Public Service Enterprise Group saw an “over-12-fold” increase in mature leads and inquiries from customers exploring “large load and data center projects” over the past year, CEO Ralph LaRossa said in the utility’s fourth-quarter earnings call Feb. 25.
The suggestion of a potentially expensive surge in demand comes after several quarters in which LaRossa has touted the utility’s South Jersey nuclear generators — Hope Creek and Salem — as primed to accommodate the needs of data centers and artificial intelligence developers. Company officials have suggested they are an important part of the utility’s future expansion and of helping the state boost its economy. (See Data Center Opportunity is Strong, Expanding, PSEG CEO Says.)
The volume of inquiries totaled 4,700 MW in the last year, compared to about 400 MW in 2023, LaRossa said. The average size of the leads in 2024 was 100 MW, and the customer inquiries even included some “large electric vehicle interconnections,” he said.
“Approximately 25% of the 4,700 MW of new business leads have been incorporated into PJM’s 2025 system peak load forecast,” he noted.
NJ Wind Port
Responding to an analyst’s question, utility executives rebuffed suggestions that the utility’s ability to develop such projects would be affected by recent FERC rulings.
The ruling gave PJM and its transmission owners 30 days to answer a series of questions about whether the RTO’s tariff needs updating to accommodate co-location arrangements.
“We continue to have discussions with multiple parties for various elements of what we’re talking about, and that interest remains strong,” CFO Daniel Cregg said.
“It would have been great to have complete answers throughout everything from what FERC said,” Cregg added. “I don’t know that we necessarily expected that, and we’ve got to wait for some [details]. But I think directionally, what they said was favorable for the flexibility to do what you want to do, and those details have yet to be written, so we’ll continue to see what happens there.”
LaRossa said he hoped for more “clarity” from FERC on the issue in the future but added that “it’s not stopping anything.”
New Jersey has spent more than $500 million to develop the New Jersey Wind Port adjacent to PSEG’s nuclear plants, off the Delaware River, with a goal of serving the state’s nascent offshore wind sector. However, state wind projects have largely stalled amid economic and supply chain difficulties, as well as opposition from the Trump administration. (See NJ Abandons 4th OSW Solicitation.)
LaRossa noted that the New Jersey Economic Development Authority announced recently that it is looking for alternative uses for the port.
“That’s one thing that we just want to point out,” he said. “And we know that there’s some interest, from the governor’s standpoint and from New Jersey’s standpoint, to continue for us to look to pursue these opportunities.”
The sheer volume of inquiries shows that “there’s interest from the industry in New Jersey” and that the state’s effort to market itself to large load clients “has been working,” LaRossa said.
Fall in Earnings
Cregg said the utility plans to invest $3.8 billion in 2025 in regulated investments on “infrastructure modernization, energy efficiency and meeting growing demand and electrification initiatives.”
That expenditure is part of an expanded five-year regulated capital investment plan of $21 billion to $24 billion between 2025 and 2029, an increase from the previous planned $18 billion to $21 billion, he said.
PSEG’s fourth-quarter results for 2024 fell from $546 million ($1.10/share) in 2023 to $286 million ($0.57/share). Non-GAAP operating earnings for the quarter were $421 million ($0.84/share), compared with $271 million ($0.54/share) in the same period last year.
Full-year 2024 earnings were also lower than those of 2023. The company reported net income of $1.772 billion ($3.54/share), compared with $2.563 billion ($5.13/share). Non-GAAP operating earnings were $1.839 billion ($3.68/share), compared with $1.742 billion ($3.48/share).
When geothermal startup Fervo Energy went out for its first round of venture capital funding in 2018, it pulled in $500,000, co-founder and CEO Tim Latimer recalled. “It’s just not a sector that the investment community was excited about.”
Fast forward to 2024, and investments in the company — which uses fracking technology to tap into hard-to-reach geothermal reservoirs — totaled just under $500 million, Latimer told the audience at a panel discussion hosted by the Atlantic Council on Feb. 20 in D.C.
The company’s roster of investors now includes cleantech leaders like Bill Gates’ Breakthrough Energy Ventures, as well as Devon Energy, a major oil and gas producer based in Oklahoma.
“I think this is a perfect example of the oil and gas industry getting into [geothermal],” he said. “People are viewing this as a bankable, mature technology for the first time. … It just has all these solutions that the world needs right now in terms of an energy resource, and so there’s enormous momentum to widen the aperture for what geothermal can do, and the technology to get it done.”
High-tech companies are looking for 24/7, carbon-free electricity to power their massive artificial intelligence data centers, and the “enhanced” geothermal systems developed by Fervo and others are increasingly seen as an essential part of the portfolio of resources that will be needed.
Fervo’s first demonstration project in Nevada is now providing power to Google data centers under an innovative “clean transition” tariff. The company is building its first utility-scale plant in Utah, with Southern California Edison signed up for two 15-year contracts for 320 MW.
Building on oil and gas industry buy-in, enhanced geothermal also has broad bipartisan support at the federal and state level.
The U.S. only has about 3 GW of geothermal energy online, most of it in California. But the Biden administration saw enhanced geothermal systems adding as much as 300 GW of new capacity to the grid by 2050, according to a report issued by the Department of Energy in March 2024.
New Energy Secretary Chris Wright is also a fan. Liberty Energy, the fracking company he led prior to being tapped to lead the department, is another one of Fervo’s investors, and in his first order as secretary, Wright listed geothermal as one of the advanced technologies the Trump administration will continue to develop and support.
