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Repair Windows errors before they cause bigger problemsFix Now →Scan for outdated or missing drivers - takes under a minuteDriver Scan →Clear out junk files and repair common Windows errorsFree Scan →The cheapest electricity option cannot be identified from a fuel price or a generator’s advertised cost per kilowatt-hour alone. Compare the full delivered cost of grid electricity with the incremental cost of on-site generation, then value any useful heat at the cost of the fuel or electricity it actually replaces. Include capital recovery, fuel, operations and maintenance, demand charges, backup service, residual grid purchases, reliability, and the facility’s hourly electrical and thermal loads.
There is no universal winner. A result that is attractive for a factory with steady steam demand can be uneconomic for an office with little coincident heat use. The calculation must use the site’s tariff, load profile, fuel quote, financing assumptions, operating schedule, and regulatory arrangements.
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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 pattern, not one particular technology. A captive plant might use a reciprocating engine, gas turbine, steam turbine, solar installation, or another generator. It may operate alone, in parallel with the grid, or as part of a larger energy system.
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Co-generation or combined heat and power
Co-generation, also called combined heat and power (CHP), produces electricity or mechanical power and useful thermal energy from the same energy source. 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.” CHP is normally installed at or near the facility that uses the outputs.
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CHP can be a form of captive generation, but the terms are not interchangeable. A captive generator may produce only electricity, while a CHP system must have a practical use for recovered heat. That heat may be steam, hot water, direct heat, or cooling produced through an absorption chiller.
Grid electricity
Grid electricity is purchased from a utility or other supplier under the applicable service tariff. The bill commonly combines customer or fixed charges, energy charges based on kilowatt-hours, and demand charges based on the customer’s maximum measured demand. Time-of-use periods, taxes, duties, power-factor provisions, and special backup or standby terms may also apply.
The core comparison: delivered grid cost versus incremental on-site cost
For ordinary self-generation, compare the delivered cost of a kilowatt-hour that the facility would otherwise buy with the cost of producing that additional kilowatt-hour on site. The on-site figure must include more than fuel:
- Capital recovery, lease payments, or financing costs.
- Delivered fuel, including transport and storage where applicable.
- Variable and fixed operations and maintenance.
- Planned overhauls, replacement parts, and scheduled downtime.
- Interconnection, metering, protection, and electricity-delivery costs.
- Electricity still purchased from the grid when the generator is unavailable or output is below demand.
- Backup, maintenance, supplemental, or other standby-service charges.
If the generator reduces a customer’s billed demand, model that effect using the tariff’s demand interval, ratchet, seasonal rules, and metering arrangement. Do not assume that producing energy behind the meter automatically eliminates a demand charge.
How CHP changes the calculation
A CHP project should be compared with a separate-production baseline: the facility’s electricity purchased from the grid plus the thermal energy it would otherwise produce with a boiler, furnace, electric heater, or purchased steam. Credit recovered heat only when it is useful, available at the required temperature and pressure, and used at the same time the CHP system produces it.
The relevant electricity metric is the cost of CHP electricity above the cost of supplying the required thermal service alone. In simplified form:
Incremental CHP electricity cost = (total CHP cost − cost of providing the required thermal output without CHP) ÷ useful CHP electricity produced.
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Value heat at the facility’s actual avoided cost. If recovered steam displaces gas-fired boiler output, use the boiler’s fuel, efficiency, maintenance, and relevant emissions or operating costs. If there is no simultaneous thermal demand, the heat has little or no economic credit; dumping heat or selling it without a firm offtake should not be treated as savings.
DOE gives broad explanatory figures of about 75% efficiency for some CHP applications versus about 50% when services are supplied separately, and describes 65%–75% as a reasonable CHP application range. These are generalized U.S. figures, not a performance guarantee. Actual efficiency depends on technology, size, load, temperatures, maintenance, and how much recovered heat is used.
Build a common comparison before entering prices
Use one annual model or an hourly model for all scenarios. Keep the facility load, operating calendar, price year, and reliability target identical. A comparison that uses annual generator output against peak grid demand, or a fuel-only generator cost against an all-in utility bill, will produce a misleading answer.
Define the facility’s electrical load
- Collect interval demand and energy data at the utility meter, preferably at the tariff’s billing interval.
- Separate weekday, weekend, seasonal, and shutdown patterns.
- Identify the annual peak demand and the time of that peak.
- Record power factor, phase requirements, voltage level, and any export or netting rules.
- Mark critical loads that must remain energized during a grid outage.
Define the thermal load
- Measure steam, hot-water, direct-heat, or cooling demand over the same time periods as the electrical load.
- Record required temperature, pressure, flow, and ramping behavior.
- Identify the minimum thermal demand, not only the annual total.
- Determine whether heat and electricity demand occur simultaneously.
- Document the existing boiler, furnace, chiller, or other thermal equipment that CHP would displace.
