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Start by separating the three pathways
A coal retirement is not automatically a gas conversion. Treat these as separate alternatives in the model.
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Retire the coal unit and replace its output elsewhere
The owner shuts the unit and meets the same energy, capacity and reserve requirement with a portfolio such as existing market purchases, a new generator, renewable resources, storage, demand response or transmission upgrades. This avoids continued coal-unit maintenance and operating liabilities, but the replacement portfolio and any transmission or firming resources must be ready by the retirement date. Site reclamation, ash management, contracts and workforce transition remain part of the retirement case.
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Convert the existing steam boiler to natural gas
Engineers modify the coal station so its boiler can fire gas, potentially retaining the steam turbine, generator, switchyard, buildings and some balance-of-plant systems. The result is still constrained by the age, condition, heat rate and operating design of the original unit. A conversion can require new burners, fuel trains, controls, instrumentation, emissions equipment, gas interconnection and a lengthy outage. The retained equipment does not guarantee the life, efficiency or ramping performance of a purpose-built NGCC plant.
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Build a new NGCC plant to replace the coal unit
An NGCC combines a combustion turbine, heat-recovery steam generator and steam turbine. It normally requires new generation equipment, interconnection work, financing and often gas-pipeline or firm-transport arrangements. The new plant can offer a longer economic life and higher efficiency than an old converted boiler, but construction and permitting create a larger upfront commitment and a schedule that may not match the coal retirement date.
What historical U.S. data can—and cannot—tell you
The U.S. Energy Information Administration (EIA) identified 121 coal plants repurposed between 2011 and 2019; 103 were converted to gas or replaced by gas-fired plants. In the same period, 49.2 GW of coal capacity from the 2010 fleet had retired. EIA reported 14.3 GW associated with boiler conversions to gas and 15.3 GW of coal capacity replaced by new NGCC projects. These are fleet outcomes, not a forecast for a particular station.
Among 17 coal plants replaced by new NGCC facilities, the new projects totaled 15.3 GW versus 7.9 GW of coal capacity replaced—94% more nameplate capacity. Developers may have built larger units to serve growing demand, improve economics or provide regional capacity; the statistic does not establish that every replacement should be 1.94 times the coal plant’s size, nor that the added capacity is deliverable in every contingency.
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EIA associated the 2011–2019 switching decisions with stricter emissions standards, low gas prices and more efficient turbine technology. It found boiler conversions concentrated among older and smaller units. Those observations describe that historical period; they are not current fuel-price, policy or technology forecasts.
Define a common service requirement before comparing costs
Comparing a 500-MW coal unit with a 500-MW gas unit on nameplate capacity alone can produce a misleading answer. Write down what the replacement must actually deliver and use the same requirement in every case.
- Specify the planning horizon. Choose a common period, such as the remaining life of the coal unit or a 20- to 30-year resource plan. Include salvage, decommissioning and end-of-horizon residual value consistently.
- Define energy and capacity needs. Use hourly or seasonal load requirements, expected annual generation, accredited capacity, reserve contribution and local deliverability—not only nameplate megawatts.
- Set reliability criteria. State the target for loss-of-load risk, contingency reserves, forced-outage assumptions, ramping and minimum stable output. Test heat waves, cold snaps, drought, wildfire, storms and fuel-supply interruptions.
- Fix geographic and market boundaries. Identify the balancing area, transmission constraints, market rules, gas zones and whether imports are firm or interruptible. U.S. assumptions should not be transferred directly to another country.
- Use common financial assumptions. Apply the same discount rate, inflation treatment, tax rules, construction-financing convention, fuel-price scenarios and carbon-cost cases to all alternatives.
Only after these definitions are fixed can a lower-cost option be distinguished from an option that simply provides less service.
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Inspect the coal unit and conversion scope
A conversion estimate starts with a physical and operating baseline. Obtain the boiler design and fuel history, turbine condition, generator capability, heat-rate curve, minimum stable load, ramp rate, outage history, remaining permits and every major maintenance obligation. Record the age and condition of mills, fans, precipitators, scrubbers, selective catalytic reduction (SCR) systems, ash handling, cooling systems, water rights and the switchyard.
