing solutions for the 2028/29 Base Residual Auction (BRA). The letter states the process will inform the contours of a proposal the board intends to file at FERC in December 2025. The process will begin with a pre-CIFP workshop Aug. 18.
The letter raises the possibility of adjusting the load used or cleared in BRAs if it’s not capacity-backed. It also encouraged improvements to existing resource adequacy tools, such as demand response or the ability for load to bring its own generation. Solutions also are encouraged to be market-based and could be either permanent, transitional or a combination of the two.
Changes to the rules for resource interconnections could allow new entries to meet some of the expected load growth. The board’s letter states that the 2022 shift to a cluster-based process for studying new service requests and allocating network upgrade costs has cleared more than 140 GW of resources in the queue, 46 GW of which have entered interconnection agreements with the RTO. The remaining queued resources are expected to be processed over the next 18 months. An additional 11 GW was added through the Reliability Resource Initiative.
Despite faster completion of interconnection studies, the board wrote that many of those projects have run into siting, permitting and supply chain challenges inhibiting their ability to enter commercial service.
This is the second CIFP focused on resource adequacy and capacity market design the RTO has initiated in recent years, with a February 2023 letter opening a process to address unrecognized reliability risks and the impact that “significant load growth” paired with generation deactivations outpacing new entry could have on “a healthy reserve margin.”
Another CIFP process was conducted in June 2025 to determine how to allocate the cost of keeping Constellation Energy’s two gas-fired units at the Eddystone Generating Station online under a Department of Energy emergency order. (See PJM Board Initiates CIFP Process for Eddystone Compensation.)
In the Aug. 8 letter, the board said a poll of stakeholder priorities found support for addressing the reliability risks posed by large loads in particular. The results were presented at the July 2025 Members Committee meeting. (See “PJM Presents Capacity Market Feedback Poll,” PJM MRC/MC Briefs: July 23, 2025.)
“A recent survey of PJM members and stakeholders reflected growing consensus that finding solutions to the potential resource adequacy challenges posed by rapidly interconnecting large loads should be one of PJM’s highest priorities,” the board wrote.
Board Overrides Stakeholder Rejection of Auction Parameters, Directs Hiring of Consultant
The board also has opened a process to explore changes to how PJM calculates the installed reserve margin (IRM) and forecast pool requirement (FPR), key parameters for determining the amount of supply that will be procured in capacity auctions. The Members Committee rejected staff’s recommended values for the 2027/28 BRA during its July 23 meeting, with stakeholders arguing the effective load-carrying capability (ELCC) modeling that serves as an input to the calculation lacks transparency. It also took issue with the endorsement being requested on the same day as the first read. (See PJM Stakeholders Reject 2027/28 Capacity Auction Parameters.)
In an Aug. 4 letter, the board nonetheless approved the parameters and directed staff to continue working with stakeholders in the ELCC Senior Task Force to draft changes to the model that could be implemented for the 2028/29 BRA. That work will be bolstered by a consultant the RTO will bring on to “identify additional recommended enhancements to discuss at the ELCCSTF or other similarly focused stakeholder group(s) for implementation after the 2028/29 BRA.” The letter also calls for a detailed description of the ELCC model to be published.
“Although the member vote is advisory, the PJM board discussed potential options for reengaging the stakeholders on this matter; however, the PJM board reflected on stakeholder feedback, including the short timeline, and is concerned about the possibility of auction delay for the 2027/2028 BRA,” the board wrote.
“Implementation of an alternative methodology to calculate the IRM and FPR would follow additional stakeholder discussion, a vote, an approved filing with the FERC, a recalculation of the IRM and FPR and a restart of the calculation of all other auction parameters currently being determined under the existing rules. This path would inevitably result in a delay of the auction, creating uncertainty in our marketplace during a period where we are in need of new supply,” the board wrote.
The approved parameters increase the IRM to 20%, up from 19.1% in the auction prior, while the FPR would increase from 0.9170 to 0.9260, effectively increasing the reserve margin and amount of capacity the RTO would aim to procure in the 2027/28 auction.
The Massachusetts Department of Energy Resources (DOER) and the state’s investor-owned electric utilities have issued a request for proposals to procure up to 1,500 MW of mid-duration energy storage, a key step toward the state’s goal of contracting 5,000 MW of energy storage by mid-2030. The procurement marks the largest energy storage solicitation issued to date in New England.
