Vol. 80 Friday, No. 205 October 23, 2015
Part II
Environmental Protection Agency
40 CFR Parts 60, 70, 71, et al. Standards of Performance for Greenhouse Gas Emissions From New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units; Final Rule
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ENVIRONMENTAL PROTECTION in hard copy at the EPA Docket Center FOAK First-of-a-kind AGENCY (EPA/DC), Room 3334, EPA WJC West FR Federal Register Building, 1301 Constitution Ave. NW., GHG Greenhouse Gas 40 CFR Parts 60, 70, 71, and 98 Washington, DC. The Public Reading GHGRP Greenhouse Gas Reporting Program GPM Gallons per Minute [EPA–HQ–OAR–2013–0495; EPA–HQ–OAR– Room is open from 8:30 a.m. to 4:30 GS Geologic Sequestration 2013–0603; FRL–9930–66–OAR] p.m., Monday through Friday, excluding GW Gigawatts legal holidays. The telephone number H2 Hydrogen Gas RIN 2060–AQ91 for the Public Reading Room is (202) HAP Hazardous Air Pollutant HFC Hydrofluorocarbon Standards of Performance for 566–1744, and the telephone number for the Air Docket is (202) 566–1742. HRSG Heat Recovery Steam Generator Greenhouse Gas Emissions From New, IGCC Integrated Gasification Combined FOR FURTHER INFORMATION CONTACT: Dr. Modified, and Reconstructed Cycle Stationary Sources: Electric Utility Nick Hutson, Energy Strategies Group, IPCC Intergovernmental Panel on Climate Generating Units Sector Policies and Programs Division Change (D243–01), U.S. EPA, Research Triangle IPM Integrated Planning Model AGENCY: Environmental Protection Park, NC 27711; telephone number (919) IRPs Integrated Resource Plans Agency (EPA). 541–2968, facsimile number (919) 541– kg/MWh Kilogram per Megawatt-hour ACTION: Final rule. 5450; email address: hutson.nick@ kJ/kg Kilojoules per Kilogram epa.gov or Mr. Christian Fellner, Energy kWh Kilowatt-hour SUMMARY: The Environmental Protection Strategies Group, Sector Policies and lb CO2/MMBtu Pounds of CO2 per Million British Thermal Unit Agency (EPA) is finalizing new source Programs Division (D243–01), U.S. EPA, performance standards (NSPS) under lb CO2/MWh Pounds of CO2 per Megawatt- Research Triangle Park, NC 27711; hour Clean Air Act (CAA) section 111(b) that, telephone number (919) 541–4003, lb CO2/yr Pounds of CO2 per Year for the first time, will establish facsimile number (919) 541–5450; email lb/lb-mole Pounds per Pound-Mole standards for emissions of carbon address: [email protected]. LCOE Levelized Cost of Electricity dioxide (CO2) for newly constructed, SUPPLEMENTARY INFORMATION: Acronyms. MATS Mercury and Air Toxic Standards modified, and reconstructed affected A number of acronyms and chemical MMBtu/hr Million British Thermal Units fossil fuel-fired electric utility symbols are used in this preamble. per Hour generating units (EGUs). This action MRV Monitoring, Reporting, and While this may not be an exhaustive Verification establishes separate standards of list, to ease the reading of this preamble performance for fossil fuel-fired electric MW Megawatt and for reference purposes, the MWe Megawatt Electrical utility steam generating units and fossil following terms and acronyms are MWh Megawatt-hour fuel-fired stationary combustion defined as follows: MWh-g Megawatt-hour gross turbines. This action also addresses MWh-n Megawatt-hour net AB Assembly Bill related permitting and reporting issues. N O Nitrous Oxide AEO Annual Energy Outlook 2 In a separate action, under CAA section AEP American Electric Power NAAQS National Ambient Air Quality 111(d), the EPA is issuing final emission ANSI American National Standards Standards guidelines for states to use in Institute NAICS North American Industry Classification System developing plans to limit CO2 emissions ASME American Society of Mechanical from existing fossil fuel-fired EGUs. Engineers NAS National Academy of Sciences BACT Best Available Control Technology NETL National Energy Technology DATES: This final rule is effective on Laboratory October 23, 2015. The incorporation by BDT Best Demonstrated Technology BSER Best System of Emission Reduction NGCC Natural Gas Combined Cycle th reference of certain publications listed Btu/kWh British Thermal Units per NOAK n -of-a-kind in the rule is approved by the Director Kilowatt-hour NRC National Research Council of the Federal Register as of October 23, Btu/lb British Thermal Units per Pound NSPS New Source Performance Standards 2015. CAA Clean Air Act NSR New Source Review NTTAA National Technology Transfer and ADDRESSES: CAIR Clean Air Interstate Rule The EPA has established Advancement Act dockets for this action under Docket ID CBI Confidential Business Information CCS Carbon Capture and Storage (or O2 Oxygen Gas No. EPA–HQ–OAR–2013–0495 Sequestration) OMB Office of Management and Budget (Standards of Performance for CDX Central Data Exchange PC Pulverized Coal Greenhouse Gas Emissions from New CEDRI Compliance and Emissions Data PFC Perfluorocarbon Stationary Sources: Electric Utility Reporting Interface PM Particulate Matter Generating Units) and Docket ID No. CEMS Continuous Emissions Monitoring PM2.5 Fine Particulate Matter EPA–HQ–OAR–2013–0603 (Carbon System PRA Paperwork Reduction Act Pollution Standards for Modified and CFB Circulating Fluidized Bed PSD Prevention of Significant Deterioration CH4 Methane PUC Public Utilities Commission Reconstructed Stationary Sources: RCRA Resource Conservation and Recovery Electric Utility Generating Units). All CHP Combined Heat and Power CO2 Carbon Dioxide Act documents in the dockets are listed on CSAPR Cross-State Air Pollution Rule RFA Regulatory Flexibility Act the www.regulations.gov Web site. DOE Department of Energy RGGI Regional Greenhouse Gas Initiative Although listed in the index, some DOT Department of Transportation RIA Regulatory Impact Analysis information is not publicly available, ECMPS Emissions Collection and RPS Renewable Portfolio Standard e.g., Confidential Business Information Monitoring Plan System RTC Response to Comments or other information whose disclosure is EERS Energy Efficiency Resource Standards RTP Response to Petitions restricted by statute. Certain other EGU Electric Generating Unit SBA Small Business Administration SCC Social Cost of Carbon material, such as copyrighted material, EIA Energy Information Administration EO Executive Order SCR Selective Catalytic Reduction will be publicly available only in hard EOR Enhanced Oil Recovery SCPC Supercritical Pulverized Coal copy. Publicly available docket EPA Environmental Protection Agency SDWA Safe Drinking Water Act materials are available either FB Fluidized Bed SF6 Sulfur Hexafluoride electronically in www.regulations.gov or FGD Flue Gas Desulfurization SIP State Implementation Plan
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SNCR Selective Non-Catalytic Reduction D. Post-Combustion Carbon Capture B. New Combustion Turbines SO2 Sulfur Dioxide E. Pre-Combustion Carbon Capture C. Modified and Reconstructed Steam and SSM Startup, Shutdown, and Malfunction F. Vendor Guarantees, Industry Statements, NGCC Units Tg Teragram (one trillion (1012) grams) Academic Literature, and Commercial XII. Interactions With Other EPA Programs Tpy Tons per Year Availability and Rules TSD Technical Support Document G. Response to Key Comments on the A. Overview TTN Technology Transfer Network Adequacy of the Technical Feasibility B. Applicability of Tailoring Rule UIC Underground Injection Control Demonstration Thresholds Under the PSD Program UMRA Unfunded Mandates Reform Act of H. Consideration of Costs C. Implications for BACT Determinations 1995 I. Key Comments Regarding the EPA’s Under PSD U.S. United States Consideration of Costs D. Implications for Title V Program USDW Underground Source of Drinking J. Achievability of the Final Standards E. Implications for Title V Fee Water K. Emission Reductions Utilizing Partial Requirements for GHGs USGCRP U.S. Global Change Research CCS F. Interactions With Other EPA Rules Program L. Further Development and Deployment XIII. Impacts of This Action VCS Voluntary Consensus Standard of CCS Technology A. What are the air impacts? WGS Water Gas Shift M. Technical and Geographic Aspects of B. Endangered Species Act WWW World Wide Web Disposition of Captured CO2 C. What are the energy impacts? Organization of This Document. The N. Final Requirements for Disposition of D. What are the water and solid waste information presented in this preamble Captured CO2 impacts? O. Non-Air Quality Impacts and Energy is organized as follows: E. What are the compliance costs? Requirements F. What are the economic and employment I. General Information P. Options That Were Considered by the impacts? A. Executive Summary EPA But Were Ultimately Not G. What are the benefits of the final B. Does this action apply to me? Determined to Be the BSER standards? C. Where can I get a copy of this Q. Summary XIV. Statutory and Executive Order Reviews document? VI. Rationale for Final Standards for A. Executive Order 12866: Regulatory D. Judicial Review Modified Fossil Fuel-Fired Electric Planning and Review and Executive E. How is this preamble organized? Utility Steam Generating Units Order 13563: Improving Regulation and II. Background A. Rationale for Final Applicability Criteria Regulatory Review A. Climate Change Impacts From GHG for Modified Steam Generating Units B. Paperwork Reduction Act (PRA) Emissions B. Identification of the Best System of C. Regulatory Flexibility Act (RFA) B. GHG Emissions From Fossil Fuel-Fired Emission Reduction D. Unfunded Mandates Reform Act EGUs C. BSER Criteria (UMRA) C. The Utility Power Sector VII. Rationale for Final Standards for E. Executive Order 13132: Federalism D. Statutory Background Reconstructed Fossil Fuel-Fired Electric F. Executive Order 13175: Consultation E. Regulatory Background Utility Steam Generating Units F. Development of Carbon Pollution and Coordination With Indian Tribal A. Rationale for Final Applicability Criteria Governments Standards for Fossil Fuel-Fired Electric for Reconstructed Sources Utility Generating Units G. Executive Order 13045: Protection of B. Identification of the Best System of Children From Environmental Health G. Stakeholder Engagement and Public Emission Reduction Comments on the Proposals Risks and Safety Risks VIII. Summary of Final Standards for Newly III. Regulatory Authority, Affected EGUs and H. Executive Order 13211: Actions Constructed and Reconstructed Their Standards, and Legal Requirements Concerning Regulations That Stationary Combustion Turbines A. Authority To Regulate Carbon Dioxide Significantly Affect Energy Supply, A. Applicability Requirements From Fossil Fuel-Fired EGUs Distribution, or Use B. Treatment of Categories and B. Best System of Emission Reduction I. National Technology Transfer and Codification in the Code of Federal C. Final Emission Standards Advancement Act (NTTAA) and 1 CFR Regulations D. Significant Differences Between Part 51 C. Affected Units Proposed and Final Combustion Turbine J. Executive Order 12898: Federal Actions D. Units Not Covered by This Final Rule Provisions To Address Environmental Justice in E. Coal Refuse IX. Rationale for Final Standards for Newly Minority Populations and Low-Income F. Format of the Output-Based Standard Constructed and Reconstructed Populations G. CO2 Emissions Only Stationary Combustion Turbines K. Congressional Review Act (CRA) H. Legal Requirements for Establishing A. Applicability XV. Withdrawal of Proposed Standards for Emission Standards B. Subcategories Certain Modified Sources I. Severability C. Identification of the Best System of XVI. Statutory Authority J. Certain Projects Under Development Emission Reduction IV. Summary of Final Standards for Newly D. Achievability of the Final Standards I. General Information X. Summary of Other Final Requirements for Constructed, Modified, and Reconstructed A. Executive Summary Fossil Fuel-Fired Electric Utility Steam Newly Constructed, Modified, and Generating Units Reconstructed Fossil Fuel-Fired Electric 1. Purpose of the Regulatory Action A. Applicability Requirements and Utility Steam Generating Units and Rationale Stationary Combustion Turbines In this final action the EPA is B. Best System of Emission Reduction A. Startup, Shutdown, and Malfunction establishing standards that limit C. Final Standards of Performance Requirements greenhouse gas (GHG) emissions from V. Rationale for Final Standards for Newly B. Continuous Monitoring Requirements newly constructed, modified, and Constructed Fossil Fuel-Fired Electric C. Emissions Performance Testing reconstructed fossil fuel-fired electric Utility Steam Generating Units Requirements utility steam generating units and A. Factors Considered in Determining the D. Continuous Compliance Requirements stationary combustion turbines, BSER E. Notification, Recordkeeping, and following the issuance of proposals for B. Highly Efficient SCPC EGU Reporting Requirements Implementing Partial CCS as the BSER XI. Consistency Between BSER such standards and an accompanying for Newly Constructed Steam Generating Determinations for This Rule and the Notice of Data Availability. Units Rule for Existing EGUs On June 25, 2013, in conjunction with C. Rationale for the Final Emission A. Newly Constructed Steam Generating the announcement of his Climate Action Standards Units Plan (CAP), President Obama issued a
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Presidential Memorandum directing the EPA proposed standards of performance The EPA received numerous EPA to issue a proposal to address for: (1) Modified fossil fuel-fired steam comments and conducted extensive carbon pollution from new power plants generating units, (2) modified natural outreach to stakeholders for this by September 30, 2013, and to issue gas-fired stationary combustion rulemaking. After careful consideration ‘‘standards, regulations, or guidelines, turbines, (3) reconstructed fossil fuel- of public comments and input from a as appropriate, which address carbon fired steam generating units, and (4) variety of stakeholders, the final pollution from modified, reconstructed, reconstructed natural gas-fired standards of performance in this action and existing power plants.’’ Pursuant to stationary combustion turbines. reflect certain changes from the authority in section 111(b) of the CAA, In this action, the EPA is issuing final proposals. Comments considered on September 20, 2013, the EPA issued standards of performance to limit include written comments that were proposed carbon pollution standards for emissions of GHG pollution manifested submitted during the public comment newly constructed fossil fuel-fired as CO2 from newly constructed, power plants. The proposal was period and oral testimony provided modified, and reconstructed fossil fuel- during the public hearing for the published in the Federal Register on fired electric utility steam generating January 8, 2014 (79 FR 1430; ‘‘January proposed standards. 1 units (i.e., utility boilers and integrated 2014 proposal’’). In that proposal, the gasification combined cycle (IGCC) 2. Summary of Major Provisions and EPA proposed to limit emissions of CO2 units) and from newly constructed and Changes to the Proposed Standards from newly constructed fossil fuel-fired reconstructed stationary combustion electric utility steam generating units turbines. Consistent with the The BSER determinations and final and newly constructed natural gas-fired requirements of CAA section 111(b), standards of performance for affected stationary combustion turbines. these standards reflect the degree of newly constructed, modified, and The EPA subsequently issued a Notice emission limitation achievable through reconstructed EGUs are summarized in of Data Availability (NODA) in which the application of the best system of Table 1 and discussed in more detail the EPA solicited comment on its initial emission reduction (BSER) that the EPA below. The final standards for new, interpretation of provisions in the modified, and reconstructed EGUs Energy Policy Act of 2005 (EPAct05) has determined has been adequately demonstrated for each type of unit. apply to sources that commenced and associated provisions in the Internal construction—or modification or Revenue Code (IRC) and also solicited These final standards are codified in 40 reconstruction, as appropriate—on or comment on a companion Technical CFR part 60, subpart TTTT, a new after the date of publication of Support Document (TSD) that addressed subpart specifically created for CAA corresponding proposed standards.2 The these provisions’ relationship to the 111(b) standards of performance for factual record supporting the proposed GHG emissions from fossil fuel-fired final standards for newly constructed rule. 79 FR 10750 (February 26, 2014). EGUs. fossil fuel-fired EGUs apply to those On June 2, 2014, the EPA proposed In a separate action that affects the sources that commenced construction standards of performance, also pursuant same source category, the EPA is issuing on or after the date of publication of the to CAA section 111(b), to limit final emission guidelines under CAA proposed standards, January 8, 2014. emissions of CO2 from modified and section 111(d) for states to use in The final standards for modified and reconstructed fossil fuel-fired electric developing plans to limit CO2 emissions reconstructed fossil fuel-fired EGUs utility steam generating units and from existing fossil fuel-fired EGUs. apply to those sources that modify or natural gas-fired stationary combustion Pursuant to those guidelines, states reconstruct on or after the date of turbines. 79 FR 34960 (June 18, 2014) must submit plans to the EPA following publication of the proposed standards, (‘‘June 2014 proposal’’). Specifically, the a schedule set by the guidelines. June 18, 2014.
TABLE 1—SUMMARY OF BSER AND FINAL STANDARDS FOR AFFECTED EGUS
Affected EGUs BSER Final standards of performance
Newly Constructed Fossil Fuel-Fired Efficient new supercritical pulverized 1,400 lb CO2/MWh-g. Steam Generating Units. coal (SCPC) utility boiler imple- menting partial carbon capture and storage (CCS). Modified Fossil Fuel-Fired Steam Gener- Most efficient generation at the affected Sources making modifications resulting in an increase in ating Units. EGU achievable through a combina- CO2 hourly emissions of more than 10 percent are re- tion of best operating practices and quired to meet a unit-specific emission limit determined equipment upgrades. by the unit’s best historical annual CO2 emission rate (from 2002 to the date of the modification); the emission limit will be no more stringent than: 1. 1,800 lb CO2/MWh-g for sources with heat input >2,000 MMBtu/h. 2. 2,000 lb CO2/MWh-g for sources with heat input ≤2,000 MMBtu/h. Reconstructed Fossil Fuel-Fired Steam Most efficient generating technology at 1. Sources with heat input >2,000 MMBtu/h are required to Generating Units. the affected source (supercritical meet an emission limit of 1,800 lb CO2/MWh-g. steam conditions for the larger; and 2. Sources with heat input ≤2,000 MMBtu/h are required to subcritical conditions for the smaller). meet an emission limit of 2,000 lb CO2/MWh-g.
1 The EPA previously proposed performance the EPA proposed standards for steam generating Reduction determination. On January 8, 2014, the standards for newly reconstructed fossil fuel-fired units and natural gas-fired combustion turbines EPA withdrew that proposal (79 FR 1352). EGUs in April 2012 (77 FR 22392). In that action, based on a single Best System of Emission 2 See CAA section 111(a)(2).
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TABLE 1—SUMMARY OF BSER AND FINAL STANDARDS FOR AFFECTED EGUS—Continued
Affected EGUs BSER Final standards of performance
Newly Constructed and Reconstructed Efficient NGCC technology for base 1. 1,000 lb CO2/MWh-g or 1,030 lb CO2/MWh-n for base Fossil Fuel-Fired Stationary Combus- load natural gas-fired units and clean load natural gas-fired units. tion Turbines. fuels for non-base load and multi- 2. 120 lb CO2/MMBtu for non-base load natural gas-fired fuel-fired units.3 units. 4 3. 120 to 160 lb CO2/MMBtu for multi-fuel-fired units.
a. Fossil Fuel-Fired Electric Utility proposed standards—one that we meet this final standard of performance Steam Generating Units conclude better represents the by capturing and storing approximately This action establishes standards of requirement that the BSER be 23 percent of the CO2 produced from the performance for newly constructed implementable at reasonable cost. facility. As an alternative compliance fossil fuel-fired steam generating units 5 The EPA proposed that the BSER for option, utilities and project developers based on the performance of a new newly constructed steam generating will also be able to construct new steam highly efficient SCPC EGU EGUs was highly efficient new generating units (both utility boilers and implementing post-combustion partial generating technology (i.e., a IGCC units) that meet the final standard carbon capture and storage (CCS) supercritical utility boiler or IGCC unit) of performance by co-firing with natural technology, which the EPA determines implementing partial CCS technology to gas. This final standard of performance to be the BSER for these sources. After achieve CO2 emission reductions for newly constructed fossil fuel-fired consideration of a wide range of resulting in an emission limit of 1,100 steam generating units provides a clear 6 comments, technical input received on lb CO2/MWh-g. and achievable path forward for the the availability, technical feasibility, The BSER for newly constructed construction of such sources while and cost of CCS implementation, and steam generating EGUs in the final rule addressing GHG emissions and publicly available information about is very similar to that in the January supporting technological innovation. 2014 proposal. In this final action, the projects that are implementing or The standard of 1,400 lb CO2/MWh-g is planning to implement CCS, the EPA EPA finds that a highly efficient new achievable by fossil fuel-fired steam confirms its proposed determination supercritical pulverized coal (SCPC) generating units for all fuel types, under that CCS technology is available and utility boiler EGU implementing partial a wide range of conditions, and technically feasible to implement at CCS to the degree necessary to achieve throughout the United States. fossil fuel-fired steam generating units. an emission of 1,400 lb CO2/MWh-g is We note that identifying a highly However, the EPA’s final standard the BSER. Contrary to the January 2014 efficient new SCPC EGU implementing reflects the consideration of legitimate proposal, the EPA finds that IGCC partial CCS as the BSER provides a path concerns regarding the cost to technology—either with natural gas co- implement available CCS technology on firing or implementing partial CCS—is forward for new fossil fuel-fired steam a new steam generating unit. not part of the BSER, but recognizes that generation in the current market Accordingly, the EPA is finalizing an IGCC technology can serve as an context. Numerous studies have emission standard for newly alternative method of compliance. predicted that few new fossil fuel-fired constructed fossil fuel-fired steam The EPA finds that a highly efficient steam generating units will be constructed in the future. These generating units at 1,400 lb CO2/MWh- SCPC implementing partial CCS is the g, a level that is less stringent than the BSER because CCS technology has been analyses identify a range of factors unrelated to this rulemaking, including proposed limitation of 1,100 lb CO2/ demonstrated to be technically feasible MWh-g. This final standard reflects our and is in use or under construction in low electricity demand growth, highly identification of the BSER for such units various industrial sectors, including the competitive natural gas prices, and to be a lower level of partial CCS than power generation sector. For example, increases in the supply of renewable we identified as the basis of the the Boundary Dam Unit #3 CCS project energy. The EPA recognizes that, in in Saskatchewan, Canada is a full-scale, certain circumstances, there may be 3 The term ‘‘multi-fuel-fired’’ refers to a stationary fully integrated CCS project that is interest in building fossil fuel-fired combustion turbine that is physically connected to currently operating and is designed to steam generating units despite these a natural gas pipeline, but that burns a fuel other capture more than 90 percent of the CO2 market conditions. In particular, than natural gas for 10 percent or more of the unit’s heat input capacity during the 12-operating-month from the lignite-fired boiler. A newly utilities and project developers may compliance period. constructed, highly efficient SCPC build new fossil fuel-fired steam 4 The emission standard for combustion turbines utility boiler burning bituminous coal generating EGUs in order to achieve or co-firing natural gas with other fuels shall be will be able to meet this final standard maintain fuel diversity within determined at the end of each operating month of performance by capturing and storing generating fleets, as a hedge against the based on the amount of co-fired natural gas. Units only burning natural gas with other fuels with a approximately 16 percent of the CO2 possibility of natural gas prices far relatively consistent chemical composition and an produced from the facility. A newly exceeding projections, or to co-produce emission factor of 160 lb CO2/MMBtu or less (e.g., constructed, highly efficient SCPC both power and chemicals, including natural gas, distillate oil, etc.) only need to maintain utility boiler burning subbituminous capturing CO2 for use in enhanced oil records of the fuels burned at the unit to 7 demonstrate compliance. Units burning fuels with coal or dried lignite will be able to variable chemical composition or with an emission technologies for lignite-fired power plants’’ 6 factor greater than 160 lb CO2/MMBtu (e.g., residual Using the most recent data on partial capture available at www.iea-coal.org.uk/documents/83436/ oil) must conduct periodic fuel sampling and rates to meet an emission standard of 1,100 lb CO2/ 9095/Techno-economics-of-modern-pre-drying- testing to determine the overall CO2 emission rate. MWh-gross, about 35 percent capture would be technologies-for-lignite-fired-power-plants,-CCC/ 5 Also referred to as just ‘‘steam generating units’’ required at an SCPC unit and about 22 percent 241; ‘‘Drying the lignite prior to combustion in the or as ‘‘utility boilers and IGCC units’’. These are capture would be required at an IGCC unit. boiler is thus an effective way to increase the 7 units that are covered under 40 CFR part 60, For a summary of lignite drying technologies, thermal efficiencies and reduce the CO2 emissions subpart Da for criteria pollutants. see ‘‘Techno-economics of modern pre-drying from lignite-fired power plants.’’
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8 recovery (EOR) projects. As regulatory account for facilities that have already increase in CO2 emissions of less than history has shown, identifying a new implemented best practices and or equal to 10 percent). highly efficient SCPC EGU equipment upgrades, the final rule also For reconstructed steam generating implementing partial CCS as the BSER specifies that modified facilities will not units, the EPA is finalizing standards in this rule is likely to further boost have to meet an emission standard more based on the performance of the most research and development in CCS stringent than the corresponding efficient generating technology for these technologies, making the standard for reconstructed steam types of units as the BSER (i.e., implementation even more efficacious generating units (i.e., 1,800 lb CO2/ reconstructing the boiler if necessary to and cost-effective, while providing a MWh-g for units with heat input greater use steam with higher temperature and competitive, low emission future for than 2,000 MMBtu/h and 2,000 lb CO2/ pressure, even if the boiler was not fossil fuel-fired steam generation. MWh-g for units with heat input less originally designed to do so).11 The The EPA is also issuing final than or equal to 2,000 MMBtu/h). emission standard for these sources is standards for steam generating units that The final standards for steam 1,800 lb CO2/MWh-g for large sources, implement ‘‘large modifications,’’ (i.e., generating units implementing large (i.e. those with a heat input rating of modifications resulting in an increase in modifications are similar to the greater than 2,000 MMBtu/h) or 2,000 lb hourly CO2 emissions of more than 10 proposed standards for such units. In CO2/MWh-g for small sources (i.e., those percent when compared to the source’s the proposal, we suggested that the with a heat input rating of 2,000 highest hourly emissions in the standard should be based on when the MMBtu/h or less). The difference in the 9 previous 5 years). The EPA is not modification is undertaken (i.e., before standards for larger and smaller units is issuing final standards, at this time, for being subject to requirements under a based on greater availability of higher steam generating units that implement CAA section 111(d) state plan or after pressure/temperature steam turbines ‘‘small modifications’’ (i.e., being subject to such a plan). We also (e.g., supercritical steam turbines) for modifications resulting in an increase in suggested that for units that undertake larger units. The standards can also be hourly CO2 emissions of less than or modifications prior to becoming subject met through other non-BSER options, equal to 10 percent when compared to to an approved CAA section 111(d) state such as natural gas co-firing. the source’s highest hourly emissions in plan, the standard should be its best b. Stationary Combustion Turbines the previous 5 years). historical performance plus an The standards of performance for additional two percent reduction. In This action also finalizes standards of modified steam generating units that response to comments on the proposal, performance for newly constructed and make large modifications are based on we are not finalizing separate standards reconstructed stationary combustion each affected unit’s own best potential that are dependent upon when the turbines. In the January 2014 proposal performance as the BSER. Specifically, modification takes place, nor are we for newly constructed EGUs, the EPA such a modified steam generating unit proposed that natural gas-fired will be required to meet a unit-specific finalizing the proposed additional two percentage reduction. stationary combustion turbines (i.e., CO2 emission limit determined by that turbines combusting over 90 percent unit’s best demonstrated historical The EPA is not promulgating final standards of performance for, and is natural gas) would be subject to a performance (in the years from 2002 to 10 withdrawing the proposed standards for standard of performance for CO2 the time of the modification). The EPA emissions if they are constructed for the has determined that this standard based steam generating sources that make modifications resulting in an increase of purpose of supplying and actually on each unit’s own best potential annually supply to the grid (1) one-third hourly CO2 emissions of less than or performance can be met through a or more of their potential electric combination of best operating practices equal to 10 percent (see Section XV of output 12 and (2) more than 219,000 and equipment upgrades and that these this preamble). As we indicated in the MWh,13 based on a three-year rolling steps can be implemented cost- proposal, the EPA has been notified of average. We refer to units that operate effectively at the time when a source is very few modifications for criteria above the electric sales thresholds as undertaking a large modification. To pollutant emissions from the power sector to which NSPS requirements ‘‘base load units,’’ and we refer to units that operate below these thresholds as 8 As the EIA has stated: Policy-related factors, have applied. As such, we expect that such as environmental regulations and investment there will be few NSPS modifications ‘‘non-base load units.’’ or production tax credits for specified generation for GHG emissions as well. Even so, we In the January 2014 proposal for sources, can also impact investment decisions. also recognize (and we discuss in this newly constructed combustion turbines, Finally, although levelized cost calculations are the EPA proposed standards for two generally made using an assumed set of capital and preamble) that the power sector is operating costs, the inherent uncertainty about undergoing significant change and subcategories of base load natural gas- future fuel prices and future policies may cause realignment in response to a variety of fired stationary combustion turbines. plant owners or investors who finance plants to The proposed standard for small place a value on portfolio diversification. While EIA influences and incentives in the considers many of these factors in its analysis of industry. We do not have sufficient combustion turbines (units with base technology choice in the electricity sector, these information at this time, however, to load ratings less than or equal to 850 concepts are not included in LCOE or LACE anticipate the types of modifications, if MMBtu/h) was 1,100 lb CO2/MWh-g. calculations. http://www.eia.gov/forecasts/aeo/ _ any, that may result from these changes. The proposed standard for large electricity generation.cfm. combustion turbines (units with base 9 40 CFR 60.14(h) provides that no physical In particular, we do not have sufficient change, or change in the method of operation, at an information about the types of 11 existing electric utility steam generating unit will be modifications, if any, that would result Steam with higher temperature and pressure treated as a modification provided that such change has more thermal energy that can be more does not increase the maximum hourly emissions in increases in CO2 emissions of 10 efficiently converted to electrical energy. above the maximum hourly emissions achievable at percent or less, and what the 12 We refer to thresholds related to an EGU’s that unit during the 5 years prior to the change. appropriate standard for such sources actual annual electrical sales (as a fraction of 10 For the 2002 reporting year the EPA introduced would be. Therefore, we conclude that potential annual output) as ‘‘percentage electric new automated checks in the software that sales criteria.’’ integrated automated quality assurance (QA) checks it is prudent to delay issuing standards 13 We refer to thresholds related to an EGU’s on the hourly data. Thus, the EPA believes that the for sources that undertake small actual annual electrical sales in megawatt-hours as data from 2002 and forward are of higher quality. modifications (i.e., those resulting in an ‘‘total electric sales criteria.’’
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load ratings greater than 850 MMBtu/h) is finalizing a standard of 1,000 lb CO2/ whether smaller existing combustion was 1,000 lb CO2/MWh-g. The EPA did MWh-g based on efficient natural gas turbines that undertake a modification not propose standards for non-base load combined cycled (NGCC) technology as can meet this standard. As a result, we units. the BSER. Alternatively, owners and have concluded that it is prudent to In the June 2014 proposal for operators of base load natural gas-fired delay issuing standards for sources that modified and reconstructed combustion combustion turbines may elect to undertake modifications until we can turbines, the EPA solicited comment on comply with a standard based on net gather more information. alternative approaches for establishing output of 1,030 lb CO2/MWh-n. A more detailed discussion of the applicability and subcategorization The EPA is eliminating the 219,000 final standards of performance for criteria, including (1) eliminating the MWh total annual electric sales stationary combustion turbines, the ‘‘constructed for the purpose of criterion for non-CHP units. In addition, applicability criteria, and the comments supplying’’ qualifier for the total electric the EPA is finalizing the sliding-scale that influenced the final standards is sales and percentage electric sales approach for deriving the unit-specific, provided in Sections VIII and IX of this criteria, (2) eliminating the 219,000 percentage electric sales threshold preamble. above which a combustion turbine MWh total electric sales criterion 3. Costs and Benefits altogether, (3) replacing the fixed transitions from the subcategory for percentage electric sales criterion with a non-base load units to the subcategory As explained in the regulatory impact variable percentage electric sales for base load units. For newly analysis (RIA) for this final rule, criterion (i.e., the sliding-scale constructed and reconstructed non-base available data—including utility approach 14), and (4) eliminating the load natural gas-fired stationary announcements and Energy Information proposed small and large subcategories combustion turbines, the EPA is Administration (EIA) modeling— for base load natural gas-fired finalizing the combustion of clean fuels indicate that, even in the absence of this combustion turbines. These proposed (natural gas with a small allowance for rule, (i) existing and anticipated applicability requirements were distillate oil) as the BSER with a economic conditions are such that few, intended to exclude combustion corresponding heat input-based if any, fossil fuel-fired steam-generating EGUs will be built in the foreseeable turbines that are used for the purpose of standard of 120 lb CO2/MMBtu. This meeting peak power demand, as standard of performance will apply to future, and (ii) utilities and project developers are expected to choose new opposed to those that are used to meet the vast majority of simple cycle generation technologies (primarily base load power demand. combustion turbines. The EPA is In both proposals, the EPA also finalizing a heat input-based clean fuels NGCC) that would meet the final solicited comment on a broad standard because we have insufficient standards and renewable generating applicability approach that would information at this time to set a uniform sources that are not affected by these final standards. These projections are include non-base load natural gas-fired output-based standard that can be consistent with utility announcements units (primarily simple cycle achieved by all new and reconstructed and EIA modeling that indicate that new combustion turbines) and multi-fuel- non-base load units. units are likely to be NGCC and that any fired units (primarily distillate oil-fired In addition, for newly constructed coal-fired steam generating units built combustion turbines) in the general and reconstructed multi-fuel-fired between now and 2030 would have applicability of subpart TTTT. As part stationary combustion turbines, the EPA CCS, even in the absence of this rule.16 of the broad applicability approach, the is finalizing an input-based standard of Therefore, based on the analysis EPA solicited comment on imposing 120 to 160 lb CO2/MMBtu based on the 15 presented in Chapter 4 of the RIA, the ‘‘no emission standard’’ or establishing combustion of clean fuels as the BSER. EPA projects that this final rule will separate numerical limits for these two The EPA has similarly determined that it has insufficient information at this result in negligible CO2 emission subcategories. changes, quantified benefits, and costs In this action, the EPA is finalizing a time to set a uniform output-based by 2022 as a result of the performance variation of the approaches put forward standard for stationary combustion standards for newly constructed in the January 2014 proposal for new turbines that operate with significant EGUs.17 However, as noted earlier, for a sources and the June 2014 proposal for quantities of a fuel other than natural gas. variety of reasons, some companies may modified and reconstructed sources. We are not promulgating final consider coal-fired steam generating Based on our review of public standards of performance for stationary units that the modeling does not comments related to the proposed combustion turbines that make anticipate. Thus, in Chapter 5 of the subcategories for small and large modifications at this time. We are RIA, we also present an analysis of the combustion turbines and our additional simultaneously withdrawing the project-level costs of a newly data analyses, we have determined that proposed standards for modifications constructed coal-fired steam generating there is no need to set two separate (see Section XV of this preamble). As we unit with partial CCS that meets the standards for different sizes of indicated in the proposal, sources from requirements of this final rule alongside combustion turbines for base load the power sector have notified the EPA the project-level costs of a newly natural gas-fired combustion turbines. of very few NSPS modifications, and we constructed coal-fired unit without CCS. The EPA has determined that all sizes expect that there will be few NSPS This analysis indicates that the of affected newly constructed and modifications for CO2 emissions as well. reconstructed stationary combustion Moreover, our decision to eliminate the 16 The EPA’s Integrated Planning Model (IPM) turbines can achieve the final standards. subcategories for small and large EGUs projects no new non-compliant coal (i.e., newly For newly constructed and and set a single standard of 1,000 lb constructed coal-fired plants that do not meet the reconstructed base load natural gas-fired final standard of performance) throughout the CO2/MWh-g has raised questions as to model horizon of 2030 (there is a small amount of stationary combustion turbines, the EPA new coal with CCS that is hardwired into the 15 Combustion turbines co-firing natural gas with modelling, consistent with EIA assumptions to 14 The sliding-scale approach determines a unit- other fuels shall determine fuel-based site-specific represent units already under construction or under specific percentage electric sales threshold standards at the end of each operating month. The development). equivalent to a unit’s net design efficiency (the site-specific standards depend on the amount of co- 17 Conditions in the analysis year of 2022 are maximum value is capped at 50 percent). fired natural gas. represented by a model year of 2020.
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quantified benefits of the standards of experience, the EPA expects that few standards for modified and performance would exceed their costs EGUs will trigger either the reconstructed sources. under a range of assumptions. modification or the reconstruction B. Does this action apply to me? As explained in the RIA and further provisions that we are finalizing in this below, the EPA has been notified of few action. In Chapter 6 of the RIA, we The entities potentially affected by power sector NSPS modifications or discuss factors that limit our ability to the standards are shown in Table 2 reconstructions. Based on that quantify the costs and benefits of the below.
TABLE 2—POTENTIALLY AFFECTED ENTITIES a
Category NAICS code Examples of potentially affected entities
Industry ...... 221112 Fossil fuel electric power generating units. Federal Government ...... b221112 Fossil fuel electric power generating units owned by the federal government. State/Local Government b221112 Fossil fuel electric power generating units owned by municipalities. Tribal Government ...... 921150 Fossil fuel electric power generating units in Indian Country. a Includes NAICS categories for source categories that own and operate electric power generating units (including boilers and stationary com- bined cycle combustion turbines). b Federal, state, or local government-owned and operated establishments are classified according to the activity in which they are engaged.
This table is not intended to be (including any public hearing) may be describes the source categories. Section exhaustive, but rather to provide a guide raised during judicial review.’’ This IV provides a summary of the final for readers regarding entities likely to be section also provides a mechanism standards for newly constructed, affected by this action. To determine mandating the EPA to convene a modified, and reconstructed fossil fuel- whether your facility, company, proceeding for reconsideration if the fired steam generating units. Sections V business, organization, etc., would be person raising an objection can through VII present the rationale for the regulated by this action, refer to Section demonstrate that it was impracticable to final standards for newly constructed, III of this preamble for more information raise such objection within the period modified, and reconstructed steam and examine the applicability criteria in for public comment or if the grounds for generating units, respectively. Sections 40 CFR 60.1 (General Provisions) and such objection arose after the period for VIII and IX provide a summary of the § 60.550840 of subpart TTTT (Standards public comment (but within the time final standards for stationary of Performance for Greenhouse Gas specified for judicial review) and if such combustion turbines and present the Emissions for Electric Utility Generating objection is of central relevance to the rationale for the final standards for Units). If you have any questions outcome of the rule. Any person seeking newly constructed and reconstructed regarding the applicability of this action to make such a demonstration should to a particular entity, consult either the submit a Petition for Reconsideration to combustion turbines, respectively. air permitting authority for the entity or the Office of the Administrator, U.S. Section X provides a summary of other your EPA regional representative as EPA, Room 3000, Ariel Rios Building, final requirements for newly listed in 40 CFR 60.4 or 40 CFR 63.13 1200 Pennsylvania Ave. NW., constructed, modified, and (General Provisions). Washington, DC 20460, with a copy to reconstructed fossil fuel-fired steam generating units and stationary C. Where can I get a copy of this both the person(s) listed in the combustion turbines. Section XI document? preceding FOR FURTHER INFORMATION CONTACT section, and the Associate addresses the consistency of the In addition to being available in the General Counsel for the Air and respective BSER determinations in these docket, an electronic copy of this final Radiation Law Office, Office of General rules and under the emission guidelines action will also be available on the Counsel (Mail Code 2344A), U.S. EPA, issued separately under CAA section Worldwide Web (WWW). Following 1200 Pennsylvania Ave. NW., 111(d). Interactions with other EPA signature, a copy of this final action will Washington, DC 20460. programs and rules are described in be posted at the following address: http://www2.epa.gov/carbon-pollution- E. How is this preamble organized? Section XII. Projected impacts of the standards. final action are then described in This action presents the EPA’s final Section XIII, followed by a discussion of D. Judicial Review standards of performance for newly statutory and executive order reviews in Under section 307(b)(1) of the CAA, constructed, modified, and Section XIV. Section XV addresses the judicial review of this final rule is reconstructed fossil fuel-fired electric withdrawal of the proposed standards available only by filing a petition for utility steam generating units and newly for steam generating EGUs that make review in the U.S. Court of Appeals for constructed and reconstructed modifications resulting in an increase of the District of Columbia Circuit by stationary combustion turbines. Section hourly CO2 emissions of less than or December 22, 2015. Moreover, under II provides background information on equal to 10 percent and the proposed section 307(b)(2) of the CAA, the climate change impacts from GHG standards for modified stationary requirements established by this final emissions, GHG emissions from fossil combustion turbines. The statutory rule may not be challenged separately in fuel-fired EGUs, the utility power sector, authority for this action is provided in any civil or criminal proceedings the statutory and regulatory background Section XVI. We address major brought by the EPA to enforce these relating to CAA section 111(b), EPA comments throughout this preamble and requirements. Section 307(d)(7)(B) of actions prior to this final action, and in greater detail in an accompanying the CAA further provides that ‘‘[o]nly an public comments regarding the response-to-comments document objection to a rule or procedure which proposed actions. Section III explains located in the docket. was raised with reasonable specificity the EPA’s authority to regulate CO2 and during the period for public comment EGUs, identifies affected EGUs, and
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II. Background raising average temperatures, climate continues to rise. These impacts are In this section, we discuss climate change increases the likelihood of heat global and may exacerbate problems change impacts from GHG emissions, waves, which are associated with outside the U.S. that raise humanitarian, both on public health and public increased deaths and illnesses. While trade, and national security issues for welfare. We also present information climate change also increases the the U.S. likelihood of reductions in cold-related about GHG emissions from fossil fuel- 3. New Scientific Assessments and mortality, evidence indicates that the fired EGUs and describe the utility Observations increases in heat mortality will be larger power sector and its changing structure. than the decreases in cold mortality in Since the administrative record We then summarize the statutory and the United States. Compared to a future concerning the Endangerment Finding regulatory background relevant to this without climate change, climate change closed following the EPA’s 2010 final rulemaking. In addition, we is expected to increase ozone pollution Reconsideration Denial, the climate has provide background information on the over broad areas of the U.S., especially continued to change, with new records EPA’s January 8, 2014 proposed carbon on the highest ozone days and in the being set for a number of climate pollution standards for newly largest metropolitan areas with the indicators such as global average surface constructed fossil fuel-fired EGUs, the worst ozone problems, and thereby temperatures, Arctic sea ice retreat, CO2 June 18, 2014 proposed carbon increase the risk of morbidity and concentrations, and sea level rise. pollution standards for modified and mortality. Climate change is also Additionally, a number of major reconstructed EGUs, and other actions expected to cause more intense scientific assessments have been associated with this final rulemaking. hurricanes and more frequent and released that improve understanding of We close this section with a general intense storms and heavy precipitation, the climate system and strengthen the discussion of comments and stakeholder with impacts on other areas of public case that GHGs endanger public health input that the EPA received prior to health, such as the potential for and welfare both for current and future issuing this final rulemaking. increased deaths, injuries, infectious generations. These assessments, from A. Climate Change Impacts From GHG and waterborne diseases, and stress- the Intergovernmental Panel on Climate Emissions related disorders. Children, the elderly, Change (IPCC), the U.S. Global Change and the poor are among the most Research Program (USGCRP), and the According to the National Research vulnerable to these climate-related National Research Council (NRC), Council, ‘‘Emissions of CO2 from the health effects. include: IPCC’s 2012 Special Report on burning of fossil fuels have ushered in Managing the Risks of Extreme Events a new epoch where human activities 2. Public Welfare Impacts Detailed in and Disasters to Advance Climate will largely determine the evolution of the 2009 Endangerment Finding Change Adaptation (SREX) and the Earth’s climate. Because CO2 in the Climate change impacts touch nearly 2013–2014 Fifth Assessment Report atmosphere is long lived, it can every aspect of public welfare. Among (AR5), the USGCRP’s 2014 National effectively lock Earth and future the multiple threats caused by human Climate Assessment, Climate Change generations into a range of impacts, emissions of GHGs, climate changes are Impacts in the United States (NCA3), some of which could become very expected to place large areas of the and the NRC’s 2010 Ocean severe. Therefore, emission reduction country at serious risk of reduced water Acidification: A National Strategy to choices made today matter in supplies, increased water pollution, and Meet the Challenges of a Changing determining impacts experienced not increased occurrence of extreme events Ocean (Ocean Acidification), 2011 just over the next few decades, but in such as floods and droughts. Coastal Report on Climate Stabilization Targets: the coming centuries and millennia.’’ 18 areas are expected to face a multitude of Emissions, Concentrations, and Impacts In 2009, based on a large body of increased risks, particularly from rising over Decades to Millennia (Climate robust and compelling scientific sea level and increases in the severity of Stabilization Targets), 2011 National evidence, the EPA Administrator issued storms. These communities face storm Security Implications for U.S. Naval the Endangerment Finding under CAA and flood damage to property, or even Forces (National Security Implications), section 202(a)(1).19 In the Endangerment loss of land due to inundation, erosion, 2011 Understanding Earth’s Deep Past: Finding, the Administrator found that wetland submergence and habitat loss. Lessons for Our Climate Future the current, elevated concentrations of Impacts of climate change on public (Understanding Earth’s Deep Past), 2012 GHGs in the atmosphere—already at welfare also include threats to social Sea Level Rise for the Coasts of levels unprecedented in human and ecosystem services. Climate change California, Oregon, and Washington: history—may reasonably be anticipated is expected to result in an increase in Past, Present, and Future, 2012 Climate to endanger public health and welfare of peak electricity demand. Extreme and Social Stress: Implications for current and future generations in the weather from climate change threatens Security Analysis (Climate and Social United States. We summarize these energy, transportation, and water Stress), and 2013 Abrupt Impacts of adverse effects on public health and resource infrastructure. Climate change Climate Change (Abrupt Impacts) welfare briefly here. may also exacerbate ongoing assessments. environmental pressures in certain The EPA has carefully reviewed these 1. Public Health Impacts Detailed in the settlements, particularly in Alaskan recent assessments in keeping with the 2009 Endangerment Finding indigenous communities, and is very same approach outlined in Section III.A Climate change caused by human likely to fundamentally rearrange U.S. of the 2009 Endangerment Finding, emissions of GHGs threatens the health ecosystems over the 21st century. which was to rely primarily upon the of Americans in multiple ways. By Though some benefits may balance major assessments by the USGCRP, the adverse effects on agriculture and IPCC, and the NRC of the National 18 National Research Council, Climate forestry in the next few decades, the Academies to provide the technical and Stabilization Targets, p. 3. body of evidence points towards scientific information to inform the 19 ‘‘Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section increasing risks of net adverse impacts Administrator’s judgment regarding the 202(a) of the Clean Air Act,’’ 74 FR 66496 (Dec. 15, on U.S. food production, agriculture and question of whether GHGs endanger 2009) (‘‘Endangerment Finding’’). forest productivity as temperature public health and welfare. These
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assessments addressed the scientific temperatures and loss of Arctic sea ice permanent—at least on a human issues that the EPA was required to increases the risk of drowning for those timescale—changes not anticipated by examine, were comprehensive in their engaged in traditional hunting and climate models tuned to modern coverage of the GHG and climate change fishing. conditions may occur.’’ The NRC issues, and underwent rigorous and The NCA3 concludes that children’s Abrupt Impacts report analyzed abrupt exacting peer review by the expert unique physiology and developing climate change in the physical climate community, as well as rigorous levels of bodies contribute to making them system and abrupt impacts of ongoing U.S. government review. particularly vulnerable to climate changes that, when thresholds are The findings of the recent scientific change. Impacts on children are crossed, can cause abrupt impacts for assessments confirm and strengthen the expected from heat waves, air pollution, society and ecosystems. The report conclusion that GHGs endanger public infectious and waterborne illnesses, and considered destabilization of the West health, now and in the future. The mental health effects resulting from Antarctic Ice Sheet (which could cause NCA3 indicates that human health in extreme weather events. The IPCC AR5 3–4 m of potential sea level rise) as an the United States will be impacted by indicates that children are among those abrupt climate impact with unknown ‘‘increased extreme weather events, especially susceptible to most allergic but probably low probability of wildfire, decreased air quality, threats to diseases, as well as health effects occurring this century. The report mental health, and illnesses transmitted associated with heat waves, storms, and categorized a decrease in ocean oxygen by food, water, and disease-carriers such floods. The IPCC finds that additional content (with attendant threats to as mosquitoes and ticks.’’ The most health concerns may arise in low- aerobic marine life); increase in recent assessments now have greater income households, especially those intensity, frequency, and duration of confidence that climate change will with children, if climate change reduces heat waves; and increase in frequency influence production of pollen that food availability and increases prices, and intensity of extreme precipitation exacerbates asthma and other allergic leading to food insecurity within events (droughts, floods, hurricanes, respiratory diseases such as allergic households. and major storms) as climate impacts rhinitis, as well as effects on Both the NCA3 and IPCC AR5 with moderate risk of an abrupt change conjunctivitis and dermatitis. Both the conclude that climate change will within this century. The NRC Abrupt NCA3 and the IPCC AR5 found that increase health risks facing the elderly. Impacts report also analyzed the threat increasing temperature has lengthened Older people are at much higher risk of of rapid state changes in ecosystems and the allergenic pollen season for mortality during extreme heat events. species extinctions as examples of ragweed, and that increased CO2 by Pre-existing health conditions also make irreversible impacts that are expected to itself can elevate production of plant- older adults susceptible to cardiac and be exacerbated by climate change. based allergens. respiratory impacts of air pollution and Species at most risk include those The NCA3 also finds that climate to more severe consequences from whose migration potential is limited, change, in addition to chronic stresses infectious and waterborne diseases. whether because they live on such as extreme poverty, is negatively Limited mobility among older adults mountaintops or fragmented habitats affecting indigenous peoples’ health in can also increase health risks associated with barriers to movement, or because the United States through impacts such with extreme weather and floods. climatic conditions are changing more as reduced access to traditional foods, The new assessments also confirm rapidly than the species can move or decreased water quality, and increasing and strengthen the conclusion that adapt. While the NRC determined that exposure to health and safety hazards. GHGs endanger public welfare, and it is not presently possible to place exact The IPCC AR5 finds that climate emphasize the urgency of reducing GHG probabilities on the added contribution change-induced warming in the Arctic emissions due to their projections that of climate change to extinction, they did and resultant changes in environment show GHG concentrations climbing to (e.g., permafrost thaw, effects on find that there was substantial risk that ever-increasing levels in the absence of impacts from climate change could, traditional food sources) have mitigation. The NRC assessment, significant impacts, observed now and within a few decades, drop the Understanding Earth’s Deep Past, populations in many species below projected, on the health and well-being projected that, without a reduction in of Arctic residents, especially sustainable levels, thereby committing emissions, CO2 concentrations by the the species to extinction. Species within indigenous peoples. Small, remote, end of the century would increase to predominantly-indigenous communities tropical and subtropical rainforests such levels that the Earth has not experienced as the Amazon and species living in are especially vulnerable given their 21 for more than 30 million years. In fact, coral reef ecosystems were identified by ‘‘strong dependence on the environment that assessment stated that ‘‘the for food, culture, and way of life; their the NRC as being particularly vulnerable magnitude and rate of the present to extinction over the next 30 to 80 political and economic marginalization; greenhouse gas increase place the existing social, health, and poverty years, as were species in high latitude climate system in what could be one of and high elevation regions. Moreover, disparities; as well as their frequent the most severe increases in radiative close proximity to exposed locations due to the time lags inherent in the forcing of the global climate system in Earth’s climate, the NRC Climate along ocean, lake, or river Earth history.’’ 22 Because of these shorelines.’’ 20 In addition, increasing Stabilization Targets assessment notes unprecedented changes, several that the full warming from any given assessments state that we may be 20 concentration of CO reached will not IPCC, 2014: Climate Change 2014: Impacts, approaching critical, poorly understood 2 Adaptation, and Vulnerability. Part B: Regional be fully realized for several centuries, thresholds. As stated in the assessment, Aspects. Contribution of Working Group II to the underscoring that emission activities Fifth Assessment Report of the Intergovernmental ‘‘As Earth continues to warm, it may be today carry with them climate Panel on Climate Change [Barros, V.R., C.B. Field, approaching a critical climate threshold commitments far into the future. D.J. Dokken, M.D. Mastrandrea, K.J. Mach, T.E. beyond which rapid and potentially Bilir, M. Chatterjee, K.L. Ebi, Y.O. Estrada, R.C. Future temperature changes will Genova, B. Girma, E.S. Kissel, A.N. Levy, S. MacCracken, P.R. Mastrandrea, and L.L. White 21 National Research Council, Understanding depend on what emission path the (eds.)]. Cambridge University Press, Cambridge, p. Earth’s Deep Past, p. 1. world follows. In its high emission 1581. 22 Id., p. 138. scenario, the IPCC AR5 projects that
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average global temperatures by the end assessment projects a global sea level impacts (through erosion and of the century will likely be 2.6 degrees rise of 0.5 to 1.4 meters (1.6 to 4.6 feet) inundation) are so severe that some Celsius (°C) to 4.8 °C (4.7 to 8.6 degrees by 2100, the NRC National Security communities are already relocating from Fahrenheit (°F)) warmer than today. Implications assessment suggests that historical homelands to which their Temperatures on land and in northern ‘‘the Department of the Navy should traditions and cultural identities are latitudes will likely warm even faster expect roughly 0.4 to 2 meters (1.3 to 6.6 tied.’’ 25 The IPCC AR5 notes, ‘‘Climate- than the global average. However, feet) global average sea-level rise by related hazards exacerbate other 23 according to the NCA3, significant 2100,’’ and the NRC Climate stressors, often with negative outcomes reductions in emissions would lead to Stabilization Targets assessment states ° for livelihoods, especially for people noticeably less future warming beyond that an increase of 3 C will lead to a living in poverty (high confidence). mid-century, and therefore less impact sea level rise of 0.5 to 1 meter (1.6 to Climate-related hazards affect poor to public health and welfare. 3.3 feet) by 2100. These assessments While rainfall may only see small continue to recognize that there is people’s lives directly through impacts globally and annually averaged changes, uncertainty inherent in accounting for on livelihoods, reductions in crop there are expected to be substantial ice sheet processes. Additionally, local yields, or destruction of homes and shifts in where and when that sea level rise can differ from the global indirectly through, for example, precipitation falls. According to the total depending on various factors. The increased food prices and food NCA3, regions closer to the poles will east coast of the U.S. in particular is insecurity.’’ 26 see more precipitation, while the dry expected to see higher rates of sea level CO2 in particular has unique impacts subtropics are expected to expand rise than the global average. For on ocean ecosystems. The NRC Climate (colloquially, this has been summarized comparison, the NCA3 states that ‘‘five Stabilization Targets assessment found as wet areas getting wetter and dry million Americans and hundreds of that coral bleaching will increase due regions getting drier). In particular, the billions of dollars of property are both to warming and ocean NCA3 notes that the western U.S., and located in areas that are less than four acidification. Ocean surface waters have especially the Southwest, is expected to feet above the local high-tide level,’’ and already become 30 percent more acidic become drier. This projection is the NCA3 finds that ‘‘[c]oastal over the past 250 years due to consistent with the recent observed infrastructure, including roads, rail from the atmosphere. drought trend in the West. At the time lines, energy infrastructure, airports, absorption of CO2 of publication of the NCA, even before port facilities, and military bases, are According to the NCA3, this the last 2 years of extreme drought in increasingly at risk from sea level rise acidification will reduce the ability of California, tree ring data was already and damaging storm surges.’’ 24 Also, organisms such as corals, krill, oysters, indicating that the region might be because of the inertia of the oceans, sea clams, and crabs to survive, grow, and experiencing its driest period in 800 level rise will continue for centuries reproduce. The NRC Understanding years. Similarly, the NCA3 projects that after GHG concentrations have Earth’s Deep Past assessment notes that heavy downpours are expected to stabilized (though more slowly than it four of the five major coral reef crises of increase in many regions, with would have otherwise). Additionally, the past 500 million years were caused precipitation events in general there is a threshold temperature above by acidification and warming that becoming less frequent but more which the Greenland ice sheet will be followed GHG increases of similar intense. This trend has already been committed to inevitable melting. magnitude to the emissions increases observed in regions such as the According to the NCA, some recent expected over the next hundred years. Midwest, Northeast, and upper Great research has suggested that even present The NRC Abrupt Impacts assessment Plains. Meanwhile, the NRC Climate day CO2 levels could be sufficient to specifically highlighted similarities Stabilization Targets assessment found exceed that threshold. between the projections for future that the area burned by wildfire is In general, climate change impacts are acidification and warming and the expected to grow by 2 to 4 times for 1 expected to be unevenly distributed extinction at the end of the Permian °C (1.8 °F) of warming. For 3 °C of across different regions of the United which resulted in the loss of an warming, the assessment found that 9 States and have a greater impact on estimated 90 percent of known species. out of 10 summers would be warmer certain populations, such as indigenous Similarly, the NRC Ocean Acidification than all but the 5 percent of warmest peoples and the poor. The NCA3 finds summers today, leading to increased that climate change impacts such as the assessment finds that ‘‘[t]he chemistry frequency, duration, and intensity of rapid pace of temperature rise, coastal of the ocean is changing at an heat waves. Extrapolations by the NCA erosion and inundation related to sea unprecedented rate and magnitude due also indicate that Arctic sea ice in level rise and storms, ice and snow to anthropogenic CO2 emissions; the summer may essentially disappear by melt, and permafrost thaw are affecting rate of change exceeds any known to mid-century. Retreating snow and ice, indigenous people in the U.S. have occurred for at least the past and emissions of CO2 and methane Particularly in Alaska, critical released from thawing permafrost, will infrastructure and traditional 25 Melillo, Jerry M., Terese (T.C.) Richmond, and also amplify future warming. livelihoods are threatened by climate Gary W. Yohe, Eds., 2014: Climate Change Impacts Since the 2009 Endangerment in the United States: The Third National Climate change and, ‘‘[i]n parts of Alaska, Assessment. U.S. Global Change Research Program, Finding, the USGCRP NCA3, and Louisiana, the Pacific Islands, and other multiple NRC assessments have p. 17. coastal locations, climate change 26 IPCC, 2014: Climate Change 2014: Impacts, projected future rates of sea level rise Adaptation, and Vulnerability. Part A: Global and that are 40 percent larger to more than 23 NRC, 2011: National Security Implications of Sectoral Aspects. Contribution of Working Group II twice as large as the previous estimates Climate Change for U.S. Naval Forces. The National to the Fifth Assessment Report of the from the 2007 IPCC 4th Assessment Academies Press, p. 28. Intergovernmental Panel on Climate Change [Field, Report due in part to improved 24 Melillo, Jerry M., Terese (T.C.) Richmond, and C.B., V.R. Barros, D.J. Dokken, K.J. Mach, M.D. Gary W. Yohe, Eds., 2014: Climate Change Impacts Mastrandrea, T.E. Bilir, M. Chatterjee, K.L. Ebi, Y.O. understanding of the future rate of melt in the United States: The Third National Climate Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N. of the Antarctic and Greenland Ice Assessment. U.S. Global Change Research Program, Levy, S. MacCracken, P.R. Mastrandrea, and L.L. sheets. The NRC Sea Level Rise p. 9. White (eds.)]. Cambridge University Press, p. 796.
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hundreds of thousands of years.’’ 27 The ice melt is sufficient to cause global sea These assessments and observed assessment notes that the full range of levels to rise 1 mm. Annual mean Arctic changes make it clear that reducing consequences is still unknown, but the sea ice has been declining at 3.5 to 4.1 emissions of GHGs across the globe is risks ‘‘threaten coral reefs, fisheries, percent per decade, and Northern necessary in order to avoid the worst protected species, and other natural Hemisphere snow cover extent has impacts of climate change, and resources of value to society.’’ 28 decreased at about 1.6 percent per underscore the urgency of reducing Events outside the United States, as decade for March and 11.7 percent per emissions now. The NRC Committee on also pointed out in the 2009 decade for June. Permafrost America’s Climate Choices listed a Endangerment Finding, will also have temperatures have increased in most number of reasons ‘‘why it is imprudent relevant consequences. The NRC regions since the 1980s, by up to 3 °C to delay actions that at least begin the Climate and Social Stress assessment (5.4 °F) in parts of Northern Alaska. process of substantially reducing concluded that it is prudent to expect Winter storm frequency and intensity emissions.’’ 33 For example: that some climate events ‘‘will produce have both increased in the Northern • The faster emissions are reduced, consequences that exceed the capacity Hemisphere. The NCA3 states that the the lower the risks posed by climate of the affected societies or global increases in the severity or frequency of change. Delays in reducing emissions systems to manage and that have global some types of extreme weather and could commit the planet to a wide range security implications serious enough to climate events in recent decades can of adverse impacts, especially if the compel international response.’’ The affect energy production and delivery, sensitivity of the climate to greenhouse NRC National Security Implications causing supply disruptions, and gases is on the higher end of the assessment recommends preparing for compromise other essential estimated range. increased needs for humanitarian aid; infrastructure such as water and • Waiting for unacceptable impacts to responding to the effects of climate transportation systems. occur before taking action is imprudent change in geopolitical hotspots, In addition to the changes because the effects of greenhouse gas including possible mass migrations; and documented in the assessment emissions do not fully manifest addressing changing security needs in literature, there have been other climate themselves for decades and, once the Arctic as sea ice retreats. milestones of note. In 2009, the year of manifest, many of these changes will In addition to future impacts, the the Endangerment Finding, the average persist for hundreds or even thousands NCA3 emphasizes that climate change concentration of CO as measured on of years. 2 • driven by human emissions of GHGs is top of Mauna Loa was 387 parts per In the committee’s judgment, the already happening now and it is million, far above preindustrial risks associated with doing business as happening in the United States. concentrations of about 280 parts per usual are a much greater concern than According to the IPCC AR5 and the million.29 The average concentration in the risks associated with engaging in NCA3, there are a number of climate- 2013, the last full year before this rule strong response efforts. related changes that have been observed was proposed, was 396 parts per 4. Observed and Projected U.S. Regional recently, and these changes are million. The average concentration in Changes projected to accelerate in the future. The 2014 was 399 parts per million. And the ° ° planet warmed about 0.85 C (1.5 F) monthly concentration in April of 2014 The NCA3 assessed the climate from 1880 to 2012. It is extremely likely was 401 parts per million, the first time impacts in eight regions of the United (>95 percent probability) that human a monthly average has exceeded 400 States, noting that changes in physical influence was the dominant cause of the parts per million since record keeping climate parameters such as observed warming since the mid-20th began at Mauna Loa in 1958, and for at temperatures, precipitation, and sea ice century, and likely (>66 percent least the past 800,000 years based on ice retreat were already having impacts on probability) that human influence has core records.30 Arctic sea ice has forests, water supplies, ecosystems, more than doubled the probability of continued to decline, with September of flooding, heat waves, and air quality. occurrence of heat waves in some 2012 marking a new record low in terms Moreover, the NCA3 found that future locations. In the Northern Hemisphere, of Arctic sea ice extent, 40 percent warming is projected to be much larger the last 30 years were likely the warmest below the 1979–2000 median. Sea level than recent observed variations in 30-year period of the last 1400 years. has continued to rise at a rate of 3.2 mm temperature, with precipitation likely to U.S. average temperatures have per year (1.3 inches/decade) since increase in the northern states, decrease ° similarly increased by 1.3 to 1.9 F since satellite observations started in 1993, in the southern states, and with the 1895, with most of that increase more than twice the average rate of rise heaviest precipitation events projected occurring since 1970. Global sea levels in the 20th century prior to 1993.31 And to increase everywhere. In the Northeast, temperatures rose 0.19 m (7.5 inches) from 1901 to 2014 was the warmest year globally in increased almost 2 °F from 1895 to 2010. Contributing to this rise was the the modern global surface temperature 2011, precipitation increased by about 5 warming of the oceans and melting of record, going back to 1880; this now inches (10 percent), and sea level rise of land ice. It is likely that 275 gigatons per means 19 of the 20 warmest years have about a foot has led to an increase in year of ice have melted from land occurred in the past 20 years, and coastal flooding. The 70 percent glaciers (not including ice sheets) since except for 1998, the ten warmest years increase in the amount of rainfall falling 1993, and that the rate of loss of ice on record have occurred since 2002.32 in the 1 percent of the most intense from the Greenland and Antarctic ice The first months of 2015 have also been events is a larger increase in extreme sheets has increased substantially in some of the warmest on record. recent years, to 215 gigatons per year precipitation than experienced in any and 147 gigatons per year respectively, other U.S. region. 29 ftp://aftp.cmdl.noaa.gov/products/trends/co2/ In the future, if emissions continue since 2002. For context, 360 gigatons of co2_annmean_mlo.txt. 30 increasing, the Northeast is expected to http://www.esrl.noaa.gov/gmd/ccgg/trends/. ° 27 NRC, 2010: Ocean Acidification: A National 31 Blunden, J., and D. S. Arndt, Eds., 2014: State experience 4.5 to 10 F of warming by Strategy to Meet the Challenges of a Changing of the Climate in 2013. Bull. Amer. Meteor. Soc., Ocean. The National Academies Press, p. 5. 95 (7), S1–S238. 33 NRC, 2011: America’s Climate Choices, The 28 Id. 32 http://www.ncdc.noaa.gov/sotc/global/2014/13. National Academies Press.
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the 2080s. This will lead to more heat interior states of the region is larger than States. Annual temperatures increased waves, coastal and river flooding, and coastal regions by 1 °F to 2 °F. by about 3 °F in the past 60 years. intense precipitation events. The Projections further suggest that there Warming in the winter has been even southern portion of the region is will be fewer tropical storms globally, greater, rising by an average of 6 °F. projected to see 60 additional days per but that they will be more intense, with Arctic sea ice is thinning and shrinking year above 90 °F by mid-century. Sea more Category 4 and 5 storms. The NCA in area, with the summer minimum ice levels in the Northeast are expected to identified New Orleans, Miami, Tampa, extent now covering only half the area increase faster than the global average Charleston, and Virginia Beach as being it did when satellite records began in because of subsidence, and changing specific cities that are at risk due to sea 1979. Glaciers in Alaska are melting at ocean currents may further increase the level rise, with homes and infrastructure some of the fastest rates on Earth. rate of sea level rise. Specific increasingly prone to flooding. Permafrost soils are also warming and vulnerabilities highlighted by the NCA Additional impacts of sea level rise are beginning to thaw. Drier conditions include large urban populations expected for coastal highways, have contributed to more large wildfires particularly vulnerable to climate- wetlands, fresh water supplies, and in the last 10 years than in any previous related heat waves and poor air quality energy infrastructure. decade since the 1940s, when episodes, prevalence of climate In the Northwest, temperatures recordkeeping began. Climate change sensitive vector-borne diseases like increased by about 1.3 °F between 1895 impacts are harming the health, safety, Lyme and West Nile Virus, usage of and 2011. A small average increase in and livelihoods of Native Alaskan combined sewer systems that may lead precipitation was observed over this communities. to untreated water being released into time period. However, warming By the end of this century, continued local water bodies after climate-related temperatures have caused increased increases in GHG emissions are heavy precipitation events, and 1.6 rainfall relative to snowfall, which has expected to increase temperatures by 10 million people living within the 100- altered water availability from to 12 °F in the northernmost parts of year coastal flood zone who are snowpack across parts of the region. Alaska, by 8 to 10 °F in the interior, and expected to experience more frequent Snowpack in the Northwest is an by 6 to 8 °F across the rest of the state. floods due to sea level rise and tropical- important freshwater source for the These increases will exacerbate ongoing storm induced storm-surge. The NCA region. More precipitation falling as rain arctic sea ice loss, glacial melt, also highlighted infrastructure instead of snow has reduced the permafrost thaw and increased wildfire, vulnerable to inundation in coastal snowpack, and warmer springs have and threaten humans, ecosystems, and metropolitan areas, potential corresponded to earlier snowpack infrastructure. Precipitation is expected agricultural impacts from increased rain melting and reduced streamflows during to increase to varying degrees across the in the spring delaying planting or summer months. Drier conditions have state. However, warmer air temperatures damaging crops or increased heat in the increased the extent of wildfires in the and a longer growing season are summer leading to decreased yields and region. expected to result in drier conditions. increased water demand, and shifts in Average annual temperatures are Native Alaskans are expected to ecosystems leading to declines in iconic projected to increase by 3.3 °F to 9.7 °F experience declines in economically, species in some regions, such as cod by the end of the century (depending on nutritionally, and culturally important and lobster south of Cape Cod. future global GHG emissions), with the wildlife and plant species. Health In the Southeast, average annual greatest warming expected during the threats will also increase, including loss temperature during the last century summer. Continued increases in global of clean water, saltwater intrusion, cycled between warm and cool periods. GHG emissions are projected to result in sewage contamination from thawing A warm peak occurred during the 1930s up to a 30 percent decrease in summer permafrost, and northward extension of and 1940s, followed by a cool period, precipitation. Earlier snowpack melt diseases. Wildfires will increasingly and temperatures then increased again and lower summer stream flows are pose threats to human health as a result from 1970 to the present by an average expected by the end of the century and of smoke and direct contact. Areas of 2 °F. There have been increasing will affect drinking water supplies, underlain by ice-rich permafrost across numbers of days above 95 °F and nights agriculture, ecosystems, and the state are likely to experience ground above 75 °F, and decreasing numbers of hydropower production. Warmer waters subsidence and extensive damage to extremely cold days since 1970. Daily are expected to increase disease and infrastructure as the permafrost thaws. and five-day rainfall intensities have mortality in important fish species, Important ecosystems will continue to also increased, and summers have been including Chinook and sockeye salmon. be affected. Surface waters and wetlands either increasingly dry or extremely wet. Ocean acidification also threatens that are drying provide breeding habitat Louisiana has already lost 1,880 square species such as oysters, with the for millions of waterfowl and shorebirds miles of land in the last 80 years due to Northwest coastal waters already being that winter in the lower 48 states. sea level rise and other contributing some of the most acidified worldwide Warmer ocean temperatures, factors. due to coastal upwelling and other local acidification, and declining sea ice will The Southeast is exceptionally factors. Forest pests are expected to contribute to changes in the location vulnerable to sea level rise, extreme heat spread and wildfires to burn larger and availability of commercially and events, hurricanes, and decreased water areas. Other high-elevation ecosystems culturally important marine fish. availability. Major consequences of are projected to be lost because they can In the Southwest, temperatures are further warming include significant no longer survive the climatic now about 2 °F higher than the past increases in the number of hot days (95 conditions. Low lying coastal areas, century, and are already the warmest °F or above) and decreases in freezing including the cities of Seattle and that region has experienced in at least events, as well as exacerbated ground- Olympia, will experience heightened 600 years. The NCA notes that there is level ozone in urban areas. Although risks of sea level rise, erosion, seawater evidence that climate change-induced projected warming for some parts of the inundation and damage to infrastructure warming on top of recent drought has region by the year 2100 is generally and coastal ecosystems. influenced tree mortality, wildfire smaller than for other regions of the In Alaska, temperatures have changed frequency and area, and forest insect United States, projected warming for faster than anywhere else in the United outbreaks. Sea levels have risen about 7
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or 8 inches in this region, contributing heat waves and degraded air and water freshwater supplies will be adversely to inundation of Highway 101 and back quality, negative impacts on affected as air temperature rises. up of seawater into sewage systems in transportation and other infrastructure Warmer oceans are leading to the San Francisco area. associated with extreme rainfall events increased coral bleaching events and Projections indicate that the and flooding, and risks to the Great disease outbreaks in coral reefs, as well Southwest will warm an additional 5.5 Lakes including shifts in invasive as changed distribution patterns of tuna to 9.5 °F over the next century if species, increases in harmful algal fisheries. Ocean acidification will emissions continue to increase. Winter blooms, and declining beach health. reduce coral growth and health. snowpack in the Southwest is projected High temperatures (more than 100 °F Warming and acidification, combined to decline (consistent with the record in the Southern Plains and more than with existing stresses, will strongly lows from this past winter), reducing 95 °F in the Northern Plains) are affect coral-reef fish communities. For the reliability of surface water supplies projected to occur much more Hawaii and the Pacific islands, future for cities, agriculture, cooling for power frequently by mid-century. Increases in sea surface temperatures are projected to plants, and ecosystems. Sea level rise extreme heat will increase heat stress for increase 2.3 °F by 2055 and 4.7 °F by along the California coast will worsen residents, energy demand for air 2090 under a scenario that assumes coastal erosion, increase flooding risk conditioning, and water losses. North continued increases in emissions. Ocean for coastal highways, bridges, and low- Dakota’s increase in annual acidification is also taking place in the lying airports, pose a threat to temperatures over the past 130 years is region, which adds to ecosystem stress groundwater supplies in coastal cities the fastest in the contiguous U.S., from increasing temperatures. Ocean such as Los Angeles, and increase mainly driven by warming winters. acidity has increased by about 30 vulnerability to floods for hundreds of Specific vulnerabilities highlighted by percent since the pre-industrial era and thousands of residents in coastal areas. the NCA include increased demand for is projected to further increase by 37 Climate change will also have impacts water and energy, changes to crop- percent to 50 percent from present on the high-value specialty crops grown growth cycles and agricultural practices, levels by 2100. in the region as a drier climate will and negative impacts on local plant and The NCA also discussed impacts that increase demands for irrigation, more animal species from habitat occur along the coasts and in the oceans frequent heat waves will reduce yields, fragmentation, wildfires, and changes in adjacent to many regions, and noted that and decreased winter chills may impair the timing of flowering or pest patterns. other impacts occur across regions and fruit and nut production for trees in Communities that are already the most landscapes in ways that do not follow California. Increased drought, higher vulnerable to weather and climate political boundaries. temperatures, and bark beetle outbreaks extremes will be stressed even further are likely to contribute to continued by more frequent extreme events B. GHG Emissions From Fossil Fuel- increases in wildfires. The highly occurring within an already highly Fired EGUs urbanized population of the Southwest variable climate system. Fossil fuel-fired EGUs are by far the is vulnerable to heat waves and water In Hawaii, other Pacific islands, and largest emitters of GHGs among supply disruptions, which can be the Caribbean, rising air and ocean stationary sources in the U.S., primarily exacerbated in cases where high use of temperatures, shifting rainfall patterns, in the form of CO2. Among fossil fuel- air conditioning triggers energy system changing frequencies and intensities of fired EGUs, coal-fired units are by far failures. storms and drought, decreasing the largest emitters. This section The rate of warming in the Midwest baseflow in streams, rising sea levels, describes the amounts of these has markedly accelerated over the past and changing ocean chemistry will emissions and places these amounts in few decades. Temperatures rose by more affect ecosystems on land and in the the context of the U.S. Inventory of ° than 1.5 F from 1900 to 2010, but oceans, as well as local communities, Greenhouse Gas Emissions and Sinks 34 between 1980 and 2010, the rate of livelihoods, and cultures. Low islands (the U.S. GHG Inventory). warming was three times faster than are particularly at risk. The EPA implements a separate from 1900 through 2010. Precipitation Rising sea levels, coupled with high program under 40 CFR part 98 called generally increased over the last water levels caused by tropical and the Greenhouse Gas Reporting century, with much of the increase extra-tropical storms, will incrementally Program 35 (GHGRP) that requires driven by intensification of the heaviest increase coastal flooding and erosion, emitting facilities that emit over certain rainfalls. Several types of extreme damaging coastal ecosystems, threshold amounts of GHGs to report weather events in the Midwest (e.g., infrastructure, and agriculture, and their emissions to the EPA annually. heat waves and flooding) have already negatively affecting tourism. Ocean Using data from the GHGRP, this section increased in frequency and/or intensity temperatures in the Pacific region also places emissions from fossil fuel- due to climate change. exhibit strong year-to-year and decadal fired EGUs in the context of the total In the future, if emissions continue fluctuations, but since the 1950s, they emissions reported to the GHGRP from increasing, the Midwest is expected to have exhibited a warming trend, with facilities in the other largest-emitting experience 5.6 to 8.5 °F of warming by temperatures from the surface to a depth ° industries. the 2080s, leading to more heat waves. of 660 feet rising by as much as 3.6 F. The EPA prepares the official U.S. Though projections of changes in total As a result of current sea level rise, the GHG Inventory to comply with precipitation vary across the regions, coastline of Puerto Rico around Rinco´n commitments under the United Nations more precipitation is expected to fall in is being eroded at a rate of 3.3 feet per Framework Convention on Climate the form of heavy downpours across the year. Freshwater supplies are already entire region, leading to an increase in constrained and will become more 34 ‘‘Inventory of U.S. Greenhouse Gas Emissions flooding. Specific vulnerabilities limited on many islands. Saltwater and Sinks: 1990–2013’’, Report EPA 430–R–15–004, highlighted by the NCA include long- intrusion associated with sea level rise United States Environmental Protection Agency, term decreases in agricultural will reduce the quantity and quality of April 15, 2015. http://epa.gov/climatechange/ ghgemissions/usinventoryreport.html. productivity, changes in the freshwater in coastal aquifers, especially 35 U.S. EPA Greenhouse Gas Reporting Program composition of the region’s forests, on low islands. In areas where Dataset, see http://www.epa.gov/ghgreporting/ increased public health threats from precipitation does not increase, ghgdata/reportingdatasets.html.
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Change (UNFCCC). This inventory, provides the information in Table 3 GHGs, including CO2 emissions, for the which includes recent trends, is below, which presents total U.S. years 1990, 2005 and 2013. organized by industrial sector. It anthropogenic emissions and sinks 36 of
TABLE 3—U.S. GHG EMISSIONS AND SINKS BY SECTOR (MILLION METRIC TONS CARBON DIOXIDE EQUIVALENT (MMT 37 38 CO2e))
Sector 1990 2005 2013
Energy39 ...... 5,290.5 6,273.6 5,636.6 Industrial Processes and Product Use ...... 342.1 367.4 359.1 Agriculture ...... 448.7 494.5 515.7 Land Use, Land-Use Change and Forestry ...... 13.8 25.5 23.3 Waste ...... 206.0 189.2 138.3 Total Emissions ...... 6,301.1 7,350.2 6,673.0 Land Use, Land-Use Change and Forestry (Sinks) ...... (775.8) (911.9) (881.7) Net Emissions (Sources and Sinks) ...... 5,525.2 6,438.3 5,791.2
40 Total fossil energy-related CO2 GHG emissions. In 2013, fossil fuel 38.3 percent of all energy-related CO2 emissions (including both stationary combustion by the utility power emissions.41 Table 4 below presents and mobile sources) are the largest sector—entities that burn fossil fuel and total CO2 emissions from fossil fuel- contributor to total U.S. GHG emissions, whose primary business is the fired EGUs, for years 1990, 2005, and representing 77.3 percent of total 2013 generation of electricity—accounted for 2013.
TABLE 4—U.S. GHG EMISSIONS FROM GENERATION OF ELECTRICITY FROM COMBUSTION OF FOSSIL FUELS (MMT 42 CO2)
GHG emissions 1990 2005 2013
Total CO2 from fossil fuel-fired EGUs ...... 1,820.8 2,400.9 2,039.8 —from coal ...... 1,547.6 1,983.8 1,575.0 —from natural gas ...... 175.3 318.8 441.9 —from petroleum ...... 97.5 97.9 22.4
In addition to preparing the official collected by the GHGRP from large Table 4 and Table 5, respectively, CO2 U.S. GHG Inventory to present stationary sources in the industrial emissions from fossil fuel-fired EGUs comprehensive total U.S. GHG sector show that the utility power sector are nearly three times as large as the emissions and comply with emits far greater CO2 emissions than any total reported GHG emissions from the commitments under the UNFCCC, the other industrial sector. Table 5 below next ten largest emitting industrial EPA collects detailed GHG emissions presents total GHG emissions in 2013 sectors in the GHGRP database data from the largest emitting facilities for the largest emitting industrial sectors combined. in the U.S. through its GHGRP. Data as reported to the GHGRP. As shown in
43 TABLE 5—DIRECT GHG EMISSIONS REPORTED TO GHGRP BY LARGEST EMITTING INDUSTRIAL SECTORS (MMT CO2e)
Industrial sector 2013
Fossil Fuel-Fired EGUs ...... 2,039.8 Petroleum Refineries ...... 176.7 Onshore Oil & Gas Production ...... 94.8 Municipal Solid Waste Landfills ...... 93.0 Iron & Steel Production ...... 84.2 Cement Production ...... 62.8 Natural Gas Processing Plants ...... 59.0 Petrochemical Production ...... 52.7 Hydrogen Production ...... 41.9 Underground Coal Mines ...... 39.8 Food Processing Facilities ...... 30.8
36 Sinks are physical units or processes that store 39 The energy sector includes all greenhouse gases Protection Agency, April 15, 2015. http://epa.gov/ GHGs, such as forests or underground or deep sea resulting from stationary and mobile energy climatechange/ghgemissions/usinventory reservoirs of CO2. activities including fuel combustion and fugitive report.html. 37 From Table ES–4 of ‘‘Inventory of U.S. fuel emissions. 42 From Table 3–5 ‘‘Inventory of U.S. Greenhouse 40 Greenhouse Gas Emissions and Sinks: 1990–2013’’, From Table ES–2 ‘‘Inventory of U.S. Gas Emissions and Sinks: 1990–2013’’, Report EPA Greenhouse Gas Emissions and Sinks: 1990–2013’’, Report EPA 430–R–15–004, United States 430–R–15–004, United States Environmental Report EPA 430–R–15–004, United States Environmental Protection Agency, April 15, 2015. Environmental Protection Agency, April 15, 2015. Protection Agency, April 15 2015. http://epa.gov/ http://epa.gov/climatechange/ghgemissions/us http://epa.gov/climatechange/ghgemissions/ climatechange/ghgemissions/usinventory inventoryreport.html. usinventoryreport.html. report.html. 38 1 metric ton (tonne) is equivalent to 1,000 41 From Table 3–1 ‘‘Inventory of U.S. Greenhouse 43 U.S. EPA Greenhouse Gas Reporting Program kilograms (kg) and is equivalent to 1.1023 short tons Gas Emissions and Sinks: 1990–2013’’, Report EPA Dataset as of August 18, 2014. http://ghgdata.epa. or 2,204.62 pounds (lb). 430–R–15–004, United States Environmental gov/ghgp/main.do.
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It should be noted that the discussion 13 percent over that time period.48 space, helping to provide new answers above concerned all fossil fuel-fired Between 2000 and 2013, approximately to how to meet the electricity needs of EGUs. Steam generators emitted 1,627 90 percent of new power generation the nation. These new technologies can MMT CO2e and combustion turbines capacity built in the U.S. has come in enable the nation to answer not just 44 emitted 401 MMT CO2e in 2013. the form of natural gas or renewable questions as to how to reliably meet energy facilities.49 In 2015, the U.S. electricity demand, but also how to C. The Utility Power Sector Energy Information Administration meet electricity demand reliably and 1. Modern Electric System Trends (EIA) projected the need for 28.4 GW of cost-effectively55 with the lowest additional base load or intermediate possible emissions and the greatest The EPA includes a background load generation capacity through 2020, efficiency. discussion of the electricity system in with approximately 0.7 GW of new coal- Natural gas has a long history of the Clean Power Plan (CPP) rulemaking, fired capacity, 5.5 GW of new nuclear meeting electricity demand in the U.S. which is the companion rulemaking to capacity, and 14.2 GW of new NGCC with a rapidly growing role as domestic this rule that promulgates emission capacity already in development.50 supplies of natural gas have guidelines for states to use in regulating The change in the resource mix has dramatically increased. Natural gas net emissions of CO2 from existing fossil accelerated in recent years, but wind, generation increased by approximately fuel-fired EGUs. Readers are referred to solar, other renewables, and energy- 36 percent between 2004 and 2014.56 In that rulemaking. The following efficiency resources have been reliably 2014, natural gas accounted for discussion of electricity sector trends is participating in the electric sector for a approximately 27 percent of net of particular relevance for this number of years. This rapid generation.57 The EIA projects that this rulemaking. development of non-fossil fuel resources demand growth will continue, with its The electricity sector is undergoing a is occurring as much of the existing Annual Energy Outlook 2015 (AEO period of intense change. Fossil fuels— power generation fleet in the U.S. is 2015) reference case forecasting that such as coal, natural gas, and oil—have aging and in need of modernization and natural gas will produce 31 percent of historically provided a large percentage replacement.51 For example, the average U.S. electric generation in 2040.58 of electricity in the U.S., with smaller age of U.S. coal steam units in 2015 is Renewable sources of electric amounts being provided by other types 45 years.52 In its 2013 Report Card for generation also have a history of of generation, including nuclear and America’s Infrastructure, the American meeting electricity demand in the U.S. renewables such as wind, solar, and Society for Civil Engineers noted that and are expected to have an increasing hydroelectric power. Coal has ‘‘America relies on an aging electrical role going forward. A series of energy historically provided the largest grid and pipeline distribution systems, crises provided the impetus for percentage of fossil-fuel generation.45 In some of which originated in the renewable energy development in the recent years, the nation has seen a 1880s.’’ 53 While there has been an early 1970s. The OPEC oil embargo in sizeable increase in renewable increased investment in electric 1973 and oil crisis of 1979 caused oil generation such as wind and solar, as transmission infrastructure since 2005, price spikes, more frequent energy well as a shift from coal to natural gas.46 the report also found that ‘‘ongoing shortages, and significantly affected the In 2013, fossil fuels supplied 67 percent permitting issues, weather events, and national and global economy. In 1978, of U.S. electricity, but renewables made limited maintenance have contributed partly in response to fuel security up 38 percent of the new generation to an increasing number of failures and concerns, Congress passed the Public capacity (over 5 GW out of 13.5 GW).47 power interruptions.’’54 However, Utilities Regulatory Policies Act From 2007 to 2014, use of lower- and innovative technologies have (PURPA) which required local electric zero-carbon energy sources has grown, increasingly entered the electric energy utilities to buy power from qualifying while other major energy sources such facilities (QFs).59 QFs were either 60 as coal and oil have experienced 48 Bloomberg New Energy Finance and the cogeneration facilities or small declines. Renewable electricity Business Council for Sustainable Energy, 2015 generation, including from large hydro- Factbook: Sustainable Energy in America, at 16 55 Business Council for Sustainable Energy (2015), available at http://www.bcse.org/images/ Comments in Docket Id. No. EPA–HQ–OAR–2013– electric projects, grew from 8 percent to 2015%20Sustainable%20Energy%20in%20 0602 at 2 (Nov. 19, 2014). America%20Factbook.pdf. 56 U.S. Energy Information Administration (EIA), 44 These figures are based on data for EGUs in the 49 Energy Information Administration, Electricity: Electric Power Monthly: Table 1.1 Net Generation Acid Rain Program plus additional ones that report Form EIA–860 detailed data (Feb. 17, 2015), by Energy Source: Total (All Sectors), 2004– to the EPA under the Regional Greenhouse Gas available at http://www.eia.gov/electricity/data/ December 2014 (2015), available at http://www.eia. Initiative. eia860/. gov/electricity/monthly/epm_table_grapher.cfm?t= 50 _ _ 45 U.S. Energy Information Administration, EIA, Annual Energy Outlook for 2015 with epmt 1 1. ‘‘Table 7.2b Electricity Net Generation: Electric Projections to 2040, Final Release, available at 57 Id. Power Sector’’ data from April 2014 Monthly http://www.eia.gov/forecasts/AEO/pdf/0383(2015). 58 The AEO 2015 Reference case projection is a Energy Review, release data April 25, 2014, The AEO numbers include projects that are under business-as-usual trend estimate, given known available at http://www.eia.gov/totalenergy/data/ development and model-projected nuclear, coal, technology and technological and demographic monthly/pdf/sec7_6.pdf. and NGCC projects. trends. EIA explores the impacts of alternative 46 U.S. Energy Information Administration, 51 Quadrennial Energy Review, http://energy.gov/ assumptions in other cases with different ‘‘Table 7.2b Electricity Net Generation: Electric epsa/quadrennial-energy-review-qer. macroeconomic growth rates, world oil prices, and Power Sector’’ data from April 2014 Monthly 52 We calculated the average age of coal steam resource assumptions. U.S. Energy Information Energy Review, release data April 25, 2014, units based on the NEEDS inventory, and included Administration (EIA), Annual Energy Outlook 2015 available at http://www.eia.gov/totalenergy/data/ units with planned retirements in 2015–2016. See with Projections to 2040, at 24–25 (2015), available monthly/pdf/sec7_6.pdf. http://www.epa.gov/airmarkets/documents/ipm/ at http://www.eia.gov/forecasts/aeo/pdf/ _ 47 Based on Table 6.3 (New Utility Scale needs v514.xlsx. 0383(2015).pdf. Generating Units by Operating Company, Plant, 53 American Society for Civil Engineers, 2013 59 Casazza, J. and Delea, F., Understanding Month, and Year) of the U.S. Energy Information Report Card for America’s Infrastructure (2013), Electric Power Systems, IEEE Press, at 220–221 (2d Administration (EIA) Electric Power Monthly, data available at http://www.infrastructurereportcard. ed. 2010). for December 2013, for the following renewable org/energy/. 60 Cogeneration facilities utilize a single source of energy sources: Solar, wind, hydro, geothermal, 54 American Society for Civil Engineers, 2013 fuel to produce both electricity and another form of landfill gas, and biomass. Available at: http://www. Report Card for America’s Infrastructure (2013), energy such as heat or steam. Casazza, J. and Delea, eia.gov/electricity/monthly/epm_table_grapher.cfm available at http://www.infrastructurereportcard. F., Understanding Electric Power Systems, IEEE ?t=epmt_6_03. org/energy/. Press, at 220–221 (2d ed. 2010).
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generation resources that use since that time. As of April 2014, 25 Power can also be generated using renewables such as wind, solar, states 67 have ‘‘enacted long-term (3+ gasification technology. An IGCC unit biomass, geothermal, or hydroelectric years), binding energy savings targets, or gasifies coal or petroleum coke to form power as their primary fuels.61 Through energy efficiency resource standards a synthetic gas (or syngas) composed of PURPA, Congress supported the (EERS).’’ 68 Funding for energy carbon monoxide (CO) and hydrogen development of more renewable energy efficiency programs has grown rapidly (H2), which can be combusted in a generation in the U.S. States have taken in recent years, with budgets for electric combined cycle system to generate a significant lead in requiring the efficiency programs totaling $5.9 billion power. development of renewable resources. In in 2012.69 particular, a number of states have 3. Technological Developments and Advancements and innovation in Costs adopted renewable portfolio standards power sector technologies provide the (RPS). As of 2013, 29 states and the opportunity to address CO2 emission Natural gas prices have decreased District of Columbia have enforceable levels at affected power plants while at dramatically and generally stabilized in RPS or similar laws.62 In its AEO 2015 the same time improving the overall recent years as new drilling techniques Reference case, the EIA found that power system in the U.S. by lowering have brought additional supply to the renewable energy will account for 38 the carbon intensity of power marketplace and greatly increased the percent of the overall growth in generation, and ensuring a reliable domestic resource base. As a result, electricity generation from 2013 to supply of power at a reasonable cost. natural gas prices are expected to be 2040.63 The AEO 2015 Reference case competitive for the foreseeable future, forecasts that the renewables share of 2. Fossil Fuel-Fired EGUs Regulated by and EIA modeling and utility U.S. electricity generation will grow this Action, Generally announcements confirm that utilities from 13 percent in 2013 to 18 percent Natural gas-fired EGUs typically use are likely to rely heavily on natural gas 64 in 2040. one of two technologies: NGCC or to meet new demand for electricity Price pressures caused by oil simple cycle combustion turbines. generation. On average, as discussed embargoes in the 1970s also brought the NGCC units first generate power from a below, the cost of generation from a new issues of conservation and energy combustion turbine (the combustion natural-gas fired power plant (a NGCC efficiency to the forefront of U.S. energy unit) is expected to be significantly 65 cycle). The unused heat from the policy. This trend continued in the combustion turbine is then routed to a lower than the cost of generation from 70 early 1990s. Some state regulatory heat recovery steam generator (HRSG) a new coal-fired power plant. commissions and utilities supported that generates steam, which is then used Other drivers that may influence energy efficiency through least-cost to produce power using a steam turbine decisions to build new power plants are planning, with the National Association (the steam cycle). Combining these increases in renewable energy supplies, of Regulatory Utility Commissioners generation cycles increases the overall often due to state and federal energy (NARUC) ‘‘adopting a resolution that efficiency of the system. Simple cycle policies. As previously discussed, many called for the utility’s least cost plan to states have adopted RPS, which require 66 combustion turbines use a single be the utility’s most profitable plan.’’ combustion turbine to produce a certain portion of electricity to come Energy efficiency has been utilized to electricity (i.e., there is no heat recovery from renewable energy sources such as meet energy demand to varying levels or steam cycle). The power output from solar or wind. The federal government these simple cycle combustion turbines has also offered incentives to encourage 61 Casazza, J. and Delea, F., Understanding can be easily ramped up and down further deployment of other forms of Electric Power Systems, IEEE Press, at 220–221 (2d electric generation including renewable ed. 2010). making them ideal for ‘‘peaking’’ 62 U.S. Energy Information Administration (EIA), operations. energy sources and new nuclear power plants. Annual Energy Outlook 2014 with Projections to Coal-fired utility boilers are primarily 2040, at LR–5 (2014). Reflecting these factors, the EIA either pulverized coal (PC) boilers or 63 U.S. Energy Information Administration (EIA), projections from the last several years fluidized bed (FB) boilers. At a PC Annual Energy Outlook 2015 with Projections to show that natural gas is likely to be the 2040, at E–12 (2015). boiler, the coal is crushed (pulverized) most widely-used fossil fuel for new 64 U.S. Energy Information Administration (EIA), into a powder in order to increase its construction of electric generating Annual Energy Outlook 2015 with Projections to surface area. The coal powder is then 2040, at 24–25(2015). capacity through 2020, along with blown into a boiler and burned. In a 65 Edison Electric Institute, Making a Business of renewable energy, nuclear power, and a coal-fired boiler using FB combustion, Energy Efficiency: Sustainable Business Models for limited amount of coal with CCS.71 Utilities, at 1 (2007). Congress passed legislation in the coal is burned in a layer of heated While EIA data shows that natural gas the 1970s that jumpstarted energy efficiency in the particles suspended in flowing air. U.S. For example, President Ford signed the Energy is likely to be the most widely-used Policy and Conservation Act (EPCA) of 1975—the fossil fuel for new construction of first law on the issue. EPCA authorized the Federal 67 American Council for an Energy-Efficient electric generating capacity through Energy Administration (FEA) to ‘‘develop energy Economy, State Energy Efficiency Resource conservation contingency plans, established vehicle Standards (EERS) (2014), available at http://aceee. 2030, a few coal-fired units still remain fuel economy standards, and authorized the org/files/pdf/policy-brief/eers-04-2014.pdf. ACEEE as viable projects at various advanced creation of efficiency standards for major household did not include Indiana (EERS eliminated), stages of construction and development. appliances.’’ Alliance to Save Energy, History of Delaware (EERS pending), Florida (programs One new coal facility that has Energy Efficiency, at 6 (2013) (citing Anders, ‘‘The funded at levels far below what is necessary to meet Federal Energy Administration,’’ 5; Energy Policy targets), Utah, or Virginia (voluntary standards) in essentially completed construction, and Conservation Act, S. 622, 94th Cong. (1975– its calculation. 1976)), available at https://www.ase.org/sites/ase. 68 American Council for an Energy-Efficient 70 Levelized Cost and Levelized Avoided Cost of org/files/resources/Media%20browser/ee_ Economy, State Energy Efficiency Resource New Generation Resources in the Annual Energy commission_history_report_2–1–13.pdf. Standards (EERS) (2014), available at http://aceee. Outlook 2015 http://www.eia.gov/forecasts/aeo/ 66 Edison Electric Institute, Making a Business of org/files/pdf/policy-brief/eers-04–2014.pdf. electricity_generation.html. Energy Efficiency: Sustainable Business Models for 69 American Council for an Energy-Efficient 71 http://www.eia.gov/forecasts/aeo/pdf/ Utilities, at 1 (2007), available at http://www.eei. Economy, The 2013 State Energy Efficiency 0383(2013).pdf; http://www.eia.gov/forecasts/aeo/ org/whatwedo/PublicPolicyAdvocacy/State Scorecard, at 17 (Nov. 2013), available at http:// pdf/0383(2012).pdf; http://prod-http-80-80049 Regulation/Documents/Making_Business_Energy_ aceee.org/sites/default/files/publications/research 8448.us-east-1.elb.amazonaws.com/w/images/6/6d/ Efficiency.pdf. reports/e13k.pdf. 0383%282011%29.pdf.
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Southern Company’s Kemper County 2015: 76 (i) Shows that a modest amount further control costs (i.e., an additional Energy Facility, deploys IGCC with of coal-fired power plants that are 31.3 GW of NGCC and no additional partial CCS. Additionally, another currently under construction are coal, for a total, from 2015 through project, Summit Power’s Texas Clean expected to begin operation in the next 2030, of 39 GW of NGCC and 0.3 GW Energy Project (TCEP), which will several years (referred to as ‘‘planned’’); of coal with CCS). deploy IGCC with CCS, continues as a and (ii) projects in the reference case 77 Under the EIA projections, existing viable project.72 The EIA modeling that a very small amount of new coal-fired generation will remain an projects that coal-fired power generation (‘‘unplanned’’) conventional coal-fired important part of the mix for power will remain the single largest portion of capacity, with CCS, will come online generation. Modeling from both the EIA the electricity sector beyond 2030. The after 2012 and through 2037 in response and the EPA project that coal-fired EIA modeling also projects that few, if to federal and state incentives. generation will remain the largest single any, new coal-fired EGUs will be built According to the AEO 2015, the vast source of electricity in the U.S. through in this decade and that those that are majority of new generating capacity 2040. Specifically, in the EIA’s AEO built will have CCS.73 Continued during this period will be either natural 2015, coal will supply approximately 40 progress on these projects is consistent gas-fired or renewable sources. percent of all electricity in the electric with the EIA modeling that suggests that Similarly, the EIA projections from the power sector in both 2020 and 2025. The EPA modeling using the a small number of coal-fired power last several years show that natural gas Integrated Planning Model (IPM), a plants may be constructed. The primary is likely to be the most widely-used fossil fuel for new construction of detailed power sector model that the reasons for this rate of current and EPA uses to support power sector projected future development of new electric generating capacity through 78 regulations, also shows limited future coal projects include highly competitive 2030. Specifically, the AEO 2015 projects construction of new coal-fired power natural gas prices, lower electricity 30.3 GW of additional base load or plants under the base case.79 The EPA’s demand growth, and increases in the intermediate load generation capacity projections from IPM can be found in supply of renewable energy. We through 2020 (this includes projects that the RIA. recognize, however, that a variety of are under development—i.e., being 5. Integrated Resource Plans factors may come into play in a decision constructed or in advance planning— to build new power generation, and we and model-projected nuclear, coal, and The trends in the power sector want to ensure that there are standards NGCC projects). The vast majority of described above are also apparent in in place to make sure that whatever fuel this new electric capacity (20.4 GW) is publicly available long-term resource is utilized is done so in a way that already under development (under plans, known as integrated resource minimizes CO2 emissions, as Congress construction or in advanced planning); plans (IRPs). intended with CAA section 111.74 it includes about 0.7 GW of new coal- The EPA has reviewed publicly available IRPs from a range of 4. Energy Sector Modeling fired capacity, 5.5 GW of new nuclear capacity, and 14.2 GW of new NGCC companies (e.g., varying in size, Various energy sector modeling capacity. The EPA believes that most location, current fuel mix), and these current fossil fuel-fired projects are plans are generally consistent with both efforts, including projections from the 80 EIA and the EPA, forecast trends in new already designed to meet limits EIA and EPA modeling projections. power plant construction and utilization consistent with this rule (or they have These IRPs indicate that companies are focused on demand-side management of existing power plants that are already commenced construction and programs to lower future electricity consistent with the above-described are thus not subject to these final demand and are mostly reliant on a mix technological developments and costs. standards). The AEO 2015 also projects of new natural gas-fired generation and The EIA’s annual report, the AEO, an additional 9.9 GW of new base load renewable energy to meet increased load forecasts the structure of and capacity additions, which are model- demand and to replace retired developments in the power sector. projected (unplanned). This consists of generation capacity. These reports are based on economic 7.7 GW of new NGCC capacity, 1.2 GW of new geothermal capacity, 0.7 GW of Notwithstanding this clear trend modeling that reflects existing policy towards natural gas-fired generation and and regulations, such as state RPS new hydroelectric capacity, and 0.3 GW of new coal equipped with CCS renewables, many of the IRPs highlight programs and federal tax credits for the value of fuel diversity and include renewables.75 The current report, AEO (incentivized with some government funding). Therefore, the AEO 2015 options to diversify new generation projection suggests that the new power capacity beyond natural gas and 72 ‘‘Odessa coal-to-gas power plant to break renewable energy. Several IRPs indicate ground this year’’, Houston Chronicle (April 1, generation capacity added through 2020 2015). is expected to already meet the final that companies are considering new 73 This projection is for business as usual and emissions standards without incurring nuclear generation, including either does not account for the proposed or final CO2 further control costs. This is also true traditional nuclear power plants or emission standard. Even in its sensitivity analysis during the period from 2020 through small modular reactors, and a smaller that assumes higher natural gas prices and number are considering new coal-fired electricity demand, EIA does not project any 2030, where new model-projected additional coal-fired power plants beyond its (unplanned) intermediate and base load generation capacity with and without reference case until 2023, in a case where power capacity is expected to be compliant CCS technology. Based on public companies assume no GHGs emission limitations, with the standards without incurring comments and on the information and until 2024 in a case where power companies contained in these IRPs, the EPA do assume GHGs emission limitations. 74 These sources received federal assistance under 76 Energy Information Administration’s Annual acknowledges that a small number of EPAct 2005. See Section III.H.3.g below. However, Energy Outlook for 2015, Final Release available at none of the constraints in that Act affect the http://www.eia.gov/forecasts/aeo/index.cfm. 79 http://www.epa.gov/airmarkets/progsregs/epa- discussion in the text above, since that discussion 77 EIA’s reference case projections are the result ipm/BaseCasev410.html#documentation. does not relate to technology use or emissions of its baseline assumptions for economic growth, 80 Technical Support Document—‘‘Review of reduction by these sources. fuel supply, technology, and other key inputs. Electric Utility Integrated Resource Plans’’ (May 75 http://www.eia.gov/forecasts/aeo/chapter_legs_ 78 Annual Energy Outlook 2010, 2011, 2012, 2015), available in the rulemaking docket EPA–HQ– regs.cfm. 2013, 2014 and 2015. OAR–2013–0495.
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new coal-fired power plants may be category.88 A ‘‘new source’’ is ‘‘any Rather, sources generally may select any built in the near future. While this stationary source, the construction or measure or combination of measures outcome would be contrary to the modification of which is commenced that will achieve the emissions level of economic modeling predictions, the after,’’ in general, final standards the standard.94 In establishing standards agency understands that economic applicable to that source are of performance, the EPA has significant modeling may not fully reflect the range promulgated or, if earlier, proposed.89 A discretion to create subcategories based of factors that a particular company may modification is ‘‘any physical change on source type, class, or size.95 . . . or change in the method of consider when evaluating new The text and legislative history of generation options, such as fuel operation . . . which increases the CAA section 111, as well as relevant diversification. Further, it is possible amount of any air pollutant emitted by court decisions, identify the factors that that some of this potential new coal- such source or which results in the the EPA is to consider in making a BSER fired construction may occur because emission of any air pollutant not determination. The system of emission developers are able to design projects previously emitted.’’ 90 The EPA, reduction must be technically feasible, with specific business plans, such as the through regulations, has determined cogeneration of chemicals, which allow that certain types of changes are exempt the costs of the system must be the source to provide competitively from consideration as a modification.91 reasonable, and the emission standard priced electricity in specific geographic The NSPS general provisions (40 CFR that the EPA promulgates based on the regions. part 60, subpart A) provide that an system of emission reduction must be existing source is considered to be a achievable. In addition, in identifying a D. Statutory Background new source if it undertakes a BSER, the EPA must consider the The U.S. Supreme Court ruled in ‘‘reconstruction,’’ which is the amount of emissions reductions Massachusetts v. EPA that GHGs 81 meet replacement of components of an attributable to the system, and must also the definition of ‘‘air pollutant’’ in the existing facility to an extent that (1) the consider non-air quality health and CAA,82 and premised its decision in fixed capital cost of the new environmental impacts and energy AEP v. Connecticut,83 that the CAA components exceeds 50 percent of the requirements. The case law addressing displaced any federal common law right fixed capital cost that would be required CAA section 111 makes it clear that the to compel reductions in CO2 emissions to construct a comparable entirely new EPA has discretion in weighing costs, from fossil fuel-fired power plants, on facility, and (2) it is technologically and amount of emission reductions, energy its view that CAA section 111 applies to economically feasible to meet the requirements, and impacts of non-air GHG emissions. applicable standards.92 quality pollutants, and may weigh them CAA section 111 authorizes and CAA section 111(a)(1) defines a differently for different types of sources directs the EPA to prescribe new source ‘‘standard of performance’’ as ‘‘a or air pollutants. We note that under the performance standards (NSPS) standard for emissions . . . achievable case law of the D.C. Circuit, another applicable to certain new stationary through the application of the best factor is relevant for the BSER sources (including newly constructed, system of emission reduction which determination: Whether the standard modified and reconstructed sources).84 [considering cost, non-air quality health would effectively promote further As a preliminary step to regulation, the and environmental impact, and energy deployment or development of EPA must list categories of stationary requirements] the Administrator advanced technologies. Within the sources that the Administrator, in his or determines has been adequately constraints just described, the EPA has her judgment, finds ‘‘cause[], or demonstrated.’’ This definition makes discretion in identifying the BSER and contribute[] significantly to, air clear that the standard of performance the resulting emission standard. See pollution which may reasonably be must be based on ‘‘the best system of generally Section III.H below. emission reduction . . . adequately anticipated to endanger public health or For more than four decades, the EPA welfare.’’ The EPA has listed and demonstrated’’ (BSER). The standard that the EPA develops, has used its authority under CAA regulated more than 60 stationary reflecting the performance of the BSER, section 111 to set cost-effective emission source categories under CAA section is commonly a numeric emission limit, standards which ensure that newly 111.85 The EPA listed the two source expressed as a numeric performance constructed, reconstructed, and categories at issue here in the 1970s— level that can either be normalized to a modified stationary sources use the best listing fossil fuel-fired electric steam rate of output or input (e.g., tons of performing technologies to limit generating units in 1971 86 and listing pollution per amount of product emissions of harmful air pollutants. In combustion turbines in 1977.87 produced—a so-called rate-based this final action, the EPA is following Once the EPA has listed a source standard), or expressed as a numeric the same well-established interpretation category, the EPA proposes and then limit on mass of pollutant that may be and application of the law under CAA promulgates ‘‘standards of emitted (e.g., 100 ug/m3—parts per section 111 to address GHG emissions performance’’ for ‘‘new sources’’ in the billion). Generally, the EPA does not from newly constructed, reconstructed, prescribe a particular technological and modified fossil fuel-fired power 81 The EPA’s 2009 endangerment finding defines system that must be used to comply plants. For each of the standards in this the air pollution which may endanger public health 93 final action, the EPA considered a and welfare as the well-mixed aggregate group of with a standard of performance. the following gases: CO2, methane (CH4), nitrous number of alternatives and evaluated oxide (N2O), sulfur hexafluoride (SF6), 88 CAA section 111(b)(1)(B). them against the statutory factors. The hydrofluorocarbons (HFCs), and perfluorocarbons 89 CAA section 111(a)(2). BSER for each category of affected EGUs (PFCs). 90 CAA section 111(a)(4); See also 40 CFR 60.14 82 and the standards of performance based 549 U.S. 497, 520 (2007). concerning what constitutes a modification, how to on these BSER are based on that 83 131 S.Ct. 2527, 2537–38 (2011). determine the emission rate, how to determine an 84 CAA section 111(b)(1)(A). emission increase, and specific actions that are not, evaluation. 85 See generally 40 CFR part 60, subparts D– by themselves, considered modifications. MMMM. 91 40 CFR 60.2, 60.14(e). 94 CAA section 111(b)(5). 86 36 FR 5931 (March 31, 1971). 92 40 CFR 60.15. 95 CAA section 111(b)(2); see also Lignite Energy 87 42 FR 53657 (October 3, 1977). 93 CAA section 111(b)(5) and (h). Council v. EPA, 198 F. 3d 930, 933 (D.C. Cir. 1999).