Determine which equipment can safely remain in service on gas. Coal mills and pulverizers may be removed or repurposed, while burners, furnace-refractory areas, controls, flame scanners, ductwork, fans and safety systems may need replacement. Gas firing changes furnace heat transfer, flame characteristics, startup procedures and emissions controls. A feasibility study should identify required code upgrades, hazardous-area classification, gas pressure and volume, emergency shutdown systems, venting, metering and a credible outage window.
The unit’s remaining economic life is a central decision variable. Spending heavily on a boiler conversion with only a short life can be uneconomic even when the construction price looks low. Conversely, a sound steam turbine, generator and interconnection can make reuse valuable if the conversion preserves adequate efficiency and availability.
Compare the complete forward cost, not a headline capital number
Put every alternative in one cash-flow model. A conversion may have lower construction cost than a new NGCC, but it does not eliminate fuel, maintenance, financing, outage or coal-site liabilities. Retirement may have little generation capital at the plant but substantial replacement, transmission and storage costs elsewhere.
| Cost category | Retirement and replacement elsewhere | Existing-boiler gas conversion | New NGCC |
|---|---|---|---|
| Generation capital | Replacement plants, storage, demand response or market contracts | Burners, fuel systems, controls, engineering and outage work | Combustion turbine, heat-recovery steam generator, steam turbine, balance of plant and construction financing |
| Fuel and delivery | Depends on the replacement portfolio and market purchases | Delivered gas price, pipeline capacity, demand charges and backup-fuel capability | Delivered gas, firm transport, pipeline extension or compression and fuel-management costs |
| Transmission and interconnection | Network upgrades and deliverability for replacement resources | Value of the existing interconnection, plus gas and electrical modifications | New interconnection studies, equipment and possible network upgrades |
| Environmental and site liabilities | Coal ash, reclamation, demolition, water and remediation obligations | Residual coal liabilities plus new gas-permitting and emissions-control costs | New-site or brownfield permitting, construction impacts and eventual decommissioning |
| Operating costs | Portfolio fixed and variable costs, reserves and market exposure | Gas heat rate, fixed and variable O&M, starts, cycling and remaining coal-equipment maintenance | NGCC heat rate, fixed and variable O&M, starts, cycling and long-term service agreements |
| Policy and carbon exposure | Depends on each replacement resource | Gas combustion emissions, methane assumptions and future carbon costs | Gas combustion emissions, methane assumptions and future carbon costs |
NETL’s 2025 baseline tool offers a consistent framework spanning six pulverized-coal and nine NGCC configurations. It is a configurable baseline, not a plant-specific conversion price or a generic dollars-per-megawatt-hour answer. Change the local heat rate, utilization, fuel delivery, financing, carbon case and retirement liabilities and the ranking can change. An older DOE-hosted National Academies comparison used a representative 1950 coal plant and then-new NGCC; its retrofit percentages are historical illustrations, not current economics.
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Model gas-price and delivery risk explicitly
Both a boiler conversion and a new NGCC replace coal exposure with gas-market exposure. Use regional delivered-price scenarios rather than a single historical average. Include fuel commodity cost, transportation, storage, imbalance charges, pipeline capacity, curtailment priority and the cost of firm service. Confirm whether the plant can operate on a second fuel; if a dual-fuel system is proposed, verify tanks, permits, testing, fuel quality, switching time and actual inventory.
Stress the gas system during the same cold-weather or high-demand events that drive electric reliability. A gas plant may be physically available yet unable to obtain fuel when residential heating demand takes pipeline capacity. Model correlated gas and electric outages, pipeline maintenance, compressor constraints and disruptions that affect several generators at once. Historical low gas prices are not forecasts.