Colorado Gov. Jared Polis (D) launched a regional effort, the Heat Beneath Our Feet Initiative, during his term as chair of the Western Governors’ Association from 2023 to 2024.
“If you look at a map of natural geothermal resources in the United States, you’ll see the West is a hot spot — pardon the pun, but it really is,” Polis said in an onstage interview with Jeremy Harrell, CEO of ClearPath, an energy policy nonprofit. “That’s where it is likely to be, and is, most economical, most deployable, [with] the highest levels of heat subsurface.”
Polis worked to restructure his state’s oil and gas commission into the Energy and Carbon Management Commission. While continuing to permit oil and gas projects, the renamed commission is now permitting geothermal in “an analogous way,” he said.
“They’ve done their rules around that in consultation with the industry and set up what I think is one of the most expedited, reliable permitting regimes for geothermal in the country,” he said.
The final report on the Heat Beneath Our Feet Initiative similarly calls for geothermal exploration to receive the same tax incentives as oil and gas exploration, a proposal that “has big bipartisan support in Congress,” Harrell said.
The Oil and Gas Connection
Traditional geothermal power plants draw superheated liquids from naturally occurring underground reservoirs to the surface to create steam to run turbines. These plants are typically located near underground tectonic rifts, meaning they are geographically limited.
For example, Iceland sits on the Mid-Atlantic Ridge, where the North American and Eurasian tectonic plates meet, allowing the island country to run its heat and electricity largely on geothermal energy.
The enhanced geothermal technology developed by Fervo and others uses the fracking and horizontal drilling technologies developed by the natural gas industry to tap into dry “hot rocks.” With horizontal, or directional, drilling, Fervo can drill multiple wells from a single site on the surface, according to the company.
Increased efficiencies in drilling are bringing down prices, according to the 2024 DOE report. The national average cost of enhanced geothermal could fall to $60 to $70/MWh by 2030 and drop still further to a highly competitive $45/MWh by 2035.
The quick movement down the price curve is drawing more investment to Colorado, according to Polis. Mt. Princeton Geothermal and Western Geothermal, both Colorado-based geothermal companies, are partnering with Iceland’s Reykjavik Geothermal on developing wells in the state.
But enhanced geothermal can also leverage other lessons learned from the oil and gas industry, said Morgan D. Bazilian, professor of public policy at the Colorado School of Mines. Geothermal researchers are looking at “what the oil and gas industry learned about community engagement, what the industry learned about project management, what the industry learned about finance and … what the industry learned about permitting and how to deal with mineral rights.”
The transferability of workforce skills between oil and gas and geothermal is another strong selling point.
Talking geothermal at the Atlantic Council on Feb. 20 are (from left) Reed Blakemore, Atlantic Council (moderator); Morgan Bazilian, Colorado School of Mines; Brian George, Google; Ravi I. Chaudhary, former assistant secretary of the Air Force; Fervo Energy CEO Tim Latimer; and Jack Waldorf, Western Governors’ Association. | Atlantic Council
Fervo’s Latimer noted that crews working on his company’s Utah project came from North Dakota, where they were drilling oil wells. While the U.S. has lost leadership in solar and storage manufacturing to China, “we have never lost the lead in drilling. Nobody in the world has the skilled workforce out there that the United States does when it comes to drilling.”
“We can easily transition those skills directly” to geothermal, he said. “There’s no retraining required. If you’re drilling an oil well one day, you can do geothermal the next.”
In the same way, coal plant operators can transition to operating geothermal plants, Latimer said. “You look at a geothermal power plant: You have rotating equipment and turbines and heat exchangers and pressure control equipment. It’s the exact same skills” as for coal.
Bazilian cautioned, however, that attracting and keeping a skilled workforce for geothermal could be difficult. Graduates from the Colorado School of Mines typically field multiple high-paying job offers, and not only in the energy sector.
“They’re going to where there’s excitement, or there’s some kind of value-add for them, or where they’re making the best salaries,” he said. “If we don’t find ways to make [geothermal] exciting … then we will fail to train the workforce of the future we need.”
National Security
The panel also touched on a less obvious but essential application for geothermal: providing emergency power and reliability at U.S. military bases.
“We’re in the midst of a decade of consequence in which potential adversaries are looking at ways to gain a strategic advantage against our nation,” said Ravi I. Chaudhary, former assistant secretary of the Air Force for energy, installations and environment.
“We’ve got to bring up our game in innovation over the next decade; otherwise our adversaries will; our global competitors will,” Chaudhary said. “Geothermal is a natural methodology by which we can build redundancy and ruggedize our installations against potential threats.”
He pointed to pilot projects at Air Force bases in San Antonio, Texas and Mountain Home, Idaho, where geothermal systems under development would be able to disconnect from the grid and keep operations going at the bases in case of a disturbance or other emergency on the grid.
At Mountain Home, for example, should a “civil disruption” affect the electric grid, an islanded geothermal system would allow the Air Force to “get the jets out of town quickly … and then plug back into the grid so we can distribute that energy to prevent more civil disruption,” Chaudhary said.
“We can ill afford to move at the speed of government these days,” he said. “We have to move at the speed of the threat … and when it comes to national security and across the board, the speed of innovation.”
The challenges for enhanced geothermal include transmission, permitting, and market and regulatory structures. Project and transmission permitting can be especially difficult in some Western states, which have millions of acres of public land under federal jurisdiction. In Colorado, public lands cover 36% of the state, Polis said, while in Nevada, the figure is more than 85%.
Google and the Grid
Brian George, the U.S. federal policy lead at Google, sees enhanced geothermal and partnerships with companies like Fervo as key components of the portfolio of clean energy resources his company is looking at to power its data centers.
