For these reasons, the EPA is proposing to remove these projects under the applicability exclusions in subpart TTTT.
Proposed ACE Repeal
The EPA is proposing to repeal the ACE Rule. A general summary of the ACE Rule, including its regulatory and judicial history, is included in section V.B. of this preamble. The EPA proposes to repeal the ACE Rule on three grounds that together and, with respect to the first two grounds, independently, justify the rule's repeal. First, the EPA no longer believes that heat rate improvements (HRI) are the BSER for existing coal-fired EGUs. In fact, the EPA now believes that HRI are unnecessary and even counterproductive in the context of this source category because they would provide negligible CO2 reductions overall and lead to increases in CO2 emissions from certain designated facilities due to the rebound effect. Moreover, due to changes in the industry and developments in the costs of controls, more impactful technologies like co-firing of natural gas and CCS, which the ACE Rule rejected, are now cost reasonable for designated facilities with longer operating horizons. Second, the ACE Rule was contrary to CAA section 111 and the EPA's implementing regulations because it did not identify the BSER or the "degree of emission limitation achievable" by applying the BSER with sufficient precision to provide the states with adequate guidance as to the level of emission reduction that their standards of performance must achieve in order for the EPA to approve them. Rather, the ACE Rule provided states with virtually unfettered discretion to determine how much, if any, emission reductions their standards would achieve. Third, as explained in the recently proposed revisions to the EPA's implementing regulations, the ACE Rule adopted an incorrect legal interpretation of CAA section 111 that precluded states from allowing their sources to comply with standards of performance by trading or averaging. On the contrary, CAA section 111(d) accords states with discretion to provide sources with compliance flexibilities, including trading or averaging in appropriate circumstances, as long as state plans maintain equivalent emission reductions as would be achieved if each affected source was achieving its applicable standard of performance.
Summary of the Key Features of the ACE Rule
The key features of the ACE Rule were that it determined that HRI was the BSER for coal-fired EGUs; it rejected several other controls, including co-firing with natural gas and CCS; and it interpreted CAA section 111 to preclude states from allowing compliance flexibilities such as trading or averaging.
The ACE Rule determined that the BSER for coal-fired EGUs was a "list of `candidate technologies,'" consisting of seven types of the "most impactful HRI technologies, equipment upgrades, and best operating and maintenance practices," (84 FR 32536; July 8, 2019), including, among others, "Boiler Feed Pumps" and "Redesign/Replace Economizer." Id. at 32537 (table 1). The rule provided a range of improvements in heat rate that each of the seven "candidate technologies" could achieve if applied to coal-fired EGUs of different capacities. For six of the technologies, the expected level of improvement in heat rate ranged from 0.1 - 0.4 percent to 1.0 - 2.9 percent, and for the seventh technology, "Improved Operating and Maintenance (O&M) Practices," the range was "0 to >2%." Id. The ACE Rule went on to explain that states were to review each of their designated facilities, on either a source-by-source or group-of-sources basis, and "evaluate the applicability of each of the candidate technologies." Id. at 32550. Specifically, "states will use the information provided by the EPA [i.e., the list of candidate technologies and each technology's range of HRI potential] as guidance but will be expected to conduct unit-specific evaluations of HRI potential, technical feasibility, and applicability for each of the BSER candidate technologies." Id. at 32538. The ACE Rule emphasized that states had "inherent flexibility" in undertaking this task with "a wide range of potential outcomes." Id. at 32542. The ACE Rule was clear that states could conclude that it was not appropriate to apply some of the technologies. Id. at 32550. Moreover, if a state did decide to apply a particular technology to a particular source, the state could determine the level of heat rate improvement from the technology to be anywhere within the range that the EPA had identified for that technology, or even outside that range. Id. at 32551. The ACE Rule went on to say that after the state applied the technologies and calculated the amount of HRI in this discretionary manner, it should determine the standard of performance that the source could achieve, Id. at 32550, but the state could then adjust that standard further based on the application of source-specific factors such as remaining useful life. Id. at 32551. Moreover, according to the ACE Rule, the state could combine both of those actions into a "hybridized" approach in which it determined the standard of performance in a single combined step. Id. at 32550.
The ACE Rule went on to identify the process by which states were required to take these actions. According to the rule, states must "evaluat[e] each" of the seven candidate technologies and provide a summary, which "include[s] an evaluation of the ... degree of emission limitation achievable through application of the technologies." Id. at 32580. Further, the state must provide a variety of information about each power plant, including, the plant's "annual generation," "CO2 emissions," "[f]uel use, fuel price, and carbon content," "operation and maintenance costs," "[h]eat rates," "[e]lectric generating capacity," and the "timeline for implementation," among other information. Id. at 32581. The EPA explained that the purpose of this data was to allow the Agency to "adequately and appropriately review the plan to determine whether it is satisfactory." Id. at 32558.
The ACE Rule projected that if states generally applied the set of candidate technologies to their sources, the rule would achieve a less-than-1-percent reduction in power-sector CO2 emissions by 2030. However, the rule also projected that it would result in increased CO2 emissions from power plants in 15 states and the District of Columbia due to the rebound effect.
The ACE Rule considered several other control measures as the BSER, including co-firing with natural gas and CCS, but rejected them. The ACE Rule rejected co-firing with natural gas primarily on grounds that it was too costly in general, and especially for sources that have limited or no access to natural gas. 84 FR 32545 (July 8, 2019). The rule also concluded that generating electricity by co-firing natural gas in a utility boiler would be an inefficient use of the gas when compared to combusting it in a combustion turbine. Id. The ACE Rule also rejected CCS on grounds that it was too costly. Id. at 32548. The rule identified the high capital and operating costs of CCS and noted the fact that the IRC 45Q tax credit, as it then applied, would provide only limited benefit to sources. Id. at 32548-49.
In addition, the ACE Rule interpreted CAA section 111 to preclude states from allowing their sources to trade or average to demonstrate compliance with their emission standards. Id. at 32556 - 57.
Changes in Factual and Policy Underpinnings of ACE Rule
The EPA's first basis for proposing to repeal the ACE Rule is that changes have occurred in the factual and policy underpinnings of the rule concerning the structure of the industry and CO2 control requirements, leading the EPA to conclude that the BSER of HRI that the ACE Rule included was flawed and that other control measures qualify as the BSER instead.
In explaining its proposal to repeal the ACE Rule and replace it with this proposed rule, the EPA is following the direction of the Supreme Court in F.C.C. v. Fox Television Stations, Inc., 556 U.S. 502 (2009). There, the Court described the type of reasoning an agency must provide to justify changing a rule it has previously adopted:
      [T]he requirement that an agency provide reasoned explanation for its action would ordinarily demand that it display awareness that it is changing position.... And of course the agency must show that there are good reasons for the new policy. But it need not demonstrate to a court's satisfaction that the reasons for the new policy are better than the reasons for the old one; it suffices that the new policy is permissible under the statute, that there are good reasons for it, and that the agency believes it to be better, which the conscious change of course adequately indicates. This means that the agency need not always provide a more detailed justification than what would suffice for a new policy created on a blank slate. Sometimes it must -- when, for example, its new policy rests upon factual findings that contradict those which underlay its prior policy; or when its prior policy has engendered serious reliance interests that must be taken into account.... It would be arbitrary or capricious to ignore such matters. In such cases it is not that further justification is demanded by the mere fact of policy change; but that a reasoned explanation is needed for disregarding facts and circumstances that underlay or were engendered by the prior policy.

Id. at 514 - 16 (emphasis in original; citation omitted).
Since the promulgation of the ACE Rule in 2019, the factual underpinnings of the rule have changed in several ways. The first concerns the structure of the power sector. The EPA discusses these changes in section IV of this preamble. For more than the past decade, coal-fired EGUs have experienced greater competitive pressure from natural gas-fired combustion turbines and renewable energy generating sources, and as a result, have been reducing their utilization and retiring. This trend has continued since the promulgation of the ACE Rule in 2019, with a number of sources announcing retirements. Importantly, in part because of the enactment of the IRA, which provides substantial incentives for renewable energy, more coal-fired EGUs are expected to announce retirements in the near future.
In addition to these significant changes in the structure of the power sector, the costs of two control measures, co-firing with natural gas and CCS, have fallen substantially for sources with longer-term operating horizons. As noted above, the ACE Rule rejected natural gas co-firing as the BSER on grounds that it was too costly and would lead to inefficient use of natural gas. However, as discussed in section X.D.2.b.ii of this preamble, the costs of natural gas co-firing have decreased, and the EPA is proposing that the costs of co-firing 40 percent by volume natural gas are reasonable for existing coal-fired EGUs in the medium-term subcategory, i.e., units that plan to operate during, in general, the 2032 to 2040 period. In addition, natural gas is available in greater amounts, and there are fewer coal-fired EGUs, than at the time of the ACE Rule's promulgation, which mitigates the concerns in that rule about inefficient use of natural gas. See section X.D.2.b.iii.(B).
Similarly, the ACE Rule rejected CCS as the BSER on grounds that it was too costly. However, as discussed in section X.D.1.b.ii of this preamble, the costs of CCS have substantially declined, partly because of developments in the technology that have lowered capital costs, and partly because the IRA extended and increased the IRC section 45Q tax credit so that it defrays a higher portion of the costs of CCS. Accordingly, for coal-fired EGUs that will continue to operate past 2040, the EPA is proposing that the costs of CCS, which have fallen to approximately $7 -  $12/MWh, are reasonable.
On the other hand, the EPA now recognizes that the ACE Rule's view of HRI improvements as appropriate for the BSER for coal-fired EGUs was flawed. HRI achieve only a limited amount of GHG emission reductions. The ACE Rule projected that if states generally applied the set of candidate technologies to their sources, the rule would achieve a less-than-1-percent reduction in power-sector CO2 emissions by 2030. Moreover, as a practical matter, as discussed in section IX.C., the ACE Rule would not necessarily achieve any reductions, and, in fact could result in at least some states establishing emission standards that allow sources to increase their emission rates. It is clear that the amount of emission reductions that the ACE Rule would achieve is minimal, which raises significant concerns that the rule's determination that HRI qualify as the BSER was flawed because one of the criteria for whether a control measure qualifies as the BSER is the amount of emission reductions that the measure achieves. Moreover, at least for a subset of sources, HRI are likely to cause a rebound effect leading to an increase in GHG emissions, for the reasons explained in section X.D.5.a. The rebound effect was quite pronounced in the ACE Rule  -  the rule projected that it would result in increased CO2 emissions from power plants in 15 states and the District of Columbia. In addition, as discussed in section IX.C, the BSER based on HRI as included in the ACE Rule would not necessarily achieve any reductions, and, in fact could result in at least some states establishing emission standards that allow sources to increase their emission rates. Accordingly, the EPA believes that HRI do not qualify as the BSER for any coal-fired EGUs.
Based on the just-described developments and changes in policy, the EPA is proposing to fundamentally change its regulatory scheme for coal-fired power plants from the ACE Rule. As discussed in section X.C.3, of this preamble, the EPA is proposing to subcategorize coal-fired power plants according to the period of time that they will continue to operate. For sources in the imminent-term and near-term subcategories  -  which include sources that, in general, have federally enforceable commitments to permanently cease operations by 2032 or 2035, respectively  -  the EPA is proposing that the BSER is routine methods of operation and maintenance, with associated presumptive emission standards that do not permit an increased emission rate and are not anticipated to have a rebound effect. For sources in the medium-term subcategory  -  which includes sources that are not in the other subcategories and that have a federally enforceable commitment to permanently cease operations by 2040  -  the EPA is proposing that the BSER is co-firing 40 percent by volume natural gas. The EPA believes that this control measure is appropriate because it achieves substantial reductions and can be implemented at reasonable cost. In addition, the EPA believes that because of the large supply of natural gas that is available, devoting part of this supply for fuel for a coal-fired steam generating unit in place of a percentage of the coal burned at the unit should not be considered an inefficient use of natural gas and will not cause any adverse impacts on the energy system. See section X.D.2.b.iii.(B). For sources in the long-term subcategory  -  which includes sources that do not have a federally enforceable commitment to permanently cease operations by 2040  -  the EPA is proposing that the BSER is CCS with 90 percent capture of CO2. The EPA believes that this control measure is appropriate because it achieves substantial reductions and can be implemented at reasonable cost. See section X.D.1.c.
The EPA is not proposing HRI as the BSER for any of the subcategories. As discussed in section X.D.5.a, the EPA does not consider HRI to be an appropriate BSER for the imminent-term and near-term subcategories because it would achieve relatively few, if any, emissions reductions, and, for at least a subset of sources, it could have the effect of increasing emissions through the rebound effect. The EPA is proposing to reject HRI as the BSER for the medium-term and long-term subcategories because HRI could also lead to a rebound effect for them, and, most importantly, because co-firing natural gas and CCS, respectively, are available, can be implemented at reasonable cost, and will achieve more GHG emissions reductions.
