Levelized Cost of Electricity (Natural Gas)

1. What LCOE Is

The levelized cost of electricity is the constant price per megawatt-hour that, over the whole life of a plant, exactly recovers every cost at the assumed discount rate. It collapses a project with a large up-front capital spend and decades of variable fuel and maintenance cost into one comparable number.

Formally it is the ratio of discounted lifetime cost to discounted lifetime output:

In practice, when output and costs are roughly constant year to year, this reduces to the annualized form used by EIA, NREL and IEA/NEA, and by the calculator: annualize the capital, then divide everything by annual generation.

2. Capital Recovery Factor

Capital is spent once, but recovered over decades, and money has a time cost. The capital recovery factor converts a lump-sum capital cost into the equivalent constant annual payment — mathematically identical to a mortgage payment:

At 8% over 30 years, CRF = 0.0888. A plant costing $1,330/kW therefore carries $118.1/kW-yr of capital recovery. Note how strongly this depends on the discount rate:

3. The Full Build-Up

Every term is reduced to dollars per MWh of net generation. A 1 kW plant at capacity factor CF generates 8,760 × CF kWh per year, so annual per-kW costs are divided by that output:

Where the unit factors come from

These constants are not arbitrary — each is a unit conversion:

• 1000 / (8760 × CF) — one kW at capacity factor CF produces 8,760 × CF kWh/yr, or 8.76 × CF MWh/yr. Dividing $/kW-yr by that gives $/MWh.
• HR / 1000 — heat rate in Btu/kWh times 1,000 kWh/MWh, divided by 10⁶ Btu/MMBtu, gives MMBtu per MWh.
• EF / 10⁶ — converts kg CO₂/MMBtu through MMBtu/MWh to tonnes CO₂/MWh.

Thermal efficiency

Heat rate and efficiency are the same statement inverted. One kWh is exactly 3,412.14 Btu, so:

4. Why Capacity Factor Dominates

Capital recovery and fixed O&M are fixed dollars per year. They do not care how much the plant runs. Divide them by a small number of MWh and the per-unit cost explodes. This single effect explains most of the spread between published LCOE figures.

Taking the same $1,330/kW combined-cycle reference plant at 8% and 30 years, varying only capacity factor:

The fuel term is flat because it is charged per MWh produced. Everything else is leverage on utilization.

5. From MW to MMscf/d

Power projects are announced in megawatts. The midstream consequence is volume, and the conversion runs through heat rate:

Worked through for a 418 MW combined cycle at 6,431 Btu/kWh and 60% capacity factor:

As a planning rule of thumb, a combined-cycle plant at full load consumes roughly 14–16 MMscf/d per 100 MW (15.0 at 6,431 Btu/kWh). The annual-average rate is lower by the capacity factor — about 9 MMscf/d per 100 MW at 60% — so the two must never be interchanged. A less efficient simple-cycle unit consumes proportionally more per MWh but usually runs far fewer hours.

6. Worked Example

A combined-cycle plant serving a steady industrial load, using the EIA AEO 2023 single-shaft reference plant.

Step 1: Capital recovery factor

Step 2: Annualize capital and spread over output

Step 3: Fuel and variable

Step 4: Total

7. What LCOE Does Not Tell You

LCOE is deliberately narrow. Used outside its scope it misleads:

• It ignores when the power is produced. A MWh at 5 pm on a summer peak is worth far more than one at 3 am. LCOE treats them identically.
• It ignores capacity value. Dispatchable plants provide firm capacity and reserves that intermittent resources cannot, and that value appears nowhere in $/MWh.
• It excludes system costs. Transmission, interconnection, backup and curtailment are outside the plant boundary.
• It is highly sensitive to assumptions. Discount rate, capacity factor and fuel price each move the answer by tens of percent, so comparisons are only valid on a common basis.
• It assumes level output and costs. Real degradation, major overhauls and escalating O&M require a full discounted cash-flow model.

References

• U.S. EIA — Cost and Performance Characteristics of New Generating Technologies, Annual Energy Outlook 2023 (March 2023), Table 1. Source of every plant-type preset: total overnight cost (2022$/kW), fixed and variable O&M, and HHV heat rate.
• NREL — Annual Technology Baseline: The 2024 Electricity Update. The ATB's fossil cost and performance derive from NETL/FECM sources rather than EIA; only the rate of cost improvement is taken from AEO2023. ATB also applies a fixed charge rate (FCR = CRF × financial factors) rather than a plain CRF, which raises the capital term by roughly 9%.
• IEA / NEA — Projected Costs of Generating Electricity, levelized cost methodology.
• EPA 40 CFR 98 Subpart C, Table C-1 — Default CO₂ Emission Factors and High Heat Values. Natural gas (weighted U.S. average): 53.06 kg CO₂/mmBtu and 1.026×10⁻³ mmBtu/scf (1,026 Btu/scf). Source of both the emission factor and the gas heating value used here.
• EPA AP-42, Table 3.1-2a — Stationary Gas Turbines, CO₂ 110 lb/MMBtu (49.90 kg/MMBtu), Rating A, based on 99.5% carbon conversion. A turbine-specific combustion factor about 6% below the 40 CFR 98 reporting value; it does not cover reciprocating engines (AP-42 Ch. 3.2).