PJM's capacity rate shock lands in utility budget rooms
Municipal utilities and electric cooperatives serving PJM Interconnection's 67 million customers are recalibrating their budgets after capacity rates jumped more than 1,000% over the past two years, according to Utility Dive reporting published Monday (2026-07-06). The bill is arriving just as data center developers push harder for grid connections that existing infrastructure was never built to accommodate.4
PJM is the largest wholesale power market in North America, and its capacity market pays generators to remain available during peak demand. When those rates surge by an order of magnitude, the cost flows through to every load-serving entity in the region, from large investor-owned utilities down to the small municipal cooperatives that spent decades operating in a predictable pricing environment.4
The driver is well-documented but still accelerating. Data centers now account for roughly half of incremental demand growth in the United States, according to the International Energy Agency's latest global assessment. US utilities have already committed to add 116 gigawatts of large load to their networks — equivalent to about 15% of US peak electricity demand — with hyperscaler capital spending on facilities forecast to top $300 billion in 2025 alone, according to Wood Mackenzie estimates.3,2
Across adjacent US power markets, the price environment has shifted sharply in ways that reinforce the PJM picture. Average electricity prices in the Midcontinent Independent System Operator grid rose 44% from 2024 to 2025, according to EIA analysis. Coal benefited most: with fuel costs up just 3%, the dark spread widened from $11/MWh to $23/MWh, a 111% increase year on year. Natural gas fared less well, with fuel costs up 63%, which limited the spark spread gain to $2/MWh, leaving it at $14/MWh by year-end.1
Winter Storm Fern sharpened the picture further. Daily average power prices in MISO exceeded $260/MWh from January 26 (2026-01-26) to January 28 (2026-01-28), even though demand over those three days ran 11% below the comparable non-storm period, EIA data show. That episode drove dark spreads across the first four months of 2026 to a $28/MWh average, 39% above the same stretch in 2025, while spark spreads averaged $9/MWh, a 15% year-on-year gain.1
One response being tested further along the eastern seaboard, in ISO-New England, is storage dispatched specifically during high-cost peak intervals. A 4.9 MW/15 MWh battery system has been deployed there to absorb energy during low-price hours and release it during the short peaks that drive a disproportionate share of annual capacity costs. PJM's scale means any comparable answer would need to be orders of magnitude larger.4
The PJM Western Hub spot price stood at $42.83/MWh as of Monday (2026-07-06) morning. NYMEX Henry Hub front-month natural gas was at $3.24/MMBtu. At that gas price, spark spreads remain thin, leaving utilities with limited margin to absorb further capacity cost escalation through generation revenue.
Grid engineers, utility executives, and regulators have described a system where permitting backlogs, supply chain constraints, and interconnection queues cannot match the speed at which data center developers want capacity, according to reporting by Quartz. For smaller municipal utilities and cooperatives, this is an unfamiliar position — capacity planning was a secondary function when demand was flat; it has become a primary budget driver in a two-year span.3
PJM's next capacity auction will reveal how much of the supply response — new generation, storage, demand response commitments — has materialised against the demand growth curve. Utilities that did not secure capacity in prior cycles are not positioned to absorb a second consecutive step up of comparable magnitude.