For these reasons, the EPA proposes to repeal the ACE Rule and to replace it with the emission guidelines proposed in this action.
Insufficiently Precise BSER and Degree of Emission Limitation
The second reason why the EPA is proposing to repeal the ACE Rule is that the rule did not identify the BSER or the degree of emission limitation achievable through the application of the BSER with sufficient precision to provide adequate guidance to the states as to the level of emission reduction that the standards of performance must achieve. The ACE Rule determined the BSER to be a menu of HRI "candidate technologies," but did not identify a meaningful degree of emission limitation and, further, authorized the states wide latitude to decide which, if any, candidate technologies to apply and what amount of heat rate improvement, if any, to achieve. As a result, the ACE Rule was contrary to CAA section 111 and the implementing regulations, and, in any event, poor policy.
CAA section 111 and the EPA's long-standing implementing regulations establish a step-by-step process for the EPA and states to regulate emissions of certain air pollutants from existing sources. First, the EPA determines the BSER and calculates the degree of emission limitation achievable by application of the BSER. The EPA promulgates this information as part of the emission guidelines, CAA section 111(d)(1), (a)(1), 40 CFR 60.22, 60.22a; this information constitutes the necessary basis for determining the emission reductions that state plans must achieve in order to comport with CAA section 111. The Supreme Court has confirmed that the EPA is responsible for determining both the BSER and the associated degree of emission limitation. West Virginia v. EPA, 142 S. Ct. 2587, 2607 (2022).
Once the EPA makes these determinations, the state must establish "standards of performance" for its sources that are based on the degree of emission limitation that the EPA determines in the emissions guidelines. CAA section 111(a)(1) makes this clear through its definition of the term "standard of performance:" "a standard for emissions of air pollutants which reflects the degree of emission limitation achievable through the application of the [BSER]." The state includes the standards of performance in its state plan and submits it to the EPA for review. CAA section 111(d)(2)(A).
The EPA approves the plan, including the standards of performance, if they are "satisfactory," under CAA section 111(d)(2)(A). EPA's long-standing implementing regulations make clear that the EPA's basis for determining whether the plan is "satisfactory" includes that the plan must contain "emission standards . . . no less stringent than the corresponding emission guideline(s)." 40 CFR 60.24(c). The EPA's revised implementing regulations contain the same requirement. 40 CFR 60.24a(c). In adopting the implementing regulations, the EPA explained that if its review of state plans were based "solely on procedural criteria," then "states could set extremely lenient standards . . . so long as EPA's procedural requirements were met." 40 FR 53343 (November 17, 1975). It should be noted that in applying the standards to any particular source, the state may take into consideration, among other factors, the remaining useful life of the source, CAA section 111(d)(1) (RULOF provision), as discussed in section XI.D.2.
In the ACE Rule, the EPA recognized that it has the responsibility to determine the BSER and the degree of emission limitation achievable through application of the BSER. 84 FR 32537 (July 8, 2019). However, the rule was flawed because it did not in fact make those determinations. Rather, what the rule described as the BSER, which was the list of "candidate technologies," and what the rule described as the degree of emission limitation achievable by application of the BSER, which was the ranges of HRI calculated for the technologies, did not identify either the BSER or the associated degree of emission limitation with sufficient precision. Instead, the rule shifted the responsibility for those determinations to the states. Accordingly, the ACE Rule did not meet the CAA section 111 or regulatory requirements to determine the BSER or the degree of emission limitation.
As described above, the ACE Rule identified the HRI in the form of a list of seven "candidate technologies," accompanied by a broad wide range of percentage improvements to heat rate that these technologies could provide. Indeed, for one of them, improved O&M practices, the range was "0 to >2%", which is effectively unbounded. 84 FR 32537 (table 1). The ACE Rule was clear that this list was simply the starting point for the state to use in calculating the standards of performance for its sources and that the state had significant discretion in doing so. That is, the seven sets of technologies were "candidate[s]" that the state could, but was not required to, apply and if the state did choose to apply one or more of them, the state could do so in a manner that yielded any percentage of heat rate improvement within the range that the EPA identified, or even outside that range, if the state chose. Thus, as a practical matter, the ACE Rule did not determine either the BSER or any degree of emission limitation; both those were up to the state. In this manner, the ACE Rule in effect transferred the EPA's responsibilities to the state, directing each state to determine for its sources what the BSER would be (that is, which HRI technologies should be applied to the source and with what intensity), and, based on that, what the degree of emission limitation achievable by application of the BSER should be. See 84 FR 32537-38 (July 8, 2019).
The only constraints that the ACE Rule imposed on the states were procedural ones, and those did not give the EPA any benchmark for how to determine whether a plan could be approved or give the states any certainty to know whether their plan would be approved. As noted above, when the state submitted its plan, it needed to show that it evaluated each candidate technology for each source or group of sources, explain how it determined the degree of emission limitation achievable, and include data about the sources. However, because the ACE Rule did not include a degree of emission limitation that the standards must reflect, and instead placed the responsibility on the states to determine that amount by deciding which "candidate technologies" the source could apply to improve its performance and by how much, the EPA had no benchmark against which to judge a state's submission to determine whether it is "satisfactory" under CAA section 111(d)(2)(A). The procedural requirements that the ACE Rule imposed on the states were not sufficient for this purpose. As the EPA stated when it adopted its implementing regulations in 1975, it is "essential" that "EPA review ... [state] plans for their substantive adequacy." 40 FR 53342-43 (November 17, 1975). The EPA rejected limiting its review based "solely on procedural criteria" because "states could set extremely lenient standards . . . so long as EPA's procedural requirements were met." Id. at 53343.
A draft partial state plan to implement the ACE Rule submitted by West Virginia highlights both the state's discretion to determine what the ACE Rule described as the BSER and associated degree of emission limitation and the risks that, absent minimum requirements for emission reductions, the states could set lenient standards. The D.C. Circuit vacated the ACE Rule before any state plans were required to be submitted or had been formally submitted, but West Virginia did release a draft of a partial state plan prior to the vacatur. The draft partial plan would have applied to one source, the Longview Power, LLC facility, and would have established a standard of performance, based on the state's consideration of the "candidate technologies," that was higher (i.e., less stringent) than the source's historical emission rate. Thus, the draft plan did not achieve any emission reductions from the source, and instead would have allowed the source to increase its emissions.
Finally, it should be noted that the ACE Rule's approach to determining the BSER and degree of emission limitation was a significant departure from prior emission guidelines under CAA section 111(d), in which the EPA included a numeric degree of emission limitation. See, e.g., 42 FR 55796, 55797 (October 18, 1977) (limiting emission rate of acid mist from sulfuric acid plants to 0.25 grams per kilogram of acid); 44 FR 29828, 29829 (May 22, 1979) (limiting concentrations of total reduced sulfur from most of the subcategories of kraft pulp mills, such as digester systems and lime kilns, to 5, 20, or 25 ppm over 12-hour averages); 61 FR 9905, 9919 (March 12, 1996) (limiting concentration of non-methane organic compounds from solid waste landfills to 20 parts per million by volume or 98-percent reduction).
For these reasons, the EPA proposes to repeal the ACE Rule. Its failure to determine a BSER and associated degree of emission limitation were contrary to CAA section 111 and the implementing regulations. In any event, those failures were poor policy because the ACE Rule failed to set a benchmark that would guide the states in developing their state plans, and by which the EPA could determine whether those state plans were satisfactory.
ACE Rule's Preclusion of Emissions Trading or Averaging
While not an independent basis for repeal, the EPA also now disagrees with the ACE Rule's interpretation of CAA section 111(d) to preclude states from allowing emissions trading or averaging among their sources. It is paradoxical that in the area where Congress left matters to states' discretion -- how to implement and enforce the standards set forth in the EPA's emission guidelines -- the ACE Rule incorrectly interpreted the statute as constraining states' discretion. That is, CAA section 111(d) accords states discretion in developing a plan that determines the emission reduction obligations of its sources, including allowing compliance flexibilities like trading or averaging in appropriate circumstances, as long as the plan achieves equivalent emissions reductions to the EPA's emission guidelines. The ACE Rule's legal interpretation that CAA section 111(d) precludes the state from adopting those flexibilities was incorrect.
Under CAA section 111(d)(1), each state is required to submit to the EPA "a plan which ... establishes standards of performance for any existing source" that emits certain types of air pollutants, and which "provides for the implementation and enforcement of such standards of performance." Under CAA section 111(a)(1), a "standard of performance" is defined as "a standard for emissions of air pollutants which reflects the degree of emission limitation achievable through the application of the [BSER]."
The ACE Rule interpreted these provisions to preclude states from allowing their sources to trade or average to demonstrate compliance with their standards of performance. 84 FR 32556 - 57 (July 8, 2019). The ACE Rule based this interpretation on its view that CAA section 111 limits the type of "system" that the EPA may select as the BSER to a control measure that could be applied inside the fenceline of each source to reduce emissions at each source. Id. at 32523 - 24. The ACE Rule also concluded that the compliance measures the states include in their plans must "correspond with the approach used to set the standard in the first place," and therefore must also be limited to inside-the-fenceline measures that reduce the emissions of each source. Id. at 32556.
The EPA has proposed to determine that the ACE Rule's legal interpretation was incorrect in its recently published notice of proposed rulemaking to amend the CAA section 111(d) implementing regulations, "Implementing Regulations under 40 CFR Part 60 Subpart Ba Adoption and Submittal of State Plans for Designated Facilities: Proposed Rule," 87 FR 79176, 79207 (December 23, 2022). As discussed in that notice, CAA section 111(d)(1) provides, in relevant part, that states "establish[]," "implement[]," and "enforce[]" "standards of performance for any existing source." No provision in CAA section 111(d), by its terms, precludes states from having flexibility in determining which measures will best achieve compliance with the EPA's emission guidelines. Such flexibility is consistent with the framework of cooperative federalism that CAA section 111(d) establishes, which vests states with substantial discretion. As the U.S. Supreme Court has explained, CAA section 111(d) "envisions extensive cooperation between federal and state authorities, generally permitting each State to take the first cut at determining how best to achieve EPA emissions standards within its domain." American Elec. Power Co. v. Connecticut, 564 U.S. 410, 428 (2011) (citations omitted). It should also be noted, however, that the flexibility that CAA section 111(d) grants to states in adopting measures for their state plans is not unfettered. The EPA may preclude certain flexibilities in specific emission guidelines where necessary to ensure that state plans achieve equivalent emission reductions to what the EPA determined is achievable through application of the BSER. Additionally, CAA section 111(d)(2) requires the EPA to review state plans to assure that they are "satisfactory."
For the reasons just noted, the EPA proposed to disagree with the ACE Rule's conclusion that state plan compliance measures must always correspond with the approach the EPA uses to determine the BSER, so long as the plan meets the requirements of CAA section 111(d) and its implementing regulations, including the requirement that the state plan (taking into account its compliance measures) achieves equivalent emissions reductions to EPA's emission guidelines. See 87 FR 79208 (December 23, 2022). The EPA's proposed legal interpretation that CAA section 111(d) does not preclude emissions trading is consistent with the D.C. Circuit's decision in American Lung Ass'n v. EPA, 985 F.3d 914 (D.C. Cir. 2021). There, the court vacated the ACE Rule, including invalidating the rule's preclusion of emissions trading in state plans, on the basis of the reasoning that the EPA explains above. Id. at 957-58. As noted in section V.B.6, the U.S. Supreme Court reversed the D.C. Circuit's vacatur of the ACE Rule's embedded repeal of the CPP in West Virginia v. EPA, 142 S. Ct. 2587 (2022), but the Court did not rule on the scope of the states' compliance flexibilities and declined to address whether CAA section 111 limits the type of "system" the EPA could consider as the BSER to inside-the-fenceline measures. See id. at 2615.
For these reasons, in its notice of proposed rulemaking to amend the CAA section 111(d) implementing regulations, the EPA proposed to interpret CAA section 111(d) as authorizing the EPA to approve state plans, in particular emission guidelines, that achieve the requisite emission limitation through the aggregate reductions from their sources, including through trading or averaging, where appropriate for a particular emission guideline and consistent with the intended environmental outcomes of the guideline. As discussed in section XI.E.2., the EPA is soliciting comment on whether trading and averaging would be appropriate compliance mechanism for the proposed emission guideline for coal-fired steam generating units and if so, how such compliance mechanisms could be implemented to ensure equivalency with the emission reductions that would be achieved if each affected source was achieving its appliable standard of performance.
The ACE Rule's flawed legal interpretation that CAA section 111(d) precludes states from emissions trading is incorrect, and adds to EPA's reasoning for proposing to repeal the rule.
