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December 17, 2025

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FERC Issues Guidance to Comply with Trump Order on Criminal Referrals

FERC issued a notice saying it would coordinate with the attorney general on what crimes it would refer to the Department of Justice for criminal prosecution (AD25-12).

The commission said June 16 it will work with DOJ to file a report with the White House’s Office of Management and Budget that lists all criminal regulatory offenses enforceable by the two, along with the range of potential criminal penalties and the applicable mens rea (guilty mind) standard for a violation. The report is due by May 9, 2026.

The notice was in response to President Donald Trump’s executive order May 9 called “Fighting Overcriminalization in Federal Regulations.” The order said that many of the regulations issued by the federal government carried criminal risk for violations.

“The situation has become so dire that no one — likely including those charged with enforcing our criminal laws at the Department of Justice — knows how many separate criminal offenses are contained in the Code of Federal Regulations, with at least one source estimating hundreds of thousands of such crimes,” Trump said. “Many of these regulatory crimes are ‘strict liability’ offenses, meaning that citizens need not have a guilty mental state to be convicted of a crime.”

FERC said its current policy is largely already in line with what Trump ordered. The commission only has authority for civil fines when companies or individuals violate its rules, but since gaining its enforcement powers under the Energy Policy Act of 2005, it has said it would refer activity to the department if the misconduct were serious enough and if parties exhibit “evidence of willful behavior.”

The notice also announced a general policy that when FERC does make criminal referrals, it will consider the risk of harm caused by the offense, the potential gain to the defendant, whether the defendant had specialized knowledge or was licensed in the industry at issue, and what evidence is available of the defendant’s general awareness of the lawfulness as well as their knowledge of the regulation at issue.

Trump directed agencies to work with the attorney general to determine whether they have the authority to establish a mens rea standard for its regulations.

“If consistent with the statutory authorities identified pursuant to the review described in subsection (a) of this section, the report should present a plan for changing the applicable mens rea standards and adopting a generally applicable background mens rea standard, and provide a justification for each criminal regulatory offense for which the agency proposes to deviate from its default mens rea standard,” the order said.

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New England Transmission Owners Add $95M to Asset Condition List

Asset-condition project costs in New England have grown by $95 million since March, according to an update to the project list presented by the region’s transmission owners at the ISO-NE Planning Advisory Committee on June 16.  

The database includes both in-development and in-service asset-condition projects, which aim to upgrade aging and deteriorating transmission infrastructure. 

The change in cost since March, driven by 20 new projects estimated to be about $84 million, is relatively small compared to overall asset-condition spending in the region. It brings the total cost of in-development projects to about $5.9 billion, while the cost of in-service projects totals about $5.5 billion. 

While stakeholders broadly agree that many of the upgrades are necessary, ACP spending has become a major issue for states and consumer advocates in recent years because of concerns about rising costs and a lack of transparency and regulatory oversight on the projects. Asset-condition projects are under FERC’s jurisdiction, with costs typically recovered through formula rates. 

At the urging of the states, ISO-NE has said it is open to taking on an “asset condition reviewer” role to help address the “informational asymmetry” between TOs and the public. The RTO has stressed that this role must not include regulatory responsibilities. (See ISO-NE Open to Asset Condition Review Role amid Rising Costs.)  

Eversource Energy has already paused stakeholder discussions on a massive, multiphase underground cable replacement project to allow time for ISO-NE review and feedback. The company wrote in May that the first phase of the project is estimated to cost between $2 billion and $3 billion. (See Eversource Outlines Billions in New Boston-area Asset-condition Needs.) 

Also at the PAC on June 16, Eversource introduced a project to replace structures on three lines in New Hampshire near the Maine border. Eversource said it has identified wood pole decay on the lines and proposed to replace all remaining wood structures on the lines at a combined cost of about $52 million. 

The company also presented a $6 million asset-condition project to replace a pair of breakers on a substation in Springfield, Mass., that are “approaching the end of their useful life and have shown signs of deterioration.” 

National Grid introduced an $11 million project on a line in Eastern Massachusetts, proposing to replace damaged shield wire, attachment hardware and insulation, and repair the foundations of four river-crossing towers.  

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MISO IMM Contends he Should Have Role in Tx Planning Oversight

The MISO Independent Market Monitor insisted to FERC that MISO’s own rules allow him to assess transmission. Market monitors of other grid operators backed him up.  

MISO’s transmission owners, on the other hand, remain steadfast with MISO that it’s inappropriate for the IMM to critique transmission planning and expect compensation (EL25-80).  