Compare capacity, flexibility and reliability—not just megawatts
For each case, calculate accredited capacity, effective load-carrying capability where applicable, forced-outage rate, planned maintenance, reserve contribution, ramp rate, start time, minimum stable generation and transmission deliverability. A replacement portfolio can meet annual energy while failing a local peak or contingency requirement. A converted boiler may retain a valuable interconnection but have slower starts or lower output than the original coal rating after derating. A new NGCC is generally more efficient and more frequently operated than a simple-cycle gas turbine, but it still depends on gas delivery and can have large single-unit outage exposure.
EPA distinguishes NGCC from simple-cycle turbines: NGCC recovers exhaust heat to make steam and is generally more efficient, while simple-cycle units are commonly used for peaks. Do not substitute a simple-cycle peaker for an NGCC in the analysis without accounting for the resulting heat rate, annual operating profile and emissions.
Test extreme-weather and transmission cases with a production-cost or capacity-expansion model, then validate critical hours with a power-flow and stability study. Ask whether the option can serve local load if a neighboring line, pipeline, generator or storage resource is unavailable. Gas flexibility can complement variable renewable generation, but the value depends on the specific configuration and regional grid.
Keep emissions boundaries clear
Direct stack carbon dioxide
The National Petroleum Council’s December 2025 report says NGCC units average approximately 58% less CO2 per megawatt-hour than coal-fired plants. That is an average direct combustion comparison as presented in the report. It is not a lifecycle result and does not account for how often each unit runs.
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TEP estimates that converting Springerville Units 1 and 2 would reduce those units’ CO2 emissions by about 40%. That is a project-specific utility forecast, not independently verified operating data. A converted boiler can show a smaller reduction than a high-efficiency new NGCC if its heat rate is poorer.
Annual emissions
Multiply the unit’s tested heat rate and fuel carbon content by expected annual generation, startup fuel and dispatch pattern. A gas unit with lower emissions per megawatt-hour can produce more total annual emissions if it operates substantially more hours or replaces zero-carbon resources. Report capacity factor and annual tons alongside the rate.
Lifecycle greenhouse gases
Lifecycle accounting must add gas production, processing and transport, including upstream methane leakage, and must identify the leakage assumptions and calculation method. The evidence summarized here does not establish a plant-specific lifecycle comparison. Do not present a direct stack figure as a full climate result.
Local pollutants
Track nitrogen oxides, sulfur dioxide, particulate matter, mercury, acid gases, water use and wastewater separately from greenhouse gases. Actual changes depend on the unit’s controls, fuel, utilization, startup behavior and permit limits. Retirement ends the coal unit’s stack emissions; a gas alternative shifts the pollutant profile rather than eliminating regulation.
Independent reader supportYour contribution helps us test, update, and keep practical guides available for everyone.Account for transmission, permitting and schedule
A retirement-and-replacement plan may require new transmission, interconnection queues, storage procurement or market contracts before the coal unit can close. A boiler conversion often has a shorter construction footprint because it reuses the site and electrical connection, but gas-supply studies, air permits, environmental reviews and a major outage can still control the schedule. A new NGCC adds construction, interconnection, gas-infrastructure and financing milestones.
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Repair common Windows errors and clear accumulated junk for a smoother, more stable PC - no reinstall needed.Free scan · no reinstallMap the critical path from engineering through permitting, procurement, outage, commissioning and reliability testing. Set a contingency plan if the replacement slips: extend coal operation where legally and technically possible, procure temporary capacity, lease generation, increase demand response or secure market imports. The retirement date should not precede proven replacement capability unless the reliability plan explicitly accepts that risk.
Evaluate community and site consequences
Separate physical plant economics from local transition effects. Retirement can reduce jobs, tax revenue, contracting and rail or mine activity while ending coal ash and combustion impacts. A conversion may preserve some operations and tax base but requires different skills, staffing and safety procedures. A new NGCC creates construction employment and a different long-term workforce profile. Quantify employment, tax, reclamation, health and community impacts with independent assumptions rather than relying solely on a project proponent’s claims.
