PJM capacity price 2027/2028: what $333.44/MW-day means for AI data centres

Summary. PJM's 2027/2028 Base Residual Auction cleared at its cap of $333.44/MW-day across the whole footprint, for the delivery year from 1 June 2027 to 31 May 2028. Because that year includes 29 February 2028, it runs 366 days, so each megawatt of capacity obligation costs $122,039 for the year, against $10,556 at the 2024/2025 price of $28.92. PJM's 17 December 2025 report shows 134,478.1 MW of unforced capacity cleared, worth $16.4 billion, leaving the region 6,516.6 MW short; without the temporary cap, PJM estimates the price would have been $529.80 ($542.83 in the Dominion zone). The 2028/2029 auction, announced on 14 July 2026, cleared at its own cap of $325/MW-day and came in 6,831 MW short. FERC has accepted, but suspended to 28 February 2027, a one-time Reliability Backstop Procurement whose costs follow large-load growth; PJM's amended version, with bids from 1 to 28 March 2027, still awaits a ruling. On 9 October 2026 FERC rejected PJM's plan to curtail new large loads that bring no capacity of their own. For AI data centre buyers, the levers are your peak load contribution, on-site or co-located supply, and contracts that say who carries capacity and backstop charges.

About this article. For data centre owners, colocation tenants and enterprise IT and finance leads with sites in PJM's region. On 13 November 2026 we checked every price, date and rule against PJM's auction reports, results workbook, planning parameters, auction schedule, manuals, Board letter and Inside Lines posts, and against FERC orders and releases. Figures are wholesale US dollar prices before utility and supplier adjustments. This is general information, not legal, tax or energy-procurement advice, and no vendor or utility paid for inclusion. Researched with AI assistance and reviewed by our editorial team.

What changes on 1 June 2027

PJM runs the wholesale grid for more than 67 million people in all or parts of 13 states, from New Jersey to Illinois and south to Virginia and North Carolina, plus the District of Columbia. Its capacity market, the Reliability Pricing Model (RPM), pays generators and demand response to be available at times of stress; your utility or supplier passes that cost to you.

On 1 June 2027 the 2027/2028 price replaces the 2026/2027 price of $329.17/MW-day, a rise of about 1.3% per day. The level is what matters: capacity costs about 11.5 times what it did in 2024/2025, and the last three auctions have all cleared at the cap.

Three facts in PJM's 2027/2028 report explain the result:

• Demand jumped. The RTO reliability requirement rose from 146,105 MW to 152,400 MW of unforced capacity (UCAP). PJM puts most of a 5,249.9 MW rise in forecast load down to additional large loads, and the installed reserve margin target rose from 19.1% to 20%.

• New supply was thin. The auction cleared only 350.7 MW of new generation and 423.6 MW of uprates. New, uprated, reactivated and imported generation together fell from 4,268.6 MW the year before to 1,919.1 MW.

• The collar held the price down. Under a FERC-approved collar, the cap was $333.44/MW-day UCAP and the floor $179.55. Offers above the cap did not clear. No zone was constrained, so every zone cleared at the same price.

The reserve margin cleared at 14.4% against a 20% target. PJM's simulation without the collar produced $529.80/MW-day and $26.3 billion of total value, $9.9 billion more than the actual result. PJM says these recent auctions are the first in its history in which the whole region fell short. Keep the uncapped figure in view when signing multi-year deals, because the collar is temporary.

Capacity prices by delivery year

Prices come from PJM's 2027/2028 report and its 14 July 2026 release; annual cost is price multiplied by days. The 2028/2029 price is lower only because the cap moved: PJM's planning parameters say the cap and floor ($325 and $175) changed with the reference resource's UCAP factor, from 77% to 79%.

The collar was set, in coordination with the governors of all 13 PJM states and FERC, for four auctions. The fourth, for 2029/2030, has a cap of $337.83/MW-day and a floor of $181.91. Its bidding window runs from 9 to 15 December 2026, with results due on 22 December 2026.

How the capacity price reaches your bill

PJM does not bill data centre operators directly. Each load-serving entity pays a Locational Reliability Charge equal to its daily UCAP obligation times the zonal capacity price, and passes it on through regulated rates or a retail contract. For 2027/2028, PJM's preliminary zonal net load price is $333.69/MW-day in every zone, fractionally above the clearing price; the final figure follows the incremental auctions.

