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A nuclear power purchase agreement (PPA) can give a data-center operator long-term rights to electricity associated with a nuclear plant, but the contract does not by itself put the facility next to the reactor, guarantee simultaneous delivery, or provide outage-proof power. Start by identifying whether the arrangement is a normal grid-delivered PPA or a physically co-located, behind-the-meter project. Then analyze capacity obligations, transmission service, backup supply, licensing milestones and cost allocation as one system.

What a nuclear PPA actually provides

A PPA is a contract that defines how a buyer will purchase electricity or electricity-related rights from a generator for a stated period. In a nuclear deal, the generator is usually an existing plant, a plant being restarted, or a proposed new unit. The agreement can support revenue certainty for the generator and a predictable procurement plan for the data-center operator.

The label “nuclear PPA” is not a technical description of power flows. A contract can be settled through the regional grid even when the buyer is hundreds of miles from the plant. The electrons serving the data center are governed by the grid’s dispatch and transmission rules; the PPA governs the commercial relationship, settlement and any associated environmental attributes. The U.S. Energy Information Administration (EIA) states that a PPA does not require the generator and load to share a site or to produce and consume electricity at the same time.

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That distinction matters when a project team presents a PPA as a resilience solution. A financial or grid-delivered contract can hedge price and supply attributes, but the data center still depends on transmission, the regional market and backup systems. A direct connection to a generator is a separate physical and regulatory arrangement with its own interconnection, protection, metering, operating and tariff requirements.

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Choose the delivery structure before negotiating price

Grid-delivered PPA

Under a conventional structure, the plant injects power into the transmission system and the data center takes service through its utility or regional market. The contract should identify the delivery point, scheduling coordinator, settlement rules, congestion treatment and the buyer’s obligation when the plant’s output differs from the contracted quantity.

This structure can serve a load in a different location and can continue operating if the nuclear unit is offline, provided the buyer retains market or utility service. However, replacement energy may be more expensive, lower in nuclear output attributes, or subject to transmission constraints. The PPA must say who bears those differences.

Co-located or behind-the-meter supply

A co-located project places a large load at, or electrically adjacent to, a generating facility. Behind-the-meter configurations may reduce the amount of power that flows through the regional transmission network, but they do not eliminate regulation. The parties must define the point of electrical separation, permitted imports and exports, metering, protection, emergency operations and what happens when on-site generation is unavailable.

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Co-location can change which transmission service is needed and how costs are allocated. It can also expose the data center to a single generating resource unless grid imports or independent generation are available. FERC staff has described several possible configurations and reliability concerns, while later Commission action directed PJM to clarify service options for co-located load.

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Questions that distinguish the two

  • Where is the contractual delivery point and where is the physical meter?
  • Who schedules generation and load, and who settles imbalances?
  • Can the data center import from the grid during a plant outage?
  • Can the generator curtail the load, and under what notice and compensation terms?
  • Which utility, transmission owner and regional operator tariffs apply?

Capacity, energy and staged growth are different obligations

Data-center announcements often quote megawatts, but “MW” can describe different things. A contract may specify a peak demand, a firm capacity reservation, an energy quantity, a staged ramp or a minimum-take obligation. Those terms have very different financial consequences.

EIA reported that AWS contracted for capacity from the Susquehanna plant of up to 960 MW, added in 120-MW increments over multiple years. The arrangement included a one-time option to cap the commitment at 480 MW. The reported figures describe contractual capacity and a ramp, not a claim that 960 MW of electricity would be delivered immediately or consumed continuously.

Before signing, model at least these cases:

  • Peak case: the highest simultaneous demand the campus can impose, including cooling and auxiliary systems.
  • Average-energy case: the expected megawatt-hours over a billing period, which may be far below the peak.
  • Ramp case: when each expansion tranche becomes binding and what happens if construction slips.
  • Minimum-take case: the payment due if the facility uses less energy than forecast.
  • Flexibility case: rights to defer, cap or release capacity, and the fees attached to those rights.

Ask the seller to define every MW number in both electrical and contractual terms. Require a schedule showing the commitment date, commercial-operation date, permitted variance, test procedures and consequences of a delayed load.