The state also outlined its expected timeline for future storage solicitations, noting that it plans to issue additional 1,000-MW mid-duration storage procurements by July 31, 2026, and July 31, 2027, and wrote that “all remaining energy storage systems capacity shall be procured by July 31, 2030.”
The Massachusetts Legislature in 2024 passed a law requiring electric distribution companies to enter long-term contracts for 5,000 MW of energy storage by mid-2030, including 3,500 MW of mid-duration storage (between four and 10 hours), 750 MW of long-duration storage (between 10 and 24 hours) and 750 MW of multi-day storage (greater than 24 hours).
The RFP is intended to procure projects “that have a strong likelihood of being financed and constructed and that will provide a reliable and cost-effective source of beneficial, reliable energy storage systems to the Commonwealth,” the DOER and the utilities wrote.
In the first solicitation, the state seeks only to procure the environmental attributes associated with storage projects. This includes credits for the state’s Clean Peak Standard, which incentivizes emissions reductions during peak demand periods.
The bid submission deadline is noon on Sept. 10, 2025. Bidders are allowed to propose projects at or above 69 kV that can supply between 40 and 1,000 MW and can propose long-term contracts running through the end of 2050.
The RFP requires projects to have a scheduled in-service date earlier than Jan. 1, 2030, and directs each bidder to “demonstrate that its proposal can be developed, permitted, financed and constructed within a commercially reasonable timeframe.”
Projects must commit to achieving capacity interconnection rights and qualifying for the ISO-NE capacity market. The RFP requires bidders to “include a realistic and specific plan to implement any transmission system upgrades or other work anticipated to be needed to achieve CCIS-equivalent interconnection.”
Developers also must provide a nonrefundable bid fee of $500/MW of proposed nameplate capacity, which is intended to cover the cost of evaluation.
Projects will be evaluated based on quantitative and qualitative criteria. They will be graded on a 100-point scale, with 80 points for direct and indirect costs to ratepayers and 20 points for qualitative factors, including project viability, climate and environmental benefits, grid reliability and resilience effects, and stakeholder engagement.
The DOER, working with an independent evaluator, will select winning bids. The utilities will be responsible for executing contracts, which will be subject to the approval of the Massachusetts Department of Public Utilities (DPU).
The DPU approved the procurement framework in late July, writing that it “represents a reasonable balancing of interests and demonstrates progress toward achieving the Commonwealth’s statutory energy storage systems requirement as well as seeking to contract for low-cost energy storage systems.”
Under the current solicitation timeline, winning bids are to be selected by Dec. 9, and long-term contracts are set to be executed by March 27, 2026.
The D.C. Circuit Court of Appeals has remanded to FERC an order rejecting a mitigation plan LG&E and KU Energy filed to replace its longstanding obligation to de-pancake rates for wholesale customers (23-1196).
The court ruled Aug. 8 that FERC did not adequately consider whether the utility’s transition mechanism provided ratepayers protection from the removal of the rate schedule the utility instituted in 2006 when it left MISO. Schedule 402 ensured customers would not pay duplicate rates across its territory after Louisville Gas & Electric and Kentucky Utilities merged in 1998 while also reimbursing them for MISO’s charges because the grid operator did not agree to reciprocally de-pancake its own rates.
After more than a decade of using Schedule 402, the company asked FERC to end its obligation, which the commission did in 2019, on the condition the utility institute a transition mechanism. But the commission reversed itself on remand from the D.C. Circuit in 2023 and directed the utility to reinstitute 402. (See FERC Upholds De-pancaking Provisions in LG&E/KU Rates.)
In its decision, FERC declined to use the pre-merger status quo — which would have rates pancaked between MISO, LG&E and KU — as a point of reference. The utility argued that FERC should have used that as a baseline and that its retail customers were picking up the costs of de-pancaking rates with MISO for wholesale customers. The utility also proposed a transition mechanism that would have continued de-pancaking some rates for wholesale customers for decades, which it argued would fully mitigate any impact on wholesale rates.
“We are not satisfied that the commission adequately addressed this important issue: that the transition mechanism agreements would have protected each customer with a reliance interest, thereby mitigating any concern that customers continue to need Schedule 402 to protect their reliance interests,” the court said. “In fact, during oral argument, counsel for FERC suggested that the transition mechanism agreements could be a potential protection offered to mitigate or end the need for de-pancaking.”