“I tend to think a lot about what are the regulatory structures that we need to have in place to be able to bring on these types of new resources that are in stages where they require significant capital investment, right?” George said. “It’s going to require a little bit of a nudge from companies like Google … to bring on the resources that do provide that 24/7 baseload power in a way that all grid customers can benefit from the reliability and clean benefits of these resources.”
At the same time, he said, transmission must become a bipartisan issue, rather than being seen as “an enabler of wind and solar.”
“Transmission is a tool to unlock economic and national security. It is a tool for us to bring more loads onto the grid, for new manufacturing entities to bring new plants onto the grid, for new resource developers to bring new generators on the grid,” he said.
“There’s a ton of demand; there’s a ton of capital ready to go,” but it’s waiting to see if transmission will be built to connect new energy to the grid, George said. Federal, state and local governments will all have a role to play, he said.
“The last thing we need to do is come in with a very heavy-handed approach, and say, ‘This is the line that shall be built,’ without consulting governors and county councils and local entities. It has to be a collaborative process. …
“Our view is that the grid should be planned in close partnership with developers and off-takers and utilities in a way that enables that grid to grow and work for everybody,” he said.
Co-locating new data centers with generation could help “to accelerate the addition of new loads and new generation to the grid,” George said. “But I would just underscore that the reliability, resilience and economic points that the grid provides are difficult to match.”
The policies of the Biden administration will continue to shape the U.S. power portfolio a while longer, even as the Trump administration tries to make a hard right turn from renewables back to fossil fuels.
The U.S. Energy Information Administration on Feb. 24 said solar and battery storage dominate planned electric generation capacity additions to the U.S. grid in 2025, with natural gas providing only 7% of the 63 GW total.
Even the wind turbines that Trump wants to halt are expected to outstrip natural gas, with 7.7 GW of new wind capacity vs 4.4 GW of new gas-fired generation. EIA noted, however, that the data behind its projections was generated in December 2024, a month before Trump began a rapid-fire attempt to limit renewables and boost fossil fuel development.
In total, EIA projects 2025 additions of 32.5 GW of solar, 18.2 GW of storage, 7.7 GW of wind, 4.4 GW of gas and 0.2 GW of all other forms of generation.
That is nearly 63 GW — about 29% higher than the 48.6 GW installed in 2024, which itself was the largest single-year addition since 2002.
The 30 GW of solar added to the grid in 2024 was a record, and EIA expects solar installation to set another record in 2025, with Texas once again accounting for the lion’s share of projected new photovoltaic capacity: 11.6 GW.
Likewise, the 10.3 GW of battery storage installed nationwide in 2024 was a record, and EIA expects 2025 installations to far surpass that total. (EIA includes batteries in the generation capacity tally as a secondary source of stored electricity, not as a primary source of electrical generation.)
Wind is expected to bounce back from a slump: The 5.1 GW added in 2024 was the least since 2014. But EIA’s 2025 projection of 7.7 GW of new wind power is off by more than 9%, as it includes 715 MW from Revolution Wind, an offshore wind farm that has pushed its completion date back to 2026.
EIA also assumes Vineyard Wind 1 will come online in 2025. The 800-MW facility began construction off the Massachusetts coast in late 2022, with an anticipated 2024 in-service date. But it experienced significant delays and component failures in 2024, and in early 2025, it is well behind schedule, with no anticipated completion date listed on the project website.
Simple-cycle combustion turbines account for about half of the 4.4 GW of new natural gas-fired capacity projected to come online in 2025, and combined-cycle units account for about a third.
EIA said five states — Utah, Louisiana, Nebraska, North Dakota and Tennessee — account for about three-quarters of the expected gas additions, the largest of which are the 840-MW Intermountain Power Project in Utah (where 1,800 MW of coal-fired capacity is being retired) and the 679-MW Magnolia Power in Louisiana.
EIA reports that in 2023, 4.18 trillion kWh of electricity was generated at utility-scale facilities in the United States — 60% fossil, 21.4% renewable and 18.6% nuclear.
The largest components were natural gas (43.1%), atomic fission (18.6%), coal (16.2%), wind (10.2%), hydropower (5.7%) and photovoltaic solar (3.9%).
The Eastern Interconnection Planning Collaborative on Feb. 24 urged FERC to not use NERC’s Interregional Transfer Capability Study (ITCS) “as a metric for determining prudent additions” to transfer capability on the grid (AD24-5).
In comments filed with the commission on the study, EIPC — an association of 18 planning authorities from the Eastern and Central U.S., including PJM, ISO-NE, NYISO, Duke Energy, Dominion Energy and the Tennessee Valley Authority — also commended NERC for the “enormous task” carried out by the ERO in a short time frame, and thanked the organization for working with industry stakeholders during the study.
NERC submitted the final installments of the ITCS to FERC in November, ahead of the December deadline set by Congress in the Fiscal Responsibility Act of 2023. (See NERC Files ITCS to FERC, Meeting Congress’ Deadline.) In the FRA, Congress directed NERC to submit to FERC a study detailing current transfer capabilities across the North American grid, recommendations for prudent additions to transfer capability that could strengthen grid reliability, and recommendations to meet and maintain total transfer capability.
The ERO’s final report, submitted in three parts — with a fourth component focused on Canada planned for release this year — recommended a total of 35 GW of additional transfer capability across FERC’s transmission planning regions. NERC Director of Reliability Assessments and Performance Analysis John Moura said the ERO had to use its discretion to narrow the FRA’s broad requirements to a workable framework; for example, NERC’s definition for “prudent” additions focuses on reliability rather than economic factors.
