The defensible way to compare captive generation, co-generation (combined heat and power, or CHP), and grid electricity is to put every option on the same facility load, operating schedule, reliability level, and price year. Calculate the grid bill actually avoided, the full delivered cost of on-site electricity, and—only for CHP—the value of useful heat that simultaneously displaces a real boiler, furnace, heating, or cooling expense. Include capital recovery, fuel, fixed and variable operations and maintenance, residual grid purchases, demand and customer charges, standby and supplemental service, interconnection, taxes, and outage assumptions. Without a location, tariff, fuel quote, load profile, thermal demand, financing terms, and operating assumptions, no option can be called universally cheapest.
What the three terms mean
Captive power
Captive power is electricity generated for a user’s own consumption or under a project arrangement serving that user. It describes the ownership or use arrangement, not one particular technology. A captive plant may use engines, turbines, fuel cells, solar, storage, or another generator, and it may remain connected to the grid.
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Co-generation or CHP
Co-generation, usually called combined heat and power (CHP), produces electricity or mechanical power and useful thermal energy from one energy source at the same time. The U.S. Department of Energy defines CHP as “The concurrent production of electricity or mechanical power and useful thermal energy (heating and/or cooling) from a single source of energy.” A CHP plant can be captive, but captive power does not necessarily provide useful heat.
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Grid electricity is purchased from a utility or other supplier under the tariff and service agreement applicable to the facility. A grid-connected generator can still rely on the grid for backup during an outage, maintenance, or periods when its output is below demand. Therefore, “on-site versus grid” is often a hybrid comparison rather than an either-or choice.
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The central comparison: delivered grid cost versus incremental on-site cost
Start with the cost of supplying the facility’s electrical and thermal services separately. Then compare that baseline with the proposed project while holding the facility’s output, schedule, and reliability constant.
For a non-CHP generator, the relevant electricity cost includes the generator’s capital recovery or financing, delivered fuel, fixed and variable O&M, planned maintenance, expected utilization, availability, interconnection and delivery costs, and the cost of electricity still purchased from the grid. A simple fuel-per-kWh figure is not a delivered cost.
For CHP, first price the thermal service the facility would otherwise obtain from a boiler, furnace, chiller, or other source. Credit recovered heat only when it is useful, available at the required conditions, and coincident with demand. The electricity should be evaluated as the incremental cost above the cost of providing that thermal service alone:
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Compare that result with the grid’s delivered cost for the same electrical units, including demand and customer charges that remain after generation is installed. Also report total facility energy cost when recovered heat materially changes the thermal bill.
Collect the site data before calculating anything
A credible comparison uses measured or documented inputs rather than a single nameplate efficiency or a generic tariff.
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- Electrical load: interval demand and energy, peak kW or kVA, power factor where billed, operating hours, weekends, shutdowns, seasonal changes, and time-of-use periods.
- Thermal load: steam, hot water, hot gas, heating, or cooling requirements; temperature and pressure; hourly demand; seasonal coincidence with electrical output; and the existing fuel and equipment used to provide it.
- Utility terms: service class, customer charge, energy rate, demand rate, seasonal or time-of-day blocks, taxes or duties, metering, export rules, standby terms, and interconnection requirements.
- Fuel supply: delivered price, heating value, transport charges, minimum purchases, escalation, quality limits, and supply-interruption risk.
- Project assumptions: installed cost, financing or discount rate, useful life, replacement schedule, fixed and variable O&M, planned outage hours, forced-outage assumptions, staffing, insurance, and permitting.
- Reliability requirement: critical loads, allowable interruption, black-start capability, islanding controls, emergency generation, and the grid service retained during an on-site outage.
Use one operating calendar and one price year for every scenario. An annual spreadsheet is adequate for a screening calculation; an hourly model is preferable when demand charges, thermal coincidence, storage, or variable renewable output matter.
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Separate every bill component
Large-customer bills commonly contain three basic elements:
| Bill element | What it pays for | Why it matters in a comparison |
|---|---|---|
| Customer charge | A recurring service or account charge | It normally remains even when energy purchases fall. |
| Energy charge | kWh or other energy consumed | Self-generation can reduce this only for the hours and output actually displaced. |
| Demand charge | The facility’s measured peak demand, often in kW or kVA | A short peak can set a monthly charge; self-generation may not eliminate it. |
Demand rates can vary by season or time of day. Some tariffs measure a coincident or non-coincident peak, apply ratchets, or use different thresholds. Read the tariff’s measurement interval and reset rules rather than multiplying an average load by an energy rate.
Model time-of-use and residual purchases
Map each interval of the facility load to the applicable energy period. Subtract only the on-site output that is available in that interval. Keep grid imports for startup, low-generation periods, maintenance, and any demand above the generator’s output. Recalculate the resulting demand peaks; a generator that reduces kWh may leave the billed peak unchanged.
