A 5 MW plant in Met-Ed territory will pay about $568,000 for capacity in the PJM delivery year that starts June 1, 2026. In the year that started June 1, 2024 the same plant, with the same load, paid about $50,000. Nothing on the plant floor changed. The RTO clearing price went from $28.92 to $329.17 per MW-day in two auctions, and it is billed against five hours of load from the summer before.
Source: Open Factory PJM Capacity Charge Estimator (compiled from PJM BRA reports 2024/25 to 2028/29, PJM Manual 18, FirstEnergy Pennsylvania tariff; as of May 2026)
At $28.92 the plant’s 4.73 MW obligation cost $49,924 a year; at $269.92 it cost $465,957; at $329.17 it costs $568,239, and at the 2027/28 cap of $333.44 it will cost $577,187 because that delivery year has 366 days. This piece covers where the price came from, what the market monitor blames, exactly how the charge reaches a Pennsylvania and an Ohio bill, what PJM’s emergency load program pays you to give back, the fight over whether the number should have been half, and the five-hour playbook that cuts it.
Three Auctions, One Price Cap
PJM buys capacity three years ahead in the Base Residual Auction, in $/MW-day of unforced capacity, against a demand curve built from its own load forecast. The 2024/25 auction cleared at $28.92. The 2025/26 auction cleared at $269.92 for most of the footprint, $466.35 in BGE and $444.26 in Dominion, with 135,684 MW procured and a total bill of $14.7 billion. PJM’s own drivers list: about 6,600 MW of retirements, a peak forecast up from 150,640 MW to 153,883 MW, and new risk modeling that cut the accredited value of gas plants.
Source: Open Factory Large-Load Cost Table (compiled from PJM BRA reports 2018/19 to 2028/29; as of May 2026)
Eleven auctions, and the last three sit within $8 of each other because a cap now holds them there: $329.17 for 2026/27, $333.44 for 2027/28, $325.00 for 2028/29. The collar came out of Pennsylvania’s complaint at FERC (docket ER25-1357) and was set at $256.75/MW-day in installed-capacity terms, which converts to a different UCAP number each year as the reference unit’s accreditation moves. FERC extended it on April 28, 2026 to the 2028/29 and 2029/30 auctions at roughly $325 cap and $175 floor, with all 13 governors and the White House National Energy Dominance Council in support. The cap is not a market price. In the 2026/27 auction every LDA cleared at exactly $329.17 and the RTO cleared 134,311 MW against a 146,105 MW reliability requirement, 139 MW over the mark by PJM’s count once fixed-resource-requirement zones are added.
The 2027/28 auction was the first in PJM history to fall short of the reliability requirement across the whole RTO, by 6,517 MW. It procured 134,479 MW at the $333.44 cap, a 14.8% reserve margin against a 20% target, and PJM said the peak forecast had risen 5,250 MW of which nearly 5,100 MW was data centers. Then the 2028/29 auction on July 14, 2026 procured 138,318 MW at the $325 cap and came in 6,831 MW short, a 14.7% reserve margin, with only 525 MW of new generation clearing. PJM told reporters that without the collar the RTO would have cleared near $555/MW-day and ComEd at $777, a $29.7 billion year instead of $16.4 billion. The collar saves your plant about $390,000 a year against that counterfactual, and it also stops the price from telling anyone to build.
The $23 Billion Data Center Attribution
Monitoring Analytics, the independent market monitor, reruns each auction with the data center load taken out of the forecast. For 2026/27 it found that including 11,993 MW of existing and forecast data center load raised auction revenue by $7,271,197,971, or 82.1%, from $8.85 billion to $16.12 billion. For 2027/28 the forecast carried 17,071 MW of data center load and the attribution was $6,497,653,512, or 65.5%. Existing data centers accounted for 4,053 MW of that; 13,018 MW was forecast growth.
Source: Monitoring Analytics, IMM Analysis of the 2026/2027 BRA Part A, October 2025, and 2027/2028 BRA Part A, January 2026
The three attributions total $23.1 billion on $47.2 billion of auction revenue: $9.33 billion of $14.7 billion in 2025/26, $7.27 billion of $16.12 billion in 2026/27, $6.50 billion of $16.41 billion in 2027/28. Joseph Bowring, the monitor’s president, told Utility Dive the 2028/29 number is $6.3 billion, or 38%, and $29.4 billion across the last four auctions. His standing recommendation since 2025 is that new data center load “bring their own new generation” so that the forecast uncertainty stops landing on everyone else. PJM’s board adopted a version of that on July 27, 2026: incremental new large loads above the 2028/29 forecast will be excluded from the demand used in auctions from 2029/30 on, and a Large Load Registry will track every site of 50 MW or more.
