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The defensible way to estimate the cost of keeping a coal plant online is to build a forward-looking, plant-specific cash-cost model—not to copy a national average. Define the unit and operating state, separate fixed costs from generation-linked costs, use the plant’s own fuel, heat-rate, maintenance and dispatch data, and then compare continued operation with retirement on the same time horizon. Report both annual dollars and dollars per net megawatt-hour (MWh), with every input tied to a date, dollar year and accounting boundary.
A cost-per-MWh figure alone cannot answer a keep-or-retire decision. The decision also depends on expected market revenue, capacity or flexibility value, reliability value where the applicable planning framework quantifies it, retirement obligations and the cost of replacement power.
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Start by defining what “online” and “cost” mean
Most disagreements arise before anyone opens a spreadsheet. “Keeping a plant online” can mean several different things:
- Running a named boiler-generator unit at a specified output.
- Dispatching the unit whenever its short-run cost is economic.
- Maintaining the unit as available capacity even if it runs infrequently.
- Keeping an entire station open, including shared fuel handling, ash systems, water systems and administration.
Write the definition at the top of the model. Then specify the forecast period, currency, dollar base year, net or gross generation basis, and whether the result is an annual cash outlay, average cost per net MWh, or an incremental keep-versus-retire value. A single-unit model and a station model are not interchangeable: shared costs must be allocated consistently, and a station may contain units with different heat rates, outage histories and retirement dates.
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Choose the decision horizon
Use the same horizon for the operating and retirement cases. A five-year decision should include five years of expected operating costs, maintenance and compliance spending, revenues and retirement or replacement effects. Historical construction spending is normally sunk and should not be counted as an avoidable future cash cost. Include capital only when future sustaining work, environmental equipment or a life-extension project changes the choice.
Choose the output metric
| Metric | Best use | Main limitation |
|---|---|---|
| Annual forward cost | Budgeting and cash planning | Does not show how much electricity the plant produces |
| Cost per net MWh | Comparing operating economics at a stated dispatch level | Can rise sharply when fixed costs are spread over low output |
| Incremental keep-versus-retire value | Investment or retirement decisions | Requires revenue, replacement and system-value assumptions |
Collect plant-specific inputs before using benchmarks
Use audited operating records, management-accounting ledgers, fuel contracts, transportation agreements, maintenance plans, engineering estimates and dispatch forecasts whenever possible. Record the unit, measurement date, accounting boundary and dollar basis for every number. A historical benchmark can reveal an implausible estimate, but it cannot replace the plant’s own contracts and engineering data.
| Input | Preferred evidence | Why it matters |
|---|---|---|
| Fixed O&M | Annual labor, insurance, property taxes, administration and other standing costs | Usually incurred even when generation is low |
| Variable O&M | Recent operating ledger reconciled to a net-MWh denominator | Changes with output and cycling |
| Delivered coal price | Fuel and rail, barge, truck or conveyor contracts, including handling charges | Fuel cost is usually the largest generation-linked item |
| Unit heat rate | Tested or operational heat rate at expected loads and ambient conditions | Converts fuel energy into dollars per MWh |
| Expected net generation | Dispatch model adjusted for planned and forced outages | Determines how fixed costs are spread and how much fuel is burned |
| Starts and shutdowns | Expected annual starts, startup fuel, auxiliary power and wear costs | Important for cycling units |
| Major maintenance | Outage schedules, overhaul quotes, inspection findings and risk allowances | Large, lumpy costs can dominate a single year |
| Compliance and other plant-specific work | Required environmental, water, ash, safety or reliability projects | May be unavoidable for continued operation |
Build the annual forward-cost ledger
A practical annual expression is:
Annual forward cost = fixed O&M + (net MWh × variable O&M per MWh) + (net MWh × heat rate × delivered fuel price per heat unit) + startup and shutdown costs + scheduled and risk-adjusted major maintenance or life-extension costs + applicable compliance and other plant-specific costs.
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1Fix the driver behind crashes, sound loss and screen glitches2Repair Windows errors before they cause bigger problems3Scan for outdated or missing drivers - takes under a minuteKeep units consistent. If heat rate is in MMBtu/MWh and coal is priced in dollars/MMBtu, their product is dollars/MWh. If the contract price is dollars per ton, convert it using the delivered coal’s heat content:
Fuel cost per MWh = heat rate (MMBtu/MWh) × coal price ($/ton) ÷ coal heat content (MMBtu/ton).
Use the contract’s delivered price, not a mine-mouth quote, when transportation and handling are paid by the plant. If the contract has escalators, quality penalties or minimum-take provisions, model those terms explicitly.
Fixed O&M
Fixed operation and maintenance (O&M) generally covers costs that do not move directly with MWh, such as station labor, supervision, property taxes, insurance and standing administrative functions. The exact boundary differs by accounting system. Confirm whether pensions, corporate overhead, ash-site obligations, fuel-handling staff and shared infrastructure are included before comparing two estimates.