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E. Regulatory Background Petitioners sought judicial review of the proposed standards of performance for: In 1971, the EPA initially included rule, contending, among other issues, (1) Modified fossil fuel-fired electric fossil fuel-fired EGUs (which includes that the rule was required to include utility steam generating units, (2) natural gas, petroleum and coal) that use standards of performance for GHG modified natural gas-fired stationary 103 steam-generating boilers in a category emissions from EGUs. The January 8, combustion turbines, (3) reconstructed that it listed under CAA section 2014 preamble to the proposed CO2 fossil fuel-fired electric utility steam 104 111(b)(1)(A),96 and promulgated the first standards for new EGUs includes a generating units, and (4) reconstructed set of standards of performance for discussion of the GHG-related litigation natural gas-fired stationary combustion sources in that category, which it of the 2006 Final Rule as well as other turbines. GHG-associated litigation. codified in subpart D.97 In 1977, the G. Stakeholder Engagement and Public EPA initially included fossil fuel-fired F. Development of Carbon Pollution Comments on the Proposals combustion turbines in a category that Standards for Fossil Fuel-Fired Electric 1. Stakeholder Engagement the EPA listed under CAA section Utility Generating Units 111(b)(1)(A),98 and the EPA The EPA has engaged extensively On April 13, 2012, the EPA initially promulgated standards of performance with a broad range of stakeholders and proposed standards under CAA section for that source category in 1979, which the general public regarding climate 111 for newly constructed fossil fuel- the EPA codified in subpart GG.99 change, carbon pollution from power fired electric utility steam generating The EPA has revised those plants, and carbon pollution reduction units. 77 FR 22392 (‘‘April 2012 regulations, and in some instances, has opportunities. These stakeholders proposal’’). The EPA withdrew that revised the codifications (that is, the 40 included industry and electric utility proposal (79 FR 1352 (January 8, 2014)), CFR part 60 subparts), several times representatives, state and local officials, and, on the same day, proposed the over the ensuing decades. In 1979, the tribal officials, labor unions, non- standards addressed in this final rule. EPA divided subpart D into 3 subparts— governmental organizations and many 79 FR 1430 (‘‘January 2014 proposal’’). Da (‘‘Standards of Performance for others. Specifically, the EPA proposed Electric Utility Steam Generating Units In February and March 2011, early in standards under CAA section 111 to for Which Construction is Commenced the process of developing carbon limit emissions of CO from newly After September 18, 1978’’), Db 2 pollution standards for new power constructed fossil fuel-fired electric (‘‘Standards of Performance for plants, the EPA held five listening utility steam generating units and newly Industrial-Commercial-Institutional sessions to obtain information and input constructed natural gas-fired stationary Steam Generating Units’’) and Dc from key stakeholders and the public. combustion turbines. Each of the five sessions had a (‘‘Standards of Performance for Small In support of the January 2014 particular target audience: The electric Industrial-Commercial-Institutional proposal, on February 26, 2014, the EPA power industry, environmental and Steam Generating Units’’)—in order to published a notice of data availability environmental justice organizations, codify separate requirements that it (NODA) (79 FR 10750). Through the 100 states and tribes, coalition groups, and established for these subcategories. In NODA and an associated technical the petroleum refinery industry. 2006, the EPA created subpart KKKK, support document, Effect of EPAct05 on The EPA conducted subsequent ’’Standards of Performance for Best System of Emission Reduction for outreach prior to the June 2014 Stationary Combustion Turbines,’’ New Power Plants, the EPA solicited proposals of standards for modified and which applied to certain sources comment on its interpretation of the reconstructed EGUs and emission previously regulated in subparts Da and provisions in the Energy Policy Act of 101 guidelines for existing EGUs, as well as GG. None of these subsequent 2005 (EPAct05),105 including how the during the public comment periods for rulemakings, including the revised provisions may affect the rationale for the proposals. Although this stakeholder codifications, however, constituted a the EPA’s proposed determination that outreach was primarily framed around new listing under CAA section partial CCS is the best system of the GHG emission guidelines for 111(b)(1)(A). emission reduction adequately The EPA promulgated amendments to existing EGUs, the outreach demonstrated for fossil fuel-fired subpart Da in 2006, which included encompassed issues relevant to this electric utility steam generating units. rulemaking and provided an new standards of performance for On June 18, 2014, the EPA proposed opportunity for the EPA to better criteria pollutants for EGUs, but did not standards of performance to limit understand previous state and include specific standards of emissions of CO from modified and 102 2 stakeholder experience with reducing performance for CO2 emissions. reconstructed fossil fuel-fired electric CO utility steam generating units and 2 emissions in the power sector. In 96 36 FR 5931 (March 31, 1971). natural gas-fired stationary combustion addition to 11 public listening sessions, 97 ‘‘Standards of Performance for Fossil-Fuel- turbines (79 FR 34960; June 2014 the EPA held hundreds of meetings with Fired Steam Generators for Which Construction Is individual stakeholder groups, and Commenced After August 17, 1971,’’ 36 FR 24875 proposal). Specifically, the EPA (December 23, 1971) codified at 40 CFR 60.40–46. meetings that brought together a variety 98 42 FR 53657 (October 3, 1977). 103 State of New York, et al. v. EPA, No. 06–1322. of stakeholders to discuss a wide range 99 ‘‘Standards of Performance for Electric Utility 104 79 FR 1430, 1444. of issues related to the electricity sector Steam Generating Units for Which Construction is 105 See Section III.H.3.g below. The Energy Policy and regulation of GHGs under the CAA. Commenced After September 18, 1978,’’ 44 FR Act of 2005 (EPAct05) was signed into law by The agency met with electric utility 33580 (June 11, 1979). President George W. Bush on August 8, 2005. associations and electricity grid 100 44 FR 33580 (June 11, 1979). EPAct05 was intended to address energy 101 71 FR 38497 (July 6, 2006), as amended at 74 production in the United States, including: (1) operators. Agency officials engaged with FR 11861 (March 20, 2009). Energy efficiency; (2) renewable energy; (3) oil and labor unions and with leaders 102 ‘‘Standards of Performance for Electric Utility gas; (4) coal; (5) Tribal energy; (6) nuclear matters representing large and small industries. Steam Generating Units, Industrial-Commercial- and security; (7) vehicles and motor fuels, including The agency also met with energy Institutional Steam Generating Units, and Small ethanol; (8) hydrogen; (9) electricity; (10) energy tax Industrial-Commercial-Institutional Steam incentives; (11) hydropower and geothermal energy; industries, such as coal and natural gas Generating Units, Final Rule.’’ 71 FR 9866 and (12) climate change technology. www2.epa.gov/ interests, as well as with representatives (February 27, 2006). laws-regulations/summary-energy-policy-act. of energy-intensive industries, such as
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the iron and steel, and aluminum local government officials, academia, criteria and subcategories based on industries, to better understand the environmental organizations, and turbine size). potential concerns of large industrial various interest groups. The agency III. Regulatory Authority, Affected purchasers of electricity. In addition, received comments on a range of topics, EGUs and Their Standards, and Legal the agency met with companies that including the determination that a new Requirements offer new technology to prevent or highly-efficient steam generating EGU reduce carbon pollution. The agency implementing partial CCS was the BSER In this section, we describe our provided and encouraged multiple for such sources, the level of the CO2 authority to regulate CO2 from fossil opportunities for engagement with state, standard based on implementation of fuel-fired EGUs. We also describe our local, tribal, and regional environmental partial CCS, the criteria that define decision to combine the two existing and energy agencies. The EPA also met which newly constructed natural gas- categories of affected EGUs—steam with representatives of environmental fired stationary combustion turbines generators and combustion turbines— justice organizations, environmental will be subject to standards, the into a single category of fossil fuel-fired groups, public health professionals, establishment of subcategories based on EGUs for purposes of promulgating public health organizations, religious combustion turbine size, and the rule’s standards of performance for CO2 organizations, and other community potential effects on the Prevention of emissions. We also explain that we are stakeholders. Significant Deterioration (PSD) codifying all of the requirements in this The EPA received more than 2.5 preconstruction permit program and rule for new, modified, and million comments submitted in Title V operating permit program. reconstructed affected EGUs in new response to the original April 2012 subpart TTTT of part 60 of Title 40 of proposal for newly constructed fossil 3. Comments on the June 2014 Proposal the Code of Federal Regulations. In fuel-fired EGUs. Because the original For Modified and Reconstructed Fossil addition, we explain which sources are proposal was withdrawn, the EPA Fuel-Fired EGUs and are not affected by this rule, and the instructed commenters that wanted Upon publication of the June 18, 2014 format of these standards. Finally, we their comments on the April 2012 proposal for modified and reconstructed describe the legal requirements for proposal to be considered in connection fossil fuel-fired EGUs, the EPA offered establishing these emission standards. a 120-day public comment period— with the January 2014 proposal to A. Authority To Regulate Carbon through October 16, 2014. The EPA held submit new comments to the EPA or to Dioxide From Fossil Fuel-Fired EGUs re-submit their previous comments. We public hearings in four locations during received more comments in response to the week of July 28, 2014. These The EPA’s authority for this rule is the January 2014 proposal, as discussed hearings also addressed the EPA’s June CAA section 111(b)(1). CAA section in the section below. 18, 2014 proposed emission guidelines 111(b)(1)(A) requires the Administrator The EPA has given stakeholder input for existing fossil fuel-fired EGUs to establish a list of source categories to provided prior to the proposals, as well (reflecting the connections between the be regulated under section 111. A as during the public comment periods proposed standards for modified and category of sources is to be included on for each proposal, careful consideration reconstructed sources and the proposed the list ‘‘if in [the Administrator’s] during the development of this emission guidelines). A total of 1,322 judgment it causes, or contributes rulemaking and, as a result, it includes speakers testified, and a further 1,450 significantly to, air pollution which may elements that are responsive to many attended but did not speak. The reasonably be anticipated to endanger stakeholder concerns and that enhance speakers were provided the opportunity public health and welfare.’’ This the rule. This preamble and the to present data, views, or arguments determination is commonly referred to Response-to-Comments (RTC) document concerning one or both proposed as an ‘‘endangerment finding’’ and that summarize and provide the agency’s actions. phrase encompasses both the ‘‘causes or responses to the comments received. The EPA received over 200 comments contributes significantly’’ component on the proposed standards for modified and the ‘‘endanger public health and 2. Comments on the January 2014 and reconstructed fossil fuel-fired EGUs welfare’’ component of the Proposal For Newly Constructed Fossil from a range of stakeholders similar to determination. Then, for the source Fuel-Fired EGUs those that submitted comments on the categories listed under section Upon publication of the January 8, January 2014 proposal for newly 111(b)(1)(A), the Administrator 2014 proposal for newly constructed constructed fossil fuel-fired EGUs (i.e., promulgates, under section 111(b)(1)(B), fossil fuel-fired EGUs, the EPA provided industry and electric utility ‘‘standards of performance for new a 60-day public comment period. On representatives, trade groups, sources within such category.’’ March 6, 2014, in order to provide the equipment manufacturers, state and In this rule, the EPA is establishing public additional time to submit local government officials, academia, standards under section 111(b)(1)(B) for comments and supporting information, environmental organizations, and source categories that it has previously the EPA extended the comment period various interest groups). The agency listed and regulated for other pollutants by 60 days, to May 9, 2014, giving received comments on a range of topics, and which now are being regulated for stakeholders over 120 days to review, including the methodology for an additional pollutant. Because of this, and comment upon, the January 2014 determining unit-specific CO2 standards there are two aspects of section proposal, as well as the NODA. A public for modified steam generating units and 111(b)(1) that warrant particular hearing was held on February 6, 2014, the use of supercritical boiler conditions discussion. with 159 speakers presenting testimony. as the basis for the CO2 standards for First, because the EPA is not listing a The EPA received more than 2 million certain reconstructed steam generating new source category in this rule, the comments on the proposed standards units. Many of the comments regarding EPA is not required to make a new for newly constructed fossil fuel-fired modified and reconstructed natural gas- endangerment finding with regard to EGUs from a range of stakeholders that fired stationary combustion turbines are affected EGUs in order to establish included industry and electric utility similar to the comments regarding standards of performance for the CO2 representatives, trade groups, newly constructed combustion turbines emissions from those sources. Under the equipment manufacturers, state and described above (e.g., applicability plain language of CAA section
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111(b)(1)(A), an endangerment finding Administrator to propose and Section II.A of this preamble is is required only to list a source category. promulgate regulations under section confirming and enhancing our Further, though the endangerment 111(b)(1)(B), Congress provided that the understanding of the near- and longer- finding is based on determinations as to Administrator should take comment and term impacts emissions of CO2 are the health or welfare impacts of the then finalize the standards with such having on Earth’s climate and the pollution to which the source category’s modifications ‘‘as he deems adverse public health, welfare, and pollutants contribute, and as to the appropriate.’’ The D.C. Circuit has economic consequences that are significance of the amount of such considered similar statutory phrasing occurring and are projected to occur as contribution, the statute is clear that the from CAA section 231(a)(3) and a result. endangerment finding is made with concluded that ‘‘[t]his delegation of Moreover, the high level of GHG respect to the source category; section authority is both explicit and emissions from fossil fuel-fired EGUs 111(b)(1)(A) does not provide that an extraordinarily broad.’’ National Assoc. makes clear that it is rational for the endangerment finding is made as to of Clean Air Agencies v. EPA, 489 F.3d EPA to regulate GHG emissions from specific pollutants. This contrasts with 1221, 1229 (D.C. Cir. 2007). this sector. EGUs emit almost one-third other CAA provisions that do require In exercising its discretion with of all U.S. GHGs and comprise by far the the EPA to make endangerment findings respect to which pollutants are largest stationary source category of for each particular pollutant that the appropriate for regulation under section GHG emissions; indeed, as noted above, EPA regulates under those provisions. 111(b)(1)(B), the EPA has in the past the CO2 emissions from fossil fuel-fired E.g., CAA sections 202(a)(1), 211(c)(1), provided a rational basis for its EGUs are almost three times as much as and 231(a)(2)(A); see also American decisions. See National Lime Assoc. v. the emissions from the next ten source Electric Power Co. Inc., v. Connecticut, EPA, 627 F.2d 416, 426 & n.27 (D.C. Cir. categories combined. Further, the CO2 131 S. Ct. 2527, 2539 (2011) (‘‘[T]he 1980) (court discussed, but did not emissions from even a single new coal- Clean Air Act directs the EPA to review, the EPA’s reasons for not fired power plant may amount to establish emissions standards for promulgating standards for oxides of millions of tons each year. See, e.g., categories of stationary sources that, ‘in nitrogen (NOX), sulfur dioxide (SO2) and Section V.K below (noting that even the [the Administrator’s] judgment,’ CO from lime plants); Standards of difference in CO2 emissions between a ‘caus[e], or contribut[e] significantly to, Performance for Petroleum Refineries, highly efficient SCPC and the same unit air pollution which may reasonably be 73 FR at 35859–60 (June 24, 2008) meeting today’s standard of anticipated to endanger public health or (providing reasons why the EPA was not performance can amount to hundreds of welfare.’ § 7411(b)(1)(A).’’) (emphasis promulgating GHG standards for thousands of tons each year). These added). petroleum refineries as part of that rule). facts provide a rational basis for Second, once a source category is Though these previous examples regulating CO2 emissions from affected listed, the CAA does not specify what involved the EPA providing a rational EGUs. pollutants should be the subject of basis for not setting standards for a Some commenters have argued that standards from that source category. The given pollutant, a similar approach is the EPA is required to make a new statute, in section 111(b)(1)(B), simply appropriate where the EPA determines endangerment finding before it may directs the EPA to propose and then that it should set a standard for an regulate CO2 from EGUs. We disagree, promulgate regulations ‘‘establishing additional pollutant for a source for the reasons discussed above. federal standards of performance for category that was previously listed and Moreover, as discussed in the January new sources within such category.’’ In regulated for other pollutants. 2014 proposal,108 even if CAA section the absence of specific direction or In this rulemaking, the EPA has a 111 required the EPA to make enumerated criteria in the statute rational basis for concluding that endangerment and cause-or-contribute concerning what pollutants from a given emissions of CO2 from fossil fuel-fired significantly findings as prerequisites source category should be the subject of power plants, which are the major U.S. for this rulemaking, then, so far as the standards, it is appropriate for the EPA source of GHG air pollution, merit ‘‘CO2 endangers public health and to exercise its authority to adopt a regulation under CAA section 111. As welfare’’ component of an reasonable interpretation of this noted, in 2009, the EPA made a finding endangerment finding is concerned, the provision. Chevron U.S.A. Inc. v. NRDC, that GHG air pollution may reasonably information and conclusions described 467 U.S. 837, 843–44 (1984).106 be anticipated to endanger public health above should be considered to The EPA has previously interpreted or welfare, and in 2010, the EPA denied constitute the requisite endangerment this provision as granting it the petitions to reconsider that finding. The finding. Similarly, so far as a cause-or- discretion to determine which EPA extensively reviewed the available contribute significantly finding is pollutants should be regulated. See science concerning GHG pollution and concerned, the information and Standards of Performance for Petroleum its impacts in taking those actions. In conclusions described above should be Refineries, 73 FR 35838 (June 24, 2008) 2012, the U.S. Court of Appeals for the considered to constitute the requisite (concluding that the statute provides D.C. Circuit upheld the finding and the finding. The EPA’s rational basis for ‘‘the Administrator with significant denial of petitions to reconsider.107 In regulating CO2 under CAA section 111 flexibility in determining which addition, assessments from the NRC, the is based primarily on the analysis and pollutants are appropriate for regulation IPCC, and other organizations published conclusions in the EPA’s 2009 under section 111(b)(1)(B)’’ and citing after 2010 lend further credence to the Endangerment Finding and 2010 denial cases). Further, in directing the validity of the Endangerment Finding. of petitions to reconsider that Finding, No information that commenters have coupled with the subsequent 106 In Chevron, the U.S. Supreme Court held that presented or that the EPA has reviewed assessments from the IPCC and NRC an agency must, at Step 1, determine whether provides a basis for reaching a different that describe scientific developments Congress’s intent as to the specific matter at issue conclusion. Indeed, current and since those EPA actions. In addition, we is clear, and, if so, the agency must give effect to have reviewed comments presenting that intent. If Congressional intent is not clear, then, evolving science discussed in detail in at Step 2, the agency has discretion to fashion an other scientific information to interpretation that is a reasonable construction of 107 Coalition for Responsible Regulation v. EPA, the statute. 684 F.3d 102, 119–126 (D.C. Circuit 2012). 108 79 FR 1430, 1455–56 (January 8, 2014).
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determine whether that information has Likewise, if the EPA were required to B. Treatment of Categories and any meaningful impact on our analysis make a cause-or-contribute-significantly Codification in the Code of Federal and conclusions. For both the finding for CO2 emissions from the Regulations endangerment finding and the rational fossil fuel-fired EGUs as a prerequisite As discussed in the January 2014 basis, the EPA focused on public health to regulating such emissions under CAA proposal of carbon pollution standards and welfare impacts within the United section 111, the same facts that support for newly constructed EGUs (79 FR States, as it did in the 2009 Finding. The our rational basis determination would 1430) and above, in 1971 the EPA listed impacts in other world regions support such a finding. As shown in fossil fuel-fired steam generating boilers strengthen the case because impacts in Tables 3 and 4 in this preamble, fossil as a new category subject to CAA other world regions can in turn fuel-fired EGUs are very large emitters section 111 rulemaking, and in 1979 the adversely affect the United States or its of CO2. All told, these fossil fuel-fired EPA listed fossil fuel-fired combustion citizens. EGUs emit almost one-third of all U.S. turbines as a new category subject to the More specifically, our approach GHG emissions, and are responsible for CAA section 111 rulemaking. In the here—reflected in the information and almost three times as much as the ensuing years, the EPA has promulgated conclusions described above—is emissions from the next ten stationary standards of performance for the two substantially similar to that reflected in source categories combined. The CO2 categories and codified those standards, the 2009 Endangerment Finding and the emissions from even a single new coal- at various times, in 40 CFR part 60, 2010 denial of petitions to reconsider. fired power plant may amount to subparts D, Da, GG, and KKKK. The D.C. Circuit upheld that approach millions of tons each year, and the CO2 In the January 2014 proposal of in Coalition for Responsible Regulation emissions from even a single NGCC unit carbon pollution standards for newly v. EPA, 684 F.3d 102, 117–123 (D.C. Cir. may amount to one million or more tons constructed EGUs (79 FR 1430) and the 2012) (noting, among other things, the per year. It is not necessary in this June 2014 proposal of carbon pollution ‘‘substantial . . . body of scientific rulemaking for the EPA to decide standards for modified and evidence marshaled by EPA in support whether it must identify a specific reconstructed EGUs (79 FR 34960), the of the Endangerment Finding’’ (id. at threshold for the amount of emissions EPA proposed separate standards of 120); the ‘‘substantial record evidence from a source category that constitutes performance for new, modified, and that anthropogenic emissions of a significant contribution; under any reconstructed sources in the two greenhouse gases ‘very likely’ caused reasonable threshold or definition, the categories. The EPA took comment on warming of the climate over the last emissions from combustion turbines combining the two categories into a several decades’’ (id. at 121); and steam generators are a significant single category solely for purposes of ‘‘substantial scientific evidence . . . contribution. Indeed, these emissions the CO2 emissions from new, modified, that anthropogenically induced climate far exceed in magnitude the emissions and reconstructed affected EGUs. In change threatens both public health and from motor vehicles, which have addition, the EPA proposed codifying public welfare . . . [through] extreme already been held to contribute to the the standards of performance in the weather events, changes in air quality, endangerment. See Coalition for same Da and KKKK subparts that increases in food- and water-borne Responsible Regulation, 684 F. 3d at 121 currently contain the standards of pathogens, and increases in (‘‘substantial evidence’’ supports the performance for other pollutants from temperatures’’ (id.); and ‘‘substantial EPA’s determination ‘‘that motor- those sources addressed in the NSPS evidence . . . that the warming vehicle emissions of greenhouse gases program, but co-proposed codifying all resulting from the greenhouse gas contribute to climate change and thus to the standards of performance for CO2 emissions could be expected to create the endangerment of public health and emissions in a new 40 CFR part 60, 110 risks to water resources and in general welfare’’). subpart TTTT. to coastal areas. . . .’’ (id.)). The facts, In this rule, the EPA is combining the unfortunately, have only grown stronger U.S. (no. 14–46, June 29, 2015) slip op. pp. 10–11 steam generator and combustion turbine (reiterating Whitman holding). The EPA notes and the potential adverse consequences categories into a single category of fossil to public health and the environment further that section 111(b)(1) contains no terms such as ‘‘necessary and appropriate’’ which could fuel-fired electricity generating units for more dire in the interim. Accordingly, suggest (or, in some contexts, require) that costs purposes of promulgating standards of that approach would support an may be considered as part of the finding. Compare performance for GHG emissions. CAA section 111(n)(1)(A); see State of Michigan, endangerment finding for this Combining the two categories is 109 slip op. pp. 7–8. The EPA, of course, must consider rulemaking. costs in determining whether a best system of reasonable because they both provide emission reduction is adequately demonstrated and the same product: Electricity services. 109 Nor does the EPA consider the cost of so can form the basis for a section 111(b) standard potential standards of performance in making this of performance, and the EPA has carefully Moreover, combining them in this rule Finding. Like the Endangerment Finding under considered costs here and found them to be is consistent with our decision to section 202(a) at issue in State of Massachusetts v. reasonable. See section V. H. and I. below. The EPA combine them in the CAA section EPA, 549 U.S. 497 (2007) the pertinent issue is a also has found that the rule’s quantifiable benefits 111(d) rule for existing sources that scientific inquiry as to whether an endangerment to exceed regulatory costs under a range of public health or welfare from the relevant air assumptions were new capacity to be built. RIA accompanies this rule. In addition, pollution may reasonably be anticipated. Where, as chapter 5 and section XIII.G below. Accordingly, here, the scientific inquiry conducted by the EPA this endangerment finding would be justified if pollutant emitted in the largest volume by the indicates that these statutory criteria are met, the (against our view) it is both required, and (again, source category, and which is (necessarily) emitted Administrator does not have discretion to decline against our view) costs are to be considered as part by every affected EGU. There is, of course, no to make a positive endangerment finding to serve of the finding. requirement that standards of performance address other policy grounds. Id. at 532–35. In this regard, 110 The ‘‘air pollution’’ defined in the each component of the air pollution which an endangerment finding is analogous to setting Endangerment Finding is the atmospheric mix of endangers. Section 111(b)(1)(A) requires the EPA to national ambient air quality standards under six long-lived and directly emitted greenhouse establish ‘‘standards of performance’’ for listed section 109(b), which similarly call on the gases: Carbon dioxide (CO2), methane (CH4), nitrous source categories, and the definition of ‘‘standard of Administrator to set standards that in her oxide (N2O), hydrofluorocarbons (HFCs), performance’’ in section 111(a)(1) does not specify ‘‘judgment’’ are ‘‘requisite to protect the public perfluorocarbons (PFCs), and sulfur hexafluoride which air pollutants must be controlled. See also health’’. The EPA is not permitted to consider (SF6). See 74 FR 66496 at 66497. The standards of Section III.G below explaining that CH4 and N2O potential costs of implementation in setting these performance adopted in the present rulemaking emissions represent less than 1 percent of total standards. Whitman v. American Trucking Assn’s, address only one component of this air pollution: estimated GHG emissions (as CO2e) from fossil fuel- 531 U.S. 457, 466 (2001); see also Michigan v. EPA, CO2. This is reasonable, given that CO2 is the air fired electric power generating units.
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many of the monitoring, reporting, and generator capable of supplying more units must burn fossil fuels for more verification requirements are the same than 25 MW net to a utility distribution than 10 percent of the unit’s total heat for both source categories, and, as system (i.e., for sale to the grid).113 input, on average, over a 3-year 114 discussed next, we are codifying all However, we are not finalizing CO2 period. Under the proposed requirements in a single new subpart of standards for certain EGUs. The EGUs approach, applicability under the final the regulations; as a result, combining that are not covered by the standards we NSPS for CO2 emissions could have the two categories into a single category are finalizing in this rule include: (1) changed on an annual basis depending will reduce confusion. It should be Non-fossil fuel units subject to a on the composition of fuel burned. We noted that in this rule, we are not federally enforceable permit that limits solicited comment on several aspects of combining the two categories for the use of fossil fuels to 10 percent or the proposed applicability criteria for purposes of standards of performance less of their heat input capacity on an non-fossil fuel units. Specifically, we for other air pollutants. annual basis; (2) combined heat and solicited comment on a broad Because these two source categories power (CHP) units that are subject to a applicability approach that would are pre-existing listed source categories federally enforceable permit limiting include non-fossil fuel-fired units as and the EPA will not be subjecting any annual net-electric sales to no more than affected units, but that would impose an additional sources in the categories to the unit’s design efficiency multiplied alternate standard when the unit fires CAA regulation for the first time, the by its potential electric output, or fossil fuels for 10 percent or less of the combination of these two categories is 219,000 MWh or less, whichever is heat input during the 3-year not considered a new source category greater; (3) stationary combustion applicability-determination period. We subject to the listing requirements of turbines that are not physically capable solicited comment on whether, if such CAA section 111(b)(1)(A). As a result, of combusting natural gas (e.g., not a subcategory is warranted, the this final rule does not list a new connected to a natural gas pipeline); (4) applicability-determination period for category under CAA section utility boilers and IGCC units that have the subcategory should be 1-year or a 3- 111(a)(1)(A), nor does this final rule always been subject to a federally year rolling period. We also solicited revise either of the two source enforceable permit limiting annual net- comment on whether the standard for categories. Thus, the EPA is not electric sales to one-third or less of their such a subcategory should be an required to make a new endangerment potential electric output (e.g., limiting alternate numerical limit or ‘‘no and contribution finding for the hours of operation to less than 2,920 emission standard.’’ combination of the two categories,111 hours annually) or limiting annual While the proposed exemption although as discussed in the previous electric sales to 219,000 MWh or less; applied to all non-fossil fuels, most section, the evidence strongly supports (5) municipal waste combustors that are commenters focused on biomass- such findings. Thus, the EPA has found, subject to subpart Eb of this part; and (6) specific issues. Many commenters in the alternative, that this category of commercial or industrial solid waste supported an exclusion for biomass- sources contributes significantly to air incineration units subject to subpart fired units that fire no more than 10 pollution which may be reasonably CCCC of this part. percent fossil fuels. Some commenters anticipated to endanger public health suggested that the exclusion for D. Units Not Covered by This Final Rule and welfare. biomass-fired units should be raised to As described in the previous section, a 25 percent fossil fuel-use threshold. C. Affected Units the EPA is not issuing standards of Many commenters supported the We generally refer to fossil fuel-fired performance for certain types of proposed 3-year averaging period for the electric generating units that would be sources—specifically, dedicated non- fossil fuel-use criterion because it subject to a CAA section 111 emission fossil fuel-fired (e.g., biomass) units and provides greater flexibility for operators standard as ‘‘affected’’ or ‘‘covered’’ industrial CHP units, as well as certain to use fossil fuels when supply chains sources, units, facilities or simply as projects under development. This for the primary non-fossil fuels are EGUs. An EGU is any boiler, IGCC unit, section discusses these sources and our disrupted, during unexpected or combustion turbine (in either simple rationale for not issuing standards for malfunctions of the primary non-fossil cycle or combined cycle configuration) them. Because the rationale applies to fuel handling systems, or when the that meets the applicability criteria. both steam generating units and unit’s maximum generating capacity is Affected EGUs include those that combustion turbines, we are describing required by system operators for commenced construction after January it here rather than in the separate steam reliability reasons. Many commenters 8, 2014, and meet the specified generating unit and combustion turbine supported the 3-year averaging period applicability criteria and, for discussions. We discuss the proposed because it is consistent with the final modifications and reconstructions, applicability criteria, the topics where requirements under the EPA’s Mercury EGUs that commenced those activities the agency solicited comment, a brief and Air Toxics Standards (MATS) and after June 18, 2014, and meet the summary of the relevant comments, and would allow non-fossil fuel-fired units specified applicability criteria. the rationale for the final applicability to use some fossil fuels for flame To be considered an EGU, the unit approach for these sources. stabilization without triggering must: (1) Be capable of combusting more applicability. Some commenters than 250 MMBtu/h (260 GJ/h) heat 1. Dedicated Non-fossil Fuel Units requested that the EPA clarify the input of fossil fuel; 112 and (2) serve a The proposed applicability for newly method an operator should use during constructed EGUs included those that the first 3 years of operations to 111 See, e.g., American Trucking Assn’s v. EPA, primarily combust fossil fuels (e.g., coal, determine if a particular unit will meet 175 F.3d 1027, 1055, rev’d on other grounds sub. oil, and natural gas). The proposed the 10 percent fossil fuel-use threshold. nom. Whitman v. Am. Trucking Assn’s, 531.U.S. applicability criteria were that affected Others asked whether or not an affected 457 (because fine particulate matter (PM2.5) was facility has a compliance obligation already included as a sub-set of the listed pollutant particulate matter, it was not a new pollutant criterion.’’ Note that 250 MMBtu/h is equivalent to during the first 3-year period and, if an necessitating a new listing). 73 MW or 260 GJ/h heat input. 112 We refer to the capability to combust 250 113 We refer to the capability to supply 25 MW 114 We refer to the fraction of heat input derived MMBtu/h of fossil fuel as the ‘‘base load rating net to the grid as the ‘‘total electric sales criterion.’’ from fossil fuels as the ‘‘fossil fuel-use criterion.’’
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affected facility does not meet the 10 the requirements in this rulemaking. encouraging capital investments in percent fossil fuel-use threshold during Similarly, an existing unit that takes a highly efficient and reliable distributed several 12-month periods during the permit limitation restricting fossil-fuel generation technologies. These first 3 years, whether compliance use would no longer be an affected unit commenters recommended that the EPA calculations would be required for such for the purposes of 111(d) state plans. adopt an explicit exemption for CHP 12-month periods. Other commenters This is consistent with our intent to units at facilities that are classified as had concerns with the 3-year averaging reduce GHG emissions from fossil fuel- industrial (e.g., gas-fired CHPs within period, stating that a source would no fired EGUs. SIC codes 2911—petroleum refining, longer be subject to the NSPS if it fell We considered using either an annual 13—oil and gas extraction, and other below the threshold for any of the or 3-year average for calculating industrial SIC codes as appropriate). applicability metrics that the EPA compliance with the final fossil fuel-use They also stated that the EPA should proposed to calculate on a 3-year (or, in criterion. Ultimately, we concluded that exclude CHP units that have an energy some cases, annual) basis. They argued an annual average would provide savings of 10 percent or more compared that this would create a situation in sufficient flexibility for dedicated non- to separate heat and power. One which no one would know whether a fossil units to combust fossil fuels for commenter suggested that the final rule particular plant will be subject to the flame stabilization and other ancillary should cover only industrial- standards until years after the emissions purposes, while maintaining commercial-institutional CHP units that had already occurred. Some consistency with the 12-month supply, on a net basis, more than two- commenters were concerned that plants compliance periods used for most thirds of their potential combined operating near the threshold could move permit limitations. A 3-year average thermal and electric energy output and in and out of the regulatory system, potentially would allow units to more than 450,000 MWh net-electric which would provide complications for combust a significant quantity of fuels output to a utility power distribution compliance, enforcement, and in a given year, leading to higher CO2 system on an annual basis for five permitting. emissions, so long as they curtailed consecutive calendar years. The fossil-fuel use in a later year. This After considering these comments, the commenter also suggested that CHP would defeat the purpose of the EPA has concluded that the proposed units which have total thermal energy criterion, which is to exempt dedicated production that approaches or exceeds fossil fuel-use criterion based on the non-fossil units only. Finally, we are their total electricity production should actual amount of fossil fuel burned is finalizing the 10 percent fossil-fuel use be exempted. not an ideal approach to determine threshold in relation to a unit’s heat Other commenters suggested applicability. As commenters pointed input capacity rather than its actual heat exempting CHP units by fuel type or out, facilities, permitting authorities, input, which is consistent with past based on the definition of potential and the public would not know when approaches we have taken under the electric output. For example, some construction is commenced whether a industrial boiler criteria pollutant NSPS. commenters suggested modifying the facility will be subject to the final NSPS, percentage electric sales threshold to be 2. Industrial CHP Units and after operation has commenced, a based on net system efficiency unit could move in and out of Another approach to generating (including useful thermal output) rather applicability each year. The intent of electricity is the use of CHP units. A than the rated net-electric-output this rulemaking is to establish CO2 CHP unit can use a boiler, combustion efficiency. They also suggested that the standards for fossil fuel-fired EGUs, not turbine, reciprocating engine, or various applicability criteria should use a for non-fossil fuel-fired EGUs. other generating technologies to default efficiency of 50 percent for CHP Therefore, to simplify compliance and generate electricity and useful thermal units. Some commenters suggested that establish CO2 standards for only those energy in a single, integrated system. a CHP unit should not be considered an sources which we set out to regulate, we CHP units are generally more efficient affected EGU if 20 percent or more of its are finalizing a fossil fuel-use criterion than conventional power plants because total gross or net energy output that will exempt dedicated non-fossil the heat that is normally wasted in a consisted of useful thermal output on a units. Specifically, units that are conventional power generation cooling 3-year rolling average basis. Other capable of burning 50 percent or more system (e.g., cooling towers) is instead commenters said that highly efficient non-fossil fuel are exempt from the final recovered as useful thermal output. CHP units that achieve an overall standards so long as they are subject to While the EPA did propose some efficiency level of 60 to 70 percent or a federally enforceable permit that applicability provisions specific to CHP higher should be excluded from limits their use of fossil fuels to 10 units (e.g., subtract purchased power of applicability. percent or less of their heat input adjacent facilities when determining The intent of this rulemaking is to capacity on an annual basis. This total electric sales), in general, the cover only utility CHP units, because approach establishes clear applicability proposed applicability criteria for they serve essentially the same purpose criteria and avoids the prospect of units electric-only units and CHP units were as electric-only EGUs (i.e., the sale of moving in and out of applicability based similar. The intent of the proposed total electricity to the grid). Industrial CHP on their actual fuel use in a given year. and percentage electric sales criteria units, on the other hand, serve a Consistent with the applicability was to cover only utility CHP units, not different primary purpose (i.e., approach in the steam generating unit industrial CHP units. To the extent that providing useful thermal output with criteria pollutant NSPS, subpart Da, the the proposal’s applicability provisions electric sales as a by-product). With final fossil fuel-use criterion does not would have the effect of covering these facts in mind and after include ‘‘constructed for the purpose industrial CHP units, we solicited considering the comments, the EPA has of’’ language. Therefore, an owner or comment on an appropriate concluded that it is appropriate to operator could change a unit’s applicability exemption, and the criteria consider two factors for the final CHP applicability in the future by seeking a for that exemption, for highly efficient exemption: (1) Whether the primary modification of the unit’s permit CHP facilities. purpose of the CHP unit is to provide conditions. A unit with the appropriate Many commenters supported the useful thermal output rather than permit limitation will not be subject to exclusion of CHP units as a means of electricity and (2) whether the CHP unit
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is highly efficient and thus achieves meet the efficiency exemption criterion is greater. This final applicability environmental benefits. and would still cover many combustion criterion will only cover CHP units that We rejected many of the approaches turbine-based industrial CHP units. condense a significant portion of steam suggested by the commenters because Conversely, while an exemption based generated by the unit and use the they did not achieve one or both of the on fuel savings relative to separate heat electric power generated as a result of factors we identified. Specifically, the and power would recognize the condensing that steam to supply electric EPA has concluded that SIC code environmental benefit of highly efficient power to the grid. CHP facilities that do classification is not a sufficient CHP units, it would not consider the not have a condensing steam turbine indicator of the purpose (i.e., it does not primary purpose of the CHP unit. (e.g., combustion turbine-based CHP correlate to useful thermal output) or In the end, the EPA has concluded units without a steam turbine and environmental benefits (i.e., efficiency) that maintaining the proposed boiler-based systems with a of a unit. Further, an exemption based percentage electric sales criterion with backpressure steam turbine) would on SIC code could result in two adjustments addresses both factors generally not be physically capable of circumvention of the intended with which we are concerned. First, we selling enough electricity to meet the applicability. For example, this are changing the definition of ‘‘potential applicability criterion, even if they sold approach would allow a new EGU to electric output’’ to be based on overall 100 percent of the electricity generated locate near an industrial site, provide a net efficiency at the maximum electric and did not subtract out the electricity trivial amount of useful thermal output production rate, instead of just electric- used by the thermal host(s). The EPA to that site, sell electricity to the grid, only efficiency. Second, we are has concluded that this is appropriate and nonetheless avoid applicability. changing the percentage electric sales because these sources are industrial by Similarly, increasing the electric sales criterion to reflect the sliding scale, design and provide mostly useful criteria to two-thirds of potential which is the overall design efficiency, thermal output. electric output and 450,000 MWh would calculated at the maximum useful CHP facilities with a steam extraction essentially amount to a blanket thermal rating of the CHP unit (e.g., a condensing steam turbine will exemption that tells us nothing about CHP unit with a extraction condensing determine their potential electric output the primary purpose or efficiency of the steam turbine would determine the based on their efficiency on a net basis unit. efficiency at the maximum extraction/ at the maximum electric production rate On the other hand, exemptions based bypass rate), of the unit multiplied by at the base load heat input rating (e.g., on useful thermal output being greater the unit’s potential electric output the CHP is condensing as much steam than 20 percent of total output, thermal instead of one-third of potential electric as possible to create electricity instead output being greater than electric output as proposed. This approach of using it for useful thermal output). output, or overall design efficiency recognizes the primary purpose of We have concluded that it is necessary value would identify whether the industrial CHP units by providing a for CHP units with extraction primary purpose of a unit is to generate more generous percentage electric sales condensing steam turbines to calculate thermal output, but they would not exemption to CHP units with high their potential electric output at the recognize the environmental benefits of thermal output. As described maximum condensing level to avoid highly efficient CHP units. While previously, CHP units with high thermal circumvention of the applicability overall efficiency may appear to be a loads tend to be more efficient and will criteria. For example, to avoid good indicator of environmental therefore have a higher allowable applicability a CHP unit could locate benefits, this is not always the case with percentage electric sales. By amending next to an industrial host and have the CHP units. Overall efficiency is a both the definition of ‘‘potential electric capability of selling significant function of both efficient design and the output’’ and the electric sales threshold, quantities of useful thermal output power to heat ratio (the amount of we assure that CHP units that primarily without ever actually intending to electricity relative to the amount of produce useful thermal output are supply much, if any, useful thermal useful thermal output). For example, exempted as industrial CHP units even output to the industrial host. If we boiler-based CHP units tend to produce if they are selling all of their electric calculated the potential electric output large amounts of useful thermal output output to the grid. As the relative at the maximum level of thermal output, relative to electric output and tend to amount of electricity generated by the this type of CHP unit could operate at have high overall efficiencies. For units CHP unit increases, efficiency will full condensing mode at base load producing primarily useful thermal generally decrease, thus limiting conditions for the entire year and still output, the equivalent separate heat and allowable electric sales before not exceed the electric sales threshold. power efficiency (i.e., the theoretical applicability is triggered. This approach During the permitting process, the overall efficiency if the electricity and also recognizes the environmental owner or operator will be able to useful thermal output were produced by benefits of increased efficiency by determine if the unit is subject to the a stand-alone EGU and stand-alone encouraging industrial CHP units to be final standards in this rule. boiler) would approach that of a stand- designed as efficiently as possible to New EGUs with only limited useful alone boiler (e.g., 80 percent). However, take advantage of the higher electric thermal output will be subject to the combustion turbine-based CHP units sales permitted by the sliding scale. final standards, but the vast majority of tend to produce relatively equal In conclusion, a CHP unit will be an new CHP units will be classified as amounts of electricity and useful affected source unless it is subject to a industrial CHP and will not be subject thermal output. In this case, the federally enforceable permit that limits to the final standards. The EPA has equivalent separate heat and power annual total electric sales to less than or concluded that this approach is similar efficiency would be closer to 65 percent. equal to the unit’s design efficiency to exempting CHP facilities that sell less Therefore, an exemption based on multiplied by its potential electric than half of their total output (electricity overall efficiency is not an indication of output or 219,000 MWh,115 whichever plus thermal), but has the benefit of the fuel savings a CHP unit will achieve accounting for overall design efficiency. relative to separate heat and power. 115 The EPA has concluded that it is appropriate Further, this approach would encourage to maintain the 219,000 MWh total electric sales avoid potentially covering smaller industrial CHP the development of CHP units that just criterion for combustion turbine based CHP units to units.
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This approach both limits applicability percent coal refuse on an annual basis. units without CCS. Specifically, we are to the industrial CHP units and Multiple commenters supported the not finalizing CO2 standards for encourages the installation of the most exemption, citing numerous industrial CHP units. Many existing coal efficient CHP systems because more environmental benefits of remediating refuse-fired units are relatively small efficient designs will be able to have coal refuse piles. Observing that coal and designed as CHP units. Due to the higher permitted electric sales while not refuse-fired EGUs typically use expense of transporting coal refuse long being subject to the CO2 standards fluidized bed technologies, other distances, we anticipate that any new included in this rulemaking. commenters disagreed with any coal refuse-fired EGU would be exemption, specifically citing the N O 3. Municipal Waste Combustors and 2 relatively small in size. Moreover, sites emissions from fluidized bed boilers. In Commercial and Industrial Solid Waste with sufficient thermal demand exist light of the environmental benefits of Incinerators such that the unit could be designed as remediating coal refuse piles cited by an industrial CHP facility and the The purpose of this rulemaking is to commenters, the limited amount of coal requirements of this rule would not establish CO2 standards for fossil fuel- refuse, and the fact that a new coal apply. fired EGUs. Municipal waste refuse-fired EGU would be located in combustors and commercial and close proximity to the coal refuse pile, F. Format of the Output-Based Standard industrial solid waste incinerators we sought additional comments 1. Net and Gross Output-Based typically have not been included in this regarding a subcategory for coal refuse- Standards source category. Therefore, even if one fired EGUs in the January 2014 For all newly constructed units, the of these types of units meets the general proposal. Specifically, we requested heat input and electric sales criteria, we EPA proposed standards as gross output additional information on the net emission rates consistent with current are not finalizing CO2 emission environmental benefits of coal refuse- monitoring and reporting requirements standards for municipal waste fired EGUs and information to support under 40 CFR part 75.116 For a non-CHP combustors subject to subpart Eb of this an appropriate emissions standard for EGU, gross output is the electricity part and commercial and industrial coal refuse-fired EGUs. One commenter generation measured at the generator solid waste incinerators subject to on the April 2012 proposal stated that terminals. However, we solicited subpart CCCC of this part. existing coal refuse piles are naturally comment on finalizing equivalent net- combusting at a rate of 0.3 percent 4. Certain Projects Under Development output-based standards either as a annually, and we requested comment on compliance alternative or in lieu of the The EPA proposed that a limited class this rate and the proper approach to proposed gross-output-based standards. of projects under development should account for naturally occurring not be subject to the proposed emissions from coal refuse piles in the Net output is the gross electrical output standards. These were planned sources January 2014 proposal. less the unit’s total parasitic (i.e., that may be capable of commencing Commenters said that a performance auxiliary) power requirements. A construction (within the meaning of standard is not feasible for coal refuse parasitic load for an EGU is a load or section 111(a)) shortly after the CFBs since there is no economically device powered by electricity, steam, hot water, or directly by the gross standard’s proposal date, and so would feasible way to capture CO2 through a be classified as new sources, but which conveyance designed and constructed to output of the EGU that does not contribute electrical, mechanical, or have a design which would be incapable capture CO2. Commenters suggested that of meeting the proposed standard of the EPA establish BSER for GHGs at useful thermal output. In general, performance. See 79 FR 1461 and CAA modified coal refuse CFBs as a boiler parasitic energy demands include less section 111(a)(2). The EPA proposed tune-up that must be performed at least than 7.5 percent of non-IGCC and non- that these sources would not be subject every 24 months. Commenters stated CCS coal-fired station power output, to the generally-applicable standard of that the EPA should exempt coal refuse approximately 15 percent of non-CCS performance, but rather would be CFB units relative to their CO2 IGCC-based coal-fired station power subject to a unit-specific permitting emissions to the extent that these units output, and about 2.5 percent of non- determination if and when construction offset the uncontrolled ground level CCS NGCC power output. The use of actually commences. The EPA indicated emissions from spontaneous CCS increases both the electric and that there could be three sources to combustion of legacy coal refuse steam parasitic loads used internal to which this approach could apply, and stockpiles and noted that the mining of the unit, and these outputs are not further indicated that the EPA could coal waste not only produces less considered when determining the ultimately adopt the generally- emissions in the long term, but also emission rate. Net output is used to applicable standard of performance for helps to reclaim land that is currently recognize the environmental benefits of: these sources (if actually constructed). used to store coal waste. In contrast, one (1) EGU designs and control equipment 79 FR 1461. commenter saw no legitimate basis for that use less auxiliary power; (2) fuels As explained at Section III.J below, coal refuse to be subcategorized and that require less emissions control the EPA is finalizing this approach in stated that it should be treated in the equipment; and (3) higher efficiency this final rule. We again note that these same manner as all other coal-fired motors, pumps, and fans. For modified sources, if and when constructed, could EGUs. and reconstructed combustion turbines, be ultimately subject to the 1,400 lb The EPA has concluded that an the EPA also proposed standards as CO2/MWh-g standard, especially if there explicit exemption or subcategory gross output emission rates, but is no engineering basis, or demonstrated specifically for coal refuse-fired EGUs is solicited comment on finalizing net action in reliance, showing that the new not appropriate. The costs faced by coal output standards. The rationale was that source could not meet that standard. refuse facilities to install CCS are due to the low auxiliary loads in non- similar to coal-fired EGUs burning any CCS NGCC designs, the difference E. Coal Refuse of the primary coals, and the final between a gross-output standard and a In the April 2012 proposal, we applicable requirements and standards net-output standard has a limited solicited comment on subcategorizing in the rule do not preclude the and exempting EGUs that burn over 75 development of new coal refuse-fired 116 79 FR 1447–48.
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impact on environmental performance. strictly require compliance on a net by commenters, the EPA is finalizing Auxiliary loads are more significant for output-basis. They believe that this is the CO2 standard for combustion turbine modified and reconstructed boilers and the only way for the standards to EGUs in a format that is similar to the IGCC units, and the EPA proposed minimize the carbon footprint of the current NSPS format for criteria standards on a net output basis for these electricity delivered to consumers. pollutants. The default final standards units. The rationale included that this These commenters believe that, at a establish a gross-output-based standard. would enable owners/operators of these minimum, net-output-based standards This allows owners/operators of new types of units to pursue projects that should be included as an option in the combustion turbines to comply with the reduce auxiliary loads for compliance final rule. CO2 emissions standard under part 60 purposes. However, the EPA solicited We are only finalizing gross-output- using the same data currently collected comment on finalizing the standards on based standards for utility boilers and under part 75.117 However, many a gross-output basis. We also proposed IGCC units. Providing an alternate net- permitting authorities commented to use either gross-output or net-output output-based standard that is based on persuasively that the environmental bases for each respective subcategory of gross-output-based emissions data and benefits of using net-output-based EGUs (i.e., utility boilers, IGCC units, an assumed auxiliary load is most standards can outweigh any additional and combustion turbines) consistently appropriate when the auxiliary load can complexities for particular units, and across all CAA section 111(b) standards be reasonably estimated and the choice have indeed adopted net-output for new, modified, and reconstructed between the net- and gross-output-based standards in recent GHG operating EGUs. standard will not impact the identified permits for combustion turbines. We Many commenters supported gross- BSER. For example, the auxiliary load expect this trend to continue and have output-based standards, maintaining for combustion turbines is relatively concluded that it is appropriate to that a net-output standard penalizes the fixed and small, approximately 2.5 support the expanded use of net-output- operation of air pollution control percent, so the choice between a gross based standards, and therefore are equipment. Several commenters and net-output-based standard will not allowing certain sources to elect disagreed with the agency’s proposed substantially impact technology choices. between gross output-based and net- rationale that a net-output standard However, in the case of utility boilers, output-based standards. Only would provide incentive to minimize we have concluded that we do not have combustion turbines are eligible to make auxiliary loads. The commenters believe sufficient information to establish an this election. utility commissions and existing appropriate net-output-based standard The rule specifies an alternative net- economic forces already provide that would not impact the identified output-based standard of 1,030 lb CO2/ utilities with appropriate incentives to BSER for these types of units. The BSER MWh-n for combustion turbines. This properly manage all of these factors. for newly constructed steam generating standard is equivalent to the otherwise- Some commenters supported a gross- units is based on the use of partial CCS. applicable gross-output-based standard output-based standard because However, unlike the case for 118 of 1,000 lb CO2/MWh-g. variations in site conditions (e.g., combustion turbines, owners/operators The procedures for requesting this available natural gas pressure, available of utility boilers have multiple alternative net-output-based standard cooling water sources, and elevation) technology pathways available to require the owner or operator to petition will likely penalize some owners and comply with the actual emission the Administrator in writing to comply benefit others simply through variations standard. The choice of both control with the alternate applicable net-output- in their particular plant-site conditions technologies and fuel impact the overall based standard. If the Administrator if a net basis is used. Several auxiliary load. For example, a coal-fired grants the petition, this election would commenters stated that if the final rule hybrid EGU (e.g., one that includes be binding and would be the unit’s sole includes a net-output-based standard, it integrated solar thermal equipment for means of demonstrating compliance. should be included as an option in feedwater heating or steam Owners or operators complying with the conjunction with a gross-output-based augmentation) or a coal-fired EGU co- net-output-based standard must option. firing natural gas would have lower similarly petition the Administrator to Several commenters opposed net- non-CCS related auxiliary loads and, switch back to complying with the output-based standards because they because the amount of CCS needed to gross-output-based standard. believe it is difficult to accurately comply with the standard would also be determine the net output of an EGU. smaller, the CCS auxiliary loads would 2. Useful Thermal Output They pointed out that many facilities also be reduced. Therefore, we cannot For CHP units, useful thermal output have transformers that support multiple identify an appropriate assumed is also used when determining the units at the facility, making unit-level auxiliary load to establish an equivalent emission rate. Previous rulemakings reporting difficult. These commenters net-output-based standard. In addition, issued by the EPA have prescribed also stated that station electric services many IGCC facilities (which could be various ‘‘discount factors’’ of the may come from outside sources to used as an alternative technology for measured useful thermal output to be supply certain ancillary loads. One complying with the standard of used when determining the emission commenter stated that the benefit of performance; see Sections IV.B and V.P rate. We proposed that 75 percent credit switching to net-output-based standards below) have been proposed or are is the appropriate discount factor for would be small and would not justify envisioned as co-production facilities useful thermal output, and we solicited the substantial complexities in both (i.e., to produce useful by-products and defining and implementing such a chemicals along with electricity). As 117 Additionally, having an NSPS standard that is standard. Conversely, other commenters noted in the proposal, we have measured using the same monitoring equipment as stated that net-metering is a well- concluded that predicting the net required under the operating permit minimizes established technology that should be electricity at these co-production compliance burden. If a combustion turbine were required, particularly for newly facilities would be more challenging to subject to both a gross and net emission limit, more expensive higher accuracy monitoring could be constructed units. implement under these circumstances. required for both measurements. Other commenters, however, In contrast, based on further 118 Assuming a 3 percent auxiliary load for the maintained that the final rule should evaluation and review of issues raised NGCC system.
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comment on a range from two-thirds to GHGs, the air pollutant regulated in this sizes within categories of new sources three-fourths credit for useful thermal rule is GHGs.121 for the purpose of establishing such output in the proposal for newly standards.’’ CAA section 111(b)(2). The H. Legal Requirements for Establishing constructed units and two-thirds to one term ‘‘standard of performance’’ is Emission Standards hundred percent credit in the proposal defined to ‘‘mean[ ] a standard for for modified and reconstructed units. 1. Introduction emissions . . . achievable through the application of the best system of The 75 percent credit was based on In the January 2014 proposal, we emission reduction which [considering matching the emission rate, but not the described the principal legal cost, non-air quality health and overall emissions, of a hypothetical CHP requirement for standards of environmental impact, and energy unit to the proposed emission rate. performance under CAA section 111(b), requirements] the Administrator Many commenters said that in order which is that the standards of determines has been adequately to fully account for the environmental performance must consist of standards demonstrated.’’ CAA section 111(a)(1). benefits of CHP and to reflect the for emissions that reflect the degree of environmental benefits of CHP, the EPA As noted in the January 2014 emission limitation achievable though proposal, Congress first included the should allow 100 percent of the useful the application of the ‘‘best system of definition of ‘‘standard of performance’’ thermal output from CHP units. emission reduction . . . adequately when enacting CAA section 111 in the Commenters noted that providing 100 demonstrated,’’ taking into account cost 1970 Clean Air Act Amendments percent credit for useful thermal output and any non-air quality health and (CAAA), amended it in the 1977 CAAA, is consistent with the past practice of environment impact and energy and then amended it again in the 1990 the EPA in the stationary combustion requirements. We noted that the D.C. CAAA to largely restore the definition turbine criteria pollutant NSPS and state Circuit has handed down numerous as it read in the 1970 CAAA. It is in the approaches for determining emission decisions that interpret this CAA legislative history for the 1970 and 1977 rates for CHP units. provision, including its component CAAAs that Congress primarily Based on further consideration and elements, and we reviewed that case addressed the definition as it read at review of the comments submitted, we law in detail.122 those times, and that legislative history are finalizing 100 percent credit for We received comments on our provides guidance in interpreting this useful thermal output for all newly proposed interpretation, and in light of provision.124 In addition, the D.C. constructed, modified, and those comments, in this rule, we are Circuit has reviewed rulemakings under reconstructed CHP sources. We have clarifying our interpretation in certain CAA section 111 on numerous concluded that this is appropriate respects. We discuss our interpretation occasions during the past 40 years, because, at the same reported emission below.123 handing down decisions dated from rate, a hypothetical CHP unit would 2. CAA Requirements and Court 1973 to 2011,125 through which the have the same overall GHG emissions as Interpretation the combined emission rate of separate 124 In the 1970 CAAA, Congress defined heat and power facilities. Any As noted above, the CAA section 111 ‘‘standard of performance,’’ under section 111(a)(1), discounting of useful thermal output requirements that govern this rule are as as—a standard for emissions of air pollutants which follows: As the first step towards reflects the degree of emission limitation achievable could distort the market and discourage through the application of the best system of the development of new CHP units. Full establishing standards of performance, emission reduction which (taking into account the credit for useful thermal output the EPA ‘‘shall publish . . . a list of cost of achieving such reduction) the Administrator appropriately recognizes the categories of stationary sources . . . determines has been adequately demonstrated. [that] cause[ ], or contribute[ ] In the 1977 CAAA, Congress revised the environmental benefit of CHP. definition to distinguish among different types of significantly to, air pollution which may sources, and to require that for fossil fuel-fired G. CO2 Emissions Only reasonably be anticipated to endanger sources, the standard: (i) Be based on, in lieu of the The air pollutant regulated in this public health or welfare.’’ CAA section ‘‘best system of emission reduction . . . adequately 111(b)(1)(A). Following that listing, the demonstrated,’’ the ‘‘best technological system of final action is greenhouse gases. continuous emission reduction . . . adequately However, the standards in this rule are EPA ‘‘shall publish proposed demonstrated;’’ and (ii) require a percentage expressed in the form of limits on only regulations, establishing federal reduction in emissions. In addition, in the 1977 standards of performance for new CAAA, Congress expanded the parenthetical emissions of CO2, and not the other requirement that the Administrator consider the constituent gases of the air pollutant sources within such category’’ and then cost of achieving the reduction to also require the GHGs.119 We are not establishing a limit ‘‘promulgate . . . such standards’’ Administrator to consider ‘‘any nonair quality on aggregate GHGs or separate emission within a year after proposal. CAA health and environment impact and energy requirements.’’ limits for other GHGs (such as methane section 111(b)(1)(B). The EPA ‘‘may distinguish among classes, types, and In the 1990 CAAA, Congress again revised the (CH4) or nitrous oxide (N2O)) as other definition, this time repealing the requirements that GHGs represent less than 1 percent of the standard of performance be based on the best 121 See 77 FR 31257–30 (June 3, 2010). technological system and achieve a percentage total estimated GHG emissions (as CO2e) 122 79 FR 1430, 1462 (January 8, 2014). reduction in emissions, and replacing those from fossil fuel-fired electric power 123 We also discuss our interpretation of the provisions with the terms used in the 1970 CAAA 120 generating units. Notwithstanding requirements for standards of performance and the version of section 111(a)(1) that the standard of this form of the standard, consistent BSER under section 111(d), for existing sources, in performance be based on the ‘‘best system of with other EPA regulations addressing the section 111(d) rulemaking that the EPA is emission reduction . . . adequately demonstrated.’’ finalizing with this rule. Our interpretations and This 1990 CAAA version is the current definition. applications of these requirements in the two Even so, because parts of the definition as it read 119 As noted above, in the Endangerment Finding, rulemakings are generally consistent with each under the 1977 CAAA were retained in the 1990 the EPA defined the relevant ‘‘air pollution’’ as the other except to the extent that they reflect CAAA, the explanation in the 1977 CAAA atmospheric mix of six long-lived and directly- distinctions between new and existing sources. For legislative history, and the interpretation in the case emitted greenhouse gases: carbon dioxide (CO2), example, the BSER for new industrial facilities, law, of those parts of the definition in the case law methane (CH4), nitrous oxide (N2O), which are expected to have lengthy useful lives, remain relevant to the definition as it reads today. hydrofluorocarbons (HFCs), perfluorocarbons should include, at a minimum, the most advanced 125 Portland Cement Ass’n v. Ruckelshaus, 486 (PFCs), and sulfur hexafluoride (SF6). 74 FR 66497. pollution controls available, but for existing F.2d 375 (D.C. Cir. 1973); Essex Chemical Corp. v. 120 EPA Greenhouse Gas Reporting Program; sources, the additional costs of retrofit may render Ruckelshaus, 486 F.2d 427, (D.C. Cir. 1973); www.epa.gov/ghgreporting/. those controls too expensive. Continued
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Court has developed a body of case law rulemaking, the EPA focused on of achieving’’ the required emission that interprets the term ‘‘standard of efficient generation, add-on controls, reductions. As described in the January performance.’’ efficiency improvements, and clean 2014 proposal,135 in several cases the fuels as the systems of emission D.C. Circuit has elaborated on this cost 3. Key Elements of Interpretation reduction. factor and formulated the cost standard By its terms, the definition of An ‘‘adequately demonstrated’’ in various ways, stating that the EPA ‘‘standard of performance’’ under CAA system, according to the D.C. Circuit, is may not adopt a standard the cost of section 111(a)(1) provides that the ‘‘one which has been shown to be which would be ‘‘exorbitant,’’ 136 emission limits that the EPA reasonably reliable, reasonably efficient, ‘‘greater than the industry could bear promulgates must be ‘‘achievable’’ by and which can reasonably be expected and survive,’’ 137 ‘‘excessive,’’ 138 or application of a ‘‘system of emission to serve the interests of pollution ‘‘unreasonable.’’ 139 For convenience, in reduction’’ that the EPA determines to control without becoming exorbitantly this rulemaking, we use ‘reasonableness’ be the ‘‘best’’ that is ‘‘adequately costly in an economic or environmental to describe costs well within the bounds demonstrated,’’ ‘‘taking into account way.’’ 130 It does not mean that the established by this jurisprudence.140 . . . cost . . . nonair quality health and system ‘‘must be in actual routine use The D.C. Circuit has indicated that the environmental impact and energy somewhere.’’ 131 Rather, the Court has EPA has substantial discretion in its requirements.’’ The D.C. Circuit has said, ‘‘[t]he Administrator may make a consideration of cost under section stated that, in determining the ‘‘best’’ projection based on existing technology, 111(a). In several cases, the Court system, the EPA must also take into though that projection is subject to the upheld standards that entailed account ‘‘the amount of air restraints of reasonableness and cannot significant costs, consistent with pollution’’ 126 reduced and the role of be based on ‘crystal ball’ inquiry.’’ 132 Congress’s view that ‘‘the costs of ‘‘technological innovation.’’ 127 The Similarly, the EPA may ‘‘hold the applying best practicable control Court has emphasized that the EPA has industry to a standard of improved technology be considered by the owner discretion in weighing those various design and operational advances, so of a large new source of pollution as a factors.128 129 long as there is substantial evidence that normal and proper expense of doing Our overall approach to determining such improvements are feasible.’’ 133 business.’’ 141 See Essex Chemical Corp. the BSER, which incorporates the Ultimately, the analysis ‘‘is partially v. Ruckelshaus, 486 F.2d 427, 440 (D.C. various elements, is as follows: First, the dependent on ‘lead time,’ ’’ that is, ‘‘the Cir. 1973); 142 Portland Cement EPA identifies the ‘‘system[s] of time in which the technology will have Association v. Ruckelshaus, 486 F.2d emission reduction’’ that have been to be available.’’ 134 Per CAA section 375, 387–88 (D.C. Cir. 1973); Sierra Club ‘‘adequately demonstrated’’ for a 111(e), standards of performance under v. Costle, 657 F.2d 298, 313 (D.C. Cir. particular source category. Second, the CAA section 111(b) are applicable EPA determines the ‘‘best’’ of these immediately after the effective date of 135 79 FR 1464 (January 8, 2014). systems after evaluating extent of their promulgation. 136 Lignite Energy Council v. EPA, 198 F.3d 930, emission reductions, costs, any non-air 933 (D.C. Cir. 1999). (1) Technical Feasibility of the Best 137 health and environmental impacts, and Portland Cement Ass’n v. EPA, 513 F.2d 506, System of Emission Reduction 508 (D.C. Cir. 1975). energy requirements. And third, the 138 Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. EPA selects an achievable standard for As the January 2014 proposal Cir. 1981). emissions—here, the emission rate— indicates, the requirement that the 139 Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. based on the performance of the BSER. standard for emissions be ‘‘achievable’’ Cir. 1981). The remainder of this subsection based on the ‘‘best system of emission 140 These cost formulations are consistent with discusses the various elements in that reduction . . . adequately the legislative history of section 111. The 1977 demonstrated’’ indicates that one of the House Committee Report noted: analytical approach. In the [1970] Congress [sic: Congress’s] view, it requirements for the technology or other was only right that the costs of applying best a. ‘‘System[s] of Emission Reduction measures that the EPA identifies as the practicable control technology be considered by the . . . Adequately Demonstrated’’ BSER is that the measure must be owner of a large new source of pollution as a The EPA’s first step is to identify technically feasible. See 79 FR 1430, normal and proper expense of doing business. 1977 House Committee Report at 184. Similarly, ‘‘system[s] of emission reduction . . . 1463 (January 8, 2014). the 1970 Senate Committee Report stated: adequately demonstrated.’’ For the b. ‘‘Best’’ The implicit consideration of economic factors in reasons discussed below, for the various determining whether technology is ‘‘available’’ types of newly constructed, modified, In determining which adequately should not affect the usefulness of this section. The and reconstructed sources in this demonstrated system of emission overriding purpose of this section would be to reduction is the ‘‘best,’’ the EPA prevent new air pollution problems, and toward that end, maximum feasible control of new sources Portland Cement Ass’n v. EPA, 665 F.3d 177 (D.C. considers the following factors: at the time of their construction is seen by the Cir. 2011). See also Delaware v. EPA, No. 13–1093 committee as the most effective and, in the long (D.C. Cir. May 1, 2015). (1) Costs run, the least expensive approach. 126 See Sierra Club v. Costle, 657 F.2d 298, 326 Under CAA section 111(a)(1), the EPA S. Comm. Rep. No. 91–1196 at 16. Some (D.C. Cir. 1981). is required to take into account ‘‘the cost commenters asserted that we do not have authority 127 See Sierra Club v. Costle, 657 F.2d at 347. to revise the cost standard as established in the case 128 See Lignite Energy Council v. EPA, 198 F.3d law, e.g., ‘‘exorbitant,’’ ‘‘excessive,’’ etc., to a 130 930, 933 (D.C. Cir. 1999). Essex Chem. Corp. v. Ruckelshaus, 486 F.2d ‘‘reasonableness’’ standard that may be considered 427, 433 (D.C. Cir. 1973), cert. denied, 416 U.S. 969 129 Although section 111(a)(1) may be read to less protective of the environment. We agree that (1974). state that the factors enumerated in the we do not have authority to revise the cost standard 131 parenthetical are part of the ‘‘adequately Portland Cement Ass’n v. Ruckelshaus, 486 as established in the case law, and we are not demonstrated’’ determination, the D.C. Circuit’s F.2d 375, 391 (D.C. Cir. 1973) (citations omitted) attempting to do so here. Rather, our description of case law appears to treat them as part of the ‘‘best’’ (discussing the Senate and House bills and reports the cost standard as ‘‘reasonableness’’ is intended determination. See Sierra Club v. Costle, 657 F.2d from which the language in CAA section 111 grew). to be a convenient term for referring to the cost at 325–26. It does not appear that those two 132 Portland Cement Ass’n v. Ruckelshaus, 486 standard as established in the case law. approaches would lead to different outcomes. In F.2d 375, 391 (D.C. Cir. 1973) (citations omitted). 141 1977 House Committee Report at 184. this rule, the EPA is following the D.C. Circuit case 133 Sierra Club v. Costle, 657 F.2d 298, 364 (1981). 142 The costs for these standards were described law and treating the factors as part of the ‘‘best’’ 134 Portland Cement Ass’n v. Ruckelshaus, 486 in the rulemakings. See 36 FR 24876 (December 23, determination. F.2d 375, 391 (D.C. Cir. 1973) (citations omitted). 1971), 37 FR 5767, 5769 (March 21, 1972).
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1981) (upholding standard imposing rulemaking, as discussed below in time, and not only on a plant-specific 148 controls on SO2 emissions from coal- Section V.O.3, the EPA considered the level at the time of the rulemaking. fired power plants when the ‘‘cost of the parasitic load requirements of partial The D.C. Circuit based this conclusion new controls . . . is substantial’’).143 CCS. The EPA is finding here that on a review of the legislative history, Moreover, section 111(a) does not whether energy requirements are stating, provide specific direction regarding considered on a source-specific basis, an The Conferees defined the best technology what metric or metrics to use in industry/national basis, or both, they are in terms of ‘‘long-term growth,’’ ‘‘long-term considering costs, again affording the reasonable. See Sections V.O.3 and cost savings,’’ effects on the ‘‘coal market,’’ EPA considerable discretion in choosing XIII.C. including prices and utilization of coal a means of cost consideration.144 reserves, and ‘‘incentives for improved As discussed below, the EPA may (4) Amount of Emissions Reductions technology.’’ Indeed, the Reports from both consider costs on both a source-specific At proposal, we noted that although Houses on the Senate and House bills basis and a sector-wide, regional, or the definition of ‘‘standard of illustrate very clearly that Congress itself was nationwide basis. The EPA is finding performance’’ does not by its terms using a long-term lens with a broad focus on identify the amount of emissions from future costs, environmental and energy here that whether costs are considered effects of different technological systems on a source-specific basis, an industry/ the category of sources or the amount of when it discussed section 111.149 national basis, or both, they are emission reductions achieved as factors reasonable. See Sections V.H and I the EPA must consider in determining The Court has upheld rules that the below. the ‘‘best system of emission reduction,’’ EPA ‘‘justified . . . in terms of the the D.C. Circuit has stated that the EPA policies of the Act,’’ including balancing (2) Non-Air Quality Health and must in fact do so. See Sierra Club v. long-term national and regional impacts: Environmental Impacts Costle, 657 F.2d 298, 326 (D.C. Cir. The standard reflects a balance in Under CAA section 111(a)(1), the EPA 1981) (‘‘we can think of no sensible environmental, economic, and energy is required to take into account ‘‘any interpretation of the statutory words consideration by being sufficiently stringent nonair quality health and environmental ‘‘best . . . system’’ which would not to bring about substantial reductions in SO2 impact’’ in determining the BSER. As incorporate the amount of air pollution emissions (3 million tons in 1995) yet does the D.C. Circuit has explained, this as a relevant factor to be weighed when so at reasonable costs without significant requirement makes explicit that a determining the optimal standard for energy penalties.... By achieving a balanced coal demand within the utility system cannot be ‘‘best’’ if it does more 146 controlling . . . emissions’’). The fact sector and by promoting the development of harm than good due to cross-media that the purpose of a ‘‘system of less expensive SO2 control technology, the 145 environmental impacts. The EPA has emission reduction’’ is to reduce final standard will expand environmentally carefully considered such cross-media emissions, and that the term itself acceptable energy supplies to existing power impacts here, in particular potential explicitly incorporates the concept of plants and industrial sources. impacts to underground sources of reducing emissions, supports the By substantially reducing SO2 emissions, drinking water posed by CO2 Court’s view that in determining the standard will enhance the potential for sequestration, and water use necessary whether a ‘‘system of emission long term economic growth at both the 150 to operate carbon capture systems. See reduction’’ is the ‘‘best,’’ the EPA must national and regional levels. Sections V.N and O below. consider the amount of emission Some commenters objected that this (3) Energy Considerations reductions that the system would case law did not allow the EPA to ignore yield.147 Even if the EPA were not source-specific impacts (particularly Under CAA section 111(a)(1), the EPA required to consider the amount of cost impacts) by basing determinations is required to take into account ‘‘energy emission reductions, the EPA has the solely on impacts at a regional or requirements.’’ As discussed below, the discretion to do so, on grounds that national level. In fact, the EPA’s EPA may consider energy requirements either the term ‘‘system of emission consideration of cost, non-air quality on both a source-specific basis and a reduction’’ or the term ‘‘best’’ may impacts, and energy requirements sector-wide, region-wide, or nationwide reasonably be read to allow that reflect source-specific impacts, as well basis. Considered on a source-specific discretion. as (for some considerations) impacts basis, ‘‘energy requirements’’ entail, for (5) Sector or Nationwide Component of that are sector-wide, regional, or example, the impact, if any, of the national. See Section V.H.6 below. system of emission reduction on the the BSER Factors source’s own energy needs. In this As discussed in the January 2014 c. Achievability of the Standard for proposal, another component of the D.C. Emissions 143 Indeed, in upholding the EPA’s consideration Circuit’s interpretations of CAA section In the January 2014 proposal, the EPA of costs under the provisions of the Clean Water Act 111 is that the EPA may consider the authorizing technology-based standards based on recognized that the first element of the performance of a best technology taking costs into various factors it is required to consider definition of ‘‘standard of performance’’ account, courts have also noted the substantial on a national or regional level and over is that ‘‘the emission limit [i.e., the discretion delegated to the EPA to weigh cost ‘standard for emissions’] that the EPA considerations with other factors. Chemical Mfr’s 146 Sierra Club v. Costle, 657 F.2d 298 (D.C. Cir. promulgates must be ‘achievable’ ’’ Ass’n v. EPA, 870 F.2d 177, 251 (5th Cir. 1989); 1981) was governed by the 1977 CAAA version of Association of Iron and Steel Inst. v. EPA, 526 F.2d the definition of ‘‘standard of performance,’’ which 1027, 1054 (3d Cir. 1975); Ass’n of Pacific Fisheries revised the phrase ‘‘best system’’ to read, ‘‘best 148 79 FR 1430, 1465 January 8, 2014) (citing v. EPA, 615 F.2d 794, 808 (9th Cir. 1980). technological system.’’ As noted above, the 1990 Sierra Club v. Costle, 657 F.2d at 351). 144 See, e.g., Husqvarna AB v. EPA, 254 F.3d 195, CAAA deleted ‘‘technological,’’ and thereby 149 Sierra Club v. Costle, 657 F.2d at 331 (citations 200 (D.C. Cir. 2001) (where CAA section 213 does returned the phrase to how it read under the 1970 omitted) (citing legislative history). not mandate a specific method of cost analysis, the CAAA. The court’s interpretation of this phrase in 150 Sierra Club v. Costle, 657 F.2d at 327–28 EPA may make a reasoned choice as to how to Sierra Club v. Costle to require consideration of the (quoting 44 FR 33583/3–33584/1). In the January analyze costs). amount of air emissions reductions remains valid 2014 proposal, we explained that although the D.C. 145 Portland Cement v. EPA, 486 F.2d at 384; for the phrase ‘‘best system.’’ Circuit decided Sierra Club v. Costle before the Sierra Club v. Costle, 657 F.2d at 331; see also Essex 147 See also NRDC v. EPA, 479 F.3d 875, 880 (D.C. Chevron case was decided in 1984, the D.C. Chemical Corp. v. Ruckelshaus, 486 F.2d at 439 Cir. 2006) (‘‘best performing’’ source for purposes Circuit’s decision could be justified under either (remanding standard to consider solid waste of CAA section 112 (d)(3) is source with the lowest Chevron step 1 or 2. 79 FR 1430, 1466 (January 8, disposal implications of the BSER determination). emission levels). 2014).
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based on performance of the BSER. 79 clear that Congress intended for CAA may justify the control technologies FR 1430, 1463 (January 8, 2014). section 111 to create incentives for new identified in this rule as the BSER even According to the D.C. Circuit, a standard technology and therefore that the EPA is without considering the factor of for emissions is ‘‘achievable’’ if a required to consider technological incentivizing technological innovation technology can reasonably be projected innovation as one of the factors in or development. to be available to new sources at the determining the ‘‘best system of e. Agency Discretion time they are constructed that will allow emission reduction.’’ 155 them to meet the standard.151 Moreover, The Court grounded its reading in the As discussed in the January 2014 according to the Court, ‘‘[a]n achievable statutory text.156 In addition, in the proposal, the D.C. Circuit has made standard is one which is within the January 2014 proposal, we noted that clear that the EPA has broad discretion realm of the adequately demonstrated the Court’s interpretation finds in determining the appropriate standard system’s efficiency and which, while additional support in the legislative of performance under the definition in not at a level that is purely theoretical history.157 We also explained that the CAA section 111(a)(1), quoted above. or experimental, need not necessarily be legislative history identifies three Specifically, in Sierra Club v. Costle, routinely achieved within the industry different ways that Congress designed 657 F.2d 298 (D.C. Cir. 1981), the Court prior to its adoption.’’ 152 To be CAA section 111 to authorize standards explained that ‘‘section 111(a) explicitly achievable, a standard ‘‘must be capable of performance that promote instructs the EPA to balance multiple of being met under most adverse technological improvement: (i) The concerns when promulgating a conditions which can reasonably be development of technology that may be NSPS,’’ 159 and emphasized that ‘‘[t]he expected to recur and which are not or treated as the ‘‘best system of emission text gives the EPA broad discretion to cannot be taken into account in reduction . . . adequately weigh different factors in setting the determining the ‘cost of demonstrated’’ under section 111(a)(1); standard.’’ 160 In Lignite Energy Council compliance.’ ’’ 153 To show that a (ii) the expanded use of the best v. EPA, 198 F.3d 930 (D.C. Cir. 1999), standard is achievable, the EPA must demonstrated technology; and (iii) the the Court reiterated: ‘‘(1) identify variable conditions that development of emerging technology.158 Because section 111 does not set forth the might contribute to the amount of Even if the EPA were not required to weight that should be assigned to each of expected emissions, and (2) establish consider technological innovation as these factors, we have granted the agency a that the test data relied on by the agency part of its determination of the BSER, it great degree of discretion in balancing are representative of potential industry- would be reasonable for the EPA to them.... EPA’s choice [of the ‘best wide performance, given the range of consider it, either because technological system’] will be sustained unless the environmental or economic costs of using the variables that affect the achievability of innovation may be considered an technology are exorbitant.... EPA [has] 154 the standard.’’ element of the term ‘‘best,’’ or because considerable discretion under section 111.161 In Sections V.J and IX.D below, we the term ‘‘best system of emission show both that the BSER for new steam reduction’’ is ambiguous as to whether f. Lack of Requirement That Standard generating units and combustion technological innovation may be Must Be Met by All Sources turbines is technically feasible and considered. The interpretation is In the January 2014 proposal, the EPA adequately demonstrated, and that the likewise consistent with the evident proposed that, under CAA section 111, standards of 1,400 lb CO /MWh-g and purpose of section 111(b) to require new 2 an emissions standard may meet the 1,000 lb CO /MWh-g are achievable sources to maximize emission 2 requirements of a ‘‘standard of considering the range of operating reductions using state-of-the-art means performance’’ even if it cannot be met variables that affect achievability. of control. Commenters stated that the by every new source in the source d. Expanded Use and Development of requirement to consider technological category that would have constructed in Technology innovation does not authorize the EPA the absence of that standard. As In the January 2014 proposal, we to identify as the BSER a technology described in the January 2014 proposal, noted that the D.C. Circuit has made that is not adequately demonstrated. the EPA based this view on (i) the The proposal did not, and we do not in legislative history of CAA section 111, 151 Portland Cement, 486 F.2d at 391–92. Some this final rule, claim to the contrary. In read in conjunction with the legislative commenters stated that the EPA’s analysis of the any event, as discussed below, the EPA history of the CAA as a whole; (ii) case requirements for ‘‘standard of performance,’’ law under analogous CAA provisions; including the BSER, attempted to eliminate the and (iii) long-standing precedent in the requirement that the standard for emissions must be 155 See 79 FR 1430, 1465 (January 8, 2014), Sierra ‘‘achievable.’’ We disagree with this comment. As Club v. Costle, 657 F.2d at 346–47. EPA rulemakings under CAA section just quoted, the EPA’s analysis recognizes that the 156 Sierra Club v. Costle, 657 F.2d at 346 (‘‘Our 111.162 standard for emissions must be achievable through interpretation of section 111(a) is that the mandated the application of the BSER. balancing of cost, energy, and nonair quality health 159 Sierra Club v. Costle, 657 F.2d at 319. 152 Essex Chem. Corp. v. Ruckelshaus, 486 F.2d and environmental factors embraces consideration 160 Sierra Club v. Costle, 657 F.2d at 321; see also 427, 433–34 (D.C. Cir. 1973), cert. denied, 416 U.S. of technological innovation as part of that balance. New York v. Reilly, 969 F. 2d at 1150 (because 969 (1974). The statutory factors which the EPA must weigh are Congress did not assign the specific weight the 153 Nat’l Lime Ass’n v. EPA, 627 F.2d 416, 433, broadly defined and include within their ambit Administrator should assign to the statutory n.46 (D.C. Cir. 1980). subfactors such as technological innovation.’’). elements, ‘‘the Administrator is free to exercise 154 Sierra Club v. Costle, 657 F.2d 298, 377 (D.C. 157 See 79 FR 1430, 1465 (January 8, 2014) (citing [her] discretion’’ in promulgating an NSPS). Cir. 1981) (citing Nat’l Lime Ass’n v. EPA, 627 F.2d S.Rep. 91–1196 at 16 (1970)) (‘‘Standards of 161 Lignite Energy Council v. EPA, 198 F.3d 930, 416 (D.C. Cir. 1980). In considering the performance should provide an incentive for 933 (D.C. Cir. 1999) (paragraphing revised for representativeness of the source tested, the EPA industries to work toward constant improvement in convenience). See also NRDC v. EPA, 25 F.3d 1063, may consider such variables as the ‘‘‘feedstock, techniques for preventing and controlling emissions 1071 (D.C. Cir. 1994) (The EPA did not err in its operation, size and age’ of the source.’’ Nat’l Lime from stationary sources’’); S. Rep. 95–127 at 17 final balancing because ‘‘neither RCRA nor EPA’s Ass’n v. EPA, 627 F.2d 416, 433 (D.C. Cir. 1980). (1977) (cited in Sierra Club v. Costle, 657 F.2d at regulations purports to assign any particular weight Moreover, it may be sufficient to ‘‘generalize from 346 n. 174) (‘‘The section 111 Standards of to the factors listed in subsection (a)(3). That being a sample of one when one is the only available Performance . . . sought to assure the use of the case, the Administrator was free to emphasize sample, or when that one is shown to be available technology and to stimulate the or deemphasize particular factors, constrained only representative of the regulated industry along development of new technology’’). by the requirements of reasoned agency decision relevant parameters.’’ Nat’l Lime Ass’n v. EPA, 627 158 79 FR 1465 (citing case law and legislative making.’’). F.2d 416, 434, n.52 (D.C. Cir. 1980). history). 162 79 FR 1430, 1466 (January 8, 2014).
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Commenters contested this assertion, reduction from EGU facilities for which determination would not be based arguing that a 111(b) standard must be a tax credit is allowed: ‘‘solely’’ on EPAct05 sources. These achievable by all new sources. We ‘‘No use of technology (or level of emission commenters urged the EPA to conclude continue to take the same position as at reduction solely by reason of the use of the that a determination ‘‘solely’’ on the proposal for the reasons described there. technology), and no achievement of any basis of information from EPAct05- We note that as a practical matter, in emission reduction by the demonstration of assisted facilities is any determination this rulemaking, the issue of whether all any technology or performance level, by or at where ‘‘but for’’ that information, the new steam-generating sources can one or more facilities with respect to which EPA could not justify its chosen implement partial-capture CCS is a credit is allowed under this section, shall standard as the BSER.168 Other be considered to indicate that the technology largely dependent on the geographic or performance level is adequately commenters argued that the provisions scope of geologic sequestration sites. As demonstrated [ ] for purposes of section 111 bar the EPA from all consideration of discussed below in Section V.M, of the Clean Air Act. . . .’’ EPAct05 facilities when determining geologic sequestration sites are widely The EPA specifically solicited that a technology or level of available, and a steam-generating plant comment on its interpretation of these performance is adequately with partial CCS that is sited near an provisions. 79 FR 10750 (Feb. 26, 2014) demonstrated. area that is suitable for geologic (Notice of Data Availability). With In this final rule, the EPA is adopting sequestration can serve demand in a respect to EPAct05 sections 402(i) and the interpretations of all three large area that may not have 421(a), the EPA proposed that these provisions that it proposed, largely for sequestration sites available. In any provisions barred consideration where the reasons previously advanced. The event, the standard of 1,400 lb CO2/MW- EPAct05-assisted facilities were the sole EPA thus interprets these provisions to g that we promulgate in this final rule support for the BSER determination, but preclude the EPA from relying solely on can be achieved by new steam that these sources could support a BSER the experience of facilities that received generating EGUs—including new utility determination so long as there is DOE assistance, but not to preclude the boilers and IGCC units—through co- additional evidence supporting the EPA from relying on the experience of firing with natural gas in lieu of determination.164 In addition, the EPA such facilities in conjunction with other installing partial CCS, which moots the viewed the two prohibitions as relating information. This reading of sections issue of the geographic availability of only to the technology or emissions 402(i) and 421(a) is consistent with the geologic sequestration. reduction for which assistance was views of the only court to date to 165 consider the matter.169 g. EPAct05 given. The EPA likewise interpreted IRC section 48A(g)—based on the plain The EPA notes that the extreme The Energy Policy Act of 2005 language and the context provided by hypothetical posed in the comments (‘‘EPAct05’’) authorizes assistance in the sections 402(i) and 421(a)—to mean that (where the EPA might avoid a limitation form of grants, loan guarantees, as well use of technology, or emission on its consideration of EPAct05-assisted as federal tax credits for investment in performance, from a facility for which facilities by including a mere scintilla of ‘‘clean coal technology.’’ Sections the credit is allowed cannot, by itself, evidence from non-EPAct05 facilities) is 402(i), 421(a), and 1307(b) (adding support a finding that the technology or not presented here, where the principal section 48A(g) to the Internal Revenue performance level is adequately evidence that partial post-combustion Code (‘‘IRC’’)) address the extent to demonstrated, but the information can CCS is a demonstrated and feasible which information from clean coal corroborate an otherwise supported technology comes from sources which projects receiving assistance under the determination or otherwise provide part received no assistance of any type under EPAct05 may be considered by the EPA of the basis for such a determination.166 EPAct05. The EPA also concludes that in determining what is the best system The EPA also proposed to interpret the the ‘‘but for’’ test urged by these of emission reduction adequately phrase ‘‘with respect to which a credit commenters is an inappropriate reading demonstrated. Section 402(i) of the is allowed under this section’’ as of the term ‘‘solely’’ in sections 402(i) EPAct05 limits the use of information referring to the entire phrase ‘‘use of and 421(a), as any piece of evidence from facilities that receive assistance technology (or level of emission may be a necessary, or ‘‘but for,’’ cause under EPAct05 in CAA section 111 reduction . . .) and [] achievement of without being a sufficient, or ‘‘sole,’’ rulemakings: any emission reduction . . . , by or at cause.170 Nonetheless, if the ‘‘but for’’ ‘‘No technology, or level of emission one or more facilities.’’ Thus, if test were applicable here, the available reduction, solely by reason of the use of technology A received a tax credit, but evidence would satisfy it. the technology, or the achievement of technology B at the same facility did the emission reduction, by 1 or more not, the constraint would not apply to 168 Comments of AFPM/API p. 46 (Docket entry: facilities receiving assistance under this technology B.167 EPA–HQ–OAR–2013–0495–10098). Act, shall be considered to be 169 State of Nebraska v. EPA, 2014 U.S. Dist. Some commenters supported the LEXIS 141898 at n. 1 (D. Nebr. 2014). (‘‘But the adequately demonstrated [ ] for EPA’s proposed interpretation. Others Court notes that § 402(i) only forbids the EPA from purposes of section 111 of the Clean Air contended that the EPA’s interpretation considering a given technology or level of emission Act. . . .’’ 163 would allow it to support a BSER reduction to be adequately demonstrated solely on IRC section 48A(g) contains a similar the basis of federally-funded facilities. 42 U.S.C. determination even where EPAct05 15962(i). In other words, such technology might be constraint concerning the use of facility information comprised 99 adequately demonstrated if that determination is technology or level of emission percent of the supporting information based at least in part on non-federally-funded for a BSER determination because that facilities’’) (emphasis original). 163 Codified at 42 U.S.C. 15962(a). EPAct05 170 For example, any vote of a Justice on the section 421(a) similarly states: ‘‘No technology, or Supreme Court may be a necessary but not 164 level of emission reduction, shall be treated as Technical Support Document, Effect of sufficient cause. In a 5–4 decision, the decision of adequately demonstrated for purpose [sic] of EPAct05 on Best System of Emission Reduction for the Court would have been different ‘‘but for’’ the section 7411 of this title, . . . solely by reason of New Power Plants, p. 6 (Docket entry: EPA–HQ– assent of Justice A or Justice B, who were in the the use of such technology, or the achievement of OAR–2013–0495–1873). majority. But it would be incorrect to say that the such emission reduction, by one or more facilities 165 Id. assent of Justice A was the ‘‘sole’’ reason for the receiving assistance under section 13572(a)(1) of 166 Id. p. 13. outcome, when the decision also required the this title’’. 167 Id. p. 14. assent of Justice B.
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Other commenters took the extreme under EPAct05, and on other In December 2013—after the proposed position that the EPAct05 provisions bar information likewise not having any action was signed, but before it was all consideration of a facility’s existence connection to EPAct05 assistance. The published—Wolverine Power if the facility received EPAct05 corroborative information from EPAct05 Cooperative announced that it was assistance.171 The EPA does not accept facilities, though supportive, is not cancelling construction of the proposed this argument because it is contrary to necessary to the EPA’s findings. coal-fired power plant in Rogers City, both the plain statutory language 172 (see MI.173 Therefore, we are not finalizing I. Severability Chapter 2 of the Response-to-Comment the proposed exclusion for that project. document) and to Congress’s intent that This rule has numerous components, In the January 2014 proposal, the EPA the EPAct05 programs advance the and the EPA intends that they be also identified two other fossil fuel-fired commercialization of clean coal severable from each other to the extent steam generating EGU projects that, as technology. For the same reason, the that they function separately. For currently designed, would not meet the EPA does not accept some commenters’ example, the EPA intends that each set proposed 1,100 lb CO2/MWh emissions suggestion that sections 402(i), 421(a), of BSER determinations and standards standard—the Plant Washington project and 48A(g) preclude the EPA from of performance in this rulemaking be in Georgia and the Holcomb 2 project in considering NETL’s cost projections for severable from each other set. That is, Kansas. We indicated that, at the time CCS, which base cost estimates on up- the BSER determination and standard of of the proposal, those projects appeared to-date vendor quotes reflecting costs for performance for newly constructed to remain under development but that the CCS technology being utilized at the fossil fuel-fired electric utility steam the project developers had represented Boundary Dam Unit #3 facility (a generating units are severable from all that the projects have commenced facility receiving no assistance under the other BSER determinations and construction for NSPS purposes and, EPAct05), but also considers that to-be- standards of performance, and the same thus, would not be new sources subject built plants will no longer be first-of-a is true for the BSER determination and to the proposed or final NSPS. Based kind. See generally Section V.I.2 below. standard of performance for modified solely on the developers’ Commenters suggest that the EPAct05 fossil fuel-fired electric utility steam representations, the EPA indicated that requires that the EPA treat future plants generating units, and so on. It is those projects, if ultimately fully as ‘‘first of a kind’’ when projecting reasonable to consider each set of BSER constructed, would be existing sources, costs, as if EPAct05 facilities simply did determination and standard of and would thus not be subject to the not exist. This reading is contrary to the performance to be severable from each standards of performance in this final text of the provisions, which as noted, other set of BSER determination and action. relates specifically to a source’s standard of performance because each To date, neither developer has sought performance and operation (whether a set is independently justifiable and does a formal EPA determination of NSPS technology is demonstrated, and the not depend on any other set. Thus, in applicability. As we specified in the level of performance achieved by use of the event that a court should strike January 2014 proposal—and we reiterate technology), not to sources’ existence. down any set of BSER determination here—if such an applicability NETL’s cost projections, on the other and standard of performance, the determination concludes that either the hand, merely acknowledge the evident remaining BSER determinations and Plant Washington (GA) project or the fact that CCS technologies exist, and standards of performance should not be Holcomb 2 (KS) project did not reasonably project that they will affected. commence construction prior to January continue to develop. See Section V.I.2. 8, 2014 (the publication of the January The NETL cost estimates, moreover, are J. Certain Projects Under Development 2014 proposal), then the project should based on vendor quotes for the CCS In the January 2014 proposal, the EPA be situated similarly to the disposition technology in use at the Boundary Dam indicated that the proposed Wolverine the EPA proposed for the Wolverine facility, a Canadian plant which EGU project (Rogers City, Michigan) project. Accordingly, the EPA is obviously is not a recipient of EPAct05 appeared to be the only fossil fuel-fired finalizing in this action that if it is assistance. See sections V.D.2.a and V. steam generating unit that was currently determined that either of these projects I.2 below. under development that may be capable has not commenced construction as In any case, as shown in Section V of ‘‘commencing construction’’ for NSPS January 8, 2014, then that project will be below, the EPA finds that a new highly- purposes at the time of the proposal. See addressed in the same manner as was efficient SCPC EGU implementing 79 FR 1461. The EPA also proposed for the Wolverine project. partial post-combustion CCS is the best acknowledged that the Wolverine EGU, In public comments submitted in system of emission reduction as designed, would not meet the response to the January 2014, adequately demonstrated and is doing proposed standard of 1,100 lb CO2/ Power4Georgians (P4G), the Plant so based in greater part on performance MWh for new utility steam generating Washington developer, reiterated that of facilities receiving no assistance EGUs. The EPA proposed that, at the they had executed binding contracts for time of finalization of the proposed the purchase and erection of the facility 171 Supplemental Comments of Murray Energy p. standards, if the Wolverine project boiler prior to publication of the January 11 (Docket entry: EPA–HQ–OAR–2013–0495–9498). 2014 proposal and believe that the 172 With respect to sections 402(i) and 421(a), remains under development and has not commenters fail to reconcile their reading of the either commenced construction or been binding contracts are sufficient to statute with the Act’s grammatical structure, as canceled, we anticipated proposing a constitute commencement of explained in detail in chapter 2 of the Response-to- standard of performance specifically for construction for purposes of the NSPS Comment document. One commenter supported its program, so that they are existing rather reading by adding suggested text to the statutory that facility. Additional discussion of language, a highly disfavored form of statutory the approach can be found in the than new sources for purposes of this construction. Comments of UARG, p.124 n.38 proposal or in the technical support (Docket entry: EPA–HQ–OAR–2013–0495–9666). document in the docket entitled ‘‘Fossil 173 ‘‘Wolverine ends plant speculation in Rogers With respect to section 48A(g), commenters misread City’’, The Alpena News, December 17, 2013. http:// the phrase ‘‘considered to indicate,’’ and do not Fuel-Fired Boiler and IGCC EGU www.thealpenanews.com/page/content.detail/id/ explain how their reading of all three provisions Projects under Development: Status and 527862/Wolverine-ends-plant-speculation-in- together is tenable. Approach.’’ Rogers-City.html?nav=5004.
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rule.174 Public comments submitted by manner proposed for the Wolverine A. Applicability Requirements and Tri-State Generation and Transmission project. 79 FR 1461. We are finalizing Rationale Association and Sunflower Electric that proposal here. However, because We generally refer to fossil fuel-fired Power Corporation, the developers of these units may never actually be fully electric utility generating units that the Holcomb 2 project, discussed the built and operated, we are not would be subject to an emission cost incurred in the development of the promulgating a standard of performance standard in this rulemaking as project. They also indicated they had at this time because such action may ‘‘affected’’ or ‘‘covered’’ sources, units, awarded contracts for the turbine/ prove to be unnecessary.178 facilities or simply as EGUs. These units generator purchase and had negotiated a meet both the definition of ‘‘affected’’ rail-supply agreement that provides for There is one possible additional new EGU, the Two Elk project in Wyoming. and ‘‘covered’’ EGUs subject to an the delivery of fuel to the proposed emission standard as provided by this Holcomb 2 site. The developers did not, In a supporting TSD accompanying the January 2014 proposal, we discussed the rule, and the criteria for being however, explicitly characterize the considered ‘‘new,’’ ‘‘modified’’ or construction status of the project.175 Two Elk project and relied on developer statements and state acquiescence that ‘‘reconstructed’’ sources as defined Other groups submitted comments under the provisions of CAA section the unit had commenced construction contending that neither project has 111 and the EPA’s regulations. This for NSPS purposes before January 8, actually commenced construction. section discusses applicability for newly 2014.179 We did not, therefore, propose In October 2013, the Kansas Supreme constructed, modified, and Court invalidated the 2010 air pollution any special section 111(b) standard for reconstructed steam generating units. permit granted to Sunflower Electric the project. Some commenters Power Corporation by the Kansas maintained that a continuous program 1. General Applicability Criteria Department of Health and Environment of construction at the facility has not The EPA is finalizing applicability (KDHE).176 In May 2014, the KDHE been maintained and that if the plant is criteria for new, modified, and issued an air quality permit addendum ultimately constructed, it should be reconstructed electric utility steam for the proposed Holcomb 2 coal plant. classified as a new source under CAA generating units (i.e., utility boilers and The addendum addressed federal section 111(b). These comments were IGCC units) in 40 CFR part 60, subpart regulations that the Kansas Supreme not specific enough to change the EPA’s TTTT that are similar to the Court held had been overlooked in the view of the project for purposes of this applicability criteria for those units in initial permitting determination. In June rulemaking. We accordingly continue to 40 CFR part 60, subpart Da (utility 2014, the Sierra Club filed an appeal rely on developer statements that this boiler and IGCC performance standards with the Kansas Appellate Court facility has commenced construction for criteria pollutants), but with some challenging the legality of the May 2014 and would not be a new source for differences. The proposed applicability permit. Since the publication of the purposes of this proceeding. criteria, relevant comments, and final January 2014 proposal, the EPA is applicability criteria specific to newly unaware of any physical construction IV. Summary of Final Standards for constructed, modified, and activity at the proposed Holcomb 2 site. Newly Constructed, Modified, and reconstructed steam generating units are In October 2014, the Plant Reconstructed Fossil Fuel-Fired Electric discussed below. Washington project was given an 18- Utility Steam Generating Units The applicability requirements in the month air permit extension by the proposal for newly constructed EGUs Georgia Environmental Protection This section sets forth the standards included that a utility boiler or IGCC Division (EPD). However, as with the for newly constructed, modified, and unit must: (1) Be capable of combusting Holcomb expansion project, the EPA is reconstructed steam generating units more than 250 MMBtu/h heat input of unaware of any physical construction (i.e., utility boilers and IGCCs). We fossil fuel; (2) be constructed for the that has taken place at the proposed explain the rationale for the final purpose of supplying, and actually Plant Washington site and a recent audit standards in Sections V (newly supply, more than one-third of its of the project described it as constructed steam generating unit), VI potential net-electric output capacity to ‘‘dormant’’.177 (modified steam generating units), and any utility power distribution system Based on this information, it appears VII (reconstructed steam generating (that is, to the grid) for sale on an annual that these sources have not commenced units). basis; (3) be constructed for the purpose construction for purposes of section of supplying, and actually supply, more 111(b) and therefore would likely be 178 In the proposed emission guidelines for than 219,000 MWh net-electric output new sources should they actually be existing EGUs, the EPA did not include estimates to the grid on an annual basis; and (4) constructed. As noted above, the EPA of emissions for either Plant Washington or the combust over 10 percent fossil fuel on proposed that, if these projects are Holcomb 2 unit in baseline data used to calculate proposed state goals for Georgia and Kansas. It a heat input basis over a 3-year average. determined to not have commenced appears that the possibility of these plants actually At proposal, applicability was construction for NSPS purposes prior to being built and operating is too remote. If either determined based on a combination of the publication of the proposed rule, unit eventually seeks an applicability determination design and actual operating conditions they will be addressed in the same and that unit is determined to be an existing source, and there is reliable evidence that the source will that could change annually depending operate, then the source will be subject to the final on the proportion and the amount of 174 Docket entry: EPA–HQ–OAR–2013–0495– 111(d) rule and the EPA will allow the state to electricity actually sold and on the 9403. adjust its state goal to reflect adjustment of the proportion of fossil fuels combusted by 175 Docket entry: EPA–HQ–OAR–2013–0495– state’s baseline data so as to include the unit. 9599. Guidance for adjustment of state goals is provided the unit. 176 ‘‘Kansas High Court Invalidates 895–MW Coal in the record for the EPA’s final CAA section 111(d) In the proposal for modified and Project Air Permit’’, Power Magazine, 10/10/2013, rulemaking. reconstructed EGUs, we proposed a available at: www.powermag.com/kansas-high- 179 ‘‘Fossil Fuel-Fired Boiler and IGCC EGU broader applicability approach such that court-invalidates-2010-895-mw-coal-project-air- Projects Under Development: Status and permit/. Approach’’, Technical Support Document at pp. applicability would be based solely on 177 http://www.macon.com/2015/06/23/3811798/ 10–1 (Docket Entry: EPA–HQ–OAR–2013–0495– design criteria and would be identical to audit-sandersville-coal-plant.html. 0024). the applicability requirements in
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subpart Da. First, we proposed electric purpose for which they were current operating permit. Without this sales criteria that the source be constructed) in an attempt to avoid restriction, existing units could avoid constructed for the purpose of selling applicability under section 111(d) obligations under state plans developed more than one-third of their potential requirements. Consequently, there could as part of the 111(d) program by electric output and more than 219,000 be a regulatory incentive for owners/ amending their operating permit to limit MWh to the grid on an annual basis, operators to circumvent the CO2 NSPS total annual electric sales to one-third of regardless of the actual amount of applicability. For units that avoid potential electric output. These units electricity sold (i.e., we did not include coverage, there would also be a would not be subject to any GHG NSPS the applicability criterion that the unit corresponding environmental impact. requirements because they would not actually sell the specified amount of For example, an owner/operator of a meet the 111(b) or 111(d) applicability electricity on an annual basis). In new unit could initially request a permit criteria and, at this time, there is no addition, we proposed a base load rating restriction to limit electric sales to less NSPS that would cover these units. As criterion that the source be capable of than one-third of potential annual described in Section III, industrial CHP combusting more than 250 MMBtu/h of electric output, but amend the operating and dedicated non-fossil units also are fossil fuel, regardless of the actual permit shortly after operation has not affected EGUs under this final amount of fossil fuel burned (i.e., we did commenced to circumvent the intended action. not include the fossil fuel-use criterion applicability. Many existing units were In this rule, we are finalizing the that an EGU actually combust more than initially built with excess capacity to definition of a steam generating EGU as 10 percent fossil fuel on a heat input account for projected load growth and a utility boiler or IGCC unit that: (1) Has basis on a 3-year average). Under this were intended to sell more than one- a base load rating greater than 260 GJ/ approach, applicability would be known third of their potential electric output. h (250 MMBtu/h) of fossil fuel (either prior to the unit actually commencing However, due to various factors (lower alone or in combination with any other operation and would not change on an than expected load growth, availability fuel) and (2) serves a generator capable annual basis. We also proposed that the of other lower cost units, etc.), certain of supplying more than 25 MW-net to a final applicability criteria would be units might have sold less than one- utility distribution system (i.e., for sale consistent for newly constructed, third of their potential electric output, at to the grid). However, we are not reconstructed, and modified units. The least during their initial period of establishing final CO2 standards for proposed broad applicability criteria operation. Therefore, the EPA has certain EGUs. These include: (1) Steam would still not have included boilers concluded that determining generating units and IGCC units that are and IGCC units that were constructed applicability based on whether a unit is currently subject to—and have been for the purpose of selling one-third or ‘‘constructed for the purpose of continuously subject to—a federally less of their potential output or 219,000 supplying one-third or more of its enforceable permit limiting annual MWh or less to the grid on an annual potential electric output and more than electric sales to one-third or less of their basis. These units are not covered under 219,000 MWh as net-electric sales’’ potential electric output (e.g., limiting subpart Da (the utility boiler and IGCC (emphasis added) could create hours of operation to less than 2,920 EGU criteria pollutant NSPS) but are applicability uncertainty for both the hours annually) or limiting annual instead covered as industrial boilers regulated community and regulators. In electric sales to 219,000 MWh or less; under subpart Db (industrial, addition, we have concluded that (2) units subject to a federally institutional, and commercial boilers applicability based on actual operating enforceable permit that limits the use of NSPS) or subpart KKKK (the conditions (i.e., actual electric sales) is fossil fuels to 10 percent or less of the combustion turbine criteria pollutant not ideal because applicability would unit’s heat input capacity on an annual NSPS). not be known prior to determining basis; and (3) CHP units that are subject We solicited comment on whether, to compliance and could change annually. to a federally enforceable permit avoid implementation issues related This action finalizes applicability condition limiting annual total electric with different interpretations of criteria based on design characteristics sales to no more than their design ‘‘constructed for the purpose,’’ the total and federally enforceable permit efficiency times their potential electric and percentage electric sales criteria restrictions included in each individual output, or to no more than 219,000 should be recast to be based on permit permit. Based on restrictions, if any, on MWh, whichever is greater. conditions. The ‘‘constructed for the annual total electric sales in the 2. Applicability Specific to Newly purpose’’ language was included in the operating permit, it will be clear from Constructed Steam Generating Units original subpart Da rulemaking. At that the time of construction whether or not time, the vast majority of new steam a new unit is subject to this rule. The In CAA section 111(a)(2), a ‘‘new generating units were clearly base load applicability includes all utility boilers source’’ is defined as any stationary units. The ‘‘constructed for the and IGCC units unless the electric sales source, the construction or modification purpose’’ language was intended to restriction was in the original and of which is commenced after the exempt industrial CHP units. These remains in the current operating permit publication of regulations (or if earlier, units tend to be relatively small and without any lapses (this is to be proposed regulations) prescribing a were not the focus of the rulemaking. In consistent with the ‘constructed for the standard of performance under this addition, units not meeting the electric purpose of’ criteria in subpart Da). We section which will be applicable to such sales applicability criteria in subpart Da have concluded that this approach is source. Accordingly, for purposes of this would be covered by other NSPS so equivalent to, but clearer than, the rule, a newly constructed steam there is limited regulatory incentive, or existing language used in subpart Da. In generating EGU is a unit that fits the impact to the environment, for owners/ addition, we have concluded that it is definition and applicability criteria of a operators to avoid applicability with the important for both the 111(b) and 111(d) fossil fuel-fired steam generating EGU utility NSPS. However, for new units, requirements for electric-only steam and commences construction on or after there is no corresponding industrial unit generating units that the permit January 8, 2014, which is the date that CO2 NSPS and existing units could restriction limiting annual electric sales the proposed standards were published debate their original intent (i.e., the be included in both the original and for those sources (see 79 FR 1430).
