New EPA Greenhouse Gas Rule Takes Aim at Fossil-Fueled Power Plants

On May 9, 2024, EPA published a final rule establishing Greenhouse Gas Standards and Guidelines for Power Plants (the “GHG Rule”). This final rule had been announced on the same day as three other EPA rules focused on fossil-fueled power generation.¹ Together, the four new rules place significant economic and logistical burdens on new and existing coal-fired power plants and communicate the Biden administration’s goal to discourage future generation planning based on fossil fuels. The record timing of Federal Register publication of these voluminous rules appears to reflect the administration’s desire not only to beat the clock for Congressional Review Act reversal by a new Congress, but also to ensure that the current administration will be defending the rules when they reach the stay stage of litigation in the D.C. Circuit.

Coal-Fired Power Plants

Coal-fired power plants face a highly uncertain future under the GHG Rule. To remain in compliance, these generating facilities must either (1) convert to natural gas co-firing by January 1, 2030 and then retire by 2039, (2) install by 2032 carbon capture and sequestration (“CCS”) technology capable of capturing 90% of all CO₂ emissions, or (3) cease operations by 2032. These requirements are based on EPA’s assertion that CCS represents the best system of emissions reduction (“BSER”), at least for plants with a run time extending beyond the next 7 years. As part of its BSER justification, EPA asserts that “CCS is an adequately demonstrated technology that achieves significant emissions reduction and is cost-reasonable, taking into account the declining costs of the technology and a substantial tax credit available to sources.”² This BSER rationale by EPA is at best overly optimistic: There are disputes over whether one U.S. plant that tried to achieve near-90% reduction of CO₂ emissions was able to do so — some say yes³ and others suggest it was only able to achieve emission reductions of 55% to 70%.⁴ Further, the BSER relies on the assumption that CO₂ and natural gas pipelines can be built to facilitate CCS or the conversion to natural gas co-firing, and that third parties will be available to off-take and store any captured CO₂. These assumptions, too, are highly uncertain, as CCS and natural gas pipeline developers themselves face significant regulatory hurdles in getting permits. Ironically, some environmental groups are leading the charge to block them.

For these and other reasons, EPA’s BSER rationale will be challenged in the litigation that already commenced upon the rule publication.⁵

New Natural Gas Power Plants⁶

Newly constructed natural gas-fired plants are treated somewhat better than their coal-consuming counterparts, in that the administration is seeking only to derate rather than abolish them: New base load gas-fired power plants (i.e., those with capacity factors greater than 40%) must meet detailed NSPS requirements based on “high efficiency” combined cycle combustion technology immediately upon start-up and then install CCS by January 1, 2032. As with the coal-fired power plant requirements, the CCS equipment must capture 90% of all CO₂ emissions. The inevitable effect of this capacity factor cut-off will be to substantially reduce the chance that new base-load gas plants can be built.

For intermediate load gas-fired power plants with capacity factors between 20% and 40%, there are no CCS requirements, but they will be required to use high-efficiency simple cycle turbine technology. For simple cycle turbines, higher efficiencies can be realized by increasing firing temperatures, increasing pressure ratios, and using intercooling on the air compressors. With these improvements, EPA notes that design efficiencies of simple cycle turbines can range from 33 to 40 percent.

Lastly, for low load or “peaking” gas-fired power plants (i.e., those with capacity factors less than 20%), the GHG Rule requirements are lessened further, with no CCS or enhanced efficiency requirements. These peaking plants, however, still must meet new NSPS emission thresholds based on a BSER of using “lower-emitting fuels” which primarily consists of natural gas with a small allowance for distillate oil (i.e., Nos. 1 and 2 fuel oils).

Existing Natural Gas Power Plants

Existing and modified natural gas power plants are excluded from these new requirements — a significant change from the proposed rule. In the GHG Rule’s press release, the EPA stated that it was “committed to expeditiously proposing GHG emission guidelines for these [existing natural gas] units,” while also announcing that the agency had already opened a non-regulatory docket to this effect and issued framing questions to gather input on how to address GHG emissions from these existing sources. Interested stakeholders can submit comments on this docket through May 28, 2024.

Grid Reliability Concerns

EPA made multiple adjustments to the proposed rule in an attempt to convey its consideration of very widely shared concerns about compromising the ability of power companies, system operators, and state utility regulators to maintain grid reliability. These adjustments included delaying CCS compliance deadlines by two years and allowing extensions (up to one year) for implementation of this control technology.