Proposed Regulatory Approach for Existing Fossil Fuel-fired Steam Generating Units
Overview
In this section of the preamble, the EPA explains the basis for its proposed emission guidelines for GHG emissions from existing fossil fuel-fired steam generating units for states' use in plan development. This includes proposing different subcategories of designated facilities, the BSER for each subcategory, and the degree of emission limitation achievable by application of each proposed BSER. In this action, the EPA is not proposing BSER for existing electric utility natural gas-fired combustion turbines, including simple cycle and combined cycle units. However, as detailed in section XII of this preamble, the EPA is soliciting comment on possible BSER for those units, to inform future regulatory action for those units.
The proposed subcategories, the BSER for each subcategory, and the associated degrees of emission limitation are summarized in table 4, below. In brief, the EPA is proposing subcategories for steam generating units based on the type and amount of fossil fuel (i.e., coal, oil, and natural gas) fired in the unit. In addition, the EPA is proposing to divide the subcategory for coal-fired units into additional subcategories based on operating horizon (i.e., the period of time that sources expect to continue to operate) and, for one of those subcategories, load levels (i.e., annual capacity factor). Further, the EPA is proposing to divide subcategories for oil- and natural gas-fired units based on capacity and, in some cases, geographic location.
For coal-fired steam generating units, as noted in section IV of this preamble, ongoing trends in the power sector are leading the owners or operators of many of these units to decrease utilization of their steam generating units and to announce or develop plans for retiring the units. In the course of the EPA's engagement with stakeholders to inform this proposed rule, industry stakeholders recommended that the EPA define subcategories and evaluate GHG control technology options that take these plans for ceasing operation into account. These additional subcategories are responsive to this industry input, and appropriately recognize that the GHG control technology options available to existing coal-fired steam generating units  -  and the cost-effectiveness of those options  -  differ depending on the sources' expected operating time horizon.
Table 4 -- Summary of Proposed BSER, Subcategories, and Degrees of Emission Limitation for Affected EGUs
                                 Affected EGUs
                            Subcategory Definition
                                     BSER
                         Degree of Emission Limitation
               Presumptively Approvable Standard of Performance
          Ranges in Values on Which the the EPA is Soliciting Comment
Long-term existing coal-fired steam generating units
Coal-fired steam generating units that have not adopted a federally enforceable commitment to permanently cease operations by January 1, 2040
CCS with 90 percent capture of CO2
88.4 percent reduction in emission rate (lb CO2/MWh-gross)
88.4 percent reduction in annual emission rate (lb CO2/MWh-gross) from the unit-specific baseline
The achievable capture rate from 90 to 95 percent and the achievable degree of emission limitation defined by a reduction in emission rate from 75 to 90 percent
Medium-term existing coal-fired steam generating units
Coal-fired steam generating units that choose to adopt a federally enforceable commitment to permanently cease operations after December 31, 2031, and before January 1, 2040, and that are not near-term units
Natural gas co-firing at 40 percent of the heat input to the unit
A 16 percent reduction in emission rate (lb CO2/MWh-gross)
A 16 percent reduction in annual emission rate (lb CO2/MWh-gross) from the unit-specific baseline
The percent of natural gas co-firing from 30 to 50 percent and the degree of emission limitation from 12 to 20 percent
Near-term existing coal-fired steam generating units
Coal-fired steam generating units that choose to adopt a federally enforceable commitment to permanently cease operations after December 31, 2031, and before January 1, 2035, and to operate with annual capacity factors less than 20 percent
Routine methods of operation
No increase in emission rate (lb CO2/MWh-gross)
An emission rate limit (lb CO2/MWh-gross) defined by the unit-specific baseline
The presumptive standard: 0 to 2 standard deviations in annual emission rate above or 0 to 10 percent above the unit-specific baseline
Imminent-term existing coal-fired steam generating units
Coal-fired steam generating units that choose to adopt a federally enforceable commitment to permanently cease operations before January 1, 2032
Routine methods of operation
No increase in emission rate (lb CO2/MWh-gross)
An emission rate limit (lb CO2/MWh-gross) defined by the unit-specific baseline
The presumptive standard: 0 to 2 standard deviations in annual emission rate above or 0 to 10 percent above the unit-specific baseline
Base load continental existing oil-fired steam generating units
Oil-fired steam generating units with an annual capacity factor greater than or equal to 45 percent
Routine methods of operation and maintenance
No increase in emission rate (lb CO2/MWh-gross)
An annual emission rate limit of 1,300 lb CO2/MWh-gross
The threshold between intermediate and base load from 40 to 50 percent annual capacity factor;
the degree of emission limitation from 1,250 lb CO2/MWh-gross to 1,800 lb CO2/MWh-gross
Intermediate load continental existing oil-fired steam generating units
Oil-fired steam generating units with an annual capacity factor greater than or equal to 8 percent and less than 45 percent
Routine methods of operation and maintenance
No increase in emission rate (lb CO2/MWh-gross)
An annual emission rate limit of 1,500 lb CO2/MWh-gross
The degree of emission limitation from 1,400 lb CO2/MWh-gross to 2,000 lb CO2/MWh-gross
Low load (continental and non-continental) existing oil-fired steam generating units
Oil-fired steam generating units with an annual capacity factor less than 8 percent
None proposed
-
-
The threshold between low and intermediate load from 5 to 20 percent annual capacity factor
Intermediate and base load non-continental existing oil-fired steam generating units
Non-continental oil-fired steam generating units with an annual capacity factor greater than or equal to 8 percent
Routine methods of operation and maintenance
No increase in emission rate (lb CO2/MWh-gross)
An emission rate limit (lb CO2/MWh-gross) defined by the unit-specific baseline
The presumptive standard: 0 to 2 standard deviations in annual emission rate above or 0 to 10 percent above the unit-specific baseline
Base load existing natural gas-fired steam generating units
Natural gas-fired steam generating units with an annual capacity factor greater than or equal to 45 percent
Routine methods of operation and maintenance
No increase in emission rate (lb CO2/MWh-gross)
An annual emission rate limit of 1,300 lb CO2/MWh-gross
The threshold between intermediate and base load from 40 to 50 percent annual capacity factor;
The acceptable standard from 1,250 lb CO2/MWh-gross to 1,400 lb CO2/MWh-gross
Intermediate load existing natural gas-fired steam generating units
Natural gas-fired steam generating units with an annual capacity factor greater than or equal to 8 percent and less than 45 percent
Routine methods of operation and maintenance
No increase in emission rate (lb CO2/MWh-gross)
An annual emission rate limit of 1,500 lb CO2/MWh-gross
The acceptable standard from 1,400 lb CO2/MWh-gross to 1,600 lb CO2/MWh-gross
Low load existing natural gas-fired steam generating units
Natural gas-fired steam generating units with an annual capacity factor less than 8 percent
None proposed
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-
The threshold between low and intermediate load from 5 to 20 percent annual capacity factor

The EPA is proposing CCS with 90 percent capture as BSER for long-term existing coal-fired steam generating units. The EPA is soliciting comment on a range of maximum capture rates (90 to 95 percent) and, to potentially account for the amount of time the capture equipment operates relative to operation of the steam generating unit, a slightly lower achievable degree of emission limitation (75 to 90 percent reduction in average annual emission rate, defined in terms of pounds of CO2 per unit of generation). As it does with all coal-fired units, the EPA calculates the proposed presumptive standards of performance for long-term units by applying the degree of emission limitation to a source-specific baseline.
Although CCS satisfies the BSER criteria for long-term coal-fired units, the EPA recognizes that many owners of existing coal-fired units have already announced plans to cease operating these units over the near- to medium-term or may soon choose to do so. For units that are planning to cease operations earlier than 2040, the cost effectiveness of CCS is likely to be less favorable in light of the capital investment required to retrofit with such systems and the relatively shorter operating period over which these units can recover costs and utilize available tax incentives for CCS. Accordingly, the EPA has determined that for units that will permanently cease operations before 2040, other GHG control options -- including standards reflecting the application of natural gas co-firing or, for units that are retiring in the near term, routine operations and maintenance -- achieve meaningful emission limitations and better satisfy the BSER criteria. Based on input provided by coal-fired unit owners and other stakeholders, the EPA believes that recognizing distinct BSER and corresponding emission limitations for units that will permanently cease operations over the imminent- to medium-term will also better align with industry trends and the business plans of many power companies.
Accordingly, the EPA is proposing to establish additional subcategories of existing coal-fired steam generating units based on operating timeframe, with a separate BSER and degree of emission limitation corresponding to each subcategory. For medium-term coal-fired steam generating units, the EPA is proposing natural gas co-firing at 40 percent of annual heat input as BSER because it achieves meaningful emission reductions and satisfies the other BSER criteria, including being cost reasonable for units on an intermediate operating timeframe. The EPA is soliciting comment on the percent of natural gas co-firing from 30 to 50 percent and the degree of emission limitation defined by a reduction in emission rate from 12 to 20 percent. For imminent-term and near-term coal-fired steam generating units, the EPA is proposing a BSER of routine methods of operation and maintenance. Because of differences in performance between units, the EPA is proposing to determine the associated degree of emission limitation as no increase in emission rate.
For natural gas- and oil-fired steam generating units, the EPA is proposing a BSER of routine methods of operation and maintenance and degrees of emission limitation of no increase in emission rate. However, because natural gas- and oil-fired steam generating units with similar annual capacity factors perform similarly to one another, the EPA is proposing presumptive standards of performance of 1,300 lb CO2/MWh-gross for base load units (i.e., those with annual capacity factors greater than 45 percent) and 1,500 lb CO2/MWh-gross for intermediate load units (i.e., those with annual capacity factors between 8 and 45 percent). Because natural gas- and oil-fired steam generating units with low load have large variations in emission rate, the EPA is not proposing BSER or degrees of emission limitation for those units in this action. However, the EPA is soliciting comment on a potential BSER of "clean fuels" and degree of emission limitation defined on a heat input basis by 120 to 130 lb CO2/MMBtu for low load natural gas-fired steam generating units and 150 to 170 lb CO2/MMBtu for low load oil-fired steam generating units. Also, because non-continental oil-fired steam generating units operate at intermediate and base load, and because there are relatively few of those units for which to define a limit on a fleet-wide basis, the EPA is proposing degrees of emission limitation for those units of no increase in emission rate and presumptive standards based on unit-specific emission rates, as detailed in section XI of this preamble. The EPA is soliciting comment on ranges of annual capacity factors to define the thresholds between the load levels and ranges in the degrees of emission limitation, as specified in section X.E of this preamble.
The remainder of this section is organized into the following subsections. Subsection B describes the proposed applicability requirements for existing steam generating units. Subsection C provides the explanation for the proposed subcategories. Subsection D contains, for coal-fired steam generating units, a summary of the systems considered for the BSER, detailed discussion of the systems and other options considered, and explanation and justification for the determination of BSER and degree of emission limitation. Subsection E contains, for natural gas- and oil-fired steam generating units, a summary of the systems considered for the BSER, detailed discussion of the systems and other options considered, and explanation and justification for the determination of BSER and degree of emission limitation.
Applicability Requirements for Existing Fossil Fuel-fired Steam Generating Units
For the emission guidelines, the EPA is proposing that a designated facility is any fossil fuel-fired electric utility steam generating unit (i.e., utility boiler) that: (1) was in operation or had commenced construction on or before January 8, 2014; (2) serves a generator capable of selling greater than 25 MW to a utility power distribution system; and (3) has a base load rating greater than 260 GJ/h (250 MMBtu/h) heat input of fossil fuel (either alone or in combination with any other fuel). Consistent with the implementing regulations, the term "designated facility" is used throughout this preamble to refer to the sources affected by these emission guidelines. For this action, consistent with prior CAA section 111 rulemakings concerning EGUs, the term "designated facility" refers to a single EGU that is affected by these emission guidelines. The rationale for this proposal concerning applicability is the same as that for 40 CFR part 60, subpart TTTT (80 FR 64543 - 44; October 23, 2015). We incorporate that discussion by reference here.
