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December 17, 2025

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Ontario to Expand Industrial Energy Efficiency Program

IESO will expand its industrial demand-side management program in September, increasing funding and allowing both larger and smaller participants than currently permitted.

The electric demand side management program (eDSM) incentives are intended to help industrial, municipal, institutional and health care organizations to implement “proven, commercially available” energy savings technologies that would otherwise be too costly.

The new program will triple the incentive cap to $15 million from $5 million per project, and allow participants five years to complete installation, up from three years.

The minimum savings to qualify will be reduced to 600 MWh/year from 2,000 MWh/year. For the first time, the program also will provide funding for feasibility studies (50% of total costs, up to $100,000).

The grid operator also is making the application process simpler, with a single sign-off application and a first-come-first-served intake.

The program is part of IESO’s $1.8 billion 2025–2027 eDSM plan, which is forecasted to reduce peak demand by 900 MW and save 4.6 TWh of electricity by 2027. Ontario, which is projecting 75% load growth by 2050, plans to spend $10.9 billion under a 12-year funding commitment that began in January, tripling the province’s historical EE spending.  (See Ontario Integrated Energy Plan Boosts Gas, Nukes and IESO Seeking Feedback on Commercial HVAC Demand Response Program.)

The new industrial program was informed by the province’s experience under its Save on Energy program, a review of industrial programs in other regions and stakeholder feedback, Nicole L. Hynum, supervisor of IESO’s Custom Business Programs, said in an Aug. 21 webinar.

“Some customers [in the industrial energy efficiency program] did identify some challenges with the program, including funding cycles that maybe didn’t align with your capital planning cycles [and] a more risky application process that didn’t work for industry because it was competitive,” Hynum said. “The thresholds for the project size were …  too large for some industries, and the incentive levels were competing with other demand-side management programs and were less than those other competing offers. So, you know, it impacted participation.”

Under the former program, incentives were proposed by participants based on their project needs. The new program will pay the lesser of $300/MWh ($450/MWh in areas having “local needs”), 75% of eligible project costs or the amount that would provide a project payback of one year.

A project that saves 5,000 MWh/year in a local needs area would receive incentives of up to $2.25 million (5,000 × $450), subject to the eligible cost payback test and a $15 million cap.

Participants can seek an exception to the $15 million cap based on their business case.

Eligible projects must save electricity for at least four years after the end of a one-year measurement and verification (M&V) reporting period.

Participants will receive 50% of their project incentive based on a review of their first-quarter M&V report and the balance after a review of the year-one M&V report.

Ineligible to participate are:

    • Electric generation projects, except approved waste energy recovery where the recovered energy offsets the facility’s own load;
    • Behind-the-meter storage, unless the storage improves the efficiency of other project components, resulting in net electricity savings;
    • Lighting projects (which can receive funding through the Save on Energy Instant Discount Program);
    • Fuel switching, unless approved by IESO; and
    • Local distribution company infrastructure efficiency measures.

The final design of the program is expected to be approved in early September, with the program launching late in the month.

“This is year one of a 12-year framework,” Hynum said. “We will no doubt be enhancing this program to meet evolving marketplace and electricity system needs.”

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Counterflow: Have You Heard the One About New Jersey Leaving PJM?

Yeah, that one. The Wall Street Journal’s op-ed broadside on Gov. Phil Murphy, New Jersey and PJM.  

We’ll get to the punchline later, but let’s start with some reality checks. 

Reality Checks

Energy independence in the past? Here’s the op-ed claim: “By 2016, New Jersey achieved energy independence … partially fueled by Pennsylvania gas.” That is a plain contradiction in terms. Not to mention that New Jersey’s gas power plants are totally fueled by out-of-state gas. 

And, come to think of it, I haven’t noticed any uranium mines in New Jersey that could fuel New Jersey’s nuclear plants.  

And even if the op-ed claim was meant to refer to New Jersey power plants (not their fuels), it’s still wrong: In 2016, New Jersey had 16,797 MW of generation capacity and 19,012 MW of peak demand (Slides 7 and 25), so New Jersey wasn’t “energy independent” no matter how you look at it.  

Steve Huntoon

Coal plants shut down? How about the op-ed claim that New Jersey “shut down” all its coal plants? Coal plants in New Jersey shut down voluntarily because of poor economics, with the last of them, Logan and Chambers, shutting down in 2022.  

Increased reliance on wind and solar? The op-ed claims that New Jersey has “increased its reliance on intermittent wind and solar power.” Actually, solar power has had a trivial increase from 117 MW to 181 MW, and wind power has changed, a la Mr. Blutarsky, from zero-point-zero MW to zero-point-zero MW. (See Slide 7 and Slide 8.) So much for facts. 

Supply-side mismanagement? New Jersey is alleged to have had supply-side mismanagement leading to a 12% decrease in generating capacity. That is a smaller decrease than the regional decline of 20% that the op-ed claims later.  

Blue-state PJM? Then there’s the claim that PJM has had the same bad policies as New Jersey because PJM’s “leadership” is driven by its “largely blue-state makeup.” This claim is baffling on multiple counts. PJM is not governed by states’ political leadership — instead by an independent board and “stakeholders” like retail customers, generators and utilities. 