The varied opinions sent to FERC were in response to MISO’s May petition for a declaratory order on whether it’s proper for the IMM to analyze the value of proposed transmission portfolios in addition to markets. (See MISO Intent on Answers as to IMM Role in Tx Planning and MISO IMM to State Regulators: Good Intentions Behind LRTP Criticism.)  

IMM David Patton argued the RTO’s tariff “unambiguously authorizes” him to monitor market impacts of MISO’s transmission planning.  

Patton cited a tariff section on monitoring duties that listed evaluation of “competitive or other market impacts of tariffs and agreements, or other rules, standards or procedures, or any other transmission provider or market participant actions governing or affecting any of the markets and services.” He said the section is intentionally “broadly worded.”  

Patton requested that FERC deny MISO’s petition and find that the IMM is allowed to monitor transmission planning free from MISO’s impediment. He included an ask for fast-track status because he said he’s currently prevented from “monitoring transmission planning decisions that will have consequential market impacts.”  

“We also note that almost all the MISO states support the IMM’s role in monitoring of MISO’s transmission planning and have raised concerns about MISO’s attempts to suppress the views of the IMM,” Patton wrote in a June 13 response.  

MISO argues the IMM’s perspective on its transmission studies is “supported by [neither] the commission’s policy statement on Market Monitoring Units nor Order No. 719.” MISO said beginning in 2023, it noticed the IMM was “expanding the scope of its activities by initiating unsolicited monitoring, evaluations and analyses” of MISO’s long-range transmission planning (LRTP) while seeking reimbursement.  

According to MISO, the IMM has billed it for about 600 hours of “unsolicited” monitoring of LRTP between 2023 and 2024, totaling about $300,000.  

Patton was a vocal opponent of MISO’s second long-range transmission plan (LRTP) portfolio throughout 2024, repeatedly telling planners they were overstating the benefits of the collection of mostly 765-kV lines and deeming the 20-year future assumptions that transmission needs were established upon unrealistic. Patton argued for a downsized portfolio. (See MISO IMM Makes Closing Arguments Against $21.8B Long-range Tx Plan and $21.8B Long-range Tx Plan Goes to Membership Vote; MISO Resolute, IMM Protesting.)  

Patton said the tariff’s Module D, which contains a MISO-IMM monitoring plan, “expressly empowers the IMM to monitor activities that the IMM ‘deems relevant’” and include reviewing agreements, rules, standards and procedures, in addition to other activities that have market impacts or can affect services. He said it’s “apparent that transmission planning decisions substantially affect the MISO’s market and services.”  

Patton said FERC and the courts have decided “repeatedly” that transmission planning affects grid operators’ markets.  

MISO says that view is a slippery slope. Having the IMM review so many aspects “could disrupt the efficient operations at MISO and introduce unnecessary costs, which all, in turn, could impact reliability and the benefits received by MISO members.”

Patton said there’s no evidence to support MISO’s claim.  

“On the contrary, in nearly every case where the IMM has raised concerns regarding MISO’s actions, MISO has worked collaboratively to make improvements that have yielded substantial efficiency benefits and other savings,” Patton said.  

‘Unsolicited’

Patton objected to MISO’s description of the planning advice as “unsolicited.” He said MISO does not “solicit” market monitoring “particularly when MISO is the focus of the monitoring.” 

“It is likely that all monitored entities, whether market participants or MISO itself, would view investigations by the IMM to be ‘unsolicited’ since no target of our monitoring and investigation would ever voluntarily solicit such activity by the IMM,” Patton reasoned.  

Patton pointed out that the MISO board of directors had requested that he discuss his divergent view of the MISO transmission planning futures and benefits estimates with RTO staff. He also said MISO reserved time for his presentations at LRTP workshops and stakeholder meetings.  

Patton also said he was offended that MISO seemed to suggest his reviews of LRTP assumptions were motivated by money.  

“MISO seems to be implying that our monitoring of transmission planning is motivated by a desire for increased compensation, which is offensive and baseless. Like all market monitoring work, we bill our work on an hourly basis. The only reason the hours related to transmission planning monitoring have increased in the past two years above the historical level of effort in the prior 20 is due to the profound concerns that we have uncovered with MISO’s most recent determinations,” Patton said. He said the $300,000 billed over 2023 and 2024 represents less than 2% of the MISO IMM budget and didn’t push MISO’s IMM spending over budget.  

Patton said market monitors in other regions like NYISO and PJM monitor transmission planning. He said that “further demonstrates that our actions with respect to MISO’s LRTP were in no way abnormal or out of step with the commission’s requirements.”  

