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December 13, 2025

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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. 

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PJM Proposes Changes to Determination of Jurisdiction over Generation

PJM on June 3 presented a first read of a proposal to revise how it determines whether generation interconnections are subject to state or federal jurisdiction based on voltage or cost-recovery methodology.

The proposal would introduce a “bright-line test” that would designate generators interconnecting to facilities below 69 kV as being under state jurisdiction and thus required to obtain a wholesale market participation agreement (WMPA). Resources connecting to higher-voltage assets would be designated as under federal jurisdiction and required to obtain a generation interconnection agreement.

The proposal also includes a “backstop” where a point of interconnection could be classified as federal or state jurisdiction independent of the voltage depending on how the transmission owner, FERC or relevant electric retail regulatory authority has determined the cost-recovery paradigm.

Presenting to the Planning Committee, PJM Associate General Counsel Thomas DeVita said the aim of the proposal is to maximize the hours staff spend processing the more complicated studies needed on resources connecting to transmission assets while still maintaining visibility on distribution-level interconnections. He said it takes staff substantially longer to process a GIA application compared to a WMPA.

Under the status quo “first use” model for determining jurisdiction, the first resource interconnecting to a distribution facility for the purpose of participating in wholesale markets is classified as being under state jurisdiction and required to obtain a WMPA. All subsequent resources using that point of interconnection are considered “dual use” and considered under FERC jurisdiction. DeVita said PJM’s model follows FERC’s approval of an ISO-NE proposal to disclaim jurisdiction over all distributed energy resources. (See FERC Approves Changes to ISO-NE DER Interconnection Process.)

PJM Vice President of Planning Jason Connell said system impact studies for a generator pursuing a WMPA are completed by electric distribution companies rather than the RTO and produce a simpler agreement for it to process.

Exelon Director RTO Relations and Strategy Alex Stern said it makes sense to make improvements to the interconnection process that have been demonstrated to be beneficial in other RTOs and could carry benefits for developers as well.

“Developers interconnecting at the distribution level might have less responsibilities at the regional grid level and in fact avoid certain responsibilities entirely, which could perhaps be a benefit to them on top of less process with PJM,” he said.

The proposal includes a dispute resolution process, beginning with the developer attempting to resolve issues directly with TOs and EDCs. If PJM determines a dispute involves its governing documents, the conflict could be arbitrated through the RTO’s tariff-defined resolution process.

If granted by the commission, DeVita said PJM is planning a go-live date in 2026 and anticipates that the Planning Community online portal could be updated to allow members to select facilities and determine whether a generator interconnecting at that site would require a GIA or WMPA.

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PJM TEAC Briefs: June 5, 2025

PJM Update on 2025 RTEP

PJM presented additional detail on the regional interchange and transmission violations that are expected to fuel need for transmission buildout in the first window of the 2025 Regional Transmission Expansion Plan (RTEP). 

The competitive window for developers to submit projects addressing needs identified in Window 1 is set to open in mid-June and close in August. 

Several large load additions have been submitted in the PPL region, while relatively little new generation is expected in the area, creating a need for new transmission to import power. The long-term seven-year case, which is used to right-size proposals brought for five-year needs, supports the conclusion that upgrades are needed to transfer energy between the Mid-Atlantic Area Council (MAAC) zone and PPL. Around 2.7 GW of load is expected near the Susquehanna switchyard by 2030, 1,400 MW near Juniata, 524 MW near Planebrook and 490 MW near Lancaster. 

Large amounts of generation planned in the southern part of the Dominion zone likely will require upgrades to the 500-kV backbone running through the region. Additional upgrades also may be required on the 765-kV corridor running from northwest PJM to the AEP zone depending on how generation comes online. 

Generation studied through the fast lane interconnection queue (around 300 projects that had minimal network upgrades identified), the 2.6-GW Coastal Virginia Offshore Wind (CVOW) project and the 1-GW Chesterfield gas generator near Richmond, Va., are expected to serve local needs and not drive significant changes to regional power flows. 

The five-year case looking at 2030 finds PJM’s western region is expected to export almost 8 GW in the summer and 6 GW in the winter, down from the previous year in both seasons. Summer imports into MAAC would increase to about 3 GW. And while the region would remain an exporter in the winter, flows out were projected to decrease from 4 GW to 2 GW in 2030. Imports into Dominion would decrease in both seasons, falling from 6 GW to around 3.75 GW in the summer and from 10 GW to 6 GW in the winter. 

Supplemental Projects

PPL presented a $159 million project to serve a new customer near Allentown, Pa., which is expected to bring 1,000 MW of load by 2031. The project would construct a new 500/138-kV substation, named Orefield, which would cut into the 500-kV line between Susquehanna and Wescosville. The 138-kV Oreville switchyard also would cut into the Wescosville-Siegfried 138-kV and Wescosville-Allentown 138-kV lines. Six 138-kV lead lines would extend from the 138-kV switchyard to the 138/34-kV substation serving the customer. The project is in the conceptual phase with a projected in-service date of May 30, 2028. 

The utility presented an additional $89 million project to serve a new customer near Harrisburg, Pa., requesting service for 450 MW coming online by 2030. A new 230-kV switchyard, named Highspire, would be constructed along the Steelton-Hummelstown 230-kV line, which would be rebuilt as a double circuit. Three 230-kV lead lines would run to a 230/34-kV customer substation. The Hummelstown 230-kV switchyard would be expanded with new 230-kV bays as part of the project. The proposal is in the conceptual phase with a projected in-service date of May 30, 2028. 

