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March 19, 2026

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LS Power to Buy 4.4 GW of Power Generation Assets in PJM

Constellation Energy will sell nearly 4.4 GW of PJM generation assets to LS Power.

The agreement announced March 18 is valued at $5 billion before closing adjustments, or approximately $1,142/kW of capacity. It will satisfy many of the federal regulatory requirements attached to Constellation’s acquisition of Calpine, which owned the power plants LS Power has agreed to buy.

FERC ordered some generation assets divested as a condition of approval, and the U.S. Department of Justice added others in its antitrust review.

The Constellation-Calpine deal was completed Jan. 7, creating the world’s largest private-sector power producer, controlling approximately 55 GW of generating capacity.

FERC’s approval in July 2025 entailed Calpine selling 3,546 MW of generation, all of it in PJM: the 1,134-MW gas-fired combined-cycle Bethlehem Energy Center, the 569-MW dual-fuel combined-cycle York Energy Center Unit 1, the 1,136-MW dual-fuel combined-cycle Hay Road Energy Center and the 707-MW gas-fired simple-cycle Edge Moor Energy Center. (See FERC Approves Constellation Purchase of Calpine with Conditions.)

LS Power is buying those, along with York Unit 2, an 828-MW gas-fired combined-cycle plant, which the DOJ agreement added to the list. (See DOJ, Constellation, Calpine Reach Antitrust Settlement.)

The DOJ agreement also included the sale of the Jack Fusco Energy Center, a 606-MW gas-fired combined-cycle facility in Texas, and minority ownership in the Gregory Power Plant, a 385-MW gas-fired combined-cycle facility in Texas.

The stake in Gregory was divested earlier in 2026. Constellation CEO Joe Dominguez said in a news release that Fusco will be divested later in the year:

“This transaction is an important step in satisfying the DOJ’s requirements and advancing our path forward. These are well-run facilities that will continue powering consumers and businesses for decades to come. We’re pleased to be moving ahead and expect to complete the remaining DOJ requirements later this year.”

LS Power CEO Paul Segal said his company has been building and operating gas-fired power plants for more than 35 years and expects a seamless integration of these new assets: “PJM is at the epicenter of the surge in electricity demand, and these are exactly the kind of assets the grid needs — efficient, dispatchable gas generation that can deliver reliable power around the clock.”

The Constellation-LS Power transaction will require DOJ, FERC and other regulatory approvals.

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NERC to Trial MSPPTF Recommendations in Large Loads Project

A new standards development project is a chance for NERC to pilot some of the recommendations from the ERO’s Modernization of Standards Processes and Procedures Task Force, ERO staff told members of the organization’s Standards Committee at their monthly meeting March 18.

The project will focus on computational large loads such as data centers, artificial intelligence computing clusters and cryptocurrency mining, an issue Howard Gugel, NERC’s senior vice president for regulatory oversight, reminded attendees “is coming at us like a freight train.”

“I just talked with a utility [whose] peak load is about 2,500 MW, and they have 15,000 MW of data center load that wants to connect to their system,” Gugel said. “It’s going to be important for us to get this right [and also] to move quickly on this. The data center folks want consistent, uniform standards across North America, and I think the transmission owners want some guidance as to what should be done … to make sure that everything operates reliably.”

That “need for speed” also made the new standards project a good candidate to test out the efficiency improvements proposed in the MSPPTF recommendations approved by the Board of Trustees in February, NERC Manager of Standards Development Sandhya Madan told SC members. (See NERC Board Accepts MSPPTF Recommendations.)

Among those recommendations were using AI to help NERC staff create a term sheet outlining the goals of the proposed standard, and the creation of a pool of subject matter experts to oversee standard development rather than the current practice of creating a dedicated standard drafting team, whose members must be recruited from industry and approved by the SC. (See NERC Modernization Task Force Leaders Present Final Recommendations.)

NERC is planning to test both proposals with the large loads project, Madan said, emphasizing that any experimentation would be “within the bounds of the current” Standard Processes Manual. She told attendees NERC had identified a group of SMEs that were “appropriately vetted and have already demonstrated some level of commitment to addressing emerging risk,” and recommended that these experts — who were not identified by name during the meeting — be chosen as the drafting team for the project.

Alison Oswald, manager of standards development at NERC, added that the ERO is “working on developing a template for a term sheet,” which the drafting team will use to create “a high-level explanation of who a standard would apply to, what goals it is trying to meet [and] what kind of requirements it might cover.”

NERC sees the project itself — which the ERO has dubbed Project 2026-02 after its approval by the SC — as the first phase of a larger effort, Madan said. This stage will focus on drafting new definitions for NERC’s Glossary of Terms, including for “computational load” and “computational load entity.”

Phase 1 will also initiate development of one or more standards to address “near-term” risks associated with computational large loads. These risks include reduced visibility into large load centers, potential instability during system disturbances and “increasing certainty for both system planning and real-time operations,” Madan said.