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Variable O&M
Variable O&M commonly includes non-fuel consumables, waste disposal and maintenance materials. Some published methodologies also include other operating supplies. Reconcile the definition to the plant ledger and denominator. A rate calculated on gross generation will not match a rate calculated on net generation.
Starts, cycling and outage effects
A unit that runs fewer hours may still incur substantial startup fuel, auxiliary electricity, emissions-control use and thermal-cycling wear. Estimate starts by operating mode—hot, warm and cold if the engineering data distinguish them—and apply the corresponding cost. Planned and forced outages reduce net MWh while some fixed costs continue, so do not assume that a lower capacity factor automatically means proportionally lower annual cost.
Lumpy maintenance and life-extension work
Do not hide a major overhaul in a smooth average unless the decision method calls for annualization. A cash-flow model should place the expenditure in the year it is expected, with a probability or risk allowance where the timing is uncertain. An annualized model can divide the expected present value over the analysis period, but it must disclose that treatment. Include only future spending that differs between keeping the unit and retiring it.
Calculate an average cost per net MWh
For reporting, divide annual forward cost by expected net generation:
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Average forward cost ($/net MWh) = annual forward cost ($) ÷ expected net generation (net MWh).
This metric is useful for dispatch screening and communication, but it can mislead when output is volatile. A unit with high fixed cost and low utilization will show a high average cost even if its short-run dispatch cost is competitive during the hours it runs. Conversely, a high-utilization unit can appear inexpensive per MWh while requiring a large overhaul payment in one forecast year.
Use LCOE carefully for an existing coal unit
The National Renewable Energy Laboratory’s cited levelized-cost structure is:
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LCOE = (overnight capital cost × financial factor + fixed O&M) ÷ (8,760 × capacity factor) + variable O&M + fuel cost × heat rate.
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One free scan finds every outdated or missing driver and matches the right update for your exact hardware.Free scan · exact hardware matchFor an existing unit, adapt the capital and financing terms to the actual question. A new-build overnight cost is not automatically a cost of keeping an already-built plant online. If the unit needs a future retrofit or life-extension project, use that project’s future cash requirement and timing rather than the plant’s original construction cost.
State whether the calculation uses net or gross capacity, how outages and starts are treated, and whether the capacity factor is an assumed average or comes from a dispatch forecast. NREL cautions that LCOE reports can be difficult to compare when their financing, operating and utilization assumptions differ, and a simple average-capacity-factor approach does not represent every operating pattern.
Compare keep and retire on an incremental basis
The decision question is not “Is the plant’s average cost high?” It is “Does the value of continued operation exceed the forward costs and risks that retirement would avoid?” Build two cases over the same years.
Continued-operation case
- Fixed and variable O&M.
- Delivered fuel and startup costs.
- Scheduled overhauls, life-extension work and compliance capital.
- Expected energy revenue or market value under the relevant dispatch forecast.
- Capacity, flexibility or reliability value when the applicable market or planning process quantifies it.
- Residual value or salvage assumptions, if material.
Retirement case
- Avoided operating, fuel and sustaining costs that truly disappear.
- Retirement, remediation, decommissioning and post-retirement obligations.
- Replacement energy, capacity, transmission or balancing costs.
- Any change in reliability or resilience value.
- Costs that continue after retirement, such as site security, ash management or pension obligations.
Discount the two cash-flow streams using the organization’s approved financial convention, then compare their present values. Keep sunk costs separate. EIA has explained that coal units often retire when operating costs exceed expected revenue or when costs exceed the plant’s value to the system, including reliability value. Fuel-price changes and new compliance investments can shift that comparison.
Do not assign reliability value by guesswork
Reliability value depends on the regional market, reserve requirements, transmission constraints, neighboring resources and the planning standard in force. If the relevant system operator or regulator has a documented method, use it and cite the date and assumptions. If no credible value is available, show a range or leave the component unquantified rather than inserting a generic premium.
Run sensitivities instead of presenting false precision
At minimum, vary the assumptions most likely to change the decision:
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| Variable | Low case | Central case | High case | What to disclose |
|---|---|---|---|---|
| Delivered coal price | Contract floor or low market case | Best current forecast | Escalation or supply-stress case | Heat content, transport and escalation date |
| Net generation | Low dispatch or outage case | Expected dispatch | High-utilization case | Capacity factor, outages and starts |
| Heat rate | Best tested performance | Forecast operating rate | Degradation or derating case | Load point and test or operating basis |
| Variable O&M | Recent lower-cost years | Normalized ledger | Wear or consumables increase | Included line items and net/gross denominator |
| Major maintenance | Deferred or lower-scope work | Approved plan | Full scope plus contingency | Timing, probability and cash versus annualized treatment |
| Compliance investment | No new requirement | Known project | Potential rule or retrofit case | Legal status, schedule and useful life |
Show which inputs are contracted, measured, modeled or assumed. A low, central and high number is meaningful only when each range has a stated basis. A tornado chart or one-variable-at-a-time table can identify the assumptions that deserve engineering or commercial review first.
