The EPA is finalizing the third activity as "GHG evaluation at permit renewal." This activity covers the processing of all permit renewal applications and will involve evaluations of whether any GHG applicable requirements are properly included.
	Some members of the public commented that finalizing a GHG adjustment would inappropriately increase sources' financial burdens. The EPA has explained, both in the proposal notice and elsewhere in this preamble, the importance of the fee-related revisions to account for the costs associated with GHG-related permitting. The EPA believes that the revisions being finalized will result in modest and reasonable fee increases necessary to cover states' increased costs. To the extent that commenters intended to argue that the adjustments we proposed would exceed the actual costs of GHG permitting, no commenters provided any information or analysis to support that position. Some commenters did state that the costs associated with GHG-related permitting should be minimal because few applicable requirements will apply to GHGs. As stated earlier in this notice, EPA's cost estimate for the proposal concerned the incremental costs of GHG permitting for any source, not just those that would have, at the time of the analysis, triggered the requirement to get a permit based on GHG emissions or applicable requirements.
	Despite some comments received to the contrary, the EPA does not believe it is appropriate to delay the finalization of the GHG adjustment. The EPA does not believe such delays would be consistent with CAA section 502(b)(3)(A) because states have been incurring costs attributable to GHG permitting for several years now and increased fees must be collected to cover the increased costs. The regulatory changes being finalized in this action provide the states with optimal flexibility and sufficient funding to implement their GHG permitting programs. Some commenters had specifically stated that the EPA should delay finalization of this rule until the completion of the next ICR renewal process. While we do not believe delaying this rule is appropriate, as explained above, the EPA notes that we remain committed to collecting and analyzing additional data on costs attributable to GHG permitting for operating permit programs. We may adjust the GHG cost adjustments in future rulemakings if necessary to comply with the requirements of the Act.
	As an alternative to the options proposed by the EPA, some commenters asserted that the EPA should make a GHG cost adjustment using a separate, but reduced fee rate ($/ton) for GHGs. We, however, believe that the option 1 approach of the final rule will be more equitable for sources and more representative of actual costs because option 1 considers the costs of the actual permitting activities performed by a particular permitting authority, while any emissions-based approach would not be as directly related to actual costs incurred by permitting authorities.
	Some commenters alleged that EPA's proposal on adjustments to the operating permit programs was vague. The EPA provided a thorough discussion of our rationale in the proposal, including the basis for the GHG adjustments, and we proposed regulatory text to implement our proposal. We explained in the proposal that support for the cost adjustment for GHGs under option 1 is contained in several analyses performed by the EPA and approved by the OMB related to the effect of the addressing GHG requirements in operating permits. These analyses have been placed in the docket for this rulemaking. The analyses include: the Regulatory Impact Assessment (RIA) for the Tailoring Rule (see Regulatory Impact Analysis for the Final Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule, Final Report, May 2010); the part 70 ICR change request for the Tailoring Rule (which was based on the RIA for the Tailoring Rule); and the current ICR for part 70 (EPA ICR number 1587.12; OMB control number 2060 - 0243).
	Several commenters asked that we make changes to the option 1 approach that we proposed, such as adding new activities or decreasing the costs we assumed for the proposal. In response to these comments, we note that we received no quantitative data or other information from commenters that we believe demonstrates the need to revise the list of activities we included under option 1 or the burden hour assumptions under option 1 for the activities. Note that to promote consistent implementation of the final option 1 approach, the preamble describes elsewhere a few clarifications concerning the activities under option 1 and one minor revision to the regulatory text of one of the activities.
	Since the EPA's proposed rulemaking, the Supreme Court decided in UARG v. EPA that the EPA may not treat GHGs as an air pollutant for purposes of determining whether a source is a major source required to obtain a title V operating permit. The EPA's review of the effect of the Supreme Court decision on the burden hour assumptions for the GHG review activities under proposed option 1 is that the effects are not significant enough to warrant revision of the burden hour assumptions in the final rule. Proposed option 1 was based on the assumption that permitting authorities would need to evaluate all permit applications for initial permit issuance, significant and minor permit modifications, and permit renewals for GHG issues (even if there are no applicable GHG requirements). Even after the UARG v. EPA decision, permitting authorities will continue to need to evaluate GHG issues for sources applying for a title V permit and for permit modifications and renewals for existing permits, and we do not anticipate that the decision will significantly affect the total number of such evaluations that will occur in any given year compared to the assumptions in our analysis, which as explained above, were based on the incremental costs of GHG permitting for any source. Thus, we are finalizing the burden hour assumptions as they were proposed. See NSPS proposal at 1494 and the supporting statement for the 2012 part 70 ICR renewal. Also, as discussed previously, we remain committed to collecting and analyzing additional data on costs and we may adjust the burden hour assumptions or other aspects of option 1 in a future rulemaking, if needed.
c. The fee pollutant clarification. We are also finalizing the proposed addition of text within 40 CFR part 60, subpart TTTT, to clarify that the fee pollutant for operating permit purposes is GHG (as defined in 40 CFR 70.2 and 71.2). We are finalizing these provisions to add clarity to our regulations and to avoid the potential need for possible future rulemakings to adjust the title V fee regulations if any constituent of GHG, other than CO2, becomes subject to regulation under section 111 for the first time. The proposal was to add this clarifying text to 40 CFR prt 60, subparts Da, KKKK and TTTT. The final rule adds the clarification text only to subpart TTTT because the EPA is codifying all of the requirements for the affected EGUs in a new subpart TTTT and including all GHG emission standards for the affected sources (electric utility steam generating units, as well as natural gas-fired stationary combustion turbines) in that newly created subpart. See Section III.B of this preamble for more on this subject.
d. The GHG clarification. The EPA is taking no action at this time on the proposal to move the definitions of "Greenhouse gases (GHG)" within the definition of "Subject to regulation" in 40 CFR parts 70 and 71. No public comments were received on this proposed clarification; however, subsequent to the proposal, on June 23, 2014, the Supreme Court in UARG v. EPA decided that GHG emissions could not be used in making certain applicability determinations under the operating permit rules. More specifically with respect to title V, as described above, the Supreme Court said that the EPA may not treat GHGs as an air pollutant for purposes of determining whether a source is a major source required to obtain a title V operating permit. In accordance with the Supreme Court decision, on April 10, 2015, the D.C. Circuit issued an amended judgment in Coalition for Responsible Regulation, Inc. v. Environmental Protection Agency, Nos. 09-1322, 10-073, 10-1092 and 10-1167 (D.C. Cir. April 10, 2015), which, among other things, vacated the title V regulations under review in that case to the extent that they require a stationary source to obtain a title V permit solely because the source emits or has the potential to emit GHGs above the applicable major source thresholds. The D.C. Circuit also directed the EPA to consider whether any further revisions to its regulations are appropriate in light of UARG v. EPA, and, if so, to undertake to make such revisions.
      In response to the Supreme Court decision and the D.C. Circuit's amended judgment, the EPA intends to conduct future rulemaking action to make the appropriate revisions to the operating permit rules. As part of any such future rulemaking action, the EPA may consider finalizing the proposal to move the definitions of GHGs within the operating permit rules.
F. Interactions with Other EPA Rules
      Fossil fuel-fired EGUs are, or potentially will be, impacted by several other recently finalized or proposed EPA rules. Many of the rules that impact fossil fuel-fired EGUs apply to existing facilities as well as newly constructed, modified, or reconstructed facilities. In fact, the rules described below are more applicable to existing EGUs than to newly constructed, modified, or reconstructed EGUs. Although those rules will affect EGUs as existing sources, because we expect that there will be few modifications or reconstructions, we don't anticipate those rules affecting EGUs as modified or reconstructed sources. In constructing new EGUs, sources can take all applicable requirements of the various rules into consideration.
1. Mercury and Air Toxics Standards (MATS)
      On February 16, 2012, the EPA issued the MATS rule (77 FR 9304) to reduce emissions of toxic air pollutants from new and existing coal- and oil-fired EGUs. The MATS rule will reduce emissions of heavy metals, including mercury (Hg), arsenic (As), chromium (Cr), and nickel (Ni); and acid gases, including hydrochloric acid (HCl) and hydrofluoric acid (HF). These toxic air pollutants, also known as hazardous air pollutants or air toxics, are known to cause, or suspected of causing, damage nervous system damage, cancer, and other serious health effects. The MATS rule will also reduce SO2 and fine particle pollution, which will reduce particle concentrations in the air and prevent thousands of premature deaths and tens of thousands of heart attacks, bronchitis cases and asthma episodes.
      New or reconstructed EGUs (i.e., sources that commence construction or reconstruction after May 3, 2011) subject to the MATS rule are required to comply by April 16, 2012 or upon startup, whichever is later.
      Existing sources subject to the MATS rule were required to begin meeting the rule's requirements on April 16, 2015. Controls that will achieve the MATS performance standards are being installed on many units. Certain units, especially those that operate infrequently, may be considered not worth investing in given today's electricity market, and are closing. The final MATS rule provided a foundation on which states and other permitting authorities could rely in granting an additional, fourth year for compliance provided for by the CAA. States report that these fourth year extensions are being granted. In addition, the EPA issued an enforcement policy that provides a clear pathway for reliability-critical units to receive an administrative order that includes a compliance schedule of up to an additional year, if it is needed to ensure electricity reliability.
2. Cross-State Air Pollution Rule (CSAPR)
      The CSAPR requires states to take action to improve air quality by reducing SO2 and nitrogen oxide (NOX) emissions that cross state lines. These pollutants react in the atmosphere to form fine particles and ground-level ozone and are transported long distances, making it difficult for other states to attain and maintain the NAAQS. The first phase of CSAPR became effective on January 1, 2015, for SO2 and annual NOX, and May 1, 2015, for ozone season NOX. The second phase will become effective on January 1, 2017, for SO2 and annual NOx, and May 1, 2017, for ozone season NOx. Many of the power plants participating in CSAPR have taken actions to reduce hazardous air pollutants for MATS compliance that will also reduce SO2 and/or NOx. In this way these two rules are complementary. Compliance with one helps facilities comply with the other.
3. Requirements for Cooling Water Intake Structures at Power Plants (316(b) Rule)
      On May 19, 2014, the EPA issued a final rule under section 316(b) of the Clean Water Act (33 U.S. Code section 1326(b)) (referred to hereinafter as the 316(b) rule.) The rule was published on August 15, 2014 (79 FR 48300; August 15, 2014), and became effective October 14, 2014. The 316(b) rule establishes new standards to reduce injury and death of fish and other aquatic life caused by cooling water intake structures at existing power plants and manufacturing facilities. The 316(b) rule subjects existing power plants and manufacturing facilities that withdraw in excess of 2 million gallons per day (MGD) of cooling water, and use at least 25 percent of that water for cooling purposes, to a national standard designed to reduce the number of fish destroyed through impingement and entrainment. Existing sources subject to the 316(b) rule are required to comply with the impingement requirements as soon as practicable after the entrainment requirements are determined. They must comply with applicable site-specific entrainment reduction controls based on the schedule of requirements established by the permitting authority. Additional information regarding the 316(b) rule for existing sources is included in section IX.C of the preamble to the CAA section 111(d) emission guidelines for existing EGUs that the EPA is finalizing simultaneously with this rule. Although the recently issued 316(b) rule discussed here applies to existing sources, there are also 316(b) technology-based standards for new sources with cooling water intake structures.
4. Disposal of Coal Combustion Residuals from Electric Utilities (CCR Rule)
      On December 19, 2014, the EPA issued the final rule for the disposal of coal combustion residuals from electric utilities. The rule provides a comprehensive set of requirements for the safe disposal of coal combustion residuals (CCRs), commonly known as coal ash, from coal-fired power plants. The CCR rule establishes technical requirements for existing and new CCR landfills and surface impoundments under Subtitle D of the Resource Conservation and Recovery Act (RCRA), the nation's primary law for regulating solid waste. New CCR landfills and surface impoundments are required to meet the technical criteria before any CCR is placed into the unit. Existing CCR surface impoundments and landfills are subject to implementation timeframes established in the rule for the individual technical criteria. For additional information regarding the CCR rule, see section IX.C of the preamble to the CAA section 111(d) emission guidelines for existing EGUs that the EPA is finalizing simultaneously with this rule.
5. Steam Electric Effluent Limitation Guidelines and Standards (SE ELG Rule)
      The EPA is reviewing public comments and working to finalize the proposed SE ELG rule which will impact fossil fuel-fired EGUs. In 2013, the EPA proposed the SE ELG rule (78 FR 34432; June 7, 2013) to strengthen the controls on discharges from certain steam electric power plants by revising technology-based effluent limitations guidelines and standards for the steam electric power generating point source category. The proposed regulation, which includes new requirements for both existing and new generating units, would reduce impacts to human health and the environment by reducing the amount of toxic metals and other pollutants currently discharged to surface waters from power plants. The EPA intends to take final action on the proposed rule by September 30, 2015. Section IX.C of the preamble to the CAA section 111(d) emission guidelines for existing EGUs that the EPA is finalizing simultaneously with this rule includes additional information regarding the SE ELG rule.
	The EPA recognizes the importance of assuring that each of the rules described above can achieve its intended environmental objectives in a commonsense, cost-effective manner, consistent with underlying statutory requirements, and while assuring a reliable power system. Executive Order (EO) 13563, "Improving Regulation and Regulatory Review," issued on January 18, 2011, states that "[i]n developing regulatory actions and identifying appropriate approaches, each agency shall attempt to promote... coordination, simplification, and harmonization. Each agency shall also seek to identify, as appropriate, means to achieve regulatory goals that are designed to promote innovation." Within the EPA, we are paying careful attention to the interrelatedness and potential impacts on the industry, reliability and cost that these various rulemakings can have.
      As discussed in earlier sections of this preamble, the EPA has identified potential alternative compliance pathways for affected newly constructed, modified, and reconstructed fossil fuel-fired steam generating units. We are finalizing an emission standard for newly constructed fossil fuel-fired steam generating units that can be met by capturing and storing approximately 20 percent of the CO2 produced from the facility or by utilizing other technologies such as natural gas co-firing. For a subcategory of steam generating units that conduct "large" modifications according to definitions in this final rule, we are finalizing an emission standard that is based on a unit-specific emission limitation consistent with each modified unit's best one-year historical performance and can be met through a combination of best operating practices and equipment upgrades. For reconstructed steam generating units, the EPA is finalizing standards of performance based on the performance of the most efficient generation technology available, which we concluded is the use of the best available subcritical steam conditions for small units and the use of supercritical steam conditions for large units. The standards can also be met through other technology options such as natural gas co-firing. In light of these potential alternative compliance pathways, we believe that sources will have ample opportunity to coordinate their response to this rule with any obligations that may be applicable to affected EGUs as a result of the MATS, CSAPR, 316(b), SE ELG and CCR rules, all of which are or soon will be final rules  --  and to do so in a manner that will help reduce cost and ensure reliability, while also ensuring that all applicable environmental requirements are met.
      The EPA is also endeavoring to enable EGUs to comply with applicable obligations under other power sector rules as efficiently as possible (e.g., by facilitating their ability to coordinate planning and investment decisions with respect to those rules) and, where possible, implement integrated compliance strategies. Section IX.C of the preamble to the CAA section 111(d) emission guidelines for existing EGUs that the EPA is finalizing simultaneously with this rule describes such an example with respect to the SE ELG and CCR rules.
      In light of the compliance flexibilities we are offering in this action, we believe that sources will have ample opportunity to use cost-effective regulatory strategies and build on their longstanding, successful records of complying with multiple CAA, CWA, and other environmental requirements, while assuring an adequate, affordable, and reliable supply of electricity.
XII. Impacts of this Action
      As explained in the "Regulatory Impact Analysis for the Standards of Performance for Greenhouse Gas Emissions for New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units" (EPA-452/R-XX-YYY, June 2015) (RIA), available data indicate that, even in the absence of the standards of performance for newly constructed EGUs, existing and anticipated economic conditions will lead electricity generators to choose new generation technologies that will meet the standards without installation of additional controls. Therefore, based on the analysis presented in Chapter 4 of the RIA, the EPA projects that this final rule will result in negligible CO2 emission changes, quantified benefits, and costs on owners and operators of newly constructed EGUs by 2022. This conclusion is based on the EPA's own modeling as well as projections by EIA. While the primary conclusion of the analysis presented in the RIA is that the standards for newly constructed EGUs will result in negligible costs and benefits, the EPA has also performed several illustrative analyses the show the potential impacts of the rule if certain key assumptions were to change. This includes an analysis of the impacts under a range of natural gas prices and the costs and benefits associated with building an illustrative coal-fired EGU with CCS. These are presented in Chapter 5 of the RIA.
