Modeling How EPA 90% Carbon Capture Rules Reshape US Coal and Gas Power Plants

A common misconception about the Environmental Protection Agency's Section 111 power plant regulations is that they act as a blanket ban on fossil fuels. In reality, the rules function as a strict technology-forcing mechanism. They establish a performance standard based on what is achievable through carbon capture and sequestration, leaving utilities to decide whether to install the technology, reduce their operating hours, or retire the assets entirely.[1][6]

The mandate divides the grid into specific operational categories. Existing coal-fired plants that intend to operate past 2039 must capture 90 percent of their carbon dioxide emissions by 2032. Similarly, any new natural gas plant designed to run as a baseload facility—defined as operating at a capacity factor greater than 40 percent—must also meet the 90 percent capture threshold by 2032.[1][4][5]

Facilities with shorter lifespans or lower utilization rates face different math. Coal plants scheduled to retire before 2039 can avoid the capture requirement by committing to a 16 percent emissions reduction by 2030, a target modeled on the feasibility of co-firing 40 percent natural gas. New gas plants operating below the 40 percent capacity threshold—often used as peaker plants to balance intermittent renewables—are exempt from the strict mandate, instead facing efficiency-based limits.[3][4]

To understand how these thresholds actually reshape the grid, researchers from the Electric Power Research Institute, Rhodium Group, and other institutions conducted a multi-model ensemble analysis published in the journal Science. The models assessed whether utilities would actually build the multi-billion-dollar capture infrastructure or simply alter their dispatch strategies to avoid the mandate.[2][3][6]

The data indicates that the rule acts primarily as an accelerant for coal retirements rather than a catalyst for widespread retrofits. Across nine different grid models, the regulations are projected to reduce United States power sector carbon emissions to between 73 and 86 percent below 2005 levels by 2040. Without the rules, the baseline transition would only achieve a 60 to 83 percent reduction.[2][3]

Beyond greenhouse gases, the carbon mandate triggers a massive downstream reduction in conventional air pollutants. By forcing older, uncontrolled coal plants offline, the rules drive an 88 to 98 percent reduction in sulfur dioxide emissions by 2035, compared to a 70 to 88 percent reduction in the baseline scenario. This 10 to 18 percentage point delta represents a significant, isolated public health benefit directly attributable to the carbon standard.[2][6]

However, the evidence supporting the feasibility of deploying carbon capture at the required scale remains contested. While the agency determined that 90 percent capture is adequately demonstrated based on pilot projects and industrial applications, the power sector currently lacks the extensive pipeline networks and Class VI injection wells necessary to transport and store millions of tons of captured carbon dioxide. The models show that if permitting and supply chain bottlenecks delay this infrastructure, utilities will default to retiring baseload plants, potentially straining grid reliability.[1][3][5][6]

Ultimately, the Section 111 rules shift the burden of proof onto the fossil fuel industry. By setting a 2032 deadline for 90 percent capture, the mandate forces utilities to either prove that commercial-scale carbon capture is economically viable or cede baseload generation to zero-carbon alternatives. The next five years of infrastructure development will determine which pathway the grid takes.[4][5][6]