The sequel is roughly thirty times bigger, and Texas isn't cooling this time. It's auditing. On August 3, the governor ordered every data center in ERCOT's interconnection queue audited before another one advances, with non-compliant projects to be denied connection. On September 14, he put the state's water board on enforcement duty, with civil and criminal liability for data centers that ignore its surveys. On September 21, he halted all state environmental permits for data centers. On September 24, the attorney general opened an investigation. Responses to the state's information requests were due October 12; the water board reports October 14; the environmental agency updates the governor on October 19; ERCOT's full audit lands December 10.

Texas runs America's only major energy-only power grid: generators are paid solely for electricity actually sold, with no capacity market paying them to keep plants available. Investment is supposed to come from volatility itself — prices spiking to $5,000 a megawatt-hour when reserves run thin, collapsing near zero when the wind blows. That design is genuinely good at one thing: letting cheap resources in fast. Merchant batteries went from a rounding error to 16.5 gigawatts, mostly without subsidies. But the design has no mechanism for telling real demand from fiction, because filing an interconnection request cost nothing. When load growth arrived faster and lumpier than any spot market could coordinate, the fiction piled up until the state had to do the coordinating itself.

"Market-purist" needs a qualifier, though. Winter Storm Uri in February 2021 — more than a third of generation offline, millions without power — already cracked the philosophy open. Since then: weatherization mandates, the offer cap cut from $9,000 to $5,000, a new capacity-like credit mechanism for dispatchable generators, and a $7.2 billion state loan fund to build new gas plants. By the time the data centers arrived, Texas was running a hybrid — market in name, increasingly administered at the edges. The boom didn't encounter a pure system. It encountered a patched one, and added a problem none of the patches addressed.

The theoretical case against the design was always the same, and economists gave it a name: missing money. A plant that only runs during the hundred scarcest hours of the year can't earn enough, even at $5,000 a megawatt-hour, to justify existing — so peaker plants, the ones you most need in a crisis, are the ones the market least wants to build. Texas argued for years that a high enough cap solved this. Uri cut the cap nearly in half, and the argument got harder. The data-center boom added a second problem, and a more practical one. The market was already unreliable at delivering the peaker plants it needed. Now it had to sort 474 gigawatts of maybe with nothing but the spot price — and the spot price can't tell who's real.

If that framing is right, it points to the questions worth asking: what breaks when a market can't answer "who's real?", who pays for a grid planned around fiction, and is Texas the preview of what's coming everywhere else?

Texas offered what data centers wanted: cheap land, cheap power, historically fast interconnection, no capacity-market costs baked into bills, abundant natural gas nearby, and no state income tax. Then the state sweetened it. Qualifying data centers were exempt from the 6.25 percent state sales tax on equipment and electricity — a subsidy the comptroller says cost about $1 billion in foregone revenue in 2025 alone, projected at $1.3 billion next year. Texas paid roughly a billion dollars a year to attract the boom it then halted. The governor's stated priority for the 2027 legislative session is eliminating the exemption entirely. The incentives took a decade to build and about a year to reverse.

ERCOT's large-load interconnection queue stood at 63 gigawatts in December 2024. By November 2025 it was 226 gigawatts, nearly three-quarters of it data centers. By August 2026, the state was considering 474 gigawatts of requests — a figure that sweeps in projects beyond the formal queue — against a record peak demand of about 91 gigawatts. Five times the grid, on paper, nearly all of it data centers. ERCOT's chief executive has said the forecast exceeds expected load growth. Everyone agrees most of it will never be built. The disagreement is over what to do about the pileup.

The political pressure arrived on a different frequency. County hearings filled with residents worried about well water, generator noise, and property values; by one industry estimate, more than $170 billion in AI data-center capacity has been blocked, withdrawn, or stalled by community opposition since the start of 2024. The grid problem and the water problem and the neighbor problem turned out to be the same problem: nobody could say which projects were real, so every project looked like a threat.

What Texas did, step by step, was put a price on sincerity. Senate Bill 6, signed in the summer of 2025, requires large loads to demonstrate site control, fund their own grid upgrades, disclose duplicate interconnection requests filed elsewhere in the state, and accept curtailment during emergencies. The implementing rules added the sharpest tooth: $50,000 per megawatt in financial security before an interconnection study even begins — $5 million for a 100-megawatt project, posted upfront, explicitly to discourage speculative filings. In June 2026, regulators approved Batch Zero, a cluster-study process for loads over 75 megawatts: first-ready, first-served, the Texas translation of the federal reforms.

