The EPA proposes that these same notice, recordkeeping, and reporting requirements would apply to the 30-year averaging compliance option. The EPA requests comment on whether any alterations or additions are appropriate for the notice, recordkeeping, and reporting requirements that would apply to the 30-year averaging compliance option. The EPA also requests comment on whether sources that utilize the 30-year averaging compliance option should include, as applicable requirements in their title V permits, a specific explanation of their compliance plan, including when CCS would be deployed, what capture rate(s) would be achieved, how the CO2 would be sequestered, and whether the company anticipates receiving government financial assistance or other incentives for the CCS.
IV. Rationale for the Proposed Standards for New Sources
A. How did the EPA establish the emission limits?
1. Rationale for Proposing to Combine the Subpart Da Category and a Component of the Subpart KKKK Category into a New Category for Purposes of Regulating GHG Emissions
      The EPA is proposing to create a new subpart in 40 CFR part 60 by combining the sources in subpart Da (the Da category) and a subset of the sources in subpart KKKK (the KKKK category)  -  -  stationary combined cycle units, but not stationary simple cycle units -- for purposes of promulgating standards of performance for emissions of GHGs from new sources. This new subpart will be numbered TTTT. Consistent with standard practice and Executive Order 13563, and in particular its emphasis on "the open exchange of information and perspectives" and "providing an opportunity for public comment on all pertinent parts of the rulemaking docket, including relevant scientific and technical findings" and on consideration of alternatives, we invite comments on our decision to combine the two source categories.
      At this time, the EPA is not proposing to subcategorize new sources and is not proposing to combine the Da category and components of the KKKK category for purposes of regulating criteria pollutants.

      CAA section 111 provides legal authority for combining the categories into a new category. Clean Air Act section 111(b)(1)(A) provides:
      The Administrator shall, within 90 days after December 31, 1970, publish (and from time to time thereafter shall revise) a list of categories of stationary sources. He shall include a category of sources in such a list if in his judgment it causes or contributes significantly to air pollution which may reasonably be anticipated to endanger public health or welfare.
(Emphasis added.)
As quoted, this provision grants to the Administrator the authority to "revise" the list of categories. Combining categories, in whole or in part, is a form of "revis[ing]" the list of categories (along with taking other actions, such as adding more categories or delisting categories), and accordingly is authorized.
      For three principal reasons, it is appropriate for the EPA to combine the Da category and the stationary combined cycle component of the KKKK category at this time for purposes of regulating GHGs. First, all of the plants covered by the new combined category (including fossil fuel-fired boilers, IGCC units and NGCC units) perform the same essential function, which is to provide generation to serve baseload or intermediate load demand. It is sensible to treat as part of the same category units that generate baseload or intermediate load electricity, regardless of their design or fossil fuel type.
      Second, all newly constructed sources have options in selecting their design (although it is true that natural gas-fired plants are inherently lower emitting with regard to CO2 than coal-fired plants. As a result, prospective owners and operators of new sources could readily comply with the proposed emission standards by choosing to construct a NGCC unit. These two factors provide sufficient legal rationale for the EPA to combine the Da category and the combined cycle component of the KKKK category for purposes of establishing a standard of performance for GHG emissions.
      The agency has previously combined one type of baseload and intermediate load combined cycle unit (IGCC, previously covered under Subpart GG) with Da units for the purposes of setting a standard [40 CFR 60.41Da(b), Feb. 28, 2005]. This action now similarly combines another type of baseload and intermediate load combined cycle unit (NGCC, previously covered under Subpart KKKK) with Subpart Da units for the purposes of setting a standard.
      A third factor lends additional support. Combining the categories does not raise adverse policy concerns. On the basis of comments made during the listening sessions, we anticipate that some commenters may question whether combining the categories and applying the NGCC standard to all new plants within the combined category may limit construction of new coal-fired power plants, and thereby have a disruptive effect on the electric power industry, increase electricity prices and/or have adverse implications for energy diversity in new generation. We do not believe that this action would have those effects. As discussed below, and importantly, economic models forecast no new construction of coal-fired generation without CCS through the analysis period, which extends until 2020 (when the standard will be revisited). Accordingly, economic conditions are expected to be the main driver precluding, or at least limiting, construction of coal-fired EGUs. Because of those economic conditions, there is a strong independent movement of power plants serving baseload generation toward NGCC. In light of that movement, it is appropriate for the EPA to focus on this technology in developing the standard, rather than subcategorizing and providing a separate standard for new coal units. See Portland Cement Ass'n v. EPA, 665 F.3d 177, 190 (D.C. Cir. 2011) (affirming the EPA's decision not to subcategorize in part because of "the universal movement in the portland cement industry towards adoption of preheater/precalciner technology").
      Notwithstanding these points, we recognize the possibility that a limited amount of new coal-fired construction may nevertheless occur. Today's action would not foreclose construction of new coal-fired EGUs. Rather, the of new coal-fired EGUs that may be expected to be built in the foreseeable future (and for reasons stated above, this is anticipated to be a relatively small number) may install CCS control equipment (if not at the time of construction, then not long thereafter) By doing so, they may achieve the same average CO2 emission rate (at least over time) as a natural gas-fired combined cycle unit. It is reasonable to expect that some coal-fired power plants may be able to implement CCS at the present time, and thereby achieve the 1,000 lb CO2/MWh standard immediately. As noted elsewhere, CCS has been demonstrated to be technologically achievable, and, even though it is costly, there are some State and Federal programs that can make CCS more affordable. Several power companies have announced plans to incorporate CCS at six already permitted coal-fired EGU construction projects in this country (as we discuss below in section V.B., concerning transitional sources). Programs exist that provide some funding for CCS through pilot or other demonstration programs, and we expect those to continue. In addition, we reasonably expect the costs of CCS to decline over time. As discussed below, we are not proposing that CCS does or does not qualify as the "best system of emission reduction" that "has been adequately demonstrated" for new coal-fired power plants. Rather, the feasibility of CCS and its availability for the limited amount of new coal-fired construction that may be expected, means that this action to combine the categories and establish the NSPS at the proposed 1,000 lb CO2/MWh emission limit will not have notable adverse effects on new coal-fired construction or, therefore, on the electric utility industry, electricity prices, or energy diversity. We welcome public comments on this discussion.
      On the other hand, at this time, we do not consider it appropriate to include simple cycle facilities as an affected source in the new 40 CFR part 60, subpart TTTT for GHG emissions from new facilities. The reason for this is that the function of a new simple cycle power plant is different than that of a new combined cycle plant or coal-fired plant. Combined cycle plants and coal-fired plants are typically designed to provide baseload or intermediate-load power, while simple cycle turbines are designed to provide peaking power. Because combined cycle power plants and coal-fired power plants both serve the same purpose and have design options to emit CO2 at similar levels, we believe it is appropriate to combine them. Because peaking turbines operate less and because it would be much more expensive to lower their emission profile to that of a combined cycle power plant or a coal-fired plant with CCS, the EPA does not believe it is appropriate to include them in this source category.
      As noted above, some commenters in the listening sessions did suggest that the EPA not combine the two source categories. The EPA has rejected that option for all the reasons outlined above: 1)Fossil-fuel-fired boilers, combined cycle natural gas units, and IGCC units all serve the same basic function, generating baseload or intermediate load power; 2)the proposed standards can be met by different types of units in the category (NGCC units or coal-fired units with CCS); and 3)it is consistent with industry trends (as further explained elsewhere in this notice: due largely to current and projected gas and coal price trends, new fossil-fuel-fired builds are projected to be natural gas combined cycle units or coal-fired units with CCS supported by federal funding). There is an additional reason for rejecting the option of retaining (and establishing separate standards for) separate source categories. The EPA's analysis (in Section 5.10 of the RIA) suggests that over a wide range of market conditions, constructing a new unit that meets a limit of 1,000 lb CO2/MWh instead of an advanced coal-fired unit without CCS would likely produce net social benefits. For all of these reasons, retaining separate source categories would be unlikely to generate substantial private cost savings, but at the same time, would create the risk of significantly higher GHG emissions and other air pollutants from some new units, resulting, in turn, in higher social costs.
      By the same token, at this time, we do not consider it appropriate to combine the Da category and the combined cycle component of the KKKK category for any pollutants other than GHGs, that is, for criteria pollutants. This is because although coal-fired EGUs have an array of control options for criteria and air toxic air pollutants to choose from, those controls generally do not reduce their criteria and air toxic emissions to the level of conventional emissions from natural gas-fired EGUs.
2. Endangerment and Cause-or-Contribute-Significantly Finding
a. Overview. In today's rulemaking, we propose or solicit comment on alternative interpretations for whether section 111 includes prerequisites to rulemaking that involve an endangerment finding and a cause-or-contribute-significantly finding. By its terms, CAA section 111 provides that once the EPA lists a source category for regulation because the category causes or contributes significantly to air pollution that may reasonably be anticipated to endanger public health or welfare, the EPA then establishes requirements for new sources in that source category. The EPA proposes to interpret these provisions so that it is authorized to promulgate the rulemaking proposed today because it has already determined that both the Da and KKKK source categories cause or contribute significantly to air pollution that may reasonably be anticipated to endanger public health or welfare. The EPA solicits comment on interpreting CAA section 111 in the alternative so as to require (i) an endangerment finding for air pollution not specifically covered by the endangerment finding the EPA made when listing the source category, but that in this case, the EPA's 2009 Endangerment Finding for GHGs under Section 202(a) of the CAA (along with the EPA's 2010 denial of petitions to reconsider (2010 Reconsideration Denial)), fulfills that requirement; and (ii) a cause-or-contribute-significantly finding for air pollutants not specifically covered by the cause-or-contribute-significantly finding the EPA made when listing the source category, and that in this case, the large amounts of CO2 emissions from power plants provide a compelling basis allowing the EPA to propose that finding. The EPA also solicits comment on another alternative, which is interpreting CAA section 111 so as not to require a specific endangerment finding or cause or contribute finding, but simply to require the EPA to establish a rational basis for regulating an air pollutant from a source category. In this case, the EPA's 2009 Endangerment Finding for GHGs and the 2010 denial of petitions to reconsider the Endangerment Finding, as well as the large amounts of CO2 emissions from power plants, provide that rational basis. Finally, as an alternative for the basis for a rational basis determination, the 2010 and 2011 Assessment Reports from the National Academies confirm the Endangerment Finding and the denial of petitions to reconsider.
b. Proposal: Previous Source Category Findings Meet Any Endangerment Prerequisite to Regulation. In this rulemaking, the EPA proposes to interpret CAA section 111 so that we are not required, as a prerequisite to regulating CO2 emissions from EGUs, to issue a new finding as to the health or welfare impacts of GHG air pollution or a finding as to the extent that affected sources contribute to that air pollution.
	Clean Air Act section 111(b)(1)(A), by its terms, requires that the Administrator list a source category for regulation if the "category ...in [the Administrator's] judgment, ... causes or contributes significantly to air pollution which may reasonably be anticipated to endanger public health or welfare." Clean Air Act section 111(b)(1)(B) goes on to provide that after listing the source category, the EPA must promulgate regulations "establishing federal standards of performance for new sources within such category." In turn, CAA section 111(a)(1) defines a "standard of performance" as a "standard for emissions of air pollutants which reflects the degree of emission reduction which (taking into account ... cost ... and any nonair quality health and environmental impact and energy requirements) ... has been adequately demonstrated."
      Thus, although CAA section 111 clearly requires the EPA to list a source category if its emissions contribute significantly to air pollution that endangers public health or welfare, and then to promulgate standards of performance for particular pollutants, section 111 does not by its terms require that the EPA make any endangerment finding with respect to those particular pollutants, or any cause-or-contribute-significantly finding with respect to the source category, at the time the EPA promulgates the standards of performance for those pollutants. The lack of any such requirement contrasts with (i) the definition of "standard of performance," which specifically requires the EPA to consider "nonair quality health and environmental impact," CAA section 111(a)(1) (emphasis added); and (ii) other CAA provisions that do require the EPA to make endangerment and cause-or-contribute findings for the particular pollutant that the EPA regulates under those provisions. E.g., CAA sections 202(a)(1), 211(c)(1), 231(a)(2)(A).