The Large-Load Cost Table carries the PJM zones next to ERCOT, Georgia and Arizona for a 50 MW connection, and in every PJM zone the capacity line is now the second-largest number on the sheet after energy. The EIA’s June 2026 industrial rates show Pennsylvania at 10.10 cents/kWh against 9.31 a year earlier and Ohio at 9.89 against 8.66, while Texas moved from 6.36 to 6.58. The 1.6% funnel in ERCOT is a queue problem; PJM’s is a bill problem.
Five Hours Set Your Bill
Your capacity charge is not billed on your peak demand, your contract capacity or your kWh. It is billed on your Peak Load Contribution, and PJM Manual 19 defines how the PLC is built: for each summer, from June 1 through September 30, PJM adds estimated load drops back to metered load, then picks the five highest non-holiday weekday RTO daily peaks, the 5CP, and publishes them in mid-October. Your utility averages your metered load in those five hours, grosses it up for line losses, and that is your PLC from the following June 1 to May 31. A plant that ran flat out at 6 pm on five days in 2025 pays for it every day from June 2026 to May 2027.
Source: PJM, Summer 2025 Weather Normalized Coincident Peaks and 5CPs, revised November 2025
The five 2025 hours were June 23 at 160,649 MW, June 24 at 160,629 MW, July 29 at 156,035 MW, June 25 at 152,903 MW and July 28 at 151,525 MW, four of them hour ending 18:00 and one at 15:00, and the fifth-place day was only 1,378 MW above the sixth. PJM’s own review of that heat wave records preliminary peaks of 161,770 MW on June 23 and 162,401 MW on June 24, the third- and fourth-highest in its history, with more than 4,000 MW of demand response deployed. The add-back rule matters: load that a PJM event removed at 6 pm on June 24 is put back into the PLC, so being paid to curtail in a PJM event does not lower next year’s tag. Curtailing on your own does.
Two utilities, two documents. AEP Ohio’s Settlement Policies spell it out: for interval-metered accounts “the actual hourly usage at those five hours is averaged,” losses are applied to reach the generation level (1.0932 secondary, 1.0552 primary, 1.0341 sub-transmission in the 2018 revision), add-backs apply only to PJM program curtailments and not to a customer that “intentionally curtails on their own for operational reasons,” and the new PLC tags go out to suppliers each December by EDI 814C, effective June 1 through May 31. FirstEnergy Pennsylvania’s retail tariff defines PLC as “a Customer’s contribution to the Company’s transmission zone normalized summer peak load,” and its supplier tariff posts each customer’s PLC to suppliers within 10 days of calculating it.
From the tag to the dollar, PJM Manual 18 section 7.5 is one line: daily UCAP obligation equals PLC times the zonal RPM scaling factor times the Forecast Pool Requirement. The scaling factor and FPR are published with each auction: for 2026/27 the FPR is 0.917, Met-Ed’s base zonal factor is 1.01418 and AEP’s is 0.96289; for 2027/28 the FPR is 0.926 with Met-Ed at 0.97785 and AEP at 0.91830; for 2028/29 the FPR is 0.9401 with Met-Ed at 0.94516 and AEP at 0.92242. Multiply the obligation by the zonal capacity price and by 365 days (366 in 2027/28) and you have the year’s charge. The PJM Capacity Charge Estimator does this for any zone and PLC; the arithmetic below is what it runs.
The Same Plant, Four Bills
Take a plant with a 5,000 kW PLC at the meter (its average draw in those five hours), primary-voltage service, and 30,000 MWh a year. In the Met-Ed zone the tariff’s published primary-service loss multiplier is 1.0171, so the PLC at generation is 5,086 kW; times 1.01418 times 0.917 gives a 4.7295 MW obligation; times $329.17 times 365 gives $568,239 for 2026/27. In AEP Ohio the primary loss factor is 1.0552, so 5,276 kW; times 0.96289 times 0.917 gives 4.6585 MW; times $329.17 times 365 gives $559,711. That is $113.65 and $111.94 per kW of metered PLC per year, and it is what a competitive supplier in either state passes through, plus margin.
