Why Texas Is Making Data Centers Wait

At the end of 2024, Texas’ grid operator had 63 GW of large new customers in its queue. By this June, that figure reached 474 GW, more than five times record peak demand, about 90% of it data centers.

Then Texas hit pause. What began as directions for data centers to pay for their own grid upgrades has since escalated to a freeze on all new permits. If you care about AI and American reindustrialization, this is important to understand. Why did it do this?

The upcoming election is part of it, but the underlying issues are worth digging into. The first is the interconnection queue. This pause is just as much about how projects apply for approval as it is about the projects themselves. Developers routinely spam projects across several sites, and many are speculative builds with no customer yet. Often these new developers have never even plugged in a GPU, let alone a power plant, so dealing with low-quality submissions puts ERCOT, which runs most of the state’s grid, in a tough spot. Planners can’t tell which are real, and they don’t want ratepayers paying for upgrades built for projects that never show up.

The second issue is community alignment. Noise, water, emissions, and power bills are top of mind for anyone who lives nearby. And regardless of the reality of these issues, people deserve straight answers when a data center comes to town, and they haven’t always gotten them (as of June, only 28 of 377 companies had answered a state survey on their resource use). In Hood County, commissioners were asked to support a tax waiver for “Project Patriot” without knowing who it was. To be fair, code names are common while companies shop for sites since a famous buyer can drive up prices, but that logic becomes tougher to defend once officials vote on tax breaks.

The broader political backdrop is important, but I’ll be focusing on the energy side: why it’s so hard to power a data center, all the ways developers are trying to do it anyway, and where things are likely headed.

That’s no longer true. The grid is stretched thin, and almost any new large load or generator now requires an upgrade. Power flows across every connected path, so buying from one plant doesn’t reserve a route to your building (there are even markets for transmission congestion rights).

So buyers went after firm power (available around the clock) they could claim more directly, typically by restarting retired plants or by building next to existing ones. Neither was a true escape, and some of the loudest fights are over “colocation,” which ERCOT describes as drawing power from a neighboring plant before it reaches the grid:

Interconnection studies are how grid planners identify the wires and substations that need upgrades for any addition to the network. ERCOT used to review studies individually under rules built for 40 to 50 large loads at a time, but 2025 brought 225 new requests by mid-November. So this June, the PUCT approved a new batch approach. Under “Batch Zero,” ERCOT studies large loads of 75 MW or more together and allocates grid capacity among them.

Primarily, the studies ask what happens when something breaks. NERC’s standard, the baseline for reliability across North America, covers a broad set of outage scenarios, with ERCOT adding its own requirements. Planners might simulate a transformer outage, then knock out a line or generator on top of that. Maintaining that reliability standard without shedding more load often means building additional infrastructure.

A newer risk is load dropping off the grid all at once. Many data centers switch to backup power at the first voltage dip to protect their hardware, so one bad fault can pull an enormous load off the grid in seconds. This happened earlier this year in Virginia, but was fortunately handled well.

Texas has even less room for error since ERCOT’s grid is largely isolated. Under some conditions, ERCOT can lose only about 3.2 GW of load at once before causing issues. A new voltage ride-through rule now requires new data centers to stay connected through routine faults, and I’ve even heard of labs running dummy jobs after a training run fails just to keep load from dropping abruptly.

All of this can sound overly conservative, but the system was designed to put reliability ahead of cost. Put simply, the grid is built for the hot summer days and frigid winters when failure can mean life or death. That duty is what makes sizing the grid so hard; you build for a few peak hours but pay for it all year.

So who does pay for all this resilience? Texas typically splits transmission costs by each large customer’s demand during the grid’s summer peaks, so a big load that ramps down on the hottest afternoons can skip much of its share of the transmission bill. In July, regulators proposed counting all 12 monthly peaks instead and charging large loads as if they ran at full size. In other words, large buyers would pay in proportion to how big their electricity pipes need to be, not how much is flowing through them.

Sounds simple enough, but splitting up costs is often the slowest part of interconnection. An upgrade built for one campus may also improve reliability for existing customers or make room for future growth that’s hard to value up front. And if any new development runs over budget or its load never shows up, everyone else is forced to cover whatever the developer’s commitments didn’t.

And those commitments are surprisingly cheap to make. The PUCT’s new large-load rules, effective October 8, charge a flat $100,000 study fee plus a $50,000-per-MW deposit. The deposit weeds out some speculative projects, but it’s a thin filter. ERCOT can reassign a project’s capacity if it falls two years behind, but even a project that loses its capacity forfeits just 20% of the deposit (at least $10 million on a 1 GW campus), plus whatever the utility has already spent. Most importantly, the deposit typically only backs the upgrades built for that project, not the more expensive regional lines whose cost everyone on the grid shares.