      Accordingly, under our proposal, once the EPA has listed a source category, and the EPA proceeds to regulate particular pollutants from that source category, CAA section 111 does not require that the EPA make an endangerment finding for the relevant air pollution or a cause-or-contribute-significantly finding for the relevant air pollutants from that source category. The fact that the EPA is, in this rulemaking, proposing to partially combine the Da and KKKK source categories does not alter this outcome. As noted above, under CAA section 111(b)(1)(A), the EPA may add a source category to the list of categories only after determining that the source category "causes, or contributes significantly to, air pollution which may reasonably be anticipated to endanger public health or welfare." The EPA has previously determined that each of the Da and KKKK categories causes or contributes significantly to such air pollution. Combining the Da category and some of the sources in the KKKK category does not necessitate that the EPA make a new cause-or-contribute-significantly finding for the expanded Da category. This is because the EPA has already found that at least one component of the new category - -  the former Da sources -- by itself causes or contributes significantly to such air pollution. There is no reason why this expansion of the Da category to include the pre-existing Da sources plus additional sources could be considered to contribute to such air pollution to an extent that is less than the contribution from the pre-existing Da sources alone. As a result, the new category must necessarily be considered to cause or contribute significantly to such air pollution.
	In addition to proposing this interpretation, we also solicit comment on alternative interpretations under CAA section 111, including those described next.
c. First Alternative Interpretation: Endangerment Finding Prerequisite. We solicit comment on an alternative interpretation under which the EPA is required, as a prerequisite to promulgating standards of performance under CAA section 111(b), to have issued an endangerment finding specifically for the relevant air pollution and a cause-or-contribute-significantly finding specifically for the relevant source category and air pollutant. In particular, what would be the legal basis for such an interpretation?
	Even if CAA section 111 is interpreted to require those findings, then, in a case in which the EPA did not make those findings under CAA section 111, it is the EPA's view that the EPA would satisfy the need for a CAA section 111 endangerment finding through an endangerment or comparable finding that the EPA made or that Congress adopted under any other provision of the CAA. For example, the EPA may regulate, under CAA section 111, (i) NAAQS pollutants because of the determinations the EPA made under CAA sections 108 and 109 and (ii) HAPs that Congress listed under CAA section 112(b)(1). It is the EPA's interpretation that once an endangerment or comparable finding is made with respect to the relevant air pollution under another CAA provision, regulation under CAA section 111 of source categories that cause or contribute significantly to that same air pollution may proceed without any need for the EPA to revisit or update that endangerment finding as part of the CAA section 111 regulatory process. Instead, any concerns about the continued validity of that endangerment finding may be resolved through a petition to reconsider that finding under the applicable CAA provision.
      Applying this alternative interpretation of CAA section 111 to this rulemaking, the 2009 Endangerment Finding for GHG air pollution fulfills any requirement under CAA section 111 that the EPA issue a finding that GHG air pollution may reasonably be anticipated to endanger public health or welfare in order for the EPA to establish standards of performance for GHG emissions from EGUs. As discussed above, the EPA already issued this endangerment finding under CAA section 202(a)(1), as part of its process for promulgating the Light Duty Vehicle Rule.
      The EPA recognizes that under this alternative interpretation, the EPA could be required to issue a cause-or-contribute-significantly finding for CO2 emissions from the fossil fuel-fired EGUs, as a prerequisite to regulating such emissions under CAA section 111. Therefore, under this alternative interpretation, in today's rulemaking, the EPA proposes to find that CO2 emissions from fossil fuel-fired EGUs cause or contribute significantly to the GHG air pollution. The EPA's basis for this proposed finding is, in part, that the large amounts of CO2 emitted by fossil fuel-fired EGUs clearly exceed the low hurdle necessary for the cause-or-contribute-significantly finding. As noted above in Tables 2 and 3, fossil fuel-fired EGUs emit almost one-third of all U.S. GHG emissions, and constitute by far the largest single stationary source category of GHG emissions. Indeed, so great is the contribution of CO2 air pollutants from EGUs to GHG air pollution, that it is simply not necessary in this rulemaking to determine thresholds for when a contribution may be considered to be a "significant[]" contribution. If it were necessary, the EPA proposes that a limited amount of contribution would meet that standard in light of the fact that GHG air pollution is caused by a large number of types of sources and that no one source category dominates the entire inventory.
d. Second alternative interpretation: Rational Basis Prerequisite. As a second alternative interpretation, the lack of any requirement in CAA section 111 addressing whether and how the EPA is to evaluate emissions of particular pollutants from sources in the listed source category as a prerequisite for regulation may be viewed as a statutory gap that requires a Chevron step 2 interpretation. In this case, the EPA is authorized to develop an interpretation that reasonably effectuates the purposes of CAA section 111. Under this alternative interpretation, the EPA must demonstrate a rational basis for controlling the emissions of the particular pollutants. That rational basis may consist of some type of factual showing that is consistent with the purposes of CAA section 111, but may be something short of an endangerment and a cause-or-contribute-significantly finding.
      There are several options for the factual showings that comprise a rational basis. Under the first option, the EPA would be justified in the present case in taking action with respect to GHG air pollution because of the EPA's 2009 Endangerment Finding that GHG air pollution may reasonably be anticipated to endanger public health and welfare. The EPA issued that Endangerment Finding quite recently, in December, 2009, and by notice dated August 13, 2010, the EPA denied ten petitions to reconsider that Finding, an action that entailed further review of scientific information.
      Under the second option, the EPA could conclude that the recent Endangerment Finding and denial of reconsideration, coupled with the even more recent assessments from the NAS, published in 2010 and 2011, which lend further credence to the science supporting the Endangerment Finding, suffice to provide a rational basis for promulgating regulations under CAA section 111 designed to address contributions to the GHG air pollution.
      Under either of these options, the EPA would need to establish a rational basis for regulating CO2 emissions from affected EGUs. The fact that affected EGUs emit almost one-third of all U.S. GHGs and comprise by far the largest stationary source category of GHG emissions, as discussed above, would readily provide such a rational basis.
3. Rationale for Emission Limits
a. Few New Coal-fired Power Plants. An important part of the basis for the EPA's proposal for new sources in this rulemaking is that all indications suggest that very few new coal-fired power plants will be constructed in the foreseeable future. Although a small number of new coal-fired power plants have been built recently, the industry generally is not building these kinds of power plants at present and is not expected to do so for the foreseeable future. The reasons include the current economic environment, which has lead to lower electricity demand, and competitive natural gas prices. Natural gas prices have stabilized over the past few years as new drilling techniques have brought additional supply to the marketplace. As a result, natural gas prices are expected to be competitive for the foreseeable future and utilities are likely to rely heavily on natural gas to meet new demand for electricity generation. On average, the cost of generation from a new NGCC power plant is expected to be lower than the cost of generation from a new coal-fired power plant.
      Other drivers that may influence decisions to build new power plants are State and Federal energy and tax policies. Many states have adopted renewable portfolio standards (RPS), which require that a certain portion of electricity come from renewable energy sources like solar or wind. The federal government has also adopted incentives for electric generation from renewable energy sources and loan guarantees for new nuclear power plants.
      These economic, cost, and policy factors create an environment in which natural gas-fired power plants, renewable energy, and nuclear power are the forms of energy generation that are most often predicted to be built to meet new electricity demand over the coming years.
      Various energy sector modeling efforts, including projections from both the EIA and the EPA, show results that are consistent with these findings. The Annual Energy Outlook (AEO) for 2011 shows a very modest amount of new coal-fired power coming online beyond 2012, although there are a number of coal-fired power plants that are currently under construction and expected to begin operation in the next year or two. According to the AEO 2011, the majority of new generating capacity will be either natural gas-fired or renewable, with some lesser amounts of nuclear power. The AEO 2011 is based on existing policy and regulations, such as state RPS programs and Federal tax credits for renewables. The new generation that EIA does show coming on-line after 2012 fits into one of three categories: generation that is currently under construction, generation that will include CCS or industrial CHP. Units in the first group would not be subject to this rule because, since they have commenced construction, they are considered existing sources. Units in the second group would include either units in the transitional category or new units. In either case, they could be built consistent with this action. Units in the third group would not be subject to this rule because CHP units that generate primarily on-site power are not considered EGUs and are thus not affected by the rule.
      The EPA modeling using the Integrated Planning Model (IPM), a detailed power sector model that the EPA uses to support power sector regulations, is keyed to the AEO in a number of respects and shows similar patterns of little future construction of new coal-fired power plants under the base case. The EPA's projections from IPM can be found in the RIA.
      As discussed below, the fact that the expected number of coal-fired power plants is so limited supports both (i) basing the standard of performance on NGCC, which is expected to be the most commonly built new fossil fuel-fired generating technology; and (ii) allowing 30-year averaging as an alternative compliance option for coal- and pet coke-fired power plants because CCS is feasible and sufficiently available for the few such plants expected, in light of the demonstration programs or other incentives available for CCS, coupled with the prospects that the costs of CCS will decline over time.
b. Basis for the Proposed Standard of Performance. In this section, we describe our basis for proposing a standard of 1,000 lb/MWh, and for taking comment on a range of 950 to 1,100 lb/MWh (430 to 500 kg/MWh). We first describe our method for calculating these levels of CO2 emissions, and then note that several states are already requiring these levels of CO2 emissions.
(1) Calculation of the Standard. For reasons explained below (see "d. Legal Justification for the Standard of Performance and 30-year averaging compliance option"), a NGCC facility is the best system of emission reduction for new baseload and intermediate load EGUs. To establish an appropriate, natural gas-based standard, we reviewed the emissions rate of natural gas-fired (non-CHP) combined cycle facilities used in the power sector that commenced operation between 2006 and 2010 and that report complete generation data to EPA. Based on this analysis, nearly 95% of these facilities meet the proposed standards on an annual basis. These units represent a wide range of geographic locations (with differing elevations and ambient temperatures), operational characteristics, and sizes.
      We are requesting comment on a range of 950 to 1,100 lb/MWh (430 to 500 kg/MWh) for the final rule. The upper limit would incorporate essentially all available new combined cycle designs and would have limited impact on improving efficiency of combined cycle facilities. This upper limit would also be consistent with standards promulgated by some states, as noted elsewhere. The stricter standard would in general eliminate designs without a steam reheat cycle and similar lower efficiency designs for use in electric-only generation, and could limit presently available options for generation below approximately 40 MW. However, an owner/operator of combined cycle facilities with higher heat rates could either implement CHP or integrated solar thermal for feedwater heating to achieve the proposed standard.
(2) States Implementing a Comparable Standard. Several states have recently established emission performance standards or other measures to limit emissions of GHGs from new EGUs that are comparable to the proposal in this rulemaking. For example, in September 2006, California Governor Schwarzenegger signed into law Senate Bill 1368. The law limits long-term investments in baseload generation by the state's utilities to power plants that meet an emissions performance standard jointly established by the California Energy Commission and the California Public Utilities Commission. The Energy Commission has designed regulations that establish a standard for new and existing baseload generation owned by, or under long-term contract to publicly owned utilities, of 1,100 lb CO2/MWh.
In May 2007, Washington Governor Gregoire signed Substitute Senate Bill 6001, which established statewide GHG emissions reduction goals, and imposed an emission standard that applies to any baseload electric generation that commenced operation after June 1, 2008 and is located in Washington, whether or not that generation serves load located within the state. Baseload generation facilities must initially comply with an emission limit of 1,100 lb CO2/MWh.