Eighteen municipal customers benefit from the de-pancaking, and 12 of them would be covered by the transition mechanism or some other agreement. The other six do not take service from MISO.
FERC needs to consider whether the transition mechanism is enough to get rid of Schedule 402, the court ruled.
“We do not make that determination for the commission but simply remand the case back to the commission so that it can weigh the evidence and determine whether the transition mechanism agreements would adequately protect ratepayers,” the court said.
New Jersey faces tough decisions on how to balance the risk of blackouts against the cost of reducing their frequency, speakers said at a resource adequacy forum organized by the state Board of Public Utilities.
Any plan to combat the expected surge in demand from data centers, they said, likely will be fraught with uncertainty because the emerging situation is unprecedented.
Possible strategies mentioned at the Aug. 5 forum include asking data centers to curb their use at high-demand moments, enhancing energy efficiency strategies, going outside of PJM for power and better coordinating distributed energy resources and storage.
In each case, a proper allocation of costs and a benefit-cost analysis will be critical, speakers said at the forum, conducted at The College of New Jersey in Ewing, N.J. The challenge is multiplied by the sheer size of the problem.
“The loads are very difficult to plan for, and they appear very, very quickly,” said Tim Gallagher, CEO of ReliabilityFirst. “These things bring very unique and significant challenges to both the planning and the operation of the bulk power system.”
Higher Prices Needed
The conference came two weeks after PJM revealed that prices at its July capacity auction soared to $329.17/MW-day (UCAP) RTO-wide for delivery year 2026/27. Prices in the 2024 auction jumped to $269.92/MW-day, the result of load growth, generation deactivations and changes to risk modeling that shrank reserve margins. (See PJM Capacity Prices Hit $329/MW-day Price Cap.)
While New Jersey officials have voiced outrage at the auction prices, and a 20% hike in the average electricity bill, the prices still don’t stimulate new generation development, warned Richard Levitan, president of Levitan and Associates, an energy management consulting firm.
“We have to be realistic about clearing prices continuing to ascend in order to get price signals to developers for new build,” he said. “We could be looking at price signals that are much, much higher, closer to $700 per MW-day.”
Acceptable Power Loss Level
Paul Youchak, of the BPU’s office of federal and regional policy, said PJM sets its reliability levels at the commonly held standard of “1-in-10,” meaning only one event every 10 years in which the RTO could not meet demand for at least 24 hours.
States that want to lower that risk can invest more in new generation, pushing up costs, he said. He questioned whether “reliability and affordability today … are diverging in a way that hasn’t diverged before?”
PJM demand curve | NJ BPU
Gallagher explained that at present, “ratepayers emphasize costs more than reliability,” in large part because “we’ve enjoyed 99.9% reliability for most of our lives.” If the state continues on the current path as demand rises, “reliability starts to suffer,” he said.
That may trigger calls for a new standard, he said, adding that NERC is moving toward a new standard of “energy adequacy, which is actually studying every hour of the year to make sure you have enough electricity for every one of those hours.”
Unified Load Forecast
Whatever standard is in place, the state faces a difficult challenge predicting future load.
Youchak emphasized how suddenly the demand picture has changed. In 2023, he said, PJM predicted that by 2038 the region would have load of about 165,000 MW. By 2025, the RTO predicted the 2038 load would be around 220,000 MW, an increase of more than one-third.
“It is an order of magnitude difference from the type of volatility we’ve seen in the past,” Youchak said.
New Jersey, with 100 data centers at present, ranks only 15th in the nation, Gallagher said. And they typically aren’t the kind of heavy-load artificial intelligence facilities that present the biggest challenges, he said. Instead, New Jersey data centers work to “support government services, public health systems, emergency and disaster response” and other functions, he said.
But because New Jersey is an energy importer, it will be impacted by the arrival of big data centers elsewhere in the RTO region, and “must plan for this rise in demand,” said Margarita Patria, a principal of Charles River Associates.
“What’s needed is a clear understanding of data center load trajectory going forward,” she said. “We need a unified approach in assessing data central load and move to perhaps probability-based forecasting tools that more accurately reflect the state of affairs and will enable more informed decision making.”
Yet the unique element of hyperscalers, the largest data centers, makes that difficult, said Tom Rutigliano, senior climate advocate for Natural Resources Defense Council.
