Who Decides What Data Centers Pay for Electricity?

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At an investor-owned utility, the company proposes what a large customer such as a data center should pay for electricity, and the state utility commission decides whether those terms become the approved rates. That matters to other customers: power lines built for a data center can take decades to pay off, a Virginia legislative study found, and if the data center closes early or draws less power than planned, other customers can end up paying the remaining costs.

Minimum payments, long contracts and financial guarantees help determine how much of that risk stays with the data center. In Virginia, the main example below, new large customers of the utility Dominion Energy must commit to pay for at least 14 years of service.

The utility proposes, the regulator decides

Investor-owned electric utilities are subject to regulation and oversight by state public utility commissions. State or local utility regulators approve rates reflecting the costs of producing and delivering electricity. An arrangement a data center negotiates with a regulated utility is not simply a private discount if it changes the terms of the utility’s approved rates. The important questions are what the customer is committing to pay, what infrastructure the utility is committing to build, and which authority has approved that arrangement.

In Virginia, the utility Dominion Energy proposed a separate class for large electricity users, including data centers, during a review of its rates. The State Corporation Commission (SCC), Virginia’s utility regulator, approved the new class, called GS-5, with an effective date of January 1, 2027.

Ownership changes the decision maker: publicly owned utilities and electric cooperatives are generally not regulated by state commissions. In Florida, for example, municipal utility rates and revenues are regulated by city commissions. Florida’s rural electric cooperative rates and revenues are regulated by elected cooperative officers. A rule adopted for one investor-owned utility should not be treated as the rule for every city utility or cooperative, even within the same state.

Retail choice adds another variation: in states that allow it, customers can buy power from a marketer while a local utility delivers it. Choosing an electricity seller does not remove the need to pay for the network that delivers the power.

Electricity use and grid costs are different bills

Energy charges are based on electricity consumed in kilowatt-hours, while demand charges are based on the maximum power needed during a billing period, typically measured in kilowatts. Virginia’s Joint Legislative Audit and Review Commission (JLARC) describes generation rates as covering power-plant costs, purchased electricity and payments for generation capacity. Generation capacity is a generator’s maximum power output. In a capacity market, generators receive payments for making that capacity available to the system, regardless of how much energy they supply. Transmission rates recover the costs of building and maintaining long-distance power lines, while distribution rates cover substations, local lines and other infrastructure serving customers. The electricity a data center buys is therefore only one part of what it costs to serve it.

The Congressional Research Service explains that more electricity sales bring more utility revenue, but rates can still rise if costs outpace that revenue. A large new customer can help spread existing costs across more sales while also triggering expensive new investments. Whether other customers benefit depends on both sides of that calculation.

JLARC’s Data Centers in Virginia report, published December 9, 2024, included a study that found the rates then in place appropriately allocated current costs to the customers causing them, including data centers. The report added that data centers’ increased energy demand will likely increase system costs for all customers.

JLARC also warned that transmission investments can take decades to recover and that, if a data center closes or uses less power than expected, remaining costs can fall on other customers. This is the risk behind long contracts and minimum payments: a utility’s investment can outlast the customer’s plans.

Virginia’s large-user class assigns commitments as well as costs

Dominion’s GS-5 class covers customers with measured or contracted demand of at least 25 megawatts on a contiguous site and a measured or expected load factor of at least 75 percent. One megawatt is 1,000 kilowatts. Load factor is the ratio of average power demand to peak demand during a specified period. A high load factor means the customer draws close to its peak much of the time. The commission says the separate class allows it to set rates reflecting the unique costs of serving those large customers, minimizing shifts to other classes.

The approved provisions require certain large customers to pay for at least 85 percent of contracted transmission and distribution demand and 60 percent of generation demand. The 60 percent generation minimum also applies to customers buying power from a competitive supplier unless they qualify for an exemption. Generation-only exemptions cover customers already using a competitive supplier or Schedule 10 interruptible service as of January 1, 2025, and customers who formally notified Dominion before that date that they intended to switch to either option before January 1, 2026. These are minimum payments, owed even when actual use is lower; they do not require a data center to use that share of electricity every month.

New large-load customers that contract for service on or after January 1, 2027, must take and pay for service for at least 14 years. Customers that began taking service from Dominion before January 1, 2016 are exempt from all minimum-demand charges.

