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December 16, 2025

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Calif. Bill Seeks to Control Electric Bills, Create Transmission Authority

A California bill that would take aim at soaring electric bills and create a transmission infrastructure authority has cleared the state Senate and now is being considered in the Assembly. 

Senate Bill 254 by Sen. Josh Becker (D) was passed by the Senate 29-10 on June 4. It’s now in the Assembly, where it had its first reading. The bill is an “urgency” measure that would take effect immediately upon adoption. 

SB 254 is a sweeping bill with nine major provisions, which Becker said would save ratepayers “tens of billions of dollars” over the next several years. He called it “the legislature’s most ambitious effort ever to rein in rising energy costs.” 

“This is not a set of modest tweaks that will make minor improvements at the edges of a problem without offending anyone,” Becker said. “This is a big deal.” 

What’s in it?

SB 254 would exclude from electric utilities’ equity rate base a collective $5 billion spent on fire risk mitigation capital projects starting Jan. 1, 2025. Similarly, $10 billion collectively spent on energization capital projects would be excluded from the rate base.

The bill would create a Power Fund, to be funded by the legislature and used to reimburse utilities for “expenditures driven by public policy goals that provide a benefit to the general public.” Those could include transportation or building electrification programs or wildfire mitigation, among others. 

The California Energy Commission would decide how money from the Power Fund is spent. Utility spending that’s reimbursed from the Power Fund would be excluded from the rate base, and infrastructure paid for through the fund would not be eligible for return on equity. 

SB 254 would require utilities to include in their rate case filings a scenario in which spending would not go up more than the projected amount of the Social Security cost of living adjustment (COLA). The CPUC still could approve spending greater than the COLA if it’s deemed necessary for safe and reliable operation. 

Transmission Authorities

SB 254 proposes the creation of the Clean Energy Infrastructure Authority (CEIA) for transmission projects. The authority would identify transmission corridors; plan, finance, acquire and own transmission lines; serve as lead agency under the California Environmental Quality Act; and exercise eminent domain powers. 

The authority would enter into agreements with utilities to build, operate and maintain the transmission infrastructure. 

The California CEIA would be similar to two transmission authorities now operating in the West: the New Mexico Renewable Energy Transmission Authority (RETA) and the Colorado Electric Transmission Authority (CETA). 

“Establishing transmission authorities continues to be a critical policy lever for states, especially those without [an RTO], to consolidate and formalize transmission planning processes,” the National Caucus of Environmental Legislators said in a policy update in April. 

The group said lawmakers in Washington, Oregon and Montana had introduced bills this year to establish new transmission authorities.  

Affordability Issues

SB 254 is part of a three-bill package, intended to address affordability issues in California, that Senate president pro tem Mike McGuire worked on with the Democratic caucus. The other two bills address housing production and workforce development. 

“Skyrocketing housing costs and utility bills are stretching budgets, and folks are struggling to achieve a job that pays a family-sustaining wage,” McGuire said in a statement announcing the bill package in April. 

But opinions differed on whether SB 254 is part of the solution. 

Sen. Kelly Seyarto (R) pointed to “unrealistic mandates” as the cause of rising electric bills. 

“[Utility companies] are going back to the CPUC time and time again,” Seyarto said. “Because we are mandating that we attain unrealistic goals for all electric vehicles, for everything being electric in California. And they’re trying madly to try and get the infrastructure, which means wires everywhere.” 

Sen. Steven Choi (R) said creating a new transmission authority would increase costs. 

“Who knows how much money this agency will be using to establish and implement the programs and create the policies and employ the employees to run that authority?” Choi said. 

Other Provisions

Among other provisions in SB 254, the bill aims to provide near-term relief to electric utility customers by increasing the amount of the “climate credit” they see on their bills each April and October. The credit is part of the state’s cap-and-trade program.  

Low-income customers would get a greater share of the climate credit under SB 254, and it would be paid out in late summer when many residents are hit with their highest electric bills. 

In a permit streamlining measure, the bill would direct CEC to develop a program environmental impact report for energy storage systems of 200 MW or more. Agencies then could build on that more generic EIR when developers propose specific projects, reducing the time needed to prepare an environmental report. 

SB 254 also would lower the project-size threshold for a project to be eligible for the CEC’s opt-in certification program, from $250 million to $100 million. It would extend the life of the program by five years, through June 2034. 

The opt-in program is for renewable energy projects such as solar, onshore wind and energy storage systems. Under the voluntary opt-in process, the CEC becomes the lead agency for permitting and state environmental review. The CEC certificate is in lieu of any permit that normally would be required through the local land-use review process and most state permits. (See 2 Huge Solar-plus-storage Projects Planned in California.) 

SB 254 also would require the CEC to try out permitting management software to further streamline project review. 