PJM IMM Supports MISO IMM 

PJM’s Independent Market Monitor said MISO appeared to be trying to “curtail” its IMM. Monitoring related to transmission planning is “within the proper scope of the market monitoring function.” The PJM IMM said MISO’s petition “represents an unreasonable intrusion” into the IMM’s independence. It sided with Patton that MISO’s tariff “clearly” authorizes the Monitor to keep an eye on transmission planning.  

The Internal Market Monitor of ISO-NE said scrutinizing how effective markets are at signaling needed investment in generation and transmission is “indisputably within the bailiwick of an IMM.” The ISO-NE IMM argued that examining transmission planning for its impacts on the market is “two sides of the same coin.”  

“The performance and competitiveness of wholesale markets are inextricably linked to the operation, access arrangements and long-term planning of the transmission system,” the ISO-NE Monitor wrote.  

The New Jersey Division of Rate Counsel and Maryland Office of People’s Counsel even registered support for the MISO IMM in a joint filing. They said the “activities performed are an important part of an IMM’s work in ensuring market fairness.”  

The Office of the Illinois Attorney General said it would be a “great disservice to ratepayers” if FERC were to agree with MISO and limit the IMM’s authority.  

MISO’s transmission owners, however, said “unsolicited monitoring and evaluation” of transmission planning is “beyond the bounds” of the IMM’s tariff-designated responsibilities.  

“While Potomac may undertake such activities of its own volition, it should not do so with the expectation of compensation from MISO, its members and their ratepayers,” the transmission owners said.  

Americans for a Clean Energy Grid expressed a similar sentiment: “Though the IMM serves a vital role in the operation of MISO’s markets, the tariff does not extend this role to transmission planning and monitoring activities.” The group agreed that MISO is under no obligation to reimburse the IMM for transmission evaluation.  

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RF: Germany’s Reliability Crisis Holds Lessons for U.S.

Recent issues in Germany arising from the adoption of renewable energy resources offer valuable lessons for U.S. utilities as their country undergoes its own energy transition, staff from ReliabilityFirst said in a recent webinar.

In the regional entity’s monthly Technical Talk with RF series, Courtney Fasca, RF’s senior reliability consultant for external affairs, reminded attendees of RF’s adage that “every instance, good or bad, is an opportunity to learn and adapt.” In her telling, Germany’s “Energiewende” — which translates roughly to “energy transition” — and the resource adequacy issues that partially arose from it qualify as such a learning opportunity.

Fasca dated the beginning of the Energiewende to 2010, when Germany’s legislature initiated a plan to reduce the country’s greenhouse gas emissions by up to 95% from their 1990 levels by 2050. This would include decommissioning all coal-fired power plants, which under a plan approved by the cabinet in 2020 would have occurred by the end of 2038.

However, subsequent events have called that target into question, Fasca said. Growing public concern about nuclear power, which in 2010 accounted for about 25% of Germany’s generation fleet, led the government to retire all of the country’s nuclear reactors by 2023. To replace the more than 20 GW of resources, utilities turned to natural gas.

Even though “the reliance on natural gas … was only meant to be a bridge between the phase-out of coal and nuclear energy and the transition to renewables,” it ended up contributing to the later challenges, Fasca continued. Germany depends on imported gas to satisfy its needs, which include home heating and industrial uses in addition to power generation, and Russia supplied more than half of the gas the country imported in 2020.

When Russia invaded Ukraine in February 2022, this dependence on Russian gas imports quickly became a major concern. Amid mutual sanctions, Russia ceased exports of gas and oil to Germany by August 2022. With the final nuclear reactors retiring just months later in April 2023 and retirements of coal plants continuing, “Germany was officially in an energy crisis,” Fasca said.

By July 2022 the price of power had risen to over $600/barrel of oil equivalent, according to the European Energy Exchange, more than $500 higher than a year earlier. Greenhouse gas emissions from the energy sector spiked in 2022 after nearly a decade of steady declines because of the reopening of 10 GW worth of coal plants, though they dropped to below 2020 levels the following year as energy conservation measures among industry and the general population took hold.

Further complications ensued in 2024 as Germany endured what has been dubbed the dünkelflaute, “a prolonged period of cloudy and windless weather” that resulted in low output from the country’s wind and solar generators. Wholesale prices spiked as a result, at one point reaching €1000 — the highest point in 18 years. To make up the shortfalls, Germany turned to imported nuclear and fossil fuel-fired energy from its neighbors.

Fasca identified several takeaways from the German experience that could be relevant to U.S. grid planners.

