On June 18, 2026, the Federal Energy Regulatory Commission (FERC) issued tailored show-cause orders to the six Regional Transmission Organizations and Independent System Operators under its jurisdiction. Each grid operator and its transmission owners were given 60 days to justify existing large-load tariff provisions or to propose reforms. Among the five issues identified by the Commission were transmission-cost transparency and the prevention of cost shifting. The proceeding formalized a question that utilities and state commissions have already begun to answer through retail tariffs: when a data center requires substantial grid expansion, who should bear the financial risk if the projected load is delayed, reduced, or never materializes?
The regulatory approach increasingly places project-specific costs and development risk on the customer creating the need for expansion. New tariffs and service agreements align payment obligations with the investments in generation, transmission, substation, and distribution required to serve concentrated loads.
Data Center Scale Changes the Cost Equation
FERC’s 2025 State of the Markets report found that the average data center entering service increased from approximately 25 megawatts (MW) in 2020 to almost 80 MW in 2025. Commission staff estimated that more than 50 gigawatts (GW) of data center capacity were operating by the end of 2025. At that scale, a single campus may require new substations, high-voltage transformers, transmission reinforcements, voltage-support equipment, and additional generation or capacity commitments before reaching full operation.
These investments are often site-specific, capital intensive, and planned years before the customer reaches final contract demand. Recent analysis of U.S. data center power demand has highlighted how concentrated loads are changing regional planning assumptions. Utilities must initiate studies, reserve equipment, and begin construction while the customer’s schedule and realized demand remain uncertain.
Forecast Uncertainty Has Become a Financial Risk
Transmission plans, resource-adequacy assessments, and utility capital programs depend on credible demand forecasts. FERC reported that revisions by PJM Interconnection and American Electric Power Ohio reduced the 2032 forecast for the AEP zone by 15% (6.1 GW), from the previous year, underscoring that a service request cannot always be treated as equivalent to an operating load.
If a utility builds infrastructure for a data center that later withdraws, delays construction, or operates below contracted capacity, the resulting investment may become underutilized. Under a conventional tariff, unrecovered fixed costs could eventually be distributed across a wider customer base. A January 2025 U.S. Department of Energy technical brief identified fair cost allocation, stranded-asset exposure, and resource-adequacy risk as central considerations in rate design for large loads. Higher data center charges therefore function primarily as risk-allocation mechanisms, not merely as higher commodity electricity prices.
Large-Load Tariffs Convert Forecasts Into Commitments
The principal tariff tools are minimum demand charges, longer contracts, collateral, exit fees, study deposits, and direct assignment of customer-specific facilities. Study fees discourage speculative requests; cancellation provisions protect work already undertaken; and minimum bills preserve cost recovery after energization.
American Electric Power Ohio’s data center tariff provides a clear example. New data centers and expansions requesting at least 25 MW must complete a formal study process, with fees ranging from $10,000 to $100,000. A customer that cancels before energization or delays its project by more than 12 months may be required to reimburse 100% of eligible buildout costs. The initial service term equals a load-ramp period of up to four years plus eight additional years, and monthly billing demand is subject to a minimum of 85% of contract capacity. Certain customers must also provide collateral equal to 50% of projected minimum charges for the full contract term.
These provisions connect the developer’s forecast to the utility’s infrastructure obligations; projects prepared to accept long-duration commitments are also more likely to remain in transmission and capacity forecasts.
Georgia Assigns Upstream Costs to Large Loads
The Georgia Public Service Commission adopted a related framework in January 2025. New customers exceeding 100 MW may be served under nonstandard terms that assign site-specific costs and upstream generation, transmission, and distribution costs attributable to serving those projects. The rule extended the potential contract length from 5 to 15 years and authorized minimum billing requirements, with each qualifying agreement subject to Commission review.
A March 2026 Commission fact sheet stated that Georgia Power’s seven-year generation-need estimate increased from 400 MW in 2022 to 6,600 MW in 2023 and then to 8,500 MW two years later. In December 2025, the Commission approved 9,985 MW of additional generation, approximately 80% of which was expected to serve data centers, with financial backstops if projected contracts did not develop.
Federal and State Cost Allocation Are Converging
FERC’s June 2026 orders preserve an important jurisdictional distinction. The Commission is addressing cost shifting among transmission customers, while state public utility commissions retain authority over retail rates, service terms, and allocation among retail classes. The two levels are nevertheless moving toward a common principle: infrastructure costs should follow the customer or class whose service requirements cause those costs to be incurred.
Oregon adopted that principle through House Bill 3546 in 2025, which requires a separate rate category for large energy-use facilities and directs that their service costs and risks be allocated without shifting them to other customers. Ohio, Georgia, and Oregon use different legal instruments, but each responds to the same problem: concentrated load growth can obligate the power system to invest before revenue is certain.
Flexible Service May Reduce Expansion Costs
Cost responsibility is also influencing flexible service options. FERC has directed regional operators to consider products for flexible loads, co-location, and generation serving nearby customers. As Certrec explained in its review of the Southwest Power Pool’s Conditional High Impact Large Load Service, a data center may obtain conditional, non-firm access while accepting the risk of curtailment.
Such arrangements can permit earlier energization or deferral of selected upgrades, but they do not eliminate the need for transparent studies or cost assignment. A customer seeking firm, continuously available service imposes a different infrastructure requirement than one prepared to curtail load, rely on onsite generation, or phase demand over several years. The price increasingly reflects both the reliability of the product being purchased and the energy consumed.
Planning and Compliance Implications
Customer commitments are becoming integral to system planning, requiring load ramps, credit support, cancellation rights, curtailment capability, and assigned upgrades to be coordinated across retail service, transmission planning, and resource adequacy. Regulatory professionals must monitor how FERC proceedings, regional tariffs, and state orders interact. Certrec’s RegSource platform provides curated updates on FERC, NERC, regional, and other industry developments.
Conclusion
Many new data center projects are facing higher infrastructure-related charges because their projects increasingly require infrastructure that is large, location-specific, and financially consequential before the first server reaches full load. Minimum bills, extended contracts, collateral, cancellation payments, and direct cost assignment are intended to convert uncertain forecasts into durable commitments and keep stranded-investment risk with the customer whose project prompted the expansion. As FERC, regional operators, and state commissions refine their rules, the decisive question will be how the cost, timing, and reliability characteristics of service are allocated without transferring disproportionate risk to existing customers.
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Disclaimer: Any opinions expressed in this blog do not necessarily reflect the opinions of Certrec. This content is meant for informational purposes only.