PJM is regulated by FERC. PJM states are not even “largely blue” — the legislatures are divided evenly, six red, six blue and two split, between its 13 states and the District of Columbia. With legislatures and governors considered it’s four red, five blue, and five split. 

Facts are stubborn things. 

What Actually Happened?

So what actually happened over the past 10 years? Low wholesale energy and capacity prices incented inefficient generators (mostly coal) to retire in New Jersey and across PJM. And they did. The PJM markets served consumers well, as summed up in a New Jersey BPU report: “The regional competitive market has performed well in offering secure, low-cost supply to New Jersey.” (See Page 9.)  

The New Jersey average residential rate increased by 23.3% from 2016 to 2024 (less than 3% per year).   

Data from the same Energy Information Administration chart shows that residential rates in the rest of PJM increased by an average of 27.9% over this same period. So the New Jersey rate increase was less than the rest of PJM. And the residential rate increase in the U.S. overall was 31.3% — so the New Jersey and PJM increases were both less. Please check out the numbers yourself.  

And, as a bonus, emissions in PJM have declined dramatically, as this chart shows. (See Slides 31 and 32.) Even if you don’t care about carbon emissions and global warming, you should at least welcome the amazing declines in nitrogen oxides and sulfur dioxide. 

New Jersey average emissions | PJM

Now we’re in a new supply-demand situation from data centers driving big increases in forecasts of future demand. (See Slide 20.) This is increasing capacity prices. The higher prices are designed to attract new generation to meet that future demand. It’s that simple. And though tough challenges loom, including higher residential rates, thus far it’s working as designed. 

By the way, something else you’d never guess from the op-ed: The capacity price increase for New Jersey is no less than that for the rest of PJM. 

Leaving PJM

Now that we understand the fundamentals of where we were and are, let’s consider the op-ed’s punchline that New Jersey should leave PJM, and go it alone. 

Hmm. New Jersey has 13,388 MW of generation capacity and 21,221 MW of peak demand. (See Slides 8 and 21.) So it’s short 7,883 MW. 

New Jersey net energy import/export trend | PJM

Here’s the chart of New Jersey’s electricity imports to meet customers’ needs. (See Slide 28.) You’ll notice that imports vary between 2,000 MW and 6,000 MW throughout the year. That means that if New Jersey left PJM to be on its own, there would be rolling blackouts around the clock, varying from 9% of New Jersey households to 28% of New Jersey households. Brilliant! 

New Natural Gas and Nuclear to the Rescue?

The op-ed goes on to suggest that New Jersey could avoid shortages and blackouts with new natural gas and new nuclear generation. Sorry, no.  

The op-ed says new natural gas plants could be delivered in New Jersey within three years — that’s not only wrong, but irrelevant. New natural gas supplies couldn’t be delivered to New Jersey for 10 years at best, as this timeline for the Northeast Supply Enhancement project illustrates. The last pipeline project proposed to serve New Jersey, the PennEast Pipeline, was proposed in 2014; targeted completion became 2023 before it was abandoned in 2021. So good luck with that. 

New nuclear is even further off, not to mention prohibitively expensive (before cost overruns), as I’ve discussed before. As Brattle recently advised the New Jersey BPU: “If it chooses to embark on an ambitious new nuclear strategy, New Jersey may have a new, probably small, nuclear unit online by the late 2030s or 2040.” (See Page 6.) Oh boy, one small nuclear unit in 15 years or so. And good luck with the siting, especially in northern New Jersey, where the new generation would be needed.  

The Upshot

New Jerseyites would suffer through many years of rolling blackouts, wondering why The Wall Street Journal promoted leaving PJM. 

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

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DOE Orders Mich. Coal Plant to Remain Available Another 90 Days

The U.S. Department of Energy has ordered the J.H. Campbell Generating Plant to remain available another 90 days, saying its capacity is needed to maintain MISO grid reliability. 

Consumers Energy had planned to retire the 1,420-MW coal-fired facility in southwest Michigan on May 31, but DOE on May 23 issued an emergency order (202-25-3) under Section 202(c) of the Federal Power Act ordering it to remain ready to operate because of a shortage of electricity and capacity to generate electricity. (See DOE Orders Michigan Coal Plant to Reverse Retirement.) 

That order expired at midnight Eastern time Aug. 21. 

Energy Secretary Chris Wright issued the follow-up order (202-25-7) at 8:50 p.m. Eastern time Aug. 20; it expires Nov. 19. 

In his Aug. 20 order, Wright indicated the generation shortfall in MISO is likely to continue. 

President Donald Trump declared an energy emergency on his first day in office, and his Cabinet agencies have been scrambling to rejigger energy policy toward the fossil fuels he favors. 

One of their stated priorities has been halting retirement of aging fossil-burning plants. 

In a news release, Wright cited seasonal outlooks by NERC and NOAA warning of high temperatures in the Midwest as well as resource adequacy projections by MISO itself.  

“The United States continues to face an energy emergency, with some regions experiencing more capacity constraints than others. With electricity demand increasing, we must put an end to the dangerous energy subtraction policies embraced by politicians for too long,” he said. 

