Fossil Energy Technologies

For the 2025 Annual Technology Baseline (ATB), the U.S. Department of Energy (DOE) Hydrocarbons and Geothermal Energy Office (HGEO) has provided updates to the cost basis for previous published technology representations. In addition, HGEO has provided updated performance estimates for commercially available new-build natural gas combined cycle (NGCC) configurations. The cases included in the 2025 ATB are not meant to be reflective of the full range of fossil fuel and technology configurations that are technically and economically feasible. Importantly, the representation of CO₂ capture rates (e.g., 90%, 95%, 97%, 98%, and 99%) should not be viewed as reflective of limits on technology capability or optimized designs.

Estimates of cost and performance for currently available fossil-fueled electricity generating technologies are representative of projects that began commercial service within the past 10 years. Reported recent surge in demand for natural gas combustion turbines and related equipment has resulted in forecasted supply constraints which, along with other market factors, suggest near-term price premiums and longer lead times. Fossil technologies are not among the limited set of technologies explored in the pilot Expanded Cost Drivers Case, and therefore 2025 ATB technology innovation scenarios do not capture supply chain constraints or other cost factor assumptions for these technologies.

Estimates of performance and costs for future fossil-fueled electricity generating technology options are intended to represent prospective improvements that may be realized for low-carbon-emitting NGCC and pulverized coal (PC) power plants through robust commercial deployment (e.g., learning-by-doing) of high technology-readiness-level technologies as well as additional investments in targeted research, development, and demonstration (RD&D) activities for improving commercial and near-commercial technology options (e.g., power cycle improvements for conventional NGCC and PC technologies as well as performance improvements and cost reductions for solvent-based post-combustion carbon capture [PCCC] systems) and/or enabling the commercial deployment of transformational highly efficient low-carbon-emitting fossil technologies (e.g., utility-scale natural gas fuel cell (NGFC) systems configured for carbon capture).

Scenario Assumptions

Estimates of future fossil technology performance and cost for the three 2025 ATB technology innovation scenarios reflect the following assumptions:

Conservative Technology Innovation Scenario (Conservative Scenario): minor reductions in capital costs through 2050 because of learning-by-doing for all fossil technologies; the Conservative Technology Innovation Scenario assumes no direct investment in targeted RD&D—therefore, performance of conventional technology options remains unchanged over time and the advanced technologies do not achieve commercial readiness

Moderate Technology Innovation Scenario (Moderate Scenario): improvements are assumed to be achieved through learning-by-doing enhanced by limited investment in targeted RD&D; meaningful performance improvements and cost reductions are recognized for conventional technologies but at a level lower than reflected in the Advanced Technology Innovation Scenario; NGFC technology achieves commercialization in 2035 but, similar to conventional technology improvements, out-year improvements for NGFC do not progress at the same rate or to the same degree as represented in the Advanced Technology Innovation Scenario

Advanced Technology Innovation Scenario (Advanced Scenario): meaningful near-term investments in targeted RD&D allow significant performance improvements and cost reductions for low-carbon-emitting fossil-fueled power plants beginning in 2035; advancements for solvent-based PCCC systems are achieved through reduced capital and operating costs as well as improved (lower) capture system energy demand; fossil-fueled power plants designed for aggressive Brayton (e.g., 3,100°F firing temperature combustion turbine [CT]) and/or Rankine [e.g., advanced ultra-supercritical (AUSC) steam cycles] power cycles are capable of supplying energy to the bulk power system; out-year performance and costs for NGFC systems are reflective of deployment of higher performing/more advanced systems compared to the Moderate Technology Innovation Scenario; minor cost reductions are achieved for coal-fueled integrated gasification combined cycle (IGCC) plants.

Additional information related to cost reductions and performance improvements associated with the advanced technologies included in the 2025 ATB are included in relevant sections below. 

Assumptions Applicable to Conventional NGCC, PC, and Coal-Fueled IGCC Electricity Generating Technology Options

Fossil-fueled electric generation technology representation in the 2025 ATB includes cost and performance estimates for natural gas- and coal-fueled electricity generating technology options both with and without carbon capture. Consistent with the prior ATB releases, performance and cost estimates for the simple-cycle natural gas combustion turbine (NGCT) technology option 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; emission control meets or exceeds the 2013 updates to applicable New Source Performance Standards as well as utility Mercury and Air Toxics Standards (MATS) and are meant to reflect the assumed best available control technology. Plant designs include treatment technologies for liquid waste streams meant to be compliant with the 2015 update to the U.S. Environmental Protection Agency's (EPA's) Effluent Guidelines for the steam electric power plant source categories. All plants use mechanical draft evaporative cooling for waste heat rejection. (Note on May 9 2024, EPA issued a final rule for supplemental effluent limitation guidelines for steam electric power generators that may impact compliance methods for affected units. EPA subsequently issued a final rule extending compliance deadlines on December 31, 2025. The ATB fossil cases reflect designs consistent with existing regulations in place as of January 1, 2024, and do not assess cost or performance impacts associated with compliance with the proposed rules.)

