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Fossil Energy Technologies

The 2021 ATB represents the first time the U.S. Department of Energy (DOE) Office of Fossil Energy and Carbon Management (FE) contributed directly to ATB updates. For this initial participation, FE focused on providing updated cost and performance information for conventional natural gas-fueled and pulverized coal (PC) technology options represented in the 2020 ATB. Future FE participation is anticipated to result in expansion of fossil technology options, which may include retrofit options for existing coal and natural gas-fueled options as well as data for systems equipped with CO2 capture greater than 90% and/or additional partial capture rates.

Estimates of cost and performance for currently available fossil-fueled electricity generating technologies are representative of current commercial offerings and/or projects that began commercial service within the past 10 years. 

Estimates of performance and costs for future fossil-fueled electricity generating technology options are meant to capture incremental cost reductions that occur over time (e.g., learning-by-doing improvements that are most often the result of more process design optimization and/or reduced costs that are due to improvements in equipment manufacturing practices) as well as deployment of advanced technologies that result from research and development (R&D).

Estimates of future fossil technology performance and cost for the three 2021 ATB technology innovation scenarios reflect the following assumptions:

  • Conservative Technology Innovation Scenario (Conservative Scenario): minor reductions in capital costs through 2050 due to learning-by-doing for all fossil technologies; minor efficiency improvements for coal-fueled integrated gasification combined cycle (IGCC) in the near-term (i.e., through 2030) that could be expected based on lessons learned from the few commercial IGCC plants that have been built to-date; the Conservative Scenario sees no improvements resulting from FE R&D.
  • Moderate Technology Innovation Scenario (Moderate Scenario): improvements that result from learning-by-doing enhanced through successful FE R&D but at a level lower than reflected in the Advanced Technology Innovation Scenario; the Moderate Scenario trajectory follows a path through the midpoints of the Conservative and Advanced Scenarios at FE R&D Program milestone dates.
  • Advanced Technology Innovation Scenario (Advanced Scenario): improvements that result from learning-by-doing augmented by technology improvements that graduate from a fully successful FE R&D program; the FE R&D improvements assume relevant FE R&D program goals are achieved on schedule targets, with second-generation technologies available by 2025 and transformational technologies available by 2030. (DOE, 2020)

It is important to recognize that estimates of future fossil technology cost and performance for the Advanced Scenario are based on representative technology pathways and should not be interpreted as representing the only technology pathways that enable meeting FE R&D goals. For the 2021 ATB, the natural gas pathway represents early improvements to post-combustion carbon capture technology for natural gas combined cycle (NGCC) applications and subsequent deployment of advanced natural gas fuel cell systems equipped with carbon capture. The coal pathway includes improvements to the base combustion plant (e.g., deployment of high efficiency advanced ultra-supercritical PC plants) as well as improvements to post-combustion capture technology. The coal pathway in the Advanced Scenario does not include improvements to the pre-combustion pathway (e.g., IGCC), and no improvements other than learning-by-doing are included for IGCC in the 2021 ATB.

Assumptions Applicable to All Fossil-Fueled Electricity Generating Technology Options

Fossil-fueled electric generation technology representation in the 2021 ATB include cost and performance estimates for PC and NGCC technology options both with and without carbon capture. Consistent with the 2020 ATB, cost and performance estimates for IGCC and simple-cycle natural gas combustion turbine (NGCT) technology options do not include carbon capture.    

All fossil-fueled power plants are evaluated on a common design basis and with similar rigor. For all cases, the design basis assumes a generic Midwestern location in the United States, and performance is evaluated at International Organization for Standardization (ISO) conditions. All fossil-fueled electricity generating technology options include environmental emission controls for criteria pollutants; mercury and hydrochloric acid meet or exceed the 2013 updates to applicable New Source Performance Standards (NSPS); and utility Mercury and Air Toxics Standards meet or exceed new source performance standards and achieve an assumed best available control technology. Plant designs include treatment technologies for liquid waste streams meant to be compliant with the 2015 update to U.S. Environmental Protection Agency's Effluent Guidelines for the steam electric power plant source categories. All plants use mechanical draft evaporative cooling for waste heat rejection. 

