Evaluation of Decarbonizing Existing Coal-Fired Power Plants Via Carbon Capture and Storage (CCS) in Utah

Abstract The decarbonization of Utah’s coal-fired power plants is essential for achieving the state and federal climate policy targets, including the Utah Roadmap objective of a 50% reduction in greenhouse gas emissions by 2030 and the U.S. Environmental Protection Agency’s (EPA) proposal to achieve a 90% reduction in CO₂ emissions from power generation by 2035. This study presents a comprehensive parametric analysis to evaluate the technical, economic, and regulatory implications of retrofitting Utah’s coal-fired power plants with carbon capture and storage (CCS). Three coal-fired power plants were examined, collectively consisting of six electric generating units (EGUs). The Bonanza unit was selected as a case study to explore the influence of different operational parameters, policy frameworks, and economic factors. Three CO₂ capture technologies including: amine-based absorption, solid adsorption, and membrane separation are assessed. Among these, amine-based absorption demonstrates superior performance, offering higher net power output, improved thermal efficiency, and lower costs across all evaluated economic metrics. Capture efficiency emerged as a critical parameter in the analysis, increasing CO₂ capture rate from 85% to 95% significantly reduced emissions and the cost per ton of CO₂ captured, but also led to higher parasitic energy loads, cooling water demand, and levelized cost of electricity (LCOE). The impact of plant operating mode showed that ultra-supercritical systems delivered higher efficiency and lower emissions, whereas subcritical plants were more economically viable due to lower capital costs. Incorporating a natural gas auxiliary system improved net plant efficiency and water use but increased the LCOE due to high gas prices and limited operational lifespan in Utah. Sensitivity to coal price was linear, with a 25% reduction in coal cost significantly improving LCOE and CO₂ mitigation economics. Capacity factor had a strong influence, with higher utilization rates substantially lowering all cost metrics. From a policy perspective, imposing taxes on CO₂ emissions raised project costs; a breakeven tax of ~$83/ton of CO2 was needed to make CCS competitive with the base/existing case (Without CCS). In contrast, the 45Q federal tax credit had a strong positive effect: a $20/ton credit enabled CCS feasibility for most EGUs, while credits above $60/ton led to negative CO₂ avoidance costs. The results confirm that CCS viability hinges not on any single factor but on the alignment of capture technology, efficiency, fuel economics, and incentive structures. A hybrid policy combining carbon emission taxation with targeted tax credits as well as capturing efficiencies technological advancements presents the most viable path to enabling deep decarbonization in Utah’s aging coal fleet.