Section 111(a)(6) of the CAA defines an "existing source" as "any stationary source other than a new source." Therefore, the emission guidelines would not apply to any EGUs that are new after January 8, 2014, or modified or reconstructed after June 18, 2014, the applicability dates of 40 CFR part 60, subpart TTTT. In addition, the EPA is proposing to include in the applicability of the emission guidelines the same exemptions as discussed for 40 CFR part 60, subpart TTTT in section VII.E.1 of this preamble. Designated EGUs that may be excluded from a state's plan are: (1) units that are subject to 40 CFR part 60, subpart TTTT, as a result of commencing a qualifying modification or reconstruction; (2) steam generating units subject to a federally enforceable permit limiting net-electric sales to one-third or less of their potential electric output or 219,000 MWh or less on an annual basis and annual net-electric sales have never exceeded one-third or less of their potential electric output or 219,000 MWh; (3) non-fossil fuel units (i.e., units that are capable of deriving at least 50 percent of heat input from non-fossil fuel at the base load rating) that are subject to a federally enforceable permit limiting fossil fuel use to 10 percent or less of the annual capacity factor; (4) CHP units that are subject to a federally enforceable permit limiting annual net-electric sales to no more than either 219,000 MWh or the product of the design efficiency and the potential electric output, whichever is greater; (5) units that serve a generator along with other steam generating unit(s), where the effective generation capacity (determined based on a prorated output of the base load rating of each steam generating unit) is 25 MW or less; (6) municipal waste combustor units subject to 40 CFR part 60, subpart Eb; (7) commercial or industrial solid waste incineration units that are subject to 40 CFR part 60, subpart CCCC; or (8) EGUs that derive greater than 50 percent of the heat input from an industrial process that does not produce any electrical or mechanical output or useful thermal output that is used outside the affected EGU. The EPA solicits comment on the proposed definition of "designated facility" and applicability exemptions for fossil fuel-fired steam generating units.
The exemptions listed above at (4), (5), (6), and (7) are among the current exemptions at 40 CFR 60.5509(b), as discussed in section VII.E.1 of this preamble. The exemptions listed above at (2), (3), and (8) are exemptions the EPA is proposing to revise for 40 CFR part 60, subpart TTTT, and the rationale for proposing the exemptions is in section VII.E.1 of this preamble. For consistency with the applicability requirements in 40 CFR part 60, subpart TTTT, we are proposing these same exemptions for the applicability of the emission guidelines.
The EPA is proposing to apply the same requirements to fossil fuel-fired steam generating units in non-continental areas (i.e., Hawaii, the Virgin Islands, Guam, American Samoa, the Commonwealth of Puerto Rico, and the Northern Mariana Islands) and non-contiguous areas (non-continental areas and Alaska) as the EPA is proposing for comparable units in the contiguous 48 states. However, units in non-continental and non-contiguous areas operate on small, isolated electric grids, may operate differently from units in the contiguous 48 states, and may have limited access to certain components of the proposed BSER due to their uniquely isolated geography or infrastructure. Therefore, the EPA is soliciting comment on the proposed BSER and degrees of emission limitation for units in non-continental and non-contiguous areas, and the EPA is soliciting comment on whether those units in non-continental and non-contiguous areas should be subject to different, if any, requirements.
Subcategorization of Fossil Fuel-fired Steam Generating Units
Steam generating units can have a broad range of technical and operational differences. Based on these differences, they may be subcategorized, and different BSER and degrees of emission limitation may be applicable to different subcategories. Subcategorizing allows for determining the most appropriate control requirements for a given class of steam generating unit. Therefore, the EPA is proposing subcategories for steam generating units based on fossil fuel type, operating horizon and load level, and is proposing different BSER and degrees of emission limitation for those different subcategories. The EPA notes that, in section XI.B of this preamble, comment is solicited on the compliance deadline (i.e., January 1, 2030), for imminent-term and near-term coal-fired steam generating units, and different subcategories of natural gas- and oil-fired steam generating units.
Subcategorization by Fossil Fuel Type
In the 2015 NSPS, the EPA promulgated GHG standards of performance for all new fossil fuel-fired steam generating units. 40 CFR 60.5509(a). Accordingly, existing fossil fuel-fired steam generating units are subject to regulation for GHG emissions under CAA section 111(d). In this action, the EPA is proposing definitions for subcategories of existing fossil fuel-fired steam generating units based on the type and amount of fossil fuel used in the unit. The subcategory definitions proposed for these emission guidelines are based on the definitions in 40 CFR part 63, subpart UUUUU, and using the fossil fuel definitions in 40 CFR part 60, subpart TTTT.
A coal-fired steam generating unit is an electric utility steam generating unit or IGCC unit that meets the definition of "fossil fuel-fired" and that burns coal for more than 10.0 percent of the average annual heat input during the 3 calendar years prior to the proposed compliance deadline (i.e., January 1, 2030), or for more than 15.0 percent of the annual heat input during any one of those calendar years, or that retains the capability to fire coal after December 31, 2029.
An oil-fired steam generating unit is an electric utility steam generating unit meeting the definition of "fossil fuel-fired" that is not a coal-fired steam generating unit and that burns oil for more than 10.0 percent of the average annual heat input during the 3 calendar years prior to the proposed compliance deadline (i.e., January 1, 2030), or for more than 15.0 percent of the annual heat input during any one of those calendar years, and that no longer retains the capability to fire coal after December 31, 2029.
A natural gas-fired steam generating unit is an electric utility steam generating unit meeting the definition of "fossil fuel-fired" that is not a coal-fired or oil-fired steam generating unit and that burns natural gas for more than 10.0 percent of the average annual heat input during the 3 calendar years prior to the proposed compliance deadline (i.e., January 1, 2030), or for more than 15.0 percent of the annual heat input during any one of those calendar years, and that no longer retains the capability to fire coal after December 31, 2029.
Subcategorization of Natural Gas- and Oil-fired Steam Generating Units by Load Level
The EPA is also proposing additional subcategories for oil-fired and natural gas-fired steam generating units, based on load levels: "low" load, defined by annual capacity factors less than 8 percent; "intermediate" load, defined by annual capacity factors greater than or equal to 8 percent and less than 45 percent; and "base" load, defined by annual capacity factors greater than or equal to 45 percent. In addition, the EPA is soliciting comment on a range from 5 to 20 percent to define the threshold value between low and intermediate load and a range from 40 to 50 percent to define the threshold value between intermediate and base load. The rationale for the proposed load thresholds is detailed in the description of the BSER for oil- and natural gas-fired steam generating units in section X.E of this preamble.
Subcategorization of Coal-fired Steam Generating Units by Operating Horizon and Load Level
As discussed in section IV of this preamble, the electric power sector is undergoing a period of significant change, with increases in the deployment of natural gas and renewable sources of electricity and decreases in the utilization of steam generating units. Many fossil fuel-fired steam generating units have plans to cease operations, are part of utilities with commitments to net zero power by certain dates, or are in states or localities with commitments to net zero power by certain dates. Over one-third of existing coal-fired steam generating capacity has planned to cease operation by 2032, and approximately half of the capacity has planned to cease operations by 2040. Certain technologies that are cost reasonable for EGUs that intend to operate for the long term are less cost reasonable for EGUs with shorter operating horizons because of shorter amortization periods and, for CCS, less time to utilize the IRC section 45Q tax credit. To accommodate this reality, and to limit unnecessary investment in facilities with shorter remaining operating periods, the EPA is proposing four subcategories for steam generating units by operating horizon (i.e., federally enforceable commitments to permanently cease operations) and, in one case, by load level (i.e., annual capacity factor) as well. "Imminent-term" steam generating units are those that choose to adopt federally enforceable commitments to permanently cease operations prior to January 1, 2032. "Near-term" steam generating units are those that choose to adopt federally enforceable commitments to permanently cease operations on or after January 1, 2032, and prior to January 1, 2035, and have federally enforceable annual capacity factor limits that are less than 20 percent. "Medium-term" steam generating units are those that choose to adopt federally enforceable commitments to permanently cease operations prior to January 1, 2040, and that are not imminent-term or near-term units. "Long-term" steam generating units are those that have not adopted federally enforceable commitments to permanently cease operations prior to January 1, 2040. Details regarding the implementation of subcategories in state plans are available in section XI.D of this preamble.
The EPA is proposing the imminent-term subcategory based on a 2-year operating horizon from the proposed compliance deadline (January 1, 2030, see section XI.B for additional details). This proposed subcategory is designed to accommodate units with operating horizons short enough that no additional CO2 control measures would be cost reasonable. The EPA is proposing the near-term subcategory to provide an alternative option for units that intend to operate for a slightly longer horizon but as peaking units, i.e., that intend to run at lower load levels. The load level of 20 percent for the near-term subcategory is based on spreading an average 2 years of generation (i.e., 50 percent in each year, a typical load level) that would occur under the imminent-term subcategory over the 5-year operating horizon of the near-term subcategory.
The EPA is proposing the 10-year operating horizon (i.e., January 1, 2040) as the threshold between medium-term and long-term subcategories because about half of the existing steam generating unit capacity has planned operation after that date. Additionally, long-term units will have a longer amortization period and may be better able to fully utilize the IRC section 45Q tax credit. The EPA is soliciting comment on the dates and load levels used to define the coal-fired subcategories. As noted in section X.D.1.a.ii.(C) of this preamble, the costs for CCS may be reasonable for units with amortization periods as short as 8 years. Therefore, the EPA is specifically soliciting comment on an operating horizon of between 8 and 10 years (i.e., January 1, 2038, to January 1, 2040) to define the date for the threshold between medium-term and long-term coal-fired steam generating units.
Legal Basis for Subcategorization
As noted in section V of this preamble, the EPA has broad authority under CAA section 111(d) to identify subcategories. As also noted in section V, the EPA's authority to "distinguish among classes, types, and sizes within categories," as provided under CAA section 111(b)(2) and as we interpret CAA section 111(d) to provide as well, generally allows the Agency to place types of sources into subcategories when they have characteristics that are relevant to the controls that the EPA may determine to be the BSER for those sources. One element of the BSER is cost reasonableness. See CAA section 111(d)(1) (requiring the EPA, in setting the BSER, to "tak[e] into account the cost of achieving such reduction"). As noted in section V, the EPA's long-standing regulations under CAA section 111(d) explicitly recognize that subcategorizing may be appropriate for sources based on the "costs of control." Subcategorizing on the basis of federally enforceable dates for permanently ceasing operation is consistent with a central characteristic of the coal-fired power industry that is relevant for determining the cost reasonableness of control requirements: A large percentage of the industry has announced, or is expected to announce, dates for ceasing operation, and the fact that many coal-fired steam generating units intend to cease operation affects what controls are "best" for different subcategories. Whether the costs of control are reasonable depends in part on the period of time over which the affected sources can amortize those costs. Sources that have shorter operating horizons will have less time to amortize capital costs and the controls will thereby be less cost-effective and therefore may not qualify as the BSER.
	In addition, subcategorizing by length of period of continued operation is similar to two other bases for subcategorization on which the EPA has relied in prior rules, each of which implicates the cost reasonableness of controls: The first is load level, noted in section X.C of this preamble. For example, in the 2015 NSPS, the EPA divided new natural gas-fired combustion turbines into the subcategories of base load and non-base load. 80 FR 64510, 64602 (table 15) (October 23, 2015). The EPA did so because the control technologies that were "best"-including consideration of feasibility and cost-reasonableness -- depended on how much the unit operated. The load level, which relates to the amount of product produced on a yearly or other basis, bears similarity to a limit on a period of continued operation, which concerns the amount of time remaining to produce the product. In both cases, certain technologies may not be cost reasonable because of the capacity to produce product -- i.e., because the costs are spread over less product produced.
The second is fuel type, as also noted in section X.C of this preamble. The 2015 NSPS provides an example of this type of subcategorization as well. There, the EPA divided new combustion turbines into subcategories on the basis of type of fuel combusted. Id. Subcategorizing on the basis of the type of fuel combusted may be appropriate when different controls have different costs, depending on the type of fuel, so that the cost-reasonableness of the control depends on the type of fuel. In that way, it is similar to subcategorizing by operating horizon because in both cases, the subcategory is based upon the cost reasonableness of controls. Subcategorizing by fuel type presents an additional analogy to the present case of subcategorizing on the basis of the length of time when the source will continue to operate because this timeframe is tantamount to the length of time when the source will continue to combust the fuel. Subcategorizing on this basis may be appropriate when different controls for a particular fuel have different costs, depending on the length of time when the fuel will continue to be combusted, so that the cost-reasonableness of controls depends on that timeframe. Some prior EPA rules for coal-fired sources have made explicit the link between length of time for continued operation and type of fuel combusted by codifying federally enforceable retirement dates as the dates by which the source must "cease burning coal."
Determination of BSER for Coal-fired Steam Generating Units
The EPA evaluated two primary control technologies as potentially representing the BSER for existing coal-fired steam generating units: CCS and natural gas co-firing. This section of the preamble discusses each of these alternatives, based on the criteria described in section V.C of this preamble.
The EPA is proposing CCS with 90 percent capture as BSER for long-term coal-fired steam generating units, that is, ones that are expected to continue to operate past 2039, because CCS can achieve an appropriate amount of emission reductions and satisfies the other BSER criteria. Because CCS is less cost reasonable for EGUs that do not plan to operate in the long term, the EPA is proposing other measures as BSER for the other subcategories of existing coal-fired steam generating units.
