In August 2018, the U.S. Environmental Protection Agency (EPA) proposed the "Affordable Clean Energy" (ACE) rule. ACE would modify provisions for existing power plants under two major Clean Air Act (CAA) programs. Among other things, ACE would "replace the Clean Power Plan (CPP)," a greenhouse gas (GHG) rulemaking that EPA promulgated under CAA Section 111(d) in 2015. ACE would also modify an applicability determination for New Source Review (NSR), which is a CAA preconstruction permitting program intended to ensure that new and modified stationary sources of air pollution do not significantly degrade air quality. EPA proposed ACE in response to Executive Order 13783, in which President Trump directed federal agencies to "review existing regulations and policies that potentially burden the development or use of domestically produced energy resources." Among the order's specific directives was that EPA review the CPP, which was one of the Obama Administration's key actions directed at reducing GHG emissions. EPA's review also led the agency to convene an "NSR Reform Task Force" to assess opportunities to simplify the NSR application and review process. Congress has also considered questions about NSR. A House hearing , held in early 2018, highlighted some long-standing and divergent views on the NSR program. Witnesses speaking in favor of NSR emphasized the program's health and environmental benefits, while other stakeholders described it as an outdated, cumbersome impediment to economic growth. For example, one of the witnesses testified that the complexities and costs of the NSR permitting process discourage pollution control and energy efficiency projects. In addition, two bills— H.R. 3127 and H.R. 3128 —were introduced in the 115 th Congress that would amend the CAA definition of modification , a key term in determining NSR applicability. Notable interest in the CPP and subsequent proposals to repeal or replace it reflects the perceived importance of their potential effects on the economy and the health, safety, and well-being of the nation. Some stakeholders contend that the U.S. economy would be adversely affected by controls on GHG emissions from power plants. At the same time, national and international scientific assessments of climate change have concluded that there is an increasing likelihood of "severe, pervasive and irreversible" GHG-induced impacts. After EPA proposed the CPP in 2014, the agency received more than 4.3 million public comments, the most ever for an EPA rule. EPA responded by making numerous changes to the rule between proposal and promulgation. Congressional and public interest has continued since EPA promulgated the CPP final rule in 2015. This report provides background information about the CAA and GHG emissions from the power sector and highlights some of the major components of EPA's ACE proposal. The topics discussed do not represent an exhaustive list of the proposal's elements. For a more comprehensive analysis of the CPP, see CRS Report R44341, EPA's Clean Power Plan for Existing Power Plants: Frequently Asked Questions , by [author name scrubbed] et al. For an analysis of the CPP's potential impact on the electric power sector, see CRS Report R44265, EPA's Clean Power Plan: Implications for the Electric Power Sector , by [author name scrubbed]. The report does not provide a legal analysis of the actions and legal interpretations proposed in ACE. For a detailed discussion of legal issues, see: CRS Legal Sidebar LSB10198, EPA Proposes the Affordable Clean Energy Rule to Replace the Clean Power Plan , by [author name scrubbed]. CRS Legal Sidebar LSB10199, EPA Proposes New Permitting Test for Power Plant Modifications , by [author name scrubbed]. CRS Report R44480, Clean Power Plan: Legal Background and Pending Litigation in West Virginia v. EPA , by [author name scrubbed]. CRS Legal Sidebar LSB10016, EPA Proposes to Repeal the Clean Power Plan , by [author name scrubbed]. This section provides background information on sources of U.S. GHGs emissions (particularly CO 2 ), CAA Section 111, the CPP, and NSR. Anthropogenic GHG emissions are generated throughout the United States from millions of discrete sources: vehicles, power plants, industrial facilities, households, commercial buildings, and agricultural activities (e.g., soils and livestock). CO 2 emissions from fossil fuel combustion account for the largest percentage (76% in 2016) of total U.S. GHG emissions. Historically, the electricity sector accounted for the largest percentage of U.S. CO 2 emissions from fossil fuel combustion. However, the transportation sector surpassed electricity in 2016. In 2017, the transportation sector accounted for 37% and the electricity sector accounted for 34% of U.S. CO 2 emissions from fossil fuel combustion. In previous decades (1973-2010), CO 2 emissions from electricity generation followed an upward course—similar to electricity generation levels in the same time period, as illustrated in Figure 1 . In 2010, their courses diverged. Although electricity generation has remained relatively flat in recent years (2010-2017), CO 2 emissions have generally continued to decline. In 2017, electricity generation was equivalent to generation levels in 2010, while CO 2 emissions were 23% below 2010 levels. Multiple factors impact CO 2 emission levels from the electricity sector. One key factor in CO 2 emission levels is the electricity generation portfolio. Electricity is generated from a variety of sources in the United States. Some sources—nuclear, hydropower, and some renewables—directly produce no CO 2 emissions with their electricity generation. Fossil fuels, on the other hand, generate different amounts of CO 2 emissions per unit of generated electricity. For example, natural-gas-fired electricity from a combined cycle unit yields approximately 43% of the CO 2 emissions of coal-fired electricity per kilowatt-hour of electricity. Therefore, shifting the U.S. electricity generation portfolio to lower emissions sources would likely have (all else being equal) a considerable impact on CO 2 emissions from the electricity sector, which in turn, would likely reduce total U.S. GHG emissions. As illustrated in Figure 2 , recent changes in the U.S. electricity generation portfolio between 2005 and 2017 have played a key role in electric power emission levels: Coal's contribution to total electricity generation decreased from 50% to 30%. Natural gas's contribution to total electricity generation increased from 19% to 32%. Non-hydro renewable energy (wind and solar) generation increased from 2% to 10%. Structural changes in the electricity sector are likely playing a role in the electricity generation portfolio changes described above. Over the last decade (2007-2017), the electricity-generating capacity (measured in megawatts) of coal-fired power plants has decreased by 19%, while natural gas capacity has increased by 45%, and (non-hydro) renewable sources has increased by 445%. If these recent changes in the