Data centres use large amounts of electricity, and adding them to a grid can require new power lines, substations, generation and capacity. Those investments can affect reliability planning and electricity costs, but whether they raise household bills—and by how much—depends on the local utility’s tariffs, regional market rules, cost-allocation decisions and whether the forecast data-centre demand actually arrives. There is no established single national figure for how much data centres have added to household bills.
What a data centre’s electricity demand changes
A large data centre is a concentrated electricity customer. Its connection affects the local grid first, but the consequences can extend across a regional power system. The size and timing of the demand matter: a utility may need to plan for a substantial load before a facility is fully built or operating.
- Local connections: A project may require a new substation, feeder upgrades or other distribution and transmission work to deliver power to the site.
- Power supply and capacity: Utilities and regional markets must plan for enough generation and other resources to serve expected demand. A large new load can change those needs, although the outcome also depends on generator availability and retirements, delays to new generation, demand forecasts and market rules.
- Reliability planning: If supply and network upgrades do not keep pace with demand, the grid faces resource-adequacy and reliability risks. The existence of a data centre does not by itself establish that local reliability has declined; the relevant question is whether planned resources and infrastructure can serve the load.
The demand is not spread evenly across the country. A 2025 Berkeley Lab and U.S. Department of Energy technical brief cited an Electric Power Research Institute estimate that 12 states accounted for 84% of U.S. data-centre growth since 2020. That is a historical concentration statistic, not a forecast of where future growth will occur.
How grid costs can reach electricity customers
Building infrastructure does not automatically mean that households pay for all of it. The utility’s tariff, regional market rules and regulatory decisions determine which costs a large customer pays directly and which may be recovered through broader utility or grid charges.
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Connection and network upgrades
A data centre may fund some customer-specific equipment or construction, while other network costs may be shared through utility rates or regional transmission charges. The allocation depends on the governing tariff and cost-allocation rules. A bill impact can therefore arise even when the data centre is not in the customer’s town, if a regional rule allocates costs across a wider area.
Generation and capacity costs
Regional capacity markets procure resources intended to help ensure enough supply is available in future periods. A large-load forecast can affect procurement needs and prices, but it is only one part of the calculation. Supply additions, retirements, interconnection delays, demand forecasts and market design also matter.
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Underused infrastructure if forecasts do not materialize
A utility might invest based on a project’s expected load before the facility reaches full operation. If the project is delayed, downsized or cancelled, some planned infrastructure could be underused. Regulators then have to determine how that risk is allocated. Minimum payment commitments, collateral, customer contributions and exit charges are among the mechanisms used to protect other customers from paying for costs tied to demand that never arrives.
What the bill evidence shows—and what it cannot prove
National price trends and local cases answer different questions. National averages show what happened across the country over a period; they can conceal concentrated costs or demand growth in particular utility territories.
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| Evidence | What was reported | How to interpret it |
|---|---|---|
| United States, 2019–2023 | Lawrence Berkeley National Laboratory reported that average U.S. retail electricity prices rose 4.8% per year nominally. After inflation, average prices were mostly flat. Distribution capital expenditure rose 50% over the same period. | LBNL said national retail electricity sales were nearly flat and were not a major cause of national cost growth, while some states and utilities saw significant load growth from data centres and industrial facilities. The national figures do not rule out local effects. |
| Affected New Jersey Basic Generation Service customers, rates effective June 1, 2025 | The New Jersey Board of Public Utilities projected increases of 17.23% to 20.20% for residential BGS bills, or $22.67 to $28.02 per month for accounts using 650 kWh per month. | The BPU identified data-centre-driven demand as one factor in PJM capacity costs, alongside supply growth and market-design issues. This is a New Jersey supply-auction example, not an estimate of the portion caused by data centres alone. |
| Maryland transmission-cost complaint announced May 7, 2026 | The Maryland Office of People’s Counsel said its FERC complaint estimated $1.6 billion in added transmission costs for Maryland customers over ten years, including $823 million for residential customers. | These are estimates attributed to the consumer advocate’s complaint and expert affidavit. They are disputed claims in a regulatory proceeding, not a final FERC finding or proof that customers have already paid those amounts. |
The New Jersey figures concern supply rates passed through to affected customers, not a nationwide data-centre surcharge. The Maryland figures concern proposed transmission-cost allocation, not a settled finding. Keeping these distinctions clear is essential when evaluating claims that a data centre “raised” a particular bill.
