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December 5, 2025

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New England Energy Executives Debate Markets, Affordability

BOSTON — An increasing political anxiety around energy affordability permeated debates about wholesale market changes, federal policy and demand growth at the annual New England Energy Summit on Dec. 2.

Speakers at the event, hosted by the New England Power Generators Association (NEPGA) and the Dupont Group, grappled with how to lower consumer costs while simultaneously supporting the development of new generation and transmission infrastructure needed to keep pace with accelerating demand growth.

Panelists also expressed differing views on how prepared the ISO-NE markets are for a rapid increase in demand.

NEPGA President Dan Dolan stressed that wholesale markets have not been the cause of rising retail energy costs in New England, noting that capacity prices have remained low in recent auctions.

These low prices have contributed to “a four-year major retirement cycle with over 3,000 MW going away,” Dolan said.

NEPGA President Dan Dolan | © RTO Insider 

He emphasized the need to first ensure the markets are sending the right signals, and then let them operate, even if that leads to periods of high prices. To allow the market to respond to high prices, state and federal policymakers must focus on lowering barriers to development, he said.

He acknowledged that this is “easy to say, but extraordinarily politically challenging to implement.”

‘Massive Stress’

ISO-NE CEO Gordon van Welie said the transition to wholesale markets has brought major cost savings to the region over the past 25 years, in part by helping to shield consumers from poor investments. But there is still work to do, he said.

“There was a moment in 2019 when we seriously considered abandoning the capacity market,” he said, pointing to problems in the RTO’s Forward Capacity Market related to forecasting, phantom entry and accreditation. Its ongoing Capacity Auction Reform project is intended to address these issues for the 2028/29 capacity commitment period (CCP).

Van Welie added that the region would benefit from a more robust bilateral trading regime, which could help reduce volatility for consumers. He expressed hope that the RTO’s proposed transition to a prompt capacity auction — in which auctions would be held about one month prior to each CCP — would “push people more into bilateral contracting.”

While ISO-NE’s prompt market proposal has garnered strong stakeholder support, some NEPOOL members have voiced concern that the shift to a prompt market could increase inter-annual price volatility, while adopting a seasonal market would introduce intra-annual volatility. Some stakeholders have asked the RTO to look at ways to encourage bilateral trading to hedge the volatility risks.

Van Welie, who is retiring from the RTO at the end of the year, said market volatility increases the likelihood of political intervention — such as price caps — in the markets.

He added that politicization around energy has already increased in recent years, creating “massive stress” within ISO-NE, with various groups often blaming the RTO for issues outside of its control and politicians using the RTO “as a piñata.”

“It’s escalated to the point of bomb threats and death threats, and I think that’s really not a good place to be,” he said.

Yin and Yang

Referring to the political blowback that occurred in PJM following skyrocketing capacity prices, Anthony Crowdell, senior analyst for Mizuho Americas, expressed pessimism about the future of wholesale markets in a world of rapidly growing demand.

“I think that politicians will end up blowing up the markets,” Crowdell said.

Regarding offshore wind development, he said the Trump administration’s efforts to undermine the industry appear to have done irreparable damage.

“Unless it is a state entity or a federal entity building it, offshore wind is done in the United States,” Crowdell said.

Justin Trudell, CEO of FirstLight Power, said changes in federal policy have caused the company to shift some investments to Canada.

“The next hundreds of millions of dollars that we invest through FirstLight are going to be in Ontario and, likely, in Quebec,” Trudell said.

“What we’re seeing in Canada is when you do have alignment with the provincial and federal governments, you’re seeing explosive growth,” he added.

Other speakers downplayed the Trump administration’s long-term effects on energy development.

“I think there’s a lot of noise in the current administration, but I don’t see a lot of tangible things,” said Curt Morgan, CEO of Alpha Generation. He added that, beyond the offshore wind industry, “I don’t think they’ve moved the needle that much.”

Sherman Knight, CEO of Competitive Power Ventures, echoed Morgan’s comments and said the federal policy changes have not shifted the company’s priorities in the 2030-2035 time frame.

“I think we have to think about it from a more fundamental standpoint of what’s going to work,” he said. “There’s so much uncertainty over that long period of time, and you just can’t develop and build even within an administrative cycle.”

With significant demand growth on the horizon, Morgan stressed the need to stop the cycle of generator retirements. He criticized ISO-NE’s Pay-for-Performance (PFP) rules, which have led to significant penalties for slow-start thermal generators during capacity deficiency events.

“I have some real concerns about how we’re treating existing generation. But I tell you, over time, that generation is going to become as valuable as gold,” he said.

He also criticized the frequency of rule changes in the ISO-NE capacity market.

“Almost every year, we’re making a tweak or a change to the capacity market,” Morgan said. “People don’t believe the markets are going to be allowed to work, and frankly they haven’t been allowed to work.”

