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December 16, 2025

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PJM Presents Updated Quadrennial Review Inputs

PJM plans to delay votes on several proposals to revise key capacity market parameters by one month to receive updated cost of new entry (CONE) values for combustion turbines and combined cycle generators as part of the ongoing Quadrennial Review process, though no impact to the auction timeline is expected. 

The MIC will vote on the proposals during its Sept. 10 meeting, followed by votes at the Markets and Reliability Committee and Members Committee on Sept. 25, with the aim of a filing being submitted to FERC in October. 

The delay will allow the Brattle Group, retained to assist in the review, to update the CONE values with physical updates — including wet compression, updated technical specifications from General Electric including higher firing temperature, and an adjusted inlet pressure assumption — and financial updates, including the impact of 100% bonus depreciation returning because of the One Big Beautiful Bill Act. Brattle and Sargent & Lundy presented additional information from GE to stakeholders on its standard payment schedule for gas turbines and showed that it was in reasonable agreement with the capital drawdown schedules used for the CC and CT in Brattle’s analysis. 

PJM’s Skyler Marzewski said that if Brattle were to exactly follow the GE turbine payment schedule, it would have little impact and result in the CONE for a CT increasing by less than $7/MW-day and less than $2/MW-day for a CC unit if incorporated into PJM’s proposed variable resource requirement (VRR) curve. He said one reason this impact is relatively small is because turbine payments are just one portion of capital drawdown, with owner-furnished equipment accounting for about 39% of overnight capital costs for a CT and 28% for a CC. 

Independent Market Monitor Joe Bowring said GE’s perspective on the total payments by purchasers, including but not limited to payments to GE, should be treated as informative on its payment schedule, not dispositive on the overall drawdown costs for a new generator. 

“The Market Monitor has built the drawdown schedule from the bottom up, while Sargent and Lundy/Brattle did a top-down analysis based on their general view about industry practice related to all payments associated with buying and installing a turbine,” Bowring wrote in an email. “GE’s general opinion about payments to others involved in the process is anecdotal and not the appropriate standard.” 

Brattle Principal Sam Newell and PJM Chief Economist Walter Graf said they met with GE, joined by Sargent & Lundy, to receive more information about the cost and payment schedule for turbines and confirmed that the capital drawdown schedule in Brattle’s analysis is reasonably aligned with GE’s payment schedule for turbines. They said the payment schedule for turbines has become increasingly front-loaded, which increases installed costs. Graf said the Monitor also was invited to this meeting but refused, and the delayed spend schedule proposed by the Monitor in its proposal results in a drastically different turbine payment schedule from what GE said would be reasonable. 

Bowring said the Monitor has discussed GE’s own payment requirements for the purchase of a turbine directly with GE and has incorporated GE’s required payment schedule in its drawdown schedule. He also disputed Graf’s characterization of the Monitor’s involvement. 

“The fact that the actual payment schedule required by GE differs from the assumptions made by Brattle is a reason to question the Brattle top-down derivation. It is not a question of what Brattle assumes is common practice. It is a question of what GE requires,” he said. 

Paul Sotkiewicz, president of E-Cubed Policy Associates, said Brattle and the Monitor should present more details on its discussions with GE and data received from the company to inform their drawdown schedules, along with more documentation from GE and engineering, procurement and construction (EPC) companies. 

“Sunshine is going to be the best disinfectant on this discussion,” he said. 

Presenting an update on the impact the changes could have on the VRR curve, Newell said the 100% bonus depreciation included in the One Big Beautiful Bill Act amounts to a tax break that “pretty significantly lowers the cost to the owner” of a new resource.

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PJM Stakeholders Frustrated by Reliability Requirement Shortfall

The Market Implementation Committee discussed the significance of PJM falling short of its reliability requirement and other details in the results of the 2026/27 Base Residual Auction, which cleared at the $329.17/MW-day cap across the RTO.  

Gregory Poulos, executive director of the Consumer Advocates of the PJM States, said the RTO had buried the lede on the importance of failing to meet the reliability requirement, particularly because load is expected to surge higher in the 2027/28 auction scheduled to be conducted in December. (See PJM Capacity Prices Hit $329/MW-day Price Cap.) 

Despite PJM’s efforts to speed interconnection studies and allow more resources to advance toward construction, only 2,400 MW of additional unforced capacity was provided by renewable resources and storage in the auction. Poulos noted that outgoing FERC Chair Mark Christie spoke during a press conference July 24 about his concern that a long-discussed reliability crisis is rearing its head in the 2026/27 BRA as slow generation growth meets data center load growth. (See Christie Says Farewell to FERC at Final Meeting as Chair.) 

Poulos told RTO Insider the advocates are frustrated by the administrative levers PJM decided to pull in the design of the 2026/27 auction, but that those issues are dwarfed by the potential impact of the 30 GW of data center load growth the RTO is projecting. He said the RTO must engage in “ruthless prioritization” as it determines the best approach to meeting its resource adequacy needs, but he said he is not aware of any changes that could handle load growth of that magnitude. 

