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December 6, 2025

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PJM MRC/MC Briefs: Oct. 23, 2025

Stakeholders Endorse Proposal to Offer Cap Advance Commitments

VALLEY FORGE, Pa. — PJM’s Markets and Reliability Committee endorsed by acclamation a proposal to use only cost-based offers for resources committed in advance of the day-ahead energy market.

The proposal was also endorsed by the MC as part of its consent agenda. (See “1st Read on Offer Capping of Advance Scheduled Resources,” PJM MIC Briefs: Aug. 6, 2025.)

The use of advance commitments has grown since PJM implemented its conservative operations protocol, which allows resources to be scheduled days ahead of an event the RTO thinks could strain system conditions. It was established in the wake of the December 2022 Winter Storm Elliott, when many generators had trouble procuring fuel when picked up by PJM dispatchers. (See “PJM Discusses Market Performance During January Winter Storms,” PJM MIC Briefs: Feb. 5, 2025.)

Paul Sotkiewicz, president of E-Cubed Policy Associates, argued against units being limited to their cost-based offers without evidence of market power issues or when their commitment is intended to resolve a transmission constraint.

Paul Sotkiewicz, E-Cubed Policy Associates | © RTO Insider 

He said the proposal represents PJM’s attempt to make up for tariff violations during the conservative operations deployment ahead of the 2025 Martin Luther King Jr. Day weekend. Resources with advance commitments were improperly offer capped despite the conservative operations not being related to transmission issues.

He also raised issues about the scope of what can be included in cost-based offers, saying resource owners can incur unrecoverable costs when responding to a conservative operations commitment. He noted that fuel costs can be high during holiday weekends and must be purchased as a block package for the whole weekend.

PJM General Counsel Chris O’Hara said he is comfortable with the proposal from a compliance perspective after conferring with the RTO’s legal team and speaking with staff at FERC about the issue.

He said stakeholders have mixed views about how frequently PJM should use offer capping and the RTO has sought to proceed with the best solution available.

LS Power Director of Project Development Tom Hoatson said the proposal provides market participants with more certainty around how they will be committed during conservative operations and that improvements to the expenses captured in cost-based offers fall under phase two of the issue charge.

Renewable Dispatch Proposal Endorsed

The committee endorsed by acclamation a proposal to rework how wind and solar resources are dispatched, including establishing an Effective EcoMax parameter intended to capture how a resource is forecast to operate in how it is dispatched. (See “Renewable Dispatch Proposal Endorsed,” PJM MIC Briefs: Aug. 6, 2025.)

The forecast feeding into Effective EcoMax would be updated before each five-minute interval in the energy market and define the maximum output of the unit’s dispatch. PJM has sought the change to reduce the curtailment of renewable resources with outdated parameters, which the existing EcoMax parameter is limited to.

The ramp rate for wind and solar resources would be limited to 20% of their installed capacity per minute, which is intended to reduce the volatility that can result from sudden shifts in output.

1st Read on GDECS Tariff Revisions

PJM presented a first read on a slate of tariff revisions drafted by the Governing Document Enhancement & Clarification Subcommittee (GDECS), which seek to reflect changes approved by FERC and remove outdated language. The subcommittee approved all of the changes.

The proposal removes language referring to capacity storage and environmentally-limited resources from a section on winter-period capacity performance resources to conform with FERC approving the elimination of an exemption from the requirement that resources offer into the capacity market (ER25-785).

A section detailing the penalties for distributed energy resources that fail a test of their capability to respond to capacity deployments would be revised to avoid the potential for double penalization if the event also results in penalties during a performance assessment interval or deficiency charges.

Several changes to Schedule 6A, which lays out black start service, are intended to clarify the capital investments that can be included in the capital recovery factor rate.

Members Committee

1st Read on Changes to Membership Requirements for PIEOUG

Greg Poulos, executive director of the Consumer Advocates of the PJM States, presented a first read on a proposal to rework the membership and voting structure for the Public Interest and Environmental Organizations User Group (PIEOUG) to resolve inconsistencies stemming from the Operating Agreement’s definition of PJM membership.

A unique user group established under the OA, the PIEOUG is exempt from the requirement that user groups be composed of full PJM members.

Greg Poulos, CAPS | © RTO Insider 

He said the user group was intended to include organizations that may not be full PJM Members, signified in the OA by capitalization. However, the voting rules for user groups allowing items to be referred to the Members Committee with 75% support appears to be limited to “Members.” Another section of the OA allows items to be referred to the Board of Managers with 90% support from a user group, but uses the lowercase term “members.”

The proposal would split PIEOUG membership into two categories: consumer advocates who are PJM Members, as well as environmental organizations and general public interest groups. Both would be permitted to vote on motions to refer items to the MC, with 75% support overall and 50% from both classifications required for the vote to pass. If the MC opts to not take up the subject, the PIEOUG could vote to refer it to the PJM board with 90% support overall and 50% from both categories.

Poulos said the two categories for PIEOUG membership is intended to ensure that state-appointed consumer advocates are not outvoted if a large number of environmental or public interest groups are admitted to the PIEOUG, which chooses its own membership.

Poulos told RTO Insider the proposal is intended to find the right balance on giving all members of the user group a voice. He said it’s rare for items to be referred to the MC or board and no such votes are being considered at this time.