EIPC’s comments acknowledged that NERC had “relatively little time to develop a study methodology, gather the required data, consult stakeholders, execute the study and validate results” and that the limited time required the ERO to “change and reduce the scope of its study.” EIPC also said it appreciated that NERC went out of its way to coordinate with grid stakeholders through the ITCS Advisory Group.
However, the collaborative did express concerns about the study — partly regarding its methodology, but mainly that large transfer capability studies like the ITCS are inherently unsuitable “to drive transmission upgrades on the power system.” EIPC pointed out that transmission service providers (TSPs) and transmission planners “have a more in-depth understanding of the current and planned transfer capability on their system” than NERC.
“Decisions on the value of specific transmission improvements are complex, and they must consider all the factors regularly evaluated by TSPs, transmission planners and resource planners,” EIPC said. “This goes beyond the factors considered for transfer capability in [large transfer capability studies]. For example, available capacity, the feasibility of upgrades, the potential for excess generation and cost allocation must be considered to ensure investments are prudent and aligned with a beneficiary-pays methodology.”
EIPC emphasized that it “shares the same goals as FERC, NERC and the rest of the industry” regarding improving grid reliability through interregional transfer capability, and that it also believes investments in transfer capability can add value to the grid “at appropriate costs.” However, it also cautioned that despite providing “interesting insights,” large-scale “snapshot-in-time” studies like the ITCS lack “the appropriate granularity” to make useful recommendations.
Calling the ITCS “not directly actionable,” EIPC suggested that federal and state regulators and policymakers seek input from “planning entities responsible for analyzing transmission security and resource adequacy needs” when determining interregional transfer capability needs. In addition, EIPC said that prudent additions should be assessed in terms of cost, not just their reliability benefits.
EIPC also recommended that FERC work with state regulators on metrics to guide decision-making on increasing interregional transfer capability. The collaborative stopped short of defining the metrics itself but suggested that they include factors such as specific needs that a proposed expansion could address, whether the potential reliability benefits exceed the projected cost of the project, and the feasibility of the proposed project to meet the identified need.
In a separate statement, EIPC said its members “stand ready to provide technical assistance” for the Eastern Interconnection if FERC decides to pursue such a metrics project.
Voting on Site Control Requirement Manual Revisions Deferred Pending Settlement
VALLEY FORGE, Pa. — Stakeholders in the Markets and Reliability Committee (MRC) voted for a third consecutive meeting to delay acting on revisions to Manual 14H intended to clarify when developers may add or remove parcels from their project footprint. PJM and EDF Renewables stated they’re working toward resolving a complaint filed on the matter (EL25-22). (See “Other Committee Business,” PJM MRC/MC Briefs: Jan. 23, 2025.)
The complaint from the American Clean Power Association, Solar Energy Industries Association and Advanced Energy United alleges PJM is violating its tariff and Manual 14H in guidance it has issued to developers around when they can change the parcels included in their projects. In past stakeholder meetings, PJM said the proposed manual revisions would codify that guidance, which renewable developers have argued is overly burdensome and would require them to retain land they have determined is unneeded.
A motion to defer voting on the manual revisions initially was rejected by stakeholders, with the 60% in support falling shy of the two-thirds sector-weighted threshold. Emma Nix, of EDF Renewables, told the committee that settlement discussions are making progress and passing the proposal would frustrate that process. The second vote passed with 82% support.
“I expect that we will have a settlement that we can share with stakeholders within the next month … things are going very smoothly,” she said.
PJM attorney Chris Holt said the RTO is limited in what it can say due to settlement confidentiality. But he confirmed discussions are progressing toward a resolution. He noted that FERC has granted an abeyance on the complaint that ends on March 10 and stated that PJM is hopeful an agreement can be reached by then. General Counsel Chris O’Hara said settlements often result in PJM committing to propose revisions to its governing documents in the FERC docket in which the settlement is made. If such an agreement is reached, those changes might not come back to the stakeholder process for consideration next month. Interested parties instead could comment on that docket.
The proposed changes would allow parcels to be added to a project at Decision Point 1, so long as the land is adjacent to the site or evidence of connecting easements is provided. Parcels also could be removed at this point, so long as the project continues to meet the minimum acreage and energy output defined in the project application. (See “Vote on Site Control Requirements Deferred,” PJM MRC/MC Briefs: Dec. 18, 2024.)
The revisions would seek to clarify language stating there are no specific site control evidentiary requirements associated with Decision Point 2 by specifying that “site control must be maintained throughout the cycle process.” A note also would be added stating that parcels similarly can be added to DP1, with the caveat that a one-year term would be imposed from the end of Phase 2 of the relevant study cycle.
No additions would be permitted at the final Decision Point 3, but reductions would be allowed so long as the acreage-per-megawatt and evidentiary requirements continue to be met. Once a generator interconnection agreement is signed, any site control changes would require a necessary study agreement to determine permissibility.
3 Packages Advancing from ELCC Task Force
PJM presented a slate of proposals aimed at adding new generation categories to the effective load carrying capability (ELCC) framework and how analysis of changes in the resource mix and risk modeling affect class accreditation. They are the first recommendations made by the ELCC Senior Task Force (ELCCSTF), which was formed last year to consider changes in the functionality and transparency of the methodology.
Two of the proposals focus on how changes in ELCC inputs can affect resource class ratings between the completion of a Base Residual Auction (BRA) and the associated delivery year, as well as how that might interact with any capacity shortfalls that could be caused if a resource sees its accreditation reduced between a BRA and incremental auction (IA).