Then came the gates. The August audit demands five disclosures from every data center 25 megawatts and up: what state incentives it received, how much of its power it brings itself versus drawing from the grid, its water sources and uses, its impact on neighboring communities, and who actually owns it. Fail to comply and the project "must be denied connection to the Texas grid." The September water order added teeth the market never had: ignore the survey and face civil and criminal liability. The September permit halt closed the other door — no environmental permits, no water rights, no wastewater approvals until the audit completes, with no megawatt threshold and no clear exemption even for behind-the-meter generation. So a project now needs both to lift before it can proceed: ERCOT’s energization pause and the state’s permit freeze, each on its own timeline.

What each step has in common: none of them is a price signal. They're all tests — of money, of disclosure, of patience. The state looked at a market producing 474 gigawatts of maybe and concluded that no price adjustment would sort it. So it stopped trying to price the problem and started administering it.

The audit treats bringing your own power as the closest thing to a safe harbor — self-sufficiency is what the state says it wants. But the TCEQ halt may cover the air permits for on-site generation too; the directive names no exemptions, and the agency isn't clarifying until October 19. So a developer doing exactly what the state asks for may find that permit frozen as well. Rationing regimes produce these contradictions. When every gate is administered by a different agency on a different calendar, the rules stop adding up.

An energy-only market produces prices for energy. It produces no price for credible commitment — for the difference between a developer who will build and one who filed a form. Filing was free, so fiction was free, and 474 gigawatts of fiction is not a rounding error. It's a planning input. ERCOT had to plan transmission around demand that didn't exist, order equipment for load that would never arrive, and explain to legislators why the forecast showed five grids. That's the point where the market's answer to "who gets power?" — whoever filed first — stopped being acceptable. The state stepped in with a different answer: whoever can prove they're real.

The winners and losers follow directly. The regime favors the deep-pocketed and the shovel-ready: hyperscalers with funded projects survive any readiness screen, and projects that bring their own power look safer than those that don't. It punishes the speculative and the thinly capitalized — $50,000 a megawatt in security plus self-funded upgrades is existential for a small developer, a rounding error for a hyperscaler. The intended casualty is the phantom filer; the collateral damage is anyone who can't post collateral, a distinction the filter doesn't bother making. There's already jurisdictional arbitrage: much of the Panhandle sits in the Southwest Power Pool, not ERCOT, so the governor's directives don't touch it — the freeze has a map, and developers can read maps. And the filter is working, in the narrow sense: lawyers in Houston report clients quietly withdrawing Texas projects, mostly the complex, permit-heavy ones, while projects with real work already done stay put.

The capital that leaves has to go somewhere. BloombergNEF estimates 49.8 gigawatts of ERCOT data-center load — about a fifth of the national pipeline — faces delay, with up to $15 billion of revenue at risk in the worst scenario, and expects barely a gigawatt of new Texas data-center capacity through early 2027. Analysts point to states with structured large-load tariffs and no moratoriums — Oklahoma, Georgia, Ohio, parts of the Midwest — though those flows are still speculation, not tracked fact. What's not speculation is that Texas isn't alone anymore. New York has imposed a statewide moratorium on hyperscale data centers. Pennsylvania's governor ordered what he called the strictest guardrails in the nation: self-funded infrastructure, local approval before state permits. Florida now makes facilities over 50 megawatts bear their full interconnection cost. And at the federal level, FERC's June show-cause orders on large-load interconnection — the same diagnosis, the same prescription of readiness screens and cost responsibility — are expected to resume in mid-November. Texas is the leading edge of a national pattern, not an outlier.

December 10 brings ERCOT's report. January brings the legislature, with the incentive exemption, SB 6's implementation, and the permit regime all on the agenda — and possibly a longer leash for the whole apparatus if the pause stretches past the November midterms, as some analysts expect. What emerges will likely be the country's first comprehensive large-load regulatory code: part market, part audit, part criminal statute. Other states are watching less to copy Texas than to avoid needing to.

Underneath it all is the asymmetry that explains why everyone's so nervous. Jim Matheson, who runs the national association of rural electric cooperatives, put it plainly this week: "When you build a whole power plant to serve [a] 1,000 megawatt data center and the data center goes away, that's a problem." Power plants are built to run for up to 80 years. Data centers sign ten-to-fifteen-year leases. The physical commitment is lopsided — concrete and steel on one side, a maybe on the other — and every piece of the Texas response is an attempt to make the maybe legible before the concrete gets poured. The $50,000-a-megawatt security, the ownership disclosures, the criminal liability for lying about water: all of it is the state trying to manufacture, by administrative force, the one thing its market never produced. Credible commitment.

