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December 19, 2025

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Trump Seeks to Keep Coal Plants Open, Attacks State Climate Policies

President Donald Trump signed a series of executive orders April 8 that seek to keep existing coal-fired power plants running, ease regulations and permitting for coal mining, and remove “unlawful and burdensome” state laws that impede the industry. 

The president also issued a proclamation that coal plants be exempt from the latest iteration of the Mercury and Air Toxics Standard, which the White House said will ensure they are not prematurely closed. 

“For four long years, Joe Biden and congressional Democrats tried to abolish the American coal industry,” Trump said at a White House ceremony flanked by coal miners. “They did everything in their power — while he was awake, which wasn’t much — shutting down dozens of coal plants, upending coal leases on federal lands, and putting thousands and thousands of coal miners out of work.” 

Trump ordered the secretary of energy to use Federal Power Act Section 202(c), which is meant to be used as a backstop to keep plants running for reliability even if that violates environmental rules, in a much broader way than previously used. 

The president also called on the Department of Justice to go after “unconstitutional” state laws that limit the use of domestic energy resources, including coal and other fossil fuels. 

The final order is titled “Reinvigorating America’s Beautiful Clean Coal Industry” and includes measures to open more federal land to coal mining. 

The White House’s fact sheets tied to the announcements cite the recent return to demand growth from the expansion of data centers, which are expected to drive up overall demand by 16% in the next five years. They also call coal “essential” to the power grid, making up 16% of total generation, which is down from 52.8% in 1990, according to the Energy Information Administration. 

Coal generation has been on a steady decline since 2007 when it produced 2,016 billion kWh, falling to just 675 billion kWh in 2023, according to EIA. 

“It is highly unlikely, in fact, probably zero probability, that anyone will ever build a new coal plant,” energy consultant Alison Silverstein said in an interview. 

Coal generation is more expensive to build than natural gas, which is facing stiff competition on its own from renewables in the markets. The best any policies can do would be to keep coal plants running longer, and that means going against decades of efforts to clean up the grid, Silverstein said. 

Silverstein wrote a report for the Department of Energy in Trump’s first term when then-Energy Secretary Rick Perry submitted a Notice of Proposed Rulemaking with FERC that would have had grid operators pay coal plants their full operating costs. Her report said that was not needed, and FERC voted the proposal down unanimously 5-0 after several of Trump’s appointees had taken office. 

FERC is not the focus of the current efforts, though some of the executive orders indicate the cabinet secretaries could consult with the agency as the policies are implemented. 

The executive order on “Strengthening the Reliability and Security of the United States Electric Grid” directs Energy Secretary Chris Wright to “streamline, systemize and expedite” the Department of Energy’s process for issuing orders under Section 202(c). It gives the secretary 30 days to review and analyze forecasted reserve margins for all regions of the bulk power system regulated by FERC to identify those with margins “below acceptable thresholds as identified by the secretary.” 

DOE will have to release that analysis in 90 days and then use it to identify at-risk plants of 50 MW or above. It then will use its 202(c) authority to prevent them from leaving the grid, or from converting fuel sources if that leads to a net reduction in generating capacity. 

Recent uses of Section 202(c) have focused on maintaining reliability in extreme weather, and in many cases it was in effect only for days, according to DOE. A famous case from 20 years ago kept a plant in Alexandria, Va., open to avoid blackouts in D.C., including the White House (EL05-145). 

One issue that will have to be addressed is what compensation coal plants required to stay online are due. Most of the existing coal fleet already is uncompetitive and most are inefficient, Silverstein said. 

“Keeping them running is costing the local utility ratepayers money because it is more expensive to buy coal production and to keep the coal plants running than it is to buy in the market from renewables or gas,” Silverstein said. “So, the thing that they are doing is essentially keeping these plants going by raising everybody’s costs.” 

“Protecting American Energy from State Overreach” directs the Department of Energy to go after state policies that “target or discriminate against out-of-state energy producers.” The order specifically calls out climate policies enacted by California, New York and Vermont. 

“These laws and policies also undermine federalism by projecting the regulatory preferences of a few states into all states,” the order says. “Americans must be permitted to heat their homes, fuel their cars and have peace of mind — free from policies that make energy more expensive and inevitably degrade quality of life.” 

The order calls on Attorney General Pam Bondi to identify all such state laws and to prioritize challenges to laws purporting to address climate change, environmental justice, carbon or greenhouse gas emissions, and funds to collect carbon penalties and taxes. “The attorney general shall expeditiously take all appropriate action to stop the enforcement” of such state laws and file a report in 60 days on those efforts, which will include recommendations for additional executive actions or legislative measures.” 

Reactions to the executive orders were mixed, with some saying they will help maintain reliability and others saying they are bad for the environment and consumers. 

National Rural Electric Cooperative Association CEO Jim Matheson and co-op executives from around the country were at the White House in support of Trump’s actions. NRECA members own at least part of 79 coal units with 21 GW of capacity, and 11 of them, totaling 3 GW, are scheduled to retire between now and 2030. 

“At a time when electricity demand is skyrocketing, we need to be adding more always-available energy to the grid, not shutting down power plants that have useful life left,” Matheson said in a statement. “Electric co-ops provide reliable power to communities across the country. Today’s announcements help drive home smart energy policies that will support efforts to keep the lights on at a price families and businesses can afford. We thank the administration for recognizing the continued importance of always-available resources in the nation’s energy mix.” 

Rep. Julie Fedorchak (R-N.D.), who was president of the National Association of Regulatory Utility Commissioners before assuming office this year, also praised the action, having introduced a resolution warning about growing demand and retiring plants April 7. 

“At a time when reliable baseload power is being shut down without adequate replacement, his executive orders are exactly what we need,” Fedorchak said. “With electricity demand from AI and data centers surging, the U.S. urgently needs always-available power — and that’s what coal provides, especially the mine-mouth coal power we produce in North Dakota.” 

Environmental Defense Fund Director Ted Kelly blasted the orders, saying that they could not overcome the market realities faced by coal. He also took issue with the use of FPA Section 202(c) and vowed to oppose the White House’s efforts. 

“That law is designed for, and limited to, sudden emergencies creating an immediate risk of blackouts or other grid instability, such as storms, wildfires or sudden major infrastructure failures,” Kelly said. “It is time-limited for the same reason, and it further limits any power generation that conflicts with environmental laws or regulations to the minimum hours needed to address the emergency. Changes to the power system over time, like load growth driven by data centers or power plant retirements driven by economics, are properly addressed by planning and action by utilities and their regulators — not by irrational and unlawful emergency actions.” 

Based on the market realities and likely challenges from EDF or Democratic state attorneys general, Silverstein predicted this second-term effort to bail out coal would wind up much like the failed NOPR from Trump’s first term. 

“This particular effort, I think, is going to have more grandstanding impact than actual impact,” Silverstein said. “I think it will affect a few coal plants and a few coal-mining and coal-plant communities, and it’s going to raise costs for everybody. But it’s hard to imagine any data center wanting to sign a contract with a 60- to 80-year-old coal plant.” 