Michael Goggin of Grid Strategies pointed out a lack of representation by independent power producers on the proposed team and asked if there was any potential to “add one or two people to bring in that perspective” while still approving the rest of the slate. Gugel observed that the SC “at any point could bring a motion forward to do an augmentation for any standard drafting team.” Goggin agreed that this “may be a viable path” to add the needed expertise.

Final IBR Standards to be Posted

Only two other standards projects came before the committee, both of which address the final milestone of FERC Order 901, covering operational and planning studies for inverter-based resources.

The team for Project 2025-03 (Order No. 901 operational studies) brought a request to authorize posting two proposed standards for a 45-calendar-day formal comment and ballot period: TOP-003-9 (Transmission operator and balancing authority data and information specification and collection) and IRO-010-7 (Reliability coordinator data information specification and collection). (The standards are found on pages 36 and 64 of the committee’s agenda, respectively.)

According to Madan, the proposed standards would address FERC’s directive by including “IBR performance and behavior in operational assessments and real-time monitoring of individual IBR plants,” along with aggregated IBRs across an operator’s footprint.” They would also require distributed energy resources to be included in operational assessments.

At the same time, Project 2025-04 (Order No. 901 planning studies) requested that the SC post TPL-001-6 (Transmission system planning performance requirements) for comment and ballot (page 99 of the agenda). Madan explained that the standard includes new requirements to study registered and unregistered IBRs, including distributed IBRs, in planning assessments.

Both requests were accepted without objection by SC members.

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WestTEC Report Fuels Calls for Regional Transmission Task Force

The Western Transmission Expansion Coalition’s 10-year outlook has spurred talks about increased coordination among jurisdictions to upgrade or build 12,600 miles of transmission in the West and fueled calls for states to create a task force to streamline permitting and other issues.

That volume of transmission would cost approximately $60 billion over 10 years to meet the region’s forecast 30% increase in peak demand by 2035, according to WestTEC’s 10-year outlook. (See West Needs $60B in Transmission Ahead of 2035, WestTEC Finds.)

Another key finding is that coordinated action between states, utilities, developers and regional partners can help the West meet this challenge, Sarah Edmonds, CEO of Western Power Pool, told RTO Insider.

“What we’re hoping to see is continued collaboration and engagement among many members of that coalition to use the results of the study to inform planning, catalyze development and advance transmission projects,” Edmonds said. “As stakeholders or regulators weigh these potential projects, they can look at the study to gain a better understanding of why projects are needed and how they fit into the larger, regional picture, perhaps making the process a little easier than it would have been otherwise.”

The WestTEC effort, jointly facilitated by WPP and WECC, addresses long-term interregional transmission needs across the Western Interconnection. The 10-year planning horizon was released in February 2026. A 20-year outlook is slated for release later in 2026.

WestTEC’s main objective is to create an “actionable” transmission study by conducting integrated planning analysis across the Western Interconnection.

But to implement the report’s findings, the region must overcome “development, regulatory and financing challenges,” according to the report.

Coordination among states, utilities, developers and regional partners “can materially improve outcomes” by addressing a host of issues, such as cost allocation, procurement of transmission components, siting and permitting, the report states.

During a March 10 WECC meeting on the report, WECC board member Jacinda Woodward asked how stakeholders can “collectively help build momentum,” noting that without engagement on the report, “we’ll be talking about this in five years from now and then we’ll be in real trouble.”

Trade organizations RTO Insider spoke with similarly called for collaboration across state lines and appeared ready to build momentum.

For example, The Western Transmission Consortium (TWTC), which is referenced in the WestTEC report as a vehicle for collaboration, said it is “excited” to implement the findings and ultimately put “steel in the ground.”

Launched in 2024, TWTC is member-owned organization with a goal of bringing together various entities to build infrastructure across the West, according to its website.

“WestTEC set the table, and we will see whether the states and federal government are serious about building the transmission needed to meet the demands and policy imperatives of the 21st century,” Ray Gifford, TWTC co-founder, told RTO Insider in an email.

That sentiment was echoed by Gridworks Executive Director Matthew Tisdale, who said “one of the biggest barriers to moving these critical transmission projects forward is permitting across multiple jurisdictions.”

“States can lead by working together through a coordinated task force to streamline processes, reduce delays and deliver the transmission our region needs,” Tisdale said. He added that the organization “is actively working with states, developers and other leaders across the West who are willing to stand up such a team.”

‘Open for Business’

There is bipartisan support among federal lawmakers for energy infrastructure permitting legislation. The House passed a bill in late 2025 that would alter the National Environmental Policy Act to speed up permitting, and senators likewise are working on a permitting bill. (See Senate Hearing Shows Support, Potential Pitfalls for Permitting Legislation and House Passes SPEED Act to Quicken Infrastructure Permitting.)

Although the WestTEC team is not involved in policymaking, there is still time for stakeholders in the West to get involved, especially in activities related to the upcoming 20-year horizon, Edmonds said during the March 10 WECC meeting.

