The disclosure and our analysis
Evidence dates
Evidence: Public Utility Commission of Texas adoption order in Project No. 58481, filed September 18, 2026, and the Texas Register acknowledgment filed the same day.
The Public Utility Commission of Texas has adopted new rule 16 TAC §25.194, setting the standards large loads must meet to connect to the ERCOT grid. The rule implements PURA §37.0561, enacted by Senate Bill 6. The adoption order was filed September 18, 2026. The Texas Register acknowledgment lists an October 2 issue date and an October 8, 2026 effective date. Status: Approved, as an adopted rule not yet in effect as of September 26. [Source 1] [Source 2]
Who it applies to
The rule applies to a large load customer that has not energized by the effective date and seeks a new interconnection of 75 MW or more at a single site. It also covers an expansion that reaches 75 MW for the first time, an expansion of a site already above 75 MW by 75 MW or more, and co-location with a generation resource. For expansions, it applies to the added load. [Source 1]
These thresholds are measured in non-coincident peak demand requested from the utility at a single site. That is a utility service figure. It is not critical IT load.
What a project must do before it is studied
Before a request enters an ERCOT interconnection study, the customer must sign and fund an intermediate agreement with its utility. The agreement requires four sets of disclosures. [Source 1]
Site control, through a deed, a lease running at least five years past the date the load reaches its requested peak demand, or a signed option to buy or lease.
Any substantially similar request elsewhere in Texas whose approval would lead it to change, delay or withdraw this one. The rule defines a material change as a delay of a year or more, a 20% or greater change in requested demand, or a move of the interconnection point.
The development schedule, progress on site studies, and the state and local approvals still needed.
How it plans to buy power, whether it has on-site generation that can run in parallel with ERCOT, and whether it plans to register as a controllable load resource.
The customer pays a $100,000 study fee, with any unused portion returned within 60 days after the study ends. ERCOT protocols may add a separate flat fee. It also posts financial security of $50,000 per MW of requested peak demand, or of the added demand for an expansion. Both amounts are indexed to inflation every five years starting in 2032. [Source 1]
After ERCOT allocates capacity
Within 60 days after ERCOT issues a study report allocating transmission capacity, the customer must sign and fund a standard large load interconnection agreement. Security at that stage is the greater of $50,000 per MW of contracted peak demand or the system upgrade costs allocated to the customer. The customer also pays contribution in aid of construction for direct interconnection costs, which the rule says is not refundable. [Source 1]
The order says the commission removed the interconnection fee that had been proposed at this stage. It describes the remaining security as protection against stranded costs, not a fee. [Source 1]
Milestones and refunds
If a customer is 24 months behind its phased energization schedule, the utility must report the unused capacity to ERCOT within 30 days. The 24 months apply to the schedule as a whole, not to each milestone. Within 60 days the utility draws on the security for amounts owed, keeps 20% of the security tied to the unused capacity, and returns the rest. [Source 1]
For a project that energizes, the order says 20% of the security is returned at energization. The remainder comes back in 20% steps as the customer meets the minimum billing milestones in its agreement. A customer allocated 0 MW gets its security back after amounts owed are collected. [Source 1]
What the reviewed order does not settle
The order says eligibility for ERCOT's transitional Batch Zero study is governed by Planning Guide Revision Request 145, approved June 18, 2026, and not by this rule. It says the path for loads under 75 MW is outside the rule's scope. [Source 1] We reviewed the order's rule text and summary sections, not every one of its 270 pages of responses to comments. The order does not publish per project cost estimates or queue positions.
Buyer analysis
The rule's obligations fall on the large load customer, usually the developer or operator, not on a colocation tenant. But they shape which Texas capacity is real. A developer that posts $50,000 per MW has money at risk behind its request. By our arithmetic, a 200 MW request means $10 million of intermediate security, before any upgrade costs.
When a provider pitches future ERCOT capacity, ask where the site stands: intermediate agreement signed, ERCOT allocation received, or standard agreement signed. Ask for the allocated contracted peak demand, the phased energization schedule in that agreement, and how far the project sits from the 24-month trigger. A site with allocated capacity and a signed agreement is further along than one that has only filed a request. None of those steps makes capacity available for lease on its own.