Source: Open Factory PJM Capacity Charge Estimator (FE PA tariff Supplement 36; AEP Ohio PUCO No. 22 and Settlement Policies; PJM Manual 18; PJM 2026/27 BRA workbook)
The two supplier routes land within $8,500 of each other at $568,239 and $559,711; the two utility default-service routes land at $482,100 and $1,848,172. AEP Ohio’s standard service offer bills capacity through a Generation Capacity Rider of 1.607 cents/kWh for demand-metered primary GS customers from June 1, 2026, which on 30,000 MWh is $482,100, or 15% under the PLC route because the rider is priced for the class’s load factor rather than yours. Met-Ed’s Hourly Pricing Default Service Rider, mandatory for Rate GP and TP customers who do not shop, bills a “Cap-AEPS-Other” component of $0.06057 per kWh from the April 2026 auction times a 1.0171 loss multiplier: $1,848,172 on 30,000 MWh, which is $370 per kW of this plant’s PLC against $113.65 on the PJM formula. The rider is a class-average price for capacity, alternative energy credits and the supplier’s other costs, and for a three-shift plant it is 3.3 times the auction cost of the same capacity by the tariff’s own numbers.
| Step | Met-Ed (PA) | AEP Ohio | Source |
|---|---|---|---|
| Average metered kW at the five 2025 CP hours | 5,000 | 5,000 | PJM 5CP file; AEP Settlement Policies |
| Loss factor to generation | 1.0171 | 1.0552 | FE PA tariff p. 208; AEP p. 8 |
| PLC at generation (kW) | 5,086 | 5,276 | computed |
| Base zonal RPM scaling factor, 2026/27 | 1.01418 | 0.96289 | PJM 2026/27 BRA workbook |
| Forecast Pool Requirement, 2026/27 | 0.917 | 0.917 | PJM 2026/27 BRA report |
| Daily UCAP obligation (MW) | 4.7295 | 4.6585 | Manual 18 s7.5 |
| Zonal capacity price ($/MW-day) | 329.17 | 329.17 | PJM 2026/27 BRA report |
| Annual charge, 365 days ($) | 568,239 | 559,711 | computed |
| Same plant, 2027/28 ($) | 561,976 | 547,521 | scaling 0.97785 / 0.91830, FPR 0.926, 366 days |
| Same plant, 2028/29 ($) | 536,029 | 542,731 | scaling 0.94516 / 0.92242, FPR 0.9401 |
The charge drifts down $32,000 over three years for the Met-Ed plant even though the price barely moves, because Met-Ed’s scaling factor falls from 1.014 to 0.945 as PJM’s forecast for the zone flattens. Peter Cavan of Unison Energy put the same arithmetic to Utility Dive for a bigger site: a 10 MW industrial customer’s monthly capacity charge goes from about $6,000 in 2024 to about $70,000 in 2028. A 2 MW service upgrade now carries about $230,000 a year of capacity exposure before the first kWh; the Large-Load Interconnection Cost tool adds it to the study fees and security for any PJM zone.
ELRP: The Same Megawatt Sold Back
PJM pays load to be curtailable. Manual 18 section 4.3 says a load management program offered as a Demand Resource and cleared in the auction is paid the resource clearing price for the delivery year, and the resource must be registered in the Pre-Emergency or Emergency Load Response Program through a Curtailment Service Provider. Demand response cleared 7,299 MW in the 2027/28 auction, up from 5,531 MW, because its accredited value rose from 69% to 92% once PJM required availability in all hours of the year. In 2028/29 it fell 277 MW to 7,365 MW of unforced capacity despite the price.
Source: Open Factory PJM Capacity Charge Estimator
A megawatt nominated into ELRP for 2027/28 earns 0.92 times $333.44 times 366 days, which is $112,276 before the CSP’s share, and that is the $112k per MW-year Voltus quotes to customers; a megawatt cut from the PLC saves the Met-Ed plant $112,395. In 2026/27 the ELRP number was $82,901 because the accreditation was 69%. Voltus’s published cases are a manufacturer that earned $75,000 and offset 55% of its 2025/26 capacity cost, and a data center that nominated 139 MW for $11 million, an 87% offset; enrollment for 2026/27 closed March 31, 2026. For the worked plant, 2 MW of curtailable compressors, chillers and one line is $224,552 a year gross in 2027/28, about 40% of the capacity charge.
The obligation is real. A Capacity Performance demand resource must be available for an unlimited number of interruptions in all hours of the delivery year from 2027/28, and the non-performance charge is the shortfall in MW times a rate equal to the RTO Net CONE times the days in the year divided by 30, spread over the settlement intervals: at the 2027/28 RTO Net CONE of $68,347 per MW-year in installed-capacity terms that is about $2,280 per MWh you promised and did not drop, capped for the year at 1.5 times the clearing price times the days times your committed MW, or roughly $183,000 per MW. PJM deployed demand response on June 23, 24 and 25, 2025, so a plant that cannot shed three afternoons running should not enroll. The Genset TCO tool prices the alternative many plants use, running standby diesel through the event, with its Tier 4 permitting hours.