“We have defined already the scenarios we’re going to look at,” she said about the 20-year study. “But the devil is in the details, and there’s a lot more conversation about those details left to be had. I always leave with the invitation that WestTEC is a very open community and a marketplace of ideas. And we’re open for business.”

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DOE Defends Use of Emergency Orders in Court Filing

The U.S. Department of Energy argued its use of Section 202(c) of the Federal Power Act to keep retiring power plants online is well within its authority in response to an ongoing emergency on the grid.

The department made that case in its first substantive brief on the appeal of Energy Secretary Chris Wright’s first order in May 2025 to keep the J.H. Campbell coal plant in Michigan from retiring, which has been extended every three months since then. The orders have been challenged by state attorneys general and environmental groups in the D.C. Circuit Court of Appeals. (See State AGs, Enviros Argue Campbell Plant Orders Exceed DOE’s Authority.)

“Though Campbell had been approved to close in 2022 for economic reasons, things changed by 2025,” the department told the court. “Independent electric grid reliability authorities and the operators of [MISO] had identified an unexpected and (in the context of the electricity sector) ‘sudden increase in the demand for electric energy’ in this region.”

DOE filed its brief March 17, and briefing in the case is scheduled to wrap up by April 10.

A week after the Campbell order came out in May 2025, the department issued one keeping the Eddystone plant in Pennsylvania from retiring. It has issued several others to block retirements, all of which have been challenged by similar groups. (See related story, Groups Contest Indiana Coal Plants’ Emergency Extensions at D.C. Circuit.) The Campbell case is further along than others and is the first test of the Trump administration’s use of 202(c) orders, which historically have been used to let power plants exceed emissions limits over a few days at the request of grid operators during periods of expected high demand.

Overall, DOE has issued 12 such orders for six power plants, which the Sierra Club estimates have cost just under $235 million.

“Not one of these orders was requested by the relevant plant owner, grid operator or state or regional regulator whose responsibility it is to keep the lights on,” Sierra Club Senior Attorney Greg Wannier said at a roundtable on rising energy costs hosted by Senate Democrats on March 17.

DOE argued in its brief that the Campbell emergency order is entirely consistent with the requirements of Section 202(c) and its history.

“Petitioners ask this court to upend the secretary’s ability to address the emergency at hand. But their legal arguments contradict the plain text of Federal Power Act Section 202(c),” DOE said. “The statute broadly defines what constitutes an ‘emergency’ for purposes of this specific provision. It does not limit the secretary to addressing ‘unexpected’ or ‘imminent’ circumstances.”

The department said the record confirms that electricity unexpectedly returned to demand growth after two stagnant decades because of electric vehicles, data centers and reshoring of manufacturing. New supply is lagging that demand growth, it said.

Section 202(c) authority is granted whenever the secretary of energy determines that an emergency exists because of “a sudden increase in the demand for electric energy, or a shortage of electric energy or of facilities for the generation or transmission of electric energy, or of fuel or water for generating facilities, or other causes,” DOE said, quoting the law.

“The secretary has conclusive discretion to use his ‘judgment’ to respond as he deems ‘best,’ upon his ‘own motion’ and ‘without notice, hearing or report,’” DOE said in the brief. “And the secretary may expressly do so even if the chosen emergency response could conflict with environmental laws.”

Longstanding DOE regulations define emergencies in several ways, including “extended periods of insufficient power supply as a result of inadequate planning or the failure to construct necessary facilities.”

The word “temporary” appears in Section 202(c), but DOE argued it modifies only “connections of facilities” and not “a shortage of electric power.” Nor are its responses required to be temporary.

“Regardless, there can be no dispute that the secretary’s action here has a logical endpoint,” DOE said. “Rather than purporting to require Campbell’s operation in perpetuity, the secretary ‘limited’ the order ‘in duration to align with the emergency circumstances.’”

The fact that the secretary has not indicated when the emergency will end does not mean he is exceeding his powers; indefiniteness is not the same as permanence, the department argues. The law also allows the secretary to renew the orders, which last 90 days.

Before DOE was created in 1977, the Federal Power Commission wielded authority under 202(c). Of the 28 times it used that authority, 11 were for indefinite emergencies, and some were in effect for more than a decade, the department noted. Even as recently as 2005, DOE kept Mirant’s Potomac River generating station open for over a year using the authority, it said.

“The statute also does not limit the secretary to any specific number of renewals — leaving the question of how long an emergency lasts to the secretary’s discretion,” DOE said.

If the only emergencies covered by 202(c) were fleeting, near-term shortages, then Congress would not have authorized the secretary to renew orders for 90 days and beyond, it argued.

Consumers Energy, owner of the Campbell plant, also filed a brief, but on the narrow issue that if the court does overturn the order, then it should be allowed to recover its costs for running it while the litigation plays out.

FERC is responsible for cost recovery under 202(c) orders, so any court action should leave its rulings on the issue in place.

