The Market Is Paying for a Problem It Hasn’t Solved
Two months in, we keep seeing the same pattern: every region thinks it has solved the grid problem, and every region has only relocated it.
A month ago I wrote the first recap. The premise was that capital is pouring into AI infrastructure on the assumption that power, transmission, and interconnection are solvable inputs. They aren’t: they are the constraint, and the constraint is neither fully capitalized nor properly priced.
The second month tested that argument against the regions themselves. Four issues plus bonus content, working outward from a single auction print toward a national map. The capacity auction that printed at the cap for the second time, with FERC extending the ceiling rather than letting the market discover what an uncapped print would look like. A Midwest retirement schedule that erases roughly a third of average demand on a timetable the replacement queue can’t meet. A pan-regional review showing nine grids making nine different bets on how to firm the same renewable buildout. A political backlash that is no longer stopping the build but is increasingly choosing where it survives. And, as bonus content, a discussion of how the transferable tax credit market has quietly become the policy tool deciding which physical systems are financed.
What follows is the second month, condensed. The full archive is at www.theaigridreport.com.
ISSUE 06 · The Market That Can’t Settle
PJM’s December 2025 capacity auction settled at $333.44 per megawatt-day. That was the cap. It was also the second consecutive PJM auction to print at the cap, after the July auction settled at $329.17. Together the two auctions secured 134,479 MW for $16.4 billion in annual payments — at a procured reserve margin of 14.8%, the lowest in PJM’s history. The cap was supposed to be temporary. On April 28, FERC extended it through the 2029/30 delivery year. The market still doesn’t know what an uncapped print would look like.
The mechanics underneath the print are the more interesting story. Roughly 5,500 MW of fossil capacity is scheduled to retire — Brandon Shores, H.A. Wagner, Conemaugh, Keystone — but none of it is leaving. Brandon Shores and Wagner are operating to May 2029 under FERC-approved RMR agreements; Keystone and Conemaugh were held open through 2032 under a Pennsylvania consent decree. PJM connected 2,117 MW of new generation across all of 2025, almost entirely solar, while forecast load growth of roughly 5,250 MW arrives over the same window, primarily in Northern Virginia. The capacity market is procuring the gap the system cannot fill, and FERC has set the price at which that procurement may occur.
The PJM-versus-ERCOT comparison anchors the piece. Same demand, same generation technologies, different process. ERCOT’s connect-and-manage interconnection, energy-only market, and single-state regulator move the queue at near-zero withdrawal. PJM filters two-thirds of projects out before they reach completion. PJM can’t copy ERCOT’s structure, but it can copy ERCOT’s cadence — and until it does, the cap is the auction, and the auction is a political instrument with FERC’s overseeing it.
ISSUE 07 · MISO Has a Retirement Problem
MISO’s headline number is a posted retirement schedule, not an auction price. Roughly 25 GW of operating generation is scheduled to retire — about 37% of MISO’s average demand, with no other major ISO close. SPP sits at roughly half that exposure; PJM is in the mid-teens; ERCOT remains below 3%. Of the 25 GW, roughly 14 GW is subbituminous coal and 8 GW is natural gas. The dispatchable, fuel-secure capacity that operates through extended weather events and low-renewable-output stress is the part of the fleet leaving the system.
Michigan is the version of the problem visible at a single regulator. DTE Energy has disclosed 8.4 GW of data-center load — Oracle (1.4 GW, approved), Google (1.0 GW, decision due September 2026), ~2 GW in advanced discussions, and 3–4 GW earlier-stage. Over the same window, ~4.6 GW of Michigan coal is scheduled to retire: Monroe (3.3 GW, 2028 and 2032) and J H Campbell (1.3 GW, operating under its fourth federal 202(c) emergency order). The same balance sheet is selling the retiring capacity and buying the new load, and the regulator can watch the arithmetic in a single docket. Campbell is the precedent the rest of the 2028 fleet now has to underwrite to — a coal unit nominally retired a year ago that is still operating, with roughly $200 million in operational losses being contested before FERC.
The queue does not solve this on a one-for-one basis. MISO has ~230 GW active in queue, and it looks like an order-of-magnitude replacement for the retirements until you apply withdrawal rates and accreditation. Coal operates at 45–55% capacity factor; solar at ~25%. Once the cascade compresses the nameplate into accredited firm capacity, the apparent 9:1 replacement ratio falls to roughly 1.6:1. The retirement schedule prints either way. The replacement supply does not.
ISSUE 08 · What America Is Trying to Build
The interconnection queue is more than a backlog. Every project in it has committed capital and accepted years of transmission-upgrade exposure before delivering a megawatt. The composition is therefore a map of what developers believe is worth building — and it now reveals a national power system converging around one consensus and diverging around one unresolved question.
The consensus is the disappearance of coal. Across more than 1 TW of active queue volume in the seven major RTOs, roughly 0.5 GW of new coal appears. The existing fleet still operates, and in PJM still settles in the capacity auction; no one is willing to spend years queuing new coal through interconnection. Solar plus storage has become the national default, with roughly 956 GW of solar and 890 GW of batteries sitting in active queues at end-2024. A decade ago the storage figure was close to zero. The queue is now a renewable-plus-battery expansion in aggregate, regardless of the regional politics surrounding it.