“This order will help ensure millions of Americans can continue to access affordable, reliable and secure baseload power regardless of whether the wind is blowing or the sun is shining.” 

Section 202(c) has been a lightly used provision historically. Just 11 orders were issued during the Biden administration, all of them weather-related. This compares with nine by Wright since mid-May, only one of which was weather-related. 

The cost of halting the J.H. Campbell retirement has been a point of contention. (See DOE Extension of Michigan Coal Plant Cost $29M in 1st Month and FERC Rules Costs of Mich. Coal Plant Extension Can be Split Among 11 States.) 

It also has been unpopular with environmental advocates. 

Sierra Club Beyond Coal Campaign Director Laurie Williams said Aug. 21: “By illegally extending this sham emergency order, Donald Trump and Chis Wright are costing hardworking Americans more money every single day for a coal plant that is unnecessary, deadly and extremely expensive.” 

Earthjustice Senior Attorney Michael Lenoff said: “Chris Wright is not a Soviet-era central planner, but his new order suggests he would fit right in. The order purports to override the considered judgment and careful work of many federal, state and regional bodies who actually have authority to keep the lights on. In their place, Secretary Wright blunders in.” 

In a statement, MISO said it will “continue coordinating with Consumers Energy to comply with the order.”  

But MISO again stressed that J.H. Campbell did not clear the planning resource auction and is unnecessary for resource adequacy in the 2025/26 planning year.  

“MISO’s 2025-2026 Planning Resource Auction indicated adequate resources to meet anticipated demand. State regulators along with utilities have the responsibility of ensuring resource adequacy. MISO remains focused on reliably operating the grid using the resources our members provide, while working closely with stakeholders and regulatory partners, providing visibility into system needs and sending market signals to inform long-term resource planning,” MISO spokesperson Brandon Morris said in a statement to RTO Insider.  

MISO leadership previously has said it might have to navigate similar future orders from the federal government to prop up retiring coal plants. 

MISO Director Todd Raba said MISO might have to navigate similar edicts in the future, with about 30 coal plants in the footprint. At MISO’s June board meeting, he said it’s a “critical topic that will have huge implications in MISO.”  

Lawmakers, health professionals and other officials gathered near the plant in West Olive, Mich., on Aug. 12 to protest its extension. On Aug. 18, a small crowd of community members marched to U.S. Rep. Bill Huizenga’s office in nearby Holland, Mich., to again protest continued operations.  

Consumers Energy said it was evaluating the order extension and expects to “continue operating the plant as required by DOE.”  

“We have worked closely with MISO and have been operating in compliance with the order and MISO’s dispatch requirements. All power generated by the Campbell plant and other Consumers generating plants is supplied to the MISO grid. Specific details on recent generation are not publicly available at this time,” spokesperson Brian Wheeler told RTO Insider.  

Wheeler also said the utility was “pleased” with FERC’s approval of an allocation that’s set to disburse cost recovery of the plant among the 11 states or portions of states in MISO Midwest.  

Consumers Energy declined to comment on the coal plant’s usefulness so far over the summer or how the plant will fit into the MISO market over the fall.  

Data from power analytics company Yes Energy shows the 1.42-GW plant has been used consistently since the beginning of August, averaging an 84-88% hourly capacity factor. 

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USEA Panel: Power Sector Moving Slower than Big Tech

A group of industry insiders looking at ways to meet data centers’ electricity demand found a common thread within their varied opinions: The power sector and its regulators need to be a lot nimbler.

The United States Energy Association’s monthly virtual press briefing Aug. 20 focused on ways Big Tech is reshaping the electric utility sector or even upending it, with the potential for major data centers to add their own power generation.

Speakers drawn from the power and technology sectors fielded questions from a panel of journalists on what is at once a potentially lucrative and disruptive scenario facing the electric power industry.

Among the themes:

How much additional generation needs to be built to serve data center loads — or is this more of transmission issue?

It is both, said Tom Falcone, president of the Large Public Power Council. There also are the secondary issues of supply chain and workforce adequacy, permitting and retirement of existing generation.

After two decades of flat demand, unprecedented growth is projected, said Clinton Vince, head of Dentons’ U.S. Energy Practice. Further, the 24/7 nature of this demand also is unprecedented, he said.

Jeff Weiss, executive chairman of Distributed Sun and truCurrent, said the 20th-century grid that exists is not up to the task: “Electricity scarcity is upon us, and this is the new world for industrials, for data centers, for consumers, where electricity is not abundant and we need to manage sources of power.” Fortunately, he added, battery storage is bridging some of the gap.

Speed is the overriding issue, said Derek Bentley, a partner at Solomon Partners, and trends are not favorable. GE Vernova needs a five-year lead time to equip a new combined-cycle gas plant that then takes a couple more years to build, while renewables are intermittent and the target of policy changes. “But with the data centers, you can generally build a data center in 12 to 18 months.”

Karen Ornelas, director of large load program management at Pacific Gas & Electric, said PG&E has started a cluster process for new load requests, which has reduced the duration and cost of engineering studies.