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3. Applicability Specific to Modified meets a final emission limitation of typically advances performance of a Steam Generating Units 1,400 lb CO2/MWh-g. The final standard technology beyond current levels of In CAA section 111(a)(4), a of performance is less stringent than the performance. 79 FR 1465, 1471. ‘‘modification’’ is defined as ‘‘any proposed emission limitation of 1,100 lb Similarly, promotion of technology physical change in, or change in the CO2/MWh-g. This change, as will be innovation can be a relevant factor in method of operation of, a stationary discussed in greater detail later in this BSER determinations. Id. and Section source’’ that either ‘‘increases the preamble, is in response to public III.H.3.d above. For these reasons, the amount of any air pollutant emitted by comments and reflects both a re- EPA at proposal voiced concerns about such source or . . . results in the examination of the potential BSER adopting standards that would allow an emission of any air pollutant not technologies and the most recent, IGCC to comply without utilizing CCS previously emitted.’’ The EPA, through reliable information regarding for slip-stream control. Id. at 1471. The technology costs. A newly constructed regulations, has determined that certain final standard of 1,400 lb CO2/MWh-g, types of changes are exempt from fossil fuel-fired supercritical utility adopted as a means of assuring boiler will be able to meet the final consideration as a modification.180 reasonableness of costs, allows IGCC For purposes of this rule, a modified standard by implementing post- units to comply without using partial steam generating EGU is a unit that fits combustion carbon capture treating a CCS. Thus, although the standard can be slip-stream of the combustion flue gas. the definition and applicability criteria met by a highly efficient new IGCC unit Alternative potential compliance paths of a fossil fuel-fired steam generating using approximately 3 percent partial are to build a new IGCC unit and co-fire EGU and that modifies on or after June CCS (see Sections V.E and V.H.7 below), 18, 2014, which is the date that the with natural gas (or use pre-combustion carbon capture on a slip-stream), or for the EPA does not believe that proposed standards were published for a supercritical utility boiler to co-fire implementation of partial CCS at such a those sources (see 79 FR 34960). with natural gas. low level, while technically feasible, is 4. Applicability Specific to The EPA of course realizes that the the option that utilities and project Reconstructed Steam Generating Units final standard of performance (1,400 lb developers will choose. The EPA believes that IGCC project developers The NSPS general provisions (40 CFR CO2/MWh-g) differs from the proposed standard (1,100 lb CO2/MWh-g). The will either choose to meet the final part 60, subpart A) provide that an standard by co-firing with natural gas— existing source is considered a new EPA notes further, however, that the methodology for determining the final which would be a less costly and very source if it undertakes a straightforward process for a new IGCC ‘‘reconstruction,’’ which is the standard of performance is identical to that at proposal—determining that a unit—or they will choose to install CCS replacement of components of an new highly efficient generating equipment that will allow the facility to existing facility to an extent that: (1) The technology implementing some degree achieve much deeper CO2 reductions fixed capital cost of the new of partial CCS is the BSER, with that than required by this rule—likely to co- components exceeds 50 percent of the degree of implementation being produce chemicals and/or to capture fixed capital cost that would be required determined based on the reasonableness large volumes of CO2 for use in EOR to construct a comparable entirely new of costs. A key means of assessing the operations. Similarly, project developers facility, and (2) it is technologically and reasonableness of cost at proposal was may also—as an alternative to utilizing economically feasible to meet the comparison of the levelized cost of partial CCS technology—meet the final applicable standards.181 electricity (LCOE) with that of other For purposes of this rule, a standard by co-firing approximately 40 dispatchable, base load non-NGCC reconstructed steam generating EGU is a percent natural gas in a new highly generating options. We have maintained unit that fits the definition and efficient SCPC EGU. that approach in identifying BSER for applicability criteria of a fossil fuel-fired While the EPA does not find that the final standard. Applying this steam generating EGU and that IGCC technology—either alone or with methodology to the most recent cost reconstructs on or after June 18, 2014, implementation of partial CCS—is part information has led the EPA to adopt which is the date that the proposed of the BSER for new steam generating the final standard of performance of EGUs, we remain convinced that it is standards were published for those 1,400 lb CO /MWh-g. See Section V.H at 2 technically feasible (see Section V.E sources (see 79 FR 34960). Table 8 below. This final standard below) and believe that it represents a B. Best System of Emission Reduction reflects the level of emission reduction achievable by a highly efficient SCPC viable alternative compliance option 1. BSER for Newly Constructed Steam implementing the degree of partial CCS that some project developers will Generating Units that remains cost comparable to the consider to meet the final standard In the January 2014 proposal, the EPA other non-NGCC dispatchable base load issued in this action. The EPA notes proposed that highly efficient new generating options. further that IGCC is available at generation technology implementing The BSER for newly constructed reasonable cost (see Table 9 below), and partial CCS is the BSER for GHG steam generating EGUs in the final rule involves use of an advanced technology. emissions from new steam generating is very similar to that in the proposal. So, although the final standard reflects EGUs. (See generally 79 FR 1468–1469.) In this final action, the EPA finds that performance of a BSER which includes In this final action, the EPA has a highly efficient new SCPC EGU partial CCS, even in the instances that determined that the BSER for newly implementing partial CCS to the degree a compliance alternative might be constructed steam generating units is a necessary to achieve an emission of utilized, that alternative would both new highly efficient supercritical 1,400 lb CO2/MWh-g is the BSER. result in emission reductions consistent pulverized coal (SCPC) boiler Contrary to the January 2014 proposal, with use of the BSER, and would reflect implementing partial CCS technology to the EPA finds that IGCC technology— many of the underlying principles and the extent of removal efficiency that either alone or implementing partial attributes of the BSER (costs are both CCS—is not part of the BSER, but rather reasonable, not greatly dissimilar than 180 40 CFR 60.2, 60.14(e). is a viable alternative compliance BSER, no collateral adverse impacts on 181 40 CFR 60.15. option. As noted at proposal, a BSER health or the environment, and reflects
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performance of an advanced 2. BSER for Modified Steam Generating for those units. The final standard for technology). Units those sources that implement larger In reaching the final standard of The EPA has determined that, as modifications is a unit-specific emission performance, the EPA is aware that at proposed, the BSER for steam generating limitation consistent with each proposal, the agency stated that it was units that trigger the modification modified unit’s best one-year historical not ‘‘currently considering’’ a standard provisions is the modified unit’s own performance (during the years from 2002 to the time of the modification), of performance as high as 1,400 lb CO / best potential performance. However, as 2 but does not include the additional two MWh-g. 79 FR 1471. However, in that explained below, the final BSER percent reduction that was proposed in same discussion, the EPA noted the determination and the scope of the January 2014 proposal. reasons for its reservations (chiefly modifications to which the final In this action, the EPA is not reservations about the extent of standards apply differ in some important respects from what the EPA finalizing standards for those sources emission reductions, promotion of that conduct smaller modifications and advanced CO control technologies, and proposed. 2 The EPA proposed that the modified is withdrawing the proposed standards whether the standard could be met by unit’s best potential performance would for those sources. See Section XV below. either utility boilers or IGCC units co- be determined depending upon when A more detailed discussion of the firing with natural gas, or otherwise the unit implemented the modification rationale for the BSER determination complying without utilizing partial (i.e., before or after being subject to an and final standards is provided in CCS), and we specifically solicited approved CAA section 111(d) state Section VI of this preamble. comment on the issue: ‘‘We request that plan). For units that commenced 3. BSER for Reconstructed Steam commenters who suggest emission rates modification prior to becoming subject Generating Units above 1,200 lb CO2/MWh address to an approved CAA section 111(d) state potential concerns about providing plan, the EPA proposed unit-specific Consistent with our proposal, the EPA adequate reductions and technology standards consistent with each modified has determined that the BSER for development to be considered BSER.’’ unit’s best one-year historical reconstructed steam generating units is Id. The proposal thus both solicited performance (during the years from the most efficient demonstrated comment on higher emission standards 2002 to the time of the modification) generating technology for these types of (including 1,400 lb CO2/MWh-g based plus an additional two percent units (i.e., meeting a standard of on a less aggressive rate of partial CCS), reduction. For sources that commenced performance consistent with a and provided ample notice of the modification after becoming subject to reconstructed boiler using the most methodology the EPA would use to an approved CAA section 111(d) plan, efficient steam conditions available, determine the final BSER and the the EPA proposed that the unit’s best even if the boiler was not originally corresponding final standard.182 For potential performance would be designed to do so). A more detailed these reasons, the EPA believes that it determined from the results of an discussion of the rationale for the BSER provided adequate notice of this efficiency audit. determination and the final standards is potential outcome at proposal, that the The final standards in this action do provided in Section VII of this final standard of performance was not depend upon when the modification preamble. commences, as long as it commences reasonably foreseeable, and that the C. Final Standards of Performance after June 18, 2014. We are establishing final standard is a logical outgrowth of emission standards for large The EPA is issuing final standards of the proposed rule. Allina Health modifications in this rule and deferring performance for newly constructed, Services v. Sebelius, 746 F. 3d 1102, at this time the setting of standards for modified, and reconstructed affected 1107 (D.C. Cir. 2014). small modifications. steam generating units based on the A more detailed discussion of the In this final action, the EPA is issuing degree of emission reduction achievable rationale for the final BSER final emission standards for affected by application of the best system of determination and of other systems that steam generating units that implement emission reduction for those categories, were also considered is provided in larger modifications that are consistent as described above. The final standards Section V.P of this preamble.183 with the proposed BSER determination are presented below in Table 6.
TABLE 6—FINAL STANDARDS OF PERFORMANCE FOR NEW, MODIFIED, AND RECONSTRUCTED STEAM GENERATING UNITS
Source Description Final standard * lb CO2/MWh-g
New Sources ...... All newly constructed steam generating EGUs ...... 1,400.
182 Although co-firing with natural gas is not part understood a matter was under consideration when provide ‘‘policy and procedural guidance’’, are of BSER, as noted above, it could be part of a they addressed it in comments). meant to be ‘‘flexible’’ and are to be implemented compliance pathway for either SCPC or IGCC units. 183 Certain commenters maintained that the BSER differently by different agencies accounting for In this regard, a number of commenters addressed determination does not comply with (purportedly) circumstances). There are also significant factual the issue of natural gas co-firing, indicating that binding legal requirements created by regulations omissions and mischaracterizations in these there were circumstances where it could be part of implementing the Information Quality Act. These comments regarding peer review of the proposed comments are mistaken as a matter of both law and standard and underlying record information. The BSER. See e.g. Comments of Exelon Corp. p. 12 fact. The Information Quality Act does not create complete response to these comments is in chapter (Docket entry: EPA–HQ–OAR–2013–0495–9406); legal rights in third parties (see, e.g. Mississippi 2 of the RTC. See also Section V.I.2.a and N below Comments of the Sierra Club p. 108 Docket entry: Comm’n on Environmental Quality v. EPA, no. 12– describing findings of the SAB panel that materials EPA–HQ–OAR–2013–0495–9514). See Northeast 1309 at 84 (D.C. Cir. June 2, 2015)), and the OMB of the National Energy Technology Laboratory had Md. Waste Disposal Authority v. EPA, 358 F.3d 936, Guidelines are not binding rules but rather, as their been fully and adequately peer reviewed, and that 952 (D.C. Cir. 2004); Appalachian Power v. EPA, title indicates, guidance to assist agencies. See State the EPA findings related to sequestration of 135 F.3d 791, 816 (D.C. Cir. 1998) (commenters of Mississippi, 744 F.3d at 1347 (the Guidelines captured CO2 reflected the best available science.
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TABLE 6—FINAL STANDARDS OF PERFORMANCE FOR NEW, MODIFIED, AND RECONSTRUCTED STEAM GENERATING UNITS—Continued
Source Description Final standard * lb CO2/MWh-g
Modified Sources ...... Sources that implement larger modifications—those re- Best annual performance (lb CO2/MWh-g) during the sulting in an increase in hourly CO2 emissions (lb time period from 2002 to the time of the modification. CO2/hr) of more than 10 percent. Reconstructed Sources ...... Large ** ...... 1,800. Reconstructed Sources ...... Small ** ...... 2,000. * Standards are to be met over a 12-operating-month compliance period. ** Large units are those with heat input capacity of >2,000 mmBtu/hr; small units are those with heat input capacity of ≤2,000 mmBtu/hr.
For newly constructed and proposed standard and because, as A. Factors Considered in Determining reconstructed steam generating units discussed in Section V below, we are the BSER and for modified steam generating identifying alternative compliance In evaluating the final determination sources that result in larger hourly pathways for new steam generating of the BSER for newly constructed increases of CO2 emissions, the EPA is EGUs. Specifically, we have concluded steam generating units, the EPA finalizing standards in the form of a that there are unlikely to be significant considered the factors for the BSER gross energy output-based CO2 emission issues with short-term variability during described above, looked widely at all limit expressed in units of mass per initial operation, in view of both the relevant information and considered all useful energy output, specifically, in reduced numerical stringency of the the data, information, and comments pounds of CO2 per megawatt-hour (lb standard, and the availability of that were submitted during the public 184 CO2/MWh-g). The standard of compliance alternatives. The EPA notes comment period. We re-examined and performance will apply to affected EGUs that co-firing of natural gas can also updated the information that was upon the effective date of the final serve as an interim means to reduce available to us and concluded, as action. emissions if a new source operator described below, that the final standard Compliance with the final standard believes additional time is needed to of 1,400 lb CO2/MWh-g is consistent will be demonstrated by summing the phase-in the operation of a CCS system. with the degree of emission reduction emissions (in pounds of CO2) for all Therefore, the applicable final standards achievable through the implementation operating hours in the 12-operating- of performance for all newly of the BSER. This final standard of month compliance period and then constructed, modified, and performance for newly constructed dividing that value by the sum of the reconstructed steam generating units fossil fuel-fired steam generating units useful energy output (on a gross basis, must be met over a rolling 12-operating- provides a clear and achievable path i.e., gross megawatt-hours) over the month compliance period. forward for the construction of new rolling 12-operating-month compliance In the Clean Power Plan, which is a coal-fired generating sources that period. The final rule requires rounding separate rulemaking under CAA section addresses GHG emissions. of emission rates with numerical values 111(d) published at the same time as the greater than or equal to 1,000 to three present rulemaking under CAA section B. Highly Efficient SCPC EGU significant figures and rounding of rates 111(b), the EPA is promulgating Implementing Partial CCS as the BSER with numerical values less than 1,000 to emission guidelines for states to develop for Newly Constructed Steam two significant figures. Generating Units state plans regulating CO2 emissions For newly constructed steam from existing fossil fuel-fired EGUs. In the sections that follow, we explain generating units, we proposed two Existing sources that are subject to state the technical configurations that may be options for the compliance period. We plans under CAA section 111(d) may used to implement BSER to meet the proposed that a newly constructed undertake modifications or final standard, describe the operational source could choose to comply with a reconstructions and thereby become flexibilities that partial CCS offers, and 12-operating-month standard or with a subject to the requirements under then provide the rationale for the final more stringent standard over an 84- section 111(b) in the present standard of performance. After that, we operating-month compliance period, rulemaking. In the section 111(d) Clean discuss, in greater detail, consideration and we solicited comment on including Power Plan rulemaking, the EPA of the criteria for the determination of an interim 12-operating-month standard discusses how undertaking a the BSER. We describe why a highly (based on use of supercritical boiler modification or reconstruction affects an efficient new SCPC EGU implementing technology, see 79 FR at 1448). We are existing source’s section 111(d) partial CCS in the amount that results in not finalizing the proposed 84- requirements. an emission limitation of 1,400 lb CO2/ operating-month compliance period MWh-g best meets those criteria, option because the final standard of V. Rationale for Final Standards for including, among others, that such a performance for newly constructed Newly Constructed Fossil Fuel-Fired system is technically feasible, provides sources is less stringent than the Electric Utility Steam Generating Units meaningful emission reductions, can be In the discussion below, the EPA implemented at a reasonable cost, does 184 Note that the standards for sources that conduct larger modifications is a unit-specific describes the rationale and justification not pose non-air quality health and numerical standard based on the unit’s best one- of the BSER determination and the environmental concerns or impair year historical performance during the period from resulting final standards of performance energy reliability, and consequently is 2002 to the time of the modification. The unit- for newly constructed steam generating adequately demonstrated. We also specific standard will also be in the form of a gross units. We also explain why this explain why the emission standard of energy output-based CO2 emission limit expressed in pounds of CO2 per megawatt-hour (lb CO2/MWh- determination is consistent with the 1,400 lb CO2/MWh-g is achievable, g). constraints imposed by the EPAct05. including under all circumstances
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reasonably likely to occur when the IGCC unit) without CCS does not assumes that a new project developer system is properly designed and represent the BSER because it does not will construct the most efficient operated. We also discuss alternative achieve emission reductions beyond the generating technology available—i.e., a compliance options that new source sector’s business as usual, when options supercritical or ultra-supercritical utility project developers can elect to use, that do achieve more emission boiler—that will inherently generate instead of SCPC with partial CCS, to reductions are available. 79 FR 1470; see lower volumes of uncontrolled CO2 per meet the final standard of performance. also Section V.P below. We also do not MWh. See Section V.J below. A well find that a highly efficient new steam performing and highly efficient new C. Rationale for the Final Emission generating unit implementing full CCS SCPC EGU will need to implement Standards is the BSER because, at this time, the lower levels of partial CCS in order to 1. The Proposed Standards costs are predicted to be significantly meet the final standard of 1,400 lb CO2/ more than the costs for implementation MWh-g than a less efficient new steam In the January 2014 proposal, the EPA of partial CCS and significantly more generating EGU. The construction of proposed an emission limitation of than the costs for competing non-NGCC highly efficient steam generating 1,100 lb CO /MWh-g, which a new 2 base load, dispatchable technologies— EGUs—as opposed to less efficient units highly efficient utility boiler burning primarily new nuclear generation—and such as a subcritical utility boiler—will bituminous coal could have met by are, therefore, potentially unreasonable. result in lower overall costs from capturing roughly 40 percent of its CO 2 See Section V.P. decreased fuel consumption and the emissions and a new highly efficient As with the proposal, the EPA has need for lower levels of required partial IGCC unit could have met by capturing determined the final BSER and CCS to meet the final standard. and storing roughly 25 percent of its corresponding emission limitation by CO2 emissions. The captured CO2 would appropriately balancing the BSER 3. Consideration of Projects Receiving then be securely stored in sequestration criteria and determining that the Funding Under the EPAct05 repositories subject to either Class II or emission limitation is achievable. The As noted in Section III.H.3.g above, Class VI standards under the final standard of performance of 1,400 the EPA’s determination of the BSER Underground Injection Control program. lb CO2/MWh-g is less stringent than at here includes review of recently The EPA arrived at the proposed proposal and reflects changes that are constructed facilities and those planned standard by examining the available responsive to comments received on, or under construction to evaluate the CCS implementation configurations and and the EPA’s further evaluation of, the control technologies being used and concluding that the proposed standard costs to implement partial CCS. The considered. Some of the projects at the corresponding levels of partial EPA has determined that a newly discussed in the January 2014 proposal, CCS best balanced the BSER criteria and constructed highly efficient and discussed here in this preamble, resulted in an achievable emission level. supercritical utility boiler burning received or are receiving financial The EPA also proposed to find that bituminous coal can meet this final assistance under the EPAct05 (P.L. 109– highly efficient new generation emission limitation by capturing 16 58). This assistance may include implementing ‘‘full CCS’’ (i.e., more percent of the CO2 produced from the financial assistance from the than 90 percent capture and storage) facility (or 23 percent if burning Department of Energy (DOE), as well as was not the BSER because the costs of subbituminous or dried lignite), which receipt of the federal tax credit for that configuration—for both utility would be either stored in on-site or off- investment in clean coal technology boilers and IGCC units—are projected to site geologic sequestration repositories under IRC Section 48A. substantially exceed the projected costs subject to control under either the Class As noted above, the EPA interprets of other non-NGCC dispatchable VI (for geologic sequestration) or Class these provisions as allowing technologies that utilities and project II (for Enhanced Oil Recovery) standards consideration of EPAct05 facilities developers are considering (e.g., new under the UIC program. This BSER is provided that such information is not nuclear and biomass). See generally 79 technically feasible, as shown by the the sole basis for the BSER FR at 1477–78. Conversely, the EPA fact that post-combustion CCS determination, and particularly so in rejected highly efficient SCPC as the technology—both the capture and circumstances like those here, where the BSER because it would not result in storage components—is demonstrated in information is corroborative but the meaningful emission reductions from full-scale operation within the essential information justifying the any newly constructed PC unit. Id. at electricity generating industry. There determinations comes from facilities 1470. The EPA also declined to base the are also numerous operating results and other sources of information with BSER on IGCC operating alone due to from smaller-scale projects that are no nexus with EPAct05 assistance. In the same concern—lack of emission reasonably predictive of operation at the discussion below, the EPA explains reductions from a new IGCC unit full-scale. It is available at reasonable its reliance on other information in otherwise planned. Id. cost, does not have collateral adverse making the BSER determination for new non-air quality health or environmental 2. Basis for the Final Standards fossil fuel-fired steam generating units. impacts, and does not have adverse The EPA notes that information from For this final action, the EPA energy implications. facilities that did not receive any DOE reexamined the BSER options available The proposed BSER was a highly assistance, and did not receive the at proposal. Those options are: (1) efficient newly constructed steam federal tax credit, is sufficient by itself Highly efficient generation without CCS, generating EGU implementing partial to support its BSER determination. (2) highly efficient generation CCS to an emission standard of 1,100 lb D. Post-Combustion Carbon Capture implementing partial CCS, and (3) CO2/MWh-g. The final BSER is a highly highly efficient generation efficient SCPC EGU implementing In this section, we describe a variety implementing full CCS. Consistent with partial CCS to achieve an emission of facts that support our conclusion that our determination in the January 2014 standard of 1,400 lb CO2/MWh-g. In the technical feasibility of post- proposal, we remain convinced that both cases, the EPA specified that the combustion carbon capture is highly efficient generation (i.e., a new BSER includes a ‘‘highly efficient’’ new adequately demonstrated. First, we supercritical utility boiler or a new EGU implementing partial CCS. This describe the technology of post-
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combustion capture. We then describe source) that would otherwise be used to capturing roughly 75 percent of CO2 EGUs that have previously utilized or generate electricity is instead used in from the plant emissions and its are currently utilizing post-combustion the solvent regeneration process. The operators plan to increase the capture carbon capture technology. This development of advanced solvents— percentage as they optimize the discussion is complemented by later those that are chemically stable, have equipment to reach full capacity. Initial sections that explain and justify our high CO2 absorption capacities, and indications are that the facility is conclusions that the technical feasibility have low regeneration energy producing more power than predicted of other aspects of partial CCS are requirements—is an active area of and that the energy penalty (parasitic adequately demonstrated—namely, the research. Many post-combustion load—the energy needed to regenerate transportation and carbon storage (see solvents will also selectively remove the CO2 capture solvent) is much lower 191 Sections V.M. and N). Further, the other acidic gases such as SO2 and than initially predicted. Water use at conclusions of this section are hydrochloric acid (HCl), which can the facility is consistent with levels that reinforced by the discussion in Section result in degradation of the solvent. For were predicted.192 The total project V.F. below, in which we identify that reason, the CO2 scrubber systems costs—for the power plant and the commercial vendors that offer carbon are normally installed downstream of carbon capture plant—was $1.467B 193 capture technology and offer other pollutant control devices (e.g., (CAD). The CO2 from the capture performance guarantees, and discuss particulate matter and flue gas system is more than 99.999 percent pure industry and technology developers’ desulfurization controls) and in some with only trace levels of N2 in the public pronouncements of their cases, the acidic gases will need to be product stream.194 This purity is food- confidence in the feasibility and scrubbed to very low levels prior to the grade quality CO2 and is a clear availability of CCS technologies. flue gas entering the CO2 capture indication that the system is working 1. Post-Combustion Carbon Capture— system. See also RIA chapter 5 well. The captured CO2 is transported How it Works (quantifying SO2 reductions resulting by pipeline to nearby oil fields in from this scrubbing process). southern Saskatchewan where it is Post-combustion capture processes Additional information on post- being used for EOR operations. Any remove CO from the exhaust gas of a 2 combustion carbon capture—including captured CO2 that is not used for EOR combustion system—such as a utility process diagrams—can be found in a operations will be stored in nearby deep boiler. It is referred to as ‘‘post- summary technical support brine-filled sandstone formations. Thus, combustion capture’’ because the CO is 2 document.188 the Boundary Dam Unit #3 project is the product of the combustion of the demonstrating CO2 post-combustion primary fuel and the capture takes place 2. Post-Combustion Carbon Capture capture, CO2 compression and transport, after the combustion of that fuel. The Projects That Have Not Received DOE and CO2 injection for both EOR and exhaust gases from most combustion Assistance Through the EPAct05 or Tax geologic storage. The CCS system is processes are at atmospheric pressure Credits Under IRC Section 48A fully integrated with the electricity and are moved through the flue gas a. Boundary Dam Unit #3 production of the plant. system by fans. The concentration of Some commenters noted that, at 110 CO2 in most combustion flue gas SaskPower’s Boundary Dam CCS MW, the Boundary Dam Unit #3 is a streams is somewhat dilute.185 Most Project in Estevan, a city in relatively small coal-fired utility boiler post-combustion capture systems utilize Saskatchewan, Canada, is the world’s and thus, in the commenters’ view, does 186 liquid solvents that separate the CO2 first commercial-scale fully integrated not demonstrate that such a system from the flue gas in CO2 scrubber post-combustion CCS project at a coal- could be utilized at a much larger utility systems. Because the flue gas is at fired power plant. The project fully coal-fired boiler. However, there is atmospheric pressure and is somewhat integrates the rebuilt 110 MW coal-fired nothing to indicate that the post- dilute, the solvents used for post- Unit #3 with a CO2 capture system using combustion system used at Boundary combustion capture are ones that Shell Cansolv amine-based solvent to Dam could not be scaled-up for use at separate the CO2 using chemical capture 90 percent of its CO2 emissions. a larger utility boiler. In fact, the carbon absorption (or chemisorption). Amine- The facility, which utilizes local capture system at Boundary Dam #3 is based solvents 187 are the most Saskatchewan lignite, began operations designed and constructed to implement commonly used in post-combustion in October 2014 and accounts of the ‘‘full CCS’’—that is to capture more than capture systems. In a chemisorption- system’s performance describe it as 90 percent of the CO2 produced from the based separation process, the flue gas is working even ‘‘better than subcritical unit. A similarly-sized processed through the CO2 scrubber and expected.’’ 189 190 The plant started by capture system—with no need for the CO2 is absorbed by the liquid further scale-up—could be used to treat solvent and then released by heating to 188 Technical Support Document—‘‘Literature a slip-stream of a much larger Survey of Carbon Capture Technology’’, available in form a high purity CO2 stream. This the rulemaking docket (Docket ID: EPA–HQ–OAR– heating step is referred to as ‘‘solvent 2013–0495). newsandmedia/latest-news/ccs-performance-data- regeneration’’ and is responsible for 189 ‘‘[W]e are achieving better than expected’’ exceeding-expectations/. much of the ‘‘energy penalty’’ of the operation out of the plant, SaskPower’s Mike Marsh 191 Correspondence between Mike Monea capture system. Steam from the boiler said April 8, 2015 in Washington, DC, summarizing (SaskPower) and Nick Hutson (EPA), February 20, 2015. (or potentially from another external the status of the first-of-a-kind plant in Saskatchewan, Canada, known as Boundary Dam 192 30 percent of the water used for cooling comes Unit 3. Marsh spoke at a meeting of the National from the recycled or reclaimed water from the 185 The typical concentration of CO2 in the flue Coal Council, which advises the Energy Department process itself; namely, water in the coal is gas of a coal-fired utility boiler is roughly around on coal-related topics. From ‘‘Bolstering EPA’s reclaimed. 15 volume percent. NSPS, Canadian CCS Plant Working ‘Better Than 193 About $1.2B USD; roughly $700M (USD) for 186 A solvent is a substance (usually a liquid) that Expected’ ’’, Climate Daily News, Inside EPA/ the carbon capture system, which was on budget. dissolves a solute (a chemically different liquid, climate (April 08, 2015); www.insideepa.com 194 ‘‘Boundary Dam—The Future is Here’’, solid or gas), resulting in a solution. (subscription required). plenary presentation by Mike Monea at the 12th 187 190 Amines are derivatives of ammonia (NH3) ‘‘CCS performance data exceeding International Conference on Greenhouse Gas where one or more hydrogen atoms have been expectations at world-first Boundary Dam Power Technologies (GHGT–12), Austin, TX (October replaced by hydrocarbon groups. Station Unit #3’’, http://www.saskpowerccs.com/ 2014).
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supercritical utility boiler (a new unit of facility. However, the same carbon demonstrates achievability of standard approximately 500 to 600 MW) in order capture equipment could be used to of performance). As mentioned above, to meet the final standard of treat approximately 50 percent of the the post-combustion capture technology performance of 1,400 lb CO2/MWh-g, flue gas from a 220 MW facility—or 20 used at Boundary Dam is transferrable which would only require partial CCS percent of the flue gas from a 550 MW to all other types of utility boilers. facility. Thus, the equipment that is on the order of approximately 16 to 23 b. AES Warrior Run and Shady Point percent (depending on the coal used). currently working very well (in fact, A ‘‘slip-stream’’ is a portion of the ‘‘better than expected’’) at the Boundary AES’s coal-fired Warrior Run flue gas stream that can be treated Dam plant can be utilized for partial (Cumberland, MD) and Shady Point separately from the bulk exhaust gas. It carbon capture at a much larger coal- (Panama, OK) plants are both circulating is not an uncommon configuration for fired unit without the need for further fluidized bed (CFB) coal-fired power the flue gas from a coal-fired boiler to scale-up. plants with carbon capture amine be separated into two or more streams The experience at Boundary Dam is scrubbers developed by ABB/Lummus. and treated separately in different directly transferrable to other types of The scrubbers were designed to process control equipment before being post-combustion sources, including a slip-stream of each plant’s flue gas. At recombined to exit from a common those using different boiler types and the 180 MW Warrior Run Plant, a plant stack.195 A slip-stream configuration is those burning different coal types. There that burns bituminous coal, often used to treat a smaller portion of is nothing to suggest that the Shell approximately 10 percent of the plant’s the bulk flue gas stream as a way of CanSolv process would not work with CO2 emissions (about 110,000 metric testing or demonstrating a control other coal types and indeed, the latest tons of CO2 per year) has been captured device or measurement technology. For NETL cost estimates assume that the since 2000 and sold to the food and implementation of post-combustion capture technology would be used in a beverage industry. At the 320 MW partial carbon capture, a portion of the new unit using bituminous coal.197 The Shady Point Plant, a plant that burns a bulk flue gas stream would be treated EPA is unaware of any reasons why the blend of bituminous and subbituminous separately to capture approximately 90 Boundary Dam technology would not be coals, CO2 from an approximate 5 transferrable to another utility boiler at percent slip-stream (about 66,000 metric percent of the CO2 from that smaller slip-stream of the flue gas. For example, a different location at a different tons of CO2 per year) has been captured elevation or climate because the control since 2001. The captured CO2 from the in order to capture 20 percent of the CO2 technology is not climate or elevation- Shady Point Plant is also sold for use in produced by a coal-fired utility boiler, 198 an operator would treat approximately dependent. the food processing industry. While 25 percent of the bulk flue gas stream Commenters also noted that the these projects do not demonstrate the (rather than treating the entire stream). Boundary Dam Unit #3 project received CO2 storage component of CCS, they financial assistance from both the Approximately 90 percent of the CO clearly demonstrate the technical 2 Canadian federal government and from viability of partial CO would be captured from the slip-stream 2 capture. The the Saskatchewan provincial gas, resulting in an overall capture of capture of CO2 from a slip-stream of the government. But the availability of—or about 20 percent. bulk flue gas, as described earlier, is the the lack of—external financial In its study on the cost and most economical method for capturing assistance does not affect the technical performance of a range of carbon less than 90 percent of the CO2. The feasibility of the technology. capture rates, the DOE/NETL amounts of partial capture that these Commenters further characterized determined that the slip-stream sources have demonstrated—up to 10 Boundary Dam as a ‘‘demonstration approach was the most economical for percent—is reasonably similar to the project’’. These descriptors are beside carbon capture of less than 90 percent level, at 16 to 23 percent, that the EPA the point. Regardless of what the project predicts would be needed by a new of the total CO .196 The advantage of the 2 is called or how it was financed, the highly efficient steam utility boiler to slip-stream approach is that the capture project clearly shows the technical meet the final standard of performance. system will be sized to treat a lower feasibility of full-scale, fully integrated These facilities, which have been volume of flue gas flow, which reduces implementation of available post- operating for multiple years, clearly the size of the CO absorption columns, 2 combustion CCS technology, which in show the technical feasibility of post- induced draft fans, and other this case also appears to be combustion carbon capture. equipment, leading to lower capital and commercially viable. operating costs. The EPA notes that, although there is c. Searles Valley Minerals The carbon capture system at ample additional information Since 1978, the Searles Valley Boundary Dam does not utilize the slip- corroborating that post-combustion CCS Minerals soda ash plant in Trona, CA stream configuration because it was is technically feasible, which we has used post-combustion amine designed to achieve more than 90 describe below, the performance at scrubbing to capture approximately percent capture rates from the 110 MW Boundary Dam Unit #3 alone would be 270,000 metric tons of CO2 per year sufficient to support that conclusion. from the flue gas of a coal-fired power 195 See Figure 1A from Atmospheric Essex Chemical Corp., 486 F. 2d at 436 Environment, 43, 3974 (2009), for an example of plant that generates steam and power for this type of configuration. (test results from single facility on-site use. The captured CO2 is used 196 ‘‘Cost and Performance of PC and IGCC for a for the carbonation of brine in the Range of Carbon Capture’’, Rev 1 (2013), DOE/ 197 In fact, in ‘‘Cost and Performance Baseline for process of producing soda ash.199 Again, NETL–2011/1498 p. 2 (‘‘A literature search was Fossil Energy Plants Volume 1a: Bituminous Coal while the captured CO2 is not conducted to verify that <90 percent CO2 capture (PC) and Natural Gas to Electricity Revision 3’’, is most economical using a ‘slip-stream’ (or bypass) DOE/NETL–2015/1723 (July 2015), Exh.2–3 the approach. Indeed, the slip-stream approach is more Shell Cansolv process is used as the capture process 198 Dooley, J. J., et al. (2009). ‘‘An Assessment of cost-effective for <90 percent CO2 capture than for a new SCPC unit using bituminous coal rather the Commercial Availability of Carbon Dioxide removing reduced CO2 fractions from the entire flue than the subcritical PC unit at Boundary Dam that Capture and Storage Technologies as of June 2009’’. gas stream, according to multiple peer-reviewed uses Canadian lignite. The study evidently assumes U.S. DOE, Pacific Northwest National Laboratory, studies.’’ See also id. at 19, 21, 77, and 478 that the CanSolv process can be used effectively for under Contract DE–AC05–76RL01830. (documenting further that treating a slip-stream is bituminous coal since this type of coal is assumed 199 IEA (2009), World Energy Outlook 2009, the most economical approach). for cost estimation purposes. OECD/IEA, Paris.
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sequestered, this project clearly received funding under EPAct05 from According to NRG, the Petra Nova demonstrates the technical feasibility of the Department of Energy, but that does Carbon Capture Project will utilize ‘‘a the amine scrubbing system for CO2 not disqualify them from being proven carbon capture process,’’ jointly capture from a coal-fired power considered. See Section III.H.3 above. developed by Mitsubishi Heavy plant.200 The fact that this system is an Industries, Ltd. (MHI) and the Kansai industrial coal-fired power plant rather a. Petra Nova WA Parish Project Electric Power Co., that uses a high- than a utility coal-fired power plant is Petra Nova, a joint venture between performance solvent for CO2 absorption irrelevant as they both serve a similar NRG Energy Inc. and JX Nippon Oil & and desorption.204 In using the MHI purpose—the production of electricity. Gas Exploration, is constructing a high-performance solvent, the Petra Each of these processes indicate a commercial-scale post-combustion Nova project will benefit from pilot- willingness of industry to utilize carbon capture project at Unit #8 of scale testing of this solvent at Alabama available post-combustion technology NRG’s WA Parish generating station Power’s Plant Barry and at other for capture of CO2 for commercial southwest of Houston, Texas. The installations. WA Parish Unit #8 came purposes. Not one of the CO2 capture project is designed to utilize partial CCS on-line in 1982 and is thus an existing systems at Warrior Run, Shady Point, or by capturing approximately 90 percent source that will not be subject to final Searles Valley was installed for of the CO2 from a 240 MW slip-stream standards of performance issued in this regulatory purposes or as government- of the 610 MW WA Parish facility. The action. However, because it will be funded demonstration projects. They project is expected to be operational in capturing roughly 35 percent of the CO2 were installed to capture CO2 for 2016 and thus does not yet directly generated by the facility, its emissions commercial use. The fact that the demonstrate the technical feasibility or will be below the final new source captured CO2 was utilized rather than performance of the MHI amine emission limitation of 1,400 lb CO2/ being stored is of no consequence in the scrubbing system. However, this project MWh-g.205 consideration of the technical feasibility is a clear indication that the developers The captured CO2 from the WA Parish of post-combustion CO2 capture have confidence in the technical CO2 Capture Project will be used in EOR technology. These commercial feasibility of the post-combustion operations at mature oil fields in the operations have helped to improve the carbon capture system. Gulf Coast region. Using EOR at performance of scrubbing systems that Hilcorp’s West Ranch Oil Field, the The project was originally envisioned are available today. For example, the production is expected to be boosted as a 60 MW slip-stream demonstration heat duty (i.e., the energy needed to from around 500 barrels per day to and received DOE Clean Coal Power remove the CO ) has been reduced by approximately 15,000 barrels per day. 2 Initiative (CCPI) funding (as provided in about 5 times from the amine process Thus the project will utilize all aspects EPAct05) on that basis. The developers originally used at the Searles Valley of CCS by capturing CO at the large later expanded the project to the larger 2 facility. The amine scrubbing process coal-fired power plant, compressing the 240 MW slip-stream because of the need used at Boundary Dam is equally CO2, transporting it by pipeline to the efficient, and the amine scrubbing to capture greater volumes of CO2 for EOR operations, and injecting it for EOR system to be used at the Petra Nova WA EOR operations. No additional DOE or and eventual geologic storage. Parish project (Thompsons, TX) is other federal funding was obtained for The carbon capture system at WA 201 the expansion from a 60 MW slip-stream Parish will utilize a slip-stream projected to be as well. 202 to a 240 MW slip-stream. configuration. However, as noted, the 3. Post-Combustion Carbon Capture At 240 MW, the Petra Nova project system is designed to capture roughly Projects That Received DOE Assistance will be the largest post-combustion 35 percent of the CO from WA Parish Through the EPAct05, but Did Not 2 carbon capture system installed on an Unit #8 (90 percent of the CO2 from the Receive Tax Credits Under IRC Section existing coal-fueled power plant. The 240 MW slip-stream from the 610 MW 48A project will use for EOR or will unit). A carbon capture system of the The EPA considers the experiences sequester 1.6 million tons of captured same size as that used at WA Parish from the CCS projects described above, CO2 each year. The project is expected could be used to treat a 240 MW slip- coupled with evidence that the design to be operational in 2016. stream from a 1,000 MW unit in order of CCS is well accepted (also described In 2014 project materials,203 the to meet the final standard of above) and the strong support that CCS project developer NRG recognized the performance of 1,400 lb CO2/MWh-g. has received from vendors and others importance of CCS technology by Again, the experience at the WA (described below) to adequately noting: Parish Unit #8 project will be directly demonstrate that post-combustion The technology has the potential to transferable to post-combustion capture partial CCS is technically feasible. The enhance the long-term viability and at a new utility boiler, even though WA EPA finds that additional projects, sustainability of coal-fueled power plants Parish Unit #8 is an existing source that described next, provide more support across the U.S. and around the world. . . . has been in operation for over 30 years. for that conclusion. These projects Post-combustion carbon capture is essential In fact, retrofit of such technology at an so that we can use coal to sustain our energy existing unit can be more challenging 200 Moreover, the final rule allows alternative ecosystem while we begin reducing our than incorporating the technology into means of storage of captured CO2 based on a case- carbon footprint. the design of a new facility. The by-case demonstration of efficacy. See Section V.M.4 below. 202 201 Thus, even if the project received DOE 204 The WA Parish project (described earlier) will The heat duty for the amine scrubbing process ® used at Searles Valley in the mid-70’s was about 12 assistance for the initial 60 MW design, the utilize the KM–CDR Process , which was jointly expansion of the project from 60 MW to 240 MW MJ/mt CO2 removed as compared to a heat duty of developed by MHI and the Kansai Electric Power TM about 2.5 MJ/mt CO2 removed for the amine should not be considered a DOE-assisted project. In Co., Inc. and uses the proprietary KS–1 high- processes used at Boundary Dam and to be used at any case, as described above, even without performance solvent for the CO2 absorption and WA Parish. ‘‘From Lubbock, TX to Thompsons, consideration of this facility at all, other desorption. 205 TX—Amine Scrubbing for Commercial CO2 Capture information adequately demonstrates the technical Using emissions data reported to the Acid from Power Plants’’, plenary address by Prof. Gary feasibility of post-combustion CCS. Rain Program, the EPA estimates that the CO2 203 Rochelle at the 12th International Conference on WA Parish CO2 Capture Project Fact Sheet; emissions from the WA Parish Unit #8 will be Greenhouse Gas Technology (GHGT–12), Austin, available at www.nrg.com/documents/business/pla- 1,250–1,300 lb CO2/MWh-g during operations with TX (October 2014). 2014-petranova-waparish-factsheet.pdf (2014). the post-combustion capture system.
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experience will be directly transferrable explaining in detail how its pilot-scale than conventional capture to other types of post-combustion work could be scaled up to successful processes.’’ 211 sources including those using different full-scale operation, and to E. Pre-Combustion Carbon Capture boiler types and those burning different accommodate the operating needs of a coals. The amine scrubbing and full-scale EGU, including reliable As described earlier, the EPA does not associated systems are not boiler type- generating capacity capable of cycling find that IGCC technology—either alone or coal-specific. The EPA is unaware of up and down to accommodate consumer or implementing partial CCS—is part of any reasons that the technology utilized demand. Recommended design changes the BSER for newly constructed steam at the WA Parish plant would not be to accomplish the desired scaling generating EGUs. However, as noted, transferrable to another utility boiler at included detailed flue gas there may be specific circumstances and a different location at a different specifications, ranges for temperature, business plans—such as co-production of chemicals or fertilizers, or capture of elevation or climate, given that the moisture and SO2 content; careful technology is not dependent on either scrutiny of makeup water composition CO2 for use in EOR operations—that climate or topography. and temperature; quality and quantity of encourage greater CO2 emission reductions than are required by this b. AEP/Alstom Mountaineer Project available steam to accommodate heat cycle based on unit load changes; and standard. In this section, we describe In September 2009, AEP began a pilot- detailed scrutiny of material and energy and justify our conclusion that the scale CCS demonstration at its balances.208 See Section V.G.3 below, technical feasibility of pre-combustion Mountaineer Plant in New Haven, WV. addressing in more detail the record carbon capture is adequately The Mountaineer Plant is a very large support for how CCS technology can be demonstrated, indicating that this could (1,300 MW) coal-fired unit that was be a viable alternative compliance retrofitted with Alstom’s patented scaled up to commercial size in both pre- and post-combustion applications. pathway. First, we explain the chilled ammonia CO2 capture technology of pre-combustion capture. technology on a 20 MWe slip-stream of c. Southern Company/MHI Plant Barry We then describe EGUs that have the plant’s exhaust flue gas. In May previously utilized or are currently 2011, Alstom Power announced the In June 2011, Southern Company and utilizing pre-combustion carbon capture successful operation of the chilled Mitsubishi Heavy Industries (MHI) technology. This discussion is ammonia CCS validation project. The launched operations at a 25 MW coal- complemented by other sections that demonstration achieved capture rates fired carbon capture facility at Alabama conclude the technical feasibility of from 75 percent (design value) to as Power’s Plant Barry. The facility, which other aspects of partial CCS are high as 90 percent, and produced CO2 completed the initial demonstration adequately demonstrated—namely, at a purity of greater than 99 percent, phase, captured approximately 165,000 post-combustion carbon capture with energy penalties within a few metric tons of CO2 annually at a CO2 (Section V.D) and sequestration percent of predictions. The facility capture rate of over 90 percent. The (Sections V.M and V.N). Further, this reported robust steady-state operation facility employed the KM CDR Process, section’s conclusions are reinforced by during all modes of power plant which uses a proprietary high Section V.F, in which we identify 209 operation, including load changes, and performing solvent for CO2 commercial vendors that offer CCS saw an availability of the CCS system of absorption and desorption that was performance guarantees as well as 206 greater than 90 percent. jointly developed by MHI and Japanese developers that have publicly stated AEP, with assistance from the DOE, utility Kansai Electric Power Co. The their confidence in CCS technologies. had planned to expand the slip-stream captured CO2 has been transported via demonstration to a commercial scale, pipeline approximately 12 miles to the 1. Pre-Combustion Carbon Capture— fully integrated demonstration at the Citronelle oil field where it is injected How It Works Mountaineer facility. The commercial- into the Paluxy formation, a saline Pre-combustion capture systems are scale system was designed to capture at reservoir, for storage.210 typically used with IGCC processes. In least 90 percent of the CO from 235 2 Project participants have reported that a gasification system, the fuel (usually MW of the plant’s 1,300 MW total ‘‘[t]he plant performance was stable at coal or petroleum coke) is heated with capacity. Plans were for the project to be the full load condition with CO capture water and oxygen in an oxygen-lean completed in four phases, with the 2 rate of 500 TPD at 90 percent CO environment. The coal (carbon), water system to begin commercial operation in 2 removal and lower steam consumption and oxygen react to form primarily a 2015. However, in July 2011, AEP mixture of hydrogen (H2) and carbon announced that it would terminate its monoxide (CO) known as synthesis gas cooperative agreement with the DOE Project. Phase 1’’, pp 10–11; available at: http:// www.globalccsinstitute.com/publications/aep- or syngas according to the following and place its plans to advance CO2 mountaineer-ii-project-front-end-engineering-and- high temperature reaction: capture and storage technology to design-feed-report. 3C + H2O + O2 → H2 + 3CO commercial scale on hold. AEP cited the 208 Id. at 11. The EPA does not view this In an IGCC system, the resulting uncertain status of U.S. climate policy information as being affected by the constraints in EPAct05. The information does not relate to use of syngas, after removal of the impurities, as a contributor to its decision, but did technology, level of emission reduction by reason can be combusted using a conventional not express doubts about the feasibility of use of technology, achievement of emission combustion turbine in a combined cycle of the technology. See Section V.L reduction by demonstration of technology, or configuration (i.e., a combustion turbine below. demonstration of a level of performance. The FEED study rather explains engineering challenges which combined with a HRSG and steam AEP also prepared a Front End would remain at full scale and how those 207 turbine). The gasification process also Engineering & Design (FEED) Report, challenges can be addressed. 209 typically produces some amount of This is the same carbon capture system that 212 206 http://www.alstom.com/press-centre/2011/5/ is being utilized at the Petra Nova project at the CO2 as a by-product along with other alstom-announces-sucessful-results-of- NRG WA Parish plant. mountaineer-carbon-capture-and-sequestration-ccs- 210 Ivie, M.A. et al.; ‘‘Project Status and Research 211 Id. 212 project/. Plans of 500 TPD CO2 Capture and Sequestration The amount of CO2 in syngas depends upon 207 ‘‘CCS front end engineering & design report: Demonstration at Alabama Power’s Plant Barry’’, the specific gasifier technology used, the operating American Electric Power Mountaineer CCS II Energy Procedia 37, 6335 (2013). conditions, and the fuel used; but is typically less
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gases (e.g., H2S) and inorganic materials synthetic natural gas that is ultimately described IGCC gasification system. As originating from the coal (e.g., minerals, transported for use in home heating and with the IGCC gasification system, the 214 ash). The amount of CO2 in the syngas electricity generation. Dakota Gasification facility gasifies coal can be increased by ‘‘shifting’’ the Capture of CO2 from the facility began (lignite) to produce a syngas which is composition via the catalytic water-gas in 2000. The Synfuels Plant, using a pre- then shifted to increase the ® shift (WGS) reaction. This process combustion Rectisol process, captures concentration of CO2 and to produce the involves the catalytic reaction of steam about 3 million tons of CO2 per year— desired ratio of CO and H2. As with the (‘‘water’’) with CO (‘‘gas’’) to form H2 more CO2 from coal conversion than any IGCC gasification system, the CO2 is and CO2 according to the following facility in the world, and is a participant then removed in a pre-combustion catalytic reaction: in the world’s largest carbon capture system, and the syngas that CO + H2O → CO2 + H2 sequestration project. On average about results is made further use of. For An emission standard that requires 8,000 metric tons per day of captured present purposes, only the manner in CO2 from the facility is sent through a which the syngas is used distinguishes partial capture of CO2 from the syngas could be met by adjusting the level of 205-mile pipeline to oil fields in the IGCC gasification system from the Saskatchewan, Canada, where it is used Dakota Gasification facility. In the IGCC CO2 in the syngas stream by controlling the level of syngas ‘‘shift’’ prior to for EOR operations that result in process, the syngas is combusted. In the treatment in the pre-combustion acid permanent CO2 geologic storage. The Dakota Gasification facility, the syngas gas treatment system. If a high level of geologic sequestration of CO2 in the oil is processed through a catalytic reservoir is monitored by the methanation process where the CO and CO2 capture is required, then multi- stage WGS reactors will be needed and International Energy Agency (IEA) H2 react to produce CH4 (methane, synthetic natural gas) and water. an advanced hydrogen turbine will Weyburn CO2 Monitoring and Storage Importantly, the CO capture system likely be needed to combust the Project. 2 that is used in the Dakota Gasification resulting hydrogen-rich syngas. Several commenters to the January Most syngas streams are at higher 2014 proposal argued that the Great facility can readily be used in an IGCC pressure and can contain higher Plains Synfuels facility is not an EGU, EGU. There is no indication that the that it operates as a chemical plant, and RECTISOL® process (or other similar concentrations of CO2 (especially if shifted to enrich the concentration). As that its experience is not translatable to physical gas removal systems) is not feasible for an IGCC EGU. In such, the pre-combustion capture an IGCC using pre-combustion carbon confirmation, according to product systems can utilize physical absorption capture technology. The commenters literature, RECTISOL®, which was (physisorption) solvents rather than the noted that the Dakota facility can be independently developed by Linde and chemical absorptions solvents described operated nearly continuously without Lurgi, is frequently used to purify earlier. Physical absorption has the the need to adjust operations to meet shifted, partially shifted or un-shifted benefit of relying on weak cyclic electricity generation demands. In gas from the gasification of coal, lignite, intermolecular interactions and, as a the January 2014 proposal, the EPA had noted that, while the facility is not an and residual oil.216 result, the absorbed CO2 can often be released (desorbed) by reducing the EGU, it has significant similarities to an b. International Projects IGCC and the implementation of the pressure rather than by adding heat. Pre- There are some international projects combustion capture systems have been pre-combustion capture technology would be similar enough for that are in various stages of used widely in industrial processes development that indicate confidence such as natural gas processing. comparison. See 79 FR at 1435–36 and n. 11. We continue to hold this view. by developers in the technical feasibility Additional information on pre- of pre-combustion carbon capture. combustion carbon capture can be As explained above, in an IGCC gasification system, coal (or petroleum Summit Carbon Capture, LLC is found in a summary technical support developing the Caledonia Clean Energy document.213 coke) is gasified to produce a synthesis gas comprised of primarily CO, H2, and Project, a proposed 570-megawatt IGCC 2. Pre-Combustion Carbon Capture some amount of CO2 (depending on the plant with 90 percent CO2 capture that Projects That Have Not Received DOE gasifier and the specific operating would be built in Scotland, U.K. Assistance Through EPAct05 or Tax conditions). A water-gas-shift reaction Captured CO2 from the plant will be Credits Under IRC Section 48A using water (H2O, steam) is then used to transported via on-shore and sub-sea pipeline for sequestration in a saline a. Dakota Gasification Great Plains shift the syngas to CO2 and H2. The formation in the North Sea. The U.K. Synfuels Plant more the syngas is ‘‘shifted,’’ the more enriched it becomes in H . In an IGCC, Department of Energy & Climate Change Each day, the Dakota Gasification 2 power can be generated by directly (DECC) recently announced funding to Great Plains Synfuels Plant uses combusting the un-shifted syngas in a allow for feasibility studies for this approximately 18,000 tons of North 217 conventional combustion turbine. If the plant. Commercial operation is Dakota lignite in a coal gasification 218 syngas is shifted such that the resulting expected in 2017. process that produces syngas (a mixture syngas is highly enriched in H , then a The China Huaneng Group—with of CO, CO , and H ), which is then 2 2 2 special, advanced hydrogen turbine is multiple collaborators, including converted to methane gas (synthetic needed. If CO is to be captured, then Peabody Energy, the world’s largest natural gas) using a methanation 2 the syngas would need to be shifted private sector coal company—is process. Each day, the process produces either fully or partially, depending upon building the 400 MW GreenGen IGCC an average of 145 million cubic feet of the level of capture required.215 216 _ The Dakota Gasification process bears www.linde-engineering.com/en/process than 20 volume percent (http://www.netl.doe.gov/ plants/hydrogen_and_synthesis_gas_plants/gas_ research/coal/energy-systems/gasification/ essential similarities to the just- processing/rectisol_wash/index.html. gasifipedia/syngas-composition). 217 http://www.downstreambusiness.com/item/ 213 Technical Support Document—‘‘Literature 214 http://www.dakotagas.com/Gasification/. Summit-Power-Wins-Funding-Studies-Proposed- Survey of Carbon Capture Technology’’, available in 215 ‘‘Cost and Performance of PC and IGCC for a IGCC-CCS-Project_140878. the rulemaking docket (Docket ID: EPA–HQ–OAR– Range of Carbon Capture’’, Rev 1 (2013), DOE/ 218 http://www.summitpower.com/projects/ 2013–0495). NETL–2011/1498. carbon-capture/.
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facility in Tianjin City, China. The goal Kansas. The plant began operation in the Plant’s CO2 [. . .] a process referred to as TM is to complete the power plant before 2000 and is the only one in North Selexol is applied to remove the CO2 such that it is suitable for compression and 2020. Over 80 percent of the CO2 will America using a petroleum coke-based be separated using pre-combustion fertilizer production process. The delivery to the sequestration and EOR process. [. . .] The carbon capture capture technology. The captured CO2 petroleum coke is generated at an oil equipment and processes proposed in this 219 will be used for EOR operations. refinery adjacent to the plant. The project have been in commercial use in the Vattenfall and Nuon’s pilot project in petroleum coke is gasified to produce a chemical industry for decades and pose little Bugennum, The Netherlands involves hydrogen rich synthetic gas, from which technology risk. (emphasis added) 224 carbon capture from coal- and biomass- ammonia and urea ammonium nitrate Thus, Mississippi Power believes that, fired IGCC plants. It has operated since fertilizers are subsequently synthesized. because the SelexolTM process has been 2011.220 As a by-product of manufacturing in commercial use in the chemical Approximately 100 tons of CO2 per fertilizers, the plant also produces industry for decades, it is well proven, day are captured from a coal- and significant amounts of CO . In March 2 and will pose little technical risk when petcoke-fired IGCC plant in Puertollano, 2011, Chaparral Energy announced a used in the Kemper IGCC EGU. Spain. The facility began operating in long-term agreement for the purchase of 221 2010. captured CO2 which is transported 68 b. Texas Clean Energy Project and Emirates Steel Industries is expected miles via CO2 pipeline for use in EOR Hydrogen Energy California Project to capture approximately 0.8Mt of CO2 operations in Osage County, OK. per year from a steel-production facility The Texas Clean Energy Project Injection at the site started in 2013. (TCEP), a 400 MW IGCC facility located in the United Arab Emirates. Full-scale At least one commenter suggested that near Odessa, Texas will capture 90 operations are scheduled to begin by the cost and complexity of carbon percent of its CO , which is 2016.222 capture from these and other industrial 2 approximately 3 million metric tons The Uthmaniyah CO2 EOR projects was significantly decreased annually. The captured CO will be Demonstration Project in Saudi Arabia because the sources already separate 2 used for EOR in the West Texas Permian will capture 0.8 Mt of CO2 from a CO as part of their normal operations. 2 Basin. Additionally, the plant will natural gas processing plant over three The EPA finds this argument produce urea and smaller quantities of years. It is expected to begin operating unconvincing. The Coffeyville process commercial-grade sulfuric acid, argon, in 2015.223 involves gasification of a solid fossil and inert slag, all of which will also be The experience of the Dakota fuel (pet coke), shifting the resulting marketed. Summit has announced that Gasification facility, coupled with the syngas stream, and separation of the they expect to commence construction descriptions of the technology in the resulting CO using a pre-combustion 2 on the project in 2015.225 The facility literature, the statements from vendors, carbon capture system. These are the will utilize the Linde Rectisol® gas and the experience of facilities same, or very similar, processes that are cleanup process to capture carbon internationally, are sufficient to support used in an IGCC EGU. The argument is dioxide 226—the same process that has our determination that the technical even less convincing when considering been deployed for decades, including at feasibility of CCS for an IGCC facility is that the Coffeyville Fertilizer process the Dakota Gasification facility, a clear adequately demonstrated. The uses the SelexolTM pre-combustion indication of the developer’s confidence experience of additional facilities, capture process—the same process that in that technology and further evidence described next, provides additional Mississippi Power described as having that the Dakota Gasification carbon support. been ‘‘in commercial use in the capture technology is transferable to chemical industry for decades’’ and is 3. Pre-Combustion Carbon Capture EGUs. Projects That Have Received DOE expected by Mississippi Power to ‘‘pose Assistance Through EPAct05, but Did little technology risk’’ when used at the F. Vendor Guarantees, Industry Not Receive Tax Credits Under IRC Kemper IGCC EGU. Statements, Academic Literature, and Commercial Availability Section 48A 4. Pre-Combustion Carbon Capture a. Coffeyville Fertilizer Projects That Have Received DOE In this section, we describe additional Assistance Through EPAct05 and Tax information that supports our Coffeyville Resources Nitrogen Credits Under IRC Section 48A determination that CCS is adequately Fertilizers, LLC, owns and operates a demonstrated to be technically feasible. a. Kemper County Energy Facility nitrogen fertilizer facility in Coffeyville, This includes performance guarantees Southern Company’s subsidiary from vendors, public statements from 219 http://sequestration.mit.edu/tools/projects/ Mississippi Power has constructed the industry officials, and review of the greengen.html. Kemper County Energy Facility in 220 Buggenum Fact Sheet: Carbon Dioxide Capture literature. Kemper County, MS. This is a 582 MW and Storage Project, Carbon Capture & 1. Performance Guarantees Sequestration Technologies @MIT, http:// IGCC plant that will utilize local sequestration.mit.edu/tools/projects/ Mississippi lignite and includes a pre- The D.C. Circuit made clear in its first buggenum.html. combustion carbon capture system to cases concerning CAA section 111 221 Puertollano Fact Sheet: Carbon Dioxide Capture and Storage Project, Carbon Capture & reduce CO2 emissions by approximately standards, and has affirmed since then, Sequestration Technologies @MIT, https:// 65 percent. The pre-combustion solvent, sequestration.mit.edu/tools/projects/ SelexolTM has also been used 224 Mississippi Power Company, Kemper County puertollanto.html. extensively for acid gas removal IGCC Certificate Filing, Updated Design, 222 ESI CCS Project Fact Sheet: Carbon Dioxide Description and Cost of Kemper IGCC Project, (including for CO2 removal) in various and Storage Project, Carbon Capture & Mississippi Public Service Commission (MPSC) Sequestration Technologies @MIT, https:// processes. In filings with the DOCKET NO. 2009–UA–0014, filed December 7, sequestration.mit.edu/tools/projects/esi_ccs.html Mississippi Public Service Commission 2009. and https://www.globalccsinstitute.com/projects/ for the Kemper project, Mississippi 225 ‘‘Odessa coal-to-gas power plant to break large-scale-ccs-projects. described the carbon capture system: ground this year’’, Houston Chronicle (April 1, 223 Uthmaniyah CO2 EOR Demonstration Project, 2015). Global CCS Institute, https://www.global The Kemper County IGCC Project will 226 http://www.texascleanenergyproject.com/ ccsinstitute.com/projects/large-scale-ccs-projects. capture and compress approximately 65% of project/.
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that performance guarantees from In addition, other well-established removing CO2 from their exhaust vendors are an important basis for companies that either offer technologies streams, with the added benefit of supporting a determination that that are actively marketed for CO2 simultaneously lowering SO2 and NO2 pollution technology is adequately capture from fossil fuel-fired power emissions. demonstrated to be technically feasible. plants or that develop those power At least one commenter suggested that In 1973, in Essex Chem. Corp. v. plants, have publicly expressed it is unlikely that any vendor is willing Ruckelshaus, 486 F.2d 427, 440 (D.C. confidence in the technical feasibility of or able to provide guarantees of the Cir. 1973), the Court upheld standards carbon capture. For example, Fluor has performance of the system as a whole, of performance for coal-fired steam developed patented CO2 recovery arguing that this shows the system isn’t generators based on ‘‘prototype testing technologies to help its clients reduce adequately demonstrated.233 However, data and full-scale control systems, GHG emissions. The Fluor product this suggestion is inconsistent with the considerations of available fuel literature 230 specifically points to the performance guarantees offered for other supplies, literature sources, and Econamine FG PlusSM (EFG+) process, air pollution control equipment. documentation of manufacturer which uses an amine solvent to capture Particulate matter (PM) is controlled in guarantees and expectations’’ (emphasis and produce food grade CO2 from post- the flue gas stream of a coal-fired power supplied)).227 Subsequently, in Sierra combustion sources. The literature plant using fabric filters or electrostatic Club v. Costle, the Court noted, in further notes that EFG+ is also used for precipitators (ESP). The captured PM is upholding the standard: ‘‘we find it carbon capture and sequestration then moved using PM/ash handling informative that the vendors of FGD projects, that the proprietary technology systems and is then transported for equipment corroborate the achievability provides a proven, cost-effective process storage or re-use. It is unlikely that a 228 of the standard.’’ for the removal of CO2 from power plant fabric filter or ESP vendor would Linde and BASF offer performance flue gas streams, and that the process provide a performance guarantee for guarantees for carbon capture can be customized to meet a power ‘‘the system as a whole.’’ Similarly, a technology. The two companies are plant’s unique site requirements, flue wet-FGD scrubber vendor would not be jointly marketing new, advanced gas conditions, and operating expected to provide a performance technology for capturing CO2 from low parameters. guarantee for handling, transportation, pressure gas streams in power or Fluor has also published an article and re-use of scrubber solids for gypsum chemical plants. In product titled ‘‘Commercially Available CO2 wallboard manufacturing. CO2 capture, literature,229 they note that Linde will Capture Technology’’ in which it transportation, and storage should, provide a turn-key carbon capture plant describes the EFG+ technology.231 The similarly, not be viewed as a single using a scrubbing process and solvents article notes, ‘‘Technology for the technology. Rather, these should be developed by BASF, one of the world’s removal of carbon dioxide (CO2) from viewed as components of an overall leading technical suppliers for gas flue gas streams has been around for system of emission reduction. Different treatment. They further note that: quite some time. The technology was companies will have expertise in each The captured carbon dioxide can be used developed not to address the GHG effect of these components, but it is unlikely commercially for example for EOR (enhanced but to provide an economic source of that a single technology vendor would oil recovery) or as a building block for the CO2 for use in enhanced oil recovery provide a guarantee for ‘‘the system as production of urea. Alternatively it can be and industrial purposes, such as in the a whole.’’ stored underground as a carbon abatement beverage industry.’’ 2. Academic and Other Literature measure. [. . .] The PCC (Post-Combustion Mitshubishi Heavy Industries (MHI) Capture) technology is now commercially offers a CO2 capture system that uses a Climate change mitigation options— available for lignite and hard coal fired proprietary energy-efficient CO including CCS—are the subject of great power plant [. . .] applications. 2 absorbent called KS–1TM. Compared academic interest, and there is a large The alliance between Linde, a world- body of academic literature on these leading gases and engineering company and with the conventional BASF, the chemical company, offers great monoethanolamine (MEA)-based options and their technical feasibility. benefits [. . .] Complete capture plants absorbent, KS–1TM solvent requires less In addition, other research organizations including CO2 compression and drying . . . solvent circulation to capture the CO2 (e.g., U.S. national laboratories and Proven and tested processes including and less energy to recover the captured others) have also published studies on guarantee . . . Synergies between process, CO2. these subjects that demonstrate the engineering, construction and operation . . . In addition, Shell has developed the availability of these technologies. A Optimized total and operational costs for the compendium of relevant literature is owner. (emphasis added) CANSOLV CO2 Capture System, which Shell describes in its product provided in a Technical Support 232 Document available in the rulemaking 227 See also Portland Cement Ass’n v. literature as a world leading amine 234 Ruckelshaus, 486 F.2d 375, 401–02 (D.C. Cir. 1973) based CO2 capture technology that is docket. (‘‘It would have been entirely appropriate if the ideal for use in fossil fuel-fired power Administrator had justified the standards . . . on 3. Additional Statements by Technology plants where enormous amounts of CO2 Developers testimony from experts and vendors made part of are generated. The company also notes the record.’’). The discussion above of vendor 228 Sierra Club v. Costle, 657 F.2d 298, 364 (D.C. that the technology can help refiners, Cir. 1981). See also National Petrochem & Refiners utilities, and other industries lower guarantees, positive statements by Assn v. EPA, 287 F. 3d 1130, 1137 (D.C. Cir. 2002) their carbon intensity and meet industry officials, and the academic (noting that vendor guarantees are an indicia of stringent GHG abatement regulations by literature supports the EPA’s availability and achievability of a technology-based determination that partial CCS is standard since, notwithstanding a desire to promote sales, ‘‘a manufacturer would risk a considerable 230 www.fluor.com/client-markets/energy- adequately demonstrated to be loss of reputation if its technology could not fulfill chemicals/Pages/carbon-capture.aspx. a mandate that it had persuaded EPA to adopt’’). 231 http://www.powermag.com/commercially- 233 Comments of Murray Energy, p. 73, (Docket 229 www.intermediates.basf.com/chemicals/web/ available-co2-capture-technology/. entry: EPA–HQ–OAR–2013–0495–10046). gas-treatment/en/function/conversions:/publish/ 232 http://www.shell.com/global/products- 234 Technical Support Document—‘‘Literature content/products-and-industries/gas-treatment/ services/solutions-for-businesses/globalsolutions/ Survey of Carbon Capture Technology’’, available in images/Linde_and_BASF-Flue_Gas_Carbon_ shell-cansolv/shell-cansolv-solutions/co2- the rulemaking docket (Docket ID: EPA–HQ–OAR– Capture_Plants.pdf. capture.html. 2013–0495).
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technically feasible. Industry officials As discussed above, vendors do in 2. Must a technology or system of have made additional positive fact offer performance guarantees. We emission reduction be in full-scale use statements in conjunction with facilities further note that, as noted above, to be considered demonstrated? that received DOE assistance under Boundary Dam Unit #3 is a full-scale Commenters maintained that the EPA EPAct05 or the IRC Section 48A tax project that is successfully can only show that a BSER is credit. These statements provide further, implementing full CCS with post- ‘‘adequately demonstrated’’ using although not necessary, support. combustion capture, and Dakota operating data from the technology or For example, Southern Company’s Gasification is likewise a full-scale system of emission reduction itself. This Mississippi Power has stated that, commercial operation that is is mistaken. Since the very inception of because the SelexolTM process has been successfully implementing pre- the CAA section 111 program, courts used in industry for decades, the combustion CCS technology. Moreover, have noted that ‘‘[i]t would have been technical risk of its use at the Kemper as we explain above, this technology entirely appropriate if the Administrator IGCC facility is minimized. For and performance is transferable to the had justified the standard, not on the example: steam electric generating sector. In basis of tests on existing sources or old The carbon capture process being utilized addition, as noted above, technology test data in the literature, but on for the Kemper County IGCC is a commercial providers and technology end users extrapolations from this data, on a technology referred to as SelexolTM. The have expressed confidence in the reasoned basis responsive to comments, SelexolTM process is a commercial availability and performance of CCS and on testimony from experts and technology that uses proprietary solvents, but technology.239 vendors . . . .’’ Portland Cement v. is based on a technology and principles that 241 G. Response to Key Comments on the Ruckelshaus, 486 F. 2d at 401–02. have been in commercial use in the chemical In a related argument, other Adequacy of the Technical Feasibility industry for over 40 years. Thus, the risk commenters stated that a system cannot associated with the design and operation of Demonstration the carbon capture equipment incorporated be adequately demonstrated unless all into the Plant’s design is manageable.235 1. Commercial Availability of its component parts are operating And . . . together.242 Courts have, in fact, The carbon capture equipment and Some commenters asserted that CCS accepted that the EPA can legitimately processes proposed in this project have been cannot be considered the BSER because infer that a technology is demonstrated in commercial use in the chemical industry it is not commercially available. There as a whole based on operation of for decades and pose little technology risk.236 is no requirement, as part of the BSER component parts which have not, as yet, Similarly, in an AEP Second Quarter determination, that the EPA finds that been fully integrated. Sur Contra la 2011 Earnings Conference Call, the technology in question is Contaminacion v. EPA, 202 F. 3d 443, Chairman and CEO Mike Morris said of ‘‘commercially available.’’ As we 448 (1st Cir. 2000); Native Village of the Mountaineer CCS project: described in the January 2014 proposal, Point Hope v Salazar 680 F. 3d 1123, the D.C. Circuit has explained that a 1133 (9th Cir. 2012). Moreover, all We are encouraged by what we saw, we’re standard of performance is ‘‘achievable’’ components of CCS are fully integrated clearly impressed with what we learned, and if a technology or other system of we feel that we have demonstrated to a at Boundary Dam: Post-combustion full certainty that the carbon capture and storage emission reduction can reasonably be CCS is being utilized at a steam electric is in fact viable technology for the United projected to be available to new sources fossil fuel-fired plant, with captured States and quite honestly for the rest of the at the time they are constructed that will carbon being transported via dedicated world going forward.237 allow them to meet the standard, and pipeline to both sequestration and EOR that there is no requirement that the Some commenters have claimed that sites. All components are likewise technology ‘‘must be in routine use CCS technology is not technically demonstrated for pre-combustion CCS at somewhere.’’ See Portland Cement v. feasible, and some further assert that the Dakota Gasification facility, except Ruckelshaus, 486 F. 2d at 391; 79 FR vendors do not offer performance that the facility does not generate 1463. In any case, as discussed above, guarantees. For example, Alstom electricity, a distinction without a CCS technology is available through commented: difference for this purpose (see Section vendors who provide performance V.E.2.a above). The EPA referenced projects fail to meet guarantees, which indicates that in fact, The short of it is that the ‘‘EPA does the ‘technically feasible’ criteria. These CCS is commercially available, which have authority to hold the industry to a technologies are not operating at significant adds to the evidence that the technology standard of improved design and scale at any site as of the rule publication. We do not support mandating technology is adequately demonstrated to be based on proposed projects (many of which technically feasible. In sum, ‘‘[t]he Natural Gas to Electricity Revision 3’’, DOE/NETL– 2015/1723 (July 2015) at p. 36. may never be built).238 capture and CO2 compression technologies have commercial operating 241 More recently, the D.C. Circuit stated: Our prior decisions relating to technology-forcing 235 Testimony of Thomas O. Anderson, Vice experience with demonstrated ability standards are no bar to this conclusion. We 240 President, Generation Development for Mississippi for high reliability.’’ recognize here, as we have recognized in the past, Power, MS Public Service Commission Docket that an agency may base a standard or mandate on 2009–UA–14 at 22 (Dec. 7, 2009). 239 We note that before filing comments for this future technology when there exists a rational 236 Mississippi Power Company, Kemper County rule asserting that CCS is not technically feasible, connection between the regulatory target and the IGCC Certificate Filing, Updated Design, Alstom issued public statements that, like the other presumed innovation. Description and Cost of Kemper IGCC Project, industry officials quoted above, affirmed that CCS API v. EPA, 706 F. 3d at 480 (D.C. Cir. 2013) Mississippi Public Service Commission (MPSC) is technically feasible. According to an Alstom (citing the section 111 case Sierra Club v. Costle, DOCKET NO. 2009–UA–0014, filed December 7, Power press release, Alstom President Phillipe 657 F. 2d at 364). The Senate Report to the original 2009. Joubert, referencing results from an internal Alstom section 111 likewise makes clear that it was not 237 American Electric Power Co Inc AEP Q2 2011 study, stated at an industry meeting: ‘‘We can now intended that the technology ‘‘must be in actual Earnings Call Transcript, Morningstar, http:// be confident that carbon capture technology (CCS) routine use somewhere.’’ Rather, the question was www.morningstar.com/earnings/28688913- works and that it is cost-effective’’. http:// whether the technology would be available for american-electric-power-co-incaep-q2–2011- www.alstom.com/press-centre/2011/6/2011-06-16- installation in new plants. S. Rep. No. 91–1196, earnings-call-transcript.aspx. CCS-cost-competiveness/. 91st Cong., 2d Sess. 16 (1970). 238 Alstom Comments, p. 3 (Docket entry: EPA– 240 ‘‘Cost and Performance Baseline for Fossil 242 See, e.g., Comments of UARG p. 5 (Docket HQ–OAR–2013–0495–9033). Energy Plants Volume 1a: Bituminous Coal (PC) and entry: EPA–HQ–OAR–2013–0495–9666).
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operational advances, so long as there is generator system, balance of plant, and capture.’’ 246 This statement—and most substantial evidence that such accessory electric plant, and of the statements in this vein—are in improvements are feasible and will instrumentation and control systems.244 reference to implementation of full CCS produce the improved performance It is important to note that, while systems that capture more than 90 necessary to meet the standard.’’ Sierra some commenters challenged the EPA’s percent of the CO2 and many reference Club, 657 F. 2d at 364. The EPA’s task use of costs in the DOE/NETL cost and widespread implementation of such is to ‘‘identify the major steps necessary performance reports, commenters did technology. The EPA has addressed the for development of the device, and give not challenge the technical methodology concerns regarding ‘‘significant cost’’ by plausible reasons for its belief that the in the work. finalizing a standard that relies on industry will be able to solve those partial CCS which we show, in this problems in the time remaining’’. API v. In addition, the AEP FEED study preamble and in the supporting record, EPA, 706 F. 3d at 480 (quoting NRDC v. indicates how the development scale can be implemented at a reasonable, EPA, 655 F. 2d 318, 333 (D.C. Cir. 1981), post-combustion CCS could be non-exorbitant cost. The Boundary Dam and citing Sierra Club for this successfully scaled up to full-scale facility, in particular, demonstrates that proposition). operation. See Section V.D.3.b above. the complexities of implementing Tenaska Trailblazer Partners, LLC also CCS—even full CCS—can be overcome. 3. Scalability of Pilot and Demonstration 245 Projects prepared a FEED study for the carbon Concerns regarding ‘‘operating issues’’ capture portion of the previously are also often associated with Commenters maintained that the EPA proposed Trailblazer Energy Center, a implementation of full CCS—and often had no basis for maintaining that pilot 760 MW SCPC EGU that was proposed with implementation of full CCS as a and demonstration plant operations to include 85 to 90 percent CO2 post- retrofit to an existing source. showed that CCS was adequately combustion capture. Tenaska selected Implementation of CCS at some existing demonstrated. This is mistaken. In a the Fluor Econamine FG PlusSM sources may be challenging because of 1981 decision, Sierra Club v. Costle, the technology and contracted Fluor to space limitations. That should not be an D.C. Circuit explained that data from conduct the FEED study. One of the issue for a new facility because the pilot-scale, or less than full-scale goals of the FEED study was to developer will need to ensure that operation, can be shown to reasonably ‘‘[c]onfirm that scale up to a large adequate space is available during the demonstrate performance at full-scale commercial size is achievable.’’ Tenaska design of the facility. Constructing CCS operation, although it is incumbent on ultimately concluded that the study had technology at an existing facility can be the EPA to explain the necessary steps achieved its objectives resulting in challenging even if there is adequate involved in scaling up a technology and ‘‘[c]onfirmation that the technology can space because the positioning of the how any obstacles may reasonably be be scaled up to constructable design at 243 equipment may be awkward when it surmounted when doing so. The EPA commercial size through (1) process and must be constructed to fit with the has done so here. discipline engineering design and CFD existing equipment at the plant. Some Most obviously, the final standard (computational fluid dynamics) commenters noted the challenges of reflects experience of full-scale analysis, (2) 3D model development, diverting steam from the plant’s steam operation of post-combustion carbon and (3) receipt of firm price quotes for cycle. Again, that is primarily an issue capture. Pre-combustion carbon capture large equipment.’’ with full CCS implementation as a is likewise demonstrated at full-scale. retrofit to an existing source. Second, the record explains in detail Much has been written about the how CCS can be implemented at full- complexities of adding CCS systems to Consideration of steam requirements for scale. The NETL cost and performance fossil fuel-fired power plants. Some of solvent regeneration can be factored into reports, indeed, contain hundreds of these statements come from high the design of a new facility. We also pages of detailed, documented government officials. Some commenters note that issues of integration with the explanation of how CCS can be argued that the EPA minimized—or plant’s steam cycle are less challenging implemented at full-scale for both even ignored—these publically voiced when implementing partial CCS. Some commenters noted conclusions utility boiler and IGCC facilities. See, for concerns in the discussion presented in example, the detailed description of the the January 2014 proposal. On the and statements from the CCS Task Force following systems projected to be contrary, the EPA has not minimized or report as contradictory to the EPA’s needed for a new supercritical PC boiler ignored these complexities, but it is determination of that partial CCS is technically feasible and adequately to capture CO2: Coal and sorbent important to realize that most of these receiving and storage, steam generator statements come in a different context: demonstrated. However, the EPA mentioned in the January 2014 and ancillaries, NOX control system, Namely, implementing full CCS, or particulate control, flue gas retrofitting CCS onto existing power 246 Report of the Interagency Task Force on desulfurization, flue gas system, CO2 plants. For example, in the Final Report Carbon Capture and Storage (August 2010), page 28. recovery facility, steam turbine of the President’s CCS Task Force, it See also DOE Carbon Capture Web site: ‘‘First was noted that ‘‘integration of CCS generation CO2 capture technologies are currently 243 Sierra Club v. Costle, 657 F. 2d 298, 341 n.157 technologies with the power cycle at being used in various industrial applications. and 380–84 (D.C. Cir. 1981). See also Essex generating plants can present significant However, in their current state of development, Chemical Corp. v. EPA, 486 F. 2d at 440 (upholding these technologies are not ready for implementation achievability of standard of performance for coal- cost and operating issues that will need on coal-based power plants because they have not burning steam generating plants which hadn’t been to be addressed to facilitate widespread, been demonstrated at appropriate scale, requisite achieved in full-scale performance based in part on cost-effective deployment of CO2 approximately one-third of the plant’s steam power ‘‘prototype testing data’’ which, along with vendor to operate, and are cost prohibitive.’’ (Dec 2010); guarantees, indicated that the promulgated standard and Testimony of Dr. S. Julio Friedmann, Deputy was achievable); Weyerhaeuser v. Costle, 590 F. 2d 244 Cost and Performance Baseline for Fossil Asst. Secretary of Energy for Clean Coal, U.S. Dept. 1054 n. 170 (D.C. Cir. 1978) (use of pilot plant Energy Plants Volume 1: Bituminous Coal and of Energy, before the Subcommittee on Oversight information to justify technology-based standard for Natural Gas to Electricity; Revision 2a, pp. 57–74. and Investigations Committee on Energy and Best Available Technology Economically 245 Final front-end engineering design (FEED) Commerce (Feb. 11, 2014): CCS technologies at new Achievable under section 304 of the Clean Water study report’’, available at: coal-fired plants would result in ‘‘something like a Act); FMC Corp. v. Train, 539 F. 2d 973, 983–84 www.globalccsinstitute.com/publications/tenaska- 70 to 80 percent increase on the wholesale price of (4th Cir. 1976)(same). trailblazer-front-end-engineering-design-feed-study. electricity.’’
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proposal, and we emphasize again here, standard. The EPA found that the specifically nuclear and biomass—from that the Task Force was charged with anticipated cost impacts are similar to the EIA AEO 2013. See 79 FR 1435. proposing a plan to overcome the those in other promulgated NSPS— In addition, the EPA proposed that barriers to the widespread, cost-effective including for this industry—that have the costs to implement partial CCS were deployment of CCS by 2020. Implicit in been upheld by the D.C. Circuit. The reasonable because a segment of the all of the conclusions, costs are also comparable to those of industry was already accommodating recommendations, and statements of other base load technologies that might them. Id. at 1478. The EPA also that final report is a goal of widespread be selected on comparable energy considered anticipated decreases in the implementation of full CCS—including portfolio diversity grounds. Finally, the cost of CCS technologies, the retrofits of existing sources. This final EPA does not anticipate any significant availability of government tax benefits, action does not require—nor does it overall nationwide costs or cost impacts loan guarantees, and direct envision—the near term widespread on consumers because projected new expenditures, and the opportunity to implementation of full CCS. On the generating capacity is expected to meet generate income from sale of captured contrary, as we have noted several times the standards even in the baseline. CO2 for EOR. Id. at 1478–80. The EPA in this preamble, the EPA and others Accordingly, after considering costs noted that the proposed standard was predict that very few, if any, new coal- from a range of different perspectives, not expected to lead to any significant fired steam generating EGUs will be the EPA concludes that the costs of the overall costs or effects on electricity built in the near term. final standard are reasonable. prices. Id. at 1480–81. The EPA also Thus, the EPA has provided an ample acknowledged the overall market record supporting its finding that partial 1. Rationale at Proposal context, noting that fossil steam EGUs, CCS is feasible at full-scale. As in Sierra even without any type of CCS, are At proposal, the EPA evaluated the Club, the EPA has presented evidence significantly more expensive than new costs of new coal-fired EGUs from full-scale operation, smaller scale natural gas-fired electricity generation, implementing full (90 percent) and installations, and reasonable, but that some electricity suppliers might partial CCS. The EPA compared the corroborated technical explanations of include new coal-fired generating predicted LCOE of those units against how the BSER can be successfully sources in their generation portfolio, the LCOE of other new dispatchable operated at full scale. See 657 F. 2d at and would pay a premium to do so. Id. technologies often considered for new 380, 382. Indeed, the EPA has more at 1478. evidence here, as the baghouse standard base load power with fuel diversity, in Sierra Club was justified based primarily including a new nuclear 2. Brief Summary of Cost Considerations largely on less-than-full-scale operation. plant, as well as a new biomass-fired Under CAA Section 111 See 657 F.2d at 380 (there was only EGU. See 79 FR at 1475–78. The As explained above, CAA section ‘‘limited data from one full scale levelized cost for a new steam EGU 111(a) directs the EPA to ‘‘tak[e] into commercial sized operation’’), 376 (‘‘the implementing full CCS was higher than account the cost’’ of achieving baghouses surveyed were installed at that of the other non-NGCC dispatchable reductions in determining if a particular small plants’’), and 341 n.157; see also technologies, and we did not propose to system of emission reduction is the best Section V.L, explaining why CCS is a identify a new steam EGU implementing that is adequately demonstrated. The more developed technology than FGD full CCS as BSER on that basis. Id. at statute does not provide further scrubbers were at the inception of the 1477. The EPA proposed that a standard guidance on how costs should be 1971 NSPS for this industry. of performance of 1,100 lb CO2/MWh-g, considered, thus affording the EPA reflecting a new steam EGU H. Consideration of Costs considerable discretion in choosing a implementing partial CCS, could be means of cost consideration. In CAA section 111(a) defines ‘‘standard achieved at reasonable cost based on a addition, it should be noted that in of performance’’ as an emission comparison of the projected LCOE evaluating the reasonableness of costs, standard that reflects the best system of associated with achieving this standard the D.C. Circuit has upheld application emission reduction that is adequately with the alternative dispatchable of a variety of metrics, such as the demonstrated, ‘‘taking into account technologies just mentioned. In the amount of control costs or product price [among other things] the cost of January 2014 proposal, the EPA used increases. See Section III.H.3.(b).(1) achieving such reduction.’’ Based on LCOE projections for new fossil fuel- consideration of relevant cost metrics in above. fired EGUs from a series of studies Following the directive of CAA the context of current market conducted by the DOE NETL. These section 111(a) and applicable precedent, conditions, the EPA concludes that the studies—the ‘‘cost and performance the EPA evaluated relevant metrics and costs associated with the final standard studies’’—detail expected costs and context in considering the are reasonable. performance for a range of technology reasonableness of the regulation’s costs. In reaching this determination, the options both with and without CCS.247 EPA considered a host of different cost The EPA’s findings demonstrate that the The EPA used LCOE projections for costs of the selected final standard are metrics, each of which illuminated a non-fossil dispatchable generation— particular aspect of cost consideration, reasonable. and each of which demonstrated that 247 For the cost estimates in the January 2014 3. Current Context the costs of the final standard are proposal, the EPA used costs for new SCPC and The EIA projects that few new coal- reasonable. The EPA evaluated capital IGCC units utilizing bituminous coal from the fired EGUs will be constructed over the costs on a per-plant basis, responding to reports ‘‘Cost and Performance Baseline for Fossil coming decade and that those that are public comment that noted the Energy Plants Volume 1: Bituminous Coal and Natural Gas to Electricity’’, Revision 2, Report DOE/ built will apply CCS, reflecting the particular significance of capital costs NETL–2010/1397 (November 2010) and ‘‘Cost and broad consensus of government, for coal-fired EGUs. As in the proposal, Performance of PC and IGCC Plants for a Range of academic, and industry forecasters.248 the EPA also considered how the Carbon Dioxide Capture’’, DOE/NETL–2011/1498, May 27, 2011. Additional cost and performance standard would affect the LCOE for information can be found in additional volumes 248 Even in its sensitivity analysis that assumes individual affected EGUs as well as that are available at http://www.netl.doe.gov/ higher natural gas prices and electricity demand, national, overall cost impacts of the research/energy-analysis/energy-baseline-studies. EIA does not project any additional coal beyond its
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The primary reasons for this projected of fuel diversity was considered in IRPs; This cost-reasonable standard will trend include low electricity demand in many cases, these plans considered preserve the opportunity for such growth, highly competitive natural gas new generation that would not rely on projects while driving new technology prices, and increases in the supply of natural gas. In particular, several deployment.255 renewable energy. In particular, U.S. utilities that considered fuel diversity in 4. Consideration of Capital Costs electricity demand growth has followed developing their IRPs included new a downward sloping trend for decades nuclear generation as a potential future As noted above, CAA section 111 with future growth expected to remain generation strategy. does not mandate any particular method very low.249 Furthermore, the EPA In addition, the EPA recognizes that for evaluating costs, leaving the EPA projects that, for any new fossil fuel- there may be interest in constructing a with significant discretion as to how to fired electricity generating capacity that new combined-purpose coal-fired do so. One method is to consider the is constructed through 2030, natural gas facility that would generate power as incremental capital costs required for a will be the overwhelming fuel of well as produce chemicals or CO2 for unit to achieve the standard of choice.250 See RIA chapter 4. use in EOR projects. These facilities performance. The EIA’s projection is confirmed by would similarly provide additional The EPA included information on an examination of Integrated Resource value due to the revenue streams from capital cost at proposal and, as 252 Plans (IRPs) contained in a TSD in the saleable chemical products or CO2. discussed further below, the LCOE docket for this rulemaking. IRPs are As demonstrated below, the agency metric relied upon at proposal and in used by utilities to plan operations and carefully considered the reasonableness this final rulemaking incorporates and investments in both owned generation of costs in identifying a standard that fully reflects capital costs.256 and power purchase agreements over allows a path forward for such projects Nonetheless, extensive comment from long time horizons. Though IRPs do not and rejects more stringent options that industry representatives and others demonstrate a utility’s intent to pursue would impose potentially excessive noted persuasively that fossil-steam a particular generation technology, they costs. In fact, based on this careful units are very capital-intensive projects do indicate the types of new generating consideration of costs, the EPA is and recommended that a separate technologies that a utility would finalizing a substantially lower cost metric, solely of capital costs, be consider for new generating capacity. standard than the one we proposed. At considered by the EPA in evaluating the The EPA’s survey of recent IRPs the same time, we note the unusual final standard’s costs. Accordingly, the demonstrates that across the nation, circumstances presented here, where EPA has considered the final standard’s utilities are not actively considering the record, and indeed simple impact on the capital costs of new constructing new coal-fired generation consideration of electricity market fossil-steam generation. The EPA has without CCS in the near term. economics, demonstrates that non- determined that the incremental capital Accordingly, construction of new economic factors such as fuel diversity costs of the final standard are reasonable uncontrolled coal-fired generating are likely to drive any construction of because they are comparable to those in capacity is not anticipated in the near new coal-fired generation. See also RIA prior regulations and to industry term, even in the absence of the chapter 4 (documenting that electric experience, and because the fossil steam standards of performance we are power companies will choose to build electric power industry has been shown finalizing in this rule, except perhaps in new EGUs that comply with the to be able to successfully absorb capital certain limited circumstances. regulatory requirements of this rule costs of this magnitude in the past. In particular, commenters suggested even in its absence, primarily NGCC Prior new source performance that some developers might choose to units, because of existing and expected standards for new fossil steam build a new coal-fired EGU, despite its market conditions). Under these generation units have had significant— not being cost competitive, in order to circumstances, the EPA’s consideration yet manageable—impacts on the capital achieve or maintain ‘‘fuel diversity.’’ of costs takes into account that higher costs of construction. The EPA Fuel diversity could provide important costs can be viewed as reasonable when estimated that the costs for the 1971 value by serving as a hedge against the costs are not a paramount factor in new NSPS for coal-fired EGUs were $19M for possibility that future natural gas prices coal capacity decisions. At the same a 600 MW plant, consisting of $3.6M for will far exceed projected levels. time, the EPA acknowledges and agrees particulate matter controls, $14.4M for Public announcements, including with the public comments that such an sulfur dioxide controls, and $1M for IRPs, confirm that utilities are interested argument, left unconstrained, could nitrogen oxides controls, representing a in technologies that could provide or justify any standard and obviate all cost 15.8 percent increase in capital costs preserve fuel diversity within generating considerations.253 The EPA has fleets. The Integrated Resource Plan reasonably cabined its consideration of the current economic posture of the industry TSD 251 notes examples where the goal whereby new capacity is not cost-competitive and costs by examining costs for comparable so would be added for non-economic reasons, it is non-NGCC base load dispatchable not using that fact to negate consideration of cost reference case until 2023, in a case where power technologies, as well as by considering here. See also Section V.I.4 below responding to companies assume no GHGs emission limitations, 254 comments that the incremental cost of partial CCS and until 2024 in a case where power companies capital costs and other cost metrics. could prove the difference between constructing do assume GHGs emission limitations. EIA, and not constructing new coal capacity. ‘‘Annual Energy Outlook 2015,’’ DOE/EIA– 252 The EPA may, of course, consider revenues 255 In this rulemaking, our determination that the 0383(2015), April 2015, ‘‘[v]ery little unplanned generated as a result of application of pollution costs are reasonable means that the costs meet the coal-fired capacity is added across all the AEO 2015 control measures in assessing the costs of a best cost standard in the case law no matter how that cases’’, p. 26. system of emission reduction. See New York v. standard is articulated, that is, whether the cost 249 EIA, ‘‘Annual Energy Outlook 2015,’’ DOE/ Reilly, 969 F.2d 1147, 1150–52 (D.C. Cir. 1992). standard is articulated through the terms that the EIA–0383(2015), April 2015, p. 8. 253 See, e.g., Comments of Murray Energy, pp. 79– case law uses, e.g., ‘‘exorbitant,’’ ‘‘excessive,’’ etc., 250 Integrated Planning Model (IPM) run by the 80 (Docket entry: EPA–HQ–OAR–2013–0495– or through the term we use for convenience, EPA (v. 5.15) Base Case, available at www.epa.gov/ 10046). ‘‘reasonableness.’’ airmarkets/powersectormodeling.html. 254 Indeed, the EPA is not only adopting a 256 See RIA chapter 4.5.4 and Fig. 4–3; see also 251 Technical Support Document—‘‘Review of standard predicated on a lower rate of carbon ‘‘Cost and Performance Baseline for Fossil Energy Electric Utility Integrated Resource Plans’’ (May capture than proposed, but also rejecting full CCS Plants Supplement: Sensitivity to CO2 Capture Rate 2015), available in the rulemaking docket EPA–HQ– for reasons of cost. See Section V.P below. Thus, in Coal-Fired Power Plants’’, DOE/NETL–2015/1720 OAR–2013–0495. although the EPA has reasonably taken into account (July 2015) p. 17.
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above the $120M cost of the plant. See been mandated by the 1978 NSPS— upheld the EPA’s consideration of costs 1972 Supplemental Statement, 37 FR increased capital costs for new EGUs by for a standard of performance that 5767, 5769 (March 21, 1972). The D.C. 10 to as much as 20 percent.258 The would increase capital costs by about 12 Circuit upheld the EPA’s determination study further noted that air pollution percent, although the rule was that the costs associated with the final control requirements in general had led remanded due to an unrelated 1971 standard were reasonable, to an estimated 37.5 to 45 percent procedural issue. 486 F.2d at 387–88. concluding that the EPA had properly increase in capital costs for coal-fired Reviewing the EPA’s final rule after taken costs into consideration. Essex power plant installation between 1971 remand, the court again upheld the Cement v. EPA, 486 F. 2d at 440. and 1980.259 standards and the EPA’s consideration In reviewing the 1978 NSPS for coal- The study retrospectively confirmed of costs, noting that ‘‘[t]he industry has fired EGUs, the D.C. Circuit recognized the EPA’s conclusion that imposition of not shown inability to adjust itself in a that ‘‘EPA estimates that utilities will these costs was reasonable, finding that healthy economic fashion to the end have to spend tens of billions of dollars ‘‘utilities with commitments to sought by the Act as represented by the by 1995 on pollution control under the pollution control tend to fare no better standards prescribed.’’ Portland Cement new NSPS’’ and that ‘‘[c]onsumers will and no worse than all electric utilities v. Ruckelshaus, 513 F. 2d 506, 508 (D.C. ultimately bear these costs.’’ Sierra in general.’’ 260 In assessing the capital Cir. 1975). Club, 657 F.2d at 314. The court cost impacts of the suite of 1970s EPA nonetheless upheld the EPA’s air pollution standards, the report The capital cost impacts incurred determination that the standard was concluded that ‘‘though controlling under these prior standards are reasonable. Id. at 410. emissions is indeed costly, it has not comparable in magnitude on an The cost and investment impacts of played a major role in impairing the individual unit basis to those projected the 1978 NSPS on electric utilities were utilities’ financial position, and is not for the present standard. We predict that subsequently evaluated in a 1982 likely to do so in the future.’’ 261 the incremental costs of control for a Congressional Budget Office (CBO) In NSPS standards for other sectors, new highly efficient SCPC unit to meet retrospective study.257 The CBO study the EPA’s determination that capital the final emission limitation of 1,400 lb highlighted that installation of cost increases were reasonable has CO2/MWh-g would be an increase of scrubbers—capital intensive pollution similarly been upheld. In Portland 21–22 percent for capital costs. See control equipment that had ‘‘in effect’’ Cement Association, the D.C. Circuit Table 7 below.262 263
TABLE 7—COMPARISON OF ESTIMATED CAPITAL COSTS FOR A NEW SCPC AND A NEW SCPC MEETING THE FINAL STANDARD OF PERFORMANCE 264
Total overnight Total as-spent cost capital (2011$/kW) (2011$/kW)
SCPC—no CCS ...... 2,507 2,842 SCPC—partial CCS (1,400 lb CO2/MWh-g) ...... 3,042 3,458 Incremental cost increase ...... 21.3% 21.7%
By comparison, a SCPC that co-fires takes into account all costs to construct As previously mentioned, at proposal with natural gas to meet the final and operate a new power plant over an the EPA relied on LCOE projections for standard of 1,400 lb CO2/MWh-g would assumed time period and an assumed fossil fuel-fired EGUs (with and without not result in an increase in capital cost capacity factor. The LCOE is a summary CCS) from DOE/NETL reports detailing over the uncontrolled SCPC. A metric, which expresses the full cost of the results of studies evaluating the compliant IGCC unit co-firing natural generating electricity on a per unit basis costs and performance of such units. For gas is predicted to have Total Overnight (i.e., megawatt-hours). Levelized costs non-fossil dispatchable generating Cost of $3,036/kW—an approximately are often used to compare the cost of sources, the EPA relied on LCOE 21.1 percent increase in capital over the different potential generating sources. projections from EIA AEO 2013. For this uncontrolled SCPC unit. While capital cost is a useful and final action, the EPA is relying on 5. Consideration of Costs Based on relevant metric for capital-intensive updated costs from the same sources. Levelized Cost of Electricity fossil-steam units, the LCOE can serve The NETL has provided updated cost as a useful complement because it takes and performance information in As in the proposal, the EPA also into account all specified costs recently published revisions of reports considered the reasonableness of costs (operation and maintenance, fuel—as used in the January 2014 proposal.265 by evaluating the LCOE associated with well as capital costs), over the whole The updated SCPC cases in the reports the final standard. The LCOE is a lifetime of the project. include up-to-date cost and performance commonly used economic metric that information from recent vendor quotes
257 Congressional Budget Office report, ‘‘The 263 We estimate that a new SCPC EGU using low 265 ‘‘Cost and Performance Baseline for Fossil Clean Air Act, the Electric Utilities, and the Coal rank coal (subbituminous coal or dried lignite) Energy Plants: Volume 1a’’ Bituminous Coal (PC) Market’’, April 1982, p. 10–11, 23. would incur a capital cost increase of 23 percent to and Natural Gas to Electricity, Revision 3, U.S. DOE meet the final standard. See ‘‘Achievability of the 258 Id. at 10–11. NETL report (2015) and ‘‘Cost and Performance Standard for Newly Constructed Steam Generating 259 Baseline for Fossil Energy Plants: Volume 1b: Id. at 22. EGUs’’ technical support document available in the 260 Id. at xvi. rulemaking docket. Bituminous Coal (IGCC) to Electricity, Revision 2— Year Dollar Update, U.S. DOE NETL report (2015). 261 Id. 264 Exhibit A–3 (p. 18); ‘‘Cost and Performance Both reports are available at www.netl.doe.gov/ 262 We explain at Section V.I.2 and 3 below the Baseline for Fossil Energy Plants Supplement: Sensitivity to CO Capture Rate in Coal-Fired Power research/energy-analysis/energy-baseline-studies. reasonableness of the EPA’s cost projections here. 2 Plants’’, DOE/NETL–2015/1720 (June 2015).
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and implementation of the Shell project’s capital costs, the fixed and within the utilities’ respective Cansolv post-combustion capture variable operating and maintenance generating fleets.271 272 The options for process—the process that is currently (O&M) costs, the fuel costs, the costs to being utilized at the Boundary Dam #3 finance the project, and finally on the 271 See, e.g. the 2014 IRP of Dominion Virginia facility. The IGCC cost and performance assumed capacity factor.269 The relative Power: results in the updated reports utilize contribution of each of these inputs to With those factors in mind, the 2014 Plan presents two paths forward for resource expansion: vendor quotes from the previous report; LCOE will vary among the generating a Base Plan, designed using least-cost planning the costs are adjusted from $2007 to technologies. For example, the LCOE for methods and consistent with the requirements of $2011. Important also to note is that a new supercritical PC plant or a new Rule R8–60 for utility plans to provide ‘‘reliable DOE/NETL utilized conventional IGCC plant is influenced more by the electric utility service at least cost over the planning period;’’ and a Fuel Diversity Plan, which includes financing for cases without CCS and capital costs (and thus the financing a broader array of low or zero-emissions options. utilized high-risk financial assumptions assumptions) and less on fuel costs than While the Fuel 2 Diversity Plan currently represents for cases that include CCS.266 a comparably sized new NGCC facility a higher cost option at today’s current and projected Using information from those reports, which would require less capital commodity prices, its resource mix provides the important benefits of greater fuel diversity and the DOE/NETL prepared a separate investment but would be more lower carbon intensity. Therefore, the Company report summarizing a study that influenced by assumed fuel costs. will continue reasonable development of the more evaluated the cost and performance of diverse and lower carbon intensive options in the various plants designed to meet a range b. Use of the LCOE Fuel Diversity Plan and will be ready to implement them as conditions warrant. . . . The Fuel Diversity of CO2 emissions by varying the CO2 The utility industry and electricity Plan places a greater reliance on generation sources capture rate (i.e., the level of partial sector regulators often use levelized with little or no carbon emissions and is less reliant capture).267 The EIA also updated LCOE costs as a summary measure for on natural gas. While following the resource projections from AEO 2013 to AEO 2014 comparing the cost of different potential expansion scenario in the least-cost Base Plan, the Company will continue evaluation and reasonable and again in AEO 2015. Those are generating sources. Use of the LCOE as development efforts for the following projects discussed in more detail in Section a comparison measure is appropriate identified in the Fuel Diversity Plan. These include: V.I.2.b and d. In evaluating costs for the where the facilities being compared Continued development of a third nuclear reactor final standards in this action, the EPA would serve load in a similar manner. at North Anna Power Station, using reactor The value of generation, as reflected technology supplied by GE-Hitachi Nuclear Energy relied primarily on the updated NETL Americas LLC. While the Company has made no LCOE projections for new fossil fuel- in the wholesale electricity price, can final commitment to building this unit, it fired EGUs provided in the reports vary seasonally and over the course of recognizes the many operational and environmental described above and on the LCOE a day. In addition, electricity generation benefits of nuclear power and continues to actively technologies differ on dimensions other develop the project. Our customers have benefitted projections for non-fossil, dispatchable from the existing nuclear fleet for many years now, generating options from the EIA’s AEO than just cost, such as ramping and they will continue to benefit from the existing 2015.268 Here, the EPA compared the efficiency, intermittency, or uncertainty fleet for many years in the future. A final decision LCOE of the final standard to the LCOE in future fuel costs. These other factors on construction of North Anna Unit 3 will not be are also important in determining the made until after the Company receives a Combined of analogous potential sources of Operating License or COL from the U.S. Nuclear intermediate and base load power. This value of a particular generation Regulatory Commission, now expected in 2016. The comparison demonstrated that the LCOE technology to a firm, and accordingly Fuel Diversity Plan includes the addition of North for a fossil steam unit with partial CCS cost comparisons between two different Anna Unit 3’s 1,453 megawatts of zero-emissions technologies are most appropriate and generation by 2028. If constructed, the project is within the range of the LCOE of would provide a dramatic boost to the regional comparable alternative non-NGCC insightful when the technologies align economy. generation sources. In particular, along these other dimensions. Isolating Additional reliance on renewable energy, nuclear and biomass generation, which a comparison of technologies based on including 247 megawatts of onshore wind capacity similarly provide both base load power their LCOE is appropriate when they at sites in western Virginia and a 12 megawatt can be assumed to provide similar offshore wind demonstration project by 2018. and fuel diversity, have comparable An additional 559 megawatts of nameplate solar LCOE. The EPA concludes that an services and similar values of electricity capacity, including several new Company-owned evaluation of the LCOE also generated. photovoltaic CPV) installations. Solar PV costs have demonstrates that the costs of the final As we indicated in the proposal, we declined significantly in recent years, making standard are reasonable. evaluated publicly available IRPs and utility-scale solar much more cost-effective than other available information (such as distributed solar, and continuing technological a. Calculation of the LCOE development, in which the Company is public announcements) to determine the participating, may allow it to become a more cost- The LCOE of a power plant source is types of technologies that utilities are effective source of intermittent generation in the calculated with the expected lifetime considering as options for new future.cover letter for 2014 IRP—https:// and average capacity factor, and generating capacity.270 In the near www.dom.com/library/domcom/pdfs/corporate/ future, the largest sources of new fossil integrated-resource-planning/va-irp-2014.pdf. represents the average cost of producing 272 Another example are the recent statements of a megawatt-hour (MWh) of electricity fuel-fired power generation are expected officials of Tri-State Generation and Transmission, over the expected lifetime of the asset. to be new NGCC units. But the IRPs also available at http://www.wyofile.com/coal-power/, The LCOE incorporates all specified suggested that utilities are interested in including: costs, and therefore is dependent on the a range of technologies that can be used ‘‘We are considering nuclear, coal and natural gas,’’ said Ken Anderson, general manager of Tri- to provide or preserve fuel diversity State at a conference in October [2010], a position 266 Cost and Performance Baseline for Fossil that Tri-State representatives say remains. ‘‘We will Energy Plants Supplement: Sensitivity to CO2 269 See, e.g. ‘‘Cost and Performance Baseline for pick our technology once policy certainty comes Capture Rate in Coal-Fired Power Plants’’, DOE/ Fossil Energy Plants Supplement: Sensitivity to CO2 about,’’ he added. . . . Longer-term forecasts are NETL–2015/1720 (June 2015) p. 18. Capture Rate in Coal-Fired Power Plants’’, DOE/ based on assumptions that may or may not prove 267 ‘‘Cost and Performance Baseline for Fossil NETL–2015/1720 (June 2015) at p. 17. well-founded. Because of this uncertainty, Tri-State Energy Plants Supplement: Sensitivity to CO2 270 See also discussion at V.C.3 above. The IRPs believes it must retain options for all fuels and Capture Rate in Coal-Fired Power Plants’’, DOE/ do not provide an indication of the utility’s technologies. NETL–2015/1720 (June 2015). Available at http:// intention to pursue a particular generation ‘‘We will not take anything off the table,’’ [Tri- www.netl.doe.gov/research/energy-analysis/energy- technology. However, the IRPs do provide an State spokesman Lee] Boughey said. That includes baseline-studies. indication of the types of new generating coal. ‘‘Coal is an affordable and plentiful resource, 268 http://www.eia.gov/forecasts/aeo/electricity_ technologies that the utility would consider for new but it does come with challenges—and we are generation.cfm. generating capacity. Continued
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dispatchable generation that can fired plant with that of a peaking natural dispatchable power shows that the final provide intermediate or base-load power gas-fired simple cycle turbine. standard’s LCOE is comparable to that and fuel diversity would include new Similarly, it may not be appropriate to of other sources, as shown in Table 8 fossil steam units, new nuclear power, compare LCOE for dispatchable below. As mentioned earlier and and biomass-fired generation. technologies (i.e., generating sources discussed in further detail below, these that can be ramped up or down as Thus, in both the proposal and in this estimates rely most heavily on DOE/ needed, e.g., coal-fired units, NGCC final rule, the EPA is comparing the NETL cost projections for fossil fuel units, nuclear) with that of non- LCOE of technologies that would be generating technologies and on the dispatchable technologies (i.e., updated EIA AEO 2015 for non-fossil reasonably anticipated to be designed, generating sources that cannot be constructed, and operated for a similar generation technologies. Recent reliably ramped up or down to meet estimates from Lazard 273 274 are also purpose—that is, to provide demand, e.g., wind, solar.) dispatchable base load power that provided for nuclear and biomass provides fuel diversity by relying on a c. Reasonableness of Costs Based on generation options. fuel source other than natural gas. In LCOE contrast, it may not be appropriate to An examination of the LCOE of compare the LCOE for a base load coal- analogous sources of base load,
TABLE 8—PREDICTED COST AND CO2 EMISSION LEVELS FOR A RANGE OF POTENTIAL NEW GENERATION TECHNOLOGIES 275
LCOE* New generation technology Emission lb CO2/MWh-g $/MWh
SCPC—no CCS (bit) ...... 1,620 76–95 SCPC—no CCS (low rank) ...... 1,740 75–94 SCPC + ∼16% partial CCS (bit) ...... 1,400 92–117 SCPC + ∼23% partial CCS (low rank) ...... 1,400 95–121 Nuclear (EIA) ...... 0 87–115 Nuclear (Lazard) ...... 0 92–132 Biomass (EIA) 276 ...... — 94–113 Biomass (Lazard) ...... — 87–116 IGCC ...... 1,430 94–120 NGCC ...... 1,000 ** 52–86 * The LCOE ranges presented in Table 8 include an uncertainty of ¥15%/+30% on capital costs for SCPC and IGCC cases and an uncertainty of ¥10%/+30% on capital costs for nuclear and biomass cases from EIA. This reflects information provided by EIA. Nuclear staff experts expect that nuclear plants currently under construction would not have capital costs under estimates and that one could expect to see a 30% ‘‘upside’’ variation in capital cost. There is also insufficient market data to get a good statistical range of potential capital cost variation (i.e. only 2 plants under construction, neither complete). The nuclear cost estimates from Lazard likewise reflect the range of expected nuclear costs. LCOE esti- mates displayed in this table for SCPC units with partial CCS as well as for IGCC units use a higher financing cost rate in comparison to the SCPC unit without capture.277 ** This range represents a natural gas price from $5/MMBtu to $10/MMBtu.