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EIA Increases 2025, 2026 Electric Sales Forecast

The U.S. Energy Information Administration has revised its forecast upward for retail electricity sales — especially in ERCOT and PJM and largely because of anticipated commercial demand.

In its Short-Term Energy Outlook released June 10, EIA projected that commercial consumption would increase 3% in 2025 and 5% in 2026. It previously predicted an average of 2% in the two years.

EIA expects total generation this summer to be 1% higher than last summer, also from commercial and industrial load growth, and it expects less generation from natural gas-fired plants because of higher natural gas prices.

The Henry Hub spot price forecast is about $4/MMBtu for 2025 and $4.90 in 2026, on average, compared with $2.20 in 2024, EIA said.

Solar generation is projected to increase from 5% of the U.S. total in 2024 to 8% in 2026 and wind from 11% to 12%.

Natural gas is projected to dip from 42% of the total in 2024 to 40% in 2026, coal from 16% to 15%, and nuclear from 19% to 18%. The outlook for hydro is a steady 6% of the total in all three years.

Breaking it down geographically:

    • Electricity sales are expected to increase from 2024 to 2026 in every region except New England, with the largest increase in the West South Central region — from 716 TWh in 2024 to 810 TWh in 2026, a 13.1% jump.
    • The same two regions had the lowest and highest all-sector electricity prices in 2024 and are projected to hold the same ranks in 2026: West South Central would rise from 9.73 cents/kWh to 10.16 while New England would rise from 23.06 to 25.79.
    • Total power generation by grid region is expected to increase or decrease from 2024 to 2026 by small percentages with two exceptions: PJM is projected to jump 7.6% from 873 TWh to 939, and ERCOT is projected to jump 19.8% from 459 TWh to 550, both from increased renewable, natural gas and coal generation.

Factoring into the report are the economy and the weather. The forecast assumes real GDP growth at an annualized 1.4% in 2025 and 1.7% in 2026.

It also assumes an easing of the trade wars and a reduction in tariffs but notes that future trade policy is a source of uncertainty in the outlook, as is consumer spending, which is projected to grow much more slowly in 2025 and 2026 than in 2024.

EIA also assumes 2025 will be slightly cooler than 2024, which was warmer than average. This allows a 5% reduction in predicted 2025 cooling degree days and a resulting decrease in electricity demand.

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Wright Addresses Recent Orders Keeping Power Plants Open at Hearing

Energy Secretary Chris Wright testified about his department’s 2026 budget request at a House hearing where members often pressed him on other issues, including his recent use of the Federal Power Act to keep coal plants from retiring. 

“The Trump administration has been laser focused on raising energy costs for Americans, despite what the president campaigned on,” Rep Frank Pallone (D-N.J.) said June 10. “And the example came in the last month when your department ordered two power plants burning coal, natural gas and fuel oil to stay online mere days before they were scheduled to shut down for good.” 

Pallone asked at the hearing of the Energy and Commerce Subcommittee on Energy who had made the decision to keep open Consumer Energy’s J.H. Campbell coal plant in Michigan and Constellation Energy’s Eddystone natural gas-fired plant outside Philadelphia. 

Wright answered that he had; Pallone then quickly moved on to press him about how much money it will cost to keep Campbell running, quoting an estimate from the Michigan Public Service Commission of tens of millions of dollars. Consumers has filed a complaint with FERC seeking compensation from MISO’s north and central zones, saying it is tracking costs and will file a specific number at the end of the summer. (See Consumers Energy Seeking Compensation for Keeping Campbell Open.) 

PJM is taking a different path, working with stakeholders to come up with a way to pay Constellation to implement DOE’s order. (See PJM Board Initiates CIFP Process for Eddystone Compensation.) 

“Mr. Secretary, your background is in the oil and gas sector, not the electric sector,” Pallone said. “So, why do you think that you knew better than the grid operators, utilities and the state regulators to actually try to revive these even though no one seemed to care? Why are you increasing electricity prices for millions of people?” 

When it comes to the Campbell plant, Wright said MISO had a blackout just two days after DOE announced that it would keep running this summer, past its retirement initially planned for May 31. (See MISO Requires Load Shed in New Orleans to Avoid Grid Instability.) 

“MISO [has] the tightest reserve margin we have in the country,” Wright said. “You need to be able to keep the lights on. Two days later, the lights went out.” 

Pallone responded that the outage in New Orleans was a different part of the market. Entergy’s territory is in MISO South, which has limited transmission links to its central and north regions and is not subject to cost recovery for running the plant this summer under Consumers’ FERC filing. 

Rep. John James (R-Mich.) asked about the Campbell plant later in the hearing, specifically asking whether Michigan’s and other states’ net-zero energy policies had contributed to the situation in MISO. 