The main motion advancing to the MRC, Package B, would lock resources’ ELCC ratings and accreditation in at their values used in the BRA, though any changes in risk modeling still would affect the Reserve Requirement Study values used in the IAs and could cause PJM to revise the amount of capacity it procures in those auctions. The alternative, Package C, would follow the status quo of updating ratings between IAs, but would lower the penalty rate for any deficiency associated with reduced accreditation to 100% of its clearing price, down from the 120% penalty rate. The two proposals were nearly tied in an ELCCSTF poll, with Package B holding 66.5158% support and 68% preference over the status quo, while Package C received 66.5025% and 74.9% preference.
Package A was introduced by Vistra and would have capped the deficiency charge at the lesser of any change in accreditation or the equivalent demand forced outage rate (EFORd).
PJM’s Pat Bruno said Package B would remove the uncertainty associated with shifting accreditation from market sellers while retaining penalties for any shortfall in installed capacity (ICAP). He gave the example of a unit experiencing a catastrophic failure or a planned resource not entering commercial service on time still being subject to deficiency charges. Package C would retain some incentive for market sellers to mitigate any lost AUCAP.
Susan Bruce, representing the PJM Industrial Customer Coalition, argued that Package B would shift all risk to load and require load to buy shortfall capacity twice, in the BRA and IA.
“The main motion addresses a concern, and I certainly am sympathetic to the concern, but it shifts the risk to load … so I think some fundamental question should be answered here,” she said.
Adrien Ford, of Constellation, said the main motion would handle the unhedgeable risk of changing ELCC ratings more effectively than the other two options considered.
The third proposal advancing from the ELCCSTF would add two new resource classes: a waste-to-energy subset of the steam generation category and oil-fired combustion turbines (CTs). The former has an estimated ELCC rating of 83% based on the parameters used in the 2025/26 third IA, while oil CTs would have an 85% rating.
1st Read on CIFP Manual Revisions
PJM’s Joseph Tutino provided a first read on a set of manual revisions to conform with FERC’s order granting PJM’s capacity market changes drafted through the Critical Issue Fast Path (CIFP) process in 2023. The package is the second set of conforming revisions, this time focusing on generation testing requirements and adding a requirement that dual-fuel resources must offer schedules with both fuels into the energy market. (See “1st Read on 2nd Phase of CIFP Manual Revisions,” PJM MIC Briefs: Jan. 8, 2025.)
The summer and winter capability testing detailed in Manual 18 would be changed to focus on whether capacity resources are able to output their daily ICAP minus the 95th percentile hourly seasonal net output. A resource that has a daily ICAP value exceeding the tested capability during that season would be subject to shortfall charges until it is able to test to a greater capability. The addition of generation operational testing to Manuals 14, 18 and 28 would allow PJM to test a resource twice per season, plus any additional retests if a unit fails to perform. The dual-fuel must-offer requirement would be codified in Manual 11.
Ford said Constellation has worked with PJM on changes to the language to reflect permit requirements. PJM’s Skyler Marzewski said the RTO views those changes as a clarification rather than substantive change to the proposal.
Members Committee
Manual Revisions Seek to Reimagine Role of MC Webinar
PJM’s Michele Greening presented revisions to Manual 34 that would restructure the MC Webinar in an effort to shift substantive discussions to be held instead at the MC. The proposal includes a single change to revise the manual to state that “reports, briefing and non-decisional business will be conducted” to instead read as “may be conducted,” allowing for more flexibility.
Vistra’s Erik Heinle said the webinar is a useful venue and should continue. But some stakeholders have grown concerned that topics discussed there are more appropriately addressed before the broader attendance that the full committee sees. In particular, he said the monthly reports the Independent Market Monitor provides should be moved to the MC.
Tom Hyzinski, of the GT Power Group, provided an example from the March 18 MC Webinar to highlight the concern raised by Heinle. Hyzinski said that although it was not covered or even noticed in the Market Monitoring Report that was posted, the Monitor mentioned at the webinar that PJM had unilaterally increased the amount of reserves they carry some time ago. That increase needs to be addressed, he said, suggesting the additional reserves PJM procures are inappropriately increasing consumer costs. Hyzinski said PJM staff were not present to refute those claims or offer alternative perspectives. (See “Stakeholders Reject PJM Synch Reserve Manual Change; RTO Overrides,” PJM MRC/MC Briefs: May 31, 2023.)
Monitor Joe Bowring responded that the argument he voiced during the webinar was that there are communication issues between PJM dispatchers and generation owners that have led to reserves underperforming and that resolving that issue would obviate the need for the higher reserve requirement. Rather than moving the reports to the MC, Bowring suggested it may be more effective for webinar participants to request that discussion of materials presented be added to the MC agenda when warranted.
Stakeholders Discuss Synchronized Reserves
PJM’s Mike Bryson said PJM may lower its synchronized reserve requirement if a trend of increased performance holds up. The RTO increased the requirement by 30% in May 2023 to address low performance. That change may be reversed if five consecutive spin events see 100% or higher performance. In response to stakeholder questions as to whether PJM will continue to monitor reserve deployment and consider ongoing changes to the requirement, Bryson said the focus is getting back to the standard procurement target before considering next steps.
Bowring said he’s glad to hear PJM is considering the change and he’s hopeful changes to how reserves are deployed will improve performance to where the baseline requirement is sufficient for PJM. (See “Stakeholders Endorse Reserve Rework, Reject Procurement Flexibility,” PJM MRC Briefs: July 24, 2024.)
Both Bowring and Bryson said the dialogue they had with generation owners whose units underperformed yielded helpful insight into what was driving the issue, and ongoing coordination would be beneficial.
