CHP Suite Guide
How to Perform a CHP Technoeconomic Analysis
A practical framework for evaluating combined heat and power (CHP) projects — when CHP makes sense, how to size it, which prime mover to pick, and how to build a defensible financial case.
Technology Overview
Combined Heat and Power (CHP), also called cogeneration, generates electricity and useful thermal energy from a single fuel source. By recovering the waste heat that a conventional power plant would otherwise reject, CHP systems achieve total fuel utilization above 80% — roughly double the efficiency of separate grid power and on-site boilers.
Whether CHP makes economic sense for a specific facility depends on three things: the shape of the thermal and electrical load profile, the local utility tariff structure (especially the spark spread between gas and electricity), and the available capital for the up-front investment. A CHP plant that sits idle most of the year because the host facility only needs heat in winter will not pay back its CAPEX. A CHP plant that runs near full output 8,000+ hours a year because the host has a steady steam load and high spark-spread economics is often a strong investment.
Common applications include hospitals, college campuses, district energy systems, industrial process facilities (food & beverage, pulp & paper, chemicals), data centers with absorption-chiller cooling, and large multifamily buildings with central domestic hot water. The right prime-mover technology — reciprocating engine, gas turbine, microturbine, or fuel cell — depends on size, load profile, emissions constraints, and noise/footprint tolerance.
Module Specs at a Glance
Capacity Range
Microturbines and fuel cells start at 30 kW. Reciprocating engines cover 100 kW to 10 MW. Gas turbines start around 1 MW and scale to 100+ MW for industrial sites.
Total Efficiency
Well-matched CHP systems achieve 75–85% total efficiency (electrical + recovered thermal), versus ~33–55% for grid power alone.
Operating Hours
Economic threshold is typically 4,000+ run-hours per year for industrial CHP and 6,000+ for district/campus thermal hosts.
Fuel Options
Natural gas, biogas, hydrogen blends. Some fuel-cell technologies tolerate higher H₂ content than reciprocating engines.
Thermal Output
Hot water (180–250°F), low-pressure steam, or high-temperature exhaust suitable for absorption chilling.
Typical Payback
5–10 years for industrial sites with strong spark-spread; 8–14 years for commercial/institutional. Sensitivity to tariff changes is the dominant risk.
How to Design a Project
A high-level workflow that mirrors how the CogenS™ platform structures the analysis end-to-end.
Gather load profile data
Pull or build 8,760-hour profiles for electric demand, heating, cooling, and DHW. If real metered data is unavailable, use a reference profile for the building type and adjust for climate. The load profile is the single biggest driver of CHP economics — guesswork here invalidates everything downstream.
Pick a sizing strategy
CHP can be sized to electric base load, thermal base load, or as part of a co-optimized DER mix. Thermal-base sizing maximizes recovered heat utilization (best for high-thermal-load hosts). Electric-base sizing limits grid imports. DER optimization solves both simultaneously alongside BESS, TES, and solar PV.
Select a prime-mover technology
Reciprocating engines have the lowest CAPEX and best part-load flexibility. Gas turbines are simpler mechanically but penalize part-load operation heavily. Microturbines fit small commercial loads. Fuel cells (PAFC, SOFC, MCFC) cost more but emit less and are quieter — a fit for noise-constrained urban sites.
Model utility tariffs and incentives
Spark spread (the price difference between electricity and gas per MMBtu) is the economic engine of CHP. Pull the actual TOU rates, demand charges, standby fees, and net-metering / interconnection costs from the serving utility. Layer in federal ITC, state grants, utility rebates, and any carbon credit / EaaS revenue.
Run the 8,760-hour simulation
Simulate hourly dispatch following the chosen strategy with real performance curves and part-load efficiency. Track fuel use, electrical output, recovered heat, supplemental boiler firing, and grid import/export. The output is annual energy flows that feed the financial model.
Build the lifecycle financial model
Calculate NPV, IRR, simple payback, and total cost of ownership over 15–25 years. Include CAPEX (equipment + install + interconnection), O&M (fixed + variable), fuel, avoided utility cost, ITC/incentives, and any waste-heat capture (EaaS) revenue. Sensitivity-test against ±20% gas price, ±20% electricity price, and run-hour variation.
Compare vendors and decide
Run the same analysis against 2–3 specific manufacturer models. Don't pick on CAPEX alone — the model that costs more upfront often wins on TCO if it has better part-load efficiency at your operating point. Document the comparison clearly so non-engineers in the decision chain see the same picture.
Related Guides
CHP System Design — Module Guide
Hands-on walkthrough of the CHP Module workflow with DER optimization and EaaS revenue modeling.
Thermal Systems TEA Guide
How to evaluate boilers, chillers, cooling towers, and DHW with shared assumptions.
Boiler System Lifecycle & Design
Auxiliary boilers are an essential complement to most CHP installations — design them right.
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