      As also explained in the RIA for this final rule, the EPA also expects that few sources will trigger either the NSPS modification or reconstruction provisions that we are finalizing today. In Chapter 6 of the RIA, we discuss factors that limit our ability to quantify the costs and benefits of the standards for modified and reconstructed sources.
A. What are the air impacts?
      As explained immediately above, the EPA does not anticipate that this final rule will result in notable CO2 emission changes by 2022 as a result of the standards of performance for newly constructed EGUs. The owners of newly constructed EGUs will likely choose technologies, primarily NGCC, which meet the standards even in the absence of this rule due to existing economic conditions as normal business practice.
      As also explained immediately above, the EPA expects few modified or reconstructed EGUs in the period of analysis.
B. Endangered Species Act
     Consistent with the requirements of section 7(a)(2) of the Endangered Species Act (ESA), the EPA has also considered the effects of this rule and has reviewed applicable ESA regulations, case law, and guidance to determine what, if any, impact there may be to listed endangered or threatened species or designated critical habitat. Section 7(a)(2) of the ESA requires federal agencies, in consultation with the U.S. Fish and Wildlife Service (FWS) and/or the National Marine Fisheries Service, to ensure that actions they authorize, fund, or carry out are not likely to jeopardize the continued existence of federally listed endangered or threatened species or result in the destruction or adverse modification of designated critical habitat of such species. 16 U.S.C. 1536(a)(2). Under relevant implementing regulations, ESA section 7(a)(2) applies only to actions where there is discretionary federal involvement or control. 50 CFR 402.03. Further, under the regulations consultation is required only for actions that "may affect" listed species or designated critical habitat. 50 CFR 402.14. Consultation is not required where the action has no effect on such species or habitat. Under this standard, it is the federal agency taking the action that evaluates the action and determines whether consultation is required. See 51 FR 19926, 19949 (June 3, 1986). Effects of an action include both the direct and indirect effects that will be added to the environmental baseline. 50 CFR 402.02. Indirect effects are those that are caused by the action, later in time, and are reasonably certain to occur. Id. To trigger a consultation requirement, there must thus be a causal connection between the federal action, the effect in question, and the listed species, and the effect must be reasonably certain to occur.
     The EPA has considered the effects of this rule and has reviewed applicable ESA regulations, case law, and guidance to determine what, if any, impact there may be to listed species or designated critical habitat for purposes of ESA section 7(a)(2) consultation. The EPA notes that the projected environmental effects of this final action are positive: reductions in overall GHG emissions, and reductions in PM and ozone-precursor emissions (SOX and NOX). These reductions are projected to be minor. Although the final rule imposes substantial controls on CO2 emissions, we project few if any new fossil fuel-fired steam generating units to be built. Emissions reductions from turbines are likewise projected to be minimal. With respect to the projected GHG emission reductions, the EPA does not believe that such reductions trigger ESA consultation requirements under section 7(a)(2). In reaching this conclusion, the EPA is mindful of significant legal and technical analysis undertaken by FWS and the U.S. Department of the Interior in the context of listing the polar bear as a threatened species under the ESA. In that context, in 2008, FWS and DOI expressed the view that the best scientific data available were insufficient to draw a causal connection between GHG emissions and effects on the species in its habitat.[329]  The DOI Solicitor concluded that where the effect at issue is climate change, proposed actions involving GHG emissions cannot pass the "may affect" test of the section 7 regulations and thus are not subject to ESA consultation. The EPA has also previously considered issues relating to GHG emissions in connection with the requirements of ESA section 7(a)(2). The EPA evaluated this same issue in the context of the light duty vehicle GHG emission standards for model years 2012-2016 and 2017-2025. There the agency projected GHG emission reductions many orders of magnitude greater over the lifetimes of the model years in question[330] and, based on air quality modeling of potential environmental effects, concluded that "EPA knows of no modeling tool which can link these small, time-attenuated changes in global metrics to particular effects on listed species in particular areas. Extrapolating from global metric to local effect with such small numbers, and accounting for further links in a causative chain, remain beyond current modeling capabilities." EPA, Light Duty Vehicle Greenhouse Gas Standards and Corporate Average Fuel Economy Standards, Response to Comment Document for Joint Rulemaking at 4-102 (Docket EPA-OAR-HQ-2009-4782). The EPA reached this conclusion after evaluating issues relating to potential improvements relevant to both temperature and oceanographic pH outputs. The EPA's ultimate finding was that "any potential for a specific impact on listed species in their habitats associated with these very small changes in average global temperature and ocean pH is too remote to trigger the threshold for ESA section 7 (a)(2)."Id. The EPA believes that the same conclusions apply to the present action, given that the projected CO 2 emission reductions are far less than those projected for either of the light duty vehicle rules. See, e.g., Ground Zero Center for Non-Violent Action v. U.S. Dept. of Navy, 383 F. 3d 1082, 1091-92 (9th Cir. 2004) (where the likelihood of jeopardy to a species from a federal action is extremely remote, ESA does not require consultation).
C.	What are the energy impacts?
      This final rule is not anticipated to have a notable effect on the supply, distribution, or use of energy. As previously stated, the EPA believes that electric power companies will choose to build new EGUs that comply with the regulatory requirements of this rule even in its absence, primarily NGCC units, because of existing and expected market conditions. As also previously stated, the EPA expects few reconstructed or modified EGUs in the period of analysis.
D. What are the water and solid waste impacts?
This final rule is not anticipated to have notable impacts on water or solid waste. As we have noted, the EPA believes that utilities and project developers will choose to build new EGUs that comply with the regulatory requirements of this rule even in its absence, primarily through the construction of new NGCC units. As also previously stated, the EPA expects few reconstructed or modified EGUs in the period of analysis. Still there are expected to be a small number of coal plants with CCS and the use of CCS systems (especially post-combustion system) will increase the amount of water used at the facility. If those plant utilize partial CCS to meet the final standard of performance (i.e., approximately 20 percent capture), the increased water use will not be significant. The EPA is unaware of any solid waste impact resulting from this rule.
E. What are the compliance costs?
      The EPA believes the standards of performance for newly constructed EGUs will have no notable compliance costs, because electric power companies are expected to build new EGUs that comply with the regulatory requirements of this final rule even in the absence of the rule, primarily NGCC units, due to existing and expected market conditions. While the EPA's analysis and projections from EIA continue to show that the rule is likely to result in negligible costs and benefits due to existing generation choices, the EPA recognizes that some companies may choose to construct coal or other fossil fuel-fired units and has set standards for these units accordingly. For this reason, the RIA also analyzes project-level costs of a unit with and without CCS, to quantify the potential cost for a fossil fuel-fired unit with CCS.
      In addition, the EPA believes the standards of performance for modified and reconstructed EGUs will have minimal associated compliance costs, because, as previously stated, the EPA expects few modified or reconstructed EGUs in the period of analysis.
F. What are the economic and employment impacts?
	The EPA does not anticipate that this final rule will result in notable CO2 emission changes, energy impacts, monetized benefits, costs, or economic impacts by 2022 as a result of the standards of performance for newly constructed EGUs. The owners of newly constructed EGUs will likely choose technologies that meet the standards even in the absence of this rule, due to existing economic conditions as normal business practice. Likewise, the EPA believes this rule will not have any impacts on the price of electricity, employment or labor markets, or the U.S. economy.
      As previously stated, the EPA anticipates few units will trigger the modification or reconstruction provisions. As with the new source standards, the EPA does not expect macroeconomic or employment impacts as a result of the standards.
G. What are the benefits of the final standards?
      There are no direct monetized climate benefits in terms of CO2 emission reductions associated with these standards of performance. However, by clarifying that in the future, newly constructed coal-fired power plants will be required to meet a particular performance standard, this rule provides a path forward for new coal-fired generation and the deployment of CCS. It ensures that new EGUs, whether gas or coal-fired, will meet standards for CO2 control into the future.
      As also previously stated, the EPA anticipates few units will trigger the modification or reconstruction provisions. In Chapter 6 of the RIA, we discuss factors that limit our ability to quantify the costs and benefits of the standards for modified and reconstructed sources.
XII. Statutory and Executive Order Reviews
Additional information about these Statutory and Executive Orders can be found at http://www2.epa.gov/laws-regulations/laws-and-executive-orders.
A. Executive Order 12866, Regulatory Planning and Review, and Executive Order 13563, Improving Regulation and Regulatory Review
	This final action is a significant regulatory action that was submitted to the Office of Management and Budget (OMB) for review. It is a significant regulatory action because it raises novel legal or policy issues arising out of legal mandates. Any changes made in response to OMB recommendations have been documented in the established dockets for this action under Docket ID No. EPA-HQ-OAR-2013-0495 (Standards of Performance for Greenhouse Gas Emissions from New Stationary Sources: Electric Utility Generating Units) and Docket ID No. EPA-HQ-OAR-2013-0603 (Carbon Pollution Standards for Modified and Reconstructed Stationary Sources: Electric Utility Generating Units). The EPA prepared an economic analysis of the potential costs and benefits associated with this action. This analysis, which is contained in the "Regulatory Impact Analysis for the Standards of Performance for Greenhouse Gas Emissions for New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units" (EPA-452/R-XX-YYY, June 2015), is available in both dockets.
     The EPA does not anticipate that this final action will result in any notable compliance costs. Specifically, we believe that the standards for newly constructed fossil fuel-fired EGUs (electric utility steam generating units and natural gas-fired stationary combustion turbines) will have negligible costs associated with it over a range of likely sensitivity conditions because electric power companies will choose to build new EGUs that comply with the regulatory requirements of this action even in the absence of the action, because of existing and expected market conditions. (See the RIA for further discussion of sensitivities). The EPA does not project any new coal-fired steam generating units without CCS to be built in the absence of this action. However, because some companies may choose to construct coal or other fossil fuel-fired EGUs, the RIA also analyzes project-level costs of a unit with and without CCS, to quantify the potential cost for a fossil fuel-fired EGU with CCS.
      The EPA also believes that the standards for modified and reconstructed fossil fuel-fired EGUs will result in minimal compliance costs, because, as previously stated, the EPA expects few modified or reconstructed EGUs in the period of analysis (through 2022). In Chapter 6 of the RIA, we discuss factors that limit our ability to quantify the costs and benefits of the standards for modified and reconstructed sources.
B. Paperwork Reduction Act (PRA)
     The information collection activities in this final action have been submitted for approval to OMB under the PRA. The Information Collection Request (ICR) document that the EPA prepared has been assigned EPA ICR number XX. Separate ICR documents were prepared and submitted to OMB for the proposed standards for newly constructed EGUs (EPA ICR number 2465.02) and the proposed standards for modified and reconstructed EGUs (EPA ICR number 2506.03). Because the CO2 standards for newly constructed, modified, and reconstructed EGUs will be included in the same new subpart (40 CFR part 60, subpart TTTT) and are being finalized in the same action, the ICR document for this action includes estimates of the information collection burden on owners and operators of newly constructed, modified, and reconstructed EGUs. Estimated cost burden is based on 2013 Bureau of Labor Statistics (BLS) labor cost data. Thus, all burden estimates are in 2013 dollars. Burden is defined at 5 CFR 1320.3(b). You can find a copy of the ICR in the dockets for this action (Docket ID Numbers EPA-HQ-OAR-2013-0495 and EPA-HQ-OAR-2013-0603), and it is briefly summarized here. The information collection requirements are not enforceable until OMB approves them.
	The recordkeeping and reporting requirements in this final action are specifically authorized by CAA section 114 (42 U.S.C. 7414). All information submitted to the EPA pursuant to the recordkeeping and reporting requirements for which a claim of confidentiality is made is safeguarded according to Agency policies set forth in 40 CFR part 2, subpart B.
	An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. The OMB control numbers for the EPA's regulations in 40 CFR are listed in 40 CFR part 9. When OMB approves this ICR, the Agency will announce that approval in the Federal Register and publish a technical amendment to 40 CFR part 9 to display the OMB control number for the approved information collection activities contained in this final action.
1. Newly Constructed EGUs
      This final action will impose minimal new information collection burden on owners and operators of affected newly constructed fossil fuel-fired EGUs (steam generating units and natural gas-fired stationary combustion turbines) beyond what those sources would already be subject to under the authorities of CAA parts 75 and 98. OMB has previously approved the information collection requirements contained in the existing part 75 and 98 regulations (40 CFR part 75 and 40 CFR part 98) under the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. and has assigned OMB control numbers 2060-0626 and 2060-0629, respectively. Apart from certain reporting costs based on requirements in the NSPS General Provisions (40 CFR part 60, subpart A), which are mandatory for all owners/operators subject to CAA section 111 national emission standards, there are no new information collection costs, as the information required by the standards for newly constructed EGUs is already collected and reported by other regulatory programs.
     The EPA believes that electric power companies will choose to build new EGUs that comply with the regulatory requirements of the rule because of existing and expected market conditions. The EPA does not project any newly constructed coal-fired steam generating units that commenced construction after proposal (January 8, 2014) to commence operation over the 3-year period covered by this ICR. We estimate that 17 affected newly constructed natural gas-fired stationary combustion turbines will commence operation during that time period. As a result of this final action, owners or operators of those newly constructed units will be required to prepare a summary report, which includes reporting of emissions and downtime, every 3 months.
2. Modified and Reconstructed EGUs
      This final action is not expected to impose an information collection burden under the provisions of the PRA on owners and operators of affected modified and reconstructed fossil fuel-fired EGUs (steam generating units and natural gas-fired stationary combustion turbines). As previously stated, the EPA expects few modified or reconstructed EGUs in the period of analysis. Specifically, the EPA believes it unlikely that fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines will take actions that would constitute modifications or reconstructions as defined under the EPA's NSPS regulations. Accordingly, the standards for modified and reconstructed EGUs are not anticipated to impose any information collection burden over the 3-year period covered by this ICR. We have estimated, however, the information collection burden that would be imposed on an affected EGU if it was modified or reconstructed.
	Although not anticipated, if an EGU were to modify or reconstruct, this final action would impose minimal information collection burden on those affected sources beyond what they would already be subject to under the authorities of CAA 40 CFR parts 75 and 98. As described above, the OMB has previously approved the information collection requirements contained in the existing part 75 and 98 regulations. Apart from certain reporting costs, which are mandatory for all owners/operators subject to CAA section 111 national emission standards, there would be no new information collection costs, as the information required by the final rule is already collected and reported by other regulatory programs.
      As stated above, although the EPA expects few sources will trigger either the NSPS modification or reconstruction provisions, if an EGU were to modify or reconstruct during the 3-year period covered by this ICR, the owner or operator of the EGU will be required to prepare a summary report, which includes reporting of emissions and downtime, every 3 months. The annual reporting burden for such a unit is estimated to be $2,665 and 32 labor hours. There are no annualized capital costs or O&M costs associated with burden for modified or reconstructed EGUs.
3. Information Collection Burden
      The annual information collection burden for newly constructed, modified, and reconstructed EGUs consists only of reporting burden as explained above. The annual reporting burden for this collection (averaged over the first 3 years after the effective date of the standards) is estimated to be $32,886 and 395 labor hours. There are no annualized capital costs or O&M costs associated with burden for newly constructed EGUs. Average burden hours per response are estimated to be 8 hours. The total number of respondents over the 3-year ICR period is estimated to be 37.
C. Regulatory Flexibility Act (RFA)
	I certify that this final action will not have a significant economic impact on a substantial number of small entities under the RFA. In making this determination, the impact of concern is any significant adverse economic impact on small entities. An agency may certify that a rule will not have a significant economic impact on a substantial number of small entities if the rule relieves regulatory burden, has no net burden or otherwise has a positive economic effect on the small entities subject to the rule.
1. Newly Constructed EGUs