electricity generation portfolio continue, U.S. CO 2 emissions may continue to decline as well—assuming the emission levels in other economic sectors, particularly the transportation sector, do not offset the reductions. As discussed in the section " CO2 Emissions Projections " below, recent analyses of CO 2 emissions project further declines in the near term under baseline scenarios. CAA Section 111 requires EPA to establish nationally uniform, technology-based standards for categories of industrial facilities, also referred to as stationary sources of air pollution. These standards establish a consistent baseline for pollution control that competing firms must meet and thereby remove any incentive for states or communities to weaken air pollution standards in order to attract industry. They also conserve clean air to accommodate future growth as well as for its own benefits. CAA Section 111(b) establishes maximum emission levels (called New Source Performance Standards, or NSPS) for new and modified major stationary sources—power plants, steel mills, and smelters, for example. The emission levels are determined by the best system of emission reduction (BSER) "adequately demonstrated," taking costs and any non-air-quality health and environmental impacts and energy requirements impacts into account. Section 111 directs EPA to determine what constitutes the BSER. Section 111 also addresses existing stationary sources of pollution. Section 111(d) requires EPA to promulgate regulations, which EPA has historically referred to as "emission guidelines." These emission guidelines establish binding requirements that states are required to address when they develop plans to regulate the existing sources in their jurisdictions. In particular, states must establish performance standards for existing sources reflecting the BSER, which is determined by EPA. States, in their plans, provide for their implementation and enforcement of the standards. Similar to Section 110 of the CAA—which requires states to develop and revise implementation plans to achieve EPA's National Ambient Air Quality Standards (NAAQS) and subsequent changes to those standards—Section 111(d) directs EPA to establish state plan "procedures." EPA promulgated these procedures in 1975 and codified them at 40 C.F.R. Part 60, Subpart B. In the CPP, EPA established "emission guidelines for states to follow in developing plans to reduce" GHGs from existing fossil-fuel-fired power plants. Specifically, the CPP set national performance standards for CO 2 emissions from existing fossil-fuel-fired power plants. One national performance applied to existing electric steam generating units (which are mostly coal), and the other applied to existing stationary combustion turbines—for example, natural gas combined cycle (NGCC) units. EPA based these standards on BSER. The agency determined BSER based on three "building blocks": (1) improving the heat rate at coal-fired units, (2) shifting generation to lower-emitting natural gas units, and (3) shifting generation from fossil fuel units to renewable energy generation. The CPP rule also set individual state targets for average emissions from existing power plants based on the CO 2 performance standards. In particular, it set interim targets for the period 2022-2029 and final targets to be met by 2030. Although EPA set state-specific targets, states would determine how to reach these goals. The CPP is the subject of ongoing litigation and has not gone into effect. The Supreme Court in 2016 stayed the implementation of the rule until the lawsuit challenging its legality is resolved. The U.S. Court of Appeals for the District of Columbia Circuit heard oral arguments in the case in September 2016 but agreed to an EPA request to continue to hold the case in abeyance while the agency reviewed the CPP and considered next steps. Upon its review of the CPP and its 2015 legal justification, EPA has now determined that the CPP exceeds its statutory authority based on a change in the agency's legal interpretation of Section 111 of the CAA. Thus, on October 10, 2017, EPA proposed to repeal the CPP. EPA also published an Advanced Notice of Proposed Rulemaking on December 28, 2017, which requested information on a potential replacement to the CPP. The 1977 CAA amendments established NSR, a preconstruction permitting program intended to support attainment of federal air quality standards and also limit air quality deterioration in areas that have met or exceeded federal air quality standards. In general, the NSR program requires the installation of modern pollution controls when new facilities are built or when existing facilities make a change that substantially increases emissions. Owners or operators must obtain an NSR permit before the construction or modification begins. Permit applicants must demonstrate, among other things, that the proposed new source or modification will not violate or worsen a violation of a NAAQS or that, in areas complying with the NAAQS, it will not exceed the increments of increased air pollution allowed under Prevention of Significant Deterioration (PSD) regulations. The CAA defines modern pollution controls as the "best available control technology" (BACT), which would achieve the maximum degree of emissions reductions, taking into consideration energy, environmental, and economic impacts. The way that the CAA applied NSR to existing facilities is described as "grandfathering," meaning that facilities that were in existence before August 7, 1977, were not required to install BACT immediately following enactment of the 1977 CAA amendments. Rather, the NSR provisions did not require existing facilities to install BACT until such facilities made major modifications. This approach was premised in part on an expectation that the "grandfathered" facilities would "either be upgraded or replaced over time and that, whenever changes were made later, existing facilities would install new, cleaner technologies to prevent or control air pollution." Historically, NSR applicability determinations have been contentious and extensively litigated. The CAA broadly defines modification as "any" physical or operational change in a stationary source "that increases the emissions of any air pollutant or results in the emission of any air pollutant not previously emitted." EPA and state air pollution control agencies have interpreted this definition to implement NSR through regulations and policy guidance. EPA's interpretation of modification under the NSR program has been subject to various legal challenges. Since 1974, EPA has construed the term to not include "routine maintenance, repair, and replacement" at a stationary source —despite the CAA's inclusion of "any" physical or operational change that increases emissions in its definition of modification . Courts have long accepted this agency-created exemption as reasonable. For additional discussion about legal interpretations of NSR applicability, see CRS Report R43699, Key Historical