FERC sustained its rejection of amendments to the Susquehanna nuclear plant interconnection service agreement (ISA) to increase the amount of power serving a co-located data center (ER24-2172).
The changes sought by Talen Energy would have increased the scale of the Amazon Web Services data center operating behind the fence of Susquehanna from 300 MW to 480 MW. That was rejected by the commission on Nov. 1 on the grounds PJM had not demonstrated the proposal was “necessary for any interest unique to the interconnection of the Susquehanna customer facility.” (See FERC Rejects Expansion of Co-located Data Center at Susquehanna Nuclear Plant.)
The April 10 rehearing order defended the commission’s earlier finding that the proposed ISA amendments were not based on “specific reliability concerns, novel legal issues and unique factors” as demonstrated by it being based on PJM’s generally applicable guidance document for co-located configurations. While the RTO since has rescinded that document, the commission noted that portions of the proposed amendments to Susquehanna’s ISA mirrored the guidance and comments debating the proposal referred to it repeatedly. The rehearing order argued that allowing a standardized practice to be the basis of ISA language that does not conform to the pro forma interconnection service agreement (ISA) would weaken the commission’s necessary standard.
In its request for rehearing, Susquehanna said the commission’s rejection was not based on the unique configuration Talen sought, but rather that it could create a precedent for other resources that would not be reflected in the pro forma ISA. The company argued that being the first of its kind is not a valid reason for denying the application.
The commission wrote that reliance on the guidance document “raised the question of whether PJM intended to offer certain terms to all similarly situated interconnection customers.”
“Creating a requirement that the commission wait for a pattern to emerge before rejecting a non-conforming provision, as Susquehanna requests, would meaningfully weaken the necessary standard and meaningfully increase the possibility for disparate treatment that the necessary standard is designed to diminish,” the commission wrote.
Susquehanna also argued that reliability concerns “haunt” the rejection order despite PJM stating that necessary studies had not identified any issues with the configuration.
In the rehearing order, the commission wrote the study findings are not relevant to the rejection order, which hinged on a determination that PJM had not shown that the non-conforming language was necessary.
Vistra requested the commission clarify whether its rejection establishes a blanket limit on amending ISAs to co-locate data centers. If the intention was to hold that such amendments are not appropriate, Vistra said the underlying issues should be outlined so Susquehanna could refile without those provisions and others could do so as well. The commission responded that the rejection order does not prejudice any future co-located load configurations.
Phillips Dissents
The rehearing order was approved on the same lines as the original rejection, with Commissioners Mark Christie and Lindsay See in support and Willie Phillips dissenting. Commissioners David Rosner and Judy Chang did not participate.
Phillips wrote that he’s hopeful the commission’s order that PJM show cause investigating whether PJM’s tariff is just and reasonable without language addressing co-located load will allow such configurations to proceed. He repeated arguments he made opposing the original rejection that data centers represent an “era defining technology” that requires regulatory leadership. (See FERC Launches Rulemaking on Thorny Issues Involving Data Center Co-location.)
“Notwithstanding my disagreement with these orders’ rationale and determination, I remain hopeful that the Commission’s recently issued order … will soon result in solutions to address what I regard as unnecessary roadblocks to the continued maturing of an industry that is vital to our economic prosperity and national security,” Phillips’ dissent on the rehearing order said.
PJM’s response to the show cause order said more FERC guidance is needed on how the RTO should allow co-located configurations to proceed and laid out several possible pathways. It also noted challenges that remain unsolved, such as how to account for ancillary services the RTO maintains are consumed by co-located loads and whether protective schemes can be adequate for preventing the load from inappropriately taking energy from the grid. (See PJM Responds to FERC Co-located Load Investigation.)
Proponents of co-location have argued that in some instances the load should be considered separate from the wholesale grid and should not be charged for services such as regulation and black start.
The complex issue regarding congestion revenue allocation in CAISO’s Extended Day-Ahead Market (EDAM) continues to raise questions and cause some confusion for market participants, with a market expert reviewing possible solutions at an April 8 Western Energy Markets Governing Body meeting.
The issue is whether certain congestion revenues should be allocated to the balancing area in which the congestion costs accrued, or to the neighboring EDAM balancing authority area where the transmission constraint is located, specifically in cases in which parallel — or loop — flows occur.
Under current EDAM market rules, Open Access Transmission Tariff (OATT) customers in one BAA will end up paying costs for congestion for parallel flows caused by binding transmission constraints in neighboring BAAs, CAISO market expert Susan Pope noted during the meeting. This requirement could make a system and its transmission users carry the costs of unexpected congestion.
OATT point-to-point (PTP) service is awarded without fully accounting for parallel flows, while management of infeasible OATT schedules today requires approaches such as curtailment of non-firm service and out-of-merit redispatch by the impacted BAA to manage congestion, Pope said.
“These congestion charges only occur when there are flows over binding constraints and the amount of the charges reflect the cost of managing the congestion on those constraints,” Pope said. “So, if the cost of managing the congestion isn’t that big, the charges aren’t going to be that big.”