The divergence is the firming layer. PJM still leans on gas and a long-dated nuclear bet — including a roughly 10 GW nuclear cluster concentrated in restarts and uprates rather than greenfield. ERCOT is attempting to firm renewable growth primarily through storage, with 176 GW of batteries in queue, the largest in the country, alongside a 233 GW large-load queue that is more than 70% data centers. MISO has shifted back toward gas as coal retires. CAISO, NYISO, and ISO New England show almost no new gas at all and are implicitly assuming either slower hyperscaler arrival, lower reliability tiers, or longer-than-planned operation of the existing thermal fleet. None of those assumptions is obviously wrong, and none is obviously safe. Same continent, different bets.
ISSUE 09 · Data Center Opposition Is Deciding Who Wins
Local rejections of US data-center projects totaled 49 across all of 2025. The first five months of 2026 produced 89. Q1 alone saw 20 cancellations representing more than $41.7 billion in shelved investment. The slope is the story: the rate of refusal is now rising faster than the rate of construction, even as the pipeline of roughly 2,788 facilities implies a two-thirds expansion off the installed base.
Both sides of the argument have real numbers. Virginia’s data-center industry supports roughly 74,000 jobs and more than $9 billion in annual GDP contribution; the state’s sales-tax exemption returns 48 cents per dollar foregone, well above the 17-cent average for other Virginia incentives. JLARC (Joint Legislative Audit and Review Commission) still classified the benefit as moderate and concluded the exemption does not fully pay for itself. The 833% year-over-year jump in PJM’s capacity-auction print, and the $11.24 monthly residential bill increase Virginia’s SCC approved for 2026, are the kitchen-table version of the same fight. The percentage of Virginia residents comfortable with a new local data center fell from 69% in 2023 to 35% in 2026. Support for state tax breaks fell from 61% to 37%. A 34-point swing in three years is what gives legislators cover to move.
The resistance is selecting the composition of the buildout rather than halting it. MISO’s data-center footprint has grown at 43% per year since 2020, driven by Virginia saturation and developers routing toward jurisdictions where opposition has not yet organized. The political-risk filter is converging on the same answer as the power-economics filter from Issue 07: the projects most exposed to community resistance are the same ones weakest on supply-side fundamentals. The version of the buildout that survives is the version whose power is sited where no one is close enough to object.
BONUS CONTENT · Transferable Tax Credits Are Quietly Reshaping Infrastructure Capital
The transferable tax credit market reached $42 billion in 2025, up 27% from $32 billion in 2024. With tax equity and preferred equity included, total tax credit monetization hit $63 billion. The market grew through OBBBA reconciliation, not despite it. Eligibility tightened, the qualifying pool narrowed, and the buyer-side market remained intact. The §6418 transferability provision that opened the market in 2022 is still the policy tool deciding which physical systems are financed.
The framing matters more than the mechanism. A transferable tax credit is technically a financial instrument, but economically it is beginning to function as a directional signal for capital allocation into energy, manufacturing, grid infrastructure, and industrial capacity. A $5 million tax liability becomes $4.5–4.6 million in credits funding a real project with a placed-in-service date. The project exists before the capital arrives, which makes the accountability structurally different from an ESG score the rating agency can revise after the fact. For family offices and long-duration capital pools that can underwrite illiquid, politically shaped, operationally complex infrastructure cycles, the structure fits unusually well. The question has moved from how to minimize the tax bill to what physical system the tax bill should fund.
The Through-Line
Five pieces, one argument extended: the constraint is moving, and it is moving in a direction the headline numbers don’t capture.
PJM’s capacity auction shows the political ceiling rather than the physical scarcity price. MISO’s retirement schedule happens whether the queue connects or not. The pan-regional queue shows what developers believe — and what they no longer believe — about which firming technology will pay. The rejection database shows which jurisdictions have organized against the build and which have not yet. The transferable tax credit market shows which projects are financed at all. Each of these is a price the market is paying for a problem it has not solved, and each of them surfaces somewhere other than where the original constraint sat.
A month ago I wrote that the grid constraint had shifted. The second month sharpened the claim: every mechanism the system uses to manage the constraint — auction caps, RMR contracts, emergency orders, queue filters, siting moratoria, tax credit eligibility — relocates the cost rather than resolving it. The open question is the same as last month, with two more data points behind it. How long can the market continue talking about the headline before it is forced to price the outcome?
Go Deeper on Each Issue
– PJM printed at the cap for the second time, and FERC extended the ceiling rather than letting the price discover itself →
– MISO’s retirement schedule is 25 GW, and the queue replacing it is composed of different generation types →
– Nine regions, nine queues, one disappearance and one emerging firming-layer disagreement →
– The rejection rate is now rising faster than the construction rate, and it is choosing where the build survives →
– Transferable tax credits have evolved beyond accounting exercises into the financing layer for the physical buildout →
What Comes Next
The third month moves underneath the queue and into the wires. Transmission planning, the FERC co-location order, and the question of whether behind-the-meter generation is a way around the grid or a new layer of it. The Constraint Index continues to update weekly. The full archive, the index, and the paid deep dives are at theaigridreport.com.