New-build NGCC and PC power plants equipped with carbon capture all employ state-of-the-art solvent-based post-combustion CO2 capture systems and include multistage compression and dehydration technology producing a dense phase liquid (15.27 MPa, 30oC) at the power plant fence line that is suitable for pipeline transport. Performance estimates are provided for 90% capture for both NGCC and PC applications. A performance estimate is also provided for 36% capture on PC power plants.  

An extensive description of the methodology and assumptions used can be found in Cost and Performance Baseline for Fossil Energy Plants Volume 1: Bituminous Coal and Natural Gas to Electricity, Revision 4 (Fossil Baseline). (James III PhD et al., 2019)

Natural Gas-Fueled Electricity Generating Technology Descriptions

The suite of natural gas-fueled electricity generating technology options is consistent with prior releases of the ATB. It includes new-build Brayton cycle (often referred to as simple cycle) combustion turbine (CT) power plants and new-build combined cycle (CC) power plants, the latter with and without post-combustion carbon capture technology. 

Natural gas-fueled options available at the start of the 2021 ATB are based on commercially available technologies, including state-of-the-art F-class turbine technology for both CT and CC options and solvent-based post-combustion carbon capture technology designed to capture 90% of the carbon in the treated flue gas. The NGCT  technology option represents a single state-of-the-art F-class turbine capable of providing full-load power output of approximately 233 megawatt net output (MW-net) (DOE/NETL, forthcoming). NGCC power plants are configured in a 2x1 configuration using two state-of-the-art F-class combustion turbine/heat recovery steam generator (HRSG) trains. Steam generated in the HRSG is combined to feed a common steam turbine. Steam turbine Rankine cycle conditions are specified to be consistent with steam conditions common to comparable CT-HRSG combinations currently operating today (single reheat, 16.5 MPa/585°C/585°C). NGCC power plants without carbon capture can provide full-load power output of approximately 727 MW-net, and NGCC power plants with 90% carbon capture can provide approximately 646 MW-net. (James III PhD et al., 2019)

Coal-Fueled Electricity Generating Technology Descriptions

All new-build PC Rankine cycle power plants (both with and without carbon capture) are sized at nominal 650 MW-net and are designed based on the most advanced steam cycle conditions (single-reheat, 24.1 MPa/593°C/593°C) for which today’s equipment vendors would provide performance guarantees that are acceptable to developers of commercial projects. Note that although the National Energy Technology Laboratory characterizes the Rankine cycle conditions as supercritical, the design conditions are considered by some to be representative of ultra-supercritical steam conditions. New-build coal-fueled integrated gasification combined cycle (IGCC) power plants without carbon are sized at nominal 634 MW-net based on a 2x2x1 configuration using two slurry-fed, oxygen-blown gasification systems (no sparing), each supplying syngas to separate state-of-the-art F-class CTs paired with dedicated HRSGs. Steam from both HRSGs is combined to feed a common steam turbine. The slurry-fed, oxygen-blown gasification technology is the same used at Duke Energy’s Edwardsport Station in Knox County, Indiana, which has been in operation since 2013. (James III PhD et al., 2019) (Turner et al., 2020)

Capital Expenditures (CAPEX)

First-year capital cost estimates are meant to represent “next commercial offering” costs. Next commercial offering costs are not intended to reflect the higher costs or performance challenges often experienced with first-of-a-kind plants; nor do they reflect benefits from cost reductions that result from learning-by-doing that are reflected in comparably lower costs for Nth-of-a-kind plants. To account for learning-by-doing, the out-year projections for the coal and natural gas pathways incorporate both improvements from FE R&D and modest capital cost improvements resulting from learning-by-doing captured by layering capital cost trends from the U.S. Energy Information Administration's (EIA’s) AEO2021 Reference Case. (EIA, 2021c)