There is strong justification for charging OATT customers for EDAM congestion costs, because the charges are tied to the marginal cost of redispatch to manage congestion on the binding constraints impacted by the OATT schedule, Pope added.
At an April 2 meeting on the subject, Anna McKenna, CAISO vice president of market design and analysis, also disputed the contention that EDAM’s existing congestion revenue framework is inherently flawed. (See EDAM Congestion Debate Builds Even as CAISO Moves to Address Issue.)
However, Pope said the ISO could address stakeholder concerns by redesigning EDAM to include an avenue for OATT customers to more fully hedge or otherwise manage EDAM congestion cost charges.
More specifically, EDAM could adopt use of congestion revenue rights (CRRs), which would provide OATT customers with a hedge against EDAM congestion charges. But the market design does not include CRRs, and CAISO would need to address core issues prior to including them, Pope said. Introducing CRRs would require new rules to establish transmission capability for CRRs while also enabling cost recovery for transmission service providers, she said.
In many RTOs and ISOs, such as NYISO, PJM, MISO and CAISO, OATT transmission reservations were infeasible when modeled, according to Pope’s presentation. Furthermore, RTOs with CRRs have required lengthy stakeholder processes to design the market rules for converting existing OATT service arrangements into CRR allocations, Pope said.
Despite these challenges, introducing CRRs for hedging EDAM congestion costs would “likely enable more efficient scheduling and decrease the cost of serving EDAM load,” Pope said. “But it will take time to design and implement CRRs when agreed upon by EDAM participants.”
In the meantime, a transitional approach is needed to address concerns about OATT transmission customers’ potential undue exposure to charges for parallel flow on binding constraints in other BAAs, Pope said.
One transitional solution is to enable PTP customers to “opt out” of EDAM settlements, which could allow them to avoid congestion charges under all grid conditions, such as by self-scheduling rights before or after EDAM without paying congestion charges, Pope said. But this approach could reduce efficiency and customer cost savings from EDAM and make it more difficult to maintain system reliability during stressed system conditions.
More Work Ahead
WEM Governing Body member John Prescott said the parallel flow congestion issue is “a very thorny problem.”
“But I appreciate the fact that everybody is rolling up their sleeves and, I hope, working in earnest to solve this problem,” Prescott said.
At the meeting, Alan Meck, principal market design analyst at Pacific Gas and Electric, asked if CAISO could break down the pros and cons of each possible solution to the matter.
“I think that I’m following this presentation, but it’s been kind of difficult,” Meck said. “It would be really helpful, I think, if you could add one additional slide synthesizing EDAM design pros and cons and where all of these different issues shake out.”
Pope reminded attendees that a good solution to the issue “is probably one that doesn’t make anybody happy.”
“If everybody’s complaining about something, that might be a good solution,” Pope said. “There’s a lot to gain by solving this problem. I just wanted to encourage everybody to sort of work together, be realistic and try to craft solutions.”
CAISO is on track to publish a full proposal on the topic on April 14, spokesperson Jayme Ackemann said. Whether the CAISO Board of Governors will vote on the proposal at its May meeting is still under consideration, she said.
NERC is examining a series of energy-focused executive orders issued by the White House in a “whirlwind week” for their impact on grid reliability, CEO Jim Robb told the ERO’s Member Representatives Committee in a conference call April 10.
The president also released a proclamation that coal plants be exempt from the latest iteration of EPA’s Mercury and Air Toxics Standards to ensure they are not prematurely closed.
Speaking at the MRC’s April Informational Session, held in advance of the MRC and Board of Trustees’ May open meetings, Robb said NERC and DOE are “still digesting” the executive actions. He added that NERC staff were meeting with DOE “as we speak” to see how the ERO can assist with the reliability assessment.
DOE must complete the assessment within 30 days of the order’s issuance and release it on the department’s website within 90 days. In addition, Energy Secretary Chris Wright must establish a process to regularly assess the assessment’s methodology, along with any analysis and results produced, and “a protocol to identify which generation resources within a region are critical to system reliability.”
Robb noted that work is underway in Congress on “a fairly similar” bill that would require FERC to use material from NERC’s Long-term Reliability Assessment to “look at how to address the resource adequacy challenges that [NERC has] been flagging for a number of years.”
While Robb acknowledged “there’s more uncertainty than certainty around these” recent events, he told members they indicate “profound changes in direction for energy policy” in the U.S. He emphasized that NERC is “in the mix” with FERC and DOE to determine the best way to meet Trump’s directives.
Robb also told members that NERC has been conducting conversations with the regional entities on enhancing the ERO’s reliability assessments by incorporating additional metrics and other means. He suggested the administration’s moves “may put a little bit more urgency in us moving down the path of renovating those assessments.”
Trustee Ken DeFontes observed that Trump’s executive orders have revealed a public awareness of energy reliability issues that surprised him. He told members about a recent community meeting he attended in Maryland about a proposed transmission line project for the generation planned to replace the Brandon Shores and Wagner plants. The stations, which are fired by coal and oil respectively, were slated for closure until their operator Talen Energy reached an agreement with PJM earlier in 2025 to keep them operating while the transmission was built.