Exelon Director of RTO Relations and Strategy Alex Stern said the extent of the capacity shortfall is fairly minor, with the auction procuring a reserve margin of 18.9% against a 19.1% requirement, which amounts to 309 MW of installed capacity. He questioned whether there are internal discussions ongoing at PJM related to expanding the options around how to get more generation online “so that we don’t just have customer bills going up but no new plants getting built.” 

PJM Director of Stakeholder Affairs Dave Anders noted that staff brought an issue charge to the Planning Committee on Aug. 5 intended to allow new resources capable of partial operation while their network upgrades are under construction to receive provisional interconnection service. While that wouldn’t move the needle on the capacity market, he said, it could allow more energy to be available to dispatchers during critical periods. 

PJM’s Pete Langbein said there are several initiatives that have resulted in changes effective for the 2027/28 auction, including expanding the availability window for demand response resources and the Reliability Resource Initiative (RRI), which added 51 resources totaling 11,793 MW of nameplate capacity to the Transition Cycle 2 study cluster. (See “Expanded Demand Response Modeling Endorsed,” PJM MIC Briefs: Feb. 5, 2025 and PJM Selects 51 Projects for Expedited Interconnection Studies.) 

“By all means, we are trying to be proactive to look at what can be done,” he said. 

PJM Senior Vice President of Operations Mike Bryson also said the executive leadership team has set resource adequacy as its top focus since the publishing of the RTO’s “4R’s” white paper finding that load growth, generation deactivations and slow new entry could compromise reliability. “It’s a focus of the entire executive team,” he said. 

Langbein said the RTO cleared very close to the requirement, and almost all generation cleared in the auction, aside from some resource owners who did not understand the process to request removal of capacity status or those with external contracts who did not realize they needed to go through the must offer exemption process.  

But “this is not horseshoes. ‘Very close’ is not same as meeting the requirement,” Independent Market Monitor Joe Bowring told RTO Insider in an email. “To the best of my knowledge, PJM has never been short in the capacity market at the total RTO level in the history of the capacity market. This is a clear warning sign. PJM needs to directly address the impact of large data center loads which will overwhelm the grid if not addressed in the very near term. Hand waving is not the appropriate response.” 

Bowring said some of the resources that did not offer ran afoul of the rules because of deadlines, and the Monitor will be looking at the subject closely and release more information. 

John Horstmann, senior director of RTO affairs for AES Ohio, asked if there has been any progress made on estimating the total amount of capacity that was removed from the market after the implementation of effective load-carrying capability (ELCC) and changes in accreditation, as well as the price impact on the total cost of capacity. 

Bowring said the Monitor is working on calculating those values and likely will include them in its series of reports on the auction. 

“The short answer is that ELCC removed a significant level of megawatts from the auction. The calculation of the exact amount requires analysis of the impact both on supply and demand of ELCC on the amount of capacity that would clear,” Bowring said. 

Presenting the auction results, Langbein said 2,669 MW of UCAP in new generation and uprates were offered in the auction, reversing a trend of declining new entry across the prior three auctions. About 1,100 MW of capacity interconnection rights scheduled to be deactivated also were withdrawn, keeping that output in service. He said staff are in the process of updating the auction report to include a note with the amount of ICAP offered in response to stakeholder requests. 

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Ørsted to Raise $9.3B, Self-finance Sunrise Wind

Ørsted is moving to raise as much as $9.33 billion on its own to finish building the Sunrise Wind project off the New York coast. 

The company said Aug. 11 the money will be sought from existing shareholders and that it must take this step because it has been unable to reach a financing deal and secure an equity partner under acceptable terms in the hostile environment President Donald Trump has created for U.S. offshore wind development. 

Ørsted CEO Rasmus Errboe said negotiations with multiple potential partners were progressing well — until April 16, when the Trump administration slapped a stop-work order on Empire Wind 1, an Equinor project off the New York coast, and did not allow construction to resume for more than a month. 

This “extraordinary and unprecedented development” significantly increased the perceived risk in the U.S. offshore wind sector, and those potential partners raised their requirements to a level untenable for Ørsted — so Ørsted must go it alone and fund the entire cost of Sunrise Wind on its balance sheet. 

With the “vast majority” of the expenditures already committed, there is far more value in moving ahead with the project than in abandoning it, Errboe said. Ørsted still expects Sunrise to produce a lifecycle internal rate of return in the mid-single digits. 

So it is seeking $6.22 billion to cover financing and capital costs, plus about $3.11 billion to strengthen the company’s capital structure and give it needed financial flexibility. 

The plan is to offer a rights issue — a discounted sale of additional shares to existing shareholders — in October, if authorized at an extraordinary general meeting in September. The Danish state, which owns a 50.1% share majority of the company, has given its full support, Errboe said, and the rights issue would be fully underwritten by Morgan Stanley. 

Ørsted’s stock tanked on the news, shedding nearly 30% of its value. 

Aside from the U.S. regulatory environment, and aside from the resulting financial squeeze, the largest western offshore wind developer presented a positive state of affairs with its first-half financial results. 

The two projects Ørsted still is actively developing in U.S. waters are on schedule. 