A report released in February by Aurora Energy Research has found that President Donald Trump’s executive orders have put 43 GW of East Coast offshore wind projects at risk of permitting delay.
The report found most of the orders, issued on Trump’s first day back in office, would not have an immediate impact on the offshore wind industry, though it contains a summary of each, as well as of other actions by the president, and potential long-term impacts.
Of more immediate concern to the industry is Trump’s halt on onshore and offshore wind power leasing and permitting, and his direction to agencies to review existing ones. (See Critics Slam Trump’s Freeze on New OSW Leases.)
“Our biggest concern with the executive orders in particular is not necessarily in the long term, but the potential for permitting risks for the projects that are already under development or already have leases downstate,” said Julia Hoos, head of USA East for Aurora.
The report examined the status of more than two dozen projects and compared their risk profiles under the moratorium. It ranked projects by development phase, with those under construction deemed the lowest risk. Projects that had approved construction and operations plans were deemed medium risk. Low- and medium-risk projects include 5.1 GW and 5.9 GW of nameplate capacity, respectively.
Projects still going through the permitting process were deemed high risk. This is the bulk of the current projects both numerically and in capacity, with 32 GW at risk.
“For projects that are more advanced, it would be pretty unprecedented for those projects to run into additional challenges,” Hoos said. “But the language of the executive order is so aggressive on revisiting the legitimacy of the leases and permitting that it’s not out of the question.”
Hoos said the executive order had caused “real nervousness” for projects that are working on their permits because a full blockage now could lead to a cancellation. For projects not fully blocked, developer costs almost surely would escalate.
Dan Shawhan, a fellow at Resources for the Future and adjunct assistant professor at Cornell University, said Aurora’s analysis “seemed reasonable” to him.
“Based on comments Trump has made, it seems like he’s interested in stopping offshore wind for as long as you can,” Shawhan said.
He advised developers and states trying to build offshore wind to “pick their battles to live to build another day. They should challenge the parts of this that they think they might be able to overturn or overcome by court challenge. They should take advantage of this time to prepare to build after the Trump administration.”
New York Reliability Risks
The report includes a section on New York’s energy future, citing 7.5 GW of at-risk projects against a backdrop of downstate fossil fuel plant retirements.
It found that delaying key offshore wind projects could push the state back toward combined cycle gas turbine plants downstate by causing increased energy prices and reliance on imports from PJM. The analysis assumes a “strong enforcement of the peaker rule,” meaning that old peaker plants would be retired.
“Demand is expected to grow in the winter with more heating electrification,” Hoos said. “Assuming the state doesn’t allow for that generation to be replaced by gas, which feels very likely given the last several years of policy, then reliability downstate is dependent on bringing in batteries and bringing in new generation.”
Hoos said offshore wind was the most feasible path for new generation to be brought online in downstate New York. Delaying those projects poses “real risk” to the region.
Shawhan said New York could avoid falling back on gas and imports if they accelerated solar development or other onshore renewables, but unless the state acted, it likely would be forced to increase fossil generation. Transmission projects that support renewables also might see increased attention from the state.
“Transmission development usually takes a long time, about a decade,” Shawhan said. “There are projects in development that might or might not be built, and this would tip the balance in favor of them being built.”
“NYSERDA will carefully review federal actions regarding offshore wind development,” a spokesperson for the New York State Research and Development Authority said in an email. “It is too soon to determine what impact, if any, federal actions might have on New York reaching its ambitious renewable energy targets.”
The authors say the system’s inefficiencies raised the cost for consumers as much as $7 billion just in PJM’s latest capacity auction.
They say the problem will persist for PJM without reforms, but add that the situation is not unique to PJM: Regional operators nationwide should see the auction as a warning sign and should expect similar repercussions if they do not address projected generation and transmission needs.
The Pacific Northwest, SPP, MISO, ERCOT and Georgia Power are seeing notable demand growth, the report states, along with PJM.
“Penny wise and pound foolish: PJM’s Capacity Auction Demonstrates the Cost Imperative of Simplified and Speedy Interconnection” was prepared by consulting firm Grid Strategies for the clean power trade organization Advanced Energy United.
Co-author Rob Gramlich said the title derives from the process by which PJM (and other RTOs) allow interconnection of new generation assets.
“Typical interconnection processes are ‘penny wise’ but ‘pound foolish,’” he said in AEU’s announcement of the report. “As illustrated by the data from PJM, grid operators are slow and methodical, which means they provide detailed cost responsibility accounting, but the associated length of time to connect new generation contributes to scarcity and raises consumers’ rates.”
PJM disagreed with the conclusions in the report. A spokesperson said via email:
“The report cites a number of factors that its authors have been actively engaged in influencing. Advanced Energy United, for example consistently advocated against requiring renewable resources to take part in the capacity auction, and they continued to oppose PJM’s successful petition to end that exemption, which FERC recently approved. We look forward to the full participation of these resources in the next auction and the downward impact on prices that comes with additional reliable capacity. The report also returns to the flawed narrative that PJM is to blame for the slow pace of adding new generation, when approximately 50,000 MW in mostly renewable projects have cleared PJM’s process but are not coming online with the pace needed to replace retiring resources and to meet growing demand.”
The report states that despite FERC’s push for proactive transmission planning, most regions still have reactive transmission planning and interconnection processes in place.
As a result, generation is added slowly and capacity market prices rise.
The report highlights the glaring example: PJM’s latest capacity auction, in which the clearing price rose 833% from the 2024/25 Base Residual Auction (BRA). (See PJM Capacity Prices Spike 10-fold in 2025/26 Auction.)