As shown in Table 8, we project that the case for new units firing bituminous base load generation diversity—or at the LCOE for new fossil steam capacity and subbituminous coals and dried least non-NGCC alternatives—to a meeting the final 1,400 lb CO2/MWh-g lignite. This is another demonstration power provider’s portfolio; hence, they standard to be substantially similar to that the costs of the final standard are are reasonably viewed as comparable that for a new nuclear unit, the reasonable because nuclear and fossil alternatives.278 principal other alternative to natural gas steam generation each would serve an As previously mentioned, the DOE/ to provide new base load power. This is analogous role in adding dispatchable NETL assumed conventional financing
looking to different technology that can address independent power producers, advanced 276 Table 8 includes LCOE figures for biomass- some of those challenges while continuing to transportation technologies, renewable energy fired generation, a potential sources of dispatchable provide a reliable and affordable power supply,’’ technologies, meters, smart grid and energy base load power that is not fueled by natural gas. Boughey said. ‘‘Some critics believe we shouldn’t efficiency technologies, and infrastructure. http:// The EPA includes this information for be looking at resource options that include coal, www.marketwatch.com/story/lazard-releases-new- completeness, while noting that biomass-fired units and even nuclear technology,’’ Boughey added. levelized-cost-of-energy-analysis-2014-09-18. in operation in the U.S. are smaller scale and thus ‘‘We believe it would be irresponsible not to 275 LCOE cost estimates for SCPC and IGCC cases are not as robust analogues as nuclear power. CO consider these fuels or technologies as part of an come from ‘‘Cost and Performance Baseline for 2 emissions are not provided for biomass units affordable, reliable and responsible resource Fossil Energy Plants Supplement: Sensitivity to CO2 portfolio.’’ Capture Rate in Coal-Fired Power Plants’’ DOE/ because different biomass feedstocks have different 273 Lazard’s Levelized Cost of Energy Analysis— NETL–2015/1720 (June 22, 2015). Cost and net CO2 emissions; therefore a single emission rate Version 8.0; September 2014; available at: http:// performance for low rank SCPC is adapted from is not appropriate to show in Table 8. www.lazard.com/media/1777/levelized_cost_of_ ‘‘Cost and Performance Baseline for Fossil Energy 277 ‘‘Cost and Performance Baseline for Fossil energy_-_version_80.pdf and in the rulemaking Plants Volume 3 Executive Summary: Low Rank Energy Plants Supplement: Sensitivity to CO2 docket. Coal and Natural Gas to Electricity’’, DOE/NETL– Capture Rate in Coal-Fired Power Plants’’, DOE/ 274 Lazard is one of the world’s preeminent 2010/1399 (September 2011). LCOE cost estimates NETL–2015/1720 (June 2015) at p. 18. financial advisory and asset management firms. for nuclear and biomass are derived from 278 LCOE comparisons of reasonably available Lazard’s Global Power, Energy & Infrastructure ‘‘Levelized Cost and Levelized Avoided Cost of Group serves private and public sector clients with New Generation Resources in the Annual Energy compliance alternatives—IGCC with natural gas co- advisory services regarding M&A, financing, and Outlook 2015’’, June 2015, www.eia.gov/forecasts/ firing, and SCPC with natural gas co-firing—are other strategic matters. The group is active in all aeo/pdf/electricity_generation.pdf. LCOE cost found below in Table 9. As shown there, these areas of the traditional and alternative energy estimates for NGCC technology are EPA estimates alternatives are either lower cost than SCPC with industries, including regulated utilities, based on a range of potential natural gas prices. partial CCS, or of comparable cost.
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for cases without CCS and assumed demonstrates that the final standard’s development of new coal projects high-risk financing for cases with some costs are in line with power sources that include highly competitive natural gas level of CCS. Specifically a high-risk provide analogous services— prices, lower electricity demand, and financial structure resulting in a capital dispatchable base load power and fuel increases in the supply of renewable charge factor (CCF) of 0.124 is used in diversity. energy. the study to evaluate the costs of all We further note a number of In its RIA, the EPA considered the cases with CO2 capture (non-capture conservative elements of the costs we overall costs of this regulation in the case uses a conventional financial used in making this comparison. In context of these prevailing market structure with a CCF of 0.116).279 As a particular, these estimates include the trends. Because of the expectation of no comparison of how this affects the highest value in the projected range of new fossil steam generation, the RIA resulting DOE/NETL costs, a new SCPC potential costs for partial CCS. They do projects that this final rule will result in utilizing 16 percent partial CCS is not reflect revenues which can be negligible costs overall on owners and projected to have an LCOE of $99/MWh generated by selling captured CO2 for operators of newly constructed EGUs by (including transportation and storage enhanced oil recovery, and reflect the 2022.283 More broadly, this regulation is costs; does not include the range for costs of partial CCS rather than not expected to have significant effects uncertainty). That projected LCOE potentially less expensive alternative on fuel markets, electricity prices, or the includes the ‘‘high risk financial compliance paths such as a utility boiler economy as a whole, as described in assumptions’’. If the LCOE for that unit co-firing with natural gas. See also detail in Chapter 4 of the RIA. were to be calculated using the V.H.7 and 8 below. In comparison, courts have upheld past regulations that imposed ‘‘conventional financing assumptions’’, 6. Overall Costs and Economic Impacts the resulting LCOE would be $94/MWh. substantial overall costs in order to This approach is in contrast to that As noted above, an assessment of protect against uncontrolled emissions. taken by the EIA which applies a 3- national costs is also an appropriate As noted above, in Sierra Club v. Costle, percentage-point cost of capital means of evaluating the reasonableness the D.C. Circuit upheld a standard of premium (the ‘climate uncertainty of costs under CAA section 111. See performance that imposed costly adder’) to non-capture coal plants to Sierra Club, 657 F.2d at 330. controls on SO2 emissions from new reflect the market reaction to potential The EPA considered the regulation’s coal-fired power plants. 657 F.2d at 410. future GHG regulation. overall costs and economic impacts as These standards had implications for Under current and anticipated market part of its RIA. The RIA demonstrates the economy ‘‘at the local and national conditions, power providers that are that these costs would be negligible and levels,’’ as ‘‘EPA estimates that utilities considering costs alone in choosing a that the effects on electricity rates and will have to spend tens of billions of fuel source for new intermediate or base other market indicators would similarly dollars by 1995 on pollution control load generation will choose natural gas be minimal. under the new NSPS.’’ Id. at 314. These results are driven by the because of its competitive current and Further, the court acknowledged that existing market context for fossil-steam projected price. However, as noted in ‘‘[c]onsumers will ultimately bear these generation. Even in the absence of the Section V.H.3, public IRPs indicate that costs, both directly in the form of standards of performance for newly utilities are considering and selecting residential utility bills, and indirectly in constructed EGUs, substantial new technologies that could provide or the form of higher consumer prices due construction of uncontrolled fossil preserve fuel diversity within generating to increased energy costs,’’ before steam units is not anticipated under fleets. For example, utilities have been concluding that the costs were existing prevailing and anticipated willing to pay a premium for nuclear reasonable. Id. future economic conditions. Modeling power in certain circumstances, as The projected total incremental projections from government, industry, capital costs associated with the indicated by the recent new and academia anticipate that few new constructions of nuclear facilities and standard we are finalizing in this rule fossil steam EGUs will be constructed are dramatically lower than was the case by IRPs that include new nuclear over the coming decade and that those for this prior standard, as well as other generation in their plans. In general, that are built would have CCS.281 prior standards summarized previously. fossil steam and nuclear generation each Instead, EIA data shows that natural gas For example, when the standard at issue can provide dispatchable, base load is likely to be the most widely-used in Sierra Club was upheld, the industry power while also maintaining or fossil fuel for new construction of 280 was expected to build, and did build, increasing fuel diversity. Utilities electric generating capacity in the near dozens of plants ultimately meeting the may be willing to pay a premium for future.282 Of the coal-fired units moving standards—at a projected incremental these generation sources because they forward at various advanced stages of cost of tens of billions of dollars.284 could serve as a hedge against the construction and development— Here, by contrast, few if any fossil steam possibility that future natural gas prices Southern Company’s Kemper County will far exceed projected levels. Energy Facility and Summit Power’s EGUs are projected to be built in the Accordingly, the LCOE analysis Texas Clean Energy Project (TCEP)— foreseeable future, indicating that the each will deploy IGCC with some level total incremental costs are likely to be 279 ‘‘Cost and Performance Baseline for Fossil of CCS. The primary reasons for this rate considerably more modest. Energy Plants Supplement: Sensitivity to CO2 Commenters stated that the cost of current and projected future Capture Rate in Coal-Fired Power Plants’’, DOE/ provision in CAA section 111(a)(1) does NETL–2015/1720 (June 2015) at p. 7. not authorize the EPA to consider the 280 As another example, San Antonio customers 281 RIA chapter 4. For example, even in the EIA’s will benefit from low-carbon power from the Texas sensitivity analysis that assumes higher natural gas nationwide costs of a system of Clean Energy Project. CPS Energy CEO Doyle prices and electricity demand, the EIA does not emission reduction in lieu of Deneby said in a news release: ‘‘Adding clean coal project any additional coal beyond its reference considering the cost impacts for to our portfolio dovetails with our strategy to case until 2023, in a case where power companies individual new plants. In this rule, we diversify and reduce the carbon intensity of the assume no GHGs emission limitations, and until power we supply to our customers.’’ 2024 in a case where power companies do assume www.bizjournals.com/sanantonio/news/2014/10/ GHGs emission limitations. AEO 2015. 283 Conditions in the analysis year of 2022 are 06/cps-energy-strikes-new-deal-to-buy-power- 282 Annual Energy Outlook 2010, 2011, 2012, represented by a model year of 2020. from.html. 2013, 2014 and 2015. 284 Sierra Club, 657 F.2d at 314.
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are considering both sets of costs and, As explained in more detail in the a. Cost and Feasibility of Natural Gas in fact, we are not identifying full CCS following subsection, a new utility Co-firing as an Alternative Compliance as the BSER primarily for reasons of its boiler can meet the final standard of Pathway cost to individual sources. At the same performance by co-firing with natural Although the EPA has determined time, total projected costs are relevant in gas. Some project developers may that implementation of partial CCS at an assessing the overall reasonableness of choose to utilize natural gas co-firing as emission limitation of 1,400 lb CO2/ costs associated with a standard. Our a means of delaying, rather than analysis demonstrates that the impacts MWh-g is the BSER for newly avoiding, implementation of partial constructed fossil fuel-fired steam on the industry as a whole are CCS. Developers can also choose to negligible, and are certainly not greater generating EGUs, we also note that install IGCC with a small amount of than ‘‘what the industry could bear and operators can consider the use of natural natural gas co-firing at costs within the survive.’’ 285 These facts support the gas co-firing to achieve the final EPA’s overall conclusion that the costs range of SCPC with partial CCS, emission limitation, likely at a lower of the standard are reasonable. although slightly higher. cost. However, as noted earlier, for a The EPA also notes that new units At the final emissions limitation of variety of reasons, some companies may that capture CO2 will likely be built in 1,400 lb CO2/MWh-g a new supercritical consider coal-fired steam generating areas where there are opportunities to PC or supercritical CFB can meet the units that the modeling does not sell the captured CO2 for some useful standard by co-firing with natural gas at anticipate. Thus, in Chapter 5 of the purpose prior to (or concomitant with) levels up to approximately 40 percent RIA, we also present an analysis of the permanent storage. The DOE refers to (heat input basis) and could potentially project-level costs of a newly this as ‘‘carbon capture, utilization and avoid (or delay) installation and use of constructed coal-fired steam generating storage’’ or CCUS. In particular, the partial CCS altogether. unit with partial CCS that meets the ability to sell captured CO2 for use in Natural gas co-firing has long been requirements of this final rule alongside enhanced oil recovery operations offers recognized as an option for coal-fired the project-level costs of a newly the most opportunity to reduce costs. In boilers to reduce emissions of criteria constructed coal-fired unit without CCS. This analysis in RIA chapter 5 indicates this regard, the newly-operating and hazardous air pollutants. EPRI that the quantified benefits of the Boundary Dam facility is selling sponsored a study to assess both standards of performance would exceed captured CO2 for EOR. The Kemper technical and economic issues their costs under a range of facility likewise plans to do so.287 associated with natural gas co-firing in coal-fired boilers.288 They determined assumptions. In some instances, the costs of CCS that the largest number of applications As required under Executive Order may be defrayed by grants or other and the longest experience time is with 12866, the EPA conducts benefit-cost benefits provided by federal or state natural gas reburning and with analyses for major Clean Air Act rules, governments. The need for subsidies to and has done so here. While such supplemental gas firing. Natural gas support emerging energy systems and reburning has been used primarily as a analysis can help to inform policy new control technologies is not unusual. NOX control technology. It is decisions, as permissible and Each of the major types of energy used appropriate under governing statutory implemented by introducing natural gas to generate electricity has been or is provisions, the EPA does not use a (up to 20 percent total fuel heat input) currently being supported by some type benefit-cost test (i.e., a determination of in a secondary combustion zone (called whether monetized benefits exceed of government subsidy such as tax the ‘‘reburn zone’’) downstream of the costs) as the sole or primary decision benefits, loan guarantees, low-cost primary combustion zone in the boiler. tool when required to consider costs or leases, or direct expenditures for some Injecting the natural gas creates a fuel- to determine whether to issue aspect of development and utilization, rich zone where NOX formed in the regulations under the Clean Air Act, and ranging from exploration to control main combustion zone is reduced to is not doing so here.286 Nonetheless, as installation. This is true for fossil fuel- nitrogen and water vapor. just noted, the RIA analysis shows that fired, as well as nuclear-, geothermal-, Higher levels of natural gas co-firing the standard of performance has net wind-, and solar-generated electricity. can be met by utilizing supplemental quantified benefits under a range of As stated earlier, the EPA considers the gas co-firing (either alone or along with assumptions. costs of partial CCS at a level to meet natural gas reburning). This involves the 7. Opportunities to Further Reduce the final standard of performance to be simultaneous firing of natural gas and Compliance Costs reasonable even without considering pulverized coal in a boiler’s primary these opportunities to further reduce combustion zone. Others have also While the EPA believes, as detailed implementation and compliance costs. evaluated configurations that would above, that there is sufficient evidence We did not in the proposal—and we do allow coal-fired units to utilize natural to show that the final standards of not here in this final action—rely on any gas.289 290 performance for new steam generating cost reduction opportunities to justify units can be met at a reasonable cost, we 288 Gas Cofiring Assessment for Coal Fired Utility also note that there are potential the costs of meeting the standard as reasonable, but again note the Boilers; Final Report, August 2000; EPRI Technical opportunities to further reduce Report available at www.epri.com. compliance costs. We believe that, in conservative assumptions embodied in 289 Many of the studies evaluated opportunities to most cases, the actual costs will be less our assessment of compliance costs. use natural gas reburn, natural gas co-firing and other configurations in existing coal-fired boilers. than those presented earlier. Those conclusions would also be applicable for new coal-fired boilers. 287 The EPA is referring to the Kemper facility 285 Portland Cement Ass’n, 513 F.2d at 508. 290 ‘‘Dual Fuel Firing—The New Future for the 286 See Memorandum ‘‘Consideration of Costs and here as an example of how costs can be defrayed, Aging U.S. Based Coal-Fired Boilers’’, presented by Benefits under the Clean Air Act’’ available in the not for use of technology or level of emission Riley Power, Inc. at 37th International Technical rulemaking dockets, EPA–HQ–OAR–2013–0495 reduction achieved. The EPA therefore does not Conference on Clean Coal and Fuel Systems June (new sources) and EPA–OAR–HQ–2013–0603 believe that the EPAct05 prevents reference to the 2012 Clearwater, FL, available at http:// (modified and reconstructed sources). fact that Kemper plans to sell captured carbon. www.babcockpower.com/pdf/RPI-TP-0228.pdf.
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A 2013 article entitled ‘‘Utility co-firing coal and gas in the same boiler, The EPA examined compliance costs Options for Leveraging Natural Gas’’ 291 converting the coal-fired boiler to gas-only for a new steam generating unit to meet noted that: operation, repowering the coal plant with the final standard of performance using natural gas-fired combustion turbines, or Utility owners of coal-fired power stations natural gas co-firing and compared replacing the coal plant with a combined that wish to balance their exposure to coal- those costs to the estimated costs of fired generation with additional natural gas- cycle plant. [. . .] Co-firing is the lowest-risk meeting the final standards using partial fired generation have several options to option for substituting gas use for coal. CCS. Those costs are provided below in consider. The four most practical options are Table 9.
TABLE 9—PREDICTED COSTS TO MEET THE FINAL STANDARD USING NATURAL GAS CO-FIRING 292
LCOE $/ New generation technology Emission lb CO2/MWh-g MWh
SCPC—no CCS ...... 1,620 82 SCPC + ∼16% partial CCS ...... 1,400 99 SCPC + ∼34% NG co-fire ...... 1,400 92 IGCC—no CCS ...... 1,434 103 IGCC + ∼6% NG co-fire ...... 1,400 105 NGCC* ...... 1,000 60 * The generation cost using NG co-fire and NGCC assume a natural gas price of $6.19/mmBtu.
The EPA thus again notes that the cost significant adverse non-air quality at a cost of at least 30 percent less than assumptions it is making in its BSER impacts or energy implications. that at Unit #3.295 These savings determination are conservative. That is, primarily come from application of Costs are Reasonably Expected To lessons learned from the Unit #3 design by costing partial CCS as BSER, the EPA Decrease Over Time may be overestimating actual and construction. compliance costs since there exist other The EPA reasonably expects that the To facilitate the transfer of the less expensive means of meeting the costs of CCS will decrease over time as technology and to accelerate promulgated standard.293 the technology becomes more widely development of carbon capture deployed. Although, for the reasons that technology, SaskPower has created the Notwithstanding that costs for a SCPC have been noted, we consider the CCS Global Consortium.296 This to meet the standard would be lower if current costs of CCS to be reasonable, consortium provides SaskPower the it co-fired with natural gas, we have not the projected decrease in those costs opportunity to share the knowledge and identified that compliance alternative as further supports their reasonableness. experience from the Boundary Dam Unit BSER because we believe that new coal- The D.C. Circuit case law that #3 facility with global energy leaders, fired steam electric generating capacity authorizes determining the ‘‘best’’ technology developers, and project would be built to provide fuel diversity, available technology on the basis of developers. SaskPower, in partnership and burning substantial amounts of reasonable future projections supports with Mitsubishi and Hitachi, is also natural gas would be contrary to that taking into account projected cost helping to advance CCS knowledge and objective. In addition, this choice would reductions as a way to support the technology development through the not promote use of advanced pollution reasonableness of the costs. creation of the Shand Carbon Capture control technology. New IGCC has costs We expect the costs of CCS Test Facility (CCTF).297 The test facility which are comparable to SCPC, as does technologies to decrease for several will provide technology developers with IGCC with natural gas co-firing,294 but reasons. We expect that significant an opportunity to test new and emerging we are choosing not to identify it as additional knowledge will be gained carbon capture systems for controlling BSER for reasons stated at Sections from deployment and operation of the carbon emissions from coal-fired power V.C.2 and V.P: use of IGCC does not new coal-fired generation facilities that plants. advance emission control beyond are either operating or are nearing The DOE also sponsors testing at the current levels of performance for completion. These would include the National Carbon Capture Center (NCCC). sources which may choose to utilize Boundary Dam Unit #3 facility, the The NCCC—located at Southern IGCC technology. Nonetheless, use of Petra Nova WA Parish project, and the Company’s Plant Gaston in Wilsonville, IGCC remains a viable, demonstrated Kemper County IGCC facility. The AL—provides first-class facilities to test compliance option to meet the 1,400 lb operators of the Boundary Dam Unit #3 new capture technologies for extended CO2/MWh-g standard of performance, are considering construction of periods under commercially and is available at reasonable cost and additional CCS units and have projected representative conditions with coal- (as shown at Section V.P below) without that the next units could be constructed derived flue gas and syngas.298
291 Utility Options for Leveraging Natural Gas, 10/ 293 Certain commenters argued that the proposed the Edwardsport and Kemper IGCC facilities have 01/2013 article in Power. Available at http:// standard essentially mandated a sole method of operated at times by firing exclusively natural gas. www.powermag.com/utility-options-for-leveraging- compliance, and hence constituted a work practice 295 ‘‘Boundary Dam—The Future is Here’’, natural-gas/. for purposes of section 111(h) of the Act. These plenary presentation by Mike Monea at the 12th commenters argued further that the EPA had failed 292 International Conference on Greenhouse Gas Costs and emissions for cases that do not to justify the proposal under the section 111(h) Technologies (GHGT–12), Austin, TX (October utilize natural gas co-firing are from ‘‘Cost and criteria. The EPA disagrees with the premise of 2014). Performance Baseline for Fossil Energy Plants these comments, but, in any case, there are clearly 296 http://www.saskpowerccs.com/consortium/. Supplement: Sensitivity to CO2 Capture Rate in multiple compliance paths available for achieving Coal-Fired Power Plants’’, DOE/NETL–2015/1720 the final standard. 297 www.saskpowerccs.com/ccs-projects/shand- (June 2015). Costs and emissions for natural gas co- 294 IGCC units already have combined cycle carbon-capture-test-facility/. fired cases are EPA estimates. capacity, and so can be readily operated in whole 298 www.nationalcarboncapturecenter.com/ or in part using natural gas as a fuel. Indeed, both index.html.
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We expect continued additional cost 1. Use of LCOE as a Cost Metric According to EIA,301 capital costs reductions to come from knowledge As noted, CAA section 111(a) directs represent approximately 63 percent of gained from continued operation of non- the EPA to consider ‘‘cost’’ in the LCOE for a new coal-fired SCPC power sector industrial projects which, determining if the BSER is adequately plant; approximately 66 percent of the as we have discussed, are informative in demonstrated. It does not provide LCOE for a new IGCC plant; transferring the technology to power further guidance as to how costs are to approximately 74 percent of the LCOE sector applications. We expect the on- be considered, thus affording the EPA for a new nuclear plant; and only about going research and development considerable discretion to choose a 22 percent of the LCOE for a new NGCC efforts—such as those sponsored by the reasonable means of cost consideration. unit. The LCOE of a new NGCC unit is DOE/NETL. See, e.g. Lignite Energy Council v. EPA, much more strongly affected by fuel Significant reductions in the cost of 198 F. 3d at 933. Certain commenters costs (natural gas). As we have CO2 capture would be consistent with nonetheless argued that LCOE was an discussed in detail in this preamble, in overall experience with the cost of impermissible metric because it does the preamble for the January 2014 pollution control technology. not measure the cost of achieving the proposal, and in associated technical Reductions in the cost of air pollution emission reduction, but rather measures support documents, the power sector control technologies as a result of the impact on the product produced by has moved toward increased use of learning-by-doing, reductions in the entity subject to the standard.300 The natural gas for a variety of reasons. If financial premiums related to risk, EPA does not agree that its authority is capital was the only cost that utilities research and development investments, so limited. Indeed, in the first decided and project developers considered, then and other factors have been observed case under section 111, the D.C. Circuit, they would almost certainly always over the decades. in holding that the EPA’s consideration choose to build a new NGCC unit. of costs was reasonable, specifically However, a variety of factors can be c. Opportunities To Reduce Cost involved in selecting a generation Through Sales of Captured CO2 noted the EPA’s examination of the impact of the standards on the regulated source beyond capital costs. Geologic storage options include use source category’s product in comparison Accordingly, in considering cost reasonableness the EPA considered of CO2 in EOR operations, which is the to competitive products. Portland injection of fluids into a reservoir after Cement Ass’n v. EPA, 486 F. 2d at 388 metrics that encompassed other costs as production yields have decreased from (‘‘costs of control equipment could be well as the value of fuel and fleet primary production in order to increase passed on without substantially diversity. Some commenters maintained that oil production efficiency. CO2-EOR has affecting competition with construction been successfully used for decades at substitutes such as steel, asphalt, and even if LCOE was a proper cost metric, many production fields throughout the aluminum’’). the comparison with the costs of a new U.S. to increase oil recovery. The use of Commenters also argued that the nuclear power plant is improper because nuclear itself is a highly CO2 for EOR can significantly lower the choice of LCOE as a cost metric masked net cost of implementing CCS. The consideration of the considerable capital expensive technology. The EPA disagrees. The comparison is opportunity to sell the captured CO2 for costs associated with CCS. The EPA EOR, rather than paying directly for its disagrees with this contention. The appropriate and valid because, as long-term storage, improves the overall LCOE does not mask consideration of discussed at V.H.3 above, under current economics of the new generating unit. capital costs. Rather, as explained at and foreseeable economic conditions According to the International Energy V.H.5 above, LCOE is a summary metric affecting the cost of new fossil steam Agency (IEA), of the CCS projects under that expresses the full cost (e.g., capital, generation and new nuclear generation construction or at an advanced stage of O&M, fuel) of generating electricity and relative to the cost of new natural gas planning, 70 percent intend to use therefore provides a useful summary generation, neither new nuclear power nor fossil steam generation are captured CO2 to improve recovery of oil metric of costs per unit of production in mature fields.299 See also Section (i.e., megawatt-hours). Provided that competitive with new natural gas if V.M.3 below. those megawatt-hours provide similar evaluated on the basis of LCOE alone. electricity services and align on Nonetheless, both are important I. Key Comments Regarding the EPA’s potential alternatives to natural gas Consideration of Costs dimensions other than just cost, then the LCOE provides a useful comparison power for those interested in In its consideration of the costs of which technologies are least cost. dispatchable base load power that associated with the final standard, the The EPA certainly does not minimize maintains or increases fuel diversity. As EPA considered a range of different cost shown in a survey of recent IRP filings that project developers must take capital 302 metrics, each with its individual costs into consideration, and as in the docket and Section II.C.5 strengths and weaknesses. As discussed discussed in Section V.H.4 above, the above, several utilities are considering above, each metric supports the EPA’s EPA accordingly has considered direct new nuclear power as a potential conclusion that the costs of the final capital costs here as part of its generation option. Because both fossil standard are reasonable. assessment and found those costs to be steam and nuclear generation serve a comparable role of offering a diverse In this section, we review the reasonable. In addition, the EPA notes source of base load power generation, comments received on assessing cost that its comparison of the marginal the EPA concludes that the comparison reasonableness and specific cost impacts from an individual illustrative of their LCOE is a valid approach to metrics. We explain how these facility’s compliance with the standard, evaluating cost reasonableness. comments informed our consideration discussed in detail above and in the RIA of different metrics and cost Chapter 5, took into account the marginal capital costs that would be 301 http://www.eia.gov/forecasts/aeo/electricity_ reasonableness in general. generation.cfm. incurred by an individual facility. 302 Technical Support Document—‘‘Review of 299 Tracking Clean Energy Progress 2013, Electric Utility Integrated Resource Plans’’ (May International Energy Agency (IEA), Input to the 300 Comments of EEI, pp 94–5 (Docket entry: 2015), available in the rulemaking docket EPA–HQ– Clean Energy Ministerial, OECD/IEA 2013. EPA–HQ–OAR–2013–0495–9780). OAR–2013–0495.
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2. Use of Cost Estimates From DOE/ requirements to support the analyses as b. Other Studies That Corroborate NETL NETL and DOE/EIA defined by the EPA Peer Review Cost Estimates In the January 2014 proposal, the EPA Handbook,’’ and concluded that ‘‘peer review on the DOE documents’’ was A variety of government, industry and relied mostly on the cost projections for academic groups routinely conduct new fossil fuel-fired generating sources conducted ‘‘at a level required by 306 studies to estimate costs of new that were informed by cost studies agency guidance.’’ generating technologies. These studies conducted by DOE/NETL. The EPA The cost estimates were indicated by ¥ use techno-economic models to predict relied on the EIA’s AEO 2013 DOE/NETL to carry an accuracy of 15 the cost to build a new generating projections for non-fossil based percent to +30 percent on the capital facility at some point in the future. generating sources (i.e., nuclear, costs, consistent with a AACE Class 4 renewables, etc.). For this final rule, the cost estimate—i.e., a ‘‘feasibility study’’ These studies often use levelized cost of EPA continues to rely most heavily on level of design engineering.307 The electricity (LCOE) to summarize costs DOE/NETL cost projections for fossil DOE/NETL further notes that ‘‘The and to compare the competiveness of fuel generating technologies and on the value of the study lies not in the the different generating technologies. updated DOE/EIA AEO 2014 for nuclear absolute accuracy of the individual case A variety of groups have recently and other base load non-fossil results but in the fact that all cases were published LCOE estimates for new generation technologies. evaluated under the same set of dispatchable generating technologies. technical and economic assumptions. Those are shown below in Table 10. The a. DOE/NETL Cost and Performance This consistency of approach allows table shows LCOE projections from the Studies meaningful comparisons among the EPA’s January 2014 proposal, from The DOE/NETL ‘‘Cost and cases evaluated.’’ 308 studies conducted by the Electric Power Performance Baselines for Fossil Energy For the final standard, the EPA made Research Institute (EPRI),310 by the Plants’’ are a series of studies conducted particular use of the most recent NETL DOE’s Energy Information by NETL to establish estimates for the cost estimates for post-combustion CCS, Administration (EIA) in their 2015 cost and performance of combustion which reflect up-to-date vendor quotes Annual Energy Outlook (AEO 2015), by and gasification based power plants and incorporate the post-combustion the DOE’s National Energy Technology with and without CO2 capture and capture technology—the Shell Cansolv Laboratory (NETL), and by researchers 303 storage. The studies evaluate amine-based process—that is being from the Department of Engineering and numerous technology configurations utilized at the Boundary Dam Unit #3 Public Policy at the Carnegie Mellon 309 utilizing different coal ranks and natural facility. The EPA used this latest University (CMU) in Pittsburgh, PA. gas. version of the NETL studies not only to 311 The EPA relied on those sources assure that it considers the most up-to- The Global CCS Institute has because the NETL studies are the most date information but also to address recently published a report that comprehensive and transparent of the public comments criticizing the examines costs of major low and zero available cost studies and NETL has a proposal for relying on out-of-date cost emissions technologies currently reputation in the power sector industry information. available for power generation and for producing high quality, reliable compares the predicted LCOEs of those 304 work. The NETL studies were 306 Letter from James Mihelcic, Chair, SAB Work technologies. Importantly, the analysis extensively peer reviewed.305 The EPA Group on EPA Planned Actions for SAB presented in the report uses cost and Science Advisory Board Work Group Consideration of the Underlying Science to performance data from several recent considering the adequacy of the peer Members of the Chartered SAB and SAB Liaisons studies, and applies a common (page 3, Jan. 24, 2014). http://yosemite.epa.gov/sab/ review noted the EPA staff’s statement sabproduct.nsf/F43D89070E89893485257C5A00 methodology and economic parameters that ‘‘the NETL studies were all peer 7AF573/$File/SAB+work+grp+memo+w+attach+ to derive comparable lifetime costs. reviewed under DOE peer review 20140107.pdf. The SAB’s statement that these Analysis and findings in the paper protocols’’, further noted the EPA staff’s guidance documents ‘‘require’’ any specific peer reflect costs specific to the U.S. review is an overstatement, since guidance statement that ‘‘the different levels of documents, by definition, do not mandate any The fact that these various groups review of these DOE documents met the specific course of action. have conducted independent studies 307 Recommended Practice 18R–97 of the and that the results of those 303 http://www.netl.doe.gov/research/energy- Association for the Advancement of Cost analysis/energy-baseline-studies. Engineering International (AACE) describes a Cost independent studies are reasonably 304 The NETL costs and studies are often cited in Estimate Classification System as applied in consistent with the estimates of DOE/ academic and other publications. Engineering, Procurement and Construction for the NETL are further indications that the 305 The initial NETL study ‘‘Cost and Performance process industries. DOE/NETL cost estimates are 308 ‘‘Cost and Performance Baseline for Fossil Baseline for Fossil Energy Plants, Vol. 1: reasonable. Bituminous Coal and Natural Gas to Electricity’’ Energy Plants Volume 1: Bituminous Coal and (2006) was subject to peer review by industry Natural Gas to Electricity’’ Rev 2a (Sept 2013); DOE/ experts, academia, and government research and NETL–2010/1397, page 9. 310 EPRI is a non-profit organization, regulatory agencies. Subsequent iterations of the 309 Cost and Performance Baseline for Fossil headquartered in Palo Alto, CA, that conducts study were not further peer reviewed because the Energy Plants Volume 1a: Bituminous Coal (PC) and research on issues related to the U.S. electric power modeling procedures used in the cost estimation Natural Gas to Electricity, Revision 3, July 6, 2015, industry (www.epri.com). were not revised. DOE/NETL–2015/1723. 311 www.globalccsinstitute.com.
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TABLE 10—SELECTION OF LEVELIZED COST OF ELECTRICITY (LCOE) PROJECTIONS
Lazard 312 EPRI 313 AEO2015 314 DOE/NETL 315 CMU 316 GCCSI 317** New generation technology $2014/MWh $2011/MWh $2013/MWh* $2011/MWh* $2010/MWh $2014/MWh
SCPC—no CCS...... 66 62–77 95 76–95 59 78 SCPC—full CCS ...... 151 102–137 — 140–176 — 115–160 SCPC—16% CCS ...... — — — 92–117 — — Nuclear*** ...... 92–132 85–97 87–115 — — 86–102 Biomass ...... 87–116 90–155 94–113 — — 123–137 IGCC ...... 102 82–96 116 94–120 — — IGCC—full CCS...... 171 105–136 144 142–178 — — NGCC ...... 61—87 33—65 73 58 63 60 * EIA, in cost projections for SCPC and IGCC with no CCS, includes a climate uncertainty adder (CUA), which is a 3-percentage point in- crease in the cost of capital. In contrast, DOE/NETL utilized conventional financing for cases without CCS and utilized high-risk financial assump- tions for cases that include CCS. ** The Global CCS Institute provided range for coal with full CCS (shown as ‘‘CCS(coal)’’ in Figure 5.2 of the referenced report) reflects a combination of costs for both PC and IGCC coal plants. *** EIA AEO assumes use of Westinghouse AP1000 technology. Other groups assume a wider range of technology options.
The LCOE values from the Lazard, inconsistencies between power sector fossil fuel power production equipment. EPRI, and NETL studies are presented as modeling absent GHG regulation and Their current projects include the 400 a range. The EPRI costs incorporate the widespread use of a cost of CO2 MW IGCC Texas Clean Energy Project uncertainty reflecting the range of emissions in power sector resource and the Caledonia Clean Energy inputs (i.e., capital costs, fuel costs, planning. The CUA reflects the Project—a new project underway in the fixed and variable O&M, etc.). The additional planning cost typically United Kingdom—and a variety of other NETL costs are indicated to carry an assigned by project developers and projects under development which are accuracy of ¥15 percent to + 30 utilities to GHG-intensive projects in a not yet public. percent, consistent with a ‘‘feasibility context of climate uncertainty. The EPA Summit is also interested in study’’ level of design. The range in believes the CUA is consistent with the potentially retrofitting CCS onto existing Table 10 is the NETL projected costs industry’s planning and evaluation coal-fired plants for the purpose of with the ¥15 percent to +30 percent framework (demonstrable through IRPs capturing CO2 for sale to EOR markets. uncertainty on the capital costs. Overall, and PUC orders) and is therefore Summit provided the EPA with copies as can be seen from the results in Table pertinent when evaluating the cost of slides from a presentation that it has 10, the range of LCOE estimates from competitiveness of alternative used in different public forums.320 The the different groups are in reasonable generating technologies. The EPA presentation focused on costs to retrofit agreement with the DOE/NETL believes the CUA is relevant in available carbon capture equipment at estimates most often representing the considering the range of costs that an existing PC power plant that is most conservative of the estimates power companies are willing to pay for ideally located to take advantage of shown. generation alternatives to natural gas. opportunities to sell captured CO2 for The EIA cost estimates include a use in EOR operations. Summit received climate uncertainty adder (CUA)— c. Industry Information That Corroborates NETL Cost Estimates proprietary costing information from represented by a three percent increase numerous technology providers and that to the weighted average cost of capital— Information from vendors of CCS information, along with other publically to certain coal-fired capacity types. The technology also supports the reliability available information, was used to EIA developed the CUA to address of the cost estimates the EPA is using develop their cost predictions.321 318 here. Specifically, the EPA had Though the primary focus of their effort 312 Lazard’s Levelized Cost of Energy Analysis— conversations with representatives from was to examine costs associated with Version 8.0 (Sept 2014); available at http://www. Summit Carbon Capture, LLC regarding _ _ _ _ retrofitting CCS to an existing coal fired lazard.com/media/1777/levelized cost of energy - available cost information. Cost _version_80.pdf and in the rulemaking docket. power plant, Summit Power also 313 ‘‘Program on Technology Innovation: estimates provided by another leading calculated costs for several new Integrated Generation Technology Options 2012; provider of CCS technology likewise are generation scenarios—including the cost Report 1026656; Available at: www.epri.com. consistent (indeed, somewhat less than) of a new NGCC, a new SCPC, a new 314 ‘‘Levelized Cost and Levelized Avoided Cost the estimates the EPA is using for of New Generation Resources in the Annual Energy SCPC with full CCS, and a new SCPC Outlook 2015’’, Available at: www.eia.gov/forecasts/ purposes of cost analysis in the rule. with partial CCS at 50 percent. The _ Summit Carbon Capture’s primary aeo/electricity generation.cfm; the LCOE values costs are reasonably consistent with displayed incorporate ¥10%/+30% for uncertainty business is large-scale carbon capture costs predicted by NETL, EIA, EPRI and for biomass and nuclear. from power and other industrial projects 315 ‘‘Cost and Performance Baseline for Fossil 319 others. The company ultimately and use of the captured CO2 for EOR. Energy Plants Supplement: Sensitivity to CO2 concluded that ‘‘in a world of uncertain Summit is actively working with several Capture Rate in Coal-Fired Power Plants’’ DOE/ gas prices, falling CO capture NETL–2015/1720 (June 22, 2015). different technology companies offering 2 316 CMU is Carnegie Mellon University; Zhai, H., CO2 capture systems, including the 320 Rubin, E.; ‘‘Comparative Performance and Cost leading equipment manufacturers for ‘‘Coal’s Role in a Low Carbon Energy Assessments of Coal- and Natural Gas-Fired Power Environment’’, presented at 2015 Euromoney Power Plants under a CO2 Emission Performance Standard & Renewables Conference, remarks by Jeffrey Brown Regulation’’, Energy & Fuels, 2013, 27, 4290, Table 318 See Section V.F above, explaining that the (amended to address EPA questions on the 1. D.C. Circuit has repeatedly stated that vendor original). Available in the rulemaking docket. 317 ‘‘The Costs of CCS and other Low-Carbon statements are probative in demonstrating that a 321 No proprietary or business confidential Technologies—2015 update’’ July 2015, Global CCS technology is adequately demonstrated under information was shared with the EPA. No specific Institute, Available at: http://hub.globalccsinstitute. section 111. vendors were mentioned by name during com/sites/default/files/publications/195008/costs- 319 http://www.summitpower.com/projects/ discussions with Summit Power. Summit also used ccs-other-low-carbon-technologies-2015-update.pdf. carbon-capture/. available DOE/NETL and EIA cost information.
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equipment prices, improving CCS Summit—are shown in Table 11 below. agreement among these projected costs process efficiency, and possible The DOE/NETL estimated costs are also and the DOE/NETL costs. There is compliance costs . . . existing coal included for comparison. The results relatively good agreement in the plants retrofitted with available CCS show predicted costs for a new SCPC incremental levelized cost to implement equipment can be cost competitive with ranging from $53/MWh to $82/MWh full CCS on the new SCPC units development of new NGCC and costs to implement full CCS ranging (ranging from 74 to 85 percent) and to generation.’’ 322 from $97/MWh to $143/MWh. Costs to implement 50 percent CCS on the new In June 2012, Alstom Power released implement varying levels of partial CCS SCPC unit (from 41 to 45 percent a report entitled ‘‘Cost assessment of are also provided for comparison. The increase). These industry estimates are fossil power plants equipped with CCS industry cost estimates are on the lower also lower than the DOE/NETL under typical scenarios’’.323 The study end of the range of costs predicted from estimates for both full and 50 percent examined costs for a new coal-fired other techno-economic studies (see partial CCS (with the incremental cost power plant implementing post- Table 11 below) and, like those combustion CCS (full CCS) in Europe, in economic studies, are affected by the percentage for full CCS being almost North America, and in Asia. The results specific assumptions. As with the techo- identical), providing further support for for the North American case—along economic studies presented earlier in the reasonableness of the EPA using the with similar cost estimates from Table 10, there is relatively good NETL cost estimates here.
TABLE 11—INDUSTRY LCOE ESTIMATES FOR IMPLEMENTATION OF POST-COMBUSTION CCS 324
Summit Alstom DOE/NETL $/MWh $/MWh* $/MWh
SCPC ...... 64.5 52.6 82.3 SCPC + full CCS ...... 117.6 97.4 152.4 Full CCS incremental cost, % ...... 82.3% 85.0% 85.2% SCPC + 50% CCS ...... 91.1 — 123.6 50% CCS incremental cost, % ...... 41.2% — 50.1% SCPC + 35% CCS ...... — — 114.7 SCPC + 16% CCS ...... — — 100.5 NGCC** ...... 47.7 35.0 **52.0 * Costs are from Figure 2 in the referenced Alstom report (North American case); costs are presented as Ö/MWh in the report. The costs were converted to $/MWh assuming a conversion rate of 1 USD = 0.76 Ö (in 2012). ** NGCC cost is estimated by the EPA using NETL information. Assumed natural gas prices = Summit ($4/mmBtu); Astom ($3.9/mmBtu); EPA ($5.00/mmBtu).
The EPA notes that in its public less) which it is publically based on results from EIA’s National comments, Alstom maintained that ‘‘no disseminating in the marketplace. See Energy Modeling System (NEMS). The CCS projects that would [sic] be also Section V.F.3 above, quoting AEO costs are updated annually, they considered cost competitive in today’s Alstom’s press release stating are highly scrutinized, and they are energy economy.’’ 325 As explained unequivocally that ‘‘CCS works and is widely used by those involved in the above, no steam electric EGU would be cost-effective’’. The EPA reasonably is energy sector. cost competitive even without CCS— relying on the specific Alstom estimates In the January 2014 proposal, the EPA and that is substantiated in the which it is using for its own commercial presented LCOE costs for new non-fossil projected costs presented above in Table purposes, and not on the generalized dispatchable generation (see 77 FR 11 where NGCC is consistently the most concerns presented in its public 1477, Table 7) from the AEO 2013. economic new generation option when comments. Those costs were updated as part of the compared to the other listed AEO 2015 release. The estimated cost d. Use of Cost Information From EIA technologies. Alstom does not explain for all of these technologies decreased Annual Energy Outlook (AEO) (or address) why the cost premium for from AEO 2013 to AEO 2014 and AEO partial CCS would be a decisive For the January 2014 proposal the 2015. This was due to changes in the deterrent for capacity that would EPA chose to rely on the EIA AEO 2013 interest rates that resulted in lower otherwise be constructed. More cost projections for non-fossil based financing costs relative to those used the important, Alstom does not challenge generation. The AEO presents long-term AEO 2013.326 The EIA commissioned a the specific cost estimates used by the annual projections of energy supply, comprehensive update of its capital cost EPA at proposal, nor disavow its own demand, and prices focused on U.S. assumptions for all generation estimates of CCS costs (which are even energy markets. The predictions are technologies in 2013. Fuel cost and
322 Others have come to similar conclusions—that with CCS under typical scenarios’’, Alstom Power, Coal-Fired Power Plants’’, DOE/NETL–2015/1720 retrofit of CCS technology at existing coal-fired June 2012. Available in the rulemaking docket: (June 2015), p. 18. power plants can be feasible—e.g., ‘‘The results EPA–HQ–OAR–2013–0495. 325 Alstom Comment p. 3 (Docket entry: EPA– indicate that for about 60 gigawatts of the existing 324 Note that in other tables in this preamble, the HQ–OAR–2013–0495–9033). The comment also coal-fired capacity, the implementation of partial EPA has presented LCOE values from the DOE/ urged the EPA to evaluate costs without considering CO capture appears feasible, though its cost is 2 EOR opportunities (which in fact is our highly dependent on the unit characteristics and NETL work as a range in order to incorporate the fuel prices.’’ (Zhai, H.; Ou, Y.; Rubin, E.S.; uncertainty on the capital costs. The range is not methodology, albeit a conservative one), and ‘‘Opportunities for Decarbonizing Existing U.S. present here for easy comparison with the industry without considering possible subsidies. Id. The Coal-fired Plants via CO2 Capture, Utilization, and costs which were not provided as a range. The full LCOE and capital cost estimates above are direct Storage’’, accepted for publication in Env. Sci & range of DOE/NETL costs for each of the cases cost comparisons, again consistent with the Tech. (2015). presented can be found in Exhibit A–3 in ‘‘Cost and commenter’s position. 323 Leandri, J., Skea, A., Bohtz, C., Heinz, G.; Performance Baseline for Fossil Energy Plants 326 www.eia.gov/oiaf/beck_plantcosts/pdf/ ‘‘Cost assessment of fossil power plants equipped Supplement: Sensitivity to CO2 Capture Rate in updatedplantcosts.pdf.
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financial assumptions are updated for indicated to the EPA that a range of The Boundary Dam Unit #3 facility each edition of the Annual Energy uncertainty of ¥10 percent to +30 utilizing post-combustion capture from Outlook. percent on the capital component of the Shell Cansolv is now operational. Petra LCOE can be expected based on market Nova, a joint venture between NRG e. Accounting for Uncertainty of uncertainties. Specifically, these staff Energy Inc. and JX Nippon Oil & Gas Projected Costs experts expect that nuclear plants Exploration, is currently constructing a As previously mentioned, the currently under construction would not post-combustion capture system at projected costs are dependent upon a have capital costs under estimates and NRG’s WA Parish generating station range of assumptions including the that one could expect to see a 30 percent near Houston, TX. The post-combustion projected capital costs, the cost of ‘‘upside’’ variation in capital cost. There capture system will utilize MHI amine- financing the project, the fixed and is also insufficient market data to get a based solvents and is currently being variable O&M costs, the projected fuel good statistical range of potential capital constructed with plans to initiate costs, and incorporation of any cost variation (i.e., only two plants operation in 2016.330 incentives such as tax credits or under construction, neither complete). Construction on Mississippi Power’s favorable financing that may be This is reasonably consistent with Kemper County Energy Center IGCC available to the project developer. There estimates for nuclear costs estimated by facility is now nearly complete. The are also regional or geographic Lazard (see Table 8 above) which combined cycle portion of the facility differences that affect the final cost of a likewise reflect a similar level of cost has been generating power using natural project. The LCOE projections in this uncertainty. The Lazard nuclear costs gas. The gasification portion of the final action are not intended to provide show a range of projected levelized facility and the carbon capture system an absolute cost for a new project using capital cost from $73/MWh to $110/ are undergoing system checks and any of these respective technologies. MWh—a range of 50 percent, very training to enable commercial Large construction projects—as these similar to the 40 percent range (i.e., ¥10 operations using a UOP SelexolTM pre- would be—would be subjected to percent to +30 percent) suggested by combustion capture system in early detailed cost analyses that would take EIA nuclear experts. The Global CCS 2016.331 into consideration site-specific Institute, in its most recent cost update, Another full-scale project, the Summit information and specific design details also provides nuclear costs as a range Power Texas Clean Energy Project has in order to determine the project costs. from $86/MWh to $102/MWh.328 not commenced construction but The DOE/NETL noted that the cost remains a viable project. Several other 3. Use of Costs From Current Projects estimates from their studies carry an full-scale projects have been proposed accuracy in the range of ¥15 percent to Although we are relying on cost and have progressed through the early +30 percent, which is consistent with a estimates drawn from techno-economic stages of design, but have been ‘‘feasibility study’’ level of design. They models, we recognize that there are a cancelled or postponed for a variety of also noted that the value of the studies few steam electric plants that include reasons. lies ‘‘not in the absolute accuracy of the CCS that have been built, or are being Some cost information is also individual case results but in the fact constructed. Some information about available for small demonstration that all cases were evaluated under the the costs (or cost-to-date) for these projects—including those that have same set of technical and economic projects is known. We discuss in this been supported by USDOE research assumptions. This consistency of section the costs at facilities which have programs. These projects would include approach allows meaningful installed or are installing CCS, why the Alabama Power’s demonstration project comparisons among the cases EPA does not consider those costs to be at Plant Barry and the AEP/Alstom evaluated.’’ reasonably predictive of the costs of the demonstration at Plant Mountaineer. The EIA AEO 2015 presented LCOE next new plants to be built, and why the Many commenters felt that the EPA costs as a single point estimate EPA considers that the next new plants should rely on those high costs when representing average nationwide costs will have lower costs along the lines considering whether the costs are and separately as a range to represent predicted by NETL.329 reasonable. The costs from these large- the regional variation in costs. In order scale projects appear to be consistently to compare the fossil fuel generation 328 ‘‘The Costs of CCS and other Low-Carbon higher than those projected by techno- Technologies—2015 update’’ July 2015, Global CCS economic models. However, the costs technologies from the NETL studies Institute, Available at: http://hub.globalccsinstitute. with the cost projections for non-fossil com/sites/default/files/publications/195008/costs- from these full-scale projects represent dispatchable technologies from EIA ccs-other-low-carbon-technologies-2015-update.pdf. first-of-a-kind (FOAK) costs and, it is AEO 2015, we assume that the EIA 329 The EPA notes that two of these facilities, reasonable to expect these costs to come studies would carry a similar level of Kemper and TCEP, received both assistance from down to the level projected in the NETL DOE under EPAct05 and the IRC section 48A tax and other techno-economic studies for uncertainty (i.e., +30 percent) and we credit; and that the AEP Mountaineer pilot project present the AEO 2015 projected costs as received assistance from DOE under EPAct05. the next new projects that are built— the average nationwide LCOE with a Under the most extreme interpretations of those which are the sources that would be range of ¥10 percent to +30 percent to provisions offered by commenters, the EPA would subject to this standard. be precluded from any consideration of any Significant reductions in the cost of account for uncertainty.327 The EIA information from those sources, including cost does not provide uncertainty estimates information, in showing whether a system of CO2 capture would be consistent with in the AEO cost projections. However, emission reduction is adequately demonstrated. We overall experience with the cost of nuclear experts from EIA staff have note, however, that many of these same commenters pollution control technology. A urged consideration of the cost information from significant body of literature suggests these sources. In fact, the EPA is not relying on 327 EIA does not provided uncertainty estimates information about the costs of these sources to in the AEO cost projections. However, EIA staff determine the BSER or the standards of on the EPA’s determination of the BSER and the have indicated to the EPA that a range of performance in this rulemaking, and the EPA is standards of performance in this rule. uncertainty of ¥10%/+30% on the capital discussing the cost information here to explain why 330 http://www.nrg.com/sustainability/strategy/ component of the LCOE can be expected based on not. Accordingly, this discussion of cost enhance-generation/carbon-capture/wa-parish-ccs- market uncertainties. See memorandum ‘‘Range of information from these sources is not precluded by project/. uncertainty for AEO nuclear costs’’ available in the the EPAct05 and IRC section 48A provisions and, 331 http://www.mississippipower.com/about- rulemaking docket, EPA–HQ–OAR–2013–0495. even if it is precluded, that would have no impact energy/plants/kemper-county-energy-facility/facts.
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that the per-unit cost of producing or CO2 capture. Most single component that these unusual circumstances are a using a given technology declines as amine systems are not practical in a flue reasonable basis for assessing costs of experience with that technology gas environment as the amine will either CCS or IGCC here. increases over time, and this has rapidly degrade in the presence of 4. Cost Competitiveness of New Coal certainly been the case with air oxygen and other contaminants. The Units pollution control technologies. Fluor Econamine FG process, the Reductions in the cost of air pollution process modeled in the NETL cost study As the EPA noted, all indications control technologies as a result of for the SCPC cases, uses a suggest that very few new coal-fired learning-by-doing, research and monoethanolamine (MEA) formulation power plants will be constructed in the development investments, and other specially designed to recover CO2 and foreseeable future. Although a small factors have been observed over the contains a corrosion inhibitor that number of new coal-fired power plants decades. We expect that the costs of allows the use of less expensive, have been built recently, the industry capture technology will follow this conventional materials of construction. generally is not building these kinds of pattern. Other commercially available processes power plants at present and is not The NETL cost estimates reasonably use sterically hindered amine expected to do so for the foreseeable account for this documented formulations (for example, the future. The reasons include the current phenomenon. Specifically, ‘‘[I]n all Mitsubishi Heavy Industries KS–1 economic environment and improved cases, the report intends to represent the solvent) which are less susceptible to energy efficiency, which has led to next commercial offering, and relies on degradation and corrosion issues. lower electricity demand, and vendor cost estimates for component The DOE/NETL and private industry competitive current and projected technologies. It also applies process are continuing to sponsor research on natural gas prices. On average, the cost contingencies at the appropriate advanced solvents (including new of generation from a new NGCC power plant is expected to be lower than the subsystem levels in an attempt to classes of amines) to improve the CO2 account for expected but undefined capture performance and reduce costs. cost of generation from a new coal-fired costs (a challenge for emerging As noted in Section V.H.7.d above, power plant, and the EPA has technologies).’’ 332 SaskPower has created the CCS Global concluded that, even in the absence of Commenters argued that the next Consortium to facilitate further the requirements of this final rule, very plants to be built would still reflect first- knowledge regarding, and use of, carbon few new coal-fired power plants will be of-a-kind costs, pointing to the newness capture technology.333 This consortium built in the near term. of the technology and the lack of provides SaskPower the opportunity to Some commenters, however, operating experience, i.e. the alleged share its knowledge and experience disagreed with this conclusion. They absence of learning by doing. The EPA with global energy leaders, technology contended instead that it is the CCS- based NSPS that would preclude such disagrees. In addition to operating developers, and project developers. new generation. However, as the EPA experience from operating and partially SaskPower, in partnership with has discussed, there is considerable constructed CCS projects, substantial Mitsubishi and Hitachi, is also helping evidence that utilities and project research efforts are underway providing to advance CCS knowledge and developers are moving away—or have a further knowledge base to reduce CO technology through the creation of the 2 already moved away—from a long term capture costs and to improve Shand Carbon Capture Test Facility dependence on coal-fired generating performance. (CCTF).334 The test facility will provide sources. A review of publicly available The DOE/NETL sponsors an extensive technology developers with an integrated resource plans show that research, development and opportunity to test new and emerging many utilities are not considering demonstration program that is focused carbon capture systems for controlling construction of new coal-fired sources on developing advanced technology carbon emissions from coal-fired power without CCS. See Section V. H.3 above. options that will dramatically lower the plants. Few new coal-fired generating sources cost of capturing CO from fossil fuel We also note certain features of the 2 have commenced construction in the energy plants compared to currently commercial plants already built that past 5 years and, of the projects that are available capture technologies. The suggest that their costs are uniquely high, and otherwise not fairly currently in the development phase, the large-scale CO2 capture demonstrations EPA is only aware of projects that will that are currently planned and in some comparable to the costs of plants meeting the NSPS using the BSER. Most include CCS in the design. As we have cases underway, under DOE’s noted in this preamble, the bulk of new initiatives, as well as other domestic obviously, many of these projects involve deeper capture than the partial and international projects, will generate docid=328417 (‘‘Report’’). As documented in this operational knowledge and enable CCS that the EPA assumes in this final Report, costs escalated significantly because the continued commercialization and action. In addition, cost overruns at the developers adopted a ‘‘compressed schedule’’ in an deployment of these technologies. Gas Kemper facility, mentioned repeatedly attempt to obtain the IRC 48A tax credit, resulting in the public comments, resulted in in ‘‘engineering and design changes which are a absorption processes using chemical normal result of detailed engineering and design solvents, such as amines, to separate major part from highly idiosyncratic . . . occurring at the same time as, rather than CO2 from other gases have been in use circumstances, and are related to the ahead of, construction activities’’, which did not since the 1930s in the natural gas cost of the IGCC system, not to the cost allow for proper sequencing during construction. of CCS.335 The EPA does not believe This ‘‘ ’just-in-time’ approach to engineering and industry and to produce food and procurement (meaning that the engineering was chemical grade CO2. The advancement often completed shortly before material of amine-based solvents is an example 333 http://www.saskpowerccs.com/consortium/. procurement and construction activities) resulted in of technology development that has 334 http://www.saskpowerccs.com/ccs-projects/ a greater number of construction work-arounds, shand-carbon-capture-test-facility/. congestion of construction craft labor in the field, improved the cost and performance of 335 See Independent Monitor’s Prudency inefficiencies and additional steps that became Evaluation Report for the Kemper County IGCC necessary during construction to cope with this 332 ‘‘Cost and Performance Baseline for Fossil Project (prepared for Mississippi Public Utilities just-in-time engineering, procurement and Energy Plants Volume 1a: Bituminous Coal (PC) and Staff), available at www.psc.state.ms.us/Insite construction approach.’’ Report, p. 6. Ironically, Natural Gas to Electricity Revision 3’’, DOE/NETL– Connect/InSiteView.aspx?model=INSITE_ work was still completed too late to obtain the tax 2015/1723 (July 2015) at p. 38. CONNECT&queue=CTS_ARCHIVEQ& credit. Id. p. 15.
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generation that has been added recently pipeline capital costs, related capital transport when EOR opportunities are has been either natural gas-fired or expenditures, and O&M costs. not available—consistent with its renewable sources. Overall, the EPA Sequestration cost estimates reflect the overall conservative cost methodology remains convinced that the energy cost of site screening and evaluation, the of assuming no revenues from sale of sector modeling is reflecting the realities cost of injection wells, the cost of captured CO2. Specifically, the EPA of the market in predicting very few injection equipment, operation and estimates transport, storage and new coal-fired power plants in the near maintenance costs, pore volume monitoring (TSM) costs of $5–$15 per 343 future—even in the absence of these acquisition expense, and long term ton of CO2 for non-EOR applications. final standards. liability protection. These sequestration This estimate is reflected in the LCOE In addition, we note that the costs reflect the regulatory requirements comparative costs.344 Administration’s CCS Task Force report of the Underground Injection Control The EPA also carefully reviewed the recognized that CCS would not become Class VI program and GHGRP subpart assumptions on which the transport cost more widely available without the RR for geologic sequestration of CO2 in estimates are based and continues to advent of a regulatory framework that deep saline formations, which are find them reasonable. The NETL studies promoted CCS or provided a strong discussed further in Sections V. M. and referenced in Section V.I.2 above based 339 price signal for CO2. In this regard, we N below. transport costs on a generic 100 km (62 note American Electric Power’s Based on DOE/NETL studies, the EPA mi) pipeline and a generic 80 kilometer 345 statements regarding the need for estimated that the total CO2 pipeline. At least one study estimated federal requirement for GHG control to transportation, storage, and monitoring that of the 500 largest point sources of aid in cost recovery for CCS projects, to (TSM) cost associated with EGU CCS CO2 in the United States, 95 percent are attract other investment partners, and would comprise less than 5.5 percent of within 50 miles of a potential storage thereby promote advancement and the total cost of electricity in all capture reservoir.346 As a point of reference, the deployment of CCS technology: ‘‘as a cases modeled—approximately $5–$15 longest CO2 pipeline in the United 340 347 regulated utility, it is impossible to gain per ton of CO2. The range of TSM States is 502 miles. For new sources, regulatory approval to recover our share costs the EPA relied on are broadly pipeline distance and costs can be of the costs for validating and deploying consistent with estimates provided by factored into siting and, as discussed in the technology without federal the Global Carbon Capture and Storage Section V.M, there is widespread requirements to reduce greenhouse gas Institute as well.341 Some commenters availability of geologic formations for emissions already in place. The suggested that the EPA underestimated geologic sequestration (GS). Moreover, uncertainty also makes it difficult to the costs associated with transporting data from the Pipeline and Hazardous attract partners to help fund the captured CO2 from an EGU to a Materials Safety Administration show industry’s share’’.336 Indeed, AEP has sequestration site.342 Specifically, that in 2013 there were 5,195 miles of stated that CCS is important for the very commenters suggested that the EPA’s CO2 pipelines operating in the United future of the industry: ‘‘AEP still estimated costs for constructing States. This represents a seven percent believes the advancement of CCS is pipelines were lower than costs based increase in CO2 pipeline miles over the critical for the sustainability of coal- on actual industry experience. previous year and a 38 percent increase fired generation.’’ 337 This final rule’s Commenters also opined that the EPA’s in CO2 pipeline miles since 2004. For action is an important component in assumed length of pipeline needed the reasons outlined above, the EPA developing that needed regulatory between the EGU and the sequestration believes its estimates have a reasoned framework. site is not reasonable and that the DOE/ basis. See also Section V.M below NETL study upon which the EPA relied further discussing the current 5. Accuracy of Cost Estimates for does not account for CO2 transport costs availability of CO2 pipelines. Transportation and Geologic when EOR is not available. With respect to sequestration, certain Sequestration The EPA believes its estimates of commenters argued that the EPA’s cost The EPA’s estimates of costs take into transportation and sequestration costs analysis failed to account for many contingencies and uncertainties (surface account the transport of CO2 and are reasonable. First, the EPA in fact and sub-surface property rights in sequestration of captured CO2. Estimates includes cost estimates for CO2 of transport and sequestration costs— particular), ignored the costs of GHGRP subpart RR, and also was not approximately $5–$15 per ton of CO2— 1397); Economic Evaluation of CO2 Storage and are based on DOE NETL studies and are Sink Enhancement Options, Tennessee Valley representative of the costs associated Authority, NETL and EPRI, December 2002; Carbon also consistent with other published with specific GS site characterization, Dioxide and Transport and Storage Costs in NETL development, and operation/injection of studies.338 For transport, costs reflect Studies (DOE/NETL–2013/1614), March 2013; Carbon Dioxide and Transport and Storage Costs in monitoring wells. Commenter American 336 www.aep.com/newsroom/newsreleases/ NETL Studies (DOE/NETL–2014/1653), May 2014; Electric Power (AEP) referred to its own ?id=1704. Cost and Performance Baseline for Fossil Energy 337 ‘‘CCS LESSONS LEARNED REPORT American Power Plants, Volume 1a: Bituminous Coal (PC) 343 See RIA at section 5.5 and proposed RIA at 5– Electric Power Mountaineer CCS II Project Phase and Natural Gas to Electricity (DOE–NETL–2015/ 30. 1’’, prepared for The Global CCS Institute Project # 1723), July 2015. 344 See RIA at section 5.5. 339 PRO 004, January 23, 2012, page 2. Available at: Carbon Dioxide and Transport and Storage 345 The pipeline diameter was sized for this to be www.globalccsinstitute.com/publications/ccs- Costs in NETL Studies. DOE/NETL–2013/1614. achieved without the need for recompression stages lessons-learned-report-american-electric-power- March 2013. P. 13. along the pipeline length. 340 mountaineer-ccs-ii-project-phase-1; See also AEP RIA at section 5.5; proposed rule RIA at 5–30. 346 JJ Dooley, CL Davidson, RT Dahowski, MA FEED Study at pp. 4, 63, Available at: 341 http://hub.globalccsinstitute.com/sites/ Wise, N Gupta, SH Kim, EL Malone (2006), Carbon www.globalccsinstitute.com/publications/aep- default/files/publications/12786/economic- Dioxide Capture and Geologic Storage: A Key mountaineer-ii-project-front-end-engineering-and- assessment-carbon-capture-and-storage- Component of a Global Energy Technology Strategy design-feed-report. technologies-2011-update.pdf. to Address Climate Change. Joint Global Change 338 Updated Costs (June 2011 Basis) for Selected 342 See, for example, comments from American Research Institute, Battelle Pacific Northwest Bituminous Baseline Cases (DOE/NETL–341/ Electric Power, pp 97–8 (Docket entry: EPA–HQ– Division. PNWD–3602. College Park, MD. 347 082312); Cost and Performance of PC and IGCC OAR–2013–0495–10618), Southern Company, pp. A Review of the CO2 Pipeline Infrastructure in Plants for a Range of Carbon Dioxide Capture 47–48 (Docket entry: EPA–HQ–OAR–2013–0495– the U.S., April 21, 2015, DOE/NETL–2014/1681, (DOE/NETL–2011/1498); Cost and Performance 10095), and Duke Energy p. 28 (Docket entry: EPA– Office of Fossil Energy, National Energy Technology Baseline for Fossil Energy Plants (DOE/NETL–2010/ HQ–OAR–2013–0495–9426). Laboratory.
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experience with the Mountaineer for purposes of the cost analysis. The have determined to be a highly efficient demonstration project. AEP noted that NETL cost estimates upon which the SCPC implementing partial CCS at a although this project was not full scale, EPA’s costs draw directly from the UIC level sufficient to achieve the final finding a suitable repository, Class VI economic impact analysis.353 standard—for such a unit utilizing notwithstanding a generally favorable That analysis is based on estimated bituminous coal that would be geologic area, proved difficult. The characteristics for a representative group approximately 16 percent. In company referred to its estimated cost of of projects over a 50-year period of determining the predicted cost and expanding the existing Mountaineer analysis, as well as industry averages for performance of such a system, the EPA plant to a larger scale project, several cost components and sub- utilized information contained in particularly the cost of site components. The EPA also made updated DOE/NETL studies that characterization and well reasonable assumptions regarding the assumed use of bituminous coal and an construction.348 assumed injection site: A deep saline 85 percent capacity factor. Here we The EPA’s cost estimates account for formation with typical characteristics examine the effects of deviating from the requirements of the Underground (e.g., representative depth and those assumed operational parameters Injection Control Class VI program, and pressure).354 on the achievability of the final standard GHGRP subpart RR, among them site With respect to AEP’s experience with of performance.356 This is in keeping screening and evaluation costs, costs for the Mountaineer demonstration project, with the requirement that a standard of injection wells and equipment, O&M sequestration siting issues are of course performance must be achievable costs, and monitoring costs. The site-specific, and raise individual issues. accounting for all normal operating estimated sequestration costs include For this reason, it is inappropriate to variability when a control system is operational and post-injection site care generalize from a particular individual properly designed, maintained, and monitoring, which are components of experience. In this regard, as explained operated. See Section III.H.1.c above. the UIC Class VI requirements, and also in Section V.N below, the construction reflect costs for sub-surface pore volume 1. Operational Fluctuations, Start-Ups, permits issued by the EPA to-date under Shutdowns, and Malfunctions property rights acquisition.349 These the Underground Injection Control Class estimates are consistent with the costs VI regulations required far fewer wells Importantly, compliance with the presented in the study CO2 Storage and for site characterization and monitoring standard must be demonstrated over a Sink Enhancements: Developing than AEP found to be necessary at its 12-operating-month average. The total Comparable Economics, which Mountaineer site. Moreover, CO2 emissions (pounds of CO2) over 12 incorporates the costs associated with notwithstanding difficulties, the operational months are summed and site evaluation, well drilling, and the company was able to successfully drill divided by the total gross output (in capital equipment required for and complete wells, and safely inject megawatt-hours) over the same 12 350 351 operational months. Such a compliance transporting and injecting CO2. captured CO2. The company also Monitoring costs were evaluated based indicated it fully expected to be able to averaging period is very forgiving of on the methodology set forth in the do so at full scale and explained how.355 short-term excursions that can be International Energy Agency For discussion of 40 CFR part 98, associated with non-routine events such Greenhouse Gas R&D Programme’s subpart RR (the GHGRP requirements as start-ups, shutdowns, and Overview of Monitoring Projects for for geologic sequestration), including malfunctions. A new fossil fuel-fired 352 Geologic Storage Projects report. costs associated with compliance with steam generating EGU—if constructed— The EPA’s cost estimates for those requirements, see Section V.N would, most likely, be built to serve sequestration thus cover all aspects below. base load power demand and would not commenters claimed the EPA be expected to routinely start-up or disregarded. The EPA believes that the J. Achievability of the Final Standards shutdown or ramp its capacity factor in use of costs and scenarios presented in The EPA finds the final standard of order to follow load demand. Thus, the studies referenced are representative 1,400 lb CO2/MWh-g to be achievable planned start-up and shutdown events over a wide range of variable conditions would only be expected to occur a few 348 AEP Comments at pp. 93, 96 (Docket entry: that are reasonably likely to occur when times during the course of a 12- EPA–HQ–OAR–2013–0495–10618). the system is properly designed and operating-month compliance period. 349 ‘‘Cost and Performance of PC and IGCC Plants Malfunctions are unplanned and for a Range of Carbon Dioxide Capture.’’ DOE/ operated. As discussed elsewhere, the NETL–2011/1498 (September 2013) p. 49. final standard reflects the degree of unpredictable events and emission Specifically, the report estimates the costs emission limitation achievable through excursions can happen at or around the associated with acquiring rights to use the pore the application of the BSER which we time of the equipment malfunction. But space in the geologic formation. Costs are estimated a malfunctioning EGU that cannot be based on studies of subsurface rights acquisition for natural gas storage. The report also estimates costs 353 Cost Analysis for the Federal Requirements operated properly should be shut down for land acquisition for surface property rights. Id. Under the Underground Injection Control Program until the malfunctioning equipment can p. 48. for Carbon Dioxide Geologic Sequestration Wells, be addressed and the EGU can be 350 Bock, B., R. Rhudy, H. Herzog, M. Klett, J. U.S. Environmental Protection Agency Office of restarted to operate properly. Davidson, D.G. De La Torre Ugarte, and D. Simbeck. Water, EPA 816–R10–013, November 2010, pages The post-combustion capture systems (2003). Economic Evaluation of CO2 Storage and 3–1, 5–42. 354 that have been utilized have proven to Sink Enhancement Options, Final Technical Report Economic Evaluation of CO2 Storage and Sink Prepared by Tennessee Valley Authority for DOE. Enhancement Options, Tennessee Valley Authority, be reliable. The Boundary Dam facility 351 As noted above, other sequestration-related NETL and EPRI, December 2002. has been operating full CCS successfully costs are also estimated, including injection wells 355 See ‘‘CCS front end engineering & design at commercial scale since October 2014. and equipment, pore volume acquisition, and long- report: American Electric Power Mountaineer CCS As described earlier, in evaluating term-liability. ‘‘Cost and Performance Baseline for II Project. Phase 1’’ at pp. 36–43. The company Fossil Energy Plants Volume 1: Bituminous Coal likewise explained the monitoring regime it would results from the Mountaineer slip- and Natural Gas to Electricity Revision 2a, utilize to verify containment, and the well September 2013 DOE/NETL–2010/1397, p. 55. construction it would utilize to guarantee secure 356 Additional information can be found in a 352 ‘‘Overview of Monitoring Requirements for sequestration. Id. at pp. 44–54. Available at: http:// Technical Support Document (TSD)— Geologic Storage Projects’’, IEA Greenhouse Gas www.globalccsinstitute.com/publications/aep- ‘‘Achievability of the Standard for Newly R&D Programme, Report Number PH4/29, mountaineer-ii-project-front-end-engineering-and- Constructed Steam Generating EGUs’’ available in November 2004. design-feed-report. the rulemaking docket.
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stream demonstration, AEP and Alstom somewhat higher, an estimated 23 from a new coal-fired steam generating reported robust steady-state operation percent increase.360 The EPA finds these unit. The EPA estimates that a new during all modes of power plant increases to be reasonable because, as highly efficient 500 MW coal-fired SCPC operation including load changes, and discussed earlier, the costs are meeting the final standard of 1,400 lb saw an availability of the CCS system of reasonably consistent with capital cost CO2/MWh-g will emit about 354,000 357 greater than 90 percent. increases in previous NSPS. See Section fewer metric tons of CO2 each year than V.H.4 above. 2. Variations in Coal Type that new highly efficient unit would have emitted otherwise. That is The use of specific coal types can K. Emission Reductions Utilizing Partial CCS equivalent to taking about 75,000 affect the amount of CO2 that is emitted 362 from a new coal-fired power plant. As Although the definition of ‘‘standard vehicles off the road each year and previously discussed, the EPA utilized of performance’’ does not by its terms will result in over 14,000,000 fewer studies by the DOE/NETL to predict the identify the amount of emissions from metric tons of CO2 in a 40-year cost and performance of new steam the category of sources and the amount operating life. To emphasize the generating units. Based on those reports, of emission reductions achieved as importance of constructing a highly the EPA predicts that a new SCPC factors the EPA must consider in efficient SCPC unit that includes partial burning low rank coal (subbituminous determining the ‘‘best system of CCS—the highly efficient 500 MW coal- coal or dried lignite) would have an emission reduction,’’ the D.C. Circuit fired SCPC with partial CCS would emit uncontrolled emission rate about 7 has stated that the EPA must do so. See about 675,000 fewer metric tons of CO2 percent higher than a similar unit firing Sierra Club v. Costle, 657 F.2d at 326 each year than that from a new, less typical bituminous coal.358 The EPA (‘‘we can think of no sensible efficient coal-fired utility boiler with an predicts that such a highly efficient new interpretation of the statutory words assumed emission of 1,800 lb CO2/ SCPC utilizing subbituminous coal or ‘‘best . . . system’’ which would not MWh-g. dried lignite would need to capture incorporate the amount of air pollution For comparison, see Table 12 below approximately 23 percent of the CO2. as a relevant factor to be weighed when The EPA also believes that it is determining the optimal standard for which provides the amount of CO2 technically feasible to do so, although controlling . . . emissions’’).361 This is emissions captured each year by other additional cost would be entailed. The consistent with the Court’s statements CCS projects. These result show that, EPA has evaluated those costs and finds in Essex Chemical Corp. v. Ruckelshaus, even though the emission reductions are them to remain reasonable.359 As shown 486 F.2d at 437 that it is necessary to significant, they are reasonably within in Table 8 above, the predicted cost ‘‘[k]eep[] in mind Congress’ intent that the range of emission reductions that are remains within the estimated range for new plants be controlled to the currently being achieved now in the other principal base load, ‘maximum practicable degree’ ’’. existing facilities. For comparison, dispatchable non-NGCC alternative The final standard of performance approximately 60,000,000 metric tons of technologies. Estimated capital cost will result in meaningful and significant CO2 were supplied to U.S. EOR using these coal types would also be emission reductions of GHG emissions operations in 2013.363
TABLE 12—ANNUAL METRIC TONS OF CO2 CAPTURED (OR PREDICTED TO CAPTURE) FROM CCS PROJECTS AND FROM A MODEL 500 MW PLANT MEETING THE FINAL STANDARD.
CO2 captured Project tonnes/year
AES Shady Point ...... 66,000 AES Warrior Run ...... 110,000 Southern Company Plant Barry ...... 165,000 Searles Valley Minerals ...... 270,000 New 500 MW SCPC EGU (1,400 lb CO2/MWh-g) ...... 354,000 Coffeyville Fertilizer ...... 700,000 Boundary Dam #3 ...... 1,000,000 Petra Nova/NRG WA Parish ...... 1,400,000 Dakota Gasification ...... 3,000,000
357 http://www.alstom.com/press-centre/2011/5/ Standard for Newly Constructed Steam Generating 361 Sierra Club v. Costle, 657 F.2d 298 (D.C. Cir. alstom-announces-sucessful-results-of- EGUs’’—available in the rulemaking docket. 1981) was governed by the 1977 CAAA version of mountaineer-carbon-capture-and-sequestration-ccs- 359 The cost of the lignite drying equipment is the definition of ‘‘standard of performance,’’ which project/. The Boundary Dam facility likewise is assumed to be low compared to the cost of the revised the phrase ‘‘best system’’ to read, ‘‘best operating reliably (see Section V.D.3.a above). See carbon capture equipment. Further, pre-drying of technological system.’’ The 1990 CAAA deleted ‘‘technological,’’ and thereby returned the phrase to also ‘‘Cost and Performance Baseline for Fossil the lignite reduces fuel, auxiliary power how it read under the 1970 CAAA. The Sierra Club Energy Plants Volume 1a: Bituminous Coal (PC) and consumption and other O&M costs. www.iea- v. Costle’s interpretation of this phrase to require Natural Gas to Electricity, Revision 3’’, DOE/NETL– coal.org.uk/documents/83436/9095/Techno- consideration of the amount of air emissions 2015/1723 (July 2015) at p. 36 (‘‘[t]he capture and economics-of-modern-pre-drying-technologies-for- remains valid for the phrase ‘‘best system.’’ CO2 compression technologies have commercial lignite-fired-power-plants,-CCC/241. 362 Using U.S. EPA Office of Transportation and operating experience with demonstrated ability for 360 Note that the 23 percent increase in expected Air Quality (OTAQ) estimate of average vehicle high reliability’’). capital costs and the 23 percent CO2 capture needed emissions of 4.7 tonnes/year. 358 For additional detail, see the Technical to meet the final standard are coincidental and are 363 Greenhouse Gas Reporting Program, data Support Document (TSD)—‘‘Achievability of the not correlated. reported as of August 18, 2014.
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L. Further Development and emissions control stimulated 1. Geologic and Geographic Deployment of CCS Technology innovation, as shown by the patent Considerations for GS analysis following initial SO2 regulatory Researchers at Carnegie Mellon Geologic sequestration (i.e., long-term University (CMU) have studied the requirements for EGU emissions. The containment of a CO stream in history and the technological response study author further found that 2 subsurface geologic formations) is to environmental regulations.364 By regulatory stringency appears to be technically feasible and available examining U.S. research funding and particularly important as a driver of patenting activity over the past century, innovation, both in terms of inventive throughout most of the United States. the CMU researchers found that activity and in terms of the GS is based on a demonstrated promulgation of national policy communication processes involved in understanding of the processes that requiring large reductions in power- knowledge transfer and diffusion. affect CO2 fate in the subsurface; these plant emissions resulted in a significant Further, as electric power generation processes can vary regionally as the upswing in inventive activity to develop doubled, the operating and maintenance subsurface geology changes. GS occurs technologies to reduce those emissions. costs of FGD systems decline to 83 through a combination of mechanisms The researchers found that, following percent of their original level. This including: (1) Structural and the 1970 Clean Air Act, there was a 10- finding, which is very much in line with stratigraphic trapping (generally fold increase in patenting activity progress ratios determined in other trapping below a low permeability industries, shows that quantifiable directed at improving the SO2 scrubbers confining layer); (2) residual CO2 that were needed to comply with technological improvements can be trapping (retention as an immobile stringent federal and state-level shown to occur solely on the basis of the phase trapped in the pore spaces of the standards. experience of operating an geologic formation); (3) solubility Much like carbon capture scrubbers environmental control technology trapping (dissolution in the in situ today, the technology to capture and forced into being by government formation fluids); (4) mineral trapping remove SO2 from power plant flue gases actions. (reaction with the minerals in the was new to the industry and was not yet M. Technical and Geographic Aspects of geologic formation and confining layer widely deployed at large coal-burning Disposition of Captured CO2 to produce carbonate minerals); and (5) plants when the EPA first promulgated preferential adsorption trapping In the following sections of the the 1971 standards. (adsorption onto organic matter in coal preamble, we discuss issues associated Many of the early Flue Gas and shale).366 These mechanisms are with the disposition of captured CO : Desulfurization (FGD) units did not 2 functions of the physical and chemical the ‘‘S’’—sequestration—in CCS. In this perform well, as the technology at that properties of CO2 and the geologic time was poorly understood and there section, we review the existing processes, technologies, and geologic formations into which the CO2 stream is was little or no prior experience on coal- injected. Subsurface formations suitable fired power plants. In contrast, amine- conditions that enable successful geologic sequestration (GS). In Section for GS of CO2 captured from affected based capture systems have a much EGUs are geographically widespread longer history of reliable use at coal- V.N., we discuss in detail the comprehensive, in-place regulatory throughout most parts of the United fired plants and other industrial States. sources. There is also a better structure that is currently available to understanding of the amine process oversee GS projects and assure their Storage security is expected to chemistry and overall process design— safety and effectiveness. Together, these increase over time through post-closure, discussions demonstrate that the and project developers have much resulting in a decrease in potential technical feasibility of GS, another key 367 sophisticated analytical tools available risks. This expectation is based in component of a partial CCS unit, is today than in the 1970s during the part on a technical understanding of the adequately demonstrated. Sequestration development of FGD scrubber variety of trapping mechanisms that is already well proven. CO has been technologies. 2 work to reduce CO2 mobility over While R&D efforts were essential to retained underground for eons in time.368 In addition, site achieving improvements in FGD geologic (natural) repositories and the characterization, site operations, and scrubber technology—and are also very mechanisms by which CO2 is trapped monitoring strategies can work in underground are well understood. The important to improving carbon capture combination to promote storage physical and chemical trapping technologies, the influence of regulatory security. mechanisms, along with the regulatory actions that establish commercial requirements and safeguards of the markets for advanced technologies dioxide from industrial sources, compressing it into Underground Injection Control Program a ‘supercritical fluid,’ and injecting that fluid cannot be minimized. The existence of and complementary monitoring and underground for the purposes of geologic national government regulation for SO 2 reporting requirements of the GHGRP, sequestration, with the goal of preventing the carbon from reentering the atmosphere. Because the together ensure that sequestered CO2 364 See Technical Support Document/ will remain secure and provide the last of these steps—geologic sequestration of the Memorandum ‘‘History Of Flue Gas Desulfurization supercritical carbon dioxide—involves that in the United States’’ (July 11, 2015) summarizing monitoring to identify and address injection of fluid into underground wells, it is the doctoral dissertation of Margaret R. Taylor, potential leakage using Safe Drinking subject to regulation under the Safe Drinking Water ‘‘The Influence of Government Actions on Water Act (SDWA) and CAA authorities Act’’). Innovative Activities in the Development of 365 Environmental Technologies to Control Sulfur (see Section V.N of this preamble). 366 See, e.g., USEPA. 2008. Vulnerability Dioxide Emissions from Stationary Sources,’’ MA Evaluation Framework for Geologic Sequestration of dissertation submitted to the Carnegie Institute of 365 See also Carbon Sequestration Council and Carbon Dioxide. Technology, Carnegie Mellon University in partial Southern Company Services v. EPA, No. 14–1406 367 Report of the Interagency Task Force on fulfillment of the requirements for the degree of (D.C. Cir. June 2, 2015) at *10 (‘‘[c]arbon capture Carbon Capture and Storage (August 2010), page 47. Doctor of Philosophy in Engineering and Public and storage is an emerging climate change 368 See, e.g., Intergovernmental Panel on Climate Policy, Pittsburgh, PA, January 2001. mitigation program that involves capturing carbon Change. (2005). Special Report on Carbon Dioxide Capture and Storage.
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The effectiveness of long-term saline and oil and gas formation types in unmineable coal seams to enhance trapping of CO2 has been demonstrated are widely available in the United methane recovery. These operations by natural analogs in a range of geologic States. The geographic availability of take advantage of the preferential settings where CO2 has remained deep saline formations and EOR is chemical affinity of coal for CO2 relative trapped for millions of years.369 For shown in Figure 1 below.372 As shown to the methane that is naturally found example, CO2 has been trapped for more in the figure, there are 39 states for on the surfaces of coal. When CO2 is than 65 million years in the Jackson which onshore and offshore deep saline injected, it is adsorbed to the coal Dome, located near Jackson, formation storage capacity has been surface and releases methane that can Mississippi.370 Other examples of identified.373 EOR operations are then be captured and produced. This natural CO2 sources include Bravo currently being conducted in 12 states. process effectively ‘‘locks’’ the CO2 to Dome and McElmo Dome in Colorado An additional 17 states have geology the coal, where it remains stored. DOE and New Mexico, respectively. These that is amenable to EOR operations. has identified over 54 billion metric natural storage sites are themselves Figure 1 also shows areas that are tons of potential CO2 storage capacity in capable of holding volumes of CO2 that within 100 kilometers (62 miles) of unmineable coal across 21 states.376 The are larger than the volume of CO2 where storage capacity has been availability of unmineable coal seams is expected to be captured from a fossil identified.374 There are 10 states with shown in Figure 1 below. fuel-fired EGU. In 2010, the Department operating CO pipelines and 18 states 2 As discussed below in Section M.7, a of Energy (DOE) estimated current CO that are within 100 kilometers (62 miles) 2 few states do not have geologic reserves of 594 million metric tons at of an active EOR location. conditions suitable for GS, or may not Jackson Dome, 424 million metric tons CO2 may also be used for other types at Bravo Dome, and 530 million metric of enhanced recovery, such as for be located in proximity to these areas. tons at McElmo Dome.371 natural gas production. Reservoirs such However, in some cases, demand in GS is feasible in different types of as unmineable coal seams also offer the those states can be served by coal-fired geologic formations including deep potential for geologic storage.375 power plants located in areas suitable saline formations (formations with high Enhanced coalbed methane recovery is for GS, and in other cases, coal-fired power plants are unlikely to be built in salinity formation fluids) or in oil and the process of injecting and storing CO2 gas formations, such as where injected those areas for other reasons, such as the 372 lack of available coal or state law CO2 increases oil production efficiency A color version of the figure, which readers through a process referred to as may find easier to view, can be found in the prohibitions and restrictions against technical support document on geographic coal-fired power plants.377 enhanced oil recovery (EOR). Both deep availability in the rulemaking docket. 373 Alaska is not shown in Figure 1; it has deep 369 Holloway, S., J. Pearce, V. Hards, T. Ohsumi, saline formation storage capacity, geology amenable 376 The United States 2012 Carbon Utilization and and J. Gale. 2007. Natural Emissions of CO2 from to EOR operations, and potential GS capacity in Storage Atlas, Fourth Edition, U.S. Department of the Geosphere and their Bearing on the Geological unmineable coal seams. Energy, Office of Fossil Energy, National Energy Storage of Carbon Dioxide. Energy 32: 1194–1201. 374 The distance of 100 kilometers reflects Technology Laboratory (NETL). 370 Intergovernmental Panel on Climate Change. assumptions in DOE–NETL cost estimates which 377 Similarly, as discussed below, the U.S. (2005). Special Report on Carbon Dioxide Capture the EPA used for cost estimation purposes. See territories lack available coal, do not currently have and Storage. ‘‘Carbon Dioxide and Transport and Storage Costs coal-fired power plants, and, as a result, are not 371 DiPietro, P., Balash, P. & M. Wallace. A Note in NETL Studies’’, DOE/NETL–2014/1653 (May expected to see new coal-fired power plants. Hawaii on Sources of CO2 Supply for Enhanced-Oil 2014). is not expected to constructed new coal plants as Recovery Operations. SPE Economics & 375 Other types of opportunities include organic it intends to utilize 100 percent renewable energy Management. April 2012. shales and basalt. sources by 2050.
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-- Existing C02 pipeline {Department ofTransportation)
---- Probable, planned, or under study C02 pipeline
Counties with active C02-EOR operations (EPA GHG Reporting Program)
Deep Saline Formations (Department of Energy, NATCARB)
Unmineable Coal Seams (Department of Energy, NATCARB)
100 km from Geologic Sequestration
Figure 1: Geologic Sequestration in the Continental United
States
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Figure 2 - Electrical Transmission Lines across the Continental
United States378
2. Availability of Geologic Sequestration analyses of the availability and potential models and published in a Carbon 379 in Deep Saline Formations CO2 sequestration capacity of deep Utilization and Storage Atlas. DOE The DOE and the United States saline formations in the United States. estimates that areas of the United States Geological Survey (USGS) have DOE estimates are compiled by the DOE’s National Carbon Sequestration 379 The United States 2012 Carbon Utilization and independently conducted preliminary Storage Atlas, Fourth Edition, U.S. Department of Database and Geographic Information Energy, Office of Fossil Energy, National Energy 378 Ventyx Velocity Suite Online. April 2015. System (NATCARB) using volumetric Technology Laboratory (NETL).
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with appropriate geology have a technologies for monitoring CO2 in the that it can be re-injected into the sequestration potential of at least 2,035 subsurface and air have been employed reservoir in addition to new CO2 that is billion metric tons of CO2 in deep saline at these projects, such as seismic received. If an EOR operator will not formations. According to DOE and as methods (crosswell seismic, 3–D and require the full volume of CO2 available noted above, at least 39 states have 4–D seismic, and vertical seismic from an EGU, the EGU has other options geologic characteristics that are profiling), atmospheric CO2 monitoring, such as sending the CO2 to other EOR amenable to deep saline GS in either soil gas sampling, well and formation operators, or sending it to deep saline onshore or offshore locations. In 2013, pressure monitoring, and surface and formation GS facilities. 385 the USGS completed its evaluation of ground water monitoring. No CO2 CO2 used for EOR may come from the technically accessible GS resources leakage has been reported from these anthropogenic or natural sources. The for CO2 in U.S. onshore areas and state sites, which further supports the source of the CO2 does not impact the waters using probabilistic availability of effective GS. effectiveness of the EOR operation. CO2 assessment.380 The USGS estimates a capture, treatment and processing steps 3. Availability of CO2 Storage via EOR mean of 3,000 billion metric tons of provide a concentrated stream of CO2 in subsurface CO2 sequestration potential, Although the determination that the order to meet the needs of the intended including saline and oil and gas BSER is adequately demonstrated and end use. CO2 pipeline specifications of reservoirs, across the basins studied in the regulatory impact analysis for this the U.S. Department of Transportation the United States. rule relies on GS in deep saline Pipeline Hazardous Materials Safety The DOE has created a network of formations, the EPA also recognizes the Administration found at 49 CFR part seven Regional Carbon Sequestration potential for securely sequestering CO2 195 (Transportation of Hazardous Partnerships (RCSPs) to deploy large- via EOR. Liquids by Pipeline) apply regardless of EOR is a technique that is used to scale field projects in different geologic the source of the CO2 and take into increase the production of oil. settings across the country to account CO2 composition, impurities, demonstrate that GS can be achieved Approaches used for EOR include steam and phase behavior. Additionally, EOR safely, permanently, and economically injection, injection of specific fluids operators and transport companies have at large scales. Collectively, the seven such as surfactants and polymers, and specifications related to the composition gas injection including nitrogen and RCSPs represent regions encompassing of the CO2 stream. The regulatory 97 percent of coal-fired CO2 emissions, CO2. EOR using CO2, sometimes referred requirements and company 97 percent of industrial CO2 emissions, to as ‘‘CO2 flooding’’ or CO2-EOR, specifications ensure EOR operators 96 percent of the total land mass, and involves injecting CO2 into an oil receive a known and consistent CO2 essentially all the geologic sequestration reservoir to help mobilize the remaining stream. sites in the United States potentially oil to make it more amenable for EOR has been successfully used at 381 available for GS. The seven recovery. The crude oil and CO2 mixture numerous production fields throughout partnerships include more than 400 is then recovered and sent to a separator the United States to increase oil organizations spanning 43 states (and where the crude oil is separated from recovery. The oil industry in the United 382 four Canadian provinces). RCSP the gaseous hydrocarbons, native States has over 40 years of experience project objectives are to inject at least formation fluids, and CO2. The gaseous with EOR. An oil industry study in 2014 one million metric tons of CO2. In April CO2-rich stream then is typically identified more than 125 EOR projects 2015, DOE announced that CCS projects dehydrated, purified to remove in 98 fields in the United States.386 supported by the department have hydrocarbons, re-compressed, and re- More than half of the projects evaluated safely and permanently stored 10 injected into the reservoir to further in the study have been in operation for 383 million metric tons of CO2. enhance oil recovery. Not all of the CO2 more than 10 years, and many have Eight RCSP ‘‘Development Phase’’ injected into the oil reservoir is been in operation for more than 30 projects have been initiated and five of recovered and re-injected. As the CO2 years. This experience provides a strong the eight projects are injecting or have moves from the injection point to the foundation for demonstrating successful completed CO2 injection into deep production well, some of the CO2 CO2 injection and monitoring saline formations. Three of these becomes trapped in the small pores of technologies, which are needed for safe projects have already injected more than the rock, or is dissolved in the oil and and secure GS (see Section N below) one million metric tons each, and one, water that is not recovered. The CO2 that can be used for deployment of CCS the Cranfield Site, injected over eight that remains in the reservoir is not across geographically diverse areas. million metric tons of CO2 between mobile and becomes sequestered. Currently, 12 states have active EOR 384 2009 and 2013. Various types of The amount of CO2 used in an EOR operations and most have developed an project depends on the volume and extensive CO2 infrastructure, including 380 U.S. Geological Survey Geologic Carbon injectivity of the reservoir that is being pipelines, to support the continued Dioxide Storage Resources Assessment Team, 2013, flooded and the length of time the EOR National assessment of geologic carbon dioxide operation and growth of EOR. An storage resources—Results: U.S. Geological Survey project has been in operation. Initially, additional 18 states are within 100 Circular 1386, p. 41, http://pubs.usgs.gov/circ/ all of the injected CO2 is newly kilometers (62 miles) of current EOR 1386/. received. As discussed above, as the operations. See Figure 1 above. The vast 381 http://energy.gov/fe/science-innovation/ project matures, some CO2 is recovered carbon-capture-and-storage-research/regional- majority of EOR is conducted in oil partnerships. with the oil and the recovered CO2 is reservoirs in the Permian Basin, which 382 http://energy.gov/fe/science-innovation/ separated from the oil and recycled so extends through southwest Texas and carbon-capture-and-storage-research/regional- southeast New Mexico. States where partnerships. Site Projects, NT42590, October 2013. Available at: EOR is utilized include Alabama, 383 http://energy.gov/articles/milestone-energy- http://www.netl.doe.gov/publications/factsheets/ department-projects-safely-and-permanently-store- project/NT42590.pdf. Colorado, Louisiana, Michigan, 10-million-metric-tons. 385 A description of the types of monitoring 384 U.S. Department of Energy, National Energy technologies employed at RCSP projects can be 386 Koottungal, Leena, 2014, 2014 Worldwide Technology Laboratory, Project Facts, Southeast found here: http://www.netl.doe.gov/research/coal/ EOR Survey, Oil & Gas Journal, Volume 112, Issue Regional Carbon Sequestration Partnership— carbon-storage/carbon-storage-infrastructure/ 4, April 7, 2014 (corrected tables appear in Volume Development Phase, Cranfield Site and Citronelle regional-partnership-development-phase-iii. 112, Issue 5, May 5, 2014).
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Mississippi, New Mexico, Oklahoma, identifies 29 states with oil reservoirs Section V.E.2.a above). During that time Texas, Utah, and Wyoming. Several amenable to EOR, 12 of which currently over 16 million metric tons of CO2 were commenters raised concerns about the have active EOR operations. A safely sequestered as evidenced by soil volume of CO2 used in EOR projects comparison of the current states with gas surveys, shallow groundwater relative to the scale of EGU emissions EOR operations and the states with monitoring, seismic surveys and and the demand for CO2 for EOR potential for EOR shows that an wellbore integrity testing. An extensive projects. At the project level, the volume opportunity exists to expand the use of shallow groundwater monitoring of CO2 already injected for EOR and the EOR to regions outside of current areas. program revealed no significant changes duration of operations are of similar The availability of anthropogenic CO2 in in water chemistry that could be 394 magnitude to the duration and volume areas outside of current sources could attributed to CO2 storage operations. of CO2 expected to be captured from drive new EOR projects by making more The International Energy Agency fossil fuel-fired EGUs. The volume of CO2 locally available. Greenhouse Gas Programme developed CO2 used in EOR operations can be large Some commenters raised concerns a best practices manual for CO2 (e.g., 55 million tons of CO2 were stored that data are extremely limited on the monitoring at EOR sites based on the in the SACROC unit in the Permian extent to which EOR operations comprehensive analysis of surface and Basin over 35 years), and operations at permanently sequester CO2, and the subsurface monitoring methods applied a single oil field may last for decades, efficacy of long term storage, or that the over the 10 years.395 injecting into multiple parts of the EOR industry does not have the The Texas Bureau of Economic field.387 According to data reported to requisite experience with and technical Geology also has been testing a wide the EPA’s GHGRP, approximately 60 knowledge of long-term CO2 range of surface and subsurface million metric tons of CO2 were sequestration. The EPA disagrees with monitoring tools and approaches to supplied to EOR in the United States in these commenters. Several EOR sites, document sequestration efficiency and 2013.388 Approximately 70 percent of which have been operated for years to sequestration permanence at the this total CO2 supplied was produced decades, have been studied to evaluate Cranfield oilfield in Mississippi (see from natural (geologic) CO2 sources and the viability of safe and secure long- Section L.1 above).396 As part of a DOE approximately 30 percent was captured term sequestration of injected CO2. Southeast Regional Carbon from anthropogenic sources.389 Examples are identified below. Sequestration Partnership study, A DOE-sponsored study has analyzed CO2 has been injected in the SACROC Denbury Resources injected CO2 into a the geographic availability of applying Unit in the Permian basin since 1972 for depleted oil and gas reservoir at a rate EOR in 11 major oil producing regions EOR purposes. One study evaluated a greater than 1.2 million tons/year. Texas of the United States and found that portion of this project, and estimated Bureau of Economic Geology is there is an opportunity to significantly that the injection operations resulted in currently evaluating the results of increase the application of EOR to areas final sequestration of about 55 million several monitoring techniques 390 392 outside of current operations. DOE- tons of CO2. This study used employed at the Cranfield project and sponsored geologic and engineering modeling and simulations, along with preliminary findings indicate no impact analyses show that expanding EOR collection and analysis of seismic to groundwater.397 The project also operations into areas additional to the surveys, and well logging data, to demonstrates the availability and capacity already identified and applying evaluate the ongoing and potential CO2 effectiveness of many different new methods and techniques over the trapping occurring through various monitoring techniques for tracking CO2 next 20 years could utilize 18 billion mechanisms. The monitoring at this site underground and detecting CO2 leakage metric tons of anthropogenic CO2 and demonstrated that CO2 can become to ensure CO2 remains safely increase total oil production by 67 trapped in geologic formations. In a sequestered. billion barrels. The study found that one separate study in the SACROC Unit, the As discussed in Section M.1 above of the limitations to expanding CO2 use Texas Bureau of Economic Geology and as shown in Figure 1, the United in EOR is the lack of availability of CO2 conducted an extensive groundwater States has widespread potential for in areas where reservoirs are most sampling program to look for evidence storage, including in deep saline 391 amenable to CO2 flooding. DOE’s of CO2 leakage in the shallow freshwater formations and oil and gas formations. Carbon Utilization and Storage Atlas aquifers. No evidence of leakage was However, some commenters maintained detected.393 that the EPA’s information regarding 387 Han, Weon S., McPherson, B J., Lichtner, P C., The International Energy Agency availability of GS sites is overly general and Wang, F P. ‘‘Evaluation of CO2 trapping mechanisms at the SACROC northern platform, Greenhouse Gas Programme conducted and ignores important individual Permian basin, Texas, site of 35 years of CO2 an extensive monitoring program at the considerations. A number of injection.’’ American Journal of Science 310. (2010): Weyburn oil field in Saskatchewan commenters, for example, maintained 282–324. between 2000 and 2010 (the site that site conditions often make 388 Greenhouse Gas Reporting Program, data reported as of August 18, 2014. receiving CO2 captured by the Dakota monitoring difficult or impossible, so 389 Greenhouse Gas Reporting Program, data Gasification synfuel plant discussed in reported as of August 18, 2014. 394 Roston, B., and S. Whittaker (2010), 10+ years 390 ‘‘Improving Domestic Energy Security and 392 Han, Weon S., McPherson, B J., Lichtner, P C., of the IEA–GHG Weyburn-Midale CO2 monitoring Lowering CO2 Emissions with ‘‘Next Generation’’ and Wang, F P. ‘‘Evaluation of CO2 trapping and storage project; success and lessons learned CO2-Enhanced Oil Recovery’’, Advanced Resources mechanisms at the SACROC northern platform, from multiple hydrogeological investigations, to be International, Inc. (ARI), 2011. Available at: http:// Permian basin, Texas, site of 35 years of CO2 published in Energy Procedia, Elsevier, Proceedings www.netl.doe.gov/research/energy-analysis/ injection.’’ American Journal of Science 310. (2010): of 10th International Conference on Greenhouse Gas publications/details?pub=df02ffba-6b4b-4721-a7b4- 282–324. Control Technologies, IEA Greenhouse Gas 04a505a19185. 393 Romanak, K.D., Smyth, R.C., Yang, C., and Programme, Amsterdam, The Netherlands. 391 395 ‘‘Improving Domestic Energy Security and Hovorka, S., Detection of anthropogenic CO2 in Hitchon, B. (Editor), 2012, Best Practices for Lowering CO2 Emissions with ‘‘Next Generation’’ dilute groundwater: field observations and Validating CO2 Geological Storage: Geoscience CO2-Enhanced Oil Recovery’’, Advanced Resources geochemical modeling of the Dockum aquifer at the Publishing, p. 353. International, Inc. (ARI), 2011. Available at: http:// SACROC oilfield, West Texas, USA: presented at 396 http://www.beg.utexas.edu/gccc/ www.netl.doe.gov/research/energy-analysis/ the 9th Annual Conference on Carbon Capture & cranfield.php. publications/details?pub=df02ffba-6b4b-4721-a7b4- Sequestration, Pittsburgh, PA, May 10–13, 2010. 397 http://www.beg.utexas.edu/gccc/ 04a505a19185. GCCC Digital Publication Series #10–06. cranfield.php.
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that sites are not available as a practical becomes mineralized. The carbonate would be permanently stored. matter.398 Commenter American materials produced can be tailored to Applicants must also demonstrate that Electric Power pointed to its own optimize performance in specific the proposed technology will not cause experience in siting monitoring wells industrial and commercial applications. or contribute to an unreasonable risk to for its pilot plant Mountaineer CCS These carbonate materials have been public health, welfare or safety. In project, which involved protracted time used in the construction industry and, evaluating applications, the EPA may and expense to eventually site more recently and innovatively, in conduct tests itself or require the monitoring wells.399 Other commenters cement production processes to replace applicant to conduct testing in support noted significant geographic disparity in Portland cement. of its application. Any application GS site availability, claiming absence of The Skyonics Skymine project, which would be publicly noticed, and the EPA sites in southeastern areas of the opened its demonstration project in would solicit comment on the country.400 October 2014, is an example of captured application and on intended action the Project- and site-specific factors do CO2 being used in the production of EPA might take. The EPA could also influence where CO2 can be safely carbonate products. This plant converts provide a conditional approval of an sequestered. However, as outlined CO2 into commercial products. It application on operating results from a above, there is widespread potential for captures over 75,000 tons of CO2 proscribed period. The EPA could also GS in the United States. If an area does annually from a San Antonio, Texas, terminate an approval, including a not have a suitable GS site, EGUs can cement plant and converts the CO2 into termination based on operating results either transport CO2 to GS sites via CO2 other products, including sodium calling into question a technology’s pipelines (see Section M.5 below), or carbonate, sodium bicarbonate, effectiveness. they may choose to locate their units hydrochloric acid and bleach.401 As noted at proposal, given the closer to GS sites and provide electric A few commenters suggested that CO2 unlikelihood of new coal-fired EGUs power to customers through utilization technologies alternative to being constructed, the EPA does not transmission lines (see Figure 2 and GS are being commercialized, and that expect there to be many (if any) Section M.7). In addition, there are these should be included as compliance applications for use of non-geologic alternative means of complying with the options for this rule. The rule generally sequestration technology. 79 FR at 1484. final standards of performance that do requires that captured CO2 be either 5. Availability of Existing or Planned not necessitate use of partial CCS, so injected on-site for geologic CO Pipelines any siting difficulties based on lack of sequestration or transferred offsite to a 2 a CO2 repository would be obviated. See facility reporting under 40 CFR subpart CO2 pipelines are the most Portland Cement Ass’n v. EPA, 665 F. RR. The EPA does not believe that the economical and efficient method of 402 3d 177, 191 (D.C. Cir. 2011), holding emerging technologies just discussed are transporting large quantities of CO2. that the EPA could adopt section 111 sufficiently advanced to unqualifiedly CO2 has been transported via pipelines standards of performance based on the structure this final rule to allow for their in the United States for nearly 40 years. performance of a kiln type that kilns of use. Nor are there plenary systems of Over this time, the design, construction, older design would have great difficulty regulatory control and GHG reporting operation, and safety requirements for satisfying, since, among other things, for these approaches, as there are for CO2 pipelines have been proven, and there were alternative methods of geologic sequestration. Nonetheless, as the U.S. CO2 pipeline network has been compliance available should a new kiln stated above, these technologies not safely used and expanded. The Pipeline of this older design be built. only show promise, but could and Hazardous Materials Safety potentially be demonstrated to show Administration (PHMSA) reported that 4. Alternatives to Geologic permanent storage of CO2. in 2013 there were 5,195 miles of CO2 Sequestration In the January 2014 proposal, the EPA pipelines operating in the United States. Potential alternatives to sequestering noted that it would need to adopt a This represents a seven percent increase CO2 in geologic formations are mechanism to evaluate these alternative in CO2 pipeline miles over the previous emerging. These relatively new technologies before any could be used year and a 38 percent increase in CO2 potential alternatives may offer the in lieu of geologic sequestration. 79 FR pipeline miles since 2004.403 opportunity to offset the cost of CO2 at 1484. The EPA is establishing such a Some commenters argued that the capture. For example, captured mechanism in this final rule. See existing CO2 pipeline capacity is not anthropogenic CO2 may be stored in § 60.5555(g). The rule provides for a adequate and that CO2 pipelines are not solid carbonate materials such as case-by-case adjudication by the EPA of available in a majority of the United precipitated calcium carbonate (PCC) or applications seeking to demonstrate to States. magnesium or calcium carbonate, the EPA that a non-geologic The EPA does not agree. The CO2 bauxite residue carbonation, and certain sequestration technology would result pipeline network in the United States types of cement through mineralization. in permanent confinement of captured has almost doubled in the past ten years PCC is produced through a chemical CO2 from an affected EGU. The criteria in order to meet growing demands for reaction process that utilizes calcium to be addressed in the application, and CO2 for EOR. CO2 transport companies oxide (quicklime), water, and CO2. evaluated by the EPA, are drawn from have recently proposed initiatives to Likewise, the combination of CAA section 111(j), which provides an expand the CO2 pipeline network. magnesium oxide and CO2 results in a analogous mechanism for case-by-case Several hundred miles of dedicated CO2 precipitation reaction where the CO2 approval of innovative technological pipeline are under construction, systems of continuous emission planned, or proposed, including 398 Comments of Southern Co., p. 38 (Docket reduction which have not been entry: EPA–HQ–OAR–2013–0495–10095). adequately demonstrated. Applicants 402 Report of the Interagency Task Force on 399 Comments of AEP pp. 93, 96 (Docket entry: would need to demonstrate that the Carbon Capture and Storage (August 2010), page 36. EPA–HQ–OAR–2013–0495–10618). proposed technology would operate 403 ‘‘Annual Report Mileage for Hazardous Liquid 400 Comments of Duke Energy, pp. 24–5 Docket or Carbon Dioxide Systems’’, U.S. Pipeline and entry: EPA–HQ–OAR–2013–0495–9426); UARG, effectively, and that captured CO2 Hazardous Materials Safety Administration, March pp. 53, 57 (Docket entry: EPA–HQ–OAR–2013– 2, 2015. Available at: http://www.phmsa.dot.gov/ 0495–9666) citing Cichanowicz (2012). 401 http://skyonic.com/technologies/skymine. pipeline/library/data-stats.