Revolution Wind, a 704-MW project that will send power to Connecticut and Rhode Island, is roughly 80% complete, with all turbine foundations and nearly 70% of the turbines installed. Commercial operation is targeted for the second half of 2026. 

Sunrise, a 924-MW project, is targeted to begin feeding the New York grid starting in the second half of 2027. Onshore construction is nearly complete, and more than a dozen turbine foundations have been installed. 

Sunrise is in a much better position than New Jersey’s Ocean Wind or Maryland’s Skipjack Wind, which Ørsted canceled and shelved, respectively. But Sunrise has had a tortuous path nonetheless. 

It dates to July 2013, when the federal government auctioned off rights to develop wind power on OCS-A 0487, a patch of the Outer Continental Shelf south of Fall River, Mass., and east of Montauk, N.Y. 

Ørsted and then-partner Eversource won an offtake contract from New York in the summer of 2019 for what was then called Sunrise Wind 1, but rising costs in 2022 and 2023 made the terms untenable. 

In 2024, New York renegotiated a much more expensive contract for Sunrise Wind — $146/MWh — and Ørsted bought out Eversource’s ownership stake in the project for $152 million. 

Later in 2024, Donald Trump was elected to a second term as president, and hours after his inauguration in January 2025, he began to fulfill a campaign-trail promise to thwart offshore wind development. Multiple policy changes announced since then have created new setbacks and hurdles for the already-struggling industry. 

Equinor recently recorded a nearly $1 billion impairment it attributed to President Trump, but so far, no other stop-work orders have been issued for the five offshore wind farms under construction and one in full operation in U.S. waters. The Trump administration’s moves have served mainly to block other wind farm plans or concepts from advancing. 

But during Ørsted’s Aug. 11 conference call, an analyst asked if the administration might not shut down Revolution or Sunrise the way it halted work on Empire. He asked: “Are you 100% comfortable the U.S. administration cannot block either of those projects?” 

“We have no indication of a similar decision or stop-work order against our northeast U.S. program, and I’m not going to speculate about potential regulatory changes that are outside our control,” Errboe said. 

Ørsted has followed all state and federal procedures with both projects, he added, “and we remain 100% committed to the continued construction of our program.” 

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NERC Posts IBR Standards for Comment

NERC is requesting comments from industry through Sept. 10 on four proposed reliability standards aimed at satisfying FERC’s directive on inverter-based resources.

The ERO posted the standards in its Standards Balloting System on Aug. 8, along with the latest update to the ERO’s Reliability Standards Development Plan (RSDP), which lays out the planned schedule of standards development from 2026 to 2028. Comments on the RSDP are due by Sept. 5.

The following standards are up for comment:

    • MOD-032-2 — Data for power system modeling and analysis;
    • IRO-010-6 — Reliability coordinator data and information specification and collection;
    • TOP-003-8 — Transmission operator and balancing authority data and information ​specification and collection; and
    • MOD-033-3 — Steady-state and dynamic system model validation.

All of the standards were developed under Project 2022-02 (Uniform modeling framework for IBRs) except for MOD-033-3, which originated from Project 2021-01 (System model validation with IBRs). NERC’s Standards Committee approved all of them for posting at its April 16 meeting. (See NERC Standards Committee Approves IBR Posting.)

In Order 901, issued in October 2023, FERC directed NERC to develop requirements pertaining to the reliable connection and operation of IBRs, grouped into four milestones to be submitted over the following three years (RM22-12). (See FERC Orders Reliability Rules for Inverter-Based Resources.) Included in Milestone 3, due Nov. 4, are requirements for providing data on IBRs and distributed energy resources to entities responsible for planning and operating the grid.

To satisfy this mandate, the standard development team for Project 2022-02 decided to update MOD-032-2 to include language from the ERO Unacceptable Models List, renamed Aug. 1 from the ERO Acceptable Models List Criteria Document. A new requirement allows planning coordinators and transmission planners to specify whether they will accept standard-library dynamic models, user-written models or both.

NERC said the requirement is “responsive to FERC concerns about model usability and non-convergence by requiring PCs and TPs … to specify usability requirements and require appropriate model documentation and instructions,” while also allowing a level of flexibility requested by stakeholders in industry engagement workshops.

Another requirement was rewritten “to require estimation of modeling data if the responsible entity … is unable to gather required data.” This is intended to give entities a way to meet FERC’s directive of submitting data even if the actual information is unavailable; however, entities that submit estimates must explain the “limitations of the estimated data” — such as legal prohibitions on requesting certain data, incomplete records of connected facilities and lack of mechanism to enforce collection — “and the method used for estimation.”

The final revisions recorded by the SDT apply to TOP-003-8 and IRO-010-6, and state that “entities responsible for developing and distributing data specifications shall include requirements for model submissions consistent with the model submitted for planning purposes, as applicable.”

The drafting team for Project 2021-01 said that “no substantive changes are needed” for MOD-033, but members did note “opportunities to improve the clarity of both the [standard’s] requirements and measures.” To this end, they proposed to add the glossary term “model validation” — approved in May by industry ballot for inclusion in NERC’s Glossary of Terms — to the standard, along with a requirement that the PC implement a model validation process for its “portion of the existing system.”