“Consumers duly complied with DOE’s order requiring the plant to remain operational,” the utility said in its brief. “Consumers incurred substantial costs to do so, and FERC determined it is just and reasonable to allocate costs associated with the DOE order to customers throughout [MISO].”

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MISO Expects Expenses to Rise Through 2030

MISO said its most recent financial estimates show operating costs continuing to creep up through 2030, making $500 million annual operating budgets the norm and forcing it to collect more from members.

The RTO predicted that by 2030, it would need anywhere from $488 million to $517 million in its base operating budget as salaries and benefits and computer maintenance become more expensive.

MISO said its base operating expenses likely would climb 5.4 to 7% annually, in line with the 6.9% average growth it experienced in its budget from 2023 to 2026. According to MISO, salaries and benefits and computer maintenance account for 56% and 34%, respectively, of the total estimated growth.

MISO also predicted it would add an additional $43 million to $48 million in project investments on top of its base operating budget by 2030.

For 2026, MISO agreed to stick to a $394.7 million base operating budget and $36 million in project investments. (See MISO Tempers 2026 Budget Plan.)

Over the next five years, MISO expects to increase its membership rate by anywhere from 3.3-6.3% annually, landing anywhere from $0.61/MWh to $0.68/MWh by 2030.

MISO upped the rate it collects from members from $0.51/MWh in 2025 to $0.54/MWh in 2026.

On average, MISO said its rates increased 8.1% from 2023 to 2026. MISO said the past three years of increases were driven mostly by increases in depreciation and lower interest income from other operating costs.

MISO expects to bill 728 TWh of load in 2026, 756 TWh in 2027 and an average 816 TWh from 2028 to 2030. By 2030, MISO said it could serve anywhere from 814 to 857 TWh in load.

“Personnel and technology are MISO’s primary asset and make up the majority of MISO’s cost profile today and are expected to continue to be pressure points in the future,” MISO CFO Melissa Brown explained during a Mach 17 teleconference of the Audit and Finance Committee of the MISO Board of Directors.

MISO said salaries and benefits, computer maintenance and outside vendor services historically have accounted for almost 90% of MISO’s operating costs. MISO said its technology costs have been mounting in recent years, with computer maintenance becoming a larger expense and third-party support shifting to business models where MISO pays for service, rather than owning the assets.

Brown also said vendors’ prices increased more than the general inflation rate for things like licenses and support agreements. MISO’s five-year financial forecast is “heavily dictated by what we need to do to keep up with market dynamics.” She said MISO is required to keep up with customer needs, new regulatory requirements and growing load.

Brown said MISO needs continual technology upgrades to achieve the computing power it needs, take advantage of improvements and keep abreast of AI advancements.

On top of those, Brown said MISO must protect itself from cyberattacks as geopolitical tensions boil over in places like Iran and Ukraine.

Brown also said the cost of employee benefits through 2027 will increase beyond what MISO originally expected to pay. “Items outside of MISO’s control have considerable impact on ongoing costs,” she said.

MISO Director Barbara Krumsiek said MISO and members haven’t seen “these kinds” of cost trends in at least a decade, if ever.

MISO CEO John Bear said the RTO used a conservative estimate for load growth. He said greater load growth would temper costs. “We’re in a little bit of a moving target right now.”

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Wash. Lawmakers Approve Bill to Create Transmission Authority

Washington lawmakers passed a bill to establish a transmission authority intended to help the state improve system capacity and meet growing demand by reducing the timeline to complete new projects.

The Senate passed SB 6355, as amended by the House, in a 32-17 vote on March 12, and the bill now goes to Gov. Bob Ferguson for his signature. As of March 18, the bill has yet to appear on the governor’s website for signing.

State Rep. Alex Ramel (D) told RTO Insider the governor’s office has been “very helpful in thinking through the details of the bill.”

Ramel, a member of the House Environment and Energy Committee, supported the creation of a Washington transmission authority (TA), pointing to similar setups in states like Colorado and New Mexico, saying those have worked “really well.”

Ramel said the TA will “help eliminate risk on getting transmission projects up and running.”

The TA would not replace “traditional players” like utilities or independent developers, but will instead address challenges that exist in the early stages of a project, such as routing and cost issues, according to Ramel.

“By having a development authority get the ball rolling when there’s all that risk and doubt, we can shave years off of the development timeline for new transmission projects,” Ramel said. This is “absolutely” necessary “to both meet the growing electricity demands, especially in western Washington, and build out renewable energy resources in places where transmission infrastructure currently doesn’t reach,” he added.

If signed by the governor, the TA would be a public body folded into the state’s Department of Commerce with the goal of improving transmission reliability, resilience and affordability, according to the bill.

The TA is intended to provide development transmission services, siting and permitting coordination, and engagement with state and federal stakeholders.

The bill outlines a host of goals for the TA, including improving reliability and resilience, providing access to low-cost renewable energy, meeting clean energy targets and working toward implementing new technologies to reduce wildfire risk.