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projects in Colorado, Louisiana, pipeline.409 The project is anticipated to For example, in September 2006, Montana, New Mexico, Texas, and commence operation in 2016.410 California Governor Schwarzenegger Wyoming. Some commenters suggested that signed into law Senate Bill 1368. The Examples are identified below. there may be challenges associated with law limits long-term investments in base the safety of transporting supercritical load generation by the state’s utilities to Kinder Morgan has reported several CO2 over long distances, or that the EPA power plants that meet an emissions proposed pipeline projects including did not adequately consider the performance standard jointly the proposed expansion of the existing potential non-air environmental impacts established by the California Energy Cortez CO2 pipeline, crossing Colorado, of the construction of CO2 pipelines. Commission and the California Public New Mexico, and Texas, to increase the The EPA has carefully evaluated the Utilities Commission. The Energy CO2 transport capacity from 1.35 billion safety of pipelines used to transport Commission has designed regulations cubic feet per day (Bcf/d) to 1.7 Bcf/d, captured CO2 and determined that that establish a standard for new and to support the expansion of CO2 pipelines can indeed convey captured existing base load generation owned by, production capacity at the McElmo CO2 to sequestration sites with certainty or under long-term contract to publicly Dome production facility in Colorado. and provide full protection of human owned utilities, of 1,100 lb CO2/MWh. The Cortez pipeline expansion is health and the environment. 76 FR at In May 2007, Washington Governor expected to be placed into service in 48082–83 (Aug. 8, 2011); 79 FR 352, 354 Gregoire signed Substitute Senate Bill 404 2015. (Jan. 3, 2014). Existing and new CO2 6001, which established statewide GHG Denbury reported that the company pipelines are comprehensively regulated emissions reduction goals, and imposed utilized approximately 70 million cubic by the Department of Transportation’s an emission standard that applies to any feet per day of anthropogenic CO2 in Pipeline Hazardous Material Safety base load electric generation that 2013 and that an additional Administration. The regulations govern commenced operation after June 1, 2008 approximately 115 million cubic feet pipeline design, construction, operation and is located in Washington, whether per day of anthropogenic CO2 may be and maintenance, and emergency or not that generation serves load utilized in the future from currently response planning. See generally 49 located within the state. Base load planned or future construction of CFR 195.2. Additional regulations generation facilities must initially facilities and associated pipelines in the address pipeline integrity management comply with an emission limit of 1,100 Gulf Coast region.405 Denbury also by requiring heightened scrutiny to lb CO2/MWh. assure the quality of pipeline integrity initiated transport of CO2 from a In July 2009, Oregon Governor Wyoming natural gas processing plant in areas with a higher potential for Kulongoski signed Senate Bill 101, in 2013 and reported transporting adverse consequences. See 49 CFR which mandated that facilities approximately 22 million cubic feet per 195.450 and 195.452. On-site pipelines generating base load electricity, whether are not subject to the Department of day of CO2 in 2013 from that plant gas- or coal-fired, must have emissions alone.406 Transportation standards, but rather equal to or less than 1,100 lb CO2/MWh, adhere to the Pressure Piping standards and prohibited utilities from entering Denbury completed the final section of the American Society of Mechanical into long-term purchase agreements for of the 325-mile Green Pipeline for Engineers (ASME B31), which the EPA base load electricity with out-of-state transporting CO2 from Donaldsonville, has found would ensure that piping and 407 facilities that do not meet that standard. Louisiana, to EOR oil fields in Texas. associated equipment meet certain In 2012 New York established Denbury completed construction and quality and safety criteria sufficient to emission standards of CO2 at 925 lb commenced operation of the 232-mile prevent releases of CO2, such that CO2/MWh for new and expanded base Greencore Pipeline in 2013; the certain additional requirements were load fossil fuel-fired plants. Greencore pipeline transports CO2 to not necessary (See 79 FR 358–59 (Jan. 3, In May 2007, Montana Governor EOR fields in Wyoming and 2014)).411 These existing controls over Schweitzer signed House Bill 25, 408 Montana. CO2 pipelines assure protective adopting a CO2 emissions performance A project being constructed by NRG management, guard against releases, and standard for EGUs in the state. House and JX Nippon Oil & Gas Exploration assure that captured CO2 will be Bill 25 prohibits the state Public Utility (Petra Nova) would capture CO2 from a securely conveyed to a sequestration Commission from approving new EGUs power plant in Fort Bend County, Texas site. primarily fueled by coal unless a
for transport to EOR sites in Jackson 6. States With Emission Standards That minimum of 50 percent of the CO2
County, Texas through an 82-mile CO2 Would Require CCS produced by the facility is captured and sequestered. 404 ‘‘Form 10–K: Annual Report Pursuant to Several states have established On January 12, 2009, Illinois Section 13 or 15(d) of the Security and Exchange emission performance standards or Governor Blagojevich signed Senate Bill Act of 1934, For the Fiscal Year Ended December other measures to limit emissions of 1987, the Clean Coal Portfolio Standard 31, 2014’’, Kinder Morgan, February 2015. GHGs from new EGUs that are Available at: http://ir.kindermorgan.com/sites/ Law. The legislation establishes kindermorgan.investorhq.businesswire.com/files/ comparable to or more stringent than emission standards for new power report/additional/KMI–2014–10K_Final.pdf. the final standard in this rulemaking. plants that use coal as their primary 405 ‘‘2013 Annual Report’’, Denbury, April 2014. feedstock. From 2009–2015, new coal- _ 409 Available at http://www.denbury.com/files/doc ‘‘The West Ranch CO2-EOR Project, NRG Fact fueled power plants must capture and financials/2013/Denbury_Final_040814.pdf. Sheet’’, NRG, 2014. Available at: www.nrg.com/ 406 store 50 percent of the carbon emissions ‘‘CO2 Sources’’, Denbury, 2015. Available at: documents/business/pla-2014-west-ranch-fact- http://www.denbury.com/operations/rocky- sheet.pdf. that the facility would otherwise emit; mountain-region/co2-sources-and-pipelines/ 410 ‘‘WA Parish Carbon Capture Project’’, NRG, from 2016–2017, 70 percent must be default.aspx. 2015. Available at: www.nrg.com/sustainability/ captured and stored; and after 2017, 90 407 http://www.denbury.com/operations/gulf- strategy/enhance-generation/carbon-capture/wa- percent must be captured and stored. coast-region/Pipelines/default.aspx. parish-ccs-project/. 408 411 ‘‘CO2 Pipelines’’, Denbury, 2014. Available at: See the B31 Code for pressure piping, 7. Coal-by-Wire http://www.denbury.com/operations/rocky- developed by the American Society of Mechanical mountain-region/COsub2-sub-Pipelines/ Engineers, Pipeline Transportation Systems for In addition, as discussed in the default.aspx. liquid hydrocarbons and other liquids. proposal, electricity demand in states
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that may not have geologic sequestration assessed and thus are depicted as not ensure the long-term, secure and safe sites may be served by coal-fired having geological formations suitable for storage of large volumes of CO2. The electricity generation built in nearby CO2 storage, even though assessment EPA developed these Underground areas with geologic sequestration, and could in fact reveal additional Injection Control (UIC) Class VI well this electricity can be delivered through formations.413 regulations under authority of the Safe transmission lines. This method, known As one considers the areas on the map Drinking Water Act (SDWA) to facilitate as ‘‘coal-by-wire,’’ has long been used in depicted in Figure 1 that fall outside of injection of CO2 for GS, while protecting the electricity sector because siting a the above enumerated categories, in human health and the environment by coal-fired power plant near the coal many instances, we find areas with low ensuring the protection of underground mine and transmitting the generation population density, areas that are sources of drinking water (USDWs). The long distances to the load area is already served by transmission lines Class VI regulations are built upon 35 generally less expensive than siting the that could deliver coal-by-wire, and/or years of federal experience regulating plant near the load area and shipping areas that have made policy or other underground injection wells, and many the coal long distances. decisions not to pursue a resource mix additional years of state UIC program For example, we noted in the that includes coal. In many of these expertise. The EPA and states have proposal that there are many examples areas, utilities, electric cooperatives, decades of UIC experience with the where coal-fired power generated in one and municipalities have a history of Class II program, which provides a state is used to supply electricity in joint ownership of coal-fired generation regulatory framework for the protection other states. In the proposal we outside the region or contracting with of USDWs for CO2 injected for purposes specifically noted that historically coal and other generation in outside of EOR. nearly 40 percent of the power for the areas to meet their demand. Some of the In addition, to complement both the City of Los Angeles was provided from relevant areas are in RTOs 414 which Class VI and Class II rules, the EPA used two coal-fired power plants located in engage in planning across the RTO, CAA authority to develop air-side Arizona and Utah and Idaho Power, balancing supply and demand in real monitoring and reporting requirements which serves customers in Idaho and time throughout the RTO. Accordingly, for CO2 capture, underground injection, Eastern Oregon, meets its demand in generating resources in one part of the and geologic sequestration through the part from coal-fired power plants RTO such as a coal generator can serve GHGRP. Information collected under the located in Wyoming and Nevada. 79 FR load in other parts of the RTO, as well GHGRP provides a transparent means at 1478. as load outside of the RTO. As we for the EPA and the public to continue In the Technical Support Document consider each of these geographic areas to evaluate the effectiveness of GS. on Geographic Availability (Geographic in the Geographic Availability TSD, we As explained below, these Availability TSD), we explore in greater make key points as to why this final rule requirements help ensure that detail the issue of coal-by-wire and the does not negatively impact the ability of sequestered CO2 will remain in place, ability of demand in areas without these regions to access new coal and, using SDWA and CAA authorities, geologic sequestration to be served by generation to the extent that coal is provide the monitoring mechanisms to coal generation located in areas that needed to supply demand and/or those identify and address potential leakage. have access to geologic sequestration. regions want to include new coal-fired We note the near consensus in the Figure 1 of this preamble (a color generation in their resource mix. public responses to the Class VI rulemaking that saline and oil and gas version of which is provided as Figure N. Final Requirements for Disposition of 1 of the Geographic Availability TSD) reservoirs provide ready means for Captured CO2 415 depicts areas of the country with: (1) secure GS of CO2. This section discusses the different existing CO2 pipeline; (2) probable, 1. Requirements for UIC Class VI and regulatory components, already in planned, or under study CO2 pipeline; Class II Wells (3) counties with active CO -EOR place, that assure the safety and 2 Under SDWA, the EPA developed the operations; (4) oil and natural gas effectiveness of GS. This section, by UIC Program to regulate the reservoirs; (5) deep saline formations; demonstrating that GS is already underground injection of fluids in a (6) unmineable coal seams; and (7) areas covered by an effective regulatory manner that ensures protection of 100 kilometers from geologic structure, complements the analysis of USDWs. UIC regulations establish six sequestration. As demonstrated by the technical feasibility of GS contained different well classes that manage a Figure 1, the vast majority of the in Sec. V.M. Together, these sections affirm that the technical feasibility of GS range of injectates (e.g., industrial and country has existing or planned CO2 is adequately demonstrated. municipal wastes; fluids associated with pipeline, active CO2-EOR operations, In 2010, the EPA finalized an effective oil and gas activities; solution mining the necessary geology for CO2 storage, or and coherent regulatory framework to fluids; and CO2 for geologic is within 100 kilometers of areas with sequestration) and which accommodate geologic sequestration.412 A review of 413 varying geologic, hydrogeological, and Figure 1 indicates limited areas that do The data in Figure 1 is based on estimates compiled by the DOE’s National Carbon other conditions. The standards apply to not fall into these categories. Sequestration Database and Geographic Information injection into any type of formation that As an initial matter, we note that the System (NATCARB) and published in the United meets the rule’s rigorous criteria, and so data included in Figure 1 is a States 2012 Carbon Utilization and Storage Atlas, apply not only to injection into deep conservative outlook of potential areas Fourth Edition. As discussed in the TSD, deep saline formation potential was not assessed for
available for the development of CO2 Alaska, Connecticut, Hawaii, Massachusetts, 415 In that rulemaking, we stated that ‘‘most storage in that we include only areas Nevada, Rhode Island, and Vermont. Oil and gas commenters encouraged the EPA not to that have been assessed to date. Portions storage potential was not assessed for Alaska, automatically exclude any potential injection of the United States—such as the State Washington, Nevada, and Oregon. Unmineable coal formations for GS at this stage of deployment.’’ We seams were not assessed for Nevada, Oregon, added that commenters suggested, in particular, of Minnesota—have not yet been California, Idaho, and New York. We are assuming ‘‘that there is sufficient technical basis and for purposes of our analysis here that they do not scientific evidence to allow GS in depleted oil and 412 The NETL cost estimates for CO2 transport have storage potential in those formations. gas reservoirs and in saline formations, noting that assume a pipeline of 100 kilometers. NETL (2015) 414 In this discussion, we use the term RTO to there is consensus on how to inject into these at p. 44. indicate both ISOs and RTOs. formation types.’’ 75 FR at 77252 (Dec. 10, 2010).
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saline formations, but also can apply to Site characterization includes elevated pressure are moving as injection into unmineable coal seams assessment of the geologic, predicted within the subsurface.426 and other formations. See 75 FR 77256 hydrogeologic, geochemical, and Well construction must use materials (Dec. 10, 2010). geomechanical properties of a proposed that can withstand contact with CO2 The EPA’s UIC regulations define the GS site to ensure that Class VI wells are over the operational and post-injection term USDWs to include current and sited in appropriate locations and CO2 life of the project.427 These future sources of drinking water and streams are injected into suitable requirements address the unique aquifers that contain a sufficient formations with a confining zone or physical characteristics of CO2, quantity of ground water to supply a zones free of transmissive faults or including its buoyancy relative to other public water system, where formation fractures to ensure USDW fluids in the subsurface and its potential fluids either are currently being used for protection.418 419 Site characterization is corrosivity in the presence of water. human consumption or that contain less designed to eliminate unacceptable sites Requirements for operation of Class than 10,000 ppm total dissolved that may pose risks to USDWs. VI injection wells account for the solids.416 UIC requirements have been Generally, injection of CO2 for GS unique conditions that will occur in place for over three decades and have should occur beneath the lowermost during large-scale GS including been used by the EPA and states to 420 formation containing a USDW. To buoyancy, corrosivity, and high manage hundreds of thousands of increase the availability of Class VI sites sustained pressures over long periods of injection wells nationwide. in geographic areas with very deep operation.428 429 a. Class VI Requirements USDWs, waivers from the injection depth requirements may be sought Owners or operators of Class VI wells In 2010, the EPA established a new where owners or operators can must develop and implement a class of well, Class VI. Class VI wells are demonstrate USDW protection.421 comprehensive testing and monitoring used to inject CO2 into the subsurface Owners or operators of Class VI wells plan for their projects that includes for the purpose of long-term must delineate the project area of review injectate analysis, mechanical integrity sequestration. See 75 FR 77230 (Dec. 10, using computational modeling that testing, corrosion monitoring, ground 2010). This rule accounts for the unique accounts for the physical and chemical water and geochemical monitoring, nature of CO2 injection for large-scale properties of the injected CO2 and pressure fall-off testing, CO2 plume and GS. Specifically, the EPA addressed the displaced fluids and is based on an pressure front monitoring and tracking, unique characteristics of CO2 injection iterative process of available site and, at the discretion of the Class VI for GS including the large CO2 injection characterization, monitoring, and director, surface air and/or soil gas volumes anticipated at GS projects, operational data.422 Within the area of monitoring.430 Owners and operators relative buoyancy of CO2, its mobility review, owners or operators must must periodically review the testing and within subsurface geologic formations, identify and evaluate all artificial monitoring plan to incorporate and its corrosivity in the presence of penetrations to identify those that need operational and monitoring data and the water. The UIC Class VI rule was corrective action to prevent the most recent area of review 431 developed to facilitate GS and ensure movement of CO2 or other fluids into or reevaluation. Robust monitoring of protection of USDWs from the particular between USDWs.423 424 Due to the the CO2 stream, injection pressures, risks that may be posed by large scale potentially large size of the area of integrity of the injection well, ground CO2 injection for purposes of long-term review for Class VI wells, corrective water quality and geochemistry, and GS. The Class VI rule establishes actions may be conducted on a phased monitoring of the CO2 plume and technical requirements for the basis during the lifetime of the position of the pressure front permitting, geologic site project.425 Periodic reevaluation of the throughout injection will ensure characterization, area of review (i.e., the area of review is required and enables protection of USDWs from project area) and corrective action, well owners or operators to incorporate endangerment, preserve water quality, construction, operation, mechanical previously collected monitoring and and allow for timely detection of any integrity testing, monitoring, well operational data to verify that the CO2 leakage of CO2 or displaced formation plugging, post-injection site care, site plume and the associated area of fluids. closure, and financial responsibility for Although subsurface monitoring is the the purpose of protecting USDWs.417 full SAB Committee, found that ‘‘while the primary and effective means of Notably: scientific and technical basis for carbon storage provisions is new and emerging science, the agency determining if there are any risks to a is using the best available science and has USDW, the Class VI rule also authorizes 416 40 CFR 144.3. conducted peer review at a level required by agency the UIC Program Director to require 417 The Class VI rule rests on a robust technical guidance.’’ Memorandum of Jan. 7, 2014, from SAB surface air and/or soil gas monitoring on and scientific foundation, reflecting scientific Work Group Chair to Members of the Chartered oversight and peer review. In developing these SAB and SAB Liaisons, p. 3. The letter was a site-specific basis. For example, the Class VI rules, the EPA engaged with the SAB, subsequently endorsed by the full SAB. Work Class VI Director may require surface providing detailed information on key issues Group Letter of Jan. 24, 2014, as edited by the full air/soil gas monitoring of the flux of CO2 relating to geologic sequestration—including Committee. out of the subsurface, with elevation of monitoring schemes; methods to predict and verify 418 75 FR 77240 and 75 FR 77247 (December 10, capacity, injectivity, and effectiveness of subsurface 2010). CO2 levels above background serving as CO2 storage; and characterization and management 419 40 CFR 146.82 and 146.83. Comments of risks associated with plume migration and indicating that EPA rules have not considered 426 40 CFR 146.84(e)(1). pressure increases in the subsurface. See: http:// issues of exposure pathways such as abandoned 427 40 CFR 146.86(b). yosemite.epa.gov/sab/sabproduct.nsf/0/ wells or formation fissures are mistaken. (See, e.g., 428 75 FR 77250–52 (December 10, 2010); see also AD09B42B75D9E36D85257704004882CF?Open Comments of UARG, p. 52 (Docket entry: EPA–HQ– Document. In addition, the EPA developed a peer id. at 77234–35. Commenters were mistaken in OAR–2013–0495–9666).) asserting (without reference to Class VI provisions) reviewed Vulnerability Evaluation Framework, 420 40 CFR 146.81(d). which served as a technical support document for that the EPA had ignored issues relating to CO2 421 40 CFR 146.95. both the Class VI and Subpart RR rules. See: http:// properties when injected in large volumes in 422 www.epa.gov/climatechange/Downloads/ 40 CFR 146.84(a). supercritical state into geologic formations. ghgemissions/VEF-Technical_Document_ 423 40 CFR 146.84(c)(1)(3) and 146.90(d)(1). 429 40 CFR 146.88. 072408.pdf. In the section 111(b) rulemaking here, 424 40 CFR 146.81(d) and 146.84. 430 40 CFR 146.90. the SAB Work Group, in a letter endorsed by the 425 40 CFR 146.84(b)(2)(iv). 431 40 CFR 146.90(j).
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an indicator of potential leakage and post-injection site care, and site closure; Alliance proposed to inject a total of 22 432 USDW endangerment. and recordkeeping, reporting, and data million metric tons of CO2 into an area Class VI well owners or operators management.446 447 448 449 of review with a radius of must develop and update a site-specific, To inform the development of the UIC approximately 24 miles over the 20-year comprehensive emergency and remedial Class VI rule, the EPA solicited life of the project, with a post-injection response plan that describes actions to stakeholder input and reviewed ongoing site care period of fifty years.453 be taken (e.g., cease injection) to address domestic and international GS research, Both permit applicants addressed potential events that may cause demonstration, and deployment siting and operational aspects of GS endangerment to a USDW during the projects. The EPA also leveraged (including issues relating to volumes of construction, operation, and post- injection experience of the UIC Program, the CO2 and nature of the CO2 injectate), injection site care periods of the such as injection via Class II wells for and included monitoring that helps project.433 EOR. A description of the work provide assurance that CO2 will not Financial responsibility conducted by the EPA in support of the migrate to shallower formations. The demonstrations are required to ensure UIC Class VI rule can be found in the permits were based on findings that that funds will be available for all area preamble for the final rule (see 75 FR regional and local features at the site of review corrective action, injection 77230 and 77237–240(December 10, allow the site to receive injected CO in well plugging, post-injection site care, 2 2010)). specified amounts without buildup of site closure, and emergency and The EPA has issued Class VI permits pressure which would create faults or remedial response.434 for six wells under two projects. In fractures, and further, that monitoring Following cessation of injection, the September 2014, a UIC Class VI provides early warning of any changes operator must conduct comprehensive injection well permit (to construct) was to groundwater or CO leakage.454 post-injection site care activities to issued by the EPA to Archer Daniels 2 The permitting of these projects show the position of the CO2 plume and Midland for an ethanol facility in the associated area of elevated pressure Decatur, Illinois. The goal of the project illustrates that permit applicants were to demonstrate that neither poses an is to demonstrate the ability of the able to address perceived challenges to endangerment to USDWs.435 The Mount Simon geologic formation, a issuance of Class VI permits. These injection well also must be plugged, and deep saline formation, to accept and permits demonstrate that these projects are capable of safely and securely following a demonstration of non- retain industrial scale volumes of CO2 endangerment of USDWs by the Class VI for permanent GS. The permitted well sequestering large volumes of CO2— owner or operator, the site must be has a projected operational period of including from steam generating units— closed.436 437 The default duration for five years, during which time 5.5 for long-term storage since the EPA would not otherwise have issued the the post-injection site care period is 50 million metric tons of CO2 will be years, with flexibility for demonstrating injected into an area of review with a permits. that an alternative period is appropriate radius of approximately 2 miles.450 b. Class II Requirements if it ensures non-endangerment of Following the operational period, USDWs.438 Following successful Archer Daniels Midland plans a post- As explained in Section M.3 above, closure, the facility property deed must injection site care period of ten years.451 CO2 has been injected into the record that the underlying land is used In September 2014, the EPA also issued subsurface via injection wells for EOR, for GS.439 four Class VI injection well permits (to boosting production efficiency by re- The EPA has completed technical construct) to the FutureGen Industrial pressurizing oil and gas reservoirs and guidance documents on Class VI well Alliance project in Jacksonville, Illinois, increasing the mobility of oil. There are site characterization, area of review and decades of industry experience in which proposed to capture CO2 corrective action, well testing and emissions from a coal-fired power plant operating EOR projects. The CO2 monitoring, project plan development, in Meredosia, Illinois and transport the injection wells used for EOR are well construction, and financial regulated through the UIC Class II CO2 by pipeline approximately 30 miles 440 441 442 443 444 445 455 responsibility. The to the deep saline GS site.452 The program. CO2 storage associated with EPA has also issued guidance Class II wells is a common occurrence documents on transitioning Class II 446 http://water.epa.gov/type/groundwater/uic/ and CO2 can be safely stored where wells to Class VI wells; well plugging, class6/upload/epa816p13004.pdf. See also 40 CFR injected through Class II-permitted 144.19 and ‘‘Key Principles in EPA’s Underground wells for the purpose of enhanced oil or 432 40 CFR 146.90(h)(1) and 75 FR at 77259 (Dec. Injection Control Program Class VI Rule Related to gas-related recovery. 10, 2010). Transition of Class II Enhanced Oil Recovery or Gas 433 40 CFR 146.94. Recovery Wells to Class VI’’, April 23, 2015, UIC Class II regulations issued under Available at: http://water.epa.gov/type/ground 434 40 CFR 146.85. section 1421 of SDWA provide water/uic/class6/upload/class2eorclass6memo.pdf. 435 40 CFR 146.93. minimum federal requirements for site 447 http://water.epa.gov/type/groundwater/uic/ 436 40 CFR 146.92. class6/upload/epa816p13005.pdf. characterization, area of review, well 437 40 CFR 146.93. 448 http://water.epa.gov/type/groundwater/uic/ construction (e.g., casing and 438 40 CFR 146.93(b). class6/upload/epa816p13001.pdf. cementing), well operation (e.g., 439 40 CFR 146.93(c). 449 http://water.epa.gov/type/groundwater/uic/ injection pressure), injectate sampling, 440 http://water.epa.gov/type/groundwater/uic/ class6/upload/epa816p13002.pdf. mechanical integrity testing, plugging class6/upload/epa816r13004.pdf. 450 http://www.epa.gov/region5/water/uic/adm/. 441 and abandonment, financial http://water.epa.gov/type/groundwater/uic/ In addition, Archer Daniels Midland received a UIC class6/upload/epa816r13005.pdf. Class VI injection well permit for a second well in responsibility, and reporting. Class II 442 http://water.epa.gov/type/groundwater/uic/ December 2014. Archer Daniels Midland had been wells must undergo periodic class6/upload/epa816r13001.pdf. injecting CO2 at this well since 2011 under a UIC mechanical integrity testing which will 443 http://water.epa.gov/type/groundwater/uic/ Class I permit issued by the Illinois EPA. detect well construction and operational class6/upload/epa816r11017.pdf. 451 http://www.epa.gov/region5/water/uic/adm/. 444 http://water.epa.gov/type/groundwater/uic/ 452 After permit issuance, and for reasons class6/upload/epa816r11020.pdf. unrelated to the permitting proceeding, DOE 453 http://www.epa.gov/r5water/uic/futuregen/. 445 http://water.epa.gov/type/groundwater/uic/ initiated a structured closeout of federal support for 454 http://www.epa.gov/r5water/uic/futuregen/; class6/upload/uicfinancialresponsibilityguidance the FutureGen project in February 2015. However, http://www.epa.gov/region5/water/uic/adm/. final072011v.pdf. these are still active Class VI permits. 455 40 CFR 144.6(b).
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conditions that could lead to loss of on this requirement, the EPA reworded variables may include calculating CO2 injectate and migration into USDWs. the proposed language under emissions from equipment leaks and Section 1425 of SDWA allows states § 60.5555(f) to use the phrase ‘‘If your vented emissions of CO2 from surface to demonstrate that their program is affected unit captures CO2’’ in place of equipment, and considerations for effective in preventing endangerment of the phrase ‘‘If your affected unit calculating CO2 from produced USDWs. These programs must include employs geologic sequestration’’. This fluids.469 permitting, inspection, monitoring, revision is not a change from the EPA’s Subpart RR provides a nationally record-keeping, and reporting initial intent. consistent mass balance framework for components. Reporting under subpart RR is reporting the mass of CO2 that is required for all facilities that have 2. Relevant Requirements of the GHGRP sequestered. Certain monitoring and received a Class VI UIC permit for operational data for a GS site is required 459 The GHGRP requires reporting of injection of CO2. Subpart RR requires to be reported to the EPA annually. facility-level GHG data and other facilities meeting the source category More information on the MRV plan and relevant information from large sources definition (40 CFR 98.440) for any well annual reporting is available in the and suppliers in the United States. The or group of wells to report basic subpart RR final rule (75 FR 75065; final rules under 40 CFR part 60 information on the mass of CO2 received December 1, 2010) and its associated specifically require that if an affected for injection; develop and implement an technical support document.470 EGU captures CO2 to meet the EPA-approved monitoring, reporting, Under this final rule, any well applicable emissions limit, the EGU and verification (MRV) plan; report the receiving CO2 captured from an affected must report in accordance with 40 CFR mass of CO2 sequestered using a mass EGU, be it a Class VI or Class II well, part 98, subpart PP (Suppliers of Carbon balance approach; and report annual must report under subpart RR.471 As 460 461 462 463 Dioxide) and the captured CO2 must be monitoring activities. explained below in Section V.N.5.a, a injected at a facility or facilities that Although deep subsurface monitoring is Class II well’s UIC regulatory status does reports in accordance with 40 CFR part the primary and effective means of not change because it receives such CO2. 98, subpart RR (Geologic Sequestration determining if there are any leaks to a Nor does it change by virtue of reporting of Carbon Dioxide). See § 60.5555(f). USDW, the monitoring employed under under subpart RR. Taken together, these requirements a subpart RR MRV Plan can be utilized, ensure that the amount of captured and if required by the UIC Program Director, 3. UIC and GHGRP Rules Provide sequestered CO2 will be tracked as to further ensure protection of Assurance To Prevent, Monitor, and appropriate at project- and national- USDWs.464 The subpart RR MRV plan Address Releases of Sequestered CO2 to levels, and that the status of the CO2 in includes five major components: Air A delineation of monitoring areas its sequestration site will be monitored, Together the requirements of the UIC based on the CO plume location. including air-side monitoring and 2 and GHGRP programs help ensure that Monitoring may be phased in over reporting. sequestered CO will remain secure, and time.465 2 Specifically, subpart PP provides provide the monitoring mechanisms to requirements to account for CO2 An identification and evaluation of the potential surface leakage pathways identify and address potential leakage supplied to the economy. This subpart using SDWA and CAA authorities. The requires affected facilities with and an assessment of the likelihood, magnitude, and timing, of surface EPA designed the GHGRP subpart RR production process units that capture a requirements for GS with consideration leakage of CO2 through these pathways. CO2 stream for purposes of supplying of UIC requirements. The monitoring CO2 for commercial applications or that The monitoring program will be designed to address the risks required by GHGRP subpart RR is capture and maintain custody of a CO2 complementary to and builds on UIC stream in order to sequester or identified.466 A strategy for detecting and monitoring and testing requirements. 75 otherwise inject it underground to FR 77263. Although the regulations for quantifying any surface leakage of CO2 report the mass of CO2 captured and 456 in the event leakage occurs. Multiple Class VI and Class II injection wells are supplied to the economy. CO2 designed to ensure protection of USDWs suppliers are required to report the monitoring methods and accounting techniques can be used to address from endangerment the practical effect annual quantity of CO2 transferred of these complementary technical offsite and its end use, including GS.457 changes in plume size and risks over 467 requirements, as explained below, is This rule finalizes amendments to time. that they also prevent releases of CO to subpart PP reporting requirements, An approach for establishing the 2 the atmosphere. specifically requiring that the following expected baselines for monitoring CO2 The UIC and GHGRP programs are pieces of information be reported: (1) surface leakage. Baseline data represent built upon an understanding of the the electronic GHG Reporting Tool pre-injection site conditions and are mechanisms by which CO is retained identification (e–GGRT ID) of the EGU used to identify potential anomalies in 2 468 in geologic formations, which are well facility from which CO was captured, monitoring data. 2 understood and proven. and (2) the e–GGRT ID(s) for, and mass A summary of considerations made to calculate site-specific variables for the Structural and stratigraphic trapping of CO2 transferred to, each GS site reporting under subpart RR.458 mass balance equation. Site-specific is a physical trapping mechanism that As noted, this final rule also requires occurs when the CO2 reaches a that any affected EGU unit that captures 459 40 CFR 98.440. stratigraphic zone with low 460 CO to meet the applicable emissions 40 CFR 98.446. permeability (i.e., geologic confining 2 461 40 CFR 98.448. limit must transfer the captured CO2 to 462 40 CFR 98.446(f)(9) and (10). 469 40 CFR 98.448(a)(5). a facility that reports under GHGRP 463 40 CFR 98.446(f)(12). 470 Technical Support Document: ‘‘General subpart RR. In order to provide clarity 464 See 75 FR at 77263 (Dec. 10, 2010). Technical Support Document for Injection and 465 40 CFR 98.448(a)(1). Geologic Sequestration of Carbon Dioxide: Subparts 456 40 CFR 98.420(a)(1). 466 40 CFR 98.448(a)(2). RR and UU’’ (Docket EPA–HQ–OAR–2009–0926), 457 40 CFR 98.426. 467 40 CFR 98.448(a)(3). November 2010. 458 40 CFR 98.426(h). 468 40 CFR 98.448(a)(4). 471 See § 60.5555(f).
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system) that prevents further upward are sited in suitable locations.472 Data monitoring and other needed actions migration. and information collected during site (including corrective action). The Residual trapping is a physical characterization are used in the default duration for the post-injection trapping mechanism that occurs as development of injection well site care period is 50 years, with residual CO2 is immobilized in construction and operating plans; flexibility for demonstrating that an formation pore spaces as disconnected provide inputs for modeling the extent alternative period is appropriate if it droplets or bubbles at the trailing edge of the injected CO2 plume and related ensures non-endangerment of USDWs. of the plume due to capillary forces. pressure front; and establish baseline As the EPA has found, the UIC Class information to which geochemical, VI injection well requirements protect Adsorption trapping is another geophysical, and hydrogeologic site against releases from all exposure physical trapping mechanism that monitoring data collected over the life pathways. Specifically, the EPA stated occurs when CO molecules attach to 2 of the injection project can be that the Class VI rules ‘‘[are] specifically the surfaces of coal and certain organic compared. designed to ensure that the CO2 (and rich shales, displacing other molecules The Class VI rules contain rigorous any incidental associated substances such as methane. subsurface monitoring requirements to derived from the source materials and Solubility trapping is a geochemical assure that the chosen site is the capture process) will be isolated trapping mechanism where a portion of functioning as characterized. This within the injection zone.’’ The EPA the CO2 from the pure fluid phase subsurface monitoring should detect further stated that ‘‘[t]he EPA concluded dissolves into native ground water and leakage of CO2 before CO2 would reach that the elimination of exposure routes hydrocarbons. the atmosphere. For example, when through these requirements, which are Mineral trapping is a geochemical USDWs are present, they are generally implemented through a SDWA UIC trapping mechanism that occurs when located above the injection zone. If CO2 permit, will ensure protection of human chemical reactions between the were to reach a USDW prior to being health and the environment. . .’’.474 dissolved CO2 and minerals in the released to the atmosphere, the presence GHGRP subpart RR complements formation lead to the precipitation of of CO2 or geochemical changes that these UIC Class VI requirements. solid carbonate minerals. would be caused by CO2 migration into Requirements under the UIC program unauthorized zones would be detected are focused on demonstrating that a. Class VI Wells by a UIC Class VI monitoring program USDWs are not endangered as a result As just discussed in Section V.N.1, that is approved and periodically of CO2 injection into the subsurface, the UIC Class VI rule provides a evaluated/adjusted based on permit while requirements under the GHGRP framework to ensure the safety of conditions. through subpart RR enable accounting underground injection of CO2 such that Likewise, UIC Class VI mechanical for CO2 that is geologically sequestered. USDWs are not endangered. As integrity testing requirements are A methodology to account for potential explained below, protection against designed to confirm that a well leakage is developed as part of the releases to USDWs likewise assures maintains internal and external subpart RR MRV plan (see Section against releases to ambient air. Through mechanical integrity. Continuous V.N.2). The MRV plan submitted for the injection well permit application monitoring of the internal mechanical subpart RR may describe (or provide by process, the Class VI permit applicant integrity of Class VI wells ensures that reference to the UIC permit) the relevant (i.e., a prospective Class VI well owner injection wells maintain integrity and elements of the UIC permit (e.g. or operator) must demonstrate that the serves as a way to detect problems with assessment of leakage pathways in the the well system. Mechanical integrity monitoring area) and how those injected CO2 will be trapped and retained in the geologic formation, and testing provides an early indication of elements satisfy the subpart RR not migrate out of the injection zone or potential issues that could lead to CO2 requirements. The MRV plan required the approved project area (i.e., the area leakage from the confining zone, under subpart RR may rely upon the providing assurance and verification knowledge of the subsurface location of of review). To assure that CO2 is confined within the injection zone, that CO2 will not reach the atmosphere. CO2 and site characteristics that are major components to be considered and Further assurance is provided by the developed in the permit application included in Class VI permits are site regulatory requirement that injection process, and operational monitoring characterization, area of review must cease if there is evidence that the results for UIC Class VI permitted wells. In summary, there are well-recognized delineation and corrective action, well injected CO2 and/or associated pressure physical mechanisms for storing CO construction and operation, testing and front may cause endangerment to a 2 473 securely. The comprehensive and monitoring, financial responsibility, USDW. Once the anomalous operating conditions are verified, the rigorous site characterization post-injection site care, well plugging, requirements of the Class VI rules assure emergency and remedial response, and cessation of injection, as required by UIC permits, will minimize any risk of that sites with these properties are site closure as described in Section selected. Subsurface monitoring serves V.N.1. release to air. Following cessation of injection, the to assure that the sequestration site Site characterization provides the operator must conduct comprehensive operates as intended, and this foundation for successful GS projects. It post-injection site care to show the monitoring continues through a post- includes evaluation of the chemical and position of the CO2 plume and the closure period. Although release of CO2 physical mechanisms that will occur in associated area of elevated pressure to to air is unlikely and should be detected the subsurface to immobilize and demonstrate that neither poses an prior to release by subsurface securely store the CO2 within the endangerment to USDWs—also having monitoring, the subpart RR air-side injection zone over the long-term (see the practical effect of preventing monitoring and reporting regime above). Site characterization requires a releases of CO2 to the atmosphere. Post- detailed assessment of the geologic, injection site care includes appropriate 474 79 FR at 353 (January 3, 2014) (Final hydrogeologic, geochemical, and Hazardous Waste Management System: Conditional Exclusion for Carbon Dioxide (CO2) Streams in geomechanical properties of the 472 40 CFR 146.82(a) and (c). Geologic Sequestration Activities under subtitle C proposed GS site to ensure that wells 473 40 CFR 146.94(b). of RCRA). See Section N.5.c below.
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provides back up assurance that The EPA does not agree. CO2 capture from the natural gas in order to meet sequestered CO2 has not been released from EGUs is demonstrated as discussed customer requirements and reduce to the atmosphere. in Sections V.D and V.E. As discussed costs. The project began injecting CO2 below, the volumes of CO2 are into the deep subsurface in 1996. The b. Class II Wells comparable to the amounts that have single offshore injection well injects The Class II rules likewise are been injected at large scale commercial approximately 1 million metric tons per designed to protect USDWs during EOR operations. The EPA also disagrees that year into a thick, permeable sandstone operation, including the injection of the volume of CO2 would quadruple above the gas producing zone. CO2 for EOR. For example, UIC Class II amounts injected into Class II EOR wells Approximately 15 million metric tons of minimum federal requirements because CO2 may be sequestered in deep CO2 have been injected since inception. promulgated under SDWA address site saline formations, which have Many US and international characterization, area of review, well widespread geographic availability (see organizations have conducted construction (e.g., casing and Section M.1). The BSER determination monitoring at Sleipner. The location cementing), well operation (e.g., and regulatory impact analysis for this and dimensions of the CO2 plume have injection pressure), injectate sampling, rule relies on GS in deep saline been measured numerous times using 3- mechanical integrity testing, plugging formations.476 However, the EPA also dimensional seismic monitoring since and abandonment, financial recognizes the potential for sequestering the 1994 pre-injection survey. The responsibility, and reporting. Class II CO2 via EOR and allows the use of EOR monitoring data have demonstrated that wells must undergo periodic as a compliance option. According to although the plume is behaving mechanical integrity testing which will data reported to the GHGRP, differently than initially modeled due to detect well construction and operational approximately 60 million metric tons of thin layers of impermeable shale that conditions that could lead to loss of CO2 were supplied to EOR in the United were not initially identified in the 477 injectate and migration into USDWs. States in 2013. Approximately 70 reservoir model, the CO2 remains The establishment of maximum percent of total CO2 supplied in the trapped in the injection zone. Numerous injection pressures, designed to ensure United States was produced from other techniques have been successfully that the pressure in the injection zone geologic (natural) CO2 sources and used to monitor CO2 storage at Sleipner. during injection does not initiate new approximately 30 percent was captured The research and monitoring at Sleipner fractures or propagate existing fractures from anthropogenic sources. CO2 demonstrates the value of a in the confining zone, prevents injection pipeline systems, such as those serving comprehensive approach to site from causing the movement of fluids the Permian Basin, have multiple characterization, computational into an underground source of drinking sources of CO2 that serve to levelize the modeling and monitoring, as is required water. The safeguards that protect pipeline supply, thus minimizing the under UIC Class VI rules. The USDWs also serve as an early warning effect of supply on the EOR operator. experience at Sleipner demonstrates GS of anthropogenic CO2 in deep mechanism for releases of CO2 to the that large volumes of CO2, of the same atmosphere. saline formations is demonstrated. First, order of magnitude expected for an as explained above, the EPA has issued EGU, can be safely injected and stored CO2 injected via Class II wells construction permits under the Class VI in saline reservoirs over an extended becomes sequestered by the trapping program. It would not have done so, and mechanisms described above in this period. under the regulations cannot have done < Section V.N.3. As with Class VI wells, Sn hvit is another large offshore CO2 so, without demonstrations that CO2 storage project, located at a gas field in for Class II wells that report under would be securely confined. One of subpart RR, there is monitoring to the Barents Sea. Like Sleipner the these projects was for a steam generating natural gas must be treated to reduce evaluate whether CO2 used for EOR will EGU. high levels of CO2 to meet processing remain safely in place both during and Second, international experience with after the injection period. Subpart RR standards and reduce costs. Gas is large scale commercial GS projects has transported via pipeline 95 miles to a provides a CO2 accounting framework demonstrated through extensive gas processing and liquefied natural gas that will enable the EPA to assess both monitoring programs that large volumes the project-level and national efficacy of plant and the CO2 is piped back offshore of CO2 can be safely injected and for injection. Approximately 0.7 million geologic sequestration to determine securely sequestered for long periods of whether additional requirements are metric tons per year CO2 are injected time at volumes and rates consistent into permeable sandstone below the gas necessary and, if so, inform the design with those expected under this rule. of such regulations. reservoir. Between 2008 and 2011, the This experience has also demonstrated operator observed pressure increases in c. Response to Comments the value and efficacy of monitoring the injection formation (Tubaen programs to determine the location of Formation) greater than expected and Commenters maintained that GS was CO2 in the subsurface and detect conducted time lapse seismic surveys not demonstrated for CO captured from 2 potential leakage through the presence and studies of the injection zone and EGUs. In addition, commenters noted of CO2 in the shallow subsurface, near concluded that the pressure increase that the volumes of captured CO would 2 surface and air. was mainly caused by a limited storage be considerably larger than from The Sleipner CO Storage Project is 2 capacity in the formation.478 In 2011, existing GS sites, and could quadruple located at an offshore gas field in the amounts injected into Class II EOR North Sea where CO must be removed 2 478 Grude, S. M. 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In each case, the increase the storage capacity. geochemical methods, including time site-specific characteristics were Approximately 3 million metric tons of lapse seismic, microseismic, wellhead evaluated on a case-by-case basis to CO2 have been injected since 2008. sampling, tracers, down-hole logging, select a site where the geologic Monitoring demonstrates that no core analysis, surface gas monitoring, conditions are suitable to ensure long- leakage has occurred, again groundwater aquifer monitoring and term, safe storage of CO2. Each project demonstrating that large volumes of satellite data. The data have been used was designed to address the site-specific CO2, of the same order of magnitude to support periodic risk assessments characteristics and operated to expected for an EGU, can be safely during the operational phase of the successfully inject CO2 for safe storage. injected and stored in deep saline project. In 2010 new data from seismic, 4. Must the standard of performance for formations over an extended period. satellite and geomechanical models As discussed above in Sections CO2 include CAA requirements on the were used to inform the risk assessment sequestration site? V.E.2.a and M, CO2 from the Great and led to the decision to reduce CO2 Plains Synfuels plant in North Dakota injection pressures due to risk of One commenter maintained as a has been injected into the Weyburn oil vertical leakage into the lower caprock, matter of law that a standard predicated field in Saskatchewan Canada since and risk of loss of well integrity. The on use of CCS is not a ‘‘system of 2000. Over that time period the project caprock at the site consisted of main emission reduction’’, and therefore is has injected more than 16 million caprock units, providing the primary not a ‘‘standard of performance’’ within metric tons of CO2. It is anticipated that seal, and lower caprock units, providing the meaning of section 111 (a)(1) of the approximately 40 million metric tons of additional buffers. There was no leakage Act. The commenter argued that the CO2 will be permanently sequestered from the well or through the caprock, standard does not require sequestration over the lifespan of the project. but the risk analysis identified an of captured CO2 but only capture, so Extensive monitoring by U.S. and increased risk of leakage, therefore, the that no emission reductions are international partners has demonstrated aforementioned precautions were taken. associated with the standard. A gloss on that no leakage has occurred. The Additional analysis of the reservoir, this argument is that there are no sources of CO2 for EOR may vary (e.g., seismic and geomechanical data led to enforceable requirements for the industrial processes, power generation); the decision to suspend CO injection in captured CO2 (‘‘[t]he fate of that 2 [captured] CO is something that the however, this does not impact the June 2011. No leakage has occurred and 2 proposed standard does not proscribe effectiveness of EOR operations (see the injected CO remains safely stored 2 with enforceable requirements’’). The Section V.M.3). in the subsurface. The decision to CO used for EOR may come from commenter further argues that a ‘‘system 2 proceed with safe shutdown of injection anthropogenic or natural sources. The of emission reduction’’ under section resulted from the analysis of seismic source of the CO2 does not impact the 111 must be ‘‘designed into the new and geomechanical data to identify and effectiveness of the EOR operation. CO2 source itself’’ so that off-site respond to storage site risk. The In Salah capture, treatment and processing steps underground sequestration of captured project demonstrates the value of provide a concentrated stream of CO2 in CO emissions ‘‘could never satisfy the developing an integrated and 2 order to meet the needs of the intended statutory requirements governing a comprehensive set of baseline site data end use. CO2 pipeline specifications of ‘standard of performance’’’ (emphasis prior to the start of injection, and the the U.S. Department of Transportation original).480 importance of regular review of Pipeline Hazardous Materials Safety The EPA disagrees with both the legal monitoring data. Commenters also noted Administration found at 49 CFR part and factual assertions in this comment. that the data collection and analysis had 195 (Transportation of Hazardous As to the legal point, the commenter proven effective at preventing any Liquids by Pipeline) apply regardless of fails to distinguish capture and release of sequestered CO2 to either the source of the CO2 and take into sequestration of carbon from every other underground drinking water sources or account CO2 composition, impurities, 479 section 111 standard which is and phase behavior. Additionally, EOR to the atmosphere. predicated on capture of a pollutant. operators and transport companies have These projects demonstrate that Indeed, all emission standards not specifications to ensure related to the sequestration of CO2 captured from predicated on outright pollutant industrial operations has been composition of CO2. These requirements destruction involve capture of the and specifications ensure EOR operators successfully conducted on a large scale pollutant and its subsequent disposition and over relatively long periods of time. receive a known and consistent CO2 in the capturing medium. Thus, metals stream. The volumes of captured CO2 are within are captured in devices like baghouses the same order of magnitude as that At the In Salah CO2 storage project in or scrubbers, leaving a solid waste or expected from EGUs. Even though Algeria, CO2 is removed from natural wastewater to be managed. Gases can be gas produced at three nearby gas fields potentially adverse conditions were captured with activated carbon or under in order to meet export quality identified at some projects (In Salah and pressure, again requiring further Sn VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00081 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 64590 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations impact’’). The EPA thus considers such Class II UIC requirements in Class VI site closure requirements are issues as solid waste and wastewater combination with the monitoring regime not required for Class II CO2 injection generation as part of determining if a of the subpart RR reporting rules, as operations. system of emission reduction is ‘‘best’’ well as the CO2 pipeline standards of EOR operations that are focused on oil and ‘‘adequately demonstrated’’ under the Department of Transportation. or gas production will be managed section 111. See Section V.O below In this regard, the EPA notes that at under the Class II program. If oil or gas (discussion of this rule’s potential cross- proposal it acknowledged the possibility recovery is no longer a significant aspect media impacts). ‘‘that there can be downstream losses of of a Class II permitted EOR operation, the key factor in determining the The further comment that the CO2 after capture, for example during standard is arbitrary because it fails to transportation, injection or storage.’’ 79 potential need to transition an EOR impose any requirements on the FR at 1484. Given the rigorous operation from Class II to Class VI is increased risk to USDWs related to captured CO2 is misplaced. The substantive requirements and the commenter mischaracterizes the monitoring required by the Class VI significant storage of CO2 in the standard as requiring capture only. The rules, the complementary monitoring reservoir, where the regulatory tools of BSER is not just capturing a certain regime of the subpart RR MRV plan and the Class II program cannot successfully manage the risk.483 amount of CO2, but sequestering it. reporting rules, as well as the regulatory Sequestration can occur either on-site or requirements for Class II wells, any such b. GHGRP Subpart RR off-site. Sequestration sites receiving losses would be de minimis. Indeed, the A number of commenters maintained and injecting the captured CO2 are same commenter maintained that the that no EOR operator would accept required to obtain UIC permits and monitoring requirements of the Class VI captured carbon from an EGU due to the report under subpart RR of the GHGRP. rule are overly stringent and that a 50- reporting and other regulatory burdens They must conduct comprehensive year post-injection site care period is imposed by the monitoring 481 monitoring as part of these obligations. unnecessarily long. As it happens, as requirements of GHGRP subpart RR.484 Although the NSPS does not impose noted above, the Class VI rules allow for They noted that preparing a subpart RR regulatory requirements on the an alternative post-injection site care MRV plan could cost upwards of transportation pipeline or the period based on a site-specific $100,000 which would be cost sequestration site, such requirements demonstration. See 40 CFR 146.93(b). prohibitive given other available sources already exist under other regulatory The EPA addresses this comment in of CO2. programs of the Department of more detail in Chapter 2 of the The EPA disagrees with this comment Transportation and the EPA. In Response-to-Comment Document. in several respects. First, the BSER particular, the EPA is reasonably relying determination and regulatory impact on the already-adopted, and very 5. Other Perceived Obstacles to Geologic analysis for this rule relies on GS in rigorous, Class VI well requirements in Sequestration deep saline formations, not on EOR. combination with the subpart RR a. Class II to Class VI transition However, the EPA also recognizes the requirements to provide secure potential for sequestering CO2 via EOR, A number of commenters maintained sequestration of captured CO2. The EPA but disagrees that subpart RR has also considered carefully the that the Class VI rules could effectively requirements effectively preclude or requirements and operating history of force all Class II wells to transition to substantially inhibit the use of EOR. the Class II requirements for EOR wells, Class VI wells if they inject The cost of compliance with subpart which, in combination with the subpart anthropogenic CO2, and further RR is not significant enough to offset the RR requirements, ensure protection of maintained that, as a practical matter, potential revenue for the EOR operator USDWs from endangerment, provide the this would render EOR unavailable for from the sale of produced oil for CCS monitoring mechanisms to identify and such CO2. The EPA disagrees with these projects that are reliant on EOR. First, address potential leakage using SDWA comments. Injection of anthropogenic the costs associated with subpart RR are and CAA authorities, and have the CO2 into Class II wells does not force relatively modest, especially in practical effect of preventing releases of transition of these wells to Class VI comparison with revenues from an EOR CO2 to the atmosphere. This is wells—not during the well’s active field. In the economic impact analysis analogous to the many section 111 operation and not when EOR operations for subpart RR, the EPA estimated that standards of performance for metals cease. We recognize the widespread use an EOR project with a Class II permit which result in a captured air pollution of EOR and the expectation that injected would incur a first year cost of up to control residue to be disposed of CO2 can remain underground. The EPA $147,030 to develop an MRV plan, and pursuant to waste management issued a memorandum to its regional an annual cost of $27,787 to maintain requirements of the rules implementing offices on April 23, 2015 reflecting these the plan; the EPA estimated annual the Resource Conservation and principles: 482 reporting and recordkeeping costs at 485 Recovery Act. It is also analogous to the Geologic storage of CO2 can continue $13,262 per year. Monitoring costs many section 111 standards of to be permitted under the UIC Class II performance for metals or organics program. 483 In this regard, the Class VI rules provide that, owners or operators that are injecting carbon captured in wet air pollution control Use of anthropogenic CO2 in EOR dioxide for the primary purpose of long-term systems resulting in wastewater operations does not necessitate a Class storage into an oil and gas reservoir must apply for discharged to a navigable water where VI permit. and obtain a Class VI geologic sequestration permit pollutant loadings are controlled under when there is an increased risk to USDWs compared to Class II operations. 40 CFR 144.19. rules implementing the Clean Water 481 Comments of UARG, p. 63 (Docket entry: 484 See e.g., comments of UARG, p, 63 (Docket Act. Again, these are non-air EPA–HQ–OAR–2013–0495–9666). entry: EPA–HQ–OAR–2013–0495–9666); Southern environmental impacts for which the 482 ‘‘Key Principles in EPA’s Underground Co., p. 37 (Docket entry: EPA–HQ–OAR–2013– EPA must account in establishing a Injection Control Program Class VI Rule Related to 0495–10095); American Petroleum Institute pp. 40– Transition of Class II Enhanced Oil Recovery or Gas 50 Docket entry: EPA–HQ–OAR–2013–0495– section 111(a) standard. The EPA has Recovery Wells to Class VI’’, April 23, 2015. 10098). reasonably done so here based on the Available at: http://water.epa.gov/type/ground 485 Subpart RR costs are presented in 2008 US regulatory regimes of the Class VI and water/uic/class6/upload/class2eorclass6memo.pdf. dollars. VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00082 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64591 are estimated to range from $0.02 per rule as including incidental associated finding that geologic sequestration of metric ton (base case scenario) to substances derived from the source CO2 from EGUs can be considered to be approximately $2 per metric ton of CO2 materials and the capture process, and adequately demonstrated. Many of the (high scenario). Using a range of any substances added to the stream to issues referred to in comments relate to scenarios (that included high end enable or improve the injection process) property rights: issues of ownership of estimates), these subpart RR costs are might be identified as ‘‘hazardous pore space, relationship of sequestration approximately three to four percent of wastes’’ subject to RCRA Subtitle C to ownership of mineral rights, issues of estimated revenues for an average EOR regulation.488 Nevertheless, to reduce dealing with multiple landowners, lack field, indicating that the costs can potential uncertainty regarding the of state law frameworks, or competing, readily be absorbed. 75 FR 75073. regulatory status of CO2 streams under inconsistent state laws.491 Other Furthermore, there is a demand for RCRA Subtitle C, and in order to commenters noted the lack of long-term new CO2 by EOR operators, even facilitate the deployment of geologic liability insurance, and noted beyond current natural sources of CO2. sequestration, the EPA recently uncertainties regarding long-term For example, in an April 2014 study, concluded a rulemaking to exclude liability generally.492 DOE concluded that future development certain CO2 streams from the RCRA of EOR will need to rely on captured definition of hazardous waste.489 In that An IPCC special report on CCS found 486 that with an appropriate site selection, CO2. Thus, the argument that EOR rulemaking, the EPA determined that if a monitoring program, a regulatory operators will obtain CO2 from other any such CO2 streams would be sources without triggering subpart RR hazardous wastes, further RCRA system, and the appropriate use of responsibilities, which assumes regulation is unnecessary to protect remediation methods, the risks of GS adequate supplies of CO2 from other human health and the environment would be comparable to risks of current sources, lacks foundation. In addition, provided certain conditions are met. activities, such as EOR, acid gas the Internal Revenue Code section 45Q Specifically, the rule conditionally injection and underground natural gas 493 provides a tax credit for CO2 excludes from Subtitle C regulations storage. Furthermore, an interagency sequestration which is far greater than CO2 streams if they are (1) transported CCS task force examined GS-related subpart RR costs.487 In sum, the cost of in compliance with U.S. Department of legal issues thoroughly and concluded complying with subpart RR Transportation or state requirements; (2) that early CCS projects can proceed requirements, including the cost of injected in compliance with UIC Class under the existing legal framework with MRV, is not significant enough to deter VI requirements (summarized above); respect to issues such as property rights EOR operators from purchasing EGU (3) no other hazardous wastes are mixed and liability.494 As noted earlier, both captured CO2. with or co-injected with the CO2 stream; the Archer Daniels Midland (ADM) and The EPA addresses these comments in and (4) generators (e.g., emission FutureGen projects addressed siting and more detail in the Response to Comment sources) and Class VI well owners or operational aspects of GS (including Document. operators sign certification statements. issues relating to volumes of the CO2 490 c. Conditional exclusion for geologic See 40 CFR 261.4(h)). The D.C. and the nature of the CO2 injectate) in sequestration of CO2 streams under the Circuit recently dismissed all challenges their permit applications. The fact that Resource Conservation and Recovery to this rule in Carbon Sequestration these applicants pursued permits Act (RCRA) Council and Southern Company indicates that they regarded any Services v. EPA, No. 787 F. 3d 1129 potential property rights issues as Certain commenters voiced concerns (D.C. Cir. 2015). resolvable. that regulatory requirements for hazardous wastes might apply to d. Other perceived uncertainties Commenter American Electric Power (AEP) referred to its own experience captured CO2 and these requirements Other commenters claimed that with the Mountaineer demonstration might be inconsistent with, or otherwise various legal uncertainties preclude a project. AEP noted that although this impede, GS of captured CO2 from EGUs. project was not full scale, finding a The EPA has acted to remove any such 488 No hazardous waste listings apply to CO 2 suitable repository, notwithstanding a (highly conjectural) uncertainty. The streams. Therefore, a CO2 stream could be identified Resource Conservation and Recovery (i.e. defined) as a hazardous waste only if it exhibits generally favorable geologic area, one or more of the hazardous characteristics. 79 FR Act (RCRA) authorizes the EPA to proved difficult. The company referred 355 (Jan 3. 2014). to years spent in site characterization regulate the management of hazardous 489 79 FR 350 (Jan. 3, 2014). 495 wastes. In particular, RCRA Subtitle C 490 The EPA made clear in the final conditional and digging multiple wells. Other authorizes a cradle to grave regulatory exclusion that that rule does not address, and is not commenters noted more generally that program for wastes identified as intended to affect the RCRA regulatory status of CO2 site characterization issues can be time- streams that are injected into wells other than Class consuming and difficult, and quoted hazardous, whether specifically listed as VI. However, the EPA noted in the preamble to the hazardous or whether the waste fails final rule that (based on the limited information certain tests of hazardous provided in public comments) should CO2 be used 491 See e.g. Comments of Duke Energy, p. 28 characteristics. The EPA currently has for its intended purpose as it is injected into UIC Docket entry: EPA–HQ–OAR–2013–0495–9426); Class II wells for the purpose of EOR/EGR UARG, p. 62 (Docket entry: EPA–HQ–OAR–2013– little information to conclude that CO2 (enhanced oil recovery/enhanced gas recovery), it is 0495–9666); AEP, p. 91 (Docket entry: EPA–HQ– streams (defined in the RCRA exclusion the EPA’s expectation that such an injection process OAR–2013–0495–10618). would not generally be a waste management 492 See e.g. Comments of UARG, pp. 26 (Docket activity. 79 FR 355. The EPA encouraged persons 486 ‘‘Near Term Projections of CO2 Utilization for entry: EPA–HQ–OAR–2013–0495–9666), 62; EEI, p. to consult with the appropriate regulatory authority 92 Docket entry: EPA–HQ–OAR–2013–0495–9780); Enhanced Oil Recovery’’. DOE/NETL–2014/1648. to address any fact-specific questions that they may Duke Energy, pp. 27, 28 Docket entry: EPA–HQ– April 2014. have regarding the status of CO in situations that 2 OAR–2013–0495–9426). 487 http://www.irs.gov/irb/2009-44_IRB/ar11.html. are beyond the scope of that rule. Id. Moreover, use 493 Intergovernmental Panel on Climate Change. The section 45Q tax credit for calendar year 2015 of anthropogenic CO2 for EOR is long-standing and (2005). Special Report on Carbon Dioxide Capture is $10.92 per metric ton of qualified CO2 that is has flourished in all of the years that EPA’s subtitle captured and used in a qualified EOR project and C regulations (which among other things, define and Storage. 494 $21.85 per metric ton of qualified CO2 that is what a solid waste is for purposes of those http://www.epa.gov/climatechange/ captured and used in a qualified non-EOR GS regulations) have been in place. The RCRA subtitle Downloads/ccs/CCS-Task-Force-Report-2010.pdf. project. http://www.irs.gov/irb/2015-26_IRB/ C regulatory program consequently has not been an 495 AEP Comments at pp. 93, 96 (Docket entry: ar14.html. impediment to use of anthropogenic CO2 for EOR. EPA–HQ–OAR–2013–0495–10618). VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00083 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 64592 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations studies suggesting that it could take 5 injection wells than AEP references.498 particular, commenters noted that the years to obtain a Class VI permit.496 See also discussion of this issue in use of CCS will increase the water usage The EPA agrees that robust site Section V.I.5 above. at units that implement CCS to meet the proposed standard of performance. At characterization and selection is O. Non-air Quality Impacts and Energy important to ensuring capacity needs Requirements least one commenter claimed that are met and that the sequestered CO2 is addition of an amine-based CCS system safely stored. Efforts to characterize As part of the determination that would double the consumptive water geologic formations suitable for GS have SCPC with partial CCS is the best use of a power plant, which would be been underway at DOE through the system of emission reduction unacceptable, especially in drought- RCSPs since 2003 (see Section V.M). adequately demonstrated, the EPA has ridden states and in the arid west and Additionally, since 2007, the USGS has given careful consideration to non-air referenced a study in the scientific been assessing U.S. geologic storage quality health and environmental literature as support.499 The commenter impacts and energy requirements, as resources for CO2. As noted earlier, also references a DOE/NETL report that DOE, in partnership with researchers, required by CAA section 111 (a). We likewise notes significant increases in universities, and organizations across have also considered those factors for the amount of cooling and process water the country, is demonstrating that GS alternative potential compliance paths required with the use of carbon capture to assure that the standard does not can be achieved safely, permanently, technology.500 However, those studies have unintended adverse health, and economically at large scales, and discuss increased water use for cases environmental or energy-related projects supported by the department where full CCS (90 percent or greater consequences. The EPA finds that have safely and permanently stored 10 capture) is implemented. As we neither the BSER, nor the possible million metric tons of CO . discussed in both the proposal and in 2 alternative compliance pathways, would In the time since the commenter this preamble, the EPA does not find have adverse consequences from either that highly efficient new generation submitted comments several Class VI a non-air quality impact or energy permits have been issued by the EPA. technology implementing full CCS is the requirement perspective. BSER for new steam generating EGUs. These projects demonstrate that a GS 1. Transport and Sequestration of site permit applicant could potentially Captured CO2 The EPA examined water use prepare and obtain a UIC permit As just discussed in detail, the EPA predicted from the updated DOE/NETL concurrent with permits required for an finds that the Class VI and II rules, as studies in order to determine the EGU. With respect to AEP’s experience complemented by the subpart RR magnitude of increased water usage for with the Mountaineer demonstration GHGRP reporting and monitoring a new SCPC implementing partial CCS project, notwithstanding difficulties, the requirements, amply safeguard against to meet the final standard of 1,400 lb company was able to successfully dig potential of injected CO2 to degrade CO2/MWh-g. The predicted water wells, and safely inject captured CO2. underground sources of drinking water consumption for varying levels of Moreover, the company indicated it and amply protect against any releases partial and full CCS are provided in fully expected to be able to do so at full of sequestered CO2 to the atmosphere. Table 13. The results show that a new scale and explained how.497 The EPA The EPA likewise finds that the plenary SCPC unit that implements 16 percent notes further that a monitoring program regulatory controls on CO2 pipelines partial CCS to meet the final standard and its associated infrastructure (e.g., assure that CO2 can be safely conveyed would see an increase in water monitoring wells) and costs will be without environmental release, and that consumption (the difference between dependent on site-specific these rules, plus the complementary the predicted water withdraw and characteristics, such as CO2 injection tracking and reporting rules in subpart discharge) of about 6.4 percent rate and volume, geology, the presence RR, assure that captured CO2 will be compared to an SCPC with no CCS and of artificial penetrations, among other properly tracked and conveyed to a the same net power output. By factors. It is thus not appropriate to sequestration site. comparison, a unit implementing 35 generalize from AEP’s experience, and percent CCS to meet the proposed 2. Water Use Impacts assume that other sites will require the emission limitation of 1,100 lb CO2/ same number of wells for site Commenters claimed that the EPA MWh-g would see an increase in water characterization or injection. In this ignored the negative environmental consumption of 16.0 percent and a new regard, we note that the ADM and impacts of the use of CCS for the unit implementing full (90 percent) CCS FutureGen construction permits for mitigation of CO2 emissions from fossil would see an increase of almost 50 Class VI wells involved far fewer fuel-fired steam generating EGUs. In percent. TABLE 13—PREDICTED WATER CONSUMPTION WITH IMPLEMENTATION OF VARIOUS LEVELS OF PARTIAL CCS 501 Raw water Increase Technology consumption, compared to gpm SCPC, % SCPC ...... 4,095 — 496 See e.g. Comments of UARG, p. 55 (Docket 498 The FutureGen UIC Class VI injection well 499 See comments of UARG at p. 84 (Docket entry: entry: EPA–HQ–OAR–2013–0495–9666), citing to permits (four in total) require nine monitoring EPA–HQ–OAR–2013–0495–9666) referencing Haibo Cichanowitz CCS Report (2012). wells. http://www.epa.gov/r5water/uic/futuregen/. Zhai, et al., Water Use at Pulverized Coal Power 497 See AEP FEED Study at pp. 36–43. The The Archer Daniels Midland UIC Class VI injection Plants with Post-combustion Carbon Capture and company likewise explained the monitoring regime well permit issued in September 2014 (CCS2) Storage, 45 Environ. Sci. Technol., 2479–85 (2011). it would utilize to verify containment, and the well requires five monitoring wells and the Archer 500 construction it would utilize to guarantee secure Id at p. 84 referencing DOE/NETL–402/ sequestration. Id. at pp. 44–54. Available at: Daniels Midland UIC Class VI injection well permit 080108, ‘‘Water Requirements for Existing and www.globalccsinstitute.com/publications/aep- issued in December 2014 (CCS1) was permitted Emerging Thermoelectric Plant Technologies’’ at 13 mountaineer-ii-project-front-end-engineering-and- with two monitoring wells. http://www.epa.gov/ (Aug. 2008, Apr. 2009 revision). design-feed-report. region5/water/uic/adm/. VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00084 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64593 TABLE 13—PREDICTED WATER CONSUMPTION WITH IMPLEMENTATION OF VARIOUS LEVELS OF PARTIAL CCS 501— Continued Raw water Increase Technology consumption, compared to gpm SCPC, % SCPC + 16% CCS ...... 4,359 6.4 SCPC + 35% CCS ...... 4,751 16.0 SCPC + 90% CCS ...... 6,069 48.2 IGCC* ...... 3,334 ¥18.6 IGCC + 90% CCS* ...... 4,815 17.6 * The IGCC results presented in the DOE/NETL report are for an IGCC with net output of 622 MWe and an IGCC with full CCS with net output of 543 MWe. The water consumption for each was normalized to 550 MWe to be consistent with the SPCP cases. Similar to other air pollution new IGCC implementing 90 percent 3. Energy Requirements controls—such as a wet flue gas CCS. The predicted water consumption desulfurization scrubber—utilization of for the new IGCC unit is nearly 20 The EPA also examined the expected post-combustion amine-based capture percent less than that predicted for the impacts on energy requirements for a systems results in increased new SCPC unit without CCS (and new unit meeting the final promulgated consumption of water. However, by almost 25 percent less than the SCPC standard and finds impacts to be finalizing a standard that is less unit meeting the final standard). The minimal. Specifically, the EPA stringent than the proposed limitation EPA rejected new IGCC implementing examined the increased auxiliary load and by rejecting full CCS as the BSER, full CCS as BSER because the predicted or parasitic energy requirements of a the EPA has reduced the increased costs were significantly more than system implementing CCS. The EPA amount of water needed as compared to alternative technologies. The EPA also examined the predicted auxiliary power a similar unit without CCS. Further, the does not find that a new IGCC EGU is demand from the updated DOE/NETL EPA notes that there are additional studies in order to determine the opportunities to minimize the water part of the final BSER (for reasons discussed in Section V.P). However, the increased energy requirement for a new usage at such a facility. For example, the SCPC implementing partial CCS to meet SaskPower Boundary Dam Unit #3 post- EPA does note that IGCC is a viable alternative compliance option and, as the final standard of 1,400 lb CO2/MWh- combustion capture project captures g. The predicted gross power output, the water from the coal and from the shown here, would result in less water auxiliary power demand, and the combustion process and recycles the consumption than a compliant SCPC captured water in the process, resulting EGU. The EPA also notes that predicted parasitic power demand (percent of in decreased need for withdrawal of water consumption at a new NGCC unit gross output) are provided in Table 14 fresh water. would be less than half that for a new for varying levels of partial and full The EPA also examined the predicted SCPC EGU with the same net output.502 CCS. water usage for a new IGCC and for a TABLE 14—PREDICTED PARASITIC POWER DEMAND WITH IMPLEMENTATION OF VARIOUS LEVELS OF PARTIAL CCS 503 Gross power Auxiliary Parasitic Generation technology output, MWe power, MWe demand (%) SCPC ...... 580 30 5.2 SCPC + 16% CCS ...... 599 38 6.3 SCPC + 35% CCS ...... 603 53 8.8 SCPC + 90% CCS ...... 642 91 14.2 IGCC ...... 748 126 16.8 IGCC + 90% CCS ...... 734 191 26.0 CCS ...... 734 191 26.0 The auxiliary power demand is the an SCPC EGU without CCS, the equipment, and steam is need to amount of the gross power output that auxiliary power is used to primarily to regenerate the capture solvents (i.e., the is utilized within the facility rather than operate fans, motors, pumps, etc. solvents are heated to release the used to produce electricity for sale to associated with operation of the facility captured CO2). the grid. The parasitic power demand and the associated pollution control The results in Table 14 show that a (or parasitic load) is the percentage of equipment. When carbon capture new SCPC unit without CCS can expect the gross power output that is needed to equipment is incorporated, additional a parasitic power demand of about 5.2 meet the auxiliary power demand.504 In power is needed to operate associated percent. A new SCPC unit meeting the 501 Exhibits A–1 and A–2 at p. 16–17 from ‘‘Cost generation or management. See Section XIII.D 504 Note that this auxiliary power demand is not and Performance Baseline for Fossil Energy Plants below. necessarily met from power or steam generated Supplement: Sensitivity to CO2 Capture Rate in 503 Exhibits A–1 and A–2 at p. 16–17 from ‘‘Cost from the EGU. External sources can also be utilized Coal-Fired Power Plants’’, DOE/NETL–2015/1720 and Performance Baseline for Fossil Energy Plants for this purpose. (June 22, 2015). Supplement: Sensitivity to CO2 Capture Rate in 502 The EPA also finds that the standards would Coal-Fired Power Plants’’, DOE/NETL–2015/1720 not result in any significant impact on solid waste (June 2015). VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00085 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 64594 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations final standard of performance by percent—less than half that for a new reduction of CO2 emissions for the implementing 16 percent partial CCS SCPC EGU with the same net output.506 following reasons: will see a parasitic power demand of With respect to potential nationwide a. Lack of Significant CO Reductions about 6.3 percent, which is not a 2 impacts on energy requirements, as When Compared to Business as Usual significant increase in energy described above in Section V.H.3 and requirement. Of course, new SCPC more extensively in the RIA chapter 4, At the outset, we reviewed the EGUs that implement higher levels of the EPA reasonably projects that no new emission rates of efficient PC and CFB CCS will expect higher amounts of non-compliant fossil-fuel fired steam units. According to the DOE/NETL parasitic power demand. As shown in electric capacity will be constructed estimates, a newly constructed Table 14, a new SCPC EGU through 2022 (the end of the 8 year subcritical PC unit firing bituminous implementing full CCS would expect to review cycle for NSPS). It is possible, as coal would emit approximately 1,800 lb 508 utilize over 14 percent of its gross power described earlier, that some new sources CO2/MWh-g, a new highly efficient output to operate the facility and the could be built to preserve fuel diversity, SCPC unit using bituminous coal would carbon capture system. But, the EPA but even so, the number of such sources emit nearly 1,720 lb CO2/MWh-g, and a does not find that a new SCPC would be small and therefore would not new IGCC unit would emit about 1,430 509 510 implementing full CCS is the BSER for significantly impact national energy lb CO2/MWh-g. Emissions from new fossil-fired steam generating units. requirements (assuming that such comparable sources utilizing sub- See Section V.P.2 below. sources would not already be reflected bituminous coal or lignite will have 511 The EPA also notes that there is on- in the baseline conditions just noted). somewhat higher CO2 emissions. going research sponsored by DOE/NETL P. Options That Were Considered by the Some commenters noted that new and others to further reduce the energy coal-fired plants utilizing supercritical requirements of the carbon capture EPA but Were Ultimately Not Determined To Be the BSER boiler design or IGCC would provide systems. Progress is being made. As was substantial emission reductions mentioned previously, the heat duty In light of the comments received, the compared to the emissions from the (the energy required to regenerate the EPA re-examined several alternative existing subcritical coal plants that are capture solvent) for the amine scrubbing systems of emission reduction and currently in wide use in the power process used at the Searles Valley reaffirms in this rulemaking our sector. However, most of the recent new facility in the mid-70’s was about 12 MJ/ proposed determination that those power sector projects using solid fossil mt CO2 removed as compared to a heat alternatives do not represent the ‘‘best’’ fuel (coal or petroleum coke) as the duty of about 2.5 MJ/mt CO2 removed system of emission reduction when primary fuel—both those that have been for the amine processes used at compared against the other available constructed and those that have been Boundary Dam and for the amine emission reduction options. These are proposed—are supercritical boilers and system that will be used at the WA described below. See also Section IV.B.1 IGCC units. About 60 percent of new Parish facility.505 above. coal-fired utility boiler capacity that has The EPA also examined the predicted 1. Highly Efficient Generation come on-line since 2005 was parasitic power demand for a new IGCC supercritical and of the new capacity and for a new IGCC implementing 90 Technology (e.g., Supercritical or Ultra- supercritical Boilers) that came on-line since 2010, about 70 percent CCS. As we have noted percent was supercritical. No new coal- elsewhere, the auxiliary power demand In the January 2014 proposal, we fired utility boilers began operation in for a new IGCC unit is more than that considered whether ‘Highly Efficient either 2013 or 2014. Coal-fired power for that of a new SCPC. As one can see New Generation without CCS plants that have come on-line most in Table 14, a new IGCC unit can expect Technology’ should constitute the BSER recently include AEP’s John W. Turk, Jr. to see a nearly 17 percent parasitic for new steam generating units. 79 FR at Power Plant, which is a 600 MW ultra- power demand; and a new IGCC unit 1468–69. The discussion focused on the supercritical 512 PC (USCPC) facility implementing full CCS would expect a performance of highly efficient located in the southwest corner of parasitic power demand of nearly 30 generation technology (that does not Arkansas, and Duke Energy’s percent. Of course, the EPA rejected include any implementation of CCS), Edwardsport plant, which is a 618 MW new IGCC implementing full CCS as such as a supercritical 507 pulverized BSER because of the potentially coal (SCPC) or a supercritical CFB 508 Exhibit ES–2 from ‘‘Cost and Performance unreasonable costs. The EPA also does boiler, or a modern, well-performing Baseline for Fossil Energy Plants Volume 1: not find that a new IGCC EGU is part of IGCC unit. Bituminous Coal and Natural Gas to Electricity’’, the final BSER (for reasons discussed Revision 2, Report DOE/NETL–2010/1397 All these options are technically (November 2010). elsewhere in Section V.P.1 below). feasible—there are numerous examples 509 ‘‘Cost and Performance Baseline for Fossil However, as we have noted, the EPA of each operating in the U.S. and Energy Plants Supplement: Sensitivity to CO2 does find IGCC to be a viable alternative worldwide. However, we do not find Capture Rate in Coal-Fired Power Plants’’, DOE/ compliance option. Utilities and project NETL–2015/1720 (June 2015); SCPC rates come them to qualify as the best system for from Exhibit A–2 and IGCC rates come from Exhibit developers should consider the A–4. increased auxiliary power demand for 506 The EPA also finds that the standards would 510 The comparable emissions on a net basis are: an IGCC when considering their options not result in any significant impact on solid waste subcritical PC—1,890 lb CO2/MWh-n; SCPC–1,705 for new power generation. The EPA also generation or management. See Section XII.D lb CO2/MWh-n; and IGCC—1,724 lb CO2/MWh-n. notes that the predicted parasitic load below. (See same references as for gross emissions 507 provided in the text). for a new NGCC unit would be about 2 Subcritical coal-fired boilers are designed and operated with a steam cycle below the critical point 511 Exhibit ES–2 from ‘‘Cost and Performance of water. Supercritical coal-fired boilers are Baseline for Fossil Energy Plants Volume 3b: Low 505 ‘‘From Lubbock, TX to Thompsons, TX— designed and operated with a steam cycle above the Rank Coal to Electricity: Combustion Cases’’, Report Amine Scrubbing for Commercial CO2 Capture from critical point of water. Increasing the steam DOE/NETL–2010/1463 (March 2011). Power Plants’’, plenary address by Prof. Gary pressure and temperature increases the amount of 512 Ultra-supercritical (U.S.C.) and advanced Rochelle at the 12th International Conference on energy within the steam, so that more energy can ultra-supercritical (A–U.S.C.) are terms often used Greenhouse Gas Technology (GHGT–12), Austin, be extracted by the steam turbine, which in turn to designate a coal-fired power plant design with TX (October 2014). leads to increased efficiency and lower emissions. steam conditions well above the critical point. VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00086 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64595 ‘‘CCS ready’’ 513 IGCC unit located in we discuss elsewhere in this final to identify highly efficient generation Knox County, Indiana. Both of those preamble, partial CCS can achieve technology (without CCS) as the BSER. facilities came on-line in 2012. It is emission limitations beyond business as At present, CCS technologies are the likely that the units that initiated usual and do so at a reasonable cost. most promising options to achieve operation in 2010 or later were The EPA also considered IGCC significant reductions in CO2 emissions conceived of, planned, designed, and technology and whether it represents from newly constructed fossil fuel-fired permitted well before 2010—likely in the BSER for new power plants utilizing steam generating units. CCS technology the early 2000s. Thus, it seems clear that coal or other solid fossil fuels. IGCC is also now a viable retrofit option for the power sector had already, at that units, on a gross-output basis, have some modified, reconstructed and point, transitioned to the selection of inherently lower CO2 emission rates existing sources—depending upon the supercritical boiler technology as when compared to similarly-sized SCPC configuration, location and age of those ‘‘business as usual’’ for new coal-fired units. However, the net emission rates sources. As CCS technologies are power plants. Since that time, there and overall emissions to the atmosphere deployed and used more there is an have been other coal-fired power plants (i.e., tons of CO2 per year) tend to be expectation that, based on previous that have been proposed and almost all more similar (though still somewhat experience with advanced technologies, of them have been either supercritical lower) for new IGCC units when the performance will improve and the boiler designs or IGCC units. In Table 1 compared to new SCPC units with the implementation costs will decline. The of the Technical Support Document same electrical output. Therefore an improved performance and lower costs Fossil Fuel-Fired Boiler and IGCC EGU emission limitation based on the will provide additional incentive for Projects Under Development: Status and expected performance of a new IGCC further implementation in the future. Approach 514 for the January 2014 unit would result in some CO2 emission The Intergovernmental Panel on proposal, the EPA listed the reductions from the segment of the Climate Change (IPCC) recently released development status of ‘‘potential industry that would otherwise construct its Fifth Assessment report, 516 which transitional sources’’ (i.e., projects that new PC units, but not from the segment recognizes that widespread deployment had been proposed and had received of the industry that would already of CCS is crucial to reach the long term Prevention of Significant Deterioration construct new IGCC units. A gross- climate goals. The authors of the report (PSD) preconstruction permits as of output-based emission limitation used models to predict the likelihood of April 13, 2012). Of the 16 proposed EGU consistent with the expected stabilizing the atmospheric projects in Table 1—most of which have performance of a new IGCC unit would concentration of CO2 at 450 ppm by been cancelled or converted to or still require some additional control, 2050 with or without carbon capture replaced with NGCC projects—the such as partial CCS, on a new and storage (CCS). They found that majority (nine) are either supercritical supercritical boiler. several of the models were not able to As is shown in Section V.J and H, PC or IGCC designs. Five of the reach this goal without CCS, which additional emission reductions beyond proposed projects were CFB designs underlines the importance of deploying those that would result from an with only one being a subcritical PC and further developing CCS on a large emission standard based on a new SCPC design. scale. boiler or even a new IGCC unit as the American Electric Power (AEP), in an The EPA is aware of only one new BSER can be achieved at a reasonable evaluation of lessons learned from the coal-fired power plant that is actively in cost. Because practicable emission Phase 1 of its Mountaineer CCS project, the construction phase. That plant is controls are available that are of wrote: ‘‘AEP still believes the Mississippi Power’s Kemper County reasonable cost at the source level and advancement of CCS is critical for the Energy Facility in Kemper County, that will have little cost and energy sustainability of coal-fired MS—an IGCC unit that plans to begin impact at the national level, the EPA is generation.’’ 517 operations in 2016 and will implement according significant weight to the Some commenters felt that the partial CCS to capture approximately 65 factor of amount of emissions proposed standard of performance for percent of the available CO 2, which will reductions in determining the BSER. As new steam generating units, based on be sold for use in EOR operations. discussed above, the D.C. Circuit has implementation of partial CCS at an Considering the direction that the emphasized this factor in describing the emission rate of 1,100 lb/MWh-g, would power sector has been taking and the purpose of CAA section 111 as to not serve to promote the increased changes that it is undergoing, achieve ‘‘as much [emission reduction] deployment and implementation of identifying a new supercritical unit as as practicable.’’ 515 CCS. The commenters argued that such the BSER and requiring an emission a standard could instead have the limitation based on the performance of b. Lack of Incentive for Technological unintended result of discouraging the such units thus would provide few, if Innovation further development of advanced coal any, additional CO2 emission reductions As discussed above, the EPA is generating technologies such as ultra- beyond the sector’s ‘‘business as usual’’. justifying its identification of the BSER supercritical boilers and improved IGCC As noted, for the most part, new sources based on its weighing of the factors designs. are already designed to achieve at least explicitly identified in CAA section Commenters further argued that such that emission limitation. This criterion 111(a)(1), including the amount of the a standard will stifle further does not itself eliminate supercritical emission reduction. Under the D.C. technology from consideration as BSER. Circuit case law, encouraging the 516 IPCC, Working Group III, Climate Change However, existing technologies must be development and implementation of 2014: Mitigation of Climate Change, http:// considered in the context of the range of mitigation2014.org/report/publication/. advanced control technology must also 517 CCS LESSONS LEARNED REPORT American technically feasible technologies and, as be considered (and, in any case, may Electric Power Mountaineer CCS II Project Phase 1, reasonably be considered; see Section Prepared for The Global CCS Institute Project # PRO 513 A ‘‘CCS ready’’ facility is one that is designed V.H.3.d above). Consideration of this 004, January 23, 2012, page 2. See also AEP FEED such that the CCS equipment can be more easily Study at pp. 4, 63 (same). Available at: http:// added at a later time. factor confirms the EPA’s decision not www.globalccsinstitute.com/publications/aep- 514 Available in the rulemaking docket (entry: mountaineer-ii-project-front-end-engineering-and- EPA–HQ–OAR–2013–0495–0024). 515 Sierra Club, 657 F.2d at 327 & n. 83. design-feed-report. VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00087 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 64596 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations development of CCS technologies. government subsidies to advance and flue gas stream to achieve an Commenters felt that the standard promote CCS technology. The final approximately 90 percent reduction in would effectively deter the construction standard is less stringent than that CO2 emissions. For a newly constructed of new coal-fired generation—and, if proposed, and can be met at a lower cost IGCC unit, a pre-combustion capture there is no new coal-fired generation, than the proposed standard, and as system would be used to capture CO2 then there will be no implementation of explained above in Section V.H, the from a fully shifted gasification syngas CCS technology and, therefore, no need EPA has carefully evaluated those costs stream to achieve an approximately 90 for continued research and development and finds them to be reasonable. percent reduction in CO2 emissions. of CCS technologies. They argued, in Further, the record and current In the proposal for newly constructed fact, that the best way to promote the economic conditions (fuel costs, sources, we found that ‘‘full CCS’’ development of CCS was to set a renewables, demand growth, etc.) show would certainly result in significant CO2 standard that did not rely on it. that non-economic factors such as a reductions from any new source The EPA does not agree with these desire for fuel diversity will likely drive implementing the technology. However, arguments and, in particular, does not future development of any new coal- we also found that the costs associated see how a standard that is not fired EGUs. For this reason, the EPA with implementation, on either a new predicated on performance of an does not find the commenters’ bare utility boiler system or a new IGCC unit, advanced control technology would assertions that the incremental cost of are predicted to substantially exceed the serve to promote development and CCS (particularly as reasonably costs for other dispatchable non-NGCC deployment of that advanced control modulated for this final standard) generating options that are being technology. On the contrary, the history would make the difference between considered by utilities and project of regulatory actions has shown that constructing and not constructing new developers (e.g., new nuclear plants and emission standards that are based on coal capacity to be persuasive. Rather, a new biomass-fired units). See 79 FR at performance of advanced control cost-reasonable standard reflecting use 1477. This remains the case, and equipment lead to increased use of that of the new technology is what will drive indeed, the difference between cost of control equipment, and that the absence new technology deployment. full capture and new nuclear technology of a requirement stifles technology The EPA expects that it is unlikely is estimated to be even greater than at development. that a new IGCC unit would install proposal. The EPA thus is not selecting There is a dramatic instance of this partial CCS to meet the final standard full capture CCS as BSER. paradigm presented in the present unless the facility is built to take Q. Summary record. In 2011, AEP deferred advantage of EOR opportunities or to construction of a large-scale CCS retrofit operate as a poly-generation facility (i.e., The EPA finds that the best system of demonstration project on one of its coal- to co-produce power along with emission reduction adequately fired power plants because the state’s chemicals or other products). For new demonstrated is a highly efficient utility regulators would not approve IGCC units, the final standard of supercritical pulverized coal boiler cost recovery for CCS investments performance can be met by co-firing a using post-combustion partial CCS so without a regulatory requirement to small amount of natural gas. Some that CO2 is captured, compressed and reduce CO2 emissions. AEP’s chairman commenters argued that IGCC is an safely stored over the long-term. was explicit on this point, stating in a advanced technology that, like CCS, Properly designed, operated, and July 17, 2011 press release announcing should be promoted. The EPA agrees. maintained, this best system can the deferral: IGCC is a low-emitting, versatile achieve a standard of performance of We are placing the project on hold technology that can be used for 1,400 lb CO2/MWh-g, an emission until economic and policy conditions purposes beyond just power production limitation that is achievable over the 12- create a viable path forward . . . We are (as mentioned just above). Commenters operating-month compliance period clearly in a classic ‘which comes first?’ further argued that a requirement to considering usual operating variability situation. The commercialization of this include partial CCS (at a level to meet (including use of different coal types, technology is vital if owners of coal- the proposed standard of performance) periods of startup and shutdown, and fueled generation are to comply with would serve to deter—rather than malfunction conditions). This standard potential future climate regulations promote—more installation of IGCC of performance is technically feasible, without prematurely retiring efficient, technology. We disagree with a similar given that the BSER technology is cost-effective generating capacity. But as argument that commenters make with already operating reliably in full-scale a regulated utility, it is impossible to respect to partial CCS for post- commercial application. The technology gain regulatory approval to recover our combustion facilities, but our final adds cost to a new facility which the share of the costs for validating and standard moots that argument for IGCC EPA has evaluated and finds to be deploying the technology without facilities because the final emission reasonable because the costs are in the federal requirements to reduce limitation of 1,400 lb CO2/MWh-g will same range as those for new nuclear greenhouse gas emissions already in not itself deter installation of IGCC generating capacity—a competing non- place. The uncertainty also makes it technology, by the terms of the NGCC, dispatchable technology that difficult to attract partners to help fund commenters’ own argument. utilities and project developers are also the industry’s share.518 considering for base load application. 2. ‘‘Full’’ Carbon Capture and Storage The EPA has also considered capital Some commenters also argued that (i.e., 90 Percent Capture) the incremental cost associated with cost increases associated with use of including CCS at the proposed level We also reconsidered whether the post-combustion partial CCS at the level would prevent new coal-fired units from emission limitation for new coal-fired needed to meet the final standard and being built. Instead, they advocated for EGUs should be based on the found them to be reasonable, and within a standard based on most efficient performance of full implementation of the range of capital cost increases for technology (supercritical) coupled with CCS technology. For a newly this industry in prior NSPS which have constructed utility boiler, this would been adjudicated as reasonable. The 518 http://www.aep.com/newsroom/newsreleases/ mean that a post-combustion capture EPA’s consideration of costs is also ?id=1704. system would be used to treat the entire informed by its judgment that new coal- VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00088 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64597 fired capacity would be constructed not conduct modifications resulting in a The effect of the EPA’s deferral on as the most economic option, but for hourly increase in CO2 emissions (mass setting standards for sources such purposes as preserving fuel per hour) of less than or equal to 10 undertaking modifications resulting in diversity in an energy portfolio, and so percent (‘‘small’’ modifications), is not smaller increases in CO2 emissions and would not be cost competitive with issuing final standards for those sources the withdrawal of the June 2014 natural gas-fired capacity, so that some in this action, and is withdrawing the proposal with respect to such sources is additional cost premium may therefore proposed standards for those sources. that such sources will continue to be be reasonable. The EPA has carefully See Section XV below. existing sources and subject to evaluated the non-air quality health and requirements under section 111(d). This A. Rationale for Final Applicability environmental impacts of the final is because an existing source does not Criteria for Modified Steam Generating standard and found them to be always become a new source when it Units reasonable: CO2 pipelines and CO2 modifies. Under the definition of ‘‘new sequestration via deep well injection are Final applicability criteria for source’’ in section 111(a)(2), an existing subject already to rigorous control under modified steam generating EGUs source only becomes a new source if it established regulatory programs which include those discussed earlier in modifies after the publication of assure prevention of environmental Section III.A.1 (General Applicability) proposed or final regulations that will release during transport and storage. In and Section III.A.3 (Applicability be applicable to it. Thus, if an existing addition, water use associated with use Specific to Modified Sources). source modifies at a time that there is of partial CCS at the level to meet the CAA section 111(a)(4) defines a no promulgated final standard or final standard is acceptable, and use of ‘‘modification’’ as ‘‘any physical change pending proposed standard that will be the technology does not impose in, or change in the method of operation applicable to it as a modified ‘‘new’’ significant burdens on energy of, a stationary source’’ that either source, that source is not a new source requirements at either the plant or ‘‘increases the amount of any air and continues to be an existing source. national level. The 1,400 lb CO2/MWh- pollutant emitted by such source or . . . Here, because the EPA is not finalizing g standard reflecting performance of the results in the emission of any air standards for sources undertaking BSER may be achieved without pollutant not previously emitted.’’ modifications resulting in smaller geographic constraint, both because Certain types of physical or operational increases in CO2 emissions and is geologic sequestration and EOR capacity changes are exempt from consideration withdrawing the proposal with respect are widely available and accessible, and as a modification. Those are described to such sources, these sources do not also because alternative compliance in 40 CFR 60.2, 60.14(e). To be clear, fall within the definition of ‘‘new pathways are available in the unusual our action in this final rule, and the source’’ in section 111(a)(2) and circumstance where a new coal-fired discussion below, does not change continue to be an ‘‘existing source’’ as plant is sited in an area without such anything concerning what constitutes or defined in section 111(a)(6). See Section access, that area has not already limited does not constitute a modification under XV below. construction of new coal-fired capacity the CAA or the EPA’s regulations.519 As we discussed in the June 2014 in some way, and the area cannot be A modified steam generating unit is a proposal, the EPA has historically been serviced by coal-by-wire. Accordingly, source that fits the definition and notified of only a limited number of the EPA finds that the promulgated applicability criteria of a fossil fuel-fired NSPS modifications 520 involving fossil standard of performance for new fossil steam generating unit and that steam generating units and therefore fuel-fired steam electric generating units commences a qualifying modification predicted that very few of these units satisfies the requirements of CAA on or after June 18, 2014 (the would trigger the modification section 111(a). publication date of the proposed provisions and be subject to the modification standards). 79 FR 34960. proposed standards. Given the limited VI. Rationale for Final Standards for For the reasons discussed below, the information that we have about past Modified Fossil Fuel-Fired Electric EPA in this final action is finalizing modifications, the agency has Utility Steam Generating Units requirements only for steam generating concluded that it lacks sufficient The EPA has determined that, as units that conduct modifications information to establish standards of proposed, the BSER for steam generating resulting in an increase in hourly CO2 performance for all types of units that trigger the modification emissions (mass per hour) of more than modifications at steam generating units provisions is each affected unit’s own 10 percent as compared to the source’s at this time. Instead, the EPA has best potential performance as highest hourly emission during the determined that it is appropriate to determined by that unit’s historical previous five years. With respect to establish standards of performance at performance. The final standards of modifications with smaller increases in this time for larger modifications, such performance are similar to those CO2 emissions (specifically, steam as major facility upgrades involving, for proposed in the June 2014 proposal. generating units that conduct example, the refurbishing or Differences between the proposed modifications resulting in an increase in replacement of steam turbines and other standards and the final standards issued hourly CO2 emissions (mass per hour) of equipment upgrades that result in in this action reflect responses to 10 percent or less compared to the substantial increases in a unit’s hourly source’s highest hourly emission during comments received on the proposal. CO2 emissions rate. The agency has Those changes are described below. the previous 5 years), the EPA is not determined, based on its review of As noted previously, the EPA is finalizing any standard or other public comments and other publicly issuing final emission standards only for requirements, and is withdrawing the available information, that it has affected modified steam generating units June 2014 proposal with respect to these adequate information regarding the that conduct modifications resulting in sources (see Section XV below). types of modifications that could result a hourly increase in CO2 emissions in large increases in hourly CO2 (mass per hour) of more than 10 percent 519 CAA section 111(a)(4); See also 40 CFR 60.14 concerning what constitutes a modification, how to emissions, as well as on the types of (‘‘large’’ modifications). The EPA is determine the emission rate, how to determine an continuing to review the appropriate emission increase, and specific actions that are not, 520 NSPS modifications resulting in increases in standards for modified sources that by themselves, considered modifications. hourly emissions of criteria pollutants. VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00089 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 64598 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations measures available to control emissions refurbishing or replacement of steam The EPA does not intend to imply from sources that undergo such turbines and other equipment upgrades that these specific projects would have modifications, and on the costs and that would significantly increase a resulted in an increase in hourly CO2 effectiveness of such control measures, unit’s capacity to burn more fossil fuel, emissions of greater than 10 percent. upon which to establish standards of thereby resulting in large emissions Capacity increases are often the result of performance for modifications with increases. Major upgrades such as these efficient improvements or are large emissions increases at this time. could increase a steam generating unit’s accompanied by other facility In establishing standards of hourly CO2 emissions by well over 10 improvements that can offset emissions performance at this time for percent.522 increases due to increased fuel input modifications with large emissions An example of such major upgrade capacity. However, these examples are increases, but not for those with small would be work performed at intended to show the types of large, increases, the EPA is exercising its AmerenUE’s Labadie Plant, a facility more capital intensive projects that can policy discretion to promulgate with four 600–MW (nominal) coal-fired potentially result in increases in hourly regulatory requirements in a sequential units located 35 miles west of St. Louis. emissions of CO2 of at least 10 percent. fashion for classes of modifications In the early 2000s, plant staff conducted The EPA believes that it is reasonable within a source category, accounting for process improvements that raised to set the threshold between ‘‘large’’ the information available to the agency, maximum unit capacity by nearly 10 modifications and ‘‘small’’ while also focusing initially on those percent (from 580 MW to 630 MW).523 modifications at 10 percent, a level modifications with the greatest potential Those changes included boiler commensurate with the magnitude of environmental impact. This approach is improvements necessitated by its switch the emissions increases that could result consistent with the case law that from bituminous to subbituminous from the types of projects described 524 authorizes agencies to establish a coal, installation of low-NOX burners, above, and we are issuing a final regulatory framework in an incremental an overfire air system, and advanced standard of performance for those fashion, that is, a step at a time.521 computer controls. One of the sources that conduct modifications To be clear, the EPA is not reaching performance gains came from upgrading resulting in hourly CO2 emission a final decision as to whether it will all four steam turbines, which increases that exceed that threshold. We regulate modifications with smaller AmerenUE chose to replace as modules are not issuing standards of performance increases, or even that such allowing engineers more freedom to for those sources that conduct modifications should be subject to maximize performance unconstrained modifications resulting in an hourly different requirements than we are by the units’ existing outer casing. increase of CO2 emissions of less than finalizing in this rule for the Another example is the refurbishment or equal to 10 percent. modifications with larger increases. We of the 2,100 MW Eskom Arnot coal-fired Therefore, the EPA is withdrawing the have made no decisions and this matter power plant in South Africa with a proposed standards for those sources is not concluded. We plan to continue resulting increase in its power output by that conduct modifications resulting in to gather information, consider the 300 MW to 2,400 MW—an increase in a hourly increase in CO2 emissions options for modifications with smaller capacity of 14 percent.525 For each of (mass per hour) of less than or equal to increases, and, in the future, develop a the plant’s six steam generating units, ten percent and is not issuing final proposal for these modifications or the company conducted a complete standards for those sources at this time. otherwise take appropriate steps. retrofit of the high pressure and See Section XV below. Utilities, states As a means of determining the proper intermediate pressure steam turbines, a and others should be aware that the threshold between the larger and capacity upgrade of the low pressure differentiation between modifications smaller increases in CO2 emissions, the steam turbine, and the replacement and with larger and smaller increases in CO2 EPA examined changes in CO2 upgrade of associated turbine side emissions only applies to sources emissions that may result from large, pumps and auxiliaries. In addition, covered under 40 CFR part 60, subpart capital-intensive projects, such as major major upgrades to the boiler plant were TTTT, i.e., it is only applicable to CO2 facility upgrades involving the conducted, including supply of new emissions from fossil fuel-fired steam pressure part components, new burners, generating units. There is no similar 521 As the U.S. Supreme Court recently stated in and modification to other equipment provision for criteria pollutants or for Massachusetts v. EPA, 549 U.S. 497, 524 (2007): such as the coal mills and classifiers, other source categories. Utilities, states ‘‘ ‘Agencies, like legislatures, do not generally and others should also be aware that the resolve massive problems in one fell regulatory fans, and heaters. Other examples are swoop;’ ’’ and instead they may permissibly provided in a technical memo available distinction between large and small implement such regulatory programs over time, in the rulemaking docket.526 modifications only applies to NSPS ‘‘ ‘refining their preferred approach as modifications. Sources undertaking circumstances change and as they develop a more 522 See e.g., Power Engineering, Steam Turbine modifications may still be subject to nuanced understanding of how best to proceed.’ ’’ Upgrades Boost Plant Reliability, Efficiency, See Grand Canyon Air Tour Coalition v. F.A.A., 154 requirements of New Source Review available at www.power-eng.com/articles/print/ F.3d 455 (D.C. Cir. 1998), City of Las Vegas v. Lujan, under CAA Title I part C or D (which volume-116/issue-11/features/steam-turbine- 891 F.2d 927, 935 (D.C. Cir. 1989), National upgrades-boost-plant-reliability-efficiency.html. have different standards for Association of Broadcasters v. FCC, 740 F.2d 1190, 523 modifications than the NSPS and 1209–14 (D.C. Cir. 1984). See also, Hazardous ‘‘Steam turbine upgrading: Low-hanging Waste Treatment Council v. U.S. E.P.A., 861 F.2d fruit’’, Power (04/15/2006), www.powermag.com/ require a case-by-case analysis) or other 277, 287 (D.C. Cir. 1988) (‘‘[A]n agency’s failure to steam-turbine-upgrading-low-hanging-fruit. CAA requirements. regulate more comprehensively is not ordinarily a 524 Note that a change in coal-type or change in The EPA notes that some commenters basis for concluding that the regulations already the use of other raw material does not necessarily expressed concern that a number of promulgated are invalid. ‘The agency might constitute an ‘‘operational change’’. See 40 CFR properly take one step at a time.’ United States 60.14(e)(4). existing fossil steam generating units, in Brewers Assoc. v. EPA, 600 F.2d 974,982 (D.C. Cir. 525 www.alstom.com/press-centre/2006/10/ order to fulfill requirements of an 1979). Unless the agency’s first step takes it down alstom-signs-power-plant-upgrade-and-retrofit- approved CAA section 111(d) plan, may a path that forecloses more comprehensive contract-with-eskom-in-south-africa/. pursue actions that involve physical or regulation, the first step is not assailable merely 526 See ‘‘U.S. DOE Information Relevant to because the agency failed to take a second. The Technical Basis for ‘‘Large Modification’’ operational changes that result in some steps may be too plodding, but that raises an Threshold’’ available in the rulemaking docket increase in their CO2 emissions on an entirely different issue....’’). EPA–HQ–OAR–2013–0495. hourly basis, and thus constitute VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00090 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64599 modifications. Some commenters would be required to meet the same analyses for heat rate improvements for suggested that the EPA should exempt standard described in the first co- the CAA 111(d) final rule. projects undertaken specifically for the proposal—that is, the modified source 2. Cost purpose of complying with CAA section would be required to meet a unit- 111(d). specific emission limit determined by Any efficiency improvement made by The EPA does not have sufficient the affected EGU’s best demonstrated EGUs for the purpose of reducing CO2 information at this time to predict the historical performance (in the years emissions will also reduce the amount full array of actions that existing steam from 2002 to the time of the of fuel that EGUs consume to produce generating units may undertake in modification) with an additional 2 the same electricity output. The cost response to applicable requirements percent emission reduction (based on attributable to CO2 emission reductions, under an approved CAA section 111(d) equipment upgrades). We also proposed therefore, is the net cost of achieving plan, or which, if any, of these actions that sources that modify after becoming heat rate improvements after any may result in increases in CO2 hourly subject to a CAA section 111(d) plan savings from reduced fuel expenses. As emissions. Nevertheless, the EPA would be required to meet a unit- summarized below, we estimate that, on expects that, to the extent actions specific emission limit that would be average, the savings in fuel cost associated with a 4 percent heat rate undertaken by existing steam generating determined by the CAA section 111(d) improvement would be sufficient to units in response to 111(d) requirements implementing authority and would be cover much of the associated costs, and trigger modifications, the magnitude of based on the source’s expected thus that the net costs of heat rate the increases in hourly CO2 emissions performance after implementation of improvements associated with reducing associated with such modifications identified unit-specific energy efficiency would generally be smaller and would CO2 emissions from affected EGUs are improvement opportunities. therefore generally not subject such relatively low. modifications to the standards of The final standards in this action do We recognize that our cost analysis performance that the EPA is finalizing not depend upon when the modification just described will represent the costs in this rule for modified steam commences (as long as it commences for some EGUs better than others generating units with larger increases in after June 8, 2014). The EPA received because of differences in EGUs’ hourly CO2 emissions. comments on the June 2014 proposal individual circumstances. We further that called into question the need to recognize that reduced generation from B. Identification of the Best System of differentiate the standard based on coal-fired EGUs will tend to reduce the Emission Reduction when the modification was undertaken. fuel savings associated with heat rate The EPA has determined that, as was Further, commenters noted that the improvements, thereby raising the proposed, the BSER for steam generating proposed requirements for sources effective cost of achieving the CO2 units that trigger the modification modifying after becoming subject to a emission reductions from the heat rate provisions is the affected EGU’s own CAA section 111(d) plan, which were improvements. Nevertheless, we still best potential performance as based on energy efficiency improvement expect that the majority of the determined by that source’s historical opportunities were vague and that investment required to capture the performance. standard setting under CAA section technical potential for CO2 emission The EPA proposed that the BSER for 111(b) is a federal duty and would reductions from heat rate improvements modified steam generating EGUs is each require notice-and-comment would be offset by fuel savings, and that unit’s own best potential performance rulemaking. The EPA considered those the net costs of implementing heat rate based on a combination of best comments and has determined that we improvements as an approach to operating practices and equipment agree that there is no need for reducing CO2 emissions from modified upgrades. Specifically, the EPA co- subcategories based on the timing of the fossil fuel-fired EGUs are reasonable. proposed two alternative standards for modification. The EPA further notes that the types of modified utility steam generating units. large, more capital intensive projects In the first co-proposed alternative, C. BSER Criteria that may trigger the ‘‘larger modified steam generating EGUs would modifications’’ threshold (i.e., result in be subject to a single emission standard 1. Technical Feasibility an hourly increase in CO2 emissions of determined by the affected EGU’s best The EPA based technical feasibility of more than 10 percent) often are demonstrated historical performance (in the unit-specific efficiency undertaken in order to increase the the years from 2002 to the time of the improvement on analyses done to capacity of the source but also to modification) with an additional 2 support heat rate improvement for the improve the heat rate or efficiency of the percent emission reduction. The EPA proposed CAA section 111(d) emission unit. proposed that the standard could be met guidelines (Clean Power Plan). That 3. Emission Reductions through a combination of best operating work was summarized in Chapter 2 of practices and equipment upgrades. To the TSD, ‘‘GHG Abatement This approach would achieve account for facilities that have already Measures’’.527 In response to comments reasonable reductions in CO2 emissions implemented best practices and on the proposed Clean Power Plan, the from the affected modified units as equipment upgrades, the proposal also approach was adjusted, as described in those units will be required to meet an specified that modified facilities would the final CAA section 111(d) emission emission standard that is consistent not have to meet an emission standard guidelines. As with proposed actions, with more efficient operation. In light of more stringent than the corresponding the EPA is basing technical feasibility the limited opportunities for emission standard for reconstructed EGUs. for final standards for modified source reductions from retrofits, these The EPA also co-proposed that the efficiency improvements on the reductions are adequate. specific standard for modified sources would be dependent on the timing of 4. Promotion of Technology and Other 527 Technical Support Documents ‘‘GHG Systems of Emission Reduction the modification. We proposed that Abatement Measures’’ (proposal) and ‘‘GHG sources that modify prior to becoming Mitigation Measures’’ (final) available in the As noted previously, the case law subject to a CAA section 111(d) plan rulemaking docket EPA–HQ–OAR–2013–0495. makes clear that the EPA is to consider VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00091 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 64600 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations the effect of its selection of the BSER on BSER. In contrast, as described in more Many commenters supported the technological innovation or detail later in this section a few upper limits of the suggested ranges, development, but that the EPA also has commenters did support partial CCS as saying the standard will be consistently the authority to weigh this factor, along BSER. met. Some commenters raised concerns with the various other factors. With the The fifth option, reductions in about the achievability of these limits selection of emissions controls, generation associated with dispatch for the many boiler and fuel types. A modified sources face inherent changes, renewable generation, and few commenters suggested that there constraints that newly constructed demand side energy efficiency, is should be separate subcategories for greenfield and even reconstructed comparable to application of measures coal-fired utility boilers and IGCC units, sources do not; as a result, modified identified in building blocks two, three since IGCC units have demonstrated sources present different, and in some and four in the emissions guidelines limits closer to 1,500 lb CO2/MWh-n ways more limited, opportunities for that we proposed under CAA section and the units’ designs are so technological innovation or 111(d). We solicited comment on any fundamentally different. Some development. In this case, the standards additional considerations that the EPA commenters said that CFB (due to lower promote technological development by should take into account in the maximum steam temperatures), IGCC, promoting further development and applicability of building blocks two, and traditional boilers each need their market penetration of equipment three and four in the BSER own subcategory. Some commenters upgrades and process changes that determination. Most commenters stated suggested that due to high moisture improve plant efficiency. that building blocks two, three and four content and high relative CO2 emissions of lignite, lignite-fired units should have VII. Rationale for Final Standards for should not be considered for its own subcategory. Other commenters Reconstructed Fossil Fuel-Fired Electric reconstructed sources. opposed the proposed standards for Utility Steam Generating Units The proposed BSER was based on the performance of the most efficient reconstructed units because they A. Rationale for Final Applicability generation technology available, which thought the BSER determination for Criteria for Reconstructed Sources we concluded was the use of the best reconstructed subpart Da units was The applicability rationale for available subcritical steam conditions inconsistent with the BSER reconstructed utility steam generating for small units and the use of determination for newly constructed units is the same as for newly supercritical steam conditions for large units. These commenters stated that the constructed utility steam generating units. We concluded this technology to EPA did not provide sufficient units. We are finalizing the same general be technically feasible, to have justification for eliminating partial criteria and not amending the sufficient emission reductions, to have carbon capture and sequestration (CCS). reconstruction provisions included in reasonable costs, and some opportunity These commenters also stated that the the general provisions. for technological innovation. The reason the EPA gave for dismissing CCS proposed emission standard for these in the proposal was a lack of ‘‘sufficient B. Identification of the Best System of sources was 1,900 lb CO2/MWh-n for information about costs.’’ These Emission Reduction units with a heat input rating of greater commenters hold that the cost rationale In the proposal, the EPA evaluated than 2,000 MMBtu/h and 2,100 lb CO2/ does not apply for reconstructed coal- seven different control technology MWh-n for units with a heat input fired power plants. The fact that configurations to determine the BSER rating of 2,000 MMBtu/h or less. The reconstructed units may face greater for reconstructed fossil fuel-fired boiler difference in the proposed standards for costs to comply with a CAA section and IGCC EGUs: (1) The use of partial larger and smaller units was based on 111(b) standard than new sources does CCS, (2) conversion to (or co-firing with) greater availability of higher pressure/ not relieve them of their compliance natural gas, (3) the use of CHP, (4) temperature steam turbines (e.g. obligation. hybrid power plants, (5) reductions in supercritical steam turbines) for larger Based on a review of the comments, generation associated with dispatch units. As explained in Section III of this we have concluded that both the changes, renewable generation, and preamble, we are finalizing the standard proposed BSER and emission standards demand side energy efficiency, (6) on a gross output basis for utility steam are appropriate, and we are finalizing efficiency improvements achieved generating units. The equivalent gross- the standards as proposed. Nothing in through the use of the most efficient output-based standards are 1,800 lb the comments changed our view that the generation technology, and (7) CO2/MWh and 2,000 lb CO2/MWh BSER for reconstructed steam generating efficiency improvements achieved respectively. units should be based on the through a combination of best operating We solicited comment on multiple performance of a well operated and practices and equipment upgrades. aspects of the proposed standards. First, maintained EGU using the most efficient Although the EPA concluded that the we solicited comment on a range of generation technology available, which first 4 technologies met most of the 1,600 to 2,000 lb CO2/MWh-g for large we have concluded is a supercritical evaluation criteria, namely they are units and 1,800 to 2,200 lb CO2/MWh- pulverized coal (SCPC) or supercritical adequately demonstrated, have g for small units. We also solicited circulating fluidized bed (CFB) boiler reasonable costs and provide GHG comment on whether the standards for for large units, and subcritical for small emissions reductions, they were utility boilers and IGCC units should be units. As described at proposal, we have inappropriate for BSER due to site subcategorized by primary fuel type. In concluded that these standards are specific constraints for existing EGUs on addition, we solicited comment on if achievable by all the primary coal types. a nationwide basis. We rejected best there are sufficient alternate compliance The final standards for reconstructed operating practices and equipment technologies (e.g., co-firing natural gas) utility boilers and IGCC units is 1,800 lb upgrades because we concluded the that the small unit subcategory is CO2/MWh-g for sources with a heat GHG reductions are not sufficient to unnecessary and should be eliminated. input rating of greater than 2,000 qualify as BSER. The majority of Those small sources would be required MMBtu/h and 2,000 lb CO2/MWh-g for commenters agree with the EPA’s to meet the same emission standard as sources with a heat input rating of 2,000 decision that these technologies are not large utility boilers and IGCC units. MMBtu/h or less. VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00092 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64601 While the final emission standards are fuel-fired units (i.e., combustion rationale for these final decisions in based on the identified BSER, a turbines capable of combusting 50 Sections IX and XV of this preamble. reconstructed EGU would not percent or more non-fossil fuel) and necessarily have to rebuild the boiler to subject to a federally enforceable permit B. Best System of Emission Reduction use steam temperatures and pressures condition restricting annual fossil fuel We are finalizing BSER that are higher than the original design. use to 10 percent or less of a unit’s determinations for the three As commenters noted, a reconstructed annual heat input capacity; (2) the large subcategories of stationary combustion unit is not required to meet the majority of industrial CHP units (i.e., turbines referred to above: base load standards if doing so is deemed to be CHP combustion turbines that are natural gas-fired units, non-base load ‘‘technologically and economically’’ subject to a federally enforceable permit natural gas-fired units, and multi-fuel- infeasible. 