Set the reliability requirement
Decide whether the project is intended to reduce normal energy cost, provide resilience, or do both. A system sized for critical loads during outages may operate fewer hours in normal conditions. Analyze outage performance separately from ordinary cost savings, including fuel availability, black-start capability, islanding controls, maintenance outages, and the duration of stored or delivered fuel.
Calculate the delivered cost of grid electricity
Obtain the current tariff for the facility’s service class and location, along with the utility’s standby and interconnection documents. The relevant bill components may include:
- Customer charge: a recurring fixed amount for the account or connection.
- Energy charge: a price for each kilowatt-hour, potentially different by time of day or season.
- Demand charge: a price applied to the highest measured demand during a billing period, with possible seasonal or time-of-use variation.
- Taxes, duties, and adjustments: charges that change the amount actually paid.
- Power-quality or power-factor charges: where the tariff applies them.
- Backup and supplemental service: charges for electricity during generator outages, maintenance, or periods when on-site output is below load.
Compute the annual bill from the actual tariff rather than dividing one invoice by total annual kilowatt-hours. A facility with a high peak and modest annual energy use can pay more per kilowatt-hour on an average basis because of demand charges. Conversely, a high-load-factor facility may have a lower average delivered cost even when its posted energy rate is unchanged.
Model residual grid purchases in every on-site scenario. The generator may produce less than the facility load, shut down for maintenance, or operate only during selected tariff periods. If a grid connection is retained, include its customer and demand charges even when annual grid energy falls sharply.
Calculate on-site generation cost
Capital and financing
Convert equipment, construction, controls, interconnection, and commissioning costs into an annual cost using the project’s financing method, useful life, discount rate, taxes, incentives, and replacement schedule. State whether the calculation uses a cash purchase, debt service, lease, or another arrangement. A low fuel cost does not make a project economical if the plant operates too few hours to recover capital.
Fuel
Use a delivered-to-site fuel quote and specify its unit, heating value, contract term, transport charges, minimum purchase obligations, and escalation assumptions. For variable fuel prices, run more than one case. A generator’s heat rate should be converted into fuel cost per kilowatt-hour under the actual operating load, not only at the manufacturer’s rated point.
Operations, maintenance, and downtime
Include routine service, consumables, labor, monitoring, major overhauls, emissions-control maintenance, insurance, and spare capacity. Apply realistic availability and planned outage hours. If a maintenance outage causes additional grid purchases or lost production, put those costs in the appropriate scenario rather than treating availability as a free assumption.
Interconnection and delivery
Account for studies, switchgear, protection, synchronization, metering, communications, export controls, and any network upgrades. Confirm whether the utility requires special standby, supplemental, or backup arrangements. These charges can materially change the economics of a plant that remains connected to the grid.
Compare at the same meter and reliability level
Choose a comparison boundary and use it consistently. A useful boundary is the facility meter: compare the cost of electricity delivered to that meter, while separately showing thermal energy delivered to the process. Include electrical losses, auxiliary consumption, fuel-handling energy, and any distribution costs that differ between options.
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1Fix the driver behind crashes, sound loss and screen glitches2Clear out junk files and repair common Windows errors3Scan for outdated or missing drivers - takes under a minuteFor a grid-only case, the reliability level is the utility service subject to its outage performance. For an on-site case that keeps the grid, the reliability level may improve, but the customer still pays for the connection and backup service. For a stand-alone plant, include redundant equipment, fuel storage, controls, and operating staff needed to achieve the same reliability. Do not claim resilience from ordinary energy-cost calculations alone.
Use a decision table with the right axes
| Comparison axis | Grid electricity | Captive generation | CHP or co-generation |
|---|---|---|---|
| Primary output | Purchased electricity | On-site electricity for the user | On-site electricity plus useful thermal energy |
| Main cost drivers | Energy, demand, customer, tax, and service charges | Capital, fuel, O&M, downtime, and residual grid service | All captive-generation costs plus thermal equipment and heat-use conditions |
| Thermal value | Separate boiler, furnace, chiller, or purchased thermal service | Usually no recovered-heat credit unless another technology supplies it | Credit only for useful, coincident heat that displaces an identified cost |
| Exposure | Tariff changes and utility demand rules | Fuel prices, utilization, availability, and maintenance | Fuel prices, utilization, availability, thermal-load coincidence, and tariff rules |
| Grid connection | Core supply arrangement | Often retained for backup or supplemental energy | Often retained for backup, supplemental energy, or exports |
The table is a framework, not a ranking. Populate each column with site-specific values and document which loads each option serves.
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Run sensitivities instead of relying on one forecast
At minimum, test the variables that can reverse the result:
- Fuel price: low, reference, and high delivered-fuel cases.
- Run hours: continuous operation, tariff-directed operation, and lower-utilization cases.
