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Short answer: For a new U.S. generator modeled to enter service in 2030, natural-gas combined cycle has the lower average levelized cost in the Energy Information Administration’s AEO2025 estimates. Nuclear offers firm, around-the-clock generation with no direct operational carbon-dioxide emissions, but new reactors require more upfront capital and a longer licensing and construction path. Gas can often be deployed sooner and operated flexibly, yet it exposes the project to fuel prices, pipeline constraints, and combustion emissions. The right choice for a data center depends on the delivered contract, location, transmission, backup design, schedule, and the emissions boundary used—not on a single national average.
What the comparison actually means for a data center
A data center is not buying an abstract megawatt-hour. It needs electricity at a specified site, every hour, with contractual performance, reserves, transmission access, and backup systems that protect computing equipment from interruptions. The generator’s technology is only one part of that supply arrangement.
The U.S. Energy Information Administration (EIA) describes data-center owners as seeking “large and reliable sources of electricity supply.” It also notes that data-center electricity demand does not fluctuate during the day in the same way as demand from residences or many other businesses. That relatively constant load makes firm generation attractive, but it also means the project must account for planned outages, grid events, fuel delivery, and the power-quality equipment inside the campus.
For a new U.S. resource entering service in 2030, EIA’s modeled averages favor natural-gas combined cycle on plant-level cost. That result is not a tariff, a generator bid, or a forecast of one campus’s delivered bill. A nuclear project can still be preferable where long-term firm supply, carbon goals, fuel diversity, or an existing reactor’s available output outweigh the cost and schedule advantages of a new gas plant.
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Cost: what the 2030 EIA numbers say—and what they do not
EIA’s Levelized Costs of New Generation Resources in the Annual Energy Outlook 2025 models resources entering service in 2030. The figures below are in 2024 dollars per megawatt-hour and include levelized tax-credit components for eligible technologies.
| Technology | Simple-average LCOE | Capacity-weighted LCOE | Approximate energy-only equivalent |
|---|---|---|---|
| Advanced nuclear | $81.45/MWh | Not stated; EIA’s chart has no modeled 2030 additions for this calculation | 8.145¢/kWh |
| Natural-gas combined cycle | $64.55/MWh | $67.09/MWh | 6.455¢/kWh simple average; 6.709¢/kWh capacity weighted |
EIA’s AEO2025 report defines levelized cost of electricity (LCOE) as the cost to build and operate a plant over its economic life. It cautions that LCOE does not capture the full value of a resource to the grid. It also does not resolve a particular data center’s delivered price, hourly profile, capacity payments, transmission upgrades, congestion, firming, backup, financing terms, or contract risk.
Why the gas average is lower
Combined-cycle gas plants generally require less upfront capital and can be built in a shorter period than a new nuclear station. Their operating cost is more exposed to fuel prices and utilization, because natural gas is consumed whenever the plant runs. A low LCOE in a national model therefore does not guarantee a low long-term cost at a constrained site or during a period of high gas prices.
Why nuclear’s higher LCOE is not the whole economic story
New nuclear projects put more of the cost into construction, licensing, financing, and skilled labor before the first kilowatt-hour is sold. Once operating, nuclear plants have historically had relatively low fuel and operating costs compared with their capital burden. Uranium is a smaller share of total nuclear cost than fuel is for a gas plant, but the owner must still fund refueling outages, maintenance, regulatory compliance, security, and eventual decommissioning.
Convert plant cost into a data-center supply cost
A procurement team should build a site-specific model that adds or subtracts the items LCOE leaves outside the comparison:
- Interconnection studies, substations, transformers, transmission upgrades, and congestion charges.
- Capacity and ancillary-service charges needed to maintain reserves and power quality.
- Fuel transport, storage, pipeline reservation, and gas-price hedging for a gas plant.
- Scheduled nuclear outages and replacement energy during refueling.
- Backup generation, uninterruptible power systems, batteries, black-start capability, and islanding controls.
- Financing costs, tax treatment, insurance, land, water, cooling, security, and permitting.