	In July 2009, Oregon Governor Kulongoski signed Senate Bill 101, which mandated that facilities generating baseload electricity, whether gas- or coal-fired, must have emissions equal to or less than 1,100 lb CO2/MWh, and prohibited utilities from entering into long-term purchase agreements for baseload electricity with out-of-state facilities that do not meet that standard. Natural gas- and petroleum distillate-fired facilities that are primarily used to serve peak demand or to integrate energy from renewable resources are specifically exempted from the performance standard.
c. Basis for CCS as a Feasible Technology Option. In this section, we describe the basis for our position that CCS is a feasible technology option for new coal-fired power plants because CCS is technically feasible and sufficiently available in light of the limited amount of new coal-fired construction expected in the foreseeable future. In brief, first, at present, CCS is technologically feasible for implementation at new coal-fired power plants and its core components (CO2 capture, compression, transportation and storage) have already been implemented at commercial scale. Second, although the costs of CCS are presently high, we have reason to expect that the costs of CCS will decrease over time. This action will itself contribute to downward pressure on CCS costs by shifting the regulatory landscape towards CCS, consistent with the recent report by the Interagency Task Force on Carbon Capture and Storage, established by President Obama on February 3, 2010, which we describe below. Third, we expect construction of no more than a few new coal-fired power plants by 2020 and those plants may well be able to take advantage of demonstration programs or other sources of funding for CCS. Fourth, several states have set emission standards that will make implementation of CCS necessary for new coal-fired power plants, some projects that implement CCS or components of it are proceeding, and other CCS projects are in the planning stages.
(1) Technological Feasibility of CCS. The current state of affairs concerning CCS was described and analyzed by the Interagency Task Force on Carbon Capture and Storage, established by President Obama on February 3, 2010, co-chaired by the DOE and the EPA, and composed of 14 executive departments and federal agencies. The Task Force was charged with proposing a plan to overcome the barriers to the widespread, cost-effective deployment of CCS within 10 years, with a goal of bringing five to ten commercial demonstration projects online by 2016. The Task Force found that, although early CCS projects face economic challenges related to climate policy uncertainty, first-of-a-kind technology risks, and the current high cost of CCS relative to other technologies, there are no insurmountable technological, legal, institutional, regulatory or other barriers that prevent CCS from playing a role in reducing GHG emissions. The Task Force also identified the need for comprehensive review of the overall environmental impacts of CCS.
(a) Capture and Compression Technologies and Costs. Capture of CO2 from industrial gas streams has occurred since the 1930s using a variety of approaches to separate CO2 from other gases. These processes have been used in the natural gas industry and to produce food and chemical-grade CO2. Although current capture technologies are feasible, the costs of CO2 capture and compression represent the largest stumbling block to widespread commercialization of CCS. Currently available CO2 capture and compression processes are estimated to represent seventy to ninety percent of the overall CCS costs.
      In general, CO2 capture technologies applicable to coal-fired power generation can be categorized into three approaches:
   * Pre-combustion systems are designed to separate CO2 and H2 in the high-pressure syngas produced at IGCC power plants.
   * Post-combustion systems are designed to separate CO2 from the flue gas produced by fossil-fuel combustion in air.
   * Oxy-combustion uses high-purity O2, rather than air, to combust coal and therefore produces a highly concentrated CO2 stream.
Each of these three carbon capture approaches (pre-combustion, post-combustion, and oxy-combustion) is technologically feasible. However, each results in increased capital and operating costs and decreased electricity output (that is, an energy penalty), with a resulting increase in the cost of electricity. The energy penalty occurs because the CO2 capture process uses some of the energy produced from the plant.
(b) Current Availability of Transportation and Sequestration. The remaining steps for CCS (i.e., pipeline transportation and storage), are also well established but less expensive than capture and compression.
      Carbon dioxide has been transported via pipelines in the U.S. for nearly 40 years. Approximately 50 million metric tons of CO2 are transported each year through 3,600 miles of pipelines. Moreover, a review of the 500 largest CO2 point sources in the U.S. shows that 95 percent are within 50 miles of a possible geologic sequestration site, which would lower transportation costs. For these reasons, the transportation component of CCS is not expected to be a significant stumbling block to the commercial availability of CCS in the future.
      With respect to sequestration, globally, there are at least four commercial integrated CCS facilities sequestering captured CO2 into deep geologic formations and applying a suite of technologies to monitor and verify that the CO2 remains sequestered. These four sites represent over 25 years of cumulative experience on safely and effectively storing anthropogenic CO2 in appropriate deep geologic formations. Estimates based on DOE studies indicate that areas of the U.S. with appropriate geology have a storage potential of 1,800 billion to more than 20,000 billion metric tons of CO2 in deep saline formations, oil and gas reservoirs and un-mineable coal seams. The U.S. experience with large-scale CO2 injection, such as at enhanced oil and gas recovery projects, combined with ongoing research, development, and demonstration programs in the U.S. and throughout the world, provide confidence that the storage  - - along with capture, compression and transport -- of large amounts of CO2 can be achieved.
	It should be noted that the EPA recently finalized two rules that aim to protect drinking water and track the amount of CO2 that is sequestered from facilities that carry out geologic sequestration. The Underground Injection Control (UIC) Class VI rule, established under authority of the Safe Drinking Water Act, sets requirements to ensure that geologic sequestration wells are appropriately sited, constructed, tested, monitored, and closed in a manner that ensures protection of underground sources of drinking water. The UIC Class VI regulations contain monitoring requirements to protect underground sources of drinking water, including the development of a comprehensive testing and monitoring plan. This includes testing of the mechanical integrity of the injection well, ground water monitoring, and tracking of the location of the injected CO2 using direct and indirect methods. Projects are also required to do extended post-injection monitoring and site care to track the location of the injected CO2 and monitor subsurface pressures until it can be demonstrated that underground sources of drinking water are no longer endangered. Subpart RR of the Greenhouse Gas Reporting Program, which was established under authority of the CAA and builds on UIC requirements, provides requirements for quantifying the amount of CO2 sequestered by these facilities. In addition, the EPA recently proposed a rule that would conditionally exclude CO2 streams from the definition of hazardous waste under RCRA, where these streams are being injected for purposes of geologic sequestration, provided that they are managed in accordance with certain conditions. That proposed rule is based upon the EPA's conclusion that the management of CO2 streams, under the proposed conditions, does not present a substantial risk to human health or the environment, and was based upon a review of existing regulatory programs applicable to the transportation of CO2 streams, and their injection into permitted UIC Class VI wells. Together, these actions help create a consistent national framework to ensure the safe and effective deployment of geologic sequestration.
(2) Expected reduction in CCS costs. Research is underway to reduce CO2 capture costs and to improve performance. The DOE/National Energy Technology Laboratory (NETL) sponsors an extensive research, development and demonstration program that is focused on developing advanced technology options that will dramatically lower the cost of capturing CO2 from fossil-fuel energy plants compared to today's available capture technologies. The DOE/NETL estimates that using today's commercially available CCS technologies would add around 80 percent to the cost of electricity for a new pulverized coal (PC) plant, and around 35 percent to the cost of electricity for a new advanced gasification-based (IGCC) plant. The CCS research, development and demonstration program is aggressively pursuing efforts to reduce these costs to a less than 30 percent increase in the cost of electricity for PC power plants and a less than 10 percent increase in the cost of electricity for new gasification-based power plants. The large-scale CO2 capture demonstrations that are currently planned and in some cases underway, under DOE's initiatives, as well as other domestic and international projects, will generate operational knowledge and enable continued commercialization and deployment of these technologies.
      Gas absorption processes using chemical solvents, such as amines, to separate CO2 from other gases have been in use since the 1930s in the natural gas industry and to produce food and chemical grade CO2. The advancement of amine-based solvents is an example of technology development that has improved the cost and performance of CO2 capture. Most single component amine systems are not practical in a flue gas environment as the amine will rapidly degrade in the presence of oxygen and other contaminants. The Fluor Econamine FG process uses a monoethanolamine (MEA) formulation specially designed to recover CO2 and contains a corrosion inhibitor that allows the use of less expensive, conventional materials of construction. Other commercially available processes use sterically hindered amine formulations (for example, the Mitsubishi Heavy Industries KS-1 solvent) which are less susceptible to degradation and corrosion issues. The DOE/NETL and private industry are continuing to sponsor research on advanced solvents (including new classes of amines) to improve the CO2 capture performance and reduce costs.
	Significant reductions in the cost of CO2 capture would be consistent with overall experience with the cost of pollution control technology. A significant body of literature suggests that the per-unit cost of producing or using a given technology declines as experience with that technology increases over time, and this has certainly been the case with air pollution control technologies. Reductions in the cost of air pollution control technologies as a result of learning-by-doing, research and development investments, and other factors have been observed over the decades.
	We expect that the costs of capture technology will follow this pattern. Rubin et al. assessed the historical rates of cost reductions achieved by other energy and environmental process technologies and then, by analogy, estimated future cost reductions that might be achieved by four types of new power plants employing CO2 capture. The results of the study suggested that total costs of CO2 capture can be expected to decline by the following percentages: NGCC by 40 percent, PC by 26 percent, IGCC by 13 percent, and Oxyfuel by 13 percent after installation of the first 100 GW of capacity.
      In a subsequent study, the model used in the initial study was extended with learning curves for several key performance variables, including overall energy loss in power plants, the energy required for CO2 capture, the CO2 capture ratio (removal efficiency) and the power plant availability. The model predicted continued reductions in cost with increased implementation.
      In addition, we note that the Administration's CCS Task Force report recognized that CCS would not become more widely available without the advent of a regulatory framework that promoted CCS or a strong price signal for CO2. Today's action is an important component in developing that framework.
(3) Limited amount of construction of new coal-fired power plants; opportunities for CCS funding. A third factor that supports CCS as a feasible technology option is that through the IPM model period of up to 2020, we expect few, if any, new builds of coal-fired EGUs, beyond those that already have approved PSD permits. We also expect continued opportunities for financial support for some CCS projects through a variety of potential mechanisms such as direct grants, tax incentives and/or regulatory programs (e.g. Clean Energy Standards or guaranteed electricity purchase price agreements). Accordingly, the few new coal-fired generation projects that may occur over this timeframe may well find that financial support for CCS is available.
(4) State Requirements for CCS; Projects and Permits for CCS. Several states have recently established requirements that new coal-fired EGUs must implement CCS, and a number of projects with CCS have been approved and/or are under construction.
      In May 2007, Montana Governor Schweitzer signed House Bill 25, adopting a CO2 emissions performance standard for electric generating units in the state. House Bill 25 prohibits the state Public Utility Commission from approving new electric generating units primarily fueled by coal unless a minimum of 50 percent of the CO2 produced by the facility is captured and sequestered.
      On January 12, 2009, Illinois Governor Blagojevich signed Senate Bill 1987, the Clean Coal Portfolio Standard Law. The legislation establishes emission standards for new power plants that use coal as their primary feedstock. From 2009-2015, new coal-fueled power plants must capture and store 50 percent of the carbon emissions that the facility would otherwise emit; from 2016-2017, 70 percent must be captured and stored; and after 2017, 90 percent must be captured and stored.
	The following is a brief summary of currently operating or planned CO2 capture or storage systems, including, in some cases, components necessary for coal-based power plant CCS applications.
AES's coal-fired Warrior Run (Cumberland, MD) and Shady Point (Panama, OK) power plants are equipped with amine scrubbers developed by ABB/Lummus. They were designed to process a relatively small percentage of each plant's flue gas. At Warrior Run, approximately 110,000 tonnes of CO2 per year are captured, whereas at Shady Point 66,000 tonnes of CO2 per year are captured. The CO2 from both plants is subsequently used in the food processing industry.
At the Searles Valley Minerals soda ash plant in Trona, CA, approximately 270,000 tonnes of CO2 per year are captured from the flue gas of a coal power plant via amine scrubbing and used for the carbonation of brine in the process of producing soda ash.
A pre-combustion Rectisol(R) system is used for CO2 capture at the Dakota Gasification Company's synthetic natural gas production plant located in North Dakota, which is designed to remove approximately 1.6 million tonnes of CO2 per year from the synthesis gas. The CO2 is purified, transported via a 200-mile pipeline, and injected into the Weyburn oilfield in Saskatchewan, Canada.