Team members also updated additional language in the standard to correspond with the “model validation” definition and to reduce redundancy and wordiness.

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PJM MIC Briefs: Aug. 6, 2025

1st Read on Offer Capping of Advance Scheduled Resources

PJM’s Phil D’Antonio presented a first read on a proposal to cap resources committed ahead of the day-ahead market at their cost-based offer. The proposal is set to be voted on by the MIC at its September meeting, and additional manual, operating agreement and tariff language would need to be drafted and voted on subsequently. (See “Offer Capping Resources with Advance Commitments,” PJM MIC Briefs: March 5, 2025.) 

Advance commitments have been used more widely since the institution of the conservative operations procedure, which allows PJM to schedule resources expected to be necessary to maintain transmission security during strained operating conditions, especially winter storms. The cost of that practice has been criticized by consumer advocates, and the use of out-of-market commitments has been opposed by some generation owners. (See PJM: ‘Conservative Operations’ Maintained Reliability During Jan. 2024 Storm.) 

Paul Sotkiewicz, president of E-Cubed Policy Associates, said PJM’s governing documents only allow for offer capping resources with advance commitments to address transmission constraints, arguing that offer capping resources committed for other purposes violates the tariff and negatively impacts price formation. 

“I think this is going down a very dangerous path,” he said. 

PJM’s proposal states that the “PJM tariff and [Operating Agreement] allow for offer capping only for transmission constraints. Current [Manuals 11 and 13] language allows offer capping for units scheduled in advance of the day-ahead market but does not have supporting tariff and OA language.” 

Offer Capping Issue Charge Revised

The committee endorsed by acclamation an expansion of the offer capping issue charge brought by the Monitor to include additional consideration of the treatment of resources with advance commitments in the day-ahead market, how uplift is calculated for resources committed for multiple days and additional transparency into how resources are scheduled. 

The issue charge was renamed to reflect the wider scope, removing references to offer capping to instead read as “resource scheduling prior to the day-ahead energy market.” (See “Monitor Proposes Rewrite of Offer Capping Issue Charge,” PJM MIC Briefs: July 9, 2025.) 

The revisions also add additional education on the triggers for allowing advance commitments, notifications that go out to stakeholders that such action has been taken, commitment instructions to resources, the inputs and models that determine commitment parameters and operational constraints not included in unit parameters, such as fuel inventory, gas nomination cycles and any run hour limitations associated with environmental permits. 

Renewable Dispatch Proposal Endorsed

Stakeholders endorsed a PJM proposal to create a new Effective EcoMax parameter for wind and solar resources intended to better capture how they are capable of operating in real-time energy market dispatching. The proposal passed with 98.9% support. (See “First Read on Real-time Renewable Dispatch,” PJM MIC Briefs: July 9, 2025.) 

The forecast for wind and solar output would be updated ahead of each five-minute interval, which then would feed into the Effective EcoMax parameter and update maximum output the generator can be dispatched up to. The existing EcoMax parameter limits security-constrained economic dispatch (SCED) based on the parameters submitted by resource owners, which can become stale and lead to units being curtailed below their potential. 

The proposal was modified by PJM to retain curtailment flags for wind resources and establish them for solar as well; they had been set to be removed for all resources in July, but a Distributed Resources Subcommittee poll showed 96% support for allowing them for renewables. 

Renewables would be limited to ramping at 20% of their ICAP per minute to minimize the volatility that can come from sudden shifts in renewable output. PJM’s Vijay Shah noted that still would allow those resources to go from 0 to 100% of their capability in a single interval. 

Regulation Market Redesign Endorsed

The committee endorsed by acclamation a slate of manual revisions to conform with PJM’s regulation market redesign, which was approved by FERC in June 2024 (ER24-1772). (See “PJM Presents Manual Revisions for Regulation Market Redesign,” PJM MIC Briefs: July 9, 2025.) 

The reworking of the market creates a single price signal with resources able to offer regulation up and down products, replacing a market model where participants offered bidirectional products to provide either Regulation A for long deployments or Regulation D for fast response. (See “PJM Presents Regulation Market Rework,” PJM MRC/MC Briefs: Dec. 20, 2023.) 

The proposal includes revisions to Manual 11: Energy & Ancillary Services Market Operations, which detail offer structure, DR participation and lost opportunity cost credits; Manual 15: Cost Development Guidelines, including a stipulation that regulation resources also participating in the energy market do not receive variable operations and maintenance cost increases; and Manual 28: Operating Agreement Accounting, which outline the regulation clearing price credit formula. 

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July Heat Wave Update, PJM OC Briefs: Aug. 7, 2025

July Heat Wave Update

PJM’s Kevin Hatch presented an update on how two heat waves between July 14-17 and 23-30 affected PJM operations, which involved multiple demand response deployments and emergency alerts and advisories. 