“One of the unique aspects of [the] Energiewende … was to drive the transition primarily through citizens, and [it] sought to involve them more in the policymaking process and to increase the transparency for renewable energy project plans and approvals,” she said. “However, this change in energy composition also required serious infrastructure and transmission upgrades, projects the public wasn’t necessarily supportive of.”

By 2020, she continued, “bureaucratic measures and ‘not in my backyard’” attitudes had slowed several renewable energy projects. At the same time, the retirement of nuclear plants meant energy prices remained high, frustrating ordinary Germans.

Since rebounding from the crisis of the Russo-Ukrainian war and the dünkelflaute, German policymakers have worked to “shield their country from power price fluctuations” and from future supply shocks. One step in this direction is an apparent softening toward nuclear power, with Chancellor Friedrich Merz’s government dropping its long-held opposition to the European Union classifying nuclear energy as “sustainable.”

One critical lesson of the German experience, Fasca said, is the importance of diversifying energy resources. With more generation types represented in the German resource mix, the country could have compensated for the loss of Russian gas imports with less cost to the environment and economy. Long-term planning also must include enough cushion for unpredictable events, whether in foreign relations, extreme weather or any other fields.

“This yearslong energy crisis in Germany did not arise due to a single decision, but a series of them,” Fasca said. “By no means do we place blame or judgment on any of these decisions, but we believe that studying and learning from them can help us bolster the reliability of the grid here in the U.S.”

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PJM Proposes Changes to Large Load Forecasting

PJM presented changes to its submission and review processes for large load adjustments (LLAs) that are intended to provide stakeholders with more transparency before they are included in future load forecasts, as well as a draft proposal to standardize how it determines what share of LLAs will be included in its forecasts.

Under the revised timeline, the Load Analysis Subcommittee (LAS) would review LLA submissions in September, rather than October, to allow more time for stakeholders to discuss the data provided by electric distribution companies and load-serving entities. PJM would open the submission window on July 1, with responses expected by early September.

Under Manual 19 Attachment B, PJM currently sends the request for LLA submissions in mid-July, with a meeting to review the responses at the LAS in September or October.

Presenting to the LAS on June 10, PJM’s Molly Mooney said the changes center around processing LLA submissions earlier in the load forecast schedule to allow more time for RTO staff and stakeholders to see the impact they may have on reliability studies. She said the timeline will provide “a little extra time will give us more wiggle room internally to give an early warning to the impact these large loads will have on that reliability impact study.”

Mooney said adjustments accounting for concentrated data center growth have led to many stakeholders submitting inquiries to PJM, and the proposal is aimed at providing more transparency around how those LLAs are developed and processed by the RTO. (See Panel Discusses Data Center Load Growth at PJM Annual Meeting.)

PJM also is considering revising the language of the request it sends to EDCs and LSEs soliciting LLAs to standardize the process, providing more guidance on the information PJM is looking for and how it would seek to fill in any gaps.

Those making submissions would be asked to identify the amount of load in both demand and capacity terms. If only expected capacity values are provided, PJM would use historic data to determine a demand value. The change also would ask that adjustments include the amount of time it would take for a project to ramp up to its full load, with a default of three years if no estimate is provided.

PJM may derate the amount of load it expects to come online based on the likelihood of the consumer entering service. Projects coming online within three years and that have made electric service obligations or construction commitments to the EDC or LSE may be included in the load forecast. Projects with in-service dates between three and eight years into the future may be derated if the consumer has not made those commitments or provided evidence of “demonstrable project milestones.” Longer-term LLAs may be submitted using expected agreement flows or extrapolations with proper substantiation.

For projects being derated, submissions should include a probability factor detailing how far a project has advanced toward completion, such as site control, state support, transmission upgrades or financial commitments. Without that information, PJM may use a default probability of 50% to derate the project.

The change also would establish a 50-MW floor for LLA submissions, though Mooney noted NERC is considering its own threshold. Smaller adjustments still would be permitted on a case-by-case basis.

Calpine’s David “Scarp” Scarpignato said he worries that derating expected energy by as much as 50% could risk undercounting much of the load that is likely to come online, undermining the accuracy of the forecast.

PJM’s Andrew Gledhill responded that when the RTO implements its long-term, regional planning proposal to comply with FERC’s Order 1920, it could include scenarios looking at both high and low data center penetration. (See FERC Order 1920 Sees Wide-ranging Rehearing Requests.)