In September 2009, American Electric Power Co. (AEP) began a pilot-scale CCS demonstration at its Mountaineer Plant in New Haven, WV. The Mountaineer Plant is a 1,300 MWe coal-fired unit that was retrofitted with Alstom's patented chilled ammonia CO2 capture technology on a 20 MWe portion, or "slipstream", of the plant's exhaust flue gas. In May 2011, Alstom Power announced the successful operation of the chilled-ammonia CCS validation project. The AEP-Alstom project, the world's first facility to both capture and store CO2 from a coal-fired power plant, represents a successful scale-up of ten times the size of previous field pilots (e.g., at We Energies Pleasant Prairie). The demonstration achieved capture rates from 75 percent (design value) to as high as 90 percent, produced CO2 at purity of greater than 99 percent, with energy penalties within a few percent of predictions. The facility reported robust steady-state operation during all modes of power plant operation including load changes, and saw an availability of the CCS system of greater than 90 percent.
      AEP, with assistance from the DOE, had planned to expand the slipstream demonstration to a commercial scale, fully integrated demonstration at the Mountaineer facility. The commercial-scale system was designed to capture at least 90 percent of the CO2 from 235 MW of the plant's 1,300 MW total capacity. Plans were for the project to be completed in four phases, with the system to begin commercial operation in 2015. However, in July 2011, AEP announced that it is terminating its cooperative agreement with the DOE and placing its plans to advance CO2 capture and storage technology to commercial scale on hold, citing the current uncertain status of U.S. climate policy and the continued weak economy as contributors to the decision.
Oxy-combustion of coal is being demonstrated in a 10 MWe facility in Germany. The Vattenfall plant in eastern Germany (Schwarze Pumpe) has been operating since September 2008. It is designed to capture 70,000 tonnes of CO2 per year
      In June 2011, Mitsubishi Heavy Industries, an equipment manufacturer, announced the successful launch of operations at a 25 MW coal-fired carbon capture facility at Southern Company's Alabama Power Plant Barry. The demonstration is planned to capture approximately 150,000 tons of CO2 annually at a CO2 capture rate of over 90 percent. The captured CO2 will be permanently stored underground in a deep saline geologic formation.
      Southern Company has begun construction of Mississippi Power Plant Ratcliffe (formerly the Kemper County IGCC Project). Plant Ratcliffe is a 582 MW IGCC plant that will utilize local Mississippi lignite and include pre-combustion carbon capture to reduce CO2 emissions by 65 percent. Operation is expected to begin in 2014. The CO2 captured from Plant Ratcliffe will be used for enhanced oil recovery (EOR) in the Heidelberg Oil Fields in Jasper County, MS.
      The Texas Clean Energy Project, a 400 MW IGCC facility located near Odessa, TX will capture 90 percent of its CO2, which is approximately 3 million tonnes annually. The captured CO2 will be used for EOR in the West Texas Permian Basin. (Additionally, the plant will produce urea and smaller quantities of commercial-grade sulfuric acid, argon, and inert slag, all of which will also be marketed.) Construction is expected to begin in 2012.
d. Legal Justification for the Standard of Performance and 30-year Averaging Compliance Option. This section describes our legal justification for proposing that new affected facilities in the TTTT category  - - which combines the Da and part of the KKKK categories  - - (i) must limit their CO2 emissions to 1,000 lb CO2/MWh, which an affected facility could achieve by constructing a NGCC unit or by constructing a coal-fired boiler that implements CCS immediately; or (ii) in the case of a coal- or pet coke-fired power plant, may either meet the 1,000 lb CO2/MWh standard or implement an 30-year averaging compliance option that allows an affected facility to meet an initial CO2 emission limit of 1,800 lb CO2/MWh (gross), and then  - - through the implementation of CCS -- meet the 1,000 lb CO2/MWh standard, on a time-averaged basis, over no longer than a 30-year period.
(1) Legal Justification for the Standard of Performance. The EPA proposes that the emission limit of 1,000 lb CO2/MWh meets the requirements for a "standard of performance" applicable to new sources under CAA section 111(b)(1)(B). The term "standard of performance" is defined under CAA section 111(a)(1) as follows:
 Definitions. For purposes of this section: (1) The term "standard of performance" means a standard for emissions of air pollutants which reflects the degree of emission limitation achievable through the application of the best system of emission reduction which (taking into account the cost of achieving such reduction and any nonair quality health and environmental impact and energy requirements) the Administrator determines has been adequately demonstrated.

      We apply this definition, in effect, from the bottom up. That is, first, we determine the "best system of emission reduction which (taking into account * * * cost [and other factors]) the Administrator determines has been adequately demonstrated." For EGUs, that is a NGCC facility, for reasons discussed below. Then, we calculate the "degree of emission limitation achievable through the application of" such best system; and after that, we formulate "a standard for emissions of air pollutants which reflects" that degree of emission limitation. This standard is 1,000 lb of CO2/MWh. These analytical steps are also discussed further below.
      In determining the "best system of emission reduction" for this category of boilers and combined cycle units, we considered a range of natural gas-fired and coal-fired generation technologies, with available controls. We considered modern supercritical and ultra-supercritical coal-fired boilers. This technology is available  - - it is currently deployed in Europe and is now being widely deployed in Asia (especially China)  - - and it offers much more efficient operation than the subcritical boilers that have more often been constructed in the U.S. These supercritical and ultra-supercritical boilers have CO2 emissions of approximately 1,800 lb/MWh and provide the lowest overall costs for conventional coal-based electricity. We also considered new IGCC, or "coal gasification" facilities, which can have CO2 emissions levels very similar to those of ultra-supercritical coal-fired units  -  -  albeit at a higher price.
      We also considered natural gas-fired boilers which have CO2 emissions of approximately 1,350 lb/MWh, obviously much lower than the advanced coal-fired or coal gasification technologies. However, it seems unlikely that utilities would choose a natural gas-fired boiler as the generation technology of choice when NGCC is a much more efficient, less expensive, and more widely used technology.
      We propose that a NGCC facility is the best system of emission reduction for two main reasons. First, natural gas is far less polluting than coal. Combustion of natural gas emits only about 50 percent of the CO2 emissions that combustion of coal does per unit of energy generated. Second, new natural gas-fired EGUs are less costly than new coal-fired EGUs, and as a result, our IPM model projects that for economic reasons, natural gas-fired EGUs will be the facilities of choice until at least 2020, which is the analysis period. Indeed, those models do not project construction of any new coal-fired EGUs during that period that would not comply with the proposed standard. This state of affairs has come about primarily because technological development and discoveries of abundant reserves have caused natural gas prices to decline precipitously in recent years and have secured those relatively low prices for the near-future. Importantly, because the IPM modeling shows that natural gas-fired plants are the facilities of choice, the proposed standard of performance in today's rulemaking  -  -  which is based on the emission rate of a new NGCC unit  -  -  does not add costs. In addition, compared to coal-fired EGUs, natural gas-fired EGUs have fewer nonair quality health and environmental impacts.
      Essentially because natural gas generation is cleaner and cheaper than coal, natural gas-fired EGUs qualify as the "best system of emission reduction which (taking into account the cost of achieving such reduction and any nonair quality health and environmental impact and energy requirements) the Administrator determines has been adequately demonstrated."
      We recognize that today's proposed approach of combining the Da category and a portion of the KKKK category, and applying as the standard of performance the rate that natural gas-fired EGUs can meet, represents a departure from prior agency practice. We consider this departure warranted in light of both the emissions benefits and the changed economic circumstances, notably the lowered prices of natural gas due to technological development and recent discoveries that have boosted recoverable reserves. We are aware that in theory, those economic circumstances could change and if they do, then a change in the standard of performance may be warranted. In this regard, we note that CAA section 111(b)(1)(B) requires that the EPA "shall, at least every 8 years, review and, if appropriate, revise [the] standards [of performance]." This 8-year review cycle provides a mechanism for the EPA to assure that the standard of performance for any particular source category continues to reflect the "best system."
(2) Legal Justification for the 30-year Averaging Compliance Option. Although the IPM model projects that for economic reasons, new coal- or pet coke-fired EGUs will not be built in the foreseeable future (beyond early CCS projects), we recognize that in a few instances, owners or operators may in fact seek to build coal- or pet coke-fired EGUs. As discussed in detail below, those owners or operators could avail themselves of CCS as a 30-year averaging compliance option. In addition, today's proposed rulemaking offers flexibility for CCS installation: The owners or operators could (i) achieve the supercritical efficiency level for an initial period (e.g., up to the first 10 years), and (ii) after that, implement CCS so as to achieve a 600 lb CO2/MWh rate on a 12-month annual average during the latter period (i.e., the back 20 years) and thereby achieve the 1,000 lb CO2/MWh rate on an average annual basis over the 30-year period. The alternative compliance option could also allow them to install and operate CCS much earlier and use the 10 year period to address any startup challenges related to being an early adopter of the technology.
      Because CO2 is long-lived in the atmosphere, the 30-year averaging period, as structured, with shorter term compliance requirements, is not expected to have a different impact on climate compared to meeting the standard of performance.
(a) CCS. The significance of CCS as a compliance alternative is several-fold. As a practical matter, it offers a vehicle for the construction of new coal- fired EGUs in those few instances in which owners or operators decide to construct such EGUs, notwithstanding the underlying economics. Also, it offers a vehicle for the continued scaling of CCS, a process that can be expected to lower the costs of CCS in the future. In addition, this compliance alternative provides further support for the reasonableness of the EPA's proposals in this rulemaking to combine the Da category and a portion of the KKKK category and to determine that a NGCC facility is the "best system of emission reduction." This is because this compliance alternative, by providing a vehicle for new coal-fired power plant builds, would minimize any disruptions that the EPA's proposals might, at least in theory, otherwise entail to the power plant industry.
      CCS as a compliance alternative does not achieve these goals by necessarily qualifying, under the CAA section 111(a)(1) definition of "standard of performance," as the "best system of emission reduction which (taking into account cost [and other factors]) the Administrator determines has been adequately demonstrated." Instead, this compliance alternative is feasible and sufficiently available for the limited amount of new coal-fired construction that is expected, whether or not it would qualify as the "best system."
      First, it is reasonable to expect that some coal-fired power plants may be able to implement CCS at the present time, and thereby achieve the 1,000 lb CO2/MWh standard immediately. As noted elsewhere, CCS has been demonstrated to be technologically achievable, and, even though it is costly, there are some state and Federal subsidy programs that can make CCS more affordable, particularly in tandem with use of captured CO2 for enhanced oil recovery, and those programs may be sufficient for the very few new coal-fired plants that are expected to be constructed in the foreseeable future. Some of these programs are discussed above.
      We note that the need for governmental subsidies to reduce the costs of CCS is hardly unique in the electricity generation sector. Each of the major types of energy used to generate electricity has been or is currently supported by some type of government subsidy -- such as tax benefits, loan guarantees, low-cost leases, or direct expenditures -- for some aspect of development and utilization, ranging from exploration to control installation. This is true of fossil fuel-fired; as well as nuclear-, geothermal, wind-, and solar-generated electricity. These subsidies have been designed to overcome cost barriers to the utilization of the energy. In this context, the need for subsidies for CCS to overcome cost barriers does not mean that CCS cannot be considered an alternative compliance method in this rulemaking.
      Second, it is reasonable to expect that some coal-fired power plants may be able to implement the supercritical efficiency standard for an initial period of time (the first 10 years) and then implement CCS and achieve lower 12-month annual average rates after that, so that the source achieves the 1,000 lb CO2/MWh standard on average over the 30-year period following construction.  This is because, again, CCS is feasible and can be expected to be sufficiently available  -  in light of continued subsidies and lower future costs  -  in light of the limited demand.