ISO-NE board Chair Cheryl LaFleur said that hints at an “age-old dilemma” that frequently came up during her time at FERC.

“People say ‘stop making changes, do not make any changes … except fix [PFP], fix ancillary services — just make my change, then stop making changes.’ It just seems to be the constant yin and yang.”

“I didn’t say it was easy,” responded Morgan.

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DOE’s National Petroleum Council Releases Report on Gas-electric Coordination

The Department of Energy released a pair of reports from the National Petroleum Council recommending changes to gas and electric coordination and to permitting rules for oil and gas.

The council is a federal advisory committee made up of leaders from the oil and gas industry and academia, with power sector interests participating in the coordination report.

“The National Petroleum Council’s findings confirm what President Trump has said from Day 1: America needs more energy infrastructure, less red tape and serious permitting reform,” Energy Secretary Chris Wright said in a statement Dec. 3. “These recommendations will help make energy more affordable for every American household.”

The coordination study shows how rising natural gas and electricity demand are combining with shifting use patterns to “strain natural gas pipelines in key regions of the United States.”

“Since natural gas became the dominant fuel for U.S. electricity generation in 2016, the interdependence between the gas and electric systems has deepened — but so have the risks of misalignment,” the report says. “The two systems function under fundamentally different commercial, regulatory and operational frameworks.”

The gas industry is built around long-term contracts and steady demand, while the wholesale power markets are based on real-time market dispatch and hourly price signals. The differences create persistent mismatches in timing and incentives, especially during periods where demand is high for both — most notably during extreme winter weather, the permitting report says.

That issue is bigger in organized wholesale power markets, in which generators depend on hourly price signals and lack the incentives to pay for firm pipeline capacity.

“Their gas procurements rely less on long-term delivery contracts and more on a variety of shorter-term commodity procurements and lower-priority transportation arrangements,” the report says. “When the gas and electric systems are both under stress, these arrangements are the first to be curtailed.”

The two reports both recommend building new infrastructure, with part of the recommended fix to longstanding coordination issues being expanding pipelines. Electricity generation has become the biggest consumer group for natural gas, beating out local delivery companies, as coal plants have retired and been replaced by generators burning cheap shale gas.

“As a result, gas demand has become far more variable and dynamic, with power generators — especially in deregulated markets — often relying on secondary or interruptible pipeline capacity, which amplifies intraday and seasonal fluctuations,” the report says. “The rapid expansion of wind and solar resources, which together account for more than 60% of new U.S. generation capacity since 2010, has made gas-fired units essential for grid balancing, requiring flexible fuel supply and rapid ramping capability.”

Some pipeline expansion has happened over the past decade, but most of that involved reversing flow directions and adding compressors rather than building new lines. That has helped to meet higher demand, but it has also contributed to fewer flexibilities for generators that would benefit from them.

Storage would also help generators, but the sector has not invested in it, with most expansions being tied to LNG exports, the report says.

The report recommends that Congress and the executive branch take immediate legislative and administrative action to reform permitting to unlock fit-for-purpose infrastructure investment. The two industries should work together to expand new infrastructure to serve generation and prioritize actions to enhance and expand existing infrastructure.

Most previous gas-electric coordination efforts have focused on the few peak winter days, but that risks the broader trajectory of the system, with electric demand poised to rise significantly in the coming decade and some regions’ grids shifting to winter peaks from summer, it says.

The report notes that current market structures fail to incentivize generators to secure either long-term gas transportation or highly flexible premium products. The two sectors’ different business models mean the pipeline sector has not expanded to meet the growing needs of power generation.

The report calls on ISO/RTOs and state and federal regulators to ensure adequate risk-based compensation for gas-fired power generators to get enough fuel and operate reliably when called upon.

FERC should direct ISO/RTOs to conduct comprehensive long-term planning that integrates resource adequacy and fuel assurance considerations, the report says.

On the gas side, the report recommends that policymakers and the industry work to address changing hourly gas flow patterns with alternative tariff structures that enable enhanced gas service offerings and flexible contracting arrangements with generators.

The Natural Gas Council, which is made of trade organizations from that industry, and the Reliability Alliance, which includes the Electric Power Supply Association, Interstate Natural Gas Association of America and the Natural Gas Supply Association, released a joint statement supporting the reports and asking for state and federal regulators to act on its recommendations.

“Time is of the essence,” they said. “Policymakers and industry must act swiftly to develop the infrastructure that will win the global energy and AI race while continuing to meet growing demand for affordable, reliable and secure energy. While the natural gas and power industries are fully capable and committed to supporting our nation’s expected energy demands, we need additional direction and policy changes from state and federal policymakers to facilitate prompt implementation of these recommendations. We ask Congress, the U.S. Department of Energy, FERC and state commissions to undertake action aimed at ensuring adoption of the recommendations in these reports.”

