EPA’s proposed standards for fossil fuel plants to face challenges

The United States Environmental Protection Agency (EPA) proposed new greenhouse gas (GHG) emissions standards and guidelines for new, reconstructed, and existing fossil fuel-fired power plants in May of this year. The electricity sector is the United States’ second-largest emissions-producing sector after transportation, and the proposal aims to avoid up to 617m metric tons of CO2 emissions through 2042. If enacted, it would be one of the most wide-reaching rules on the electricity industry enacted by the EPA thus far and would help the US toward its Paris Agreement pledges. The rule is meant to exhibit the “best system of emissions reduction,” or BSER, inclusive of adequately demonstrated emissions reduction ability, cost, energy requirements, and other health and environmental impacts, as required by Section 111 of the Clean Air Act (CAA). The proposed rule generally would regulate facilities according to subcategories that factor in type of unit, size of unit, frequency of use, and expected operating horizon. This is relevant for capital cost recovery for pathways to compliance versus a decision to retire older facilities.

The proposed rule is structured to allow for flexibility in meeting the standards, and with enough lead time for generators to do so. Ultimately, existing plants could be brought into compliance by installing carbon capture and sequestration (CCS) technologies, cofiring with natural gas or with clean hydrogen[1] – all of which require incremental investment. Alternative avenues for compliance include retirement or annual operational changes, specifically lowering capacity factor. New, low-load gas plants (with a capacity factor less than 20%) can be compliant by running efficiently, whereas new plants with intermediate and high capacity factors[2] must additionally rely on CCS or clean hydrogen cofiring.

The proposed regulations for electricity generators can be summarized as the following:

The guidelines would take effect starting in 2030 for more frequently used plants. They become more stringent over time and vary based on the subcategories of facility characteristics outlined below.

[1] Clean hydrogen is defined as having an emissions intensity of less than 0.45kg CO2e/kg H2. Such a definition likely constitutes electrolytic hydrogen, powered by renewable electricity and non-emitting resources including nuclear and hydroelectric power. The EPA has also solicited comments around the inclusion of a definition of low-GHG hydrogen in its final rule.

[2] The EPA defines new plants with an intermediate capacity factor as operating at a “capacity factor that ranges between 20% and a source-specific upper bound that is based on the design efficiency of the combustion turbine.” The baseload category is defined as above the intermediate threshold.

[3] The EPA proposed ACE in August 2018 to establish emissions guidelines for coal-fired power plants. It was intended to replace the CPP.

This proposed rule is not EPA’s first attempt to regulate emissions, as the past two presidential administrations introduced the Clean Power Plan (CPP) and ACE. EPA’s stated mission is “to protect human health and the environment.” As part of that mission, the agency implements environmental law written by Congress, including writing regulations and setting national standards that states and tribes can then enforce through their own regulations. EPA has most recently attempted to regulate power plant GHG emissions under the CPP, which was issued under the Obama administration in 2015. The regulation was ultimately never implemented and later invalidated by the Supreme Court in West Virginia v. EPA in June 2022. This most recently proposed rule – while appearing specifically written to be within the confines of the court’s decision – is facing opposition from a variety of stakeholders who claim it will negatively impact system reliability or that its provision for regulating carbon emissions is too lax.

The proposed rule is currently in the middle of the rule-making process and its final form must reflect the input gathered from stakeholders during its public comment period. If passed, this rule would represent a substantial impetus to change for the US electricity generation capacity. EPA is planning to finalize the rule by June 2024 (see figure 2). Once the rule is finalized, the EPA will give individual states 24 months to submit plans for implementing standards for existing capacity. These state-level standards must be as stringent as the agency’s guidelines, though there is flexibility based on a facility’s remaining useful life and other factors. In such an instance, to determine whether flexibility is warranted, the state must demonstrate that a facility cannot achieve the BSER as outlined in the rule. The agency may also grant flexibility to help maintain reliability on a temporary basis, under certain circumstances.

This rule is one of several that EPA has recently proposed to address climate, health, and environmental impacts from power plants. Other proposals include the Good Neighbor Plan, tightened Mercury and Air Toxic Standards, and a revised Cross-State Air Pollution Rule.

If implemented, the rule potentially has wider ramifications for the existing power fleet. For plants nearing retirement age, retirement of existing capacity may be more economically prudent than undertaking increased capital investment for alternative fuel cofiring or installation of CCS. This is especially true for coal facilities, where costs of compliance are likely to be higher, given their carbon intensity. EPA recognizes that for some generation assets, the route to compliance may be retirement. Presently, some 43GW of coal capacity across the US is scheduled to retire through 2030, per the latest Energy Information Administration (EIA) Preliminary Monthly Electric Generator Inventory report. Yet, more plants than just those with a publicly stated retirement date could be at risk for retirement.

