The EPA Power Plant Rule amid Demand Growth

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On April 2, the United States Environmental Protection Agency (EPA) announced a final rule on greenhouse gas emissions for fossil fuel–fired power plants. The rule establishes strict emissions reduction standards for the existing fleet of coal-fired power plants, but notably takes a step back from the initial rule proposal by dropping requirements for the existing fleet of gas-fired power plants.

In the time since that initially proposed rule, the electric power sector has undergone a paradigm shift due to the emergence of expected demand growth across the country coming from industrial expansion and AI-driven data center investment. With demand growing, generation reserve margins declining, and interconnection queues for new generation severely backlogged, the EPA rule raises major questions about the stability of the U.S. power sector and the overall coherence of federal policymaking in the sector.

A Brief Review of the Final EPA Rule

The EPA’s final rule focuses on the U.S. coal-fired power plant fleet. The United States has roughly 225 operating coal-fired power plants, which produce 675 terawatt-hours annually, representing 16 percent of overall electricity production in 2023 and over 50 percent of greenhouse gas emissions from the electricity sector.

For these power plants, the EPA gives several options. Those which commit to retirement by 2032 are subject to no new emissions requirements; plants which commit to retirement by 2039 should reduce emissions by 16 percent by 2032; and otherwise, the rule requires that plants implement carbon capture and sequestration (CCS) technology by 2032, capturing at least 90 percent of emissions.

Given the commercial immaturity of CCS technology, high costs, and the complex permitting requirements of CCS-enabling infrastructure such as wells and CO2 pipelines, it is difficult to imagine that many plant owners will view investment in such a technology as attractive. Even with the 45Q tax credit offering 85 dollars per ton of carbon sequestered, CCS for coal plants is considered a “longer-term” (post-2030) opportunity for carbon management in the Department of Energy’s recent liftoff report for carbon management. Thus, it should be expected that most of the coal fleet will effectively disappear by 2039, with perhaps a scattering of CCS-operated plants remaining, if this rule is implemented. This implies a retirement of up to 188 gigawatts (GW) of peak effective capacity.

The final rule leaves the existing fleet of gas-fired power plants untouched, but new baseload combined cycle plants will also be subject to a 90 percent greenhouse gas capture rate through CCS. This should materially change the investment picture for utilities planning to build gas-fired power plants in response to surging demand growth, most notably in the Southeast of the United States. The EPA estimates that compliance with this standard increases the levelized cost of a new plant by 62 percent, though utilities may opt to build multiple plants and run each at a low-capacity factor and thereby avoid the CCS requirements. In either case, the rule places a substantial premium on the cost of new gas-fired generation capacity.

The EPA Rule in the Context of Demand Growth

Given the context of surging growth in power demand across the United States, a major question is the impact of the EPA rule on the ability of the power sector to simultaneously meet this demand growth and backfill the retiring coal fleet, all while maintaining reliability and affordability. The EPA acknowledges this question and has scaled back the requirements of the rule with this challenge in mind: the coal plant compliance date was pushed back two years, requirements on the existing gas-fired fleet were dropped, and new reliability-based deadline extension options were introduced. Still, the combined magnitude of plant retirements and demand growth coming over the next decade or so illustrate the challenge of meeting the growing load while cutting emissions.

On the demand side, the North American Electric Reliability Corporation’s (NERC) 2023 long-term resource adequacy report offers a useful starting point; it sees peak electric demand in the United States growing by 78 GW over the next 10 years. Data points from other sources suggest similar or faster rates of growth. ERCOT, the Texas grid operator, recently issued a long-term demand forecast showing 62 GW of demand growth by 2030. PJM, the grid operator for 13 states in the mid-Atlantic, forecasts 25 GW of peak summer demand growth by 2034. With these figures in mind, by all accounts the NERC forecast will be revised considerably upward in its 2024 report.

Taking the potential coal retirements (188 GW) and NERC’s peak demand growth forecast (78 GW) together, the United States is looking at a need for well over 250 GW of peak effective new capacity deployment required in the coming decade.