      Third, although we do not propose that the 30-year averaging compliance option meets the definition of the "best system of emission reduction [(BSER)] ... adequately demonstrated," under CAA section 111, we note that identifying CCS as a compliance option based in part on the expectation that CCS will cost less in the future is consistent with the section 111 requirements for determining the BSER adequately demonstrated. In determining what emissions controls qualify as the BSER adequately demonstrated  -  which must take costs into account  -  the EPA is authorized under CAA section 111 to anticipate that technology that is costly at present will come down in price in the future. It is clear from the legislative history of section 111 and relevant case law that the EPA may anticipate future developments  - - as long as supported by an adequate record  - - in determining whether a particular system of emission reduction is the BSER adequately demonstrated. The Senate Committee Report to the 1970 CAA Amendments, which first enacted CAA section 111, made clear that the EPA may anticipate future developments in determining the BSER adequately demonstrated:
      	As used in this section, the term "available control technology" is intended to mean that the Secretary should examine the degree of emission control that has been or can be achieved through the application of technology which is available or normally can be made available. This does not mean that the technology must be in actual, routine use somewhere. It does mean that the technology must be available at a cost and at a time which the Secretary determines to be reasonable. The implicit consideration of economic factors in determining whether technology is "available" should not affect the usefulness of this section. The overriding purpose of this section would be to prevent new air pollution problems, and toward that end, maximum feasible control of new sources at the time of their construction is seen by the committee as the most effective and, in the long run, the least expensive approach.

Sen. Rep. 91-1196 at 16 (emphasis added). As quoted, this statement makes clear that a standard of performance may be based on a technology that is not "in actual routine use somewhere," but that "normally can be made available." Moreover, the technology need not be available until "a time which the Secretary determines to be reasonable." Id.
	In addition, the D.C. Circuit has been explicit that in setting a CAA section 111 standard of performance, the EPA may make reasonable projections of what technology will be available to the regulated industry in the future. The Court stated, in Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375 (D.C. Cir. 1973):
      We begin by rejecting the suggestion of the cement manufacturers that the Act's requirement that emission limitations be "adequately demonstrated" necessarily implies that any cement plant now in existence be able to meet the proposed standards. Section 111 looks toward what may fairly be projected for the regulated future, rather than the state of the art at present, since it is addressed to standards for new plants -- old stationary source pollution being controlled through other regulatory authority. It is the "achievability" of the proposed standard that is in issue. * * *

      The * * * standard is analogous to the one examined in International Harvester * * *. The Administrator may make a projection based on existing technology, though that projection is subject to the restraints of reasonableness and cannot be based on "crystal ball" inquiry.

Id. at 391 (emphasis added). Again, although these statements in the legislative history and case law are in the context of establishing the basis for a standard of performance, the same principle  - - that the EPA may reasonably project the path of technological development  - - supports treating CCS as a compliance alternative.
      Although, for the reasons noted above, we do expect the costs of CCS to decline, we recognize that the amount of the decrease is uncertain. Even so, the presence of cost uncertainty by itself does not mean that prospective power plants cannot be expected to adopt the 30-year averaging compliance option. We note that prospective power plants face significant cost uncertainties in any event.
	For example we note that recently, several owner/operators have announced that they do not intend to construct coal-fired power plants without CCS. They have explained that they anticipate more widespread CO2 control requirements in the future, so that constructing coal-fired plants at this time without CCS could leave them subject to liability for high retrofit control costs in the future. This sentiment indicates that some sources may avail themselves of the 30-year averaging compliance option.
	The inclusion of a 30-year averaging compliance option has precedent in EPA rulemaking under the CAA. In the past, the EPA has promulgated rules that adopt an emission limit based on a particular technology (such as, in the present rulemaking, NGCC), but has supported that action on grounds that sources have compliance alternatives, even though higher priced. See "Finding of Significant Contribution and Rulemaking for Certain States in the Ozone Transport Assessment Group Region for Purposes of Reducing Regional Transport of Ozone:  Final Rule" 63 FR 57356, 57378 (Oct. 27, 1998) (in the rule that became known as the "NOx SIP Call," the EPA based NOx emission limits that states were required to meet on the assumption that states could adopt specified control measures that were "highly cost-effective," but the EPA identified other control measures that, even though not as cost-effective, the states could adopt instead).
(b) 30-year Period. We propose a 30-year period because (i) we generally expect that ten years provides sufficient time either for owners/operators who are interested in considering cost improvements that occur as a result of the lessons learned from early adopters, or provides early adopters sufficient time to address any startup challenges; and (ii) as noted above, 30 years provides enough time for sources to achieve the 1,000 lb CO2/MWh emission limit following an elevated level of emissions over the first 10-year period.
(c) Supercritical Efficiency Level. According to the Depart of Energy Cost and Performance Baseline for Fossil Energy Plants reports, the use of supercritical steam is the most cost effective option for new conventional coal-fired generation and results in the lowest overall costs. In addition, the increased efficiency results in reduced cooling water requirements and reduced environmental impacts associated with coal mining, delivery, and handling. Therefore, considering the benefits and minimal, if any, cost of using supercritical steam conditions, as opposed to subcritical steam conditions, we have concluded that an annual standard based on the best performing conventional coal-fired generation is appropriate.
      There are a dozen bituminous-fired and 2 subbituminous-fired EGUs that have demonstrated the proposed annual standard is achievable on a long term basis. Furthermore, we have concluded that with coal drying technology, which is being used on a number of power plants today, the annual standard is achievable by a wide range of units firing a variety of coal types, including lignites. There are multiple vendors that offer processes to upgrade lignites to heating values that are equal to or greater than those of subbituminous coals. The best performing subbituminous-fired EGU has maintained a 12-month emissions rate of 1,730 lb CO2/MWh. A new EGU using a similar design would be able to burn upgraded lignite and be in compliance with the proposed annual standard.
      We solicit comment on all aspects of the alternative compliance option, including the 30-year averaging period we propose in this action. Although we are not proposing that CCS, including the 30-year averaging compliance option, does or does not qualify as the BSER adequately demonstrated, we also solicit comment on that issue.
B. How did the EPA determine the other requirements for the proposed standards?
1. Compliance Requirements
      The proposed compliance requirements, to the extent possible, incorporate monitoring already being performed as part of existing part 60 and part 75 requirements.
      In addition, we intend to recognize the environmental benefit of electricity generated by CHP facilities to account for the increased end use efficiency resulting from avoided transmission and distribution losses. Actual line losses vary from location to location, but we intend to assume a benefit of 5 percent avoided transmission and distribution losses when determining the electric output for CHP facilities. This provision would be restricted to facilities where the useful thermal output is at least 20 percent of the total output.
	We also propose to base compliance requirements on a 12-month rolling average basis. The variability in GHG emissions rates is such that establishing a shorter averaging period would necessitate establishing a standard to account for the conditions that result in the lowest efficiency and therefore the highest GHG emissions rate. A 12-month rolling average accounts for variable operating conditions, allows consistent emissions rate averaging, allows for a more protective standard and decreased compliance burden, and simplifies compliance for state permitting authorities. Because the 12-month rolling average can be calculated each month, this form of standard makes it possible to assess compliance and take any needed corrective action on a monthly basis. The EPA proposes that it is not necessary to have a shorter averaging period for CO2 from these sources because the effect of GHGs on climate change depends on global atmospheric concentrations which are dependent on cumulative total emissions over time, rather than hourly or daily emissions fluctuations or local pollutant concentrations.
	Even so, we solicit comment on, in the alternative basing compliance requirements on an annual (calendar year) average basis.
V. Requirements for Modifications, Transitional Sources, Reconstructions
A. Requirements for Modifications
1. Overview
Under CAA section 111, existing sources are treated as new sources if they undertake "modification[s]," which are generally defined as physical or operational changes that increase emissions. CAA section 111(a)(2) and (4). The EPA's regulations exempt certain types of changes from the definition of modification. 40 CFR 60.14(e). Available information does not provide an adequate basis for the EPA to develop proposed standards of performance for modifications. Our base of knowledge concerning NSPS modifications has depended largely on the enforcement actions brought against power plants and on self-reporting by power plants.  Over the lengthy history of the NSPS program, those have been too few in number to allow us to develop a sufficiently robust base of knowledge to propose a standard of performance for NSPS modifications for GHGs at this time.
We note that the types of projects that these EGUs are most likely to undertake that could increase GHG emissions are projects that put on pollution controls required under other CAA provisions and that emit CO2 as a byproduct, and those types of projects are specifically exempted from the definition of "modifications" under 40 CFR 60.14(e)(5). In addition, based on past experience, we expect that actions that do constitute modifications to be from different types of sources and to take different forms. In light of this, the EPA does not have sufficient information to develop standards of performance for modifications, and therefore the EPA is not proposing any standards for modifications. As a result, EGUs that undertake pollution control projects or other physical or operational changes would continue to be treated as existing sources.
2. Statutory and Regulatory Requirements
      Clean Air Act section 111(b)(1)(B) requires the EPA to promulgate "standards of performance" for "new sources" within source categories. For certain pollutants, CAA section 111(d)(1) requires the EPA to prescribe regulations for state plans covering "existing source[s]" in a category regulated for that pollutant under section 111(b). Clean Air Act section 111(a)(2) defines a "new source" as "any stationary source, the construction or modification of which is commenced after the publication of regulations (or, if earlier, proposed regulations) prescribing a standard of performance under this section which will be applicable to such source." Clean Air Act section 111(a)(6)defines an "existing source" as "any stationary source other than a new source." Clean Air Act section 111(a)(4) defines "modification" as "any physical change in, or change in the method of operation of, a stationary source which increases the amount of any air pollutant emitted by such source or which results in the emission of any air pollutant not previously emitted."
      The EPA's regulations provide that under CAA section 111(a)(4), for purposes of determining whether an existing electric utility steam generating unit undertakes a modification, a physical or operational change is treated as increasing emissions only when it increases the "maximum hourly emissions" above the "maximum hourly emissions achievable" at the unit. 40 CFR 60.14(h). In addition, the EPA's regulations exempt certain physical or operational changes from the definition of modification. 40 CFR 60.14(e)(5). The exemptions include pollution control projects:
      (e) The following shall not, by themselves, be considered modifications ...:
      ...
      (5)  The addition or use of any system or device whose primary function is the reduction of air pollutants, except when an emission control system is removed or is replaced by a system which the Administrator determines to be less environmentally beneficial.

40 CFR 60.14(e)(5). Thus, the EPA's current regulations define a modification as a physical or operational change that increases an existing affected EGU's maximum achievable hourly rate of emissions, but specifically exempt from that definition pollution control projects, which are projects that entail the installation of pollution control equipment or systems.
3. The EPA's Proposed Course of Action
      We expect EGUs to undertake changes in the foreseeable future that would increase their maximum achievable hourly rate of CO2 emissions for purposes of the NSPS. We expect that the most of those actions would constitute pollution control projects. In many cases, those projects would involve the installation of add-on control equipment required to meet CAA requirements for conventional air pollutants. We expect that these increases in CO2 emissions would occur as a chemical byproduct of the operation of the control equipment, and would be small. In other cases, those projects will involve equipment changes to meet the requirements of this rulemaking and that may have the effect of increasing the sources' maximum hourly achievable emission rate, even while decreasing actual emission rate. Because such actions would be treated as pollution control projects under the EPA's current NSPS regulations, they would be specifically exempted from the definition of modification.
      Aside from pollution control projects, in the past, there have also been, as noted, a limited number of instances, on an annual basis, in which power plants have undertaken actions that should be treated as NSPS modifications. The sources that took these actions vary widely, one from another, depending on, among other things, size, fuel type, and physical plant configuration. The diversity of sources undertaking modifications has reflected the diversity among power plants as a whole. Moreover, the types of modifications they have undertaken have also varied widely.