Stakeholders Discuss MC Annual Plan

MC Vice Chair Jason Barker opened a discussion on whether language in Manual 34: Stakeholder Process detailing the creation of an annual plan is anachronistic. He said the committee has not created a formal plan detailing its priorities to PJM management in recent years, with approval of issue charges instead fulfilling that role.

Jason Barker, Vitol | © RTO Insider

Carl Johnson, of the PJM Public Power Coalition, said the goal of the annual plan was to ensure items weren’t being overlooked. While there were a few successful efforts to establish annual plans years ago, prioritization within the stakeholder process has largely been ceded to PJM staff. While there could be value in a discussion on whether the annual plan should remain in the manual, this might not be the proper time given the other topics stakeholders are focused on.

Tangibl Group Director of RTO and Regulatory Affairs Ken Foladare said PJM has consistently set agendas that provide little time for discussion of important issues, requiring moderators to cut off conversation to move onto other subjects. He noted that the Oct. 14 Critical Issue Fast Path meeting allowed just 30 minutes for questions on stakeholder proposals, leaving individuals unable to participate. If this is repeatedly happening, the RTO needs to either allot more time or discussion should be allowed to go over time.

Barker said some stakeholders routinely engage in time-consuming behaviors, such as cross-examining PJM staff or asking argumentative questions. That may be appropriate at times, but better management of time could allow everyone to have their questions answered.

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Storage Projects Dominate ISO-NE Transitional Cluster Study

ISO-NE’s first interconnection cluster study held under new rules is made up mostly of large battery resources and contains only five wind and solar projects.

The transitional cluster study, which ISO-NE initiated in early October, includes 26 interconnection requests, with a net total of 7,205 MW. The requests include 21 battery storage projects, two solar projects, two offshore wind projects and one onshore wind project.

FERC Order 2023 required RTOs to transition from serial, first-come first-served interconnection processes, to first-ready first-served cluster study processes. The reforms are intended to reduce queue backlogs by disincentivizing speculative interconnection requests and sharing infrastructure upgrade costs among interconnection customers.

The transitional study marks the first cluster study under the new rules and is set to conclude in August 2026.

Alex Lawton, director at Advanced Energy United, said he expects the Order 2023 interconnection changes to “raise the bar for interconnection requests” and “increase the likelihood of projects actually being constructed.”

Looking at the projects included in the first cluster study, he said he was “a little bit surprised to see so few solar projects but not surprised to see so much storage.”

“We absolutely need a lot more storage, but we also need other low-cost clean generation resources too, to bring new supply to meet growing demand,” he said.

The storage requests in the cluster study total 5,632 MW, ranging in size from about 19 to 706 MW, with a median size of 214 MW.

The cluster includes a 1,200-MW interconnection request from SouthCoast Wind; a capacity-only request from Avangrid’s New England Wind 1 project (previously called Park City Wind); and an 18-MW land-based wind project in Maine.

For solar, the cluster includes a 102-MW project in New Hampshire and a 253-MW project in Maine.

In its announcement of the study, ISO-NE noted that “more than 50 other requests with previously completed studies, most of which have signed interconnection agreements, remain in the queue and can continue working toward completing the interconnection process.”

Francis Pullaro, president of RENEW Northeast, said the large number of storage projects in the cluster study likely is a result of procurement opportunities for large-scale storage projects in the region.

Massachusetts has an ongoing procurement for up to 1,500 MW of storage. The state received 13 bids from eight companies in September and is scheduled to select winning bids in December. (See Massachusetts Seeks 1,500 MW of Mid-duration Energy Storage.)

Maine has been working toward a 200-MW storage procurement, and Connecticut is in the process of selecting projects for a procurement open to solar, onshore wind and co-located storage. Meanwhile, state incentive programs generally are focused on small-scale projects.

“Frankly, there’s not a lot of procurement opportunity for transmission-level solar,” Pullaro said.

He added that it is “very challenging to find sites for large projects where you can get through siting and manage public acceptance,” and that, to site large-scale solar projects, “you’re usually talking about farmlands or having to clear cut forests.”

The relatively small number of non-storage projects in the cluster, coupled with the significant number of withdrawals that have occurred over the past year, appears to be a major challenge for state clean energy goals, said Aidan Foley, founder of Glenvale Solar.

According to ISO-NE data, 22,480 MW of FERC-jurisdictional battery and clean energy projects have withdrawn from the RTO’s interconnection queue this year. This includes about 10 GW of batteries, 11 GW of wind and 1.3 GW of solar.

“The sheer supply of projects, other than offshore wind, is terrible,” Foley said. “The region is just totally screwed in terms of meeting its clean energy goals, and the next five years is going to be an absolute dead zone.”

He said cost and new technical requirements posed barriers for projects seeking to enter the transitional cluster study. Because the ISO-NE queue has been closed since June 2024, newer projects without queue positions were not able to join the study, he added.

“The cost is really a humongous amount to anybody trying to weigh the investment needs of their portfolio,” Foley said. He estimated the study process would require a roughly $6 million investment for generators larger than 20 MW seeking to participate in the transitional cluster.

Foley has argued that the study costs — including a $5 million commercial readiness deposit — are disproportionately burdensome for smaller resources that fall under ISO-NE’s Large Generator Interconnection Procedures (LGIPs).

