Combined heat & power

The short version

Combined heat and power (CHP) — also called cogeneration — is on-site generation of electricity using a fuel (typically natural gas) where the waste heat from generation is captured and used productively. Conventional separate generation of electricity (35–45% efficient) and heat from a boiler (90% efficient) achieves roughly 50–55% total fuel efficiency. A well-designed CHP system using the same fuel can achieve 65–85% total efficiency by capturing what would otherwise be waste heat — a fundamental efficiency advantage that translates directly to lower operating costs and emissions for facilities that need both electricity and thermal energy.

What total efficiency actually means

A combustion turbine or reciprocating gas engine running independently converts roughly 35–45% of fuel energy into electricity. The rest leaves as heat — in exhaust gas, jacket water, lubricant cooling. In a CHP installation, that heat is captured by a heat recovery steam generator (HRSG), heat exchangers, and absorption chillers, then used for facility space heating, hot water, process heat, steam, or cooling. The net result is that the same combustion event delivers two valuable energy streams. For a facility currently buying grid electricity (which embeds 65% generation losses already paid for) and burning gas in a boiler for heat (90% efficient), the switch to CHP eliminates the generation losses for the electricity portion entirely.

The spark spread and breakeven economics

The CHP business case is fundamentally a fuel arbitrage. CHP displaces retail electricity purchases at the local utility rate (often $0.10–$0.20/kWh for commercial customers) using natural gas at $4–$8/MMBtu. A typical reciprocating gas CHP achieves 9,000 Btu/kWh heat rate, meaning about $0.06–$0.08/kWh in fuel cost per kWh generated, plus $0.01–$0.02 in O&M. The remaining spread — typically $0.04–$0.10/kWh — funds the capital cost and provides project return.

Project economics work best where electricity rates are high relative to gas prices: New York, New England, California (especially before NEM 3.0 changed solar competition), and Hawaii. Project economics struggle where electricity rates are low (Southeast, parts of Midwest) or where gas prices spike volatility-driven (post-2022 Northeast winters). Most institutional CHP projects use long-term gas hedges or supply contracts to lock in spark spread for project finance purposes.

Where CHP wins — and the IRA boost

CHP economics depend on having simultaneous electric and thermal demand year-round. Strong candidates include hospitals (24/7 electric + hot water + heating + sometimes steam sterilization), universities (campus heating loops + dorm hot water + facility electric), large hotels and resorts, food processors with process heat needs, large multi-family buildings with central systems, district energy operators, and increasingly data centers that pair CHP with absorption chillers for hot-aisle cooling. Facilities with seasonal heat demand or low thermal loads are weaker candidates and may struggle to capture the full efficiency advantage.

The Inflation Reduction Act significantly improved CHP economics, and the One Big Beautiful Bill Act (July 2025) preserved most of that improvement — in contrast to its accelerated termination of wind and solar credits. CHP systems up to 50 MW with at least 60% total efficiency qualify for the 48 ITC at a base 6% scaling to 30% with prevailing wage and apprenticeship compliance, plus bonus credits up to 20 percentage points for domestic content and energy community siting. Combined with MACRS accelerated depreciation and the option to monetize credits via transferability, federal tax incentives can offset 40–50% of installed cost — bringing payback periods on well-sited CHP projects to 3–5 years in favorable markets. New Foreign Entity of Concern (FEOC) rules now apply to supply chains, requiring careful sourcing documentation.