PJM Capacity Prices and Data Center Load Growth

PJM runs a forward capacity market, the Reliability Pricing Model, that pays generators, storage and demand response to be available during peak conditions. The main event is the Base Residual Auction (BRA), which procures capacity for a delivery year that runs from June through May. The auction sets a clearing price in dollars per MW-day, and load-serving entities pass those costs to customers.¹

Capacity is separate from energy. A data center pays for energy on every megawatt-hour it uses, and separately pays a capacity charge based on its share of the system peak. For a large, flat load running near full output during summer peaks, capacity can be a material share of the delivered power cost. Our guide to electricity rates for data centers covers the other bill components, and PJM data center site selection covers the regional market structure.

The auction is also a resource adequacy signal. When it clears short of the reliability requirement, that tells utilities and regulators the region does not have enough committed supply for forecast peak load, which shapes how quickly they are willing to connect new large loads.

The 2025/2026 auction, held in 2024, cleared at a record $269.92 per MW-day across most of the footprint, up from $28.92 the year before.⁶ Two zones with large data center concentrations cleared higher still: Baltimore Gas and Electric at $466.35 and Dominion at $444.26, reflecting limited supply inside those zones and transmission limits on imports.⁶

The next three auctions all hit the cap: $329.17 for 2026/2027 and $333.44 for 2027/2028.² The 2027/2028 auction fell 6,623 MW short of the reliability requirement, the first time the RTO as a whole came up short, and PJM said peak load for that year was forecast about 5,250 MW higher than in the forecast used for the 2026/2027 auction, with nearly 5,100 MW of the increase from data centers.¹¹

The 2028/2029 auction, announced July 14, 2026, cleared at the $325 cap across the entire footprint. It procured 138,318 MW of generation and demand response, plus 10,864 MW under Fixed Resource Requirement plans, for 149,182 MW in total, and still fell 6,831 MW short. Total procurement cost was $16.4 billion, and PJM estimated the uncapped price at $554.72 per MW-day.¹¹²

The cap is not a market outcome. After the 2025/2026 price spike, PJM filed in February 2025 to lower the cap from roughly $500 to about $325 per MW-day, with a floor near $175, for the 2026/2027 and 2027/2028 auctions.⁴ PJM proposed an extension in February 2026, and FERC accepted it in April 2026 for the 2028/2029 auction and the 2029/2030 auction that closes on December 15, 2026, with a cap near $325 and a floor near $175 per MW-day, both adjusted annually for the accreditation of PJM’s reference resource.⁴

For a site underwriting a 15- or 20-year load, that leaves a gap. The collar covers delivery through May 2030. After that, absent another extension or market redesign, PJM’s uncapped estimate of $554.72 per MW-day for 2028/2029 is a reasonable stress case for what tight supply could produce, though new generation, demand response or rule changes could pull prices down.¹ Treat capacity cost beyond 2030 as a range, not a number.

PJM’s independent market monitor, Monitoring Analytics, has repeatedly tied the price increases to data center load. It attributed $6.5 billion, or 40%, of the $16.4 billion 2027/2028 cost to data center load.¹³ For 2028/2029, its president attributed about $6.3 billion, or 38%, of $16.4 billion in charges to data centers.³ Across the last four base auctions, he put data-center-driven capacity charges at $29.4 billion, about 46% of the $63.6 billion total.³ The monitor had not yet published the analysis behind those figures when they were reported.³

The load forecast is the hinge. PJM’s 2026 long-term forecast projects summer peak of about 222,000 MW in 2036, a 10-year increase of nearly 66,000 MW, or 3.6% per year.⁷ It lowered near-term peaks through 2032 partly because of stricter vetting of requested large-load adjustments.⁷ Because the BRA buys capacity against forecast load, speculative data center requests that never get built still raise prices for everyone, which is why utilities now ask for more commitment up front. See large-load tariffs and service agreements.

In January 2026, after the Critical Issue Fast Path process on large loads, the PJM Board issued a decision covering load forecasting, bring-your-own new generation arrangements, expedited interconnection for new supply, and a reliability backstop procurement. It defined large load additions as 50 MW or more at a single point of interconnection.⁵

The Board has also sought FERC approval for curtailing new data center loads that do not bring their own capacity during capacity shortages.¹⁴ For siting, that means a project’s power position in PJM increasingly depends on whether it brings or contracts for new supply, accepts some interruptibility, or does neither. Our guides to flexible data center loads and on-site generation and bridge power cover the first two paths.

The backstop procurement was meant to fill the roughly 6.8 GW shortfall from the 2028/2029 auction.¹⁰ On September 29, 2026, FERC accepted parts of PJM’s filing but found deficiencies in cost allocation, transmission-owner exit rules and collateral requirements, suspended those provisions through February 28, 2027, and set a paper hearing.⁹ PJM delayed the auction, which had been set to begin September 30, and had not set a new timeline as of early October 2026.¹⁰

A customer’s capacity obligation in PJM is its peak load contribution: its average load during the five highest summer system peak hours, which must fall on separate days between June and September. That figure, adjusted by zonal and system scaling factors, sets the customer’s capacity obligation for the following delivery year, and the utility or supplier bills it against the zonal capacity rate.⁸ A data center running near full load in July and August will carry close to its full demand as its contribution.

Two site-level consequences follow. First, zones matter: constrained zones such as BGE and Dominion have cleared well above the RTO price when import limits bind, so a parcel’s transmission zone belongs in the screen.⁶ See Northern Virginia and Maryland. Second, the ability to reduce load in the five peak hours, through on-site generation, storage or workload shifting, has direct value under the current tariff.⁸

The table leaves out zonal scaling factors, which move the effective rate up or down, and any hedge in a retail supply contract. PJM notes that load hedged through self-supply or bilateral contracts is not directly exposed to auction clearing prices, so the contract structure decides how much of a price swing reaches the operator.¹

1. 01Identify the transmission zone and its recent zonal clearing prices, not just the RTO price.⁶
2. 02Check whether the serving utility procures capacity through a Fixed Resource Requirement plan instead of the auction.¹
3. 03Model capacity cost at the cap through May 2030 and at uncapped levels after that.⁴¹
4. 04Ask the utility how its large-load tariff handles capacity, collateral and minimum bills, and whether new loads must bring supply.⁵
5. 05Track the backstop procurement and how your state assigns its costs to new large loads.⁹¹⁰
6. 06Estimate your peak load contribution and what it would take to reduce load in the five summer peak hours.⁸
7. 07Compare against other markets with different structures, such as ERCOT under Texas Senate Bill 6.

Confirm current terms with the utility, your retail supplier and regulatory counsel before relying on any capacity forecast. If you want an independent view of a PJM parcel’s power position, you can get a site reviewed.