PJM’s markets provided reliable service in 2024, but tightening supply and demand are laying bare design flaws that have inhibited the competitiveness of the RTO’s markets, the Independent Market Monitor wrote in its 2024 State of the Market Report on March 13.
During a press briefing ahead of the publication of the report, Monitor Joe Bowring detailed several drivers behind the total price of wholesale power increasing 4.6% in 2024. Those include transmission service costs increasing from $10.7 billion in 2023 to $11.8 billion in 2024 and day-ahead energy costs going from $23.9 billion to $26.2 billion.
The real-time load-weighted average LMP was $33.74 in 2024, an 8.6% increase that Bowring largely attributed to PJM improperly applying the transmission constraint penalty factor (TCPF). He said that when lines are close to being overloaded, RTO staff will reduce their ratings by 5% in the security-constrained economic dispatch software, which leads to the TCPF being triggered more frequently and pushing prices to the $2,000/MWh cap. That practice, he said, accounted for $3.01 of the average LMP and 52.4% of the increase in 2024. Ancillary service redispatch costs contributed an additional 31.2%, and higher fuel and consumable costs accounted for 18.9%.
PJM spokesperson Jeff Shields said the RTO is reserving its comments on the report for its formal response. Wholesale consumer costs are also set to the discussed at the Public Interest and Environmental Organizations User Group meeting March 20.
The report found the energy market was overall competitive and effective, though increased ownership concentration in the local market led it to not be competitive, and the aggregate market was only partly so. In the more granular markets, the Monitor wrote that transmission constraints can create opportunities for market power. Market participant behavior was competitive, the Monitor wrote, with marginal units typically making offers close to their marginal costs — though some economic withholding was identified both under normal market conditions and at high demand.
The report said market sellers have been able to avoid being mitigated to their cost-based offers by submitting inflexible parameters or positive markups, an issue it said had LMPs. It also argued there are no mitigation protections in the aggregate market and that the application of market power rules in the local market need improvement. It recommended that PJM expeditiously implement its proposal to schedule any resources that fail the three-pivotal-supplier market power test on their cost-based offers. (See “Schedule Selection Formula Endorsed,” PJM MRC Briefs: July 24, 2024.)
Bowring noted another of the Monitor’s recommendations is being pursued by PJM in a joint package of proposals that would revise how uplift and deviation charges are assessed. It would prevent resources not following dispatch from receiving uplift payments and introduce a Tracking Ramp Limited Desired MW metric looking at how resources respond to instructions over time. (See “First Read on Proposal to Overhaul Uplift,” PJM MIC Briefs: March 5, 2025.)
Capacity Market
The Monitor’s outlook on the capacity market was dimmer. Overall, aggregate and local market structure was determined to be noncompetitive, as was participant behavior. The report faulted PJM’s rollout of marginal effective load-carrying capability for resource accreditation; resources categorically exempt from the requirement that market sellers offer into Base Residual Auctions withholding their capacity; gas generators being capped at their summer ratings; resources operating on reliability-must-run contracts not being required to offer into the market; and a maximum price set at the gross cost of new entry rather than 1.5 times net CONE.
The Monitor said the ELCC paradigm adds risk and volatility to the capacity market and recommended revising the model to use unit-specific data; match supply and demand in every hour of the year; and recognize actual unit performance and availability, rather than modeling performance simulated on data from a limited number of past performance assessment intervals. During the Critical Issue Fast Path process in 2023, the Monitor’s proposal to increase the granularity of the capacity market centered around evaluating resources’ ability to deliver capacity in every hour. Unit-specific accreditation remains a topic of discussion at the ELCC Senior Task Force. (See “Monitor Proposes Hourly Model with Annual Pricing,” PJM Stakeholders Finalize CIFP Proposals Ahead of Vote.)
While the Monitor lauded FERC’s Feb. 20 approval of a PJM proposal to eliminate the categorical must-offer exemption for intermittent and storage resources, it faulted an element of the package allowing market sellers to request a unit-specific offer cap set at a unit’s Capacity Performance quantifiable risk value without any net revenue offset. In comments on the filing, it argued that not accounting for energy and ancillary service revenues in the offer cap would undermine the purpose of the capacity market: to provide the missing money resources require to be available as capacity (ER25-785).
While supply and demand are tightening, Bowring said capacity prices in the 2025/26 BRA were double what would reflect a competitive offer under the market conditions. He attributed much of that to the exclusion of intermittent, storage and RMR resources from the supply stack, as well as the capping of gas generators at their summer ratings. Given that the majority of reliability risk is now concentrated in the winter, when gas units may perform better, he argued that as much as 20% of gas capacity is not recognized. (See PJM Market Monitor Releases Second Section of 2025/26 Capacity Auction Report.)
Bowring expressed support for an agreement PJM reached with Pennsylvania Gov. Josh Shapiro to set the maximum capacity clearing price at $325/MW-day, which would be roughly in line with the Monitor’s recommendation that the maximum price be defined as 1.5 times net CONE. The inclusion of a $175/MW-day price floor, however, could distort market outcomes, he said. (See PJM Presents Capacity Price Cap and Floor to Members Committee.)
Bowring said market signals cannot incentivize new generation without changes to PJM’s interconnection planning processes. He said the Monitor strongly supports the RTO’s Reliability Resource Initiative, which FERC approved to allow 50 projects ranked on their capacity contribution and in-service dates to be added the Transition Cycle 2 (TC2). The initiative’s goal of expediting resources that can quickly bring large amounts of capacity could be expanded by creating a permanent process that fast tracks new projects that would mitigate defined reliability needs. While Bowring said that could include general resource adequacy, it could also mitigate the need for transmission expansion and RMR agreements when generators retire. (See FERC Approves PJM’s One-time Fast-track Interconnection Process.)
The synchronized reserve market and its regional elements were determined to be noncompetitive because of ownership concentration in the Mid-Atlantic Dominion subzone. The market design was rated as flawed because of PJM unilaterally extending the operating reserve demand curve with a 30% adder in 2023. Deputy Monitor Catherine Tyler said the report includes new recommendations on reserves: Require that resources have automatic generator control (AGC) technology installed to be eligible to be synchronized and primary reserves, and eliminate the adder. During the March 6 Operating Committee meeting, PJM presented a plan to scale the adder back if reserve performance improves across three consecutive deployments, with the hope that changes to how it uses AGC during reserve deployments will improve performance. Tyler said that so long as not all reserve resources are required to have electronic communications installed, the impact of those changes will be muted. (See PJM OC Briefs: March 6, 2025.)
Bowring said that when the Monitor reached out to underperforming resources, it found that some were not getting the all-call phone call for as long as seven to eight minutes into a 10-minute deployment.
“The technology was outdated. … There’s been some improvements there, but not enough, and that requirement needs to be extended to everybody,” he said.
Bowring also argued that significant amounts of congestion revenue that is owed to consumers is being diverted through financial transmission rights auctions. If load held recognized property rights over congestion, some customers might be willing to sell variable congestion in return for a more predictable payment. But without the ability to set strike prices or receive all revenues from a sale, that capability does not currently exist. Total congestion in 2024 amounted to $1.75 billion, up 64.2% over the prior year, but 69.9% of that was paid to customers through auction revenue rights and the self-scheduled FTRs revenues offset.
“The goal of the FTR market design should be to ensure that customers have the rights to 100% of the congestion that customers pay. Customers have received $4.6 billion less in congestion revenues than load should have received, from the 2011/2012 planning period through the first seven months of the 2024/2025 planning period, as a result of flaws in the PJM FTR market design,” the Monitor said in the report’s announcement.