Include taxes, duties, and service terms
Use the current tariff schedule for the facility’s jurisdiction and service class. Include taxes or duties that would be avoided, retained, or shifted under self-generation. Confirm whether the tariff requires a minimum bill, power-factor adjustment, export metering, or a separate supply contract.
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Capital and financing
Convert installed cost into an annual capital charge using the project’s financing terms, discount rate, life, and residual value. Include engineering, construction, controls, switchgear, fuel connection, civil works, permitting, commissioning, and replacements. Comparing a financed generator with an unstated cash purchase or ignoring the cost of capital can reverse the result.
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Fuel and operating cost
Use the fuel delivered to the site, not a wholesale headline price. Account for the unit’s output at the expected load, part-load efficiency, startup fuel, minimum loading, and fuel-quality constraints. Add fixed O&M, variable O&M, consumables, labor, service contracts, emissions compliance, insurance, and planned maintenance.
Availability and residual grid service
Schedule maintenance and forced outages explicitly. During those hours the facility either buys from the grid or curtails load. If the grid connection is retained, include its customer, demand, backup, maintenance, and supplemental charges even when annual grid energy falls sharply. If the project exports electricity, model the applicable compensation and interconnection costs separately from self-consumption.
Evaluate CHP by valuing useful heat correctly
Establish the separate-production baseline
Identify how the facility would provide heat or cooling without CHP, including fuel, boiler or furnace efficiency, electricity for pumps and fans, O&M, and thermal distribution losses. That baseline is the maximum defensible value of recovered heat. Do not assign the heat a generic “efficiency credit” if the facility has no simultaneous demand for it.
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Test thermal coincidence and constraints
For every operating interval, determine how much CHP heat is actually used. Reduce the credit when heat demand is lower than recoverable output, when temperature or pressure is unsuitable, or when storage and controls cannot shift the heat. Dumped or rejected heat has no avoided-fuel value. A CHP plant sized for electrical demand alone may run inefficiently or produce more heat than the site can use.
Calculate the incremental electrical cost
Allocate the CHP project’s total cost between the thermal service that replaces the separate-production baseline and the incremental electricity. The allocation can be expressed as an excess-cost calculation rather than an arbitrary percentage split. Compare the resulting incremental electricity cost with the grid’s avoided delivered cost, while reporting the total cost of both electrical and thermal services.
The DOE’s “Combined Heat and Power Basics” page uses broad explanatory figures of about 75% efficiency for CHP applications versus about 50% when services are provided separately, and describes 65%–75% as a reasonable CHP range. These are generalized U.S. figures, not guarantees for a particular engine, turbine, fuel, load, or climate. Use the manufacturer’s tested performance and the site’s actual thermal utilization for a project decision.
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Keep reliability and grid-service costs in the same comparison
The U.S. Department of Energy’s standby-rate guidance distinguishes several services that can appear when a facility has on-site generation:
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- Backup power: grid supply during an unplanned generator outage.
- Maintenance power: supply while the generator is intentionally offline.
- Supplemental power: grid supply when on-site output is below the facility’s demand.
- Economic replacement power: grid supply when buying electricity costs less than operating the generator.
A standby tariff may charge for reserved capacity, actual backup use, maintenance periods, or a demand ratchet. The facility may also retain ordinary customer and demand charges. Obtain the utility’s current standby and interconnection documents; do not assume that installing generation removes the billed peak or makes the grid connection free.
Compare options at the same reliability level. If the grid-only case provides automatic restoration and the captive case accepts long interruptions, the apparent energy saving is not an equivalent service. For a resilience project, analyze outage performance—fuel storage, black start, islanding, critical-load capacity, and recovery time—separately from normal energy-cost savings.
A practical calculation workflow
- Define the boundary. State whether the comparison covers only electricity or both electricity and thermal services, and identify the meter or site boundary.
- Choose the time basis. Use the same hourly intervals, operating calendar, weather year, and tariff price year for every case.
- Reconstruct the grid bill. Apply customer, energy, demand, time-of-use, tax, minimum-bill, and other tariff rules to the measured load.
- Model captive output. Enter unit size, dispatch, part-load performance, fuel, capital recovery, fixed and variable O&M, maintenance, availability, interconnection, and residual imports.
- Model CHP heat. Establish separate thermal production, calculate coincident useful heat, and credit only the avoided thermal cost that is actually displaced.
- Apply standby and supplemental terms. Recalculate demand, reserved capacity, maintenance service, backup energy, and any ratchets after generation is added.
- Compare equivalent outputs. Report delivered cost per useful electrical unit, total facility energy cost, annual cash cost, and capital requirement at the same reliability.
- Run sensitivities. Vary fuel price, run hours, thermal-load coincidence, demand peaks, capital cost and financing, outages, and tariff changes.
