For most of ERCOT's history, connecting load was the easy half of the grid. You asked, the utility built, and the queue everyone argued about was the generation queue. Senate Bill 6, signed on 20 June 2025, ended that.
The statute and the rule that implements it are short enough to read and specific enough to plan against, and the numbers in them are large. This is what the regime requires.
The statute: a 75 MW line in the sand
SB 6 adds Section 37.0561 to the Utilities Code, directing the PUCT to establish standards for interconnecting large load customers in ERCOT. On the threshold, the bill is direct: "The commission shall establish a demand threshold of 75 megawatts unless the commission determines that a lower threshold is necessary."
Seventy-five megawatts, at a single site, is now the line between an ordinary customer and a regulated category.
Three other parts of SB 6 matter as much as the threshold.
Curtailment during firm load shed. New Section 39.170(a) requires protocols allowing transmission-voltage customers to be curtailed "during firm load shed." Crucially, the provision "applies only to a load interconnected after December 31, 2025, that is not" a critical industrial or natural gas facility. That date is a genuine cliff: a campus energised in 2025 sits on one side of it, an otherwise identical campus energised in 2026 sits on the other.
A paid demand-response product. Section 39.170(b) requires "a reliability service to competitively procure demand reductions from large load customers with a demand of at least 75 megawatts to be deployed in the event of an anticipated emergency condition." Curtailment is the obligation; this is the market that pays for flexibility offered ahead of it.
Backup generation can be compelled. Section 37.0561(e) allows the independent organization to direct the utility to "require the large load customer to either deploy the customer's on-site backup generating facilities or curtail load." Diesel gensets a data centre bought for its own uptime become, under defined conditions, a grid resource it can be told to run.
SB 6 also directs the Commission to evaluate "whether the current four coincident peak methodology used to calculate wholesale transmission rates" assigns costs appropriately — a study, not an amendment, but one worth watching, because 4CP is how large Texas loads have historically managed their transmission bill.
The rule: proposed 16 TAC §25.194
On 12 March 2026 the PUCT voted to publish draft 16 TAC §25.194, proposed in Project No. 58481 and published in the Texas Register on 27 March 2026, with comments due 17 April 2026. It is a proposal, not a final rule, and the figures below can still move.
The rule defines a large load customer as "an entity requesting a new or expanded interconnection where the customer's total expected non-coincident peak demand at a single site is equal to or exceeds 75 MW." Note non-coincident peak at a single site: this is the customer's own maximum, not its contribution to system peak, and campuses are aggregated.
The intermediate agreement
The rule's structural innovation is a contract that has to exist before a study can start. An intermediate agreement is "an agreement that is executed by a large load customer, the interconnecting DSP, and, if different from the interconnecting DSP, the interconnecting TSP before the interconnection study are initiated."
In the old sequence, a developer could ask for a study, see the answer, and then decide. The intermediate agreement inverts that: commit, then learn.
The money
The study fee is tiered. A customer "with requested peak demand that is equal to or greater than 75MW and less than 250MW must pay a study fee not less than $100,000 to the interconnecting DSP or the interconnecting TSP for transmission studies performed by the interconnecting DSP, the interconnecting TSP, and ERCOT, as applicable." At 250 MW and above, the floor is $300,000. Both are floors — "not less than" — with actual costs above the floor recoverable and CPI adjustment beginning in 2027.
The number that changes project finance is the per-megawatt one: $50,000 per MW, appearing both as financial security tied to the intermediate agreement and as a non-refundable interconnection fee on contracted peak demand at the interconnection agreement stage.
Do the arithmetic on a gigawatt campus and it is $50 million. On a 300 MW facility, $15 million. These are commitments made before commercial operation, on a project whose tenant may not be signed.
It is worth knowing the commission had been considering double. The staff proposal for publication records that "the commission decided to reduce the financial security and interconnection fee commitments from $100,000 per megawatt to $50,000 per megawatt." Fifty thousand is the concession, not the opening bid.
What has to be disclosed
The rule asks for operating detail that large loads have not historically had to publish: a detailed energization schedule including MW, MW-reactive and power factor data; disclosure of backup generation with fuel source, run-hour limits and ramp time to full output; and disclosure of any co-located generation and of controllable load.