Court Decisions Shaping EPA's Program Under the Clean Air Act , by [author name scrubbed]. EPA proposed to replace the CPP with revised emission guidelines for existing fossil fuel steam generating units, which are largely coal-fired units. Specifically, EPA proposed a new BSER for these electric generating units (EGUs) based on heat rate improvement (HRI) measures, discussed below. EPA did not propose a BSER for other types of EGUs, such as stationary combustion turbines, which includes NGCC units. Under the proposal, states would establish unit-specific performance standards based on the list of candidate technologies identified by EPA and other considerations, such as the remaining useful life of the unit. In other words, EPA would not establish a numeric performance standard for steam EGUs, as the agency did as part of the CPP. EPA based the proposal on its finding that the BSER set in the CPP exceeded EPA's statutory authority by using measures that applied to the power sector rather than measures carried out within an individual facility. EPA stated that under Section 111(d), BSER should "be determined by evaluating technologies or systems of emission reduction that are applicable to, at, and on the premises of the facility for an affected source." EPA also proposed revisions to the corresponding emission guidelines in order to clarify the roles of the agency and of states under Section 111(d) and to "provide states with needed time and flexibility to accomplish their role." The ACE proposal would alter the CPP's allocation of tasks for establishing emission standards between EPA and the states. Under ACE, EPA would continue to determine "nationally applicable BSER," but the states would establish numeric performance standards based on source-specific considerations. EPA noted that the CAA directs EPA to allow states to account for source-specific factors, such as the remaining useful life of the source, when developing performance standards. The ACE proposal applies a narrower interpretation of BSER compared to the CPP. Specifically, EPA proposed to define BSER for existing, fossil fuel steam EGUs as on-site HRI. The ACE proposal would limit the BSER for CO 2 emissions to existing fossil fuel steam EGUs, which are largely coal-fired units. While the ACE preamble discusses the BSER based on existing coal-fired EGUs, the proposal's applicability to other existing fossil-fuel-fired steam EGUs—namely natural gas steam units and fuel oil units—is ambiguous. In particular, EPA proposed to define affected EGU as a fossil-fuel-fired "steam generating unit" that exceeds a specified nameplate capacity and base load rating. The ACE preamble specifies that it would not establish BSER for other types of existing EGUs. EPA proposed to exclude integrated gasification combined cycle units and stationary combustion turbines (e.g., NGCC units) from the definition of affected source . EPA stated that it could not establish BSER for these sources because it did not have sufficient information "on adequately demonstrated systems of emission reduction—including HRI opportunities—for existing natural gas-fired stationary combustion turbines." For the CPP, EPA took a broader view of BSER for existing power plants and based it on three "building blocks": (1) HRI at coal-fired EGUs, (2) shifting generation from higher-emitting coal units to lower-emitting NGCC units, and (3) shifting generation from fossil fuel units to renewable energy generation. From these building blocks, the agency established two national CO 2 emission performance standards, one for fossil steam units (e.g., coal-fired units) and one for stationary combustion turbines (e.g., NGCC units). Based on these national standards, EPA calculated emission reduction targets for each state. The CPP allowed states to choose various options to meet those emission targets. The "heat rate" measures the amount of energy that a power plant uses to generate one kilowatt-hour of electricity. A power plant with a lower, more efficient heat rate uses less fuel to generate the same amount of electricity as a power plant with a higher heat rate. Using less fuel per kilowatt-hour may result in lower emissions of CO 2 as well as sulfur dioxide and nitrogen oxides. HRI can also lead to greater use of the more efficient fossil-fuel-fired power plants, which contributes to a "rebound effect." That is, efficiency gains may lead to increased electricity generation by fossil-fuel-fired plants instead of relying on other electricity generation technologies, thereby increasing absolute emissions and, to some extent, offsetting the emission reductions from the HRI. According to EPA, its ACE analysis "indicates that the system-wide emission decreases due to reduced heat rate are likely to be larger than any system-wide increases due to increased operation." In the CPP, EPA raised concerns about the rebound effect—particularly when using an HRI approach in isolation (as is done in the ACE proposal)—and concluded in 2015 that a combined approach using all three building blocks would alleviate such concerns. Specifically, EPA stated that applying building block 1 [HRI at coal-fired EGUs] in isolation can result in a "rebound effect" that undermines the emissions reductions otherwise achieved by heat rate improvements…. [T]he building block 1 measures described below cannot by themselves constitute the BSER because the quantity of emission reductions achieved—which is a factor that the courts have required EPA to consider in determining the BSER—would be of insufficient magnitude in the context of this pollutant and this industry. The potential rebound effect, if it occurred, would exacerbate the insufficiency of the emission reductions. However, applying building block 1 in combination with other building blocks can address this concern. See " CO2 Emissions Projections " later in this report for a more detailed discussion about rebound effects in the context of EPA's CO 2 emission projections under ACE and the CPP. Under ACE, EPA is not proposing specific performance standards for the BSER. EPA stated that the agency is not required to establish a performance standard that "presumptively reflects such degree of emission reduction which is achievable through application of the BSER, as that is appropriately the states' role." Instead, EPA proposed a list of "candidate technologies" of HRI measures that constitute the BSER. States could use this list to establish standards of performance for existing steam-fired units under Section 111(d). Specifically, states would need to evaluate each HRI measure on the candidate technology list to (1) determine which ones are appropriate for each power plant and (2) establish the source-specific "standard of performance that reflects the degree of emission reduction" from application of the technology. The candidate technologies list includes HRI measures that EPA determined were "most impactful." The list of candidate measures, which the agency based partly on a 2009 EPA-funded