“You can imagine the community was not very happy about [the new transmission]. What’s interesting is, one of the ladies got up and said, ‘Well, I understand President Trump just issued an executive order mandating that coal plants not be shut down. So if we can get that through, then the plants will stay in business, and we don’t need the transmission line,’” DeFontes said. “She was just somebody from the community. I was surprised; the word’s getting out.”
PJM and Alphabet on April 10 announced a partnership to develop a suite of new tools using artificial intelligence to speed the RTO’s generation interconnection process.
Amanda Peterson Corio, head of data center energy at Google, said grid planners face an explosion in the number of new service requests they have received, straining their ability to process applications. Google sister company X Development is leading the initiative to build on its Grid Planning Tool and Grid Aware software to create a streamlined work environment PJM can use to more quickly bring new generation onto the grid at a time when the RTO is sounding alarm bells about future resource adequacy.
The planning tool has been deployed in Chile to simulate the grid 20 years into the future with hourly granularity, while Grid Aware uses visual information from sources like Google Maps to facilitate inspections and identify where repairs may be needed.
“This initiative brings together our most advanced technologies to help solve one of the greatest challenges of the AI era: evolving our electricity systems to meet this moment,” Corio said. “We see the opportunity to help secure America’s electricity needs with the many resources seeking to provide energy to the grid and believe this work with PJM is a great catalyst for innovation across the United States.”
The sluggish pace of new entry is one of three contributors to a potential capacity deficiency that PJM has identified in the 2029/30 delivery year, alongside generation deactivations and ballooning load largely fueled by data centers. Executive Vice President of Operations, Planning & Security Aftab Khan said the RTO’s shift to a cluster-based approach to studying interconnection requests is allowing it to more expeditiously work through its backlogged queue, but it still will take about two years for projects to go through the process. Integrating more artificial intelligence into those studies can add more efficiency and quality to studies, he said. (See PJM Reaches Milestone on Clearing Interconnection Queue Backlog.)
“Innovation will be critical to meeting the demands on the future grid, and we’re leveraging some of the world’s best capabilities with these cutting-edge tools to further reduce completion times for new service requests,” Khan said. “PJM is committed to bringing new generation onto the system as quickly and reliably as possible.”
Renewable developers and consumer advocates have pointed to PJM’s interconnection queue as a central obstacle to getting clean energy onto the grid and allowing generation owners to respond to high capacity prices. In a complaint filed at FERC, Pennsylvania Gov. Josh Shapiro (D) argued for a lower maximum capacity price on the grounds the new generation cannot respond to price signals sent by upcoming Base Residual Auctions. PJM has defended the process, saying more projects are clearing the queue but are becoming mired in other issues challenging development, such as supply chain constraints and permitting requirements. (See PJM Presents Capacity Price Cap and Floor to Members Committee.)
Page Crahan, general manager of X’s electric-oriented Tapestry, said a core challenge grid operators face is information being siloed across disparate information streams and tools, an environment she said could be streamlined through using Google’s expertise in data management to create a unified model of the grid, pulling together the output of existing tools to create a “knowledge graph.” She said the name Tapestry was chosen to represent the goal of creating a platform that can stitch together the fragmented elements of the grid.
Speaking during a press conference ahead of the announcement of the partnership, Crahan said one area that could be improved by adding AI is processing PDF applications submitted by generation owners with new projects. Assessing the information in those files creates a bottleneck in the study process, where planners have to consult multiple tools, models and datasets when modeling how a new generator may impact existing equipment. She also gave the example of using AI to aid in validating information provided in interconnection applications; rather than planners having to refer to multiple documents to determine whether the land rights are associated with the correct builder, she said Tapestry software could sift through those files.
Tapestry already has partnered with system operators across the globe, including developing “near real-time grid virtualization” software to simulate AES’ distribution grids in Ohio and Indiana, as well as advanced inverter technology working with Australia’s Commonwealth Scientific and Industrial Research Organization.
Crahan said Chile’s National Electric Coordinator (CEN) has deployed the Grid Planning Tool to allow planners to simulate its grid 86% faster, allowing 30 times the number of scenarios to be run. Google’s DeepMind software also has improved CEN’s weather forecasting for wind.
Unlike those other projects, Crahan said the work with PJM will be the “first of its kind” to integrate AI into the modeling interconnection study process of a large grid coordinator. X is aiming to deliver the first tools to PJM in 2025, she said.
In response to questions on how the effort to speed interconnections may interact with President Donald Trump’s executive order April 8 seeking to ease regulations on coal generation, Khan said PJM is fuel agnostic and will welcome any resource that can improve reliability. He added there are many factors that can impact the viability of coal, including the growth of gas generation. (See related story, Trump Seeks to Keep Coal Plants Open, Attacks State Climate Policies.)
Corio said Google remains dedicated to its climate goals and will continue to seek clean energy sources that can provide firm capacity. She specified that coal is not a clean technology under that framework.
The American Clean Power Association on April 8 released a report produced by The Brattle Group laying out how organized markets can replicate the success CAISO and ERCOT have had in deploying energy storage resources.