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Texas RE Offers Compliance Help for New Registrants

With new registrants entering the Texas Reliability Entity’s system at an ever-increasing rate, staff from the regional entity stressed the importance of adhering to NERC’s reliability standards at an April 8 webinar.

Speaking to attendees of the webinar, part of the regular Talk with Texas RE series, Cybersecurity Principal William Sanders said the organization has noted a significant increase in the number of new registrants over the past few years, from 31 in 2022 to 53 in 2024. Most of the new additions were generator owners, he continued, reflecting the “large amount of generation being built” in the Texas Interconnection.

Texas’ recent generation additions have come at “an incredibly rapid pace,” ERCOT CEO Pablo Vegas told the grid operator’s Board of Directors in December. Solar resources and battery storage accounted for 83% of the 1,775 active interconnection requests at the time. (See ERCOT Faces Uphill Battle to Meet Large Loads.)

Sanders said the accelerating pace of registration prompted Texas RE to reach out to these incoming entities. Whether they are builders of new generation resources or purchasers of existing assets, many of them may be responsible for following NERC’s standards for the first time, he said. Noting that “Texas RE’s violation data is different from the rest of the interconnections, just because of how many new entities we have,” Sanders said the RE wanted “to make sure that [new registrants] have everything in place they need to be successful.”

To best serve their target audience of prospective generation builders or purchasers, Sanders and his co-presenter Alex Petak, enforcement attorney at Texas RE, focused their presentation on standards violations most often recorded within 31 days, one year, or two years of registration. Sanders covered NERC’s Critical Infrastructure Protection (CIP) standards, while Petak handled the suite of standards grouped under the Operations and Planning (O&P) label. Both discussed the most-violated requirements and best practices to prevent infringements.

Among the CIP standards, Sanders said the most-recorded violation is of requirement R2 of the CIP-003 family, the currently enforceable version of which is CIP-003-8 (Cybersecurity — security management controls). This requirement mandates that entities “with at least one asset … containing low impact [grid] cyber systems shall implement one or more documented cybersecurity plan(s)” for those systems.

Sanders reviewed the mandatory components of such cybersecurity plans, which comprise:

    • Cybersecurity awareness: Staff must be trained on cybersecurity best practices at least every 15 months.
    • Physical security controls: Any physical barriers, such as fences, locks and security cameras, between intruders and cyber assets.
    • Electronic access controls: Firewalls and other obstacles to online intruders.
    • Cybersecurity incident response plans: Plans must be tested at least once every 36 months.
    • Transient cyber asset and removable media: Safety protocols for USB drives and other physical media that can be added to or removed from a computer.

Other CIP violations frequently recorded within the first two years of registration include requirements R1 and R2 of CIP-002 (Cybersecurity — BES cyber system categorization). These require GOs to identify assets that contain low-impact grid cyber systems and review and update those identifications every 15 months.

“If your organization only has one generation facility, this may seem fairly straightforward. You obviously know about the generation asset [around] which your entire company is built,” Sanders said. “However, that documentation does need to exist, and for entities who are purchasing generation assets, you might have multiple generation facilities under a single [registration], [and] we need to have surety that you are aware of each of those facilities.”

In his O&P presentation, Petak noted that “facility ratings come up a lot in the early days,” with violations of NERC’s FAC family of standards comprising more than 20% of noncompliances that begin within 31 days of registration.

He reminded attendees that requirements R1 and R2 of FAC-008 (Facility ratings) mandate that GOs maintain documented methodologies for determining facility ratings, while R6 requires how those ratings are to be implemented and maintained. All three requirements are among the most frequent violations within the first month of registration, with R6 topping the list.

However, after the first 31 days, the biggest share of infringements shifts to NERC’s modeling (MOD) requirements, particularly MOD-026-1 (Verification of models and data for generator excitation control system or plant volt/var control functions) and MOD-027-1 (Verification of models and data for turbine/governor and load control or active power/frequency control functions).

Noncompliance with these standards usually is associated with requirement R2 of each one, which require GOs to have models in place for the applicable system functions. Petak noted that a common complaint among GOs is that “the deadline sneaks up on them in some way, or they were not tracking the deadline well enough,” and they or their third-party contractors lacked time to complete the verification.

“Having some sort of tracking software can definitely help out” with meeting the deadlines, Petak said. “In fact, most of the mitigating activities that we see when we’re processing these noncompliances involve the entity initiating some sort of software into their compliance program. So doing it before the noncompliance comes up would be ideal.”

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ERCOT: 60 GW in Additional Demand by 2031

ERCOT unveiled a long-term load forecast for 2031 on April 8 that adjusts projections provided by transmission providers and accounts for the uncertain nature of data centers and other large users. 

The numbers still are staggering. Even reducing the amount of utilities’ projected loads based on historical data, the study forecasts demand to reach 145 GW in 2031. That is less than transmission providers’ projections of 218 GW in 2031. 

The grid operator’s current peak demand is 85.5 GW, set in August 2023.  

“Several people are looking forward to [this], with bated breath,” Bill Flores, chair of ERCOT’s Board of Directors, told COO Woody Rickerson before he presented the adjusted methodology to the directors. 

The new treatment of load projections is a result of state legislation passed in 2023 (House Bill 5066) that updated regional transmission planning rules and required ERCOT to consider prospective loads identified by transmission providers. Previously, state laws prohibited the grid operator from factoring in load that was not financially committed or signed. 

The legislation also directs ERCOT to file an annual report quantifying the capability of existing and planned generation and load resources. Staff plan to meet that requirement by using their semiannual Capacity, Demand and Reserves (CDR) report, as they did in December 2024 by using the TSPs’ load forecast. 

ERCOT COO Woody Rickerson | ERCOT

However, that CDR revealed negative planning reserve margins as early as 2026. (See ERCOT’s Revised CDR Report Met with Doubts.) 

“We’re going to pivot away from using that forecast in this year’s May CDR,” Rickerson told the board. He noted the legislation’s “most impactful difference” was ERCOT accepting transmission providers’ officer-attested letters, which he attributes to much of the future data center load growth. 

The adjusted load forecast is based on three adjustments:  

    • delaying the in-service date by 180 days for all new large loads;
    • reducing new data center demand to 49.8% of the requested forecasts;
    • reducing officer-attestation loads to 54.55% of forecasts.

Rickerson said the reductions represent a “measured percentage of power being used” versus the forecasts. 

“An important part to keep in mind here is that this is a forecast based on the most recent data we have, and we’ll continue to update that as we move forward,” he said. “Those numbers were derived from loads that had been forecasted that we can now see and measure. Those numbers, as we move forward, can change as forecasts become more accurate.” 

The problem, Rickerson said, is how to count the large loads (75 MW or more) that data centers, hyper-scalers and crypto miners are planning.  