The total cost to consumers was $12.5 billion higher than in the previous BRA, but it could have been as little as $5.5 billion higher, the authors state, had PJM begun proactive transmission planning and simplified its interconnection process years ago.
Updated resource accreditation numbers and new market rules around extreme weather effects factor into the equation, but the report focuses heavily on the basic laws of supply and demand: Load is growing, existing generation is retiring and new generation is coming online too slowly.
Supply offered in the 2025/2026 BRA was about 6.6 GW lower than in 2024/25, while estimated peak load demand was about 3 GW higher.
The report notes that PJM interconnection service requests totaled well over 200 GW at the end of 2023 and estimates that 68.6 GW of accredited capacity is in the PJM interconnection queue.
But very little of that has been coming online. Only about 3 GW was placed in service in 2022, less than 5 GW in 2023 and less than 2 GW in the first 8.5 months of 2024.
The report is backward-looking and analyzes how past cost increases might have been minimized had reforms been enacted earlier. But looking forward, the authors suggest PJM’s partly complete, multiyear interconnection reform process may not prove significantly more efficient when it finally is finished.
Broader strokes are needed nationwide, they write: “While much of the discussion around the exorbitant price tag has treated [the 2025/26 BRA] as a one-off issue that can be fixed by tweaks to market rules, the issue is more fundamental. … Regions across the country should expect to face similar repercussions if they do not address the generation and grid infrastructure needs posed by increased power demand.”
PJM said via email that it is working toward continued improvement: “PJM continues to pursue additional streamlining of the interconnection process, in addition to its recent proposals to speed the entry of new generation resources and to expand the participation of existing resources.”
Independent Market Monitor
Independent Market Monitor Joseph Bowring said he does not agree with the report’s central thesis: that queue issues are a primary cause of higher prices in the PJM capacity market.
He does agree that faster and more efficient interconnection processes are needed, and he told RTO Insider that PJM should have begun pursuing them earlier.
But he disagreed with some other points and conclusions in the report:
Historical data on PJM’s inefficient interconnection process is not a good guide to how the new and improved rules will work.
The problems with PJM’s interconnection queue are due partly to developers crowding it with weak and/or duplicate projects unlikely ever to reach construction.
Most of the proposed resources in PJM’s queue are intermittent, and while they would provide critically needed power, they cannot solve reliability issues.
The report overstates the impact of supply-and-demand fundamentals in the last auction.
Bowring also noted the most recent regulatory changes may change the picture painted by the report.
For example, FERC on Feb. 11 approved PJM’s Reliability Resource Initiative, which will allow PJM to move resources ahead in the queue if they are close to commercial operation. This should help, he said, and PJM should strengthen this approach.
A California electric resource portfolio that incorporates 63 GW of clean energy and new storage by 2035 has received approval from state regulators and will be sent to CAISO for use in its 2025/26 transmission planning process.
The California Public Utilities Commission voted 4-0 on Feb. 20 to approve the portfolio, which as modeled reaches 99% clean energy serving retail load by 2035. The portfolio projects a decrease in natural gas generation in the CAISO system, with a 71% drop from 2026 to 2035 and an 80% reduction by 2040.
“This is an extremely promising glimpse of a possible future,” Commissioner John Reynolds said before the vote.
The electric resource portfolio is an annual exercise for the CPUC, which described it as a “key input” into CAISO’s transmission planning. In addition to a “base case” portfolio, the commission approved a “sensitivity portfolio” that incorporates a larger amount of long-lead time resources, such as geothermal energy, offshore wind and long-duration energy storage.
Wind Study
The commission’s decision also asks CAISO to study “but not yet trigger the investment in new transmission to support some out-of-state wind and Northern California wind” outside of the CAISO balancing authority area.
The decision noted that the amount of out-of-state wind on new transmission in the 2025/26 portfolio has increased to 9 GW in 2035, up from 6 GW in 2034 in last year’s portfolio. Sources of out-of-state wind include New Mexico and Wyoming.
“The new amounts, if fully developed, will require additional transmission beyond those projects that are already approved and in development, including SunZia, SWIP-North and TransWest,” the CPUC said in its decision.
The additional transmission could be “complex to accomplish” and “require regional cooperation,” the decision said.
Another issue discussed in the decision is the deliverability of energy from offshore wind (OSW) along the Northern California coast. Most deliverability on existing Northern California transmission has been allocated to resources now in the interconnection queue, the CPUC said, pointing to battery storage projects in particular.
“If … CAISO does not reserve some deliverability for OSW and ensure there is adequate transmission available for that deliverability, it will all be used by the storage in the queue,” the CPUC said. But adding transmission for OSW runs the risk of overbuilding “at considerable cost,” if all the resources are not developed.
The decision directs CPUC staff to work with CAISO to identify storage projects with transmission plan deliverability that could have the biggest impact on OSW in the area.
Building the Portfolio
The CPUC built its electric resource portfolio using information from 2022 integrated resource plans filed by utilities under its jurisdiction, plus additional identified resources.
The base case is “reliability- and policy-driven,” according to the CPUC. For example, it factors in a greenhouse gas emissions target for the electricity sector of 25 million metric tons (MMT) by 2035.
And the two study years for the base case portfolio, 2035 and 2040, satisfy the 0.1 loss of load expectation (LOLE) standard. The process also includes busbar mapping, which identifies locations of electricity generation and storage.
Along with its base case portfolio, the CPUC also typically develops a sensitivity portfolio as a “reasonable alternative” for CAISO to evaluate.