Notably, the cluster study contains only three projects smaller than 100 MW. All three of these requests are less than 20 MW, which is the size threshold that determines whether resources are subject to ISO-NE’s LGIPs or Small Generator Interconnection Procedures (SGIPs).

Generators seeking to interconnect under the SGIPs were required to submit a $1 million commercial readiness deposit in the transitional cluster, compared to the $5 million deposit required from LGIP resources.

In the stakeholder process leading up to ISO-NE’s Order 2023 compliance proposal, several stakeholders pushed for lower commercial readiness deposits, and Foley advocated for scaling deposit requirements to resource size. (See NEPOOL PC Backs ISO-NE Tariff Revisions for Order 2023 Compliance.)

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Brookfield Nearing Deal for Unfinished S.C. Nuclear Reactors

Santee Cooper is entering final negotiations with Brookfield Asset Management over two partially built nuclear reactors left in limbo for the past eight years.

The companies expect to reach a memorandum of understanding after a six-week period to examine resumption of construction and talk with potential power customers.

The developments announced Oct. 24 are the latest indication of the strong interest in nuclear power and are a remarkable turnaround for what had been one of the U.S. nuclear industry’s costliest failures.

Work on V.C. Summer Unit 2 and Unit 3 was halted after extensive delays and cost overruns, yielding a patchwork of reinforced concrete and mothballed equipment at a cost of more than $9 billion. Four executives eventually went to prison for their misdeeds in the project, the last of them in November 2024.

In January, spurred by the renewed interest in nuclear power’s steady emissions-free power, Santee Cooper put out a request for proposals for sale of the project. (See Santee Cooper Seeks Buyer for Unfinished Nuclear Project.)

The state-owned public power and water utility said it received more than 70 initial expressions of interest and 15 formal proposals. Its board of directors approved the letter of intent with Brookfield on Oct. 24.

The centerpiece of the deal is the two partially built Westinghouse AP1000 reactors. Their combined 2.2-GW rating is a potentially lucrative asset in an era of rising electricity demand and higher electricity costs.

Importantly, Santee Cooper maintained the equipment already on site during the eight years it sat idle.

“The state of the units, and the fact that they use the same Westinghouse AP1000 technology that is now operating in Georgia and overseas, make these assets very attractive to the nuclear power industry,” Santee Cooper CEO Jimmy Staton said in the news release.

Westinghouse will continue to be involved in the completion of the two reactor units, Staton said. Brookfield is majority owner of Westinghouse.

Of interest to ratepayers — who had to help foot the bill for what became known as Nukegate — the Brookfield deal is built on private funding.

“Brookfield came to Santee Cooper with a proposal that set out the path to turn our prior nuclear investment into lasting value for our customers and all South Carolinians,” said Santee Cooper Board Chair Peter McCoy.

“Our goals include completing these reactors with private money and no ratepayer or taxpayer expense, delivering financial relief to our customers and gaining significant additional power capacity for South Carolina. Brookfield’s proposal would do just that, and the company has the financial capability to stand behind its proposal.”

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Patton Calls on ERCOT to Operate its System Less Conservatively

WASHINGTON — ERCOT can ensure long-term reliability with its energy-only market, but it must operate its grid less conservatively for that to happen, said Potomac Economics President David Patton, the Texas grid operator’s Independent Market Monitor.

ERCOT’s ancillary services demand curves, which are part of the soon-to-go-live real-time co-optimization plus batteries (RTC+) initiative, imply a value of lost load of about $35,000/MWh, which is already well short of the $200,000/MWh implied by the one-day-in-10-years reliability standard, Patton said at S&P Global’s Nodal Trader Conference on Oct. 24.

“What makes me pessimistic in Texas is that there are multiple levels of problems getting to an efficient shortage price,” Patton said. “And most of it is driven by an extraordinarily conservative posture by ERCOT in how it operates the system.”

The grid operator pays for excessive ancillary services and has demand response programs that kick in too early, both preventing it from reaching the needed scarcity prices that energy-only models rely on to attract investment, he added.

“I think until we get some degree of alignment between how ERCOT operates the system and the markets, we’re going to be stuck in a state where it’s nearly impossible to set efficient shortage prices,” Patton said. “And, so, I don’t know how it would motivate people to build dispatchable generation.”

Plenty of DR is caused by the market, Patton said, with cryptomining data centers dropping offline when prices start to hit about $100/MWh, when the activity becomes unprofitable. But he said he is worried about DR from “outside the market” such as a residential DR program that will pay the load class to curtail at peak hours.

“The value of residential consumption is like $3,000, $4,000, $5,000/MWh, but the tightest net load hours like when ERCOT imposes that and artificially cuts the load. … I’m guessing the price in those hours is going to be $50, $60, $70[/MWh],” Patton said.

That will serve to artificially hold the price down when the market would proceed to shortage pricing, he added.

ERCOT has grown its renewable energy production more than any domestic market, with 40 GW of wind, 33 GW of solar and 14 GW of batteries — and more of that is coming, said Keith Collins, vice president of commercial operations.