The board questioned Rickerson on the accuracy of data provided by transmission providers.  

“Data centers are not something that we were forecasting or looking at four, five years ago, so this is new information. How fast it builds out is something we’re all going to learn together,” he said. 

Rickerson said the quality of data needs to be adjusted “based on just the leading edge of historic numbers.” As ERCOT gets more of those numbers, he said, the grid operator’s adjusted load forecast and the transmission providers’ aggregate projections likely will merge into one. 

ERCOT CEO Pablo Vegas said Senate Bill 6, an omnibus energy bill being considered in the 2025 Legislature, includes provisions addressing the inputs into transmission providers’ forecasts. 

The ISO will begin incorporating the adjusted load forecast in transmission planning, resource adequacy and outage coordination analyses. Rickerson said a good-cause exception may be required from the Public Utility Commission. 

There could be some good news in the future over the escalating demand ERCOT faces. 

Pia Orrenius, a senior economist with the Federal Reserve Bank of Dallas, followed Rickerson’s presentation by saying the Texas economy is “likely slowing.” 

“[Business] outlooks have recently turned pessimistic,” she told the board, noting surveys of Texas businesses are “flashing some warning signs.” 

“Growth is likely to slow further … and will probably slow further than we’re currently forecasting,” she said. “The main reason is tariffs. They’re going to lead to higher prices. Consumption and investment will slow and possibly decline.” 

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MISO Fast Lane Proposal Disadvantages IPPs, Retail Choice States, Critics Tell FERC

MISO’s proposal to use a temporary “fast lane” in its interconnection queue to speed up necessary resource additions would give utility-owned generation preferential treatment, according to protesters’ comments filed with FERC on April 7, with a group of former commissioners saying it should be a nonstarter.

The RTO on March 17 filed its proposal to install the fast lane by the beginning of summer with FERC. (See MISO Says Queue Fast Track Design Settled, Ready for FERC.) The plan would have projects designated as essential by regulators traversing a separate queue equipped with dedicated, individual studies instead of the cluster-style studies MISO uses in its ordinary queue (ER25-1674).

MISO staff have said its current interconnection procedures are not up to the task of processing new projects expeditiously because of a buildup of projects with study delays. The grid operator has proposed using the special process for the next four years to overcome capacity deficits.

The plan drew a letter from eight former FERC commissioners — Democrats and Republicans alike — to express “deep concern.” The group, which includes past Chairs Richard Glick, Neil Chatterjee, Joseph T. Kelliher and Pat Wood III, said creating a special, expedited interconnection study treatment in the queue “presents the opportunity for self-dealing by utilities to advance their affiliated generation.”

The former commissioners said the fast lane’s process, in which a proposed generating facility must either be owned by a load-serving entity or have a power purchase or similar agreement with proof of load, appears unworkable. The group pointed out that independent competitive generation projects historically have been unable to finalize offtake terms and arrangements in contracts until they are assigned network upgrade costs in the queue. They called the plan a threat to FERC’s policy of open-access transmission.

They also questioned whether regulators would use an independent process or seek to avoid undue discrimination when selecting projects for special study treatment. They said PJM and CAISO’s recent adoption of queue expressways differ from MISO’s, which is “not narrowly tailored and allows affiliated generation to receive preferential treatment.”

“It has been nearly 30 years since FERC first planted the flag of open access when the commission issued Order No. 888. We have come too far to reverse course now, especially when, as other regions have demonstrated, more narrowly tailored options to expedite the generator interconnection process for resource adequacy purposes are available,” warned the former commissioners, which also include James Hoecker, Donald Santa, Nora Mead Brownell and John Norris.

States Divided

Support for the proposal among MISO’s states fell along retail choice lines.

The Illinois Commerce Commission said it believed the fast lane would discriminate against retail choice jurisdictions and give preferential treatment to vertically integrated states. While state identification of need would work for those that use integrated resource plans, it wouldn’t work for Illinois, which relies on competitive markets to ensure resource adequacy, the ICC said.

Illinois is MISO’s only true retail choice state; Michigan allows up to 10% of a utility’s retail electric sales to be purchased from alternative suppliers.

“Unless the proposal is amended, the projects in Illinois will be at a disadvantage,” the ICC argued. MISO’s proposal as is does not contain “workable language” to include Illinois or Michigan in short-term reliability considerations, it said.

Rolling out the special queue lane in a staggered manner wouldn’t be a solution, either, the ICC said, because by the time MISO established specialized rules for Illinois, the state would have suffered “irreparable economic harm” from the delay.

Vistra, which operates resources in downstate Illinois’ Zone 4, agreed. The company said the fast lane would bestow undue preference for generation in vertically integrated states, violating the Federal Power Act, and give LSEs a leg up over independent power producers.

Vistra said MISO is failing to ensure the fast lane would be limited to interconnection requests needed to meet resource adequacy or reliability requirements. The company argued that a request from a regulatory authority to study a resource does not mean it will meaningfully contribute to resource sufficiency.

“If MISO is going to take the exceptional step of allowing select resources to bypass the queue in the name of meeting near-term reliability needs, then there must be a reasonable basis for concluding that these resources can meet the specific reliability needs identified by MISO,” Vistra said.

The Michigan Public Service Commission expressed concern the plan could worsen “inherent inequities” unless applicants for expedited treatment show they have analyzed whether existing projects in the queue could solve the resource adequacy problem they seek to address. Absent that step, MISO could facilitate discriminatory practices and “do grave harm to fundamental principles of open-access transmission that have been core tenants of FERC’s regulatory framework since the issuance of Order 888 in 1996,” the PSC said.

It also said it doubted MISO’s commitment to bringing projects online as soon as possible because its plan includes a three-year grace period beyond its proposed three-year-out commercial operation date for expedited projects.

Earthrise Energy, which also owns generation in southern Illinois, said FERC should direct MISO to amend its filing so it includes a separate plan for Illinois and Michigan.

But the proposal drew plenty of support from vertically integrated states, including two governors.

Missouri Gov. Mike Kehoe, whose state turned up a capacity deficit in MISO’s 2023/24 Planning Resource Auction, said it is “committed to swift action to meet the needs of this moment.” He said the express lane can help the industry meet unprecedented load growth reliably.

Indiana Gov. Mike Braun also supported the fast lane, saying it’s “essential for energy development” in his state.

“We are committed to providing reliable, affordable energy to all Hoosiers, but we cannot move as swiftly as necessary without MISO being equally as swift,” Braun wrote. MISO is right to recognize it needs urgency and a unique means to manage a confluence of accelerated load growth, a rash of resource retirements and lagging resource additions, he said.

The Organization of MISO States framed the plan as a “necessary but limited mechanism” to maintain reliability across the footprint. OMS said most of its members support “enabling an alternative pathway other than the standard queue to meet immediate resource adequacy needs.”

The Arkansas, Louisiana, Mississippi and Texas commissions supported the proposal. Entergy operating companies, which make up the lion’s share of MISO South, were similarly on board.

