Two states are now writing very different rules for how a company must commit to buying electricity before a large facility goes online, and the differences go well beyond the price per kilowatt-hour. Missouri's largest utility already has a state-approved framework in place. Texas is proposing one that would run for two decades. For a company comparing a Missouri site against a Texas site, those two regulatory structures are not variations on the same theme. They are different bets about how long a company must be locked in, when the financial clock starts, and how a slower-than-planned ramp gets priced.
Both states are responding to the same underlying pressure: utilities building infrastructure for enormous new loads want assurance that the cost does not land on residential customers if a project is delayed, downsized, or abandoned. But the mechanisms each state has chosen to provide that assurance differ enough that a company treating "large-load tariff" as a single, comparable line item across states is likely to misprice at least one of its site options.
Missouri's Framework Is Already Final
On Nov. 24, 2025, the Missouri Public Service Commission approved a settlement, embedded in Ameren Missouri's large-load tariff, that requires large customers to sign electric service agreements with a minimum 12-year term plus a ramp period of up to five years. Customers pay demand charges on at least 80% of contracted capacity, regardless of how much power they actually draw, and must post collateral equal to two years of minimum monthly bills, with discounts available for stronger credit ratings. Customers who want to leave early must give 24 months' notice or pay an exit fee tied to the minimum monthly bill for the contract's remaining term. The settlement also includes an earnings-sharing mechanism: if Ameren Missouri's return on equity exceeds a 9.74% threshold, the utility must return a share of the excess to customers, with a portion directed specifically to low-income ratepayer programs.
The framework applies to new facilities with expected monthly demand of at least 75 megawatts, and to existing customers expanding demand by the same threshold. It was negotiated among a broad set of stakeholders, including Google, Ameren Missouri, two other regional utilities, and consumer and industrial groups, which is part of why it reads less like a unilateral utility filing and more like a settled compromise unlikely to shift again soon.
Texas Is Proposing a 20-Year Clock That Can Start Before Energization
Texas is taking a different approach, and it is still just a proposal. On July 9, 2026, the Public Utility Commission of Texas released a draft rule under Project No. 58000 that would require qualifying large-load customers to make 240 consecutive monthly payments, a 20-year commitment, with minimum billing demand set at the greatest of the customer's contracted peak demand, its highest non-coincident demand from the prior year, or its measured 12-month coincident-peak demand. Comments on the proposal are due August 11, and the rule is not final.
The more consequential detail may be when the billing clock starts. Under the proposed framework, transmission billing would begin once reserved capacity becomes available to serve the customer, whether or not the facility has started operating or is using any of that capacity yet. A large load that has not yet energized would still be billed against its contracted peak demand. For a project running behind schedule on construction, equipment delivery, or commissioning, that timing detail turns a development delay into an electricity bill before a single server or production line is running.
Two Sites, Two Different Formulas for the Same 100 Megawatts
Comparing a Missouri site to a Texas site on these terms alone requires modeling structurally different mechanics, not just different numbers. Missouri's minimum bill is a flat 80% of contracted demand; Texas's proposed minimum is whichever of three separate demand measures turns out highest, which can shift depending on how a facility's early usage pattern compares to its contracted capacity. Missouri gives new customers up to five years to ramp toward full contracted demand before the minimum applies at full force; the Texas proposal ties billing to when the utility's capacity is ready, not to how quickly the customer's own construction and commissioning proceed. Missouri requires two years of collateral upfront, while the Texas billing proposal, as drafted, does not include a comparable collateral requirement.
None of that shows up by comparing a cents-per-kilowatt-hour rate side by side. It shows up when a site-selection team maps out what happens if a project's ramp takes six months longer than planned, or if construction slips past the date grid capacity becomes available. In Missouri, a slow ramp mostly changes how much of the minimum bill a company pays during the ramp period, since the ramp schedule itself is built into the tariff. In Texas, under the proposed rule, a construction delay after capacity is reserved can generate a bill before the facility exists in any operational sense, because the clock starts on the utility's readiness rather than the customer's.
That distinction matters most for projects where construction timelines carry real uncertainty, which describes most large data center and manufacturing buildouts. A company with a disciplined, well-tested construction plan may find the Texas structure manageable, since it can align its own energization schedule with the utility's capacity timeline. A company more exposed to permitting delays, equipment lead times, or supply chain risk has a stronger reason to weight Missouri's ramp-based approach more favorably, even before comparing either state's underlying electricity rate.
The Comparison Extends Beyond These Two States
Missouri and Texas are not outliers in building large-load-specific rules. Other states have approved their own versions of the same underlying goal, keeping infrastructure costs off residential ratepayers, and each has made different choices about contract length, minimum demand, and collateral. What Missouri and Texas illustrate most clearly is how differently regulators can solve the same problem, and how much that variation matters once a company's site-selection model treats tariff design as a variable rather than a formality. Texas's own approach to large-load risk is not limited to this proposed billing rule either; separate ERCOT interconnection requirements already impose financial security earlier in the process, before a project even reaches the billing questions this proposal addresses.
The Texas Rule Is Still Open for Comment
The Texas proposal is not finished. Comments are due August 11, and the Public Utility Commission of Texas could narrow, expand, or restructure the billing provisions before adopting a final rule. Missouri's framework, by contrast, is already operating: Ameren Missouri's large-load tariff took effect following the Commission's November order, and companies signing service agreements today are working under its 12-year minimum term. For a company weighing sites in both states, that difference in regulatory maturity is itself worth tracking. A Missouri site comes with known, finalized terms. A Texas site comes with terms still being negotiated in a regulatory docket, which cuts both ways: less certainty today, but a live opportunity to weigh in before the rule is set.