How much electricity data centres may use
Lawrence Berkeley National Laboratory’s 2026 update projects that data centres could account for 11.8% of total U.S. electricity in 2030, with a scenario range of 9.5% to 15.3%. These are projections, not measured 2030 consumption. The range reflects uncertainty about how much demand will materialize; it should not be read as a guaranteed share or as a bill increase.
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For local planning, the relevant information is more specific than a national share: the proposed facility’s expected megawatt load, its ramp-up schedule, available grid capacity and the upgrades needed to serve it. Two projects with similar eventual demand can have different effects if one can use existing capacity while the other requires costly new infrastructure.
Independent reader supportYour contribution helps us test, update, and keep practical guides available for everyone.What utilities and regulators can do about cost shifting
Regulators are considering how to connect large loads without leaving existing customers exposed to costs they did not cause or making service unreliable. Measures discussed or adopted in U.S. proceedings include:
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- Requiring a large customer to pay for directly attributable interconnection work or contribute to construction.
- Setting minimum contract terms, minimum payments, financial security or exit charges to address the risk that projected demand does not arrive.
- Making interconnection and transmission cost responsibilities more transparent.
- Using demand charges or phased load ramping so charges and construction better match the load’s arrival.
- Offering firm or interruptible service, where the customer’s service terms specify whether and under what conditions its load may be curtailed.
- Allowing flexibility, such as shifting some electricity use to different times or using on-site energy and storage where technically and commercially feasible.
These are design options, not automatic bill savings. Flexible service or on-site energy can change when or how much a facility draws from the grid, but the benefits depend on technical feasibility, costs, commercial terms and regulation.
Recent regulatory actions
- Pennsylvania: The Pennsylvania Public Utility Commission adopted a final order on April 30, 2026, and issued model tariff guidance on May 30, 2026, addressing large-load connections. The record covers issues including minimum terms, financial security, construction contributions, demand charges, phased ramping, exit fees, service options, transparent cost structures and customer-funded upgrades.
- Regional grid operators: On June 18, 2026, FERC issued tailored show-cause orders to PJM, MISO, SPP, CAISO, ISO-NE and NYISO. The orders gave each operator and its transmission owners 60 days to justify current tariffs or propose changes addressing large-load interconnection, cost shifting, transmission-cost transparency, co-location and flexible service; they also required generation-adequacy reports within 30 days. The orders began a regulatory process, not a uniform national tariff.
Separately, the U.S. Department of Energy’s 2024 transmission scenario assessment modeled $320 billion in present-value savings through 2050 in an enhanced-transmission scenario. That is a modeled power-system result, not a forecast of savings from data centres or of lower bills in any particular utility territory.
How to assess a claim about your community or bill
Before attributing a rate increase to a proposed or operating data centre, look for the underlying utility filing, tariff, market result or regulatory decision. Compare the following details for the same project and service territory:
- Load and timing: What is the facility’s current and forecast megawatt demand, and when is each phase expected to come online?
- Required work: Which generation, transmission, substation and distribution upgrades are specifically needed to serve it?
- Who pays: Which costs are billed directly to the customer, recovered from utility customers, or allocated through regional market rules?
- Protection if the project changes: Are there minimum payment commitments, collateral, construction contributions or exit fees if the load is delayed, reduced or cancelled?
- Service and reliability terms: Is the load firm or interruptible, and what do the service terms say about curtailment and backup supply?
- Evidence behind the bill figure: Is it an actual bill change, a utility forecast, a modeled scenario or an allegation in a pending dispute? Check the customer class, territory, usage assumptions and effective dates.
These details matter more than a national statistic when estimating a particular household’s exposure. A bill claim without a named territory, cost mechanism and time period cannot establish how much a local customer will pay.
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