      Because of the limited number of modifications, their disparate nature, and the disparate type of sources, we do not at present have an adequate base of information to propose standards of performance for modifications. For example, we do not have adequate information as to the types of physical or operational changes sources may undertake or the amount of increase in CO2 emissions from those changes. Nor do we have adequate information as to the types of control actions sources could take to reduce emissions, including the types of controls that may be available or the cost or effectiveness of those controls. The most likely candidates for control actions would be efficiency measures and we do not have adequate information as to the types of sources and types of changes at issue that could provide the basis for a proposal for efficiency measures. If there were a more robust set of data on facilities of a particular type undertaking NSPS modifications of a particular kind, the EPA may be able to develop a standard of performance for that type. But, as noted, that is not the case here.
      As a result, in this action, the EPA is not proposing standards of performance for NSPS modifications for GHGs. The EPA is soliciting comment on the types of sources that may be expected to undertake modifications, the types of modifications, the types of control measures, and all other aspects of this issue. This solicitation of comment is in the nature of an advance notice of proposed rulemaking. If we receive sufficient additional information, we may issue a proposal for modifications in the future. However, to reiterate, we are not proposing any standards of performance for these modifications at this time. Accordingly, the EPA does not expect to promulgate any standards of performance for modifications when it takes final action on this rulemaking.
      The definitional provisions of CAA section 111, quoted above, make clear that a stationary source that undertakes construction or modification is considered a "new source" only if there is a proposed or final "standard of performance under this section which will be applicable to such source." CAA section 111(a)(2). Accordingly, if there is no proposed or promulgated standard of performance applicable to a particular source, then the source cannot be considered a "new source" and therefore will not be subject to any standards of performance we finalize for new sources.
      Further, under the definitional provisions, any source that is not a "new" source is an "existing source." CAA section 111(a)(6). Therefore, affected EGUs that undertake NSPS modifications for GHGs will continue to be treated as existing sources. Although modified sources would not be subject to the 1,000 lb CO2/MWh standard for new sources, the EPA anticipates that modified sources would become subject to the requirements the EPA would promulgate at the appropriate time, for existing sources under 111(d). It is important to note that at the same time that the EPA promulgated the pollution control provision in the EPA's regulations under CAA section 111, the EPA promulgated a similar provision in EPA's NSR regulations. The D.C. Circuit, in New York v. EPA, 413 F.3d 3, 40 (D.C. Cir. 2005), vacated the NSR pollution-control-project exemption. Because of the similarities between the NSR and the section 111 pollution control project regulatory provisions, the Court's vacatur of the NSR regulatory provision may call into question the continued validity of the section 111 regulatory provision. As a result, we are soliciting comment on whether this exemption from the definition of "modification" for pollution control projects, under 40 CFR 60.14(e)(5), continues to be valid or not, and what course of action, if any, would be appropriate for the EPA to take.
B. Requirements for Transitional Sources
1. Overview
      In this action, the EPA is not proposing a standard of performance for transitional sources. We define these sources as coal-fired power plants that, by the date of this proposal, have received approval for their PSD preconstruction permits that meet CAA PSD requirements (or that have approved PSD permits that expired and are in the process of being extended, if those sources are participating in a Department of Energy CCS funding program), and that commence construction within a year of the date of this proposal. For convenience, we refer to the new sources for which we are proposing a standard of performance as non-transitional sources.
      Transitional sources are a distinct set of sources with unique circumstances. We have identified 15 proposed sources that may qualify as transitional sources based on the above criteria. These proposed sources differ considerably one from another. They range in size from as small as 80 megawatts (MW) to as large as 1320 MWs; they will burn different fuels: conventional coal, waste coal, or petcoke; and they will use different technologies:  circulating fluidized bed (CFB), integrated gasification combined cycle (IGCC), supercritical pulverized coal, or sub-critical pulverized coal.
Recent industry practice raises the probability that no more than a few of these 15 proposed sources will in fact be constructed.
      We recognize that by the date of this proposal, some of the 15 proposed sources may have incurred substantial sunk costs and may have progressed in their preconstruction planning to the point where they are poised to commence construction in the very near future. Under these circumstances, the 1,000 lb CO2/MWh standard of performance that applies to non-transitional sources would not be appropriate for these proposed sources. As noted, that standard is based on natural gas combined cycle (NGCC) as the "best system of emission reduction ... adequately demonstrated" because NGCC is the least expensive and lowest emitting design for a fossil-fuel fired power plant, and because a proposed new source may choose to construct as a NGCC facility. However, proposed coal-fired power plants that have already received a PSD permit and that have incurred substantial sunk costs and developed plans to commence construction in the very near future are not in the same position as non-transitional sources. Applying the 1,000 lb CO2/MWh standard would likely result in the loss of their sunk costs and would likely cause multi-year delays, or even abandonment, of their plans to construct. (Nor is the 1,000 lb CO2/MWh standard appropriate for CCS sources, as discussed below.) This is not within the scope of BSER.
      However, we do not have sufficient information concerning the 15 proposed sources to identify which ones may be in this position. Specifically, we do not have information as to the extent of their sunk costs, their preconstruction planning, or their overall business plans.
      Accordingly, we propose to include a requirement that proposed sources must commence construction within 12 months of today's rulemaking proposal as a mechanism for revealing which of these sources qualifies as a transitional source. We believe that any of these 15 proposed sources that commences construction within 12 months of today's rulemaking proposal should be considered to have incurred substantial sunk costs and will have engaged in sufficient preconstruction planning so that the 1,000 lb CO2/MWh standard should not apply. Any of these 15 proposed sources that do not commence construction within this period should not be considered to be similarly situated. For any of these latter sources that ultimately are constructed, the 1,000 lb CO2/MWh standard would apply.
      Having identified which proposed sources could qualify as transitional sources, we further believe that for several reasons, it is not appropriate to propose any standard of performance for those sources. As noted above, we necessarily lack information specifically as to which of the 15 proposed sources will actually qualify as transitional sources, and, given the range of size, fuel types, and technologies among these proposed sources, that renders it problematic to propose standards of performance. In addition, for the proposed sources that are planning to install CCS, we lack important information concerning the extent to which they are planning to capture CO2 or their costs to do so. We also lack information as to whether they have made contractual arrangements for the sale of the CO2 or carbon credits, which may be critical to their financing arrangements. In addition, attempting to propose a standard of performance would give rise to serious practical problems that would undermine the usefulness of the requirement that sources commence construction within 12 months of today's rulemaking proposal as a mechanism for revealing which of these sources qualifies as a transitional source. These include creating uncertainty as to the level of the final standard of performance to which the proposed sources would be subject, which may have the effect of forcing them to delay commencing construction until after we finalize the standards, at which time they would have missed their 12-month window to commence construction and as a result, would fail to qualify as transitional sources. We note that CAA section 111 does not require that we propose or promulgate standards of performance for all sources in a source category, and on numerous occasions in past rulemakings the EPA has taken the similar approach of not proposing standards of performance for all sources in the source category.
      Even without an applicable standard of performance, transitional sources will remain constrained in their emissions of CO2 by the requirements of their PSD permits. In addition, although transitional sources would not be subject to the 1,000 lb CO2/MWh standard for new sources, the EPA anticipates that transitional sources would become subject to the requirements the EPA would promulgate at the appropriate time, for existing sources under 111(d).
2. Identification of transitional sources
      For purposes of this action, we define a transitional source as a coal-fired power plant that has received approval for its complete PSD preconstruction permit by the date of this proposal (or that has an approved PSD permit that expired and for which the source is seeking an extension, if the source has been issued or awarded a DOE CCS loan guarantee or grant) for the project, and that commences construction within 12 months of the date of this proposal. For this purpose, the date of this proposal is the date of publication in the Federal Register of this notice of proposed rulemaking. The 12-month period would not be extended for any reason, including because of any challenges to the permit that may be brought in any Federal or State court or agency.
      The EPA is aware of approximately 15 sources that could potentially qualify as transitional sources because, except as otherwise noted, they have obtained PSD permits but have not yet commenced construction. These proposed sources vary considerably one from another. They range in size from as small as 80 megawatts (MW) to as large as 1320 MWs; they will burn different fuels: conventional coal, waste coal, or petcoke; and they will use different technologies:  circulating fluidized bed (CFB), integrated gasification combined cycle (IGCC), supercritical pulverized coal, or sub-critical pulverized coal.
      Based on recent industry practice, it appears that no more than a few of these sources will be constructed.
      Of these 15 identified potential transitional sources, six have indicated that they plan to install CCS (and in most if not all cases have been issued or awarded a DOE CCS loan guarantee or grant). These six projects are: The Texas Clean Energy Project in Texas, the Trailblazer project in Texas, the Taylorville project in Illinois, the Good Spring facility in Pennsylvania, the Power County Advanced Energy Center in Idaho and the Cash Creek Generation Plant in Kentucky. The remaining nine plants, which are without CCS, are: Limestone 3, White Stallion and Coletto Creek in Texas, Holcomb 2 in Kansas, James De Young and Wolverine in Michigan, Washington County in Georgia, Bonanza in Utah, and Two Elk in Wyoming.
      We request that during the public comment period on this rulemaking, each of these EGUs confirm to us that we have correctly identified the status of their PSD permits and, in the case of any sources that had approved permits that are in the process of being extended, and that plan to install CCS, that they have been issued or awarded a DOE CCS loan guarantee or grant. We also request that the sources indicate whether their permits are undergoing challenges before Federal or state authorities or courts. We further request that any other EGU not listed above that has a complete PSD permit and that otherwise meets the parameters for transitional sources described in this section identify itself to us (including indicating whether its PSD permit is undergoing challenge before Federal or state authorities or courts). In our final rulemaking, we intend to include a confirmed list of sources that would qualify as transitional sources if they commence construction within the 12-month period following publication of this proposal in the Federal Register.
      As commenters have noted, among these 15 proposed sources, some may have incurred substantial sunk costs associated with processing their permits as well as taking additional preconstruction steps (e.g., purchasing land) so that they may be able to commence construction within the near term. As examples of these types of steps, several sources, such as the Texas Clean Energy Project, have signed contracts for the sale of electricity, the sale or disposal of CO2 or other enabling products, or supporting systems. Although the Taylorville project's PSD permit has expired, the source is seeking to extend it, and the source has entered into CCS funding arrangements with DOE. These actions indicate that this proposed source, too, has sunk costs and may be in a position to commence construction within the near term, and therefore is similarly situated to the other 14 proposed plants (assuming that it is able to secure an extension of its PSD permit).
      Even so, we face major gaps in our information about these sources that would inform us at this point as to which of these sources have incurred costs and material commitments to the extent that a 1,000 lb CO2/MWh standard would be so costly and disruptive as not to be BSER. For example, we do not have specific information as to those sources' specific sunk costs, specific project development actions to date, or overall business plan. Accordingly, we are not able to determine which ones are in a position to commence construction in the near term. In addition, for the sources whose PSD permit indicates that they will install CCS, we do not have specific information as to the amount of CO2 that they plan to capture; their costs to operate CCS; or their possible revenue streams associated with CCS, such as from the sale or use of CO2 in enhanced oil recovery or the possible sale of carbon credits in voluntary or other carbon markets.
      Instead, the 12-month period, serving as a surrogate for the missing information, provides a mechanism for revealing the qualification of proposed sources for treatment as transitional sources. In light of the complex of requirements, which range from siting to financing, needed to commence construction of a project as large and expensive as a power plant, any proposed source that does commence construction within the relatively short period of 12 months of the date of proposal can be said to have incurred substantial sunk costs and to have taken preconstruction steps by the time of this proposal. It is these sources that would be most disadvantaged by being subjected to the standards of performance proposed in today's rulemaking. The one-year period serves as a type of surrogate for a more precise information as to the amount of sunk costs sources must incur or steps leading to commencement of construction that sources must undertake in order to qualify as transitional sources, as well as which sources have incurred those costs or taken those steps, which information is not available at this time. In addition, 12 months is long enough to give these sources a reasonable period to commence construction in accordance with the terms of their permit. Any proposed source that does not commence construction within 12 months cannot be said to be similarly situated.