40 CFR 60.15(b). This condition limiting annual net-electric fired units. For newly constructed and provision inherently requires case-by- sales to the product of the unit’s net reconstructed base load natural gas-fired case reconstruction determinations in design efficiency multiplied by the stationary combustion turbines, the the light of considerations of economic unit’s potential output, or 219,000 BSER is the use of efficient NGCC and technological feasibility. However, MWh, whichever is greater); (3) technology. For newly constructed and this case-by-case determination would combustion turbines that are physically reconstructed non-base load natural gas- consider the identified BSER (the use of incapable of burning natural gas (i.e., fired stationary combustion turbines, the best available steam conditions), as not connected to a natural gas pipeline); the BSER is the use of clean fuels (i.e., well as—at a minimum—the first four and (4) municipal waste combustors and natural gas with an allowance for a commercial or industrial solid waste technologies the EPA considered, but small amount of distillate oil). For incinerators (units subject to subparts rejected, as BSER for a nationwide rule. multi-fuel-fired stationary combustion Eb or CCCC of this part). One or more of these technologies could turbines, the BSER is also the use of be technically feasible and reasonable For combustion turbines subject to an emission standard, we are finalizing clean fuels (e.g., natural gas, ethylene, cost, depending on site specific propane, naphtha, jet fuel kerosene, fuel considerations and, if so, would likely three subcategories: base load natural gas-fired units, non-base load natural oils No. 1 and 2, biodiesel, and landfill result in sufficient GHG reductions to gas). comply with the applicable gas-fired units, and multi-fuel-fired reconstructed standards. Finally, in units. We use the term base load natural C. Final Emission Standards some cases, equipment upgrades and gas-fired units to refer to stationary best operating practices would result in combustion turbines that (1) burn over For all newly constructed and sufficient reductions to achieve the 90 percent natural gas and (2) sell reconstructed base load natural gas-fired reconstructed standards. electricity in excess of their design combustion turbines, we are finalizing efficiency (not to exceed 50 percent) an emission standard of 1,000 lb CO2/ VIII. Summary of Final Standards for multiplied by their potential electric MWh-g, calculated on a 12-operating- Newly Constructed and Reconstructed output. To be in this subcategory, a month rolling average basis. We are also Stationary Combustion Turbines stationary combustion turbine must finalizing an optional emission standard This section summarizes the final exceed the ‘‘natural gas-use criterion’’ of 1,030 lb CO2/MWh-n, calculated on a applicability requirements, BSER on a 12-operating-month rolling average 12-operating-month rolling average determinations, and emission standards and the ‘‘percentage electric sales’’ basis, for stationary combustion turbines for newly constructed and reconstructed criterion on both a 12-operating-month in this subcategory. For newly stationary combustion turbines. In and 3-year rolling average basis. We use constructed and reconstructed non-base addition, it also summarizes significant the term non-base load natural gas-fired load natural gas-fired combustion differences between the proposed and units to refer to stationary combustion turbines, we are finalizing a standard of final provisions. turbines that (1) burn over 90 percent 120 lb CO2/MMBtu, calculated on a 12- natural gas and (2) have net-electric operating-month rolling average basis. A. Applicability Requirements sales equal to or below their design For newly constructed and We are finalizing BSER efficiency (not to exceed 50 percent) reconstructed multi-fuel-fired determinations and emission standards multiplied by their potential electric combustion turbines, we are finalizing a for newly constructed and reconstructed output. These criteria are calculated on standard of 120 to 160 lb CO2/MMBtu, stationary combustion turbines that (1) the same rolling average bases as for the calculated on a 12-operating-month have a base load rating for fossil fuels base load subcategory. Finally, we use rolling average basis. The emission greater than 260 GJ/h (250 MMBtu/h) the term multi-fuel-fired units to refer to standard for multi-fuel-fired combustion and (2) serve a generator capable of stationary combustion turbines that turbines co-firing natural gas with other selling more than 25 MW-net of burn 10 percent or more non-natural gas fuels shall be determined at the end of electricity to the grid. We also are on a 12-operating-month rolling average each operating month based on the finalizing applicability requirements basis. We are not finalizing the percentage of co-fired natural gas. Table that will exempt from the final proposed emission standards for 15 summarizes the subcategories, BSER standards (1) all stationary combustion modified sources and are withdrawing determinations, and emission standards turbines that are dedicated non-fossil those standards. We explain our for combustion turbines. VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00093 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 64602 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations TABLE 15—COMBUSTION TURBINE SUBCATEGORIES AND BSER Subcategory BSER Emission standard Base load natural gas-fired combusiton turbines ...... Efficient NGCC ...... 1,000 lb CO2/MWh-g or 1,030 lb CO2/MWh-n Non-base load natural gas-fired combustion turbines ...... Clean fuels ...... 120 lb CO2/MMBtu 528 Multi-fuel-fired combustion turbines ...... Clean fuels ...... 120 to 160 lb CO2/MMBtu D. Significant Differences Between units. The final rule retains all of the percentage of potential electric sales Proposed and Final Combustion proposed applicability criteria in some based on the unit’s design efficiency or Turbine Provisions form, but most closely tracks the broad 219,000 MWh, whichever is greater. As shown in Tables 16 and 17 below, applicability approach by finalizing the Second, the proposed applicability the proposed rule included several percentage electric sales and natural criteria did not include non-fossil fuel general applicability criteria and two gas-use criteria as thresholds that units that burn 10 percent or less fossil subcategorization criteria for distinguish among three subcategories fuel on a 3-year rolling average. The combustion turbines. In addition to the of combustion turbines with separate final rule similarly replaces the actual proposed applicability and emissions standards. fuel-use aspect of the proposal with an subcategorization framework, we The final rule also includes exemption for non-fossil fuel units that solicited comment on a ‘‘broad exceptions to the broad applicability take federally enforceable permit applicability approach’’ that included approach that we solicited comment on, conditions limiting fossil-fuel use to 10 most combustion turbines irrespective with some changes that are responsive percent or less of annual heat input of the actual amount of electricity sold to public comments. Categorical capacity. Finally, the proposed to the grid or the actual amount of exceptions to the broad applicability applicability criteria did not include natural gas burned (i.e., non-base load criteria are the exclusions for CHP units, combustion turbines that burn 90 units and multi-fuel-fired units, non-fossil fuel units, and combustion percent or less natural gas on a 3-year respectively). The broad applicability turbines not able to combust natural gas. rolling average basis. In contrast, the approach changed the proposed First, the proposed applicability criteria final rule includes most fossil fuel-fired ‘‘percentage electric sales’’ and ‘‘natural did not include CHP units that were combustion turbines regardless of the gas-use’’ criteria to distinguish among constructed for the purpose of or that amount of natural gas burned, with an subcategory-specific emissions actually sell one-third or less of their exception for combustion turbines that standards. Specifically, in the broad potential electric output or 219,000 are not connected to natural gas applicability approach, we solicited MWh, whichever is greater, to the grid. pipelines. Finally, in response to public comment on subjecting non-base load The final rule eliminates the comments, we are not finalizing the units and multi-fuel-fired units to ‘‘no ‘‘constructed for the purpose of’’ and subcategories for large and small emissions standard,’’ while still actual sales aspects of the proposal and combustion turbines that were including them in the general replaces them with an exemption for contained in the proposal. Instead, all applicability. We also solicited CHP units that take federally base load natural gas-fired combustion comment on establishing a separate enforceable permit conditions turbines must meet an emission numerical standard for non-base load restricting net-electric sales to a standard of 1,000 lb CO2/MWh-g. TABLE 16—PROPOSED APPLICABILITY CRITERIA VERSUS FINAL APPLICABILITY CRITERIA Applicability Criteria Proposed Applicability Final Applicability Base load rating criterion ...... Base load rating > 73 MW (250 MMBtu/h) .... Base load rating > 260 GJ/h 529 (250 MMBtu/h) Total electric sales criterion ...... Constructed for purpose of and actually sell- Ability to sell > 25 MW-n to the grid ing > 219,000 MWh-n to the grid. Percentage electric sales criterion ...... Constructed for purpose of and having actual Changed to subcategorization criterion per net-sales to the grid > one-third of potential broad applicability approach electric output. Natural gas-use criterion ...... Actually burns > 90 percent natural gas ...... • Changed to subcategorization criterion per broad applicability approach • Exemption for combustion turbines that are not connected to a natural gas supply Fossil fuel-use criterion ...... Actually burns > 10 percent fossil fuel ...... Exemption based on permit condition limiting amount of fossil fuel burned to ≤ 10 percent of annual heat input capacity Combined Heat and Power (CHP) exemption NA ...... Exemption based on permit condition limiting net-electric sales to ≤ design efficiency multi- plied by potential electric output, or 219,000 MWh-n, whichever is greater Non-EGU exemption ...... Exemption for municipal solid waste combus- Same as proposal tors and commercial or industrial solid waste incinerators. 528 The emission standard for combustion be determined based on the amount of co-fired turbines co-firing natural gas with other fuels shall natural gas at the end of each operating month. VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00094 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64603 TABLE 17—PROPOSED SUBCATEGORIES VERSUS FINAL SUBCATEGORIES Subcategory Proposed Criteria Final Criteria Small combustion turbine subcategory ...... Base load rating ≤ 850 MMBtu/h ...... NA Large combustion turbine subcategory ...... Base load rating > 850 MMBtu/h ...... NA Base load natural gas-fired base load combus- NA ...... • Actually burns > 90 percent natural gas tion turbine subcategory. • Net-electric sales > design efficiency (not to exceed 50 percent) multiplied by potential electric output Non-base load natural gas-fired combustion NA ...... • Actually burns > 90 percent natural gas turbine subcategory. • Net-electric sales ≤ design efficiency (not to exceed 50 percent) multiplied by potential electric output Multi-fuel-fired combustion turbine subcategory NA ...... Actually burns ≤ 90 percent natural gas IX. Rationale for Final Standards for the grid) on a 3-year rolling average; (3) of their potential electric output on an Newly Constructed and Reconstructed be constructed for the purpose of annual basis, well below the proposed Stationary Combustion Turbines supplying and actually supply more one-third electric sales threshold. than 219,000 MWh net-electric output This section discusses the EPA’s a. Solicitation of comment on to the grid on a 3-year rolling average; rationale for the final applicability applicability, generally criteria, BSER determinations, and (4) combust over 10 percent fossil fuel standards of performance for newly on a 3-year rolling average; and (5) We solicited comment on a range of constructed and reconstructed combust over 90 percent natural gas on issues related to applicability. In stationary combustion turbines. In this a 3-year rolling average. We proposed conjunction with the proposed one- section, we present a summary of what exempting municipal solid waste third (i.e., 33.3 percent) electric sales we proposed, a selection of the combustors and commercial and threshold, we solicited comment on a significant comments we received, and industrial solid waste incinerators. threshold between 20 to 40 percent of our rationale for the final Under these proposed applicability potential electric output. We also determinations, including how the criteria, two types of stationary solicited comment on a variable comments influenced our decision- combustion turbines that are currently percentage electric sales criterion, making. subject to criteria pollutant standards which would allow more efficient, under subpart KKKK would not have lower emitting turbines to run for longer A. Applicability been subject to CO2 standards. The first periods of operation before becoming This section describes the proposed type was stationary combustion turbines subject to the standards of performance. applicability criteria, applicability that are constructed for the purpose of Under this ‘‘sliding scale’’ approach, the issues we specifically solicited selling and that actually sell one-third percentage electric sales criterion would comment on, the relevant significant or less of their potential output or be based on the net design efficiency of comments, and the final applicability 219,000 MWh or less to the grid on a 3- the combustion turbine being installed. criteria. We also provide our rationale year rolling average basis (i.e., non-base In this way, more efficient combustion for finalizing applicability criteria based load units). The second type was turbines would be able to sell a greater strictly on design and permit combustion turbines that actually portion of their potential electric output restrictions rather than actual operating combust 90 percent or less natural gas compared with less efficient combustion characteristics. Finally, we explain why on a 3-year rolling average basis (i.e., turbines before becoming subject to an the proposed percentage electric sales multi-fuel-fired units). emission standard. This approach had and natural gas-use applicability criteria We proposed the electric sales criteria the benefit of incentivizing the are being finalized instead as criteria to in part because they already exist in development and installation of more distinguish between separate other regulatory contexts (e.g., the coal- efficient simple cycle combustion subcategories of stationary combustion fired EGU criteria pollutant NSPS) and turbines to serve peak load. turbines. would promote consistency between We also solicited comment on 1. Proposed Applicability Criteria regulations. Our understanding at whether the percentage electric sales proposal was that the percentage criterion for stationary combustion In the January 2014 proposal, we electric sales criterion would turbines should be defined on a single proposed several applicability criteria distinguish between non-base load units calendar year basis. In addition, we for stationary combustion turbines. (e.g., low capital cost, flexible, but solicited comment on eliminating the Specifically, to be subject to the relatively inefficient simple cycle units) 219,000 MWh aspect of the total electric proposed emission standards, we and base load units (i.e., higher capital sales criterion to eliminate any proposed that a unit must (1) be capable cost, less flexible, but relatively efficient incentive for generators to install of combusting more than 73 MW (250 combined cycle units). multiple, small, less-efficient stationary MMBtu/h) heat input of fossil fuel; (2) While the proposed applicability combustion turbines that would be be constructed for the purpose of criteria did not explicitly exempt simple exempt due to their lower output. We supplying and actually supply more cycle combustion turbines from the further solicited comment on whether to than one-third of its potential electric emission standards, we concluded that, provide an explicit exemption for all output capacity to a utility power as a practical matter, the vast majority simple cycle combustion turbines distribution system for sale (that is, to of simple cycle turbines would be regardless of the amount of electricity 529 73 MW is equivalent to 260 GJ/h. We changed excluded because they historically have sold. We additionally solicited comment units to avoid potential confusion of MW referring operated as peaking units and, on on how to implement the proposed to electric output rather than heat input. average, have sold less than five percent electric sales, fossil fuel-use, and natural VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00095 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 64604 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations gas-use criteria given that they were to of selling more than 25 MW). In contrast combustion turbines and could have the be evaluated as 3-year rolling averages to the proposed applicability criteria, unintended consequence of increasing during the first three years of operation, under the broad applicability approach, CO2 emissions. and we requested comment on non-base load (e.g., simple cycle) and c. Percentage electric sales criterion appropriate monitoring, recordkeeping, multi-fuel-fired (e.g., oil-fired) and reporting requirements. We combustion turbines would remain Commenters from the power sector specifically solicited comment on subject to the rule regardless of their generally supported a complete whether these proposed requirements electric sales or fuel use. We solicited exemption for simple cycle turbines. raised implementation issues because comment on all aspects of this ‘‘broad These commenters stated that simple they were based on source operation applicability approach,’’ including the cycle turbines are uniquely capable of after construction has occurred. extent to which it would achieve our achieving the ramp rates (the rate at We also solicited comment on policy objective of assuring that owners which a power plant can increase or excluding electricity sold during system and operators install NGCC combustion decrease output) necessary to respond to emergencies from the calculation of turbines if they plan to sell more than emergency conditions and hourly percentage electric sales. The rationale the specified electric sales threshold to variations in output from intermittent for this exclusion was that simple cycle the grid. renewables. Commenters noted that combustion turbines intended only for 2. Comments on Applicability simple cycle combustion turbines serve peaking applications might be required a different purpose than NGCC power to operate above the proposed This section summarizes the blocks. In addition, commenters noted percentage electric sales threshold if a comments we received specific to each that electricity generation dispatch is major power plant or transmission line of the proposed applicability criteria. based on the incremental cost to became unexpectedly unavailable for an We also received more general generate electricity and that because extended period of time. The EPA comments on the scope of the proposed NGCC units have a lower incremental proposed that this flexibility would be framework as compared to the scope of generation cost than simple cycle units, appropriate if the unit were called upon the broad applicability approach. economics will drive the use of NGCC to run after all other available generating Comments on applicability for technologies over simple cycle units. assets were already running at full load. dedicated non-fossil and CHP units are However, commenters also stated that discussed in Section III. b. Solicitation of comment on broad historic simple cycle operating data may applicability approach a. Base load rating criterion not be representative of future system requirements as coal units retire, In both the January 2014 proposal for Many commenters supported a base generation from intermittent renewable newly constructed EGUs and the June load rating of 260 GJ/h (250 MMBtu/h) 2014 proposal for modified and because it is generally consistent with generation increases, and numerous reconstructed EGUs, the EPA solicited the threshold used in states market and regulatory drivers impact comment on finalizing a broad participating in the Regional plant operations. In the absence of a applicability approach instead of the Greenhouse Gas Initiative (RGGI) and complete exemption, these commenters proposed approach. Under the proposed under Title IV programs. Other supported a percentage electric sales approach, a stationary combustion commenters opposed the proposed threshold between 40 to 60 percent of a turbine could be an affected EGU one applicability thresholds and stated that unit’s potential electric output. year, but not the next, depending on the all new, modified, and reconstructed Some commenters said that because unit’s actual electric sales and the units that sell electricity to the grid, the proposed percentage electric sales composition of fuel burned. The broad including small EGUs and simple cycle criterion applied over a three-year applicability approach is consistent combustion turbines, should be affected period, it would adversely affect grid with historical NSPS applicability EGUs because they would otherwise reliability because operators approaches that are based on design have a competitive advantage in energy conservatively would hedge short-term criteria and include different emission markets as they would not be required operating decisions to ensure that they standards for subcategories that are to internalize the costs of compliance. have sufficient capacity to respond to distinguished by operating unexpected scenarios during future characteristics. Specifically, we b. Total electric sales criterion compliance periods when the demand solicited comment on whether we Commenters noted that the 219,000 for electricity is higher. These should completely remove the electric MWh total electric sales threshold put commenters were concerned that such sales and natural gas-use criteria from larger combustion turbines at a compliance decisions would drive up the general applicability framework. competitive disadvantage by distorting the cost of electricity as the most Instead, the percentage electric sales the market and could have the perverse efficient new units are taken out of and natural gas-use thresholds would impact of increasing CO2 emissions. service to avoid triggering the NSPS and serve as subcategorization criteria for These commenters noted that the older, less efficient units with no distinguishing among classes of EGUs 219,000 MWh total electric sales capacity factor limitations are ramped and subcategory-specific emissions threshold would allow combustion up instead. standards. Under this broad turbines smaller than approximately 80 Some commenters supported the applicability approach, the ‘‘constructed MW to sell more than one-third of their sliding-scale approach (i.e., a percentage for the purpose of’’ component of the potential electric output, but larger, electric sales threshold based on the percentage electric sales criterion would more efficient combustion turbines design efficiency of the combustion be completely eliminated so that would still be restricted to selling one- turbine) and stated that incentives for applicability for combustion turbines third of their potential electric output to manufacturers to develop (and end would be determined only by a unit’s avoid triggering the NSPS. They argued users to purchase) higher efficiency base load rating (i.e., greater than 260 that this would result in a regulatory combustion turbines could help mitigate GJ/h (250 MMBtu/h)) and its capability incentive for generators to install concerns about a monolithic national to sell power to a utility distribution multiple, less-efficient combustion constraint on simple cycle capacity system (i.e., serving a generator capable turbines instead of fewer, more-efficient factors. VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00096 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64605 In contrast, others commented that potential to increase CO2 emissions, justify operating a peaking unit above a fast-start NGCC units intended for regardless of the deign efficiency of the 10-percent capacity factor on a 3-year peaking and intermediate load turbine. Therefore, a unit could have an rolling average. applications can achieve comparable emission rate in excess of the proposed d. Broad applicability approach ramp rates to simple cycle combustion standard. turbines, but with lower CO2 emission Regarding the relationship between In response to the EPA’s request for rates. These commenters said that the percentage electric sales criterion comments on whether the proposed simple cycle turbines should be and system emergencies, multiple applicability requirements that restricted to their historical role as true commenters supported exclusion of retrospectively look back at actual peaking units and that the proposed electricity generated as a result of a events (i.e., the electric sales and fuel one-third electric sales threshold system emergency from counting use criteria) would create provided sufficient flexibility. Some towards net sales. These commenters implementation issues, several commenters suggested that the one-third stated that the exclusion was permitting authorities opposed the electric sales threshold could be appropriate because the benefits of provisions because units could be reduced to 20 percent or lower without operating these units to generate subject to coverage one year but not the adverse impacts on grid reliability. electrical power during emergency next, resulting in compliance issues and Commenters noted that a complete conditions would outweigh any adverse difficulties in determining proper pre- exclusion for simple cycle turbines impacts from short-term increases in construction and operating permit would create a regulatory incentive for CO2 emissions. One commenter stated conditions. These permitting authorities generators to install and operate less that, in addition to declared grid suggested that in order for a source to efficient unaffected units instead of emergencies, other circumstances might avoid applicability, the source should more efficient affected units, thereby warrant emergency exemption under the be subject to a federally enforceable increasing CO2 emissions. According to rule, including extreme market permit condition with associated these commenters, any applicability conditions, limitations on fuel supply, monitoring, recordkeeping, and distinctions should be based on and reliability responses. reporting conditions for assessing utilization and function rather than Multiple commenters opposed the applicability on an ongoing basis. Other purpose or technology. exclusion of system emergencies when commenters stated that an applicability Commenters in general supported the calculating a source’s percentage test that concludes after construction use of 3-year rolling averages instead of electric sales for applicability purposes and operation have commenced is a single-year average for the percentage because NSPS must apply continuously, inconsistent with the general purpose of and total electric sales criteria because, even during system emergencies. These an applicability test—to provide clear in their view, the 3-year rolling averages commenters stated that the EPA does and predictable standards of would provide a better overall picture of not have the authority under the CAA performance for new sources that would normal operations. Some commenters to suspend the applicability of a apply when they begin operations. stated that a rolling 12-month or standard during periods of system Some commenters opposed the calendar-year average could be severely emergency. Some commenters stated proposed retrospective applicability skewed in a given year because of that an exclusion would be unnecessary criteria related to actual output supplied unforeseen or unpredicted events. They because the EPA Assistant during a preceding compliance period said that using a 3-year averaging Administrator for Enforcement has the because EGUs must know what methodology would provide system authority to advise a source that the performance standards will apply to operators with needed flexibility to government will not sue the source for them during the licensing process, and dispatch simple cycle units at higher taking certain actions during an such criteria do not allow the permitting than normal capacity factors. In emergency. Commenters said that this authority and the public to know in contrast, some commenters stated that, enforcement discretion approach has advance whether an emission standard because capacity is forward-looking provided prompt, flexible relief that is applies to a proposed new unit. Other (e.g., payments for capacity are often tailored to the needs of the particular commenters said that EGUs undergoing made several years in advance), the 3- emergency and the communities being permitting should be allowed to request year averaging period provides limited served and is only utilized where the limits in their operating permit benefit because owner/operators need to relief will address the particular conditions in order to remain below the reserve the ability to respond to emergency at hand. applicability thresholds, as this unforeseen events. Commenters added that this methodology is consistent with the pre- Commenters noted that potential enforcement discretion approach is construction permitting requirements in compliance issues could result from the consistent with the CAA’s mandate that many federally approved SIPs and the inconsistent time frame between the 3- emission limits apply continuously and current approach under the Title V calendar-year applicability period and provide safeguards against abuse. One permitting program. the 12-operating-month compliance commenter stated that emergencies Many commenters stated a preference period. For example, a facility could sell happen rarely and typically last for for the ‘‘proposed applicability more than one-third of its potential short periods, that the proposed approach’’ over the ‘‘broad applicability electric output over a 3-year period, but percentage electric sales threshold approach.’’ These commenters did not sell less than one-third of its potential would allow a source to operate at its think it was necessary to require non- electric output during any given 12- full rated capacity for up to 2,920 hours base load or multi-fuel-fired combustion operating-month compliance period per year without triggering applicability, turbines to be subject to emission within that 3-year period. During a 12- and that the potential occurrence of grid standards. They stated that there is no operating-month period with electric emergencies would represent a tiny justification for imposing burdensome sales of less than one-third of potential fraction of this time. Another monitoring, reporting, and electric output, a unit could be commenter stated that no emergency recordkeeping requirements that would operating for long periods at part load short of large scale destruction of power have no environmental benefit (i.e., and have multiple starts and stops. generating capacity by terrorism, war, would not reduce CO2 emissions) These operating conditions have the accident, or natural disaster could because these units would be subject to VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00097 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 64606 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations ‘‘no emissions standards.’’ Other broad applicability approach, we are 260 GJ/h because some commenters commenters supported the broad finalizing the percentage electric sales misinterpreted the 73 MW form (which applicability approach and stated that and natural gas-use thresholds as is mathematically equivalent to 250 all new, modified, and reconstructed subcategorization criteria instead of as MMBtu/h) as the electrical output rating units that sell electricity to the grid, applicability criteria. In addition, for of the generator. This change is a non- including small EGUs, oil-fired non-CHP combustion turbines, we are substantive unit conversion intended to combustion turbines, and simple cycle eliminating the proposed 219,000 MWh limit misinterpretation. While some combustion turbines should be affected total electric sales criterion. Finally, we commenters suggested that we expand EGUs because they would otherwise are eliminating the proposed this applicability criterion to cover have a competitive advantage in energy ‘‘constructed for the purpose of’’ smaller EGUs as well, we did not markets as they would not be required qualifier for the total and percentage propose to cover smaller units. Because to internalize the costs of compliance. electric sales criteria. We are also not smaller units emit relatively few CO2 In contrast, to preserve the discretion finalizing CO2 standards for dedicated emissions compared to larger units and of state planners under section 111(d), non-fossil fuel-fired or industrial CHP because we currently do not have many other commenters supported the combustion turbines. The rationale for enough information to identify an broad applicability approach and the not finalizing CO2 standards for appropriate BSER for these units, we are inclusion of new simple cycle units dedicated non-fossil and industrial CHP not finalizing CO2 standards for smaller within the scope of the section 111(b) units is discussed in more detail in units. emission standards so that similar, Section III. existing simple cycle units could be The EPA agrees with commenters that b. Total electric sales criterion subject to the 111(d) standards. the NSPS applicability framework The proposed 219,000 MWh total Numerous other commenters stated that should be structured so that permitting sales criterion was based on a 25 MW all units that sell electricity to the grid authorities, the regulated community, unit operating at base load the entire should be subject to a standard, and the public can determine what year (i.e., 25 MW * 8,760 h/y = 219,000 including simple cycle units, because standards apply prior to a unit having MWh/y). This criterion was included in they view the utility grid as a single commenced construction. With this in the original subpart Da coal-fired EGU integrated system and that doing so may mind, the EPA has concluded that the criteria pollutant NSPS. Coal-fired EGUs simplify development of future proposed fossil fuel-use, natural gas-use, tend to be much larger than 25 MW, and frameworks for cost-effective carbon percentage electric sales, and total the criterion’s primary purpose was to reductions from existing units, such as electric sales applicability criteria for exempt industrial CHP facilities from frameworks based on system-wide combustion turbines are not ideal the criteria pollutant NSPS. In the approaches. approaches. Because applicability context of combustion turbines, determinations based on these criteria however, commenters expressed 3. Final Applicability Criteria and could change from year to year (i.e., concerns that the 219,000 MWh electric Rationale units could move in and out of coverage sales threshold would actually Based on our consideration of the each year depending on actual operating encourage owners and operators to comments received related to the parameters), some operators would not install multiple, smaller, less-efficient proposed applicability criteria and know the extent of their compliance simple cycle combustion turbines practical implementation issues, we are obligations until after the compliance instead of a single, larger, more-efficient revising how those criteria will be period. simple cycle turbine. The reason for this implemented. The final applicability Further, from a practical is that the 219,000 MWh threshold criteria for combustion turbines are implementation standpoint, existing would allow smaller simple cycle generally consistent with the broad permitting rules generally require pre- combustion turbines of less than 80 MW applicability approach on which we construction permitting authorities to to sell significantly more electricity solicited comment. Section VIII of this include enforceable conditions limiting relative to their potential electric output preamble presents each proposed operations such that unaffected units than larger turbines. Many commenters applicability criterion together with the will not trigger applicability thresholds. also indicated that having the flexibility form of the criterion in the final rule. Such conditions are often called to operate a simple cycle turbine at a The final general applicability ‘‘avoidance’’ or ‘‘synthetic minor’’ higher capacity factor is important framework includes the proposed conditions, and these conditions because it allows for capacity payments criteria based on the combustion typically include ongoing monitoring, from the transmission authority. In light turbine’s base load rating and the recordkeeping, and reporting of these comments, we are not finalizing combustion turbine’s total electric sales requirements to ensure that operations the 219,000 MWh total electric sales capacity. The final general applicability remain below a particular regulatory criterion for non-CHP combustion framework also includes multiple threshold. turbines. Instead, we are finalizing a exemptions that are relevant to The following sections provide criterion that will exempt combustion combustion turbines: combustion further discussion of the final general turbines that do not have the ability to turbines that are not connected to applicability criteria and the rationale sell at least 25 MW to the grid. This natural gas pipelines; CHP facilities for changing certain proposed approach will maintain our goal of with federally enforceable limits on applicability criteria to exempting smaller EGUs, while total electric sales; dedicated non-fossil subcategorization criteria. avoiding the perverse environmental units with federally enforceable limits incentives mentioned by the on the use of fossil fuels; and municipal a. Base load rating criterion commenters. As explained in Section waste combustors and incineration We are retaining the applicability III, however, industrial CHP units are units. criterion that a combustion turbine must sized based on demand for useful The final applicability framework be capable of combusting more than 260 thermal output, so there is less of an reflects multiple variations from the GJ/h (250 MMBtu/h) heat input of fossil incentive for owners and operators to proposal that are responsive to public fuel. We revised the proposed 73 MW install multiple smaller units. Therefore, comments. First, consistent with the form of the base load rating criterion to we are maintaining the 219,000 MWh VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00098 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64607 total electric sales criterion for CHP to start and stop more frequently and 111(d) applicability criteria based on units. operate at part load. Yet, even if these historical operations, existing NGCC units sell below the percentage electric units could have decided to take a c. Percentage electric sales criterion sales threshold, they would still be permit restriction limiting their electric Commenters generally opposed the affected units if they did not take a sales going forward to avoid proposed percentage electric sales permit restriction. As commenters applicability. Under any of these criterion approach because it was based noted, part-load operation and frequent scenarios, our goals with respect to in part on actual electric sales, meaning starts and stops can reduce the 111(d) would not be accomplished. applicability could change periodically efficiency of a combustion turbine. To avoid this result, the EPA has (i.e., a unit’s electric sales may change While we are confident that our final concluded that it is appropriate to over time, rising above and falling standards for base load natural gas-fired finalize the broad applicability below the electric sales threshold). The combustion turbines can be achieved by approach and set standards for EPA agrees this situation is not ideal. To units serving either base or intermediate combustion turbines regardless of what avoid situations in which applicability load, we are not as confident that percentage of their potential electric changes from year to year, we first affected NGCC units that might someday output they sell to the grid. To considered two approaches using permit be operated as non-base load units (e.g., accommodate the continued use of restrictions. Under the first approach, a as NSPS units age, their incremental simple cycle and fast-start NGCC standard would apply to all sources generating costs will tend to be higher combustion turbines for peaking and with permit restrictions mandating than newer units and they will dispatch cycling applications, however, the EPA electric sales above a threshold (i.e., an less) could achieve the standards. has subcategorized natural gas-fired approach that closely mirrors the More importantly, however, we are combustion turbines based on a proposed percentage electric sales concerned that using a permitting variation of the proposed percentage criterion). Under the second approach, a approach for the percentage electric electric sales criterion. Specifically, and standard would apply to all sources sales criterion would create problems as explained in more detail in Section without permit restrictions limiting due to the interaction between 111(b) IX.B.2, we are finalizing the sliding- electric sales to a level below that and 111(d). Under the second scale approach on which we solicited threshold (i.e., effectively identifying permitting approach we considered, comment. non-base load units and excluding them units with low electric sales would be from applicability). As stated in the excluded from applicability, while units d. Natural gas-use criterion proposal, we did not think it was with high electric sales would be Similar to the proposed electric sales critical to include peaking and cycling included. While these low-electric sales criteria, commenters generally opposed units because peaking turbines operate units would generally be simple cycle the proposed natural gas-use criterion less and because it would be much more combustion turbines and the high- being based on actual operating expensive to lower their emission electric sales units would generally be parameters. As with the electric sales profile to that of a combined cycle NGCC combustion turbines, this would criteria, the EPA agrees that power plant or a coal-fired plant with not always be the case. In contrast, we applicability that can switch CCS. are finalizing an applicability approach periodically due to operating parameters The first approach is not practical, in the 111(d) emission guidelines that is is not ideal. The EPA evaluated two however, because new combustion based on a combustion turbine’s design approaches for implementing the intent turbines could avoid applicability by characteristics rather than electric sales. of the proposed natural gas-use criterion simply not having a permit restriction at Simple cycle combustion turbines are (i.e., to exclude non-natural gas-fired all. Moreover, even if a combustion excluded from applicability, while combustion turbines) through operating turbine were subject to the restriction, it NGCC units are included. As a result, permit restrictions. Under the first could violate its permit if it did not the universe of sources covered by the approach, an emission standard would operate enough to sell the requisite 111(b) standards would not necessarily apply to all combustion turbines with a amount of electricity. This would be be the same universe of sources covered permit restriction mandating that nonsensical, especially because system by the 111(d) standards. natural gas contribute over 90 percent of demand would not always be sufficient To resolve this issue, we considered total heat input.530 Under the second to allow all permitted units to operate whether we could change the 111(d) approach, an emission standard would above the threshold. Therefore, we applicability criteria to be based on apply to all combustion turbines rejected the first permitting approach. historical operation rather than design In contrast, the second approach without a permit restriction limiting characteristics. For example, if an natural gas use to 90 percent or less of would be a viable method for existing combustion turbine had 531 identifying and exempting peaking units total heat input. As with the historically sold less than one-third of percentage electric sales criterion, the from applicability. However, there are its potential output to the grid, then it multiple drawbacks to such an first approach is not practical because would be exempt from the emission combustion turbines could avoid applicability approach. First, this guidelines. However, many existing approach would subject those turbines NGCC units have historically sold less 530 This approach could also be written as ‘‘an without a permit restricting electric than this amount of electricity, meaning emission standard would apply to all combustion sales to the final emission standards, that they would not be subject to the turbines with a permit restriction limiting the use which raises concerns as to whether rule. We ran into similar issues when of non-natural gas fuels to 10 percent or less of the turbines with lower actual sales could considering other thresholds. For total heat input.’’ Applicability could then be avoided by simply being permitted to burn non- achieve the standards. For example, example, a percentage electric sales natural gas fuels for more than 876 hours per year new NGCC units tend to dispatch prior threshold of 10 percent would still even if they actually intended to seldom, if ever, to older existing units and will generally exempt roughly 5 percent of existing combust the alternate fuels. operate for extended periods of time NGCC units from 111(d), while 531 This approach could also be written as ‘‘an emission standard would apply to all combustion near full load and sell electricity above simultaneously raising achievability turbines without permit restrictions mandating that the percentage electric sales threshold. concerns with the 111(b) standard. non-natural gas use contribute over 10 percent or However, as NGCC units age, they tend Moreover, even if we had finalized more of total heat input.’’ VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00099 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 64608 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations applicability by simply not having a B. Subcategories suggested that 1,500 MMBtu/h would be permit that requires the use of more We are finalizing a variation of the a better cut-point because data reported than 90 percent natural gas, even if they broad applicability approach for to Gas Turbine World (GTW) showed intend to only burn natural gas. We combustion turbines where the that new combustion turbines are not disregarded this approach because it percentage electric sales and natural currently offered with a heat input would essentially provide a pathway for gas-use criteria serve as thresholds that rating between 1,300 MMBtu/h and all NGCC units to avoid applicability distinguish between three subcategories. 1,800 MMBtu/h, so the higher cut-point under both 111(b) and 111(d). The These subcategories are base load would more accurately reflect when second approach is problematic because natural gas-fired units, non-base load more efficient technologies are operating permit restrictions to improve natural gas-fired units, and multi-fuel- available. In contrast, other commenters said air quality are typically written to limit fired units. Under the final that differentiation between small and high emission activities (e.g., limiting subcategorization approach, multi-fuel- large combustion turbines was not the use of distillate oil to 500 hours fired combustion turbines are justified at all because many of the same annually), not to limit lower emitting distinguished from natural gas-fired efficiency technologies that reduce the activities. This approach could lead to turbines if fuels other than natural gas emission rates of larger units could be perverse environmental impacts by (e.g., distillate oil) supply 10 percent or incorporated into smaller units (e.g., incentivizing the use of non-natural gas more of heat input. Natural gas-fired upgrades that increase the turbine fuels, which would typically result in turbines are further subcategorized as engine operating temperature, increase higher CO2 emissions. Furthermore, the base load or non-base load units based the turbine engine pressure ratio, or add second approach would not limit the on the percentage electric sales multi-pressure steam and a steam reheat fuels that can be burned by affected criterion. The percentage electric sales cycle). These commenters also said that units (i.e., combustion turbines not threshold that distinguishes base load separate standards for small and large required to use non-natural gas fuels) and non-base load units is based on the turbines would undermine the incentive and would continue to cover specific turbine’s design efficiency (i.e., for technology innovation, which they combustion turbines even when they the sliding-scale approach). The described as a key purpose of the NSPS burn over 10 percent non–natural gas percentage electric sales threshold is program, and that relaxing standards for fuels. Because all non-natural gas fuels capped at 50 percent. smaller units would discourage This section describes comments we except H have CO emission rates investment in more efficient 2 2 received regarding the proposed size- higher than natural gas, this approach technologies, resulting in increased CO2 based subcategories and our rationale emissions. These commenters would exacerbate the concerns raised by for not finalizing them. In addition, it commenters about the achievability of recommended that the limit for both describes comments we received large and small units be no higher than the 111(b) requirements when burning regarding sales-based subcategories and back up fuels. 1,000 lb CO2/MWh-g. our rationale for adopting the sliding After evaluating these comments, the In light of these issues, the EPA has scale to distinguish between EPA has decided not to subcategorize concluded that permit restrictions are subcategories. Finally, it describes combustion turbines based on size for not an ideal approach to distinguishing comments we received regarding fuel- several reasons. First, the heat input between natural gas-fired and multi- based subcategories and our rationale values listed in Gas Turbine World do fuel-fired combustion turbines and are for adopting fuel-based subcategories. not include potential heat input from 532 finalizing a variation of the broad 1. Size-Based Subcategories duct burners. Because the heat input applicability approach. The EPA has from duct burners is necessary to concluded that the only practical At proposal, the EPA identified two accurately determine potential electric approach to implement the natural gas- size-based subcategories: (1) large output, our definition of ‘‘base load use criterion is to look at the turbine’s natural gas-fired stationary combustion rating’’ includes the heat input from any physical ability to burn natural gas. turbines with a base load rating greater installed duct burners. The EPA Therefore, we are not finalizing CO than 850 MMBtu/h and (2) small natural reviewed the heat input data for existing 2 gas-fired stationary combustion turbines standards for combustion turbines that NGCC units that has been submitted to with a base load rating of 850 MMBtu/ are not capable of firing any natural gas CAMD. These data include the heat h or less. The EPA received numerous (i.e., not connected to a natural gas input from duct burners and show that comments regarding our proposal to pipeline). From a practical standpoint, multiple NGCC power blocks have been subcategorize combustion turbines by the burners of most combustion turbines built in the past with heat input size. Some commenters agreed with the capacities that fall within the range that can be modified to burn natural gas, so 850 MMBtu/h cut-point between large this exemption is essentially limited to commenters suggested new turbines are and small units, some suggested not offered. Therefore, the EPA has combustion turbines that are built in increasing it to 1,500 MMBtu/h, and remote or offshore locations without concluded that the regulated others suggested eliminating size-based community uses various sizes of NGCC access to natural gas. Consistent with subcategorization altogether. For turbines and when the heat input from the broad applicability approach, we are example, some commenters stated that duct burners is included, there is no finalizing standards for all other the 850 MMBtu/h cut-point was clear break between the NGCC unit sizes combustion turbines, but are inappropriate because it was originally that could distinguish between small subcategorizing between natural gas- calculated based on NOX performance, and large units. In fact, subcategorizing fired turbines and multi-fuel-fired not CO2 performance. These turbines. Specifically, and as explained commenters stated that 850 MMBtu/h 532 Duct burners are optional supplemental in more detail in Section IX.B.3, we are was not a logical demarcation between burners located in the HRSG that are used to distinguishing between these classes of more efficient and less efficient generate additional steam. Heat input to duct turbines based on whether they burn burners could in theory be twice that of the combustion turbines, but rather would combustion turbine engine, but are more commonly greater than 90 percent natural gas or divide the units into arbitrary size sized at 10 to 30 percent of the heat input to the not. classifications. These commenters combustion turbine engine. VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00100 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64609 by size could unduly influence the or permit restrictions limiting the that would operate under the percentage development of future NGCC offerings amount of electricity that can be sold. electric sales threshold instead of because manufacturers could be Instead, we are finalizing the percentage higher-capital-cost, more-efficient units incentivized to design new products at electric sales criterion as a threshold to that would operate above the threshold. the top end of the small subcategory to distinguish between two natural gas- After evaluating these comments, the take advantage of the less stringent fired combustion turbine subcategories. EPA has concluded that it is appropriate emission standard. The industry uses a number of terms to to adopt a two-tiered subcategorization Second, commenters suggested that a describe combustion turbines with approach based on a percentage electric cut-point of 1,500 MMBtu/h reflects different operating characteristics based sales threshold to distinguish between when more efficient technologies on electric sales (e.g., capacity factors). non-base load and base load units. become available. However, when we Combustion turbines that operate at While we agree with commenters that reviewed actual operating data and near-steady, high loads are generally separate standards for peaking, design data, we only found a relatively referred to as ‘‘base load’’ or intermediate, and base load units is weak correlation between turbine size ‘‘intermediate load’’ units, depending attractive on the surface, we ultimately and CO2 emission rates and did not see on how many hours the units operate concluded that a three-tiered approach a dramatic drop in CO2 emission rates annually. Combustion turbines that is not appropriate for several reasons. at 1,500 MMBtu/h. The variability of operate continuously with variable First, the increased generation from emission rates among similar size units loads that correspond to variable renewable sources that is anticipated in far exceeds any difference that could be demand are referred to as ‘‘load the coming years makes it very difficult attributed to a difference in size. In following’’ or ‘‘cycling’’ units. to determine appropriate thresholds to addition, the most efficient one-to-one Combustion turbines that only operate distinguish among peaking, configuration NGCC power block with a during periods with the highest intermediate, and base load base load rating of 1,500 MMBtu/h or electricity demand are referred to as subcategories. Indeed, the boundaries less has a design emission rate of the ‘‘peaking’’ units. However, it is difficult between these demand-serving 767 lb CO2/MWh-n (984 MMBtu/h). The to characterize a particular unit using functions may blur or shift in the years most efficient one-to-one configuration just one of these terms. For example, a to come. The task is further complicated NGCC power block with a base load particular unit may serve as a load because each transmission region has a rating just greater than 1,500 MMBtu/h following unit during winter, but serve different mix of generation technologies has a design emission rate of 772 lb as a base load unit during summer. In and load profiles with different peaking, CO2/MWh-n (1,825 MMBtu/h). Because addition, none of these terms has a intermediate, and base load the smaller unit has a lower design precise universal definition. In this requirements. emission rate than the larger unit, preamble, we refer to the subcategory of Second, there are only two distinct increasing the cut-point does not make combustion turbines that sell a combustion turbine technologies— sense. significant portion of their potential Finally, the EPA has concluded that, simple cycle units and NGCC units. In electric output as ‘‘base load units.’’ while certain smaller NGCC designs theory, the BSER for the intermediate This subcategory includes units that may be less efficient than larger NGCC load subcategory could be based on would colloquially be referred to as base designs, most existing small units have high-efficiency simple cycle units or load units, as well as some intermediate demonstrated emission rates below the fast-start NGCC units, but these are load and load following units. We refer range of emission rates on which we variations on traditional technologies to all other units as ‘‘non-base load solicited comment. We have concluded and not necessarily distinct. Moreover, units.’’ This subcategory includes that the lower design efficiencies of we do not have specific cost information some small NGCC units are primarily peaking units, as well as some load on either high-efficiency simple cycle related to model-specific design choices following and intermediate load units. turbines or fast-start NGCC units, so our in both the turbine engine and HRSG, The threshold that distinguishes ability to make cost comparisons to not an inherent limitation in the ability between these two subcategories is conventional designs is limited. of small NGCC units to have comparable determined by a unit’s design efficiency Finally, even if we could identify efficiencies to large NGCC units. and varies from 33 to 50 percent, hence appropriate sales thresholds to Specifically, manufacturers could the term ‘‘slide scale’’ approach. distinguish between peaking, improve the efficiency of the turbine Numerous commenters supported intermediate load, and base load engine by using turbine engines with three sales-based subcategories for subcategories, we do not have sufficient higher firing temperatures and high peaking, intermediate load, and base information to establish a meaningful compression ratios and could improve load units. These commenters said that output-based standard for an the efficiency of the steam cycle by each subcategory should be intermediate load subcategory at this switching from single or double- distinguished by annual hours of time. In the transition zone from pressure steam to triple-pressure steam operation and that each should have a peaking to base load operation (i.e., and adding a reheat cycle. For all of different BSER and emission standard. cycling and intermediate load), these reasons, we have decided against Other commenters opposed the tiered combustion turbines may have similar subcategorizing combustion turbines approach. These commenters said that electric sales, but very different based on size. Our rationale for setting separate standards for different operating characteristics. For example, a single standard for small and large operating conditions would be despite having similar sales, one unit combustion turbines is explained in complicated to implement and enforce, might have relatively steady operation more detail in Section IX.D.3.a below. while providing few benefits. These for a short period of time, while another commenters said that a tiered approach could have variable operation 2. Sales-Based Subcategories could also have the unintended throughout the entire year. The latter As described above in Section consequence of encouraging less unit would likely have a higher CO2 IX.A.3.c, the final applicability criteria efficient technologies because it would emission rate. For all of these reasons, do not include an exemption for non- create a regulatory incentive to install the EPA has concluded that we do not CHP units based on actual electric sales lower-capital-cost, less-efficient units have sufficient information at this time VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00101 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 64610 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations to establish three sales-based as for higher capacity applications, such This lack of a significant change in subcategories. as supporting the growth of intermittent the operation of simple cycle turbines Instead, as we explained above, we renewable generation. could be explained by the Southwest are finalizing two sales-based With the changing electric sector in Power Pool’s relatively large amount of subcategories. To determine an mind, we set out to identify an exported power. If most of the region’s appropriate threshold to distinguish appropriate percentage electric sales renewable generation was being between base load and non-base load threshold to distinguish between non- exported, the intermittent nature of this units, the EPA considered the important base load and base load natural gas-fired power would primarily impact other characteristics of the combustion units. Two factors were of primary transmission regions. An alternate turbines that serve each type of demand. importance to our decision. First, the explanation, however, is that other For non-base load units, low capital threshold needed to be high enough to generating assets are flexible enough to costs and the ability to start, stop, and address commenters’ concerns about the respond to the intermittent nature of change load quickly are key. Simple need to maintain flexibility for simple wind and solar generation and that cycle combustion turbines meet these cycle units to support the growth of simple cycle turbines are not necessary criteria and thus serve the bulk of peak intermittent renewable generation. to back up these assets to the degree demand. In contrast, for base load units, Second, the threshold needed to be low some commenters suggested. If this is efficiency is the key consideration, enough to avoid creating a perverse the case, then new simple cycle turbines while capital costs and the ability to incentive for owners and operators to may primarily continue to fill their start and stop quickly are less avoid the base load subcategory by historical role as peaking units going important. While NGCC units have installing multiple, less efficient forward, while other technologies, such relatively high capital costs and are less turbines instead of fewer, more efficient as fast-start NGCC units, may provide flexible operationally, they are more turbines. the primary back up capacity for new efficient than simple cycle units. NGCC To determine the potential impact of wind and solar. units recover the exhaust heat from the intermittent renewable generation on combustion turbine with a HRSG to b. Texas the operation of simple cycle units, we power a steam turbine, which reduces The portion of in-state generation examined the average electric sales of fuel use and CO emissions by from wind and solar in Texas increased 2 simple cycle turbines in the lower 48 approximately one-third compared to a from 4 to 9 percent between 2008 and states between 2005 and 2014 using simple cycle design. Consequently, base 2014. The average growth rate of wind load units use NGCC technology. information submitted to CAMD. We and solar was 13 percent, while overall Because simple cycle turbines have combined this data with information demand grew at an average rate of 2 historically been non-base load units, reported to the EIA on total in-state percent annually. Similar to the we have concluded that it is appropriate electricity generation, including wind Southwest Power Pool, the average to distinguish between the non-base and solar, from 2008 through 2014. We electric sales of simple cycle turbines load and base load subcategories in a focused on data from the Southwest has remained relatively unchanged. In way that recognizes the distinct roles of Power Pool (data approximated by EGUs fact, the average electric sales of these the different turbine designs on the in Nebraska, Kansas, and Oklahoma), turbines decreased at an annual rate of market. Texas, and California. All of these 1.1 percent. Total generation from The challenge, however, is setting a regions have relatively large amounts of simple cycle turbines increased at an threshold that will not distort the generation from wind and solar and annual rate of 6.6 percent, however, due market. The future distinction between experienced increases in the portion of to simple cycle capacity additions that non-base load and base load units is total electric generation provided by occurred at approximately four times unclear. For example, some commenters wind and solar during the 2008–2014 the rate one would expect from the indicated that increased generation from period. growth in overall demand. intermittent renewable sources has a. Southwest Power Pool The most likely technologies to back created a perceived need for additional up intermittent renewable generation cycling and load following generation The portion of in-state generation have low incremental generating costs that will operate between the traditional from wind and solar in the Southwest and can start up and stop quickly. roles of peaking and base load units. To Power Pool increased from 3 to 16 Highly efficient simple cycle units meet fulfill this perceived need, some percent between 2008 and 2014. The these criteria. As such, the EPA has manufacturers have developed high- average growth rate of wind and solar concluded that the most efficient simple efficiency simple cycle turbines. These was 28 percent, while overall electricity cycle turbines in a given region are the high-efficiency turbines have higher demand grew 1 percent annually on most likely to support intermittent capital costs than traditional simple average. Based on statements in some of renewable generation. Focusing on these cycle turbine designs, but maintain the comments, we expected to see a simple cycle turbines will address similar flexibilities, such as the ability large change in the operation of simple concerns raised by commenters about to start, stop, and change load rapidly. cycle turbines in this region. However, the future percentage electric sales of Other manufacturers have developed the average electric sales from simple highly efficient simple cycle turbines fast-start NGCC turbines to fill the same cycle turbines only increased at an and give an indication of the impact of role. These newer NGCC designs have annual rate of 1.7 percent, and remained increased renewable generation on non- lower design efficiencies than NGCC essentially unchanged at 3 percent of base load units intended to back up designs intended to only operate as base potential electric output between 2008 wind and solar. There are two highly load units, but are able to startup more and 2014. Total generation from simple efficient intercooled simple cycle quickly to respond to rapid changes in cycle turbines in the Southwest Power turbines installed in Texas. These two electricity demand. As a result of these Pool increased slightly more, at an combustion turbines sell an average of new technological developments, both annual rate of 2.5 percent, which was 10 percent of their potential electric high-efficiency simple cycle and fast- the result of additional simple cycle output annually, compared to an start NGCC units can be used for capacity being added to address average of 3 percent for the remaining traditional peaking applications, as well increased electricity demand. simple cycle turbines. No simple cycle VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00102 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64611 turbine in Texas sold more than 25 demand-response programs are frame units range from 30 percent for percent of its potential electric output currently providing adequate back up to smaller designs to 36 percent for the annually. The rapid growth in simple intermittent renewable generation. In largest designs. These efficiency values cycle capacity, but not overall capacity the future, however, existing NGCC follow the methodology the EPA has factors, could indicate that the units will likely operate at higher historically used and are based on the additional generation assets are capacity factors. They will therefore be higher heating value (HHV) of the fuel. providing firm capacity for intermittent less available to provide back up power In contrast, combustion turbine vendors generation sources such as wind and for intermittent generation. In addition, in the U.S. often quote efficiencies solar, but that capacity is infrequently the amount of power generated by based on the lower heating value (LHV) required. Based on the data, even highly intermittent sources is expected to of the fuel. The LHV of a fuel is efficient simple cycle turbines are increase in the future. Both of these determined by subtracting the heat of expected to continue to sell less than factors could require additional vaporization of water vapor generated one-third of their potential electric flexibility from the remaining during combustion of fuel from the output. generation sources to maintain grid HHV. For natural gas, the LHV is reliability. approximately 10 percent lower than c. California Even though fast-start NGCC units, the HHV. Therefore, the corresponding The portion of in-state generation reciprocating internal combustion LHV efficiency ranges would be 35 to 44 from wind and solar in California engines, energy storage technologies, percent for aeroderivative designs and increased from 3 to 11 percent between and demand-response programs are 33 to 40 percent for frame designs. We 2008 and 2014. The average growth rate promising technologies for providing considered basing the percentage of wind and solar was 25 percent, while back up power for renewable electric sales threshold on both the HHV overall demand has remained stable. generation, none of them historically and LHV. The EPA typically uses the The operation of simple cycle turbines have been deployed in sufficient HHV, but in light of commenters’ in California has changed more capacity to provide the potential concerns regarding uncertainty in the significantly than in the other evaluated capacity needed in the future to operation of non-base load units in the regions. The average electric sales from facilitate the continued growth of future, we opted to be conservative and simple cycle turbines increased from 5.1 renewable generation. While we use the LHV efficiency. to 5.9 percent, an annual rate increase anticipate that state and federally issued We anticipate that high-efficiency of 4.5 percent. As in Texas, considerable permits for new electric generating simple cycle and fast-start NGCC additional simple cycle capacity has sources will consider the CO2 benefits of turbines will make up the majority of been added in recent years. The total these technologies compared to simple new capacity intended for non-base load capacity of simple cycle turbines is cycle turbines, the EPA has concluded applications. Based on the sliding-scale increasing at 15 percent annually even at this time that it is appropriate to approach, owners and operators of new though overall demand has remained finalize a percentage electric sales simple cycle combustion turbines will relatively steady. In addition, the threshold that provides additional be able to sell between 33 to 44 percent newest simple cycle turbines are flexibility for simple cycle turbines. of the turbine’s potential electric output. operating at higher capacity factors than Specifically, we have concluded that Our analysis showed that 99.5 percent the existing fleet of simple cycle a percentage electric sales threshold of existing simple cycle turbines have turbines, resulting in an average based on a unit’s design net efficiency not sold more than one-third of their increase in generation from simple cycle at standard conditions is appropriate. potential electric output on an annual turbines of 21 percent. Many of the new This is the sliding-scale approach on basis. In addition, 99.9 percent of additions are intercooled simple cycle which we solicited comment. Several existing simple cycle turbines have not turbines that may have been installed commenters supported this approach sold more than 36 percent of their with the specific intent to back up wind because it provides sufficient potential electric output on an annual and solar generation. operational flexibility for new simple basis. The two simple cycle turbines The average electric sales for the cycle and fast-start NGCC combustion that exceeded the 36 percent threshold intercooled turbines ranged from 3 to 25 turbines and simultaneously promotes had annual electric sales of 39 and 45 percent, with a 7 percent average. No the installation of the most efficient percent and are located in Montana and simple cycle turbines in California have generating technologies. By allowing New York, respectively. As noted sold more than one-third of their more efficient turbines to sell more earlier, the most efficient simple cycle potential electric output on an annual electricity before becoming subject to turbine currently available is 44 percent basis. The operation of simple cycle the standard for the base load efficient and would accommodate the turbines that existed prior to 2008 has subcategory, the sliding scale should operations at the Montana facility. The not changed significantly. Average reduce the perverse incentive for only existing simple cycle turbine that electric sales for these turbines owners and operators to install more exceeded the maximum allowable increased at an annual rate of 0.1 lower-capital-cost, less-efficient units percentage electric sales threshold of 44 percent. This indicates that support for instead of fewer higher-capital-cost, percent, which is based on current new renewable generation is being more-efficient units. At the same time, simple cycle designs, sold an provided by new units and not by the the sliding scale should incentivize abnormally high amount of electricity in installed base of simple cycle units. turbine manufacturers to design higher 2014. It is possible that this unit was These units are still serving their efficiency simple cycle turbines that operating under emergency conditions. historical role of providing power owners and operators can run more As explained below, the incremental during peak periods of demand. frequently. generation due to the emergency would Based on our data analysis, the The net design efficiencies for not have counted against the percentage proposed one-third electric sales aeroderivative simple cycle combustion electric sales threshold. threshold would appear to offer turbines range from approximately 32 We are capping the percentage sufficient operational flexibility for new percent for smaller designs to 39 percent electric sales threshold at 50 percent of simple cycle turbines. Existing NGCC for the largest intercooled designs. The potential electric output for multiple units, other generation assets, and net design efficiencies of industrial reasons. First, NGCC emission rates are VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00103 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 64612 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations relatively steady above 50 percent 3. Fuel-Based Subcategories C. Identification of the Best System of electric sales, so there is no reason that As described in Section IX.A.3.d, we Emission Reduction a NGCC unit with sales greater than this are finalizing a version of the broad This section summarizes the EPA’s amount should not have to comply with applicability approach. Under the broad proposed BSER determinations for the output-based standard for the base applicability approach, the EPA stationary combustion turbines, load subcategory. Second, the net design solicited comment on a provides a summary of the comments efficiency of the fast-start NGCC units subcategorization approach based in we received, and explains our final intended for peaking and intermediate part on natural gas-use. We received few BSER determinations for each of the load applications is 49 percent. As comments on this issue. One of the three subcategories we are now described earlier, this technology can comments we did receive was that finalizing. For natural gas-fired serve the same purpose as high- combustion turbines that burn fuels stationary combustion turbines efficiency simple cycle turbines. If we other than natural gas have higher CO2 operating as base load units, we were to set a cap any lower than 50 emissions due to the higher relative proposed and are finalizing the use of percent, it could create a disincentive carbon content of alternate fuels. NGCC technology as the BSER. For the for owners and operators to choose this Besides hydrogen,533 natural gas has the other two subcategories of affected promising new technology. lowest CO2 emission rate on a lb/ combustion turbines—non-base load Finally, the EPA solicited comment MMBtu basis of any fossil fuel. on excluding electricity sold during natural gas-fired combustion turbines Therefore, burning fuels other than and multi-fuel-fired combustion system emergencies from counting natural gas will result in a higher CO towards the percentage electric sales 2 turbines—we are finalizing the use of emission rate. We interpret this clean fuels as the BSER. threshold. After considering the comment to mean that, if we were to comments, we have concluded that this subcategorize based on fuel use, 1. Proposed BSER exclusion is necessary to provide turbines that burn non-natural gas fuels flexibility, maintain system reliability, We considered three alternatives in should receive a less stringent emission evaluating the BSER for base load and minimize overall costs to the sector. standard. We disagree with commenters that natural gas-fired combustion turbines: For the reasons described in the (1) Partial CCS, (2) high-efficiency suggested that the EPA’s existing applicability section, we have decided enforcement discretion would be a simple cycle aeroderivative turbines, to set emission standards for all and (3) modern, efficient NGCC viable alternative. An enforcement combustion turbines capable of burning discretion-based approach would not turbines. We rejected partial CCS as the natural gas, regardless of the actual fuel BSER because we concluded that we did provide certainty to the regulated burned, to avoid the practical problems community, public, and regulatory not have sufficient information to that would have arisen under the determine whether implementing CCS authorities on the applicability of the proposed approach. However, as emission standards, which is a primary for combustion turbines was technically commenters explained, multi-fuel-fired feasible. We rejected high-efficiency reason why we are finalizing the broad combustion turbines cannot achieve the applicability approach. Moreover, simple cycle aeroderivative turbines as emission standards achieved by natural- the BSER because this standalone system emergencies are defined events, gas fired turbines. For this reason, it so commenters’ fears that the exclusion technology does not provide emission would not be reasonable to require reductions and generally is more will be subject to abuse are overstated. affected EGUs to comply with a Therefore, electricity sold during hours expensive than NGCC technology for standard based on the use of natural gas base load applications. In contrast, of operation when a unit is called upon during periods when significant to operate due to a system emergency NGCC is the most common type of new quantities of non-natural gas fuels are fossil fuel-fired EGU currently being will not be counted toward the being burned. If we did not planned and built for generating base percentage electric sales threshold. subcategorize, owners and operators load power. NGCC is technically However, electricity sold by units that would not be able to combust other feasible, and NGCC units are currently are not called upon to operate due to a fuels in their turbines, including process the lowest-cost, most efficient option for system emergency (e.g., units already gas, blast furnace gas, and petroleum- new base load fossil fuel-fired power operating when the system emergency is based liquid wastes, which might generation. After considering the declared) will be counted toward the otherwise be wasted. In addition, options, the EPA proposed to find that percentage electric sales threshold. without the ability to burn back up fuels modern, efficient NGCC technology is In summary, the EPA is finalizing the during natural gas curtailments, grid the BSER for base load natural gas-fired percentage electric sales criterion as a reliability could be jeopardized. threshold to distinguish between two Therefore, we are finalizing a separate combustion turbines. natural gas-fired combustion turbine fuel-based subcategory for multi-fuel- For non-base load natural gas-fired subcategories. Specifically, all units that fired combustion turbines. To units and multi-fuel-fired units, we did have electric sales greater than their net distinguish between this subcategory not propose a specific BSER or LHV design efficiencies (as a percentage and the natural gas-fired subcategories, associated numeric emission standards, of potential electric output) are base we are using the same threshold as but instead solicited comment on these load units. All units that have electric proposed. Specifically, combustion issues. sales less than or equal to their net LHV turbines that burn ninety percent or less 2. Comments on the Proposed BSER for design efficiencies are non-base load natural gas on a 12-operating-month Base Load Natural Gas-Fired units. We are capping the percentage rolling average basis will be included in Combustion Turbines electric sales threshold at 50 percent of this subcategory and subject to a This section summarizes the differing potential electric output. This sliding- separate emission standard, which is comments submitted on the proposed scale approach will limit the operation discussed in Section IX.D.3.d. of the least efficient units, provide BSER for base load natural gas-fired flexibility for renewable energy growth, 533 Hydrogen would only be considered a fossil combustion turbines. Some commenters and incentivize the development of fuel if it were derived for the purpose of creating supported partial CCS as the BSER, more efficient simple cycle units. useful heat from coal, oil, or natural gas. others supported advanced NGCC VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00104 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64613 designs as the BSER, and others selected, but is intended to be a base more renewable energy sources are supported the proposed BSER. load NGCC unit with CCS used for EOR. integrated into the grid. These These commenters also referenced commenters added that NGCC units a. Partial CCS reports authored by DOE, NETL, the operate differently than coal-fired units Some commenters stated that our Clean Air Task Force (CATF), CCS Task because the former start, stop, and cycle proposed BSER analysis for stationary Force, ICF Inc., and Global CCS frequently, whereas the latter tend to combustion turbines was inconsistent Institute, suggesting that, because CCS operate at relatively steady loads and do with our proposed BSER analysis for technology for NGCC is included in not start and stop frequently. They coal-fired units. They stated that the these reports, it is adequately stated that even if technical barriers EPA had determined that the use of CCS demonstrated. Some commenters could be overcome, the application of was feasible for coal-fired generation referred to a DOE/NETL study that CCS to combustion turbines would be based on current CCS projects under suggested that the cost of CCS for NGCC more costly (compared to the development at coal-fired generating units would be more cost-effective than application of CCS to coal-fired units) stations, but did not come to the same for coal-fired EGUs. One non-industry on a dollars-per-ton basis. In addition, conclusion for combustion turbines. commenter emphasized that a these commenters said that other These commenters stated that CO2 technology does not have to be in use industries’ experience with CCS could removal is just as technologically to be considered adequately not be transferred to NGCC units due to feasible and economically reasonable for demonstrated. differences in flue gas CO2 a natural gas-fired EGU as for a coal- In addition, some commenters concentration. fired EGU. While some of these disagreed with the EPA’s decision to Some commenters stated that CAA commenters wanted the EPA to treat combustion turbines differently section 111(a) requires the EPA to reconsider CCS as the BSER for NGCC, than coal-fired units with respect to CCS account not only for the cost of many of these commenters were on the basis that combustion turbines achieving emission reductions, but also attempting to prove that if the agency startup, shutdown, and cycle load more for impacts on energy requirements and did not choose CCS as the BSER for frequently than coal-fired units. the environment. The commenters cited NGCC units, then the agency should not According to these commenters, the to Sierra Club v. Costle, where the D.C. for coal-fired units either. operating characteristics of combustion Circuit observed that the EPA ‘‘must Some commenters referenced the turbines do fluctuate, but so do those of exercise its discretion to choose an Northeast Energy Association NGCC coal-fired units. Another commenter achievable emission level which plant in Bellingham, MA, which said that even if NGCC operations vary represents the best balance of economic, operated from 1991–2005 with 85–95 more than they do for coal-fired units, environmental, and energy percent carbon capture on a 320 MW it is not an impediment to using CCS considerations.’’ 534 The commenters unit for use in the food and beverage because combustion turbine operators stated that requiring CCS on combustion industry, that was referred to in the could bypass the carbon capture system turbines would adversely affect the proposal. This plant captured 330 tons during startup and shutdown modes nation’s energy needs and the of CO2 per day from a 40 MW slip (which are typically shorter and less environment because imposing CCS on stream and was decommissioned as a intensive efforts compared to the startup combustion turbines would invariably result of financial difficulties, including or shutdown of a coal facility) and then delay the emission reductions that can rising gas prices and discontinuation of employ the carbon capture system when be obtained from new NGCC projects tax credits. According to these operating normally. One commenter that displace load from older, less commenters, this plant provided stated that most future base load fossil efficient generating technologies. In sufficient proof that CCS technology is fuel-fired generation will be NGCC and addition, the commenters stated that, adequately demonstrated for NGCC that not making CCS the BSER for NGCC because combustion turbines are units. Additionally, these commenters would result in significant CO2 projected to provide a significant share referred to other NGCC plants that are emissions. of new power generation, the EPA planned or in development that will Other commenters supported the should recognize that requiring CCS on incorporate CCS. The plants mentioned EPA’s determination that CCS is not the these units would have a were the Sumitomo Chemical Plant in BSER for combustion turbines. These disproportionally higher impact on Japan, the Peterhead CCS project in commenters said that CCS is not electricity prices when compared to the Scotland, and the GE-Sargas Plant in adequately demonstrated for projected number of new coal-fired Texas. The Sumitomo Chemical Plant combustion turbines because none are projects. These commenters concluded has a base load NGCC unit with CCS currently operating, under construction, that the EPA could not determine that operating on an 8 MW slip-stream that or in the advanced stages of CCS is the BSER for combustion captures about 150 tons of CO2 per day development. They also noted that CCS turbines without producing severe and for commercial use in the food and would have to be demonstrated for the unacceptable consequences for the beverage industry. This carbon capture range of facilities included in the availability of affordable electricity in system has been operating since 1994. regulated source category, which they the U.S. The Peterhead CCS project in Scotland alleged includes both simple cycle and is in the planning stages. It is a NGCC units. They specifically noted b. NGCC Turbines collaboration between Shell and SSE to that the Bellingham, MA demonstration Some commenters stated that the provide 320 MW of electricity to its facility was not a full-scale commercial proposed BSER analysis should have customers from a base load NGCC unit NGCC power plant operating with CCS. reflected the emission rates achieved by with 90 percent carbon capture. The These commenters agreed with the the latest designs deployed at advanced, CO2 will be transported to the depleted EPA that CCS does not match well with state-of-the-art NGCC installations. Goldeneye reservoir in the ocean where the operating flexibilities of NGCC and These commenters stated that advanced it will be stored and continuously simple cycle units. They agreed with the NGCC technologies are the best system monitored. The GE-Sargas Plant in EPA that frequent cycling restricts the Texas is a planned joint venture that efficacy of CCS on these units, a 534 Sierra Club v. Costle, 657 F.2d 298, 330 (D.C. does not currently have a location problem which would only get worse as Cir. 1981). VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00105 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 64614 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations for reducing CO2 emissions with no units, non-base load natural gas-fired are not aware of any pilot-scale CCS negative environmental impacts and no units, and multi-fuel-fired units. projects that have demonstrated how negative economic impacts on rate fast and frequent starts, stops, and a. Base Load Natural Gas-Fired Units payers. They stated that advanced cycling will impact the efficiency and NGCC technologies are capable of As described in the proposal, we reliability of CCS. Furthermore, for achieving emission rates that are 8 evaluated CCS, NGCC, and high- those periods in which a NGCC unit is percent lower than conventional NGCC efficiency simple cycle combustion operating infrequently, the CCS system facilities. They also said that the turbines as the potential BSER for this might not have sufficient time to majority of existing sources that do not subcategory. We selected NGCC as the startup. During these periods, no CO2 deploy these advanced technologies are BSER because it met all the BSER control would occur. Thus, if the NGCC currently able to meet the standard and criteria. This section describes our unit is intended to operate for relatively that the proposal failed to explain why response to issues raised by commenters short intervals for at least a portion of these lower-emitting advanced and our rationale for maintaining that the year, the owner or operator could technologies that are more than NGCC is the BSER for base load natural have to oversize the CCS to increase adequately demonstrated were not gas-fried combustion turbines. control during periods of steady-state selected as the BSER. (1) Partial CCS operation to make up for those periods when no control is achieved by the CCS, c. Simple Cycle Turbines Some commenters stated that CCS leading to increased costs and energy Many commenters opposed the EPA’s could be applied equally to both coal- penalties. While we are optimistic that proposal to set emission standards for fired and natural gas-fired EGUs. To these hurdles are surmountable, it is combustion turbines based on their support this conclusion, the simply premature at this point to make function rather than based on their commenters pointed to a retired NGCC- a finding that CCS is technically feasible design. These commenters stated that with-CCS demonstration project, as well for the universe of combustion turbines the EPA’s determination that NGCC as a few overseas projects and projects that are covered by this rule. technology is the BSER for base load in the early stages of development. Notably, the Department of Energy natural gas-fired combustion turbines While we have concluded that these has not yet funded a CCS demonstration would apply equally to simple cycle commenters made strong arguments that project for a NGCC unit, and no NGCC- turbines if they sell electricity in excess the technical issues we raised at with-CCS demonstration projects are of the percentage electric sales proposal could in many instances be currently operational or being threshold. They pointed to the word overcome, we have concluded that there constructed in the U.S. In contrast, ‘‘achievable’’ in CAA section 111(a)(1) is not sufficient information at this time multiple CCS demonstration projects for and stated that applying an emission for us to determine that CCS is coal-fired units are in various stages of standard based on NGCC technology to adequately demonstrated for all base development throughout the U.S., and a simple cycle units was legally load natural-gas fired combustion full-capture system is in operation at the indefensible because simple cycle units turbines. Boundary Dam facility in Canada. See cannot achieve emission rates as low as While the commenters make a strong Sections V.E and D above. NGCC units. In contrast, many other case that the existing and planned One commenter suggested that not commenters agreed with the EPA’s basic NGCC-with-CCS projects demonstrate having CCS as the BSER for combustion approach and stated that NGCC the feasibility of CCS for NGCC units turbines would ultimately halt the technology should be the BSER for base- operating at steady state conditions, development of CCS in the U.S. We load functions, while simple cycle many NGCC units do not operate this disagree. A number of coal-fired power technology should be the BSER for way. For example, the Bellingham, MA plants are currently being built with peak-load functions. and Sumitomo NGCC units cited by the CSS, while some existing plants are commenters operated at steady load considering CCS retrofits. Moreover, the 3. Comments on Non-Base Load and conditions with a limited number of NSPS sets the minimum level of control Multi-Fuel-Fired Combustion Turbines starts and stops, similar to the operation for new sources. We expect that state air Multiple commenters suggested that of coal-fired boilers.535 In contrast, our agencies and other air permitting high efficiency simple cycle or fast-start base load natural gas-fired combustion authorities will evaluate CCS when NGCC technologies should be the BSER turbine subcategory includes not only permitting new NGCC power plants, for non-base natural gas-fired load units. true base load units, but also some taking into consideration case-specific They explained that high efficiency intermediate units that cycle more parameters, like operating simple cycle units and fast-start NGCC frequently, including fast-start NGCC characteristics, to determine whether units are actually more efficient when units that sell more than 50 percent of CCS could be BACT or LAER in specific serving non-base load demand than their potential output to the grid. Fast- instances. While the NGCC-with-CCS NGCC units that are designed strictly for start NGCC units are designed to be able units that currently are in the planning base load operation. Some commenters to start and stop multiple times in a stages do not provide us with enough also suggested that we should single day and can ramp to full load in assurance to determine that CCS is subcategorize multi-fuel-fired less than an hour. In contrast, coal-fired adequately demonstrated for combustion turbines, but did not EGUs take multiple hours to start and combustion turbines, it is our provide any specific technologies that ramp relatively slowly. These expectation that these units and others should be considered in the BSER differences are important because we to come will provide additional analysis. information for both permitting reviews 535 As explained in Section V.J above, a new fossil and the next NSPS review in eight 4. Identification of the BSER fuel-fired steam generating EGU would, most likely, be built to serve base load power demand years. After our evaluation of the comments exclusively and would not be expected to routinely and additional analysis, we identified startup, shut down, or ramp its capacity factor in (2) NGCC Turbines the BSER for each subcategory of order to follow load demand. Thus, planned start- Regarding the advanced NGCC up and shutdown events would only be expected combustion turbine that we are to occur a few times during the course of a 12- technologies advocated by several finalizing: base load natural gas-fired operating-month compliance period. commenters, the EPA has concluded VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00106 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64615 that the term ‘‘advanced’’ simply refers percentage electric sales criterion for the concluded that CCS does not meet the to incremental improvements to base load natural gas-fired combustion BSER criteria because the low capacity traditional NGCC designs, not a new turbine subcategory is based on the factors and irregular operating patterns and unique technology. These sliding scale. This means that the (e.g., frequent starting and stopping and incremental improvements include dividing line between the base load operating at part load) of non-base load higher firing temperatures in the turbine subcategory and the non-base load units make the technical challenges engine, increasing the number of steam subcategory will change depending on a associated with CCS even greater than pressures, and adding a reheat cycle to unit’s nameplate design efficiency. For those associated with base load units. In the steam cycle. The emission rates a conventional simple cycle turbine, the addition, because the CCS system would achieved by these so-called ‘‘advanced’’ base load subcategory will begin at remain idle for much of the time while technologies were included within the around 33 percent electric sales, while these units are not running, CCS would data set of newer NGCC designs that we for a newer fast-start NGCC turbine, the be less cost-effective for these units than used to establish the final emission base load subcategory will begin at for base load units. standards. In addition, our review of the approximately 50 percent electric sales. We have also concluded that the high- operating data for NGCC power blocks Anywhere within this range, our cost efficiency NGCC units designed for base installed since 2000 indicates that a calculations have shown that NGCC load applications do not meet any of the unit’s mode of operation in response to technology is more cost-effective than BSER criteria for non-base load units. system demand (e.g., capacity factor) simple cycle technology. Therefore, we First, non-base load units need to be affects efficiencies achieved to the are finalizing our determination that able to start and stop quickly, and NGCC extent that we cannot evaluate the modern, efficient NGCC technology is units designed for base load impact of particular subcomponents the BSER for base load natural-gas fired applications require relatively long used within the power block. As a combustion turbines. startup and shutdown periods. result, a conventional NGCC power Therefore, conventional NGCC designs (3) Simple Cycle Turbines block located in a region of the country are not technically feasible for the non- where system demand requires the Many commenters mistakenly thought base load subcategory. Also, non-base power block to run continuously at a that the EPA proposed to require some load units operate less than 10 percent steady high load can achieve higher simple cycle combustion turbines to of the time on average. As a result, efficiencies than an ‘‘advanced’’ NGCC meet an emission standard of 1,000 lb conventional NGCC units designed for power block located in a region where CO2/MWh-g, a level that they assert is base load applications, which have system demand requires the power unachievable. On the contrary, the EPA relatively high capital costs, will not be block to cycle on and off to match is not finding that NGCC technology and cost-effective if operated as non-base system demand. For this reason, our a corresponding emission standard of load units. In addition, it is not clear data set included a large population of 1,000 lb CO2/MWh-g is the BSER for that a conventional NGCC unit will lead technologies and load conditions to simple cycle turbines. Instead, the EPA to emission reductions if used for non- ensure that new NGCC power blocks is finding that NGCC technology is the base load applications. As some can achieve the final emission standards BSER for base load turbine applications. commenters noted, conventional NGCC in all regions of the country. This means that if an owner or operator units have relatively high startup and As we explained in the proposal, wants to sell more electricity to the grid shutdown emissions and poor part-load NGCC technology meets all of the BSER than the amount derived from a unit’s efficiency, so emissions may actually be criteria. For base load functions, NGCC nameplate design efficiency calculated higher compared with simple cycle units are technically feasible, cost- as a percentage of potential electric technologies that have lower overall effective (indeed, less expensive than output, then the owner or operator design efficiencies but better cycling simple cycle combustion turbines), and should install a NGCC unit. If the owner efficiencies. Finally, requiring have no adverse energy or or operator elects to install a simple conventional NGCC units as the BSER environmental impacts. Moreover, cycle turbine instead, then the practical for non-base load combustion turbines NGCC units reduce emissions because effect of our final standards will be to would not promote technology because they have a lower CO2 emission rate limit the electric sales of that unit so these units would not be fulfilling their than simple cycle units. Finally, that it serves primarily peak demand, intended role. In fact, it could hamper selecting NGCC as the BSER will not to subject it to an unachievable the development of technologies with promote the development of new emission standard. lower design efficiencies that are technology, such as the incremental specifically designed to operate b. Non-base Load Natural Gas-Fired improvements advocated by the efficiently as non-base load units (i.e., Load Units commenters, which will further reduce high-efficiency simple cycle and fast- emissions in the future. To identify the BSER for non-base start NGCC units). For all these reasons, Some commenters suggested that the load natural gas-fired units, we we have concluded that conventional costs and efficiency impacts of startup evaluated a range of technologies, NGCC units designed for base load and shutdown events are higher for including partial CCS, high-efficiency applications are not the BSER for non- NGCC units than for simple cycle units. NGCC technology designed for base load base load natural gas-fired units. Consequently, we refined the LCOE applications, fast-start NGCC, high- Compared to conventional NGCC costing approach used at proposal by efficiency simple cycle units (i.e., technology, fast-start NGCC units have adding these additional costs and aeroderivative turbines), and clean lower design efficiencies, but are able to efficiency impacts to our cost fuels. For each of these technologies, we start and ramp to full load more quickly. comparison. Even accounting for these considered technical feasibility, costs, Therefore, it is possible that requiring new costs and impacts, we found that energy and non-air quality impacts, fast-start NGCC as the BSER for non- NGCC technology results in a lower cost potential for emission reductions, and base load units would result in emission of electricity than simple cycle ability to promote technology. reductions and further promote the technology when a unit’s electric sales While CCS would result in emission development of fast-start NGCC exceed approximately one-third of its reductions and promote the technology, which is relatively new and potential electric output. The final development of new technology, we advanced. However, because the VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00107 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 64616 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations majority of non-base load combustion EIA data,536 natural gas comprises more many industrial facilities do not have turbines operate less than 10 percent of than 96 percent of total heat input for the space available to build a HRSG and the time, it would be cost-prohibitive to simple cycle combustion turbines. In the associated cooling tower. Therefore, require fast-start NGCC, which have addition, natural gas is frequently the requiring NGCC as the BSER could have relatively high capital costs compared to lowest cost fossil fuel used in unforeseen energy impacts at these simple cycle turbines, as the BSER for combustion turbines, so it is cost- types of facilities. Moreover, these same all non-base load applications. Also, as effective. Clean fuels will also result in kinds of facilities also burn by-product we explained above in Section IX.B.2, some emission reductions by limiting fuels. Faced with a decision to install an we do not have sufficient emissions data the use of fuels with higher carbon NGCC unit, these facilities might seek for fast-start NGCC units operating over content, such as residual oil. Finally, alternative energy options, which could the full range of non-base load the use of clean fuels will not have any lead to increased flaring or venting of conditions (e.g., peaking, cycling, etc.), significant energy or non-air quality by-product fuels because they are no so we would not be able to establish a impacts. Based on these factors, the EPA longer being burned onsite for energy reasonable emission standard. has determined that the BSER for non- recovery. Therefore, in light of these High-efficiency simple cycle turbines base load natural gas-fired units is the potential energy and non-air quality are primarily used for peaking use of clean fuels, specifically natural impacts, we have concluded that NGCC applications. High-efficiency simple gas with a small allowance for distillate technology is not the BSER for multi- cycle turbines often employ oil. Natural gas has approximately thirty fuel-fired combustion turbines. aeroderivative designs because they are percent lower CO2 emissions per Similarly, while high-efficiency more efficient at a given size and are million Btu than other fossil fuels simple cycle turbines would result in able to startup and ramp to full load commonly used by utility sector non- emission reductions and promote the more quickly than industrial frame base load units. advancement of this technology, we are designs. Requiring high-efficiency not confident that high-efficiency simple cycle turbines as the BSER could c. Multi-Fuel-Fired Units simple cycle units are technically result in some emission reductions To identify the BSER for multi-fuel- feasible or cost-effective for this compared with conventional simple fired units, we again evaluated CCS, subcategory. Aeroderivative turbines are cycle turbines. It would also promote NGCC technology, high-efficiency not as flexible with regards to what fuels technology development by simple cycle units (i.e., aeroderivative that can be burned. Because by-product incentivizing manufacturers to increase turbines), and clean fuels. For each of fuels vary in composition, it is not clear the efficiency of their simple cycle these technologies we considered that all by-products fuels could be turbine models. However, technical feasibility, costs, energy and burned in a high-efficiency simple cycle aeroderivative designs have higher non-air quality impacts, emission turbine. In addition, even if a by- initial costs that must be weighed reductions, and technology promotion. product fuel could be burned in an against the specific peak-load profiles For many of the same reasons we aeroderivative turbine, we do not have anticipated for a particular new non- provided above in our discussion of the information on the potential for base load unit. Many utility companies BSER for non-base load natural gas-fired increased maintenance costs, so we have elected to install the heavier combustion turbines, only clean fuels cannot determine whether using high- industrial frame turbines because the meets the BSER criteria for multi-fuel- efficiency simple cycle turbines would ramping capabilities of aeroderivative fired units. be cost-effective. turbines are not required for their While CCS would result in emission The final option that we considered system demand profiles (i.e., the speed reductions and the promotion of for the BSER was clean fuels. The use and durations of daily changes in technology, we concluded that CCS of clean fuels is technically feasible and electricity demand), and the fuel savings does not meet the BSER criteria because cost-effective. The use of clean fuels do not justify the higher initial costs. multi-fuel-fired units tend to start, stop, also provides an environmentally We currently do not have precise and operate at part load frequently. beneficial alternative to the flaring or enough costing information to compare Also, there are impurities and venting of by-product fuels and limits the cost-effectiveness of aeroderivative contaminants in some alternate fuels the use of dirtier fuels with higher CO2 turbines and industrial frame turbines which make the technical challenges of emission rates, such as residual oils. for all non-base load applications. applying CCS to multi-fuel-fired units Clean fuels also promote technology Determining cost-effectiveness is further greater than for natural gas-fired units. development by allowing manufacturers complicated because the efficiencies of In regards to NGCC technology, we to develop new combustion turbine the available aeroderivative and have concluded that it is technically designs that are capable of burning by- industrial frame technologies feasible, would result in emission product fuels that currently cannot be significantly overlap. For example, the reductions, is cost-effective, and would burned in combustion turbines. Finally, efficiencies of aeroderivative turbines promote the development of technology. the use of clean fuels does not have any range from 32 to 39 percent, while the However, a BSER determination based significant energy or non-air quality efficiencies of industrial frame turbines on the use of NGCC technology could impacts. Based on these factors, the EPA range from 30 to 36 percent. Based on pose challenges for facilities operating has determined that the BSER for multi- these cost uncertainties, we cannot in remote locations and certain fuel-fired combustion turbines is the use conclude that high-efficiency simple industrial facilities. In remote locations, of clean fuels. cycle turbines are the BSER for natural the construction of a NGCC facility is gas-fired non-base load applications at often not practical because it requires D. Achievability of the Final Standards this time. larger capital investments and We are finalizing emission standards The final option that we considered significant staffing for construction and for three subcategories of combustion for the BSER was clean fuels, operation. In contrast, simple cycle turbines. Specifically, units that sell specifically natural gas with a small turbines are cheaper and can be electricity in excess of a threshold based allowance for distillate oil. The use of operated with minimal staffing. Also, on their design efficiency and that burn clean fuels is technically feasible for more than 90 percent natural gas (i.e., non-base load units. Based on available 536 http://www.eia.gov/electricity/data/eia923/. base load natural gas-fired units) will be VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00108 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64617 subject to an output- based standard. supporting tiered emission standards the HRSG to minimize thermal stresses The output-based standard is based on are included in the discussion of non- on pressure vessels and boiler tubes. the performance of existing NGCC units base load natural gas-fired units. We did During these startup periods, significant and takes into account a range of not receive comments on an appropriate CO2 emissions occur, but steam operating conditions, future emission standard for multi-fuel-fired production is not sufficient for the degradation, etc. Units not meeting units. steam turbine generator to produce either the percentage electric sales or electricity. They also stated that a a. Emission standards for Base Load natural gas-use criteria (i.e., non-base similar situation occurs during Natural Gas-Fired Units load natural gas-fired and multi-fuel shutdown when the steam cycle does units, respectively) will be subject to an Many commenters stated that the not generate electricity, but the input-based standard based on the use proposed emission standards did not combustion turbine is still combusting of clean fuels. This section summarizes properly take into account the losses in fuel as it proceeds through the what emission standards we proposed efficiency that occur due to long-term shutdown process. These commenters and related issues we solicited comment degradation over multiple decades, recommended that the EPA could on, describes the comments we received operation at non-base load conditions address these issues by creating a regarding the proposed emission (load cycling, frequent startups and subcategory for NGCC units that cycle standards and our responses to those shutdowns, and part-load operations), and operate at intermediate load. comments, and provides our rationale site-specific factors such as ambient Many commenters said that site- for the final emission standards. conditions and cooling technology, and specific factors can often preclude secondary fuel use (e.g., distillate oil). operators from achieving design 1. Proposed Standards These commenters stated that the EPA efficiencies based on ISO conditions. For large newly constructed, should conduct a more comprehensive These factors include high elevations, modified, and reconstructed stationary analysis that addresses worst-case high ambient temperatures, and cooling combustion turbines (base load rating conditions for each of these factors. system constraints. They stated that greater than 850 MMBtu/h), we They also stated that all of the units local water temperatures can impact proposed an emission standard of 1,000 included in the analysis supporting the condenser operating pressure and heat lb CO2/MWh-g. For small stationary proposal were relatively new and rates. They also said that areas with combustion turbines (base load rating of therefore have experienced limited limited water resources could require 850 MMBtu/h or less), we proposed an degradation. The commenters stated systems that rely on air-cooled emission standard of 1,100 lb CO2/ that, while some degradation in condensers, which cannot achieve MWh-g. We also solicited comment on efficiency can be recovered during thermal efficiencies comparable to a range of 950–1,100 lb CO2/MWh-g for periodic maintenance outages, it is not water-cooled plants. These commenters large stationary combustion turbines always possible or feasible to repair a stated that the final rule should include and a range of 1,000–1,200 lb CO2/ degraded component immediately provisions for addressing site-specific MWh-g for small stationary combustion because repairs often involve extended constraints that preclude individual turbines. outages that must be scheduled well in affected EGUs from achieving the In addition, we solicited comment on advance. They stated that a new unit emissions rates achieved on average by increasing the size distinction between that initially could meet the standard at other sources. large and small stationary combustion base load conditions can experience Some commenters stated that the turbines to 900 MMBtu/h to account for increasing heat rates with age even proposed standards for modified and larger aeroderivative designs; increasing when adhering to the manufacturer’s reconstructed combustion turbines the size distinction to 1,000 MMBtu/h to recommended maintenance program. would foreclose future opportunities for account for future incremental increases Some commenters stated that the operators to undertake projects to in base load ratings; increasing the size proposed standards were derived by restore the performance of both distinction to between 1,300 to 1,800 looking at emissions data from years degraded units subject to the NSPS and MMBtu/h; and eliminating the size with historically low natural gas prices. existing, pre-NSPS units. They said that subcategories altogether. To account for They surmised that the NGCC units it is not possible to bring older potential reduced efficiencies when were taking advantage of these prices by combustion turbines (built prior to the units are not operating at base load, we running at historically high capacity year 2000) up to the efficiency levels of also solicited comment on whether a factors and concluded that the modern units because many newer separate, less stringent standard should efficiencies and CO2 emission rates technological options that deploy higher be established for non-base load underlying the proposed standards were temperatures are not available for pre- combustion turbines. not representative of periods with 2000 combustion turbines. higher natural gas prices. Other Commenters from the power sector 2. Comments commenters said that many NGCC units generally supported increasing the As described previously, we are not are increasingly required to cycle and standards to 1,100 lb CO2/MWh-g and finalizing the size-based subcategories operate at lower capacities (compared to 1,200 lb CO2/MWh-g for the newly that we proposed and instead are the proposal’s baseline) to accommodate constructed large and small turbines, finalizing emission standards for sales- hourly variations in intermittent respectively. They also advocated and fuel-based subcategories. renewable generation. They anticipated finalizing standards for modified and Specifically, we are finalizing emission that this type of generation will reconstructed standards that are 10 standards for three subcategories of increase, requiring NGCC units to start, percent higher than the final standards stationary combustion turbines: base stop, and operate at part load more for new sources because combustion load natural-gas fired units, non-base frequently than in the past, increasing turbines constructed prior to 2000 were load natural gas-fired units and multi- CO2 emissions. not included in the EPA’s analysis. fuel-fired units. The relevant comments Some commenters indicated that, Conversely, some commenters stated concerning the emission standards for during startup, combustion turbines that the proposed standards for the first two subcategories are discussed must be operated at low load for combustion turbines do not reflect the below. Any comments we received extended periods to gradually warm up emission rates that are achievable by VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00109 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 64618 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations modern, efficient NGCC power blocks. 1,450 lb CO2/MWh-g. An air quality MWh-g. Individual unit maximum These commenters stated that the regulator from a state with rapidly emission rates ranged from 898 to 1,175 appropriate standard, consistent with increasing renewable generation lb CO2/MWh-g. Two of the units had a Congressional objectives under CAA supported a limit of 825 lb CO2/MWh- maximum emissions rate equal to or 537 section 111, should be 800 lb CO2/ g for all base load NGCC units; 1,000 lb greater than 1,000 lb CO2/MWh-g. MWh-g based on the performance of the CO2/MWh-g for large intermediate load However, one of the units with a lowest emitters in the CAMD database. NGCC units; 1,100 lb CO2/MWh-g for maximum emission rate above 1,000 lb Some commenters stated that a standard small intermediate load NGCC units. CO2/MWh-g was only selling of 850 lb CO2/MWh-g reflects BSER for This commenter also recommended that approximately 20 percent of its high-capacity factor units because half the EPA set a numerical limit potential electric output (significantly of the NGCC units in the CAMD specifically for peaking units after the below the design-specific percentage database are achieving this level of completion of a peaking unit-specific electric sales threshold) when the emissions. One commenter from the BSER analysis. Several commenters emission rate occurred. If this unit were power sector who operates NGCC power supported tiered standards based on a new unit, the applicable emission plants stated that the final standard for capacity factor. They proposed 825 lb standard would be the heat input-based new large combustion turbines should CO2/MWh-g for base load units (those clean fuels standard, and the unit would be 925 lb CO2/MWh-g. Another operating over 4,000 hours annually), not be out of compliance. Therefore, 16 commenter also supported an emission 875 lb CO2/MWh-g for intermediate and of the 17 existing small NGCC units standard of 925 lb CO2/MWh-g, which load-following units (those operating have demonstrated that an emission rate is consistent with recent BACT between 1,200 and 4,000 hours of 1,000 lb CO2/MWh-g is achievable. In determinations in the state of New York. annually), and 1,100 lb CO2/MWh-g for addition, the six newest units, which Several other commenters stated that a peaking units (those operating less than commenced construction between 2007 reasonable standard for new large 1,200 hours per year). and 2012, all have maximum 12- combustion turbines should be 950 lb operating-month emission rates of less CO2/MWh-g and that the final standard 3. Final Standards than 950 lb CO2/MWh-g. While these for new small combustion turbines a. Newly Constructed Base Load Natural units might not be old enough to have should be 1,000 lb CO2/MWh-g. Gas-Fired Units experienced degradation, their Numerous commenters stated that the maximum emission rates demonstrate In evaluating the achievability of the final standards for new sources should that the final standard of 1,000 lb CO / base load natural gas-fired emission 2 not exceed 1,000 lb CO2/MWh-g for MWh-g includes a significant standard, we focused on three types of either large or small combustion compliance margin for any future data. Specifically, we looked at existing turbines. Other commenters stated that, degradation. because the standards were developed NGCC emission rates, recent PSD permit For large units, the average maximum based on emission rates that are being limits for CO2 emissions, and NGCC 12-operating-month emission rate was design efficiency data and achieved by the majority of existing 895 lb CO2/MWh-g, with individual unit units, the final standards should be the specifications. Based on this analysis, maximum emission rates ranging from we have concluded that an emission same for new, modified, and 751 to 1,334 lb CO2/MWh-g. Twenty- reconstructed units. rate of 1,000 lb CO2/MWh-g is three of the 328 large NGCC units had appropriate for all base load natural gas- maximum 12-operating-month emission b. Emission Standards for Non-Base fired combustion turbines, regardless of rates greater than 1,000 lb CO /MWh-g. Load Natural Gas-Fired Units and Multi- size. 2 Fuel-Fired Units While we do not have precise design Since the standards were proposed, efficiency information for each of these Many commenters stated that the EPA the EPA has expanded the NGCC units, and thus cannot calculate the cannot finalize ‘‘no emission standard’’ emission rate analysis that supported precise percentage electric sales for non-base load units, which the EPA the proposed emission standards to threshold to which each unit would be solicited comment on in the broad include emissions information for subject, it appears that all of the NGCC units that commenced operation applicability approach. They argued emission rates in excess of 1,000 lb CO2/ that this approach was not consistent in 2011, 2012, and 2013, and updated MWh-g occurred during periods when with the definition of ‘‘standard of the emissions data to include emissions electric sales were low and would be performance’’ in CAA section 111(a)(1), through 2014. In our analysis, we below the threshold. Thus, if these units which requires there to be an ‘‘emission evaluated 345 NGCC units with online were new units, they would only have limitation’’ that reflects a ‘‘system of dates ranging from 2000 to 2013. The to comply with the heat input-based emission reduction.’’ Some commenters analysis included emissions data from clean fuels standard. Therefore, recommended that non-base load units 2007 to 2014 as submitted to the EPA’s essentially all existing NGCC units should be subject to work practice CAMD. The average maximum 12- would have been in compliance with standards, such as operating safely with operating-month CO2 emission rate for the final emission standard. We note good air pollution control practices, all NGCC units was 897 lb CO2/MWh- also that there are 51 new NGCC units including CO2 monitoring and reporting g, with individual unit maximums that have started operation since 2010, requirements. Other commenters ranging from 751 to 1,334 lb CO2/MWh- and the average maximum 12-operating- pointed to recent PSD permits that g. month emission rate for these units is include tiered emission limits for the Consistent with our proposed size- 833 lb CO2/MWh-g. Therefore, the final different roles served by combustion based subcategories, we also reviewed emission standard includes a very turbines. They cited BACT limits from the emissions data for small and large significant compliance margin to 1,328 to 1,450 lb CO2/MWh-g for NGCC units separately. For small units, account for any potential future peaking units. One commenter we evaluated emissions data from 17 degradation of large units. supported tiered limits consistent with NGCC units with heat input ratings of recent BACT determinations in the state 850 MMBtu/h or less. These units had 537 For emission standards of 1,000 lb CO2/MWh- of New York, which include limits for an average maximum 12-operating- g and above, the emission standard uses three simple cycle combustion turbines of month CO2 emission rate of 953 lb/ significant figures. See Section X.D. VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00110 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64619 To evaluate degradation further, the to a chemical plant was in the data set. all of the limits except one were still EPA reviewed the emission rate This facility had a permit limit of 1,362 below 1,000 lb CO2/MWh-g. information for the 55 oldest NGCC lb CO2/MWh based only on gross Finally, we also reviewed NGCC units in our data set (i.e., units that electrical output and does not account design efficiency data and specifications came online in 2000 and 2001). for useful thermal output. Therefore, we submitted to Gas Turbine World. According to the commenters, we did not include it in the analysis either. Specifically, we reviewed the reported should expect to see degradation when Finally, we excluded two permits that efficiency data for 88 different 60 Hz reviewing the annual emissions data for did not clearly specify if the output- NGCC units manufactured by Alstom, these turbines because they are 14 to 15 based standard was on a gross or net GE Energy Aeroderivative and Heavy years old. However, we did not see any basis. Duty, Mitsubishi Heavy Industries, Pratt sign of degradation. The CO2 rates for The remaining 28 permit limits were & Whitney, Rolls-Royce, and Siemens these turbines have little standard expressed in lb CO2/MWh or a heat rate Energy. The designs ranged in model deviation between 2007 and 2014. In basis that could be converted to lb CO2/ year from 1977 to 2011, capacities addition, there were many instances MWh. Eight permit limits were based on ranged from 31 to 1,026 MW, and base where the CO2 emission rate of a unit net output, ranging from 774–936 lb load ratings ranged from 236 to 3,551 actually decreased with age. This CO2/MWh-n. The lowest emission limit MMBtu/h. The average reported design indicates that the efficiency of the unit was for a hybrid power plant with a emission rate for these units was 834 lb is increasing, possibly as a result of solar component that could contribute CO2/MWh-n and ranged from 725 to 941 good operating and maintenance up to 50 MW. Twenty permit limits lb CO2/MWh-n. Therefore, our optional procedures or upgrades to equipment were based on gross output, ranging standard of 1,030 lb CO2/MWh-n would that improved efficiency beyond the from 833–1,100 lb CO2/MWh-g. Of these allow for an average compliance margin original design. Based on these findings, 28 permit limits, the only limit in excess of 24 percent, with a range from 10 to we have concluded that our analysis of our final emission standard of 1,000 42 percent, over the design rate. Ninety- adequately accounts for potential lb CO2/MWh-g is for a relatively small five percent of designs would have a degradation. NGCC unit (base load rating of 366 compliance margin of 13 percent or We also evaluated the impact of MMBtu/h) that commenced more, the top end of the range of elevation, ambient temperature, cooling construction prior to the proposal and compliance margins determined to be type, and operating conditions (startups, thus will not be subject to the appropriate in the PSD permits we shutdowns, and average run time per requirements of this final rule. reviewed. start) because commenters indicated Each of the permit limits discussed Because some commenters were that these could affect a unit’s ability to above that is 1,000 lb CO2/MWh or less concerned that smaller NGCC units will achieve the standard. We saw little includes all periods of operation, not be able to achieve the emission correlation between elevation or including startup, shutdown, and standard, we specifically considered the ambient temperature and emission rate. malfunction events. In addition, each design rates for smaller units. For the 52 In addition, any correlation was permit limit was set after back up and small units (base load rating of 850 relatively small and would have an additional fuel use were taken into MMBtu/h or less), the average design insignificant impact on the ability of a consideration. While some permits emission rate was 865 lb CO2/MWh and unit to achieve the final standard. We restrict fuel use to only natural gas, ranged from 796 to 941 lb CO2/MWh-n. identified 32 large NGCC units with dry others allow limited usage (duration and Therefore, our optional standard of cooling towers. The average maximum type) of back up and other fuels. For 1,030 lb CO2/MWh-n would allow for an 12-operating-month emission rate for example, the Pioneer Valley Energy average compliance margin of 19 this group of units was 875 lb CO2/ Center has unrestricted use of natural percent, with a range of 10 to 29 MWh. This rate was actually lower than gas, but can burn ultra-low sulfur diesel percent, over the design rate. Ninety- the average rate for the large NGCC (ULSD) for up to 1,440 hours per 12- five percent of small NGCC designs group as a whole. Based on these month period. This permit requires the would have a compliance margin of 13 findings, we have concluded that the unit to comply with a limit of 895 lb percent or more. final emission standard will not limit CO2/MWh-n even when burning up to We further refined our analysis by the use of dry cooling technologies. 