Traditional statistical methods of basing predictions on past performance have difficulty accounting for the dramatic influx of data sector loads that have no precedent, he and other speakers said. And forecasts may include data center projects that may never come to fruition, speakers said.
Andrew Gledhill, senior analyst for resource adequacy planning at PJM, said the organization is working on “implementation guidelines, talking about the key criteria” that should be included in forecasts, such as “the uncertainty of data center development when you start looking at five to 10 years.”
One way to address that is to produce “accuracy metrics on these projections,” including after-the-fact scrutiny of data center forecasts to determine “what came to fruition, how did the numbers match up with what they were expecting at the time?” Gledhill said.
The shifting demand profile of the region has added to the importance of getting the forecasts correct. Part of the challenge is that the highest peaks are now in the winter. A loss of power can plunge residents into darkness and cold and create much more severe consequences than in the past, when summer peaks dominated and the main impact was loss of air conditioning.
New Jersey load forecasts | NJ BPU
“If we don’t have electricity for a sufficient period of time today, people actually die,” Gallagher said, citing the dozens of deaths that occurred during power loss triggered by the severe winter storm in December 2022.
In addition, peaks triggered by data centers are more sustained, and so more challenging to handle than the relatively brief demand surges resulting from a cold spell or a heat wave, Gledhill said. Of the 32 GW of demand increase expected in the PJM region by 2030, 30 GW will come from data centers, he said.
“That’s generally flat load,” he said. “So the load profile, as we move into time, is getting flatter and flatter, which means that there’s going to be more hours of risk that pop up.”
Managing Demand
Sam Newell, principal with the Brattle Group, said the state should “foster energy efficiency demand response programs,” essentially asking users at a “mass market level” to reduce their load at peak times. The state, for example, can set up virtual power plants to manage a network of distributed energy resources, such as solar panels, batteries and electric vehicles, to handle load at peak moments.
Speakers also suggested that big energy users be asked to cut energy use when the overall load gets heavy. But big data centers are reluctant to take that step, in part because “it’s difficult for them to predict when an AI-related data center is going to go into learning mode, and that’s when their electric demand ramps up significantly,” he said.
In addition, Newell said, “a lot of the data centers are not hyperscalers. But they might have 400 to 600 tenants in the data center, and it’s difficult for them to pick exactly which ones of those tenants” should take part in demand-response load cuts, he said.
One audience member asked if New Jersey should continue the current level of subsidies for solar when the availability factor — the percentage of its full name plate capacity that it can generate electricity — for solar is only about 11%, due to the limited time in which panels generate electricity. In contrast, PJM rates a nuclear generator at 93%, offshore wind at 69% and a gas combustion turbine at 60%.
Rutigliano said the benefit of solar is it’s cheap and clean. But he acknowledged that “it doesn’t give you a lot of reliability value.”
“I’ll confess, NRDC’s modeling says that the most cost-effective way to a low-carbon grid is a fossil fleet that’s around the same size as what we have now; it just doesn’t run very often,” he said. “Since the reliability or research adequacy issue is the clear and present one, subsidies now in PJM should be flowing to storage, to wind. Offshore wind actually brings more value than a combustion turbine.”
In a surprise move, President Donald Trump will tap Democratic Commissioner David Rosner to become FERC chair, multiple news outlets have reported.
Axios first reported the development Aug. 8, citing an unnamed White House official as the source, with the story also being picked up by Bloomberg.
Rosner, a FERC staffer who had been detailed as an aide to the Senate Energy and Natural Resources Committee under the leadership of former Sen. Joe Manchin (I-W.V.), was appointed to the commission in 2024 by President Joe Biden to fill the seat left by former Chair Richard Glick — whose renomination was quashed by Manchin.
The Senate approved Rosner’s appointment on a vote of 67-27, with most opposition coming from Republicans. He also lost backing from Sens. Ed Markey (D-Mass.), Bernie Sanders (I-Vt.) and Elizabeth Warren (D-Mass.) and was opposed by environmental group Friends of the Earth. (See Rosner, See Clear Senate to Fill out FERC.)
“David Rosner was a paid cheerleader for the LNG boom before it was fashionable,” Lukas Ross, climate and energy deputy director at Friends of the Earth, said at the time of Rosner’s nomination. “Letting Joe Manchin control FERC from beyond his political grave should be a nonstarter for every other Democrat in the caucus.”