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TEP Wins Approval for Data Center Energy Supply Agreement

Arizona regulators approved a 286-MW energy supply agreement between Tucson Electric Power and the developer of an embattled data center project near Tucson.

The Arizona Corporation Commission (ACC) voted 4-1 on Dec. 3 to approve TEP’s agreement with data center developer Beale Infrastructure Group and its affiliate, Humphrey’s Peak Power, to supply energy to the Project Blue data center in Pima County.

TEP officials said they won’t need new, dedicated resources for the 286-MW agreement. Instead, they’ll have capacity from resources already planned through the company’s 2023 integrated resource plan. Capacity also will be freed up through expiring wholesale contracts with utilities that now plan to use other market resources, they said, as well as delays and reductions in industrial load.

Commissioners said that without the energy supply agreement (ESA), the developer could simply take service under a large-load tariff — without customer protections that are in the agreement. TEP representatives noted that they’re obligated to provide service to customers in its territory.

“I don’t think we have an option at ‘no,’” Commissioner Lea Marquez Peterson said. “We need to make sure that we have an ESA … that protects all the ratepayers.”

Among the protections in the 10-year agreement is a minimum monthly charge that would apply if actual electricity demand is less than the contracted amount. Beale must give at least three years notice to terminate the agreement.

Power will be provided under a commission-approved rate schedule that would be subject to commission review in future TEP rate case proceedings.

TEP said the agreement would allow it to spread fixed costs across more retail electric sales, reducing the need for rate increases.

Beale will pay TEP the estimated $4 million for two new 138-kV transmission lines to exclusively serve the project. The cost of a new switchyard will be recovered through the utility’s FERC open access transmission tariff.

Beale is expected to start taking service in May 2027, ramping up to 286 MW in 2028.

Opponents Speak Out

Project opponents, including many Tucson-area residents, expressed skepticism of the agreement. Some predicted the data center would further increase utility bills for residents, who are already struggling to make ends meet.

“The main question that has not been answered by TEP is, where is this 286 MW really coming from and when are we going to pay for that?” Lee Ziesche of the No Desert Data Center Coalition told the commission. “There is nothing in the energy supply agreement that protects us from paying for generation.”

Opponents also questioned the viability of the data center project. Just days before the commission meeting, news outlets reported — based on comments from Pima County supervisors — that Amazon had pulled out of Beale’s data center project.

“As far as we know, Beale doesn’t have a customer,” a project opponent told the commission.

In an email to RTO Insider, a Beale spokesperson pointed to previous public comments from Amazon Web Services saying they had no agreements in place in Tucson. A Beale representative also addressed the issue during the ACC meeting.

“We feel confident that we will have a customer ready by the time the data center comes online,” said Sam Arons, vice president of energy and sustainability for Beale Infrastructure.

Commissioner Rachel Walden voted against the energy supply agreement. She shared residents’ questions about how generation would be paid for and said the agreement should include more protections, such as a higher buyout rate if the developer pulls out.

“This kind of sets the stage for future contracts,” she said.

Annexation Request Rejected

Beale Infrastructure plans to build Project Blue on a 290-acre parcel in Pima County. The county Board of Supervisors approved the sale and rezoning of the county-owned land to Beale in June.

The developer asked the city of Tucson to annex the project site, a step needed to procure water to cool the data center. The developer offered to build an 18-mile pipeline to bring in reclaimed water.

But in August, the Tucson City Council voted unanimously to reject the project, mainly due to concerns about the large amounts of water and energy it would require.

In September, Beale announced an updated design for Project Blue in which a closed-loop, air cooled system would be used for cooling. Under the new design, “minimal” amounts of water would be recirculated through a closed-loop, air-cooled system to provide industrial cooling, Beale said.

The new cooling method didn’t change the amount of capacity requested in TEP’s energy supply agreement.

Beale has also committed to pursuing 100% renewable energy for its Pima County data center. Initially the data center will be powered by renewable and non-renewable energy, and Beale will buy renewable energy credits to offset the non-renewable power.

Longer-term, Beale plans to work with TEP on developing new renewable resources for the data center, which the developer would pay for.

Future Phases

The energy supply agreement approved Dec. 3 applies only to Project Blue, which is the first phase of Beale’s plans for data center development in the Tucson area.

A second project, known as Luckett Industrial, is planned on two parcels in Marana, Ariz. One parcel is served by TEP and the other is served by Trico Electric Cooperative.

“Trico and TEP have both submitted letters stating that they will work with Beale to support the data center’s needs without impact to service or rates for [other] customers,” a Beale spokesperson said in an email.

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MISO Declines Stakeholder Ask for Pause on 2025 Queue to Clear Backlog

MISO said it will not postpone the kickoff of a study on its 2025 cycle of interconnection requests, rebuffing stakeholders’ requests for a slowdown to clear some of the queue’s four-year backlog.