- Contract penalties, curtailment rights, renewable or clean-energy compliance, and the value of firm capacity.
Comparing a new-reactor LCOE with the operating cost of an existing reactor is also misleading. They answer different questions: one concerns a new capital project, while the other concerns output from an already-built asset.
Reliability: firm generation is not the same as guaranteed uptime
Nuclear operating profile
Nuclear units are designed to run continuously at high output. That steady profile matches a data center’s largely constant demand. EIA characterizes nuclear generation as consistent and available around the clock, while noting that nuclear plants have difficulty ramping rapidly up and down to follow changing loads.
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Natural-gas operating profile
Gas generation is dispatchable: operators can start, stop, or ramp many units faster than a nuclear plant. That flexibility can help follow a changing campus load, cover a nuclear or renewable shortfall, and provide reserves. Actual ramp rate, start time, minimum operating level, and efficiency depend on the plant design and operating condition.
Gas reliability is tied to more than the generator. Extreme cold can affect pipeline pressure and fuel availability; storms can interrupt transmission or gas infrastructure; and a single interconnection can leave a campus exposed even when the power station itself is available.
Evaluate the complete reliability chain
Neither technology automatically delivers a data center’s required service level. Assess the full chain:
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- Generation availability, forced-outage history, maintenance schedule, and black-start capability.
- Two independent transmission or distribution paths, or a documented alternative if dual feeds are not possible.
- Fuel security: uranium services and refueling logistics for nuclear; pipeline, storage, pressure, and supplier diversity for gas.
- Reserve margin, spinning and non-spinning reserves, and the operator’s dispatch rights.
- On-site batteries, UPS systems, generators, transfer switches, and the time each layer can carry the load.
- Protection against voltage sags, frequency excursions, harmonics, and disturbances that a generator capacity factor does not measure.
DOE’s July 2024 recommendations advise evaluating backup technologies across cost, performance, reliability, availability, emissions, space, and supply chain. That framework is more useful than assuming a plant’s capacity factor equals a campus uptime guarantee.
New nuclear, existing nuclear, and gas are different procurement choices
New nuclear construction
New reactors face site selection, environmental review, licensing, financing, construction, commissioning, and fuel-readiness requirements. DOE says licensing, demonstration, and deployment of new designs will take years and that widespread commercial advanced reactors are likely in the 2030s. For a campus that must energize in the next few years, a new reactor usually cannot be treated as the default schedule solution.
Existing nuclear output
An existing plant can supply a data center through a power-purchase agreement (PPA), a utility contract, a capacity arrangement, or a co-located structure. Relicensing, uprating, or restarting an existing unit can also change available output without building an entirely new reactor. Those options still require transmission rights, outage coverage, and regulatory approvals.
EIA cites a 20-year agreement announced in 2024 for power from Three Mile Island Unit 1 and an agreement under which AWS contracted for up to 960 MW from Talen’s Susquehanna plant, with phased increases described by EIA. These examples demonstrate possible commercial structures; they are not standard prices or proof that every existing plant can offer the same terms.
New gas generation
Gas plants are among the sources DOE identifies as able to help meet near-term demand. A project may still face turbine lead times, air permits, water constraints, interconnection queues, pipeline capacity, and local emissions limits. “Faster than new nuclear” does not mean instant, and a gas plant without firm fuel and transmission arrangements may not provide firm power when the grid is stressed.
Deployment timeline and permitting can decide the winner
Start with the campus’s required commercial-operation date, then work backward through every dependency. A schedule that ignores the grid queue or fuel infrastructure is not a power plan.
- Set the load date and shape. Document initial megawatts, expansion phases, hourly load, power factor, cooling load, and acceptable interruption duration.
- Screen sites for deliverability. Confirm available transmission, substation capacity, water or air-cooling options, gas pipeline access, seismic and flood constraints, and land for backup systems.
- Choose the supply arrangement. Compare utility service, a PPA, a tolling or capacity contract, co-location, and a behind-the-meter plant. Define who owns fuel, outages, interconnection upgrades, and balancing risk.