study, includes steam turbine blade upgrades—which according to EPA, may offer the greatest potential for HRI—seal improvements to reduce air leaks, and use of computer models that can optimize combustion conditions. The proposed rule does not explicitly identify criteria used to classify these particular measures as the "most impactful," though it presents the estimated range of HRI potential for each listed candidate technology. EPA also considered the cost of the candidate technology measures, reporting estimates from the 2009 study. EPA proposes to allow affected sources to use "either BSER technologies or some other non-BSER technology or strategy" to comply with the standards established in the state plan. EPA identified examples of non-BSER technologies that were not on the candidate technologies list, including carbon capture and storage and fuel co-firing (natural gas or certain biomass). EPA noted, however, that the agency "takes no position regarding whether there may be other methods or approaches to meeting such a standard." In ACE, EPA proposes that states have "considerable flexibility" in establishing performance standards generally and "considerable latitude for implementing measures and standards" for affected EGUs specifically. EPA proposes that states may account for various factors, including the remaining useful life of the source, when establishing unit-specific performance standards. Consideration of source-specific factors would allow states to establish less stringent standards "than would otherwise be suggested by strict implementation of the BSER technologies." EPA notes that Congress explicitly identified one factor—remaining useful life of the source—in the CAA and proposes to codify this and other factors in its implementing regulations. These factors include "unreasonable cost of control resulting from plant age, location, or basic process design" and "physical impossibility of installing necessary control equipment." EPA also proposed to allow states to include in their plans "emissions averaging among [affected] EGUs across a single facility" but not between affected and non-affected units or between units at separate facilities. EPA identified several concerns about averaging between affected and non-affected units at the same facility, in particular that it would be "contrary to the intention of the rule which is to focus on reducing the rate at coal-fired EGUs when they run, not to reduce the amount they run." Averaging across existing affected EGUs at a single facility would be consistent with the proposed BSER, according to EPA's determination. However, EPA determined that "legal and practical concerns may weigh against the inclusion of averaging and trading between existing sources" located at different facilities. EPA acknowledged that averaging and trading could provide states flexibility, however, and requested comment on ways to permit trading between affected units without "encouraging generation shifting." EPA's ACE proposal would allow states to determine the appropriate compliance deadlines for affected units based on the standards of performance determined as part of the state plan process (discussed below). That is, EPA proposes that "states will include custom compliance schedules for affected EGUs as part of their state plan." States that choose a compliance schedule extending more than 24 months beyond the submission of the state plan would have to specify "legally enforceable increments of progress for that source" in the state plan. Under the CPP, EPA directed states to establish interim targets that would be measured between 2022 and 2029. The CPP also required states to demonstrate their progress in implementing a gradual application of BSER with "glide paths" that the states identify for reductions in three time periods: 2022-2024, 2025-2027, and 2028-2029. The second action that EPA proposed in ACE would revise the "general implementing" regulations (40 C.F.R. Part 60, Subpart B). Originally promulgated in 1975, these regulations establish procedures for state plans. EPA determined that these regulations "do not reflect section 111(d) in its current form as amended by Congress in 1977, and do not reflect section 110 in its current form as amended by Congress in 1990." In particular, EPA seeks to codify its current legal interpretation that states have "broad discretion in establishing and applying emissions standards consistent with the BSER." EPA therefore proposed changes that would, among other things, revise some definitions, lengthen the time for development and review of state plans, add a step for EPA to determine whether state plan submissions are complete, and modify a variance provision. EPA proposed to codify the revised implementing regulations in a new subpart—40 C.F.R. Part 60, Subpart Ba. Subpart Ba would apply to the proposed ACE emission guidelines for affected EGUs and corresponding state plans as well as any future emission guidelines and associated state plans issued under Section 111(d). EPA proposed to redefine the phrase emission guideline as a "final guideline document" to reflect the agency's current interpretation that Section 111 does not require EPA to establish a presumptive standard. The current regulations define emission guideline as a "guideline set forth in subpart C of this part, or in a final guideline document published under §60.22(a)." EPA concluded that the current regulatory definition has "arguably required EPA to provide a presumptive emission standard"—that is, a standard that reflects the degree of emission limitation achievable through BSER application. EPA determined that nothing in CAA Section 111(a)(1) or Section 111(d) "compels EPA to provide a presumptive standard." Moreover, the agency regards a presumptive standard as a potential limitation, because it "could be viewed as limiting a state's ability to deviate from the prescribed methodology." EPA proposed instead to provide "information" about the emission limit that could be achieved. EPA also proposed to replace the term emission standard with performance standard . The current regulations, which EPA promulgated in 1975, reflect the CAA of 1970 (P.L. 91-604), which required state plans to include "emission standards" for existing sources. EPA has since twice amended the regulatory definitions, including for emission standards . Congress replaced " emission standards " with standard of performance in the CAA amendments of 1977 ( P.L. 95-95 ). While EPA has since amended some of the definitions in this section, the agency stated that it has not revised the regulations to reflect the "standard of performance" terminology from the CAA amendments of 1977. EPA proposed to lengthen the time periods for the development and review of state plans as well as federal plans under Section 111(d). EPA cited workload considerations as one reason for lengthening the timelines. EPA also stated that it proposed this change in order to be consistent with the timelines for