The Plant That Outlives the Bridge

On-site gas has become a way to energize a data center years before the grid can. On October 1, 2026, Enerflex announced an award for about 450 MW of behind-the-meter gas generation for a North American data center developer, with deliveries in 2027 and 2028, and said demand is growing for "reliable, prime power that does not require grid connection."¹ Some of these plants are meant to run off-grid for good. Many are a bridge until the grid connection is ready.

Bridges tend to run long. In April 2026 ERCOT's large-load queue held 445.8 GW of applications through 2033. 321 GW of those had not yet submitted studies, and 5.9 GW was energized. Much of that queue will never be built, but each real project waits in the same line.² New heavy-duty turbines are booked toward 2029, as set out in If You Can't Get a Turbine Until 2029, What Powers the Load? The bridge lasts as long as the interconnection takes, a clock nobody on the project controls (see The Hidden Clocks of Power). When the grid does arrive, the plant is likely to stay, because the equipment outlives a wait of a few years and removing it strands capital already spent.

So the real question is what the plant's years after interconnection are worth, and to whom. The answer depends on whether the bridge already paid for the plant.

The later years are a windfall or a bill

All figures here are percent of the plant's build cost per year, for a 15 percent return, on the same basis as What 15 Percent Takes on a Data Center Gas Plant. To pay off the plant fully during the bridge, the data center has to pay:

If the bridge pays off the plant, the later years are a windfall. Backup payments, market income and the resale value of the units are largely upside after running costs, and the question is who owns them. Some data centers may pay that much for speed. Whether a given load can depends on its margin.

If it does not, the later years are a bill. A plant paid 20 percent a year for a three-year bridge still needs about 13 percent a year as backup to reach its return over 25 years. The market pays only part of that. On real-time prices, a backup plant at ERCOT's North and Houston hubs would have earned 7 to 11 percent of its build cost from energy in 2023 and 1 to 3 percent in 2024 and 2025; at the West hub, where gas is cheaper, about 4 to 17. A backup fee from the data center has to cover the rest.

Either way, a backup plant runs fewer hours and starts more often, so its maintenance follows starts rather than hours, and someone has to agree who pays for each start.

The public record rarely says who holds these years. We tracked 31 data center gas plants in Data Center Gas Plants: The Record. Where end-of-term terms are disclosed for off-grid plants, they are renewals, extensions and one buyout right, some at the customer's option. For plants in organized markets they are not disclosed at all. Private contracts may say more. What the public terms do not show is who keeps the later value of a plant that was paid off, or who pays the backup fee for one that was not. Both are easiest to settle before the first unit ships.

A plant that can move is worth more at the end

An off-grid plant has one buyer, the data center next door, so its value after the contract depends on renewal. Moving is the alternative to staying on as backup: at the end of the contract the owner can keep the units as backup or sell them to another site, and whichever pays more sets what the plant is worth. On a 10-year contract:

Units that can be lifted, moved and sold to another site keep a value outside the first contract. A large turbine on its own foundations is much harder to move. That residual value can reduce the required annual charge by roughly 6 to 12 percent, which the data center sees as a lower price or the owner keeps as a higher return. It holds only if there is a buyer for used units when the contract ends.

Whether the plant can export

In Texas, whether the plant can export largely determines what it can become after interconnection. Once the site connects, Senate Bill 6 of 2025 treats a plant that cannot export and can carry at least half the site as backup. In an emergency, after its market services are used, ERCOT can require the data center to run that plant or cut load, and the law sets no payment for it.³ The same law creates a paid service for loads of 75 MW or more that cut demand on 24 hours' notice, but it excludes loads already selling into other ERCOT services, so a site has to choose. In April 2026 ERCOT split out its rules for large loads that bring their own generation, to consider them separately.²

A plant that can export can sell into the market, but the market pays most in the hours the grid is short, which are the hours the data center needs the plant most. It earns most only if the load can step aside then. Texas has one order with that condition, in a different arrangement: a 760 MW data center added behind the grid connection of Freestone Energy Center, an existing 1,099 MW gas plant. The order keeps the plant's available capacity in ERCOT's dispatch, and the data center "fully curtails its consumption" within 30 minutes when ERCOT directs.⁴ Switchgear, protection, telemetry and an interconnection plan for export cost far less before the order than after the plant is built.