The bill also cites the Western Transmission Expansion Coalition’s (WestTEC) recent 10-year outlook. Specifically, the TA would be required to identify “high-priority transmission corridors from those identified in the western transmission expansion coalition’s west-wide transmission needs study 10-year horizon report published in February 2026.”

WestTEC’s outlook found that the West must build or upgrade 12,600 miles of transmission at a cost of about $60 billion to meet the region’s forecasted 30% increase in peak demand and other needs by 2035. (See West Needs $60B in Transmission Ahead of 2035, WestTEC Finds.)

The anticipated 30% increase in peak demand — from 168 GW in 2024 to 219 GW in 2035 — is more than three times greater than what the region has experienced over the past decade, according to WestTEC.

SB 6355 notes this, finding that Washington, which has set out to completely decarbonize its grid by 2045, could struggle to meet those targets with demand for electricity increasing due to electric vehicles, home heating, cooling, manufacturing and data centers.

“There are significant federal, state and private investments in clean energy development, including wind, solar and battery storage, that support decarbonization goals and supply new electrical load,” the bill states. “However, Washington’s existing transmission system lacks the capacity to accommodate the growing demand for clean electricity.” 

Oregon faces a similar challenge and lawmakers in the Beaver State are exploring the creation of a transmission authority that would coordinate with Washington. (See Northwest Lawmakers Explore Building Transmission Without BPA’s Help.)

Public Power Concerns

However, the prospects of TAs in the Pacific Northwest have faced some resistance.

Lauren Tenney Denison, director of market policy and grid strategy at Public Power Council, said there could be some benefits if the TA is limited to focusing on identifying potential corridors for transmission development. She declined to comment specifically on SB 6355.

“We are concerned about a transmission authority scoped with broader authorities such as planning, owning and especially operating transmission,” Tenney Denison said. “A transmission authority that is empowered to develop a binding cost allocation methodology for proposed transmission is also concerning.”

She added it is “critical” the TA “ensures input from and coordination” with large entities like the Bonneville Power Administration and consumer-owned utilities.

The TA will consist of a 10-member board appointed by the governor and approved by the Senate by Jan. 1, 2027. The board must have an executive director in place by June 30, 2027, according to SB 6355.

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N.J. Bills Targeting Balcony Solar, Nuclear and PJM Move Ahead

New Jersey legislators have backed a bill that would require operators of artificial intelligence data centers and crypto mining facilities to run them with clean energy and submit an energy use plan to the state.

The requirements were spelled out in a bill, S680, approved by the Senate Environment and Energy Committee. The bill also would require the ventilation and cooling systems of data centers to be designed to minimize the energy used to cool computers and to optimize water use. The bill would require the operator to use heat generated by the computers for water or space heating.

The bill was one of several promoting clean energy backed by assembly or senate committees in recent days that seek to harness renewable energy to halt the increase in the state’s electricity rates and counter the predicted future shortfall of energy that is driving them. (See Departing N.J. Governor Touts Clean Energy to Solve State Power Woes.)

Other clean energy bills that secured committee approval included one that would exempt portable solar generation devices — known as “plug-in solar” — from “certain interconnection, net metering and other requirements.” Another bill would weaken the permit laws that make it difficult to develop a coastal nuclear generator.

A third bill would create a $15 million fund to provide grants to public schools for solar energy projects. A fourth bill would require the state to work with its neighbors to study alternatives to participating in the PJM grid.

Sen. Bob. Smith (D), the committee chairman and a bill co-sponsor, called the sourcing of power for data centers and similar heavy energy users a “huge issue.” He also said heavy energy users should be told “you gotta bring your own electricity, or build your own electricity, or come in contract with a new power plant that’s going to provide electricity. We, the ratepayers, shouldn’t be paying for it.”

Bold Step, or Overstep

Allison McLeod, interim executive director of the New Jersey League of Conservation Voters, called the bill “a bold and necessary step to protect New Jersey’s working families and local businesses from being forced to bear the cost of the global data center boom.”

“We cannot allow Big Tech to drive our electricity rates sky-high and strain our state’s infrastructure while padding corporate profits,” she said.

Ray Cantor, a lobbyist for New Jersey Business and Industry Association, one of the state’s largest trade groups, said he did not disagree that large energy users should bring their own power. Though the bill does not require that, he said “it is inferred” users would be required to use 100% clean energy.

“The major concern we have with this legislation is its emphasis on clean energy,” he said. “Data centers need to run 24/7, 365. You cannot do that with renewables alone.”

He suggested the clean energy requirement be removed from the bill and the sponsors recraft it as a “bring your own type of solution,” promoting renewable sources alongside natural gas and other generation sources.

Plug-in Solar

Several of the bills that advanced echoed Gov. Mikie Sherrill’s (D) championing of solar, a central element in her plan to develop additional electricity generation sources. (See New N.J. Governor Rapidly Confronts Electricity Crisis.)