Current Technology Options: Capital costs represented here are based on bottom-up estimates that begin with steady-state process models that are used to size major plant equipment and define utility (i.e., process steam and auxiliary power needs) and balance-of-plant requirements. Capital cost estimates are provided as total overnight cost, which is meant to capture (1) all on-site facilities and infrastructure that support the plant (e.g., shops, offices, labs, and roads), including direct and indirect labor (Midwest Merit Shop basis) required for its construction and/or installation; (2) engineering, procurement, and construction (EPC) costs; (3) project and process contingencies; and (4) pre-production costs, inventory capital, initial costs for catalysts and chemicals and various other owners' costs. Total overnight costs do not include escalation, interest on debt, or return on equity investment that are typically incurred during construction. An expanded description of the capital cost estimating methodology can be found in the National Energy Technology Laboratory Fossil Baseline (James III PhD et al., 2019). All capital costs for fossil technology options included in the 2021 ATB are reported in constant 2018$ in the respective source documents and have been escalated to constant 2019$ using EIA NEMS escalators (EIA, 2021a) (EIA, 2021b).

Future Capital Costs: Out-year cost projections are aligned with existing FE R&D program goals (DOE, 2020). Future cost improvements reflect achieving targets for reductions in the cost of electricity of CO2 capture-equipped fossil-fueled electricity generating technologies (compared to a 2017 baseline) and are represented as a two-step technology deployment rollout (second generation technologies available by 2025 and transformational technologies available by 2030). Out-year cost estimates are based on representative technology pathways, which include a mix of improvements in performance, capital cost, and operating cost. Several multiple technology pathways have the potential of achieving relevant FE R&D goals. 

Capital cost estimate scope is meant to represent a complete power plant facility with the plant boundary limit defined as the total plant facility within the “fence line”. Overnight costs include necessary receiving (e.g., fuel, consumables, etc.) and export (e.g., product, byproduct, waste removal, etc.) infrastructure, with electricity delivery to the bulk power system terminating at the high voltage side of the main power transformers. Capital cost estimates for technology options equipped with carbon capture include all necessary process equipment and infrastructure to deliver CO2 at suitable conditions (i.e., pressure, temperature, and composition) for pipeline transport. No costs are included beyond the fence line for CO2 transport, use or storage. 

Operation and Maintenance (O&M) Costs

Operating cost estimates (current and future) are inclusive of major cost elements associated with operating and maintain a power plant over its expected useful life. Operating costs are segregated into fixed operation and maintenance costs (FOM) and variable operation and maintenance (VOM). FOM includes all labor (operations, maintenance, supervision, and administrative labor) as well as annual property taxes and insurance costs. VOM includes all non-fuel consumables, waste disposal costs (ash, spent catalyst materials, other liquid waste streams), and maintenance materials. (James III PhD et al., 2019) For NGCT, VOM for maintenance materials assumes a starts-based maintenance requirement and assigns a per-start cost and assumed annual number of starts. (DOE/NETL, forthcoming)

Similar to CAPEX, operating and maintenance cost estimates are meant to include all operations within the fence line. Operation and maintenance cost estimates for technology options equipped with carbon capture do not include FOM or VOM for management of CO2 beyond the fence line (i.e., no FOM or VOM associated with transport, use or storage of captured CO2).


The following references are specific to this page; for all references in this ATB, see References.

DOE/NETL. “New Reference for NGCT”,” Forthcoming.

James III PhD, Robert E., Dale Kearins, Marc Turner, Mark Woods, Norma Kuehn, and Alexander Zoelle. “Cost and Performance Baseline for Fossil Energy Plants Volume 1: Bituminous Coal and Natural Gas to Electricity.” NETL, September 24, 2019.

Turner, Marc, Arun Iyengar, and Mark Woods. “COST AND PERFORMANCE BASELINE FOR FOSSIL ENERGY PLANTS SUPPLEMENT: SENSITIVITY TO CO2 CAPTURE RATE IN COAL-FIRED POWER PLANTS.” National Energy Technology Laboratory (NETL), Pittsburgh, PA, Morgantown, WV, and Albany, OR (United States), December 23, 2020.

EIA. “U.S. Energy Information Administration (EIA) - GDP Implicit Price Deflator, Annual,” 2021a.

EIA. “U.S. Energy Information Administration (EIA) - Primary Metals Production Index, Annual,” 2021b.

EIA. “Annual Energy Outlook 2021.” Energy Information Administration, January 2021c.

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