Entergy Texas noted that it needs to bring its Legend and Lone Star gas plants — worth 1.2 GW collectively — online by 2028 to serve growing demand. Entergy Louisiana said it needs three new gas plants of its own at 2.26 GW to serve a new Meta data center. Entergy Arkansas said MISO’s queue backlogs “unreasonably impede” new generation coming online.

Questions over Fairness for IPPs

IPPs predicted that the fast lane, which wouldn’t use a megawatt cap to limit entries, soon would form a “second, unmanageable queue that would paralyze the MISO interconnection process.”

They also echoed Vistra’s concerns that regulators could make errors deciding which projects are essential and questioned “MISO’s decision to delegate many of the key terms and conditions of interconnection service to state and local regulatory authorities outside of FERC’s jurisdiction and leave those processes ripe for arbitrary and unduly discriminatory outcomes in violation of the FPA.”

They echoed the former FERC commissioners’ discrimination arguments and said the plan would put those developing competitive generation at a disadvantage while creating opportunities for LSEs to engage in self-dealing.

Public interest organizations, including the Sierra Club, Natural Resources Defense Council and Union of Concerned Scientists, called the proposal a “queue-jumping mechanism for preferred projects.”

Alliant Energy battery storage in Portage, Wis. | Alliant Energy

“In MISO’s own telling, such a proposal is necessitated by MISO’s failure to maintain a process that timely processes interconnection requests from new generation. And as a result of this failure, MISO now claims that it needs to create a separate interconnection process to ensure that these preferred projects are able to come online by the time they are needed for grid reliability,” the groups said. They added that MISO was missing a “technical quantification” of its RA need in its proposal.

NextEra Energy said the “gravity of harm that will be caused … cannot be overstated” and predicted the proposal would give vertically integrated utilities free rein to “self-build their own generation solutions, bypassing gigawatts of independent generation stranded in MISO’s legacy interconnection queue.”

The Coalition of Midwest Power Producers (COMPP) lambasted the filing as well. It said MISO didn’t quantify its resource inadequacy and wrongly omitted Michigan’s Zone 7 and Illinois’ Zone 4 from the plan. COMPP said together, those two zones contain about 31 GW of load, just 3 GW less than the whole of MISO South. It asked FERC to reject the filing.

The Clean Grid Alliance (CGA) said the expedited proposal is redundant because MISO already has efforts underway to speed up its queue, including study automation help from tech startup Pearl Street, higher fees and the capping of annual entrants at 50% peak load.

CGA said expedited generation would be allowed to claim transmission capacity that otherwise could be available for projects in the traditional queue, causing harm to developers. It also said MISO didn’t seem to be considering that some of its 56 GW with signed generator interconnection agreements would overcome delays to come online and handily manage a projected shortfall of a few gigawatts. (See MISO Members Grapple with 54 GW in Incomplete Gen, Predict Storage Expansion.)

“Rather than meaningfully parsing out data from its queue and even attempting to match queued generation to sub-region resource adequacy shortfalls, MISO merely makes conclusory statements and cites to its reports that claim there is a resource adequacy shortfall,” CGA argued.

LSEs: RA Needs Above All

Michigan-based Consumers Energy said that even though the 1,603-project, 296-GW interconnection queue appears to be able to deliver on resource adequacy, more than 70% of projects drop out of the queue.

Consumers said the high withdrawal rate, coupled with supply chain, permitting and study delays, translates into waiting times for projects that regularly exceed three years. On the other hand, a fast lane is a “tool that can help identify necessary projects and provide a path for a limited number of these resource adequacy projects to get connected in time to meet customer needs.”

Duke Indiana said the fast track would be a solid plan, pointing out that NERC’s 2024 Long-Term Reliability Assessment indicated that MISO may experience a 4.7-GW shortfall in 2028 “if the current expected generator retirements occur without the addition of significantly more generation.”

DTE Energy, Alliant Energy, Ameren and WEC Energy Group likewise filed in support, all stressing MISO’s resource adequacy needs.

Transmission owners said the proposal is “tailored” to avert conflicts between expedited projects and those in the queue’s usual definitive planning phase by allowing both to be processed in tandem. TOs also said the plan is “intentionally targeted and time-bound with a built-in sunset date, at the latest, by the end of 2028.”

MISO has acknowledged its stakeholders are concerned over the potential for discrimination between generation projects and whether a need really exists to create a dedicated fast track in the queue. But staff maintain the proposal is necessary and won’t be unduly preferential.

“We have a significant resource adequacy need we’ve been projecting for a few years,” MISO’s Andy Witmeier said at a Dec. 6, 2024, workshop. He pointed to the warnings MISO delivers on a quarterly basis in front of its Board of Directors.

Witmeier said MISO is confident that it has enough “inherent barriers” in place to the fast lane that there won’t be a “mad rush” where developers enter projects “willy nilly.” He said projects must be recognized and accepted by a state to meet a known need before they are able to gain entry.

“MISO has always been open to queue reform and trying to make the process better … and more efficient for all users,” Witmeier said, noting that in the five years he has worked on the queue, the RTO has continually made improvements.

He said it is prepared to hire additional consultants, contractors or temporary personnel to take on the additional work of the fast lane, resulting in higher processing fees for interconnection customers, though it should be straightforward. MISO won’t create special studies; it will just conduct its usual interconnection studies on a condensed timeline by focusing on a single generating unit, he said. “We know how to study interconnection requests.”

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MISO Discards Interim Participation Option from Order 2222 Plan

MISO on April 7 announced it will scrap its plan to use an existing demand response participation category to get aggregators of distributed energy resources participating on a limited basis a few years ahead of its full implementation of FERC Order 2222 in 2030.  

During a DER Task Force meeting, MISO counsel Michael Kessler said the RTO decided that trying to bend the interim plan to all Order 2222 requirements as FERC recommended would be “unduly burdensome.” Kessler said MISO plans to inform FERC by July that it will abandon its DR participation idea rather than try to make it fully compliant with the rule. 

FERC accepted MISO’s second try at Order 2222 compliance Jan. 16, granting the RTO until mid-2029 to prepare before fully accepting DER aggregators into its markets in 2030. (See FERC Permits 2030 Finish Date for MISO Order 2222 Compliance.) 

The commission accepted MISO’s explanation that its underlying computer systems need work over the next four years. However, it told the RTO its plan to allow DER aggregations in its markets earlier in a two-phase rollout needed to be either deleted or revised significantly. 

MISO proposed to use a two-stage approach to Order 2222 compliance. First, it would use an existing DR resource participation category to get DER aggregations participating sooner — albeit on a limited basis — and providing energy, contingency reserves and capacity through behind-the-meter generation or controllable load. MISO would have begun registering DER aggregations under its DRR Type I model by Sept. 1, 2026, and would have allowed participation to begin by June 1, 2027. DER aggregations would have been limited to 1 MW or larger under the model. 