Specifically, for medium-term units, that is, ones that choose to adopt federally enforceable commitments to permanently cease operations after December 31, 2031, and before January 1, 2040, and are not near-term units, the EPA is proposing a BSER of 40 percent natural gas co-firing on a heat input basis. However, the EPA is taking comment on the date that defines the threshold between medium-term and long-term coal-fired steam generating units, and it is possible that the costs of CCS may be considered reasonable for some portion of the units that may be covered by the medium-term subcategory as proposed.
For imminent-term and near-term units, that is, ones that choose to adopt federally enforceable commitments to permanently cease operations before January 1, 2032, and between December 31, 2031, and January 1, 2035, coupled with an annual capacity factor limit, respectively, the EPA is proposing a BSER of routine methods of operation and maintenance that maintain current emission rates.
Long-term Coal-fired Steam Generating Units
In this section of the preamble, the EPA evaluates CCS and natural gas co-firing as potential BSER for long-term coal-fired steam generating units.
The EPA is proposing CCS with 90 percent capture of CO2 at the stack as BSER for long-term coal-fired steam generating units. The Agency is taking comment on the range of the amount of capture of CO2 from 90 to 95 percent. CCS achieves substantial reductions in emissions and can capture and permanently sequester more than 90 percent of CO2 emitted by coal-fired steam generating units. The technology is adequately demonstrated, as indicated by the facts that it has been operated at scale and is widely applicable to sources, and there are vast sequestration opportunities across the continental U.S. Additionally, accounting for the tax credit under IRC section 45Q, the costs for CCS are reasonable. Moreover, the non-air quality health and environmental impacts and energy requirements of CCS are not unreasonably adverse. These factors provide the basis for proposing CCS as BSER for these sources. In addition, determining CCS as the BSER promotes this useful control technology.
The EPA also evaluated natural gas co-firing at 40 percent of heat input as a potential BSER for long-term coal-fired steam generating units. While the unit level emission rate reductions of 16 percent achieved by 40 percent natural gas co-firing are reasonable, those reductions are less than CCS with 90 percent capture of CO2. Therefore, because CCS achieves more reductions at the unit level and is cost reasonable, the EPA is not proposing natural gas co-firing as the BSER for these units.
 CCS
In this section of the preamble, the EPA evaluates the use of CCS as the BSER for existing long-term coal-fired steam generating units. This section incorporates by reference the parts of section VII.F.3.b.iii of this preamble that discuss the aspects of CCS that are common to new combustion turbines and existing steam generating units. This section also discusses additional aspects of CCS that are relevant for existing steam generating units and, in particular, long-term units.
Adequately Demonstrated
The EPA is proposing that CCS is technically feasible and has been adequately demonstrated, based on the utilization of the technology at existing coal-fired steam generating units and industrial sources in addition to combustion turbines. While the EPA would propose that CCS is adequately demonstrated on those bases alone, this determination is further corroborated by EPAct05-assisted projects.
The fundamental CCS technology has been in existence for decades, and the industry has extensive experience with and knowledge about it. Thus, the EPA will explain how existing and planned fossil fuel-fired electric power plants and other industrial projects that have installed or expect to install some or all of the components of CCS technology support the EPA's proposed determination that CCS is adequately demonstrated for existing coal-fired power plants, and the EPA will explain how EPAct05-assisted projects support that proposed determination, consistent with the legal interpretation of the EPAct05 in section VII.F.3.b.iii.(A).
CO2 Capture Technology
The technology of CO2 capture, in general, is detailed in section VII.F.3.b.iii of this preamble. As noted there, solvent-based (i.e., amine-based) post-combustion CO2 capture is the technology that is most applicable at existing coal-fired steam generating units. Technology considerations specific to existing coal-fired steam generating units, including energy demands, non-GHG emissions, and water use and siting, are discussed in section X.D.1.a.iii of this preamble. As detailed in section VII.F.3.b.iii.(A) of this preamble, the CO2 capture component of CCS has been demonstrated at existing coal-fired steam generating units, industrial processes, and existing combustion turbines. In particular, SaskPower's Boundary Dam Unit 3 has demonstrated capture rates of 90 percent of the CO2 in flue gas using solvent-based post-combustion capture retrofitted to existing coal-fired steam generating units. While the EPA would propose that the CO2 capture component of CCS is adequately demonstrated on the basis of Boundary Dam Unit 3 alone, CO2 capture has been further demonstrated at other coal-fired steam generating units (CO2 capture from slipstreams of AES's Warrior Run and Shady Point) and industrial processes (e.g., Quest CO2 capture project), detailed descriptions of which are provided in section VII.F.3.b.iii.(A)2 of this preamble. The core technology of CO2 capture applied to combustion turbines is similar to that of coal-fired steam generating units (i.e., both may use amine solvent-based methods); therefore the demonstration of CO2 capture at combustion turbines (e.g., the Bellingham, Massachusetts, combined cycle unit), as detailed in section VII.F.3.b.iii.(A)3 of this preamble, provide additional support for the adequate demonstration of CO2 capture for coal-fired steam generating units. Finally, EPAct05-assisted CO2 capture projects (e.g., Petra Nova) further corroborate the adequate demonstration of CO2 capture.
CO2 Transport
As discussed in section VII.F.3.b.iii of this preamble, CO2 pipelines are available and their network is expanding in the U.S., and the safety of existing and new CO2 pipelines is comprehensively regulated by PHMSA. Other modes of CO2 transportation also exist.
Based on data from DOE/NETL studies of storage resources, 77 percent of existing coal-fired steam generating units that have planned operation during or after 2030 are within 80 km (50 miles) of potential saline sequestration sites, and another 5 percent are within 100 km (62 miles) of potential sequestration sites. Additionally, of the coal-fired steam generating units with planned operation during or after 2030, 90 percent are located within 100 km of one or more types of sequestration formations, including deep saline, unmineable coal seams, and oil and gas reservoirs. This distance is consistent with the distances referenced in studies that form the basis for transport cost estimates in this proposal.
Geologic Sequestration of CO2
Geologic sequestration (i.e., the long-term containment of a CO2 stream in subsurface geologic formations) is well proven and broadly available throughout the U.S. Geologic sequestration is based on a demonstrated understanding of the processes that affect the fate of CO2 in the subsurface. As discussed in section VIII.F.3.a.iii of this preamble, there have been numerous instances of geologic sequestration in the U.S. and overseas, and the U.S. has developed a detailed set of regulatory requirements to ensure the security of sequestered CO2. This regulatory framework includes the UIC Class VI well regulations, which are under the authority of SDWA, and the GHGRP, under the authority of the CAA.
Geologic sequestration potential for CO2 is widespread and available throughout the U.S. Through an availability analysis of sequestration potential in the U.S. based on resources from the DOE, the USGS, and the EPA, the EPA found that there are 43 states with access to, or are within 100 km from, onshore or offshore storage in deep saline formations, unmineable coal seams, and depleted oil and gas reservoirs.
Sequestration potential as it relates to distance from existing resources is a key part of the EPA's regular power sector modeling development, using data from DOE/NETL studies. These data show that of the coal-fired steam generating units with planned operation during or after 2030, 60 percent are located within the boundary of a saline reservoir, 77 percent are located within 40 miles (80 km) of the boundary of a saline reservoir, and 82 percent are located within 62 miles (100 km) of a saline reservoir. Additionally, of the coal-fired steam generating units with planned operation during or after 2030, 90 percent are located within 100 km of any of the considered formations, including deep saline, unmineable coal seams, and oil and gas reservoirs.
Costs
The EPA has analyzed the costs of CCS for existing coal-fired long-term sources, including costs for CO2 capture, transport, and sequestration. The EPA is proposing that this analysis demonstrates that the costs of CCS for these sources are reasonable.
The EPA assessed costs of CCS for a reference unit as well as the average cost for the fleet of coal-fired steam generating units with planned operation during or after 2030. The reference unit, which represents an average unit in the fleet, has a 400 MW-gross nameplate capacity and a 10,000 Btu/kWh heat rate. Applying CCS to the reference unit with a 12-year amortization period and assuming a 50 percent annual capacity factor -- a typical value for the fleet -- results in annualized total costs that can be expressed as an abatement cost of $14/ton of CO2 reduced and an incremental cost of electricity of $12/MWh. For the fleet of coal-fired steam generating units with planned operation during or after 2030, and assuming a 12-year amortization period and 50 percent annual capacity factor, the average total costs of CCS are $8/ton of CO2 reduced and $7/MWh. Included in these estimates is the EPA's assessment that the transport and storage costs are roughly $30/ton, on average. These total costs also account for the IRC section 45Q tax credit, a detailed discussion of which is provided in section VII.F.3.b.iii.(B)3 of this preamble. Compared to the representative costs of controls for other pollutants (i.e., wet FGD SO2 emission control costs of $15.00 to $18.50/MWh as detailed in section VII.F.3.b.iii.(B)5 of this preamble), the costs for CCS on long-term coal-fired steam generating units are similar or better on an incremental cost of electricity ($/MWh) basis. Therefore, the EPA is proposing that for the purposes of the BSER analysis, CCS is cost reasonable for long-term coal-fired steam generating units. The EPA also evaluated costs of CCS under various other assumptions of amortization period and annual capacity factor. Finally, it is noted that these CCS costs are lower than those in prior rulemakings due to the IRC section 45Q tax credit and reductions in the cost of the technology.
CO2 Capture Costs at Existing Coal-fired Steam Generating Units
A variety of sources provide information for the cost of CCS systems, and they generally agree around a range of cost. The EPA has relied heavily on information recently developed by NETL, in the U.S. Department of Energy, in particular, "Cost and Performance Baseline for Fossil Energy Plants," and the "Pulverized Coal Carbon Capture Retrofit Database." In addition, the EPA developed an independent engineering cost assessment for CCS retrofits, with support from Sargent and Lundy.
CO2 Transport and Sequestration Costs
 As discussed in section VII.F.3.b.iii. of this preamble, NETL's "Quality Guidelines for Energy System Studies; Carbon Dioxide Transport and Sequestration Costs in NETL Studies" is one of the more comprehensive sources of information on CO2 transport and storage costs available. The Quality Guidelines provide an estimation of transport costs for a single point-to-point pipeline. Estimated costs reflect pipeline capital costs, related capital expenditures, and operations and maintenance costs. These Quality Guidelines also provide an estimate of sequestration costs reflecting the cost of site screening and evaluation, permitting and construction costs, the cost of injection wells, the cost of injection equipment, operation and maintenance costs, pore volume acquisition expense, and long-term liability protection.
NETL's Quality Guidelines model costs for a given cumulative storage potential. At a storage potential of 25 gigatons of CO2, costs range between $7.54/ton ($8.32/metric ton) sequestered (in the Illinois Basin) and $18.00/ton ($19.84/metric ton) sequestered (in the Powder River Basin).
Amortization Period and Annual Capacity Factor
In the EPA's cost analysis for long-term coal-fired steam generating units, the EPA assumes a 12-year amortization period and a 50 percent annual capacity factor. The 12-year amortization period is consistent with the period of time during which the IRC section 45Q tax credit can be claimed and the 50 percent annual capacity factor is consistent with the historical fleet average. However, increases in utilization are likely to occur for units that apply CCS due to the incentives provided by the IRC section 45Q tax credit. Therefore, the EPA also assessed the costs for CCS retrofitted to existing coal-fired steam generating units assuming a 70 percent annual capacity factor. For a 70 percent annual capacity factor and a 12-year amortization period, the costs for the reference unit are -$8/ton of CO2 reduced and -$7/MWh. For either capacity factor assumption, the $/MWh costs are comparable to or less than the representative cost of installing and operating wet FGD, costs for which are detailed in VII.F.3.b.iii.(B)5.
As noted in section X.C.3 of this preamble, the EPA is also taking comment on the date for the threshold between medium-term and long-term coal-fired steam generating units. For a 70 percent annual capacity factor and an 8-year amortization period, costs for the reference unit are $24/ton of CO2 reduced and $21/MWh, and it is possible that the cost of generation may be reasonable relative to the representative cost for wet FGD. However, CCS may be less cost favorable for units with shorter amortization periods. For a 70 percent annual capacity factor and a 7-year amortization period, costs for the reference unit are $34/ton of CO2 reduced and $21/MWh. Additional details of the cost analysis are available in the GHG Mitigation Measures  -  111(d) TSD.