	The EPA believes that electric power companies will choose to build new fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines that comply with the regulatory requirements of the final rule because of existing and expected market conditions. The EPA does not project any new coal-fired steam generating units without CCS to be built. We expect that any newly constructed natural gas-fired stationary combustion turbines will meet the standards. We do not include an analysis of the illustrative impacts on small entities that may result from implementation of the final rule because we anticipate negligible compliance costs over a range of likely sensitivity conditions as a result of the standards for newly constructed EGUs. Thus the cost-to-sales ratios for any affected small entity would be zero costs as compared to annual sales revenue for the entity. Accordingly, there are no anticipated economic impacts as a result of the standards for newly constructed EGUs. (See the "Regulatory Impact Analysis for the Standards of Performance for Greenhouse Gas Emissions for New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units" (EPA-452/R-XX-YYY, June 2015) for further discussion of sensitivities.) We have therefore concluded that this final action will have no net regulatory burden for all directly regulated small entities.
2. Modified and Reconstructed EGUs
      The EPA expects few modified fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines in the period of analysis. An NSPS modification is defined as a physical or operational change that increases the source's maximum achievable hourly rate of emissions. The EPA does not believe that there are likely to be EGUs that will take actions that would constitute modifications as defined under the EPA's NSPS regulations.
      In addition, the EPA expects few reconstructed fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines in the period of analysis. Reconstruction occurs when a single project replaces components or equipment in an existing facility and exceeds 50 percent of the fixed capital cost that would be required to construct a comparable entirely new facility.
      In Chapter 6 of the RIA, we discuss factors that limit our ability to quantify the costs and benefits of the standards for modified and reconstructed sources. However, we do not anticipate that the rule would impose significant costs on those sources, including any that are owned by small entities. (See the "Regulatory Impact Analysis for the Standards of Performance for Greenhouse Gas Emissions for New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units" (EPA-452/R-XX-YYY, June 2015).
D. Unfunded Mandates Reform Act (UMRA)
This final action does not contain an unfunded mandate of $100 million or more as described in UMRA, 2 U.S.C. 1531 - 1538, and does not significantly or uniquely affect small governments.
The EPA believes the final rule will have negligible compliance costs on owners and operators of newly constructed EGUs over a range of likely sensitivity conditions because electric power companies will choose to build new fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines that comply with the regulatory requirements of the rule because of existing and expected market conditions. The EPA does not project any new coal-fired steam generating units without CCS to be built and expects that any newly constructed natural gas-fired stationary combustion turbines will meet the standards. (See the "Regulatory Impact Analysis for the Standards of Performance for Greenhouse Gas Emissions for New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units" (EPA-452/R-XX-YYY, June 2015) for further discussion of sensitivities.)
      As previously stated, the EPA expects few modified or reconstructed fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines in the period of analysis. In Chapter 6 of the RIA, we discuss factors that limit our ability to quantify the costs and benefits of the standards for modified and reconstructed sources. However, we do not anticipate that the rule would impose significant costs on those sources. (See the "Regulatory Impact Analysis for the Standards of Performance for Greenhouse Gas Emissions for New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units" (EPA-452/R-XX-YYY, June 2015).)
      We have therefore concluded that the standards for newly constructed, modified, and reconstructed EGUs do not impose enforceable duties on any state, local or tribal governments, or the private sector, that may result in expenditures by state, local and tribal governments, in the aggregate, or to the private sector, of $100 million or more in any one year. We have also concluded that this action does not have regulatory requirements that might significantly or uniquely affect small governments. The threshold amount established for determining whether regulatory requirements could significantly affect small governments is $100 million annually and, as stated above, we have concluded that the final action will not result in expenditures of $100 million or more in any one year. Specifically, the EPA does not project any new coal-fired steam generating units without CCS to be built and expects that any newly constructed natural gas-fired stationary combustion turbines will meet the standards. Further, the EPA expects few modified or reconstructed fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines in the period of analysis.
E. Executive Order 13132, Federalism
      This final action does not have federalism implications. It will not have substantial direct effects on the states, on the relationship between the national government and the states, or on the distribution of power and responsibilities among the various levels of government. The EPA believes that electric power companies will choose to build new fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines that comply with the regulatory requirements of the final rule because of existing and expected market conditions. In addition, as previously stated, the EPA expects few modified or reconstructed fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines in the period of analysis. We, therefore, anticipate that the final rule will impose minimal compliance costs.
F. Executive Order 13175, Consultation and Coordination with Indian Tribal Governments
      This final action does not have tribal implications as specified in Executive Order 13175. The final rule will impose requirements on owners and operators of newly constructed, modified, and reconstructed EGUs. The EPA is aware of three facilities with coal-fired steam generating units, as well as one facility with natural gas-fired stationary combustion turbines, located in Indian Country, but is not aware of any EGUs owned or operated by tribal entities. We note that because the rule addresses CO2 emissions from newly constructed, modified, and reconstructed EGUs, it will affect existing EGUs such as those located at the four facilities in Indian Country only if those EGUs were to take actions constituting modifications or reconstructions as defined under the EPA's NSPS regulations. As previously stated, the EPA expects few modified or reconstructed EGUs in the period of analysis. Thus, the rule will neither impose substantial direct compliance costs on tribal governments nor preempt Tribal law. Accordingly, Executive Order 13175 does not apply to this action.
      Nevertheless, because the EPA is aware of Tribal interest in carbon pollution standards for the power sector and, consistent with the EPA Policy on Consultation and Coordination with Indian Tribes, the EPA offered consultation with tribal officials during development of this rule. Prior to the April 13, 2012 proposal (77 FR 22392), the EPA sent consultation letters to the leaders of all federally recognized tribes. Although only newly constructed, modified, and reconstructed EGUs will be affected by this action, the EPA's consultation regarded planned actions for new and existing sources. The letters provided information regarding the EPA's development of NSPS and emission guidelines for EGUs and offered consultation. A consultation/outreach meeting was held on May 23, 2011, with the Forest County Potawatomi Community, the Fond du Lac Band of Lake Superior Chippewa Reservation, and the Leech Lake Band of Ojibwe. A description of that consultation is included in the preamble to the proposed standards for new EGUs (79 FR 1501, January 8, 2014).
The EPA also offered consultation to the leaders of all federally recognized tribes after the proposed action for newly constructed EGUs was signed on September, 20, 2013. On November 1, 2013, the EPA sent letters to tribal leaders that provided information regarding the EPA's development of carbon pollution standards for new, modified, reconstructed and existing EGUs and offered consultation. No tribes requested consultation regarding the standards for newly constructed EGUs.
In addition to offering consultation, the EPA also conducted outreach to tribes during development of this rule. The EPA held a series of listening sessions prior to proposal of GHG standards for newly constructed EGUs. Tribes participated in a session on February 17, 2011, with the state agencies, as well as in a separate session with tribes on April 20, 2011. The EPA also held a series of listening sessions prior to proposal of GHG standards for modified and reconstructed EGUs and GHG emission guidelines for existing EGUs. Tribes participated in a session on September 9, 2013, together with the state agencies, as well as in a separate tribe-only session on September 26, 2013. In addition, an outreach meeting was held on September 9, 2013, with tribal representatives from some of the federally recognized tribes. The EPA also met with tribal environmental staff with the National Tribal Air Association, by teleconference, on July 25, 2013, and December 19, 2013. Additional detail regarding this stakeholder outreach is included in the preamble to the proposed emission guidelines for existing EGUs (79 FR 34830, June 18, 2014).
G. Executive Order 13045, Protection of Children from Environmental Health Risks and Safety Risks
      This action is not subject to Executive Order 13045 because it is not economically significant as defined in Executive Order 12866. While the action is not subject to Executive Order 13045, the EPA believes that the environmental health or safety risk addressed by this action has a disproportionate effect on children. Accordingly, the agency has evaluated the environmental health and welfare effects of climate change on children.
       CO2 is a potent greenhouse gas that contributes to climate change and is emitted in significant quantities by fossil fuel-fired power plants. The EPA believes that the CO2 emission reductions resulting from implementation of these final guidelines, as well as substantial ozone and PM2.5 emission reductions as a co-benefit, will further improve children's health.
      The assessment literature cited in the EPA's 2009 Endangerment Finding concluded that certain populations and lifestages, including children, the elderly, and the poor, are most vulnerable to climate-related health effects. The assessment literature since 2009 strengthens these conclusions by providing more detailed findings regarding these groups' vulnerabilities and the projected impacts they may experience.
      These assessments describe how children's unique physiological and developmental factors contribute to making them particularly vulnerable to climate change. Impacts to children are expected from heat waves, air pollution, infectious and waterborne illnesses, and mental health effects resulting from extreme weather events. In addition, children are among those especially susceptible to most allergic diseases, as well as health effects associated with heat waves, storms, and floods. Additional health concerns may arise in low income households, especially those with children, if climate change reduces food availability and increases prices, leading to food insecurity within households.
       More detailed information on the impacts of climate change to human health and welfare is provided in Section II.A of this preamble.
H. Executive Order 13211, Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use
      This final action is not a "significant energy action" because it is not likely to have a significant adverse effect on the supply, distribution, or use of energy. The EPA believes that electric power companies will choose to build new fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines that comply with the regulatory requirements of the final rule because of existing and expected market conditions. In addition, as previously stated, the EPA expects few modified or reconstructed fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines in the period of analysis. Thus, this action is not anticipated to have notable impacts on emissions, costs or energy supply decisions for the affected electric utility industry.
I. National Technology Transfer and Advancement Act
      This final action involves technical standards. The following voluntary consensus standards are used in the final rule: American Society for Testing and Materials (ASTM) Methods D388-12 (Standard Classification of Coals by Rank), D396-13c (Standard Specification for Fuel Oils), D975-14 (Standard Specification for Diesel Fuel Oils), D3699-13b (Standard Specification for Kerosene), D6751-12 (Standard Specification for Biodiesel Fuel Blend Stock (B100) for Middle Distillate Fuels), D7467-13 (Standard Specification for Diesel Fuel Oil, Biodiesel Blend (B6 to B20)), and American National Standards Institute (ANSI) Standard C12.20 (American National Standard for Electricity Meters - 0.2 and 0.5 Accuracy Classes). The rule also requires use of Appendices A, B, D, F and G to 40 CFR part 75; these Appendices contain standards that have already been reviewed under the NTTAA.
J. Executive Order 12898: Federal Actions to Address Environmental Justice in Minority Populations and Low-Income Populations
      Executive Order 12898 (59 FR 7629; February 16, 1994) establishes federal executive policy on environmental justice. Its main provision directs federal agencies, to the greatest extent practicable and permitted by law, to make environmental justice part of their mission by identifying and addressing, as appropriate, disproportionately high and adverse human health or environmental effects of their programs, policies and activities on minority populations and low-income populations in the U.S. The EPA defines environmental justice as the fair treatment and meaningful involvement of all people regardless of race, color, national origin, or income with respect to the development, implementation, and enforcement of environmental laws, regulations, and policies. The EPA has this goal for all communities and persons across this Nation. It will be achieved when everyone enjoys the same degree of protection from environmental and health hazards and equal access to the decision-making process to have a healthy environment in which to live, learn, and work.
      Leading up to this rulemaking the EPA summarized the public health and welfare effects of GHG emissions in its 2009 Endangerment Finding. As part of the Endangerment Finding, the Administrator considered climate change risks to minority or low-income populations, finding that certain parts of the population may be especially vulnerable based on their circumstances. These include the poor, the elderly, the very young, those already in poor health, the disabled, those living alone, and/or indigenous populations dependent on one or a few resources. See Sections F and G, above, where EPA discusses Consultation and Coordination with Tribal Governments and Protection of Children. The Administrator placed weight on the fact that certain groups, including children, the elderly, and the poor, are most vulnerable to climate-related health effects.
      Strong scientific evidence that the potential impacts of climate change raise environmental justice issues is found in the major assessment reports by the U.S. Global Change Research Program (USGCRP), the Intergovernmental Panel on Climate Change (IPCC), and the National Research Council (NRC) of the National Academies, summarized in the record for the Endangerment Finding. Their conclusions include that poor communities can be especially vulnerable to climate change impacts because they tend to have more limited adaptive capacities and are more dependent on climate-sensitive resources such as local water and food supplies. In addition, Native American tribal communities possess unique vulnerabilities to climate change, particularly those on established reservations that are restricted to reservation boundaries and therefore have limited relocation options. Tribal communities whose health, economic well-being, and cultural traditions depend upon the natural environment will likely be affected by the degradation of ecosystem goods and services associated with climate change.
 	Southwest native cultures are especially vulnerable to water quality and availability impacts. Native Alaskan communities are likely to experience disruptive impacts, including coastal erosion and shifts in the range or abundance of wild species crucial to their livelihoods and well-being. The most recent assessments continue to strengthen scientific understanding of climate change risks to minority and low-income populations in the United States. The new assessment literature provides more detailed findings regarding these populations' vulnerabilities and projected impacts they may experience. In addition, the most recent assessment literature provides new information on how some communities of color may be uniquely vulnerable to climate change health impacts in the United States. These studies find that certain climate change related impacts -- including heat waves, degraded air quality, and extreme weather events -- have disproportionate effects on low-income and some communities of color, raising environmental justice concerns. Existing health disparities and other inequities in these communities increase their vulnerability to the health effects of climate change. In addition, the studies also find that climate change poses particular threats to health, wellbeing, and ways of life of indigenous peoples in the United States.
      As the scientific literature presented above and in the Endangerment Finding illustrates, low income communities and communities of color are especially vulnerable to the health and other adverse impacts of climate change.
      The EPA believes the human health or environmental risk addressed by this final action will not have potential disproportionately high and adverse human health or environmental effects on minority, low-income or indigenous populations. The final rule limits GHG emissions from newly constructed, modified, and reconstructed fossil fuel-fired electric utility steam generating units and natural gas-fired stationary combustion turbines by establishing national emission standards for CO2.
      The EPA has determined that the final rule will not result in disproportionately high and adverse human health or environmental effects on minority, low-income or indigenous populations because the rule is not anticipated to notably affect the level of protection provided to human health or the environment. The EPA believes that electric power companies will choose to build new fossil fuel-fired electric utility steam generating units and natural gas-fired stationary combustion turbines that comply with the regulatory requirements of the final rule because of existing and expected market conditions. The EPA does not project any new coal-fired steam generating units without CCS to be built and expects that any newly built natural gas-fired stationary combustion turbines will meet the standards. In addition, as previously stated, the EPA expects few modified or reconstructed fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines in the period of analysis. This final rule will ensure that, to whatever extent there are newly constructed, modified, and reconstructed EGUs, they will use the best performing technologies to limit emissions of CO2.
K. Congressional Review Act (CRA)
      This final action is subject to the CRA, and the EPA will submit a rule report to each House of the Congress and to the Comptroller General of the United States. This action is not a "major rule" as defined by 5 U.S.C. 804(2).
XIII. Statutory Authority
The statutory authority for this action is provided by sections 111, 301, 302, and 307(d)(1)(C) of the CAA as amended (42 U.S.C. 7411, 7601, 7602, 7607(d)(1)(C)). This action is also subject to section 307(d) of the CAA (42 U.S.C. 7607(d)).