Currently, around 60GW of nameplate coal fleet capacity nationally – including some with stated retirement dates – is already 50 years or older, a threshold that could be considered nearing retirement age. This is compared to a national fleet that amounts to about 200GW of total capacity. EPA has estimated that the integration of the proposed rule will see 126GW (18GW annually) of capacity retired from 2023 to 2035. In a baseline capacity scenario, EPA forecasts the retirement of 104GW (15GW annually), assuming expected market behavior and regulatory conditions. Ultimately, EPA forecasts that this retired capacity will be replaced by renewable capacity along with gas-fired combined cycles and gas-fired combustion turbines (see figures 4 and 5). Depending on capacity factor, those new gas plants will then need to be compliant with the NSPS.

As the new decade starts, the trade-off for total system requirements will be how prominently those dispatchable resources will feature in the generation stack. Substantially more expected renewable and storage capacity driven by the Inflation Reduction Act (IRA) will be installed, and electrification across sectors including commercial, residential, transportation, and lower-heat industrial will increase total US electricity demand. The age or retrofits of existing plants could also result in derating their capacity.[4]

[4] Outside of regulated markets, independent system operators (ISOs) and regional transmission organizations (RTOs) run wholesale markets where independent power producers and generators produce electricity and trade power. These seven RTO/ISOs represent the US electricity wholesale markets.

Note: NYISO, CAISO, and ISONE have negligible coal capacity.

PJM Interconnection regional transmission organization (RTO) and the Midcontinent Independent System Operator (MISO), which have the largest concentration of coal-fired capacity compared to other US regions, could see generation capacity retired rather than upgraded or retrofitted, culling dispatchable generation in those regions. Currently, about 22GW – more than half – of PJM’s coal plants is 50 years or older. When including natural gas-fired assets, about 27GW of capacity are close to retirement age, representing close to one-third of PJM’s total nameplate capacity (see figure 6). By 2030, when the EPA requirements begin to kick in, about 40GW of PJM capacity will have hit that age threshold. Meanwhile, PJM is expected to see demand growth from electrification and from the substantial data center presence in the region. Given there is already concern surrounding capacity margins in PJM, any potential to compel incremental capacity to retire could be construed as risking reliability.

MISO has more total coal capacity than PJM, though it has about 12GW of nameplate coal capacity aged 50 years or older. There is negligible coal capacity in the New York Independent System Operator (NYISO), the Independent System Operator New England (ISONE), and the California Independent System Operator (CAISO). The retirement in those regions was driven by a variety of factors, including the competitiveness of natural gas pricing, competitive wholesale market pricing, and tightening environmental regulations, including renewable portfolio standards and cap and trade in California.

Fossil fuel-fired electricity-generating facilities with an anticipated longer operating horizon will have to undertake additional investment in order to adhere to the rule. EPA has estimated that compliance will cost existing generators USD 10bn to 14bn. The EPA has detailed its cost estimates for CCS at turbines and for hydrogen cofiring that were used to underpin that overall cost for generator compliance.

For owners looking at the costs required to come into compliance, knowing implementation will begin to take place at the turn of this decade, the full cost of necessary investment is somewhat unclear. Clean hydrogen and CCS technologies are not yet scaled, but their costs should decline as their adoption grows, economies of scale are reached, and technology continues to evolve. Indeed, looking at the examples of the two existing North American coal plants with differing CCS technologies, Boundary Dam and Petra Nova, capture costs did decline and costs for the next generation of plants with CCS is expected to continue to decline.

For clean hydrogen, fuel costs will ultimately depend on how the hydrogen is produced and in what region, where it is stored or if it is produced on-site, and what distance it may need to be transported. For the electrolyzer itself, learning rates for equipment and supply chains will also be important cost considerations for the future realized levelized cost of green hydrogen.

Since the passage of the IRA, the Internal Revenue Service has been publishing guidance on how to qualify for the act’s potential tax credits and at what value levels (see figure 8). However, some guidance is still pending, including that for clean hydrogen.

Without that initial guidance, the exact criteria for achieving full production tax credit value of USD 3/kg to help potentially offset the cost of clean hydrogen cofiring is unclear. The publication of that guidance is necessary for potential producers and investors to understand temporal matching and other potential requirements, which could greatly shift the costs of production. In order to be compliant, other plants may seek to reduce their capacity factor to either be considered intermediate load (i.e., less than 50% capacity factor) or to fall under the 20% capacity factor threshold for low load, rather than undertake the investments necessary under the pathways outlined above. The rule could also encourage less-efficient gas capacity to operate somewhat more frequently. Indeed, under EPA’s modeled baseline, natural gas-fired and coal-fired facilities will be operated less frequently as time progresses, given the increase of renewable capacity.