New-build fossil-fueled power plants equipped with carbon capture and carbon capture retrofits of existing fossil-fueled power plants employ state-of-the-art (SOA) CO₂ capture systems and include multistage compression and dehydration technology producing a dense phase liquid (15.27 megapascals [MPa], 30^oC) at the power plant fence line that is suitable for pipeline transport. NGCC and PC power plants reflect SOA solvent-based PCCC systems with new builds reflecting cost and performance estimates of systems designed for 95% and “Max” capture (see relevant fuel-specific sections below) and retrofits reflecting cost and performance estimates designed for 90% and 95% capture. Cost and performance estimates for coal-fueled IGCC reflect only new builds, and IGCC equipped with carbon capture reflect pre-combustion solvent systems designed for 90% capture. 

An extensive description of the methodology and assumptions used for all National Energy Technology Laboratory (NETL) techno-economic analyses as well as specifics relevant to new builds of conventional coal combustion and natural gas-fueled technologies can be found in the 2025 update to HGEO's Cost and Performance Baseline for Fossil Energy Plants Volume 1: Bituminous Coal and Natural Gas to Electricity, (Turner et al., 2025). Although the methodology is essentially unchanged, IGCC was not included in the 2025 update, and details can be found in Cost and Performance Baseline for Fossil Energy Plants Volume 1: Bituminous Coal and Natural Gas to Electricity, Revision 4a (Schmitt et al., 2022). Details about the methodology and characteristics of NGCC retrofits can be found in Cost and Performance of Retrofitting NGCC Units for Carbon Capture: Revision 3 (Schmitt and Homsy, 2023). Details about the methodology and characteristics of PC retrofits can be found in Eliminating the Derate of Carbon Capture Retrofits: Revision 2 (Buchheit et al., 2023).

Conventional Natural Gas-Fueled Electricity Generating Technology Descriptions

Natural gas-fueled options available are based on commercially available large utility-scale F- and H-class technologies (single CT output >200 megawatts-electric [MWe] smaller industrial scale and aeroderivative turbines are not included in the ATB), including both CT and CC options for SOA F-class turbine technology. Only the CC option is presented for SOA H-class turbines. The NGCT F-class technology option represents a single SOA F-class turbine capable of providing full-load power output of approximately 233-MW net output (MW-net). NGCC power plants are configured in a 2x1 configuration using two SOA combustion turbine/heat recovery steam generator (HRSG) trains. Steam generated in the HRSG is combined to feed a common steam turbine. F- and H-class NGCC steam turbine Rankine cycle conditions are specified to be consistent with steam conditions common to comparable CT-HRSG combinations currently operating (single-reheat, 17.2 MPa/585°C/585°C). F-class 2x1 NGCC power plants without carbon capture can provide full-load power output of approximately 741 MW-net. H-class NGCC power plants without carbon capture can provide full-load power output of approximately 1,118 MW-net in the 2x1 configuration and approximately 649 MW-net in the 1x1 configuration. Note the CT in the 1x1 H-class NGCC configuration is larger than the CTs in the 2x1 H-class NGCC configuration—the latter because of a consideration that a 2x1 configuration based on the larger H-class CT (net output in excess of 1,200 MW-net) may be larger than current market conditions might support for a single new-build power plant (Turner et al., 2025). 

Both new-build NGCC power plants equipped with carbon capture and carbon capture retrofits to existing NGCC power plants use fully integrated SOA solvent-based PCCC systems, and all energy requirements (thermal and electric) of the PCCC system are directly supplied by the “host” power plant. Thermal energy requirements (i.e., regenerator steam demand) are provided by extracting steam from the crossover between the intermediate pressure (IP) and low pressure (LP) sections of the Rankine bottoming cycle and electric power is “deducted” from the net output available for export to the grid.