“MISO doesn’t want to be looked at as slowing down the queue process. We do think we’re ready to kick off. … We’re committed to Jan. 5,” Manager of Generation Interconnection Ryan Westphal told the Interconnection Process Working Group during a teleconference Dec. 2.

Westphal said MISO would commence studies on the 2025 cycle of projects on Jan. 5, 2026, as scheduled.

Some stakeholders have advised MISO to delay the first studies on the 2025 queue cycle until the RTO is further along processing projects that entered three and four years ago, allowing developers to reach decisions on whether to continue with their plans. (See Stakeholders Ask MISO to Pause ’25 Queue to Get a Handle on 4-Year Backlog.)

But Westphal said FERC Order 2023 requires MISO to begin new interconnection study cycles 90 days after it closes an application window.

Westphal said MISO would have to seek a waiver with FERC to delay studies and cannot assume the commission would approve it, leaving the RTO no choice but to forge ahead with the early January timetable. He said MISO is working on prescreening the 2025 entrants.

“Seeking a waiver to postpone the 2025 cycle could be construed as MISO trying to slow down our queue process, which is directly counter to MISO’s direction to complete queue cycles in 373 days,” Westphal said.

Some stakeholders remain adamant that there are too many unknowns following study results to simultaneously process four years of interconnection requests.

REV Renewables’ Humberto Branco said the 2023 cycle is essentially a “wild card.” He said MISO trying to manage all cycles across all regions “just to get it done” is too much.

“There is some uncertainty there, I acknowledge that,” Westphal said. “We have to move these cycles forward as best we can.” He added that even later-stage queue projects fall victim to restudies.

Westphal said MISO continues to automate what it can using Pearl Street’s SUGAR (Suite of Unified Grid Analyses with Renewables) software. He said the RTO is now focused on automating some aspects of model building. (See MISO: New Software Effective, Faster than Previous Queue Study Process.)

Westphal said MISO only includes network upgrades for generation projects that have made it to the third phase of the queue in its base case modeling. He said those upgrades are the most likely to be constructed and not disrupt lower-queued projects. Westphal said MISO doesn’t want to give developers unrealistic cost responsibilities.

MISO Director of Resource Utilization Andy Witmeier said interconnection customers can mitigate the risk of higher-than-expected network upgrades by using model data posted by the RTO in their own analyses.

“The status quo is no longer acceptable. We have to continue to move these queue cycles forward to get this cleared and move to a one-year queue process,” Witmeier told stakeholders.

MISO’s Central and West planning regions still have projects in the queue from the 2021 cycle. Westphal said MISO is “trying to wrap up” those projects in early 2026.

The 2022 cycle — MISO’s largest — will emerge from the three-part queue’s second phase in early 2026. The RTO meanwhile expects the 2023 cycle to enter the second phase of studies late this year and conclude in early April 2026, while the 2025 cycle will finish up the first phase in mid-April.

Altogether, MISO has 174 GW worth of projects in its queue, a value that has fallen from 312 GW at the beginning of 2025. (See MISO Interconnection Queue Dips Below 175 GW.)

Coalition of Midwest Power Producers’ Travis Stewart said he appreciated MISO’s engineering efforts but asked staff to post projected dates according to when it could “realistically” reach milestones, not just the tariff-defined deadlines. He added that he has noticed the RTO is processing queue cycles noticeably faster now.

“It feels, from my perspective, that the pendulum has swung in terms of timing,” Stewart said.

Westphal agreed that MISO is seeing speedier results. He said the RTO is poised to complete the 2025 cycle in the span of a year.

“We’ve all got to be ready to move fast, and not just MISO, to get these cycles processed,” Westphal said.

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MISO Floats ‘Zero Injection’ Agreements to Bring Co-located Gen Online

MISO is considering a new type of interconnection agreement for generation built on site and strictly for new large loads.

Marc Keyser, with MISO’s external affairs team, said the RTO wants to introduce “zero-injection generator interconnection agreements.” Under the agreements, generators built solely to serve a data center or other large load customer would connect to the grid without the ability to inject power into the grid and serve load solely at the same interconnection point.

“Let’s explore this hypothesis of zero-injection generator interconnection agreements. … We’re hearing our members say, ‘Please move quickly. Please help us facilitate large load interconnections.’ So, this is one way of doing it,” Keyser told stakeholders at a Planning Subcommittee meeting Dec. 3.

Keyser said zero-injection GIAs could benefit large load customers, with MISO recognizing on-site generation in interconnection studies, “potentially reducing network upgrade requirements to interconnect.”

“The intent here is speed,” Keyser said, adding that MISO could “reflect the reality” in its queue analyses that some new generators are built solely to serve a single large-load customer.

Keyser acknowledged that the new GIA type would have limits and said a generator that wants full rights on the MISO system would still have to submit to the full-length queue process.

“It’s certainly not a full solution. You have a generator that cannot inject when you come out of the end of this,” he said.

The idea is part of MISO’s larger push to create registration and market participation rules for co-located generation and load.