Ramp time to full output is the interesting one. It is the question a system operator asks when it wants to know how fast this thing can get out of the way.
What stakeholders are fighting about
The comment file is where the real disagreements sit. One filing in Project 58481 makes two arguments that are likely to shape the final rule.
First, that ERCOT is underfunded by the fee split: the study fee as drafted means "the majority of this fee goes to the utility, with only a relatively small portion allotted to ERCOT's own study costs," and commenters recommend "increasing ERCOT's share of the study fee to ensure ERCOT is adequately funded to perform its critical system reliability analyses in a timely manner." If the point of the rule is faster, better studies, the money has to reach the entity doing the hardest modelling.
Second, that the security should not apply to phased growth: "the proposed financial security requirement of $50,000 per MW should apply only to brand-new large load projects, not to incremental expansions at existing sites." As drafted, a customer already at 400 MW adding another 75 MW posts security on the increment. For the phase-by-phase build-outs that are the industry norm, that is a recurring capital charge rather than a one-time entry fee.
How this compares
It is worth putting the Texas numbers next to the other market that has just rewritten its large-load rules. SPP's HILL process, accepted by FERC in January 2026, sets its threshold at 50 MW above 69 kV (or 10 MW at and below), charges a $10,000 application fee and a $100,000 study deposit, and asks $8,000/MW of security — but only from the generator that a large load brings with it under HILLGA, not from the load.
Texas is asking $50,000/MW from the load itself. That is a different theory of the problem. SPP is trying to make sure the generation is real; Texas is trying to make sure the load is real, because the stranded-cost risk SB 6 names is transmission built for a data centre that never opens.
What the rule does not do
It is as important to be clear about the gaps, because they are where the next round of rulemaking will land.
It does not set a curtailment product. The proposed rule addresses controllable-load disclosure; it does not itself define how or how often a large load is curtailed, or what it is paid. Those live in SB 6's Section 39.170 and in the ERCOT protocols that implement it, on their own timetable.
It does not resolve 4CP. SB 6 asked the Commission to evaluate whether the four coincident peak methodology still assigns wholesale transmission cost appropriately. That evaluation is a separate workstream. Until it concludes, a large Texas load still has the same incentive it has always had — curtail hard in the four fifteen-minute intervals that set next year's transmission bill — and the Commission has said out loud that it is looking at whether that incentive still makes sense when the loads doing it are this big.
It does not price co-located generation. A data centre that brings its own on-site generation sits at the intersection of the load rules, the generation interconnection rules and the question of what it owes for grid services it still relies on. SB 6 gives the independent organization authority to direct deployment of on-site backup; the economics of a behind-the-meter plant serving a 75 MW-plus load are still being worked out docket by docket.
It does not change the generation queue. Nothing in §25.194 makes it faster to build the megawatts these loads will consume. The rule disciplines the load side of the ledger. The supply side is still governed by ERCOT's connection study process and by whether anyone chooses to build.
What to do about it
Pin your energisation date against 31 December 2025. Everything about the curtailment obligation turns on which side of that date a load interconnects.
Carry $50,000/MW in the capital plan, and model it as sunk. The interconnection fee is non-refundable. This is not a deposit that comes back if the project changes shape.
Decide early whether you are flexible. Section 39.170(b)'s competitively procured demand-reduction service converts flexibility into revenue rather than a pure obligation. A facility that can genuinely shed or shift has a business case for doing so; a facility that claims it can and cannot will discover the difference during an emergency.
Inventory your backup generation honestly. Run-hour limits, permit conditions and ramp times are all disclosable, and Section 37.0561(e) means they may be called on.
Treat the intermediate agreement as the point of no return. It is executed before studies begin, and it is where the security attaches.
Watch the final rule. The proposal closed for comment on 17 April 2026; the study fee split and the treatment of phased expansions are the two provisions most likely to change, and both matter to a build-out plan. The PUCT's own SB 6 implementation overview is the clearest map of the parallel dockets.
Related on this site
- US data center directory — and Texas data centers specifically
- Live ERCOT grid conditions — what the system is doing right now
- ERCOT's 765 kV backbone — the transmission being built for this load
- Natural gas power plants in Texas — the supply side