The Maryland Office of People’s Counsel (OPC) has published a report on how a spike in capacity prices and generator deactivations will affect state ratepayers, finding monthly costs could increase by as much as 24% for some.
The largest share of the impact is due to the significant jump in Base Residual Auction clearing prices seen in the 2025/26 auction results released last month, which saw prices across the RTO reach $269.92/MW-day from $28.92/MW-day the year prior. The Baltimore Gas and Electric (BGE) region surged higher to $466.35/MW-day due to a lack of internal generation, and transmission constraints. (See PJM Capacity Prices Spike 10-fold in 2025/26 Auction.)
At the same time, ratepayers are expected to cover the cost of a reliability-must-run (RMR) agreement to pay Talen Energy to keep its Brandon Shores and H.A. Wagner generators operational while transmission upgrades are built to accommodate the plants’ deactivations. Talen has requested $774 million in a pending FERC filing to keep the generators online (ER24-1787, ER24-1790). (See FERC Orders Settlement Judge Procedures in Two PJM Generator Deactivations.)
The cost of those transmission upgrades also likely will fall squarely on Maryland ratepayers: Of the $726 million in upgrades required before the Talen generators can retire, 81%, or $630 million, is estimated to be allocated to the state. (See FERC Approves PJM RTEP Projects over State Protests.)
In an announcement of the report, Maryland People’s Counsel David Lapp said the same resource deactivations are hitting Maryland ratepayers on multiple fronts, raising capacity costs and saddling them with high transmission upgrade and RMR costs while those plants are paid to remain idle, but not contributing capacity.
“Customers are facing massive rate increases from potential retirements of old and uneconomic fossil fuel power plants — potential retirements that were entirely foreseeable and that PJM should have planned for,” Lapp said. “Customers will bear the brunt of PJM’s planning failures and other dysfunctional market rules, while generation companies will walk away with record profits.”
Conducted by Synapse Energy Economics on behalf of the OPC, the analysis estimates that BGE rates could increase by 5% to cover the RMR costs and an additional 14% due to the higher capacity costs, which amounts to an additional $21 for the average residential customer. The capacity market impacts also will be felt in the APS, DPL-S and Pepco zones, which could see rates increase by 24, 2 and 11%, respectively.
Taking Brandon Shores and Wagner out of the capacity market had a significant impact on prices in the BGE zone, Synapse wrote, stating that in the years running up to the 2025/26 auction, about a third of the capacity consumed in the region was produced locally. Removing the two generators brought that figure down to about 10%. The report estimated that if Brandon Shores and Wagner had remained in the capacity market, the BGE zone would not have seen price separation from the rest of the RTO, which would have seen the clearing price halved to $163.46/MW-day.
“At that price, electric customers across the RTO would save over $5 billion in that delivery year. Further, comparing this counterfactual analysis to the actual results of the capacity market and Talen’s proposed RMR, we found that Talen’s revenues for the 2025-2026 delivery year are $360 million higher than what they would have been had Talen’s units participated in the capacity market,” the report said.
Lapp said a small number of deactivations are causing an outsized spike in rates.
“The fact that the retirement of such a relatively small amount of generation could cause capacity market price spikes that cost customers across PJM more than $5 billion shows … PJM’s market is stacked against the customers that pay the bills,” Lapp said.
Market Changes and Queue Backlog Contributing to Higher Prices
The report notes that several changes to the capacity market structure were implemented in the 2025/26 BRA, including using a marginal effective load carrying capability (ELCC) approach to accrediting resources and risk modeling that shifted the riskiest hours toward the winter. Those redesigns had the effect of shifting the variable resource rate (VRR) curve to the left, reducing available supply and likely increasing costs. Forecast peak loads also increased by over 3 GW in the 2025/26 delivery year, increasing demand. (See FERC Approves 1st PJM Proposal out of CIFP.)