Loads reached their apex on the afternoon of July 29, with a preliminary integrated hourly peak of 157,487 MW, which Hatch said would be the ninth highest the RTO has seen. He said the day saw atypically high load ramping, renewable performance below the seasonal effective load-carrying capability (ELCC) value, and generation outages exceeding the three-year average. Around 3.7 GW of DR was deployed. 

The declaration of maximum generation and load management alerts without extreme temperatures raised concerns for PJM that load growth and renewable penetration could jeopardize resource adequacy. During the Aug. 5 Planning Committee meeting, PJM said it had initiated 11 maximum generation and load management alerts in 2025, more than the prior decade combined. 

The first heat wave saw maximum generation and load management alerts July 15 and 16, which Hatch said included notifications to neighboring balancing authorities that off-system sales could be curtailed. 

A generation maintenance outage recall was issued ahead of the second heat wave, followed by hot weather alerts starting in PJM West on July 22 and for the whole RTO the following day. Maximum generation and load management alerts were issued for July 24, 25, 28, 29 and 30. Pre-emergency load management was called July 28 for the BGE, PEPCO and Dominion zones, expanded to the full RTO the next day, when all available long- and short-lead DR was called. 

Synchronized Reserve Performance Inquiry

The Independent Market Monitor presented the results of a poll of resource owners who saw their units underperform during the July 1 synchronized reserve performance inquiry, which saw 79.5% response for individual resources. The event lasted 10 minutes and 38 seconds, with 2,398 MW of generation and 544 MW of DR assigned.  

Joel Romero Luna, of Monitoring Analytics, said the owners of 33 underperforming resources were contacted and responses covered 20 units. The single-largest identifiable cause of those units’ shortfall was inaccurate parameters having been submitted, accounting for around 50 MW of the 581-MW shortfall. Around 225 MW of shortfall was categorized into an “other” category due to the number of resource owners falling below the confidentiality requirement of at least four generation owners providing the same information, allowing anonymized aggregation. 

He said outreach to generation owners is continuing with the goal of increasing the response rate. 

July Operating Metrics

PJM saw an average hourly forecast error of 1.7% for July and an average peak error of 1.78%, according to the RTO’s monthly operating metrics. The 3% daily peak error benchmark was exceeded three days, with over-forecasting on July 19, 24 and 26 attributed to storms causing load to come in lower than expected. 

The month saw four spin events, two shared reserve events, seven maximum generation and load management alerts, five pre-emergency load management reduction actions, seven shortage cases, 10 hot weather alerts and 39 post-contingency local load relief warnings. All the shortage cases occurred July 28, with one primarily due to generation loss and six due to solar generation falling faster than load was expected to decline between 6:59 p.m. and 7:25 p.m. 

Two of the spin events exceeded 10 minutes, allowing the RTO to begin measuring a rolling average to track synchronized reserve performance for the purpose of potentially backing down a 30% adder to the reserve requirement. PJM established the adder in May 2023 to address poor reserve performance, which PJM aimed to address through changes to reserve deployment implemented in December 2024.  

In March 2025, PJM began measuring reserve performance, backdated to December 2024, and created a paradigm under which the adder could be reduced if reserve performance is above 75% across a rolling average of three events exceeding 10 minutes.  

Under that model, the adder would be reduced by 10% if performance across the rolling average is between 75 and 85%. It would be reduced by 20% if the average is between 85 and 95%, and it would be eliminated at performance above 95%. The adder could be increased by 10% if performance falls below 75%, but the reserve requirement must remain within a 100-to-130% band. (See PJM OC Briefs: March 6, 2025.) 

The July 1 and 22 events, paired with a spin event Feb. 5, carry an average of 74.4% performance, meaning the adder remains untouched. For the next event to reduce the adder by 10%, performance would need to be 66.7% or greater; performance at 96.7% or greater would result in the adder being reduced by 20%. 

The July 22 event lasted 10 minutes and 32 seconds and saw 2,764 MW of generation and 548 MW of DR assigned, with performance at 79 and 80% respectively. A July 30 event last 5 minutes and 57 seconds, with 3,588 MW of generation and 328 MW of DR assigned, with performance at 59 and 72% respectively; the next day another spin event was declared lasting 6 minutes and 16 seconds, with 2,802 MW of generation and 582 MW of DR assigned, with 45 and 63% performance. 

Generation Deactivation Manual Revisions

The Operating Committee endorsed by acclamation revisions to Manual 14D: Generator Operational Requirements to rework the requirements for a resource requesting deactivation. The proposal will advance to the Markets and Reliability Committee for a first read at its Aug. 20 meeting, followed by endorsement on Sept. 25. (See “1st Read on Manual Revisions Detailing Generation Deactivation Process,” PJM OC Briefs: July 10, 2025.) 

Resource owners would be required to provide PJM with at least one year’s notice before going offline and follow the must-offer exemption process if they are seeking to not participate in the capacity market. The proposal also expands transparency requirements, mandating that resource owners entering into a reliability-must-run agreement with PJM provide the RTO and the Monitor with an estimate of the costs that would be recovered under the agreement, which would be publicly posted. Ongoing monthly updates would be required during the term of the RMR agreement. The Monitor also would publicize market power letters. 