The Senate Environment and Energy Committee backed a bill S2368, which would make it easier to use “portable solar generation devices” and exempt from certain state rules and regulations.

These devices, of 1,200 watts or less, are “designed to be connected to a building’s electrical system through a standard 120-volt alternating current outlet,” according to the bill. Smith, who co-sponsored the bill, said they are known in Europe as “balcony solar.”

“European residents are dealing with their energy issues by buying their own solar panel, plugging it in as a source of electricity for their home,” he said. “And that, of course, takes some pressure off the grid, as well as provides clean, renewable electricity for their home.” Sen. John F. McKeon (D), also a bill co-sponsor, said the devices can cut a household electricity bill by as much as 20%.

The bill would exempt users from requirements that they “obtain or execute interconnection agreements prior to operating the device,” and net metering requirements. The bill also would exempt an operator from needing to obtain the utilities’ approval before installing or using the device.

Elowyn Corby, Mid-Atlantic regional director for Vote Solar, a solar lobbying group, welcomed the state’s focus on “plug-in solar” devices, describing them as small solar arrays that set up on a balcony, in a window or a yard and can democratize the sector.

“This is about power in both senses of the word,” she said. “It’s about generating your own electricity. But it’s also about giving families more agency in our energy future.”

Increasing Solar Project Size

The Senate committee also backed S1815, which would allocate $15 million to a Board of Public Utilities-managed program that would provide grants to schools for solar energy projects, in part to help reduce costs.

A second solar bill endorsed by the committee, S3183, would modify provisions in state solar incentive program laws to allow two projects to “co-locate” on the same property. The legislation also would temporarily — until December 2028 — allow projects of up to 20 MW to participate in the community solar program if they are on landfills, brownfields, contaminated sites or mining sites. The current maximum project size is 5 MW.

The same bill also would change state law governing the net metering program to “raise the maximum size of projects allowed in the program” from 5 MW in direct current to 20 MW in alternating current. An identical bill was approved by the Assembly Telecommunications and Utilities Committee on March 13.

Lyle Rawlings, president of the Mid-Atlantic Solar and Storage Industries Association, said the legislation is an example of “taking off the handcuffs” of the solar sector and called it an important step toward creating an “all-of-the-above energy solution” that includes solar.

“For a long, long time, there have been all sorts of handcuffs holding back solar development, including and especially the most cost-effective solar developments which are the large scale (projects) — especially large scale behind the meter,” he said. “This bill does some correction of that.”

Joseph Gurrentz, a lobbyist for the New Jersey Utilities Association, said the organization has reservations that need to be addressed before it could be “neutral” on the bill. One of them was the proposal to allow co-location of solar projects.

“The language would allow what is effectively a larger generation project to be divided into multiple smaller projects, so that each portion would qualify for a higher incentive level,” said Gurrentz, speaking to the Telecommunications and Utilities Committee. “And from a ratepayer perspective, this could mean that subsidy costs would increase without increasing the amount of energy that is provided.”

Noting the bill likely would trigger a surge in interconnection engineering studies, he also suggested utilities should be able to “recover the full cost of those studies from the developer requesting the interconnection.”

Alternatives to PJM

The committee approved A4528, which would modify the state’s Coastal Area Facility Review Act, to make it easier to develop nuclear facilities along the coastline. The bill would enable the state commissioner of the Department of Environmental Protection to grant construction and operation approval if the nuclear waste disposal method to be used met the standards established by the Nuclear Regulatory Commission.

Another bill backed by the committee, A3967, would require New Jersey to work with neighboring states to study and make suggestions on collective action to resolve the current energy shortfall. Among the proposals to be studied is a proposal that “any electric load serving entity” should show that it has contracted for 80% of its needed capacity for five years.

Other suggestions to be studied under the bill are whether New Jersey should withdraw from PJM’s capacity market and “develop a multistate compact” to find an alternative, and the feasibility of the state pulling out of the regional, high-voltage electric transmission grid operated and managed by PJM,” and either establishing a new grid or joining an existing alternative.

Several Telecommunications and Utilities Committee members said the bill should jump-start a needed discussion about the state’s situation, and PJM’s role in it.

“We have no say of the actions of PJM, so I think we need the multistate, regional discussion approach,” said Assemblyman Wayne P. DeAngelo (D), the committee chairman. He described PJM as the “air traffic controllers of the electric generation world.”

“We should be discussing who’s potentially getting data centers, who’s not, where the impact is going to be,” he said. “These discussions aren’t taking place.”

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ISO-NE Refines Details on Asset Condition Reviewer

Updating stakeholders on its proposal for an internal asset condition reviewer, ISO-NE said it now plans to review asset condition projects estimated by transmission owners to exceed $25 million in regionalized costs.

ISO-NE initially proposed reviewing projects with costs greater than or equal to a $30-$50 million threshold. But the RTO has since adopted the New England States Committee on Electricity’s (NESCOE’s) proposal of a $25 million threshold.