The job changed. The old task was pricing energy efficiently; the new one is deciding, among 474 gigawatts of maybe, who gets to build. Prices can’t answer that question. What the state needs is credible commitment, a way to tell which developers will actually build. That is now the central problem in American power markets.

Sources consulted for this essay: ERCOT and PUCT publications on the energy-only market and the Batch Zero framework; the August and September 2026 directive letters from Governor Abbott; Baker Botts' analysis of Senate Bill 6; the McGuireWoods 50-state survey of data-center legislation; the Texas Comptroller's revenue estimates; BloombergNEF's August assessment of delayed load (scenario analysis); reporting from Utility Dive, PowerMag, New Project Media, and the Texas House Focus report on grid reliability.

ERCOT, which runs the Texas grid, reported in early August that developers had filed requests to connect about 474 gigawatts of large new electric load — more than five times the state's all-time record peak demand of about 91 gigawatts, with roughly 90 percent of the requests tied to data centers. Everyone involved understands most of it is fiction. ERCOT's own chief executive has said the forecast is higher than expected load growth. On August 3, Governor Greg Abbott ordered every data center in the interconnection process audited before another one advances, writing that any project failing to comply "must be denied connection to the Texas grid. Simply put, Texans must come first." In September he extended the freeze to environmental permits.

Texas is the vivid case, but the condition is national — and it matters more than almost anyone outside the industry realizes. Somewhere inside this administrative machinery is the institution that now rations the binding constraint on the AI buildout: not chips, not capital, but time-to-power. Because the queue is no longer a waiting room. It is the market.

What's being traded is priority access to the grid — really, time. The buyers are developers and hyperscalers, bidding against each other with deposits, collateral, and a willingness to lose both. There's no seller in the usual sense; the grid operator rations a fixed supply of interconnection, and the price of admission is whatever it costs to survive the process. It clears at decision points, where the undercapitalized get filtered out and the committed pay up. If that framing is right, it points to the questions worth asking: who does a market like this select for, and who ends up paying for the grid?

If you want to connect anything big to the grid — a power plant, a data center, a factory — you have to ask permission. The grid operator studies whether the wires near you can handle it, what upgrades would be needed, and who pays for them. This is called interconnection, and for most of the industry's history it was plumbing: administrative, boring, first-come, first-served.

The plumbing broke in the most predictable way imaginable. Under first-come, first-served, a queue position cost almost nothing and was worth a great deal: it was a free call option on future grid capacity. If power demand materialized near your project, you held a golden ticket. If it didn't, you'd spent little more than the application fee. So everyone filed — the serious, the speculative, and the fictional. Filing early and often wasn't gaming the system. It was the system working exactly as its incentives dictated.

Berkeley Lab keeps the authoritative scorecard, and the latest edition is staggering for a simple reason: the queue now holds more power plants, on paper, than the country has ever built. At the end of 2025, some 2,061 gigawatts of generation and storage capacity sat in interconnection queues across roughly 8,200 projects — more than the entire installed generating fleet of the United States, which is about 1,374 gigawatts. The country is being asked to connect more than it has ever built, all at once. The mix tells you where capital wants to go: 773 gigawatts of solar, 749 of storage, 253 of natural gas (up 86 percent in a single year), 220 of wind.

And most of it will never be built. Of every project that requested interconnection between 2000 and 2020, only about 19 percent — 13 percent of the capacity — had reached commercial operation by the end of 2025. More than 1.8 terawatts have been withdrawn since 2020; in 2025 alone, withdrawals topped 750 gigawatts while only about 600 gigawatts of new requests entered. Only around 311 gigawatts, about 12 percent of the active queue, had signed interconnection agreements — the closest thing the queue has to a commitment device. The typical project that did manage to get built in recent years waited something like four to five years from request to switch-on.

This is not a pipeline. A pipeline delivers things. This is purgatory with paperwork — and purgatory, it turns out, had a business model. The speculative mass slowed the studies for everyone, which lengthened timelines, which caused more withdrawals, which forced the restudies of everything queued behind them. A doom loop, administered one serial study at a time. And it had consequences beyond long waits. Viable projects died in the queue, squeezed between upgrade costs that ran 44 percent higher in 2019–2023 than in the five years before and timelines no business plan could survive. In effect, the country was rationing new power through waiting times. That couldn't hold — not with the scale of construction now being attempted — so regulators rebuilt the process around money: deposits to enter, collateral to stay, forfeiture for leaving late. And a filter with money in it started behaving like a market, whether or not anyone quite intended that.