The language would remove a $2 million cap on project investments allowable under the deactivation avoidable cost credit (DACC) compensation methodology, limit the adder for investments to 10% and remove language causing the credit to be determined through the daily deficiency rate rather than the deactivation avoidable cost rate (DACR) when the DACR and applicable multiplier exceed the deficiency rate. 

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PJM Initiates Load Shed in Baltimore Region After Substation Disconnect

PJM initiated a load-shedding event Aug. 11 in the Baltimore Gas and Electric (BGE) region after the Brandon Shores substation went offline.

A PJM announcement states that the substation “experienced an unplanned disconnection” in the morning, after which transmission capability into the region was limited for much of the day and consumers were asked to conserve energy.

A voltage reduction action was initiated at 2:15 p.m. followed by a load-shed directive at 3:52 p.m. PJM’s emergency procedure page states that the directive was initiated due to an N-5 cascade risk identified on the Chestnut-Fredrick Road 115-kV line in BGE. The load-shed directive lasted 28 minutes, ending at 4:20, while the voltage reduction ended at 5:09.

“While BGE worked to address the transmission outage, electricity demand briefly exceeded the current capacity of the local transmission system as demand peaked in the afternoon. To prevent damage to equipment and the risk of cascading outages across a broader area, at 3:52 p.m. Eastern, PJM directed BGE to lower flows across overloaded lines by reducing electricity load. BGE concurred and implemented its load-reduction plan, resulting in limited outages,” PJM said in a notification to members.

Since the load shed was limited to BGE and did not extend to a full sub-zone, a performance assessment interval (PAI) was not initiated. PJM stated that some versions of its app incorrectly notified users of a PAI trigger.

BGE reported to PJM that transmission equipment that had been “inoperable” for much of the day had been brought back into service after the load-shed directive, allowing the action to be terminated. As of the 6:36 p.m. communication, some equipment still was offline.

“We expect that BGE will soon be returning to service those customers who were shed as part of our original directive. Continued reliable operation of the local transmission system will depend upon the operability of the transmission facilities that tripped this morning, but for now, the system is in a place such that we can serve our peak evening demand in the area,” PJM said.

The most recent load shed PJM had entered occurred on June 15, 2022, when storms damaged multiple transmission lines and put 200,000 customers along three 138-kV lines out of power. Following the December 2022 Winter Storm Elliott, PJM said it was one generation trip away from possibly having to implement a voltage reduction action. (See PJM Orders Load Sheds in AEP Following Storms and PJM Recounts Emergency Conditions, Actions in Elliott Report.)

Limited transmission capability in the Baltimore region contributed to the need for PJM to enter into a reliability-must-run (RMR) agreement with Talen Energy after it requested to deactivate its 1,289-MW Brandon Shores and the adjacent 843-MW H.A. Wagner generators.

Transmission violations identified with those units offline led to several transmission projects being added to the Regional Transmission Expansion Plan and a $180 million annual agreement to keep the two generators online.

The region also saw capacity prices surge above the rest of the RTO due to limited capability to import power from the rest of PJM. (See FERC Approves $180M Annually for RMR Deals with Brandon Shores and Wagner Plants and PJM Market Participants React to Spike in Capacity Prices.)

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Pa., Va. Governors Float Clements, Christie as PJM Board Candidates

Pennsylvania Gov. Josh Shapiro (D) and Virginia Gov. Glenn Youngkin (R) have requested that PJM consider former FERC Commissioners Mark Christie (R) and Allison Clements (D) to fill two vacant seats on the RTO’s Board of Managers.

“Last month, we joined seven of our fellow governors in urging PJM to begin to restore purpose and vision for the organization, independent from the wishes of any particular sector, by tapping nationally respected leaders to fill the two vacant board seats,” the governors wrote in a letter to the RTO on Aug. 11. “That diverse group of governors strongly urged PJM to appoint a bipartisan slate of energy luminaries: recently retired FERC Chairman Mark Christie and former FERC Commissioner Allison Clements.”

Nine governors signed onto a July 16 letter to PJM calling for a process for states to nominate candidates to the board and requesting a meeting with the RTO’s Nominating Committee. Virginia Energy Director Glenn Davis attended the Members Committee’s meeting to reiterate the governors’ concerns, saying they had candidates in mind. (See State Governors Seeking Ability to Nominate 2 Members to PJM Board.)

“Christie and Clements are widely respected leaders who understand the problems facing PJM and the region,” Shapiro and Youngkin wrote. “They have the independence and know-how to chart a principled new direction for the organization. We believe their appointments will begin to restore transparency and accountability to decision-making at PJM.”

They argued that PJM’s stakeholder process — with more than 1,000 voting members and requiring a supermajority for action — has resulted in a stalemate in recent years, requiring the Board of Managers to take unilateral action, which they suggested contributed to the ouster of two board members in May, including Chair Mark Takahashi. (See PJM Stakeholders Vote Out 2 Board Members.)

The nine governors also seek to create an association to engage in dialogue between their offices and PJM leadership. They plan to hold a technical conference Sept. 23 at the National Constitution Center in Philadelphia to discuss “organizational and market reforms at PJM.”