“Many people at DOE have been in dialogues with NERC and with MISO about these issues, but I think you hit the nail on the head,” Wright said. “What do we want? We want to reshore manufacturing to Michigan. We want to bring data centers to Michigan. We need to grow the supply of affordable, reliable electricity in Michigan.” 

Closing a coal plant 15 years before the end of its intended lifespan works against that goal, with Wright saying Michigan officials made the decision for “virtue signaling.” 

“That’s not the best interest of Michigan ratepayers and Michigan citizens,” Wright said. “But, yes, utilities get bullied and influenced by state politicians and national politicians that have political agendas around energy that are often not aligned with ratepayers and citizens.” 

James then made a pitch for Consumers’ proposed allocation for the plant, spreading it across 12 other states in MISO’s north and central regions so that the contract is not “financially punitive” to Michigan customers. 

“MISO is a large organization,” James said. “Where this power is dispatched is going to benefit a larger organization and, so, therefore, those costs should necessarily be spread out, as we all have to make sure that we are cooperating to make sure that we keep our power high and keeping our costs low.” 

Rep. Julie Fedorchak (R-N.D.) used her time for questions to note that she introduced the Baseload Reliability Protection Act with seven other Republican co-sponsors that would keep dispatchable power plants open to help the grid meet growing power demand. 

“Given that NERC’s assessment today is that two-thirds of our systems in the U.S. don’t have enough power to meet demand given certain circumstances today, and we’re looking at retiring 115 GW of baseload generation, and we’re seeing significant demand increases — all of that looks like a huge train wreck to me and to many others,” Fedorchak said. 

The bill would prohibit the retirement or conversion of dispatchable power generators in areas NERC has identified as having “elevated reliability risks,” protect those plants from any fines from noncompliance with environmental rules, and allow DOE to offer grants and loans to support needed plant upgrades and extend operational life. The bill provides exemptions when continued operation poses safety risks or is economically unviable. 

Wright said the policies in the bill align with what DOE has been working on to ensure the grid can accommodate new demand from data centers and reshored manufacturing. 

“We have a team in our Office of Electricity that’s looking at grid reserve margins across the different areas of the country,” Wright said. “And we’re looking at planned retirements, and then we’re going to try to proactively engage with all of them.” 

“This might be a five-year thing,” Fedorchak said. “This might not be forever, but right now, we’re behind, so let’s stop retiring. Let’s make sure we’re bringing new resources on as quickly as possible. I stand with my colleagues across the aisle to work on permitting reform, to bring things up as quickly as possible. But meanwhile, we need to keep what we have. That should not be a partisan statement.” 

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CREPC TC Close to Wrapping Up Cost Allocation Study

The Committee on Regional Electric Power Cooperation’s (CREPC) Transmission Collaborative (TC) is wrapping up work on a cost allocation study together with Energy Strategies, while another transmission expansion coalition study with the Western Power Pool is behind schedule, staff said during the Western Interstate Energy Board’s annual meeting on June 9.

Since the TC’s inception in 2024, the group’s primary focus has been working on a cost allocation study with Energy Strategies called the “State Exploration of Western Transmission Cost Allocation Frameworks,” Robin Arnold, WIEB’s director of state, federal and international affairs, said in a brief update.

Energy Strategies is “wrapping up work on that as we speak. We’ve received a lot of feedback through the TC on that study that’s helped inform what the final report will look like,” Arnold said.

The TC also is involved in the actionable transmission study under development by the Western Power Pool’s WestTEC. (See WestTEC Tx Study on Track Despite Delays.)

“This has been ongoing since we began the collaborative and will continue as long as that study is going,” Arnold said. “They’re a little behind schedule now, but we’ve been providing feedback as necessary wherever.”

The TC focuses on regional transmission issues by creating a space for CREPC members and staff “to collaborate on transmission coordination and development in the West through sharing viewpoints and information from the diversity of Western states and provinces,” according to WIEB’s website.

TC meetings mostly have been closed to outside stakeholders to give the “group a chance to learn about the issues and ask as many questions as they want to and just really talk amongst themselves on these various transmission issues,” Arnold said.

TC also has received updates from The Western Transmission Consortium (TWTC), a group focused on developing new ways to fund various projects. TWTC has identified a portfolio of projects in the Southwest for initial project curation and also is working on a study in the Pacific Northwest, according to Arnold.

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FERC Gives MISO 3 More Years on Ambient-Adjusted Ratings

FERC has decided it’s practical for MISO to have an almost three-year extension of the commission’s directive to implement ambient-adjusted transmission line ratings (ER22-2363-002). 

With FERC’s June 6 decision, MISO has until December 2028 to fulfill its responsibilities under Order 881. Without the postponement, the RTO would have had until July to prepare its systems to accept more varied line ratings from transmission owners. 