development and review of state implementation plans and federal implementation plans under Section 110. The existing regulations require state plans to be submitted to EPA within nine months after publication of a final emission guideline unless otherwise specified in an emission guideline. For example, the CPP required each state to submit an initial state plan within 13 months, at which time the state could seek a two-year extension for the submittal of its final plan. EPA is proposing to provide states with three years after the notice of the availability of the final emission guideline to adopt and submit a state plan to EPA. The existing regulations provide EPA four months after the submittal deadline to review the state plan submissions. EPA's proposal would give the agency six months to determine whether a state plan is complete. Once the EPA made a determination of completeness, the agency would have 12 months to review the state plan. The completeness determination would be a new addition to the Section 111(d) implementing regulations. EPA proposed 14 criteria—eight items pertaining to administrative issues and six items pertaining to the state plan's technical support—that the agency would consider to determine whether the state plan is complete. Finally, if states do not submit an approvable state plan, EPA would promulgate a federal plan. The current regulations direct EPA to promulgate a federal plan six months after the state's submittal deadline. EPA proposed that the agency would have two years to promulgate a federal plan after finding that a state has failed to submit a complete plan or after EPA disapproves a state plan. The current implementing regulations specify that state plans for health-based pollutants must be as stringent as the emission guideline established by EPA unless the state demonstrates, on a case-by-case basis, that a source meets certain factors. This so-called variance provision would allow a state to apply less stringent standards for health-based pollutants if the state demonstrates any of the following factors: Unreasonable cost of control resulting from plant age, location, or basic process design; Physical impossibility of installing necessary control equipment; or Other factors specific to the facility (or class of facilities) that make application of a less stringent standard or final compliance time significantly more reasonable. Under ACE, EPA proposed a new variance provision that includes these three factors verbatim but also explicitly accounts for a statutory factor—the remaining useful life of the source. Under ACE, EPA proposed to revise the test used to determine whether physical or operational changes to an EGU constitute a "major modification" that triggers NSR. The proposed revision would not be mandatory. Rather, states would have the option to decide whether to incorporate it into state regulations. EPA expects that the proposed NSR revision would "help prevent NSR from being a barrier to the implementation of efficiency projects at EGUs" for states that adopt the new applicability test. The current test for NSR permits, which is codified in the NSR regulations, requires consideration of emissions increases on an annual basis. EPA proposed to consider whether the modification at an existing EGU would increase emissions on an hourly basis. Under ACE, NSR would not be triggered if the modification to an existing EGU does not increase emissions on an hourly basis. These EGUs would not be required to install additional pollution controls, even if the modification leads to an increase in the annual emissions. EPA acknowledged that adoption of HRI measures could increase a facility's annual emissions despite the decrease in the hourly rate of emissions. For example, EGUs that adopt HRI measures may operate more efficiently, which in turn may lower their operating costs. The reduced operating costs may lead these units to be dispatched for more hours in a year, thereby increasing emissions on an annual basis. Under existing law, the higher annual emissions may trigger the NSR process. Under ACE, however, the annual emissions would not be considered in states that adopt the revised NSR test. That is, facilities in those states would not be required to consider the potential increase in annual emissions, provided the hourly rate of emissions does not increase. EPA explained the basis for the proposed NSR revision partly as a way to facilitate "prompt implementation of a revised CAA Section 111(d) standard for EGUs." EPA stated that "over the years, some stakeholders have asserted that the NSR rules discourage companies" from implementing energy efficiency projects. Other stakeholders, however, have suggested that the proposed NSR revision has broader implications for the energy and air quality programs. For example, one state agency described ACE as "a significant overhaul" of NSR that would increase the number of "projects that are excluded from requirements to install reasonable controls," thereby allowing "poorly controlled and grandfathered sources to continue to operate without cost-effective controls." Moreover, it is uncertain how the proposed NSR revision would affect each state's air quality objectives. In general, it is difficult to discern the incremental effect of the proposed NSR change from the scenarios that EPA analyzed. As a result, the extent to which the proposed NSR provisions contribute to the estimated emissions changes and the associated projections of air quality impacts is unclear. EPA conducted air quality modeling—based on the agency's estimated emission changes under several implementation scenarios—and projected that ACE would increase ambient concentrations of particulate matter and ozone in some areas relative to the CPP. While EPA's air quality modeling did not identify areas that would experience a change in attainment status as a result of ACE, these projections do not account for potentially important factors, such as implementation decisions made at the state level. For example, the extent to which the actual impacts diverge from the agency's projections will depend in part on "a variety of federal and state decisions with respect to NAAQS implementation and compliance, including [PSD] requirements." In addition, EPA's analysis did not account for federal initiatives that may extend the life of coal-fired power plants beyond planned retirement dates. That is, actual emissions under ACE could be higher than estimated emissions if the coal-fired power plants that were assumed to retire in EPA's analysis continue operating beyond planned retirement dates. The ACE proposal does not repeal or otherwise change CO 2 performance standards for new and modified power plants, sometimes referred to as the "111(b) standards." Once EPA lists a source category, such as fossil-fuel-fired EGUs, Section 111(b) requires EPA to establish NSPS for new and modified sources within a listed source category. Once EPA promulgates NSPS under Section 111(b) for new or