What current Arizona projects illustrate
Springerville Units 1 and 2
TEP’s current project information says its 2023 integrated resource plan called for retiring Unit 1 in 2027 and Unit 2 in 2032, citing rising coal-fuel costs, delivery risks, anticipated mine closures and regulatory or environmental considerations. A later plan extends Unit 1 coal use beyond the earlier summer-2027 date and accelerates the end of coal combustion at Unit 2 relative to the prior summer-2032 plan; TEP anticipates converting both units to gas by 2030. TEP estimates about 40% lower CO2 emissions.
These dates, demand assumptions and emissions figures are TEP planning statements. They demonstrate how a utility can value an existing site and capacity while changing fuel; they do not prove that a similar conversion is least-cost or on schedule at another station.
Coronado
SRP says converting Coronado to gas is its lowest-cost way to preserve capacity it expects to need for peak demand. SRP forecasts a 50% increase in customer peak demand by 2035 and targets ending coal generation and completing the conversion by late 2029. Those are SRP’s rationale and schedule, not an independent comparative finding. A review should test the forecast, alternatives, fuel security and construction risk.
A reproducible comparison workflow
- Inventory the coal asset. Record equipment condition, heat rate, capacity, outage history, controls, water, ash, permits, contracts and remaining life.
- Define the service obligation. Specify energy, local capacity, reserves, ramping, reliability metric, horizon and retirement deadline.
- Design all three cases. Describe the replacement portfolio, the exact boiler-conversion scope and the new NGCC configuration at comparable service levels.
- Obtain engineering and schedule estimates. Include outage duration, interconnection, gas infrastructure, permitting, commissioning and contingency dates.
- Build consistent cash flows. Add capital, financing, fixed and variable O&M, fuel delivery, transmission, controls, ash, remediation, decommissioning and replacement resources.
- Run market and reliability scenarios. Vary gas and coal prices, carbon costs, utilization, renewable additions, storage, pipeline constraints, forced outages and extreme weather.
- Report emissions by boundary. Show direct CO2 per megawatt-hour, annual tons, local pollutants and a separate lifecycle case with stated methane assumptions.
- Document uncertainty and decision triggers. Identify which assumptions would reverse the ranking and what measurements or contract terms would reduce that uncertainty.
Data checklist and common analytical mistakes
- Do not equate nameplate capacity with firm service. Use accredited capacity, deliverability, reserves and outage performance.
- Do not count a conversion as a new plant. Retained steam equipment may limit efficiency, flexibility and life.
- Do not use a generic dollars-per-megawatt-hour figure. Local fuel, financing, utilization, carbon and remediation assumptions determine the result.
- Do not treat a utility forecast as a measured outcome. Label schedules, demand growth and emissions reductions as forecasts until independently verified after operation.
- Do not hide gas infrastructure risk. Verify firm pipeline capacity, curtailment priority, storage and any dual-fuel capability.
- Do not mix emissions boundaries. Keep direct stack, annual dispatch, local pollutants and lifecycle methane accounting distinct.
- Do not transfer U.S. assumptions automatically. Regulation, fuel markets, transmission rules and project economics differ by country.
- Do not omit coal liabilities. Ash, reclamation, water, contracts, remediation and workforce transition remain costs after the generator stops burning coal.
Bottom line
The right comparison is a three-way, service-matched analysis: retire and replace elsewhere, convert the existing boiler, or build a new NGCC. Boiler conversion can preserve a site and interconnection with less new construction, but age and heat rate may limit its value. New NGCC can provide higher efficiency and a longer operating life, at the cost of larger capital, construction and gas-infrastructure commitments. Retirement with a portfolio can avoid fossil-fuel exposure at the unit, but only if replacement capacity, transmission, storage and reserves are delivered on time. Because no plant condition, fuel contract, grid constraint or planning horizon is specified here, the evidence supports a decision method—not a universal least-cost or reliability winner.
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