Thermal Power Plant Cost: What It Actually Is, by Technology

There is no single answer to what a thermal power plant costs, and any page that gives you one number has removed the information you needed.

Overnight capital cost for thermal generation runs from $836 per kW for an H-class simple cycle turbine to $7,355 per kW for ultra-supercritical coal with 95 percent carbon capture. That is a spread of nearly nine to one, and every point on it is correct for some configuration.

What determines where you land is technology, scale, carbon capture and financing, in roughly that order. What determines your delivered cost per megawatt-hour is something else again, and it is mostly capacity factor.

This guide gives the full cost matrix from EIA, explains what those figures exclude, and covers the three metrics that together tell you whether a project is worth building.

What a Thermal Power Plant Costs

Overnight capital cost by technology, from the US Energy Information Administration's capital cost study.

Source: US Energy Information Administration capital cost study. Overnight capital cost includes contingency and excludes regional multipliers, learning effects and interest charges.

What that means at real project sizes

A 627 MW single-shaft combined cycle plant at $921/kW is approximately $577 million. A 1,227 MW combined cycle at $868/kW is approximately $1.06 billion. A 650 MW ultra-supercritical coal plant at $4,103/kW is approximately $2.67 billion, and the same plant with carbon capture is approximately $4.78 billion.

Those four numbers describe plants of broadly similar output and differ by a factor of eight.

Is coal cheaper than gas

Not on capital cost, and not by a small margin. Ultra-supercritical coal at $4,103/kW costs roughly 4.7 times a comparable combined cycle plant at $868/kW. Coal's historical cost advantage was in fuel, not capital, and that advantage has narrowed as gas production has risen.

A thermal power plant converts heat into electricity, burning fuel to raise steam or to drive a combustion turbine directly. The category spans coal, gas and oil-fired plant, though new oil-fired baseload is effectively obsolete and is not included in current cost studies as a build option.

For heat rate, configuration selection and how technology choice affects operating performance rather than capital cost, see our guide to power generation systems compared.

What Drives Capital Cost

Four factors move thermal capital cost, and technology is only the first of them.

Technology and cycle. A combined cycle plant adds a heat recovery steam generator and steam turbine to a gas turbine, roughly doubling equipment count for a modest capital increase and a large efficiency gain. Heat rate improves from 9,142 to 6,266 Btu/kWh, a 31 percent reduction in fuel per unit of output, for roughly 4 percent more capital per kW.

Scale. Within the same cycle type, scale dominates. An aeroderivative simple cycle plant at 211 MW costs $1,606/kW against $836/kW for an H-class simple cycle at 419 MW. That is 92 percent more per kW for the same cycle, driven by unit size and by the number of installations, balance of plant and interconnections required.

Steam conditions. Supercritical steam cycles operate above the critical point of water, where liquid and vapour phases cease to be distinct, and ultra-supercritical cycles operate at higher temperatures and pressures still. Both improve efficiency and both require higher-grade alloys and thicker pressure parts, which is part of why coal steam plant costs multiples of gas turbine plant.

Carbon capture. The largest single capital variable, covered in its own section below.

Boiler and pressure part scope sits inside the coal and combined cycle figures above. For what that equipment comprises and the codes governing it, see our guide to industrial boiler combustion systems.

What Overnight Cost Excludes

Overnight capital cost is what a plant would cost if it could be built instantly, and the exclusions are large enough to change a financing decision.

EIA states that overnight capital cost includes contingency factors and excludes regional multipliers and learning effects, and that interest charges are excluded. Its separate capital cost documentation states that capital cost excludes financing-related costs including fees and interest during construction, and that fixed O&M expenses exclude owner's costs such as insurance, property taxes and asset management fees.

Four categories sit outside the headline number.

Interest during construction. A thermal plant takes years to build, and debt drawn during construction accrues interest before the asset earns anything. On a multi-year build this is a material addition to total installed cost.

Owner's costs. Land, permitting, development, owner's engineering, insurance during construction, property taxes and asset management. These are the owner's scope, not the EPC contractor's, and they are frequently underestimated at sanction.