But in its Jan. 16 order, FERC said MISO’s proposed 1-MW size threshold is too large, as Order 2222’s minimum for participation is only 100 kW.  

The commission also said MISO’s DR placeholder doesn’t address the coordination, data requirements or means to discourage double-counting of resource contributions required under Order 2222. It decided the RTO missed the mark on using an existing participation model to eke out partial compliance. 

FERC gave MISO 180 days to either explain how the DRR Type I participation model could comply with Order 2222 or strike the first phase of participation from its compliance plan. MISO decided over the past few weeks it would not salvage that aspect for a separate filing to allow DER aggregations to provide some services by the middle of 2027. 

Kessler said MISO attempting to make its planned, interim step complaint with Order 2222 likely would require the same system changes that aren’t doable until full compliance with the rule in late 2029 through mid-2030.

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Industry Must Share Risk Over Nuclear-Powered Data Centers, Experts Say

LA JOLLA, Calif. — As the U.S. Department of Energy explores using federal land for data centers powered by nuclear energy, experts say public-private risk sharing will be crucial to making nuclear viable. 

The DOE on April 3 issued a request for information related to developing data centers on federal land, with 16 potential sites identified as “uniquely positioned for rapid data center construction, including in-place energy infrastructure with the ability to fast-track permitting for new energy generation such as nuclear,” according to a news release. 

The issue of nuclear energy and data centers also was discussed in La Jolla, Calif., during the joint spring conference of the Committee on Regional Electric Power Cooperation and Western Interconnection Regional Advisory Body (CREPC-WIRAB) on April 4.  

WECC’s 2024 Western Assessment of Resource Adequacy (WARA) found that annual demand in the Western Interconnection will grow from 942 TWh in 2025 to 1,134 TWh in 2034. That 20.4% increase is more than four times the 4.5% growth rate from 2013 to 2022 and twice the 9.6% growth forecast in 2022 resource plans. (See West to See ‘Staggering’ Load Growth, WECC Report Says.) 

WECC said large loads are a major factor in the rapid demand growth, including data centers, factories and cryptocurrency mining. Electrification also plays a role.  

While there is widespread support for nuclear energy, which holds the potential to supply large amounts of baseload emissions-free electricity, there is a need for risk sharing, especially in the beginning as the industry navigates costs, construction cycles, regulations and other challenges, said Marcus Nichol, executive director of new nuclear at the Nuclear Energy Institute. 

“The utilities that might own and operate and build these, they’re willing to take on some risk,” Nichol said. “We’re actively working with them to help reduce the risk so that it’s more manageable. But they need help to be able to take this on.” 

Nichol noted that there are federal tax incentives in place, and U.S. Sen. Jim Risch (R-Idaho) introduced the Accelerating Reliable Capacity Act in December to accelerate investment in commercial nuclear projects by minimizing cost overrun risk. 

States also are “looking at their own state-tailored policies to be able to help contribute to taking on some of the risk,” Nichol said. Some data center developers also are looking to “contribute and take on some of the risk as well,” Nichol added. 

Meta, Microsoft and Amazon all have announced plans to power data centers with nuclear technology. (See Meta Seeks Nuclear Partners; AWS Boosts Efficiency.) 

For example, Constellation Energy plans to reopen Three Mile Island Unit 1 under a power purchase agreement with Microsoft to sell about 835 MW to serve the company’s data centers. (See Constellation to Reopen, Rename Three Mile Island Unit 1.) 

Amazon, meanwhile, has committed $1 billion to early stage development work, said Nate Hill, head of energy policy at Amazon. 

“From Amazon’s perspective, we’re willing to put our capital at risk to help get some of these early stage projects off the ground,” Hill said. “Because, I mean, when you think about it, like some of the costs of these projects could be more than the market cap of some utilities. So, there’s going to have to be risk sharing.” 

Katie Rogers, manager of reliability assessments at WECC, noted that the numbers could change as WECC learns more about how much of the demand will be realized. 

Still, the industry must move toward holistic grid planning and share the burden, Rogers said. 

“It feels very much like that we maybe need to have a different approach to how we plan the grid, and maybe not looking at, you know, one person carrying or one subset of people carrying all the risk if it has broader implications to the grid,” Rogers said. “It needs to be looked at holistically with everything.” 

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FERC Approves ISO-NE Order 2023 Interconnection Proposal

FERC has accepted ISO-NE’s compliance proposal for Order 2023, setting the stage for sweeping changes to the RTO’s interconnection procedures.  

The April 4 ruling came nearly eight months after ISO-NE’s proposed effective date of Aug. 12, 2024, and followed months of stakeholder requests for rapid action to preserve the transition timeline and prevent significant delays to projects in the interconnection queue (ER24-2009, ER24-2007). 

FERC’s ruling largely accepted ISO-NE’s proposal but directed the RTO to make relatively minor changes in an additional filing.

Order 2023 and the follow-up ruling, Order 2023-A, require transmission providers to transition from serial interconnection processes to cluster study processes, in which interconnection requests will be studied simultaneously. 

ISO-NE filed its Order 2023 compliance proposal in May 2024 with the support of NEPOOL after an extensive process of stakeholder engagement and revisions. (See NEPOOL PC Backs ISO-NE Tariff Revisions for Order 2023 Compliance and ISO-NE Order 2023 Compliance Proposal Fails to Pass NEPOOL TC.) 

In comments submitted to FERC, developers generally supported the filing, though several groups requested changes, such as a shorter cluster study timeline and reduced study deposit requirements. (See Clean Energy Groups Respond to ISO-NE Order 2023 Filing.) 

Allco Finance had urged the commission to reject the proposal due to impacts it would have on distribution-level projects and argued ISO-NE does not have jurisdiction over state-level interconnection procedures. But FERC ruled the complaint was outside the scope of the proceeding, finding the company had not demonstrated ISO-NE failed to comply with Order 2023 or Order 2023-A.  

Despite arguments from some stakeholders that ISO-NE should adopt the 150-day cluster study timeline outlined by Order 2023, the commission accepted the RTO’s proposal for a 270-day process. ISO-NE said a 150-day timeline would be infeasible for the region. 

FERC agreed the 270-day timeline “reflects ISO-NE’s unique regional issues and the comprehensive scope of its studies, including electromagnetic transient studies for inverter-based resources.” 

The commission also approved ISO-NE’s proposal to reduce the cluster restudy timeline from 150 to 90 days, noting the RTO “will use the same base case data as the cluster study and will involve fewer interconnection requests, thereby allowing interconnection requests to proceed expeditiously through the interconnection study process.” 

FERC also accepted ISO-NE’s proposal to require a flat $250,000 deposit and a $50,000 application fee for the cluster study, writing that “extending the $250,000 deposit to smaller generators is reasonable due to regional differences because … project size is not a ready indicator of study cost or complexity for interconnection requests in New England.” 

It rejected arguments by Glenvale Solar that ISO-NE’s proposed deposit requirements are prohibitive for smaller projects participating in the process, saying the “proposed flat deposit structure reasonably approximates study costs in New England.”