“The peak loads don’t really matter as much with the solar on the hot days,” Collins said. “What matters is when the sun isn’t there, and that’s what we see in the load ramps, the net load that we see in the summer days. In the winters, we’re seeing when the sun isn’t up yet and the peaks are rising, that’s the concern, and it’s a big area of concern for us — the need to get dispatchable resources. That’s where our dispatchable reliability reserve service is hopefully going to point us to focus on getting those types of resources.”

Collins said the problem with scarcity pricing is that it will create incentives for all resources, when ERCOT needs more supply that can actually help balance renewables when their production drops.

Getting the Signals Right

Texas last debated major reforms for its wholesale market nearly five years ago after Winter Storm Uri led to widespread blackouts.

“After Uri, they looked at lots of options,” Collins said. “Many options were crossed off the table and, so, we’ll have to revisit some of those.”

Patton pushed back on Collins’ description of how scarcity pricing works, arguing it favors resources that can produce energy when the grid needs it most.

“If I have an unreliable unit that has a lot of forced outages, they’re going to miss a lot of the shortages; they’re going to make less money,” Patton said. “A solar resource is probably not going to make any money getting shortages, because shortages are going to happen when the sun has gone down. If I have a wind resource, I’m not going to make very much money, because you’re not going to have shortages when the wind is blowing.”

Reliable, dispatchable resources will get high prices when the grid needs energy the most, so a key to getting energy-only models right is ensuring their signals align with that need, he said.

“You may say: ‘We need other products to supplement that, because we have certain reliability needs that go beyond what our needs are in any one five-minute interval,’” Patton said. “So, I think we do need the dispatchable reliability service, but that’s not going to be the answer to providing price signals.”

Ideally, ERCOT would procure fewer reserves and let the system operate in a way that is more conducive to its energy-only design.

“There’s no way to fix excessive conservatism with market design like that. At some point, you have to move from both ends,” Patton said. “You have to operate the system in a manner that’s more consistent with the true value of electricity. And then you have to identify market design issues that are undermining pricing as well, and hopefully then get to a point where your energy price is going to do most of the job in terms of motivating investment.”

The Public Utility Commission of Texas told ERCOT to start operating more conservatively after Uri, Collins noted.

“There have been directions from the commission,” Collins said. “Now, there was some recent discussion about perhaps revisiting that. We’re happy to have that conversation. And if the commission were to direct us, we would take actions.”

Patton argued that many of the conservative operations are coming from the grid operator itself because the PUC has approved only proposals to procure additional reserves that come from ERCOT.

“I think the conservative mindset is coming from ERCOT operations,” Patton added. “Clearly, there’s a sense that [the PUC wants] them to be conservative, but I don’t think they’re driving them to be this conservative.”

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Options for Clean Dispatchable Power Each Have Caveats

All seven clean energy technologies evaluated for a new report might someday help New York reach its decarbonization goals, but each would require innovation and support to reach that potential.

The authors say that while hydrogen, biofuels, advanced nuclear, carbon capture and storage, next-generation geothermal, long-duration energy storage and virtual power plants all are in development, none exists at a scale to serve as a dispatchable emissions-free resource to backstop all the intermittent wind and solar generation New York wants to build.

The New York State Energy Research and Development Authority submitted the “Zero by 40 Technoeconomic Assessment” to the Department of Public Service on Oct. 22 (15-E-0302).

The report was prepared by the Electric Power Research Institute. Its title alludes to the state’s statutory goal of a zero-emission power grid by 2040.

The Public Service Commission in May 2023 ordered the report to identify methods of closing the gap between existing renewable energy technologies and future system reliability needs.

The cost and complexity of all-new or greatly expanded infrastructure is likely to be a limiting factor in the near term, giving a larger role by default to technologies that would not require significant infrastructure upgrades, the authors wrote.

The report comes as the state’s clean-energy transition lags well behind the timeline envisioned for it. State officials expect to miss the 2030 statutory goal of 70% renewable energy, perhaps by a wide margin. Delayed fossil retirements or even new fossil generation are being contemplated as a result.

The report groups the seven technologies evaluated into three functional categories: low capacity factor resources to deploy at peak system need (hydrogen and biofuels); high capacity factor resources that can a provide firm supplement to renewables (advanced nuclear, next-generation geothermal and CCS attached to thermal plants); and filling gaps with resources to balance supply and demand (long-duration storage and VPPs).

Hydrogen

Hydrogen can be a zero- to low-carbon energy resource, depending how it is produced. Economywide demand for hydrogen would be the most economical scenario; building a bulk underground storage and pipeline transport system just for the power sector would be costly.

Pipelines are expensive and slow to build. But without them, the cost and logistics of statewide use of hydrogen for power grid reliability would be prohibitive.

The greatest near-term opportunity appears to be in upstate New York, if low-cost or curtailed renewable electricity could power hydrogen production co-located with geologic storage.

However, there may not be excess renewable electricity to generate hydrogen in 2040, and the cost of hydrogen is expected to be significantly higher than natural gas.

Biofuels

Renewable natural gas (RNG) and renewable diesel (RD) are the biofuels most relevant to the power sector because they are drop-in replacements for natural gas and distillate fossil fuels.

RNG has relatively few infrastructure needs, but its feedstocks are limited and are required for decarbonization of other sectors. So RNG would most likely serve as a peaking resource. The air-quality impact of RNG combustion depends on whether it is evaluated by net emissions, which are zero or close to zero, or by gross emissions, which are similar to natural gas.