Tom Wilson, principal technical executive at EPRI, said demand flexibility will help ease the crunch that is developing. EPRI’s DCFlex initiative has involved more than 50 entities in multiple sectors to demonstrate ways data centers can moderate that 24/7 demand.

Balancing Act

How do you balance the sharp increase in new load with the imperatives of affordability and reliability? How do you balance the needs of new data centers with those of existing residential and industrial customers?

There is a lot of uncertainty, Falcone said, “and so what you see is a lot of reforms happening at the state level and with individual utilities to better understand and also get some financial commitments that are longer-term.”

Weiss said the nation is trying to grow in the 21st century using a 20th-century utility system, a prescription for failure, and “the regulatory construct puts a lot of lethargy” in moving forward from that. “Everything we do takes 10 years or more. We need to figure out how to do everything in two years … and it’s critical to our economy that we do that.”

That’s why so many behind-the-meter partnerships are being formed, Bentley said. “Unfortunately, there isn’t just a silver bullet solution right now, and so it does require a lot of things, all coming together, a lot of constituents working together to solve the problem.”

Bud Albright, senior energy adviser at the National AI Association, reminded listeners that policy does not exist in a vacuum: “We need to get in front of the public at a grassroots level, to educate them if you will, to the benefits of bringing new power online wherever it is. As we all know, there’s huge pushback when data centers come in, the public saying, ‘Don’t take our power, don’t take our power. It’s going to drive our costs up.’”

Trump Card

President Donald Trump is pushing through significant policy changes in the energy sector. What is he getting right, and what does he need to improve?

Vince praised Trump’s moves on nuclear power, battery storage and delayed fossil retirements but added: “I think the discontinuation of credits and other limitations on the solar and wind industry is unfortunate.”

The president has correctly framed the issue, which is the need for a review of existing processes and significant changes, Falcone said.

Redland Energy Group Principal John Howes said: “I think the president has done some very good things. For example, he’s done a lot to eliminate some of the bias against fossil fuels which existed in the last administration.” More attention must be paid to permitting reform, he said, as well as to the foundational components of the system, such as transformers, and to its human component, through workforce development.

Disruptive Presence

If hyperscalers can move more nimbly and set up behind-the-meter generation more quickly, do they become a threat to utilities?

If someone wants to cut the cord and truly be off the grid, they can order the equipment and install it, Falcone said, and maybe reach the finish line more quickly. But otherwise, they need to operate within the same construct as everyone else attached to the grid.

Vince said some utilities are working well with Big Tech and finding solutions. But many are not, and capitalized hyperscalers are proceeding without them, taking an entrepreneurial approach. “The slower utilities, I think, will be disadvantaged tremendously,” he said.

It need not be mutually exclusive, Bentley said — a data center that builds its own generation may not remain permanently or entirely behind the meter or off the grid. “We’re seeing a lot of unique and tailored solutions … a lot of innovative structures.”

Wilson said flexibility and adaptability such as demand response or onsite storage will help: “Agility is not just being able to buy equipment faster, but it’s being able to be an asset to the grid, as opposed to a passive load.”

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NERC Standards Committee Tackles Final Order 901 Tranche

With NERC entering the final phase of a FERC-directed standards project to address reliability risks of inverter-based resources, the chair of NERC’s Standards Committee said the ERO aims “to use [its] resources efficiently and wisely” to meet the commission’s deadline. 

Meeting via teleconference Aug. 20, SC members voted to move forward with two standards authorization requests (SAR) for the fourth and final milestone of Order 901, in which FERC directed NERC to develop requirements pertaining to the reliable connection and operation of IBRs. (See FERC Orders Reliability Rules for Inverter-Based Resources.)  

Milestone 4 of the order mandates that NERC submit standards by Nov. 4, 2026, “addressing planning and operational studies for registered IBRs, unregistered IBRs and IBR-DERs [distributed energy resources] in the aggregate” (RM22-12). Previous milestones concerned IBR performance requirements, including voltage and frequency ride-through, disturbance monitoring data sharing and post-event performance validation.  

The SARs approved in the SC meeting tackle planning and operational studies separately and already have been reviewed by NERC’s Reliability and Security Technical Committee. (See NERC RSTC Tackles Priority Projects in Quarterly Meeting.) With the committee’s approval, both SARs will be posted for a 30-day informal comment period, and NERC will solicit nominations for drafting team members for at least 15 days; the operational studies team will be designated Project 2025-03, while those working on planning studies will be Project 2025-04. 

NERC Manager of Standards Development Sandhya Madan told listeners that considering the deadline, NERC has classified both projects as “high priority,” which the ERO applies to projects that address “significant” risks as identified by the following criteria: 

    • subject of a NERC or FERC directive with a set due date; 
    • identified as a priority in NERC’s work plan; or 
    • recommended to address a specific risk by compliance feedback, stakeholder feedback or a study. 

Also considered high priority was NERC’s project to revise CIP-015-1 (Cybersecurity — internal network security monitoring), approved by FERC during its June open meeting. (See FERC Approves NERC’s Proposed INSM Standard.) In its order approving the standard, the commission directed the ERO to require that utilities extend the implementation of INSM to electronic access control or monitoring systems and physical access control systems outside their electronic security perimeter, the electronic border around their internal networks. 