The commission also approved ISO-NE’s proposal for a $500,000 initial commercial readiness deposit, writing that the amount will help deter speculative interconnection requests. Order 2023 requires commercial readiness deposits to be twice the size of study deposits. 

“While higher than the pro forma [Large Generator Interconnection Procedures], we find the variation is justified because the $500,000 amount reflects historically high network upgrade costs in ISO-NE,” FERC wrote.  

Optimism Around Transitional CNR Study

FERC also accepted ISO-NE’s initial prohibition of using surety bonds for deposits, despite Order 2023’s direction to do so, saying the RTO demonstrated it needs more time to develop the procedures for accepting the bonds. The order directed the RTO to submit more information about when it will begin accepting surety bonds for commercial readiness and study deposits. 

ISO-NE’s transition process for adopting the changes also largely complies with Order 2023, FERC wrote. The commission wrote that the creation of a transitional capacity network resource (CNR) group study helps to appropriately balance “the need to move expeditiously to the new cluster study process with the need to respect the investments and expectations of interconnection customers at an advanced stage in the existing interconnection process.” 

The transitional CNR group study is intended to allow projects with complete system impact studies to gain capacity interconnection rights without needing to go through the full cluster study. Going forward, interconnection customers will achieve capacity interconnection rights through the cluster studies.  

In recent months, project developers have raised alarms that FERC’s inaction on ISO-NE’s compliance proposal could threaten the ability to align the transitional CNR study with the qualification activities for ISO-NE’s 2025 reconfiguration auction (RA). (See New England Generators Remain in Limbo on Interconnection Reform.) 

ISO-NE had said it would need a ruling by March 31 to align the transitional CNR group study with the 2025 RA qualification process due to a show-of-interest submission deadline at the end of April. On March 31, FERC took the unusual step of informing ISO-NE and stakeholders that it planned to issue an order in the coming days. (See FERC Announces Impending Order on ISO-NE Order 2023 Compliance.) 

Alex Lawton of Advanced Energy United, who has been vocal about the importance of the transitional CNR study, said he’s optimistic FERC’s ruling will enable ISO-NE to proceed with the study.  

A representative of ISO-NE said the RTO “is reviewing the April 4, 2025, order in detail and assessing next steps.” 

The ruling also accepted independent entity variations related to site control requirements, the opportunity to reduce project size prior to a cluster restudy, energy storage modeling and the evaluation of alternative transmission technologies. 

FERC directed ISO-NE to make a series of relatively minor changes to its proposal within 60 days, including to correct multiple “unexplained deviations” from the pro forma language, and to add pro forma language that was omitted. The commission also found the proposal did not comply with Order 2023’s ride-through requirements. 

The commission accepted ISO-NE’s proposed Aug. 12, 2024, effective date and the June 13, 2024, deadline for interconnection customers to have a valid interconnection request to be eligible to participate in the first cluster study. While the RTO briefly reopened its interconnection queue April 1, requests submitted after this date will not be eligible to participate in the transitional cluster study. (See ISO-NE to Reopen Queue as it Continues to Wait on Ruling from FERC.) 

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Groups Ask FERC to Axe Languishing Proposal to Cut Transmission Incentives

The Edison Electric Institute, GridWise Alliance and WIRES asked FERC on April 3 to end a proceeding that has been open for five years to consider cuts to transmission incentives (RM20-10). 

The commission opened the rulemaking in March 2020 and supplemented it a year later to propose eliminating the existing RTO membership transmission incentive for utilities that have been participating in an organized market for more than three years. The proposal would have focused project-specific incentives on the benefits to customers from transmission investment. 

“The commission’s current transmission incentives policy is working to the benefit of customers, transmission owners and the public interest,” they said in a joint filing. “With the rising demand for electricity, the commission’s existing transmission incentives policy has become even more essential.” 

A lot has changed since the rulemaking launch, they said, including a rapid and unforeseen return to demand growth because of large data centers, reshoring of industry and general electrification pressures. The COVID-19 pandemic led to an economic slowdown and uncertainties in the economic forecasts on which the industry relies. 

FERC also issued Orders 1920 and 1920-A, which are intended to identify considerable new transmission portfolios that might also introduce new risks to development because of the selection of larger and more complex projects, the groups argued. The world also is entering into a period of greater geopolitical tensions and competition, in which promoting domestic energy independence and security is considered a heightened priority. 

While the three trade groups want FERC to abandon the rulemaking, they argued even if the commission wants to go forward, it should take more comments so parties can update the record for the changes over the past half decade. 

President Donald Trump has declared a national energy emergency, in which he emphasized the urgent need to revamp and expand the grid to meet growing demand and ensure reliable supply, they noted. 

“This infrastructure is not only essential for accommodating the increasing power demands from various sectors, but also for maintaining and enhancing the overall resilience and efficiency of the nation’s energy system, which itself underlies the broader economy,” they said. “A reliable, resilient and efficient energy delivery system is the foundation to providing cost-effective electric service to customers of all kinds, thereby aligning with the administration’s broader goals of fostering economic growth and energy security.” 

The incentives date back to the Energy Policy Act of 2005, which acknowledged that increased levels of transmission infrastructure were needed to keep costs reasonable and the system reliable. FERC implemented them in 2006 with Order 679, which established tailored incentives to address risks and challenges associated with transmission development. 

“After nearly two decades, it is undeniable that the commission’s transmission incentives policy has provided the signal and support for transmission investments that ultimately benefit electric customers,” the groups said. As FERC considers changing the incentive policy, it has to weigh whether this would disrupt expectations, create uncertainty and possibly chill investment by eliminating rate treatments that cut risk and aid in lower financing costs to benefit consumers, they said. 

FERC’s proposed change would treat the RTO adder as an incentive to join an organized market, but the groups argued that was not Congress’ intent. 

“The commission is, ultimately, ‘a creature of statute and has only those authorities delegated to it by … Congress,’” they said. “Any action that would restrict eligibility for this incentive beyond the requirement that a transmission owner join an RTO is ultra vires [beyond its legal authority].” 

RTO membership requires TOs to transfer operational control of their facilities to the grid operators, which perform functions like planning, marketing and congestion management. The grid operators can require TOs to make investments in high-risk transmission projects, with the RTO adder helping to offset that risk. 

“Transmission owners in RTOs must also comply with a more expansive set of federal regulations, such as Order Nos. 719, 745, 841 and 2222, which significantly and disproportionally impact RTO regions,” the groups said. “Through these actions, the commission has fundamentally altered the business model, exposed certain future capital investments of transmission owners to competition, increased the potential that investments will be delayed and deprive customers of the benefits, and created significant uncertainty and related regulatory risk.” 

The RTO adder offsets risks incurred in delivering the benefits of RTO membership to customers such as access to cheaper power, efficient dispatch over a wide area and enhanced reliability, which together far outweigh the cost of the adder, they argued. 