Comparison to Costs for CCS in Prior Rulemakings
In the CPP and ACE Rule, the EPA determined that CCS did not qualify as the BSER due to cost considerations. Two key developments have led the EPA to reevaluate this conclusion: the costs of CCS technology have fallen and, most importantly, the extension and increase in the IRC section 45Q tax credit, as included in the IRA, in effect provide a significant stream of revenue for sequestered CO2 emissions. The CPP and ACE Rule relied on a 2015 NETL report estimating the cost of CCS. NETL has issued updated reports to incorporate the latest information available, most recently in 2022, which show cost reductions. The 2015 report estimated levelized cost of CCS at a new pulverized coal facility at $74/MWh (2022$), while the 2022 report estimated levelized cost at $44/MWh (2022$). Additionally, the IRA increased the IRC section 45Q tax credit from $50/metric ton to $85/metric ton (and, in the case of EOR or certain industrial uses, from $35/metric ton to $60/metric ton), assuming prevailing wage and apprenticeship conditions are met. The combination of lower costs and higher tax credits significantly improves the cost effectiveness of CCS for purposes of determining whether it qualifies as the BSER.
Non-air Quality Health and Environmental Impact and Energy Requirements
CCS for steam generating units is not expected to have unreasonable adverse consequences related to non-air quality health and environmental impacts or energy requirements. As discussed later in the preamble, the EPA has considered non-GHG emissions impacts, the water use impacts, the transport and sequestration of captured CO2, and energy requirements resulting from CCS. Because the non-air quality health and environmental impacts are closely related to the energy requirements, the latter are discussed first.
Energy Requirements
For a steam generating unit with 90 percent amine-based CO2 capture, parasitic/auxiliary energy demand increases and the net power output decreases. Amine-based CO2 capture is an energy-intensive process. In particular, the solvent regeneration process requires substantial amounts of heat in the form of steam and CO2 compression requires a large amount of electricity. Heat and power for the CO2 capture equipment can be provided either by using the steam and electricity produced by the steam generating unit or by an auxiliary cogeneration unit. However, any auxiliary source of heat and power is part of the "designated facility," along with the steam generating unit. The standards of performance apply to the designated facility. Thus, any CO2 emissions from the connected auxiliary equipment need to be captured or they will increase the facility's emission rate.
Using integrated heat and steam can reduce the capacity (i.e., the amount of electricity that a unit can distribute to the grid) of a 474 MW-net (501 MW-gross) coal-fired steam generating unit without CCS to 425 MW-net with CCS and contributes to a reduction in net efficiency of 23 percent. Despite decreases in efficiency, IRC section 45Q tax credits provide an incentive for increased utilization. The Agency is proposing that the energy penalty is relatively minor compared to the GHG benefits of CCS and, therefore, does not disqualify CCS as being considered the BSER for existing coal-fired steam generating units.
Additionally, the EPA considered the impacts on the power sector, on a nationwide and long-term basis, of determining CCS to be the BSER for long-term coal-fired steam generating units. The EPA is proposing that designating CCS as the BSER for existing long-term coal-fired steam generating units would have limited and non-adverse impacts on the long-term structure of the power sector. Absent the requirements defined in this action, the EPA projects that 9 GW of coal-fired steam generating units would apply CCS by 2030 and 35 GW of coal-fired steam generating units, some without controls, would remain in operation in 2040. Designating CCS to be the BSER for existing long-term coal-fired steam generating units would likely result in more of the coal-fired steam generating unit capacity applying CCS. The time available before the compliance deadline of January 1, 2030, provides for adequate resource planning, including accounting for the downtime necessary to install the CO2 capture equipment at long-term coal-fired steam generating units. While the IRC 45Q tax credit is available, long-term coal-fired steam generating units are anticipated to run at base load conditions. Total generation from coal-fired steam generating units in the other subcategories would gradually decrease over an extended period of time through 2039, subject to the commitments those units have chosen to adopt. Any decreases in the amount of generation from coal-fired steam generating units, whether locally or more broadly, are compensated for by increased generation from other sources. Additionally, for the long-term units applying CCS, the EPA is proposing the increase in the annualized cost of generation for those units is reasonable. Therefore, the EPA is proposing that there would be no unreasonable impacts on the reliability of electricity generation. A broader discussion of reliability impacts of the proposed actions is available in section XIV.F of this preamble. Finally, changes in the amount of generation from coal-fired steam generating units may contribute to additional generation from combined cycle combustion turbines. Since these EGUs have lower GHG and criteria pollutant emission rates than existing coal-fired steam generating units, overall emissions from the power sector would likely decrease.
Non-GHG Emissions
For amine-based CO2 capture retrofits to coal-fired steam generating units, decreased efficiency and increased utilization would otherwise result in increases of non-GHG emissions; however, importantly, most of those impacts would be mitigated by the flue gas conditioning required by the CO2 capture process and by other control equipment that the units already have or may need to install to meet other CAA requirements. Decreases in efficiency result in increases in the relative amount of coal combusted per amount of electricity generated and would otherwise result in increases in the amount of non-GHG pollutants emitted per amount of electricity generated. Additionally, increased utilization would otherwise result in increases in total non-GHG emissions. However, substantial flue gas conditioning, particularly to remove SO2, is critical to limiting solvent degradation and maintaining reliable operation of the capture plant. To achieve the necessary limits on SO2 levels in the flue gas for the capture process, steam generating units will need to add an FGD column, if they do not already have one, and may need an additional polishing column (i.e., quencher). A wet FGD column and a polishing column will also reduce the emission rate of particulate matter. Additional improvements in particulate matter removal may also be necessary to reduce the fouling of other components of the capture process (e.g., heat exchangers). NOx emissions can cause solvent degradation and nitrosamine formation by chemical absorption of NOX, depending on the chemical structure of the solvent. A conventional multistage water wash and mist eliminator at the exit of the CO2 scrubber is effective at removal of gaseous amine and amine degradation products (e.g., nitrosamine) emissions.  NOX levels of the flue gas required to avoid solvent degradation and nitrosamine formation in the CO2 scrubber vary. For most units, the requisite limits on NOX levels to assure that the CO2 capture process functions properly may be met by the existing NOX combustion controls, and those units may not need to install SCR for process purposes. However, most existing coal-fired steam generating units either already have SCR or will be covered by proposed Federal Implementation Plan (FIP) requirements regulating interstate transport of NOX (as an ozone precursors) from EGUs. See 87 FR 20036 (April 6, 2022). For units not otherwise required to have SCR, increased utilization from a CO2 capture retrofit could result in increased emissions that may trigger New Source Review (NSR) permitting requirements and, in turn, may require the installation of SCR for those units. See section XIII.A of this preamble.
Water Use and Siting
Water consumption at the plant increases when applying carbon capture, due to solvent water makeup and cooling demand. Water consumption can increase by 36 percent on a gross basis. A separate cooling water system dedicated to a CO2 capture plant may be necessary. However, the amount of water consumption depends on the design of the capture system. For example, the cooling system cited in the CCS feasibility study for SaskPower's Shand Power station would rely entirely on water condensed from the flue gas and thus would not require any increase in external water consumption. Regions with limited water supply may rely on dry or hybrid cooling systems, although, in areas with adequate water, wet cooling systems can be more effective.
With respect to siting considerations, CO2 capture systems have a sizeable physical footprint and a consequent land-use requirement. The EPA is proposing that the water use and siting requirements are manageable and therefore the EPA does not expect any of these considerations to preclude coal-fired power plants generally from being able to install and operate CCS. However, the EPA is soliciting comment on these issues.
Transport and Geologic Sequestration
As noted in section VII.F.3.b.iii of this preamble, PHMSA oversight of CO2 pipeline safety protects against environmental release during transport and UIC Class VI regulations under the SDWA, in tandem with GHGRP subpart RR requirements, ensure the protection of USDWs and the security of geologic sequestration.
Extent of Reductions in CO2 Emissions
CCS can be applied to coal-fired steam generating units at the source and reduce the CO2 emission rate by 90 percent or more. Increased steam and power demand have a small impact on the reduction in emission rate that occurs with 90 percent capture. According to the 2016 NETL Retrofit report, 90 percent capture will result in emission rates that are 88.4 percent lower on a lb/MWh-gross basis and 87.1 percent lower on a lb/MWh-net basis compared to units without capture. After capture, CO2 can be transported and securely sequestered. Although steam generating units with CO2 capture will have an incentive to operate at higher utilization because the cost to install the CCS system is largely fixed and the IRC section 45Q tax credit increases based on the amount of CO2 captured and sequestered, any increase in utilization will be far outweighed by the substantial reductions in emission rate.
Technology Advancement
The EPA considered the potential impact of designating CCS as the BSER for long-term coal-fired steam generating units on technology advancement, and the EPA is proposing that designating CCS as the BSER will provide for meaningful advancement of CCS technology, for many of the same reasons as noted in section VII.F.3.b.iii.(F) of this preamble.
Natural Gas Co-firing
The EPA also evaluated natural co-firing at 40 percent of the heat input as the potential BSER for long-term coal-fired steam generating units. Because the EPA is proposing natural gas co-firing as the BSER for medium-term units, details that are common to medium-term and long-term units are discussed in section X.D.2.b of the preamble. Based on the discussion therein, the EPA is proposing that natural gas co-firing is adequately demonstrated and that the non-air quality health and environmental effects and energy requirements are not unreasonable. The costs of natural gas co-firing for a long-term unit may also be reasonable. For example, for a representative unit with a 10-year amortization period, the cost of reductions is $53/ton of CO2. Finally, while the unit-level emission rate reductions of 16 percent achieved by 40 percent natural gas co-firing are reasonable, those reductions are less than CCS with 90 percent capture. Therefore, because CCS achieves more reductions at the unit level and is proposed as cost reasonable for long-term units, the EPA is not proposing natural gas co-firing as the BSER for long-term coal-fired steam generating units.
Conclusion
The EPA proposes that CCS at a capture rate of 90 percent is the BSER for long-term coal-fired steam generating units because CCS is adequately demonstrated, as indicated by the facts that it has been operated at scale and is widely applicable to sources, and there are vast sequestration opportunities across the continental U.S. Additionally, accounting for the tax credit under IRC section 45Q, the costs for CCS are reasonable. Moreover, any adverse non-air quality health and environmental impacts and energy requirements of CCS, including impacts on the power sector on a nationwide basis, are limited and are outweighed by the benefits of the significant emission reductions at reasonable cost. In contrast, co-firing 40 percent natural gas would achieve far fewer emission reductions without improving the cost effectiveness of the control strategy. These considerations provide the basis for proposing CCS as the best of the systems of emission reduction for long-term coal-fired power plants. In addition, determining CCS as the BSER promotes this useful control technology.
Medium-term Coal-fired Steam Generating Units
In this section of the preamble, the EPA evaluates CCS and natural gas co-firing as potential BSER for medium-term coal-fired steam generating units.
In section X.D.1.a of this preamble, the EPA evaluated CCS with 90 percent capture of CO2 as the BSER for long-term coal-fired steam generating units. Much of this evaluation is relevant for medium-term units. However, because they have shorter operating horizons and, as a result, a shorter period for amortization and for collecting the IRC section 45Q tax credits, CCS would be less cost effective for those units. Therefore, the EPA is not proposing CCS as BSER for medium-term coal-fired steam generating units.
Instead, the EPA is proposing that 40 percent natural gas co-firing on a heat input basis is the BSER for medium-term coal-fired steam generating units. Co-firing 40 percent natural gas, on an annual average heat input basis, results in a 16 percent reduction in CO2 emission rate. The technology has been adequately demonstrated, can be implemented at reasonable cost, does not have adverse non-air quality health and environmental impacts or energy requirements, and achieves meaningful reductions in CO2 emissions. Co-firing also advances useful control technology and has acceptable national and long-term impacts on the energy sector, which provide additional, although not essential, support for treating it as the BSER.
CCS
In this section of the preamble, the EPA evaluates the use of CCS as the BSER for existing medium-term coal-fired steam generating units. This evaluation is much the same as the evaluation for long-term units, with the important difference of costs.
For long-term units, as discussed earlier in this preamble, the EPA's analysis used to evaluate the reasonableness of CCS costs employs a 12-year amortization period, which is consistent with the period of time during which the IRC section 45Q tax credit can be claimed. However, existing coal-fired steam generating units that choose to adopt federally enforceable commitments to permanently cease operations prior to 2040 -- ones in the medium-term subcategory, as well as in the near-term, and imminent-term subcategories -- would have a shorter period to amortize capital costs and also would not be able to fully utilize the IRC section 45Q tax credit. As a result, for these sources, the cost effectiveness of CCS is less favorable. As noted in section X.D.1.a.ii.(C) of this preamble, for a 70 percent annual capacity factor and a 7-year amortization period, costs for the reference unit are $39/ton of CO2 reduced and $34/MWh. This $/MWh generation cost is less favorable relative to the representative cost ($/MWh) for wet FGD, the costs for which are detailed in section VII.F.3.b.iii.(B)5. Due to the higher incremental cost of generation, the EPA is not proposing CCS as the BSER for medium-term coal-fired steam generating units.