To meet FERC’s deadline of submitting the revisions by Sept. 1, 2026, NERC solicited 19 nominations from industry and recommended appointing 15 nominees to the project team, including a chair, two co-vice chairs and 12 members. NERC Manager of Standards Development Alison Oswald said the ERO desired two vice chairs instead of the usual one “to make sure that there’s always someone from the leadership team that can be able to attend the [project’s] numerous expected calls and in-person meetings.” 

Oswald also confirmed that nine of the 15 recommended members, including at least one member of the leadership team, will return from the team that drafted the original standard. The proposal passed without objection. 

A proposal to appoint five candidates to supplement the team for Project 2017-01 (Modifications to BAL-003 — Phase 2), which has lost four members who are retired or no longer able to serve, sparked some discussion after Robert Blohm of Keen Resources suggested adding a sixth member to achieve regional balance. The aims of the low-priority project include addressing “the real-time aspects of frequency response necessary to remain reliability [and developing] measurements to incorporate real-time resource and load characteristics.” 

Blohm said his proposed candidate, who like other nominees was not identified by name during the meeting, had “the most direct subject matter drafting team experience” of all the nominees. In addition, he pointed out that the five candidates recommended by NERC represented five of the ERO’s six regions and that adding this person would ensure all regions were represented.  

Other members were reluctant to take up Blohm’s cause, with several indicating they trusted NERC’s vetting. Oswald said NERC felt the five recommended candidates had “the correct mix of regional representation and utilities that would be subject to the standard,” but suggested the remaining candidates “would be great additions as active observers on the project.” Blohm’s motion to add the candidate failed with 13 votes against and five in favor; a subsequent motion to approve NERC’s slate passed unanimously. 

Finally, members agreed to authorize a 30-calendar day solicitation of nominations to supplement the team for Project 2022-05 (Modifications to CIP-008 reporting threshold), which has also seen four members depart since its inception in 2023.  

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FERC Approves SPP’s Separate Winter, Summer PRMs

FERC approved SPP’s tariff revision that establishes separate planning reserve margins for the summer and winter seasons, saying it will provide “more granularity” by recognizing the reliability differences between the two seasons (ER25-89).

“We find that having separate, seasonal PRMs will help align resource adequacy requirements with seasonal reliability risks, which have been increasingly occurring in the winter season,” the commissioners wrote in their Aug. 19 order. “Moreover, as SPP points out, separate PRMs will help ensure that [load-responsible entities] are appropriately planning for both seasons.”

FERC granted the RTO’s request for an Oct. 1 effective date.

SPP performs a probabilistic loss-of-load expectation (LOLE) study at least biennially to determine the PRM. It told FERC that its 2024 report identified a predominant loss-of-load risk in the winter because it included incremental cold-weather outages in the 2023 study that would increase with the additional incorporation of intermittent resources.

Under the grid operator’s resource adequacy requirement (RAR), staff first determine a PRM based on an LOLE study analyzing the ability to reliably serve the balancing authority area’s forecasted annual peak demand, based on a one-day-in-10-years loss-of-load standard and the accredited value of the footprint’s resources. LREs are responsible for owning or procuring the capacity to meet their seasonal non-coincident peak load plus the PRM.

The Arkansas Electric Cooperative Corp. (AECC), East Texas Electric Cooperative and Northeast Texas Electric Cooperative protested SPP’s filing. AECC expressed concerns that the 2023 LOLE study results failed to assign an LRE’s winter RAR proportionately to its contribution to cold-weather outages, saying the grid operator failed to support its move from an annual peak demand construct to a seasonal PRM framework.

AECC and the other two cooperatives asserted that the PRMs’ swift implementation prevented a “robust consideration” of alternatives by members during the stakeholder process.

FERC rejected the arguments, noting it already had found SPP’s seasonal RAR construct just and reasonable.

The commission found that SPP’s proposal to use expected unserved energy (EUE) as one of the determinants will produce a more robust PRM. It said EUE “provides data on the magnitude and duration of outage events and is impacted by changes in load shape and load peak duration” that differ from season to season.

SPP’s board approved the separate PRMs in August 2024 despite stakeholder concerns. The approval set a 36% PRM for the winter season and a 16% margin for the summer, effective for 2026/27 and 2026, respectively. (See “Board Approves 36% PRM for Winter over Stakeholder Objections,” SPP Board of Directors/RSC Briefs: Aug. 5-6, 2024.)

The grid operator’s stakeholders had recommended a 33% winter PRM.

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Budget Cuts Threaten Calif. VPP Program

Clean energy advocates are urging California lawmakers to restore funding to a fast-growing distributed energy program that can serve as a peaker plant alternative and showed its ability to support the grid during a test run. 

Funding for the Demand Side Grid Support (DSGS) program is expected to run out this year and an estimated $75 million is needed to keep it going in 2026, representatives of more than 30 clean energy groups and companies said in a letter to state lawmakers. 

The letter also calls for $50 million for the Distributed Electricity Backup Assets (DEBA) program, which incentivizes the construction of cleaner and more efficient distributed energy assets to be on-call for emergencies. DSGS and DEBA are California Energy Commission programs. 