Regional multipliers. Labour rates, site conditions, seismic requirements and local content rules vary construction cost materially between regions. EIA's published figures exclude them.

Transmission and interconnection. Connecting the plant to the network is a separate scope with its own cost and its own schedule.

When comparing a vendor quotation against a published benchmark, establish which of these four the quotation includes. A price that looks competitive against EIA's figure may simply be excluding more.

For how EPC contract structure allocates cost overrun risk and what liability caps actually transfer, see our guide to what an EPC company is and what its risk transfer is worth.

Operating Cost: Fixed, Variable and Fuel

Thermal operating cost splits into three components with different units, and confusing them is the most common error in a plant economics comparison.

Fixed O&M is the annual expenditure per unit of project capacity, expressed in $/MW-year or $/kW-year. EIA defines it as costs that remain relatively constant regardless of plant utilisation, including worker salaries and maintenance or refurbishment scheduled on a calendar basis rather than by operating hours.

Variable O&M is the expenditure per unit of generation, expressed in $/MWh. It covers costs closely tied to actual operating hours, including consumable maintenance items and refurbishment scheduled by operating hours.

Fuel is expressed in $/MWh and is the product of the plant's heat rate and the fuel price in native units, such as dollars per thousand cubic feet or per ton.

Why the distinction decides things

Fixed O&M is the number that determines whether an existing plant stays open, because it is incurred whether or not the plant generates. A unit running at low capacity factor spreads the same fixed cost over less output, which is how plants become uneconomic without anything technically changing.

Variable O&M and fuel scale with generation, so they affect dispatch decisions hour by hour rather than the decision to keep the asset.

Fuel price sensitivity

Fuel is the largest operating cost for most thermal plant and the one over which an owner has least control. Lazard's LCOE analysis prices an H-class combined cycle plant at approximately $48/MWh with fuel at $3.45/MMBtu, and that figure moves materially with gas price.

Spark spread is the margin between the electricity price a plant receives and the cost of the fuel required to generate it, adjusted for heat rate. It is the practical measure of whether a gas plant is worth running in a given hour, and a better efficiency directly widens it.

For contracting the O&M scope itself and what an availability guarantee actually means, see our guide to choosing a power plant O&M provider.

Capacity Factor: The Largest Lever on Delivered Cost

Capacity factor changes delivered cost per megawatt-hour more than capital cost does, because it determines how much generation the fixed costs are spread across.

Capacity factor is actual generation over a period divided by the generation that would have occurred at continuous full output. A plant at 40 percent capacity factor spreads its fixed costs over less than half the output of the same plant at 87 percent.

EIA's own sensitivity work demonstrates the effect directly. Its Alternative Electricity case assumes combined cycle plants operate at an 87 percent capacity factor rather than being limited to 40 percent as in the baseline, and states that LCOE is lower as a result because the same costs are distributed over higher generation.

Same plant. Same capital cost. Materially different cost per MWh.

What capacity factor to assume

EIA calculates annual expected generation hours for dispatchable plant from an annual capacity factor corresponding to the unit's maximum annual availability. For units primarily serving peak load, it uses a 30 percent annual capacity factor.

Assume the capacity factor your dispatch position actually supports, not the one the technology is capable of. A peaking plant modelled at baseload capacity factor produces an LCOE that will never be achieved.

If capacity factor comes in lower than assumed

Fixed costs do not fall, so cost per MWh rises proportionally. This is the single most common way a project underperforms its business case without any technical fault, and it is why the regulatory limits on operating hours covered below matter financially rather than only environmentally.

LCOE, LACE and the Value-Cost Ratio

LCOE alone will mislead you, and EIA publishes a companion metric specifically to correct for it.

LCOE, the levelized cost of electricity, is the estimated cost required to build and operate a generator over a specified cost recovery period, expressed in dollars per megawatt-hour. It includes installed capital cost and operating expenses converted to an equal annual quantity.

LACE, the levelized avoided cost of electricity, is an estimate of the revenue available to that generator, specifically the potential revenue from displacing other more expensive generation, converted to an equal annual amount over the same period.