PPL presented a $73.5 million project to serve a new customer near Jermyn, Pa., seeking to bring 500 MW of load online by 2029. A new 230-kV switchyard, named Callender Gap, would be built along the Lackawanna-Paupack 230-kV line and serve a new 230/34-kV customer substation with three 230-kV lead lines. The line segment between Lackawanna and Callender Gap would be upgraded to double circuit. The project is in the conceptual phase with an in-service date of May 30, 2028. 

PECO presented a $27 million project to build the Forge Spring 230-kV substation to provide 50 MVA of capacity to the distribution grid in the King of Prussia, Pa., area. The new facility would cut into the Betzwood-Barbadoes line and feature eight 230-kV breakers. It is in the conceptual phase with a projected in-service date of Dec. 31, 2029. 

Dominion presented a $108 million project in Virginia to create an additional 230-kV supply to the Elmont-Fredericksburg corridor, which is seeing a large number of substations constructed to serve data center load. An existing supplemental project is planned to rebuild the Kraken-Elmont 230-kV line, which will establish double circuit structures and a 115-kV corridor between Fredericksburg and Elmont. The new project would install 230-kV conductor on the double circuit structures between Elmont and Kraken and use open arms of existing structures from Elmont to Chickahominy. The result would be two new 230-kV circuits from Kraken to Chickahominy. The project is in the conceptual phase with a Dec. 31, 2030, in-service date. 

Dominion presented a $32.3 million project to serve a data center customer in Spotsylvania, Va., planning to bring 108 MW of load by 2028. The project would construct the 230-kV Tributary substation by cutting into the New Post-Ladysmith CT 230-kV line with 2.4 miles of new double-circuit lines. The project is in the engineering phase with a projected in-service date of April 1, 2027. 

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Consumers Energy Seeking Compensation for Keeping Campbell Open

Consumers Energy filed a complaint with FERC against MISO seeking compensation for keeping open the J.H. Campbell coal plant this summer as ordered by the U.S. Department of Energy under Federal Power Act Section 202(c) (EL25-90).

The utility filed the complaint because MISO’s tariff lacks a method to ensure it gets paid for reversing the retirement of the 1,400-MW coal plant, which had been set to shut down May 31. Instead, Consumers has been bidding the plant actively into MISO’s markets and producing energy there when dispatched. (See DOE Orders Michigan Coal Plant to Reverse Retirement.)

The firm also said it has procured fuel, done review and planning for maintenance, and taken other steps to comply with the order. It has set up an account to track all those costs.

DOE’s order calls on Consumers and MISO to file any needed waivers with FERC to ensure the firm gets paid for keeping the plant open.

Consumers was not requesting any specific dollar figure in the filing, saying it will make a filing when DOE’s emergency order is over that explains the just and reasonable costs it incurred in running the plants, minus market revenues.

The utility and MISO agree the tariff lacks a mechanism for the utility to recover costs from complying with the order, and MISO cannot unilaterally offer the utility a rate agreement under Section 202(c). The utility asked for fast-track processing of the complaint and to make the compensation mechanism effective May 23, the date of DOE’s order.

“As soon as the DOE order was issued, Consumers Energy began incurring and will continue to incur costs to comply with the DOE order’s directive to ‘take all measures necessary to ensure that the Campbell plant is available to operate’ for the duration of the DOE order,” the utility said. “The precise order costs will not be known until after the DOE order expires on Aug. 21, 2025.”

FERC has the authority under Section 202(c) to approve compensation for any plants required to stay open under the law. That authority is supplemented by Section 309, which gives the commission the “power to perform any and all acts, and to prescribe, issue, make and rescind such orders, rules and regulations as it may find necessary or appropriate to carry out the provisions of this act.” That part of the law gives FERC the authority to set up rules for cost recovery before those costs are fully known, Consumers argued.

The utility said the costs should be assigned to MISO Zones 1 through 7, which make up the RTO’s northern and central regions, the reliability of which DOE said it was addressing with the order.

“Michigan load will of course pay its fair share of Consumers Energy’s order costs (net of market revenues) because, as the DOE order points out, MISO Zones 1-7 (i.e., the northern and central zones) include Michigan. But Consumers Energy believes that, whatever the order costs turn out to be after netting market revenues, they should be allocated beyond the state of Michigan,” it said. “Consumers Energy customers are already paying for the cost to fulfill the capacity needs of Zone 7.”

DOE’s order noted that while the plant’s retirement was approved by MISO, and Michigan has adequate supplies without it, the north and central zones still face elevated reliability risks this summer.

Beyond the FPA, the government is constitutionally required to pay Consumers for running the plant the summer, the utility argued.

“Specifically, the Fifth Amendment Takings Clause bars the federal government from taking private property for public use without just compensation,” Consumers said.

The utility filed its complaint under Section 206, but it said this was done to cover its bases. In the event FERC finds it lacks the authority under sections 202(c) and 309, it can find the MISO tariff unjust and unreasonable under 206.

“Consumers Energy will incur costs associated with the DOE order, but the MISO tariff does not presently include a mechanism that would allow MISO to compensate Consumers Energy for such costs or allocate those costs to load in the MISO region,” it said. “The MISO tariff is thus unjust and unreasonable as applied to Consumers Energy and its compliance with the DOE order, and the commission should order MISO to adopt a tariff revision to provide a cost recovery mechanism for Consumers Energy’s order costs net of market revenues.”