List of Subjects
40 CFR Part 60
      Environmental protection, Administrative practice and procedure, Air pollution control, Incorporation by reference, Intergovernmental relations, Reporting and recordkeeping requirements.
40 CFR Part 70
      Environmental protection, Administrative practice and procedure, Air pollution control, Intergovernmental relations, Reporting and recordkeeping requirements.
40 CFR Part 71
      Environmental protection, Administrative practice and procedure, Air pollution control, Reporting and recordkeeping requirements.
40 CFR Part 98
      Environmental protection, Greenhouse gases and monitoring, Reporting and recordkeeping requirements.
Dated:__________________.

________________________
Gina McCarthy,
Administrator
For the reasons stated in the preamble, title 40, chapter I, part 60, 70, 71, and 98 of the Code of the Federal Regulations is amended as follows:
PART 60-- STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES
      1. The authority citation for part 60 continues to read as follows:
	Authority: 42 U.S.C. 7401, et seq.
      2. Part 60 is amended by adding subpart TTTT to read as follows:
Subpart TTTT Standards of Performance for Greenhouse Gas Emissions for Electric Utility Generating Units
Sec.
Applicability

§ 60.5508	What is the purpose of this subpart?
§ 60.5509	Am I subject to this subpart?

Emission Standards

§ 60.5515	Which greenhouse gases are regulated by this subpart?
§ 60.5520	What CO2 emissions standard must I meet?

General Compliance Requirements

§ 60.5525	What are my general requirements for complying with this subpart?

Monitoring and Compliance Determination Procedures

§ 60.5535	How do I monitor and collect data to demonstrate compliance?
§ 60.5540	How do I demonstrate compliance with my CO2 emissions standard and determine excess emissions?

Notifications, Reports, and Records

§ 60.5550	What notifications must I submit and when?
§ 60.5555	What reports must I submit and when?
§ 60.5560	What records must I maintain?
§ 60.5565	In what form and how long must I keep my records?

Other Requirements and Information

§ 60.5570	What parts of the General Provisions apply to my affected EGU?
§ 60.5575	Who implements and enforces this subpart?
§ 60.5580	What definitions apply to this subpart?