“At a time when affordability and reliability are under such strain, cutting these programs would take away proven cost-saving solutions just as they are most needed,” the letter stated. 

The Brattle Group recently completed an analysis of DSGS, focusing on the program’s “Option 3,” in which battery owners agree to make their stored energy available to the grid during energy emergency alerts or when day-ahead prices go over $200/MWh. Participants sign up through DSGS providers, which include companies such as solar-and-storage providers Sunrun and Tesla Energy. 

Participants are compensated based on the power they share with the grid. 

“It’s not a subsidy. It’s not a giveaway or anything like that,” Edson Perez, a senior principal at Advanced Energy United, told RTO Insider. Perez is one of the authors of the letter to lawmakers. 

The Brattle study, which was prepared for Sunrun and Tesla Energy, estimates that DSGS Option 3 will reach 700 MW of nameplate battery capacity in 2025 and grow further to 1,300 MW by 2028. 

Besides boosting the grid, DSGS can save money. Brattle projected program net cost savings of $28 million to $206 million from 2025 to 2028. The lower figure assumes the program provides capacity value and some energy cost savings. Program costs are mainly the payments to participating battery owners. 

The higher savings scenario assumes California is paying more than $200/kW-year for emergency resources and that tariffs and supply chain issues are increasing capacity costs. In that case, DSGS would be “a significantly lower-cost alternative,” Brattle said. 

The Brattle study also assessed a virtual power plant (VPP) test event July 29 involving about 100,000 residential batteries. The batteries were primarily enrolled in the DSGS program, and the two main aggregators in the test were Sunrun and Tesla Energy. 

The batteries provided an average of 535 MW of support to the CAISO grid during the 7-to-9 p.m. test period. (See Home Batteries Provide 535 MW to CAISO Grid on VPP Test Day.) 

“Aggregating home generation and storage produces a reliable, flexible energy resource that dispatches at the same scale as multiple peak generation plants to help meet soaring electricity demand,” Sunrun CEO Mary Powell said in a statement. 

Although the governor’s proposed budget in January included money for the DSGS program, that funding disappeared in later budget revisions. Perez said those who signed the letter to key legislators would leave it up to the lawmakers to decide how to fund DSGS. 

And at least one state senator has indicated his support for doing so. 

Sen. Josh Becker (D), chair of the Senate Energy, Utilities and Communications Committee, discussed the DSGS program during an Aug. 19 oversight hearing on grid reliability. 

“That’s a program that I think has had a great success,” Becker said. “We had a great virtual power plant success recently. We need to make sure those are funded.” 

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Developer Looks to Build 4 SMRs in New Jersey

The company that plans to restart the Palisades nuclear facility in Michigan is pushing to build four 300-MW small modular reactors (SMRs) on the site of the decommissioned Oyster Creek Generating Station in New Jersey. 

The company that owns the site, Holtec International of Camden, N.J., says the project would be accompanied by a solar farm that would take up much of the 700-acre site. The two projects together would generate 1,350 MW of clean electricity, making the site “a magnet for data centers on the lookout to meet their voracious appetite for clean energy,” especially those interested in the site’s proximity to markets such as Philadelphia and New York, the company said in a statement. 

“Our plant, (called) SMR 300, is walk-away safe,” Kris Singh, CEO of Holtec, said at a joint meeting of the state Assembly Environment, Natural Resources, and Solid Waste and Senate Environment and Energy committees on Aug. 14. “It has absolutely no risk. Everything is passive. It’s not run by pumps and motors that can fail and cause an accident.” 

The project’s ability to use the existing infrastructure left by the previous nuclear plant would provide “massive savings in development capital costs and production time,” the company said in a release.  

The New Jersey Department of Environmental Protection (DEP) said it is “unaware” of any specific plans for the Oyster Creek site and added that the federal Nuclear Regulatory Commission (NRC) has sole jurisdiction for the construction and operation of nuclear reactors. The NRC, which will hold a public meeting on the “termination plan” for the former generating station, did not respond for comment on a new plant rising. 

Energy Crunch

Opened in 1969 on the Jersey Shore, the 650-MW Oyster Creek plant ceased operations in 2018 under an agreement between owner Exelon and the DEP to address concerns the plant’s withdrawals of water from nearby Barnegat Bay and subsequent discharges damaged the environment. The operator opted not to install an expensive sealed cooling system with cooling towers to resolve the contamination problem. 

Holtec’s New Jersey SMR proposal comes as the state, an energy importer, and other states served by PJM are facing a looming and dramatic shortfall in power, due largely to the expected arrival of AI and other data centers. PJM estimates that of the 32 GW of demand increase expected in the PJM region by 2030, 30 GW will come from data centers. (See N.J. Confronts Data Center Load Surge.) 

While Gov. Phil Murphy (D) vigorously pursued wind and solar projects, the state more recently has embraced nuclear energy, releasing a request for information in May to help the state explore the development of new nuclear plants as part of its effort to generate more power. (See New Jersey Opts to Explore Nuclear Options.) 