“As these configurations become more common, we want to make sure our frameworks evolve to serve them,” MISO Director of Expansion Planning Jeanna Furnish said.

Keyser said the new type of GIA could work alongside MISO’s other efforts to incorporate large loads, including its interconnection queue fast lane, its long-range transmission planning, its expedited transmission request process and its ongoing efforts to cut regular queue processing down from about four years to 373 days.

Furnish said MISO would focus on how it can better enable large load integration over 2026.

But stakeholders said implementing the new, limited GIAs might not be as simple as RTO staff made it seem.

WEC Energy Group’s Chris Plante said stakeholders need time to “opine on the merits of such an arrangement.” Plante said he wasn’t sure MISO applying network status to generation barred from injection would square with FERC’s rule against RTOs netting behind-the-meter generation with load.

“I’m not even sure that we know this is feasible from that standpoint,” Plante said. “I’m very concerned that we’ve put something on the table that hasn’t gone through a full stakeholder discussion.”

Keyser said the proposal is in the early stages and that MISO doesn’t intend to “create a netting situation between load and generation.” He said the RTO would contemplate the loss of generation in its interconnection studies so as not to lump load and generation together.

He added that MISO has filed GIAs in the past with zero megawatts of injection service specified in them.

But Plante said MISO should examine what the generation would do without the load. He said if load trips and its dedicated generation does not, the generation would be injecting on the grid, “even if momentarily.”

“Can we sustain the loss of a 1.2-GW data center?” Plante asked hypothetically.

The Sustainable FERC Project’s Natalie asked MISO to stay focused on the technical details of the proposal, especially how curtailments of generation and load might be handled should either go offline unexpectedly.

“I want to make sure we don’t forget the important technical questions,” McIntire said.

American Transmission Co.’s Erik Winsand said MISO must decide on how it would conduct technical studies, as well as what tariff changes might be necessary to make zero-injections GIAs a reality.

MISO staff committed to refining their plan. Keyser asked stakeholders to bring opinions on whether the RTO should require a contractual link between load and generation or if the load and generation should be allowed to span electrically similar pricing nodes. He also asked for more advice on whether MISO should prepare for planning and reliability risks under the new GIAs.

Hoosier Energy’s Tommy Roberts said the idea was “exceptional” and that the RTO should move quickly to implement it.

“We’re going to get run over if we move slowly,” he said.

However, Roberts said he was concerned that diagrams in MISO’s presentation appeared to show two separate points of interconnection between the load and generation, instead of both behind a single point of interconnection.

“There is some level of injection just between two points on a switchyard out of data center,” Roberts pointed out.

Keyser agreed that the chart MISO presented was flawed and said the intent is for both load and generation to be situated behind the same point of interconnection.

MISO is scheduled to discuss its proposal at a Planning Advisory Committee meeting Jan. 21, 2026, and again during a stakeholder workshop Jan. 30 dedicated to discussing the implications of large loads.

Keyser said MISO would move “rapidly” over 2026 to firm up the proposal.

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ACP Tallies 11.7 GW of Solar, Storage, Wind Additions in Q3

New solar, battery storage and onshore wind power generation totaled 11.7 GW in the third quarter of 2025, the American Clean Power Association reported.

This is a record for the quarter and brings U.S. nameplate capacity for the three technologies to 344.3 GW.

As it released its quarterly market report Dec. 4, ACP said the high level of buildout had been expected, due to the momentum developed in the past several years.

But it warned that two other third-quarter metrics reflect the uncertainty and risks facing the renewables sector: The development pipeline of clean energy projects increased less than 1% from the previous quarter, and power purchase agreements were 31% lower than in the third quarter of 2024.

ACP CEO Jason Grumet said the unstable policy and regulatory landscape threatens the ability of the U.S. to meet future energy needs:

“The policy chaos at the federal level has seeped into every part of project timelines, stalling growth precisely when we need to meet demand and keep energy prices affordable for American families and businesses.”

He said this might be masked by the impressive numbers of the third quarter, which include:

    • 1,027 MW of new onshore wind;
    • 4,686 MW of storage;
    • 5,982 MW of solar;
    • 30,900 MW of wind, solar and storage installed in the first nine months of 2025, a record; and
    • 186,185 MW of wind, solar and storage in the pipeline of construction or advanced development, also a record.

The numbers within the report reflect a number of continuing trends:

Utility-scale solar continues to lead capacity additions. Onshore wind has long been the leading U.S. renewable, with 157.6 GW of installed capacity as of September, but solar is rapidly catching up and stood at 146.2 GW. The pipeline includes nearly 100 GW of solar but only about 28 GW of land-based wind.

The pipeline of U.S. clean power projects is represented on a map of the nation. | American Clean Power Association

Energy storage capacity continues to trace a sharp growth curve — 32% more additions were recorded in the third quarter of 2025 than in the third quarter of 2024, bringing total deployment to 40,321 MW/112,002 MWh.