RD may be particularly important to New York’s grid as it shifts to a winter-peaking system. But it is expected to be significantly more expensive than fossil distillate, and it is less efficient than RNG in combustion turbines.

Biofuels and hydrogen have near-term supply constraints, but the availability of hydrogen has the potential to outstrip biofuels because of the finite supply of biofuel feedstocks.

Advanced Nuclear

Nuclear reactors are expensive; operating them at a high capacity factor is more economical. So while advanced reactors are expected to be capable of more flexible operation than today’s conventional fleet, they are likely to remain baseload power.

Developing any new nuclear generation in New York by 2040 will require early and careful planning, as the timeline may stretch a dozen years per facility, unless federal intervention or economies of scale speeds up the regulatory and construction process.

Carbon Capture and Storage

CCS can be used on a natural gas-fired peaker plant, but it is best used on baseload power plants because it is expensive and less efficient on an intermittent basis.

CCS would require significant buildout of transport and storage infrastructure that does not exist in New York. Such an ecosystem would face challenges in regulation, permitting and public acceptance but could benefit hard-to-decarbonize industrial applications.

Even a carbon capture rate of nearly 100% would not make a significant reduction in upstream emissions totals as tallied by New York’s greenhouse gas accounting system.

Geothermal

The geological landscape of New York is largely unexplored for its geothermal power potential, but the potential is believed to be quite low — less than 1 GW by 2040 — using existing technology.

But in the longer term, with continued technological innovation, there is a theoretical potential for greater use of the earth’s heat to generate electricity in New York. The cost of such an effort is highly uncertain.

Long-duration Energy Storage

Short-duration storage (less than 10 hours) presently can meet most grid-balancing needs, but greater reliance on renewable power will require larger capacities and longer durations of storage.

The report examines 18 electrochemical, mechanical and thermal energy storage technologies capable of operating for durations greater than 10 hours.

Electrochemical and mechanical technologies generally are more ready for deployment. Electrochemical technologies are more modular and can provide more grid services but come with safety considerations, higher costs and shorter lifetimes. Thermal technologies potentially are useful for industrial decarbonization.

All come with round-trip efficiency losses, and some with standby losses.

Emerging technologies must be assessed to mitigate any risks as they move from early development to deployment.

Electricity market design changes are needed to support market-based deployment of long-duration storage.

Virtual Power Plants

VPPs could serve as a key intermediary between flexible distributed energy resources and load-flexible appliances.

A recent study showed VPPs could reach 8.5 GW of flexibility potential in New York by 2040, a cost-effective approach to balancing supply and demand.

VPPs carry low capital costs and short lead times, but realizing their potential would require improving customer recruitment and participation; standardizing communications and market interfaces; and addressing metering and telemetry costs. Programs with easier enrollment and reduced user interface are expected to have the greatest impact.

Where to Begin

The report identifies several no-regrets actions the state can take to set the stage needed for its 2040 goals:

    • Do not overly rely on one technology; pursue a diverse portfolio.
    • Start early.
    • Invest in grid-enhancing technologies to reduce the need for backstop resources.
    • Invest in innovation.
    • Develop strategies across industries to overcome infrastructure hurdles.
    • Engage early with developers, end users and other stakeholders.
    • Model a range of costs and performance attributes of technologies to deploy.
    • Reassess options regularly and remain flexible as new options become available.
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Counterflow: Beam Me Up, Scotty

There was a big event the other day rolling out the U.S. Army’s new Janus Program, “a next-generation nuclear power program that will deliver resilient, secure and assured energy to support national defense installations and critical missions.”

The Army will contract for 18 nuclear “microreactors” (two each at nine Army bases). “The reactors will help keep weapons powered and maintain critical base operations when other energy sources go down because of bad weather, cyberattacks or other grid disruptions.”

This is wasteful, counterproductive and dangerous. It is worse than the Department of Defense microgrid initiative that I critiqued eight years ago.

Like the microgrid initiative, the Janus Program ignores the fact that the vast bulk (87%) of Army base power outages are from problems on the base’s distribution system. Existing building-specific diesel backup generators provide backup for distribution system outages. Nuclear microreactors (like microgrids) would not provide backup for distribution system outages. Thus, microreactors would cause base buildings to lose backup for 87% of outages, eliminating the vast bulk of existing backup capability.

Steve Huntoon

Moreover, Army bases don’t need complex microreactors to add to their infrastructure burdens. Instead, our bases need expansion of sensible and incredibly cheap resilience exercises, like those provided by MIT’s Lincoln Laboratory.

With specific focus on cyberattack disruptions, microreactors and the rest of the base’s electric system would be connected to communication networks. Building-specific diesel backup generators are not. So microreactors would create new vulnerability to cyberattacks.

And these microreactors would pose a huge threat to our troops. It appears they would not have containment structures, which means that an attack could spread highly radioactive nuclear fuel across a base and surrounding areas. If captured, the fuel could furnish the nuclear material for a dirty bomb or even fissile material for a crude nuclear bomb. No such risks exist with diesel or other fossil fuel generators.

This vulnerability exposes the irrationality of microreactors. If they are sited overseas because of attack threats to fossil fuel supplies, then those same attack threats would exist for the microreactors, with much worse potential consequences. If they are sited on or close to U.S. soil, then there are no threats to fossil fuel supplies that microreactors would relieve.