“It is important that the majority of spending be subject to review to help ensure that the projects consumers are paying for are reasonable,” NESCOE wrote to ISO-NE on March 6.

ISO-NE said the $25 million threshold “allows for an extensive review of the region’s upcoming projects to address stakeholders’ concerns” and aligns with thresholds for review included in a 2025 law passed in Connecticut and a bill recently passed in the Massachusetts House of Representatives.

It said it plans to periodically evaluate the threshold to evaluate the efficiency of the review process and effects of inflation and supply chain constraints.

Al McBride, vice president of system planning at ISO-NE, said the RTO plans for “periodic reviews of [transmission owner]-provided project forecasts to identify projects that should have been captured in the [asset condition] reviewer process or projects that may hit the threshold based on their documented scope.”

Some stakeholders expressed concern that transmission owners could try to avoid scrutiny from the reviewer by segmenting projects or estimating costs to fall just shy of the threshold.

Reactions to the proposal at the NEPOOL Transmission Committee meeting on March 18 were mixed. While some applauded the broader scope of review, others expressed concern it would subject the bulk of asset condition projects to review and create excessive work for the RTO.

Dave Burnham, director of transmission policy at Eversource Energy, said the company “fully supports” ISO-NE’s development of an asset condition reviewer but “recognizes it will be a significant effort for the ISO.”

“We had recommended an initial $50 million threshold for project reviews to help ensure that the process is effective and meaningful as soon as possible,” he said. “We understand that the ISO believes it can effectively implement a lower threshold of $25 million and look forward to working further with the ISO and stakeholders on the implementation of the process.”

ISO-NE originally proposed the creation of a first-of-its-kind asset condition reviewer role in mid-2025 to address concerns about escalating expenses associated with asset condition costs. It employed a consultant to conduct an interim review of a subset of projects and aims to establish the permanent role by the start of 2027.

In its current form, ISO-NE envisions the role to be strictly advisory, intended to provide scrutiny into project needs, cost effectiveness and asset management practices. The transmission owners would retain responsibility and legal liability for the maintenance of their infrastructure.

While the reviewer could not approve or block projects, its analysis could be used by states or consumer advocates to challenge project costs through FERC formula rate proceedings.

ISO-NE also plans to “identify inconsistencies and inefficiencies” between the asset management practices of transmission owners and promote standardization and the adoption of best practices.

McBride stressed the role “must maintain impartiality, provide technical competence, and build trust and credibility by sharing information clearly and completely.”

The asset condition reviewer would be a new department with full-time staff within ISO-NE’s system planning team. This structure would allow coordination with other planning efforts and enable right-sizing asset condition projects to more efficiently meet expected demand growth, McBride said.

ISO-NE plans to begin discussions on right-sizing once it has largely completed development of the reviewer role, likely in the third quarter of this year.

While the states initially advocated for an independent transmission monitor separate from ISO-NE, there appears to be some growing acceptance of ISO-NE’s proposed approach. But some stakeholders continue to express concerns about whether the reviewer would be adequately impartial.

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Groups Contest Indiana Coal Plants’ Emergency Extensions at D.C. Circuit

Multiple public interest organizations have taken their challenge of the U.S. Department of Energy’s emergency orders keeping two Indiana coal plants operating past their planned retirement dates to the D.C. Circuit Court of Appeals.

The Sierra Club, the Environmental Law and Policy Center, and Earthjustice — representing the Citizens Action Coalition of Indiana, Just Transition Northwest Indiana and Hoosier Environmental Council — petitioned the D.C. Circuit to review DOE’s pair of Dec. 23 orders keeping Northern Indiana Public Service Co.’s R.M. Schahfer and CenterPoint Energy’s F.B. Culley coal plants running through March 23. They asked the court to overturn both orders in their pair of March 16 filings (26-1056 and 26-1057).

DOE denied the groups’ rehearing requests on the orders in late February. They argued that forcing the coal plants to remain open is “unnecessary and threatens to increase electricity bills and pollution.”

“The 90-day federal ‘emergency’ orders override the decisions made in the interest of customers by power companies, grid operators and state utility regulators to retire the plants,” Earthjustice said in a press release. The environmental law group cited its prior research showing that the Schahfer and Culley coal units would cost ratepayers more than $20 million to operate for the first 90-day period. That’s notwithstanding any extensive repairs that NIPSCO says are necessary for Schahfer to operate. NIPSCO previously estimated that operating Schahfer beyond 2025 would require more than $1 billion. (See Enviros Warn NIPSCO Against Rebuilding Coal Unit on DOE Emergency Order.)

Kerwin Olson, executive director of the Citizens Action Coalition, said CenterPoint and NIPSCO residential customers already face the highest electric bills in Indiana.

“They simply can’t afford it,” Olson said in a press release.