Performance and cost estimates for new-build NGCC power plants designed for carbon capture include PCCC systems designed for 95% and 97% CO₂ capture. These rates were selected because of the growing body of vendor information, design studies, and project announcements indicating capture rates of 95% or greater are technically feasible and increasingly economically favorable compared to lower capture rates. New-build NGCC power plants include Rankine bottoming cycles sized to satisfy the steam requirements of the PCCC system with IP/LP crossover steam conditions suitable for the PCCC system. Because the total power generation is a function of the CT(s), the maximum output of an NGCC is “fixed” at the full-load power output of the unabated NGCC plant and the full-load output of an NGCC power plant equipped with PCCC is reduced because of the smaller LP turbine (compared to the unabated NGCC power plant) and the PCCC system auxiliary power requirements. As would be expected, energy penalty trends correlate (although nonlinearly) with design capture rate (e.g., systems designed for higher capture have greater energy penalties than systems designed for lower capture).

NGCC Retrofit Technology Description

Performance and cost estimates for PCCC retrofits to existing NGCC power plants are provided for systems designed for 90% and 95% CO₂ capture. These rates were selected to acknowledge the growing recognition that capture rates of 95% or greater are technically feasible but also that achieving very high capture rates may be more challenging when retrofitting older plants not specifically designed for PCCC. Representation of PCCC retrofits for existing NGCC power plants reflect “generic” retrofits for existing F- and H-class 2x1 NGCC power plants with “pre-retrofit” power plant performance the same as the corresponding NGCC plant configured without PCCC (e.g., the ATB representation of F-class NGCC without CO₂ capture is used as the pre-retrofit “baseline” for the performance penalties shown as decreases to plant net output and increase to plant efficiency). Similar to the new-build NGCC equipped with PCCC, the PCCC retrofits to existing NGCC power plants are also fully integrated. Because the retrofitted NGCC plant maintains the pre-retrofit Rankine cycle, the extraction of steam for the PCCC from the IP/LP crossover means the LP section of the steam turbine is operated well below design steam flow rates, which results in an even larger energy penalty compared to the inclusion of PCCC in the design of a new-build NGCC. This additional derate is reflected in the performance estimates for the retrofit cases.

It should be emphasized that performance impacts associated with retrofitting PCCC to existing NGCC plants is extremely dependent on the attributes of the pre-retrofit plant. Consistent with the prior ATB releases, the estimates included in the 2025 ATB are meant to be representative of a notional, generic plant. The source material (Schmitt and Homsy, 2023); (Buchheit et al., 2023) provides significantly greater detail than is provided in this narrative. In addition, NETL has published a spreadsheet model (Natural Gas Combined Cycle CO₂ Capture Retrofit Database) as a companion to the cited report that allows a user to consider several attributes that have been generalized for the representations provided in the 2025 ATB.

Advanced NGCC Technology Description

Meaningfully improved power cycles that could outperform the NGCC SOA power plant case studies described in published NETL work (Schmitt et al., 2022) are considered feasible with sufficient investment in targeted RD&D. Further improvements in performance are achievable through deployment of more aggressive Brayton cycle conditions (assumed to be enabled in part through improved materials and fabrication methods that allow for significantly higher firing temperatures) leading to future deployment of CTs that can outperform the already highly efficient H- and J-class commercially available today. Moreover, there is room for meaningful improvements for solvent-based PCCC systems. Lower capital cost may be recognized through standardization of design approaches; value engineering that leads to reliability improvements that allow for decreased redundancy, minimizing over-design margins, improved manufacturing practices such as cost savings through enhanced supply chain efficiency; and/or process component modularization that lowers field labor and material requirements. Capture system operating cost reductions may also be achieved through decreased solvent makeup costs (either through decreased degradation and replacement rates, lower solvent supplier costs, or both). Improved capture system performance may be recognized through decreases in system energy requirements (thermal or electrical) that may be achieved through higher performing solvents, increased thermal integration, or capture system designs that lead to lower parasitic load for balance-of-plant components. 

Performance projections for advanced technologies available for NGCC applications are based on published NETL work (Leptinsky et al., 2023), (Leptinsky et al., 2024). 