Shapiro and Youngkin wrote that failing to consider candidates recommended by the governors would undermine confidence in PJM’s governance.

Former FERC Chair Mark Christie | © RTO Insider 

“As governors from different parties, we have points of disagreement on energy policy, but we are united by the need to get PJM back on track to fixing the problems we collectively face,” they wrote. “By working together with a diverse, bipartisan coalition of governors, we are committed to solving these collective problems, and to ensuring that the citizens of our states and the region receive the affordable, reliable power that they deserve.”

Christie left FERC on Aug. 8 after serving for more than four years, including being chair since Jan. 20. (See FERC Chair Mark Christie Leaves Agency After One Last Dissent.)

Clements served from late 2020 until June 30, 2024, when she was replaced by Commissioner Judy Chang. (See Senate Confirms Chang as Clements’ Replacement on FERC.) She now works as a senior adviser for the consultancy Capstone, as a partner with digital infrastructure advisory firm ASG and as principal of 804 Advisory.

Neither could be reached for comment.

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Interim Deliverability Proposal, PJM PC/TEAC Briefs: Aug. 5, 2025

Planning Committee

PJM Proposes Widening of Interim Deliverability Study Procedures

To increase energy supplies, PJM proposes expanding its process for allowing new resources to inject onto the grid while their required network upgrades are being completed, allowing a unit to operate partially.  

The proposal includes two issue charges to rework the interim deliverability study process and expand provisional interconnection service. 

PJM Director of Interconnection Planning Donnie Bielak said the RTO’s aim is to create a path for generators that fail interim deliverability studies but are able to inject some energy without causing network overloads, to operate as energy-only until they complete their full network upgrades. When an interim deliverability study identifies a local constraint affecting the ability for the resource to operate, an operational guide would be produced detailing the conditions under which dispatchers could use the unit. 

Bielak said the impetus for the change is a surge in Energy Emergency Alert (EEA) Level 1 actions the RTO has initiated this year. The maximum generation and load management alert, the trigger for entering EEA-1, has been used 11 times in 2025, outnumbering all declarations since 2016. 

“This is a pretty striking uptick in the use of this emergency procedure, which is only underscoring the need for more generation to be available to our control room,” he said. 

Under the proposal, the deadline for developers to request an interim deliverability study would be pushed back from July 31 to June 30 to provide staff with more time to complete the studies. Developers would continue to cover the cost of their administration. 

Paul Sotkiewicz, president of E-Cubed Policy Associates, welcomed the change and said it should have been pursued earlier, but faulted PJM for advancing it through the quick-fix process, which allows an issue charge and solution to be voted on concurrently. He argued the proposal cannot be made through manual revisions alone and would require tariff changes as well. 

John Rohrbach, representing Southern Maryland Electric Cooperative, noted that, under PJM’s rules, resources without a capacity commitment have no accompanying day-ahead and real-time energy market must-offer obligation, making their market participation voluntary — a point on which Bielak agreed. 

Stakeholders Endorse Revisions to PJM Protection Standards

The Planning Committee endorsed revisions to Manual 07: PJM Protection Standards to add a section saying the circuit cases studies produced by PJM planning staff should not be used in isolation. The language recommends generation owners (GOs) coordinate with the transmission owners (TOs) serving their points of interconnection, while TOs should coordinate with their neighbors. 

The revisions also seek to expand relay communication requirements, add reporting open circuit conditions for station batteries and include additional detail on transformer high-side lead protection. 

Relay Plans Endorsed

The committee endorsed a proposal to sunset the Relay Testing Subcommittee (RTS) and roll its work into the Relay Subcommittee (RS). 

The revisions to the RS charter also seek to clarify the group is open only to NERC-registered transmission or generation owners in the PJM region who are signatories to the RTO’s operating agreement. Attendees are required to hold critical energy/electric infrastructure information (CEII) clearance. Invited guests are permitted to attend. 

Addition of ELCC Classes Endorsed

Stakeholders endorsed manual revisions codifying the addition of two generation categories to be modeled under PJM’s effective load-carrying capability (ELCC) analysis. The concept was greenlit by the Markets and Reliability Committee at its March meeting and approved by FERC (ER25-1813). (See PJM Stakeholders Endorse Proposals to Rework ELCC Accreditation.) 

The language breaks oil-fired combustion turbines out of the catchall “other unlimited resource” category, putting them in their own bucket, and establishes waste-to-energy steam generation as an independent class from “steam.” The latter would be renamed to “other steam” as part of the change. The changes will be effective for the 2027/28 delivery year. 

During the June MRC meeting, PJM presented ELCC values for the 2027/28 auction that rate oil CTs at 80% and waste-to-energy generation at 83%. The PJM Board of Managers approved parameters for the RTO’s Base Residual Auction derived in part from those ratings, contravening stakeholder opposition rooted in arguments that the ELCC methodology lacks transparency. (See PJM Stakeholders Reject 2027/28 Capacity Auction Parameters.) 