While the EPA is not proposing CCS as BSER for the proposed subcategory of medium-term units, the EPA is taking comment on what dates most appropriately define the threshold between medium-term and long-term units and the EPA is also taking comment on the level of costs of CCS that should be considered reasonable.
Natural Gas Co-firing
In this section of the preamble, the EPA evaluates natural gas co-firing as potential BSER for medium-term coal-fired steam generating units. Considerations that are common to the proposed subcategories of existing coal-fired steam generating units are discussed in this section (X.D.1.a) of the preamble, in addition to considerations that are specific to medium-term units.
For a coal-fired steam generating unit, the substitution of natural gas for some of the coal, so that the unit fires a combination of coal and natural gas, is known as "natural gas co-firing." The EPA is proposing natural gas co-firing at a level of 40 percent of annual heat input as BSER for medium-term coal-fired steam generating units.
Adequately Demonstrated
The EPA is proposing to find that natural gas co-firing at the level of 40 percent of annual heat input is adequately demonstrated for coal-fired steam generating units. Many existing coal-fired steam generating units already use some amount of natural gas, and several have co-fired at relatively high levels at or above 40 percent of heat input in recent years.
Boiler Modifications
Most existing coal-fired steam generating units can be modified to co-fire natural gas in any desired proportion with coal, up to 100 percent natural gas. Generally, the modification of existing boilers to enable or increase natural gas firing typically involves the installation of new gas burners and related boiler modifications, including, for example, new fuel supply lines and modifications to existing air ducts. The introduction of natural gas as a fuel can reduce boiler efficiency slightly, due in large part to the relatively high hydrogen content of natural gas. However, since the reduction in coal can result in reduced auxiliary power demand, the overall impact on net heat rate can range from a 2 percent increase to a 2 percent decrease.
It is common practice for steam generating units to have the capability to burn multiple fuels onsite, and of the 565 coal-fired steam generating units operating at the end of 2021, 249 of them reported consuming natural gas as a fuel or startup source. Coal-fired steam generating units often use natural gas or oil as a startup fuel, to warm the units up before running them at full capacity with coal. While startup fuels are generally used at low levels (up to roughly 1 percent of capacity on an annual average basis), some coal-fired steam generating units have co-fired natural gas at considerably higher shares. Based on hourly reported CO2 emission rates from the start of 2015 through the end of 2020, 29 coal-fired steam generating units co-fired with natural gas at rates at or above 60 percent of capacity on an hourly basis. The capability of those units on an hourly basis is indicative of the extent of boiler burner modifications and sizing and capacity of natural gas pipelines to those units, and implies that those units are technically capable of co-firing at least 60 percent natural gas on a heat input basis on average over the course of an extended period (e.g., a year). Additionally, during that same 2015 through 2020 period, 29 coal-fired steam generating units co-fired natural gas at over 40 percent on an annual heat input basis. Because of the number of units that have demonstrated co-firing above 40 percent of heat input, the EPA is proposing that co-firing at 40 percent is adequately demonstrated. A more detailed discussion of the record of natural gas co-firing, including current trends, at coal-fired steam generating units is included in the GHG Mitigation Measures  -  111(d) TSD.
Natural Gas Pipeline Development
In addition to any potential boiler modifications, the supply of natural gas is necessary to enable co-firing at existing coal-fired steam boilers. As discussed in the previous section, many plants already have at least some access to natural gas. In order to increase natural gas access beyond current levels, many will find it necessary to construct natural gas supply pipelines.
The U.S. natural gas pipeline network consists of approximately 3 million miles of pipelines that connect natural gas production with consumers of natural gas. To increase natural gas consumption at a coal-fired boiler without sufficient existing natural gas access, it is necessary to connect the facility to the natural gas pipeline transmission network via the construction of a lateral pipeline. The cost of doing so is a function of the total necessary pipeline capacity (which is characterized by the length, size, and number of laterals) and the location of the plant relative to the existing pipeline transmission network. The EPA estimated the costs associated with developing new lateral pipeline capacity sufficient to meet 60 percent of the net summer capacity at each coal-fired steam generating unit. As discussed in the GHG Mitigation Measures  -  111(d) TSD, the EPA estimates that this lateral capacity would be sufficient to enable each unit to achieve 40 percent natural gas co-firing on an annual average basis.
The EPA considered the availability of the upstream natural gas pipeline capacity to satisfy the assumed co-firing demand implied by these new laterals. This analysis included pipeline development at all EGUs that could be included in this subcategory. The EPA's assessment reviewed the reasonableness of each assumed new lateral by determining whether the peak gas capacity of that lateral could be satisfied without modification of the transmission pipeline systems to which it is assumed to be connected. This analysis found that most, if not all, existing pipeline systems are currently able to meet the peak needs implied by these new laterals in aggregate, assuming that each existing coal-fired unit in the analysis co-fired with natural gas at a level implied by these new laterals, or 60 percent of net summer generating capacity. While this is a reasonable assumption for the analysis to support this mitigation measure in the BSER context, it is also a conservative assumption that overstates the amount of natural gas co-firing expected under the proposed rule.
The maximum amount of pipeline capacity, if all coal-fired steam capacity in the medium-term subcategory implemented the proposed BSER by co-firing 40 percent natural gas, would be a fraction of the pipeline capacity constructed recently. The EPA estimates that this maximum total capacity would be about 17.3 billion cubic feet per day, which would require almost 4,000 miles of pipeline costing roughly $13.3 billion. Over 5 years, this maximum total incremental pipeline capacity would amount to 800 miles per year and approximately $2.7 billion per year in capital expenditures, on average. By comparison, based on data collected by EIA, the total annual mileage of natural gas pipelines constructed over the 2017 - 2021 period ranged from approximately 1,000 to 2,500 miles per year, with a total capacity of 10 to 25 billion cubic feet per day. This represents an estimated annual investment of up to nearly $15 billion. These historical annual values are much higher than the maximum annual values that could be expected under this proposed BSER measure -- which, as noted above, represent a conservative estimate that overstates the amount of co-firing that the EPA projects would occur under this proposed rule.
These conservatively high estimates of pipeline requirements also compare favorably to industry projections of future pipeline capacity additions. Based on a review of a 2018 industry report, titled "North America Midstream Infrastructure through 2035: Significant Development Continues," investment in midstream infrastructure development is expected to average about $37 billion per year through 2035, which is lower than historical levels. Approximately $10 to $20 billion annually is expected to be invested in natural gas pipelines through 2035. This report also projects that an average of over 1,400 miles of new natural gas pipeline will be built through 2035, which is similar to the approximately 1,670 miles that were built on average from 2013 to 2017. These values are considerably greater than the average annual expenditure of $2.7 billion on 800 miles per year of new pipeline construction that would be necessary for the entire operational fleet of coal-fired steam generating units to co-fire with natural gas. The actual pipeline investment for this subcategory would be substantially lower.
Costs
The capital costs associated with the addition of new gas burners and other necessary boiler modifications depend on the extent to which the current boiler is already able to co-fire with some natural gas and on the amount of gas co-firing desired. The EPA estimates that, on average, the total capital cost associated with modifying existing boilers to operate at up to 100 percent of heat input using natural gas is approximately $52/kW. These costs could be higher or lower, depending on the equipment that is already installed and the expected impact on heat rate or steam temperature.
While fixed O&M (FOM) costs can potentially decrease as a result of decreasing the amount of coal consumed, it is common for plants to maintain operation of one coal pulverizer at all times, which is necessary for maintaining several coal burners in continuous service. In this case, coal handling equipment would be required to operate continuously and therefore natural gas co-firing would have limited effect on reducing the coal-related FOM costs. Although, as noted, coal-related FOM costs have the potential to decrease, the EPA does not anticipate a significant increase in impact on FOM costs related to co-firing with natural gas.
In addition to capital and FOM cost impacts, any additional natural gas co-firing would result in incremental costs related to the differential in fuel cost, taking into consideration the difference in delivered coal and gas prices, as well as any potential impact on the overall net heat rate. The EPA's post-IRA 2022 reference case projects that in 2030, the average delivered price of coal will be $1.47/MMBtu and the average delivered price of natural gas will be $2.53/MMBtu. Thus, assuming the same level of generation and no impact on heat rate, the additional fuel cost would be above $1/MMBtu on average in 2030. The total additional fuel cost could increase or decrease depending on the potential impact on net heat rate. An increase in net heat rate, for example, would result in more fuel required to produce a given amount of generation and thus additional cost. In the GHG Mitigation Measures  -  111(d) TSD, the EPA's cost estimates assume a 1 percent increase in net heat rate.
Finally, for plants without sufficient access to natural gas, it is also necessary to construct new natural gas pipelines ("laterals"). Pipeline costs are typically expressed in terms of dollars per inch of pipeline diameter per mile of pipeline distance (i.e., dollars per inch-mile), reflecting the fact that costs increase with larger diameters and longer pipelines. On average, the cost for lateral development within the contiguous U.S. is approximately $280,000 per inch-mile (2019$), which can vary based on site-specific factors. The total pipeline cost for each coal-fired steam generating unit is a function of this cost, as well as a function of the necessary pipeline capacity and the location of the plant relative to the existing pipeline transmission network. The pipeline capacity required depends on the amount of co-firing desired as well as on the desired level of generation -- a higher degree of co-firing while operating at full load would require more pipeline capacity than a lower degree of co-firing while operating at partial load. It is reasonable to assume that most plant owners would develop sufficient pipeline capacity to deliver the maximum amount of desired gas use in any moment, enabling higher levels of co-firing during periods of lower fuel price differentials. Once the necessary pipeline capacity is determined, the total lateral cost can be estimated by considering the location of each plant relative to the existing natural gas transmission pipelines as well as the available excess capacity of each of those existing pipelines. For purposes of the cost reasonableness estimates as follows, the EPA assumes pipeline costs of $92/kW, which is the median value of all unit-level pipeline cost estimates, as explained in the GHG Mitigation Measures  -  111(d) TSD. The range in costs reflects a range in the amortization period of the capital costs over 6 to 10 years, which is consistent with the amount of time over which the units in the medium-term subcategory could be operational.
The EPA sums the natural gas co-firing costs as follows: For a typical base load coal-fired steam generating unit in 2030, the EPA estimates that the cost of co-firing with 40 percent natural gas on an annual average basis is approximately $53 to $66/ton CO2 reduced, or $9 to $12/MWh, respective to amortization periods of 10 to 6 years. This estimate is based on the characteristics of a typical coal-fired unit in 2021 (400 MW capacity and an average heat rate of 10,500 Btu/kWh) operating at a typical capacity factor of about 50 percent, and it assumes a pipeline cost of $92/kW, as discussed earlier in this preamble.
Based on the coal-fired steam generating units that existed in 2021 and that do not have known plans to cease operations or convert to gas by 2030, and assuming that each of those units continues to operate at the same level in 2030 as it operated in 2017-2021, on average, the EPA estimates that the weighted average cost of co-firing with 40 percent natural gas on an annual average basis is approximately $64 to $78/ton CO2 reduced, or $11 to $14/MWh. The $/ton cost estimate is lower than average for approximately 82 GW, and the $/MWh cost estimate is lower than average for 86 GW (about 69 percent and 72 percent, respectively, of the relevant coal fleet). These estimates and all underlying assumptions are explained in detail in the GHG Mitigation Measures  -  111(d) TSD.
As was described in section X.D.1 of this preamble, the EPA has compared the estimated costs discussed in section X.D.2 of this preamble to costs that coal-fired steam generating units have incurred to install controls that reduce other air pollutants, such as SO2. Representative wet FGD SO2 emission control costs are $15.00 to $18.50/MWh, as detailed in section VII.F.3.b.iii.(B)5 of this preamble. The estimated range of annualized costs of natural gas co-firing (approximately $9 - $14/MWh) is lower than or comparable to the representative annualized costs of installing and operating wet FGD, which are detailed in section VII.F.3.b.iii.(B)5 of this preamble. The range of cost effectiveness estimates presented in this section is lower than previously estimated by the EPA in the proposed CPP, for several reasons. Since then, the expected difference between coal and gas prices has decreased significantly, from over $3/MMBtu to about $1/MMBtu in this proposal. Additionally, a recent analysis performed by Sargent and Lundy for the EPA supports a considerably lower capital cost for modifying existing boilers to co-fire with natural gas. The EPA also recently conducted a highly detailed facility-level analysis of natural gas pipeline costs, the median value of which is slightly lower than the value used by the EPA previously to approximate the cost of co-firing at a representative unit.
Based on the range of costs presented in this section, the EPA is proposing that the costs of natural gas co-firing are reasonable for the medium-term coal-fired steam generating unit subcategory.