Advanced NGCC Technology Configurations

Advanced Capture System Improvements

The core processes modeled for the advanced NGCC technology options are considered further improvements on commercially available technologies. However, the substantial improvements over current SOA and the need for meaningful investment in RD&D on the advanced NGCC technology options are assumed to be available for a commercial online date no sooner than 2035, and full recognition of the performance improvements appears only in the Advanced Scenario. Beginning in 2035, X-class performance is available for new-build F-class and H-class technology options and the advanced capture system performance improvements are available for new builds and retrofits of existing uncontrolled F- and H-class plants. The performance trajectories for the Moderate Scenario represent meaningful improvements beyond the Conservative Scenario but not to the degree portrayed in the Advanced Scenario. The performance trajectories for NGCC technology representation in the Moderate Scenario do not reflect specific modeled cases and are estimated at the midpoints of the respective technology option-specific Conservative and Advanced Scenario performance trajectories.

Advanced NGFC Technology Description 

NGFC technologies are explicitly represented as discrete advanced technology options in the 2025 ATB. NGFC technology representation in the 2025 ATB reflects atmospheric pressure solid oxide fuel cell technology for the topping cycle paired with a steam Rankine bottoming cycle. NGFC technology options reflect systems without CO₂ capture as well as systems capable of 98% carbon capture. Performance projections for NGFC technology options are based on recently published NETL work (Iyengar et al., 2022).

NGFC Technology Configurations

Deployed NGFC technologies are considered transformational technologies compared to current commercially available NGCC technology options, and they are not considered available under the Conservative Scenario. NGFC technologies are assumed to be available beginning in 2035 for both the Moderate and Advanced Scenarios. Once deployed, NGFC technology performance is assumed to improve over time and achieve the improved attributes by 2050 for the Moderate and Advanced Scenarios as depicted in the table above. The performance trajectories for NGFC technology representation in both the Moderate and Advanced Scenarios reflect the modeled cases consistent with the specified case designations from the cited report.

Conventional Coal-Fueled Electricity Generating Technology Descriptions

The suite of conventional coal-fueled electricity generating technology options remains consistent with the prior ATB releases.

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 NETL characterizes the Rankine cycle conditions as supercritical, the design conditions are considered by some to be representative of ultra-supercritical steam conditions. 

Similar to NGCC, both new-build PC power plants equipped with carbon capture and PCCC retrofits to existing PC power plants use fully integrated SOA solvent-based PCCC systems, and all energy requirements (thermal and electric) of the PCCC system are directly supplied by the “host” power plant. Thermal energy requirements (i.e., regenerator steam demand) are provided by extracting steam from the crossover between the IP and LP sections of the Rankine bottoming cycle, and electric power is “deducted” from the net output available for export to the grid.

Performance and cost estimates for new-build PC power plants designed for carbon capture include PCCC systems designed for 95% and 99% CO₂ capture. These rates were selected because of the growing body of vendor information, design studies, and project announcements indicating capture rates of 95% or greater are technically feasible and increasingly economically favorable compared to lower capture rates. New-build PC power plants include Rankine bottoming cycles sized to satisfy the steam requirements of the PCCC system with IP/LP crossover steam conditions suitable for the PCCC system. Because the steam turbine used in PC power plants is not constrained to discrete sizes, full-load power output is not constrained as it is for the NGCC cases—and all new-build PC plants are sized at nominal 650-MW-net output regardless of whether they are equipped with PCCC. (Note that because the PC boiler of a plant designed for capture ends up being "oversized" compared to a plant not designed for capture, the PC plant designed for capture has a higher gross output than the comparable no-capture plant). As would be expected, energy penalty trends correlate (although nonlinearly) with design capture rate (e.g., systems designed for higher capture have greater energy penalties than systems designed for lower capture). 

Coal Retrofit Technology Description

Performance and cost estimates for PCCC retrofits to existing PC power plants are provided for systems designed for 90% and 95% CO₂ capture. These rates were selected to acknowledge the growing recognition that capture rates of 95% or greater are technically feasible but also that achieving very high capture rates may be more challenging when retrofitting older plants not specifically designed for PCCC. Representation of PCCC retrofits for existing PC power plants reflects “generic” retrofits for existing PC plants designed with subcritical Rankine cycles. The pre-retrofit power plant performance is reflective of Case B11A from (Schmitt et al., 2022) (e.g., Case B11A is used as the pre-retrofit “baseline” for the performance penalties shown as decreases to plant net output and increases to plant efficiency). Similar to the new-build PC equipped with PCCC, the PCCC retrofits to existing PC power plants are also fully integrated. However, because the design of the pre-retrofit plant is effectively fixed (i.e., boiler and steam turbine sizes are unaltered for the retrofit), the extraction of steam for the PCCC from the IP/LP crossover means the LP section of the steam turbine is operated well below design steam flow rates (as is the case for the NGCC retrofits)—which results in larger energy penalty compared to the inclusion of PCCC in the design of a new-build PC. This additional derate is reflected in the performance estimates for the retrofit cases.