The rating for oil CTs fell by 5% over initial estimates PJM presented at the March MRC meeting, while the waste-to-energy class rating remained the same. Those values were based on the 2025/26 third Incremental Auction (IA). 

Transmission Expansion Advisory Committee

Market Efficiency Update

PJM has received several proposals to address congestion under the 2024/25 market efficiency window 1, which opened on April 11 and closed June 10. The window identified congestion on the Museville-Smith Mountain 138-kV line driven by expected load growth, and renewable development affecting the West Point-Lanexa and Garrett-Garrett Tap 115-kV lines. 

Six projects focus on the Museville-Smith Mountain line, with three greenfield proposals costing between $270 million and $1.6 billion and three upgrades between $1.8 million and $131.6 million. Seven projects address the West Point-Lanexa congestion, including two battery storage proposals costing between $83.9 million and $221.7 million, three upgrades between $28.1 million and $90.9 million and two substation expansions between $21.4 million and $23.4 million. One update was proposed for Garrett-Garrett Tap with a $9.9 million cost. 

Supplemental Projects

FirstEnergy presented a $20.4 million project in the Met-Ed zone to resolve low voltage identified in a contingency where two 230/69-kV transformers at the South Reading substation are offline. The project would install a new 230/69-kV transformer, a 69-kV grounding transformer, two new 230-kV circuit breakers, a 69-kV breaker and new relaying. It has a projected in-service date of Feb. 15, 2027, and is in the conceptual phase. 

The utility also revised the scope of a project to rebuild the 7.2-mile Penelec section of the Ashtabula-Erie West 345-kV line to address maintenance issues with insulators and H-frame structures. The project now  to is proposed to include replacing disconnect switches at Erie West and revise relay settings at Ashtabula, increasing the cost from $38.7 million to $52.4 million and pushing the in-service date from April 9, 2027, to May 31, 2027. 

Exelon presented a $24.4 million project to replace a 345/138-kV transformer at its Skokie substation in deteriorating condition and with a possibly loose core/coil assembly. The first phase would install a new 138-kV, 115.2-MVAR capacitor bank, followed by removal of the tertiary 34-kV capacitor bank and replacement of the transformer and a 138-kV circuit breaker. 

AEP presented several new service requests to serve large loads across Ohio, including a: 

    • 1,000-MW customer near the Hanging Rock substation in Scioto County by March 1, 2029; 
    • 1,200-MW load near the Muskingum substation in Waterford by Nov. 1, 2028;
    • Customer near the East Lima substation in Lima seeking service for 500 MW by Dec. 31, 2028, which is expected to ramp to 900 MW;
    • 300-MW load near the East Lima-Fostoria Central 345-kV line in Findlay by Sept. 30, 2028; and 
    • 500-MW customer south of the Maddox Creek substation in Van Wert by Dec. 31, 2028. 
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EPRI, Epoch AI Estimate Power Demands of Artificial Intelligence

A new report by EPRI and Epoch AI estimates U.S. power demand by artificial intelligence could jump from 5 GW today to more than 50 GW by 2030.

The sharp rise is due not only to the growth in the amount of large-scale training but also its increasing duration, and is tempered only partly by hardware efficiency improvements, the two organizations said in their Aug. 11 announcement of “Scaling Intelligence: The Exponential Growth of AI’s Power Needs.”

Beyond large-scale training, more power capacity will be needed for AI research and for the actual use of finished AI models. But the training needs alone are formidable: Power consumption for training cutting-edge AI models is doubling annually.

“Frontier AI training runs — the computationally intensive process of training large, advanced AI models — currently consume approximately 100-150 MW each and are projected to reach 1-2 GW each by 2028, exceeding 4 GW per training run by 2030,” the authors write.

Training duration is assumed to have a 10% to 20% annual growth rate in the future. This compares with 25% to 50% in recent years. Increasing the duration can spread the same amount of power use across over a longer period, smoothing out peak demand. But the authors say durations now exceed 100 days, so further increases may yield diminishing returns.

Meanwhile, for the study, hardware efficiency is assumed to improve 33% to 52% annually.

The authors say the split of demand between training AI models and using them is important, as it could affect the size, location, power demands and potential flexibility of AI data centers. But it is currently uncertain, and the landscape is changing rapidly.

Some forecasts show AI consuming more than 5% of U.S. generation capacity by 2030, with some training runs equivalent to the output of entire power plants.

As has been noted many times, meeting such a level of peak demand just with new capacity could be quite challenging and extremely expensive. Some flexibility of demand during peak periods would help make the process less expensive and difficult.

The authors suggest: “Planning should account for both concentrated and distributed data center loads as well as the potential for real-time flexibility in training and inference workloads and from on-site generation and storage assets.”

“Inference” — usage of a trained AI model, such as generating responses to user requests — could support more flexibility than AI training.

The authors state that the rapid rate of growth of AI computing seen recently and projected in the next several years almost certainly must slow by the 2030s, because it is accompanied by a growth in cost that is not quite as rapid but is nevertheless unsustainable.

Whether that slowdown starts before 2030 may depend on technical innovations, data constraints or diminishing returns to scaling, they write.