3. The EPA's treatment of transitional sources
      In this action, the EPA is treating transitional sources as a distinct set of sources. We make clear that the proposed standard of performance for non-transitional sources of 1,000 lb CO2/MWh is not applicable to transitional sources because that standard is not based on the BSER adequately demonstrated for transitional sources. In addition, in light of the unique circumstances of transitional sources, including of a lack of information and other considerations, we do not propose any other standard of performance for transitional sources.
      Although a transitional source would not be subject to new source CO2 emissions controls under CAA section 111(b), it would be subject to CO2 emissions limits due to any CO2 limits in the source's PSD permit. If the source received the permit prior to January 2, 2011, the permit will not include CO2 limits, but in that case, as a practical matter, CO2 emissions would be limited by whatever design or operating constraints are imposed on the source under the PSD permit.
      We also note that the fact that transitional sources would not be subject to the proposed standard of performance, would not relieve them from any requirements applicable to existing sources under section 111(d) and related state plans.
4. Legal basis for the EPA's treatment of transitional sources

      In this section, we describe the legal basis for our treatment of transitional sources. First, we identify the relevant CAA section 111 provisions. Second, we explain why the standard of performance we propose for non-transitional sources does not apply to transitional sources, which is because that standard does not reflect the best system of emission reduction adequately demonstrated for transitional sources. Third, we explain why we are not proposing any other standard of performance for transitional sources, which is due to lack of information and other considerations. In the course of these explanations, we discuss the relevant CAA section 111 requirements and our interpretations of them.
a. Key CAA section 111 provisions
      As the first step in the process of promulgating regulations under section 111, under CAA section 111(b)(1)(A), the Administrator must "publish ... a list of categories of stationary sources." Then, the Administrator must "[propose] ... Federal standards of performance for new sources within [the source] category," and then "promulgate ... such standards with such modifications as he deems appropriate." Section 111(b)(1)(B). Section 111(b)(2) goes on to provide that "[t]he Administrator may distinguish among classes, types, and sizes within categories of new sources for the purpose of establishing such standards."
      Section 111 includes several key definitions. The provision defines a "new source" as "any stationary source, the construction or modification of which is commenced after the publication of regulations (or, if earlier, proposed regulations) prescribing a standard of performance under this section which will be applicable to such source."  CAA section 111(a)(2).  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 best system of emission reduction which (taking into account the cost of achieving such reduction and any nonair quality health and environmental impact and energy requirements) the Administrator determines has been adequately demonstrated.

CAA section 111(a)(2).
      Once the Administrator promulgates standards for new sources under CAA section 111(b), the States, consistent with EPA regulatory requirements, must take action under CAA section 111(d) to establish requirements for "any existing source for any air pollutant (i) [that falls into specified categories] but (ii) to which a standard of performance under this section would apply if such existing source were a new source...." Section 111(d)(1). An "existing source" is defined as "any stationary source other than a new source." Section 111(a)(6).
b. Reasons for not applying the 1,000 lb CO2/MWh standard of performance to transitional sources

(i). Introduction
      In this action, the EPA is treating transitional sources as a distinct set of sources, although the EPA is not establishing a specific subcategory for these sources in the regulatory provisions. Under CAA section 111, the EPA may not apply a standard of performance to sources unless it reflects the "best system of emission reduction" (BSER) adequately demonstrated.
      As noted, the EPA proposes that non-transitional source fossil-fired power plants that commence construction after the date of proposal are subject to the standard of 1,000 lb CO2/MWh, and the EPA proposes to base this standard on the EPA's identification of natural gas combined cycle (NGCC) as the BSER adequately demonstrated. The EPA justifies this proposal because owners or operators contemplating construction of non-transitional power plants to serve baseload and intermediate load demand have choices: they can choose the type of facility and therefore may choose to construct a NGCC plant. As a result, for these sources, NGCC constitutes the BSER, and the 1,000 lb CO2/MWh emission limit reflects that BSER and therefore is the appropriate standard of performance under section 111. Moreover, for those that choose to construct a coal-fired unit, they may choose to construct the plant in a place and a manner that allows installation of CCS  - - and thereby meet the 1,000 lb CO2/MWh standard -- either at the time of construction or, in accordance with the 30-year averaging proposal, some years later.
(ii) Transitional sources and NGCC

      In contrast, the circumstances surrounding transitional sources are quite different. Transitional sources are a very small group of sources with a distinct profile of costs, preconstruction planning, overall business plans, technical and design concerns, and equitable concerns. Because they are such large facilities, their sunk costs and planning horizons are substantial.
      Transitional sources have already incurred substantial costs in permitting and taking other steps preparatory to commencing construction as coal-fired power plants within 12 months of the date of this proposal, which may include purchasing land for the new facility. Considering these sunk costs, converting their plant design to NGCC would be significantly more expensive than for proposed non-transitional sources that have not reached the stage of development that transitional sources have reached. The EPA is required to consider costs in determining the BSER adequately demonstrated, and under these circumstances, the costs factor points away from treating NGCC as BSER for transitional sources.
      In addition, because transitional sources have obtained a PSD permit and have developed their plans to the point where they are on the verge of commencing construction, the converting of their plant design to NGCC would be significantly more disruptive to their plans than for proposed non-transitional sources. It may require them to start over the process of developing the plant, and thereby render futile the planning and steps they have taken to date. These losses would, at a minimum, lead to delays in their commencing construction that realistically would be measured in years, and in fact may lead them to abandon the project.
      Although the potentially significant planning impacts at issue here are not explicitly identified as part of the definition of the "standard of performance," they should nevertheless be considered in determining the BSER. This is because CAA section 111(a)(2), in its definition of "new source," clearly contemplates that sources are expected to be able to commence construction after the EPA proposes, and before the EPA promulgates, a standard of performance applicable to them. There is nothing in CAA section 111 that suggests that Congress expected that the EPA may determine the BSER in a way that would significantly disrupt the plans of the regulated sources that are implicated here. Therefore, for this reason, too, the 1,000 lb CO2/MWh standard cannot be considered to reflect the BSER for transitional sources, and therefore cannot be the appropriate standard of performance.
      Nor can transitional sources reasonably be expected to meet the 1,000 lb CO2/MWh standard through the installation of CCS, for the reasons discussed below.
      Note that the EPA takes the position that in this particular action, both of those factors  - - sunk costs and extent of planning to commence construction - -  must be considered in determining whether the 1,000 lb CO2/MWh standard reflects the BSER adequately demonstrated. That is, both are necessary conditions, and neither one, by itself, is a sufficient condition. We believe that these reasons concerning costs and planning suffice to justify our position that the 1,000 lb CO2/MWh standard is not appropriate for transitional sources.
(iii). Coal-fired transitional sources not designed for CCS
      As noted, while it is generally the case that proposed new sources could choose to build coal-fired power plants with CCS and thereby meet the 1,000 lb CO2/MWh standard, that is not the case for those transitional sources that are not designed for CCS. As a practical matter, it would be challenging for such a source to proceed with construction without substantial re-design of the project in order to install CCS and thereby be in compliance with the 1,000 lb CO2/MwH standard. There are several reasons for this. First, captured CO2 must be sequestered or used. If this was not considered as part of the original site selection, the source will likely be significantly challenged in its efforts to adopt CCS. Second, if CCS was not considered in the original project design, space considerations may make it difficult to now accommodate it in the facility's design. Third, the requirement to use CCS could necessitate a change in the very power generation technology that a source may choose to use. For instance, instead of building a pulverized coal boiler, IGCC technology may be more appropriate. This is not to say that CCS could not be added to a project at this stage. Projects like the AEP Mountaineer project have shown that CCS can be successfully retrofitted into an existing plant. However, unlike in an existing facility where retrofit decisions must take into account previously made design decisions, in a facility in the pre-design phase, there is more opportunity for cost savings from re-designing the project, rather than having to adapt through retrofit.
      It bears emphasis that the requirements created by the new source standard in today's action are fundamentally different from post-combustion controls required to meet new source standards for conventional pollutants in the sense that those controls could be much more easily re-designed into an already planned plant without changing the plant's basic underlying characteristics (such as type of unit or even location). In contrast, CCS is more fundamental to both the design and siting of a unit, and therefore would likely involve fundamental changes to the underlying project. This is much more difficult in a project that has progressed through the permitting stage and is very close to commencing construction than it would be in other types of projects.
(iv). Coal-fired transitional sources designed for CCS
      Although some of the proposed sources that may qualify as transitional sources are planning for CCS, that does not provide a basis for concluding that the 1,000 lb CO2/MWh standard is appropriate for them. As noted, the EPA is not, in this rulemaking, proposing that CCS is the BSER adequately demonstrated for coal-fired EGUs.
      Moreover, these proposed sources have established their location and developed their business plans without the expectation that the proposal in this rulemaking for CCS would apply to them. For example, their plans may assume installing CCS in a manner that results in emissions at levels higher than 1,000 lb CO2/MWh, or it may assume the sale of emission reduction credits based on an allowable emission rate above 1,000 lb CO2/MWh. Imposition of an unexpected emission rate requirement at such a late date could upset carefully crafted financial plans, causing delay or even cancellation of the project.
      Importantly, we do not have information as to key components of their proposed project and business plan, including, among other things, the amount of capture from the planned CCS system or possible revenue streams associated with CCS. Any proposal for what is BSER would depend on those costs and other information. Accordingly, we are not able to propose determinations that are essential to proposing the BSER for these proposed sources. As a result, we are not able to propose a standard of performance for these proposed sources.
(v). Equitable considerations
      For all transitional sources, the costs and delays discussed above give rise to equitable considerations that also support our treatment of these proposed sources. As noted, owners or operators of transitional sources have incurred significant expenses and undertaken a long planning period that has led them to being able to commence construction in the very near future, and, having invested so substantially in their current plans, should as an equitable matter be allowed to proceed without concern about requirements other than those in their PSD permits. To reiterate, they are in a posture that is fundamentally different from non-transitional sources.
c. Reasons for not applying other standard of performance
      Although, for the reasons described above, the 1,000 lb CO2/MWh standard that the EPA proposes for non-transitional sources does not reflect BSER for transitional sources, the EPA is not proposing any other standard of performance for transitional sources. It is reasonable to read section 111 not to require the EPA to propose a standard of performance when faced with the specific circumstances presented by transitional sources in the context of this rulemaking. These circumstances include: (1) the EPA's lack of information with regard to these sources and the appropriate BSER for these sources; (2) the unique challenges with regard to adaptation of proposed projects to the requirements of this standard; (3) the small number of these sources and the possibility that promulgating a standard of performance would not have a beneficial environmental impact; and (4)  although transitional sources would not be subject to the 1,000 lb CO2/MWh standard for new sources, the EPA anticipates that transitional sources would become subject to the requirements the EPA would promulgate at the appropriate time, for existing sources under 111(d).
 (i). CAA requirements for promulgating standards of performance for sources in a source category.
      The EPA interprets the CAA provisions described above to authorize the EPA not to promulgate a standard of performance for transitional sources. Under section 111(b)(1)(B), once the EPA lists a category of sources, the EPA is required to propose and promulgate standards of performance for new sources in that category. The EPA is not, however, required to promulgate standards of performance that cover all new sources . This is clear from the directive in section 111(b)(1)(B), which requires that the EPA propose standards of performance "for new sources" within the category, but does not require that the EPA propose such standards for all new sources or for any new source. The EPA may fulfill that directive by proposing standards that cover some, but not all, sources that newly commence construction or modification.
	Similarly, the term "new source" in section 111(a)(2) is defined to incorporate the limitation that the EPA must propose or promulgate a standard applicable to the source for the source to be considered "new." That is, section 111(a)(2) defines a "new source" as any source for which construction or modification commences after the EPA proposes "a standard of performance ... which will be applicable to such source." By its terms, this provision contemplates that the EPA may not propose a standard of performance applicable to certain sources, and that if the EPA does not, those sources would not be considered to be "new source[s]" and therefore not subject to any new source standard of performance.