It should be similarly emphasized that performance impacts associated with retrofitting PCCC to existing PC plants are extremely dependent on the attributes of the pre-retrofit plant. The estimates included in the 2025 ATB are meant to be representative of a notional, generic plant. The source material (Buchheit et al., 2023) provides significantly greater detail than is provided in this narrative. In addition, NETL has published a spreadsheet model (Pulverized Coal CO₂ Capture Retrofit Database) as a companion to the cited report that allows a user to consider several attributes that have been generalized for the representations provided in the 2025 ATB.

IGCC Technology Description

New-build coal-fueled IGCC power plants without carbon capture are sized at nominal 641 MW-net based on a 2x2x1 configuration (no sparing) using two slurry-fed, oxygen-blown gasification systems (no sparing), each supplying syngas to separate SOA 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 as that used at the Wabash River Generating Station in West Terre Haute, Indiana, which began commercial demonstration in 2000 and was operated until its retirement in 2016.

New-build coal-fueled IGCC power plants with carbon capture are sized at nominal 499 MW-net based on a 2x2x1 configuration using two slurry-fed, oxygen-blown gasification “quench-only” systems (see Case B5B-Q in (Schmitt et al., 2022)), each supplying high-hydrogen fuel gas to separate SOA F-class CTs (modified for the high-hydrogen fuel gas) paired with dedicated HRSGs. Steam from both HRSGs is combined to feed a common steam turbine. Design considerations for carbon capture (e.g., processes present only to enable CO₂ capture) include water-gas shift reactors, two-stage acid gas removal, CO₂ compression and dehydration, and increased nitrogen dilution of the fuel gas feed to the CT. The slurry-fed, oxygen-blown gasification technology is the same as that used at Duke Energy’s Edwardsport Station in Knox County, Indiana, which has been in operation since 2013. 

Advanced PC Technology Description

Similar to NGCC, sufficient investment in targeted RD&D could result in meaningful improvements that are feasible and could facilitate the commercial deployment of higher performing plants compared to the SOA supercritical PC power plants included in the 2025 ATB. Further improvements in performance are achievable through the deployment of more aggressive Rankine cycle conditions (assumed enabled in part through improved materials and fabrication methods that allow for significantly higher main steam temperature and pressure (i.e., AUSC)) than what is commercially available today. Moreover, the same advances described above for solvent-based PCCC systems can be applied to PC applications. 

Performance projections for advanced technologies available for PC applications are based on recently published NETL work (AUSC without capture: (Shultz et al., 2020); all others: (Leptinsky et al., 2023)). 

Advanced PC Technology Configurations

Advanced Capture System Improvements

Like NGCC, the core processes modeled for the advanced PC technology options are considered further improvements on commercially available technologies. However, given the substantial improvements over current SOA and the need for meaningful investment in RD&D, the advanced technology options are assumed to be available for a commercial online date no sooner than 2035, and full recognition of the performance improvements appear only in the Advanced Scenario. Beginning in 2035, the AUSC Rankine cycle option is available for new-build PC plants and the advanced capture system performance improvements are available for new-build AUSC PC and retrofit of existing subcritical PC plants. The performance trajectories for the Moderate Scenario represent meaningful improvements beyond the Conservative Scenario but not to the degree reflected in the Advanced Scenario. (Turner et al., 2025)(Leptinsky et al., 2024)The performance trajectories for PC technology representation in the Moderate Scenario do not reflect specific modeled cases and are estimated at the midpoints of the respective technology option-specific Conservative and Advanced Scenario performance trajectories.

Advanced Coal-Fueled IGCC Technology Description

No performance advancements are considered for coal-fueled IGCC power plants. 

Capital Expenditures (CAPEX)

Initial-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. 

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 and consumables) and export (e.g., product, byproduct, and waste removal) 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.

Current Technology Options: Capital costs represented in the source documents 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 (TOC), which is meant to capture 1) all on-site facilities and infrastructure that support the plant (e.g., shops, offices, laboratories, and roads), including direct and indirect labor (Midwest Merit Shop basis) required for its construction and/or installation; 2) engineering, procurement, and construction 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 investments that are typically incurred during construction. An expanded description of the capital cost estimating methodology can be found in the respective NETL Fossil Baseline reports (coal combustion and natural gas (Turner et al., 2025) (Iyengar et al., 2022); IGCC (Schmitt et al., 2022)).