The “Energy Storage Market Reform Roadmap” includes detailed changes for the energy, capacity and ancillary services markets, with individual “road maps” for MISO, NYISO and PJM guiding how to grow storage in their territories.
The report and road maps focus on those grid operators because they have “opportunities for market reform,” their states are pursuing decarbonization, and they have a mix of central planning and market-based investment.
CAISO and ERCOT have shown that with updated market rules, energy storage delivers substantial value and complements both thermal and renewable generation to help meet reliability needs.
“Energy storage technologies add a new dimension of flexibility and efficiency to our electric grid,” ACP Vice President of Energy Storage Noah Roberts said in a statement. “Energy storage has proven to boost reliability and lower energy costs. In Texas, the state added 5 GW of energy storage in one year, eliminating calls for customers to reduce electricity use during historic summer heat, stabilizing the grid through volatile winter storms, all the while delivering more than a billion dollars in energy cost savings. This road map outlines actionable steps to better utilize energy storage to deliver reliable and affordable power across the United States.”
Before FERC issued Order 841 in December 2020 to open up the RTOs to energy storage, the resource faced barriers to participation in the markets, which were designed around the attributes of other generators. Where the organized markets have encouraged deployment and removed barriers, storage has helped prevent blackouts and reduced pressure on customers during tight operating conditions on the grid, while delivering cost savings, ACP said.
One of the areas the report and road maps focus on is the need to replace retiring generation while maintaining reliability and meeting growing demand in many parts of the country. Storage can help replace the reliability services retiring generation provided while keeping a lid on high capacity prices, ACP said.
Many generators were planned to support local transmission needs, especially when they were built in load pockets. Retirements will continue to trigger transmission violations, and some of those are too localized for capacity markets to solve.
The industry’s historic answer for those situations is to build transmission, and sometimes to keep power plants running with out-of-market, reliability-must-run contracts while that is built. But storage, or non-wires alternatives, can contribute to solving those issues at lower costs to consumers, the paper says. “RTOs should identify solution(s) that lead to the lowest costs for ratepayers when procuring reliability solutions out of market.”
Some RTOs, including PJM, do not consider non-wires alternatives for retiring generators. Others do, but they are rarely picked because of a lack of comprehensive benefit-cost analysis, which is exacerbated by the short notice period between the solicitation date and required online date, the report says.
On average in PJM, RMRs have cost $300/MW-day, which is well above the market clearing prices in the long term of $100/MW-day, according to the paper. Studies have shown the benefits of competitive solicitations both in transmission infrastructure procurement and generator procurement, it says.
Energy storage — especially long-duration and multiday — may be able to resolve both transmission security constraints and provide flexibility value to the grid, the report argues.
The report highlights how CAISO oversaw a process to replace the 165-MW Oakland gas plant that announced its retirement in 2016. The ISO picked Pacific Gas and Electric’s Oakland Clean Energy Initiative, which included some transmission upgrades, storage and demand response that met the need at a lower cost than transmission or generation solutions alone.
It also pointed to NYISO’s efforts to replace the dual-fuel Narrows and Gowanus plants that were slated for retirement this year. The plants were to be replaced by the Champlain Hudson Express Line to bring hydropower down from Quebec, but the line was delayed until 2027.
NYISO identified a short-term reliability need and issued a competitive solicitation for a solution, but none of the responses could solve it in time. Recently, NYISO said the peaker plants will still be needed for the next couple of years. (See related story, NYISO Reaffirms Need for NYC Peakers in Summer.)
“As electricity grids struggle to keep pace with the feverish growth in energy demand across the country, every electron of power counts,” Eolian COO Stephanie Smith said in a statement. “Battery energy storage helps both thermal and renewable energy technologies optimize their participation and increase reliability and resilience by providing power when and where it is needed quickly. By updating existing rules to account for new technologies, regional electricity markets can enhance grid performance and lower costs for consumers.”
ALBANY, N.Y. — Energy and transmission development in New York can be an exercise in patience and persistence, with supportive policy messages counterbalanced by complex regulations, high costs and long timelines.
The annual New York Energy Summit often is a showcase of this dichotomy, a chance to catch up on the latest developments in the Empire State and share thoughts on how to build on those changes or get around them.
The 2025 edition of the event could have been more of this, given the important policy decisions being hashed out a block away in the state Capitol. But they often seemed overshadowed by national developments — a brewing global trade war, trillion-dollar hourly swings in the financial markets and murmurs of a recession or stagflation bearing down on the U.S. economy.
Clearly the need to expand and modernize New York’s grid persists regardless of who is in the White House, and the timelines will extend beyond the term of any one president, or any three.
But as recent weeks have shown, a president can change the landscape markedly in much less than a single term — or even worse, shroud the landscape in a fog of uncertainty.
As New York Public Service Chair Rory Christian noted in a keynote address: “Difficult times lie ahead.”
“Inaction is not an option,” he said. “I encourage you to lean into this moment, not despite the uncertainty, but because of it.”