MISO cited vendors’ delays supplying software for the range of line ratings required under Order 881. (See MISO to Seek 3-Year Order 881 Delay for Vendor Holdups.) 

The commission said MISO “demonstrated that delays in the delivery of vendor software are beyond its control.” FERC said the extra three years are key to ensuring continuing reliable market operations.   

“We are persuaded by MISO’s argument that requiring MISO to implement interim processes could further postpone MISO’s overall compliance efforts,” FERC wrote.  

The commission accepted MISO’s explanation that its ability to test the capability hinges on having Limit Exchange Portal (LEP) upgrades in place, which has the RTO and its TOs drawing on the same limited collection of software vendors. MISO also said it needed its new market clearing engine in place before it could use the more technologically advanced LEP.  

The commission overruled the Organization of MISO States’ suggestion that the RTO could introduce AARs as much as possible in stages. It agreed with MISO that that would “ignore the interlinked nature of the software development MISO requires.” FERC said ordering staggered compliance could cause further delay.  

FERC took MISO up on its offer to make annual informational filings that describe its progress on the LEP.  

During MISO’s quarterly board meetings in March, ITC Holdings’ Brian Drumm said TOs have met regularly with the RTO on Order 881 compliance since the rule was issued. He said the TOs take seriously their duty to implement AARs, which he called no small task.  

“It’s an overlay of an entire network and information flowing back and forth,” Drumm said. TOs are “all trying to capture the attention of a very select pool of vendors.” 

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Developer Shelves Atlantic Shores, Seeks to Cancel ORECs

Atlantic Shores Offshore Wind is putting its 1.5-GW New Jersey offshore wind proposal on hold. 

The developer petitioned the New Jersey Board of Public Utilities to terminate the order providing the project with Offshore Renewable Energy Certificates (ORECs), the subsidies that would make construction financially feasible. 

The petition said in the wake of President Donald Trump’s Day 1 action targeting offshore wind development, Atlantic Shores has had to cancel contracts for key components and services, reduce its personnel and not make planned investments.  

“Most recently, this includes cancellation of the [interconnection service agreement] and associated upgrades to the regional transmission grid,” the petition indicated. 

The developer wrote that the petition follows tremendous efforts and investment of resources in the fully permitted project; the sums were redacted in a public copy provided to NetZero Insider on June 9. 

The BPU said it will review the petition but added it still believes offshore wind has value: “The state continues to recognize the immense potential of offshore wind to create jobs, stimulate economic development and contribute significantly to our clean energy targets. We will continue to ensure that New Jersey remains a leader in clean and affordable energy for residents and businesses.” 

Atlantic Shores CEO Joris Veldhoven said in a prepared statement that this is not the end of the project, only the end of a chapter: “This reset period presents us an opportunity to ensure utility customers continue to get a fair deal for critical infrastructure delivery. And with record demand for electricity outpacing supply, one thing’s for sure: New Jersey needs more power generation.” 

Atlantic Shores Offshore Wind was a joint venture between Shell New Energies US and EDF Renewables North America. Since the 2021 OREC order, it has encountered the same headwinds as nearly every other offshore wind proposal from Maryland to Maine. 

It submitted a rebid (presumably at higher cost) for the Atlantic Shores 1 in 2024, in the fourth New Jersey offshore wind solicitation, along with a new proposal for Atlantic Shores 2. (See 3 OSW Proposals Submitted to N.J.) But the state abandoned that solicitation in early 2025, in part due to President Trump’s opposition to offshore wind. (See N.J. Abandons 4th OSW Solicitation.) 

Also, Shell quit the partnership. (See Shell Quits Atlantic Shores Offshore Wind Project in N.J.) Further, the Trump administration suspended the air quality permit issued to Atlantic Shores during the Biden administration — without which construction could not proceed — and gave no indication when that permit might be usable again. (See EPA Puts Hold on Atlantic Shores OSW Permit.) 

Other New Jersey proposals have had problems as well. 

Ørsted became the first developer in the current era to cancel a U.S. offshore wind project outright when it spiked its permitted Ocean Wind 1 and 2 projects in 2023. (See Ørsted Cancels Ocean Wind, Suspends Skipjack.) Leading Light Wind had trouble finding a turbine supplier and was granted a delay by the BPU in 2024. (See New Jersey BPU Approves Invenergy Offshore Wind Delay.) Attentive Energy sought and received a delay from the BPU on some of its obligations earlier in 2025. (See N.J. BPU Backs Wind, Solar Adjustments Amid Dissent.) 

US Wind

There was more optimistic news farther down the coast: US Wind received the final permit it needs from Maryland to proceed to construction of the wind projects it has contracted with that state.  