Applicability
§ 60.5508 What is the purpose of this subpart?
This subpart establishes emission standards and compliance schedules for the control of greenhouse gas (GHG) emissions from a steam generating unit, IGCC, or a stationary combustion turbine that commences construction after January 8, 2014 or commences modification or reconstruction after June 18, 2014. An affected steam generating unit, IGCC, or stationary combustion turbine shall, for the purposes of this subpart, be referred to as an affected EGU.
§ 60.5509 Am I subject to this subpart?
      (a) Except as provided for in paragraph (b) of this section, the GHG standards included in this subpart apply to any steam generating unit, IGCC, or stationary combustion turbine that commenced construction after January 8, 2014 or commenced modification or reconstruction after June 18, 2014 that meets the relevant applicability conditions in paragraphs (a)(1) and (a)(2) of this section.
      (1) Has a base load rating greater than 260 GJ/h (250 MMBtu/h) of fossil fuel (either alone or in combination with any other fuel), and
      (2) Serves a generator capable of selling greater than 25 MW of electricity to a utility power distribution system.
      (b) You are not subject to the requirements of this subpart if your affected EGU meets any of the conditions specified in paragraphs (b)(1) through (b)(9) of this section.
      (1) Your EGU is a steam generating unit or IGCC that is currently and always has been subject to a federally enforceable permit limiting net-electric sales to one-third or less of its potential electric output or 219,000 MWh or less on an annual basis.
      (2) Your EGU is capable of combusting 90% or more non-fossil fuel and subject to a federally enforceable permit limiting fossil fuel use to 10% or less of the annual capacity factor.
      (3) Your EGU is a combined heat and power unit that is subject to a federally enforceable permit limiting annual net-electric sales to the design efficiency times the potential electric output or 219,000 MWh (whichever is greater) or less.
(4) Your EGU serves a generator along with other steam generating unit(s), IGCC, or stationary combustion turbine(s) where the effective generation capacity (determined based on a prorated output of the base load rating of  each steam generating unit, IGCC, or stationary combustion turbine) is 25 MW or less.
(5) Your EGU is a municipal waste combustor unit that is subject to subpart Eb of this part.
(6) Your EGU is a commercial or industrial solid waste incineration unit that is subject to subpart CCCC of this part.
      (7) Modified units that conduct modifications resulting in a potential hourly increase in CO2 emissions (mass per hour) of 10 percent or less.
      (8) Your EGU is a stationary combustion turbine that is subject to a federally enforceable permit limiting annual net-electric sales to the design efficiency times the potential electric output or less as net-electrical sales.
      (9) Your stationary combustion turbine is not capable of combusting natural gas (e.g., not connected to a natural gas pipeline).
Emission Standards
§ 60.5515 Which greenhouse gases are regulated by this subpart?
(a) The greenhouse gas regulated by this subpart is carbon dioxide (CO2).
(b) PSD and Title V Thresholds for Greenhouse Gases.
(1) For the purposes of § 51.166(b)(49)(ii) of this chapter, with respect to GHG emissions from affected EGUs, the "pollutant that is subject to the standard promulgated under section 111 of the Act" shall be considered to be the pollutant that otherwise is subject to regulation under the Act as defined in § 51.166(b)(48) and in any SIP approved by the EPA that is interpreted to incorporate, or specifically incorporates, § 51.166(b)(48) of this chapter.
(2) For the purposes of § 52.21(b)(50)(ii) of this chapter, with respect to GHG emissions from affected facilities, the "pollutant that is subject to the standard promulgated under section 111 of the Act" shall be considered to be the pollutant that otherwise is subject to regulation under the Act as defined in § 52.21(b)(49) of this chapter.
(3) For the purposes of § 70.2 of this chapter, with respect to greenhouse gas emissions from affected facilities, the "pollutant that is subject to any standard promulgated under section 111 of the Act" shall be considered to be the pollutant that otherwise is "subject to regulation" as defined in §  70.2 of this chapter.
(4) For the purposes of § 71.2, with respect to greenhouse gas emissions from affected facilities, the "pollutant that is subject to any standard promulgated under section 111 of the Act" shall be considered to be the pollutant that otherwise is "subject to regulation" as defined in § 71.2 of this chapter.
§ 60.5520 What CO2 emission standard must I meet?
      (a) For each affected EGU subject to this subpart, you must not discharge from the affected EGU any gases that contain CO2 in excess of the applicable CO2 emission standard specified in Table 1 or Table 2 of this subpart, consistent with paragraphs (b) and (c) of this section, as applicable.
      (b) Except as specified in paragraph (c) of the section, you must comply with the applicable gross energy output standard and your operating permit must include monitoring, recordkeeping, and reporting methodologies based on the applicable gross energy output standard. For the remainder of this subpart, where the term "gross or net energy output" is used, the term that applies to you is "gross energy output."
      (c) As an alternate to meeting the requirements in paragraph (b) of this section, an owner or operator may petition the Administrator in writing to comply with the alternate applicable net energy output standard. If the Administrator grants the petition, the source will beginning on the date the Administrator grants the petition have to comply with the applicable net energy output based standard included in this subpart. Your operating permit must include monitoring, recordkeeping, and reporting methodologies based on the applicable net energy output standard. For the remainder of this subpart, where the term "gross or net energy output" is used, the term that applies to you is "net energy output." Owners or operators complying with the net output based standard must petition the Administrator to switch back to complying with the gross energy output based standard.
General Compliance Requirements
§ 60.5525 What are my general requirements for complying with this subpart?
      Compliance with the applicable CO2 emission standard of this subpart shall be determined on a 12-operating month rolling average basis. See Tables 1-2 for the applicable CO2 emission standards.
      (a) You must be in compliance with the emission standards in this subpart that apply to your affected EGU at all times. However, you must determine compliance with the emission standards only at the end of the applicable operating month, as provided in paragraph (a)(1).
      (1) For each affected EGU subject to a CO2 emissions standard based on a 12-operating month rolling average, you must determine compliance monthly by calculating the average CO2 emissions rate for the affected EGU at the end of the initial and each subsequent 12-operating month period.
      (b) At all times you must operate and maintain each affected EGU, including associated equipment and monitoring equipment, in a manner consistent with safety and good air pollution control practice. The Administrator will determine if you are using consistent operation and maintenance procedures based on information available to the Administrator that may include, but is not limited to, fuel use records, monitoring results, review of operation and maintenance procedures and records, review of reports required by this subpart, and inspection of the EGU.
      (c) Within 30 days after the end of the initial compliance period (i.e., no more than 30 days after the first 12-operating month compliance period), you must make an initial compliance determination for your affected EGU(s) with respect to the applicable emissions standard in Table 1 or Table 2 of this subpart, in accordance with the requirements in this subpart. The first operating month included in the initial 12-operating month compliance period shall be determined as follows:
      (1) For an affected EGU that commences commercial operation (as defined in §72.2 of this chapter) on or after the effective date of this rule, the first month of the initial compliance period shall be the first operating month (as defined in §60.5580) after the calendar month in which emissions reporting is required to begin under:
      (i) §63.5555(c)(3)(i), for units subject to the Acid Rain Program; or
      (ii) §63.5555(c)(3)(ii)(A), for units that are not in the Acid Rain Program.
      (2) For an affected EGU that has commenced commercial operation (as defined in §72.2 of this chapter) prior to the effective date of this rule:
      (i) If the date on which emissions reporting is required to begin under §75.64(a) of this chapter has passed prior to the effective date of this rule, emissions reporting shall begin according to §63.5555(c)(3)(i) (for Acid Rain program units), or according to §63.5555(c)(3)(ii)(B) (for units that are not subject to the Acid Rain Program). The first month of the initial compliance period shall be the first operating month (as defined in §60.5580) after the calendar month in which the rule becomes effective; or
      (ii) If the date on which emissions reporting is required to begin under §75.64(a) of this chapter occurs on or after the effective date of this rule, then the first month of the initial compliance period shall be the first operating month (as defined in §60.5580) after the calendar month in which emissions reporting is required to begin under §63.5555(c)(3)(ii)(A).
      (3) For a modified or reconstructed EGU that becomes subject to this subpart, the first month of the initial compliance period shall be the first operating month (as defined in §60.5580) after the calendar month in which emissions reporting is required to begin under §63.5555(c)(3)(iii).
              Monitoring and Compliance Determination Procedures
§ 60.5535 How do I monitor and collect data to demonstrate compliance?
      (a) You must prepare a monitoring plan to quantify the hourly CO2 mass emission rate (tons/hr), in accordance with the applicable provisions in § 75.53(g) and (h) of this chapter.  The electronic portion of the monitoring plan must be submitted using the ECMPS Client Tool and must be in place prior to reporting emissions data and/or the results of monitoring system certification tests under this subpart.  The monitoring plan must be updated as necessary.  Monitoring plan submittals must be made by the Designated Representative (DR), the Alternate DR, or a delegated agent of the DR (see §60.5555(c)).
      (b) You must determine the hourly CO2 mass emissions in kilograms (kg) from your affected EGU(s) according to paragraphs (b)(1) through (5) of this section, or, if applicable,  as provided in paragraph (c) of this section.
(1) For an affected coal-fired EGU or for an IGCC unit you must, and for all other affected EGUs you may, install, certify, operate, maintain, and calibrate a CO2 continuous emission monitoring system (CEMS) to directly measure and record hourly average CO2 concentrations in the affected EGU exhaust gases emitted to the atmosphere, and a flow monitoring system to measure hourly average stack gas flow rates, according to § 75.10(a)(3)(i) of this chapter. As an alternative to direct measurement of CO2 concentration, provided that your EGU does not use carbon separation (e.g., carbon capture and storage), you may use data from a certified oxygen (O2) monitor to calculate hourly average CO2 concentrations, in accordance with §75.10(a)(3)(iii) of this chapter. If you measure CO2 concentration on a dry basis, you must also install, certify, operate, maintain, and calibrate a continuous moisture monitoring system, according to § 75.11(b) of this chapter.
(2) For each continuous monitoring system that you use to determine the CO2 mass emissions, you must meet the applicable certification and quality assurance procedures in § 75.20 of this chapter and appendices A and B to part 75 of this chapter.
      (3) You must use only unadjusted exhaust gas volumetric flow rates to determine the hourly CO2 mass emissions rate from the affected EGU; you must not apply the bias adjustment factors described in Section 7.6.5 of Appendix A to part 75 of this chapter to the exhaust gas flow rate data.
      (4) You must select an appropriate reference method to setup (characterize) the flow monitor and to perform the on-going RATAs, in accordance with part 75 of this chapter.  If you use a Type-S pitot tube or a pitot tube assembly for the flow RATAs, you must calibrate the pitot tube or pitot tube assembly; you may not use the 0.84 default Type-S pitot tube coefficient specified in Method 2.
      (5) Calculate the hourly CO2 mass emissions (kg) as described in paragraphs (a)(6)(i) through (iv) of this section.  Perform this calculation only for "valid operating hours", as defined in §60.5540(a)(1).
      (i) Begin with the hourly CO2 mass emission rate (tons/hr), obtained either from Equation F-11 in Appendix F to part 75 of this chapter (if CO2 concentration is measured on a wet basis), or by following the procedure in section 4.2 of Appendix F to part 75 of this chapter (if CO2 concentration is measured on a dry basis).
      (ii) Next, multiply each hourly CO2 mass emission rate by the EGU or stack operating time in hours (as defined in §72.2 of this chapter), to convert it to tons of CO2.
      (iii) Finally, multiply the result from paragraph (b)(5)(ii) of this section by 909.1 to convert it from tons of CO2 to kg.  Round off to the nearest kg.
      (iv) The hourly CO2 tons/hr values and EGU (or stack) operating times used to calculate CO2 mass emissions are required to be recorded under §75.57(e) of this chapter and must be reported electronically under §75.64(a)(6).  You must use these data to calculate the hourly CO2 mass emissions.
      (c) If your affected EGU exclusively combusts liquid fuel and/or gaseous fuel as an alternative to complying with paragraph (b) of this section, you may determine the hourly CO2 mass emissions according to paragraphs (c)(1) through (4) of this section.
      (1) You must implement the applicable procedures in appendix D to part 75 of this chapter to determine hourly EGU heat input rates (MMBtu/h), based on hourly measurements of fuel flow rate and periodic determinations of the gross calorific value (GCV) of each fuel combusted.
      (2) For each measured hourly heat input rate, use Equation G-4 in Appendix G to part 75 of this chapter to calculate the hourly CO2 mass emission rate (tons/hr).  You may determine site-specific carbon-based F-factors (Fc) using Equation F-7b in section 3.3.6 of appendix F to part 75 of this chapter, and you may use these Fc values in the emissions calculations instead of using the default Fc values in the Equation G-4 nomenclature.
      (3) For each "valid operating hour" (as defined in §60.5540(a)(1), multiply the hourly tons/h CO2 mass emission rate from paragraph (c)(2) of this section by the EGU or stack operating time in hours (as defined in §72.2 of this chapter), to convert it to it to tons of CO2. Then, multiply the result by 909.1 to convert from tons of CO2 to kg.  Round off to the nearest two significant figures.
      (4) The hourly CO2 tons/h values and EGU (or stack) operating times used to calculate CO2 mass emissions are required to be recorded under §75.57(e) of this chapter and must be reported electronically under §75.64(a)(6)  You must use these data to calculate the hourly CO2 mass emissions.
      (d) Consistent with § 60.5520, you must install, calibrate, maintain, and operate a sufficient number of watt meters to continuously measure and record the hourly gross electric output or net electric output, as applicable, from the affected EGU(s). These measurements must be performed using 0.2 class electricity metering instrumentation and calibration procedures as specified under ANSI Standards No. C12.20. For a combined heat and power (CHP) EGU, as defined in §60.5580, you must also install, calibrate, maintain, and operate meters to continuously (i.e., hour-by-hour) determine and record the total useful thermal output. For process steam applications, you will need to install, calibrate, maintain, and operate meters to continuously determine and record the hourly steam flow rate, temperature, and pressure. Your plan shall ensure that you install, calibrate, maintain, and operate meters to record each component of the determination, hour-by-hour.
      (e) Consistent with § 60.5520, if two or more affected EGUs serve a common electric generator, you must apportion the combined hourly gross or net energy output to the individual affected EGUs according to the fraction of the total steam load contributed by each EGU.  Alternatively, if the EGUs are identical, you may apportion the combined hourly gross or net electrical load to the individual EGUs according to the fraction of the total heat input contributed by each EGU.
(f) In accordance with § 60.13(g) and § 60.5520, if two or more affected EGUs that implement the continuous emission monitoring provisions in paragraph (b) of this section share a common exhaust gas stack and are subject to the same emissions standard in Table 1 or Table 2 of this subpart, you may monitor the hourly CO2 mass emissions at the common stack in lieu of monitoring each EGU separately. If you choose this option, the hourly gross or net energy output (electric, thermal, and/or mechanical, as applicable) must be the sum of the hourly loads for the individual affected EGUs and you must express the operating time as "stack operating hours" (as defined in § 72.2 of this chapter). If you attain compliance with the applicable emissions standard in § 60.5520 at the common stack, each affected EGU sharing the stack is in compliance.
(g) In accordance with § 60.13(g) and § 60.5520 if the exhaust gases from an affected EGU that implements the continuous emission monitoring provisions in paragraph (b) of this section are emitted to the atmosphere through multiple stacks (or if the exhaust gases are routed to a common stack through multiple ducts and you elect to monitor in the ducts), you must monitor the hourly CO2 mass emissions and the "stack operating time" (as defined in § 72.2 of this chapter) at each stack or duct separately. In this case, you must determine compliance with the applicable emissions standard in Table 1 or 2 of this subpart by summing the CO2 mass emissions measured at the individual stacks or ducts and dividing by the total gross or net energy output for the affected EGU.
§60.5540 How do I demonstrate compliance with my CO2 emissions standard?
 	(a) In accordance with § 60.5520, to demonstrate compliance with the applicable CO2 emission standard in Table 1 or 2 of this subpart, for the initial and each subsequent 12-operating month rolling average compliance period, you must follow the procedures in paragraphs (a)(1) through(a)(7) of this section to calculate the CO2 mass emissions rate for your affected EGU(s) in units of the applicable emissions standard (kg/MWh). You must use the hourly CO2 mass emissions and generation load data from §60.5535 in the calculations.
(1) Each compliance period shall include only "valid operating hours" in the compliance period, i.e., operating hours for which:
(i) "Valid data" (as defined in §60.5580) are obtained for all of the parameters used to determine the hourly CO2 mass emissions (kg); and
(ii) The corresponding hourly gross or net energy output value is also valid data (Note: for hours with no useful output, zero is considered to be a valid value).
(2) You must exclude operating hours in which:
(i) The substitute data provisions of part 75 of this chapter are applied for any of the parameters used to determine the hourly CO2 mass emissions; or
(ii) An exceedance of the full-scale range of a continuous emission monitoring system occurs for any of the parameters used to determine the hourly CO2 mass emissions; or
(iii) The total gross or net energy output (Pgross/net) is unavailable.
(3) For each compliance period, at least 95 percent of the operating hours in the compliance period must be valid operating hours, as defined in paragraph (a)(1) of this section.
(4) You must calculate the total CO2 mass emissions by summing the valid hourly CO2 mass emissions values from §60.5535 for all of the valid operating hours in the compliance period.
(5) For each valid operating hour of the compliance period that was used in paragraph (a)(4) of this section to calculate the total CO2 mass emissions, you must determine Pgross/net  (the corresponding hourly gross or net energy output in MWh) according to the procedures in paragraphs (a)(3)(i) and (ii) of this section, as appropriate for the type of affected EGU(s). For an operating hour in which a valid CO2 mass emissions value is determined according to paragraph (a)(1)(i) of this section, if there is no gross or net electrical output, but there is mechanical or useful thermal output, you must still determine the gross or net energy output for that hour. In addition, for an operating hour in which a valid CO2 mass emissions value is determined according to paragraph (a)(1)(i) of this section, but there is no (i.e., zero) gross electrical, mechanical, or useful thermal output, you must use that hour in the compliance determination. For hours or partial hours where the gross electric output is equal to or less than the auxiliary loads, net electric output shall be counted as zero for this calculation.
      (i) Calculate Pgross/net for your affected EGU using the following equation. All terms in the equation must be expressed in units of megawatt-hours (MWh).  To convert each hourly gross or net energy output (Consistent with § 60.5520) value reported under part 75 of this chapter to MWh, multiply by the corresponding EGU or stack operating time.
      Pgross/net = PeST+ PeCT + PeIE-(Pe)FWT +  PtPS + PtHR + PtIE
      Where: a
      Pgross/net =	In accordance with § 60.5520, gross or net energy output of your affected EGU for each valid operating hour (as defined in 60.5540(a)(1)) in MWh.
      (Pe)ST =	Electric energy output plus mechanical energy output (if any) of steam turbines in MWh.
      (Pe)CT =	Electric energy output plus mechanical energy output (if any) of stationary combustion turbine(s) in MWh.
      (Pe)IE =	Electric energy output plus mechanical energy output (if any) of your affected EGU's integrated equipment that provides electricity or mechanical energy to the affected EGU or auxiliary equipment in MWh.
      (Pe)FW =	Electric energy used to power boiler feedwater pumps at steam generating units in MWh. Not applicable to stationary combustion turbines, IGCC EGUs, or EGUs complying with a net energy output based standard.
      (Pt)PS =	Useful thermal output of steam (measured relative to SATP conditions, as applicable)  that is used for applications that do not generate additional electricity, produce mechanical energy output, or enhance the performance of the affected EGU. This is calculated using the equation specified in paragraph (a)(5)(ii) of this section in MWh.
      (Pt)HR =	Non steam useful thermal output (measured relative to SATP conditions, as applicable) from heat recovery that is used for applications other than steam generation or performance enhancement of the affected EGU in MWh.
      (Pt)IE =	Useful thermal output (relative to SATP conditions, as applicable) from any integrated equipment is used for applications that do not generate additional steam, electricity, produce mechanical energy output, or enhance the performance of the affected EGU in MWh.
      T = 	Electric Transmission and Distribution Factor.
      T = 	0.95 for a combined heat and power affected EGU where at least on an annual basis 20.0 percent of the total gross or net energy output consists of electric or direct mechanical output and 20.0 percent of the total gross or net energy output consists of useful thermal output on a 12-operating month rolling average basis.
      T = 	1.0 for all other affected EGUs.