The report also argues that PJM has left customers vulnerable to high prices by delaying capacity auctions while rule changes are implemented, compressing the auction schedule and leaving little time for generators to be planned to take advantage of high prices and to increase available supply. Under the current schedule, the 2026/27 BRA is scheduled to be conducted in December, 1.5 years before that delivery year begins. Paired with a backlogged interconnection queue, it says it’s unlikely any large generators will come online before Brandon Shores and Wagner are set to deactivate in 2028, potentially leaving high prices in place for years.
“Thus, the strong price signal sent by the high-capacity market prices in the BGE LDA (and the RTO as a whole) may not induce timely new generation into service within the LDA before the completion of the transmission lines that end the need for these RMRs (or to help alleviate prices seen across the region). Instead, the clogged queue could lock in a windfall for the existing generating units continuing to operate in the BGE LDA and across the PJM region generally,” the report says.
There are 13 projects pending in the interconnection queue that would be sited in the BGE zone, amounting to about 1.2 GW of capacity. Construction on those projects could begin in mid-2025, according to PJM’s queue timeline, to begin mitigating capacity prices in 2026/27. The amount of time needed for construction, though, could result in many units coming online after that auction. Historical completion rates also suggest a share of those projects will be canceled, the report says.
The report states there’s a great deal of uncertainty on the transmission side, stating that 3.5 years to complete the upgrades necessary to allow the Talen generators to retire without issue could prove to be too short. If more time is needed, the RMR agreement could be extended.
“If the transmission projects are not complete by the end of 2028, and/or the continued operation of the RMR units are required beyond December of that year, the RMR costs for electric customers would necessarily increase,” the report said.
Deputy People’s Counsel William Fields told RTO Insider he doubts there will be time for the price signal sent in the 2025/26 auction to lead to new resources coming online ahead of future auctions. The interaction of a backlogged interconnection queue and compressed auction schedule leaves ratepayers with the worst of both worlds: paying generators to remain online without them being in the capacity supply stack to offset auction prices.
“A price signal without an ability to respond to it doesn’t accomplish much other than customers paying more money,” he said.
He said concerns about the auction outcome were mounting ahead of the posting of the results, leading the OPC to commission the report. While the spike in prices will have a significant impact, he said transmission costs have been steadily making up an increasing share of consumers’ rates. Some of those new projects could lead to reduced congestion, but whether that will come to pass is not yet apparent.
Stakeholders Discussing Changes to RMR Rules
PJM stakeholders are considering changing several areas of how RMR agreements function, including the timeline generators must provide PJM ahead of their desired deactivation date, how the compensation rate is determined and possible alternatives to the RMR structure. The Deactivation Enhancement Senior Task Force met Aug. 19 to discuss proposals from the Independent Market Monitor and PJM that would seek to use actual incurred costs to be the basis of RMR compensation.
The OPC sought a wider scope for the task force, including education on transmission technologies, such as energy storage or grid-enhancing technologies (GETs), that can provide an alternative to traditional upgrades, comparable structures RTOs employ to keep resources online when they are needed for transmission reliability and cost-effective alternatives to RMRs. (See “Consumer Advocates Seek Wider Scope for Deactivation Task Force,” PJM MRC/MC Briefs: June 27, 2024.)
The office also has advocated for proposals that require RMR resources to participate in the capacity market, which both the Monitor and PJM have declined to include. In a May protest of Talen’s RMR filing, the OPC argued the agreement would not subject the generators to the same performance requirements resources participating in the capacity market are held to, raising the question of whether they would be capable of responding to a PJM deployment. (See FERC Orders Settlement Judge Procedures in Two PJM Generator Deactivations.)
The Planning Committee also is considering proposals on how revising capacity interconnection rights (CIRs) can be transferred from a deactivating generator to a new resource. One aim would be reducing the need for RMR agreements by creating an expedited process for planned resources that could resolve identified transmission violations. The five packages are slated to be voted on during the Sept. 10 PC meeting. That could, however, be delayed to October if the components are changed substantially. (See “Manual 14B Revisions Include Change to Light Load Model,” PJM PC/TEAC Briefs: Aug. 6, 2024.)