This intractable dilemma would appear to explain changing DOD messages about siting: first far-flung bases, then dropping that approach, and then resurrecting it during the Janus Program rollout.

| DOD

Oh, on the minor matter of cost: Diesel backup generators cost about $600,000/MW. The Army says the Janus Program would build on DOD’s Project Pele, which involves a 1.5-MW microreactor contracted for in 2022 at an estimated cost of $300 million, amounting to $200 million/MW. That is 33,300% more than the cost of diesel backup generators. It’s even 1,200% more than the cost of the new Vogtle units in Georgia.

And did I mention that in 2022, the delivery date for the Project Pele microreactor was said to be 2024? The delivery date now is said to be 2028. Two years until delivery has tripled to become six years until delivery, which should surprise no one familiar with the nuclear industry.

Speaking of money, where are the untold billions for the Army microreactors going to come from? The Janus Program rollout mentions the Defense Innovation Unit (DIU), which has an annual budget of about $1 billion. The planned microreactors would cost many times that, hurting existing DIU initiatives and spending money that Congress has not authorized or appropriated (not to put too fine a point on it).

In normal times we might look to the Pentagon press corps to ask about some of this, but the Trump administration has revoked almost all Pentagon press passes. And we know how congressional oversight is going these days.

To the Moon, Alice!

Not to be outdone by DOD, NASA plans to send a 100-kW microreactor to the moon, at an estimated cost of $6.2 billion. This works out to $62 billion/MW. What this microreactor would do on the moon is not entirely clear, other than somehow compete with China and/or Russia in somehow laying claim to something. Maybe it could charge Elon Musk’s cellphone when he shows up?

Speaking of Musk, where is DOGE when we need it?

Columnist Steve Huntoon, a former president of the Energy Bar Association, practiced energy law for more than 30 years.

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Van Welie Discusses the Challenges Markets Face in New England

WASHINGTON — In ISO-NE CEO Gordon van Welie’s time running the grid operator, it has seen natural gas come to dominate generation in the region. An even bigger shift is under way now as state policies demand a grid increasingly powered by renewables.

The shift to natural gas led to cleaner generation than the mix 25 years ago, but it also has come with unexpected developments, van Welie said Oct. 23 at the S&P Global Nodal Trader Conference. “One of the big assumptions at the start of the market was that fuel will always be available,” he added. “And of course, the fuel is not always available.”

While natural gas generation is cheap enough most of the time to push other resources off the system, during winter cold snaps, the region struggles to attract enough of the fuel. Gas and electricity prices then skyrocket. With state policy shifting more heating and transportation demand onto the grid, winters promise to become more volatile.

“So, the big point, from a trading point of view, is much higher volatility than we’ve ever seen in the winter,” van Welie said. “The second point is that emissions reduction will be seasonal. We will decarbonize the spring and the fall way before we decarbonize the winter, if ever.”

ISO-NE sees negative prices in the shoulder seasons because of the proliferation of renewables. And van Welie said he expects that trend will grow. But serving a rising share of winter demand with 100% renewables would be costly because the reliability value of wind and solar declines as more resources are added to the grid.

Solar has a massive impact in New England, which van Welie described as a 42-GW system with 10 to 12 GW sitting behind the meter.

“If you can have firm, dispatchable, zero-carbon generation, the mythical ‘DEFR’ as New York invented this resource in their capacity expansion models — dispatchable emissions-free resource — you can really not only support reliability, you can dramatically reduce all that cost,” van Welie said. “The problem is that resource doesn’t exist today. Maybe SMRs will fulfill that role in the future, but for now, the balancing resource is natural gas.”

Another economical answer is price-responsive demand because reductions can happen during winter peaks when producing power is most expensive. On top of price volatility issues, getting the last 15 to 20% of decarbonization will be the most expensive. The grid needs to expand to handle more renewables, which cuts energy market revenues for balancing resources needed to meet winter peaks.

“You need balancing resources to keep the lights on,” van Welie said. “That money has got to come from somewhere, so that’s the resource adequacy construct, and those constructs are under a lot of pressure right now.”

ISO-NE expects the role of natural gas to grow in coming years as demand growth is outpacing the addition of renewable resources, which eventually will bring down emissions, though doing so all on their own could prove too costly for the region’s future policymakers.

“Taking the last bit of carbon out of the system becomes increasingly expensive,” van Welie said.

With affordability an ever present issue, policymakers might decide that 80% of the way to net-zero emissions is enough, he added.

The queue in New England today is dominated by renewables and batteries because that is what investors think can get built and what state policies are pushing. A significant resource the region was counting on was offshore wind, which has 15 GW under development.

“That’s got a big question mark against it. It’s been disrupted,” van Welie said. “My guess is offshore wind has been knocked back at least a decade, and so does raise the question for the region, which is, where’s the supply coming from in order to meet this demand that’s projected?”

The questions around offshore wind have New England policymakers thinking about gas again, but that must be weighed against long-term decarbonization goals that could risk stranded costs. While the markets did well to bring investment onto the grid and shield customers from the risk of bad investments, ISO-NE is making major changes to its capacity construct to better deal with winter reliability issues.