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What happens when the nuclear plant is offline?

A nuclear unit can provide steady output, which may fit a data center’s relatively steady base demand. That alignment does not make one reactor an outage-proof supply plan. Scheduled refueling and maintenance, forced outages, transmission failures, fuel or equipment constraints, and licensing delays can all interrupt output.

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Grid-delivered outage arrangements

For a grid-delivered PPA, specify whether the buyer automatically receives replacement power through the utility or regional market. The contract should assign the cost of replacement energy, congestion, imbalance charges and lost environmental attributes. It should also state whether a prolonged outage is a force-majeure event, a seller default, or a separately priced contingency.

Co-located outage arrangements

For a physically connected load, an outage can remove the local source and the transmission path at the same time. The operator needs documented rights to import power, the maximum import level, priority during system emergencies and the equipment required to island or reconnect safely. If non-firm service is used, the load may be curtailed when the grid is constrained.

Independent backup

UPS systems, standby generators, batteries, demand-response capability and redundant utility feeds remain engineering decisions rather than automatic PPA benefits. A PPA may support financial planning for energy, but it does not replace the data center’s continuity-of-operations design or its testing requirements.

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Transmission service and cost allocation can dominate the economics

FERC’s February 2025 review of PJM co-location arrangements identified uncertainty about tariff rates, terms and conditions for large loads paired with generation. In a later directive, FERC found the PJM tariff insufficiently clear and required revisions involving network integration service, interim non-firm service, and new firm or non-firm contract-demand service. The order also addressed behind-the-meter rules, reliability reporting and filing deadlines.

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Those labels are not interchangeable. A firm service may provide defined withdrawal rights subject to specified conditions and charges. Non-firm service can leave the load exposed to curtailment when the system lacks deliverability. Network service may trigger studies, upgrades, reservations and ongoing charges. The effective tariff and project-specific agreement control; the names alone do not establish the final price or reliability level.

Commissioner Rosner’s concurrence described the directive as creating “new pathways for co-location—directly connecting a large load with the power needed to serve it at the same site—and load flexibility that enable large co-located loads to reduce how much they lean on the grid, while ensuring that they pay their fair share.” That is an explanation of the order’s design, not a universal conclusion that every co-located project lowers costs or shifts costs to other customers.

FERC Chairman Mark Christie said in the February 20, 2025 announcement that “Co-location arrangements are a fairly new phenomenon that entail huge ramifications for grid reliability and consumer costs.” Operators should therefore obtain a project-specific allocation of interconnection studies, network upgrades, metering, protection, reservation, standby and emergency-service costs.

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Deal figures that illustrate the range of structures

Parties and date Reported arrangement What the figure does—and does not—show
Constellation Energy and Microsoft, announced September 2024 20-year PPA associated with Microsoft data centers in the mid-Atlantic and a proposed restart of Three Mile Island Unit 1 EIA’s October 1, 2024 account reported a 2028 restart target, subject to Nuclear Regulatory Commission and state and local approvals and substantial plant work. It was not confirmation of commercial operation.
Talen Energy and AWS, reported 2024 Up to 960 MW from the Susquehanna plant, added in 120-MW increments; a one-time option could cap the commitment at 480 MW The numbers describe staged contractual capacity. They are not a market-wide standard for PPA size or proof of immediate delivered energy.
Amazon and Talen, described by the U.S. Department of Energy in March 2024 $650 million transaction to purchase a co-located data center and up to 960 MW from Susquehanna The $650 million figure refers to the transaction as DOE described it, not to the price of electricity alone.
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Contract diligence checklist for operators

1. Define delivery and settlement

  • Identify the physical and contractual delivery points.
  • Name the scheduling coordinator, balancing authority and settlement entity.
  • State whether energy is delivered, financially settled, or both.
  • Specify treatment of congestion, losses, imbalance and negative-price periods.

2. Translate MW into a payment obligation

  • Classify each quantity as peak capacity, energy, a reservation, a minimum take or an option.
  • Document staged additions, notice periods and testing requirements.
  • List caps, deferral rights, termination charges and consequences of under-use.
  • Check whether the buyer must pay before the data center reaches commercial operation.