The $12 Billion Fight Over the Reserve Study
SemiAnalysis spent six months rebuilding PJM’s Reserve Requirement Study from Manual 20A and the posted 2028/29 workbooks and published the result on August 16, 2026: PJM understates its existing fleet by about 3.8 GW because it derates thermal units for summer heat but never uprates them for winter cold, and because its outage statistics still carry Winter Storm Elliott, when 46 GW and 24% of the fleet failed, even though 400 of roughly 700 gas units had reported winterization upgrades by January 2024 and the fleet lost 9% in Storm Gerri, 9% in the January 2025 MLK storm and 10% in Storm Fern. With the two corrections, 2025/26 clears at $135 instead of $270 ($6.7 billion) and 2026/27 at $230 instead of $329 ($4.9 billion), $11.6 billion in a range of $8.0 to $14.5 billion.
Source: PJM 2028/2029 BRA Results Report, July 2026; SemiAnalysis, August 2026
The bars are 6,831 MW and about 3,000 MW: the backstop procurement PJM plans for October is sized to the first number, and the second would have fit inside the voluntary subscription design that PJM’s members endorsed on June 30, 2026 and the board rejected on July 27. PJM has answered the argument before. The market monitor found in September 2024 that crediting winter capability would have cut the 2025/26 bill by $2.7 billion with the reserve margin held fixed and up to $8.0 billion without. PJM’s October 11, 2024 response agreed “there potentially exists additional thermal capacity available during winter months” but said the IMM ignored winter deliverability limits, and that if extra winter capability shifted risk into summer “this would increase, not decrease, the reliability requirement.” PJM’s own May 2025 sensitivity measured the winter uplift at 8,561 MW; its task force passed seasonal ratings 178 to 54 in July 2025; the senior committee killed the package on August 20, 2025 at 30.7% of the weighted vote; E3’s December 2025 review said PJM “asymmetrically applies ambient derates.” No vote since.
For the worked plant the difference between the two models is about $233,000 a year: at $135 the 2025/26 charge would have been $233,000 instead of $465,957. We think the cold-air half of the argument is settled and the winterization half is a judgment call PJM should be making in the open rather than by default. Deliverability is the one objection that has not been tested, because PJM never ran the studies. The Large-Load Policy Tracker carries the docket dates: comments on the backstop filing closed August 21, and the 2029/30 auction runs in December.
The Backstop and What to Do Monday
PJM filed the Reliability Backstop Procurement at FERC on July 31, 2026 as docket ER26-3380: a one-time window from September 30 to October 21 for new resources against the 6,831 MW shortfall, contracts of up to 15 years, a MW-weighted average cap of $555/MW-day, results by December 2, resources online no later than June 1, 2032, and the target reduced by any bilateral contracts signed first. Costs go to zones pro rata to the procurement target and then to load-serving entities, and PJM’s board wrote that “because PJM does not have jurisdiction to allocate retail costs directly to individual data centers, state action will be essential”. At the cap, 6.8 GW is $1.38 billion a year, or $24.19/MW-day spread across the 156,013 MW requirement. Whether a 5 MW plant sees it depends on whether Harrisburg and Columbus put it on loads of 50 MW and above, and neither has decided.
Monday, in this order. Ask your supplier or utility for your current PLC tag and the five hours behind it; AEP Ohio sends it every December by EDI 814C and FirstEnergy posts it to the supplier lists. If you are on Met-Ed, Penelec or Penn Power hourly-priced default service with a load factor over 50%, get two supplier quotes with the capacity line broken out as PLC times the pass-through, because the rider is charging your plant $370 per PLC-kW for a $114 product. Put PJM’s Hot Weather Alerts on the plant manager’s phone and pre-plan a 2 MW shed for 3 to 7 pm on any June-to-September weekday PJM forecasts above ~148 GW; five of those days in 2026 set your bill from June 2027 to May 2028. Call a CSP before next March 31 about 2027/28 enrollment, with June 23 to 25, 2025 as the test of whether you can drop load three afternoons running. The Large-Load Cost Table has the PJM zones’ capacity line beside Georgia, Texas and Arizona for anyone deciding where the next plant goes, and What 50 MW Costs in 15 US Markets walks the rest of the sheet.
Behind the paywall: the five-hour playbook that takes the worked plant’s capacity line from $561,976 to $337,186 before ELRP and to about $113,000 net with 2 MW enrolled, the battery that pays back in 2 to 6 years on the PJM Capacity Charge Estimator’s numbers, and the four December 2 outcomes priced for this plant.