“We need to move to a prompt, seasonal market with marginal accreditation and modeling of the gas constraints,” van Welie said. “We’ll be the first region to actively clear the capacity market by modeling a gas constraint.”

If the markets are going to succeed at guiding New England through an affordable, reliable transition to a net-zero grid, as they did to a system dominated by natural gas, states must embrace the markets,” van Welie said.

“Ultimately, the markets are a means to an end,” van Welie said. “The states are the ones that created the markets. The states are the ones that can undo the markets. So, they need to have ownership and support for the market construct.”

If states support a capacity market it could work. If they do not, they will find a way around it and meet their policy goals some other way, he added.

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Trump’s TVA Nominees Reject Privatization

Each of President Donald Trump’s nominees to the Tennessee Valley Authority’s board of directors said they did not support the privatization of the utility or selling its assets, as feared by some environmentalists.

Speaking at their confirmation hearing before the Senate Environment and Public Works Committee on Oct. 22, Mitch Graves, Jeff Hagood and Randy Jones each simply said “no” when asked by Sen. Ed Markey (D-Mass.) whether they supported TVA’s privatization. Florida Public Service Commissioner Arthur Graham said, “I think there’s absolutely no reason to do anything different here.”

When asked by Markey to agree not to “sell off any portion of TVA’s service region” or infrastructure assets, the nominees mostly answered to the senator’s liking.

“I do not see any reason to sell any of TVA’s assets off,” Jones said, which Graham echoed after Markey said: “that was the correct answer.”

Graves said, “I don’t think that’s the board’s decision,” to which Hagood agreed.

The nonprofit group Appalachian Voices had urged senators to question the nominees on privatization based on comments Trump made during his first administration. The TVA board has lacked a quorum for months after the president fired three of its members. (See Nonprofits Warn of Potential TVA Privatization Ahead of Board Hearings.)

The committee will vote on advancing the nominees to the Senate floor Oct. 29.

All four spoke about TVA’s importance in keeping electricity affordable for its customers. Graves, a member of the Memphis Light, Gas & Water board, and Hagood, a Knoxville-based attorney, each emphasized preserving it as a local institution.

When questioned about meeting load growth, each emphasized the importance of nuclear power, with Hagood calling it TVA’s “best hope.”

“We need a sense of urgency” on nuclear, agreed Jones, an insurance executive who also serves on the Guntersville Electric Board in Alabama.

Graham said small modular reactors are “key” to meeting increased demand. But first he wanted “to make sure the numbers people are talking about [in terms of gigawatts] are legitimate. I mean, is this a pipe dream, or is this actually going to come true? I believe it is,” but the board needs to verify the anticipated demand through its integrated resource plan, he said. “I saw what happened in Georgia with Vogtle … and no one wants to be the next one going down that path.”

Sen. Mark Kelly (D-Ariz.) suggested power purchase agreements for large loads to protect customers from rate hikes created by the increased demand. Graves said he “100% agreed” with Kelly “that it cannot be on the backs of ratepayers.”

Each also agreed they would consider creating a separate rate class for large load facilities like data centers.

“This is all we’re about now, is data centers,” Jones said in agreement. “But what’s it going to cost to supply the power for them? And what if they leave five years from now and we’re left holding the bag?”

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NYISO Stakeholders Debate New York City Reliability Need

Stakeholders spent much of the Electric System Planning Working Group’s meeting Oct. 20 debating the validity of NYISO’s recent finding of a reliability need in New York City by summer 2026.

In its third-quarter Short Term Assessment of Reliability (STAR), the ISO said there would be a shortfall in the city if several ongoing projects — including the Champlain Hudson Power Express (CHPE), Empire Wind and the Propel NY Transmission Project — fail to be energized by their anticipated in-service dates. The projects would provide the power that would be unavailable from the planned retirements of the Gowanus and Narrows generators. (See NYISO Again Identifies Reliability Need for NYC.)

“Until these plans are completed and demonstrate their power capabilities, the identified reliability needs in New York City would continue to remain,” said Keith Burrell, a transmission planning adviser for NYISO.

Stakeholders tried to get the ISO to clearly articulate how likely it might be that that CHPE would be in service by the second quarter of 2026, potentially solving the nearest-term reliability need for New York City.

“I guess I’m trying to understand whether CHPE needs to be proposed as a solution or is it a solution that is going to be looked at in each STAR?” asked Tony Abate, representing the New York Power Authority.

Another NYISO staff member repeated Burrell, saying that once CHPE has demonstrated its ability to provide power, that would be a solution.

“I’m struggling to understand what has changed in the last 90 days,” said Howard Fromer, director of regulatory affairs for Bayonne Energy Center, referring to the most recent STAR. “It can’t be the load. Has it materially changed from what you were using in the Q2 STAR?”

“We’ve been identifying needs in the STARs all along and continue to identify CHPE as a potential solution,” Burrell said. He pointed to a figure in the most recent report that illustrated the city’s transmission security margin. According to those forecasts, if CHPE entered service as planned, there would not be a deficiency until 2029.

After some discussion about what future STAR reports might look like if CHPE came online as expected, the ISO clarified that each STAR was a snapshot of system conditions in time. If a project, or deactivation, meets the base inclusion criteria, it gets into the latest STAR.