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PJM TEAC Briefs: April 1, 2025

PJM Presents Scope Change to RTEP Projects

PJM presented a $97 million increase to a project included in the 2022 Regional Transmission Expansion Plan (RTEP) Window 3. The change would remove two 230-kV lines between the Mars substation and Sojourner and Shellhorn facilities and reroute them to terminate at the south side of Mars to avoid intersecting with new lines being planned. The original scope is to build a 500-kV line between Mars and Golden and a 230-kV line from Mars to Lockridge and terminating at Golden. The changes bring the total cost to $439.9 million.

Projects included in the 2022 RTEP Window 3 also have obviated the need for two prior projects totaling $7.5 million. The rebuilding of a line between Loudoun and Morrisville will supplant a $4.5 million project to rebuild a 1.3-mile segment of that facility. A $3 million project to replace breakers at the Ox 500-kV substation also is being canceled as the same work is included in baseline projects.

Supplemental Projects

FirstEnergy presented a pair of projects amounting to $37.6 million to replace two 500/138-kV transformers and disconnect switches at its Pruntytown Substation in the APS zone due to the assets nearing end of life and experiencing maintenance issues. The projects are in the conceptual phase with in-service dates of Dec. 13, 2030, and June 13, 2031.

The replacement of another aging 500/345-kV transformer at Wylie Ridge is expected to cost $20 million with a projected in-service date of Dec. 13, 2030. The transformer has increased hydrogen and ethylene readings, moisture buildup and low dielectric strength, according to FirstEnergy.

American Electric Power presented a $50.4 million project to build a new 345-kV substation, to be named Navistar, in the AEP zone to serve a new customer bringing 437 MW of load to the New Carlisle, Ind., area. The facility would be cut into the Dumont-New Prairie 345-kV double circuit lines and would be configured as a breaker and a half with 11 345-kV breakers and two bus ties to the customer. The project is in the scoping phase with a projected in-service date of March 15, 2027.

Dayton Power and Light presented a $480 million project to serve two new customers located near Jeffersonville and Wilmington, Ohio, by expanding several 345-kV substations and linking the Clinton, Fayette and Atlanta facilities with new 345-kV lines. The Fayette and Atlanta substations would be expanded to breaker-and-a-half configurations to accommodate a 25-mile double circuit between the two sites, as well as two customer feeds from Fayette.

The Clinton facility would be expanded with equipment for a new 27-mile line to Fayette and two 345-kV customer feeds. The project is in the conceptual phase with a projected in-service date in January 2031. The Jeffersonville load is expected to come online in September 2026 and ramp up to 1.5 GW of load by 2031, while the Wilmington customer is expected to come on in 2028 and grow to 500 MW.

PPL presented a $101 million project to expand the proposed Tresckow 230-kV substation to include a four-bay breaker and a half 69-kV yard to serve a customer expected to bring 300 MW of load to Hauto, Pa., in 2028. Four 230/69-kV transformers also would be installed, as well as two 69-kV double circuit lines connecting Tresckow to the Frac-Tres 69-kV No. 1 and No. 2 lines. The project is in the conceptual phase with a projected in-service date of May 30, 2028.

Duke presented a $49 million project to build a new 345-kV substation, to be named Gold Finch, along the Silver Grove-Red Bank 345-kV line to serve a new customer seeking to interconnect 300 MW in Clermont County, Ohio. Gold Finch would be configured as a ring bus with four 345-kV breakers and a control building. The project is in the scoping phase with an in-service date of June 1, 2028.

Dominion presented a $450 million project to upgrade several lines and transformers to address load drop and thermal violations on the Ladysmith CT-Fredericksburg and Ladysmith CT-Four Rivers 230-kV lines. The violations were identified in the 2025 do no harm analysis. The project is in the conceptual phase with an in-service date of July 1, 2029.

Phase 1 of the project, expected to be complete in January 2028, includes rebuilding 6.5 miles of the Summit DP-Fredericksburg Sub 230-kV line with higher capacity conductor; reconductoring 7.3 miles of the Ladysmith-Ladysmith CT line; adding two 500-kV capacitor banks to Ladysmith; and building a new 230-kV line running between Ladysmith, New Post, Lee’s Hill and Allman using a mix of new structure and vacant arms.

Phase 2 would go online in July 2029 to expand the Kraken 500-kV switching station to cut into the Summit DP-Fredericksburg Sub 230-kV line, the St. Johns-Four Rivers 230-kV line and the planned Ladysmith-Allman 230-kV line. The St. Johns-Four Rivers and Four Rivers-Elmont lines also would be rebuilt. The 115-kV lines from Fredericksburg-Four Rivers, Pinewood-Four Rivers, Four Rivers-Elmont, and Pinewood-N. Doswell lines would be “wrecked” and a new double circuit 230-kV line would be built from Kraken to Allman, along with a single circuit line from Kraken to Elmont.

Several additional Dominion projects would serve new service requests across its footprint. A $10.1 million project would construct a 230-kV ring bus with four breakers at its Trabue substation; two new 230-kV substations, Ruther Glen and Carmel Church, would be added to the Ladysmith CT-Four Rivers line for $87 million; and two new 230-kV substations, New Post and Lee’s Hill, would be built along the Fredericksburg-Ladysmith CT line for $43 million.

The Wabash Valley Power Alliance presented an $80 million project to construct a 15-mile, 345-kV line between AEP’s Elderberry substation and NIPSCO’s Stillwell substation. The line will be operated by MISO and is being submitted to PJM’s supplemental planning process to allow study coordination.

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PJM MIC Briefs: April 2, 2025

Stakeholders Narrowly Endorse Uplift Changes

VALLEY FORGE, Pa. — The Market Implementation Committee endorsed a joint PJM and Independent Market Monitor proposal to rework how uplift and deviation charges are calculated for market sellers depending on how they respond to market signals and dispatch instructions. It passed with 53.3% support and is set to go for a first read at the Markets and Reliability Committee on May 21. (See “First Read on Proposal to Overhaul Uplift,” PJM MIC Briefs: March 5, 2025.) 

The changes would establish a new tracking ramp-limited MW desired (TRLD) metric to replace the three existing MW desired metrics used in calculating balancing operating reserve (BOR) credits and deviation charges. The TRLD would follow how a unit responds to instructions over time, rather than focusing on individual five-minute intervals as the ramp-limited desired, dispatch and locational marginal pricing-desired metrics do. 

PJM’s Lisa Morelli said that would address scenarios where a unit ignoring dispatch and keeping its output steady can avoid deviation charges. 

The TRLD would account for any dispatch instructions arising from ancillary services a market seller is responding to as well, such as regulation or sync reserve, allowing corresponding automatic exemptions from deviation to be eliminated. 