Independent reader supportYour contribution helps us test, update, and keep practical guides available for everyone.Illustrative calculation with clearly stated assumptions
The following example demonstrates the mechanics; it is not a benchmark for any particular plant. Assume a unit has $42 million of annual fixed O&M, expected net generation of 3.0 million MWh, variable O&M of $5.50/net MWh, a heat rate of 10.0 MMBtu/net MWh, and delivered coal at $2.40/MMBtu. Assume $9 million of startup and shutdown costs and $18 million of scheduled maintenance in the forecast year.
- Variable O&M: 3.0 million MWh × $5.50 = $16.5 million.
- Fuel: 3.0 million MWh × 10.0 MMBtu/MWh × $2.40 = $72.0 million.
- Add fixed O&M, startup and maintenance: $42.0 million + $16.5 million + $72.0 million + $9.0 million + $18.0 million = $157.5 million.
- Average forward cost: $157.5 million ÷ 3.0 million MWh = $52.50/net MWh.
If maintenance is expected only once every four years, a cash-flow comparison would place the $18 million in the relevant year. A planning summary might annualize its present value, but both cases must use the same convention when compared with retirement.
Use historical benchmarks with their boundaries intact
EIA’s Form 1-based cost-group analysis reported historical 2008–2017 results, not a current quote for a named unit. It found approximately $28–$40/MWh for the highest operating-cost group and $20–$26/MWh for the lowest group. Only about 55% of the U.S. coal fleet reported the Form 1 data used in the study in 2008, so the ranges do not represent the entire fleet and should not be pasted into a plant model without reconciliation.
The same EIA analysis projected that 66% of units in the highest operating-cost group versus 36% in the lowest group would retire between 2019 and 2030. That was a study-specific projection, not a current forecast or a causal estimate for an individual plant.
EIA identifies Table 8.4 of the Electric Power Annual as a historical source for operation, maintenance and fuel expenses by major fuel type. The table page was last reviewed in April 2024; use the current table version when quoting a particular national-year average, and state the year and coverage.
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EIA reported that 2.6 gigawatts (GW) of U.S. coal-fired capacity retired during 2025, the least since 2010. At the beginning of 2025, operators had planned 8.5 GW of retirements, but some plans were delayed or canceled. These figures describe fleet context; they are not inputs for a specific plant’s fuel, O&M or maintenance cost.
Retirement schedules can change with market conditions, fuel prices, reliability needs, regulation and owner decisions. EIA’s 2021 analysis noted that coal plants usually are not built with a specific planned or enforced retirement age. Treat announced dates as plans until the owner, regulator or grid authority confirms the effective date.
Common modeling errors and how to correct them
Using the plant’s original construction cost
Original construction spending is generally sunk. Replace it with future sustaining or life-extension cash that differs between the keep and retire cases.
Mixing gross and net generation
Use net MWh consistently for heat rate, variable O&M and average-cost calculations unless every input is explicitly gross-based.
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Check whether a benchmark includes labor, waste disposal, ash handling, environmental equipment, major overhauls or corporate overhead. Reconcile definitions before adding values.
Ignoring low-utilization effects
Fixed costs do not fall in proportion to output. Model the expected dispatch and spread fixed costs over the resulting net MWh.
Double-counting maintenance
If variable O&M already includes routine maintenance materials, do not add those same items again. Keep major overhauls separate only when the source rate excludes them.
Treating an announced retirement as completed
Separate planned, delayed, canceled and realized retirements, and date-stamp every status.
Calling an LCOE a retirement decision
LCOE summarizes cost under assumptions. A retirement decision also needs revenue, replacement effects, system value and retirement obligations.
Quick Recap
A practical spreadsheet layout
- Create an assumptions sheet with unit name, net capacity, dollar year, forecast years, dispatch, outage rates and all source dates.
- Create a fuel sheet with contract price, heat content, transportation, escalation and heat-rate scenarios.
- Create an O&M sheet separating fixed, variable, startup and shutdown costs.
- Create a maintenance and compliance schedule with year, scope, probability, cash amount and treatment.
- Create operating and retirement cases with identical discounting, inflation and horizon conventions.
- Create an output sheet showing annual dollars, dollars per net MWh, present value, break-even fuel price and sensitivity results.
- Add a reconciliation column explaining why each benchmark differs from the plant-specific input.
Final review checklist
- Is the boundary a unit or station, and are shared costs allocated consistently?
- Is “online” defined as running, economic dispatch, or available capacity?
- Are all dollars tied to a base year and all inputs tied to dates?
- Are fixed O&M, variable O&M, fuel, starts, maintenance and compliance separated?
- Are heat rate, coal price and heat content expressed in compatible units?
- Are net MWh, outages and cycling assumptions explicit?
- Are sunk costs excluded from avoidable future costs?
- Are keep and retire cases modeled over the same horizon?
- Are revenue, replacement cost and reliability value documented rather than guessed?
- Do historical benchmarks retain their coverage and vintage limitations?
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