modified sources in that category, EPA is to require the states, under 111(d), to submit plans establishing standards of performance for existing sources that would be subject to NSPS if they were new, unless the sources or the pollutants regulated by the NSPS are already subject to standards under other sections of the act. EPA promulgated the performance standards for new power plants in 2015 under CAA Section 111(b)—the "111(b) rulemaking"—concurrent to the 111(d) standards for existing plants in the CPP. Although the performance standards for new power plants remain in effect, EPA stated that it is "currently considering revising" them. In 2009, EPA made two findings under CAA Section 202: (1) that GHGs currently in the atmosphere potentially endanger public health and welfare and (2) that new motor vehicle emissions cause or contribute to that pollution. (Collectively, these findings are known as the "endangerment finding.") The endangerment finding triggered EPA's duty under CAA Section 202(a) to promulgate emission standards for new motor vehicles. In the 2015 NSPS rule for new and modified power plants, EPA concluded that it did not need to make a separate endangerment finding under Section 111, which directs EPA to list categories of stationary sources that cause or contribute significantly to "air pollution which may reasonably be anticipated to endanger public health or welfare." EPA reasoned that because EGUs had been listed previously under Section 111, it was unnecessary to make an additional endangerment finding for a new pollutant emitted by a listed source category. The agency also argued that, even if it were required to make a finding, EGUs would meet that endangerment requirement given the significant amount of CO 2 emitted from the source category. The ACE proposal does not reconsider EPA's 2009 GHG endangerment finding or the conclusions related to the endangerment finding in the 2015 NSPS for new and modified power plants. EPA clarified that ACE is "not re-opening any issues" related to the trigger for power plant CO 2 standards under Section 111. Without reconsidering the GHG endangerment finding, EPA appears to have a continuing obligation to limit emissions of CO 2 from power plants and other sources. EPA estimated the emission changes and the monetized benefits and costs under four scenarios, comparing each one to a baseline that assumed implementation of the CPP. The first scenario—the "No CPP" scenario—modeled a world without either the CPP or the ACE proposal. The remaining three scenarios considered implementation of the ACE proposal and modeled different levels of HRI at corresponding levels of assumed capital costs at affected coal-fired EGUs in the contiguous United States. EPA explained that data limitations required the agency to assume a uniform level of HRI and capital cost within each ACE scenario rather than modeling a "more customized HRI and cost functions to specific units." EPA projected that power sector emissions of CO 2 , SO 2 , and NO x would increase under the ACE proposal compared to the CPP. For example, compared to the CPP in the year 2030, EPA estimated that CO 2 emissions would increase 3% (47 million short tons to 61 million), SO 2 emissions would increase 5.0-5.9% (45,000 short tons to 53,000), and NO x emissions would increase 4.1-5.0% (32,000 short tons to 39,000) in the year 2030 under each of the ACE scenarios. EPA also projected that ACE would, in most scenarios, decrease CO 2 , SO 2 , and NO x emissions compared to a baseline without the CPP. For example, compared to a baseline without the CPP in the year 2030, EPA estimated that CO 2 emissions would decrease 1% (13 million short tons to 27 million), SO 2 emissions would decrease 0.7-1.6% (7,000 short tons to 15,000), and NO x emissions would decrease 1.0-1.8% (8,000 short tons to 15,000) in 2030 under ACE. EPA also compared this No-CPP baseline to a CPP implementation scenario, which showed that CO 2 emissions would decrease 4% (74 million short tons), SO 2 emissions would decrease 6.3% (60,000 short tons), and NO x emissions would decrease 5.7% (47,000 short tons) in 2030. In sum, EPA's projections show that, compared to a world without the CPP, ACE would generally reduce CO 2 , SO 2 , and NO x emissions, but the reductions are lower than those projected for the CPP. As discussed below, however, the emissions estimates for the ACE scenarios are particularly uncertain given the "considerable uncertainty regarding the specific technology measures that might be applied by States." This section compares projections of CO 2 emissions from each of the scenarios EPA modeled in its 2018 proposed rule and emission projections from other organizations. EPA's ACE proposal and its supporting documents contain estimates of CO 2 emission projections in future years for several different scenarios, including: No CPP. This scenario models a repeal of the CPP without any replacement. It assumes that none of the affected sources adopt HRI. CPP . This scenario, which EPA refers to as its baseline scenario, assumes states use their mass-based targets to comply with the 2015 CPP. In particular, EPA assumes intrastate trading between covered sources but no incremental demand-side energy efficiency investments. CPP with demand-side energy efficiency. 152 This scenario is the same as the above CPP scenario, except that it assumes that demand-side energy efficiency measures are undertaken as a compliance option under the CPP framework. ACE ( 2% HRI at $50/kilowatt ). This scenario models "modest improvements" in HRI in the absence of the NSR revisions also proposed in ACE. The model required each affected coal-fired EGU to improve its heat rate by 2% at a capital cost of $50 per kilowatt. The model allowed a source to either adopt the improvement or retire, depending on the economics of either option. ACE ( 4.5% HRI at $50/kilowatt) . This scenario assumes implementation of the proposed NSR revisions and, at each source, models a 4.5% HRI at a capital cost of $50 per kilowatt. The model allowed a source to either adopt the improvement or retire, depending on the economics of either option. ACE (4.5% HRI at $100/kilowatt) . This scenario assumes implementation of the proposed NSR revisions and, at each source, models a 4.5% HRI at a capital cost of $100 per kilowatt. The model allowed a source to either adopt the improvement or retire, depending on the economics of either option. EPA's CO 2 projections show that, compared to a world without the CPP, ACE would generally reduce CO 2 emissions, but the reductions are lower than those projected for the CPP. See Figure 3 , which indicates that EPA's projected CO 2 emissions are generally lower than recent historical emissions. Figure 3 also presents a magnified view of EPA's scenario projections in the subset box, which shows that CO 2 emissions do not vary much under the different ACE scenarios. While uncertainty is inherent in any projection, the emission estimates for the ACE scenarios may