- Document assumptions. Record the tariff version, fuel quote date, load source, equipment performance basis, and every excluded cost.
Comparison axes that prevent misleading conclusions
| Axis | Grid supply | Captive generation | CHP or co-generation |
|---|---|---|---|
| Electrical cost basis | Delivered tariff energy, demand, customer, tax, and service charges | Capital, fuel, O&M, availability, interconnection, and residual grid cost | Incremental electrical cost after crediting useful, coincident thermal service |
| Thermal service | Provided separately by the site’s boiler, furnace, chiller, or other equipment | Usually unchanged unless the generator also recovers heat | Provided from the same energy source and valued at the avoided separate-production cost |
| Grid connection | Primary supply | Often retained for backup, maintenance, supplemental, or economic replacement power | Often retained for the same services |
| Main exposure | Tariff, demand, and regulatory changes | Fuel, utilization, maintenance, capital, and outage performance | All captive exposures plus thermal-load coincidence and heat-use limits |
Sensitivity tests that matter most
Fuel price
Run low, central, and high delivered-fuel cases, including transport or supply charges. A project that wins only at one fuel price is not robust.
Annual run hours and utilization
Test production at the expected schedule, reduced hours, and maintenance or outage conditions. Capital recovery is spread over fewer kWh when utilization falls.
Thermal-load coincidence
Reduce the fraction of recoverable heat used at the same time as generation. This is often the decisive CHP variable; a high nameplate efficiency cannot compensate for rejected heat.
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Demand peaks
Shift or increase modeled peaks to test whether the generator actually lowers the tariff’s billed demand. Include the tariff’s seasonal, time-of-use, and ratchet rules.
Capital and financing
Vary installed cost, interest or discount rate, project life, replacement cost, and construction delay. A lower operating cost can be outweighed by financing and fixed charges.
Tariff and regulatory change
Test changes to energy, demand, standby, export, taxes, and interconnection terms. Treat future rates as scenarios, not certainties.
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India-specific checks for a current project
For an Indian facility, use the applicable state and utility tariff order and the site’s actual bills. The Central Electricity Authority lists Tariff and Duty of Electricity Supply in India—March 2026; that report is a current official reference, not a universal rate or a substitute for the schedule governing a particular connection.
On 14 March 2026, the Ministry of Power’s Press Information Bureau announced that the Government notified the Electricity (Amendment) Rules, 2026, amending Rule 3 of the Electricity Rules, 2005, in relation to captive generating plants. The announcement says the change is intended to clarify the captive framework. Before relying on captive status, verify the operative Gazette text, state rules and orders, ownership and consumption arrangements, wheeling or other charges, and current utility requirements. These India-specific points do not establish eligibility or savings in another jurisdiction.
Common mistakes and how to correct them
- Comparing fuel cost with a retail kWh rate: add capital, O&M, maintenance, availability, grid service, and interconnection costs.
- Counting all recovered heat as savings: credit only useful heat that displaces a documented thermal expense in the same period.
- Removing the grid bill entirely: retain customer, demand, backup, maintenance, supplemental, and residual energy charges when the connection remains.
- Using average load for demand charges: model the tariff’s actual peak interval, season, time-of-use period, and any ratchet.
- Mixing assumptions: use the same load, operating hours, weather, price year, and reliability standard in every scenario.
- Treating generalized efficiency as a guarantee: replace broad DOE explanatory ranges with equipment data and site-specific thermal utilization.
- Ignoring outages and maintenance: schedule planned downtime and forced outages, then price the replacement electricity or curtailment.
- Calling one option universally cheapest: state the location, tariff, fuel, load, thermal demand, financing, and dispatch assumptions behind the result.
What a decision-ready result should show
A useful report presents annual and, where needed, hourly results for each scenario. Show total facility energy cost, electrical cost at the meter, thermal cost, capital requirement, annual fuel and O&M, grid imports, demand and standby charges, expected availability, emissions or permitting constraints where relevant, and sensitivity ranges. State which electrical and thermal loads each option serves and whether the comparison assumes export, islanding, or continued grid backup.
For a material investment, have an engineer or energy analyst validate interval data, tariff interpretation, thermal integration, equipment performance, interconnection, and outage assumptions. A technical guide such as the U.S. Department of Energy’s Guide to Combined Heat and Power Systems for Boiler Owners and Operators can provide project-planning context, but it cannot replace a site feasibility study.
The decision rule
Choose grid electricity when its fully delivered, reliability-equivalent cost is lower than the incremental on-site cost and the facility has no compelling resilience or thermal-integration objective. Choose captive generation when the modeled project—including capital, fuel, O&M, residual grid service, and outages—reduces total cost or meets a reliability requirement at an acceptable risk. Choose CHP only when the site has a substantial, coincident thermal demand and the recovered heat’s verified avoided cost makes the incremental electricity competitive. The result is a site-specific calculation, not a universal ranking.
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