- Map permits and critical-path equipment. Include nuclear licensing or gas air permits, environmental review, transformers, switchgear, turbines or reactor modules, and construction labor.
- Build an interim plan. If the final firm source arrives later than the first servers, specify temporary grid service, staged generation, storage, or load growth limits rather than assuming the permanent plant will be early.
- Stress-test the schedule. Model a delayed interconnection, a refueling outage, a pipeline restriction, a turbine or reactor outage, extreme weather, and a slower-than-planned data-center buildout.
Emissions: use the right boundary
Direct plant emissions
Nuclear electricity generation does not directly emit carbon dioxide during operation. Natural-gas combustion does emit direct carbon dioxide and other air pollutants. That distinction is useful, but “zero direct emissions” is not the same as zero emissions across the entire fuel cycle.
Lifecycle emissions
A lifecycle comparison may include uranium mining, conversion, enrichment, fuel fabrication, reactor construction, decommissioning, gas production and processing, pipeline transport, methane leakage, plant construction, and waste management. Results depend on the accounting boundary, methane assumptions, plant efficiency, utilization, and time horizon. No single directly comparable nuclear-versus-gas lifecycle figure is established here, so a procurement team should not combine incompatible studies or present one technology’s operational figure as a lifecycle result.
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For U.S. grid emissions factors, the EPA’s eGRID database provides generation, emissions, emission rates, heat input, and resource-mix data. Its latest update identified on the source page covers 2023 data. Use the factor that matches the data center’s geography and reporting method, and document whether the calculation reflects grid-average electricity, a contractual instrument, or physically delivered generation. A contract for nuclear output does not automatically mean every electron consumed at a remote campus came from that plant.
Fuel, supply-chain, and price risk
Gas exposure
Gas economics move with fuel prices, plant utilization, pipeline transportation, storage, weather, and regional competition. A plant can have a low modeled average cost yet produce expensive energy during a fuel-price spike. Contracts can reduce exposure through fixed-price gas, hedges, storage, or take-or-pay pipeline rights, but each protection has a cost and counterparty risk.
Nuclear exposure
Nuclear fuel is a smaller portion of total generation cost, so short-term uranium price movements generally have less influence on operating cost than gas-price movements have on a gas plant. Nuclear projects instead concentrate risk in capital financing, construction performance, licensing, specialized labor, component supply, outage planning, and long-term regulatory obligations.
Supply-chain resilience
Ask suppliers to disclose lead times and contingency plans for transformers, switchgear, turbines, reactor components, cooling equipment, control systems, fuel services, and replacement parts. A dual-fuel or multi-unit gas design may improve resilience, while a nuclear arrangement may benefit from long fuel cycles but still requires planned refueling logistics and qualified outage crews.
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Location, transmission, and commercial structure
DOE’s Office of Electricity warns that data centers can affect regional grids because of steep load increases, geographic constraints caused by latency requirements, and the need for firm power. A low-cost generator hundreds of miles away may be less useful than a higher-cost resource with deliverable transmission at the campus.
| Arrangement | What it can provide | Questions to resolve |
|---|---|---|
| Utility supply | Grid access, balancing, and established reliability rules | Tariff, interconnection date, capacity charges, congestion, curtailment, and upgrade responsibility |
| Long-term PPA | Price and volume framework for contracted energy or capacity | Hourly matching, outage replacement, shaping, basis risk, credit support, and termination rights |
| Co-location or behind-the-meter generation | Shorter electrical path and potential control over dispatch | Island operation, regulation, fuel supply, emissions permits, protection systems, and who bears plant risk |
| Portfolio approach | Diversification across grid, firm generation, storage, and backup | How resources are dispatched, reserved, tested, and credited during a common-mode outage |
Capacity value matters because a data center needs power during stressed hours, not merely an annual energy total. The contract should specify deliverable megawatts, outage notice, replacement energy, performance guarantees, and remedies when the resource is unavailable.