In past meetings, Morelli gave the example of a unit operating at 100 MW being dispatched down to 95 MW in accordance with its ramp rate. If that unit ignored the signal and stayed at 100 MW, it would not exceed the 10% margin that defines when a unit is deviating from dispatch under the status quo. Additionally, because dispatch is limited by ramp rates in the next interval, PJM could bring it down only to 95 MW in the following interval. 

The proposal also would rework the BOR credit formula by taking the lesser of real-time output or the TRLD and adjusting for ramp parameters for each interval, which Morelli said would simplify the equation. The start and end points for uplift eligibility would be revised to align with when a market seller’s commitment began and to run through either the end of that commitment or the unit’s minimum run time. 

Morelli said PJM’s goal is not to reduce uplift and the changes are likely to be a net benefit for many participants, as they also address scenarios where generators are undercompensated in some scenarios. 

If endorsed by the Members Committee in July, Morelli said PJM would aim to file tariff revisions at FERC in September. The changes would be implemented in two phases, starting with simulated results in market settlements reporting system (MSRS) reports before affecting actual settlements in late 2026 or early 2027.  

Responding to stakeholders questioning how PJM could respond to any gaps or unintended consequences identified during the soft launch, Morelli said the intention is to have enough detail in the tariff language to give direction to how the TRLD would function, with finer detail spelled out in the manuals. Any edge cases stakeholders are concerned about could be addressed by adjusting the manuals without needing to make additional FERC filings. The governing document language likely would empower PJM to adjust the TRLD if there are instances where SCED would dispatch a unit inconsistent with locational marginal pricing or the unit’s offers. 

Committee Endorses Manual 11 Periodic Review

Stakeholders endorsed revisions to Manual 11: Energy & Ancillary Services Market Operations drafted through the document’s periodic review. The changes were deferred during the committee’s March 5 meeting after concerns were raised with the language designating data centers as plug load. (See “Periodic Review of Manual 11 Deferred,” PJM MIC Briefs: March 5, 2025.) 

PJM’s Joseph Tutino said the proposal was changed since the first read to include data centers and crypto mining as “business segment” load following feedback that plus load typically includes smaller devices, such as household appliances. He said the remaining changes are mainly typographical. 

PJM’s Maria Belenky told the committee in March that data centers are considered plug load for the purpose of curtailment service providers (CSPs) reporting load enrolled in demand response. 

First Reads on Manual Revisions

PJM presented a first read on revisions to Manuals 6, 11, 28 and 29 to conform with FERC’s May 2023 order accepting a PJM proposal on how it proceeds with settlement under a market suspension. PJM’s transmittal letter states that a market suspension never has occurred but could result from “extraordinary circumstances such as a failure of computer systems.” (See “Market Suspension,” PJM Market Implementation Committee Briefs: June 8, 2022.) 

The filing stated that the tariff has no way of determining energy and ancillary service prices when zonal dispatch rates cannot be calculated by software. Three different sets of rules are included for determining real-time prices when suspensions last less than six hours, between six and 24, or for longer. Shorter suspensions would use the average real-time prices for each hour prior to and following the outage; for moderate duration events, day-ahead prices would be used if available, otherwise real-time prices would be used; and for suspensions exceeding a day, an aggregate supply curve would be developed (ER23-1431).  

The proposed Manual 28 language would use actual output for calculating energy offers during real-time energy market suspensions. Lost opportunity costs (LOC) would not be included for suspensions longer than one day, and BOR charges would be allocated to real-time load plus exports if a suspension exceeds one hour. 

PJM also gave a first read on revisions to Manual 18 to conform with FERC orders granting several changes PJM sought to make to its capacity market in recent months (ER25-682, ER25-785, ER24-2995). 

The bulk of the changes arise from FERC’s Feb. 14 order granting a host of capacity market changes meant to address tightening supply and demand. The corresponding manual revisions would codify delayed Base Residual Auction (BRA) dates; model resources operating on reliability-must-run (RMR) agreements as capacity; continue the use of a combustion turbine generator as the reference resource; and clarify that market sellers do not hold “safe harbor” from claims of market power exercise by holding a categorical exemption from the requirement that all resources holding capacity interconnection rights (CIRs) must offer into the capacity market. (See FERC OKs Changes to PJM Capacity Market to Cushion Consumer Impacts.) 

It also includes the elimination of must-offer exemptions for intermittent, storage and hybrid resources, requiring market sellers to offer those units into capacity auctions starting with the 2026/27 BRA scheduled to be conducted in July. Stakeholders and intervenors argued the exemption artificially increased auction clearing prices, while many generation owners argued the existing and proposed market rules do not allow them to reflect the risk exempt resources would take on with a capacity obligation. 

The final change would be to memorialize the removal of the energy efficiency addback and eliminate the resource class outright following the 2025/26 delivery year. PJM argued to the commission that the addback was a holdover from a prior set of rules and no longer was needed, as EE was captured in its load forecast. Removing capacity status for EE was sought as the RTO argued that it could not be demonstrated that capacity market revenues were used to reduce load. (See PJM Asks FERC to Eliminate Energy Efficiency from Capacity Market.) 

Stakeholders Discuss Pseudo-tied Resources

The committee continued its discussions on how pseudo-tied generators are assigned to locational deliverability areas for the purpose of determining clearing prices and the amount of local capacity PJM models as available within a zone. The subject was brought up by the North Carolina Electric Membership Corp. (NCEMC) to explore whether a load-serving entity seeking to self-supply with pseudo-tied generation should receive the clearing price for an LDA or the RTO-wide clearing price, with the latter being the status quo. 

PJM’s Nebiat Tesfa said pseudo-tied resources are those that have an indirect connection to PJM, hold firm transmission service and are studied to ensure deliverability akin to internal resources. Those studies do not, however, determine whether any particular resource is deliverable to a specific LDA; to ensure the right to inject to an LDA, either incremental capacity transfer rights (ICTRs) or investment in qualifying transmission upgrades (QTUs) must be obtained. In some cases, modeling the flow from a pseudo-tied resource can use the reliability requirement for an LDA to increase, she said. 

PJM’s Tim Horger said the RTO’s priority going into the topic is ensuring there are no inconsistencies between internal and pseudo-tied resources when modeling congestion or transmission. 

In its own presentation, NCEMC said there were circumstances in the 2025/26 BRA where LSEs were exposed to price separation within their LDAs and were prevented from using their own resources adjacent to that zone and which they believe are electrically serving that load. It said analysis of dispatch data shows that those units are providing congestion management in Mid-Atlantic Dominion. 

Horger said PJM and stakeholders have to be careful when considering changes down the path of using distribution factor (DFAX) analysis to determine whether a given resource is helping a specific LDA. 

Carl Johnson, representing the PJM Public Power Coalition, said if resources are tied to an LDA, especially when it’s the same organization trying to serve load with its own resources, there should be a way of recognizing that the cost shouldn’t be different just because an LDA separates. 

PJM’s Jonathan Kern said the CETL study is agnostic about which capacity resource is supplying an LDA, so there’s going to be some association with the CETL and generation outside the LDA but not associated with any particular resource.