In addition to supporting fossil fuels, the Trump administration also favors co-location of data center loads with nuclear power plants.
“David Rosner has committed to executing President Trump’s America First energy policy agenda,” Axios quoted the White House official as saying.
The official also told the publication that Rosner has been “instrumental” in working to “accelerate the building of power data centers to win the AI race” and that the choice “emphasized the president’s desire to work with action-oriented people who will deliver positive results for Americans.”
In June, President Trump nominated Laura Swett of Vinson & Elkins to replace Christie, a development Christie said he learned about through a media inquiry about his replacement. (See Trump Replacing FERC Chair Christie with Laura Swett.)
While commissioners appointed by Democrats currently control FERC 2-1, Senate confirmation of nominees Swett and David LaCerte would put Republican appointees in the majority, possibly putting the chairmanship back in play. (See LaCerte Nominated to Complete Phillips’ Term at FERC.)
Meantime, power industry stakeholders and watchers are sure to speculate about the motives behind Rosner’s appointment.
Posting on X late Aug. 8, former FERC Chair Neil Chatterjee wrote:
“Theory — the WH is doubling down on data center co-location and is looking to seat a @ferc majority that will support a framework moving forward. Christie was an outstanding Chair. See has been a conservative commissioner… but they both voted against Talen-AWS. My best guess.”
Chatterjee was referring to the commission’s rejection last November of a proposed amendment to Talen Energy’s interconnection service agreement with PJM and utility PPL that would have allowed Amazon Web Services to expand its co-located load at its Susquehanna nuclear plant in Pennsylvania. (See FERC Rejects Expansion of Co-located Data Center at Susquehanna Nuclear Plant.)
FERC Chair Mark Christie officially stepped down at the close of business Aug. 8, leaving the commission with a quorum of three until the Senate considers two pending nominees from President Donald Trump.
He posted his last letter outlining FERC’s work over the previous week, which he started writing after Elon Musk emailed all federal employees asking them to send emails doing the same in February.
On Aug. 7, Christie posted on Musk’s social media site X that he had filed his last dissent as a FERC commissioner, in which he sided against the majority who partially granted a complaint Savion filed against PJM (EL25-63).
In the order, the majority sided with Savion, which argued it should have gotten an extension on an interconnection construction service agreement (ICSA) for a 66-MW solar development it was building at the same site, with the same point of interconnection, as an existing 111-MW solar plant it previously built. The project was built on a former surface coal mine in Martin County, Ky.
Savion argued PJM violated its rights under the ICSA, saying the RTO should have let it suspend work on the second part of the Martin project for 18 months after a construction firm building withdrew from the project unexpectedly and tariffs on solar panels were changed in 2024.
PJM said it was not eligible for suspension of the ICSA because the transmission infrastructure had been fully constructed.
FERC sided with Savion, finding that PJM improperly denied the suspension and saying that the 18-month suspension should be effective on Dec. 14, 2024, when Savion first requested it. Some work is left to be done on the interconnection facilities, which means the suspension still can go into effect, the majority reasoned.
Christie dissented, saying the order would let interconnection capacity go unused and further disrupt and delay PJM’s queue. AEP had finished building the transmission, and 111 MW of the Martin solar facility already was connected to the grid.
“The ICSA permits a project developer to suspend work ‘associated with the construction and installation’ of the transmission owner interconnection facilities,” Christie said. “Here, the record demonstrates that ‘construction and installation’ is complete.”
AEP has a couple of tasks to do, but the project is injecting power over the interconnection point. So just because some adjustments might be made, that does not mean there is remaining work that can be “suspended,” he said.
“The majority’s expansive reading of Section 3.4 would allow a customer to ‘suspend’ work through and including the time at which the project is operational and injecting power to the system and any time in the future,” Christie said. “This reading is illogical. It is plainly at odds with the purpose of suspension, which is to stop work on interconnection facilities when the generating facility is delayed (not when the generating facility is operational).”
Christie said PJM “hits the nail on the head” in its argument that the complaint is seeking to delay completion of the project and in the process “hoard the interconnection capacity” in a way that is unfair to other projects that use the capacity.
“The resulting delays and uncertainty hinder development of new generation and stifles competition, which harms PJM at a time when it desperately needs that new generation; instead, today’s order benefits a single developer to the ultimate detriment of consumers,” Christie said.