But here too, the move does not guarantee clear sailing — Maryland’s offshore wind ambitions also have run into complications.  

Ørsted canceled the state contract for Skipjack Wind and placed the project on hold. (See Ørsted Cancels Skipjack Wind Agreement with Maryland.) Giant wind turbines were deemed incompatible with government activity off parts of the state’s coastline, at least in the near future. (See Potential Military/NASA Conflict with OSW Seen in Wind Energy Area and BOEM Clears Way for Central Atlantic Wind Lease Auction.) US Wind received bigger ORECs for its projects, Marwin 1 and Momentum Wind. (See Maryland Offers OSW Developer More Lucrative Terms.) 

And of course, an outspoken wind power opponent was elected U.S. president a year and a half after Maryland Gov. Wes Moore set an 8.5 GW offshore wind goal for his state. 

Trump since has put an indefinite hold on new offshore wind leases and ordered a review of previously permitted projects. (See Critics Slam Trump’s Freeze on New OSW Leases.) 

This potentially ratchets up the risk and uncertainty for a developer that holds all necessary permits and must decide whether to take a final investment decision and move toward start of construction of one of these multibillion-dollar projects, which proved to be risky propositions even under President Biden. 

US Wind still is awaiting a county-level construction permit in Delaware, where it plans to land its export cable and build a substation. But it has secured its federal approvals. And with the June 6 construction permit from the state Department of the Environment, it holds all Maryland permits as well. 

NetZero Insider asked when US Wind might make a final investment decision on its offshore wind proposal. A spokesperson did not directly address the query but provided a statement from CEO Jeff Grybowski: 

“US Wind’s projects will produce massive amounts of homegrown energy and will help satisfy the region’s critical need for more electricity. We look forward to continued engagement with the state as we work to bring this critical energy project online.” 

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PJM Board Initiates CIFP Process for Eddystone Compensation

PJM’s Board of Managers on June 9 initiated a critical issue fast path (CIFP) process to determine how to compensate Constellation Energy for continuing to run two gas-fired units at the utility’s Eddystone plant under a Department of Energy emergency order.

While PJM and MISO both have provisions to compensate generation that must remain online to maintain transmission reliability, they lack mechanisms for retaining and paying resources whose deactivation is delayed for resource adequacy purposes.

The announcement initiating the CIFP process said the purpose is to “engage with stakeholders and to receive feedback on the specific issue of the appropriate cost allocation methodology associated with the recovery of the DACC [deactivation avoidable cost credit] payments to Constellation for the Eddystone Units.”

The board communication says Constellation agreed to use the DACC to determine compensation for keeping units 3 and 4 at the 760-MW Eddystone plant online. However, PJM’s tariff contemplates applying the credit only for units serving under reliability-must-run agreements for transmission purposes. (See DOE Orders PJM, Constellation to Keep 760-MW Eddystone Generators Online.)

“This discussion may also include the potential establishment of a generic cost allocation structure that could be utilized in the event that additional [Federal Power Act Section] 202(c) orders are issued in the future for resource adequacy purposes, and the generator owners subject to those orders elect to utilize the DACC as their form of compensation,” the communication says.

Since the emergency order requires the Eddystone units to be operational on June 1, the CIFP process will proceed on a shortened timeline beginning with a problem statement, issue charge and solution proposed on June 10 and stakeholder feedback and alternatives solicited on June 12. A meeting for package development will be held on June 16, and a June 18 meeting will review the final proposed solution and allow “members and invited non-members” to provide feedback to the board.

Consumers Energy has filed a complaint against MISO asking FERC to require the RTO to file tariff revisions detailing how it will compensate generators required to defer their deactivations under Section 202(c) emergency orders. Consumers’ 1,560-MW J.H. Campbell generator in Michigan only has also been required to remain operational under a separate DOE emergency order (EL25-90).

“To be clear, the specific costs, if any, to be recovered by Consumers Energy are not at issue in this complaint. Rather, Consumers Energy plans to make a Section 202(c) filing after the conclusion of the extended service required by the DOE order in which it will present, explain and support what it believes are its just and reasonable costs associated with running the Campbell plant from the date of the DOE order, netting out applicable market revenues,” the complaint states.

‘False Narrative’

The Eddystone emergency order also was discussed at the June 3 PJM Operating Committee meeting, at which Senior Vice President of Operations Mike Bryson reiterated the RTO’s support for the order.

“PJM did not initiate the request for the emergency order; PJM does support the emergency order,” he said.

Bryson said the DOE reached out to PJM to inquire about generators that have requested deactivation, with a particular focus on “immediate concern generation” that would go offline by the end of May. The RTO responded by providing a spreadsheet of resources that are set to retire, highlighting those that are set to go offline in the next three years and are seeking to withdraw their deactivation request.