A battery helps before and after interconnection

Following an AI training load is harder than supplying its energy. NERC's large-load task force found that the switch between training and saving checkpoint progress "may happen in under one second," and that for AI training loads "there may be no UPS for the IT equipment."⁵ With no UPS, nothing buffers those swings, and a unit trip reaches the IT load directly. Gas engines and turbines accept only limited load steps and ramp at limited rates. Covering fast swings with them alone means running extra units part-loaded.

A grid-forming battery takes the fast swings and rides through a unit starting or tripping, while the engines carry the sustained energy. The same battery and controls also make it easier to answer a market signal or a curtailment order later, if the plant is set up to export and the load can step aside. Any cut in installed units that relies on the battery has to be shown in a reliability study first.

Fuel and permits still set the boundary

Is the gas supply as firm as the uptime promise? In Winter Storm Uri in February 2021, gas production and power generation failed together, as the FERC and NERC inquiry documented.⁶ And does the air permit cover the running hours a backup or market role needs, or only the bridge years?

What to put in writing before the equipment order

• Whether the bridge payments repay the plant, and who owns it and its later income after interconnection either way.
• What the data center pays for backup if the plant is not repaid, in the first contract rather than at renewal.
• Who pays for starts and maintenance once the plant runs as backup.
• Export rights: whether the plant can export, and whether the campus can step aside in the hours the market pays.
• Removal and resale: whether the owner can move and sell the units at the end of the term.
• How much of the reserve and fast-response duty a battery takes, shown in a study.
• Firm fuel and a permit that covers the later running hours.
• What is energizing 12 to 24 months earlier worth? On the illustrative case in When Faster Power Stops Being Expensive, the best path changes at about $49 and again at about $114 per MWh of what the load earns.

The highest leverage point is the design and contract review before the equipment order. Every answer above is cheap there. Afterward, each becomes a retrofit or a renegotiation.

Sources

Footnotes

1. Enerflex Ltd., press release of October 1, 2026, furnished on Form 6-K. https://www.sec.gov/Archives/edgar/data/0001904856/000119312526410172/efxt-ex99_1.htm ↩

2. ERCOT Monthly Operational Overview, April 2026. https://www.ercot.com/files/docs/2026/05/13/ERCOT-Monthly-April-2026-FINAL.pdf ↩ ↩²

3. Texas Senate Bill 6, 89th Legislature, enrolled text, adding Utilities Code sections 37.0561(e) and 39.170(b). https://capitol.texas.gov/tlodocs/89R/billtext/html/SB00006F.htm ↩

4. Public Utility Commission of Texas, Docket 58872, item 104, order of May 7, 2026 (Freestone Energy Center, net metering arrangement). https://interchange.puc.texas.gov/Documents/58872_104_1639665.PDF ↩

5. NERC Large Loads Task Force, "Characteristics and Risks of Emerging Large Loads," white paper, July 2025, PDF pages 11 and 13. https://www.nerc.com/globalassets/who-we-are/standing-committees/rstc/whitepaper-characteristics-and-risks-of-emerging-large-loads.pdf ↩

6. FERC and NERC, "February 2021 Cold Weather Outages in Texas and the South Central United States," FERC, NERC and Regional Entity joint staff report, November 2021. https://ferc.gov/sites/default/files/2022-12/A-3%20-%20The%20February%202021%20Cold%20Weather%20Outages%20in%20Texas%20and%20the%20South%20Central%20United%20States.pdf ↩