      (ii) If applicable to your affected EGU, you must calculate (Pt)PS using the following equation:
      (Pt)PS = Qm x H3.6 x 109
      Where:
      Qm = 	Measured steam flow in kilograms (kg) (or pounds (lb)) for the operating hour.
      H = 	Enthalpy of the steam at measured temperature and pressure (relative to SATP conditions, as applicable) in Joules per kilogram (J/kg) (or Btu/lb).
      3.6 x 10[9] = Conversion factor (J/MWh) (or 3.413 x 106 Btu/MWh).

(6) In accordance with § 60.5520, you must calculate the total gross or net energy output for the affected EGU's compliance period by summing the hourly gross or net energy output values for the affected EGU that you determined under paragraph (a)(5) of this section for all of the valid operating hours in the applicable compliance period.
(7) You must calculate the CO2 mass emissions rate for the affected EGU(s) (kg/MWh) by dividing the total CO2 mass emissions value calculated according to the procedures in paragraph (a)(4) of this section by the total gross or net energy output value calculated according to the procedures in paragraph (a)(6) of this section. Round off the result two significant figures.
      (b) In accordance with § 60.5520, to demonstrate compliance with the applicable CO2 emission standard, for the initial and each subsequent 12-operating month compliance period, the CO2 mass emissions rate for your affected EGU must be determined according to the procedures specified in paragraph (a)(1) through (7) of this section and must be less than or equal to the applicable CO2 emissions standard in Table 1 or 2 of this subpart.
      Notification, Reports, and Records
§ 60.5550 What notifications must I submit and when?
      (a) You must prepare and submit the notifications specified in § 60.7(a)(1) and (a)(3) and § 60.19, as applicable to your affected EGU(s) (see Table 3 of this Subpart).
      (b) You must prepare and submit notifications specified in § 75.61 of this chapter, as applicable to your affected EGUs.
§ 60.5555 What reports must I submit and when?
      (a) You must prepare and submit reports according to paragraphs (a) through (d) of this section, as applicable.
      (1) For affected EGUs that are required by § 60.5525 to conduct initial and on-going compliance determinations on a 12-operating month rolling average basis, you must submit electronic quarterly reports as follows. After you have accumulated the first 12-operating months for the affected EGU, you must submit a report for the calendar quarter that includes the twelfth operating month no later than 30 days after the end of that quarter. Thereafter, you must submit a report for each subsequent calendar quarter, no later than 30 days after the end of the quarter.
      (2) In each quarterly report you must include the following information, as applicable:
      (i) Each rolling average CO2 mass emissions rate for which the last (twelfth) operating month in a 12-operating month compliance period falls within the calendar quarter. You must calculate each average CO2 mass emissions rate for the compliance period according to the procedures in § 60.5540. You must report the dates (month and year) of the first and twelfth operating months in each compliance period for which you performed a CO2 mass emissions rate calculation. If there are no compliance periods that end in the quarter, you must include a statement to that effect;
      (ii) If one or more compliance periods end in the quarter you must identify each operating month in the calendar quarter where your EGU violated the applicable CO2 emission standard;
      (iii) If one or more compliance periods end in the quarter and there are no violations for the affected EGU, you must include a statement indicating this in the report;
      (iv) The percentage of valid operating hours in each 12-operating month compliance period described in paragraph (a)(1)(i) of this section (i.e., the total number of valid operating hours (as defined in §60.5540(a)(1)) in that period divided by the total number of operating hours in that period, multiplied by 100 percent);
      (v) Consistent with § 60.5520, the CO2 emissions standard (as identified in Table 1 or 2) with which your affected EGU must comply; and
      (vi) Consistent with § 60.5520, an indication whether or not the hourly gross or net energy output (Pgross/net) values used in the compliance determinations are based solely upon gross electrical load.
      (3) In the final quarterly report of each calendar year, you must include the following:
      (i) Consistent with § 60.5520, gross energy output or net energy output sold to an electric grid over the 4 quarters of the calendar year; and
      (ii) The potential electric output of the EGU.
      (b) You must submit all electronic reports required under paragraph (a) of this section using the Emissions Collection and Monitoring Plan System (ECMPS) Client Tool provided by the Clean Air Markets Division in the Office of Atmospheric Programs of EPA.
(c) (1) For affected EGUs under this subpart that are also subject to the Acid Rain Program, you must meet all applicable reporting requirements and submit reports as required under subpart G of part 75 of this chapter.
(2) For affected EGUs under this subpart that are not in the Acid Rain Program, you must also meet the reporting requirements and submit reports as required under subpart G of part 75 of this chapter, to the extent that those requirements and reports provide applicable data for the compliance demonstrations required under this subpart.
(3) (i) For all newly-constructed affected EGUs under this subpart that are also subject to the Acid Rain Program, you must begin submitting the quarterly electronic emissions reports described in paragraph (c)(1) of this section in accordance with §75.64(a), i.e., beginning with data recorded on and after the earlier of:
(A) The date of provisional certification, as defined in §75.20(a)(3) of this chapter; or
(B) 180 days after the date on which the EGU commences commercial operation (as defined in §72.2 of this chapter).
(ii) For newly-constructed affected EGUs under this subpart that are not subject to the Acid Rain Program, you must begin submitting the quarterly electronic reports described in paragraph (c)(2) of this section, beginning with data recorded on and after:
(A) The date on which reporting is required to begin under §75.64(a), if that date occurs on or after the effective date of this rule; or
(B)  The effective date of this rule, if the date on which reporting would ordinarily be required to begin under §75.64(a) has passed prior to the effective date of this rule.
(iii) For reconstructed or modified units, reporting of emissions data shall begin at the date on which the EGU becomes an affected unit under this subpart, provided that the ECMPS Client Tool is able to receive and process net electrical generation data on that date.  Otherwise, emissions data reporting shall begin on the date that the Client Tool is first able to receive and process net generation data.
(4) If any required monitoring system has not been provisionally certified by the applicable date on which emissions data reporting is required to begin under paragraph (c)(3) of this section, the maximum (or in some cases, minimum) potential value for the parameter measured by the monitoring system shall be reported until the required certification testing is successfully completed, in accordance with §75.4(j) of this chapter, §75.37(b) of this chapter, or section 2.4 of appendix D to part 75 of this chapter (as applicable).  Operating hours in which CO2 mass emission rates are calculated using maximum potential values are not "valid operating hours" (as defined in §60.5540(a)(1)), and shall not be used in the compliance determinations under §60.5540.
(d) For affected EGUs subject to the Acid Rain Program, the reports required under paragraphs (a) and (c)(1) of this section shall be submitted by:
(1) The person appointed as the Designated Representative (DR) under §72.20 of this chapter; or
(2) The person appointed as the Alternate Designated Representative (ADR) under §72.22 of this chapter; or
(3) A person (or persons) authorized by the DR or ADR under §72.26 of this chapter to make the required submissions.
(e) For affected EGUs that are not subject to the Acid Rain Program, the owner or operator shall appoint a DR and (optional) an ADR to submit the reports required under paragraphs (a) and (c)(2) of this section. The DR and ADR must register with the Clean Air Markets Division (CAMD) Business System.  The DR may delegate the authority to make the required submissions to one or more persons.
      (e) If your affected EGU captures CO2 to meet the applicable emission limit, you must report in accordance with the requirements of 40 CFR Part 98 Subpart PP and either:
      (1) Report in accordance with the requirements of 40 CFR Part 98 subpart RR, if injection occurs on-site, or
(2) Transfer the captured CO2 to an EGU or facility that reports in accordance with the requirements of 40 CFR Part 98 subpart RR, if injection occurs off-site.
§ 60.5560 What records must I maintain?
(a) You must maintain records of the information you used to demonstrate compliance with this subpart as specified in § 60.7 (b) and (f).
(b) (1) For affected EGUs subject to the Acid Rain Program, you must follow the applicable recordkeeping requirements and maintain records as required under subpart F of part 75 of this chapter.
(2) For affected EGUs that are not subject to the Acid Rain Program, you must also follow the recordkeeping requirements and maintain records as required under subpart F of part 75 of this chapter, to the extent that those records provide applicable data for the compliance determinations required under this subpart.  Regardless of the prior sentence, at a minimum, the following records must be kept, as applicable to the types of continuous monitoring systems used to demonstrate compliance under this subpart:
(i) Monitoring plan records under §75.53(g) and (h) of this chapter;
(ii) Operating parameter records under §75.57(b)(1) through (b)(4) of this chapter;
(iii) The records under §75.57(c)(2) of this chapter, for stack gas volumetric flow rate;
(iv) The records under §75.57(c)(3) for continuous moisture monitoring systems;
(v) The records under §75.57(e)(1), except for paragraph (e)(1)(x), for CO2 concentration monitoring systems or O2 monitors used to calculate CO2 concentration;
(vi) The records under §75.58(c)(1), paragraphs (c)(1)(i), (c)(1)(ii), and (c)(1)(viii) through (c)(1)(xiv), for oil flow meters;
(vii) The records under §75.58(c)(4), paragraphs (c)(4)(i), (c)(4)(ii), (c)(4)(iv), (c)(4)(v), and (c)(4)(vii) through (c)(4)(xi), for gas flow meters;
(viii) The quality-assurance records under §75.59(a) of this chapter, paragraphs (a)(1) through (a)(12) and (a)(15), for CEMS;
(ix) The quality-assurance records under §75.59(a) of this chapter, paragraphs (b)(1) through (b)(4), for fuel flow meters; and
(x) Records of data acquisition and handling system (DAHS) verification under §75.59(e) of this chapter.
(c) You must keep records of the calculations you performed to determine the hourly and total CO2 mass emissions (tons) for:
(1) Each operating month (for all affected EGUs);
(2) Each compliance period, including, each 12-operating month compliance period.
      (d) Consistent with § 60.5520, you must keep records of the applicable data recorded and calculations performed that you used to determine your affected EGU's gross or net energy output for each operating month.
      (e) You must keep records of the calculations you performed to determine the percentage of valid CO2 mass emission rates in each compliance period.
      (f) You must keep records of the calculations you performed to assess compliance with each applicable CO2 mass emissions standard in Table 1 or 2 of this subpart.
      (g)  You must keep records of the calculations you performed to determine any site-specific carbon-based F-factors you used in the emissions calculations (if applicable).
§ 60.5565 In what form and how long must I keep my records?
      (a) Your records must be in a form suitable and readily available for expeditious review.
      (b) You must maintain each record for 3 years after the date of conclusion of each compliance period.
      (c) You must maintain each record on site for at least 2 years after the date of each occurrence, measurement, maintenance, corrective action, report, or record, according to § 60.7. You may maintain the records off site and electronically for the remaining year(s) as required by this subpart.
                      Other Requirements and Information
§ 60.5570 What parts of the General Provisions apply to my affected EGU?
      Notwithstanding any other provision of this chapter, certain parts of the General Provisions in § 60.1 through 60.19, listed in Table 3 to this subpart, do not apply to your affected EGU.
§ 60.5575 Who implements and enforces this subpart?
(a) This subpart can be implemented and enforced by the EPA, or a delegated authority such as your state, local, or tribal agency. If the Administrator has delegated authority to your state, local, or tribal agency, then that agency (as well as the EPA) has the authority to implement and enforce this subpart. You should contact your EPA Regional Office to find out if this subpart is delegated to your state, local, or tribal agency.
(b) In delegating implementation and enforcement authority of this subpart to a state, local, or tribal agency, the Administrator retains the authorities listed in paragraphs (b)(1) through (5) of this section and does not transfer them to the state, local, or tribal agency. In addition, the EPA retains oversight of this subpart and can take enforcement actions, as appropriate.