- Thermal coincidence: the share of recovered heat used immediately at the required conditions.
- Peak demand: whether generator dispatch actually reduces the tariff-measured peak.
- Capital and financing: construction-cost changes, interest rates, useful life, and overhaul timing.
- Tariffs: energy, demand, standby, supplemental, taxes, and future tariff structures.
- Outages and availability: planned maintenance, forced outages, and grid interruptions.
Report a range or break-even point where practical. For example, calculate the fuel price at which incremental on-site electricity equals delivered grid cost, or the annual operating hours required to recover capital. These thresholds are more useful than a single payback number when future prices are uncertain.
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Site data checklist
Before accepting a feasibility result, assemble the following records:
- The latest utility bills and the complete applicable tariff schedule.
- Interval electricity data covering representative seasons and operating modes.
- Demand-interval definitions, ratchets, time-of-use periods, and power-factor rules.
- Standby, backup, maintenance, supplemental, and interconnection terms.
- Fuel quotations, heating values, transport terms, and escalation assumptions.
- Boiler, furnace, chiller, or purchased-steam fuel and maintenance costs.
- Thermal measurements showing temperature, pressure, flow, and coincidence with electrical demand.
- Generator performance curves, expected availability, maintenance intervals, and auxiliary loads.
- Capital estimates, financing terms, taxes, incentives, permitting, and replacement assumptions.
- Critical-load schedules and the required outage duration for resilience planning.
Industrial energy-management, metering, or CHP-feasibility engineering can help collect and validate these inputs. A technical handbook can explain equipment and design concepts, but it cannot substitute for a site-specific tariff and engineering study.
Independent reader supportYour contribution helps us test, update, and keep practical guides available for everyone.India-specific checks
For an Indian facility, use the applicable state or utility tariff order and the site’s actual bills. The Central Electricity Authority lists “Tariff and Duty of Electricity Supply in India—March 2026” as an official reference report, but a national report is not a substitute for the schedule governing a particular connection.
The Ministry of Power’s Press Information Bureau announced on 14 March 2026 that the Government notified the Electricity (Amendment) Rules, 2026, amending Rule 3 of the Electricity Rules, 2005 concerning captive generating plants. The announcement says the change is intended to clarify the captive framework. Before relying on eligibility, ownership, consumption, or savings assumptions, verify the operative Gazette text, state rules, utility orders, and the project’s ownership and consumption arrangement. This Indian legal and tariff context should not be generalized to other jurisdictions.
Common errors and how to correct them
Comparing fuel cost with the full utility bill
Error: dividing fuel expense by generator output and comparing that figure with the utility’s all-in bill. Correction: add capital, O&M, availability, interconnection, residual grid energy, demand effects, and standby service before comparing.
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Giving all recovered heat a value
Error: treating every unit of exhaust heat as a saving. Correction: credit only heat that meets the process requirement and displaces an identified thermal cost at the same time.
Assuming the grid bill disappears
Error: removing customer, demand, and backup charges after installing a generator. Correction: read the local tariff and model the connection, standby, supplemental purchases, and demand ratchets that remain.
Using rated output as annual output
Error: multiplying nameplate capacity by every hour in the year. Correction: use the facility’s operating calendar, dispatch strategy, availability, maintenance, and load-following limits.
Ignoring thermal-load mismatch
Error: sizing CHP to electrical demand while assuming heat will always be used. Correction: size around coincident thermal demand, or model heat rejection and the resulting loss of credit.
Calling resilience a cost saving
Error: assigning a financial saving to avoided outages without documenting outage frequency, production losses, and system capability. Correction: present resilience benefits as a separate analysis with explicit outage assumptions.
How to present the final result
Give decision-makers at least four outputs:
- Annual total facility cost: electricity plus the thermal service required by the facility.
- Cost per useful electrical unit: grid-delivered cost and incremental on-site cost on the same boundary.
- Thermal utilization: useful recovered heat, its coincidence with demand, and the avoided thermal cost.
- Risk range: sensitivity to fuel, tariffs, utilization, capital, outages, and demand peaks.
State the assumptions beside every headline figure: location, tariff year, fuel basis, operating hours, financing, thermal-load coincidence, and whether backup service is included. A transparent range is more defensible than a universal claim that one supply path is cheapest.
Bottom line
To compare captive power, co-generation, and grid electricity costs, start with the facility’s actual tariff and interval loads. Calculate the full delivered grid bill, then calculate the full incremental cost of on-site electricity after capital, fuel, O&M, outages, demand effects, and continuing grid service. For CHP, subtract only the value of useful heat that genuinely replaces another thermal cost. Reconcile all options at the same meter and reliability level, then stress-test fuel prices, run hours, thermal coincidence, capital, outages, and tariff changes. Without those inputs, a claim that captive power, CHP, or grid electricity is universally cheapest is not supportable.
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