The emergency order was facilitated by an April 8 executive order that widens how the Section 202(c) authority may be used, which Bryson said sparked PJM’s interest due to the focus on retaining generation found to be critical to maintaining resource adequacy and preventing resources over 50 MW from deactivating or changing their fuel type if the conversion would reduce accredited capacity. (See Trump Seeks to Keep Coal Plants Open, Attacks State Climate Policies.)

Bryson said PJM has been vocal in congressional testimony about projected resource adequacy issues, load forecasts and its February 2023 “Energy Transition in PJM: Resource Retirements, Replacements & Risks” position paper. (See PJM Whitepaper to Highlight Future RA Concerns.)

In a June 2 statement, the Delaware Riverkeeper Network disputed that there is any emergency requiring Eddystone to remain online and said its continued operation harms public health and degrades water and air quality. It argued that Eddystone contributes to high ozone concentrations that exceed federal standards.

“Our nation has excess fossil fuel energy, so much so that it is being exported to countries oversees,” Maya van Rossum, head of the network, said in the statement. “The assertion of an energy emergency is a lie; a false narrative pedaled by Donald Trump as an excuse he can use to prolong continued use of aging energy operations like Eddystone, and to advance his demand that all federal agencies expedite approval of dirty fossil fuel operations in our region and nationwide.

“Proof of the lie is that while Donald Trump is perpetuating and fast tracking dirty fossil fuels, he is doing so in a way that disadvantages solar and wind projects which would provide for our region and nation’s energy needs while at the same time protect communities from air pollution and environmental degradation and help protect present and future generations from the ravages of climate crisis,” she said.

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PJM Operating Committee Briefs: June 3, 2025

Monthly Operating Metrics

The month of May saw one spin event to PJM, a shared reserve event, three high-system-voltage actions and 24 post-contingency local load relief warnings, according to the RTO’s monthly operating metrics.  

The hourly forecast error rate was below the 25-month average at 1.31%, with the average peak forecast off by 1.45%. 

A thunderstorm May 16 caused the peak load to be 4.84% lower than expected, which carried into the next day when lower-than-expected temperatures corresponded with a 4.74% overforecast peak load, PJM’s Marcus Smith said. Memorial Day also was overforecast by 4.19%, which was attributed to the holiday being the coldest in four years. Lower temperatures also contributed to a 3.21% overforecast on May 29. High afternoon temperatures on May 11 led to a 3.29% underforecast. 

A spin event was initiated on May 19 with 2,641 MW of generation and 688 MW of demand response assigned, of which 1,679 MW and 474 MW, respectively, responded. The event lasted seven minutes and 31 seconds, meaning it does not count toward the rolling average of reserve performance PJM is using to determine when it should scale back a 30% adder on the synchronized and primary reserve requirement.  

Only reserve deployments longer than 10 minutes contribute to the average, which would result in the adder being reduced if performance across three events average is above 75%. Thus far, only one event since the deployment of automatic generation control (AGC) has qualified, an event Feb. 5 that lasted 10 minutes and three seconds and had a 65% response rate. 

PJM Presents Cold Weather Preparations

PJM will update its Markets Gateway with a field for owners of gas generators to indicate whether they foresee any issues with procuring fuel during extreme cold weather as part of the RTO’s compliance with NERC’s TOP-002-5 standard for operations planning. 

The standard was updated to add a new requirement for balancing authorities to show how they will prepare for winter storms, with enforcement beginning Oct. 1. 

The additional field in Markets Gateway can be filled out at any time, but it becomes mandatory during cold weather advisories and alerts. Additional detail about the change will be presented to the Electric Gas Coordination Subcommittee, which is scheduled to meet June 12. 

Manual Revisions Endorsed

The committee endorsed revisions to Manuals 10 and 14D to reflect the third phase of PJM’s rules for hybrid resources. The changes include expanding the hybrid model to apply to non-inverter-based generation paired with storage or inverter-based resources, as well as allowing market sellers to choose whether to offer storage as open-loop or closed-loop. 

The package includes changing language to be more reflective of the wider combinations of generation types that could be classified as hybrid under the proposal. For instances where storage is capable of charging from the grid, the resource owner would be permitted to choose whether to offer it as open- or closed-loop, allowing for situations where a battery is physically capable of charging but the owner has determined not to operate it in that fashion. 

Any non-inverter components of a hybrid should report their output into eDART as their installed capacity, measured as committed and available megawatts. 

Stakeholders also endorsed revisions to Manual 12: Balancing Operations drafted through the document’s periodic review. The language includes updates to the operating mode change procedure to detail how dispatchers will coordinate with transmission owners and load-serving entities when redispatching generation or switching between on- and off-cost modes. The proposal also requires market sellers with self-scheduled units to call the PJM master coordinator when seeking to change output if NERC tags cannot be processed. 