“New Jersey is, and has been, a nuclear state,” said Christine Guhl-Sadovy, Board of Public Utilities president, who noted that nuclear facilities in the state provide 40% of New Jersey’s electricity. That power is provided by three nuclear facilities in South Jersey — Hope Creek, Salem 1 and Salem 2 — that either are operated or co-operated by the Public Service Enterprise Group (PSEG). The state has contributed $2 billion in subsidies to the upkeep of the plants, to ensure they remain part of the state’s generating fleet, Guhl-Sadovy noted. 

To demonstrate Murphy’s commitment to nuclear power, Guhl-Sadovy said PSEG is “finalizing an upgrade of hundreds of megawatts at their existing plants, which will bring more capacity online.” 

Embracing Small Reactors

Two bills pending in the legislature address issues of interest to nuclear projects, although neither is close to enactment. S4423 would enable the BPU to authorize site approval for an SMR in a municipality where a nuclear facility previously was located. The legislation would give the agency the ability to supersede municipal and county decisions to authorize reactors able to generate 300 MW of power or less. The reactors would be licensed by the NRC, and nuclear fuel would be stored on-site. 

Another bill, S422, would establish a state Nuclear Power Advisory Commission, charged with “conducting a study and preparing a report on the role that nuclear energy power plants, including small-scale nuclear energy power plants, should play in the state’s energy future.” 

Sen. Bob Smith (D), chairman of the Senate Environment and Energy Committee, who co-sponsored both bills, said he believes Holtec is on the right track. 

“Oyster Creek is absolutely one of the right spots for SMR technology, and the distribution system already being there makes it even more valuable,” he said. “We should talk, but you’ve got to have some skin in the game.” 

Smith said he had visited the location in Lacey, and township officials would be “welcoming of additional energy facilities down there. They took a tremendous economic hit in terms of employment lost as the plan shut down. They see it as a major asset for the town.” 

Holtec is reopening the 800-MW Palisades facility in Michigan, which shut down in 2022. The company has been awarded a $300 million grant by the state and a $1.52 billion loan guarantee by the U.S. Department of Energy, the company said. The project involves the development of two of the company’s SMR-300 reactors. 

“We had to achieve a long-term power agreement,” said Kelly Trice, Holtec president. “We did achieve a 30-year power agreement. Nuclear can’t live on three-year power agreements. It’s just stupid. No one’s going to amortize that kind of money over that amount of time. And that’s where I think the grid operators need to change their math. Nuclear plants, on average, last 100 years.” 

He said the company expects to break ground at the end of 2027 on the project and “be on the grid in 2031, both plants.” 

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NYISO Unveils Changes to Demand Curve

NYISO has proposed to stop using “winter to summer” and “summer to winter” ratios to determine maximum clearing and reference point prices in its seasonal demand curves.  

Their use is no longer necessary for the demand curves because NYISO is developing distinct seasonal minimum installed capacity requirements, ISO staff says.  

“If NYISO were to move to the seasonal requirement structure without removing these availability adjustments, the seasonal [installed capacity] ICAP demand curves would be adjusted for seasonal differences twice,” Alexis Drake, a NYISO senior market design specialist, said during an Aug. 19 meeting of the ISO’s ICAP Working Group. 

The two ratios are adjustments to seasonal capacity availability the ISO uses to account for seasonal differences in ICAP availability on the spot market.  

During the last demand curve reset, the ISO looked into using seasonal ICAP demand curves to reflect differences in winter/summer reliability risk. During the current capability year (2025/26), NYISO used the ratios to calculate separate demand curves for each season.  

Drake said that method more accurately reflects future New York grid needs in upcoming spot market auctions. 

What Happened to Seasonal CAFs?

In a previous meeting, the ISO unexpectedly dropped seasonal capacity accreditation factors (CAFs) from its winter reliability enhancements project. (See NYISO Drops Seasonal CAFs from Winter Reliability Project.) Stakeholders had asked the ISO to walk through its internal analysis and discussions of seasonal CAFs.  

“This presentation is about correcting that oversight,” said Mike Swider, NYISO capacity and new resource integration market designer. 

CAFs represent the marginal reliability contribution of resources in the ICAP market counted toward New York State Reliability Council resource adequacy requirements. None of the calculations on the ISO or NYSRC end incorporate seasonality. The Installed Reserve Margin and the Locational Minimum Installed Capacity Requirement cases represent reliability risk annually across both seasons. Annual CAFs are calculated using the final, annual LCR case.  

Swider said there is no “stable criteria” to calculate marginal reliability values for each season. Using the installed reserve margin as the ultimate basis for modeling seasonal reliability risks creating situations where certain resource classes have no, or almost no, CAF value.  

“If there is only summer risk, some resources, even the perfect resources conceptually, receive zero CAF value in the winter,” Swider said. “We have concern about large resources entering and exiting and changing the seasonal risk from year to year and the volatility that’s entailed.” 

A resource that isn’t compensated for its capacity contribution might pull out of the market, introducing reliability risks even in months — such as November — where those risks aren’t ordinarily forecasted.  

Swider said the ISO also looked into using weighted CAFs using seasonal CAF values and attribute payments to potentially mitigate these issues. He said there was “no basis” for setting weights and no “clear cost basis” for attribute payments as a service.  