Beyond these adjustments, EPA added a short-term reliability “emergency mechanism” that would exempt power plants from certain emissions standards during acute grid emergencies. To address “long-term” reliability issues, EPA will allow states to extend compliance deadlines and mandated retirement dates for existing power plants for up to one year under certain conditions. While these adjustments may alleviate some of the reliability concerns that have been raised with respect to the GHG Rule, EPA appears to have avoided addressing the growing supply/demand imbalance for electricity generation in the United States. Some estimates suggest that to meet growing demand, more than 50 to 100 GW of new generation will need to be added to the grid over the next decade,⁷ which is the same time frame during which this GHG Rule appears likely to force the retirement of more than 150 GW of U.S. coal-fired generation. That increases the need for new (non-fossil) generation to a whopping 250 GW just to keep the lights on.

Legal Challenges

The present GHG rule represents EPA’s third try to force an extraordinary de-carbonization of the U.S. generation portfolio using authority claimed under CAA Section 111. The first two tries failed to survive judicial review. Most recently, in West Virginia v. EPA, the Court held the Obama-era EPA’s Clean Power Plan to be invalid under the “major questions” doctrine, which prohibits agencies from using vague or minor or longstanding but disused statutory provisions to justify rulemakings that have broad societal impacts. The Court further stated that Congress did not grant the agency (in Section 111 of the Clean Air Act) the authority to devise emissions caps based on generation shifting assumptions, rather than through emissions reduction technologies directly available to the regulated unit.⁸ In an attempt to avoid exactly this same result, EPA deliberately drafted this new GHG Rule to impose technological requirements on a plant-specific basis rather than state-wide emission budgets based on EPA’s views of the idealized mix of renewables in each state.

But this third time still seems unlikely to be a charm. The forced use of CCS on coal-fired plants, as well as conversion to natural gas firing, suffers from many challenges. First, like the overturned Clean Power Plan, the GHG Rule relies on something other than end-of-pipe controls solely within the purview of the power plant operator: Captured carbon must be taken by some third party and sequestered, not emitted to the atmosphere. This relates to a second weakness, namely the unavailability of a network of off-takers wherever needed; that is, it assumes that CO₂ and natural gas pipelines can be built to convert existing plants to off-take captured CO₂ or to co-firing with natural gas. These assumptions may well be a pipe dream for quite some time. And this in turn leads to a third weakness, namely the absence of demonstrated use of CCS in the power industry, as evidenced by the questionable performance of the few government-supported projects already attempted at scale and the setting of compliance deadlines seven-plus years into the future (premised on the hope that systems will be in place by then). A fourth weakness is in EPA’s demonstration of cost-effectiveness, which relies on its highly controversial social cost of carbon, as well as the present availability of tax credits. (The very need for taxpayer support may be seen as evidence that CCS is not economic.) Fifth, the record includes detailed and earnest comments from many state and regional utility authorities asserting that the functional abolition of coal plants will have an adverse effect on grid reliability, and such concerns are to be weighed in any rulemaking under Section 111. Given rapidly increasing electricity demand across the U.S., the reliability concerns may be even more acute than they were when the rule was first proposed. Sixth, the simultaneous release of an entire suite of rules burdening coal-based power production will make it easier for a reviewing court to conclude that the rationales stated for adoption of the rules are not the rationales actually leading to their adoption, thereby invoking an emerging “rule against pretext.” Especially given prior efforts to contort Section 111(d) into a prohibition against fossil-fired power, the Supreme Court and perhaps even the D.C. Circuit are likely to review this effort with a jaundiced eye.

A key and simultaneous litigation and implementation inflection point to watch is whether the D.C. Circuit or the Supreme Court stays the GHG Rule while litigation over the rule’s legality plays out. Recall that the Supreme Court stayed implementation of the Clean Power Plan while it considered that rule’s legality, which it ultimately struck down. However, if no stay is granted, it will take years for the litigation to reach an ultimate legal conclusion. With the implementation time lines EPA has imposed, without a stay many plants will begin to close sooner rather than later. A similar result was seen in the multiyear litigation of a MATS rule in 2015, with the then EPA Administrator, Gina McCarthy, boasting that, as a simple result of the time required to litigate the MATS rule, “[m]ost of [the regulated generating units] are already in compliance, [and] investments have been made.”⁹ Equally important, immediately implementing the new rules will require an overnight need for new generation supplies, transmission facilities and CCS pipelines to be built and made operational, given the long lead times inherent in building these types of new facilities. All this raises the stakes of a stay very high.