The value-cost ratio is LACE divided by LCOE. When LACE exceeds LCOE the ratio is greater than 1, and the project is considered economically feasible.

EIA's AEO2026 LCOE report states that while these metrics do not fully capture every factor in a capacity expansion decision, used together as a value-cost ratio they provide a reasonable comparison of first-order economic competitiveness across a wider variety of technologies than any of them individually.

Why this matters for thermal specifically

LACE for combined cycle plants is higher than for intermittent resources because a dispatchable plant can generate during the hours when power prices are highest. A megawatt-hour delivered into a peak evening is worth substantially more than one delivered at 2am in spring.

Comparing generation technologies on LCOE alone therefore understates dispatchable value. That is the strongest financial argument available for thermal capacity, it comes from the government's own methodology, and almost no commercial page makes it.

The IEA publishes an equivalent measure, the value-adjusted levelized cost of electricity or VALCOE, which incorporates both the cost of electricity and its value to the system.

Indicative LCOE by technology

Lazard's LCOE+ analysis gives unsubsidised plant-gate midpoints of approximately $48/MWh for H-class gas combined cycle at $3.45/MMBtu fuel, $71/MWh for ultra-supercritical coal, $110/MWh for coal with 90 percent post-combustion carbon capture, and $141/MWh for a gas peaker. These are plant-gate figures excluding subsidy, transmission and system integration costs.

EIA also notes that combined cycle and solar show relatively little LCOE variation between regions, while other technologies vary more.

Carbon Capture Economics

Carbon capture is the largest single variable in thermal capital cost, and it also degrades heat rate, so it raises both capital and fuel cost per unit of output.

Carbon capture and storage separates CO2 from the flue gas and transports it for permanent storage. The capture process consumes energy, which is why heat rate worsens: coal with capture goes from 8,638 to 12,293 Btu/kWh, meaning 42 percent more fuel for the same output.

Does it pay

It depends on tax credits and on permitted capacity factor. EIA's AEO2026 analysis notes that natural gas combined cycle with CCS is cost competitive because of tax credit and higher allowable capacity factor under EPA Section 111 regulations. Without the credit, the arithmetic is different.

That is a genuinely important point. Under the Section 111 framework, a combined cycle plant with carbon capture is permitted to run more hours than one without, which raises its capacity factor, which lowers its LCOE. The regulation is not only a cost, it is also what makes the capture case work.

Emissions basis

Pulverised coal generation produces approximately 0.84 metric tons of CO2 per MWh on published research estimates, which is the figure carbon pricing applies to. At a carbon price of $100 per tonne, that is roughly $84/MWh added to the cost of every megawatt-hour, which exceeds the entire uncaptured LCOE of a combined cycle plant.

The Regulatory Constraint on What Can Be Built

New unabated coal generation is effectively unavailable as a capacity expansion option in the United States, and EIA's modelling reflects that directly.

EIA's AEO2026 Counterfactual Baseline case excludes coal-fired power plants from capacity expansion. They re-enter only in the Alternative Electricity case, which assumes the requirements of the Clean Air Act Section 111 rule issued in April 2024 are repealed.

The same rule restricts operating hours for new natural gas-fired combined cycle units. EIA notes that in the Alternative case those restrictions are removed, spreading fixed cost components over more generation, which is the capacity factor mechanism described above.

EIA's earlier capital cost documentation makes the same point about coal directly: ultra-supercritical coal without carbon capture cannot be built under current regulations, and the carbon capture case was added to the study specifically to meet the new source performance standard for carbon emissions.

What this means practically

If you are evaluating new thermal capacity in the US, the realistic options are gas combined cycle, gas simple cycle, or either of those with carbon capture. Unabated coal is not on the list, and a cost comparison that includes it is comparing against something you cannot build.

For NOx standards applying to new and reconstructed combustion turbines under 40 CFR Part 60 Subpart KKKKa, see our guide to power generation systems compared.

Is thermal still being built

Yes, and demand is rising. EIA forecasts US electricity sales reaching a record 4,135 billion kilowatt-hours in 2026, driven by data centre development and increased manufacturing. Gas-fired capacity remains the largest single component of US installed capacity and the dominant dispatchable option for new build. What has changed is the fuel and the permitting envelope, not the need for firm capacity.