“I think what people are trying to identify is, ‘What is the next step?’” said Yachi Lin, director of system planning for NYISO. “And the next step is that NYISO will be soliciting [solutions] starting in early November. In that solicitation we will have more details about the solicitation type.”

Lin said that a market-based solution that could potentially come online earlier to serve the need found in the STAR would be “something for the NYISO to consider.”

“But we don’t know yet what the kind of proposed solution or answer to the solicitation is. It’s difficult for us to forecast what the outcome is going to be,” Lin said.

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Economic Uncertainty Looms over NYISO Conference

Presenters at NYISO’s 2025 Fall Economic Conference painted a confusing portrait: Conflicting evidence between a weak labor market and overall economic growth leaves uncertainty about whether the economy might tip into a recession.

“I could have just presented a ‘shrug’ emoji and just left for the next few hours. But I feel like that probably would not have been that enlightening,” said Adam Kamins, senior director of Moody’s Analytics. “Instead, we’ll try to walk through all the different sources of uncertainty.”

NYISO engages Moody’s Analytics to present on state and federal economic trends twice a year as part of the Load Forecasting Task Force. Economic outlook is a major component of load growth.

In the Oct. 23 presentation, Kamins showed an index of employment gains across 260 industries from the Bureau of Labor Statistics. Over the previous six months, the balance of industries adding vs. shedding jobs tipped in favor of shedding. Monthly growth in non-farm payroll has flattened, according to the BLS.

Another point of concern in the labor market is the sharp decline in immigration due to a Biden executive order in June 2024 capping asylum requests. That was followed by President Donald Trump’s dramatic increase in immigration enforcement actions and deportations. This has led the foreign-born share of the labor force to contract.

“We are seeing hiring at very, very low levels,” said Kamins. “The way firms are hiring is consistent with the kind of thing you would see during a recession.”

Firms are “just sitting tight” on their workforces, said Kamins. Companies are waiting to see where the economy is going.

A stakeholder asked whether Kamins and other economists had considered the “integrity” of data coming out of the Trump administration. Kamins pointed at the firing of BLS head Erika McEntarfer in June when the jobs data were not to Trump’s liking. While the BLS largely was staffed by “apolitical civil servants,” Kamins explained, if the administration puts political actors in charge of the bureau, that could damage the credibility of BLS data.

“We’ve started to think about what other ways can we verify the data we’re getting from the BLS,” Kamins said. While he wasn’t as worried about the BLS as he is about the Federal Reserve, Moody’s is taking steps to confirm government figures. “We’ve done some of the work to create our own indexes of other sources out there. Bottom line, yes, it’s a concern.”

Later in the presentation, Kamins showed a timeline of the effective U.S. tariff rates and the statutory increases that have bounced around since Trump took office. He said the effective U.S. tariff rate was higher than it had been since 1920. A survey from the Federal Reserve Bank of Dallas found that more than 75% of manufacturers intended to pass on tariff costs to consumers, and 50% said they were absorbing costs internally.

“There are some that are doing both,” said Kamins. “There was a lot of action to make the impact of tariffs not necessarily that evident to consumers.”

Eventually, this would increase costs across the economy, which in turn would create inflationary pressure, Kamins explained. Tools and hardware, vehicles, bicycles, jewelry, meat, poultry and fish are places where you can find evidence of tariff-based price increases.

This increased price pressure makes it difficult for the Federal Reserve to balance its targets in the job market and inflation. Kamins added this is even more difficult because of the administration’s erosion of Fed independence.

“Any day now there’s going to be a nominee for who will be the next Fed chair,” Kamins said. “I think that will be a very telling indicator of where things are headed. Whether there’s going to be a political operative or if it’s someone who is generally respected in the economics community.”

New York’s Resilient Economy

While the nation might be experiencing an overall decline in job growth, New York’s labor market is healthier, Kamins said. The labor market is anchored by hiring in state government, health care, education and construction. New York’s consumer sentiment is higher than the U.S. average, meaning that people feel better about the economy in New York than elsewhere.

Several metro areas in New York are experiencing economic expansion, particularly Albany, Kingston and Rochester. The upstate city of Glens Falls is a trouble spot. Kamins said it was more reliant on Canadian tourism than other areas of the state and likely already is in recession.

Some of this growth is from the state’s lack of reliance on federal money. According to the state comptroller, New York historically has been one of the few states to put more money back into the federal government than it receives. As of the most recent report, New York had not fully returned to this pre-pandemic norm, but it was getting close.

“It’s a bit of a good-news, bad-news situation,” said Kamins. “The good news is that New York is not as dependent on federal government expenditures as some of its peers. … The bad news is that by no means is New York immune from potential cuts.”

Kamins said New York faced the most risk from federal funding cuts through programs like Medicaid. New York and Minnesota were the only two states that signed a provision of the Affordable Care Act, the Basic Health Program, to create a state-administered public option. If that were cut, New York would get hit harder than most other states.

New York also is heavily dependent on microchip fabrication for its upstate economic outlook. Without the impact of the new Micron chip fabrication center, upstate economic outlook looks much bleaker.

Housing prices have begun to level off statewide as more supply comes onto the market. Prices are high, and that likely will drive office-to-apartment conversions in markets like New York City. Supply-constrained areas like Rochester and Monroe County have seen supply gains more rapidly than other areas of the state.