Even before costs of the plants are allocated to ratepayers, the Indiana Utility Regulatory Commission initiated an affordability inquiry into the state’s five investor-owned utilities, including NIPSCO and CenterPoint. Rates in Indiana have jumped sharply in recent years. (See Indiana Commission Opens Affordability Inquiry into Utilities.)

Sierra Club Senior Attorney Greg Wannier said the Trump administration’s orders are illegal and another attempt to “bolster the coal industry and shift energy costs onto Hoosiers.”

“Propping up expensive, polluting coal will only exacerbate the affordability crisis families are facing,” Wannier said.

Earthjustice also pointed out that groundwater at Schahfer is “highly contaminated by its leaking coal ash pond.” In late 2025, EPA allowed Schahfer, along with 10 other coal plants, to continue to dump coal ash in unlined ponds until Oct. 17, 2031, delaying closure of the ponds by three years.

“Federal law simply doesn’t permit the federal government to manipulate power sector assets in this way without a true emergency,” Sameer Doshi, Earthjustice senior attorney, said in a statement. “The plant owners and everyone with responsibility for grid stability planned several years ahead for the orderly retirement of these aging units. Now the Trump administration is forcing continued and unnecessary burning of coal, which will mean more air and water pollution as well as higher electricity bills. We’re asking the court to curb this abuse.”

Both units are in MISO territory along with Consumers Energy’s J.H. Campbell Plant, which also was ordered to stay online by DOE. FERC has already cleared Campbell to use a MISO Midwest-wide allocation when proposing costs to be recovered. (See DOE Defends Use of Emergency Orders in Court Filing.)

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Alternative Western RA Program Starts to Take Shape

Participants in CAISO’s Extended Day-Ahead Market likely would remain subject to the market’s daily resource sufficiency evaluation even if they joined a new resource adequacy program that’s being crafted, developers of the new RA program said.

“The idea is it takes you right up to the doorstep of EDAM RSE. And then you participate in EDAM as designed,” said Jon Olson, director of energy trading and contracts at the Sacramento Municipal Utility District (SMUD).

The group developing the RA program is open to “some kind of swapping of RSE or potential obligations,” said Olson, who noted one goal of the program is to avoid the need for EDAM tariff adjustments.

Olson, along with Ben Faulkinberry of PacifiCorp, gave a presentation on the potential new RA program during a March 16 meeting of CAISO’s Western Energy Markets (WEM) Regional Issues Forum.

Participants in the RA project are PacifiCorp, Portland General Electric, Public Service Company of New Mexico, Los Angeles Department of Water and Power, NV Energy, the Turlock Irrigation District and the Balancing Authority of Northern California — of which SMUD is a member. The group is “self-organized,” Faulkinberry said, with CAISO involved as a technical consultant.

The group plans to release a draft design document in April. Faulkinberry said the document will leave “plenty of space for regional input.”

“Our intention was never to come out of the door with a fully baked, fully designed program,” said Faulkinberry, who is senior originator in PacifiCorp’s energy supply business unit.

WRAP Alternative

The new resource adequacy program is seen as an alternative to Western Power Pool’s Western Resource Adequacy Program (WRAP).

Participants in the day-ahead market competing with EDAM — SPP’s Markets+ — will be required to join WRAP. EDAM members also may join WRAP, but some expected EDAM participants have expressed concerns about the program and decided to withdraw. (See PacifiCorp Next to Leave WRAP After Raising Concerns.)

A variety of RA programs isn’t a problem for EDAM. CAISO has described the EDAM resource sufficiency evaluation as a “universal adaptor that connects entities with varying resource adequacy programs to efficiently commit/dispatch resources.”

Faulkinberry said the new RA program might appeal to utilities in Oregon, where jurisdictional entities must comply with state resource adequacy rules or participate in a qualifying regional program. The new RA program could become one such qualifying program.

One of the new RA program’s guiding principles is to use transmission connectivity within the EDAM footprint to allow capacity savings for customers. Market dispatch would be used for RA resource delivery, “so that the whole breadth and depth of the regional footprint could ensure that entities received megawatts when they needed them the most,” Faulkinberry said.

Other guiding principles include minimizing administrative burdens and having a common capacity counting standard, with ways to incentivize compliance.

Voluntary Offering

The RA program would be a voluntary offering, with an option for participants to withdraw if they feel it’s not working.

The group has been discussing a bevy of topics, such as methodology for capacity counting and load forecasts, transmission requirements, cure options if there’s a deficiency, binding-phase timing, transparency and ways to “instill trust in each other’s showings,” Faulkinberry said.

The presentation to the WEM Regional Issues Forum followed a March 7 letter that RA program developers sent to the CAISO WEM Body of State Regulators, outlining how the program could take shape. (See EDAM Utilities Moving to Develop RA Program.)

Following release of the draft design document, the group plans to solicit stakeholder feedback and issue a revised design document in the fall. That document then would be handed off to the Regional Organization for Western Energy (ROWE).

ROWE’s newly formed Formation Committee is scheduled to discuss the RA program March 19.