Financing Structure

How a thermal project is financed affects delivered cost as much as several of the engineering decisions, and overnight capital cost excludes all of it.

Four elements determine financing cost.

Capital structure. The debt to equity ratio, and the cost of each. EIA notes that its own financing assumptions vary by cost of debt and cost of equity, and across technologies based on differing tax depreciation treatments and on the market risks associated with certain carbon-intensive generation options.

That last clause matters: carbon-intensive assets attract a risk premium in financing, independently of their engineering cost.

Interest during construction. Debt drawn through a multi-year build accrues before revenue begins, and it is excluded from every published overnight cost figure.

Debt service coverage ratio, or DSCR, is the ratio of cash available for debt service to the debt service due. Lenders set a minimum, and it determines how much debt a project can carry against a given revenue forecast.

Revenue certainty. A power purchase agreement, or PPA, is a contract to sell output at agreed terms for an agreed period, and a tolling agreement is a variant in which the offtaker supplies the fuel and pays a capacity charge. Either raises the debt a project can support, because it reduces revenue risk.

Stranded asset risk

A thermal plant financed over 25 to 30 years must remain economic across that period. Where policy, fuel price or dispatch position shifts, the asset can become uneconomic before the debt is repaid. Lenders price this, and it is one reason carbon-intensive projects carry a higher cost of capital.

Mitigations include shorter debt tenors, contracted revenue for the debt period, fuel flexibility, and designing for a conversion or capture retrofit rather than assuming the original configuration runs to term.

Second-order effects

Capital expenditure sets the depreciation basis and the asset's recorded useful life, which affects return calculations. Insurers price on equipment type, protection systems and maintenance regime. And a plant with contracted revenue is financeable on terms a merchant plant is not.

Where the decision is whether to build at all rather than what to build, life extension of an existing asset frequently beats new build on capital. See our guide to brownfield power generation decisions.

Prismecs provides financing solutions to support capital projects alongside engineering and delivery.

Comparing Options Consistently

Most generation cost comparisons fail because the options are priced on different bases, not because the analysis is wrong.

Six things must be held constant across every option before the numbers mean anything.

The cost basis. Whether each figure is overnight cost, total installed cost including interest during construction, or a delivered EPC price. State which, for every option.

The scope boundary. Whether transmission, interconnection, owner's costs, spares and commissioning are inside or outside each number.

The capacity factor. Use the one your dispatch position supports, and apply the same one to comparable technologies.

Fuel price. Use a single forward curve across all options, and test the sensitivity.

The cost recovery period. LCOE is meaningless without it, and a 30-year comparison disadvantages assets with longer book lives.

The value side. Compare LACE alongside LCOE, or accept that you are understating dispatchable options.

Estimate class

Cost estimates carry accuracy ranges, and the AACE International recommended practice for cost estimate classification defines classes from Class 5, an order-of-magnitude estimate at concept stage, to Class 1, a check estimate at full definition. Require the estimate class with every figure, because a Class 5 estimate and a Class 1 estimate are not comparable even for the same plant.

Performance basis

Where performance is contractual, ASME PTC 46, Performance Test Code on Overall Plant Performance, governs whole-plant net output and heat rate testing, and ASME PTC 22, Performance Test Code on Gas Turbines, covers gas turbine output and heat rate. Name the code, the reference conditions and the correction methodology before award, because a heat rate guarantee without a test basis cannot be enforced and heat rate drives fuel cost for the asset's life.

For procuring the long-lead equipment inside these estimates, see our guide to the industrial procurement process.

How the Economics Change by Sector and Region

The cost matrix holds everywhere. What changes is which column matters.

Utility scale

LCOE and LACE together decide the build, and regional variation is significant. EIA publishes both as capacity-weighted and simple averages across 25 US supply regions, with combined cycle showing relatively little regional variation compared with other technologies.