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Senate Finance Committee Looks to Eliminate Energy Tax Credits in 2028

Senate Finance Committee Chair Mike Crapo (R-Idaho) released language for the massive reconciliation bill that includes major cuts to tax subsidies for clean energy. 

A version of the bill already passed the House with deep cuts to energy credits that would cause them to sunset and include restrictions that many in the industry say would render them useless. (See House Passes Reconciliation Package that Would End Energy Tax Credits.) 

The bill would make the 2017 Trump tax cuts permanent, thus avoiding a “$4 trillion tax hike,” Crapo said June 16. 

“The legislation also achieves significant savings by slashing Green New Deal spending and targeting waste, fraud and abuse in spending programs while preserving and protecting them for the most vulnerable,” he added. 

The language the Finance Committee released June 16 would phase down key tax credits even more quickly than in the proposal the House passed. The House version would let clean energy projects get full tax credits through 2028 before being cut over the next several years and expiring entirely on Jan. 1, 2032. 

While the House bill required projects to be completed to receive credits, the Senate version keeps the current language that projects only need to start by a certain date to get them. But it slashes the production tax credit and the investment tax credit to 60% of their current total starting in 2026, then 20% for projects starting in 2027, and finally makes projects that start after Dec. 31, 2027, ineligible for them entirely. 

The language would include new prohibitions for the 45U production tax credit for nuclear plants, limiting the use of fuel from some foreign suppliers. 

The bill also would cut tax credits for plug-in electric vehicles entirely, as well as other credits aimed at making homes and commercial facilities more energy efficient. 

Edison Electric Institute interim CEO Pat Vincent-Collawn said the Senate language offers “more reasonable timelines” for phasing out energy tax credits and preserving their transferability. 

“Financial certainty and access to cost-effective financing are critical tools for electric companies as they continue to make needed investments to meet rising customer demand and to expand generation capacity,” Vincent-Collawn said in a statement. “These modifications are a step in the right direction, and we thank Chairman Crapo for his leadership in balancing business certainty with fiscal responsibility. We look forward to continuing to work with lawmakers to ensure the final package incorporates practical, pro-growth policies that support our shared goals of strengthening America’s energy security and keeping customer bills as low as possible.” 

The Union of Concerned Scientists said the Senate language, like the version that cleared the House, would slow down clean electricity deployment, undermine domestic manufacturing of batteries and electric vehicles, and make EVs more expensive and less available. 

“This proposal specifically and repeatedly sidelines the exact clean technology solutions that are ready and able to deliver benefits for people and communities all across this country,” UCS Energy Analyst Julie McNamara said in a statement. “These are the solutions that have driven enormous gains to date and are poised to deliver so much more — if only lawmakers would let them.” 

Steven Nadel, executive director of the American Council for an Energy-Efficient Economy, called on senators to leave the credits for energy efficiency and electric vehicles in place. 

“Canceling these credits would increase monthly bills for American families and businesses,” Nadel said in a statement. “Why would we stop helping families save energy when prices are going up and up? Americans didn’t vote for higher energy bills. At a time when we’re concerned about strain on the electric grid, it’s particularly absurd to waste more electricity.” 

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NV Energy Seeks OK for $500M Wildfire Self-insurance Policy

With the risk of catastrophic wildfire growing in Nevada and across the West, NV Energy is seeking approval for a $500 million wildfire liability self-insurance policy.

The self-insurance, to be paid for by ratepayers over 10 years, would bring NV Energy’s wildfire liability coverage to about $1 billion. The company now has $405 million in commercial coverage and $100 million in existing self-insurance.

The Public Utilities Commission of Nevada (PUCN) has scheduled a hearing on the proposal for June 24.

NV Energy wants the additional self-insurance “in order to have adequate wildfire liability insurance in place in the event that a catastrophic wildfire in Nevada is alleged to be caused or exacerbated by utility equipment,” the company said in a filing with the PUCN.

The chance of a wildfire causing $1 billion or more in financial losses in NV Energy territory in the next 10 years is 18% or more, Nathan Pollak, of Scidan Consulting Group, testified as part of NV Energy’s application. And the chance of a wildfire causing $2 billion in financial losses in the next decade is 10%, he said.

Pollak recommended NV Energy have $1 billion to $1.5 billion in wildfire liability coverage.

But NV Energy said it is facing rising costs and reduced availability of commercial insurance.

“The products available are expensive and non-traditional – presenting drawbacks that make them less prudent than the self-insurance policy,” Mariya Coleman, NV Energy’s vice president of corporate insurance and claims, said in the application.

Striking a Balance

NV Energy would create a captive insurance company to administer its self-insurance, just as it did for its existing $100 million self-insurance policy.