New York’s grid is like most others — it needs extensive and expensive modernization and expansion as it faces potentially huge load growth. The state also has some of the most ambitious plans in the nation to decarbonize the power portfolio feeding that grid, as well as some of the highest costs and most rigorous processes for carrying all these plans out.
Rapid-fire directives coming from the White House since Jan. 20 have made the prospect more daunting.
Inflation and interest rate fluctuations have created new financial risks, as have President Donald Trump’s repeated tariff threats. Previously committed grants and tax incentives remain under threat.
“If there’s one message to take away today it is that the state of New York is fully committed to our clean energy goals,” said Georges Sassine, vice president of large-scale renewables for the New York State Energy Research and Development Authority, which is leading the efforts to decarbonize the state, particularly its generation portfolio.
Christian heads the Department of Public Service, which leads regulatory efforts to put the infrastructure in place to accomplish these policy goals.
“[The goals] require, above all, a modernized grid,” Christian said. “We’re entering an era where our history of flat demand and flat load growth is no longer the norm. We’re in an era where need for interconnecting multiple resources in a short period of time is no longer a luxury but a necessity.”
Christian laid out some of the steps being taken toward this Grid of the Future, as the proceeding is named, and toward the flexibility needed to make it meet the needs at an affordable cost.
Like any long-running process with thousands of stakeholders, there is not unanimous agreement on the details, nor universal satisfaction with the pace.
The state has seen slow buildout of renewables in the nearly six years since passage of its landmark climate law mandated the transition, and multiple panelists said state regulators need to adjust their approach accordingly — fossil fuels will be needed longer than the state hoped.
Matt Schwall, director of regulatory affairs for Alpha Generation, said all six of his company’s plants in New York are operating with Title Five state air permits that are expired and awaiting renewal.
“And that’s not just unique to us; that’s every generator in the state. It’s tough to convince an investor to put money in the state when you don’t know if you can even get a permit.”
Independent Power Producers of New York President Gavin Donohue, whose members produce much of the state’s electricity, said reliability concerns are growing.
“The state needs to be realistic about what it takes to keep the lights on, on a day-to-day basis, and there needs to be a recognition that permits need to be issued in an effort to maintain that reliability,” he said.
NYISO Vice President of Market Structures Shaun Johnson said: “Particularly in some areas of the state, we have razor-thin margins. We, at the moment, don’t have a lot of flexibility to be able to ramp up new generation quickly and meet those future demand needs.”
The solution, he added, is not simple; it is a mix of load demand, market signals and state policy that will attract investors. “Because at the end of the day, they can choose — am I going to come to New York? Am I going to go to Virginia? Am I going to go to Texas? Where am I deploying my capital? And in some ways, we’re all competing against each other for that capital.”
New York has had some very visible problems adding generation — 88 renewable projects canceled their offtake contracts after cost escalations swept the industry in 2023. Those projects would have provided sizable progress toward the state’s clean energy goals and toward meeting the need for more gigawatts of capacity. The contracts are gone but the projects themselves are not necessarily dead, and the state will try to draw them and others back into its portfolio.
Sassine said more requests for proposals (RFPs) are in the works, along with requests for information (RFI) to shape those RFPs.
“We very much look forward in these RFI processes to get feedback from all stakeholders on how we should be thinking about risk-sharing, going forward in light of all this federal uncertainty,” he said.
The state-owned New York Power Authority has begun working in its new role as a renewables developer, and the vice president leading the effort, Vennela Yadhati, said renewables have a key advantage over the fossil fuel generation that suddenly is in favor in Washington: speed of deployment.
Multiple speakers at the summit noted the yearslong wait for a newly built gas turbine. Yadhati contrasted the relative speed with which solar and onshore wind generation are being built and cited the resilience those industries have developed.
“The renewables industry has been through administration changes in the past,” she said. “We have been through uncertainty in the past, but we continue to strive and thrive, actually, in this market.”
Marguerite Wells, executive director of Alliance for Clean Energy New York, placed some of the onus for moving ahead on the renewable energy developers themselves.
Some developers, she said, have submitted “tire kicker” proposals they were not fully committed to, contributing to the sluggish nature of the NYISO interconnection queue, and others have cut corners on their community outreach efforts — a potentially serious mistake in a home-rule state where local opinion can slow or block a proposal.
As the level of public opposition and concern around projects and politicization of renewables grows, it is more and more incumbent on developers “to do a better and better job with community relations and stakeholder work,” Wells said. “I think that often gets short shrift.”
New York’s infamously slow timelines, she added, are getting better, through the state’s streamlined regulatory processes and through NYISO’s newly revamped interconnection process.
“I think we can see that the new process is doing what it’s supposed to do,” Wells said. “It’s painful to go through it now. It’s much more expensive and it’s faster, and it’s more technically challenging to get all that work done in a shorter period of time. But the end goal is to have an interconnection process that more similarly mimics what Texas has done, which is get a project through in a year or two. Used to be five to seven in New York, and that’s not necessary.”
U.S. Rep. Daniel Goldman (D) conceded that his opinions hold no sway with Trump and that he is worried about the fate of renewable projects both present and future.
But he said the country’s need for electricity and the benefits renewables have provided for red congressional districts will be more influential than the opinions of a congressman representing a deep-blue New York City district.