Industrial captive generation

Avoided retail electricity cost, not wholesale LCOE, is the comparison. That is frequently a much higher number, which makes captive generation economic at capacity factors that would not support a merchant plant. Where a coincident thermal load exists, cogeneration improves the case further.

Data centres

Time to power outranks cost per MWh, because a delayed energisation is contractual with the end customer. Simple cycle or reciprocating capacity is frequently selected over more efficient combined cycle purely on schedule.

Remote and island systems

The alternative is diesel at high delivered fuel cost, so the LCOE bar is much higher and smaller, less efficient plant becomes economic. Logistics cost dominates fuel price.

Smaller plants

Below roughly 100 MW the $/kW penalty is severe. The aeroderivative figure of $1,606/kW at 211 MW against $836/kW at 419 MW shows the gradient, and it steepens further below that. Modular and packaged solutions, or storage, frequently beat a small thermal plant.

Outside the United States

The engineering costs are broadly comparable and the regulatory and financing positions are not. Local content requirements, import duties, labour rates and currency exposure all move installed cost. Carbon pricing regimes differ materially, and where one exists it enters LCOE directly at roughly 0.84 tonnes per MWh for coal-fired generation.

What Prismecs Does

Prismecs delivers power generation projects and supports the capital decisions behind them, and its delivered portfolio is gas turbine and distributed generation rather than coal steam plant.

Verified project scope includes eight TM2500 dual-fuel units totalling 260 MW at Birr, Switzerland delivered as a fast-track reserve plant in six months with a new 220 kV interconnection; four TM2500 units totalling 110 MW at Duqm, Oman with O&M crews, CMMS and parts support; an LM2500XPRESS plant at Miaoli, Taiwan delivered in ten months; three LM6000PC units adding 150 MW of fast-start reserve; and an LM6000 fleet decommissioned in Norway, transported and recommissioned at a new site.

Relevant capability spans EPCM services for project delivery, power generation asset services for the equipment, technology and consulting for options analysis, O&M services for the operating phase, and financing solutions for the capital structure.

Apply this article's criteria to any figure you are given, including ours. Ask whether the number is overnight cost or total installed cost. Ask what scope sits outside it. Ask what capacity factor the LCOE assumes. Ask for the AACE estimate class. Ask for the ASME test code behind any heat rate guarantee.

To request a generation options cost comparison, send your required capacity, expected capacity factor, fuel availability and price basis, site location and required in-service date to sales@prismecs.com or call +1 (888) 774-7632. We return a costed options comparison on a consistent basis, with the scope boundary and estimate class stated for each.

Frequently Asked Questions

What does a thermal power plant cost per kW?

Between $836 and $7,355 per kW depending on technology and carbon capture, per EIA's capital cost study. An H-class simple cycle turbine is $836/kW, a 2x2x1 combined cycle plant $868/kW, an aeroderivative simple cycle $1,606/kW, a combined cycle with 95 percent carbon capture $2,365/kW, ultra-supercritical coal $4,103/kW, and ultra-supercritical coal with capture $7,355/kW. Any single quoted figure conceals that range.

What does a 500 MW thermal power plant cost?

It depends entirely on technology. At combined cycle rates of roughly $921/kW, a 627 MW plant is about $577 million. At ultra-supercritical coal rates of $4,103/kW, a 650 MW plant is about $2.67 billion. With 95 percent carbon capture that same coal plant is about $4.78 billion. Plants of comparable output can differ in capital cost by a factor of eight.

Is coal cheaper than natural gas for power generation?

Not on capital cost. Ultra-supercritical coal at $4,103/kW is roughly 4.7 times the capital cost of a comparable combined cycle plant at $868/kW. Coal's historical advantage was fuel price rather than capital, and that has narrowed. On levelized cost, Lazard puts H-class combined cycle around $48/MWh against approximately $71/MWh for ultra-supercritical coal.

What does overnight capital cost exclude?

Interest during construction, financing fees, regional cost multipliers, learning effects, and owner's costs including insurance, property taxes and asset management fees. EIA states these exclusions explicitly. On a multi-year build, interest during construction alone is a material addition to total installed cost, which is why a vendor price and a published benchmark are rarely comparable without establishing scope.