The manual revisions include a change to require intermittent or inverter-based hybrid resources to set their emergency minimum to zero, while non-inverter-based hybrids would be required to set their minimum to the economic minimum parameter for the non-inverter component. The changes conform with FERC’s approval of PJM’s hybrid resource rules. 

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PJM MIC Briefs: June 2, 2025

PJM Presents Education on Demand Response in Regulation Market

The PJM Market Implementation Committee on June 2 discussed a proposal to allow demand response resources to participate in the regulation market when there are energy injections at the same point of interconnection to the distribution grid. (See “Stakeholders Discuss DR Participation in Regulation Market,” PJM MIC Briefs: May 7, 2025.)

PJM’s Pete Langbein said curtailment service providers (CSPs) cannot participate in the regulation market during the same interval where there is either energy being injected at the same POI or no load is present unless the resource has entered into a wholesale market interconnection agreement. The proposal would allow DR to participate as a regulation-only resource so long as it has received authorization from the relevant electric distribution company and entered into a net energy metering (NEM) agreement.

The regulation-only resource would not receive energy-market compensation for injections onto the grid and submeter performance and testing would be required.

Langbein said most regulation-only DR are customers with behind-the-meter storage that they want to offer into the regulation market without participating in the energy or capacity markets.

PJM’s Ilyana Dropkin, chair of the Distributed Resources Subcommittee (DISRS), said the proposal is part of the RTO’s Order 2222 compliance filing, but some subcommittee participants felt the 2028 implementation date is too far off and that it would be beneficial to make this change sooner.

Amanda Rumsey, manager of RTO and federal regulatory policy for PPL Electric Utilities, said the company does have tariffs allowing net metering through state programs, but Pennsylvania law does not allow energy injections from storage to participate in an NEM agreement. She questioned whether the rule change could create situations where EDCs could be caught between state law requirements and the new market rules.

Langbein said the proposal would not override any state laws. If an EDC’s NEM agreement prohibits this kind of arrangement in compliance with state laws, it would not be allowed.

3rd Phase of Hybrid Resource Rules Endorsed

Stakeholders endorsed by acclamation a set of manual revisions implementing the third phase of PJM’s rules for hybrid resources. The changes conform with FERC’s approval of PJM’s overall ruleset (ER25-1095). (See “1st Read on 3rd Phase of Hybrid Resource Rules,” PJM MIC Briefs: May 7, 2025.)

The revisions to Manuals 11, 27 and 28 expand the hybrid resource model to allow non-inverter-based generation at the same POI as battery storage to be combined into a single market unit. They also expand the language detailing how a hybrid resource with a capacity obligation meets its mandate to offer into the energy market.

The proposal would rewrite the definition of open-loop storage to allow generation owners to elect whether a battery capable of charging off the grid will be offered as open or closed loop. The status quo rules require storage capable of using PJM supply to charge to offer as open loop, but the RTO’s Maria Belenky said there are instances in which generation owners may wish to operationally limit the storage to charge off the generation elements of the hybrid.

A generation-only hybrid would meet its energy must-offer requirement by submitting the forecast output, capped at the inverter capability, while a hybrid with a storage component should offer the “anticipated intermittent and battery output.” The total amount of energy offered over the course of the day should be equal to or greater than the forecast intermittent output with a gross up of the battery efficiency. The resource owner either can use PJM’s forecast or substitute their own so long as it meets PJM’s requirements.

Revisions to the formula for lost opportunity cost credits would make storage and hybrid resources instructed to increase charging to mitigate transmission constraints or reliability issues eligible for credits. Resources instructed to reduce charging would not be eligible.

Elements of the Phase 3 rules also were endorsed by the Planning Committee and Operating Committee on June 3.

2 Renewable Dispatch Packages Advance to MIC

PJM presented education on a pair of proposals aimed at improving how intermittent resources are dispatched ahead of a first read scheduled for the MIC’s meeting July 9.

The proposals are aimed at making the data that PJM’s security-constrained economic dispatch (SCED) relies on more accurate by tying resources’ “effective Eco Max” parameter to PJM’s forecast of their expected output. The parameter would be updated for every five-minute interval in real-time SCED, while hourly forecasts would be produced six days out.

PJM’s Vijay Shah said SCED is limited to dispatching resources up to their Eco Max parameter, which can be lower than intermittent resources’ real-time capability. The proposals would allow a forecast value to be used as the maximum dispatchable output instead.