Last year’s sensitivity case was a high natural gas retirement scenario, which the CPUC said was “designed to assist in planning for the potential future retirement of fossil-fueled resources.”
SPP has promoted Felek Abbas to senior vice president and chief technology and security officer, combining his current duties as CSO with responsibility for information technology and corporate facilities.
Abbas joined SPP in January 2024 as vice president and CSO, overseeing SPP’s cyber and physical security, emergency management and business continuity. He takes over the IT responsibilities of Sam Ellis, who retired in February.
“Given the rapidly increasing changes and risks confronting our industry, it’s essential we have the very best leading our pursuit of transformative technology,” said incoming SPP CEO Lanny Nickell.
Abbas has more than 30 years of electric industry experience in cybersecurity, engineering, consulting, risk management, audit and compliance. Previously, he was senior manager of cybersecurity for power and utilities at Ernst & Young. Abbas also has served as a NERC critical infrastructure protection compliance adviser and auditor.
VALLEY FORGE, Pa. — The Markets and Reliability Committee endorsed a proposal to rework how demand response (DR) resources are modeled in PJM’s effective load carrying capability (ELCC) framework, most significantly by replacing the availability window with round-the-clock profiling of DR load.
The proposal received 74% sector-weighted support and was approved by the Members Committee Feb. 20 as part of its consent agenda. (See “Expanded Demand Response Modeling Endorsed,” PJM MIC Briefs: Feb. 5, 2025.)
The revisions to the Reliability Assurance Agreement and Manual 20A are envisioned to more accurately align the capability of DR resources with the times reliability risks are most pronounced, particularly in the winter when a greater share of risks lie outside the 6-9 a.m. seasonal availability window. PJM’s Pat Bruno said about 17% of loss of load hours fall outside the availability window, having a significant impact on DR accreditation.
The package also would redefine the winter peak load (WPL) for DR participants to be measured at a set hour PJM believes best reflects the resource class’s overall ability to match system needs. Because individual resources’ WPL are measured at their highest point, regardless of time, adding them up to form a class-wide peak load would overstate the amount of curtailment capability there is, because those peaks would not necessarily coincide.
The third component would model the expected curtailment capability each DR resource is expected to provide by hour to reflect lower potential overnight in the ELCC and risk modeling analyses.
Bruno said the proposal would improve reliability, increase DR parity with generation by recognizing capability in all hours, capture more load and reduction capability, and improve the incentives for curtailment service providers to sign up customers that have more capability to curtail throughout the day.
The proposal targets implementation in the 2027/28 Base Residual Auction (BRA), which DR providers and consumer advocates argued waits too long to unlock the resource’s potential to mitigate tightening supply and demand in the capacity market. An alternative would have made the changes effective for the 2026/27 BRA. But some stakeholders argued that would complicate planning parameters and rules already subject to many changes with just months before the auction is set to be run in July. Bruno said PJM preferred the alternative to realize the reliability and risk modeling benefits sooner.
Calpine’s David “Scarp” Scarpignato said any change to the timeline on which planning parameters would be published would disrupt the ability for load serving entities to engage in bilateral transactions ahead of the auction, noting that the “R” in BRA stands for residual in recognition of its role in procuring capacity not secured through those trades.
“Even when it’s in our financial interest, we don’t always propose moving these parameters around,” he said. “You’re screwing up the market when you’re moving these timelines around like people are talking about.”
Had the alternative been endorsed, Bruno said PJM would have sought expedited treatment at FERC to minimize any impact on the planning parameters. Were that not granted, he said PJM could either publish two sets of parameters with and without the changes or delay publishing specific parameters that could be impacted by the filing. Those parameters are the installed reserve margin, forecast pool requirement, accredited unforced capacity factor, RTO-wide reliability requirement, and the capacity emergency transfer objective.
CPower’s Aaron Breidenbaugh said the proposal goes beyond paper changes to the amount of capacity DR could provide. Eliminating the availability window would require participating consumers to be ready to curtail at any time, he said, including hours they are not accustomed to thinking about.
“There’s going to be a lot of effort to try to accommodate that, but that’s exactly where the reliability benefit comes from,” he said.
Susan Bruce, representing the PJM Industrial Customer Coalition, said the 74% support for the package undercounted support for the actual changes proposed. Because the MRC votes on the main motion first and alternatives are considered only if that fails, she said some consumers voted in opposition in an effort to have an opportunity to vote on the faster implementation included in the alternate.
Market Monitor Joe Bowring opposed the PJM proposal. He noted that PJM does not use DR’s actual performance during the same critical hours that are used for all other capacity resources.
“The experience with DR during Winter Storm Elliott demonstrated that customer loads were already very low when DR was called and that DR provided only a very limited response,” he said in an email to RTO Insider. “PJM is crediting DR with an ELCC higher than gas fired combined cycles because PJM is assuming a response that is not supported by the data. PJM treats DR as an emergency only resource unlike all other capacity resources.
“PJM does not know the nodal location of DR. PJM simply ignores increases in DR load above WPL for DR when it is called. PJM fails to apply the same DR ELCC method for the summer as it proposes to apply in the winter. There is no reason to make an expedited and inadequately supported change to the DR ELCC while ignoring other ELCC issues. All ELCC issues are interdependent and should be part of an overall review,”
Bowring said the Monitor estimated that DR resources would be paid about an additional $235 million under the new ELCC if the next auction clears at the maximum price, an increase of about 36%. He agreed with PJM’s proposed use of a single coincident peak hour, elimination of the aggregate scaling factor and expansion of the performance obligation to all hours of the year.