contain more uncertainty than the estimates for the CPP. The CPP would establish unit-specific, federally enforceable performance standards underpinning the state-specific emission rate and emission reduction targets. In contrast, the ACE proposal would not establish a numeric performance standard for coal-fired EGUs. The proposed rule authorizes states to determine performance standards at individual EGUs based on the technology options identified in EPA's proposed rule (i.e., BSER) and other considerations, such as the remaining useful life of the unit. EPA states that "affected sources may not be able to apply the technology options because they have already adopted these technologies, they are not applicable to the source, or for other reasons." For these reasons, EPA states that HRI outcomes of the proposed rule contain "considerable uncertainty." Another factor in the uncertainty of the emissions projections involves the "rebound effect." As discussed above (see " HRI and Potential Emission Impacts "), EPA raised concerns about the rebound effect in its 2015 CPP final rule, stating that "improved competitiveness and increased generation at the EGUs implementing heat rate improvements could weaken or potentially even eliminate the ability of building block 1 [i.e., HRI] to achieve CO 2 emission reductions." However, in its 2018 proposed rule, EPA stated that its "analysis indicates that the system-wide emission decreases due to reduced heat rate are likely to be larger than any system-wide increases due to increased operation." A Resources for the Future study examined the emission impacts of the rebound effect with an "inside the fence line" approach and found that implementing an average fleet-wide HRI of 4% at coal-fired power plants could reduce CO 2 emissions at power plants by 2.6% in 2030 compared to a no-policy baseline scenario. The study pointed out that this result was a national estimate and that eight states would see CO 2 emission increases (and corresponding increases in co-pollutants) at their power plants in 2030 (compared to a baseline scenario). A more recent Resources for the Future analysis of rebound effects noted that the agency's analysis did not account for federal energy sector initiatives that may extend the life of coal-fired power plants beyond planned retirement dates. That is, actual emissions under ACE could be higher than estimated emissions if the coal-fired power plants that were assumed to retire in EPA's analysis continue operating beyond planned retirement dates. As of October 2018, CRS is unaware of analyses other than the EPA's that model the ACE proposal and examine potential rebound effects. In recent years, other organizations have prepared CO 2 emissions projections, comparing policy scenarios with and without the CPP. Selected results from the 2018 proposed rule and other groups are identified in Table 1 . The emission estimates in Table 1 include (1) electricity sector CO 2 emission projections for 2030 and (2) the percent reduction in 2030 compared to 2005 electricity sector CO 2 emission levels. Observations regarding the CO 2 emissions percentage reduction in 2030 compared to 2005 emissions levels include the following: Compared to the other studies, the emissions projections from EPA's 2018 ACE proposed rule display a more narrow range across the policy scenarios EPA modeled. For example, the CPP and non-CPP scenarios differ by 2% (4% with the CPP demand-side efficiency scenario). The estimated percentage emission reductions between the ACE proposed HRI scenarios and the CPP and non-CPP scenarios range between 0% and 1%. The emission reduction differences between CPP and non-CPP scenarios are greater in the studies from earlier years. For example, a comparison between CPP and non-CPP scenarios from the past three EIA analyses shows the percentage difference has decreased from 16% (in 2016) to 8% (in 2018). This reflects the fact that many of the changes EPA expected to result from the CPP (e.g., natural gas and renewables replacing coal-fired units) have already happened as the result of market forces in the electric power sector. The reference case scenarios in more recent studies project significantly lower emissions in 2030 when compared to earlier studies. For example, the reference case in the 2015 EPA analysis projected an emission reduction of 16% below 2005 levels in 2030, while the 2018 EPA analysis projected an emission reduction of 32% below 2005 levels in 2030. As EPA notes in its 2018 analysis, "over the past few years, the power sector has changed notably." In particular, EPA's 2015 projections do not include the renewable energy tax extensions enacted in December 2015. Comparisons between the projections in Table 1 should be made with caution for several reasons. Models from different organizations may include different assumptions about future economic conditions and underlying energy inputs (e.g., natural gas prices). As noted above, the underlying conditions have changed considerably in the past few years. There is also uncertainty related to factors previously discussed, including potential rebound effects and about which technology measures would be adopted under ACE. A comparison between CO 2 emissions projections and actual CO 2 emissions illustrates the uncertainties of emission projections. Figure 4 compares actual U.S. CO 2 emissions between 1990 and 2017 with selected EIA emission projections made in past years. In general, actual emissions have remained well below projections. For example, the AEO from 2006 projected that CO 2 emissions would be almost 6.9 billion metric tons in 2017, about 33% higher than observed emissions. Compared to the current regulation—which is the CPP—the ACE proposal would reduce compliance costs but would also yield lower emission reductions, thereby increasing the climate-related damages (forgone benefits) and human health damages (forgone benefits). EPA's analysis shows that the estimated value of the forgone benefits would outweigh the compliance cost savings when replacing the CPP with ACE, yielding net costs. Specifically, EPA estimated that the net costs of replacing the CPP with ACE range from $12.8 billion to $72.0 billion (2016 dollars) over a 15-year period (2023-2037). These estimates account for forgone benefits—the forgone domestic climate benefits and the forgone co-benefits—that is, the human health benefits from emission reductions not targeted by either ACE or the CPP: SO 2 and NO x emissions. EPA's analysis also shows that repealing and not replacing the CPP would yield net costs ranging from $14.8 billion to $76.2 billion (2016$) over a 15-year period (2023-2037). This range accounts for forgone domestic climate benefits and forgone human health co-benefits. Consideration of co-benefits and other indirect impacts is typically viewed as a principle of benefit-cost analysis and consistent with federal guidance. In particular, OMB Circular A-4 directs agencies to "look beyond the direct benefits and