Your share is set by your peak load contribution (PLC), sometimes called a capacity tag. The load-serving entity's obligation is the sum of its customers' PLCs times a zonal scaling factor times the Forecast Pool Requirement (FPR), which is 0.926 for 2027/2028. The scaling factor adjusts for load growth since the summer the tags were measured.

Each utility allocates its zone's summer peak to customers using its own method, typically your share of load at PJM's system peaks. PJM publishes the 5CP for this: the five highest non-holiday weekday daily peaks between 1 June and 30 September, usually released in mid-October. Ask your utility for its method in writing. Two timing points follow:

• Your 2027/2028 tag is mostly set already. Tags for a delivery year come from the previous summer, so bills from 1 June 2027 use summer 2026 peaks.

• Summer 2027 sets the 2028/2029 tag, which will be priced at $325/MW-day. Peak-shaving work done before June 2027 pays off from June 2028.

Several things change what you actually pay:

• Fixed-price retail contracts. If your supplier fixed capacity costs before the December 2025 auction, it carries the risk until renewal, unless your contract passes capacity through or has a change-in-law clause.

• Hedged load. PJM notes that the $16.4 billion auction value is not a cost to load, because load hedged through self-supply or bilateral contracts is not exposed to the clearing price.

• Fixed Resource Requirement (FRR) utilities. Some utilities meet capacity needs through their own plans rather than the auction; FRR entities committed 11,299 MW UCAP for 2027/2028. Their customers pay through regulated rates, not the auction price directly.

• Zones that left FRR. PJM's report shows the Dominion zone joined the auction from 2025/2026, and former FRR load in the DEOK zone from 2027/2028. Our Dominion GS-5 rate class guide covers how Virginia now prices large loads.

• Capacity is one slice. PJM says it is a fraction of wholesale costs, alongside energy and transmission.

Where capacity shows up, by buyer type

Worked example per MW (illustrative, 2027/2028)

This planning example uses the RTO price of $333.44/MW-day over 366 days and treats each MW of PLC as one MW of UCAP obligation. In practice the FPR of 0.926 alone would cut the figures by 7.4%, while the zonal scaling factor, which adds load growth, can push them back up; suppliers may also add margin. Treat the results as budget figures, not invoices.

Step 1: one megawatt of obligation. 1 MW × $333.44 × 366 days = $122,039.04 a year, or about $10,170 a month, which is about $10.17 per kW-month. With the FPR applied and a scaling factor of exactly 1, it would be $122,039.04 × 0.926 = $113,008.

Step 2: per MWh. Capacity is charged on your peak, so flat loads spread it more thinly.

• At a 100% load factor, 1 MW uses 8,784 MWh in the year, so capacity adds $13.89/MWh.

• At 70%, it is 6,148.8 MWh and $19.85/MWh.

• At 40%, for example an office building, it is 3,513.6 MWh and $34.73/MWh.

AI halls run nearly flat: low cost per MWh, large absolute exposure.

Step 3: three buyers.

The AI campus pays about $2.9 million more for capacity in 2027/2028 than it would have at the 2024/2025 price ($3,173,015 minus $274,451). For the colocation tenant, $170,855 a year works out to about $14.24 per contracted IT kW-month if the provider passes it through. On an all-in fixed price, the provider absorbs it until renewal.

For the enterprise, cutting 0.5 MW at the summer 2027 system peaks lowers its 2028/2029 tag; at $325/MW-day over 365 days, that saves about $59,313 (0.5 × 325 × 365). Building controls, a battery or demand response can deliver it if you can predict the peak days.

Large-load rules for 2027: what passed and what did not

Capacity price is only half the story for new AI capacity. PJM's large-load rules are changing on a timetable that overlaps the 2027/2028 delivery year, and FERC's order of 9 October 2026 changed the picture.

• The 50 MW definition is in force. The PJM Board's 16 January 2026 letter set large load additions at 50 MW or more at a single point of interconnection. FERC accepted PJM's Large Load definition and a Large Load Registry, effective 12 October 2026. Affiliated facilities within a one-mile radius count as one site, so splitting a campus does not avoid the threshold. Load-serving entities must report each Large Load to PJM, including its ramp schedule, backup generation and supply contracts.