The company said the 10-year period to fund the new self-insurance policy strikes a balance between avoiding rate shock to customers while completing the funding in a reasonable amount of time.

About three-quarters of the cost would be paid by customers of Sierra Pacific Power, NV Energy’s subsidiary in northern Nevada, with Nevada Power customers in southern Nevada picking up the remainder.

If there are any payouts from the self-insurance fund, NV Energy has proposed replenishing it with another customer rate hike.

Shareholders would commit to a 10% co-insurance payment on any claims, up to $50 million. The co-insurance payment wouldn’t depend on results of a reasonableness review.

“This co-insurance payment preserves a strong incentive on the part of the companies to mitigate wildfire risk and to settle third-party claims prudently,” Michael Behrens, NV Energy’s chief financial officer, said in the application.

The co-insurance share is greater than that of the self-insurance policies of two major California utilities, Behrens noted. The shareholder co-insurance payment in Pacific Gas and Electric’s self-insurance policy is 5%; for Southern California Edison, it’s about 2.5%.

Some stakeholders criticized NV Energy’s proposal, saying it is inefficient to have two separate self-insurance policies with different structures, rules and coverage.

Instead, NV Energy should expand and modify its existing self-insurance policy, said utilities consultant Bradley Mullins, who filed testimony on behalf of several gaming interests and other parties.

Mullins said it would be more appropriate for NV Energy to collect the self-insurance funding from ratepayers over 50 years, since a $1 billion wildfire is estimated to be roughly a 1-in-50-year event. And no costs from “imprudence, gross negligence or willful misconduct” should be borne by ratepayers, he said.

Capital Impacts

In his testimony, Behrens of NV Energy said catastrophic wildfires have had serious financial consequences for electric utilities throughout the West.

In cases where utility equipment was implicated in massive wildfires in California, Hawaii, Oregon and Texas, the respective utilities saw downgrades to their credit ratings, “in many cases to non-investment grade,” Behrens said.

“Even a utility that has not been alleged to have caused or exacerbated a catastrophic wildfire faces the risk of a lower credit rating and higher cost of capital if it is not perceived to have sufficiently prepared for the financial risks,” he said.

Behrens noted that utilities are a capital-intensive sector that use debt to finance the long-term assets needed to provide service.

The impact of wildfires on utility finances also was a topic of discussion June 2 during the Western Conference of Public Service Commissioners. Investment analysts said wildfire risk could hinder Western utilities’ ability to raise capital to fund infrastructure projects. (See Analysts to Western Regulators: Wildfire Risk is Issue du Jour.)

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IESO Seeks to Shore up Capacity Market

The IESO Technical Panel approved for posting rule changes to reduce unfulfilled capacity commitments by making it easier for participants to transfer their obligations and harder to buy them out.

The panel on June 10 approved posting the revisions for comment by voice vote with no objections or abstentions.

IESO conducts a capacity auction once a year, and suppliers can bid on obligations for either of two periods — summer (defined as May 1 to Oct. 31) or winter (Nov. 1 to April 30) — or for both. Auctions are conducted in late November for the capacity periods beginning the next year. This year’s auction will be held Nov. 26-27 for the periods beginning May 1 and Nov. 1, 2026, with results posted Dec. 4. 

Resources are expected to participate in the energy market during the periods for which they purchased obligations through the auction, or they can buy out or transfer their obligations. Buyouts are subject to a charge equal to 30% of the total obligation value. 

According to IESO, the market saw its “highest level of competition ever” in 2024, with 2,122.2 MW secured for summer and 1,524.6 MW for winter at $332.39/MW-day and $139/MW-day, respectively. It said it secured 15% more capacity than in 2023’s auction, at lower prices. 

But Adam Cumming, IESO market rules adviser, told the Technical Panel that every year “a small number of resources” — representing about 100 MW, according to the ISO — are unable to fulfill their obligations “for a variety of reasons.” Among these is simply not completing the necessary registration requirements during the forward period (after the auction but before the obligation period) by the posted deadlines. 

Unfulfilled obligations reduce “the capacity available to the IESO and distorts auction clearing price signals,” the ISO said in a presentation in May. 

Among the changes the panel approved for posting is an increase in the buyout charge to 50%, intended to deter participants from taking on commitments they cannot meet and incentivize those with obligations to fulfill them. “Hopefully with the increased costs, people will be a little bit more careful in choosing their obligation size,” Cumming said. 