In response to a stakeholder question about whether NYISO had examined what other RTOs do with respect to seasonal values, Swider said the ISO had looked at MISO and SPP’s processes.  

“[MISO] had to do some interesting gymnastics to calculate seasonal CAFs,” Swider said. “In the end it wasn’t useful for us.”  

Swider said another issue is that, unlike other RTOs, NYISO does not select its own reliability criteria, a task that falls to the NYSRC. Even if the ISO was able to pick its own reliability criteria, its winter risk modeling wouldn’t need to adopt MISO’s modeling techniques, he said, because MISO is modeling a lot of terrestrial wind, for example — a resource not prevalent in New York.  

The ISO also went over tariff and manual revisions, respectively, for the Firm Fuel project and for Certain New Resource Entry, the latter intended to handle the Champlain Hudson Power Express. 

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Calif. Officials Probe Utilities on Wildfire Safety Measures

California officials asked Southern California Edison to show humility in its approach to the January wildfires in Los Angeles and probed Pacific Gas and Electric about its safety culture after the utility’s 2019 bankruptcy during an interagency briefing hosted by the California Public Utilities Commission on Aug. 19.

SCE, PG&E, Bear Valley Electric Service, San Diego Gas & Electric, Pacific Power and Liberty Utilities briefed California officials on their wildfire safety procedures and mitigation work.

SCE independent board member Tim O’Toole opened the company’s presentation by discussing the deadly L.A. fires that ravaged the city in January. He called them “an awful catastrophe,” stating that SCE is focused on supporting impacted communities.

“Nonetheless, we remain very proud and confident in the progress we’ve made in all the areas we’re going to review with you today,” O’Toole added. “And I wouldn’t want that pride and that confidence to be misunderstood or mischaracterized as insensitive or that there’s some denial of reality.”

O’Toole noted also that the cause of the fire is unknown, adding, “what we do have knowledge of, and are confident in, is that our unmatched hardening of our grid and the other mitigation measures we’ve implemented have created ever greater protection for our communities and our customers.”

Among the steps SCE has taken are installing more than 6,610 miles of covered conductor and over 1,870 weather stations, 48 miles of undergrounding since 2021 and increased inspections in high fire-risk areas, according to SCE’s presentation.

Caroline Thomas Jacobs, director of the Office of Energy Infrastructure Safety at the California Natural Resources Agency, acknowledged the cause of the L.A. fires is still unknown but sought more humility from SCE.

Addressing O’Toole, Thomas Jacobs said, “Your tone sounded defensive and justifying the progress that’s made as opposed to acknowledging the humility of what an event like the January fires I would think would bring … to the board.”

Thomas Jacobs added that “hopefully all of us are learning lessons from the January fires, including our organization, on how we look at the wildfire mitigation plans. We need to … bring a humility to those events and a level of curiosity and openness to create the opportunity for us to all move forward and learn from it.”

O’Toole responded he is proud of his team but also wanted to acknowledge the pain the fires have caused.

“I just feel like I didn’t articulate it well enough, but I certainly believe that what you said is the appropriate sentiment,” O’Toole said.

Of the L.A. fires, the Eaton Fire and the Palisades Fire were the two most destructive. The L.A. County Fire Department and the California Department of Forestry and Fire Protection are still investigating the cause of the Eaton fire, but videos of the fire’s early stages suggest a possible link to SCE’s equipment, SCE representatives said in February. (See SCE Probes Link Between Equipment and Eaton Fire.)

On July 23, SCE announced a new wildfire recovery compensation program for victims of the Eaton Fire. The program is expected to operate through 2026, a company press release said.

‘Totally Different Place’

Also participating in the Aug. 19 meeting were representatives from PG&E. Similar to SCE, the company has focused on undergrounding, installing more weather stations and cameras, and other grid hardening efforts to mitigate wildfire risk.

The company received blame for a series of California wildfires starting in 2015. The fires included the 2018 Camp Fire, which leveled the town of Paradise, killed 84 people and drove PG&E to file for bankruptcy reorganization in January 2019.

Cheryl Campbell, chair of PG&E’s Board of Directors and Safety and Nuclear Oversight Committee, said the company is in a “totally different place” compared with 2019.

Campbell noted that with the hiring of Patti Poppe as chief executive officer in 2021, PG&E has made “tremendous progress.” She highlighted reductions in workforce fatalities and improvements in public safety power shutoffs.

PG&E has also reduced the unit cost for undergrounding. In 2019, the unit cost exceeded $4 million/mile. The average unit cost between 2023 and 2024 was $3.1 million, according to the utility’s presentation.

Sumeet Singh, executive vice president of operations and chief operating officer at PG&E, said the company sees opportunities to further reduce undergrounding costs by, for example, improving construction methods and entering cost-effective contracts with third parties. There are also regulatory efforts to improve undergrounding, Singh noted. (See Newsom Issues Order to Speed Undergrounding of Lines in Los Angeles.)

“We absolutely see opportunities to continue to improve upon the $3.1 million a mile that we’re currently averaging on the underground side, and our intent is to get to that glide path of $2.6 or below over the next several years,” Singh said.