# Public Utility Commission The state body that regulates retail electricity, gas and water service — setting the rates customers actually pay, approving what utilities may build and recover, and defining the customer classes across which costs are divided. Names vary by state: Public Utility Commission, Public Service Commission, Corporation Commission, Board of Public Utilities. In most states commissioners are appointed by the governor; in a minority, including Georgia and Alabama, they are elected. > [!important] The most consequential office almost nobody votes for > A state utility commission decides whether a utility may spend a billion dollars and charge customers for it, over what period, and which customers. Its decisions bind for decades and are reviewed almost exclusively by parties with a financial stake. Turnout in elected-commissioner races is a fraction of turnout for governor. Where commissioners are appointed, confirmation is typically uncontested. This is a large amount of distributive power sitting in a venue with almost no public attention, and it is the reason [[Regulatory Capture]] is the default hypothesis rather than an accusation. ## What a commission controls - **Retail rates.** The [[Rate Case]] is the core proceeding: the utility proposes a revenue requirement, intervenors contest it, and the commission sets rates. - **Customer classes.** Which category a customer falls into determines the rate structure applied. Creating a *new* class — as several states did for data centers in 2025 and 2026 — is the sharpest tool a commission has. - **Prudence review.** Whether an investment was reasonable when made, and therefore whether the utility may recover it. This is where stranded-cost risk is adjudicated. - **Certificates of need** for new generation and transmission in most states. - **Service quality, disconnection rules, and interconnection standards** for distribution-level customers. It does **not** control wholesale power prices, interstate transmission tariffs, or [[Regional Transmission Organization]] market design — those belong to the [[Federal Energy Regulatory Commission]]. ## Why the states became decisive in 2026 FERC's June 2026 large-load intervention deliberately stopped at the wholesale line. FERC required transmission owners to obtain financial commitments from large loads and found behind-the-meter netting unjust, but it expressly left the prevention of *retail* cost-shifting to the states, noting that states retain responsibility to create new rate classes and assign upgrade costs in retail tariffs. PJM's curtailment design has the same structure: because states decide which customers connect to state-regulated utilities, enforcement of the large-load regime lands on state commissions. The result is that the actual answer to "who pays for the AI buildout" is being written fifty times, in fifty venues, by bodies with wildly varying resources and appetites. A consumer advocate quoted in August 2026 put the readiness problem plainly: no state was completely prepared. ## What states have actually done | State | Action | Date | |---|---|---| | Indiana | IURC large-load tariff: loads above 70 MW at one site or 150 MW aggregate face a minimum 12-year contract, exit fees for capacity reductions over 20%, and a minimum monthly demand charge of at least 80% of contract capacity | February 2025 | | Ohio | PUCO ordered an AEP Ohio data-center-specific tariff requiring payment on a minimum of 85% of contracted capacity whether used or not, with a four-year ramp | Order 2025-07-09, tariff effective 2025-07-23 | | Virginia | SCC approved Dominion's new GS-5 class for customers at 25 MW and above — at least 85% of contracted distribution and transmission demand, at least 60% of generation demand, and a minimum 14-year contract | Approved November 2025, effective 2027-01-01 | | Georgia | PSC approved minimum billing requirements and longer contract terms for customers with expected peak demand at or above 100 MW | 2025 | | Pennsylvania | PUC large-load tariff framework: costs of utility upgrades for data-center interconnection recovered from the large-load customer, with deposits and collateral sized to cover the infrastructure if the project falls through | 2026-04-30 | The common instrument across all five is the **minimum take** — a floor on billed demand regardless of consumption. It is the regulatory answer to the stranded-cost problem, and it is what an actual commitment looks like as opposed to an announcement. See [[Large Load Tariff]]. ## The public-power variant Not every large-load decision runs through a commission. The [[TVA]] board, a federal corporation's board rather than a state regulator, voted on 2026-08-20 in Memphis to move data centers out of the manufacturing service rate into a dedicated class at roughly 10% higher, phased over three fiscal years, and to impose a **Capacity Commitment Charge of approximately $1.5 million per megawatt** on new or expanding data-center load above 5 MW from 2026-10-01, payable over three to five years. The FY2027 budget contained no residential rate increase. TVA's Integrated Resource Plan projects a need for 11–32 GW of additional generation. Because TVA sets its own rates without a state commission, it could act in a single board meeting what a rate case would take a year to reach. Institutional form determines speed. ## See Also - [[Rate Case]] — the proceeding through which a commission works - [[Large Load Tariff]] — the 2025–2026 instrument of choice - [[Cost Allocation]] — the underlying question every commission is answering - [[Federal Energy Regulatory Commission]] — the other side of the jurisdictional line