Goldman urged listeners to stick with the approach that most of the renewable energy community seems to have adopted the day after Election Day, emphasizing the good of the nation rather than the good of the planet.
“Let’s set aside the climate benefits as we are making this case right now, because the economic and national security case for clean energy is stronger than ever.”
He added: “We absolutely cannot give up with this administration — even if those wind turbines are unattractive.”
Sergio Garcia, executive director of project finance at Rabobank, counseled patience and a longer view. Financial planning is difficult until budget and policy negotiations produce a firm picture of the tax incentives that grew from the Inflation Reduction Act.
“Right now, we’re all distracted with the IRA,” he said. “It’ll change — in what form, I have no clue. Until we have visibility in there, it makes your jobs a lot harder, because you need to deploy capital.”
Garcia added: “It’s a reality check, right? It did work before the IRA, and it’ll work again in one form or another, and renewables will continue to strive because it is the lowest levelized cost of energy. So I think there’s plenty to do. I think that banks are all active, and we’re all like looking for projects to finance.”
Texas’ loan program for gas generation has lost two more projects, marking the third and fourth companies to withdraw projects from the due diligence review process.
Constellation and WattBridge became the latest to pull projects from the Public Utility Commission’s In-ERCOT Generation Loan Program, part of its Texas Energy Program. The companies took out four projects totaling 1,410 MW.
The 16 remaining applications total 8,346 MW of capacity and $4.46 billion in requested loan amounts. The TEF is a $5 billion, low-interest program designed by lawmakers to quickly add new natural gas plants.
PUC spokesperson Ellie Breed said staff intend to advance additional applications to the due diligence phase at a future open meeting.
Constellation was seeking financing for 300 MW of gas-fired generation at its Wolf Hollow III facility. It told the PUC in March it was unable to determine “with certainty” the project’s overall costs because of the “uncertain timing” in receiving an air permit from the Texas Commission on Environmental Quality. That would prevent Constellation from signing a binding loan document.
Wattbridge withdrew three projects totaling 1,110 MW of capacity. It said the TEF’s financing terms “introduce risk and costs that result in lower than anticipated returns with elevated risks.”
The company also said it was withdrawing a 510-MW project in the Houston region from the pool of remaining applicants.
Two other companies pulled their projects from the TEF earlier in 2025. They cited supply chain issues as delaying the projects and keeping them from meeting a December 2025 deadline for initial loan disbursements. (See 2 Companies Withdraw Texas Energy Fund Projects from Consideration.)
More than 4,650 MW of capacity has been withdrawn or denied from the original submitted applications. Nearly a third (3,903 MW of 12,249 MW) of the projects that advanced to due diligence now have been withdrawn or denied.
“Texas will get new gas resources … but gas plants take time,” noted Stoic Energy principal Doug Lewin in his newsletter. “They can’t be developed fast enough to ensure reliability or allow for economic growth in the next three or four years, and possibly longer than that.”
Kristi Hobbs, ERCOT’s vice president of system planning and weatherization, told board members April 7 that all 16 Texas Energy Fund projects recommended for due diligence by the PUC have submitted full interconnection study (FIS) applications with the ISO and are in various phases of the generation-interconnection process. Seven applicants have completed the full study processes.
“Moving forward, a lot of progress on those,” Hobbs told the board.
The TEF was created by the Texas Legislature in 2023 to add more dispatchable generation to the grid and was approved by voters later that year. Managed by the PUC, it is designed to provide grants and loans to finance construction, maintenance, modernization and operation of electric facilities in the state.
The fund is composed of four programs: In-ERCOT Generation Loans, In-ERCOT Completion Bonus Grants, Outside-ERCOT Grants and Texas Backup Power Package.
In other business, Hannah Johlas of ISO-NE presented an analysis of how ambient temperatures affect the performance of non-nuclear thermal resources, which the RTO developed in response to stakeholder requests. The analysis included an evaluation of third-party studies, capacity audit data and historical operational data.
All three components of the study showed a significant decline in the capacity of thermal resources as temperatures increased, equal to about a 3-4% decline in performance between 90 and 100 degrees Fahrenheit. The analysis did not evaluate the effects of ambient temperatures on fuel availability or resource outages.
While ISO-NE plans to calculate resource capacity accreditation at 90 F in the summer and 20 F in the winter, some stakeholders express concern that temperatures beyond this range could affect reliability.
ISO-NE does not plan to include modeling of ambient temperature effects in the CAR project due to the limited impacts and challenges of incorporating the additional modeling into the project. Johlas said it’s uncommon for the entire resource fleet to face temperatures above 90 F, even as climate change increases temperatures.
Some stakeholders pushed back on this conclusion, making the case that extreme heat often coincides with stress on the grid, and that a 3-4% reduction in the capacity of a 22,000-MW thermal fleet could cause a capacity reduction of up to 880 MW.
Demand Response Distributed Energy Resource Aggregations
Also at the MC, Dennis Cakert of ISO-NE presented conforming changes for FERC Order 2222, focused on demand response distributed energy resource aggregations (DRDERAs), which are aggregations of DERs that can reduce demand and inject energy into the grid.