The proposed rule, as constructed, appears to operate within the confines established in West Virginia v. EPA (2022), which invalidated the CPP. In West Virginia v. EPA, the Supreme Court ruled that the EPA does not have the statutory authority to reorder the power industry to require generation shifting, essentially shifting fossil-fueled generation to sources that emit less CO2. This can only be done with congressional authority. As written, the proposed rule is regulation “within the fence line,” at the facility level, in contrast to the more sweeping 2015 CPP, which was sector wide. The currently proposed decarbonization rule also specifically relies on pillars outlined in the majority opinion from West Virginia v. EPA (efficiency, fuel-switching, and add-on controls) as its foundation. In that sense, the proposed pathways for compliance are all meant to help control emissions at their source. However, a robust system fostering the low-GHG hydrogen and CCS pathways could also be understood as being beyond the fence line, given the networks of pipeline and other infrastructure they would presume.

Yet the major questions doctrine highlighted in West Virginia v. EPA could also prove to be a potential hurdle for the rule ultimately being implemented. The major questions doctrine presumes that Congress does not delegate “highly consequential power” to determine questions of major economic or political significance to federal agencies. In West Virginia v. EPA, the Supreme Court wrote in the majority opinion that the agency must point to “clear congressional authorization for the power it claims,” specifically noting that “this court doubts that ‘Congress … intended to delegate … decision[s] of such economic and political significance,’ i.e., how much coal-based generation there should be over the coming decades, to any administrative agency.”

Additionally, a central argument against the proposed rule will be that clean hydrogen cofiring and CCS are not adequately demonstrated technologies. Per Section 111(d) of the Clean Air Act, EPA performance standards must reflect the BSER, and these must be adequately demonstrated. There are currently limited commercial, rather than demonstration, power plants in service under either the CCS or clean hydrogen pathway in the US.

The EPA, foreseeing this potential for objection, has specifically addressed in the proposed rule why the adoption of these new technologies would be considered adequately demonstrated:

In that sense, the proposed rule assumes a notable ramp up in the deployment of both clean hydrogen and CCS driven by the IRA and Infrastructure Investment and Jobs Act (IIJA). The EPA explicitly outlines that new policy including the 45Q tax credit for carbon oxide sequestration will decrease the cost of CCS, and that the IRA and IIJA have allowed Congress to provide extensive support for low-GHG hydrogen development.

EPA also noted that its proposed rules are aligned with the net-zero targets, clean energy, and emissions reduction commitments of select states, localities, and utilities, as well as the trend of retiring coal-fired assets and replacing units with natural gas-fired assets or renewables.

The proposal will undoubtedly result in legal challenges, as the CPP and ACE have. The comments on the rule, which were due by August 8 after the original public comment period was extended, reveal the full range of stakeholder support and opposition. Utilities have tended to point toward technical challenges to implementing the newer technologies at the scale required for emissions reduction. Additionally, they have pointed to the need to continue to ensure reliability. Several of the US’s largest independent system operators and regional transmission operators, PJM, MISO, Southwest Power Pool, and the Electric Reliability Council of Texas, Inc., filed a joint comment that reliability will fall to concerning levels, given the trend of dispatchable generation retirement already in place. Their concern is that this effect could be magnified if the proposed rule were to be implemented. Thirty-nine Republican senators called on EPA to withdraw the proposed rules, stating the agency was overstepping its authority and operating outside of the confines of West Virginia v. EPA, due to its call for generation shifting.

On the other side, some clean energy groups have also argued that the established pathways are not BSER and could actually increase emissions. They also argue that these pathways tend to be unfavorable to communities with environmental justice concerns and that the clean hydrogen pathway is water intensive.

EPA’s anticipated timing of finalizing the rule in June of 2024 allows little leeway for defense before the November 2024 election. A change of administration could see the rule repealed. If Republicans keep control of the House of Representatives and gain control of the Senate, the rule could also potentially face repeal under the Congressional Review Act. Another potential challenge for the rule would be once again facing a conservative-led Supreme Court that has already ruled against the agency for generation shifting and the major questions doctrine.

At the annual Federal Energy Regulatory Commission Reliability Technical Conference, held on November 9, 2023, the afternoon sessions were devoted to the proposed rule. As part of the engagement process ahead of the issuance and publication of a final rule, EPA and industry stakeholders discussed how the proposal will impact grid reliability, its affordability, the feasibility of the proposed compliance timelines, and the relative lifecycle of CCS and hydrogen. EPA will continue this engagement process with various RTOs, the Department of Energy, and power providers and will consider the input in the final rulemaking.