direct costs" of a rulemaking and quantify and monetize co-benefits as well as adverse impacts not already considered in the direct cost estimates. Likewise, EPA's Guidelines for Preparing Economic Analyses recommends that the agency's economic analysis "include directly intended effects and associated costs, as well as ancillary (or co-) benefits and costs." EPA excludes the forgone human health co-benefits from some of the benefit-cost comparisons. EPA explained these comparisons as a way to consider the benefit of reducing the "targeted pollutant" (CO 2 ) against the compliance cost. The estimated compliance costs are the same regardless of whether EPA counts the human health co-benefits. Therefore, the benefit-cost comparisons that exclude the co-benefits show a lower net impact—that is, they weigh a lower estimate of the forgone benefits against compliance cost savings. Specifically, the exclusion of forgone human health co-benefits from these comparisons yields estimates that range from net costs to net benefits. These benefit-cost comparisons, which are limited to compliance cost savings and forgone domestic climate benefits—range from a net cost of $5.4 billion to a net benefit of $3.4 billion over a 15-year period (2023-2037). In addition, repealing without replacing the CPP appears more favorable when EPA excludes the forgone human health co-benefits. Under this scenario, the estimated present value of repealing the CPP ranges from a net benefit of $1.2 billion to $2.7 billion (2016$) over a 15-year period (2023-2037). EPA also compares the three ACE scenarios to an alternative baseline that does not include the CPP. When EPA excludes the forgone human health co-benefits, these comparisons yield present value estimates that range from a net cost of $6.6 billion to a net benefit of $2.0 billion (2016$) over a 15-year period (2023-2037). The net cost figure signifies that the estimated value of the forgone domestic climate benefits outweighs the estimated compliance cost savings. The net benefit figure signifies that the estimated compliance cost savings outweigh the estimated value of the forgone domestic climate benefits. While these comparisons provide some perspective on the potential effects of ACE (separate from the CPP), the scenario design makes it difficult to discern the incremental effect of key components of the ACE proposal. EPA designed two of the ACE scenarios to account for "benefits from the proposed revisions to NSR." The third ACE scenario does not. The level and cost of HRI improvements also vary among the three scenarios, making it difficult to understand how much the proposed NSR revisions and assumed level of HRI affects the benefit-cost estimates.

Summary: In August 2018, the U.S. Environmental Protection Agency (EPA) proposed three actions in the "Affordable Clean Energy Rule" (ACE). First, EPA proposed to replace the Obama Administration's 2015 Clean Power Plan (CPP) with revised emission guidelines for existing fossil fuel steam electric generating units (EGUs), which are largely coal-fired units. Second, EPA proposed revised regulations to implement emission guidelines under Clean Air Act (CAA) Section 111(d). Third, EPA proposed to modify an applicability determination for New Source Review (NSR), a CAA preconstruction permitting program for new and modified stationary sources. The first action stems from EPA's finding that the CPP exceeded EPA's statutory authority by using measures that applied to the power sector rather than measures carried out within an individual facility. In the ACE rule, EPA proposed to base the "best system of emission reduction" (BSER) for existing coal-fired EGUs on heat rate improvement (HRI) measures. EPA did not propose a BSER for other types of EGUs, such as natural gas combined cycle units. In addition, EPA did not establish a numeric performance standard as the agency did in the CPP. Instead, EPA proposed a list of "candidate technologies" of HRI measures that constitute the BSER. States would establish unit-specific performance standards based on this list and other unit-specific considerations. Second, EPA proposed to revise the general implementing regulations to clarify EPA's and states' roles under Section 111(d) based on the agency's current legal interpretation that states have broad discretion to establish emissions standards consistent with the BSER. The proposed changes would, among other things, revise definitions and lengthen the time for development and review of state plans. Third, EPA proposed to revise the NSR applicability test for EGUs. According to EPA, this would prevent NSR from discouraging the installation of energy efficiency measures. EGUs that adopt HRI measures and operate more efficiently may be used for longer time periods, thereby increasing annual emissions and potentially triggering NSR. Under ACE, NSR would not be triggered if the EGU modification did not increase emissions on an hourly basis, even if the modification increases annual emissions. EPA estimated emission changes under multiple scenarios. EPA projected that power sector emissions of carbon dioxide (CO2), sulfur dioxide (SO2), and nitrogen oxides (NOx) would increase under the ACE proposal compared to the CPP. EPA also projected that ACE would, in most scenarios, decrease CO2, SO2, and NOx emissions compared to a baseline without the CPP. Power sector emissions projections, comparing CPP and non-CPP scenarios, provide context for evaluating the potential impacts of the ACE proposal. The CO2 emission reduction differences between CPP and non-CPP scenarios are greater in the studies from earlier years. For example, a comparison between CPP and non-CPP scenarios from the past three Energy Information Administration analyses shows that the percentage difference has decreased from 16% (in 2016) to 8% (in 2018), reflecting the fact that many of the changes EPA expected to result from the CPP (i.e., natural gas and renewables replacing coal-fired units) have happened already due to market forces and other factors. Comparisons between modeling projections of electricity sector CO2 emissions should be made with caution, however, given potential differences in modeling assumptions about future economic conditions and underlying energy inputs (e.g., natural gas prices). EPA estimated that compared to the CPP, ACE would reduce compliance costs and yield lower emission reductions, thereby increasing climate-related damages and human health damages ("forgone benefits"). According to EPA, the estimated value of the forgone benefits would outweigh the compliance cost savings when replacing the CPP with ACE, yielding net costs. Specifically, EPA estimated that this replacement would yield net costs ranging from $12.8 billion to $72.0 billion (2016$) over a 15-year period (2023-2037). Excluding forgone human health co-benefits from these comparisons yields estimates that range from a net cost of $5.4 billion to a net benefit of $3.4 billion over a 15-year period (2023-2037).