Suppliers who fail to complete the registration process no longer would have the option of simply forfeiting their deposits and would be required to buy out their obligations. “This change will ensure that all instances of unfulfilled commitments are subject to the buyout charge process,” the ISO said. 

The revisions also would remove the requirement that obligations can only be transferred between resources with the same attributes. 

IESO told the panel that stakeholders are supportive of the changes after working on them for over a year; in the case of the buyout charge increase, the figure was proposed by capacity market participants themselves, it said. 

The revisions will be open for comment until June 24. The panel will vote July 15 on recommending them to the Board of Directors for approval at its meeting in August. 

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PJM Stakeholders Propose Cost Allocation Models for DOE Emergency Orders

The PJM Members Committee is set to vote on several proposals drafted by the RTO and stakeholders to determine how to allocate costs associated with generators required to remain online through the U.S. Department of Energy’s emergency orders under Federal Power Act Section 202(c). 

Package sponsors, RTO staff, the Independent Market Monitor and other stakeholders will meet with PJM’s Board of Managers just before the committee’s meeting June 18 as the final phase of an expedited Critical Issue Fast Path (CIFP) process initiated to determine how to raise the funds to compensate Constellation Energy for continuing to operate its 760-MW Eddystone Generating Station, which DOE ordered to remain online past its May 31 deactivation date through Aug. 28. 

Constellation and PJM agreed to use the deactivation avoidable cost credit (DACC) model used to compensate resources retained past their deactivation date on reliability-must-run agreements. The allocation methodology associated with the DACC, however, is designed for assigning costs to load in the region of the transmission violations leading to an RMR arrangement; PJM has said it is not suited to instances where the federal government mandates a generator remain online for resource adequacy. (See PJM Board Initiates CIFP Process for Eddystone Compensation.) 

PJM proposed to allocate the costs to all RTO load by dividing each market buyer’s share of the RTO-wide unforced capacity (UCAP) obligation and multiplying that figure by the credit to Constellation. A new line item would be added to billing statements to show the cost of 202(c) credits, with information also posted to PJM’s website. During the CIFP meeting June 12, PJM Senior Director of Market Settlements Lisa Morelli said the RTO had estimated the 90-day cost to load to be $34.72/MW of UCAP. 

Package D from the East Kentucky Power Cooperative would assign costs to all RTO native load and exports using actual megawatt-hour consumption per month unless the resource subject to the 202(c) order is within a zone that fell short of its capacity procurement obligation — in which case the costs would be allocated to that zone — or if the RTO cleared short of its obligation, in which case costs would be assigned to each locational deliverability area (LDA) according to their contribution to the shortfall. The charges would be calculated by adding a market buyer’s energy consumption and exports and dividing that sum by total monthly energy production, then multiplying that by the credit to Constellation. Resources exporting to external balancing authorities they have capacity obligations to would be excluded. 

The cooperative’s Package E would assign costs to each buyer according to the same formula regardless of how each zone cleared in the capacity market. 

Stakeholders were divided on whether the proposal should focus solely on compensating Constellation for operating Eddystone under the current emergency order or establishing rules for other resources subject to a 202(c) order. Morelli said establishing more lasting rules would carry the benefit of avoiding additional rushed CIFP processes if more resources are ordered to remain online. 

Two PJM packages would apply more broadly, though with differing criteria; Package A would apply to all DOE orders under Section 202(c) in which the resource owner opts to be compensated through models similar to the DACC, while Package C would limit that to orders issued within 180 days of PJM filing the cost allocation proposal. Morelli said establishing a time limit for the proposal would give time for stakeholders to continue discussions for a more holistic solution without the result of the CIFP becoming permanent. 

Package B from Gabel Associates and EKPC’s Package E would limit the changes to the Eddystone order expiring on Aug. 28. Package D from EKPC would apply to all units subject to a 202(c) order not subject to an RMR agreement and being compensated through models akin to the DACC. 

Proposals with a wider applicability also differed on how they would allocate costs if future DOE orders specified a region within PJM where localized resource adequacy concerns prompted the need to retain a generator beyond its desired deactivation date. PJM’s packages would assign the charges only to load in the LDAs or zones identified, while Gabel would continue to allocate them to all RTO load. 

Stakeholders opposed to a locational element to allocating costs argued that Eddystone is not being retained to serve a particular zone and future orders could retain generation for resource adequacy issues that have not yet manifested. 

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New Pipelines Unlikely for New England, Experts Say

BOSTON — Despite interest from the Trump administration, new gas pipelines into New England remain unlikely due to a lack of counterparties willing to pay for the new lines, energy industry experts said at a recent roundtable discussion.  