Fully connecting a large data center can take 5 to 10 years. To accelerate deployment, a phased connection approach is becoming more common, which gives the utility more gradual targets to plan around, as well as a way for the developer to prove they can handle everything they’ve asked for. All of this also assumes Batch Zero is moving, which it isn’t right now. ERCOT has even paused approvals for data centers of 75 MW or more to switch on, including 17 that had finished every other ERCOT step. Until the audit’s December report settles which projects are eligible, ERCOT can’t study them together, so the timeline is “TBD” and the load forecast is on hold.

For a developer facing the interconnection queue, skipping the grid entirely looks appealing. Idle GPUs cost far more than the electricity to run them, so speed matters most — what folks call “time to power.” That’s why developers are planning to bring their own power on site (“behind the meter”), but almost always alongside a connection to the grid, or as a bridge to one:

SemiAnalysis is already tracking 75 GW of equipment orders for behind-the-meter assets, but every site I’m aware of intends to connect to the grid as soon as it can, chiefly because on-site power almost always costs more. So, once the grid is available, say in year five, you switch.

In the meantime, pairing on-site assets with even a partial connection is smart for the same reasons we built a grid in the first place. When one plant trips, the rest of ERCOT’s 1,460-plus generating units cover for it, but an islanded load (cut off from the grid) doesn’t have that luxury. The grid also provides things we take for granted, like inertia, fault current, steady voltage, and black start. An island has to supply all of that itself — power systems folks know how hard this can be.

AI workloads make the job even harder. At xAI’s first Memphis site, swings of 10 to 20 MW several times a second were wearing out turbine shafts until xAI added 150 MW of Tesla Megapacks. A grid ERCOT’s size dilutes swings like that, but on a private plant the turbines really feel it. Expect more batteries and other energy storage as rack-level power density grows and swings become more dramatic.

Then there’s fueling a site. Winter Storm Uri’s lesson is that gas plants can fail together. And since they tend to keep little fuel on site (NERC calls gas a “just-in-time” fuel), spare turbines don’t always help. Sometimes the pipeline doesn’t even exist yet. Solar trades that fuel risk for the sun and weather, and at gigawatt scale, you need a lot of batteries. Keeping a 1 GW campus running through one 14-hour winter night takes 14 GWh from batteries, about half of all the battery storage on ERCOT’s grid as of June. For an island seeking 100% uptime, covering rare events like a cloudy week or another Uri gets expensive.

Whatever the fuel, you want an island that fails gracefully and predictably, with no single point of failure. Even nuclear, about as reliable as power plants get, runs only about 92% of the time, mostly because each reactor goes offline for weeks to refuel. Redundancy in this case means effectively an entire second power plant. Thus, behind-the-meter setups favor modularity, like the more than 500 gas engines of about 4 MW each planned for Shackelford, though hundreds of engines can be a pain to maintain.

Full reliability for an island is very, very hard, but some labs and hyperscalers have shown that, forced to choose between reliability and speed, they’ll pick speed. Meta has turned to tents with no backup generators, and SemiAnalysis finds buyers growing more willing to accept outages, with some island designs aiming for as little as 99% uptime, or about 88 hours of downtime a year. With GPU time this expensive, that still beats years of waiting, so for many buyers a temporary island makes sense even if it’s messy.

A “private grid” that ties several plants and campuses together can take back many of the benefits a lone island gives up, at least in theory. But today Texas, like most states, only allows building your own power within tight limits:

The Cato Institute’s consumer-regulated electricity proposal would loosen those limits by allowing private utilities to serve multiple customers across their own network. This isn’t an entirely new idea; Utah’s SB 132 lets loads of 100 MW or more contract for a fully off-grid system. Texas currently doesn’t let a network like this serve multiple customers, but if the demand for power remains insatiable, I’d expect the more permissive states to win larger chunks of the buildout with this “Wild West” utility structure. (However, you may also risk a utility “death spiral,” with the grid’s fixed costs falling on fewer and fewer customers.)

The flip side is a utility building the island itself. Outside ERCOT, El Paso Electric plans to put 813 small gas generators from ERock (366 MW in all) beside Meta’s new campus and run them as an island, on Meta’s dime, for up to five years. This is an option because, unlike the transmission and distribution utilities inside ERCOT, it still owns power plants. After the island period, it would connect the plant to its grid and could seek to spread the cost across all its customers, though in September administrative judges recommended approval only if those customers are protected.

Anything that runs on fuel also needs an air permit that matches how it operates, so a diesel generator permitted only for emergencies can’t run all the time. Optimis