Advanced Technology Options: Estimates of the capital costs for the advanced technology options are all-inclusive for the same TOC elements as described above for current technology options and were developed in a manner consistent with NETL’s published methodologies that allow direct comparison with the comparable SOA NGCC and PC technology options (Leptinsky et al., 2024) (Leptinsky et al., 2023), (Iyengar et al., 2022), and (Shultz et al., 2020). 

Capital costs for new-build conventional coal (combustion) and NGCC technologies are reported in constant January 2023 USD in the recently updated source document . Capital costs for all other technologies (coal and natural gas retrofits and all advanced technologies) are reported in constant December 2018 USD in the respective source documents. All source document costs have been escalated to constant July 2023 USD for the 2025 ATB using relevant process-specific indices from Chemical Engineering Plant Cost Index, Handy-Whitman Index of Public Utility Construction Costs, and U.S. Bureau of Labor Statistics Consumer Price Index (BLS, 2025).

Future Capital Costs: To account for learning-by-doing, out-year projections for all coal and natural gas technology options except coal-fueled IGCC and NGFC incorporate cost reductions attributable to “learning-by-doing” by applying capital cost trends from the U.S. Energy Information Administration's (EIA’s) Annual Energy Outlook (AEO) 2025 Reference Case through 2050 (EIA, 2025). Further cost reductions through 2060 are projected be extrapolating the AEO2025 Reference Case but assume a decreased rate of improvement (i.e., reduced slope) compared to pre-2050 cost trends.

• The Conservative Scenario represents minimal improvements over time and includes only conventional technology options (no advanced technology options appear in the Conservative Scenario) with cost reductions reflecting the AEO2025 cost trends for all options except coal-fueled IGCC (IGCC was not included in AEO2025). Learning-by-doing capital cost reductions for coal-fueled IGCC technology options are estimated by eliminating the project contingency from the full total project cost (TPC) for the no-capture (~6.7% of TPC) and capture (~7.0% of TPC) technology representations.
• The Moderate Scenario assumes some degree of cost reduction over time that exceeds the learning-by-doing reflected in the Conservative Scenario but not to the degree reflected in the Advanced Scenario (see below). The cost trajectories for non-NGFC options are estimated at the midpoints of the respective technology option-specific Conservative and Advanced Scenario cost trajectories. The NGFC technology option appears in the Moderate and Advanced Scenarios, and the out-year (2060) costs for NGFC with and without capture are reflective of the relevant as-published case (adjusted to July 2023 USD) described above. No additional reductions because of learning-by-doing are applied.
• The Advanced Scenario represents significant reductions in capital costs that are achieved through recognizing the costs of the applicable advanced technologies (excluding NGFC) in the assumed first online year (i.e., 2035) followed by learning-by-doing through the end of the time span for the 2025 ATB (i.e., 2060). Out-year costs for the NGFC technology option are treated the same way as in the Moderate Scenario where 2060 costs for NGFC with and without capture are reflective of the relevant as-published case (adjusted to July 2023 USD) described above, and no additional reductions because of learning-by-doing are applied. There are no additional cost reductions for coal-fueled IGCC technology options beyond those included in the Conservative Scenario. 

Operation and Maintenance (O&M) Costs

Operating cost estimates (Base Year and future) are inclusive of major cost elements associated with operating and maintaining a power plant over its expected useful life. Operating costs are segregated into fixed operations and maintenance (FOM) costs and variable operations 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 nonfuel consumables, waste disposal costs (ash, spent catalyst materials, other liquid waste streams), and maintenance materials (PC & NGCC (Turner et al., 2025) , IGCC (Schmitt et al., 2022), advanced PC & NGCC (Leptinsky et al., 2023) (Leptinsky et al., 2024), NGFC (Iyengar et al., 2022)). For NGCT, VOM for maintenance materials assumes a starts-based maintenance requirement and assigns a per-start cost and assumed annual number of starts (James et al., 2019).

Similar to capital expenditures (CAPEX), operating and maintenance cost estimates are meant to include all operations within the fence line. Operations 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 or use or storage of captured CO₂).

Because the NETL cost estimating methodology factors capital costs into several operating and maintenance cost components (property taxes and insurance [FOM component] as well as maintenance labor [FOM component] and maintenance materials [VOM component] are calculated as a percentage of TPC), out-year operating and maintenance costs are adjusted for the CAPEX reductions described above. The assumed cost reductions for the Advanced Capture System solvent makeup costs are reflected where applicable. 

References

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