A practical decision framework
Favor a nuclear-centered strategy when
- The campus can wait for an existing plant arrangement or a new project’s longer schedule.
- Continuous firm output and low direct operational emissions are high priorities.
- The site has dependable transmission and a credible plan for refueling and forced outages.
- Long-term price stability and fuel diversity justify higher upfront or contractual costs.
- The buyer can accept the licensing, regulatory, and specialized-workforce requirements.
Favor a gas-centered strategy when
- Near-term energization and dispatch flexibility are more important than minimizing direct emissions.
- The site has firm pipeline access, storage or backup-fuel options, and practical air-permit headroom.
- The buyer can manage fuel-price exposure through hedges or contract design.
- Fast ramping is valuable for staged load growth, reserve service, or an interim bridge.
Favor a portfolio rather than a single technology when
- The project needs construction before a long-lead firm resource is available.
- Transmission, fuel, or permitting risk is concentrated in one path.
- The campus has multiple phases with different timing and load shapes.
- Emissions targets require lower-carbon supply while reliability requires dispatchable backup.
How to compare bids without being misled
- Normalize the units. Put all offers in consistent 2024 or current dollars, distinguish $/MWh from monthly capacity charges, and identify one-time versus recurring costs.
- Separate energy from capacity. Record the guaranteed megawatts, annual energy, qualifying capacity, ancillary services, and any derating during extreme conditions.
- Specify the emissions method. Label direct stack emissions, lifecycle emissions, and purchased-electricity accounting separately.
- Price outage coverage. Include planned nuclear refueling, gas maintenance, forced outages, transmission failures, and replacement power.
- Test fuel scenarios. Run gas-price and pipeline-constraint cases, plus nuclear construction, financing, and outage cases.
- Value schedule certainty. Assign a cost to delayed server deployment, temporary generation, and missed capacity milestones.
- Verify deliverability. Require an interconnection study, transmission path, congestion assumptions, and evidence that contracted capacity can reach the campus during a stressed hour.
- Audit the reliability claim. Ask for definitions of availability, outage notification, restoration time, black start, islanding, and performance guarantees.
U.S. demand context
DOE, citing an Electric Power Research Institute estimate, says data centers could consume up to 9% of U.S. electricity generation annually by 2030, compared with 4% of total load in 2023. “Up to” marks a projection, not a measured future outcome. The estimate nevertheless explains why utilities, developers, and grid planners are evaluating large firm resources, transmission expansion, storage, efficiency, and flexible demand at the same time.
At the project level, the implication is straightforward: reserve an interconnection early, model phased load growth, and do not assume that a national generation-cost average represents the marginal cost or reliability value at a constrained local node.
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| Question | Advanced or existing nuclear | Natural-gas combined cycle |
|---|---|---|
| Modeled 2030 new-build cost | $81.45/MWh simple-average LCOE for advanced nuclear resources in EIA AEO2025 | $64.55/MWh simple-average and $67.09/MWh capacity-weighted LCOE in EIA AEO2025 |
| Operating profile | Steady, firm output; limited rapid ramping; planned refueling outages | Dispatchable and generally more flexible; output and cost depend on fuel availability |
| Direct operational CO₂ | None from nuclear electricity generation | Produced by gas combustion |
| Lifecycle accounting | Requires uranium, construction, and decommissioning boundaries | Requires production, methane leakage, transport, combustion, and construction boundaries |
| Near-term deployment | New designs face lengthy licensing and construction; existing plants are a separate option | Often better suited to near-term additions, subject to equipment, permits, interconnection, and fuel infrastructure |
| Primary economic risk | Capital, financing, construction, licensing, and outage risk | Fuel price, pipeline availability, emissions compliance, and utilization risk |
The defensible conclusion is conditional: EIA’s modeled 2030 average favors new combined-cycle gas on plant-level cost, while nuclear’s continuous output and lack of direct operational CO₂ can carry substantial value for a data center. Select the technology only after pricing the complete, deliverable supply arrangement for the site and start date.
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