A company that wants to plug a large data center into the Texas grid would sign one standard contract that makes it post cash-backed guarantees, report how much water it will use and disclose its backup generators, under a draft the Public Utility Commission of Texas will consider Nov. 5.
Commissioners will decide that day whether to publish the 172-page draft for public comment, according to a staff memo filed Oct. 29 as agenda item 40. The form would replace deals that developers and utilities now negotiate one at a time. It writes into a contract the requirements of Senate Bill 6, the 2025 law on huge power users, and of the commission’s large-load rule that took effect Oct. 8.
The money terms are the heaviest. The draft says the customer must post security with each utility involved equal to the greater of $50,000 per megawatt of the peak demand it reserves, an amount the commission can adjust under its rule, or the cost of grid upgrades assigned to it. A second guarantee, a letter of credit, would cover 60 months of the customer’s “minimum billing demand.” That is a charge, still being written in a separate commission rulemaking, that makes a customer pay for the grid capacity it reserves whether or not it uses all of it. Under the draft, the charge cannot shrink even if the customer cuts its requested demand or grid operators reassign its capacity.
The draft also sets a clock. A customer’s phased power-up schedule may not slip more than 24 months in total, except for events beyond its control such as a disaster. If it does, the utility must tell the Electric Reliability Council of Texas, the agency that runs the grid for most of the state, within 30 days, and the council may give the unused capacity to someone else. The utility would draw on the customer’s security to cover what is owed, subtract 20% of the security tied to the unused capacity and return the rest.
Disclosure is the third piece. In an exhibit on water, a customer must project the gallons it will withdraw each year, how much it will recycle, and its net use. It must name each source, such as city water, wells, surface water or reclaimed wastewater, and say whether the use is metered or estimated. One-time uses, such as flushing cooling systems before startup, are counted separately.
For backup generators, the customer must list each unit’s capacity in megawatts, its fuel, any limits on running hours under its permits, and how fast it can ramp up. The Electric Reliability Council or the commission may audit those figures “as many” times as necessary and may demand proof from the water or power provider. All parties must also comply with the Lone Star Infrastructure Protection Act, a Texas law limiting certain foreign companies’ ties to critical infrastructure.
Before a project is energized, the customer could hand the agreement only to a company named in advance as an end user that will run the same kind of load. Both sides’ executives would have to attest in writing that the new company can pay the minimum charge and post its guarantee. The commission also asks whether assignment should be barred outright and whether a local utility must build lines for a data center that sits beside its own power plant.
Staff say the benefit will be “standardization of large load interconnection agreements to support business development while minimizing the potential for stranded infrastructure costs.” They found no adverse effect on small businesses or rural communities. The notice warns that comments cannot try to overturn what the large-load rule already requires, which narrows the debate to how the terms are carried out. As of Oct. 30, the project docket held only the staff filing and a request to restyle the project, so no developer, utility or consumer group had yet put its objections on the record. The draft also says its terms may change once the separate cost-recovery rules are final.
In plain terms, the form asks each developer to show it can pay for the grid it reserves and to say in numbers how much water and backup power it will draw. Commissioners vote Nov. 5, and comments and any request for a public hearing are due Dec. 14.