Building New Capacity

The question is, then, can this requirement be met? Projects tabulated by the Lawrence Berkeley National Lab (LBNL) provide a promising data point, with 1,570 GW of generation capacity requesting interconnection. Put in perspective, the brand new Vogtle 4 nuclear reactor in Georgia has a capacity of only 1.3 GW; for further perspective, the combined capacity of all operational generation plants across the United States today is roughly 1,280 GW.

But these large, headline-grabbing numbers require nuanced interpretation. To start, wind and solar projects make up 1,452 GW of the total, and the effective capacity values for these resources are far lower than the nameplate capacity values, roughly 38 percent and 30 percent for wind and solar, respectively. Derating these nameplate capacities in the same way grid operators do in their resource planning models leaves only 149 GW of wind and 326 GW of solar in the queue.

Positively, the LBNL data shows a trend toward hybridization, for example pairing a solar array with battery storage at a single project site, which improves the effective capacity value of a given project. Over 1,000 GW of battery storage capacity sits in the interconnection queue. As a class of resources that do not themselves generate electricity but can shift it through time, they can dampen peak demand periods which pose reliability risks and reduce the overall need for new generation.

Another crucial interpretive note is that most projects in the interconnection queue will never be built. Just 19 percent of projects submitted into interconnection queues from 2000 to 2018 were built, and the LBNL data suggests that this trend is worsening. These requests represent potential projects that developers are scouting; submitting an interconnection request and entering the queue is just one preliminary step to study the feasibility of a given site. Many additional steps are required for a project to be built, such as securing an offtake agreement, securing debt financing from a third-party lender, and navigating permitting processes at the local, state, and federal levels. Scaling down the numbers once again for this completion rate leaves the United States with only 26 GW of wind and 62 GW of solar effective capacity likely to be built in the coming years.

The Role of Transmission

These scaled-down estimates of the interconnection queue set against roughly 250 GW of combined generation needs establish the basis for a worrisome resource adequacy and reliability situation. Grid operators like PJM and MISO are already sounding the alarm as the physical realities of engineering and power-flow dynamics add extra layers of complexity to this challenge.

Most of the retiring coal-fired capacity is located close to demand centers in the Midwest and along the East Coast. The replacement volumes of potential wind and solar capacity are generally located at sites with limited access to the transmission system and far from centers of demand. To make this work, a vastly expanded transmission network is needed, an outcome held up primarily by the difficult politics of cost allocation. Despite cost and permitting challenges, expanded transmission capacity will play as important a role in meeting the load growth challenge as new generation itself. Expanded transmission capacity not only improves the speed and completion rates of projects in the interconnection queue, but also improves interregional transfers, which in effect derive increased value from the existing fleet of generation resources.

A Need for Sector Wide Strategy

The EPA rule unmistakably places additional pressure on the electric power sector as it tries to serve surging demand, reduce carbon intensity, and keep rates affordable for both households and industries seeking an edge in the global marketplace.

A rapid phasedown of the coal-fired fleet over the coming decade can be managed if other policy levers are actively pursued. These well-established priorities include expanded regional and interregional transmission systems, the deployment of demand-side and grid-enhancing technologies, improved gas-electric coordination and midstream investment, and a muscular nuclear power expansion program. Unfortunately, the viability of this path is uncertain given the wide set of jurisdictions involved at the federal level, including the Nuclear Regulatory Commission, Federal Energy Regulatory Commission, Department of Energy, and other agencies with permitting authority, let alone the complex patchwork of policies at the state and regional grid operator level.

What’s certain is the ever-increasing centrality of the electric power sector to the U.S. economy and its ever-growing role in enabling U.S. strategic ambitions in key industries. The time for a strategic perspective and approach to policymaking in the electric power sector is now.

Cy McGeady is a fellow with the Energy Security and Climate Change Program at the Center for Strategic and International Studies in Washington, D.C.