What is the difference between fixed and variable O&M?

Fixed O&M is annual expenditure per unit of capacity, in dollars per MW-year, covering costs that remain constant regardless of utilisation such as salaries and calendar-scheduled maintenance. Variable O&M is expenditure per unit of generation, in dollars per MWh, covering costs tied to operating hours such as consumables and hours-based refurbishment. Fixed O&M is the number that decides whether an existing plant stays open.

How much does capacity factor affect cost per MWh?

Substantially, and often more than capital cost does. EIA's own sensitivity work compares combined cycle plants operating at 87 percent capacity factor against the same plants limited to 40 percent, and notes LCOE is lower at the higher factor because the same costs are distributed over more generation. Same plant, same capital, materially different delivered cost.

What is LCOE and why is it not enough?

Levelized cost of electricity is the cost to build and operate a generator over a specified recovery period, in dollars per megawatt-hour. It measures cost only, not value. A megawatt-hour delivered at peak demand is worth more than one delivered overnight, and dispatchable plants capture that while intermittent resources largely cannot. Comparing technologies on LCOE alone therefore understates dispatchable value.

What is LACE and the value-cost ratio?

Levelized avoided cost of electricity estimates the revenue available to a generator from displacing more expensive generation, converted to an equal annual amount over the cost recovery period. The value-cost ratio is LACE divided by LCOE. When LACE exceeds LCOE the ratio is above 1 and the project is considered economically feasible. EIA publishes both because either alone gives an incomplete comparison.

How much does carbon capture add to a power plant?

For combined cycle, capital cost rises from $921/kW to $2,365/kW, an increase of 157 percent, with heat rate worsening from 6,226 to 7,239 Btu/kWh. For ultra-supercritical coal, capital rises from $4,103/kW to $7,355/kW, up 79 percent, with heat rate worsening from 8,638 to 12,293 Btu/kWh, meaning 42 percent more fuel per unit of output. Capture raises both capital and fuel cost.

Can a new coal plant be built in the United States?

Not as unabated coal in practice. EIA's AEO2026 Counterfactual Baseline case excludes coal-fired power plants from capacity expansion, and they re-enter only in an alternative case assuming the April 2024 Clean Air Act Section 111 rule is repealed. EIA's capital cost documentation states directly that ultra-supercritical coal without carbon capture cannot be built under current regulations.

Does carbon capture ever pay for itself?

It can, under specific conditions. EIA's AEO2026 analysis notes that natural gas combined cycle with carbon capture is cost competitive because of tax credits and a higher allowable capacity factor under EPA Section 111 regulations. The higher permitted operating hours lower LCOE by spreading fixed costs over more generation. Without the credit and the capacity factor allowance, the arithmetic changes substantially.

What CO2 does a coal plant emit per MWh?

Published research estimates put pulverised coal generation at approximately 0.84 metric tons of CO2 per megawatt-hour. At a carbon price of $100 per tonne, that adds roughly $84 per MWh to generation cost, which exceeds the entire unabated levelized cost of a modern gas combined cycle plant. Carbon price sensitivity is therefore the dominant variable in any coal business case.

What should I require in a cost estimate?

The cost basis, meaning overnight, total installed or delivered EPC price. The scope boundary, including whether transmission, interconnection, owner's costs and commissioning are inside. The capacity factor assumed. The fuel price basis. The cost recovery period. And the AACE International estimate class, since a Class 5 order-of-magnitude estimate and a Class 1 check estimate are not comparable even for the same plant.

Which test code proves a plant's heat rate guarantee?

ASME PTC 46, Performance Test Code on Overall Plant Performance, governs whole-plant net output and heat rate. ASME PTC 22, Performance Test Code on Gas Turbines, covers gas turbine output and heat rate. Name the code, reference conditions and correction methodology before award. Heat rate drives fuel cost for the asset's entire life, so an unenforceable guarantee on it is among the most expensive contractual gaps available.

Tags: Thermal Power Plant Cost LCOE and LACE Capital Cost Per kW Carbon Capture Economics Power Project Financing