(1) Approval of alternatives to the emission standards.
(2) Approval of major alternatives to test methods.
(3) Approval of major alternatives to monitoring.
(4) Approval of major alternatives to recordkeeping and reporting.
(5) Performance test and data reduction waivers under § 60.8(b).
§ 60.5580 What definitions apply to this subpart?
      As used in this subpart, all terms not defined herein will have the meaning given them in the Clean Air Act and in subpart A (General Provisions of this part).
Annual capacity factor means the ratio between the actual heat input to an EGU during a calendar year and the potential heat input to the EGU had it been operated for 8,760 hours during a calendar year at the base load rating.
Base load rating means the maximum amount of heat input (fuel) that an EGU can combust on a steady state basis, as determined by the physical design and characteristics of the EGU at ISO conditions. For a stationary combustion turbine, baseload rating includes the heat input from duct burners.
      Coal means all solid fuels classified as anthracite, bituminous, subbituminous, or lignite by the American Society of Testing and Materials in ASTM D388 (incorporated by reference, see § 60.17), coal refuse, and petroleum coke. Synthetic fuels derived from coal for the purpose of creating useful heat, including but not limited to solvent-refined coal, gasified coal (not meeting the definition of natural gas), coal-oil mixtures, and coal-water mixtures are included in this definition for the purposes of this subpart.
Coal refuse means waste products of coal mining, physical coal cleaning, and coal preparation operations (e.g. culm, gob, etc.) containing coal, matrix material, clay, and other organic and inorganic material.
Combined cycle unit means an electric generating unit that uses a stationary combustion turbine from which the heat from the turbine exhaust gases is recovered by a heat recovery steam generating unit (HRSG) to generate additional electricity.
Combined heat and power unit or CHP unit, (also known as "cogeneration") means an electric generating unit that that use a steam-generating unit or stationary combustion turbine to simultaneously produce both electric (or mechanical) and useful thermal output from the same primary energy source.
Design efficiency means the rated overall net efficiency (e.g., electric plus thermal output) on a higher heating value basis of the EGU at the base load rating and ISO conditions.
Distillate oil means fuel oils that comply with the specifications for fuel oil numbers 1 and 2, as defined by the American Society of Testing and Materials in ASTM D396 (incorporated by reference, see § 60.17); diesel fuel oil numbers 1 and 2, as defined by the American Society for Testing and Materials in ASTM D975 (incorporated by reference, see § 60.17); kerosene, as defined by the American Society of Testing and Materials in ASTM D3699 (incorporated by reference, see § 60.17); biodiesel as defined by the American Society of Testing and Materials in ASTM D6751 (incorporated by reference, see § 60.17); or biodiesel blends as defined by the American Society of Testing and Materials in ASTM D7467 (incorporated by reference, see § 60.17).
      Fossil fuel means natural gas, petroleum, coal, and any form of solid, liquid, or gaseous fuel derived from such material for the purpose of creating useful heat.
Gaseous fuel means any fuel that is present as a gas at ISO conditions and includes, but is not limited to, natural gas, refinery fuel gas, process gas, coke-oven gas, synthetic gas, and gasified coal.
Gross energy output means:
      (1) For stationary combustion turbines and IGCC, the gross electric or direct mechanical output from both the EGU (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expander(s)) plus 100 percent of the useful thermal output.
      (2) For electric utility steam generating units, the gross electric or mechanical output from the affected EGU(s) (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expander(s)) minus any electricity used to power the feedwater pumps plus 100 percent of the useful thermal output;
      (3) For combined heat and power facilities where at least 20.0 percent of the total gross energy output consists of electric or direct mechanical output and 20.0 percent of the total gross energy output consists of useful thermal output on a 12-operaitng month rolling average basis, the gross electric or mechanical output from the affected EGU (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expander(s)) minus any electricity used to power the feedwater pumps (the electric auxiliary load of boiler feedwater pumps is not applicable to IGCC facilities), that difference divided by 0.95, plus 100 percent of the useful thermal output.
	Heat recovery steam generating unit (HRSG) means a EGU in which hot exhaust gases from the combustion turbine engine are routed in order to extract heat from the gases and generate useful output. Heat recovery steam generating units can be used with or without duct burners.
	Integrated gasification combined cycle unit or IGCC means a combined cycle stationary combustion turbine that is designed to burn fuels containing 50 percent (by heat input) or more solid-derived fuel not meeting the definition of natural gas. The Administrator may waive the 50 percent solid-derived fuel requirement during periods of the gasification system construction, startup and commissioning, shutdown, or repair. No solid fuel is directly burned in the EGU during operation.
ISO conditions means 288 Kelvin (15o C), 60 percent relative humidity and 101.3 kilopascals pressure.
Liquid fuel means any fuel that is present as a liquid at ISO conditions and includes, but is not limited to, distillate oil and residual oil.
Mechanical output means the useful mechanical energy that is not used to operate the affected EGU(s), generate electricity and/or thermal energy, or to enhance the performance of the affected EGU. Mechanical energy measured in horsepower hour should be converted into MWh by multiplying it by 745.7 then dividing by 1,000,000.
      Natural gas means a fluid mixture of hydrocarbons (e.g., methane, ethane, or propane), composed of at least 70 percent methane by volume or that has a gross calorific value between 35 and 41 megajoules (MJ) per dry standard cubic meter (950 and 1,100 Btu per dry standard cubic foot), that maintains a gaseous state under ISO conditions. In addition, natural gas contains 20.0 grains or less of total sulfur per 100 standard cubic feet. Finally, natural gas does not include the following gaseous fuels: landfill gas, digester gas, refinery gas, sour gas, blast furnace gas, coal-derived gas, producer gas, coke oven gas, or any gaseous fuel produced in a process which might result in highly variable sulfur content or heating value.
      Net-electric sales means
      (1) The gross electric sales to the utility power distribution system minus purchased power; or
      (2) For combined heat and power facilities where at least 20.0 percent of the total gross energy output consists of electric or direct mechanical output and at least 20.0 percent of the total gross energy output consists of useful thermal output on an annual basis, the gross electric sales to the utility power distribution system minus purchased power of the thermal host EGU or facilities.
      (3) Electricity supplied to other facilities that produce electricity to offset auxiliary loads are included when calculating net-electric sales.
      (4) Electric sales that that result from a grid emergency are not included when calculating net-electric sales.
      Net-electric output means: the amount of gross generation the generator(s) produces (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expander(s)), as measured at the generator terminals, less the electricity used to operate the plant (i.e., auxiliary loads); such uses include fuel handling equipment, pumps, fans, pollution control equipment, other electricity needs, and transformer losses as measured at the transmission side of the step up transformer (e.g., the point of sale).
      Net energy output means:
      (i) Except as provided under paragraph (ii) of this definition, the net electric or mechanical output  from the affected EGU plus 100 percent of the useful thermal output; or
      (ii) For combined heat and power facilities where at least 20.0 percent of the total gross or net energy output consists of electric or direct mechanical output and at least 20.0 percent of the total gross or net energy output consists of useful thermal output on a 12-operating month rolling average basis, the net electric or mechanical output from the affected EGU divided by 0.95, plus 100 percent of the useful thermal output;
      Oil means crude oil or petroleum or a fuel derived from crude oil or petroleum, including distillate and residual oil, and gases derived from solid oil-derived fuels (not meeting the definition of natural gas).
      Operating month means a calendar month during which any fuel is combusted in the affected EGU at any time.
Petroleum means crude oil or a fuel derived from crude oil, including, but not limited to, distillate and residual oil.
Standard ambient temperature and pressure (SATP) conditions means 298.15 Kelvin (25o C, 77 [o]F)) and 100.0 kilopascals (14.504 psi, 0.987 atm) pressure. The enthalpy of water at SATP conditions is 50 Btu/lb.
      Potential electric output means 33 percent or the design efficiency on a net output basis multiplied by the base load rating (expressed in MMBtu/h) of the EGU, multiplied by 10[6] Btu/MMBtu, divided by 3,413 Btu/KWh, divided by 1,000 kWh/MWh, and multiplied by 8,760 h/yr (e.g., a 35 percent efficient affected EGU with a 100 MW (341 MMBtu/h) fossil-fuel heat input capacity would have a 310,000 MWh 12 month potential electric output capacity).
      Solid fuel means any fuel that has a definite shape and volume, has no tendency to flow or disperse under moderate stress, and is not liquid or gaseous at ISO conditions. This includes, but is not limited to, coal, biomass, and pulverized solid fuels.
      Stationary combustion turbine means all equipment, including but not limited to the turbine engine, the fuel, air, lubrication and exhaust gas systems, control systems (except emissions control equipment), heat recovery system, fuel compressor, heater, and/or pump, post-combustion emission control technology, and any ancillary components and sub-components comprising any simple cycle stationary combustion turbine, any combined cycle combustion turbine, and any combined heat and power combustion turbine based system plus any integrated equipment that provides electricity or useful thermal output to the combustion turbine engine, heat recovery system or auxiliary equipment. Stationary means that the combustion turbine is not self-propelled or intended to be propelled while performing its function. It may, however, be mounted on a vehicle for portability. If a stationary combustion turbine burns any solid fuel directly it is considered a steam generating unit.
      Steam generating unit means any furnace, boiler, or other device used for combusting fuel and producing steam (nuclear steam generators are not included) plus any integrated equipment that provides electricity or useful thermal output to the affected EGU(s) or auxiliary equipment.
      Useful thermal output means the thermal energy made available for use in any heating application (e.g., steam delivered to an industrial process for a heating application, including thermal cooling applications) that is not used for electric generation, mechanical output at the affected EGU, to directly enhance the performance of the affected EGU (e.g., economizer output is not useful thermal output, but thermal energy used to reduce fuel moisture is considered useful thermal output), or to supply energy to a pollution control device at the affected EGU. Useful thermal output for affected EGU(s) with no condensate return (or other thermal energy input to the affected EGU(s)) or where measuring the energy in the condensate (or other thermal energy input to the affected EGU(s)) would not meaningfully impact the emission rate calculation is measured against the energy in the thermal output at SATP conditions. Affected EGU(s) with meaningful energy in the condensate return (or other thermal energy input to the affected EGU) must measure the energy in the condensate and subtract that energy relative to SATP conditions from the measured thermal output.
      Valid data means quality-assured data generated by continuous monitoring systems that are installed, operated, and maintained according to part 75 of this chapter.  For CEMS, the initial certification requirements in §75.20 of this chapter and appendix A to part 75 of this chapter must be met before quality-assured data are reported under this subpart; for on-going quality assurance, the daily, quarterly, and semiannual/annual test requirements in sections 2.1, 2.2, and 2.3 of appendix B to part 75 of this chapter must be met and the data validation criteria in sections 2.1.5, 2.2.3, and 2.3.2 of appendix B to part 75 of this chapter apply.  For fuel flow meters, the initial certification requirements in section 2.1.5 of appendix D to part 75 of this chapter must be met before quality-assured data are reported under this subpart (except for qualifying commercial billing meters under section <IP_ADDRESS> of appendix D), and for on-going quality assurance, the provisions in section 2.1.6 of appendix D to part 75 of this chapter apply (except for qualifying commercial billing meters).
Violation means a specified averaging period over which the CO2 emissions rate is higher than the applicable emissions standard located in Table 1 or Table 2 of this subpart.

