The biggest bottleneck in the AI buildout is not semiconductors or fiber. It is electricity. And the market that makes that bottleneck most visible, PJM Interconnection, covering 67 million people across 13 states and the District of Columbia, just delivered its clearest signal yet that scarcity has become durable, not cyclical.
PJM’s 2028/29 Base Residual Auction results, released July 14, 2026, marked the second consecutive year the auction failed to procure enough resources to meet the grid’s reliability requirement, leaving a shortfall of about 6,800 MW. Capacity prices cleared at $325/MW-day, hitting the FERC-approved cap. Without the price collar, the auction would have cleared at nearly $555/MW-day across PJM’s footprint. The cap is suppressing the price signal. The underlying imbalance is getting worse.
Who Pays for the Data Center?
PJM’s independent market monitor has been direct: “Data center load growth is the primary reason for recent and expected capacity market conditions, including total forecast load growth, the tight supply and demand balance, the significant shortfall in cleared capacity, and high prices.” The 2028/29 auction was further affected by a roughly 2 GW increase in forecast demand, largely caused by data center development.
The political response is now accelerating in ways that matter for capital allocation. PJM’s Board of Managers outlined a broader framework in January 2026, directing work in 2026 on large-load integration and market reforms, including a backstop generation procurement process. Separately, the Board initiated an April 2026 Critical Issue Fast Path process focused on developing a Reliability Backstop Procurement proposal, later expanded to include a “connect and manage” framework. The question of who bears the cost of connecting a 500-megawatt data center is being rewritten in real time.
The PJM Board’s January 2026 decisional letter established six components on large load additions, including load forecasting improvements, the creation of a voluntary Bring Your Own New Generation (BYONG) track paired with an expedited interconnection track, a reliability backstop procurement, and a holistic market review. Whatever the final rules look like, one outcome is already certain: the era of data centers free-riding on existing grid capacity is closing.
What the Mogul Sees
Most coverage of this story focuses on data center operators and their power costs. The more interesting investment question runs the other direction: who gets paid when electricity is genuinely scarce?
Dispatchable assets are being valued as scarce reliability infrastructure rather than short-duration commodity assets. That distinction is worth sitting with. A gas turbine or a nuclear reactor with firm interconnection rights in a load-growth zone is no longer priced primarily as a commodity business. It is priced as a piece of critical infrastructure with no near-term replacement.
The auction results make the revenue picture concrete. Constellation Energy cleared 18,875 MW in the auction and should garner about $2.2 billion in revenue for the 2028/29 capacity year alone. Vistra cleared 10,924 MW and Talen Energy cleared 10,180 MW, generating about $1.3 billion and about $1.2 billion in capacity revenue respectively.
Talen’s Q2 2026 earnings call described PJM scarcity as “a monetizable earnings tailwind,” with management noting that West Hub spark spreads had increased nearly 50% from the prior year and that the last three PJM base residual auctions cleared at the applicable price cap. Constellation raised full-year 2026 adjusted operating earnings guidance to $11.50–$12.50 per share following its own Q2 results.
What Could Go Wrong
The risk case deserves honest treatment. The price collar itself is the first concern: while the price cap and floor reduce volatility, they do not solve the underlying supply-demand imbalance, and FERC approved extending those parameters to the 2028/29 and 2029/30 auctions to limit volatility for consumers. Generators are collecting less than the market would clear without intervention.
Regulatory risk cuts both ways. Final tariff structures could impose network charges, minimum-take requirements, or curtailment obligations that reduce the apparent advantage of co-location, and political pressure to protect residential ratepayers could produce less favorable rules than generators currently expect.
The interconnection queue itself is broken in ways that slow the supply response: since 2020, 45% of projects added to PJM’s queue have withdrawn before completing the interconnection process, and average interconnection costs rose from $29 per kilowatt in 2017–2019 to $240 per kilowatt in 2020–2022. That same dysfunction that constrains competitors also protects incumbents.
The Long-Term Verdict
The investment case for owners of dispatchable PJM generation is not a trade on the next auction. With prices hitting the FERC-approved cap in three consecutive auctions and the shortfall widening from about 6,500 MW in 2027/28 to about 6,800 MW in 2028/29, there is no basis for expecting a price reversal in the near term.
Constellation (CEG), Vistra (VST), and Talen (TLN) hold the most direct exposure to this dynamic through large, well-located PJM fleets. NRG (NRG) benefits through its integrated retail platform and dispatchable generation, though with less concentration in nuclear baseload. Exelon (EXC) operates as a regulated utility and captures the capacity cost dynamic differently, primarily through rate recovery rather than merchant upside.
The AI infrastructure buildout is visible and discussed everywhere. The electricity scarcity it is creating is discussed far less. For patient capital, the more durable opportunity may be in the wires and turbines that no data center can run without.