• Connect and manage was rejected. The Board had directed a framework under which new large loads without their own new supply could be curtailed before pre-emergency demand response, with states and transmission owners choosing which loads, by the end of 2026. PJM filed it as an Interim Resource Adequacy Service, from 1 June 2027. FERC rejected that service, the rules for bringing your own new capacity, and the related definition of New Large Load (without prejudice), and gave guidance for any refiling. We found no refiled proposal on PJM's news channel by 13 November 2026.

• The Expedited Interconnection Track is open. It opened on 31 July 2026 for state-backed projects that can run within three years, with up to 10 projects a year in 2026 and 2027, each offering at least 250 MW UCAP, and a target of an interconnection agreement within 10 months. By 10 November 2026 PJM had accepted four projects totalling 2,615 MW of nameplate capacity, three of them battery storage, due online in mid-2029. The track closes at the end of 2027.

• Load forecast vetting. Utilities must remove duplicate requests and show a financial commitment; PJM defaults to a three-year ramp and, typically, 70% utilisation.

• Ride-through. On 22 July 2026 about 3,900 MW of large loads unexpectedly switched to backup generation after routine transmission events; PJM is developing ride-through requirements and NERC is drafting standards.

The Reliability Backstop Procurement

The backstop is the rule most likely to add a new line to large customers' costs. FERC accepted PJM's proposal on 29 September 2026 but suspended it for five months, to an effective date of 28 February 2027, subject to refund and further proceedings. PJM filed an amended proposal on 29 October 2026:

• Target: about 6,800 MW, the 2028/2029 shortfall, recalculated with updated data and reduced by qualifying bilateral contracts for new supply.

• Terms: commitments of up to 15 years, at a maximum MW-weighted average of $555/MW-day.

• Eligible supply: new resources only, including new demand response and distributed resources with documentation, in commercial operation by 1 June 2032. FRR entities are outside the procurement and its costs.

• Dates: distributors report new large-load quantities before the window; bids from 1 to 28 March 2027; final target on 28 April; results on 10 May 2027.

• Cost allocation: to load-serving entities based on firm large-load growth between the actual summer 2026 peak and the 2028/2029 forecast. Those entities must post credit and stay liable if they leave PJM.

A utility with heavy large-load growth since 2026 will carry more of the cost, and how it passes that on is a state question: expect riders, collateral demands or contract clauses aimed at large customers.

The table summarises status on 13 November 2026 from the PJM and FERC sources cited above.

Behind-the-meter and co-location options

FERC's order of 18 December 2025 found PJM's tariff unjust and unreasonable for co-located load. It requires the transmission customer serving a co-located load to choose from four services: Network Integration Transmission Service (NITS), a new interim non-firm service while upgrades are built, a new Firm Contract Demand service, or a new Non-Firm Contract Demand service. It also found PJM's behind-the-meter generation (BTMG) rules no longer just and reasonable, and required a transition period with grandfathering for some existing contracts.

On 18 June 2026 FERC issued large-load show cause orders to all six US grid operators, including PJM, covering co-location, behind-the-meter generation and services for flexible loads. PJM's August 2026 workshop slides say a co-located load compliance order of the same date directs the new services to co-located load and load with BTMG. Three details matter:

• Netting under NITS. Load with qualifying BTMG served under NITS can net up to 50 MW of generation against load for transmission and capacity cost allocation, with exceptions for qualifying co-generation and existing BTMG.

• Contract demand instead of netting. Load served under the new contract demand services cannot use BTMG netting, but it sets how much transmission and capacity it pays for.

• Your utility may not offer it. FERC requires PJM to offer the new services, but it does not require load-serving entities to offer them to retail customers. Ask your utility or supplier early.

In practice, five options can reduce capacity exposure. The demand response figure comes from PJM's 2027/2028 report.

Backup diesel generators are built and permitted for outages, so check your air permit before counting them in a peak-shaving plan. The US Department of Energy had by mid-October 2026 issued nine emergency orders that year letting PJM direct backup generation at data centres and other large loads to run; PJM said it had not used that power. PJM is also studying compute flexibility with Emerald AI and others, including at an NVIDIA AI factory in Manassas, Virginia. Training clusters with checkpointing can often pause for a few summer hours; inference serving live users usually cannot.