3. Allocate outage and delay risk

  • Cover planned maintenance, refueling, forced outages, fuel constraints and transmission outages.
  • Set replacement-power rights and pricing.
  • Define curtailment priority, notice, restoration and compensation.
  • Address a restart or licensing delay separately from an ordinary plant outage.

4. Verify regulatory and construction milestones

  • Confirm the operating license and any required Nuclear Regulatory Commission actions.
  • Track state and local approvals, construction scope, interconnection studies and energization dates.
  • Align the plant’s commercial-operation date with each data-center commissioning phase.
  • Require notice and remedies if a milestone slips.

5. Price the grid arrangement

  • Identify the applicable regional and utility tariffs.
  • Determine permitted grid withdrawals, import limits and emergency service.
  • Assign network upgrades, transmission reservations, standby service, metering and protection costs.
  • Confirm whether the selected service is firm or non-firm and when curtailment can occur.

6. Document environmental attributes

Do not assume that a nuclear PPA automatically conveys renewable-energy certificates, emissions claims or other environmental attributes. Specify what is transferred, how double counting is prevented, which registry or accounting method applies, and what happens if rules change. The sources reviewed do not establish uniform market terms for these provisions.

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Restarted, existing and new nuclear generation require different diligence

An operating plant generally has an established license, interconnection and operating history, although its available capacity and outage schedule still need verification. A restart project adds engineering inspections, licensing, state and local approvals, financing and construction milestones. A new reactor adds a longer development path and greater schedule uncertainty.

EIA’s account of the proposed Three Mile Island Unit 1 restart illustrates the difference between an announced target and an operating asset: the October 1, 2024 report placed the target in 2028 while approvals and substantial work remained. A data-center energization plan should therefore use conditional milestones, not treat the announcement date as guaranteed supply.

Regulatory status operators should monitor

FERC opened a PJM-focused review and show-cause proceeding in February 2025. Its later directive required PJM tariff revisions and described several service pathways for co-located load, along with reliability-related reporting and filing deadlines. Commissioner Rosner’s December 18, 2025 concurrence explains how contracted withdrawals and curtailment exposure could differ among those services.

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The available material does not establish whether every post-order tariff filing and reliability-reporting step due in 2026 was completed, or what final rates apply to a particular project. Before committing capital, verify the current FERC docket, effective PJM tariff, state rules and local utility arrangements. A FERC staff paper such as “The Co-Located Load Solution” is policy analysis, not a Commission order and not a substitute for the governing tariff.

A practical evaluation sequence

  1. Map the electrical topology. Draw the plant, switchyard, meters, transmission connections, utility feeds, backup generators and the proposed data-center load.
  2. Classify the contract. Decide whether the PPA is grid-delivered, co-located, behind the meter or a combination, and identify every delivery and settlement point.
  3. Build synchronized schedules. Match reactor licensing, construction, interconnection, commissioning and load-ramp dates.
  4. Run reliability scenarios. Model planned outage, forced outage, transmission constraint, curtailment, delayed restart and simultaneous campus expansion.
  5. Obtain tariff confirmation. Get written positions from the transmission provider, regional operator and utility on service eligibility, withdrawal rights, upgrades and charges.
  6. Negotiate remedies. Tie payment, replacement energy, termination, delay and performance remedies to measurable milestones and outage categories.
  7. Validate claims governance. Establish how energy, capacity and environmental attributes are measured, reported and audited.

Common mistakes to avoid

  • Calling a financial PPA a direct wire or dedicated plant.
  • Treating a contracted MW ceiling as continuous delivered energy.
  • Assuming a nuclear unit’s high capacity factor eliminates the need for backup.
  • Using a non-firm import service without quantifying curtailment exposure.
  • Quoting a restart year as though the plant were already licensed and operating.
  • Presenting a transaction value as the electricity price.
  • Assuming co-location automatically reduces costs for other customers or for the buyer.

The strongest nuclear-power procurement plans connect the commercial PPA to a physical single-line diagram, an outage plan, an effective tariff and a dated licensing schedule. Without those four pieces, the contract may secure an attractive supply attribute while leaving the data center exposed to the very grid, construction and reliability risks it was intended to manage.

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