Non-air Quality Health and Environmental Impact and Energy Requirements
Natural gas co-firing for steam generating units is not expected to have any significant adverse consequences related to non-air quality health and environmental impacts or energy requirements.
Non-GHG Emissions
Non-GHG emissions are reduced when steam generating units co-fire with natural gas because less coal is combusted. SO2, PM2.5, acid gas, mercury and other hazardous air pollutant emissions that result from coal combustion are reduced proportionally to the amount of natural gas consumed, i.e., under this proposal, by 40 percent. Natural gas combustion does produce NOX emissions, but in lesser amounts than from coal-firing. However, the magnitude of this reduction is dependent on the combustion system modifications that are implemented to facilitate natural gas co-firing.
Additionally, sufficient regulations exist related to natural gas pipelines and transport that assure natural gas can be safely transported with minimal risk of environmental release. PHMSA develops and enforces regulations for the safe, reliable, and environmentally sound operation of the nation's 2.6 million mile pipeline transportation system. Recently, PHMSA finalized a rule that will improve the safety and strengthen the environmental protection of more than 300,000 miles of onshore gas transmission pipelines. PHMSA also recently promulgated a rule covering natural gas transmission, as well as a rule that significantly expanded the scope of safety and reporting requirements for more than 400,000 miles of previously unregulated gas gathering lines. Additionally, FERC oversees the development of new natural gas pipelines.
Energy Requirements
The introduction of natural gas co-firing will cause steam boilers to be slightly less efficient due to the high hydrogen content of natural gas. Co-firing at levels between 20 percent and 100 percent can be expected to decrease boiler efficiency between 1 percent and 5 percent. However, despite the decrease in boiler efficiency, the overall net output efficiency of a steam generating unit that switches from coal- to natural gas-firing may change only slightly, in either a positive or negative direction. Since co-firing reduces coal consumption, the auxiliary power demand related to coal handling and emissions controls typically decreases as well. While a site-specific analysis would be required to determine the overall net impact of these countervailing factors, generally the effect of co-firing on net unit heat rate can vary within approximately plus or minus 2 percent.
The EPA previously determined in the ACE Rule (84 FR 32520 at 32545; July 8, 2019) that "co-firing natural gas in coal-fired utility boilers is not the best or most efficient use of natural gas and [...] can lead to less efficient operation of utility boilers." That determination was informed by the more limited supply of natural gas, and the larger amount of coal-fired EGU capacity and generation, in 2019. Since that determination, the expected supply of natural gas has expanded considerably, and the capacity and generation of the existing coal-fired fleet has decreased, reducing the total mass of natural gas that might be required for sources to implement this measure. Additionally, the natural gas co-firing measure is now being proposed for a medium-term coal-fired steam generating unit subcategory, a group of units that will operate at most for 10 years following the compliance date, which would further reduce the total amount of required natural gas.
Furthermore, regarding the efficient operation of boilers, the ACE determination was based on the observation that "co-firing can negatively impact a unit's heat rate (efficiency) due to the high hydrogen content of natural gas and the resulting production of water as a combustion by-product." That finding does not consider the fact that the effect of co-firing on net unit heat rate can vary within approximately plus or minus 2 percent, and therefore the net impact on overall utility boiler efficiency for each steam generating unit is uncertain.
For all of these reasons, the EPA is proposing that natural gas co-firing at medium-term coal-fired steam generating units does not result in any significant adverse consequences related to energy requirements.
Additionally, the EPA considered longer term impacts on the energy sector, and the EPA is proposing these impacts are reasonable. Designating natural gas co-firing as the BSER for medium-term coal-fired steam generating units would not have significant adverse impacts on the structure of the energy sector. Steam generating units that currently are coal-fired would be able to remain primarily coal-fired. The replacement of some coal with natural gas as fuel in these sources would not have significant adverse effects on the price of natural gas or the price of electricity.
Extent of Reductions in CO2 Emissions
One of the primary benefits of natural gas co-firing is emission reduction. CO2 emissions are reduced by approximately 4 percent for every additional 10 percent of co-firing. When shifting from 100 percent coal to 60 percent coal and 40 percent natural gas, CO2 stack emissions are reduced by approximately 16 percent. Non-CO2 emissions are reduced as well, as noted earlier in this preamble.
Technology Advancement
Natural gas co-firing is already well-established and widely used by coal-fired steam boiler generating units. As a result, this proposed rule is not likely to lead to technological advances or cost reductions in the components of natural gas co-firing, including modifications to boilers and pipeline construction. However, greater use of natural gas co-firing may lead to improvements in the efficiency of conducting natural gas co-firing and operating the associated equipment.
Conclusion
The EPA proposes that natural gas co-firing at 40 percent of heat input is the BSER for medium-term coal-fired steam generating units because natural gas co-firing is adequately demonstrated, as indicated by the facts that it has been operated at scale and is widely applicable to sources. Additionally, the costs for natural gas co-firing are reasonable. Moreover, any adverse non-air quality health and environmental impacts and energy requirements of natural gas co-firing are limited and are outweighed by the benefits of the emission reductions at reasonable cost. In contrast, CCS, although achieving greater emission reductions, would be less cost-effective, in general, for the proposed subcategory of medium-term units.
While the EPA is not proposing CCS as BSER for the proposed subcategory definition of medium-term units, the EPA is taking comment on the dates that define the threshold between medium-term and long-term units and on what amount of costs should be considered reasonable.
Imminent-term and Near-term Coal-fired Steam Generating Units
In this section of the preamble, the EPA evaluates CCS, natural gas co-firing, and routine methods of operation and maintenance as the BSER for imminent-term and near-term coal-fired steam generating units. Primarily because of the effect of a short operating horizon on the cost of controls for these units, the EPA proposes routine methods of operation and maintenance as the BSER.
CCS
As noted in section X.D.2.a of this preamble, the EPA is not proposing CCS for medium-term units due to $/MWh costs being less favorable based on the appropriate cost metrics. Because of the shorter operating horizons for imminent-term and near-term coal-fired steam generating units, CCS is less cost favorable for them than for medium-term units. Therefore, the EPA is not proposing CCS as BSER for imminent-term or near-term coal-fired steam generating units. Additional details of cost values for amortization periods representative of imminent-term and near-term units are available in the GHG Mitigation Measures  -  111(d) TSD.
Natural Gas Co-firing
Much of the discussion of natural gas co-firing in section X.D.2.b of this preamble for medium-term units is relevant for imminent-term and near-term units, except that natural gas co-firing is less cost effective for the latter units because of their short operating horizons. For a 2-year amortization period, annualized costs for the representative unit are $130/ton of CO2 reduced and $23/MWh of generation. Therefore, the EPA is not proposing natural gas co-firing as BSER for imminent-term or near-term units. Additional details of cost are available in the GHG Mitigation Measures  -  111(d) TSD.
Routine Methods of Operation and Maintenance
For the imminent-term and near-term coal-fired steam generating units, the EPA is proposing that the BSER is routine methods of operation and maintenance already occurring at the unit, so as to maintain the current unit-specific CO2 emission rates (expressed as lb CO2/MWh). Furthermore, requiring additional investment in those units could have the counterproductive effects of leading them to increase operations and thereby increase CO2 emissions.
Routine methods of operation and maintenance are adequately demonstrated because units already operate by those methods. They will not result in additional costs from any controls, and will not create adverse non-air quality health and environmental impacts or energy requirements. They will not achieve CO2 emission reductions at the unit level relative to current performance, but they can prevent worsening of emission rates over time. Although they do not advance useful control technology, they do not have adverse impacts on the energy sector from a nationwide or long-term perspective.
Degree of Emission Limitation
Under CAA section 111(d), once the EPA determines the BSER, it must determine the "degree of emission limitation" achievable by the application of the BSER. States then determine standards of performance and include them in the state plans, based on the specified degree of emission limitation. Proposed presumptive standards of performance are detailed in section XI.D of this preamble. There is substantial variation in emission rates among coal-fired steam generating units -- the range is, approximately, from 1,700 lb CO2/MWh-gross to 2,500 lb CO2/MWh-gross -- which makes it challenging to determine a single, uniform emission limit. Accordingly, for each of the four subcategories of coal-fired steam generating units, the EPA is proposing to determine the degree of emission limitation by a percentage change in emission rate, as follows:
Long-term Coal-fired Steam Generating Units
As discussed earlier in this preamble, the EPA is proposing the BSER for long-term coal-fired steam generating units as "full-capture" CCS, defined as 90 percent capture of the CO2 in the flue gas. The degree of emission limitation achievable by applying this BSER can be determined on a rate basis. A capture rate of 90 percent results in reductions in the emission rate of 88.4 percent on a lb CO2/MWh-gross basis, and this reduction in emission rate can be observed over an extended period (e.g., an annual calendar-year basis). Therefore, the EPA is proposing that the degree of emission limitation for long-term units is an 88.4 percent reduction in emission rate on a lb CO2/MWh-gross basis over an extended period (e.g., an annual calendar-year basis).
As noted in section X.D.1.a of this preamble, new CO2 capture retrofits on existing coal-fired steam generating units may achieve capture rates greater than 90 percent, and the EPA is taking comment on a range of capture rates that may be achievable. As also discussed in section X.D.1.a, the operating availability (i.e., the amount of time a process operates relative to the amount of time it planned to operate) of industrial processes is usually less than 100 percent. Assuming that CO2 capture achieves 90 percent capture when available to operate, that CCS is available to operate 90 percent of the time the coal-fired steam generating unit is operating, and that the steam generating unit operates the same whether or not CCS is available to operate, total emission reductions would be 81 percent. Higher levels of emission reduction could occur for higher capture rates coupled with higher levels of operating availability relative to operation of the steam generating unit. If the steam generating unit were not permitted to operate when CCS was unavailable, there may be local reliability consequences, and the EPA is soliciting comment on how to balance these issues. Additionally, the EPA is soliciting comment on a range of the degree of emission limitation achievable, in the form of a reduction in emission rate of 80 to 90 percent when determined over an extended period (e.g., an annual calendar-year basis).
Medium-term Coal-fired Steam Generating Units
As discussed earlier in this preamble, the BSER for medium-term coal-fired steam generating units is 40 percent natural gas co-firing. The application of 40 percent natural gas co-firing results in reductions in the emission rate of 16 percent. Therefore, the degree of emission limitation for these units is a 16 percent reduction in emission rate on a lb CO2/MWh-gross basis over an extended period (e.g., an annual calendar-year basis).
Imminent-term and Near-term Coal-fired Steam Generating Units
As discussed above, the BSER for imminent-term and near-term coal-fired steam generating units is routine methods of operation and maintenance. Application of this BSER results in no increase in emission rate. Thus, the degree of emission limitation corresponding to the application of the BSER is no increase in emission rate on a lb CO2/MWh-gross basis over an extended period (e.g., an annual calendar-year basis).
Other Emission Reduction Measures
Heat Rate Improvements
Heat rate is a measure of efficiency that is commonly used in the power sector. The heat rate is the amount of energy input, measured in Btu, required to generate one kWh of electricity. The lower an EGU's heat rate, the more efficiently it operates. As a result, an EGU with a lower heat rate will consume less fuel and emit lower amounts of CO2 and other air pollutants per kWh generated as compared to a less efficient unit. HRI measures include a variety of technology upgrades and operating practices that may achieve CO2 emission rate reductions of 0.1 to 5 percent for individual EGUs. The EPA considered HRI to be part of the BSER in the CPP and to be the BSER in the ACE Rule. However, the reductions that may be achieved by HRI are small relative to the reductions from natural gas co-firing and CCS. Also, some facilities that apply HRI would, as a result of their increased efficiency, increase their utilization and therefore increase their CO2 emissions (as well as emissions of other air pollutants), a phenomenon that the EPA has termed the "rebound effect." Therefore, the EPA is not proposing HRI as a part of BSER.
CO2 Reductions from HRI in Prior Rulemakings
In the CPP, the EPA quantified emission reductions achievable through heat rate improvements on a regional basis by an analysis of historical emission rate data, taking into consideration operating load and ambient temperature. The Agency concluded that EGUs can achieve on average a 4.3 percent improvement in the Eastern Interconnection, a 2.1 percent improvement in the Western Interconnection, and a 2.3 percent improvement in the Texas Interconnection. See 80 FR 64789 (October 23, 2015). The Agency then applied all three of the building blocks to 2012 baseline data and quantified, in the form of CO2 emission rates, the reductions achievable in each interconnection in 2030, and then selected the least stringent as a national performance rate. Id. At 64811 - 19. The EPA noted that building block 1 measures could not by themselves constitute the BSER because the quantity of emission reductions achieved would be too small and because of the potential for an increase in emissions due to increased utilization (i.e., the "rebound effect").
A description of the ACE Rule is detailed in section IX of this preamble.
Updated CO2 Reductions from HRI