New large-load customers that contract on or after January 1, 2027, and lack sufficient credit may have to post collateral guaranteeing up to 60 percent of their minimum charges over the contract term. Minimum bills specify what is owed; collateral provides a way to secure payment if the customer cannot meet that obligation.

The commission describes these provisions as measures designed to reduce the risk that infrastructure built primarily for large customers is recovered from everyone else. Reducing a risk is not eliminating it: adopting a safeguard is not evidence that every household’s future bill is protected from every source of higher costs.

Ohio’s contracts show why the details matter

A utility tariff sets out its rates, charges and service terms. The Public Utilities Commission of Ohio (PUCO) adopted a data-center tariff settlement for the utility AEP Ohio, now called Ohio Power Company, on July 9, 2025, and the tariff became effective July 23, 2025. PUCO said the utility faced load growth requiring significant transmission infrastructure and that the settlement was intended to safeguard other customers. The tariff applies in that utility’s service territory; it is not one rule for all Ohio customers.

New data centers and expansions must apply to the utility, and requests of at least 25,000 kilowatts also carry a load-study fee and a set large-load process; those were the requirements as of October 2, 2026. The initial contract covers a ramp-up period of no more than four years, during which the customer’s demand builds, plus eight more years. If electric infrastructure is not ready by the estimated service date, the customer may petition the commission to adjust the contract term; otherwise, the term remains.

Each month, an Ohio data center under the tariff is billed for at least the greater of two demand figures: 85 percent of its highest monthly billing demand in the previous 11 months, or a minimum based on its contract capacity, shown below.

The contract-capacity minimum cannot exceed 85 percent of total contract capacity. This is a formula for demand charges, not an obligation to buy 85 percent of the electricity promised.

Before service begins, a separate agreement requires the customer to repay 100 percent of the utility’s buildout costs if the customer cancels the project, or delays it by more than 12 months, before the target date for power to be switched on. That agreement’s obligation expires when the project is completed. The pre-service agreement addresses a different failure than a minimum bill: construction can cost money before the customer ever starts using electricity.

Customers that do not meet both the specified strong credit ratings and cash thresholds must provide a guarantee or collateral equal to 50 percent of minimum charges for the full contract term. Together, the contract length, cancellation repayment and collateral decide what a data center owes if its plans change.

State laws and wholesale markets add another layer

Legislatures can set obligations that regulators must then translate into utility rules. In competitive parts of Texas, retail providers sell electricity plans that include transmission and distribution rates fully regulated by the Public Utility Commission of Texas. Texas Senate Bill 6 directs the commission to write rules requiring covered large-load customers to help pay the utility’s costs of connecting them to its system.

The commission’s large-load interconnection standards, its rules for connecting such customers to the grid, have an effective date of October 8, 2026. The standards require large-load agreements to acknowledge minimum transmission-demand payments but leave the details of the charge to a separate commission proceeding, Project 58000. Adoption of the interconnection rule therefore does not mean the separate cost-recovery proceeding is final.

The Federal Energy Regulatory Commission regulates interstate electricity transmission and wholesale electricity sales, while retail rates generally remain outside its jurisdiction. A state commission decides the regulated retail bill, but some costs feeding into that bill arise in regional markets.

Capacity markets aim to ensure that electricity supply can meet long-term demand by signaling where and how much capacity is needed, with distribution utilities buying from generation owners. The Congressional Research Service explains that the prices those markets set primarily reflect the expected balance of supply and demand in the coming years. This creates another route for growing demand to affect costs, distinct from shifting a particular data center’s connection expenses onto neighbors.

Virginia’s 2026 Energy Plan sets a vision of affordable and reliable power for families and businesses and outlines pathways for the state’s energy future. Such a plan sets a policy direction; the rate decision sets the obligations large customers must meet.

Look for the approved terms and the case behind them

Start with the utility serving the site, then look for its approved large-user rate schedule and the regulator’s order adopting it. Check which customers qualify, the minimum payment calculation, how long the commitment lasts and what happens if the project is canceled. A proposal may describe protections that the final order changes, so the approved version is the one that answers who must pay.

Virginia’s SCC Docket Search provides case documents, and its case-information page links to the official route for submitting public comments. Written comments must identify the applicable case number, and submitting them does not require oral testimony. Use the current case’s notice for participation instructions, rather than a hearing deadline from an older rate case.

Once Virginia’s new class takes effect, the test will be whether the assigned charges recover the costs they were meant to cover, including when demand falls short.