Order 2222 requires transmission operators to eliminate barriers for distributed energy resource aggregations to participate in wholesale markets.
ISO-NE proposes to make DRDERAs eligible to participate in the day-ahead ancillary services market and to receive net commitment period compensation (NCPC). Including DRDERAs in NCPC would prevent “economic incentives to not offer true costs or follow dispatch instructions” in the energy market, Cakert said.
ISO-NE also proposes to reduce the minimum size requirement for resources participating in the regulation market from 5 MW to 100 kW “to align with the approved Order No. 2222 design.”
The changes would take effect in November 2026. ISO-NE will continue discussions on the conforming changes at the MC in May, targeting a vote on the proposal in June.
Tie Benefits
Matthew Ide, representing the Interconnection Rights Holders Management Committee, presented on the value of tie benefits and pushed back on the New England Power Generators Association’s (NEPGA’s) arguments in March that including tie benefits in the installed capacity requirement (ICR) creates reliability risks. (See ISO-NE Gives Updates on Prompt, Seasonal Capacity Market Changes.)
The ICR determines the amount of capacity ISO-NE must procure in the capacity market, while tie benefits refer to the emergency support New England can expect to receive from neighboring regions during a capacity shortage.
At the MC in March, Bruce Anderson of NEPGA said the “current market design ‘assumes away’ approximately 2,000 MW of capacity demand based on the belief that system energy from neighboring control areas is equivalent to ‘firm capacity,’” creating risks of under-procurement and price suppression.
At the April MC meeting, Ide emphasized that tie benefits are not a market product, and instead are “the reasonably assumed reliability benefits that come from transmission infrastructure that enables emergency assistance between regions.”
Tie benefits “are a reasonable and appropriate input into the ICR calculation,” he added.
Ide said tie benefits are supported by contracts ensuring ISO-NE will receive tie benefits from neighboring regions if this support does not jeopardize reliability in the neighboring region. Even if weather conditions are similar across regions, it’s highly unlikely for regions to experience resource outages threatening reliability at the same time, he said.
“Network load customers pay for all the tie benefits that come from the [pool transmission facility] ties through regional transmission rates. In return, load receives the benefit of a lower ICR and less need to procure capacity to meet the ICR,” he added.
He noted that FERC has found including tie benefits in the ICR to be just and reasonable, and that a recent ISO-NE analysis found the “underlying methodology is robust and thorough in the capacity quantification of tie benefits.”
ICR in a Prompt Auction
Manasa Kotha of ISO-NE discussed how the transition to a prompt market will affect the RTO’s methodology for establishing the ICR. He said ISO-NE will begin the ICR process about a year prior to each capacity commitment period.
“The primary conforming change for the ICR setting process is mainly the timeframe,” Kotha said, adding that reducing this timing from four years to one year will allow ISO-NE top use more up-to-date data, load assumptions and interface limits.
“Under CAR-Prompt, the data will all be provided closer in time to the commitment period, which is expected to enhance the accuracy of the ICR-related values,” Kotha said.
ISO-NE discussed its plans for preventing and mitigating market power as it overhauls its capacity market and resource retirement processes at the NEPOOL Markets Committee’s meeting April 8.
The RTO’s Capacity Auction Reform (CAR) project proposes to reduce the time between auctions and capacity commitment periods, transitioning the region from a forward market to a prompt construct. ISO-NE also plans to decouple resource retirements from the capacity offer process because the timing of the prompt market would not give the RTO enough time to address reliability issues created by retirements.
Under the new format, ISO-NE would require retiring resources to submit deactivation notices two years prior to their retirement from the market. As proposed, retirement notices would be binding and trigger an ISO-NE review process of potential reliability and market power issues. (See ISO-NE Gives Updates on Prompt, Seasonal Capacity Market Changes.)
The market power analysis would include a conduct test to evaluate whether the resource is expected to be economic and a net portfolio benefits test to study whether a market participant’s overall portfolio would benefit from the resource retirement.
If a resource fails both tests, ISO-NE would issue a penalty equal to 1.5 times the participant’s expected portfolio-wide revenue increase from the retirement. These charges would be credited as a refund to all market participants.
“The market power charge is expected to be used infrequently,” said Kevin Coopey, principal analyst at ISO-NE. “Ideally, the risk of being charged deters the exercise of market power.”
The tests and charges would be based on expected market outcomes prior to the forward auction, instead of the actual market results.
“By evaluating market power at the notification deadline, we consider the perspective of the participant at the time of the deactivation notification,” Coopey said.
Coopey said basing market power charges on the actual auction results would create a nearly two-year delay for participants to learn the actual charge amount, creating significant uncertainty associated with unexpected events distorting market results and risks of excessively large charges.
Some stakeholders expressed concern about reconciling differences between the market expectations of participants and the ISO-NE Internal Market Monitor.
“The IMM acknowledges that different assumptions may be reasonable when the market participant holds different market information or beliefs,” Coopey said. “The IMM will accept different assumptions when they are reasonably justified.”