The core distinction between the two proposals centers on whether curtailment flags should be available for wind and solar generation. Curtailment flags for all resources are set to be removed in July, though they never were available for solar generation, which would remain the target under PJM’s proposal. A package introduced to the DISRS by Shell, American Electric Power, Dominion Energy and Gabel Associates would retain the flags for wind and establish new ones for solar. (See “Renewable Dispatch,” PJM MRC Briefs: April 26, 2023.)

A nonbinding poll at the DISRS found 96% support for the stakeholder package, while PJM’s received 15% support. The threshold for a subcommittee poll to indicate support for a proposal requires three members from at least two sectors to be in favor, which was surpassed for both packages.

Shah said eliminating curtailment flags would require generation owners to follow their basepoints and avoid situations where intermittent resources with low marginal costs are curtailed because their bid-in parameters are lower than actual output, resulting in higher cost units being committed.

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MISO-SPP JTIQ Fed Funds Caught Up in DOE Review of Grants

The U.S. Department of Energy is preparing a case-by-case review of all the agency’s financial assistance awards under the Biden administration that it says could have “significant ramifications” for current and prospective recipients.  

That review includes a $464.5 million grant to MISO and SPP under DOE’s Grid Resilience and Innovation Partnerships (GRIP) program.  

The grant, the largest awarded by DOE, would offset about 25% of the capital cost for five projects in the RTOs’ $1.6 billion Joint Targeted Interconnection Queue (JTIQ) portfolio. (See DOE Announces $3.46B for Grid Resilience, Improvement Projects.) 

A spokesperson for the Minnesota Department of Commerce said all GRIP funds are subject to the process review. Grant applicants face a June 16 deadline to provide the requested data to DOE, said Kristen Glazer, Commerce’s assistant communications director. The department is the lead applicant on the project, which also involves the Great Plains Institute, along with the two RTOs.

MISO and SPP both told RTO Insider they are coordinating with each other and the other JTIQ partners to respond to the data request. Minnesota said it has not been given a “definitive timeline” by DOE for the review’s completion. 

“In the meantime, we remain confident in the value of the proposed projects,” SPP spokesperson Derek Wingfield said. 

MISO told stakeholders earlier in 2025 that DOE had not indicated that GRIP funding is in jeopardy. It said the JTIQ portfolio “is not contingent upon the receipt of GRIP funding.” 

The grid operators say the five 345-kV JTIQ projects will enable the interconnection of “tens of thousands of MW of new generation” on their seam to serve new data centers and other large loads. 

The GRIP funds were awarded in 2023 but to date, only the Minnesota Commerce Department has received disbursement from the DOE. Glazer said the department is working with the RTOs and other partners to develop the contractual mechanisms ensuring they get funds for their work.

DOE announced the review process in a May press release. It requested additional information to evaluate 179 awards covering more than $15 billion in financial assistance. The agency said it is prioritizing “large-scale commercial projects” that require more detailed information from the awardees in a process that could extend to other DOE program offices. 

Energy Secretary Chris Wright said agency staff had spent 110 days reviewing “billions of dollars that were rushed out the door, particularly in the final days of the Biden administration” that it found concerning. He said agency staff would ensure due diligence to use “taxpayer dollars to generate the largest possible benefit to the American people.” 

“Any reputable business would have a process in place for evaluating spending and investments before money goes out the door, and the American people deserve no less from their federal government,” Wright said. 

DOE is requiring recipients to provide written responses and supporting documentation and to cooperate with program personnel on any follow-up requests. Projects that meet the agency’s standards will proceed, but those that don’t will be modified or terminated, based on the department’s outcome. 

“It feels like they’re going to use that process to down-select, including projects that were awarded but maybe not contracted,” Grid United CEO Michael Skelly said during the Edison Electric Institute’s annual meeting in June. “It’s not totally clear what’s happening there, but the one kind of wild card is there’s a real interest in moving quickly because they get the imperative around load growth and the need to build things.” 

Sitting next to Skelly on the EEI panel, ALLETE CEO Beth Owen said her organization operates an HVDC modernization project that relies on federal and state support. She said ALLETE is attempting to make the case with the federal government that the granted dollars need to flow. 

“We’ve spent a lot of time with the administration helping explain why these projects are important and why the DOE grant is an important part for customers,” Owen said. “This is an existing project that’s being modernized that will help ensure reliability and energy security. We’ve been using all of the things that we know are important to this administration. … In a high inflationary environment, those dollars are going to be critical to this project for those reasons.” 

FERC in November 2024 approved tariff revisions and modifications to the joint operating agreement between MISO and SPP that enshrine a structural and cost-allocation framework for the JTIQ projects. Their novel approach to joint planning focused on backbone projects they say will unlock 28 GW of capacity and reduce curtailments in a highly congested region. (See FERC Approves JTIQ Framework, Cost Allocation.) 

Amanda Durish Cook contributed to this article.