The 4.5 GW of capacity added in Texas accounted for 39% of all U.S. clean power additions in the third quarter of 2025, due in large part to a surge in storage installations. Solar and storage additions totaling approximately 2 GW placed California second on the list of states. Only two projects came online in Utah, but they totaled 725 MW of nameplate capacity, which was enough for third place.

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CISA Publishes Guide for AI Critical Infrastructure Integration

To help critical infrastructure owners address the “opportunity and risk” of artificial intelligence, the Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency, along with the FBI and several overseas counterparts, released guidance for incorporating AI into operational technology systems.

CISA and the FBI developed the Principles for the Secure Integration of AI in OT document in collaboration with the National Security Agency’s AI Security Center, as well as security centers representing Canada, Germany, New Zealand, the United Kingdom and the Netherlands.

OT consists of hardware and software that interact with the physical environment, or manage devices that do so, according to the National Institute of Standards and Technology. They include industrial control systems, building management systems, fire control systems and physical access control systems.

The agencies wrote in an alert that while AI promises multiple benefits for OT environments, such as “increased efficiency, enhanced decision-making and cost savings,” it also poses “unique risks” for safety, security and reliability. The document focuses on machine learning, large language models and AI agents, but the authors wrote it also can be applied to “systems using traditional statistical modeling and logic-based automation.”

“While AI can enhance the performance of OT systems that power vital public services, it also introduces new avenues for adversarial threats,” Nick Andersen, CISA’s executive assistant director for cybersecurity, said in a news release. “That’s why CISA, in close coordination with our U.S. and international partners, is committed to providing clear, actionable guidance. We strongly encourage OT owners and operators to apply the principles in this joint guide to ensure AI is implemented safely, securely and responsibly.”

The guidance is organized into four key principles:

    • understanding the risks and impacts of AI in OT environments, the importance of educating personnel on these risks, and the secure AI development lifecycle;
    • considering the business cases for integrating AI into OT spaces, its short- and long-term challenges, and the role of vendors;
    • establishing governance mechanisms and testing procedures for AI models; and
    • embedding oversight mechanisms to ensure safe operation and cybersecurity of AI-enabled OT systems.

Risks posed by AI include the potential for manipulation of data, models and deployment software that causes incorrect outcomes or bypasses security and physical safety guardrails. Even without external manipulation, the authors observed that “AI models can only be as effective as the quality of their training data.” Collecting high-quality sensor data for the AI program can be difficult in distributed OT environments, they wrote, while centralizing operational data can create a target for cyber threat actors.

AI models also can become less accurate over time, the authors continued, as data is introduced that is not part of its initial training set. In addition, operators may have trouble understanding a model’s decision-making process, making it hard to diagnose and correct errors. Finally, operators may miss crucial information if they become too reliant on AI to manage their systems.

Regarding the business case for AI, the agencies recommended that infrastructure owners and operators determine whether AI is the most appropriate solution for their needs and requirements. This assessment should include security, performance, complexity, cost and effects on physical safety of the OT environment, along with the organization’s capacity for maintaining an AI system compared to established technologies.

OT vendors “play a crucial role in advancing AI integration,” the authors continued, writing that “some OT devices now come with built-in AI technology, which may require internet connectivity to function.” Operators “should demand transparency and security considerations” from vendors regarding their use of AI and connectivity, with contractual guarantees of open communication.

Governance mechanisms for AI should outline clear roles for leadership, OT and information technology subject matter experts, and cybersecurity teams. They also should provide data governance policies, audits and compliance testing to validate and verify performance.

“AI holds tremendous promise for enhancing the performance and resilience of operational technology environments — but that promise must be matched with vigilance,” CISA acting Director Madhu Gottumukkala wrote. “OT systems are the backbone of our nation’s critical infrastructure, and integrating AI into these environments demands a thoughtful, risk-informed approach. This guidance equips organizations with actionable principles that AI adoption strengthens, not compromises, the safety, security and reliability of essential services.”

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U.S. Solicitor General Sides Against Duke Energy in Antitrust Case

The Supreme Court should reject an appeal from Duke Energy of an antitrust case it lost in lower courts, the Office of the Solicitor General said in a brief filed Dec. 1 (24-917).

The 4th U.S. Circuit Court of Appeals found in August 2024 that Duke’s alleged anticompetitive conduct against NTE Energy — an independent power producer serving municipal customers in North Carolina — warranted another look in a lower court, which sided with the other parties. Duke filed a petition for review at the Supreme Court in February. (See 4th Circuit Remands Duke Energy Market Power Lawsuit Filed by NTE.)

“This appeal arises out of a campaign by an established monopolist to stop a more efficient rival from disturbing its long-dominant hold over a regional energy market,” OSG said.