Responding to stakeholder requests for ISO-NE to allow participants to withdraw retirement requests, Coopey said the RTO is “considering the feedback,” adding that “the increased optionality of having withdrawable notifications must be balanced against the risk of increasing the likelihood of reliability retentions.”
ISO-NE has expressed concern that participants could fish for out-of-market resource retentions if they are allowed to withdraw a retirement request when a resource is not retained.
Responses to the proposal for a market power charge have been mixed, with some stakeholders arguing the proposal may not be punitive enough to prevent exercising market power, while others made the case it would be too punitive and could create reliability issues by preventing deteriorating resources from retiring.
Ben Griffiths of LS Power advocated for more flexibility on the timing of retirement submissions, proposing that resources not needed for reliability should be allowed to retire with less than two years of advance notice.
“Without commenting on the merits of the two-year notice proposal, allowing for accelerated exit of resources determined nonessential for reliability would reduce market inefficiencies and resource owner concerns about forced market participation,” Griffiths said.
“Optional, expeditious deactivation for non-reliability resources lets the region split the difference on notification: Longer notice period lets the region proactively explore reliability implications of each deactivating resource, while accelerated exit allows it to avoid a lengthy exit period when they aren’t needed,” he added.
Also at the MC meeting, ISO-NE presented its plans for mitigating market power concerns on offers within the capacity market. Andrew Copland of ISO-NE said that “in the ISO’s current design, most key components of seller-side market power mitigation framework will remain substantively unchanged.”
He said ISO-NE will run a conduct test and a pivotal-supplier test to evaluate market power, and it plans to impose a “binding offer ceiling at the IMM’s estimated competitive offer price” for resources that fail both tests. Copland said ISO-NE will publish a capacity cost review threshold; all offers that surpass the threshold will be subject to cost review by the IMM.
Copland also noted that ISO-NE is updating its auction participation rules for the prompt market and will require “all commercial resources capable of providing capacity … to offer it into the auction.”
He said resources that hold unused capacity interconnection rights pose a barrier for other resources looking to enter the market and could cause these resources to incur significant interconnection costs. He noted that participants can include multiple cost levels within a capacity offer from a single resource to account for the potential added costs of offering a resource’s full capacity.
ERCOT, Oncor and the Texas Public Utility Commission have asked FERC to deny a petition from Puerto Rican company Pluvia to bring the territory under the commission’s Federal Power Act jurisdiction (EL25-57).
The parties all filed similar motions, but none of them were aware of the petition, filed in early February, until after the due dates for comments, they said.
If the commission granted Pluvia’s petition, the precedent would threaten ERCOT’s jurisdictional status, in which its few connections to the rest of North America’s grid do not give FERC jurisdiction over its markets, the Texas grid operator said April 8.
“ERCOT recognizes the immense challenges the people of Puerto Rico have endured since Hurricane Maria and supports efforts to rebuild and modernize the island’s electric grid,” it told FERC. “Yet, as explained below, Pluvia’s petition is not the right path to achieve these crucial goals.”
Granting the petition would require an unprecedented reinterpretation and expansion of FERC’s licensing jurisdiction under FPA Part I, which authorizes the commission to license non-federal hydroelectric projects on federal reservations or affecting navigable waters of the U.S., and under another section that gives FERC power to grant preliminary permits for such projects.
But using storage to transmit power is not a hydro project; the proposed sites in Puerto Rico are not considered federal reservations; and the transportation of cargo from the mainland to the territory would not involve crossing navigable waters of the U.S., ERCOT argued.
“Such a radical change could have serious implications for the jurisdictional independence of Texas’s intrastate ERCOT grid,” said the PUC, which oversees ERCOT’s markets in the same way FERC regulates others in the U.S. All the transmission between it and other states is provided pursuant to FERC orders under sections 210 and 211 of the FPA.
“Because Pluvia’s proposal does not involve any physical flow of electric energy between states, Pluvia presents no valid basis for the requested declaration,” the PUC said. “What Pluvia requests would be a radical redefinition, contrary to precedent, of the meaning of ‘electric energy’ under the FPA to include stored potential energy that would later be converted into electric energy. And it would redefine ‘transmission’ under the FPA to include the shipment of charged storage devices that does not involve the flow or comingling of electric energy in interstate commerce. …
“This ‘clarification’” — as Pluvia said in its request — “is contrary to law and totally unjustified: It would require the commission to ignore the plain text of the FPA and depart from well-established precedent analyzing the same issues in the context of the ERCOT market.”
Oncor had filed to intervene in late March, making similar arguments, and Pluvia had asked FERC to deny the late intervention.
Oncor responded that while it was late, Pluvia’s project is in early stages and FERC actually weighing the merits of its earlier filing would not burden it. FERC has been liberal in allowing late interventions in cases involving its jurisdiction, Oncor said.
“Even if Oncor had not moved to intervene in this proceeding, the commission still would need to assure itself that it has statutory authority to grant the relief Pluvia seeks,” the utility said. “As such, Oncor intervening to raise jurisdictional arguments does not unduly prejudice or burden Pluvia.”