      Thus, these provisions do not, by their terms, mandate that the EPA propose standards for each and every source in the source category. Under Chevron step 1, these provisions do not unambiguously require that the EPA propose standards of performance for all sources in the source category. We read these provisions as according the EPA some measure of discretion for the EPA to determine not to set standards for a particular portion of the source category, where appropriate, bounded by the principle of rationality. If these provisions are read to be ambiguous as to whether the EPA has discretion to propose and promulgate standards of performance for all sources in the source category, we believe it reasonable to read the provisions to provide such discretion in appropriate circumstances and that such reading is entitled to deference under Chevron step 2. In addition, interpreting these provisions to give the EPA the discretion not to propose and promulgate standards covering all sources in a category under appropriate circumstances  -  such as those present here -- is consistent with the caselaw that authorizes agencies to establish a regulatory framework in an incremental fashion, that is, a step at a time.
(ii). Precedents in prior NSPS rulemakings
      In applying section 111 over the past several decades, there have been a number of rulemakings in which the EPA has promulgated new source performance standards that do not cover all sources within the relevant source category that newly commence construction or modification. Some examples include the following: (i) In an early NSPS, involving lime kilns, the EPA promulgated an NSPS for certain types of kilns, but not for all types of sources that remained within the relevant source category. The D.C. Circuit, in its opinion reviewing the rule, noted this state of affairs, without expressing concerns. National Lime Ass'n v. EPA, 627 F.2d 416, 426 & n. 28 (D.C. Cir. 1980) (noting that "of the various types of kilns that may be used in the calcinations of limestone, only rotary kilns are regulated by the standards," and not "the vertical kiln; the rotary hearth kiln; and the fluidized bed kiln"). (ii) In the EPA's initial promulgation of NSPS regulations for petroleum refineries, the EPA did not promulgate standards of performance for certain units, including fluid coking units, delayed coking units, and process heaters, instead promulgating standards of performance for those units subsequently. See 40 CFR 60.100a(a); "Standards of Performance for Petroleum Refineries: Proposed Rules," 72 Fed. Reg. 27178 (May 14, 2007). (iii) Similarly, in the EPA's recent revision of the NSPS regulations for coal preparation and processing plants, the EPA "expand[ed] applicability of the existing NSPS by revising the definitions of thermal dryers, pneumatic coal-cleaning equipment, and coal. It also establishe[d] work practice standards for open storage piles. The final rule amend[ed] the definition of thermal dryer for units constructed, reconstructed, or modified after May 27, 2009, to include both direct and indirect dryers drying all coal ranks (i.e., bituminous, subbituminous, lignite, and anthracite coals) and coal refuse."  "Standards of Performance for Coal Preparation and Processing Plants," 74 Fed. Reg. 51950, 51952 (Oct. 8, 2009). (iv) In subpart KKKK of the NSPS regulations, the EPA promulgated regulations for the source category of stationary combustion turbines. The EPA did not promulgate regulations for turbines with smaller than 10 MMBtu/hr heat input, emergency units, or combustion turbine test cells. 40 CFR 60.4305(a), 60.4310(a), (d). (v) For other source categories, the EPA also declined to propose and promulgate standards of performance for the smaller sources. For example, for the source category of metal furniture coating operations, the EPA did not apply standards of performance to metal furniture surface coating operations that use less than 3.842 liters of coating (as applied) per year. 40 CFR 60.310(b). (vi) In proposing standards of performance for natural gas processing plants, the EPA proposed standards for only two of the three emission points in the plants ("storage emission sources" and "equipment leaks") and declined to propose standards for the third emission point ("process emission sources") on grounds that "[b]est demonstrated control technology has not been identified for [the latter] sources."  "Standards of Performance for New Stationary Sources; Onshore Natural Gas Processing Plants in the Natural Gas Production Industry, Equipment Leaks of VOC," 49 Fed. Reg. 2636, 2637 (January 20, 1984).
(iii). Lack of basis for specifying information
      A major reason why the EPA is not proposing a standard of performance for transitional sources is that it is relying, in part, on the one-year commence-construction limit to qualify a source as transitional: the EPA does not have sufficient information about the proposed sources' sunk costs and preconstruction steps to be able to identify which of these proposed sources may qualify as transitional sources. In addition, even if the EPA could determine that a particular proposed source would in fact become a transitional source, the EPA lacks information that, under these circumstances, may be important for determining BSER. For example, the EPA lacks information as to the amount of the proposed source's sunk costs, which may be relevant in determining BSER for these proposed sources. In addition, for proposed CCS sources, as noted above, the EPA does not have information as to key components of their proposed project and business plan, including, among other things, the amount of capture from the planned CCS system or possible revenue streams associated with CCS.
      Moreover, because transitional sources are defined by reference to the fact that they will commence construction within 12 months of the date of this proposal, it would be futile for the EPA to attempt to develop that information and then issue a proposal. By the time the EPA could do this, which would likely take at least a year, this set of sources will have become a null set: they either will have commenced construction, such that they would no longer be deemed "new sources" for purposes of CAA section 111, or they will not have commenced construction, such that they would be subject to the new source standard for non-transitional sources we are proposing today.
(iv). Practical problems
      In addition, the EPA's lack of information and other considerations give rise to several serious practical problems that would arise were the EPA to propose a standard of performance for transitional sources. Importantly, were the EPA to propose a standard of performance, all transitional sources would face substantial uncertainty as to what final standard the EPA would promulgate. This uncertainty would arise for several reasons. As noted, the EPA lacks information concerning transitional sources. In addition, transitional sources differ one from another in terms of design and in other respects, which would render the EPA's task more complex. As a result, there is risk that the EPA might finalize standards of performance different from what the EPA proposed. The final standards of performance may be more difficult for a given transitional source to meet.
      Other forms of uncertainty may arise as well. For example, a possible standard of performance that the EPA would consider would be based on identifying the BSER for transitional sources as the controls to which they would be subject under the terms of their PSD permits, with no further controls under section 111. With this approach, the EPA would need to determine the emission rate for each source that would reflect that source's level of CO2 emissions in accord with the terms of its PSD permit. This emission rate would constitute the "no-further-control" standard of performance. Note that under such an approach, each source would receive an emission limit unique to that source. However, some of the transitional sources may have a PSD permit that does not regulate CO2 because GHGs were not subject to PSD until the January 2, 2011 effective date of the first regulatory action controlling CO2 emissions under the CAA. Particularly for those sources, this approach could create uncertainty as to what the EPA would promulgate as the emission rate in the final standard of performance. This is because since these sources' permits do not specify a CO2 limit, the EPA would have to develop limits based on the design of the unit (including the project's type of technology and fuels).
      The uncertainties that the sources could experience as to what the final standards of performance would entail could well deter those sources from commencing construction until the EPA promulgated the final standard of performance. Such delay would undermine the usefulness of the requirement that sources commence construction within 12 months of today's rulemaking proposal as a mechanism for revealing which of these sources qualifies as a transitional source, and thus defeat the policy underlying the EPA's approach to transitional sources, which, for the reasons explained above, is to exclude from coverage by this new source standard only those sources that commence construction within 12 months of proposal. If sources are deterred from commencing construction until after the final rule, they will have lost the benefit of the 12-month window. As another practical problem, we also note concern with attempting to promulgate standards of performance for transitional sources at a time when it may reasonably be expected that some of the 15 sources with PSD permits may well not commence construction within 12 months (or may never do so). As a result, the effort to develop a standard of performance for those sources would have been unnecessary.
(v). Small number of transitional sources, lack of environmental benefit	As part of our reasoning for not proposing a standard of performance for transitional sources, we also take into consideration the fact that we expect the number of transitional sources to be small, no more than a few of the 15 potential sources listed above. Further, if we were to propose a "no further control" standard of performance, as described above, that approach would provide little, if any, environmental benefit because that standard would not likely provide further control beyond the limits of the sources' PSD permits. In fact, treating transitional sources as existing sources may achieve more reductions than a no-further-control NSPS standard for those sources by including them under the flexible existing source standard that the EPA expects to promulgate.
(vi). Other considerations.
      The EPA's approach of not proposing a standard of performance for transitional sources does not leave these sources uncontrolled. Rather, they would remain subject to whatever CO2 emission limits are included in, or result from compliance with, their PSD permits. And, although transitional sources would not be subject to the 1,000 lb CO2/MWh for new sources, the EPA anticipates that transitional sources would become subject to the requirements the EPA would promulgate at the appropriate time for existing sources under 111(d).
      In notable contrast, in the previous rulemakings cited above in which the EPA did not propose coverage of all sources within the relevant source category, because of the pollutants at issue in these actions, the decision not to propose coverage of all sources within the relevant source category operated without the assurance afforded by section 111(d) that uncovered sources would necessarily be picked up as existing sources subject to existing source guidelines. Where, as here, that assurance mechanism applies, the recognition and application of the Agency's discretion to not propose coverage of all sources in the source category is all the more appropriate.
      We recognize that this approach of not proposing a standard of performance for transitional sources could raise the question of consistency with the requirement implicit in the definition of "new source" under CAA section 111(a)(2) that a source be subject to a standard of performance when it commences construction after the date of proposal for that standard. We believe the approach is consistent with, and does not circumvent, that requirement. As noted, CAA section 111 does not require that all sources that newly commence construction be treated as new sources, and in past section 111 rulemakings, the EPA has not applied the standards of performance that it proposes and promulgates to all sources that newly commence construction in a source category. In addition to the reasons for not promulgating a standard for transitional sources provided above, where, as here, the pollutants covered by the proposed new source standard give rise to an obligation to develop section 111(d) guidelines for existing sources with the source category, ultimate coverage of the sources in question is inevitable, eliminating any prospect of a regulatory gap of any material concern.

C. Requirements for Reconstructions
1. Overview
      The EPA's framework regulations under CAA section 111 provide that reconstructed sources  - - which, in general, are existing sources that conduct extensive replacement of components -- are to be treated as new sources and, therefore, subject to new source standards of performance. In today's rulemaking, we do not propose any standard of performance for reconstructed sources, and we take comment how to approach reconstructions. We note that if we do not establish a new standard of performance for reconstructions, as a practical matter, that would mean that reconstructed sources would be treated as existing sources.
2. Background
a. The EPA Regulations. The EPA's framework regulations, interpreting the definition of "new source" in CAA section 111(a)(2), provide that an existing source, "upon reconstruction," becomes subject to the standard of performance for new sources. 40 CFR 60.15(a). The regulations define "reconstruction" as  -
      [T]he replacement of components of an existing facility to such an extent that:

      (1)       The fixed capital cost of the new components exceeds 50 percent of the fixed capital cost that would be required to construct a comparable entirely new facility, and

      (2)       It is technologically and economically feasible to meet the applicable standards set forth in this part.

40 CFR 60.15(b). Thus, a reconstruction occurs if the existing source replaces components to such an extent that the capital costs of the new components exceed 50 percent of the capital costs of an entirely new facility, even if the existing source does not increase emissions. In addition, the component replacement constitutes a reconstruction only if it is technologically and economically feasible for the source to meet the applicable standards.
      The regulations go on to require the owner or operator of an existing source that proposes to replace components to an extent that exceeds the 50 percent level, to notify the EPA and to provide specified information, including "a discussion of any economic or technical limitations the facility may have in complying with the applicable standards of performance after the proposed replacements."  In addition, the regulations require the EPA to determine, within a specified time period, whether the proposed replacement constitutes a reconstruction. 40 CFR 60.15(d) - (e).
b. Reconstructions. As with modifications, our base of knowledge concerning reconstructions has depended largely on the enforcement actions brought against power plants and on self-reporting by power plants.  Over the lengthy history of the NSPS program, those have been too few in number to allow us to develop a sufficiently robust base of knowledge to propose a standard of performance for reconstructions for GHGs at this time. The EPA is not aware that any power plants are presently planning any project that could meet the requirements for a reconstruction.
2. Options