In July 2023, the Federal Energy Regulatory Commission unanimously issued Order No. 2023, the biggest overhaul of generator interconnection rules in two decades. The diagnosis was blunt: the queue was clogged with speculative, commercially non-viable requests. But the cure was plumbing. Study projects in clusters instead of one by one. Replace first-come, first-served with first-ready, first-served. Require real site control, real study deposits, and commercial readiness deposits to enter and to stay. Penalize withdrawals. Penalize transmission providers for late studies. This July, the D.C. Circuit upheld the entire rule, writing that "FERC, in short, identified a real problem in the energy generation system, selected a reasonable alternative to the status quo, and provided rational policy reasons for its decision."

PJM, the grid operator for thirteen eastern states, is the live demonstration. Years ago it stopped taking new interconnection applications entirely while it worked through a backlog north of 300 gigawatts. When its reformed queue reopened this year, 811 projects applied for roughly 220 gigawatts; 715 were accepted into the cycle for 201.5 gigawatts; 617 entered the first study phase in late September for about 169 gigawatts. The screen filtered out a quarter of applicants before a single study was performed — the mechanism working as designed. The first real money decision, when developers must post additional security or walk away, lands at the end of November. Around the screen, PJM has built a whole apparatus of speed lanes: surplus interconnection service for unused headroom at existing plants, provisional service, transfers of capacity rights from retiring generators to replacements at the same site, a one-time initiative to fast-track eight or nine gigawatts of reliability-critical projects. The operator is, in effect, running a bazaar of quasi-markets around the main event.

PJM's price list is where the story turns.

To enter the queue: a study deposit of $75,000 to $400,000 depending on project size, ten percent of it non-refundable from the start. A readiness deposit of $4,000 per megawatt. Documented control of 100 percent of your site for at least a year. At the final decision point: security equal to 100 percent of your allocated network-upgrade costs, plus three years of site control, before interconnection-agreement negotiations even begin. Miss a decision point and escalating portions of your deposits are forfeited. Forfeited deposits are pooled across the cycle to backfill the network upgrades stranded by late-stage withdrawals. The quitters literally fund the grid.

There is even a circuit breaker, the way a real exchange has circuit breakers: if your allocated upgrade costs jump more than 25 percent — and more than $10,000 per megawatt — at the second decision point, you get your deposits back. The designers knew they were building something with prices in it. They just didn't call it a market.

But that is what it is. It has entry prices, collateral requirements, forfeiture, and something very close to a property right: your queue position determines whether you get studied, what share of shared upgrade costs you absorb, and whether you survive to the end. Nobody held a hearing on whether America should have a market for interconnection rights. FERC built a filter to kill speculation, and a filter with money at stake becomes a market. That is the mechanism — designed as a filter, functioning as a market.

Morgan Stanley's power analysts have reportedly estimated that a one-year head start on electricity is worth about $4.50 per watt to a data center developer. Time-to-power is the commodity now, and the queue is the exchange where it trades. A hyperscaler doesn't primarily compete on chips or capital anymore. It competes on interconnection.

And like every market, this one has an allocation criterion — a rule for who gets the goods. Under first-come, first-served, the queue allocated on punctuality: who asked first. Under first-ready, first-served with escalating collateral, it allocates on capital and readiness: who can post $4,000 a megawatt without blinking, hold site control for years, and swallow the full cost of network upgrades at the final decision point.

The winners select themselves: deep-pocketed developers and hyperscalers, obviously — the parties for whom a seven-figure deposit is a rounding error. Incumbents who can transfer interconnection rights from a retiring plant to a new one at the same site, converting a dead asset into a live queue position. And, notably, natural gas: nearly 100 of the 201.5 gigawatts accepted into PJM's first reformed cycle is gas-fired, the largest single fuel share. That is not a coincidence and not quite a conspiracy either. Under a market that allocates on speed, the fuel that can be permitted and built fastest is the fuel that wins. Gas doesn't have to be anyone's favorite. It just has to be ready.

The other side of the ledger is less comfortable. Smaller developers, for whom escalating at-risk deposits are existential rather than annoying. Technologies with long development lead times, which are structurally worse at demonstrating "readiness" on a regulator's timetable. And the speculative option-plays — the intended casualty, the one category everyone agrees should die. The trouble is that the filter cannot tell a speculator from a small developer with a good site and thin capitalization. Collateral requirements never can. They are a test of balance sheets wearing the costume of a test of seriousness.