The pipeline financing uncertainty is driven by the New England states’ push for heating electrification, the lack of incentives for gas generators to procure firm capacity, and a 2016 ruling by the Massachusetts Supreme Judicial Court that electric customers cannot cover the costs of a new pipeline. 

“The biggest reason I am skeptical of a new pipeline is: Who is the counterparty?” Dan Dolan, president of the New England Power Generators Association (NEPGA), told attendees of Raab Associates’ New England Electricity Restructuring Roundtable on June 13. “Unless Enbridge or Williams or Kinder Morgan are willing to build on spec and are willing to take merchant risk … I don’t see it.” 

Cheryl LaFleur, chair of the ISO-NE board of directors, highlighted financing challenges and a lack of interest from the states as the key obstacles to the development of new pipelines. 

“A pipeline is definitely the most efficient way to move gas from point A to point B — that has always been true,” LaFleur said. “It is up to the states how much gas they think the region will need and if they want a pipeline. It is not up to ISO New England.”

In May, the Trump administration reportedly reached a deal with New York to lift a stop-work order on the Empire Wind project in exchange for concessions from Gov. Kathy Hochul (D) on the Constitution Pipeline project, which was halted after failing to receive permits from the state in 2018. (See BOEM Lifts Stop-work Order on Empire Wind.) 

Several speakers agreed that, if New England was offered a similar, hypothetical deal lifting regulatory barriers for offshore wind and gas pipeline projects, lawmakers should take the trade.  

Rachel Fox, director of policy and strategy at the American Petroleum Institute, speculated that, while offshore wind “is by no means favored by this administration,” the Trump administration may allow projects to move forward “if it’s part of a deal for a natural gas pipeline.” 

Liz Stanton, executive director of the Applied Economics Clinic, warned about the health effects of gas generation on local communities, but said the New England states should take the deal because efforts to bring a pipeline to New England appear unlikely to succeed. 

Dolan of NEPGA was skeptical the Trump administration would seek this type of deal with the region, noting that the under-construction Vineyard Wind and Revolution Wind projects are well under way and have not been specifically targeted by the Trump administration. He said a deal likely would need to clear obstacles to incremental offshore wind generation beyond these projects, which the administration may be reluctant to do. 

Retail Gas Demand

On the gas distribution side, speakers discussed an apparent rift that has emerged in Massachusetts between lawmakers and utilities over the interpretation of language in a major 2024 clean energy bill passed in the state. (See Mass. Clean Energy Permitting, Gas Reform Bill Back on Track.) 

According to Sen. Michael Barrett, one of the lead negotiators on the bill, the bill authorized gas utilities to disconnect customers from the gas system if viable heating alternatives are available. This change was intended to amend the utilities’ “obligation to serve,” preventing a single gas customer from holding up the decommissioning of an entire section of gas pipe. 

“Last year, we amended Section 92 of Chapter 164, which is the sole basis for the so-called obligation to serve in Massachusetts, and we amended it with the legislative intent of giving our state DPU flexibility … to resolve the so-called holdout problem,” Barrett said.  

But despite the legislative changes, gas companies continue to argue they are not authorized to deny gas services to existing customers, and that the change in state law applies only to new customers. 

“There’s a disagreement, I think, in terms of what authority the utilities have to substitute electric for gas, or for the DPU to authorize that substitution,” said Jamie Van Nostrand, chair of the Massachusetts Department of Public Utilities.  

He said the issue of holdout customers has come up in a National Grid electrification demonstration project, which aims to “decommission one or more leak-prone gas pipe segments through coordinated whole-home electrification of customers.” 

The company, Van Nostrand said, has taken “is taking the position that decommissioning a segment will require 100% participation of the customers on that segment,” creating numerous potential points of failure for the efforts to decommission each segment of pipe.  

As the state looks to move the bulk of its residential gas customers to electric heating, it would be “very hard to achieve a gas transition without addressing this issue,” Van Nostrand said. 

Looking forward, Van Nostrand said the DPU plans to look at the issue more closely “and give the parties an opportunity to brief on that, because it is a real critical issue as we look at the success of these electrification projects.”  

Caroline Hon, vice president of New England regulation and pricing for National Grid, did not directly answer a question from Sen. Barrett about why National Grid continues to take the stance the utilities do not have the authority to disconnect customers when viable alternatives exist. 

Hon framed customer conversions as an equity issue and said that “if we aren’t thinking about this thoughtfully, it can be very regressive, and the most vulnerable people, the customers who can’t actually to convert, are going to be the ones who really suffer.”