Key Takeaways

The GHG Rule represents the latest effort by EPA in recent years to reduce carbon dioxide emissions from fossil-fired power plants. Although the final rule should go into effect well before the upcoming Congressional Review Act lookback period, its future still remains uncertain. Legal challenges to the GHG Rule’s validity are already underway and are being brought against the backdrop of prior successful challenges, and while other real-world challenges — like keeping the lights on — remain.

First, many consider CCS to be a nascent technology, not ready for prime time. Attempted trials of this technology at actual scale power plants have encountered unexpected costs and operational setbacks. If the GHG Rule remains valid going forward, fossil power plant operators would have to begin rapidly implementing CCS at an unprecedented scale in order to avoid the forced retirements of their assets. Whether CCS can become economically scalable to meet these future demands remains to be seen.

Even if CCS could be successfully deployed at scale, as the GHG Rule purportedly intends, the challenges associated with subsurface storage of carbon dioxide remain. Controlling leaks and elevated pressure gradients from large subsurface carbon reservoirs is needed to help minimize risks of significant groundwater contamination and induced seismicity over time. An increasing number of environmental organizations have repudiated CCS technology as a potential solution to reducing carbon emissions, citing these and similar concerns. Furthermore, communities near these power plants, where the CCS operations ostensibly would take place, are becoming increasingly concerned that CCS would cause greater environmental damage — at least at the local level — than if the carbon dioxide were simply released into the atmosphere. Such communities are likely to frame being exposed to any such risks in the interests of a “broader good” as presenting environmental justice concerns.

Finally, EPA’s sudden embrace of CCS represents a departure from the agency’s prior treatment of this technology. In the past, as part of its Underground Injection Control regime, the EPA has taken up to six years to issue a Class VI permit required for injection wells.¹⁰ As of March 2024, EPA has issued only eight Class VI permits for the entire program since its initiation in 2010.¹¹ States are attempting to overcome this federal permitting bottleneck by seeking primacy to take over regulatory oversight of such permitting from EPA. Overall, this low volume of CCS permits likely is the combination of the factors previously mentioned, plus additional factors such as high capital costs and technological limitations. But given these meager results, EPA’s BSER classification of CCS seems hard to rationalize. Skeptics might even suggest that EPA is fully aware that this technology cannot be deployed practicably at scale and is instead using CCS as a convenient tool to force the closures of fossil power plants.

¹ Mercury and Air Toxics Standards (“MATS”) Final Rule, 89 Fed. Reg. 38,508 (May 7, 2024) (reducing the PM limit by a factor of 3 and imposing continuous emission monitoring requirements).

Steam Electric Power Generating Effluent Limitation Guidelines (“ELG”) Final Rule, 89 Fed. Reg. 40,198 (May 9, 2024) (establishing more stringent discharge standards for three wastewater streams generated at coal-fired power plants: flue gas desulfurization wastewater, bottom ash transport water, and combustion residual leachate).

Coal Combustion Residuals (“CCR”) Final Rule, 89 Fed. Reg. 38,950 (May 8, 2024) (requiring management of inactive coal ash surface impoundments located at inactive power plants and historical coal ash disposal areas).

² 89 Fed. Reg. 39,801 (May 9, 2024).

³ See https://www.bloomberg.com/news/articles/2023-02-08/the-world-s-largest-carbon-capture-plant-gets-a-second-chance-in-texas.

⁴ See https://ieefa.org/resources/ill-fated-petra-nova-ccs-project-nrg-energy-throws-towel.

⁵ See Petition for Review, West Virginia, et al., v. EPA, No. 24-1120 (D.C. Cir. May 9, 2024).

⁶ Notably, EPA continues to exclude modified gas-fired plants from the NSPS.

⁷ See https://www.nytimes.com/interactive/2024/03/13/climate/electric-power-climate-change.html.

⁸ See 597 U.S. 697, 723-24 (2022).

⁹ Mot. for Stay of Rule, Utility Air Regulatory Group v. EPA, No. 15-1363 (D.C. Cir. Oct. 23, 2015).

¹⁰ Current Class VI Projects under Review at EPA.

¹¹ Congressional Research Service, Class VI Carbon Sequestration Wells: Permitting and State Program Primacy, page 7 (Apr. 16, 2024).