The beneficiary of a government grant of a monopoly more than a century ago, Duke has controlled the wholesale power market in the Carolinas for decades. Barriers to entry — including the high cost of power plants and the paucity of anchor clients big enough to help finance a competitor’s generator — have helped it keep that monopoly.

“By dissuading such customers from switching to a potential competitor, an entrenched monopolist can prevent new entrants from gaining a foothold in the region — without creating a better product, producing a better service or implementing a general price cut,” OSG said. “The summary-judgment record would support a finding that that is exactly what happened here.”

Duke’s old power plants were not competitive with NTE’s, which used newer technology to produce electricity at a cheaper rate, so when the IPP tried to build one in in the Carolinas, Duke targeted the competition itself, OSG argued.

“Petitioner recognized that this new plant would be viable only if respondent could sell power to the city of Fayetteville, the one sizable customer in the area whose contract was coming due,” OSG said. “Petitioner therefore took a variety of steps intended to deter Fayetteville from switching to a new supplier.”

Duke has not sought review of the underlying facts of the case, in which the 4th Circuit found that the various acts it took added up to what a jury could find to be an anticompetitive campaign, OSG noted.

“When a monopolist engages in a coordinated campaign to squelch competition, no circuit holds that each discrete aspect of the defendant’s conduct must be analyzed in isolation,” OSG said. “Instead, courts uniformly agree, consistent with this court’s precedent, that a holistic analysis is appropriate in circumstances like these. The petition for a writ of certiorari should be denied.”

Duke’s petition for the Supreme Court to review the case argues that, on their own, none of its actions were illegal, saying the 4th Circuit effectively found that “0+0=1.”

“The district court found that antitrust math is no different from ordinary arithmetic. If an antitrust plaintiff pleads a series of independently lawful acts, each of which does not violate this court’s precedents, those acts cannot together add up to some nebulous antitrust violation,” Duke said in its petition. “The Court of Appeals concluded otherwise, embracing a ‘monopoly broth’ theory prominent in the 1960s to 1980s but long since discarded.”

The Supreme Court needs to intervene to restore antitrust law to the principles that have governed in more recent decades, the company argued. It overhauled how to prove monopolization under the Sherman Act starting in the 1990s.

“It replaced open-ended standards and generalized questions of anticompetitive intent with clear rules for particular categories of conduct,” Duke said. “That doctrinal shift has provided much needed certainty for businesses and judges alike and has prevented antitrust law from chilling vigorous competition in the marketplace. Antitrust plaintiffs have long resisted that shift.”

The U.S. Chamber of Commerce, the NC Chamber Legal Institute and the Business Roundtable filed an amicus brief taking Duke’s side.

“In just a few short months, the decision below has already been cited dozens of times in briefs and decisions across the country as plaintiffs urge lower courts to disregard this court’s discrete doctrinal standards in favor of ‘holistic’ analyses,” they said.

Allowing the 4th Circuit’s finding to stand would supercharge that trend with antitrust plaintiffs filing allegations of “complex” anticompetitive schemes that cannot satisfy the court’s clear tests and would thus be “dead on arrival” in other circuits, they added.

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West Needs Unified IBR Approach, WIRAB Says

Western state utility commissioners should encourage “standardization and harmonization” to effectively integrate inverter-based resources throughout the region, according to a guide developed by the Western Interconnection Regional Advisory Body and Elevate Energy Consulting.

The guide, a “technical resource” intended to assist commissioners, is a follow-up to a report on IBRs commissioned by WIRAB in 2024. Elevate Energy and WIRAB hosted a webinar to discuss the document and its findings Dec. 2.

The report notes that over the next decade, approximately 85% of new generation in the West is expected to be IBRs. If not integrated correctly, this can lead to vulnerabilities in modeling, coordination and operational performance, according to the report.

To correctly integrate IBRs, the industry must focus on “standardization and harmonization,” Ryan Quint, CEO of Elevate Energy, said during the webinar. “In particular, adopting the latest and greatest standards.”

“FERC and NERC have said, ‘We strongly … encourage folks to adopt [IEEE 2800-2022], but we are not mandating it,’ meaning there are no requirements for [the] significant … amount of decisions that need to be made about how we want to configure, control and operate IBRs,” Quint said. “So, unless those requirements are specified, there are potential gaps that exist.”

Encouraging standard adoption of IBRs is especially tricky in the West because many entities are involved in the process, Quint noted.

Other regions may have one ISO or RTO where all the decisions are made with “one central entity responsible for administering that process and following those rules that have been created or imposing those rules,” Quint said.

“In the West, we’ve got dozens and dozens and dozens of planning coordinators, transmission planners, that all have varying sizes, areas of expertise, challenges of their own,” Quint said. “Regional coordination, bringing these entities together in a unified way, is really an important concept, particularly in the West. And that becomes very applicable with the adoption of new standards, the improvement of requirements, the checks and balances that happen during the interconnection process, etc.”