16 percent distillate oil. Each permit only considering the most efficient Finally, the EPA evaluated the impact of limit takes into account the mode of design for a given combustion turbine run time per start, average duty cycle, operation for the combustion turbine. engine. For example, GE Energy and number of starts on emission rates. For example, the permit for the Lower Aeroderivative offers four design While these factors do influence Colorado River Authority’s Ferguson options for its LM2500 model-type, all emission rates, the non-base load plant evaluated emission limits for the with a rating of approximately 45 MW. natural gas-fired subcategory inherently plant at 50, 75, and 100 percent gross The design emission rates for these addresses efficiency issues related to load. The emission limit of 918 lb CO2/ various options range from 827 to 914 operating conditions. MWh-n accounts for the unit’s expected lb CO2/MWh-n. When only the most In addition to evaluating existing operation at 50 percent gross load. For efficient models for a particular NGCC emissions data, the EPA reviewed NGCC units with duct burners on their combustion turbine engine design are the CO2 emission limits included in HRSGs, the permit limits account for the considered, all NGCC models have over PSD preconstruction permits issued hours of operation with duct burners a 13 percent compliance margin. In since January 1, 2011. We evaluated all firing. Finally, most of these permits other words, developers of new base permit limits over an annual period. In include compliance margins to account load natural gas-fired combustion total, we identified 31 major source PSD for efficiency losses due to degradation turbines concerned about the permits with 39 discrete limits on CO2 and other factors (e.g., actual operating achievability of the final standard have emissions. Eight of the limits were parameters, site-specific design multiple more efficient options offered expressed in terms of lb/h or tons per considerations, and the use of back up by the same manufacturer. Therefore, year, so we did not include them in the fuel). In total, these compliance margins we have concluded that the final analysis. In addition, one CHP unit that result in a 10 to 13 percent increase in emission standard allows sufficient generates electricity and supplies steam the permitted CO2 emission limits, yet flexibility for end users to select an VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00111 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 64620 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations NGCC design appropriate for their (3) a combustion turbine exhaust system compressors with more advanced specific requirements. that is ‘‘matched’’ to the steam cycle for compressor technologies, potentially After considering these three sources maximum efficiency. In order for an improving the combustion turbine’s of information—actual NGCC emission existing NGCC unit to trigger the efficiency by an additional 3.8 percent. rate data, PSD permit limits for NGCC reconstruction provisions, the unit Thus, the total potential CO2 emissions facilities, and NGCC design would have to essentially be entirely reductions for just the combustion information—we have concluded that a rebuilt. This would involve extensive turbine portion of a combined cycle unit standard of 1,000 lb CO2/MWh is both upgrades to both the combustion turbine is 6.6 percent. achievable and appropriate for newly engine and the HRSG. Therefore, a In addition to upgrades to the constructed base load natural gas-fired reconstructed NGCC unit will be able to combustion turbine engine, an operator combustion turbines. While we maximize the efficiency of the turbine reconstructing a NGCC unit will have anticipate that the large majority of new engine and the steam cycle and match the opportunity to improve the NGCC units will operate well below this the two for maximum efficiency. efficiency of the HRSG and steam cycle. emission rate, this standard provides According to comments submitted in For example, a steam turbine flexibility for developers to take into response to the proposal for existing manufacturer identified three retrofit account site-specific conditions (e.g., sources under CAA section 111(d), there technologies available for reducing the ambient conditions and cooling system), are various options available to improve CO2 emissions rate of existing steam operating characteristics (e.g., part-load the efficiency of existing combustion turbines by 1.5 to 3 percent: (1) Steam- operation and frequent starting and turbines. One combustion turbine path upgrades can minimize stopping), and reduced efficiency due to aerodynamic and steam leakage losses; manufacturer provided comments degradation. The standard also (2) replacement of the existing high describing specific technology upgrades accommodates the full size range of pressure turbine stages with state-of-the- for the compressor, combustor, and gas turbines. art stages capable of extracting more turbine components. This manufacturer We also expect multiple technology energy from the same steam supply; and stated that operators of existing turbines developments to further increase the (3) replacement of low-pressure turbine can replace older internal components performance of new base load natural stages with larger diameter components along the gas path with state-of-the-art gas-fired stationary combustion that extract additional energy and that components that have higher turbines. Vendors continue to improve reduce velocities, wear, and corrosion. the single cycle efficiency of aerodynamic efficiencies and improved In addition, an operator combustion turbines. The use of more seal designs. These gas-path reconstructing a NGCC unit could efficient combustion turbine engines enhancements enable existing sources to upgrade the entire steam cycle. For improves the overall efficiency of NGCC both improve the efficiency of the example, combined cycle units facilities. In addition, existing smaller turbine engine and improve the systems originally constructed with only a single NGCC facilities were likely designed used for cooling the metal parts along pressure level can be upgraded to also using single or dual pressure HRSGs the hot-gas path to allow existing include second and third pressure without a reheat cycle. New designs can systems to achieve higher operating levels. Studies 538 539 540 show that incorporate three pressure steam temperatures. In total, the manufacturer converting a single pressure HRSG with generators with a reheat cycle to stated that utilities deploying these gas- steam reheat to a double pressure improve the overall efficiency of the path improvements on reconstructed configuration with steam reheat can NGCC facility. Finally, additional industrial frame combustion turbines reduce the CO2 emission rate of a NGCC technologies to reduce emission rates with nominal output ratings of 170 to unit by 1.5 to 1.7 percent. These same for new combustion turbines include 180 MW can increase their output by 10 studies show that converting from a CHP and integrated non-emitting MW while reducing CO2 emissions by single pressure configuration with technologies. For example, an NGCC more than 2.6 percent compared to reheat to a triple pressure configuration unit that is designed as a CHP unit baseline. In addition to gas-path and with reheat can yield a 1.8 to 2 percent where ten percent of the overall output software improvements, the reduction in the CO2 emission rate. is useful thermal output would have an manufacturer stated that the newest Similarly, units constructed with only a emission rate approximately five low-NOX combustor designs can be double pressure configuration without percent less than an electric-only NGCC. retrofitted on modified and reheat can obtain a 0.4 percent In sum, we believe that our final reconstructed turbines to achieve lower reduction by adding a reheat cycle or a emission standards of 1,000 lb CO2/ NOX emissions, which improves 0.9 percent reduction by converting to a MWh-g and 1,030 lb CO2/MW-n are not turndown (i.e., to enable stable triple pressure configuration and adding only readily achievable, but likely operations at lower loads compared to a reheat cycle. Existing NGCC turbines conservative. the lowest stable load achievable at that convert to these advanced HRSG baseline conditions) and efficiencies configurations and that deploy the b. Reconstructed Base Load Natural Gas- across all load conditions. The previously discussed combustion Fired Units manufacturer indicated that operators of turbine and steam turbine upgrades can We disagree with commenters that existing combustion turbines deploying stated that reconstructed combustion both state-of-the-art gas-path and 538 ‘‘Exergetic and Economic Evaluation of the turbines will not be able to achieve the software upgrades and combustor Effects of HRSG Configurations on the Performance proposed emission standards. For the upgrades can increase output on frame- of Combined Cycle Power Plants.’’ M. Mansouri, et al. Energy Conversion and Management 58:47–58, reasons listed below, we have style turbines with nominal output 2012. concluded that an existing base load ratings of 170 to 180 MW by 14 MW, 539 ‘‘Combined Cycle Power Plant Performance natural-gas fired unit that reconstructs while reducing CO2 emissions by 2.8 Analyses Based on Single-Pressure and can achieve an emission rate of 1,000 lb percent. In addition to the preceding Multipressure Heat Recovery Steam Generator.’’ M. CO /MWh-g, regardless of its size. upgrades, the manufacturer stated that Rahim, Journal of Energy Engineering, 138:136–145, 2 2012. Highly efficient NGCC units include existing combustion turbines can 540 ‘‘Thermodynamic Evaluation of Combined (1) an efficient combustion turbine achieve the largest efficiency Cycle Plants.’’ N. Woudstras et al. Energy engine, (2) an efficient steam cycle, and improvements by upgrading existing Conversion and Management 51:1099–1110, 2010. VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00112 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64621 realize CO2 emission rate reductions minor, the compliance burden is also a combustion turbine that burns 80 ranging from 6 to 10 percent, depending minimal. Owners and operators of non- percent natural gas and 20 percent on their baseline design and condition. base load natural gas-fired combustion distillate oil would be subject to an Based on the available options to turbines burning fuels with consistent emission standard of 130 lb CO2/MMBtu improve the efficiency of existing NGCC chemical compositions that meet the (rounded to two significant figures), units and the fact that the vast majority clean fuels requirement (e.g., natural which is equivalent to the actual of existing NGCC units are already gas, ethane, ethylene, propane, naphtha, emission rate of a unit burning this achieving emission rates of 1,000 lb jet fuel kerosene, fuel oils No. 1 and 2, combination of fuels. On the other hand, CO2/MWh-g or less, we have concluded and biodiesel) will only need to a combustion turbine that burns 100 that all reconstructed NGCC units can maintain records that they burned these percent residual oil would be subject to achieve this emission rate. fuels in the combustion turbine. No an emission standard of 160 lb CO2/ Finally, we note that an owner or additional recordkeeping or reporting MMBtu, but would have a higher actual operator that is considering will be required. Owners and operators emission rate, and would thus be out of reconstructing an existing simple cycle burning fuels with higher CO2 emission compliance. In this way, the standard turbine should decide how they wish to rates and/or chemical compositions that will restrict higher carbon fuels from operate that turbine in the future. If they vary (e.g., residual oil, non-jet fuel being burned in multi-fuel-fired units, anticipate operating above the kerosene, landfill gas) will have to but will be readily achievable by units percentage electric sales threshold, then follow the procedures in part 98 of this burning clean fuels. they should install a HRSG and steam part to determine the average CO2 According to information submitted turbine and convert to a NGCC power emission rate of the fuels burned during to the EIA, the primary, non-natural gas block in accordance with our the applicable 12-operating-month fuels used by combustion turbines today determination that NGCC is the BSER compliance period and submit quarterly for the production of electricity should for base load applications. If they intend reports to verify that they are in all meet our definition of a clean fuel. to operate the turbine below the compliance with the required emission Thus, while the emission reductions percentage electric sales threshold, standard. that will result from restricting the use however, then the clean fuels standard, of fuels with higher CO2 emission rates described below, will apply. d. Newly Constructed and is minor, the compliance burden is also Reconstructed Multi-Fuel-Fired Units minimal. Owners and operators of c. Newly Constructed and We also are finalizing an input-based multi-fuel-fired combustion turbines Reconstructed Non-Base Load Natural standard based on the use of clean fuels, burning fuels with consistent chemical Gas-Fired Units as opposed to an output-based standard, compositions that meet the clean fuels The EPA agrees with the commenters for multi-fuel units for several reasons. requirement (e.g., natural gas, ethylene, who stated that ‘‘no emission limit’’ Specifically, we do not currently have propane, naphtha, jet fuel kerosene, fuel would be inconsistent with the continuous CO2 emissions data for oils No. 1 and 2, and biodiesel) will requirements of CAA 111(a)(1). We multi-fuel-fired units, we have not only need to maintain records that they therefore are finalizing an input-based evaluated the potential efficiency burned these fuels in the combustion standard based on the use of clean fuels impacts of different fuels, and the range turbine. No additional recordkeeping or for non-base load natural gas-fired of carbon content of non-natural gas reporting will be required. Owners and combustion turbines in recognition that fuels complicates establishing an operators burning fuels with higher CO2 efficiency can be reduced due to appropriate output-based standard. emission rates and/or chemical operation at low loads, cycling, and Based on this lack of data, we have compositions that vary (e.g., residual frequent startups. The EPA has concluded that we cannot establish an oil, non-jet fuel kerosene, landfill gas) concluded that, at this time, we do not output-based emission standard for will have to follow the procedures in have sufficient information to set a multi-fuel-fired combustion turbines at part 98 of this part to determine the meaningful output-based standard for this time. average CO2 emission rate of the fuels non-base load natural gas-fired The input-based emissions standard burned during the applicable 12- combustion turbines. The input-based for this subcategory is based on the use operating-month compliance period and standard requires non-base load units to of clean fuels. The use of clean fuels submit quarterly reports to verify that burn fuels with an average emission rate will ensure that newly constructed and they are in compliance with the of 120 lb CO2/MMBtu or less. This reconstructed combustion turbines required emission standard. standard is readily achievable because minimize CO2 emissions during all e. Modified Units the CO2 emission rate of natural gas is periods of operation by limiting the use 117 lb CO2/MMBtu. The most common of fuels with higher CO2 emission rates. The EPA is not finalizing the back up fuel is distillate oil, which has To accurately represent the BSER and proposed emission standards for a CO2 emission rate of 163 lb CO2/ limit the ability of units to co-fire higher stationary combustion turbines that MMBtu. A non-base load natural gas- CO2 emitting fuels with natural gas, we conduct modifications. As explained in fired combustion turbine burning 9 have concluded that it is necessary to Section XV below, we are withdrawing percent distillate oil and 91 percent use an equation based on the heat input the June 2014 proposal with respect to natural gas has an emission rate of 121 from natural gas to determine the these sources. We received a significant lb CO2/MMBtu, which rounds to 120 lb applicable emission standard. The 12- number of comments asserting that CO2/MMBtu using two significant operating-month standard will vary modified combustion turbines could not digits. Therefore, the vast majority of from 120 lb CO2/MMBtu to 160 lb CO2/ meet the proposed emission standards owners and operators of non-base load MMBtu depending on the fraction of of 1,000 lb/MWh-g for large turbines natural gas-fired combustion turbines heat input from natural gas. The and 1,100 lb/MWh-g for small turbines. will be able to achieve the standard standard will be calculated by adding For the reasons explained in Section using business-as-usual fuels. the product of the percent of heat input IX.B.1 above, we have decided not to While the emission reductions that from natural gas and 120 with the subcategorize combustion turbines will result from restricting the use of product of the heat input from non- based on size for a number of reasons fuels with higher CO2 emission rates is natural gas fuels and 160. For example, and are setting a single standard of VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00113 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 64622 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 1,000 lb/MWh-g for all base load natural issuing final standards for those sources Specifically, startup and shutdown gas-fired turbines instead. While we are at this time. See Section XV below. We periods are included in the compliance confident that all new and reconstructed note that the effect of this withdrawal is calculation as periods of partial load. units will be able to achieve this that modified combustion turbines will The final method to calculate standard, we are less confident that all continue to be existing sources subject compliance is to sum the emissions for smaller combustion turbines that to section 111(d).541 all operating hours and to divide that undertake a modification, specifically value by the sum of the electric energy those that were constructed prior to X. Summary of Other Final output (and useful thermal energy 2000, will be able to do so. Until we Requirements for Newly Constructed, output, where applicable for affected have the opportunity to further Modified, and Reconstructed Fossil CHP EGUs), over a rolling 12-operating- investigate the full range of Fuel-Fired Electric Utility Steam month period. In their compliance modifications that turbine owners and Generating Units and Stationary determinations, sources must operators might undertake, we consider Combustion Turbines incorporate emissions from all periods, it premature to finalize emission This section describes the final including startup or shutdown, during standards for these sources. action’s requirements regarding startup, which fuel is combusted and emissions Combustion turbines have unique shutdown, and malfunction; continuous are being monitored, in addition to all characteristics that make determining an monitoring; emissions performance power produced over the periods of appropriate emission standard for testing; continuous compliance; and emissions measurements. As explained modified sources a more challenging notification, recordkeeping, and in Section V.J.1, given that the duration task than for coal-fired boilers. For reporting for newly constructed, of startup or shutdown periods is example, each combustion turbine modified, and reconstructed affected expected to be small relative to the engine has a specific corresponding steam generating units and combustion duration of periods of normal operation combustor. The development of more turbines. We also explain final decisions and that the fraction of power generated efficient combustor upgrades for regarding several of these requirements. during periods of startup or shutdown is existing turbine designs typically expected to be very small, the impact of requires manufacturers to expend A. Startup, Shutdown, and Malfunction these periods on the total average over considerable resources. Consequently, Requirements a 12-operating-month period is expected not all manufacturers offer combustor In its 2008 decision in Sierra Club v. to be minimal. upgrades for smaller or older designs EPA, 551 F.3d 1019 (D.C. Cir. 2008), the Periods of startup, normal operations, because it would be difficult to recoup D.C. Circuit vacated portions of two and shutdown are all predictable and their investment. In contrast, efficiency provisions in the EPA’s CAA section routine aspects of a source’s operations. upgrades for boilers can generally be 112 regulations governing the emissions Malfunctions, in contrast, are neither installed regardless of the specific of hazardous air pollutants (HAP) predictable nor routine. Instead they boiler’s characteristics. during periods of startup, shutdown, are, by definition sudden, infrequent In addition, natural gas has the lowest and malfunction (SSM). Specifically, and not reasonably preventable failures CO2 emission rate (in terms of lb CO2/ the Court vacated the SSM exemption of emissions control, process or MMBtu) of any fossil fuel. As a result, contained in 40 CFR 63.6(f)(1) and 40 monitoring equipment. (40 CFR 60.2). an owner or operator that adds the CFR 63.6(h)(1), holding that under The EPA interprets CAA section 111 as ability to burn a back up fuel, such as section 302(k) of the CAA, emissions not requiring emissions that occur distillate oil, to an existing turbine standards or limitations must be during periods of malfunction to be would likely trigger an NSPS continuous in nature and that the SSM factored into development of section modification. This is a relatively low- exemption violates the CAA’s 111 standards. Nothing in CAA section capital-cost upgrade that would requirement that some CAA section 112 111 or in case law requires that the EPA significantly increase a unit’s potential standards apply continuously. consider malfunctions when hourly emission rate, even though the Consistent with Sierra Club v. EPA, determining what standards of annual emissions increase would be the EPA has established standards in performance reflect the degree of relatively minor because operating this rule that apply at all times. In emission limitation achievable through permits generally limit the amount of establishing the standards in this rule, ‘‘the application of the best system of distillate oil that a unit can burn. We the EPA has taken into account startup emission reduction’’ that the EPA need to conduct additional analysis to and shutdown periods and, for the determines is adequately demonstrated. determine an appropriate emission reasons explained below as well as in While the EPA accounts for variability standard for units that undertake this Section V.J.1 above, has not established in setting emissions standards, nothing type of modification, which does not alternate standards for those periods. in CAA section 111 requires the agency involve any of the combustion turbine to consider malfunctions as part of that components that impact efficiency. 541 As discussed above in Section VI.A of this analysis. A malfunction should not be To be clear, the EPA is not reaching preamble, a modified source that is not covered by treated in the same manner as the type a final decision that modifications a final or pending proposed standard continues to of variation in performance that occurs should be subject to different be an ‘‘existing source’’ and so will be covered by during routine operations of a source. A requirements under section 111(d). Under the requirements than we are finalizing in definition of ‘‘existing source’’ in section 111(a)(6), malfunction is a failure of the source to this rule for new and reconstructed an existing source is any source that is not a new perform in a ‘‘normal or usual manner’’ sources. We have made no decisions, source. Under the definition of ‘‘new source’’ in and no statutory language compels the and this matter is not concluded. We section 111(a)(2), a modified source is a new source EPA to consider such events in setting only if the modification occurs after the publication plan to continue to gather information, of regulations (or proposed regulations, if earlier) CAA section 111 standards of consider the options for modifications, that will be applicable to that source. Because we performance. and develop a new proposal for are not finalizing regulations with respect to Further, accounting for malfunctions modifications in the future. Therefore, modified steam turbines, and are withdrawing the in setting emission standards would be proposal with respect to such sources, there are the EPA is withdrawing the proposed neither final regulations nor pending proposed difficult, if not impossible, given the standards for all combustion turbines regulations which will be applicable to such myriad different types of malfunctions that conduct modifications and is not modifications. that can occur across all sources in the VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00114 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64623 category and given the difficulties that period are not likely to result in a approach is adequate); but see Marathon associated with predicting or accounting violation of the standard. Oil Co. v. EPA, 564 F.2d 1253, 1272–73 for the frequency, degree, and duration In the unlikely event that a source (9th Cir. 1977) (requiring a more of various malfunctions that might fails to comply with the applicable CAA formalized approach to consideration of occur. As such, the performance of units section 111 standards as a result of a ‘‘upsets beyond the control of the permit that are malfunctioning is not malfunction event, the EPA would holder’’). Under the EPA’s regulatory ‘‘reasonably’’ foreseeable. See, e.g., determine an appropriate response affirmative defense provisions, if a Sierra Club v. EPA, 167 F.3d 658, 662 based on, among other things, the good source could demonstrate in a judicial (D.C. Cir. 1999) (‘‘The EPA typically has faith efforts of the source to minimize or administrative proceeding that it had wide latitude in determining the extent emissions during malfunction periods, met the requirements of the affirmative of data-gathering necessary to solve a including preventative and corrective defense in the regulation, civil penalties problem. We generally defer to an actions, as well as root cause analyses would not be assessed. Recently, the agency’s decision to proceed on the to ascertain and rectify excess U.S. Court of Appeals for the District of basis of imperfect scientific information, emissions. The EPA would also Columbia Circuit vacated an affirmative rather than to ‘invest the resources to consider whether the source’s failure to defense in one of the EPA’s CAA section conduct the perfect study.’ ’’) See also, comply with the CAA section 111 112 regulations. NRDC v. EPA, 749 F.3d Weyerhaeuser v Costle, 590 F.2d 1011, standard was, in fact, sudden, 1055 (D.C. Cir., 2014) (vacating 1058 (D.C. Cir. 1978) (‘‘In the nature of infrequent, not reasonably preventable affirmative defense provisions in CAA things, no general limit, individual and was not instead caused in part by section 112 rule establishing emission permit, or even any upset provision can poor maintenance or careless operation. standards for Portland cement kilns). anticipate all upset situations. After a 40 CFR 60.2 (definition of malfunction). The court found that the EPA lacked certain point, the transgression of If the EPA determines in a particular authority to establish an affirmative regulatory limits caused by case that an enforcement action against defense for private civil suits and held ‘uncontrollable acts of third parties,’ a source for violation of an emission that under the CAA, the authority to such as strikes, sabotage, operator standard is warranted, the source can determine civil penalty amounts in such intoxication or insanity, and a variety of raise any and all defenses in that cases lies exclusively with the courts, other eventualities, must be a matter for enforcement action and the federal not the EPA. Specifically, the Court the administrative exercise of case-by- district court will determine what, if found: ‘‘As the language of the statute case enforcement discretion, not for any, relief is appropriate. The same is makes clear, the courts determine, on a specification in advance by true for citizen enforcement actions. case-by-case basis, whether civil regulation.’’). In addition, emissions Similarly, the presiding officer in an penalties are ‘appropriate.’’’ See NRDC administrative proceeding can consider during a malfunction event can be at 1063 (‘‘[U]nder this statute, deciding any defense raised and determine significantly higher than emissions at whether penalties are ‘appropriate’ in a whether administrative penalties are any other time of source operation. For given private civil suit is a job for the appropriate. 542 example, if an air pollution control In summary, the EPA interpretation of courts, not EPA.’’). In light of NRDC, device with 99 percent removal goes off- the CAA and, in particular, CAA section the EPA is not including a regulatory line as a result of a malfunction (as 111 is reasonable and encourages affirmative defense provision in this might happen if, for example, the bags practices that will avoid malfunctions. final rule. As explained above, if a in a baghouse catch fire) and the Administrative and judicial procedures source is unable to comply with emission unit is a steady state type unit for addressing exceedances of the emissions standards as a result of a that would take days to shut down, the standards fully recognize that violations malfunction, the EPA may use its case- source would go from 99 percent control may occur despite good faith efforts to by-case enforcement discretion to to zero control until the control device comply and can accommodate those provide flexibility, as appropriate. was repaired. The source’s emissions situations. Further, as the D.C. Circuit recognized, during the malfunction would be 100 In the January 2014 proposal for in an EPA or citizen enforcement action, times higher than during normal newly constructed EGUs, the EPA had the court has the discretion to consider operations. As such, the emissions over proposed to include an affirmative any defense raised and determine a 4-day malfunction period would defense to civil penalties for violations whether penalties are appropriate. Cf. exceed the annual emissions of the caused by malfunctions in an effort to NRDC, at 1064 (arguments that source during normal operations. As create a system that incorporates some violations were caused by unavoidable this example illustrates, accounting for flexibility, recognizing that there is a technology failure can be made to the malfunctions could lead to standards tension, inherent in many types of air courts in future civil cases when the that are not reflective of (and regulation, to ensure adequate issue arises). The same is true for the significantly less stringent than) levels compliance while simultaneously presiding officer in EPA administrative that are achieved by a well-performing, recognizing that despite the most enforcement actions.543 non-malfunctioning source. It is diligent of efforts, emission standards reasonable to interpret CAA section 111 may be violated under circumstances 542 The court’s reasoning in NRDC focuses on to avoid such a result. The EPA’s civil judicial actions. The court noted that ‘‘EPA’s entirely beyond the control of the ability to determine whether penalties should be approach to malfunctions is consistent source. Although the EPA recognized assessed for Clean Air Act violations extends only with CAA section 111 and is a that its case-by-case enforcement to administrative penalties, not to civil penalties reasonable interpretation of the statute. discretion provides sufficient flexibility imposed by a court.’’ Id. 543 Although the NRDC case does not address the Given that compliance with the in these circumstances, it included the EPA’s authority to establish an affirmative defense emission standard is determined on a affirmative defense to provide a more to penalties that is available in administrative 12-operating-month rolling average formalized approach and more enforcement actions, the EPA is not including such basis, the impact of periods of regulatory clarity. See Weyerhaeuser Co. an affirmative defense in the final rule. As explained above, such an affirmative defense is not malfunctions on the total average over a v. Costle, 590 F.2d 1011, 1057–58 (D.C. necessary. Moreover, assessment of penalties for 12-operating-month period is expected Cir. 1978) (holding that an informal violations caused by malfunctions in administrative to be minimal. Thus, malfunctions over case-by-case enforcement discretion Continued VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00115 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 64624 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations B. Continuous Monitoring Requirements day window of time allotted under 40 operating hours’’ (as defined in 40 CFR The majority of comments received on CFR 75.4(b), and are required to meet 72.2). Then, if compliance with the the proposal supported the EPA’s use of the applicable on-going quality applicable emission limit is attained at existing monitoring requirements under assurance procedures in appendices B the common stack, each EGU sharing the Acid Rain Program, which are and D of part 75. the stack will be in compliance with the The rule requires all valid data CO2 emissions limit. contained in 40 CFR part 75 • requirements. In response to this, the collected and recorded by the If the operator is required to (or EPA is finalizing monitoring monitoring systems (including data elects to) determine compliance using requirements that incorporate and recorded during startup, shutdown, and CEMS and the effluent from the EGU reference the part 75 monitoring malfunction) to be used in assessing discharges to the atmosphere through compliance. Failure to collect and multiple stacks (or, if the effluent is fed requirements for the majority of the CO2 and energy output monitoring record required data is a violation of the to a stack through multiple ducts and is requirements while ensuring accuracy monitoring requirements, except for monitored in the ducts), then and stringency required under the periods of monitoring system monitoring the hourly CO2 mass program. malfunctions, repairs associated with emission rate and the ‘‘stack operating This final rule requires owners or monitoring system malfunctions, and time’’ at each stack or duct separately is operators of EGUs that combust solid required monitoring system quality required. In this case, compliance with fossil fuel to install, certify, maintain, assurance or quality control activities the applicable emission limit is and operate continuous emission that temporarily interrupt the determined by summing the CO2 mass monitoring systems (CEMS) to measure measurement of stack emissions (e.g., emissions measured at the individual calibration error tests, linearity checks, stacks or ducts and dividing by the total CO2 concentration, stack gas flow rate, and (if needed) stack gas moisture and required zero and span gross output for the unit. The rule requires 95 percent of the content in accordance with 40 CFR part adjustments). The rule requires only those operating operating hours in each compliance 75, in order to determine hourly CO 2 hours in which valid data are collected period (including the compliance mass emissions rates (tons/hr). The rule allows owners or operators and recorded for all of the parameters in periods for the intermediate emission of affected EGUs that burn exclusively the CO2 mass emission rate equation to limits) to be valid hours, i.e., operating gaseous or liquid fuels to install fuel be used for calculating compliance with hours in which quality-assured data are flow meters as an alternative to CEMS applicable emission limits. Additionally collected and recorded for all of the for EGUs using CO2 CEMS, only parameters used to calculate CO2 mass and to calculate the hourly CO2 mass emissions rates using Equation G–4 in unadjusted stack gas flow rate values emissions. EGU owners or operators should be used in the emissions have the option to use back up appendix G of part 75. To implement calculations. In this rule, part 75 bias monitoring systems, as provided in 40 this option, hourly measurements of adjustment factors (BAFs) should not be CFR 75.10(e) and 75.20(d), to help meet fuel flow rate and periodic applied to the flow rate data. These this data capture requirement. This determinations of the gross calorific restrictions on the use of part 75 data for requirement is separate from the value (GCV) of the fuel are also part 60 compliance are consistent with requirement for a source to demonstrate required, in accordance with appendix previous NSPS regulations and compliance with an applicable emission D of part 75. In addition to requiring monitoring of revisions. Additionally if an affected standard. When demonstrating EGU combusts natural gas and/or fuel compliance with an emission standard the CO2 mass emission rate, the rule oil and the CO2 mass emissions rate are the calculation must use all valid data requires EGU owners or operators to measured using Equation G–4 in to calculate a compliance average even monitor the hourly unit operating time appendix G of part 75, then if the percent of valid hours recorded in and ‘‘gross output’’, expressed in determination of site-specific carbon- the period is less than the 95 percent megawatt hours (MWh). The gross based F-factors using Equation F–7b in requirement. output includes electrical output plus section 3.3.6 of appendix F of part 75 is any mechanical output, plus 75 percent allowed, and use of these F values in C. Emissions Performance Testing of any useful thermal output. c the emissions calculations instead of Requirements The rule requires EGU owners or using the default F values in the Similarly to the comments received operators to prepare and submit a c Equation G–4 nomenclature is also on monitoring for the proposal, monitoring plan that includes both allowed. commenters in general supported the electronic and hard copy components, This final rule includes the following use of current testing requirements in accordance with 40 CFR 75.53(g) and special compliance provisions for units required under the Acid Rain Program (h). The electronic portion of the with common stack or multiple stack 40 CFR part 75 requirements. Thus the monitoring plan should be submitted to configurations; these provisions are EPA is finalizing requirements for the EPA’s CAMD using the Emissions consistent with 40 CFR 60.13(g): performance testing as consistent with Collection and Monitoring Plan System • If two or more EGUs share a part 75 requirements where appropriate (ECMPS) Client Tool. The hard copy common exhaust stack, are subject to to ensure the quality and accuracy of portion of the plan should be sent to the the same emission limit, and the data and measurements as required by applicable state and EPA Regional operator is required to (or elects to) the final rule. office. Further, all monitoring systems determine compliance using CEMS, In accordance with 40 CFR 75.64(a), used to determine the CO2 mass then monitoring the hourly CO2 mass the final rule requires an EGU owner or emission rates have to be certified emission rate at the common stack operator to begin reporting emissions according to 40 CFR 75.20 and section instead of monitoring each EGU data when monitoring system 6 of part 75, appendix A within the 180- separately is allowed. If this option is certification is completed or when the chosen, the hourly gross electrical load 180-day window in 40 CFR 75.4(b) proceedings and judicial proceedings should be consistent. Cf. CAA section 113(e) (requiring both (or steam load) is the sum of the hourly allotted for initial certification of the the Administrator and the court to take specified loads for the individual EGUs and the monitoring systems expires (whichever criteria into account when assessing penalties). operating time is expressed as ‘‘stack date is earlier). For EGUs subject to the VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00116 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64625 1,400 lb CO2/MWh-g) emission because an actual emission rate of to require the use of three significant standard, the initial performance test 1,049.9 lb CO2/MWh rounds to 1,000 lb digits when completing compliance consists of the first 12 operating months of CO2 per MWh when only two calculations resulting in numerical of data, starting with the month in significant figures are required in the values larger than 1,000. This is which emissions are first required to be final step of compliance calculations. particularly important when reported. The initial 12-operating-month Commenters also suggested that the considering the relatively small compliance period begins with the first emission limits be written in scientific emission rate changes that may be month of the first calendar year of EGU notation (e.g., 1.10 x 10¥3 lb CO2/ required for compliance with the unit- operation in which the facility exceeds MWh) to clarify the number of specific emission standards being the capacity factor applicability significant digits that should be used finalized for modified steam generating threshold. when evaluating compliance. Other and IGCC units because a rounding error The traditional 3-run performance commenters suggested that the final step of 5 percent may be larger than the tests (i.e., stack tests) described in 40 in compliance calculations should percent difference between the affected CFR 60.8 are not required for this rule. reflect rounding the emission rate to the unit’s historically best emission rate and Following the initial compliance nearest whole number using the ASTM the emission rate immediately determination, the emission standard is rounding convention (ASTM E29). preceding the modification. met on a 12-operating-month rolling The General Provisions of Part 60 The final rule requires rounding of average basis. specify the rounding conventions for emission rates with numerical values compliance calculations at 40 CFR greater than or equal to 1,000 to three D. Continuous Compliance 60.13(h)(3) including the provision that significant figures and rounding of rates Requirements ‘‘after conversion into units of the with numerical values less than 1,000 to Commenters supported the use of a standard, the data may be rounded to two significant figures. 12-operating-month rolling average for the same number of significant digits E. Notification, Recordkeeping, and the compliance period for the final used in the applicable subpart to specify Reporting Requirements standards. In response, this final rule the emission limit.’’ specifies that compliance with the 1,400 The final rule requires that the 12- Commenters supported the lb CO2/MWh-g emission limit is operating-month rolling average coordination of notification, determined on a 12-operating-month emission rate must be rounded to three recordkeeping, and reporting required rolling average basis, updated after each significant figures if the applicable under this rule in conjunction with the new operating month. For each 12- emissions standard is greater than or requirements already in place under operating-month compliance period, equal to 1,000 (e.g., an actual emission part 75, so the EPA has made the quality-assured data from the certified rate of 1,004.9 lb CO2/MWh is rounded requirements as efficient and Part 75 monitoring systems is used to 1,000 lb CO2/MWh); for standards of streamlined as possible with the current together with the gross output over that 1000 or less, the final rule requires requirements under part 75. The final period of time to calculate the average rounding the actual emission rate to two rule requires an EGU owner or operator CO2 mass emissions rate. significant figures (e.g., an actual to comply with the applicable The rule specifies that the first emission rate of 454.9 kg CO2/MWh is notification requirements in 40 CFR operating month included in the initial rounded to 450 kg CO2/MWh). 75.61, 40 CFR 60.7(a)(1) and (a)(3), and 12-operating-month compliance period Historically, many of the emissions 40 CFR 60.19. The rule also requires the is the month in which reporting of limits under part 60 have been applicable recordkeeping requirements emissions data is required to begin expressed to two significant digits (e.g., in subpart F of part 75 to be met. For under 40 CFR 75.64(a), i.e., either the the original SO2 emission standard for EGUs using CEMS, the data elements month in which monitoring system coal-fired units under Subpart D was 1.2 that are recorded include, among others, certification is completed or the month lb SO2/MMBtu). The rounding hourly CO2 concentration, stack gas in which the 180-day window allotted conventions under the General flow rate, stack gas moisture content (if to finish certification testing expires Provisions allow the reporting of all needed), unit operating time, and gross (whichever month is earlier). emission rates in the range from 1.15 to electric generation. For EGUs that Initial compliance with the applicable 1.249 as 1.2 lb SO2/MMBtu. During exclusively combust liquid and/or emissions limit in kg/MWh is calculated compliance periods with emissions at gaseous fuel(s) and elect to determine by dividing the sum of the hourly CO2 the lower end of this range, the operator CO2 emissions using Equation G–4 in mass emissions values by the total gross is required to report higher emissions appendix G of part 75, the key data output for the 12-operating-month than actually occurred; during elements in subpart F that are recorded period. Affected EGUs continue to be compliance periods at the upper end of include hourly fuel flow rates, fuel subject to the standards and this range the operator is allowed to usage times, fuel GCV, gross electric maintenance requirements in the CAA report lower emissions than actually generation. section 111 regulatory general occurred. In either case the absolute The rule requires EGU owners or provisions contained in 40 CFR part 60, error remains small because the operators to keep records of the subpart A. emission rate in this example is a calculations they perform to determine Several commenters stated that the relatively small numerical value. In the total CO2 mass emissions and gross final rule should require operators to addition, the required emission output for each operating month. round their calculated emissions rates to reductions typically are large enough Records of the calculations performed to three significant figures when that rounding does not impact the determine the average CO2 mass comparing their actual rates to the emission control strategy of affected emission rate (kg/MWh) and the standard. These commenters said that units. However, the final standards for percentage of valid CO2 mass emission allowing use of only two significant CO2 emissions include numerical values rates in each compliance period are digits when calculating the 12- that are larger than many historical required to be kept. The rule also operating-month rolling average emissions standards and require a requires sources to keep records of emission rate would constitute relatively small percent reduction in calculations performed to determine relaxation of the standard by 5 percent emissions. Accordingly, it is appropriate site-specific carbon-based F-factors for VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00117 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 64626 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations use in Equation G–4 of part 75, included in the report. If one or more of emission reduction that assure that appendix G (if applicable). compliance periods end in the quarter these sources are inherently low- Sources are required to keep all but there are no violations, a statement emitting at the time of construction. The records for a period of 3 years. All to that effect must be included in the following reasons support this approach required records must be kept on-site for report. to the BSER. a minimum of two years, after which the Currently, ECMPS is not programmed New sources are expected to have records can be maintained off-site. to receive the additional information long operating lives over which initial The rule requires all affected EGU included in the report required under 40 owners/operators to submit quarterly CFR 60.5555(a)(2) for affected EGUs. capital costs can be amortized. Thus, electronic emissions reports in However, we will make the necessary new construction is the preferred time accordance with subpart G of part 75. modifications to the system in order to to drive capital investment in emission The reports in appendix G that do not fully implement the reporting controls. In this case, the BSER for new include data required to calculate requirements of this rule upon steam generators, partial CCS, requires compliance with the applicable CO2 promulgation. substantial capital expenditures, which emission standard are not required to be new sources are best able to reported under this rule. The rule XI. Consistency Between BSER accommodate. requires the reports in 40 CFR 60.5555 Determinations for This Rule and the While CAA section 111(b)(1)(B) and to be submitted using the ECMPS Client Rule for Existing EGUs (a)(1) by their terms do not mandate that Tool. Except for a few EGUs that may In the CAA section 111(d) rule for be exempt from the Acid Rain Program the BSER assure that new sources are existing steam units and combustion inherently low emitting, that approach (e.g., oil-fired units), this is not a new turbines that the EPA is promulgating at to the BSER is consistent with the reporting requirement. Sources subject the same time as this CAA section legislative history.544 See Section to the Acid Rain Program are already 111(b) rule, the EPA is identifying as III.H.3.b.4 above. For instance, the 1970 required to report the hourly CO2 mass part of the BSER for those sources, emission rates that are needed to assess building block 1 (for steam units, Senate Committee Report explains that compliance with this rule. efficient operation), building block 2 ‘‘[t]he overriding purpose of this section Additionally, in the final rule and as (for steam units, dispatch shift to [concerning new source performance part of an agency-wide effort to existing NGCC units), and building standards] would be to prevent new air streamline and facilitate the reporting of block 3 (for steam units and combustion pollution problems, and toward that environmental data, the rule requires turbines, substitution of generation with end, maximum feasible control of new selected data elements that pertain to new renewable energy). In this section, sources at the time of their construction compliance under this rule, and that we explain why the EPA is not is seen by the committee as the most serve the purpose of identifying identifying building blocks 1, 2, or 3 as effective and, in the long run, the least violations of an emission standard, to be part of the BSER for new, modified, or expensive approach.’’ 545 Existing reported periodically using ECMPS. reconstructed steam generators or sources, on the other hand, would be Specifically, EGU owners/operators combustion turbines. regulated through emission standards, must submit quarterly electronic reports which were broadly understood at the within 30 days after the end of each A. Newly Constructed Steam Generating quarter consistent with current part 75 Units time to reflect available technology, reporting requirements. The first report alternative methods of prevention and 1. Preference for Technological Controls is for the quarter that includes the final control, alternative fuels, processes, and as the BSER for New EGUs 546 547 (12th) operating month of the initial 12- operating methods. operating-month compliance period. For As discussed in this preamble and in that initial report and any subsequent more detail in the preamble to the CAA 544 Although Congress expressed a clear report in which the 12th operating section 111(d) rule for existing sources, preference that new sources would be ‘‘designed, built, equipped, operated, and maintained so as to month of a compliance period (or the phrase ‘‘system of emission reduce emissions to a minimum,’’ the Senate periods) occurs during the calendar reduction’’ is undefined and provides Committee Report also makes clear that the term quarter, the average CO2 mass emissions the EPA with discretion in setting a standard of performance ‘‘refers to the degree of rate (kg/MWh) is reported for each standard of performance under CAA emission control which can be achieved through process changes, operation changes, direct emission compliance period, along with the dates section 111(b) or emission guidelines control, or other methods.’’ Sen. Rep. No. 91–1196 (year and month) of the first and twelfth under CAA section 111(d). Because the at 15–17, 1970 CAA Legis. Hist. at 415–17 operating months in the compliance phrase by its plain language does not (emphasis added). 545 period and the percentage of valid CO2 limit our review of potential systems in Sen. Rep. No. 91–1196 at 15–16, 1970 CAA mass emission rates obtained in the either context, the same systems could Legis. Hist. at 416 (emphasis added). 546 See 1970 CAA Amendments, Pub. L. 91–604, compliance period. The dates of the first be considered for application in new section 4, 84 Stat. 1676, 1679 (Dec. 31, 1970) and last operating months in the and existing sources. That said, many (describing information that the EPA must issue to compliance period clearly bracket the other factors and considerations direct the states and appropriate air pollution control period used in the determination, which us to focus on different systems when agencies along with the issuance of ambient air quality criteria under Section 4 of the 1970 CAA facilitates auditing of the data. establishing a standard of performance titled ‘‘Ambient Air Quality and Emission Reporting the percentage of valid CO2 under CAA section 111(b) and an Standards’’). mass emission rates is necessary to emission guideline under CAA section 547 In the 1977 CAA Amendments, Congress demonstrate compliance with the 111(d). Thus, it is useful to describe part revised section 111(a)(1) to mandate that the EPA base standards for new sources on technological requirement to obtain valid data for 95 of the underlying basis for the BSER— controls, but, at the same time, made clear that the percent of the operating hours in each partial CCS—that the EPA has EPA was not required to base the emission compliance period. Any violations that determined for new steam units before guidelines for existing sources on technological occur during the quarter are identified. discussing the building blocks that form controls. In the 1990 CAA Amendments, Congress repealed the section 111(a)(1) requirements that If there are no compliance periods that the BSER for existing units. distinguished between new and existing sources end in the quarter, a definitive For new steam generating units, the and largely restored the 1970 CAA Amendments statement to that effect must be EPA is identifying, as the BSER, systems version of section 111(a)(1). VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00118 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64627 2. Practical Implications of Including standard that would include both an sources will be available as trading the Building Blocks emission-rate limit that reflects partial partners. Several practical considerations make CCS and a requirement for allowances In addition, for section 111(d) the building blocks inappropriate for that reflects building blocks 2 and 3. sources, we are granting a 7-year period new sources. Thus, for the following Accordingly, the following discussion of lead-time for the implementation of reasons, the EPA does not consider it assumes either a rate-based or mass- the building blocks. This is due, in part, appropriate to include the building based standard, or part of a hybrid to the benefits of allowing the ERC and blocks as part of the BSER for new standard. allowance markets to develop. However, sources: In both a rate-based program and a the new source standards take effect mass-based program, building blocks 2 immediately, so new sources would not a. Additional Cost and 3 measures can be implemented have the advantage of this lead time Partial CCS will impose substantial through a range of methods, including were they subject to more stringent (albeit reasonable) costs on new steam- trading with other EGUs. While it is not standards that also reflected the generating EGUs, and, as a result, the necessarily the case that every existing building blocks.549 EPA does not believe that including source will be able to implement each In addition, if there are an additional measures as part of the BSER of the methods, in general, existing unexpectedly large number of new would be appropriate. One disadvantage sources will have a range of measures to sources, then they would be obliged to in adding additional costs is that doing choose from. However, at least some of invest in greater amounts of building so would make it more difficult for new those methods may not be available to blocks 2 and 3, and that could reduce steam-generating EGUs to compete with new sources, which would render the amounts of building blocks 2 and 3 new nuclear units. Because the BSER is compliance with their emission limits available for existing sources, and selected after considering cost (among more challenging and potentially more thereby raise the costs of building other factors), the EPA is not required costly. blocks 2 and 3 for existing sources. This to,548 and in this case believes it would One example is emission trading with could compromise the BSER under not be appropriate to, select the most other affected EGUs. For existing section 111(d) and undermine the stringent adequately demonstrated sources, emission trading is an ability of existing sources to comply system of emission reduction (through important option for implementing the with their section 111(d) obligations.550 the combination of partial CCS and the building blocks. There are large B. New Combustion Turbines building blocks) for purposes of setting numbers of existing sources, and they a standard of performance under CAA will become subject to the section For new combustion turbines, the section 111(b). 111(d) standards of performance at the building blocks are not appropriate as Building block 1 measures are not same time. It may be more cost-effective part of the BSER either. Building block appropriate (or would be redundant) for some to implement the building 1 is limited to steam generating units, because the BSER for new steam blocks than others, and, as a result, and therefore has no applicability to generating units is based on highly some may over-comply and some may new combustion turbines. Measures efficient supercritical technology, i.e., under-comply, and the two groups may comparable to those in building block 1 state-of-the-art, efficient equipment. See trade with each other. Because of the would not be appropriate because new Section V.K above. Accordingly, there is large numbers of existing sources, the highly efficient NGCC construction little improvement in efficiency that can trading market can be expected to be already entails high efficiency be justified as part of the BSER. robust. Trading optimizes efficiency. As equipment and operation. Building Building block 2 and 3 measures are a result, existing sources have more block 2 is also limited to steam not appropriate for the BSER because flexibility in the overall amount of their generating units and is not appropriate new steam units would have a investment in building blocks 2 and 3 as part of the BSER for new NGCC units significantly limited range of options to and can adjust investment obligations because it would not result in any implement building blocks 2 and 3. The among themselves through emissions emission reductions. new source performance standard was trading. The reasons why building block 3 are proposed and is being finalized as a In contrast, new sources construct one not appropriate are the same as rate-based standard. Thus, if building at a time, and it is unknown how many discussed above for why building blocks blocks 2 and 3 were included in the new sources there will be. Without a 2 and 3 are not appropriate for new sizeable number of new sources, there BSER, a more stringent rate-based steam generating units (limited range of will not be a robust trading market. standard would be applicable to all new options for implementation (including Thus, a new source cannot count on sources. However, it is conceivable that lack of availability of trading), lack of the EPA could propose a hybrid being able to find a new source trading partner. In addition, it is not possible to 549 At least in theory, we could consider 548 For example, as early as a 1979 NSPS count on new sources being able to promulgating a standard of performance for new rulemaking for affected EGUs, the EPA recognized trade with existing sources, for several affected EGUs that becomes more stringent that it was not required to establish as the BSER the reasons. First, as noted, there are beginning in 7 years, based on a more stringent most stringent adequately demonstrated system of indications in the legislative history that BSER. We are not inclined to adopt that approach emission reduction available, and instead could because section 111(b)(1)(B) requires that we review weigh the amount of additional emission reductions new sources should be well-controlled and, if necessary, revise the section 111(b) against the costs. See 44 FR 52792, 52798 (Sept. 10, at the source, which casts doubt on standards of performance no later than every 8 1979) (‘‘Although there may be emission control whether new sources should be allowed years anyway. technology available that can reduce emissions to meet their standards through the 550 The EPA is authorized to consider the BSER below those levels required to comply with for new and existing sources in conjunction with standards of performance, this technology might not purchase of emission credits. Second, each other. In the 1977 CAA Amendments, be selected as the basis of standards of performance new sources must meet their standards Congress revised section 111(a)(1) to require due to costs associated with its use. Accordingly, of performance as soon as they begin technological controls for new combustion sources standards of performance should not be viewed as operations. If they do so before the year at least in part because this requirement would the ultimate in achievable emission control. In fact, preclude new sources from relying on low-sulfur the Act requires (or has potential for requiring) the 2022, when existing sources become coal to achieve their emission limits, which, in imposition of a more stringent emission standard in subject to section 111(d) state plan turn, would free up low-sulfur coal for existing several situations.’’). standards of performance, no existing sources. VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00119 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 64628 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations lead-time for implementation, and the of its regulations that make clear that authorized by the EPA to administer the possibility of reducing the availability of the threshold for determining whether a PSD program and to issue PSD permits. renewable energy for existing sources). PSD source must satisfy the BACT If a state is not authorized, then the EPA requirement for GHGs continues to issues the PSD permits for facilities in C. Modified and Reconstructed Steam apply after promulgation of this rule. that state. and NGCC Units This rule does not require any To identify the pollutants subject to For modified and reconstructed steam additional revisions to State the PSD permitting program, EPA generators, the EPA identified the BSER Implementation Plans. As discussed regulations contain a definition of the as maintenance of high efficiency or further below, this final rule may have term ‘‘regulated NSR pollutant.’’ 40 CFR implementation of a highly efficient bearing on the determination of BACT 52.21(b)(50); 40 CFR 51.166(b)(49). This unit. The resulting emission limit must for new, modified, and reconstructed definition contains four subparts, which be met over the specified time period EGUs that require PSD permits. With cover pollutants regulated under various and cannot be deviated from or respect to the Title V operating permits parts of the CAA. The second subpart averaged. As a result, a modified or program, this rule does not affect covers pollutants regulated under reconstructed steam generator generally whether sources are subject to the section 111 of the CAA. The fourth will require ongoing maintenance and requirement to obtain a Title V subpart is a catch-all provision that may find it prudent to operate below its operating permit based solely on applies to ‘‘[a]ny pollutant that is limit as a safety margin. This represents emitting or having the potential to emit otherwise subjection to regulation under a substantial commitment of resources. GHGs above major source thresholds. the Act.’’ For these units, the additional costs of However, this rule does have some This definition and the associated implementing the building blocks implications for Title V fees, which the PSD permitting requirements applied to would not be appropriate. EPA is addressing in this final rule. GHGs for the first time on January 2, In addition, building block 1 is not Finally, the fossil fuel-fired EGUs 2011, by virtue of the EPA’s regulation appropriate for modified or covered in this rule are or will be of GHG emissions from motor vehicles, reconstructed steam generating units potentially impacted by several other which first took effect on that same date. because the BSER for these units is recently finalized or proposed EPA 75 FR 17004 (Apr. 2, 2010). As such, already based on highly efficient rules, and such potential interactions GHGs became subject to regulation performance. For the same reasons, it with other EPA rules are discussed under the CAA and the fourth subpart does not make sense to attempt to below. of the ‘‘regulated NSR pollutant’’ develop the analogue to building block definition became applicable to GHGs. 1 for reconstructed NGCC units—the B. Applicability of Tailoring Rule On June 3, 2010, the EPA issued a BSER for them, too, is already based on Thresholds Under the PSD Program final rule, known as the Tailoring Rule, highly efficient performance. In our January 8, 2014 proposal, the which phased in permitting Building block 2 is not appropriate for EPA proposed to adopt regulatory requirements for GHG emissions from reconstructed NGCC units because it language in 40 CFR part 60 that would stationary sources under the CAA PSD would not yield any reductions. ensure the promulgation of this NSPS and Title V permitting programs (75 FR Building blocks 2 and 3 are not would not undercut the application of 31514). Under its understanding of the appropriate for modified or rules that limit the application of the CAA at the time, the EPA believed the reconstructed steam generators, and PSD permitting program requirements to Tailoring Rule was necessary to avoid a building block 3 is not appropriate for only the largest sources of GHGs. An sudden and unmanageable increase in reconstructed NGCC units, for the same intervening decision of the United the number of sources that would be reasons that they are not appropriate for States Supreme Court has, to a large required to obtain PSD and Title V new EGUs, as described above (limited extent, resolved the legal issue that led permits under the CAA because the range of options for implementation the EPA to propose these part 60 sources emitted GHGs emissions over (including lack of availability of provisions. The Supreme Court has applicable major source and major trading), lack of lead-time for since clarified that the PSD program modification thresholds. In Step 1 of the implementation, and the possibility of does not apply to smaller sources based Tailoring Rule, which began on January reducing the availability of renewable on the amount of GHGs they emit. 2, 2011, the EPA limited application of energy for existing sources). However, because the largest sources PSD or Title V requirements to sources XII. Interactions With Other EPA emitting GHGs remain subject to the of GHG emissions only if the sources Programs and Rules PSD permitting requirements, the EPA were subject to PSD or Title V has concluded that it remains ‘‘anyway’’ due to their emissions of non- A. Overview appropriate to adopt the proposed GHG pollutants. These sources are This final rule will, for the first time, regulatory provisions in 40 CFR part 60 referred to as ‘‘anyway sources.’’ In Step regulate GHGs under CAA section 111. in this rule. We discuss our reasons for 2 of the Tailoring Rule, which began on In Section IX of the preamble to the this action in detail below. July 1, 2011, the EPA applied the PSD proposed rule, the EPA addressed how Under the PSD program in part C of and Title V permitting requirements regulation of GHGs under CAA section title I of the CAA, in areas that are under the CAA to sources that were 111 could have implications for other classified as attainment or unclassifiable classified as major, and, thus, required EPA rules and for permits written under for NAAQS pollutants, a new or to obtain a permit, based solely on their the CAA Prevention of Significant modified source that emits any air potential GHG emissions and to Deterioration (PSD) preconstruction pollutant subject to regulation at or modifications of otherwise major permit program and the CAA Title V above specified thresholds is required to sources that required a PSD permit operating permit program. The EPA obtain a preconstruction permit. This because they increased only GHG proposed to adopt provisions in the permit assures that the source meets emissions above applicable levels in the regulations that explicitly addressed specific requirements, including EPA regulations. some of these implications. application of BACT to each pollutant In the PSD program, the EPA For purpose of the PSD program, the subject to regulation under the CAA. implemented the steps of the Tailoring EPA is finalizing provisions in part 60 Many states (and local districts) are Rule by adopting a definition of the VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00120 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64629 term ‘‘subject to regulation.’’ The promulgating. Stakeholders questioned EPA had not yet done so, it could limitations in Step 1 of the Tailoring whether the EPA must revise its PSD ‘‘establish an appropriate de minimis Rule are reflected in 40 CFR regulations —and, by the same token, threshold below which BACT is not 52.21(b)(49)(iv) and 40 CFR whether states must revise their SIPs— required for a source’s greenhouse gas 51.166(b)(48)(iv). With respect to to assure that the Tailoring Rule emissions.’’ 134 S. Ct. at 2449. ‘‘anyway sources’’ covered by PSD thresholds will continue to apply to In accordance with the Supreme during Step 1, this provision established sources potentially subject to PSD under Court decision, on April 10, 2015, the that GHGs would not be subject to PSD the CAA based on GHG emissions. U.S. Court of Appeals for the District of requirements unless the source emitted In the January 8, 2014 proposed rule, Columbia Circuit (the D.C. Circuit) GHGs in the amount of 75,000 tons per the EPA explained that the agency had issued an amended judgment vacating year (tpy) of carbon dioxide equivalent included an interpretation in the the regulations that implemented Step 2 (CO2e) or more. The primary practical Tailoring Rule preamble, which means of the Tailoring Rule, but not the effect of this paragraph is that the PSD that the Tailoring Rule thresholds regulations that implement Step 1 of the BACT requirement does not apply to continue to apply if and when the EPA Tailoring Rule. The court specifically GHG emissions from an ‘‘anyway promulgates requirements under CAA vacated 40 CFR 51.166(b)(48)(v) and 40 source’’ unless the source emits GHGs at section 111. 79 FR 1488 (citing 75 FR CFR 52.21(b)(49)(v) of the EPA’s or above this threshold. The Tailoring 31582). Nevertheless, to ensure there regulations, but did not vacate 40 CFR Rule Step 2 limitations are reflected in would be no uncertainty as to this issue, 51.166(b)(48)(iv) or 40 CFR 40 CFR 52.21(b)(49)(v) and the EPA proposed to adopt explicit 52.21(b)(48)(iv). The court also directed 51.166(b)(48)(v). These provisions language in 40 CFR 60.46Da(j), 40 CFR the EPA to consider whether any further contain thresholds that, when applied 60.4315(b), and 40 CFR 60.5515 of the revisions to its regulations are through the definition of ‘‘regulated agency’s regulations. The proposed appropriate in light of UARG v. EPA, NSR pollutant,’’ function to limit the language makes clear that the thresholds and, if so, to undertake such revisions. scope of the terms ‘‘major stationary for GHGs in the EPA’s PSD definition of The practical effect of the Supreme source’’ and ‘‘major modification’’ that ‘‘subject to regulation’’ apply through Court’s clarification of the reach of the determine whether a source is required the second subpart of the definition of CAA is that it eliminates the need for to obtain a PSD permit. See e.g. 40 CFR ‘‘regulated NSR pollutant’’ to GHGs Step 2 of the Tailoring Rule and 51.166(a)(7)(i) and (iii); 40 CFR regulated under this rule. subsequent steps of the GHG permitting 51.166(b)(1); 40 CFR 51.166(b)(2). The EPA received comments phase in that the EPA had planned to supporting the adoption of this consider under the Tailoring Rule. This This structure of the EPA’s PSD proposed language, but several also eliminates the possibility that the regulations created questions regarding commenters also expressed concern that promulgation of GHG standards under the extent to which the limitations in adding this language to part 60 alone section 111 could result in additional the Tailoring Rule would continue to would not be sufficient. Several sources becoming subject to PSD based apply to GHGs once they became commenters urged the EPA to instead solely on GHGs, notwithstanding the regulated, through this final rule, under revise the PSD regulations in parts 51 limitations the EPA adopted in the section 111 of the CAA. 79 FR 1487– and 52. In addition, commenters Tailoring Rule. However, for an interim 1488. As discussed above, the definition expressed concern that further steps period, the EPA and the states will need of ‘‘regulated NSR pollutant’’ in the PSD were needed to amend the SIPs before to continue applying parts of the PSD regulations contains a separate PSD there would be certainty that the definition of ‘‘subject to regulation’’ to trigger for air pollutants regulated under Tailoring Rule limitations continued to ensure that sources obtain PSD permits the NSPS, 40 CFR 51.166(b)(49)(ii) (the apply after the adoption of CO2 meeting the requirements of the CAA. ‘‘NSPS trigger provision’’). Thus, when standards under CAA section 111 in this The CAA continues to require that GHGs become subject to a standard final rule. PSD permits issued to ‘‘anyway promulgated under CAA section 111 for On June 23, 2014, the United States sources’’ satisfy the BACT requirement the first time under this rule, PSD Supreme Court, in Utility Air Regulatory for GHGs. Based on the language that requirements would presumably apply Group v. Environmental Protection remains applicable under 40 CFR for GHGs on an additional basis besides Agency, issued a decision addressing 51.166(b)(48)(iv) and 40 CFR through the regulation of GHGs from the application of PSD permitting 52.21(b)(49)(iv), the EPA and states may motor vehicles. However, the Tailoring requirements to GHG emissions. The continue to limit the application of Rule, on the face of its regulatory Supreme Court held that the EPA may BACT to GHG emissions in those provisions, incorporated the revised not treat GHGs as an air pollutant for circumstances where a source emits thresholds it promulgated into only the purposes of determining whether a GHGs in the amount of at least 75,000 fourth subpart of the PSD definition of source is a major source (or tpy on a CO2e basis. The EPA’s regulated NSR pollutant (‘‘[a]ny modification thereof) for the purpose of intention is for this to serve as an pollutant that otherwise is subject to PSD applicability. The Court also said interim approach while the EPA moves regulation under the Act’’). The that the EPA could continue to require forward to propose a GHG Significant regulatory text does not clearly that PSD permits, otherwise required Emission Rate (SER) that would incorporate the thresholds into the based on emissions of pollutants other establish a de minimis threshold level NSPS trigger provision in the second than GHGs, contain limitations on GHG for permitting GHG emissions under subpart (‘‘[a]ny pollutant that is subject emissions based on the application of PSD. Under this forthcoming rule, the to any standard promulgated under BACT. The Supreme Court decision EPA intends to propose restructuring section 111 of the Act’’). For this reason, effectively upheld PSD permitting the GHG provisions in its PSD a question arose as to whether the requirements for GHG emissions under regulations so that the de minimis Tailoring Rule limitations would Step 1 of the Tailoring Rule for ‘‘anyway threshold for GHGs will not reside continue to apply to the PSD sources’’ and invalidated application of within the definition of ‘‘subject to requirements after they are PSD permitting requirements to Step 2 regulation.’’ This restructuring will be independently triggered for GHGs by the sources based on GHG emissions. The designed to make the PSD regulatory NSPS that the EPA is now Court also recognized that, although the provisions on GHGs universally VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00121 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 64630 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations applicable, without regard to the when emitted by an anyway source in make revisions to the PSD regulations in particular subparts of the definition of amounts of 75,000 tpy CO2e or more. their SIPs at this time. The EPA has ‘‘regulated NSR pollutant’’ that may Thus, in this final rule, the EPA is previously observed that the form of cover GHGs. Upon promulgation of this adopting the proposed text of 40 CFR each pollutant regulated under the PSD PSD rule, it will then provide a 60.5515 for this purpose without program is derived from the form of the framework that states may use when substantial change. pollutant described in regulations, such updating their SIPs consistent with the As to the concern expressed by some as an NSPS, that make the pollutant Supreme Court decision. commenters that revisions to part 60 regulated under the CAA. 56 FR 24468, While the PSD rulemaking described alone are not sufficient, the GHG SER 24470 (May 30, 1991); 61 FR 9905, above is pending, the EPA and approved rulemaking described above will 9912–18 (Mar. 12, 1996); 75 FR 31522. state, local, and tribal permitting include proposed revisions to the PSD Moreover, it is more likely that states authorities will still need to implement regulations in parts 51 and 52 that would need to consider a SIP revision the BACT requirement for GHGs. In should ultimately address this concern. if the EPA were to revise 40 CFR 51.166 order to enable permitting authorities to The EPA acknowledges that the in this rule. Revisions to 51.166 can continue applying the 75,000 tpy CO2e commenters concern will not be fully trigger requirements for states to revise threshold to determine whether BACT addressed for an interim period of time, their PSD program provisions under 40 applies to GHG emissions from an but (for the reasons discussed above) the CFR 51.166(a)(6). ‘‘anyway source’’ after GHGs are subject part 60 provisions adopted in this rule Given the process required in states to to regulation under CAA section 111, are sufficient to make explicit that the review their SIPs and submit them to the EPA has concluded that it continues 75,000 tpy CO2e BACT applicability the EPA for approval, it is most efficient to be appropriate to adopt the proposed level for GHGs will apply to GHGs that for all concerned when the EPA is able language in 40 CFR 60.5515 (subpart are subject to regulation under the CAA to consolidate its revisions to 40 CFR TTTT). Because the EPA is not section 111 standards adopted in this 51.166. The EPA, thus, believes it will finalizing the proposed regulations in rule. be less work for states if we issue a subparts Da and KKKK, it is not Rather than adopting a temporary comprehensive set of rules addressing necessary to adopt the comparable patch in its PSD regulations in this rule regulation of GHGs under the PSD provisions that the EPA proposed in 40 to address the implications for PSD of program after the Supreme Court CFR 60.46Da(j) and 40 CFR 60.4315(b). regulating GHGs under CAA section decision. The EPA has evaluated 40 CFR 111, the EPA believes it will be most In comments on the proposed rules, 60.5515 in light of the Supreme Court efficient for the EPA and the states if the states generally did not express concern decision and the comments received on EPA completes a comprehensive PSD that the proposed revisions to part 60 the question of whether this CAA rule that will address all the were insufficient to avoid the need for section 111 standard will undermine the implications of the Supreme Court SIP revisions. In our proposal, we application of the Tailoring Rule decision. The revisions the EPA will addressed any state with an approved limitations. While most of the Tailoring consider based on the Supreme Court PSD SIP program that applies to GHGs Rule limitations are no longer needed to decision will inherently address the which believed that this final rule avoid triggering the requirement to commenters concerns about the would require the state to revise its SIP obtain a PSD permit based on GHGs definition of the ‘‘subject to regulation’’ so that the Tailoring Rule thresholds alone, the limitation in 40 CFR and the proposed part 60 provisions. To continue to apply. First, the EPA 51.166(b)(48)(iv) and 40 CFR the extent this PSD rule is not complete encouraged any state that considered 52.21(b)(49)(iv) will remain important to before the EPA proposes additional such revisions necessary to make them provide an interim applicability level CAA section 111 standards for GHGs, as soon as possible. Second, if the state for the GHG BACT requirement in the EPA will need to consider adding could do so promptly, the EPA said it ‘‘anyway source’’ PSD permits. Thus, provisions like 40 CFR 60.5515 to other would assess whether to proceed with a there continues to be a need to ensure subparts of part 60. In a separate separate rulemaking action to narrow its that the regulation of GHGs under CAA rulemaking finalized concurrently with approval of that state’s SIP so as to section 111 does not make this BACT this rule, the EPA is also finalizing assure that, for federal purposes, the applicability level for anyway sources corresponding edits to 40 CFR 60.5705 Tailoring Rule thresholds will continue effectively inoperable. The language in in subpart UUUU to clarify that the to apply as of the effective date of the 40 CFR 60.5515 will continue to be regulated pollutant is the same for both final NSPS rule. 79 FR 1487. The EPA effective at avoiding this result after the the CAA section 111(b) and section did not receive any comments or other judicial actions described above and the 111(d) rules. As of this time, the EPA feedback from states requesting that the adoption of this final rule. The has not proposed GHG standards for EPA narrow their program to ensure the provisions in part 60 reference 40 CFR other source categories under CAA Tailoring Rule thresholds continue to 51.166(b)(48) and 40 CFR 52.21(b)(49) of section 111. To the extent needed, this apply after promulgating this rule. We the EPA’s regulations. However, the approach of adding provisions to a few do not believe such action will be courts have now vacated 40 CFR subparts in part 60 would be less necessary in any state after the Supreme 51.166(b)(48)(v) and 40 CFR burdensome to states and more efficient Court decision and our action in this 52.21(b)(49)(v), and the EPA will take than revising 40 CFR 51.166 at this time rule is to adopt the proposed part 60 steps soon to eliminate these subparts solely to address the implications of provisions for purposes of ensuring the from the CFR. As a result of these steps, regulating GHGs under CAA section Step 1 BACT applicability level for the language of final 40 CFR 60.5515 111. GHGs continues to apply on an interim will not incorporate the vacated parts of The EPA understands that many basis. 40 CFR 51.166(b)(48) and 40 CFR commenters expressed concern that PSD 52.21(b)(49), but these provisions in part SIPs would also have to be amended to C. Implications for BACT 60 will continue to apply to those address the implications of regulating Determinations Under PSD subparts of the PSD rules that are GHGs under CAA section 111. However, New major stationary sources and needed on an interim basis to limit the language in 40 CFR 60.5515 is major modifications at existing major application of BACT to GHGs only designed to avoid the need for states to stationary sources are required by the VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00122 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64631 CAA to, among other things, obtain a to units that may be within a source. whether a standard of performance for permit under the PSD program before Under this NSPS, an affected facility is the new source NSPS, specifically the commencing construction. The emission a new EGU or a modified or BSER for solid fuel-fired EGUs that is thresholds that define PSD applicability reconstructed EGU. The new source based on partial CCS, could become the can be found in 40 CFR parts 51 and 52, NSPS requirements apply, in general, to BACT floor when permitting a modified and the PSD thresholds specific to any stationary source that adds a new or reconstructed EGU or non-EGU GHGs are explained in the preceding EGU that is an affected facility under source. As noted above, BACT is a case- section of this preamble. this NSPS. This could, for example, specific review by a permitting agency. Sources that are subject to PSD must include a proposed brand new In evaluating BACT, the permitting obtain a preconstruction permit that (‘‘greenfield’’) power plant or an authority should consider all available contains emission limitations based on existing power plant that proposes to control technologies that have the application of BACT for each regulated add a new EGU (e.g., to increase its potential for practical application to the NSR pollutant. The BACT requirement generating capacity). While this latter facility or emission unit under is set forth in section 165(a)(4) of the scenario is considered a ‘‘new affected evaluation. See GHG Permitting CAA, and in EPA regulations under 40 facility’’ under the NSPS, it is generally Guidance at 24. This BACT review must CFR parts 51 and 52. These provisions viewed under PSD as a ‘‘modification’’ include any technologies that are part of require that BACT determinations be of an existing stationary source. Thus, an applicable NSPS for the specific type made on a case-by-case basis. CAA the new source NSPS requirements of source and would therefore establish section 169(3) defines BACT, in general, could apply to a modification, as that the minimum level of stringency for the as: term is defined under PSD. BACT. Thus, it is possible that partial In addition, this NSPS will apply to CCS could be considered in a BACT ‘‘an emissions limitation . . . based on the some modified and reconstructed units, maximum degree of reduction for each review as an available control option for pollutant . . . emitted from any proposed as those terms are defined under part a modified or reconstructed EGU major stationary source or major modification 60. Consequently, this NSPS could facility, or for another type of source which the Administrator . . . [considering establish a BACT floor for existing (e.g., natural gas processing plant), but energy, environmental, and economic stationary sources that are modifying an this NSPS is not an applicable standard impacts] . . . determines is achievable for existing EGU and experience an to such sources so it would not establish such facility . . .’’ emissions increase that makes the a requirement that partial CCS is a Furthermore, this definition in the CAA source subject to PSD review. However, minimum level of stringency for the specifies that a physical change that triggers the NSPS BACT for those sources. modification or reconstruction Some commenters expressed concern ‘‘[i]n no event shall application of [BACT] requirements does not necessarily that, if the EPA finalizes a BSER for result in emissions of any pollutants which subject the source to PSD requirements, utility boilers and IGCC units that is will exceed the emissions allowed by any applicable standard established pursuant to and vice versa. In general, in order to based on partial CCS, it would establish section 111 or 112 of the Act.’’ trigger the NSPS modification or a BACT Floor for new EGUs that would reconstruction requirements, a physical be inconsistent with prior BACT This condition of CAA section 169(3) change must increase the maximum determinations for EGUs in both permits has historically been interpreted to hourly emission rate of the pollutant (to issued by EPA Regions and permits mean that BACT cannot be less stringent be an NSPS modification) or the fixed issued by state agencies on which the than any applicable standard of capital cost of the change must exceed EPA has commented. Many of these performance under the NSPS. See, e.g., 50 percent of the fixed capital cost of a comments were more directed at the U.S. EPA, PSD and Title V Permitting comparable entirely new facility (to be development and deployment of CCS Guidance for Greenhouse Gases, EPA– an NSPS reconstruction). See 40 CFR (i.e., the commenter did not believe CCS 457/B–11–001 (March 2011) (‘‘GHG 60.2, 60.14, 60.15. Under the PSD should be the basis for BSER) rather Permitting Guidance’’ or ‘‘Guidance’’) at program, however, a physical change (or than examining whether an NSPS 20–21. Thus, upon completion of an change in the method of operation) must should establish the BACT floor for NSPS, the NSPS establishes a ‘‘BACT result in an increase in annual applicable sources, which is the legal Floor’’ for PSD permits that are issued emissions of the pollutant by a specified consequence of setting an NSPS under to affected facilities covered by the emission threshold in order to be the terms of the CAA. Consequently, we NSPS. subject to PSD requirements. This respond to these comments in other BACT is a case-by-case review that emission calculation considers the sections of this preamble that support considers a number of factors. These unit’s past annual emissions and its the selection of partial CCS as the basis factors include the availability, projected annual emissions. See, e.g., 40 for the BSER for fossil fuel-fired electric technical feasibility, control CFR 52.21(a)(2)(iv)(C). In addition, the utility steam generating units. effectiveness, and the economic, PSD emissions test for a modification With regard to the commenters who environmental and energy impacts of allows the existing source to consider stated that a BSER for EGUs that is the control option. See GHG Permitting qualifying emission reductions and based on partial CCS would be Guidance at 17–46. The fact that a increases at the source within a inconsistent with BACT determinations minimum control requirement (i.e., the contemporaneous period to ‘‘net out’’ of, in previous GHG PSD permits, it is BACT Floor) is established by the EPA or avoid, triggering PSD review. Thus, it important to recognize that a BACT through an applicable NSPS does not is important to understand the determination is a case-by-case analysis bar a permitting agency from justifying differences in how the term and that technological capabilities and a more stringent control level as BACT ‘‘modification’’ is used in the NSPS and costs evolve over time.551 In addition, to for a specific PSD permit. PSD programs, and that a physical It is important to understand how this change that is a modification under one 551 In this regard, the 2011 GHG Permitting NSPS may relate to determining BACT program may not necessarily be a Guidance states that ‘‘although CCS is not in widespread use at this time, EPA generally for new and existing EGUs that require modification under the other program. considers CCS to be an ‘available’ add-on pollution PSD permits. PSD generally applies to In the preamble to the proposed NSPS control technology for facilities emitting CO2 in major sources, while this NSPS applies for new sources, the EPA discussed Continued VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00123 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 64632 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations date the EPA has not issued a PSD BACT), the EPA is not necessarily technology feasibility and cost. GHG permit with GHG BACT for a source that required to comment negatively on the Permitting Guidance at 36, 43. While would be an affected facility requiring draft permit, or to otherwise request or acknowledging these potential partial CCS under this NSPS (i.e., a require that the state agency amend the challenges when it was issued in March fossil fuel-fired steam generating unit), BACT to include CCS. For state agencies 2011, the Guidance clearly does not rule so one cannot determine whether the that have their own EPA-approved state out the selection of CCS as BACT for EPA—as a PSD permitting authority— implementation plan, the state has any source category and it is forward has been either consistent or primacy over their permitting actions looking. GHG Permitting Guidance at 43 inconsistent by setting a BSER of partial and discretion to interpret their (‘‘. . . as a result of ongoing research CCS in this NSPS. Although, in the approved rules and to apply the and development, . . . CCS may course of a BACT review, some applicable federal and state regulatory become less costly and warrant greater permitting authorities may have requirements that are in place at the consideration . . . in the future’’) determined that CCS is not time for the facility in question. The Nothing in the Guidance is inconsistent technologically feasible or economically EPA’s role is to provide oversight to with EPA’s present position that CCS is achievable for a gas-fired EGU, because ensure that the state operates their PSD adequately demonstrated for the types of the case-by-case nature of the BACT program in accordance with the CAA of sources covered by this NSPS, as analysis it does not automatically follow and applicable rules. If the EPA does articulated elsewhere in this preamble. that the same conclusion is appropriate not adversely comment on a certain A commenter asserted that the GHG for a solid fuel-fired EGU. Furthermore, draft permit or BACT determination, it Permitting Guidance should be PSD permitting requirements first does not necessarily imply EPA amended because it calls for applied to GHGs in January 2011 and endorsement of the proposed permit or consideration of CCS in BACT more information about GHG control determination. determinations even though the technology has been gained in this four- Some commenters also felt that the proposed NSPS identified ‘‘partial CCS’’ and-a-half year period. Thus, we would determination of partial CCS as BSER is as BSER for new boiler and IGCC EGUs. expect BACT decisions to evolve as inconsistent with the agency’s position The Guidance explains that ‘‘the well, such that a GHG BACT review for on CCS in the EPA’s GHG Permitting purpose of Step 1 of the process is to a coal-fired EGU in 2015 may look very Guidance, which they say supports the cast a wide net and identify all control different from a review that was done in notion that additional work is required options with potential application to the 2011. before CCS can be integrated at full- emissions unit under review.’’ GHG Additionally, if a state agency is scale electric utility applications. It is Permitting Guidance at 26. The EPA processing a permit application for a important to recognize that the EPA’s agrees that the GHG Permitting solid fuel-fired EGU and does not Permitting Guidance is guidance, so it Guidance only uses the term ‘‘CCS’’ and propose CCS as BACT (or does not even does not contain any final does not distinguish ‘‘partial CCS’’ from consider CCS as an available control for determination of BACT for any source. ‘‘full CCS.’’ But considering the purpose Furthermore, we disagree with the of Step 1 of the process, we believe that large amounts and industrial facilities with high- commenters’ characterization of the the term ‘‘CCS’’, as it is used in the GHG purity CO2 streams.’’ GHG Permitting Guidance at GHG Permitting Guidance. The Permitting Guidance, adequately 35. The Guidance goes on to note that CCS may not be technically feasible at modified sources (citing Guidance specifically states ‘‘[f]or the describes the varying levels of CO2 possible issues with ‘‘space for CO2 capture purposes of a BACT analysis for GHGs, capture. A BACT review should analyze equipment at an existing facility’’), or in other the EPA classifies CCS as an add-on all available technologies in order to specific circumstances. Id. at 36 (‘‘Logistical pollution control technology that is adequately support the BACT hurdles for CCS may include obtaining contracts for offsite land acquisition . . ., the need for funding ‘‘available’’ for facilities emitting CO2 in determination, and may require . . ., timing of available transportation large amounts, including fossil fuel- evaluation of partial CCS, full CCS, and/ infrastructure, and developing a site for secure long fired power plants, and for industrial or no CO2 capture. The specific facility term storage. Not every source has the resources to facilities with high-purity CO2 streams type and CO2 capture conditions will overcome the offsite logistical barriers necessary to apply CCS technology to its operations, and smaller (e.g., hydrogen production, ammonia dictate the level(s) of CO2 capture that sources will likely be more constrained in this production, natural gas processing, are most appropriate to consider as regard’’). Id. at 42–3 EPA also noted that CCS may ethanol production, ethylene oxide ‘‘available’’ in a BACT review. be expensive in individual instances and thus production, cement production, and eliminated as a control option for that reason under D. Implications for Title V Program step 4 of the BACT analysis, noting further that iron and steel manufacturing). For these revenues from EOR may offset other costs. Id. at 42– types of facilities, CCS should be listed Under the Title V program, certain 3. See also UARG v. EPA, 134 S.Ct. 2427, 2448 in Step 1 of a top-down BACT analysis stationary sources, including ‘‘major (2014) (noting that EPA’s GHG Permitting Guidance for GHGs.’’ GHG Permitting Guidance at sources’’ are required to obtain an states that carbon capture is reasonably comparable operating permit. This permit includes to more traditional, end-of-stack BACT 32. As discussed elsewhere in the technologies, and that petitioners do not dispute Guidance, technologies that should be all of the CAA requirements applicable that). listed in Step 1 are those that ‘‘have the to the source, including adequate As explained at Section V.I.5 above, in potential for practical application to the monitoring, recordkeeping, and determining that partial CCS is BSER for new fossil emissions unit and regulated pollutant reporting requirements to assure fuel steam electric plants, the EPA has carefully considered the issue of logistics (including cost under evaluation.’’ GHG Permitting sources’ compliance. These permits are estimates for land acquisition, transportation, and Guidance at 24. The EPA continues to generally issued through EPA-approved sequestration) and costs generally. Nor would new stand by its position on the availability state Title V programs. plants face the same types of constraints as of CCS in this context, as expressed in In the January 8, 2014 proposal, the modified or reconstructed sources in a BACT determination, since a new source has more leeway the GHG Permitting Guidance. EPA discussed whether this rulemaking in choosing where to site. See text at V.G.3. above. The GHG Permitting Guidance would impact the applicability of Title Moreover, the GHG Permitting Guidance considered continues on to discuss case-specific V requirements to major sources of BACT determinations for all types of sources, not factors and potential limitations with GHGs. 79 FR 1489–90. The relevant just those for which the EPA has determined in this rule that partial CCS is the BSER, and the concerns applying CCS, and it acknowledges that issue for Title V purposes was, in expressed in the Guidance thus must be considered CCS may not be ultimately selected as essence, whether promulgation of CAA in that broader context. BACT in ‘‘certain cases’’ based on section 111 requirements for GHGs VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00124 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64633 would undermine the Tailoring Rule, accordance with that decision, the D.C. required to apply for, and operate which, as explained above, phased in Circuit’s amended judgment in pursuant to, a Title V permit that permitting requirements for GHG Coalition for Responsible Regulation, assures compliance with all applicable emissions for stationary sources under Inc. v. Environmental Protection CAA requirements, including any GHG- the CAA PSD and Title V permitting Agency, vacated the Title V regulations related applicable requirements. programs. Based on the EPA’s under review in that case to the extent E. Implications for Title V Fee understanding of the CAA at that time, that they require a stationary source to Requirements for GHGs the proposal discussed this issue in the obtain a Title V permit solely because context of the regulatory and statutory the source emits or has the potential to 1. Why is the EPA revising Title V fee definitions of ‘‘major source,’’ focusing emit GHGs above the applicable major rules as part of this action? on revisions that had been made in the source thresholds. The D.C. Circuit also The January 8, 2014 notice of Tailoring Rule to the definitions in the directed the EPA to consider whether proposed rulemaking (79 FR 1430) (the Title V regulations of ‘‘major source’’ any further revisions to its regulations ‘‘EGU GHG NSPS proposal’’ or ‘‘NSPS and ‘‘subject to regulation.’’ 79 FR are appropriate in light of UARG v. EPA, proposal’’) proposed the first section 1489–90 (quoting 75 FR 31583). Under and, if so, to undertake to make such 111 standards to regulate GHGs at EGUs. the Title V regulations, as revised by the revisions. These court decisions make That notice also included proposed Tailoring Rule, ‘‘major source’’ is clear that promulgation of CAA section revisions to the fee requirements of the defined to include, in relevant part, ‘‘a 111 requirements for GHGs will not 40 CFR part 70 and part 71 operating major stationary source . . . that result in the EPA imposing a permit rules under Title V of the CAA directly emits, or has the potential to requirement that stationary sources to avoid inadvertent consequences for emit, 100 tpy or more of any air obtain a Title V permit solely because fees that would be triggered by the pollutant subject to regulation.’’ The such sources emit or have the potential promulgation of the first CAA section proposal further explained that the GHG to emit GHGs above the applicable 111 standard to regulate GHGs. If we do 552 threshold that had been established in major source thresholds. not revise the fee rules by the time of the Tailoring Rule had been To be clear, however, unless the promulgation of the NSPS standards incorporated into the definition of exempted by the Administrator through for GHGs, then approved part 70 ‘‘subject to regulation’’ under 40 CFR regulation under CAA section 502(a), programs implemented by state, local 70.2 and 71.2, such that those any source, including an area source (a and tribal permitting authorities 554 that definitions specify ‘‘ ‘that GHGs are not ‘‘non-major source’’), subject to an NSPS rely on the ‘‘presumptive minimum’’ subject to regulation for purposes of is required to apply for, and operate approach and the part 71 program defining a major source, unless as of pursuant to, a Title V permit that implemented by the EPA would be July 1, 2011, the emissions of GHGs are assures compliance with all applicable required to account for GHGs in from a source emitting or having the CAA requirements for the source, emissions-based fee calculations at the potential to emit 100,000 tpy of GHGs including any GHG-related applicable same dollar per ton ($/ton) rate as other on a CO2e basis.’ ’’ Id. (quoting 75 FR requirements. This aspect of the Title V air pollutants. The EPA believes this 31583). The proposal thus concluded program is not affected by UARG v. would result in the collection of fees in that the Title V definition of ‘‘major EPA, as the EPA does not read that excess of what is required to cover the source,’’ as revised by the Tailoring decision to affect either the grounds reasonable costs of an operating permit other than those described above on Rule, did not on its face distinguish program. See NSPS proposal 79 FR which a Title V permit may be required among types of regulatory triggers for 1490. Title V. It further noted that the Title V or the applicable requirements that must In response to these concerns, the 553 program had already been triggered for be addressed in Title V permits. EPA proposed regulatory changes to GHGs, and thus concluded that the Consistent with the proposal, the EPA limit the fees collected based on GHG promulgation of CAA section 111 has concluded that this rule will not emissions and proposed two fee requirements would not further impact affect non-major sources and there is no adjustment options to increase the fees Title V applicability requirements for need to consider whether to exempt collected based on the costs for major sources of GHGs. 79 FR 1489–90. non-major sources. Thus, sources that permitting authorities to conduct certain As noted elsewhere in this section, are subject to the CAA section 111 review activities related to GHG after the proposal for this rulemaking standards promulgated in this rule are emissions, while still providing was published, the United States sufficient funding for an operating Supreme Court issued its opinion in 552 As explained elsewhere in this notice, the EPA permit program. Also, we proposed an UARG v. EPA, 134 S.Ct. 2427 (June 23, intends to conduct future rulemaking action to option that would have provided for no 2014), and in accordance with that make the appropriate revisions to the operating permit rules to respond to the Supreme Court fee adjustments to recover the costs of decision, the D.C. Circuit subsequently decision and the D.C. Circuit’s amended judgment. conducting review activities related to issued an amended judgment in To the extent there are any issues related to the GHG emissions. Id. 79 FR 1490. The Coalition for Responsible Regulation, potential interaction between the promulgation of Inc. v. Environmental Protection CAA section 111 requirements for GHGs and Title EPA did not propose any action related V applicability based on emissions above major to state and local permitting authorities Agency, Nos. 09–1322, 10–073, 10–1092 source thresholds, the EPA expects there would be and 10–1167 (D.C. Cir., April 10, 2015). that do not use the presumptive an opportunity to consider those during that minimum approach. Those decisions support the same rulemaking. Most commenters on the proposal, overall conclusion as the EPA discussed 553 See Memorandum from Janet G. McCabe, including state and local permitting in the proposal, though for different Acting Assistant Administrator, Office of Air and Radiation, and Cynthia Giles, Assistant authorities, were supportive of reasons. Administrator, Office of Enforcement and exempting GHGs from the emissions- With respect to Title V, the Supreme Compliance Assurance, to Regional Administrators, Court said in UARG v. EPA that the EPA Regions 1–10, Next Steps and Preliminary Views on based fee calculations of the permit may not treat GHGs as an air pollutant the Application of Clean Air Act Permitting Programs to Greenhouse Gases Following the 554 Hereafter, for the sake of simplicity, we will for purposes of determining whether a Supreme Court’s Decision in Utility Regulatory generally refer to part 70 permitting authorities as source is a major source required to Group v. Environmental Protection Agency (July 24, ‘‘state’’ permitting authorities and refer to part 70 obtain a Title V operating permit. In 2014) at 5. programs as ‘‘state’’ programs. VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00125 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 64634 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations rules, but support for the fee adjustment two alternative ways to account for the burden, and ‘‘GHG evaluation at permit options was mixed, with state and local costs of addressing GHGs in operating renewal’’ at 10 hours of burden. See also permitting authorities generally permits through a cost adjustment. First, 79 FR 1494, fn. 280 (providing a supporting either of the two fee we proposed a modest additional cost description of each of these activities). adjustments, and other commenters for each GHG-related activity of certain For part 70, the burden hours per generally supporting the option that types that a permitting authority would activity would be multiplied by the cost provides for no fee adjustment. process (‘‘the GHG adjustment option of staff time (in $/hour) specific to the 2. Background on the Fee Requirements 1’’). Alternatively, we proposed a state, including wages, benefits, and of Title V modest additional increase in the per overhead, to determine the cost of each ton rate used in the presumptive activity. All the activities for a given In the NSPS proposal, the EPA minimum calculation for all non-GHG period would be totaled to determine explained the statutory and regulatory fee pollutants (‘‘the GHG adjustment the total GHG adjustment for the state. background related to the requirement option 2’’). The EPA also solicited See 79 FR 1494. that permitting authorities collect fees comment on an option that would from the owner or operator of Title V For part 71, we proposed a labor rate provide no additional cost adjustment to assumption of $52 per hour in 2011 sources that are sufficient to cover the account for GHGs (‘‘the GHG adjustment costs of the operating permit program. dollars. Using that labor rate, we option 3’’). All of the GHG adjustment proposed to determine the GHG fee CAA section 502(b)(3)(A) requires an options are based on the assumption operating permit program to include a adjustment for each GHG permitting that the GHG exemption is finalized. program activity to be a specific dollar requirement that sources ‘‘pay an See NSPS Proposal 79 FR 1493–1495. annual fee, or the equivalent over some amount for each activity (‘‘set fees’’) that The EPA additionally proposed two the source would pay for each activity other period, sufficient to cover all clarifications. The first was regulatory reasonable (direct and indirect) costs performed. See 79 FR 1495. The EPA text in 40 CFR part 60, subparts Da, proposed to revise 40 CFR 70.9(b)(2)(v) required to develop and administer the KKKK, and TTTT, to clarify that GHGs, permit program.’’ See also 40 CFR and 40 CFR 71.9(c)(8) to implement this as opposed to CO2, is the regulated option. 70.9(a). CAA section 502(b)(3)(B)(i) pollutant for fee purposes (‘‘the fee requires that, in order to have an pollutant clarification’’). Id. at 1505, c. The GHG Adjustment Option 2 approvable operating permit program, 1506 and 1511. The second was a The second proposed GHG the permitting authority must show that proposal to move the existing definition ‘‘the program will result in the adjustment option (option 2) was to of ‘‘Greenhouse gases (GHGs)’’ within increase the dollar per ton ($/ton) rates collection, in the aggregate, from all 40 CFR 70.2 and 71.2 to promote clarity sources [required to get an operating used in the fee calculations for each in the regulations (‘‘the GHG non-GHG fee pollutant. The revised permit]’’ of either ‘‘an amount not less clarification’’). Id. 79 FR 1490, 1517, than $25 per ton of each regulated $/ton rates would be multiplied by the 1518. total tons of non-GHG fee pollutants pollutant [adjusted annually for changes For background purposes, below is a actually emitted by any source to in the consumer price index], or such brief summary of each of the proposals. other amount as the Administrator may determine the applicable total fees. The determine adequately reflects the a. The GHG Exemption EPA proposed to increase the $/ton rates 557 reasonable costs of the permit program.’’ To address the fee issues discussed in by 7 percent. See NSPS proposal 79 See also 40 CFR 70.9(b)(2). This has the NSPS proposal, the EPA proposed to FR 1494, 1495. been generally referred to as the exempt GHG emissions from the d. The GHG Adjustment Option 3 ‘‘presumptive minimum’’ approach. If a definition of ‘‘regulated pollutant (for permitting authority does not wish to presumptive fee calculation)’’ in 40 CFR The EPA also solicited comment on use the presumptive minimum 70.2 and the definition of ‘‘regulated not charging any fees related to GHGs approach, it may demonstrate ‘‘that pollutant (for fee calculation)’’ in 40 (option 3). The basis for this proposed collecting an amount less than the CFR 71.2.555 See NSPS preamble 79 FR option was the observation that most [presumptive minimum amount] will’’ 1493, 1495. sources that need to address GHGs in a result in the collection of funds permit would also emit non-GHG fee sufficient to cover the costs of the b. The GHG Adjustment Option 1 pollutants, and thus, the cost of program. CAA section 503(b)(3)(B)(iv); The first proposed ‘‘GHG adjustment’’ permitting for any particular source may see also 40 CFR 70.9(b)(5). This has option (option 1) was to include an be accounted for adequately without been generally referred to as the additional cost for each GHG-related charging any additional fees related to ‘‘detailed accounting’’ approach. CAA activity of certain types that a GHGs. Id. 79 FR 1494–1495. section 502(b)(3)(B)(ii) sets forth a permitting authority would process (an e. The Fee Pollutant Clarification definition of ‘‘regulated pollutant’’ for activity-based adjustment). The three purposes of calculating the presumptive activities identified for this option were Another fee-related proposal was to minimum that includes each pollutant ‘‘GHG completeness determination (for add regulatory text to 40 CFR part 60, regulated under section 111 of the CAA. initial permit or for updated subparts Da, KKKK, and TTTT, to See also 40 CFR 70.2. application)’’ at 43 hours of burden,556 clarify that the fee pollutant for 3. What fee rules did we propose to ‘‘GHG evaluation for a modification or operating permit purposes would be revise? related permit action’’ at 7 hours of considered to be ‘‘GHGs,’’ (as defined in In the NSPS proposal, to exempt 555 Hereafter we will refer to these definitions as 557 The EPA estimated that both options 1 and 2 GHGs from emissions-based fee the ‘‘fee pollutant’’ definitions. Also, note that both would result in about a 7 percent increase in the calculations, we proposed to exempt fee pollutant definitions cross-reference the fees collected by operating permit programs affected GHGs from the definition of ‘‘regulated definitions of ‘‘regulated air pollutant’’ which by the proposed rule. For example, the presumptive includes air pollutants ‘‘subject to any standard minimum fee rate in effect for September 1, 2014 pollutant’’ for purposes of operating promulgated under section 111 of the Act.’’ through August 31, 2015 is $48.27/ton. A 7 percent permit fee calculations (‘‘the GHG 556 Burden is the hours of staff time necessary to increase under option 2 would result in a revised exemption’’). The EPA then proposed perform a task. fee of $51.65/ton. VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00126 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64635 40 CFR 70.2 and 71.2),558 rather than public comment opportunities, the EPA permitting authorities’ ability to charge solely CO2, which would be regulated believes sufficient public comment sufficient fees to cover the cost of GHG under the section 111 standards and opportunities were provided on the fee permitting 559 if the state is barred from implemented through the EGU GHG rule changes because the proposal met exceeding minimum requirements set NSPS. Id. 79 FR 1505, 1506, and 1511. all public participation requirements by the EPA. Despite this adverse and we provided additional public comment, the EPA believes it is f. The GHG Clarification outreach, including to state and local appropriate to finalize the GHG The EPA proposed to move the permitting authorities, which discussed exemption because we are not finalizing existing definition of ‘‘Greenhouse gases the fee rule proposal. In addition to the any requirements that would require (GHGs)’’ within the definition of publication of the proposed rulemaking states to charge any particular fees to ‘‘Subject to regulation’’ in 40 CFR 70.2 in the Federal Register, the EPA held any particular sources. The changes we and 71.2 to a separate definition within numerous hearings, reached out to state are finalizing to part 70 concern the those sections to promote clarity in the partners and the public, and developed presumptive minimum approach, which regulations. Id. 79 FR 1490, 1517, 1518. numerous fact sheets and other sets a minimum fee target for states that 4. What action is the EPA finalizing? information to support public comment have decided to follow the presumptive on this rule. The EPA has complied minimum approach. Neither the statute In this action, the EPA is finalizing with the applicable public participation nor the final rule require any state the following elements as proposed: (1) requirements and executive orders. The following the presumptive minimum The GHG exemption, (2) the GHG proposal met all the requirements for approach (or any other approach) to adjustment option 1, and (3) the fee public notice—it contained a clear and charge fees to sources using any pollutant clarification. detailed explanation of how the part 70 particular method. Thus, the GHG Public commenters on the proposal and 71 rules would be affected by the exemption will not limit states’ ability stated both support and opposition to promulgation of the CAA section 111 to structure their individual fee using the NSPS rulemaking action to standard for EGUs and how the EPA programs however they see fit in order revise the Title V fee rules. Two proposed to revise the related regulatory to meet the requirement that they collect commenters stated that proposing the provisions. We received many revenue sufficient to cover all Title V fee revisions within the NSPS comments on the proposal to revise the reasonable costs of their permitting rulemaking would result in fewer fee rule for operating permits programs, program. See CAA section 502(b)(3); 40 commenters, particularly state and local and we are taking those comments into CFR 70.9(b)(3). permitting authorities, having consideration in the finalization of the b. The GHG Adjustment Option 1 knowledge of the changes to the fee rulemaking action. rules and sufficient opportunity to The EPA is finalizing GHG adjustment comment on the changes because the a. The GHG Exemption option 1 because we believe it will NSPS proposal is limited to a single The EPA is taking final action to result in a system for the calculation of source category, and one stated that a revise the definition of regulated costs for part 70 and fees for part 71 that separate proposal for the fee rules pollutant (for presumptive fee is most directly related to the costs of would provide a sufficient opportunity calculation) in 40 CFR 70.2 and GHG permitting. The EPA has for public comment. The EPA believes regulated pollutant (for fee calculation) determined that some adjustment to cost it is appropriate to move forward with in 40 CFR 71.2 to exempt GHG and fee accounting is important because final action amending the Title V fee emissions. This regulatory amendment the recent addition of GHG emissions to regulations as part of this NSPS. As we will have the effect of excluding GHG the operating permitting program does explained in the preamble for the emissions from being subject to the add new burdens for permitting proposal and elsewhere in this final statutory ($/ton) fee rate set for the authorities. Although GHG adjustment rule, the fee rules and the section 111 presumptive minimum calculation option 3 (no GHG permitting fee standards are interrelated because, if we requirement of part 70 and the fee adjustments) was supported by many do not revise the fee rules, promulgation calculation requirements of part 71. We industrial commenters, the EPA rejected of the final NSPS will trigger certain received supportive comments from the it because it is in tension with the requirements related to Title V fees for majority of public commenters, statutory requirement that permitting GHG emissions that the EPA believes including state and local permitting authorities collect sufficient fees to will result in the collection of excessive authorities and others, on revising the cover all the reasonable costs of fees in states that implement the operating permit rules to exempt GHGs permitting. See CAA section presumptive minimum approach and in from the emission-based calculations 502(b)(3)(A). Some state and local the part 71 program. Thus, it is that use the statutory fee rates. We are permitting authorities provided important to finalize the revisions to the finalizing this portion of the proposal comments supporting option 1, while fee rules at the same time or prior to this for the same reasons we explained in others supported option 2, and some NSPS, and it is within the EPA’s the proposal notice, including that supported either option, stating no discretion to address the NSPS and the leaving these regulations unchanged preference. Also, a few state and local fee rules at the same time as part of the would have resulted in the collection of permitting authorities supported same rulemaking action. In response to fee revenue far beyond the reasonable finalizing no adjustment and a few the commenters who were concerned costs of an operating permit program. others asked for flexibility to set fee that including the fee rule proposal as The EPA believes that these revisions adjustments not proposed by the EPA, part of the NSPS proposal would result (in conjunction with the GHG but that they believed would be in the public not having sufficient adjustment, see below) are consistent appropriate for their program. with the CAA requirements for fees 558 Note that in 40 CFR 70.2 and 71.2, the term pursuant to the authority of section 559 We use the term ‘‘GHG permitting’’ in this ‘‘Greenhouse gases (GHGs)’’ is defined as the 502(b)(3)(B)(i). section of the notice to refer to measures ‘‘aggregate group of six greenhouse gases: Carbon undertaken by permitting authorities to ensure that dioxide, nitrous oxide, methane, Some members of the public opposed GHGs and any applicable requirements related to hydrofluorocarbons, perfluorocarbons, and sulfur the proposed GHG exemption for GHGs are appropriately addressed in Title V hexafluoride.’’ reasons including that it may limit permitting. VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00127 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 64636 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations The EPA is finalizing option 1 instead Consistent with 40 CFR 70.4(i), a state properly addressed, as needed, in the of option 2 because the option 1 that wishes to change its operating application. The fee for this activity is adjustments are based on the actual permit program as a result of this final a one-time charge that covers the initial costs for permitting authorities to rule must apprise the EPA. The EPA application and any supplements or process specific actions that require will review the materials submitted updates. The EPA believes that a single GHG reviews. The option 2 approach, concerning the change and decide if a charge for a GHG completeness which would have added a 7 percent formal program revision process is determination will be adequate to cover surcharge to the $/ton rate used in the needed and will inform the state of next the reasonable costs for a permitting fee-related calculations, may have been steps. The communication apprising the authority to review an initial administratively easier to implement, EPA of any such changes should application and any subsequent but is tied to the emissions of non-GHG include at least a narrative description application updates related to initial air pollutants, which are not directly of the change and any other information permit issuance; thus, any updates to an related to the costs of GHG permitting. that will assist the EPA in its assessment initial application are included in a Consistent with CAA section of the significance of the changes. single ‘‘GHG completeness 502(b)(3)(B)(i), the Administrator has Certain changes, such as switching from determination,’’ rather than as a determined that the final rule’s the presumptive minimum method to a separate activity for which the source approach of exempting GHG emissions detailed accounting method, will be would be charged in addition to the from fee-related calculations and considered substantial program completeness determination for the accounting for the GHG permitting costs revisions and be subject to the initial application. This is an important through option 1 will result in fees that requirements of 40 CFR 70.4(i)(2). distinction because many sources will cover the reasonable costs of the With respect to the part 71 program, submit multiple permit application permitting programs. in this final action the EPA is revising updates, either voluntarily or as 40 CFR 71.9(c) to require each part 71 required by the permitting authority, The EPA is revising the part 70 source to pay an annual fee which is the during application review, many of regulations through this final action, sum of the activity-based fee of 40 CFR which do not require a separate or specifically 40 CFR 70.9(b)(2), to modify 71.9(c)(8) and the emissions-based fee of comprehensive completeness the presumptive minimum approach to 40 CFR 71.9(c)(1)–(4),561 which determination. add the activity-based cost of GHG excludes GHG emissions. To determine The EPA is finalizing regulatory text permitting activities, outlined in the the activity-based fee, the revised 40 that would describe the second listed revised 40 CFR 70.9(b)(2)(v), to the CFR 71.9(c)(8) requires the source to pay activity as ‘‘GHG evaluation for a permit emissions-based calculation of 40 CFR a ‘‘set fee’’ for each listed activity that modification or related permit 70.9(b)(2)(i), which is being revised to has been initiated since the fee was last action.’’ 562 The EPA had proposed that now exclude GHG emissions. To paid. Under part 71, fees are typically the second listed activity under option determine the activity-based GHG paid at the time of initial application 1 would be ‘‘GHG evaluation for a adjustment under 40 CFR 70.9(b)(2)(v), submittal, and thereafter, annually on modification or related permit action.’’ the permitting authority will multiply the anniversary of the initial fee For the final rule, we are clarifying that the burden hours for each activity (set payment, or on any other dates that may we are adding a cost for a ‘‘permit forth in the regulation) by the cost of be established in the permit. These set modification’’ rather than for a staff time (in $ per hour), including fees would not change until such time ‘‘modification.’’ The term wages, benefits, and overhead, as as we may revise our part 71 rule to ‘‘modification’’ may be interpreted to determined by the state, for the change the set fees. refer to any change at a source, even a particular activities undertaken during The final rule implements the option change that would not be required to be the particular time period. 1 approach by listing three activities processed as a ‘‘permit modification,’’ States that implement the performed by permitting authorities that while ‘‘permit modification’’ refers to presumptive minimum approach will involve GHG reviews. The following any revision to an operating permit that need to follow the final rule’s option 1 describes the activities as described in cannot be processed as an approach.560 States that use the detailed our proposal and certain clarifications administrative permit amendment and accounting approach are not directly we are making in the final rule to ensure thus requires a review by a permitting affected by this rulemaking, but they consistent implementation. authority as either a significant or minor must ensure that their fee collection The EPA is finalizing that the first permit modification. programs are sufficient to fully fund all listed activity under option 1 is ‘‘GHG The EPA is finalizing the third reasonable costs of the operating permit completeness determination (for initial activity as ‘‘GHG evaluation at permit program, including costs attributable to permit or updated application).’’ This renewal.’’ This activity covers the GHG-related permitting. The EPA activity must be counted for each new processing of all permit renewal suggests states that use the detailed initial permit application, even for applications and will involve accounting approach consider the 7 applications that do not include GHGs evaluations of whether any GHG percent assumption for the costs of GHG emissions or applicable requirements, applicable requirements are properly permitting in any such analysis, since an important part of any included. consistent with the EPA analysis of completeness determination will be to Some members of the public options 1 and 2 in the proposal. determine that GHG emissions and commented that finalizing a GHG applicable requirements have been adjustment would inappropriately 560 A presumptive minimum state may require various changes to its approved operating permit 561 Note that the emissions-based fee calculation 562 The EPA notes that the term ‘‘permit program before it may begin to implement the differs somewhat depending on whether the part 71 modification’’ in this context refers to all significant option 1 approach. For example, its regulations, program is being implemented by the EPA (see 40 permit modifications and minor permit and/or program procedures and practices, may need CFR 71.9(c)(1)); a state, local or tribal agency with modifications under operating permit rules, but not to be revised, depending on the structure of the fee delegated authority from the EPA (see § 71.9(c)(2)); to ‘‘administrative permit amendments,’’ as such provisions in the state’s program; thus, the exact the EPA with contractor assistance (see § 71.9(c)(3)); amendments are not defined as ‘‘permit response necessary to address this final action may or an agency with partial delegation authority (see modifications’’ in the permit rules. See, e.g., 40 CFR vary from state to state. § 71.9(c)(4)). 70.7(d), (e), and (f). VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00128 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64637 increase sources’ financial burdens. The approach of the final rule will be more of the effect of the Supreme Court EPA has explained, both in the proposal equitable for sources and more decision on the burden hour notice and elsewhere in this preamble, representative of actual costs because assumptions for the GHG review the importance of the fee-related option 1 considers the costs of the activities under proposed option 1 is revisions to account for the costs actual permitting activities performed that the effects are not significant associated with GHG-related permitting. by a particular permitting authority, enough to warrant revision of the The EPA believes that the revisions while any emissions-based approach burden hour assumptions in the final being finalized will result in modest and would not be as directly related to rule. Proposed option 1 was based on reasonable fee increases necessary to actual costs incurred by permitting the assumption that permitting cover states’ increased costs.563 To the authorities. authorities would need to evaluate all extent that commenters intended to Some commenters alleged that the permit applications for initial permit argue that the adjustments we proposed EPA’s proposal on adjustments to the issuance, significant and minor permit would exceed the actual costs of GHG operating permit programs was vague. modifications, and permit renewals for permitting, no commenters provided The EPA provided a thorough GHG issues (even if there are no any information or analysis to support discussion of our rationale in the applicable GHG requirements). Even that position. Some commenters did proposal, including the basis for the after the UARG v. EPA decision, state that the costs associated with GHG- GHG adjustments, and we proposed permitting authorities will continue to related permitting should be minimal regulatory text to implement our need to evaluate GHG issues for sources because few applicable requirements proposal. We explained in the proposal applying for a title V permit and for will apply to GHGs. As stated earlier in that support for the cost adjustment for permit modifications and renewals for this notice, the EPA’s cost estimate for GHGs under option 1 is contained in existing permits, and we do not the proposal concerned the incremental several analyses performed by the EPA anticipate that the decision will costs of GHG permitting for any source, and approved by the OMB related to the significantly affect the total number of not just those that would have, at the effect of the addressing GHG such evaluations that will occur in any time of the analysis, triggered the requirements in operating permits. given year compared to the assumptions requirement to get a permit based on These analyses have been placed in the in our analysis, which as explained GHG emissions or applicable docket for this rulemaking. The analyses above, were based on the incremental requirements. include: The Regulatory Impact costs of GHG permitting for any source. Despite some comments received to Assessment (RIA) for the Tailoring Rule Thus, we are finalizing the burden hour the contrary, the EPA does not believe (see Regulatory Impact Analysis for the assumptions as they were proposed. See it is appropriate to delay the finalization Final Prevention of Significant NSPS proposal at 1494 and the of the GHG adjustment. The EPA does Deterioration and Title V Greenhouse supporting statement for the 2012 part not believe such delays would be Gas Tailoring Rule, Final Report, May 70 ICR renewal. Also, as discussed consistent with CAA section 2010); the part 70 ICR change request for previously, we remain committed to 502(b)(3)(A) because states have been the Tailoring Rule (which was based on collecting and analyzing additional data incurring costs attributable to GHG the RIA for the Tailoring Rule); and the on costs and we may adjust the burden permitting for several years now and current ICR for part 70 (EPA ICR hour assumptions or other aspects of increased fees must be collected to number 1587.12; OMB control number option 1 in a future rulemaking, if cover the increased costs. The 2060–0243). needed. regulatory changes being finalized in Several commenters asked that we c. The Fee Pollutant Clarification this action provide the states with make changes to the option 1 approach We are also finalizing the proposed optimal flexibility and sufficient that we proposed, such as adding new addition of text within 40 CFR part 60, funding to implement their GHG activities or decreasing the costs we subpart TTTT, to clarify that the fee permitting programs. Some commenters assumed for the proposal. In response to pollutant for operating permit purposes had specifically stated that the EPA these comments, we note that we is GHG (as defined in 40 CFR 70.2 and should delay finalization of this rule received no quantitative data or other 71.2). We are finalizing these provisions until the completion of the next ICR information from commenters that we to add clarity to our regulations and to renewal process. While we do not believe demonstrates the need to revise avoid the potential need for possible believe delaying this rule is appropriate, the list of activities we included under future rulemakings to adjust the title V as explained above, the EPA notes that option 1 or the burden hour fee regulations if any constituent of we remain committed to collecting and assumptions under option 1 for the GHG, other than CO , becomes subject analyzing additional data on costs activities. Note that to promote 2 to regulation under section 111 for the attributable to GHG permitting for consistent implementation of the final first time. The proposal was to add this operating permit programs. We may option 1 approach, the preamble clarifying text to 40 CFR part 60, adjust the GHG cost adjustments in describes elsewhere a few clarifications subparts Da, KKKK, and TTTT. The future rulemakings if necessary to concerning the activities under option 1 final rule adds the clarification text only comply with the requirements of the and one minor revision to the regulatory to subpart TTTT because the EPA is Act. text of one of the activities. As an alternative to the options Since the EPA’s proposed rulemaking, the Supreme Court decided in UARG v. requirements that must be addressed in Title V proposed by the EPA, some commenters permits. See Memorandum from Janet G. McCabe, asserted that the EPA should make a EPA that the EPA may not treat GHGs Acting Assistant Administrator, Office of Air and GHG cost adjustment using a separate, as an air pollutant for purposes of Radiation, and Cynthia Giles, Assistant but reduced fee rate ($/ton) for GHGs. determining whether a source is a major Administrator, Office of Enforcement and We, however, believe that the option 1 source required to obtain a Title V Compliance Assurance, to Regional Administrators, 564 Regions 1–10, Next Steps and Preliminary Views on operating permit. The EPA’s review the Application of Clean Air Act Permitting 563 The EPA estimated in the proposal that option Programs to Greenhouse Gases Following the 1 would result in about a 7 percent overall increase 564 The EPA does not, however, read the UARG Supreme Court’s Decision in Utility Regulatory in the annual part 70 fees that are collected by all decision to affect other grounds on which a Title Group v. Environmental Protection Agency (July 24, permitting authorities nationally. See 79 FR 1494. V permit may be required or the applicable 2014) at 5. VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00129 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 64638 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations codifying all of the requirements for the impact fossil fuel-fired EGUs apply to provides a clear pathway for reliability- affected EGUs in a new subpart TTTT existing facilities as well as newly critical units to receive an and including all CO2 emission constructed, modified, or reconstructed administrative order that includes a standards for the affected EGUs (electric facilities. In fact, the rules described compliance schedule of up to an utility steam generating units, as well as below are more applicable to existing additional year, if it is needed to ensure natural gas-fired stationary combustion EGUs than to newly constructed, electricity reliability.566 turbines) in that newly created subpart. modified, or reconstructed EGUs. 2. Cross-State Air Pollution Rule See Section III.B of this preamble for Although those rules will affect EGUs as (CSAPR) more on this subject. existing sources, because we expect that there will be few NSPS modifications or The CSAPR requires states to take d. The GHG Clarification reconstructions, we don’t anticipate action to improve air quality by The EPA is taking no action at this those rules affecting EGUs as modified reducing SO2 and NOX emissions that time on the proposal to move the or reconstructed sources. In cross state lines. These pollutants react definitions of ‘‘Greenhouse gases constructing new EGUs, sources can in the atmosphere to form fine particles (GHG)’’ within the definition of take all applicable requirements of the and ground-level ozone and are ‘‘Subject to regulation’’ in 40 CFR parts various rules into consideration. transported long distances, making it 70 and 71. No public comments were difficult for other states to attain and received on this proposed clarification; 1. Mercury and Air Toxics Standards maintain the NAAQS. The first phase of however, subsequent to the proposal, on (MATS) CSAPR became effective on January 1, June 23, 2014, the Supreme Court in On February 16, 2012, the EPA issued 2015, for SO2 and annual NOX, and May UARG v. EPA decided that GHG the MATS rule (77 FR 9304) to reduce 1, 2015, for ozone season NOX. The emissions could not be used in making emissions of toxic air pollutants from second phase will become effective on certain applicability determinations new and existing coal- and oil-fired January 1, 2017, for SO2 and annual under the operating permit rules. More EGUs. The MATS rule will reduce NOX, and May 1, 2017, for ozone season specifically with respect to title V, as emissions of heavy metals, including NOX. Many of the power plants described above, the Supreme Court mercury (Hg), arsenic (As), chromium participating in CSAPR have taken said that the EPA may not treat GHGs (Cr), and nickel (Ni); and acid gases, actions to reduce hazardous air as an air pollutant for purposes of including hydrochloric acid (HCl) and pollutants for MATS compliance that determining whether a source is a major hydrofluoric acid (HF). These toxic air will also reduce SO2 and/or NOX. In this source required to obtain a title V pollutants, also known as hazardous air way these two rules are complementary. operating permit. In accordance with pollutants or air toxics, are known to Compliance with one helps facilities the Supreme Court decision, on April cause, or suspected of causing, damage comply with the other. 