Decision table: what to do by role

Implementation checklist and dates

1. November to December 2026. Request your 2027/2028 PLC tag from your utility or supplier. Watch the 2029/2030 auction: bids 9 to 15 December, results 22 December 2026.

1. January to February 2027. Review colocation master agreements and retail supply contracts for capacity and change-in-law clauses. Watch for FERC's ruling on the amended backstop; the suspension runs to 28 February 2027.

1. 1 to 28 March 2027. The backstop bid window, if FERC allows it. Developers with new supply should prepare offers.

1. 28 April and 10 May 2027. Final backstop target, then results. Update budgets for any new charge.

1. 1 June 2027. The 2027/2028 delivery year starts at $333.44/MW-day.

1. 1 June to 30 September 2027. The system peaks in this window set your 2028/2029 tag. Run your peak-shaving plan and log results.

1. Ongoing. Track any refiled connect-and-manage proposal, co-location compliance filings and state large-load tariff cases.

Align the power plan with the rack plan; our 800 VDC data centre power guide covers rack-level changes, and the Three Mile Island restart guide explains how nuclear supply is contracted inside PJM. For siting, compare power cost, connection time and curtailment terms across markets; our Azure East US 3 guide covers one new region in Atlanta, outside PJM.

How eCorpIT can help

eCorpIT is a Gurugram-based technology organisation, founded in 2021, assessed at CMMI Level 5 and MSME certified, with senior-led engineering teams working across AWS, Microsoft and Google platforms. Our data centre and cloud networking team helps infrastructure buyers compare on-premises, colocation and cloud options, model power and capacity commitments against GPU workload ramps, and schedule deferrable jobs away from peak hours. Talk to us at /contact-us/.

Last updated: 13 November 2026.

References

1. 2027/2028 Base Residual Auction Report, 17 December 2025 — PJM Interconnection

1. PJM Capacity Auction Procures 138,318 MW of Generation Resources, news release, 14 July 2026 — PJM Interconnection

1. FERC Accepts PJM Reliability Backstop Proposal, 30 September 2026 — PJM Inside Lines

1. PJM Files Amended Reliability Backstop Proposal, 29 October 2026 — PJM Inside Lines

1. Order Accepting Tariff Revisions in Part and Rejecting Tariff Revisions in Part, Docket No. ER26-3515-000, 9 October 2026 — Federal Energy Regulatory Commission (posted by PJM)

1. 2028/2029 RPM Base Residual Auction Planning Period Parameters, 12 May 2026 — PJM Interconnection

1. 2029/2030 RPM Base Residual Auction Planning Period Parameters, 3 September 2026 — PJM Interconnection

1. RPM auction schedule (2029/2030 Base Residual Auction dates) — PJM Interconnection

1. PJM Manual 18: PJM Capacity Market, revision 63, effective 24 September 2026 — PJM Interconnection

1. 2027/2028 Base Residual Auction results workbook — PJM Interconnection

1. PJM Manual 19: Load Forecasting and Analysis, revision 39, effective 30 June 2026 — PJM Interconnection

1. Board decisional letter on the Critical Issue Fast Path for large load additions, 16 January 2026 — PJM Board of Managers

1. PJM Accepts Fourth Expedited Interconnection Track Project, 10 November 2026 — PJM Inside Lines

1. PJM, FERC Focus on Large Load Challenges at Tech Conference, 22 October 2026 — PJM Inside Lines

1. Reliability Backstop Procurement fact sheet, updated July 2026 — PJM Interconnection

1. Fact sheet: FERC directs nation's largest grid operator to create new rules to embrace innovation and protect consumers, 18 December 2025 — Federal Energy Regulatory Commission

1. FERC Launches Aggressive Targeted Action to Speed Large Load Integration, 18 June 2026 — Federal Energy Regulatory Commission

1. Overlap of Large Load, Co-Located Load and Load with BTMG, Co-Located Load Workshop, 18 August 2026 — PJM Interconnection

1. Providing Reliable Electricity in a New Reality, 15 October 2026 — PJM Inside Lines