Texas is the control group that proves the mechanism, because Texas spent years running the old system on the load side. Where queue position stayed cheap, fiction piled up five grids deep. So Texas is now building the same filter for loads that FERC built for generators. Senate Bill 6 requires large-load customers to demonstrate site control, self-fund their grid upgrades, disclose duplicate interconnection requests across the state, and accept curtailment during grid stress. ERCOT's new Batch Zero process studies big loads in clusters — first-ready, first-served, the Texas translation of Order No. 2023. And the governor's audit functions as a solvency test: demonstrate site control, funded upgrades, and full disclosure of load and water use, or be denied connection regardless of your place in line. Different state, different politics, same discovery. When the line is free, everyone gets in it, and the line stops working.

The same apparatus is now being turned on the buyers, which is where the story stops being about power plants and starts being about the entire economy. On June 18, FERC issued six show-cause orders — one for each regional grid operator — aimed at interconnection rules for large loads: data centers, advanced manufacturing, anything drawing more than 50 megawatts. The orders demand faster and more transparent study processes and, crucially, clear rules for who pays for the upgrades new loads trigger. As Commissioner LaCerte put it in a concurrence, "We are at an inflection point in the history of American energy infrastructure. The extraordinary and rapid growth of large loads in RTOs and ISOs is faster than the current system can handle." The proceedings were paused in August at the operators' request, to give them time to write real tariff proposals, and are expected to resume around mid-November — days before PJM's developers face their first real-money decision at the end of the month. The market is about to hold its first trading session.

Underneath every queue fight, though, is the same older fight: who pays. The interconnecting customer is supposed to cover the network upgrades its project triggers — the "but-for" test — but when a cluster of projects jointly triggers a billion-dollar transmission build, the allocation is politics done by spreadsheet. And the sums are getting large enough to notice.

In July, PJM proposed a one-time "backstop" auction to procure 6.8 gigawatts of capacity for reliability, at an estimated cost of up to $20 billion, with contracts running as long as fifteen years — an extraordinary departure for a market built on annual capacity auctions. On September 29, FERC partially approved the plan but suspended it for five months, ruling that the cost allocation might be unjust and unreasonable, and pointedly suggesting the costs be assigned using updated load forecasts so that new large loads bear them. "Existing customers should not be left paying costs attributable to new demand," Commissioner See wrote in concurrence. The chairman was blunter: "This commission will not be forced into accepting a deeply flawed, eleventh-hour procurement mechanism with billion-dollar implications for consumers." For context on what's at stake: data centers were $6.5 billion of the $16.4 billion total in PJM's last capacity auction — 40 percent, paid by everyone.

The parable is Susquehanna. In March 2024, Amazon paid $650 million for a data-center campus next to Talen Energy's nuclear plant in Pennsylvania and tried to take power straight from the reactors, behind the meter. Utilities objected that the arrangement let one giant customer rely on the grid without paying for it; FERC rejected the expanded deal 2–1 in November 2024, and the appeal was dismissed that January. Then the whole thing was rebuilt the boring way: a seventeen-year, grid-delivered power purchase agreement for up to 1,920 megawatts through 2042, worth something like $18 billion notionally, which took effect this April. Strip away the electrons and the story is pure queue economics. "Behind the meter" was never about physics. It was about who pays for the shared grid — and the answer, in the end, runs through the market.

Every era rations its scarcest input through whatever institution happens to be lying around. Ours happens to be interconnection paperwork: procedures designed for a slower grid, in a slower century, to answer a duller question — in what order do we study these power plants?

It now answers a different question: where does the AI buildout physically happen, which utilities get to grow their rate base, who earns the return on the largest capital deployment in a generation. And it answers not by willingness to pay for electricity, but by willingness to post collateral for a place in line. The old system — free options, five-year waits, fiction piled five grids deep — was worse. The point is to notice what we have built.

Nobody designed a market for the right to plug into America. We got one anyway, assembled out of deposits, deadlines, and forfeitures. It now rations the binding constraint on the AI buildout, and almost nobody outside the industry has ever heard of it. The queue was supposed to be plumbing. It turned out to be the market. The work ahead is deciding whether it's the market we want: who it should select for, what it should price, and who should pay.

Sources consulted for this essay: Lawrence Berkeley National Laboratory, "Queued Up: 2026 Edition" (slide deck); PJM Inside Lines reporting on Cycle 1 of the reformed interconnection process; FERC Order No. 2023 and the D.C. Circuit's July 2026 decision in Advanced Energy United v. FERC; FERC's June 2026 show-cause orders on large-load interconnection (e.g., EL26-72-000) and related concurrences; the August 2026 directive letter from Governor Abbott to the PUCT and ERCOT; PJM's July 2026 backstop procurement filing and FERC's September 2026 order; reporting from Reuters, Utility Dive, E&E News, PowerMag, and Latitude Media.