Standardization brings reliability benefits to not only transmission providers, but also developers and contractors, who will have a clearer understanding of the rules, Quint said.

To achieve harmonization, the industry needs a stakeholder-engaged assessment, which would include regional training, support for smaller entities and utility flexibility.

The need to streamline integration of IBRs also applies to large load interconnections, Quint noted.

The technical resource states that commissions “can set expectations, require transparency and ensure utilities are prepared to integrate IBRs without compromising affordability, reliability or resilience.”

The resource suggests seven key focus areas for IBR oversight:

    • enhanced and harmonized interconnection requirements,
    • IBR modeling, data quality and study processes,
    • using modern IBR capabilities,
    • commissioning practices and post-commissioning monitoring,
    • utility operational readiness,
    • coordination and sharing across jurisdictions, and
    • maximizing capabilities of legacy IBR devices.

Arizona Corporation Commissioner Lea Márquez Peterson, WIRAB’s chair, said the goal of the resource is to “equip regulators with clear, practical oversight tools and the kinds of questions that surface potential issues early, drive meaningful conversations with utilities and ultimately support better outcomes for the Western Interconnection as a whole.”

“NERC and FERC are strengthening standards, but regulatory oversight varies, and some responsibilities fall on our shoulders as commissioners,” Márquez Peterson said. “WIRAB’s role is to help bridge the space between complex technical issues and the regulatory decisions that shape reliability. This resource is one way we can support that mission.”

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NYISO Monitor Says More Data Needed to Verify Out-of-market Actions

The NYISO Market Monitoring Unit cannot verify the need for out-of-market actions on the part of transmission owners for reliability, it told the Installed Capacity Working Group on Dec. 1.

This is because the tariff does not specifically grant the MMU the power to obtain the data necessary to verify such actions, said Pallas LeeVanSchaick, vice president at Potomac Economics, the MMU.

LeeVanSchaick included the analysis as part of a presentation of the third-quarter State of the Market report in response to stakeholder questions on the first-quarter report in August. (See NYISO Stakeholders Concerned About Lack of Data on Supplemental Commitments.)

The MMU is unable to verify whether all day-ahead reliability units and supplemental resource evaluation calls are scheduled because of actual reliability needs. These out-of-market actions actually became less frequent in New York City because of new 138-kV transmission, but 23% of them could not be verified.

LeeVanSchaick said that while the NYISO tariff gives the MMU broad access to data from “market parties” and “sellers,” TOs do not specifically qualify as either. This means the MMU is dependent on the data that TOs give to NYISO, which are frequently not detailed enough to verify reliability calls. He noted, however, that NYISO has begun to receive more detailed information on out-of-market commitments “in recent months.”

Multiple stakeholders expressed concern that the Monitor had “their hands tied” trying to get data from TOs. A TO representative said they had a unique responsibility for local reliability and that this had to be taken into consideration should any new regulations be developed.

Stakeholders and the MMU seemed open to discussing the issue further at upcoming meetings, which may create calls for tariff changes to address information gaps.

State of the Market

All-in prices ranged from $62/MWh in the North Country to $100/MWh in New York City, up 36 to 50% from last year. LeeVanSchaick said that this was primarily driven by natural gas price increases of 42 to 66%.

Additionally, NYISO became a net exporter of energy to Quebec for the first time in summer, averaging 480 MW. Canada’s exports to the ISO fell 1.4 GW year-over-year. July’s heat waves led load to peak at 30.6 GW, 6% higher than last year’s.

Congestion revenues rose 35% year-over-year, caused by transmission outages in Western New York and New York City. Long Island lines accounted for the largest share of congestion statewide, particularly on high-load days in July.

Over the summer, the Monitor identified an average of 2.2 GW of forced outages on high-load days, far higher than the anticipated 1.6 GW of market outages. During the most extreme heat waves, additional capacity was unavailable in real time because of the inability of generators to ramp, ambient heat and ambient humidity. In total these three factors removed 600 MW of capacity statewide. LeeVanSchaick said this “overstated significantly” the available capacity on the market.

Other Business

The ICAP Working Group also reviewed tariff revisions for the Improved Duct-Firing Modeling project and the NYISO/Hydro Quebec interconnection agreement.

It also discussed revisions to the aggregation manual for municipal electric utilities. NYISO staff said they believe a new section of the manual will need to be added to support the participation of distributed energy resources within municipal utility territories.

In addition, NYISO responded to stakeholder requests for information about how much generation had elected to be considered firm for the 2026/27 capability year. (See NYISO Business Issues Committee OKs Firm Fuel Accreditation Concept.)

In New York City, 7.6 GW of capacity elected as firm, representing 82% of capacity covered by the firm fuel option. On Long Island, 89% of capacity elected firm, totaling 4.6 GW. In the Capital District, which is the only area upstate modeled as being fuel constrained, 80% of eligible capacity totaling 2.8 GW elected firm.