Table 1 of Subpart TTTT of Part 60  -  CO2 Emission Standards for Affected Steam Generating Units and Integrated Gasification Combined Cycle Facilities that Commenced Construction after January 8, 2014 and Reconstruction or Modification after June 18, 2014 (net energy output-based standards are only applicable to affected EGUs subject to a federally enforceable permit limiting GHG emissions on a net energy output basis)
      Note: all numerical values have a minimum of 2 significant figures
Affected EGU
CO2 Emission Standard
Newly constructed steam generating unit or integrated gasification combined cycle (IGCC) EGU
640 kg CO2/MWh of gross energy output (1,400 lb CO2/MWh)
Reconstructed steam generating unit or IGCC EGU that has base load rating of 2,100 GJ/h (2,000 MMBtu/h) or less
910 kg of CO2 per MWh of gross energy output (2,000 lb CO2/MWh)
Reconstructed steam generating unit or IGCC EGU that has a base load rating greater than 2,100 GJ/h (2,000 MMBtu/h)
820 kg of CO2 per MWh of gross energy output (1,800 lb CO2/MWh)
Modified steam generating or IGCC unit
A unit-specific emission limit determined by the unit's best historical annual CO2 emission rate (from 2002 to the date of the modification); the emission limit will be no lower than:
1.	1,800 lb CO2/MWh-gross for units with a base load rating greater than 2,000 MMBtu/h.; or
2.	2,000 lb CO2/MWh-gross for units with a base load rating of 2,000 MMBtu/h or less.

Table 2 of Subpart TTTT of Part 60  -  CO2 Emission Standards for Affected Stationary Combustion Turbines that Commenced Construction after January 8, 2014 and Reconstruction or Modification after June 18, 2014
      Note: all numerical values have a minimum of 2 significant figures
Affected EGU
CO2 Emission Standard
Newly constructed, reconstructed, or modified stationary combustion turbine
450 kg of CO2 per MWh of gross energy output (1,000 lb CO2/MWh); or
490 kilograms (kg) of CO2 per megawatt-hour (MWh) of net energy output (1,080 lb/MWh)

Table 3 to Subpart TTTT of Part 60  -  Applicability of Subpart A General Provisions to Subpart TTTT
General Provisions citation
Subject of citation
Applies to subpart TTTT
Explanation
§ 60.1
Applicability
Yes

§ 60.2
Definitions
Yes
Additional terms defined in § 60.5580
§ 60.3
Units and Abbreviations
Yes

§ 60.4
Address
Yes
Does not apply to information reported electronically through ECMPS. Duplicate submittals are not required.
§ 60.5
Determination of construction or modification
Yes

§ 60.6
Review of plans
Yes

§ 60.7
Notification and Recordkeeping
Yes
Only the requirements to submit the notifications in 60.7(a)(1) and (a)(3) and to keep records of malfunctions in §60.7(b), if applicable
§ 60.8
Performance tests
No

§ 60.9
Availability of Information
Yes

§ 60.10
State authority
Yes

§ 60.11
Compliance with standards and maintenance requirements
No

§ 60.12
Circumvention
Yes

§ 60.13
Monitoring requirements
No
All monitoring is done according to Part 75
§ 60.14
Modification
No

§ 60.15
Reconstruction
No

§ 60.16
Priority list
No

§ 60.17
Incorporations by reference
Yes

§ 60.18
General control device requirements
No

§ 60.19
General notification and reporting requirements
Yes
Does not apply to  notifications under
§75.61 or to information reported through ECMPS.

PART 70 --  STATE OPERATING PERMIT PROGRAMS
      3. The authority citation for part 70 continues to read as follows:
Authority: 42 U.S.C. 7401 et seq.
      4. Section 70.2 is amended by revising the introductory text, removing "or" from the end of paragraph (2), adding "or" to the end of paragraph (3), and adding paragraph (4) to the definition of "Regulated pollutant (for presumptive fee calculation)."
      The revision and additions read as follows:
§ 70.2  Definitions.
*	*	*	*	*
      Regulated pollutant (for presumptive fee calculation), which is used only for purposes of § 70.9(b)(2), means any regulated air pollutant except the following:
*	*	*	*	*
      (4) Greenhouse gases.
*	*	*	*	*
	5. Section 70.9 is amended by revising paragraph (b)(2)(i), and by adding paragraph (b)(2)(v) to read as follows:
§ 70.9   Fee determination and certification.
*	*	*	*	*
      (b) *  *  *
	(2)(i) The Administrator will presume that the fee schedule meets the requirements of paragraph (b)(1) of this section if it would result in the collection and retention of an amount not less than $25 per year [as adjusted pursuant to the criteria set forth in paragraph (b)(2)(iv) of this section] times the total tons of the actual emissions of each regulated pollutant (for presumptive fee calculation) emitted from part 70 sources and any GHG cost adjustment required under paragraph (b)(2)(v) of this section.
*	*	*	*	*
      (v) GHG cost adjustment. The amount calculated in paragraph (b)(2)(i) of this section shall be increased by the GHG cost adjustment determined as follows:  For each activity identified in the following table, multiply the number of activities performed by the permitting authority by the burden hours per activity, and then calculate a total number of burden hours for all activities. Next, multiply the burden hours by the average cost of staff time, including wages, employee benefits and overhead.

                                   Activity
Burden hours per activity
GHG completeness determination (for initial permit or updated application)

GHG evaluation for a modification or related permit action

GHG evaluation at permit renewal

                                                                             43

                                                                              7

                                                                             10

*	*	*	*	*
PART 71 --  FEDERAL OPERATING PERMIT PROGRAMS
      6. The authority citation for part 71 continues to read as follows:
Authority: 42 U.S.C. 7401 et seq.
      7. Section 71.2 is amended by removing "or" from the end of paragraph (2), adding "or" to the end of paragraph (3), and adding paragraph (4) to the definition of "Regulated pollutant (for fee calculation)."
      The revisions and additions read as follows:
§ 71.2   Definitions.
*	*	*	*	*
      Regulated pollutant (for fee calculation), which is used only for purposes of § 71.9(c), means any "regulated air pollutant" except the following:
*	*	*	*	*
      (4) Greenhouse gases.
*	*	*	*	*
      8. Section 71.9 is amended by:
      a. Revising paragraphs (c)(1), (c)(2)(i), (c)(3), and (c)(4), and
      b. Adding paragraph (c)(8).
      The revisions and additions read as follows:
§ 71.9   Permit fees.
*	*	*	*	*
      (c) *  *  *
      (1) For part 71 programs that are administered by EPA, each part 71 source shall pay an annual fee which is the sum of:
      (i) $32 per ton (as adjusted pursuant to the criteria set forth in paragraph (n)(1) of this section) times the total tons of the actual emissions of each regulated pollutant (for fee calculation) emitted from the source, including fugitive emissions; and
      (ii) Any GHG fee adjustment required under paragraph (c)(8) of this section.
      (2) *  *  *
      (i) Where the EPA has not suspended its part 71 fee collection pursuant to paragraph (c)(2)(ii) of this section, the annual fee for each part 71 source shall be the sum of:
      (A) $24 per ton (as adjusted pursuant to the criteria set forth in paragraph (n)(1) of this section) times the total tons of the actual emissions of each regulated pollutant (for fee calculation) emitted from the source, including fugitive emissions; and
      (B) Any GHG fee adjustment required under paragraph (c)(8) of this section.

*	*	*	*	*
      (3) For part 71 programs that are administered by EPA with contractor assistance, the per ton fee shall vary depending on the extent of contractor involvement and the cost to EPA of contractor assistance. The EPA shall establish a per ton fee that is based on the contractor costs for the specific part 71 program that is being administered, using the following formula:
Cost per ton=( E x32)+[(1− E )x$ C ]
      Where E represents EPA's proportion of total effort (expressed as a percentage of total effort) needed to administer the part 71 program, 1- E represents the contractor's effort, and C represents the contractor assistance cost on a per ton basis. C shall be computed by using the following formula:
C =[ B + T + N ] divided by 12,300,000
      Where B represents the base cost (contractor costs), where T represents travel costs, and where N represents nonpersonnel data management and tracking costs.   In addition, each part 71 source shall pay a GHG fee adjustment for each activity as required under paragraph (c)(8) of this section.
      (4) For programs that are delegated in part, the fee shall be computed using the following formula: