Introduction
Natural gas is the dominant fuel for US electricity generation, accounting for approximately 43% of total output in 2025. Gas-fired power plants are the workhorse of the US grid: they provide both continuous baseload generation and rapid-response peaking capacity, they set the marginal electricity price in most hours (as explained in the electricity market structure overview), and their economics directly determine spark spread profitability for merchant generators. For energy bankers, understanding the two main gas generation technologies, their cost structures, and the current investment cycle is essential because gas plant valuations, new build financing, and fleet acquisitions represent a significant share of power sector deal flow.
The investment case for natural gas generation has strengthened dramatically since 2023. The combination of surging data center electricity demand, coal plant retirements, and the limitations of intermittent renewable generation has created an urgent need for new dispatchable capacity. The US gas-fired power development pipeline has more than doubled over the past year to over 250 GW, and 2026 is expected to see record new gas capacity additions.
Combined Cycle vs. Simple Cycle: Two Different Businesses
Natural gas power plants come in two fundamental configurations, each serving a different role in the electricity system and operating under different economics.
Combined Cycle Gas Turbines (CCGTs)
A combined-cycle plant generates electricity in two stages. First, natural gas is burned in a combustion turbine (the gas turbine cycle), spinning a generator. The hot exhaust gases from the turbine (which would otherwise be wasted) are then directed into a heat recovery steam generator (HRSG), which produces steam to drive a second generator (the steam turbine cycle). By capturing this waste heat, combined-cycle plants achieve thermal efficiencies of 55-63%, nearly double the efficiency of a simple-cycle turbine.
- Heat Rate
A measure of power plant efficiency expressed in BTU per kilowatt-hour (BTU/kWh), representing the amount of fuel energy required to produce one kilowatt-hour of electricity. A lower heat rate means higher efficiency. Modern combined-cycle plants achieve heat rates of 6,200-7,200 BTU/kWh, while simple-cycle peakers range from 9,000-11,000 BTU/kWh. Heat rate directly determines fuel cost per MWh: at a Henry Hub gas price of $4.00/MMBtu, a 6,800 BTU/kWh CCGT incurs fuel costs of approximately $27.20/MWh, while a 10,000 BTU/kWh peaker incurs $40.00/MWh.
CCGTs operate as baseload or intermediate generators, running 40-70% of the time (capacity factors of 40-70%). Their low fuel costs make them economically dispatched in most hours, earning energy market revenue consistently. Construction costs for a new CCGT range from approximately $1,000-1,500/kW, with a typical 1,000 MW plant costing $1.0-1.5 billion to build.
Simple Cycle Gas Turbines (SCGTs)
A simple-cycle turbine burns gas and generates electricity in a single stage without heat recovery. This makes the plant less efficient (30-42% thermal efficiency, heat rates of 9,000-11,000 BTU/kWh) but gives it two critical advantages: much faster startup times (10-15 minutes vs. 30-60 minutes for a CCGT) and significantly lower construction costs ($700-1,100/kW).
SCGTs operate as peaker plants, running only during periods of high electricity demand when prices spike above their higher fuel costs. Peakers typically operate at capacity factors of only 5-20%, earning the majority of their revenue during a small number of high-price hours, particularly during summer heat waves and winter cold snaps.
| Characteristic | Combined Cycle (CCGT) | Simple Cycle (SCGT/Peaker) |
|---|---|---|
| Heat Rate | 6,200-7,200 BTU/kWh | 9,000-11,000 BTU/kWh |
| Thermal Efficiency | 55-63% | 30-42% |
| Capacity Factor | 40-70% | 5-20% |
| Startup Time | 30-60 minutes | 10-15 minutes |
| Construction Cost | $1,000-1,500/kW | $700-1,100/kW |
| Primary Role | Baseload/intermediate | Peak demand, fast ramping |
| Revenue Model | Energy margins + capacity | Scarcity pricing + capacity |
The economic and operational differences between these two plant types create distinct investment profiles. CCGTs are valued as long-lived, cash-flow-generating assets analogous to infrastructure (supporting higher leverage and lower return requirements), while peakers are valued as option-like assets whose value depends on the frequency and severity of scarcity events (supporting lower leverage but requiring higher equity returns).
Gas Generation as the "Marginal" Price Setter
In most US wholesale electricity markets, natural gas generators are the marginal units, meaning they are the last generators dispatched to meet demand and their cost sets the market-clearing electricity price (the LMP). This occurs because nuclear and renewable generators (with near-zero fuel costs) are dispatched first, filling the base of the supply stack, while gas generators fill the remaining demand.
This marginal pricing dynamic has several important implications:
Gas prices drive electricity prices. Because gas generators set the marginal price, changes in natural gas prices directly affect electricity prices. The EIA forecasts Henry Hub gas prices averaging approximately $3.50/MMBtu in 2025 and $3.80/MMBtu in 2026, which translates to electricity prices of approximately $35-55/MWh in major markets (depending on heat rates and demand levels).
Efficient gas plants earn wider margins. A CCGT with a 6,500 BTU/kWh heat rate earns a larger spark spread than a competing CCGT with a 7,500 BTU/kWh heat rate, because both receive the same electricity price but the more efficient plant has lower fuel costs. This efficiency advantage compounds over thousands of operating hours.
Nuclear and renewable generators are "inframarginal" beneficiaries. Because nuclear and renewables have near-zero fuel costs, they earn the full LMP as profit whenever gas-set prices are high. This is why Constellation's nuclear fleet has become extraordinarily valuable: it receives gas-set electricity prices with virtually no fuel cost.
The New Gas Build Wave
The US is experiencing the largest wave of new gas-fired power plant development in over two decades. The development pipeline has surged to over 250 GW (more than double the level a year ago), driven by three converging forces:
Coal retirement replacement. As coal plants continue to retire (coal's share has declined from 50% in 2005 to 15% in 2025), gas generation is the primary replacement for dispatchable capacity. Coal retirements remove approximately 10-15 GW of capacity per year.
Data center demand. The AI data center power boom requires reliable, dispatchable generation. While data center operators prefer clean energy, the physics of 24/7 power delivery mean that gas generation (often paired with battery storage and renewables) is essential for filling the gaps when solar and wind are not producing.
Renewable intermittency complement. As solar and wind penetration grows, the grid needs more flexible, fast-ramping generation to balance intermittent supply. Gas peakers and fast-start CCGTs fill this role. The growth of renewables does not reduce the need for gas generation; it changes its operating pattern from continuous baseload to flexible, demand-following dispatch.
The permitting and interconnection bottleneck has created a significant arbitrage between the replacement cost of new gas generation ($1,000-1,500/kW for construction alone, plus permitting and interconnection costs that can add another $200-500/kW in time value) and the acquisition price of existing, operating plants (which have recently traded at $700-950/kW in transactions like Vistra/Lotus and NRG/LS Power). This acquisition-versus-build calculus is the primary driver of gas generation M&A.
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