10, 2015, the D.C. Circuit issued an nervous system damage, cancer, and 3. Requirements for Cooling Water amended judgment in Coalition for other serious health effects. The MATS Intake Structures at Power Plants Responsible Regulation, Inc. v. rule will also reduce SO2 and fine (316(b) Rule) Environmental Protection Agency, Nos. particle pollution, which will reduce 09–1322, 10–073, 10–1092 and 10–1167 particle concentrations in the air and On May 19, 2014, the EPA issued a (D.C. Cir. April 10, 2015), which, among prevent thousands of premature deaths final rule under section 316(b) of the other things, vacated the title V and tens of thousands of heart attacks, Clean Water Act (33 U.S. Code section regulations under review in that case to bronchitis cases and asthma episodes. 1326(b)) (referred to hereinafter as the the extent that they require a stationary New or reconstructed EGUs (i.e., 316(b) rule.) The rule was published on source to obtain a title V permit solely sources that commence construction or August 15, 2014 (79 FR 48300; August because the source emits or has the reconstruction after May 3, 2011) 15, 2014), and became effective October potential to emit GHGs above the subject to the MATS rule are required to 14, 2014. The 316(b) rule establishes applicable major source thresholds. The comply by April 16, 2012 or upon new standards to reduce injury and D.C. Circuit also directed the EPA to startup, whichever is later. death of fish and other aquatic life consider whether any further revisions Existing sources subject to the MATS caused by cooling water intake to its regulations are appropriate in light rule were required to begin meeting the structures at existing power plants and 567 of UARG v. EPA, and, if so, to undertake rule’s requirements on April 16, 2015. manufacturing facilities. The 316(b) to make such revisions. Controls that will achieve the MATS In response to the Supreme Court 566 Following promulgation of the MATS rule, performance standards are being industry, states and environmental organizations decision and the D.C. Circuit’s amended installed on many units. Certain units, challenged many aspects of the EPA’s threshold judgment, the EPA intends to conduct especially those that operate determination that regulation of EGUs is future rulemaking action to make the infrequently, may be considered not ‘‘appropriate and necessary’’ and the final standards appropriate revisions to the operating regulating hazardous air pollutants from EGUs. The worth investing in given today’s U.S. Court of Appeals for the D.C. Circuit upheld permit rules. As part of any such future electricity market, and are closing. The all aspects of the MATS rule. White Stallion Energy rulemaking action, the EPA may final MATS rule provided a foundation Center v. EPA, 748 F.3d 1222 (D.C. Cir. 2014). The consider finalizing the proposal to move on which states and other permitting decision was unanimous on all issues except a the definitions of GHGs within the dissent was filed because the EPA did not consider authorities could rely in granting an cost when determining regulation of EGUs is operating permit rules. additional, fourth year for compliance appropriate. In Michigan v. EPA, case no. 14–46, F. Interactions With Other EPA Rules provided for by the CAA. States report the Supreme Court reversed the D.C. Circuit that these fourth year extensions are decision upholding the MATS rule finding that EPA Fossil fuel-fired EGUs are, or being granted. In addition, the EPA erred by not considering cost when determining potentially will be, impacted by several that regulation of EGUs was ‘‘appropriate’’ pursuant issued an enforcement policy that to section 112(n)(1). The Supreme Court considered other recently finalized or proposed only the narrow question of cost and did not review 565 EPA rules. Many of the rules that rulemakings is not a defense to a violation of the the other holdings of the D.C. Circuit, nor did the CAA. Sources cannot defer compliance with Supreme Court vacate the MATS rule. 565 We discuss other rulemakings solely for existing requirements because of other upcoming 567 CWA section 316(b) provides that standards background purposes. The effort to coordinate regulations. applicable to point sources under sections 301 and VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00130 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64639 rule subjects existing power plants and 5. Steam Electric Effluent Limitation natural gas co-firing. For a subcategory manufacturing facilities that withdraw Guidelines and Standards (SE ELG Rule) of steam generating units that conduct in excess of 2 million gallons per day The EPA is reviewing public ‘‘large’’ modifications according to (MGD) of cooling water, and use at least comments and working to finalize the definitions in this final rule, we are 25 percent of that water for cooling proposed SE ELG rule which will finalizing an emission standard that is purposes, to a national standard impact fossil fuel-fired EGUs. In 2013, based on a unit-specific emission designed to reduce the number of fish the EPA proposed the SE ELG rule (78 limitation consistent with each destroyed through impingement and FR 34432; June 7, 2013) to strengthen modified unit’s best one-year historical entrainment. Existing sources subject to the controls on discharges from certain performance and can be met through a the 316(b) rule are required to comply steam electric power plants by revising combination of best operating practices with the impingement requirements as technology-based effluent limitations and equipment upgrades. For soon as practicable after the entrainment guidelines and standards for the steam reconstructed steam generating units, requirements are determined. They electric power generating point source the EPA is finalizing standards of must comply with applicable site- category. The proposed regulation, performance based on the performance specific entrainment reduction controls which includes new requirements for of the most efficient generation based on the schedule of requirements both existing and new generating units, technology available, which we established by the permitting authority. would reduce impacts to human health concluded is the use of the best Additional information regarding the and the environment by reducing the available subcritical steam conditions 316(b) rule for existing sources is amount of toxic metals and other for small units and the use of included in Section IX.C of the pollutants currently discharged to supercritical steam conditions for large preamble to the CAA section 111(d) surface waters from power plants. The units. The standards can also be met emission guidelines for existing EGUs EPA intends to take final action on the through other technology options such that the EPA is finalizing proposed rule by September 30, 2015. as natural gas co-firing. In light of these simultaneously with this rule. Although Section IX.C of the preamble to the CAA potential alternative compliance the recently issued 316(b) rule section 111(d) emission guidelines for pathways, we believe that sources will discussed here applies to existing existing EGUs that the EPA is finalizing have ample opportunity to coordinate sources, there are also 316(b) simultaneously with this rule includes their response to this rule with any technology-based standards for new additional information regarding the SE obligations that may be applicable to sources with cooling water intake ELG rule. affected EGUs as a result of the MATS, structures. The EPA recognizes the importance of CSAPR, 316(b), SE ELG and CCR rules, assuring that each of the rules described all of which are or soon will be final 4. Disposal of Coal Combustion above can achieve its intended rules—and to do so in a manner that Residuals From Electric Utilities (CCR environmental objectives in a will help reduce cost and ensure Rule) commonsense, cost-effective manner, reliability, while also ensuring that all consistent with underlying statutory applicable environmental requirements On December 19, 2014, the EPA are met.568 issued the final rule for the disposal of requirements, and while assuring a The EPA is also endeavoring to enable coal combustion residuals from electric reliable power system. Executive Order EGUs to comply with applicable utilities. The rule provides a (E.O.) 13563, ‘‘Improving Regulation obligations under other power sector comprehensive set of requirements for and Regulatory Review,’’ issued on rules as efficiently as possible (e.g., by the safe disposal of coal combustion January 18, 2011, states that ‘‘[i]n facilitating their ability to coordinate residuals (CCRs), commonly known as developing regulatory actions and planning and investment decisions with coal ash, from coal-fired power plants. identifying appropriate approaches, each agency shall attempt to promote respect to those rules) and, where The CCR rule establishes technical . . . coordination, simplification, and possible, implement integrated requirements for existing and new CCR harmonization.’’ E.O. 13563 further compliance strategies. Section IX.C of landfills and surface impoundments states that ‘‘[e]ach agency shall also seek the preamble to the CAA section 111(d) under Subtitle D of the Resource to identify, as appropriate, means to emission guidelines for existing EGUs Conservation and Recovery Act (RCRA), achieve regulatory goals that are that the EPA is finalizing the nation’s primary law for regulating designed to promote innovation.’’ simultaneously with this rule describes solid waste. New CCR landfills and Within the EPA, we are paying careful such an example with respect to the SE surface impoundments are required to attention to the interrelatedness and ELG and CCR rules. meet the technical criteria before any potential impacts on the industry, In light of the compliance flexibilities CCR is placed into the unit. Existing reliability and cost that these various we are offering in this action, we believe CCR surface impoundments and rulemakings can have. that sources will have ample landfills are subject to implementation As discussed in earlier sections of this opportunity to use cost-effective timeframes established in the rule for preamble, the EPA has identified regulatory strategies and build on their the individual technical criteria. For potential alternative compliance longstanding, successful records of additional information regarding the pathways for affected newly complying with multiple CAA, CWA, CCR rule, see Section IX.C of the constructed, modified, and and other environmental requirements, preamble to the CAA section 111(d) reconstructed fossil fuel-fired steam while assuring an adequate, affordable, emission guidelines for existing EGUs generating units. We are finalizing an and reliable supply of electricity. that the EPA is finalizing along with this emission standard for newly rule. constructed highly efficient fossil fuel- 568 It should be noted that regulatory obligations fired steam generating units that can be imposed upon states and sources operate 306 of the Act must require that the location, met by capturing and storing independently under different statutes and sections design, construction and capacity of cooling water approximately 16 to 23 percent of the of statutes; the EPA expects that states and sources intake structures reflect the best technology will take advantage of available flexibilities as available for minimizing adverse environmental CO2 produced from the facility or by appropriate, but will comply with all relevant legal impacts. utilizing other technologies such as requirements. VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00131 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 64640 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations XIII. Impacts of This Action standard of performance by the ESA. Section 7(a)(2) of the ESA As explained in the ‘‘Regulatory implementing partial post-combustion requires federal agencies, in Impact Analysis for the Standards of CCS are likely to use commercially- consultation with the Service(s), to Performance for Greenhouse Gas available amine-based capture systems. ensure that actions they authorize, fund, Emissions for New, Modified, and Some concern has been raised regarding or carry out are not likely to jeopardize Reconstructed Stationary Sources: emissions of amines and amine the continued existence of federally Electric Utility Generating Units’’ (EPA– degradation by-products (e.g., NH3) from listed endangered or threatened species 452/R–15–005, August 2015) (RIA), the capture process. To reduce the or result in the destruction or adverse available data indicate that, even in the amine emissions, MHI introduced the modification of designated critical absence of the standards of performance first optimized washing system within habitat of such species. 16 U.S.C. for newly constructed EGUs, existing an absorber column in 1994, and 1536(a)(2). Under relevant and anticipated economic conditions developed a proprietary washing system implementing regulations, ESA section will lead electricity generators to choose in 2003. In that system, a proprietary 7(a)(2) applies only to actions where new generation technologies that will reagent is added to the water washing there is discretionary federal meet the standards without installation section to capture amine impurities involvement or control. 50 CFR 402.03. of additional controls. Therefore, based such as amine, degraded amine, Further, under the regulations on the analysis presented in Chapter 4 ammonia, formaldehyde, acetaldehyde, consultation is required only for actions 570 of the RIA, the EPA projects that this carbonic acids and nitrosamines. that ‘‘may affect’’ listed species or MHI has continued to improve this designated critical habitat. 50 CFR final rule will result in negligible CO2 emission changes, quantified benefits, technology for further reduction of 402.14. Consultation is not required and costs on owners and operators of amine emissions and established an where the action has no effect on such newly constructed EGUs by 2022.569 ‘‘advanced amine emission reduction species or habitat. Under this standard, This conclusion is based on the EPA’s system’’. it is the federal agency taking the action own modeling as well as projections by Research performed by MHI at that evaluates the action and determines EIA. While the primary conclusion of Alabama Power’s Plant Barry indicated whether consultation is required. See 51 the analysis presented in the RIA is that that an increasing SO3 content in the FR 19926, 19949 (June 3, 1986). Effects the standards for newly constructed flue gas caused a significant increase of of an action include both the direct and EGUs will result in negligible costs and amine emissions. During testing, at indirect effects that will be added to the benefits, the EPA has also performed Plant Barry, MHI applied its proprietary environmental baseline. 50 CFR 402.02. several illustrative analyses that show washing system and confirmed that the Direct effects are the direct or the potential impacts of the rule if amine emission were drastically immediate effects of an action on a certain key assumptions were to change. reduced.571 Others have also studied listed species or its habitat.574 Indirect This includes an analysis of the impacts emissions and control strategies and effects are those that are ‘‘caused by the under a range of natural gas prices and have determined that a conventional proposed action and are later in time, the costs and benefits associated with multi-stage water wash and mist but still are reasonably certain to building an illustrative coal-fired EGU eliminator at the exit of the CO2 occur.’’ Id. To trigger the consultation with CCS. These are presented in scrubber is effective at removal of requirement, there must thus be a causal Chapter 5 of the RIA. gaseous amine and amine degradation connection between the federal action, As also explained in the RIA for this products emissions.572 573 Additional the effect in question, and the listed final rule, the EPA also expects that few research continues in this area. species, and if the effect is indirect, it must be reasonably certain to occur. sources will trigger either the NSPS B. Endangered Species Act modification or reconstruction The EPA notes that the projected provisions that we are finalizing in this Consistent with the requirements of environmental effects of this final action rule. In Chapter 6 of the RIA, we discuss section 7(a)(2) of the Endangered are positive: Reductions in overall GHG factors that limit our ability to quantify Species Act (ESA), the EPA has also emissions, and reductions in PM and the costs and benefits of the standards considered the effects of this rule and ozone-precursor emissions (SOX and for modified and reconstructed sources. has reviewed applicable ESA NOX). The EPA recognizes that regulations, case law, and guidance to beneficial effects to listed species can, A. What are the air impacts? determine what, if any, impact there as a general matter, result in a ‘‘may As explained immediately above, the may be to listed endangered or affect’’ determination under the ESA. EPA does not anticipate that this final threatened species or the designated However, the EPA’s assessment that the rule will result in notable CO2 emission critical habitat of such species and rule will have an overall net positive changes by 2022 as a result of the whether consultation with the U.S. Fish environmental effect by virtue of standards of performance for newly and Wildlife Service (FWS) and/or reducing emissions of certain air constructed EGUs. The owners of newly National Marine Fisheries Service pollutants does not address whether the constructed EGUs will likely choose (together, the Services) is required by rule may affect any listed species or technologies, primarily NGCC, which designated critical habitat for ESA meet the standards even in the absence 570 Sharma, S.; Azzi, M.; ‘‘A critical review of section 7(a)(2) purposes and does not of this rule due to existing economic existing strategies for emission control in the constitute any finding of effects for that monoethanolamine-based carbon capture process conditions as normal business practice. and some recommendations for improved purpose. The fact that the rule will have As also explained immediately above, strategies’’, Fuel, 121, 178 (2014). overall positive effects on the national 571 the EPA expects few EGUs to trigger the Kamijo, T.; et al., ‘‘SO3 Impact on Amine NSPS modification or reconstruction Emission and Emission Reduction Technology’’, 574 See Endangered Species Consultation provisions in the period of analysis. Energy Procedia, Volume 37, 1793 (2013). Handbook, U.S. Fish & Wildlife Service and New steam generating EGUs that 572 Sharma, S. (2014). National Marine Fisheries Service at 4–25(March 573 Mertens, J.; et al., ‘‘Understanding 1998) (providing examples of direct effects: e.g., choose to comply with the final ethanolamine (MEA) and ammonia emissions from driving an off road vehicle through the nesting amine based post combustion carbon capture: habitat of a listed species of bird and destroying a 569 Conditions in the analysis year of 2022 are Lessons learned from field tests’’, Int’l J. of GHG ground nest; building a housing unit and destroying represented by a model year of 2020. Control, 13, 72 (2013). the habitat of a listed species). VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00132 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64641 and global environment does not mean emission reductions many orders of which asserted that the rule will cause that the rule may affect any listed magnitude greater over the lifetimes of a shift to alternative sources of energy species in its habitat or the designated the model years in question 576 and, such as wind and solar and that such critical habitat of such species within based on air quality modeling of facilities may have impacts on listed the meaning of ESA section 7(a)(2) or potential environmental effects, species. The comment inquired the implementing regulations or require concluded that ‘‘EPA knows of no regarding ESA consultation in ESA consultation. modeling tool which can link these connection with the rule. We reiterate The EPA notes that the emission small, time-attenuated changes in global that no consultation is required for a reductions achieved by the rule are metrics to particular effects on listed rule without potential for a specific projected to be minor. See Section XIII.F species in particular areas. Extrapolating impact on listed species in their and G. below, and RIA chapter 4. from global metric to local effect with habitats. Although the final rule imposes such small numbers, and accounting for C. What are the energy impacts? substantial controls on CO2 emissions, further links in a causative chain, we project few if any new fossil fuel- remain beyond current modeling This final rule is not anticipated to fired steam generating units to be built. capabilities.’’ EPA, Light Duty Vehicle have a notable effect on the supply, Emissions reductions from turbines are Greenhouse Gas Standards and distribution, or use of energy. As likewise projected to be minimal. Corporate Average Fuel Economy previously stated, the EPA believes that Moreover, we reasonably project that Standards, Response to Comment electric power companies will choose to capacity additions during the analysis Document for Joint Rulemaking at 4–102 build new EGUs that comply with the period out to 2022 would already be (Docket EPA–OAR–HQ–2009–4782). regulatory requirements of this rule compliant with the rule’s requirements The EPA reached this conclusion after even in its absence, primarily NGCC (e.g., natural gas combined cycle units, evaluating issues relating to potential units, because of existing and expected low capacity factor natural gas improvements relevant to both market conditions. As also previously combustion turbines, and small temperature and oceanographic pH stated, the EPA expects few EGUs to amounts of coal-fired units with CCS outputs. The EPA’s ultimate finding was trigger the NSPS modification or supported by federal and state funding). that ‘‘any potential for a specific impact reconstruction provisions in the period See RIA chapter 4. on listed species in their habitats of analysis. With respect to the projected GHG associated with these very small D. What are the water and solid waste emission reductions, the EPA does not changes in average global temperature impacts? believe that such minor reductions and ocean pH is too remote to trigger the trigger ESA consultation requirements threshold for ESA section 7(a)(2).’’Id. This final rule is not anticipated to under section 7(a)(2). In reaching this The EPA believes that the same have notable impacts on water or solid conclusion, the EPA is mindful of conclusions apply to the present action, waste. As we have noted, the EPA believes that utilities and project significant legal and technical analysis given that the projected CO2 emission undertaken by FWS and the U.S. reductions are far less than those developers will choose to build new Department of the Interior (DOI) in the projected for either of the light duty EGUs that comply with the regulatory context of listing the polar bear as a vehicle rules. See, e.g., Ground Zero requirements of this rule even in its threatened species under the ESA. In Center for Non-Violent Action v. U.S. absence, primarily through the that context, in 2008, FWS and DOI Dept. of Navy, 383 F. 3d 1082, 1091–92 construction of new NGCC units. As expressed the view that the best (9th Cir. 2004) (where the likelihood of also previously stated, the EPA expects scientific data available were jeopardy to a species from a federal few EGUs to trigger the NSPS insufficient to draw a causal connection action is extremely remote, ESA does modification or reconstruction between GHG emissions and effects on not require consultation). The EPA’s provisions in the period of analysis. the species in its habitat.575 The DOI conclusion is entirely consistent with Still there are expected to be a small Solicitor concluded that where the DOI’s analysis regarding ESA number of coal plants with CCS and the effect at issue is climate change, requirements in the context of federal use of CCS systems (especially post- proposed actions involving GHG actions involving GHG emissions.577 combustion system) will increase the emissions cannot pass the ‘‘may affect’’ The EPA received a comment on the amount of water used at the facility. If test of the section 7 regulations and thus proposal referencing a prior letter sent those plants utilize partial CCS to meet are not subject to ESA consultation. to the EPA by three U.S. Senators,578 the final standard of performance (i.e., The EPA has also previously approximately 16 to 23 percent capture), considered issues relating to GHG 576 See 75 FR at 25438 Table I.C 2–4 (May 7, the increased water use will not be emissions in connection with the 2010); 77 FR at 62894 Table III–68 (Oct. 15, 2012). significant. See Section V.O.2. The EPA 577 requirements of ESA section 7(a)(2) and The EPA has received correspondence from is unaware of any solid waste impact Members of Congress asserting that the Services resulting from this rule.579 has supplemented DOI’s analysis with have identified several listed species affected by additional consideration of GHG global climate change. The EPA’s assessment of E. What are the compliance costs? modeling tools and data regarding listed ESA requirements in connection with the present For steam generating EGUs, the EPA species. The EPA evaluated this same rule does not address whether global climate change may, as a general matter, be a relevant has carefully analyzed the costs of issue in the context of the light duty consideration in the status of certain listed species. meeting the promulgated standard of Rather, the requirements of ESA section 7(a)(2) vehicle GHG emission standards for performance for a highly efficient SCPC model years 2012–2016 and 2017–2025. must be considered and applied to the specific action at issue. As explained above, the EPA’s There the agency projected GHG conclusion that ESA section 7(a)(2) consultation is Protection Agency, and Dan Ashe, Director, U.S. not required here is premised on the specific facts Fish and Wildlife Service, dated March 6, 2014. 575 See, e.g., 73 FR 28212, 28300 (May 15, 2008); and circumstances of the present rule and is fully 579 Estimated costs for the rule include costs for Memorandum from David Longly Bernhardt, consistent with prior relevant analyses conducted fly ash and bottom ash disposal and for spent Solicitor, U.S. Department of the Interior re: by DOI, FWS, and the EPA. solvent recovery and handling. See ‘‘Cost and ‘‘Guidance on the Applicability of the Endangered 578 See Letter from David Vitter, James M. Inhofe, Performance Baseline for Fossil Energy Plants Species Act’s Consultation Requirements to and Mike Crapo, United States Senate Committee Volume 1a: Bituminous Coal (PC) and Natural Gas Proposed Actions Involving the Emission of on Environment and Public Works, to Gina to Electricity, Revision 3’’, DOE/NETL–2015/1723 Greenhouse Gases’’ (Oct. 3, 2008). McCarthy, Administrator, U.S. Environmental (July 2015) at pp. 43, 130. VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00133 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 64642 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations using partial CCS and found these costs G. What are the benefits of the final Units’’ (EPA–452/R–15–005, August to be reasonable. See Sections V.H and standards? 2015), is available in both dockets. I above. This analysis assumes new The EPA does not anticipate that this capacity not otherwise compliant with We are not projecting direct final action will result in any notable the standards would be constructed. monetized climate benefits in terms of compliance costs. Specifically, we Based on the analysis in chapter 4 of the CO2 emission reductions associated believe that the standards for newly RIA, the EPA believes the standards of with these standards of performance. constructed fossil fuel-fired EGUs performance for newly constructed This is because, as stated above, the (electric utility steam generating units EGUs will have no notable compliance EPA believes that electric power and natural gas-fired stationary costs, because electric power companies companies will choose to build new combustion turbines) will have are expected to build new EGUs that EGUs that comply with the regulatory negligible costs associated with it over comply with the regulatory requirements of this rule even in its a range of likely sensitivity conditions requirements of this final rule even in absence, primarily NGCC units, because because electric power companies will the absence of the rule, primarily NGCC of existing and expected market choose to build new EGUs that comply units, due to existing and expected conditions. See RIA chapter 4. with the regulatory requirements of this market conditions. While the EPA’s Moreover, a cost-reasonable standard is, action even in the absence of the action, analysis and projections from EIA in fact, what will drive new technology because of existing and expected market continue to show that the rule is likely deployment and provide a path forward conditions. (See the RIA for further to result in negligible costs and benefits for new coal-fired capacity. See Section discussion of sensitivities). The EPA due to existing generation choices, the V.L above. does not project any new coal-fired EPA recognizes that some companies As also previously stated, the EPA steam generating units without CCS to may choose to construct coal or other anticipates few units will trigger the be built in the absence of this action. fossil fuel-fired units and has set NSPS modification or reconstruction However, because some companies may standards for these units accordingly. provisions. In Chapter 6 of the RIA, we choose to construct coal or other fossil For this reason, the RIA also analyzes discuss factors that limit our ability to fuel-fired EGUs, the RIA also analyzes project-level costs of a unit with and quantify the costs and benefits of the project-level costs of a unit with and without CCS, to quantify the potential standards for modified and without CCS, to quantify the potential cost for a fossil fuel-fired unit with CCS. reconstructed sources. cost for a fossil fuel-fired EGU with In addition, the EPA believes the CCS. XIV. Statutory and Executive Order The EPA also believes that the standards of performance for modified Reviews standards for modified and and reconstructed EGUs will have reconstructed fossil fuel-fired EGUs will minimal associated compliance costs, Additional information about these result in minimal compliance costs, because, as previously stated, the EPA Statutory and Executive Orders can be because, as previously stated, the EPA found at http://www2.epa.gov/laws- expects few EGUs to trigger the NSPS expects few EGUs to trigger the NSPS regulations/laws-and-executive-orders. modification or reconstruction modification or reconstruction provisions in the period of analysis. A. Executive Order 12866: Regulatory provisions in the period of analysis F. What are the economic and Planning and Review and Executive (through 2022). In Chapter 6 of the RIA, employment impacts? Order 13563: Improving Regulation and we discuss factors that limit our ability Regulatory Review to quantify the costs and benefits of the The EPA does not anticipate that this standards for modified and final rule will result in notable CO2 This final action is a significant reconstructed sources. emission changes, energy impacts, regulatory action that was submitted to monetized benefits, costs, or economic the Office of Management and Budget B. Paperwork Reduction Act (PRA) impacts by 2022 as a result of the (OMB) for review. It is a significant The information collection activities standards of performance for newly regulatory action because it raises novel in this final action have been submitted constructed EGUs. The owners of newly legal or policy issues arising out of legal for approval to OMB under the PRA. constructed EGUs will likely choose mandates. Any changes made in The Information Collection Request technologies that meet the standards response to OMB recommendations (ICR) document that the EPA prepared even in the absence of this rule, due to have been documented in the has been assigned EPA ICR number existing economic conditions as normal established dockets for this action under 2465.03. Separate ICR documents were business practice. Likewise, the EPA Docket ID No. EPA–HQ–OAR–2013– prepared and submitted to OMB for the believes this rule will not have any 0495 (Standards of Performance for proposed standards for newly impacts on the price of electricity, Greenhouse Gas Emissions from New constructed EGUs (EPA ICR number employment or labor markets, or the Stationary Sources: Electric Utility 2465.02) and the proposed standards for U.S. economy. See RIA chapter 4.6.580 Generating Units) and Docket ID No. modified and reconstructed EGUs (EPA As previously stated, the EPA EPA–HQ–OAR–2013–0603 (Carbon ICR number 2506.01). Because the CO2 anticipates few units will trigger the Pollution Standards for Modified and standards for newly constructed, NSPS modification or reconstruction Reconstructed Stationary Sources: modified, and reconstructed EGUs will provisions. As with the new source Electric Utility Generating Units). The be included in the same new subpart (40 standards, the EPA does not expect EPA prepared an economic analysis of CFR part 60, subpart TTTT) and are macroeconomic or employment impacts the potential costs and benefits being finalized in the same action, the as a result of the standards. associated with this action. This ICR document for this action includes analysis, which is contained in the estimates of the information collection 580 The employment analysis in the RIA is part of ‘‘Regulatory Impact Analysis for the burden on owners and operators of the EPA’s ongoing effort to ‘‘conduct continuing Standards of Performance for newly constructed, modified, and evaluations of potential loss or shifts of employment which may result from the Greenhouse Gas Emissions for New, reconstructed EGUs. Estimated cost administration or enforcement of [the Act]’’ Modified, and Reconstructed Stationary burden is based on 2013 Bureau of pursuant to CAA section 321(a). Sources: Electric Utility Generating Labor Statistics (BLS) labor cost data. VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00134 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64643 Thus, all burden estimates are in 2013 2014) to commence operation over the reporting burden for such a unit is dollars. Burden is defined at 5 CFR 3-year period covered by this ICR. We estimated to be $1,333 and 16 labor 1320.3(b). You can find a copy of the estimate that 12 affected newly hours. There are no annualized capital ICR in the dockets for this action constructed NGCC units and 25 affected costs or O&M costs associated with (Docket ID Numbers EPA–HQ–OAR– newly constructed natural gas-fired burden for modified or reconstructed 2013–0495 and EPA–HQ–OAR–2013– simple cycle combustion turbines will EGUs. 0603), and it is briefly summarized here. commence operation during that time 3. Information Collection Burden The information collection requirements period. As a result of this final action, are not enforceable until OMB approves owners or operators of those newly The annual information collection them. constructed units will be required to burden for newly constructed, modified, The recordkeeping and reporting prepare a summary report, which and reconstructed EGUs consists only of requirements in this final action are includes reporting of emissions and reporting burden as explained above. specifically authorized by CAA section downtime, every 3 months. The annual reporting burden for this 114 (42 U.S.C. 7414). All information collection (averaged over the first 3 submitted to the EPA pursuant to the 2. Modified and Reconstructed EGUs years after the effective date of the recordkeeping and reporting This final action is not expected to standards) is estimated to be $60,977 requirements for which a claim of impose an information collection and 651 labor hours. There are no confidentiality is made is safeguarded burden under the provisions of the PRA annualized capital costs or O&M costs according to agency policies set forth in on owners and operators of affected associated with burden for newly 40 CFR part 2, subpart B. modified and reconstructed fossil fuel- constructed, modified, or reconstructed An agency may not conduct or fired EGUs (steam generating units and EGUs. Average burden hours per sponsor, and a person is not required to stationary combustion turbines). As response are estimated to be 7 hours. respond to, a collection of information previously stated, the EPA expects few The total number of respondents over unless it displays a currently valid OMB EGUs to trigger the NSPS modification the 3-year ICR period is estimated to be control number. The OMB control or reconstruction provisions in the 62. numbers for the EPA’s regulations in 40 period of analysis. Specifically, the EPA C. Regulatory Flexibility Act (RFA) CFR are listed in 40 CFR part 9. When believes it unlikely that fossil fuel-fired OMB approves this ICR, the agency will electric utility steam generating units or I certify that this final action will not announce that approval in the Federal stationary combustion turbines will take have a significant economic impact on Register and publish a technical actions that would constitute a substantial number of small entities amendment to 40 CFR part 9 to display modifications or reconstructions as under the RFA. In making this the OMB control number for the defined under the EPA’s NSPS determination, the impact of concern is approved information collection regulations. Accordingly, the standards any significant adverse economic activities contained in this final action. for modified and reconstructed EGUs impact on small entities. An agency may are not anticipated to impose any certify that a rule will not have a 1. Newly Constructed EGUs information collection burden over the significant economic impact on a This final action will impose minimal 3-year period covered by this ICR. We substantial number of small entities if new information collection burden on have estimated, however, the the rule relieves regulatory burden, has owners and operators of affected newly information collection burden that no net burden or otherwise has a constructed fossil fuel-fired EGUs would be imposed on an affected EGU positive economic effect on the small (steam generating units and stationary if it was modified or reconstructed. entities subject to the rule. combustion turbines) beyond what Although not anticipated, if an EGU 1. Newly Constructed EGUs those sources would already be subject were to modify or reconstruct, this final to under the authorities of CAA parts 75 action would impose minimal The EPA believes that electric power and 98. OMB has previously approved information collection burden on those companies will choose to build new the information collection requirements affected EGUs beyond what they would fossil fuel-fired electric utility steam contained in the existing part 75 and 98 already be subject to under the generating units or natural gas-fired regulations (40 CFR part 75 and 40 CFR authorities of CAA 40 CFR parts 75 and stationary combustion turbines that part 98) under the provisions of the 98. As described above, the OMB has comply with the regulatory Paperwork Reduction Act, 44 U.S.C. previously approved the information requirements of the final rule because of 3501 et seq. and has assigned OMB collection requirements contained in the existing and expected market control numbers 2060–0626 and 2060– existing part 75 and 98 regulations. conditions. RIA Chapter 4. The EPA 0629, respectively. Apart from certain Apart from certain reporting costs to does not project any new coal-fired reporting costs to comply with the comply with the emission standards steam generating units without CCS to emission standards under the rule, there under the rule, there would be no new be built. We expect that any newly are no new information collection costs, information collection costs, as the constructed natural gas-fired stationary as the information required by the information required by the final rule is combustion turbines will meet the standards for newly constructed EGUs is already collected and reported by other standards. We do not include an already collected and reported by other regulatory programs. analysis of the illustrative impacts on regulatory programs. As stated above, although the EPA small entities that may result from The EPA believes that electric power expects few sources will trigger either implementation of the final rule because companies will choose to build new the NSPS modification or reconstruction we anticipate negligible compliance EGUs that comply with the regulatory provisions, if an EGU were to modify or costs over a range of likely sensitivity requirements of the rule because of reconstruct during the 3-year period conditions as a result of the standards existing and expected market covered by this ICR, the owner or for newly constructed EGUs. Thus the conditions. The EPA does not project operator of the EGU will be required to cost-to-sales ratios for any affected small any newly constructed coal-fired steam prepare a summary report, which entity would be zero costs as compared generating units that commenced includes reporting of emissions and to annual sales revenue for the entity. construction after proposal (January 8, downtime, every 3 months. The annual Accordingly, there are no anticipated VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00135 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 64644 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations economic impacts as a result of the steam generating units or natural gas- modification or reconstruction standards for newly constructed EGUs. fired stationary combustion turbines provisions in the period of analysis. (See the ‘‘Regulatory Impact Analysis that comply with the regulatory E. Executive Order 13132: Federalism for the Standards of Performance for requirements of the rule because of Greenhouse Gas Emissions for New, existing and expected market This final action does not have Modified, and Reconstructed Stationary conditions. The EPA does not project federalism implications. It will not have Sources: Electric Utility Generating any new coal-fired steam generating substantial direct effects on the states, Units’’ (EPA–452/R–15–005, August units without CCS to be built and on the relationship between the national 2015) for further discussion of expects that any newly constructed government and the states, or on the sensitivities.) We have therefore natural gas-fired stationary combustion distribution of power and concluded that this final action will turbines will meet the standards. (See responsibilities among the various have no net regulatory burden for all the ‘‘Regulatory Impact Analysis for the levels of government. The EPA believes directly regulated small entities. Standards of Performance for that electric power companies will Greenhouse Gas Emissions for New, choose to build new fossil fuel-fired 2. Modified and Reconstructed EGUs Modified, and Reconstructed Stationary electric utility steam generating units or The EPA expects few fossil fuel-fired Sources: Electric Utility Generating natural gas-fired stationary combustion electric utility steam generating units to Units’’ (EPA–452/R–15–005, August turbines that comply with the regulatory trigger the NSPS modification 2015) for further discussion of requirements of the final rule because of provisions in the period of analysis. An sensitivities.) existing and expected market NSPS modification is defined as a As previously stated, the EPA expects conditions. In addition, as previously physical or operational change that few fossil fuel-fired electric utility steam stated, the EPA expects few fossil fuel- increases the source’s maximum generating units or natural gas-fired fired electric utility steam generating achievable hourly rate of emissions. The stationary combustion turbines to trigger units or natural gas-fired stationary EPA does not believe that there are the NSPS modification or reconstruction combustion turbines to trigger the NSPS likely to be EGUs that will take actions provisions in the period of analysis. In modification or reconstruction that would constitute modifications as Chapter 6 of the RIA, we discuss factors provisions in the period of analysis. We, defined under the EPA’s NSPS that limit our ability to quantify the therefore, anticipate that the final rule regulations. costs and benefits of the standards for will impose minimal compliance costs. In addition, the EPA expects few modified and reconstructed sources. F. Executive Order 13175: Consultation reconstructed fossil fuel-fired electric However, we do not anticipate that the and Coordination With Indian Tribal utility steam generating units or natural rule would impose significant costs on Governments gas-fired stationary combustion turbines those sources. (See the ‘‘Regulatory in the period of analysis. Reconstruction Impact Analysis for the Standards of This final action does not have tribal occurs when a single project replaces Performance for Greenhouse Gas implications as specified in Executive components or equipment in an existing Emissions for New, Modified, and Order 13175. The final rule will impose facility and exceeds 50 percent of the Reconstructed Stationary Sources: requirements on owners and operators fixed capital cost that would be required Electric Utility Generating Units’’ (EPA– of newly constructed, modified, and to construct a comparable entirely new 452/R–15–005, August 2015).) reconstructed EGUs. The EPA is aware facility. We have therefore concluded that the of three facilities with coal-fired steam In Chapter 6 of the RIA, we discuss standards for newly constructed, generating units, as well as one facility factors that limit our ability to quantify modified, and reconstructed EGUs do with natural gas-fired stationary the costs and benefits of the standards not impose enforceable duties on any combustion turbines, located in Indian for modified and reconstructed sources. state, local or tribal governments, or the Country, but is not aware of any EGUs However, we do not anticipate that the private sector, that may result in owned or operated by tribal entities. We rule would impose significant costs on expenditures by state, local and tribal note that because the rule addresses CO2 those sources, including any that are governments, in the aggregate, or to the emissions from newly constructed, owned by small entities. (See the private sector, of $100 million or more modified, and reconstructed EGUs, it ‘‘Regulatory Impact Analysis for the in any one year. We have also will affect existing EGUs such as those Standards of Performance for concluded that this action does not have located at the four facilities in Indian Greenhouse Gas Emissions for New, regulatory requirements that might Country only if those EGUs were to take Modified, and Reconstructed Stationary significantly or uniquely affect small actions constituting modifications or Sources: Electric Utility Generating governments. The threshold amount reconstructions as defined under the Units’’ (EPA–452/R–15–005, August established for determining whether EPA’s NSPS regulations. As previously 2015). regulatory requirements could stated, the EPA expects few EGUs to significantly affect small governments is trigger the NSPS modification or D. Unfunded Mandates Reform Act $100 million annually and, as stated reconstruction provisions in the period (UMRA) above, we have concluded that the final of analysis. Thus, the rule will neither This final action does not contain an action will not result in expenditures of impose substantial direct compliance unfunded mandate of $100 million or $100 million or more in any one year. costs on tribal governments nor preempt more as described in UMRA, 2 U.S.C. Specifically, the EPA does not project Tribal law. Accordingly, Executive 1531–1538, and does not significantly or any new coal-fired steam generating Order 13175 does not apply to this uniquely affect small governments. units without CCS to be built and action. The EPA believes the final rule will expects that any newly constructed Nevertheless, because the EPA is have negligible compliance costs on natural gas-fired stationary combustion aware of Tribal interest in carbon owners and operators of newly turbines will meet the standards. pollution standards for the power sector constructed EGUs over a range of likely Further, the EPA expects few fossil fuel- and, consistent with the EPA Policy on sensitivity conditions because electric fired electric utility steam generating Consultation and Coordination with power companies will choose to build units or natural gas-fired stationary Indian Tribes, the EPA offered new fossil fuel-fired electric utility combustion turbines to trigger the NSPS consultation with tribal officials during VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00136 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64645 development of this rule. Prior to the G. Executive Order 13045: Protection of heat waves, storms, and floods. April 13, 2012 proposal (77 FR 22392), Children From Environmental Health Additional health concerns may arise in the EPA sent consultation letters to the Risks and Safety Risks low income households, especially leaders of all federally recognized tribes. This action is not subject to Executive those with children, if climate change Although only newly constructed, Order 13045 because it is not reduces food availability and increases modified, and reconstructed EGUs will economically significant as defined in prices, leading to food insecurity within be affected by this action, the EPA’s Executive Order 12866. While the action households. More detailed information on the consultation regarded planned actions is not subject to Executive Order 13045, impacts of climate change to human for new and existing sources. The letters the EPA believes that the environmental health and welfare is provided in provided information regarding the health or safety risk addressed by this Section II.A of this preamble. EPA’s development of NSPS and action has a disproportionate effect on emission guidelines for EGUs and children. Accordingly, the agency has H. Executive Order 13211: Actions offered consultation. A consultation/ evaluated the environmental health and Concerning Regulations That outreach meeting was held on May 23, welfare effects of climate change on Significantly Affect Energy Supply, 2011, with the Forest County children. Distribution, or Use Potawatomi Community, the Fond du CO2 is a potent GHG that contributes This final action is not a ‘‘significant Lac Band of Lake Superior Chippewa to climate change and is emitted in energy action’’ because it is not likely to Reservation, and the Leech Lake Band of significant quantities by fossil fuel-fired have a significant adverse effect on the Ojibwe. A description of that power plants. As stated above, the EPA supply, distribution, or use of energy. consultation is included in the preamble believes the final rule will have See Section V.O.3 above. The EPA to the proposed standards for new EGUs negligible effects on owners and believes that electric power companies (79 FR 1501, January 8, 2014). operators of newly constructed EGUs will choose to build new fossil fuel-fired The EPA also offered consultation to over a range of likely sensitivity electric utility steam generating units or the leaders of all federally recognized conditions because electric power natural gas-fired stationary combustion tribes after the proposed action for companies will choose to build new turbines that comply with the regulatory newly constructed EGUs was signed on fossil fuel-fired electric utility steam requirements of the final rule because of September, 20, 2013. On November 1, generating units or natural gas-fired existing and expected market 2013, the EPA sent letters to tribal stationary combustion turbines that conditions. In addition, as previously leaders that provided information comply with the regulatory stated, the EPA expects few fossil fuel- regarding the EPA’s development of requirements of the rule because of fired electric utility steam generating carbon pollution standards for new, existing and expected market units or natural gas-fired stationary modified, reconstructed and existing conditions. However, the RIA also combustion turbines to trigger the NSPS EGUs and offered consultation. No analyzes project-level costs of a unit modification or reconstruction tribes requested consultation regarding with and without CCS, to quantify the provisions in the period of analysis. the standards for newly constructed potential cost for a fossil fuel-fired unit Thus, this action is not anticipated to EGUs. with CCS. RIA chapter 5. Under these have notable impacts on emissions, scenarios, the rule would result in In addition to offering consultation, costs or energy supply decisions for the substantial reductions of both CO2, and affected electric utility industry. the EPA also conducted outreach to also fine particulate matter (sulfate PM tribes during development of this rule. 2.5) such that net quantifiable benefits I. National Technology Transfer and The EPA held a series of listening exceed regulatory costs under a range of Advancement Act (NTTAA) and 1 CFR sessions prior to proposal of GHG assumptions. Under these same Part 51 standards for newly constructed EGUs. scenarios, this rule would have a This final action involves technical Tribes participated in a session on positive effect for children’s health. standards. The EPA has decided to use February 17, 2011, with the state The assessment literature cited in the 10 voluntary consensus standards (VCS) agencies, as well as in a separate session EPA’s 2009 Endangerment Finding in the final rule. with tribes on April 20, 2011. The EPA concluded that certain populations and One VCS, American National also held a series of listening sessions lifestages, including children, the Standards Institute (ANSI) Standard prior to proposal of GHG standards for elderly, and the poor, are most C12.20, ‘‘American National Standard modified and reconstructed EGUs and vulnerable to climate-related health for Electricity Meters—0.2 and 0.5 GHG emission guidelines for existing effects. The assessment literature since Accuracy Classes,’’ is cited in the final EGUs. Tribes participated in a session 2009 strengthens these conclusions by rule to assure consistent monitoring of on September 9, 2013, together with the providing more detailed findings electric output. This standard state agencies, as well as in a separate regarding these groups’ vulnerabilities establishes the physical aspects and tribe-only session on September 26, and the projected impacts they may acceptable performance criteria for 0.2 2013. In addition, an outreach meeting experience. and 0.5 accuracy class electricity was held on September 9, 2013, with These assessments describe how meters. This standard is available at tribal representatives from some of the children’s unique physiological and http://www.ansi.org or by mail at federally recognized tribes. The EPA developmental factors contribute to American National Standards Institute also met with tribal environmental staff making them particularly vulnerable to (ANSI), 25 W. 43rd Street, 4th Floor, with the National Tribal Air climate change. Impacts to children are New York, NY 10036. Association, by teleconference, on July expected from heat waves, air pollution, Six VCS, ASTM Methods D388–99, 25, 2013, and December 19, 2013. infectious and waterborne illnesses, and ‘‘Standard Classification of Coals by Additional detail regarding this mental health effects resulting from Rank’’; D396–98, ‘‘Standard stakeholder outreach is included in the extreme weather events. In addition, Specification for Fuel Oils’’; D975–08a, preamble to the proposed emission children are among those especially ‘‘Standard Specification for Diesel Fuel guidelines for existing EGUs (79 FR susceptible to most allergic diseases, as Oils’’; D3699–08, ‘‘Standard 34830, June 18, 2014). well as health effects associated with Specification for Kerosine’’; D6751–11b, VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00137 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 64646 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations ‘‘Standard Specification for Biodiesel Plant Performance’’ are cited in the final 2314 includes procedures for the Fuel Blend Stock (B100) for Middle rule for their guidance on measuring the determination of the following Distillate Fuels’’; and D7467–10, performance of stationary combustion performance parameters, corrected to ‘‘Standard Specification for Diesel Fuel turbines. PTC–22 provides directions the reference operating parameters: Oil, Biodiesel Blend (B6 to B20)’’ are and rules for conduct and report of electrical or mechanical power output cited in the final rule to identify the results of thermal performance tests for (gas power, if only gas is supplied), different fuel types. ASTM D388 covers open cycle simple cycle combustion thermal efficiency or heat rate; and the classification of coals by rank, that turbines. The object is to determine the combustion turbine engine exhaust is, according to their degree of thermal performance of the combustion energy (optionally exhaust temperature metamorphism, or progressive turbine when operating at test and flow). This standard is available at alteration, in the natural series from conditions, and correcting these test http://www.iso.org/iso/home.htm or by lignite to anthracite. ASTM D396 covers results to specified reference conditions. mail at International Organization for grades of fuel oil intended for use in PTC 22 provides explicit procedures for Standardization (ISO), 1, ch. de la Voie- various types of fuel-oil-burning the determination of the following Creuse, Case postale 56, CH–1211 equipment under various climatic and performance results: corrected power, Geneva 20, Switzerland. operating conditions. These include corrected heat rate (efficiency), Since no EPA Methods were used, Grades 1 and 2 (for use in domestic and corrected exhaust flow, corrected there was no need for a NTTAA search. small industrial burners), Grade 4 exhaust energy, and corrected exhaust The rule also requires use of appendices (heavy distillate fuels or distillate/ temperature. Tests may be designed to A, B, D, F and G to 40 CFR part 75 and residual fuel blends used in satisfy different goals, including the procedures under 40 CFR 98.33; commercial/industrial burners equipped absolute performance and comparative these appendices contain standards that for this viscosity range), and Grades 5 performance. The objective of PTC 46 is have already been reviewed under the and 6 (residual fuels of increasing to provide uniform test methods and NTTAA. viscosity and boiling range, used in procedures for the determination of the J. Executive Order 12898: Federal industrial burners). ASTM D975 covers thermal performance and electrical Actions To Address Environmental seven grades of diesel fuel oils based on output of heat-cycle electric power Justice in Minority Populations and grade, sulfur content, and volatility. plants and combined heat and power Low-Income Populations These grades range from Grade No. 1– units (PTC 46 is not applicable to Executive Order 12898 (59 FR 7629; D S15 (a special-purpose, light middle simple cycle combustion turbines). Test February 16, 1994) establishes federal results provide a measure of the distillate fuel for use in diesel engine executive policy on environmental applications requiring a fuel with 15 performance of a power plant or thermal justice. Its main provision directs ppm sulfur (maximum) and higher island at a specified cycle configuration, federal agencies, to the greatest extent volatility than that provided by Grade operating disposition and/or fixed practicable and permitted by law, to No. 2–D S15 fuel) to Grade No. 4–D (a power level, and at a unique set of base make environmental justice part of their heavy distillate fuel, or a blend of reference conditions. PTC 46 provides mission by identifying and addressing, distillate and residual oil, for use in explicit procedures for the as appropriate, disproportionately high low- and medium-speed diesel engines determination of the following and adverse human health or in applications involving predominantly performance results: corrected net environmental effects of their programs, constant speed and load). ASTM D3699 power, corrected heat rate, and policies, and activities on minority covers two grades of kerosene suitable corrected heat input. These standards populations and low-income for use in critical kerosene burner are available at http://www.asme.org or populations in the U.S. The EPA defines applications: No. 1–K (a special low- by mail at American Society of environmental justice as the fair sulfur grade kerosene suitable for use in Mechanical Engineers (ASME), Two treatment and meaningful involvement non-flue-connected kerosene burner Park Avenue, New York, NY 10016– of all people regardless of race, color, appliances and for use in wick-fed 5990. national origin, or income with respect illuminating lamps) and No. 2–K (a One VCS, International Organization to the development, implementation, regular grade kerosene suitable for use for Standardization method ISO and enforcement of environmental laws, in flue-connected burner appliances and 2314:2009, ‘‘Gas Turbines—Acceptance regulations, and policies. The EPA has for use in wick-fed illuminating lamps). Tests’’ is cited in the final rule for its this goal for all communities and ASTM D6751 covers biodiesel (B100) guidance on determining performance persons across this Nation. It will be Grades S15 and S500 for use as a blend characteristics of stationary combustion achieved when everyone enjoys the component with middle distillate fuels. turbines. ISO 2314 specifies guidelines same degree of protection from ASTM D7467 covers fuel blend grades and procedures for preparing, environmental and health hazards and of 6 to 20 volume percent biodiesel with conducting and reporting thermal- equal access to the decision-making the remainder being a light middle or acceptance tests in order to determine process to have a healthy environment middle distillate diesel fuel, collectively and/or verify electrical power output, in which to live, learn, and work. designated as B6 to B20. These mechanical power, thermal efficiency Leading up to this rulemaking the standards are available at http:// (heat rate), turbine exhaust gas energy EPA summarized the public health and www.astm.org or by mail at ASTM and/or other performance characteristics welfare effects of GHG emissions in its International, 100 Barr Harbor Drive, of open-cycle simple cycle combustion 2009 Endangerment Finding. As part of P.O. Box CB700, West Conshohocken, turbines using combustion systems the Endangerment Finding, the PA 19428–2959. supplied with gaseous and/or liquid Administrator considered climate Two VCS, American Society of fuels as well as closed-cycle and semi- change risks to minority or low-income Mechanical Engineers (ASME) closed-cycle simple cycle combustion populations, finding that certain parts of Performance Test Codes PTC 22–2014, turbines. It can also be applied to simple the population may be especially ‘‘Performance Test Codes on Gas cycle combustion turbines in combined vulnerable based on their Turbines’’ and PTC 46–1996, cycle power plants or in connection circumstances. Populations that were ‘‘Performance Test Codes on Overall with other heat recovery systems. ISO found to be particularly vulnerable to VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00138 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64647 climate change risks include the poor, provides more detailed findings utility steam generating units and the elderly, the very young, those regarding these populations’ natural gas-fired stationary combustion already in poor health, the disabled, vulnerabilities and projected impacts turbines that comply with the regulatory those living alone, and/or indigenous they may experience. In addition, the requirements of the final rule because of populations dependent on one or a few most recent assessment reports provides existing and expected market resources. See Sections XIV.F and G, new information on how some conditions. The EPA does not project above, where the EPA discusses communities of color may be uniquely any new coal-fired steam generating Consultation and Coordination with vulnerable to climate change health units without CCS to be built and Tribal Governments and Protection of impacts in the United States. These expects that any newly built natural gas- Children. The Administrator placed reports find that certain climate change fired stationary combustion turbines weight on the fact that certain groups, related impacts—including heat waves, will meet the standards. In addition, as including children, the elderly, and the degraded air quality, and extreme previously stated, the EPA expects few poor, are most vulnerable to climate- weather events—have disproportionate fossil fuel-fired electric utility steam related health effects. effects on low-income and some generating units or natural gas-fired The record for the 2009 communities of color, raising stationary combustion turbines to trigger Endangerment Finding summarizes the environmental justice concerns. Existing the NSPS modification or reconstruction health disparities and other inequities strong scientific evidence in the major provisions in the period of analysis. assessment reports by the U.S. Global in these communities increase their This final rule will ensure that, to Change Research Program (USGCRP), vulnerability to the health effects of whatever extent there are newly the Intergovernmental Panel on Climate climate change. In addition, assessment constructed, modified, and Change (IPCC), and the National reports also find that climate change reconstructed EGUs, they will use the Research Council (NRC) of the National poses particular threats to health, best performing technologies to limit Academies that the potential impacts of wellbeing, and ways of life of climate change raise environmental indigenous peoples in the United States. emissions of CO2. justice issues. These reports concluded As the scientific literature presented K. Congressional Review Act (CRA) that poor communities can be especially above and in the Endangerment Finding vulnerable to climate change impacts illustrates, low income communities This final action is subject to the CRA, because they tend to have more limited and some communities of color are and the EPA will submit a rule report adaptive capacities and are more especially vulnerable to the health and to each House of the Congress and to the dependent on climate-sensitive other adverse impacts of climate change. Comptroller General of the United resources such as local water and food The EPA believes the human health or States. This action is not a ‘‘major rule’’ supplies. In addition, Native American environmental risk addressed by this as defined by 5 U.S.C. 804(2). tribal communities possess unique final action will not have potential XV. Withdrawal of Proposed Standards vulnerabilities to climate change, disproportionately high and adverse particularly those impacted by human health or environmental effects for Certain Modified Sources degradation of natural and cultural on minority, low-income or indigenous populations. The final rule limits GHG In this action, as discussed above in resources within established reservation Sections IV and VI, the EPA is issuing boundaries and threats to traditional emissions from newly constructed, modified, and reconstructed fossil fuel- final standards of performance for subsistence lifestyles. Tribal affected fossil fuel-fired steam communities whose health, economic fired electric utility steam generating units and newly constructed and generating EGUs that implement well-being, and cultural traditions modifications resulting in an increase of depend upon the natural environment modified stationary combustion turbines by establishing national CO2 emissions (in lb/hr) of more than 10 will likely be affected by the percent. In addition, the EPA is degradation of ecosystem goods and emission standards for CO2. The EPA has determined that the final withdrawing the proposed standards of services associated with climate change. rule will not result in disproportionately performance for emissions of carbon The 2009 Endangerment Finding record high and adverse human health or dioxide (CO ) from modified fossil fuel- also specifically noted that Southwest 2 environmental effects on minority, low- fired EGUs not covered by those final native cultures are especially vulnerable income or indigenous populations standards. Specifically, the EPA is to water quality and availability because the rule is not anticipated to withdrawing the proposed standards for impacts. Native Alaskan communities notably affect the level of protection fossil fuel-fired steam generating EGUs are already experiencing disruptive provided to human health or the that implement modifications resulting impacts, including coastal erosion and environment. The EPA believes that shifts in the range or abundance of wild in an increase of CO2 emissions (in lb/ electric power companies will choose to hr) of less than or equal to 10 percent. species crucial to their livelihoods and build new fossil fuel-fired electric well-being. A detailed rationale for the withdrawal The most recent assessments continue of these proposed standards is provided Intergovernmental Panel on Climate Change [Field, in Section VI above. to strengthen scientific understanding of C.B., V.R. Barros, D.J. Dokken, K.J. Mach, M.D. climate change risks to minority and Mastrandrea, T.E. Bilir, M. Chatterjee, K.L. Ebi, Y.O. The EPA is also, in this action, low-income populations in the United Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N. withdrawing proposed standards for 581 Levy, S. MacCracken, P.R. Mastrandrea, and L.L. States. The new assessment literature White (eds.)]. Cambridge University Press, 1132 pp. modified stationary combustion IPCC, 2014: Climate Change 2014: Impacts, turbines. A detailed rationale for the 581 Melillo, Jerry M., Terese (T.C.) Richmond, and Adaptation, and Vulnerability. Part B: Regional withdrawal of these proposed standards Gary W. Yohe, Eds., 2014: Climate Change Impacts Aspects. Contribution of Working Group II to the is provided in Section IX above. in the United States: The Third National Climate Fifth Assessment Report of the Intergovernmental Assessment. U.S. Global Change Research Program, Panel on Climate Change [Barros, V.R., C.B. Field, The proposed standards for modified 841 pp. D.J. Dokken, M.D. Mastrandrea, K.J. Mach, T.E. fossil fuel-fired EGUs that the EPA is IPCC, 2014: Climate Change 2014: Impacts, Bilir, M. Chatterjee, K.L. Ebi, Y.O. Estrada, R.C. withdrawing in this action were Adaptation, and Vulnerability. Part A: Global and Genova, B. Girma, E.S. Kissel, A.N. Levy, S. Sectoral Aspects. Contribution of Working Group II MacCracken, P.R. Mastrandrea, and L.L. White published in the Federal Register on to the Fifth Assessment Report of the (eds.)]. Cambridge University Press, 688 pp. June 18, 2014 (79 FR 34960). VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00139 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 64648 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations XVI. Statutory Authority § 60.17 Incorporations by reference. (December 15, 2009), IBR approved for The statutory authority for this action * * * * * § 60.5580. is provided by sections 111, 301, 302, (d) The following material is available * * * * * and 307(d)(1)(C) of the CAA as amended for purchase from the American ■ 3. Part 60 is amended by adding (42 U.S.C. 7411, 7601, 7602, National Standards Institute (ANSI), 25 subpart TTTT to read as follows: W. 43rd Street, 4th Floor, New York, NY 7607(d)(1)(C)). This action is also Subpart TTTT—Standards of Performance subject to section 307(d) of the CAA (42 10036, Telephone (212) 642–4980, and for Greenhouse Gas Emissions for Electric U.S.C. 7607(d)). is also available at the following Web Generating Units site: http://www.ansi.org. List of Subjects (1) ANSI No. C12.20–2010 American Applicability 40 CFR Part 60 National Standard for Electricity Sec. 60.5508 What is the purpose of this Environmental protection, Meters—0.2 and 0.5 Accuracy Classes (Approved August 31, 2010), IBR subpart? Administrative practice and procedure, 60.5509 Am I subject to this subpart? Air pollution control, Incorporation by approved for § 60.5535(d). reference, Intergovernmental relations, (2) [Reserved] Emission Standards Reporting and recordkeeping * * * * * 60.5515 Which pollutants are regulated by requirements. (g) * * * this subpart? (15) ASME PTC 22–2014, Gas 60.5520 What CO2 emissions standard must 40 CFR Part 70 Turbines: Performance Test Codes, I meet? Environmental protection, (Issued December 31, 2014), IBR General Compliance Requirements Administrative practice and procedure, approved for § 60.5580. 60.5525 What are my general requirements Air pollution control, Intergovernmental (16) ASME PTC 46–1996, for complying with this subpart? relations, Reporting and recordkeeping Performance Test Code on Overall Plant requirements. Monitoring and Compliance Determination Performance, (Issued October 15, 1997), Procedures IBR approved for § 60.5580. 40 CFR Part 71 60.5535 How do I monitor and collect data * * * * * Environmental protection, to demonstrate compliance? Administrative practice and procedure, (h) * * * 60.5540 How do I demonstrate compliance Air pollution control, Reporting and (37) ASTM D388–99 (Reapproved with my CO2 emissions standard and ε1 determine excess emissions? recordkeeping requirements. 2004) Standard Classification of Coals by Rank, IBR approved for §§ 60.41, Notifications, Reports, and Records 40 CFR Part 98 60.45(f), 60.41Da, 60.41b, 60.41c, 60.5550 What notifications must I submit Environmental protection, 60.251, and 60.5580. and when? Greenhouse gases and monitoring, * * * * * 60.5555 What reports must I submit and Reporting and recordkeeping (42) ASTM D396–98, Standard when? requirements. Specification for Fuel Oils, IBR 60.5560 What records must I maintain? 60.5565 In what form and how long must I Dated: August 3, 2015. approved for §§ 60.41b, 60.41c, keep my records? Gina McCarthy, 60.111(b), 60.111a(b), and 60.5580. Administrator. * * * * * Other Requirements and Information For the reasons stated in the (46) ASTM D975–08a, Standard 60.5570 What parts of the general preamble, title 40, chapter I, parts 60, Specification for Diesel Fuel Oils, IBR provisions apply to my affected EGU? 70, 71, and 98 of the Code of the Federal approved for §§ 60.41b 60.41c, and 60.5575 Who implements and enforces this 60.5580. subpart? Regulations are amended as follows: 60.5580 What definitions apply to this * * * * * PART 60—STANDARDS OF subpart? (138) ASTM D3699–08, Standard Table 1 of Subpart TTTT of Part 60—CO2 PERFORMANCE FOR NEW Specification for Kerosine, including Emission Standards for Affected Steam STATIONARY SOURCES Appendix X1, (Approved September 1, Generating Units and Integrated 2008), IBR approved for §§ 60.41b, Gasification Combined Cycle Facilities that ■ 1. The authority citation for part 60 60.41c, and 60.5580. Commenced Construction after January 8, continues to read as follows: 2014 and Reconstruction or Modification * * * * * Authority: 42 U.S.C. 7401 et seq. after June 18, 2014 (187) ASTM D6751–11b, Standard Table 2 of Subpart TTTT of Part 60—CO ■ 2 2. Section 60.17 is amended by: Specification for Biodiesel Fuel Blend Emission Standards for Affected Stationary ■ a. Redesignating paragraphs (d) Stock (B100) for Middle Distillate Fuels, Combustion Turbines that Commenced through (t) as paragraphs (e) through (u) including Appendices X1 through X3, Construction after January 8, 2014 and and adding paragraph (d); (Approved July 15, 2011), IBR approved Reconstruction after June 18, 2014 (Net ■ b. In newly redesignated paragraph for §§ 60.41b, 60.41c, and 60.5580. Energy Output-based Standards Applicable (g), further redesignating paragraph as Approved by the Administrator) * * * * * (g)(15) as paragraph (g)(17) and adding Table 3 to Subpart TTTT of Part 60— (190) ASTM D7467–10, Standard paragraphs (g)(15) and (16); Applicability of Subpart A of Part 60 ■ c. In newly redesignated paragraph Specification for Diesel Fuel Oil, (General Provisions) to Subpart TTTT Biodiesel Blend (B6 to B20), including (h), revising paragraphs (h)(37), (42), Applicability (46), (138), (187), and (190); and Appendices X1 through X3, (Approved ■ c. In newly redesignated paragraph August 1, 2010), IBR approved for § 60.5508 What is the purpose of this (m), further redesignating paragraph §§ 60.41b, 60.41c, and 60.5580. subpart? (m)(1) as paragraph (m)(2) and adding * * * * * This subpart establishes emission paragraph (m)(1). (m) * * * standards and compliance schedules for The revisions and additions read as (1) ISO 2314:2009(E), Gas turbines– the control of greenhouse gas (GHG) follows: Acceptance tests, Third edition emissions from a steam generating unit, VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00140 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64649 IGCC, or a stationary combustion stationary combustion turbine) is 25 emissions from affected facilities, the turbine that commences construction MW or less. ‘‘pollutant that is subject to the standard after January 8, 2014 or commences (5) Your EGU is a municipal waste promulgated under section 111 of the modification or reconstruction after combustor that is subject to subpart Eb Act’’ shall be considered to be the June 18, 2014. An affected steam of this part. pollutant that otherwise is subject to generating unit, IGCC, or stationary (6) Your EGU is a commercial or regulation under the Act as defined in combustion turbine shall, for the industrial solid waste incineration unit § 52.21(b)(49) of this chapter. purposes of this subpart, be referred to that is subject to subpart CCCC of this (3) For the purposes of 40 CFR 70.2, as an affected EGU. part. with respect to greenhouse gas (7) Your EGU is a steam generating emissions from affected facilities, the § 60.5509 Am I subject to this subpart? unit or IGCC that undergoes a ‘‘pollutant that is subject to any (a) Except as provided for in modification resulting in an hourly standard promulgated under section 111 paragraph (b) of this section, the GHG increase in CO2 emissions (mass per of the Act’’ shall be considered to be the standards included in this subpart apply hour) of 10 percent or less (2 significant pollutant that otherwise is ‘‘subject to to any steam generating unit, IGCC, or figures). Modified units that are not regulation’’ as defined in 40 CFR 70.2. stationary combustion turbine that subject to the requirements of this (4) For the purposes of 40 CFR 71.2, commenced construction after January subpart pursuant to this subsection with respect to greenhouse gas 8, 2014 or commenced reconstruction continue to be existing units under emissions from affected facilities, the after June 18, 2014 that meets the section 111 with respect to CO2 ‘‘pollutant that is subject to any relevant applicability conditions in emissions standards. standard promulgated under section 111 paragraphs (a)(1) and (2) of this section. (8) Your EGU is a stationary of the Act’’ shall be considered to be the The GHG standards included in this combustion turbine that is not capable pollutant that otherwise is ‘‘subject to subpart also apply to any steam of combusting natural gas (e.g., not regulation’’ as defined in 40 CFR 71.2. generating unit or IGCC that connected to a natural gas pipeline). commenced modification after June 18, § 60.5520 What CO2 emission standard (9) The proposed Washington County must I meet? 2014 that meets the relevant EGU project described in Air Quality (a) For each affected EGU subject to applicability conditions in paragraphs Permit No. 4911–303–0051–P–01–0 (a)(1) and (2) of this section. this subpart, you must not discharge issued by the Georgia Department of from the affected EGU any gases that (1) Has a base load rating greater than Natural Resources, Environmental contain CO2 in excess of the applicable 260 GJ/h (250 MMBtu/h) of fossil fuel Protection Division, Air Protection (either alone or in combination with any CO2 emission standard specified in Branch, effective April 8, 2010, Table 1 or 2 of this subpart, consistent other fuel); and provided that construction had not (2) Serves a generator or generators with paragraphs (b), (c), and (d) of this commenced for NSPS purposes as of section, as applicable. capable of selling greater than 25 MW of January 8, 2014. electricity to a utility power distribution (b) Except as specified in paragraphs (10) The proposed Holcomb EGU (c) and (d) of this section, you must system. project described in Air Emission (b) You are not subject to the comply with the applicable gross energy Source Construction Permit 0550023 requirements of this subpart if your output standard, and your operating issued by the Kansas Department of affected EGU meets any of the permit must include monitoring, Health and Environment, Division of conditions specified in paragraphs (b)(1) recordkeeping, and reporting Environment, effective December 16, through (10) of this section. methodologies based on the applicable (1) Your EGU is a steam generating 2010, provided that construction had gross energy output standard. For the unit or IGCC that is currently and not commenced for NSPS purposes as of remainder of this subpart (for sources always has been subject to a federally January 8, 2014. that do not qualify under paragraphs (c) enforceable permit condition limiting Emission Standards and (d) of this section), where the term annual net-electric sales to no more than ‘‘gross or net energy output’’ is used, the one-third of its potential electric output § 60.5515 Which pollutants are regulated term that applies to you is ‘‘gross energy or 219,000 MWh, whichever is greater. by this subpart? output.’’ (2) Your EGU is capable of (a) The pollutants regulated by this (c) As an alternate to meeting the combusting 50 percent or more non- subpart are greenhouse gases. The requirements in paragraph (b) of this fossil fuel and is also subject to a greenhouse gas standard in this subpart section, an owner or operator of a federally enforceable permit condition is in the form of a limitation on stationary combustion turbine may limiting the annual capacity factor for emission of carbon dioxide. petition the Administrator in writing to all fossil fuels combined of 10 percent (b) PSD and title V thresholds for comply with the alternate applicable net (0.10) or less. greenhouse gases. (1) For the purposes energy output standard. If the (3) Your EGU is a combined heat and of 40 CFR 51.166(b)(49)(ii), with respect Administrator grants the petition, power unit that is subject to a federally to GHG emissions from affected beginning on the date the Administrator enforceable permit condition limiting facilities, the ‘‘pollutant that is subject grants the petition, the affected EGU annual net-electric sales to no more than to the standard promulgated under must comply with the applicable net either 219,000 MWh or the product of section 111 of the Act’’ shall be energy output-based standard included the design efficiency and the potential considered to be the pollutant that in this subpart. Your operating permit electric output, whichever is greater. otherwise is subject to regulation under must include monitoring, (4) Your EGU serves a generator along the Act as defined in § 51.166(b)(48) of recordkeeping, and reporting with other steam generating unit(s), this chapter and in any SIP approved by methodologies based on the applicable IGCC, or stationary combustion the EPA that is interpreted to net energy output standard. For the turbine(s) where the effective generation incorporate, or specifically incorporates, remainder of this subpart, where the capacity (determined based on a § 51.166(b)(48). term ‘‘gross or net energy output’’ is prorated output of the base load rating (2) For the purposes of 40 CFR used, the term that applies to you is of each steam generating unit, IGCC, or 52.21(b)(50)(ii), with respect to GHG ‘‘net energy output.’’ Owners or VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00141 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 64650 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations operators complying with the net combustion turbines qualifying under of this subpart for the applicable CO2 output-based standard must petition the this paragraph are only required to emission standards. Administrator to switch back to maintain purchase records for permitted (a) You must be in compliance with complying with the gross energy output- fuels. the emission standards in this subpart based standard. (2) Stationary combustion turbines that apply to your affected EGU at all (d) Stationary combustion turbines permitted to burn fuels that do not have times. However, you must determine subject to a heat input-based standard in a consistent chemical composition or compliance with the emission standards Table 2 of this subpart that are only that do not have an emission rate of 160 only at the end of the applicable permitted to burn one or more uniform lb CO2/MMBtu or less (e.g., non-uniform operating month, as provided in fuels, as described in paragraph (d)(1) of fuels such as residual oil and non-jet paragraph (a)(1) of this section. this section, are only subject to the fuel kerosene) must follow the (1) For each affected EGU subject to monitoring requirements in paragraph monitoring, recordkeeping, and a CO2 emissions standard based on a 12- (d)(1). All other stationary combustion reporting requirements necessary to operating-month rolling average, you turbines subject to a heat input based complete the heat input-based must determine compliance monthly by standard in Table 2 are subject to the calculations under this subpart. calculating the average CO2 emissions requirements in paragraph (d)(2) of this General Compliance Requirements rate for the affected EGU at the end of section. the initial and each subsequent 12- (1) Stationary combustion turbines § 60.5525 What are my general operating-month period. that are only permitted to burn fuels requirements for complying with this (2) Consistent with § 60.5520(d)(2), if with a consistent chemical composition subpart? your affected stationary combustion (i.e., uniform fuels) that result in a Combustion turbines qualifying under turbine is subject to an input-based CO2 consistent emission rate of 160 lb CO2/ § 60.5520(d)(1) are not subject to any emissions standard, you must determine MMBtu or less are not subject to any requirements in this section other than the total heat input in million Btus monitoring or reporting requirements the requirement to maintain fuel (MMBtu) from natural gas (HTIPng) and under this subpart. These fuels include, purchase records for permitted fuel(s). the total heat input from all other fuels but are not limited to, natural gas, For all other affected sources, combined (HTIPo) using one of the methane, butane, butylene, ethane, compliance with the applicable CO2 methods under § 60.5535(d)(2). You ethylene, propane, naphtha, propylene, emission standard of this subpart shall must then use the following equation to jet fuel kerosene, No. 1 fuel oil, No. 2 be determined on a 12-operating-month determine the applicable emissions fuel oil, and biodiesel. Stationary rolling average basis. See Table 1 or 2 standard during the compliance period: Where: make an initial compliance § 63.5555(c)(3)(i) (for Acid Rain program CO2 emission standard = the emission determination for your affected EGU(s) units), or according to standard during the compliance period with respect to the applicable emissions § 63.5555(c)(3)(ii)(B) (for units that are in units of lb/MMBtu. standard in Table 1 or 2 of this subpart, not subject to the Acid Rain Program). HTIPng = the heat input in MMBtu from in accordance with the requirements in The first month of the initial natural gas. this subpart. The first operating month compliance period shall be the first HTIPo = the heat input in MMBtu from all included in the initial 12-operating- fuels other than natural gas. operating month (as defined in month compliance period shall be 120 = allowable emission rate in lb of CO2/ § 60.5580) after the calendar month in MMBtu for heat input derived from determined as follows: which the rule becomes effective; or natural gas. (1) For an affected EGU that (ii) If the date on which emissions 160 = allowable emission rate in lb of CO2/ commences commercial operation (as MMBtu for heat input derived from all defined in § 72.2 of this chapter) on or reporting is required to begin under fuels other than natural gas. after October 23, 2015, the first month § 75.64(a) of this chapter occurs on or (b) At all times you must operate and of the initial compliance period shall be after October 23, 2015, then the first maintain each affected EGU, including the first operating month (as defined in month of the initial compliance period associated equipment and monitors, in § 60.5580) after the calendar month in shall be the first operating month (as a manner consistent with safety and which emissions reporting is required to defined in § 60.5580) after the calendar good air pollution control practice. The begin under: month in which emissions reporting is Administrator will determine if you are (i) Section 63.5555(c)(3)(i), for units required to begin under using consistent operation and subject to the Acid Rain Program; or § 63.5555(c)(3)(ii)(A). maintenance procedures based on (ii) Section 63.5555(c)(3)(ii)(A), for (3) For a modified or reconstructed information available to the units that are not in the Acid Rain EGU that becomes subject to this Administrator that may include, but is Program. subpart, the first month of the initial not limited to, fuel use records, (2) For an affected EGU that has compliance period shall be the first monitoring results, review of operation commenced COMMERCIAL operation operating month (as defined in (as defined in § 72.2 of this chapter) and maintenance procedures and § 60.5580) after the calendar month in prior to October 23, 2015: records, review of reports required by which emissions reporting is required to this subpart, and inspection of the EGU. (i) If the date on which emissions (c) Within 30 days after the end of the reporting is required to begin under begin under § 63.5555(c)(3)(iii). initial compliance period (i.e., no more § 75.64(a) of this chapter has passed than 30 days after the first 12-operating- prior to October 23, 2015, emissions month compliance period), you must reporting shall begin according to VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00142 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 ER23OC15.002 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64651 Monitoring and Compliance moisture value from § 75.11(b) or submit through (4) of this section. If you use Determination Procedures a petition to the Administrator under non-uniform fuels as specified in § 75.66 of this chapter for a site-specific § 60.5520(d)(2), you may determine CO2 § 60.5535 How do I monitor and collect default moisture value. mass emissions during the compliance data to demonstrate compliance? (2) For each continuous monitoring period according to paragraph (c)(5) of (a) Combustion turbines qualifying system that you use to determine the this section. under § 60.5520(d)(1) are not subject to CO2 mass emissions, you must meet the (1) If you are subject to an output- any requirements in this section other applicable certification and quality based standard and you do not install than the requirement to maintain fuel assurance procedures in § 75.20 of this CEMS in accordance with paragraph (b) purchase records for permitted fuel(s). If chapter and appendices A and B to part of this section, you must implement the your combustion turbine uses non- 75 of this chapter. applicable procedures in appendix D to uniform fuels as specified under (3) You must use only unadjusted part 75 of this chapter to determine § 60.5520(d)(2), you must monitor heat exhaust gas volumetric flow rates to hourly EGU heat input rates (MMBtu/h), input in accordance with paragraph determine the hourly CO2 mass based on hourly measurements of fuel (c)(1) of this section, and you must emissions rate from the affected EGU; flow rate and periodic determinations of monitor CO2 emissions in accordance you must not apply the bias adjustment the gross calorific value (GCV) of each with either paragraph (b), (c)(2), or (c)(5) factors described in Section 7.6.5 of fuel combusted. of this section. For all other affected appendix A to part 75 of this chapter to (2) For each measured hourly heat sources, you must prepare a monitoring the exhaust gas flow rate data. input rate, use Equation G–4 in plan to quantify the hourly CO2 mass (4) You must select an appropriate appendix G to part 75 of this chapter to emission rate (tons/h), in accordance reference method to setup (characterize) calculate the hourly CO2 mass emission with the applicable provisions in the flow monitor and to perform the on- rate (tons/h). You may determine site- § 75.53(g) and (h) of this chapter. The going RATAs, in accordance with part specific carbon-based F-factors (Fc) electronic portion of the monitoring 75 of this chapter. If you use a Type-S using Equation F–7b in section 3.3.6 of plan must be submitted using the pitot tube or a pitot tube assembly for appendix F to part 75 of this chapter, ECMPS Client Tool and must be in the flow RATAs, you must calibrate the and you may use these Fc values in the place prior to reporting emissions data pitot tube or pitot tube assembly; you emissions calculations instead of using and/or the results of monitoring system may not use the 0.84 default Type-S the default Fc values in the Equation G– certification tests under this subpart. pitot tube coefficient specified in 4 nomenclature. The monitoring plan must be updated as Method 2. (3) For each ‘‘valid operating hour’’ necessary. Monitoring plan submittals (5) Calculate the hourly CO2 mass (as defined in § 60.5540(a)(1), multiply must be made by the Designated emissions (kg) as described in the hourly tons/h CO2 mass emission Representative (DR), the Alternate DR, paragraphs (b)(5)(i) through (iv) of this rate from paragraph (c)(2) of this section or a delegated agent of the DR (see section. Perform this calculation only by the EGU or stack operating time in § 60.5555(c)). for ‘‘valid operating hours’’, as defined hours (as defined in § 72.2 of this (b) You must determine the hourly in § 60.5540(a)(1). chapter), to convert it to tons of CO2. CO2 mass emissions in kilograms (kg) (i) Begin with the hourly CO2 mass Then, multiply the result by 909.1 to from your affected EGU(s) according to emission rate (tons/h), obtained either convert from tons of CO2 to kg. Round paragraphs (b)(1) through (5) of this from Equation F–11 in Appendix F to off to the nearest two significant figures. section, or, if applicable, as provided in part 75 of this chapter (if CO2 (4) The hourly CO2 tons/h values and paragraph (c) of this section. concentration is measured on a wet EGU (or stack) operating times used to (1) For an affected coal-fired EGU or basis), or by following the procedure in calculate CO2 mass emissions are for an IGCC unit you must, and for all section 4.2 of appendix F to part 75 of required to be recorded under § 75.57(e) other affected EGUs you may, install, this chapter (if CO2 concentration is of this chapter and must be reported certify, operate, maintain, and calibrate measured on a dry basis). electronically under § 75.64(a)(6) of this a CO2 continuous emission monitoring (ii) Next, multiply each hourly CO2 chapter. You must use these data to system (CEMS) to directly measure and mass emission rate by the EGU or stack calculate the hourly CO2 mass record hourly average CO2 operating time in hours (as defined in emissions. concentrations in the affected EGU § 72.2 of this chapter), to convert it to (5) If you operate a combustion exhaust gases emitted to the tons of CO2. turbine firing non-uniform fuels, as an atmosphere, and a flow monitoring (iii) Finally, multiply the result from alternative to following paragraphs system to measure hourly average stack paragraph (b)(5)(ii) of this section by (c)(1) through (4) of this section, you gas flow rates, according to 909.1 to convert it from tons of CO2 to may determine CO2 emissions during § 75.10(a)(3)(i) of this chapter. As an kg. Round off to the nearest kg. the compliance period using one of the alternative to direct measurement of (iv) The hourly CO2 tons/h values and following methods: CO2 concentration, provided that your EGU (or stack) operating times used to (i) Units firing fuel gas may determine EGU does not use carbon separation calculate CO2 mass emissions are the heat input during the compliance (e.g., carbon capture and storage), you required to be recorded under § 75.57(e) period following the procedure under may use data from a certified oxygen of this chapter and must be reported § 60.107a(d) and convert this heat input (O2) monitor to calculate hourly average electronically under § 75.64(a)(6) of this to CO2 emissions using Equation G–4 in CO2 concentrations, in accordance with chapter. You must use these data to appendix G to part 75 of this chapter. § 75.10(a)(3)(iii) of this chapter. If you calculate the hourly CO2 mass (ii) You may use the procedure for measure CO2 concentration on a dry emissions. determining CO2 emissions during the basis, you must also install, certify, (c) If your affected EGU exclusively compliance period based on the use of operate, maintain, and calibrate a combusts liquid fuel and/or gaseous the Tier 3 methodology under continuous moisture monitoring system, fuel, as an alternative to complying with § 98.33(a)(3) of this chapter. according to § 75.11(b) of this chapter. paragraph (b) of this section, you may (d) Consistent with § 60.5520, you Alternatively, you may either use an determine the hourly CO2 mass must determine the basis of the appropriate fuel-specific default emissions according to paragraphs (c)(1) emissions standard that applies to your VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00143 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 64652 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations affected source in accordance with Alternatively, if the EGUs are identical, emissions standard (i.e., either kg/MWh either paragraph (d)(1) or (2) of this you may apportion the combined hourly or lb/MMBtu). You must use the hourly section, as applicable: gross or net electrical load to the CO2 mass emissions calculated under (1) If you operate a source subject to individual EGUs according to the § 60.5535(b) or (c), as applicable, and an emissions standard established on an fraction of the total heat input either the generating load data from output basis (e.g., lb of CO2 per gross or contributed by each EGU. § 60.5535(d)(1) for output-based net MWh of energy output), you must (f) In accordance with §§ 60.13(g) and calculations or the heat input data from install, calibrate, maintain, and operate 60.5520, if two or more affected EGUs § 60.5535(d)(2) for heat-input-based a sufficient number of watt meters to that implement the continuous emission calculations. Combustion turbines firing continuously measure and record the monitoring provisions in paragraph (b) non-uniform fuels that contain CO2 hourly gross electric output or net of this section share a common exhaust prior to combustion (e.g., blast furnace electric output, as applicable, from the gas stack and are subject to the same gas or landfill gas) may sample the fuel affected EGU(s). These measurements emissions standard in Table 1 or 2 of stream to determine the quantity of CO2 must be performed using 0.2 class this subpart, you may monitor the present in the fuel prior to combustion electricity metering instrumentation and hourly CO2 mass emissions at the and exclude this portion of the CO2 calibration procedures as specified common stack in lieu of monitoring mass emissions from compliance under ANSI Standards No. C12.20 each EGU separately. If you choose this determinations. (incorporated by reference, see § 60.17). option, the hourly gross or net energy (1) Each compliance period shall For a combined heat and power (CHP) output (electric, thermal, and/or include only ‘‘valid operating hours’’ in EGU, as defined in § 60.5580, you must mechanical, as applicable) must be the the compliance period, i.e., operating also install, calibrate, maintain, and sum of the hourly loads for the hours for which: operate meters to continuously (i.e., individual affected EGUs and you must (i) ‘‘Valid data’’ (as defined in hour-by-hour) determine and record the express the operating time as ‘‘stack § 60.5580) are obtained for all of the total useful thermal output. For process operating hours’’ (as defined in § 72.2 of parameters used to determine the hourly steam applications, you will need to this chapter). If you attain compliance CO2 mass emissions (kg) and, if a heat install, calibrate, maintain, and operate with the applicable emissions standard input-based standard applies, all the meters to continuously determine and in § 60.5520 at the common stack, each parameters used to determine total heat record the hourly steam flow rate, affected EGU sharing the stack is in input for the hour are also obtained; and temperature, and pressure. Your plan compliance. (ii) The corresponding hourly gross or shall ensure that you install, calibrate, (g) In accordance with §§ 60.13(g) and net energy output value is also valid maintain, and operate meters to record 60.5520 if the exhaust gases from an data (Note: For hours with no useful each component of the determination, affected EGU that implements the output, zero is considered to be a valid hour-by-hour. continuous emission monitoring value). (2) If you operate a source subject to provisions in paragraph (b) of this (2) You must exclude operating hours an emissions standard established on a section are emitted to the atmosphere in which: heat-input basis (e.g., lb CO2/MMBtu) through multiple stacks (or if the (i) The substitute data provisions of and your affected source uses non- exhaust gases are routed to a common part 75 of this chapter are applied for uniform heating value fuels as stack through multiple ducts and you any of the parameters used to determine delineated under § 60.5520(d), you must elect to monitor in the ducts), you must the hourly CO2 mass emissions or, if a determine the total heat input for each monitor the hourly CO2 mass emissions heat input-based standard applies, for fuel fired during the compliance period and the ‘‘stack operating time’’ (as any parameters used to determine the in accordance with one of the following defined in § 72.2 of this chapter) at each hourly heat input; or procedures: stack or duct separately. In this case, (ii) An exceedance of the full-scale (i) Appendix D to part 75 of this you must determine compliance with range of a continuous emission chapter; the applicable emissions standard in monitoring system occurs for any of the (ii) The procedures for monitoring Table 1 or 2 of this subpart by summing parameters used to determine the hourly heat input under § 60.107a(d); the CO2 mass emissions measured at the CO2 mass emissions or, if applicable, to (iii) If you monitor CO2 emissions in individual stacks or ducts and dividing determine the hourly heat input; or accordance with the Tier 3 methodology by the total gross or net energy output (iii) The total gross or net energy under § 98.33(a)(3) of this chapter, you for the affected EGU. output (Pgross/net) or, if applicable, the may convert your CO2 emissions to heat total heat input is unavailable. input using the appropriate emission § 60.5540 How do I demonstrate (3) For each compliance period, at factor in Table C–1 of part 98 of this compliance with my CO2 emissions least 95 percent of the operating hours chapter. If your fuel is not listed in standard and determine excess emissions? in the compliance period must be valid Table C–1, you must determine a fuel- (a) In accordance with § 60.5520, if operating hours, as defined in paragraph specific carbon-based F-factor (Fc) in you are subject to an output-based (a)(1) of this section. accordance with section 12.3.2 of EPA emission standard or you burn non- (4) You must calculate the total CO2 Method 19 of appendix A–7 to this part, uniform fuels as specified in mass emissions by summing the valid and you must convert your CO2 § 60.5520(d)(2), you must demonstrate hourly CO2 mass emissions values from emissions to heat input using Equation compliance with the applicable CO2 § 60.5535 for all of the valid operating G–4 in appendix G to part 75 of this emission standard in Table 1 or 2 of this hours in the compliance period. chapter. subpart as required in this section. For (5) Sources subject to output based (e) Consistent with § 60.5520, if two the initial and each subsequent 12- standards. For each valid operating or more affected EGUs serve a common operating-month rolling average hour of the compliance period that was electric generator, you must apportion compliance period, you must follow the used in paragraph (a)(4) of this section the combined hourly gross or net energy procedures in paragraphs (a)(1) through to calculate the total CO2 mass output to the individual affected EGUs (7) of this section to calculate the CO2 emissions, you must determine Pgross/net according to the fraction of the total mass emissions rate for your affected (the corresponding hourly gross or net steam load contributed by each EGU. EGU(s) in units of the applicable energy output in MWh) according to the VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00144 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64653 procedures in paragraphs (a)(3)(i) and for an operating hour in which a valid (i) Calculate Pgross/net for your affected (ii) of this section, as appropriate for the CO2 mass emissions value is determined EGU using the following equation. All type of affected EGU(s). For an operating according to paragraph (a)(1)(i) of this terms in the equation must be expressed hour in which a valid CO2 mass section, but there is no (i.e., zero) gross in units of megawatt-hours (MWh). To emissions value is determined electrical, mechanical, or useful thermal convert each hourly gross or net energy according to paragraph (a)(1)(i) of this output, you must use that hour in the output (consistent with § 60.5520) value section, if there is no gross or net compliance determination. For hours or reported under part 75 of this chapter to electrical output, but there is partial hours where the gross electric MWh, multiply by the corresponding mechanical or useful thermal output, output is equal to or less than the EGU or stack operating time. you must still determine the gross or net auxiliary loads, net electric output shall energy output for that hour. In addition, be counted as zero for this calculation. Where: energy output consists of useful thermal selected monitoring option under output on a 12-operating-month rolling Pgross/net = In accordance with § 60.5520, gross § 60.5535(d)(2). or net energy output of your affected average basis, or 1.0 for all other affected EGUs. (7) If you are subject to an output- EGU for each valid operating hour (as based standard, you must calculate the defined in § 60.5540(a)(1)) in MWh. (ii) If applicable to your affected EGU CO mass emissions rate for the affected (Pe) = Electric energy output plus 2 ST (for example, for combined heat and EGU(s) (kg/MWh) by dividing the total mechanical energy output (if any) of power), you must calculate (Pt) using steam turbines in MWh. PS CO2 mass emissions value calculated the following equation: (Pe)CT = Electric energy output plus according to the procedures in mechanical energy output (if any) of paragraph (a)(4) of this section by the stationary combustion turbine(s) in total gross or net energy output value MWh. calculated according to the procedures (Pe)IE = Electric energy output plus Where: in paragraph (a)(6)(i) of this section. mechanical energy output (if any) of Q = Measured steam flow in kilograms (kg) your affected EGU’s integrated m Round off the result to two significant (or pounds (lb)) for the operating hour. equipment that provides electricity or figures if the calculated value is less H = Enthalpy of the steam at measured mechanical energy to the affected EGU or than 1,000; round the result to three temperature and pressure (relative to auxiliary equipment in MWh. significant figures if the calculated value SATP conditions or the energy in the (Pe)FW = Electric energy used to power boiler is greater than 1,000. If you are subject condensate return line, as applicable) in feedwater pumps at steam generating to a heat input-based standard, you units in MWh. Not applicable to Joules per kilogram (J/kg) (or Btu/lb). × 9 must calculate the CO2 mass emissions stationary combustion turbines, IGCC CF = Conversion factor of 3.6 10 J/MWh × 6 rate for the affected EGU(s) (lb/MMBtu) EGUs, or EGUs complying with a net or 3.413 10 Btu/MWh. by dividing the total CO mass energy output based standard. (6) Calculation of annual basis for 2 (Pe)A = Electric energy used for any auxiliary emissions value calculated according to standard. Sources complying with the procedures in paragraph (a)(4) of loads in MWh. Not applicable for energy output-based standards must determining Pgross. this section by the total heat input calculate the basis (i.e., denominator) of (Pt)PS = Useful thermal output of steam calculated according to the procedures (measured relative to SATP conditions, their actual annual emission rate in in paragraph (a)(6)(ii) of this section. as applicable) that is used for accordance with paragraph (a)(6)(i) of Round off the result to two significant applications that do not generate this section. Sources complying with figures. additional electricity, produce heat input based standards must mechanical energy output, or enhance calculate the basis of their actual annual (b) In accordance with § 60.5520, to the performance of the affected EGU. emission rate in accordance with demonstrate compliance with the This is calculated using the equation paragraph (a)(6)(ii) of this section. applicable CO2 emission standard, for specified in paragraph (a)(5)(ii) of this the initial and each subsequent 12- section in MWh. (i) In accordance with § 60.5520 if you are subject to an output-based standard, operating-month compliance period, the (Pt)HR = Non steam useful thermal output CO mass emissions rate for your (measured relative to SATP conditions, you must calculate the total gross or net 2 as applicable) from heat recovery that is energy output for the affected EGU’s affected EGU must be determined used for applications other than steam compliance period by summing the according to the procedures specified in generation or performance enhancement hourly gross or net energy output values paragraph (a)(1) through (7) of this of the affected EGU in MWh. for the affected EGU that you section and must be less than or equal (Pt)IE = Useful thermal output (relative to determined under paragraph (a)(5) of to the applicable CO2 emissions SATP conditions, as applicable) from standard in Table 1 or 2 of this part, or any integrated equipment is used for this section for all of the valid operating hours in the applicable compliance the emissions standard calculated in applications that do not generate accordance with § 60.5525(a)(2). additional steam, electricity, produce period. mechanical energy output, or enhance (ii) If you are subject to a heat input- Notification, Reports, and Records the performance of the affected EGU in based standard, you must calculate the MWh. total heat input for each fuel fired § 60.5550 What notifications must I submit TDF = Electric Transmission and Distribution during the compliance period. The and when? Factor of 0.95 for a combined heat and calculation of total heat input for each (a) You must prepare and submit the power affected EGU where at least on an annual basis 20.0 percent of the total individual fuel must include all valid notifications specified in §§ 60.7(a)(1) gross or net energy output consists of operating hours and must also be and (3) and 60.19, as applicable to your electric or direct mechanical output and consistent with any fuel-specific affected EGU(s) (see Table 3 of this 20.0 percent of the total gross or net procedures specified within your subpart). VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00145 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 ER23OC15.003 ER23OC15.004 64654 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations (b) You must prepare and submit (vi) Consistent with § 60.5520, an (B) October 23, 2015, if the date on notifications specified in § 75.61 of this indication whether or not the hourly which reporting would ordinarily be chapter, as applicable, to your affected gross or net energy output (Pgross/net) required to begin under § 75.64(a) of this EGUs. values used in the compliance chapter has passed prior to October 23, determinations are based solely upon 2015. § 60.5555 What reports must I submit and gross electrical load. (iii) For reconstructed or modified when? (3) In the final quarterly report of each units, reporting of emissions data shall (a) You must prepare and submit calendar year, you must include the begin at the date on which the EGU reports according to paragraphs (a) following: becomes an affected unit under this through (d) of this section, as (i) Consistent with § 60.5520, gross subpart, provided that the ECMPS applicable. energy output or net energy output sold Client Tool is able to receive and (1) For affected EGUs that are required to an electric grid, as applicable to the process net energy output data on that by § 60.5525 to conduct initial and on- units of your emission standard, over date. Otherwise, emissions data going compliance determinations on a the four quarters of the calendar year; reporting shall be on a gross energy 12-operating-month rolling average and output basis until the date that the basis, you must submit electronic (ii) The potential electric output of the Client Tool is first able to receive and quarterly reports as follows. After you EGU. process net energy output data. have accumulated the first 12-operating (b) You must submit all electronic (4) If any required monitoring system months for the affected EGU, you must reports required under paragraph (a) of has not been provisionally certified by submit a report for the calendar quarter this section using the Emissions the applicable date on which emissions that includes the twelfth operating Collection and Monitoring Plan System data reporting is required to begin under month no later than 30 days after the (ECMPS) Client Tool provided by the paragraph (c)(3) of this section, the end of that quarter. Thereafter, you must Clean Air Markets Division in the Office maximum (or in some cases, minimum) submit a report for each subsequent of Atmospheric Programs of EPA. potential value for the parameter calendar quarter, no later than 30 days (c)(1) For affected EGUs under this measured by the monitoring system after the end of the quarter. subpart that are also subject to the Acid shall be reported until the required (2) In each quarterly report you must Rain Program, you must meet all certification testing is successfully include the following information, as applicable reporting requirements and completed, in accordance with § 75.4(j) applicable: submit reports as required under of this chapter, § 75.37(b) of this (i) Each rolling average CO2 mass subpart G of part 75 of this chapter. chapter, or section 2.4 of appendix D to emissions rate for which the last (2) For affected EGUs under this part 75 of this chapter (as applicable). (twelfth) operating month in a 12- subpart that are not in the Acid Rain Operating hours in which CO2 mass operating-month compliance period Program, you must also meet the emission rates are calculated using falls within the calendar quarter. You reporting requirements and submit maximum potential values are not must calculate each average CO2 mass reports as required under subpart G of ‘‘valid operating hours’’ (as defined in emissions rate for the compliance part 75 of this chapter, to the extent that § 60.5540(a)(1)), and shall not be used in period according to the procedures in those requirements and reports provide the compliance determinations under § 60.5540. You must report the dates applicable data for the compliance § 60.5540. (month and year) of the first and twelfth demonstrations required under this (d) For affected EGUs subject to the operating months in each compliance subpart. Acid Rain Program, the reports required period for which you performed a CO2 (3)(i) For all newly-constructed under paragraphs (a) and (c)(1) of this mass emissions rate calculation. If there affected EGUs under this subpart that section shall be submitted by: are no compliance periods that end in are also subject to the Acid Rain (1) The person appointed as the the quarter, you must include a Program, you must begin submitting the Designated Representative (DR) under statement to that effect; quarterly electronic emissions reports § 72.20 of this chapter; or (ii) If one or more compliance periods described in paragraph (c)(1) of this (2) The person appointed as the end in the quarter, you must identify section in accordance with § 75.64(a) of Alternate Designated Representative each operating month in the calendar this chapter, i.e., beginning with data (ADR) under § 72.22 of this chapter; or quarter where your EGU violated the recorded on and after the earlier of: (3) A person (or persons) authorized applicable CO2 emission standard; (A) The date of provisional by the DR or ADR under § 72.26 of this (iii) If one or more compliance certification, as defined in § 75.20(a)(3) chapter to make the required periods end in the quarter and there are of this chapter; or submissions. no violations for the affected EGU, you (B) 180 days after the date on which (e) For affected EGUs that are not must include a statement indicating this the EGU commences commercial subject to the Acid Rain Program, the in the report; operation (as defined in § 72.2 of this owner or operator shall appoint a DR (iv) The percentage of valid operating chapter). and (optionally) an ADR to submit the hours in each 12-operating-month (ii) For newly-constructed affected reports required under paragraphs (a) compliance period described in EGUs under this subpart that are not and (c)(2) of this section. The DR and paragraph (a)(1)(i) of this section (i.e., subject to the Acid Rain Program, you ADR must register with the Clean Air the total number of valid operating must begin submitting the quarterly Markets Division (CAMD) Business hours (as defined in § 60.5540(a)(1)) in electronic reports described in System. The DR may delegate the that period divided by the total number paragraph (c)(2) of this section, authority to make the required of operating hours in that period, beginning with data recorded on and submissions to one or more persons. multiplied by 100 percent); after: (f) If your affected EGU captures CO2 (v) Consistent with § 60.5520, the CO2 (A) The date on which reporting is to meet the applicable emission limit, emissions standard (as identified in required to begin under § 75.64(a) of this you must report in accordance with the Table 1 or 2 of this part) with which chapter, if that date occurs on or after requirements of 40 CFR part 98, subpart your affected EGU must comply; and October 23, 2015; or PP and either: VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00146 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64655 (1) Report in accordance with the under this subpart. Regardless of the based F-factors you used in the requirements of 40 CFR part 98, subpart prior sentence, at a minimum, the emissions calculations (if applicable). RR, if injection occurs on-site, or following records must be kept, as § 60.5565 In what form and how long must (2) Transfer the captured CO2 to an applicable to the types of continuous I keep my records? EGU or facility that reports in monitoring systems used to demonstrate accordance with the requirements of 40 compliance under this subpart: (a) Your records must be in a form CFR part 98, subpart RR, if injection (i) Monitoring plan records under suitable and readily available for occurs off-site. § 75.53(g) and (h) of this chapter; expeditious review. (3) Transfer the captured CO2 to a (ii) Operating parameter records (b) You must maintain each record for facility that has received an innovative under § 75.57(b)(1) through (4) of this 3 years after the date of conclusion of technology waiver from EPA pursuant chapter; each compliance period. to paragraph (g) of this section. (iii) The records under § 75.57(c)(2) of (c) You must maintain each record on (g) Any person may request the this chapter, for stack gas volumetric site for at least 2 years after the date of Administrator to issue a waiver of the flow rate; each occurrence, measurement, requirement that captured CO from an 2 (iv) The records under § 75.57(c)(3) of maintenance, corrective action, report, affected EGU be transferred to a facility this chapter for continuous moisture or record, according to § 60.7. Records reporting under 40 CFR part 98, subpart monitoring systems; that are accessible from a central RR. To receive a waiver, the applicant (v) The records under § 75.57(e)(1) of location by a computer or other means must demonstrate to the Administrator this chapter, except for paragraph that instantly provide access at the site that its technology will store captured (e)(1)(x), for CO2 concentration meet this requirement. You may CO as effectively as geologic 2 monitoring systems or O2 monitors used maintain the records off site for the sequestration, and that the proposed to calculate CO2 concentration; remaining year(s) as required by this technology will not cause or contribute (vi) The records under § 75.58(c)(1) of subpart. to an unreasonable risk to public health, this chapter, specifically paragraphs welfare, or safety. In making this (c)(1)(i), (ii), and (viii) through (xiv), for Other Requirements and Information determination, the Administrator shall oil flow meters; consider (among other factors) operating (vii) The records under § 75.58(c)(4) of § 60.5570 What parts of the general provisions apply to my affected EGU? history of the technology, whether the this chapter, specifically paragraphs technology will increase emissions or (c)(4)(i), (ii), (iv), (v), and (vii) through Notwithstanding any other provision other releases of any pollutant other (xi), for gas flow meters; of this chapter, certain parts of the than CO2, and permanence of the CO2 (viii) The quality-assurance records general provisions in §§ 60.1 through storage. The Administrator may test the under § 75.59(a) of this chapter, 60.19, listed in Table 3 to this subpart, system itself, or require the applicant to specifically paragraphs (a)(1) through do not apply to your affected EGU. (12) and (15), for CEMS; perform any tests considered by the § 60.5575 Who implements and enforces Administrator to be necessary to show (ix) The quality-assurance records this subpart? the technology’s effectiveness, safety, under § 75.59(a) of this chapter, (a) This subpart can be implemented and ability to store captured CO2 specifically paragraphs (b)(1) through without release. The Administrator may (4), for fuel flow meters; and and enforced by the EPA, or a delegated grant conditional approval of a (x) Records of data acquisition and authority such as your state, local, or technology, with the approval handling system (DAHS) verification tribal agency. If the Administrator has conditioned on monitoring and under § 75.59(e) of this chapter. delegated authority to your state, local, reporting of operations. The (c) You must keep records of the or tribal agency, then that agency (as Administrator may also withdraw calculations you performed to well as the EPA) has the authority to approval of the waiver on evidence of determine the hourly and total CO2 implement and enforce this subpart. You should contact your EPA Regional releases of CO2 or other pollutants. The mass emissions (tons) for: Administrator will provide notice to the (1) Each operating month (for all Office to find out if this subpart is public of any application under this affected EGUs); and delegated to your state, local, or tribal provision and provide public notice of (2) Each compliance period, agency. any proposed action on a petition before including, each 12-operating-month (b) In delegating implementation and the Administrator takes final action. compliance period. enforcement authority of this subpart to (d) Consistent with § 60.5520, you a state, local, or tribal agency, the § 60.5560 What records must I maintain? must keep records of the applicable data Administrator retains the authorities (a) You must maintain records of the recorded and calculations performed listed in paragraphs (b)(1) through (5) of information you used to demonstrate that you used to determine your affected this section and does not transfer them compliance with this subpart as EGU’s gross or net energy output for to the state, local, or tribal agency. In specified in § 60.7(b) and (f). each operating month. addition, the EPA retains oversight of (b)(1) For affected EGUs subject to the (e) You must keep records of the this subpart and can take enforcement Acid Rain Program, you must follow the calculations you performed to actions, as appropriate. applicable recordkeeping requirements determine the percentage of valid CO2 (1) Approval of alternatives to the and maintain records as required under mass emission rates in each compliance emission standards. subpart F of part 75 of this chapter. period. (2) Approval of major alternatives to (2) For affected EGUs that are not (f) You must keep records of the test methods. subject to the Acid Rain Program, you calculations you performed to assess (3) Approval of major alternatives to must also follow the recordkeeping compliance with each applicable CO2 requirements and maintain records as mass emissions standard in Table 1 or monitoring. required under subpart F of part 75 of 2 of this subpart. (4) Approval of major alternatives to this chapter, to the extent that those (g) You must keep records of the recordkeeping and reporting. records provide applicable data for the calculations you performed to (5) Performance test and data compliance determinations required determine any site-specific carbon- reduction waivers under § 60.8(b). VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00147 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 64656 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations § 60.5580 What definitions apply to this Distillate oil means fuel oils that Heat recovery steam generating unit subpart? comply with the specifications for fuel (HRSG) means an EGU in which hot As used in this subpart, all terms not oil numbers 1 and 2, as defined by exhaust gases from the combustion defined herein will have the meaning ASTM International in ASTM D396–98 turbine engine are routed in order to given them in the Clean Air Act and in (incorporated by reference, see § 60.17); extract heat from the gases and generate subpart A (general provisions of this diesel fuel oil numbers 1 and 2, as useful output. Heat recovery steam part). defined by ASTM International in generating units can be used with or Annual capacity factor means the ASTM D975–08a (incorporated by without duct burners. ratio between the actual heat input to an reference, see § 60.17); kerosene, as Integrated gasification combined EGU during a calendar year and the defined by ASTM International in cycle facility or IGCC means a combined potential heat input to the EGU had it ASTM D3699 (incorporated by cycle facility that is designed to burn been operated for 8,760 hours during a reference, see § 60.17); biodiesel as fuels containing 50 percent (by heat calendar year at the base load rating. defined by ASTM International in input) or more solid-derived fuel not Base load rating means the maximum ASTM D6751 (incorporated by meeting the definition of natural gas, amount of heat input (fuel) that an EGU reference, see § 60.17); or biodiesel plus any integrated equipment that can combust on a steady state basis, as blends as defined by ASTM provides electricity or useful thermal determined by the physical design and International in ASTM D7467 output to the affected EGU or auxiliary characteristics of the EGU at ISO (incorporated by reference, see § 60.17). equipment. The Administrator may conditions. For a stationary combustion Electric Generating units or EGU waive the 50 percent solid-derived fuel turbine, base load rating includes the means any steam generating unit, IGCC requirement during periods of the heat input from duct burners. unit, or stationary combustion turbine gasification system construction, startup Coal means all solid fuels classified as that is subject to this rule (i.e., meets the and commissioning, shutdown, or anthracite, bituminous, subbituminous, applicability criteria) repair. No solid fuel is directly burned or lignite by ASTM International in in the EGU during operation. ASTM D388–99 (Reapproved 2004) e1 Fossil fuel means natural gas, petroleum, coal, and any form of solid, ISO conditions means 288 Kelvin (incorporated by reference, see § 60.17), (15°C), 60 percent relative humidity and coal refuse, and petroleum coke. liquid, or gaseous fuel derived from such material for the purpose of creating 101.3 kilopascals pressure. Synthetic fuels derived from coal for the Liquid fuel means any fuel that is useful heat. purpose of creating useful heat, present as a liquid at ISO conditions Gaseous fuel means any fuel that is including, but not limited to, solvent- and includes, but is not limited to, present as a gas at ISO conditions and refined coal, gasified coal (not meeting distillate oil and residual oil. the definition of natural gas), coal-oil includes, but is not limited to, natural Mechanical output means the useful mixtures, and coal-water mixtures are gas, refinery fuel gas, process gas, coke- mechanical energy that is not used to included in this definition for the oven gas, synthetic gas, and gasified operate the affected EGU(s), generate purposes of this subpart. coal. electricity and/or thermal energy, or to Combined cycle unit means an Gross energy output means: enhance the performance of the affected electric generating unit that uses a (1) For stationary combustion turbines EGU. Mechanical energy measured in stationary combustion turbine from and IGCC, the gross electric or direct horsepower hour should be converted which the heat from the turbine exhaust mechanical output from both the EGU into MWh by multiplying it by 745.7 gases is recovered by a heat recovery (including, but not limited to, output then dividing by 1,000,000. steam generating unit (HRSG) to from steam turbine(s), combustion Natural gas means a fluid mixture of generate additional electricity. turbine(s), and gas expander(s)) plus 100 hydrocarbons (e.g., methane, ethane, or Combined heat and power unit or percent of the useful thermal output. propane), composed of at least 70 CHP unit, (also known as (2) For steam generating units, the percent methane by volume or that has ‘‘cogeneration’’) means an electric gross electric or mechanical output from a gross calorific value between 35 and generating unit that that use a steam the affected EGU(s) (including, but not 41 megajoules (MJ) per dry standard generating unit or stationary combustion limited to, output from steam turbine(s), cubic meter (950 and 1,100 Btu per dry turbine to simultaneously produce both combustion turbine(s), and gas standard cubic foot), that maintains a electric (or mechanical) and useful expander(s)) minus any electricity used gaseous state under ISO conditions. thermal output from the same primary to power the feedwater pumps plus 100 Finally, natural gas does not include the energy source. percent of the useful thermal output; following gaseous fuels: Landfill gas, Design efficiency means the rated (3) For combined heat and power digester gas, refinery gas, sour gas, blast overall net efficiency (e.g., electric plus facilities where at least 20.0 percent of furnace gas, coal-derived gas, producer useful thermal output) on a lower the total gross energy output consists of gas, coke oven gas, or any gaseous fuel heating value basis at the base load electric or direct mechanical output and produced in a process which might rating, at ISO conditions, and at the 20.0 percent of the total gross energy result in highly variable CO2 content or maximum useful thermal output (e.g., output consists of useful thermal output heating value. CHP unit with condensing steam on a 12-operating-month rolling average Net-electric sales means: turbines would determine the design basis, the gross electric or mechanical (1) The gross electric sales to the efficiency at the maximum level of output from the affected EGU utility power distribution system minus extraction and/or bypass). Design (including, but not limited to, output purchased power; or efficiency shall be determined using one from steam turbine(s), combustion (2) For combined heat and power of the following methods: ASME PTC 22 turbine(s), and gas expander(s)) minus facilities where at least 20.0 percent of Gas Turbines (incorporated by any electricity used to power the the total gross energy output consists of reference, see § 60.17), ASME PTC 46 feedwater pumps (the electric auxiliary electric or direct mechanical output and Overall Plant Performance (incorporated load of boiler feedwater pumps is not at least 20.0 percent of the total gross by reference, see § 60.17) or ISO 2314 applicable to IGCC facilities), that energy output consists of useful thermal Gas turbines—acceptance tests difference divided by 0.95, plus 100 output on an annual basis, the gross (incorporated by reference, see § 60.17). percent of the useful thermal output. electric sales to the utility power VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00148 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64657 distribution system minus purchased Standard ambient temperature and any heating application (e.g., steam power of the thermal host facility or pressure (SATP) conditions means delivered to an industrial process for a facilities. 298.15 Kelvin (25 °C, 77 °F) and 100.0 heating application, including thermal (3) Electricity supplied to other kilopascals (14.504 psi, 0.987 atm) cooling applications) that is not used for facilities that produce electricity to pressure. The enthalpy of water at SATP electric generation, mechanical output offset auxiliary loads are included when conditions is 50 Btu/lb. at the affected EGU, to directly enhance calculating net-electric sales. Solid fuel means any fuel that has a the performance of the affected EGU (4) Electric sales that that result from definite shape and volume, has no (e.g., economizer output is not useful a system emergency are not included tendency to flow or disperse under thermal output, but thermal energy used when calculating net-electric sales. moderate stress, and is not liquid or to reduce fuel moisture is considered Net-electric output means the amount gaseous at ISO conditions. This useful thermal output), or to supply of gross generation the generator(s) includes, but is not limited to, coal, energy to a pollution control device at produces (including, but not limited to, biomass, and pulverized solid fuels. the affected EGU. Useful thermal output output from steam turbine(s), Stationary combustion turbine means for affected EGU(s) with no condensate combustion turbine(s), and gas all equipment including, but not limited return (or other thermal energy input to expander(s)), as measured at the to, the turbine engine, the fuel, air, the affected EGU(s)) or where measuring generator terminals, less the electricity lubrication and exhaust gas systems, the energy in the condensate (or other used to operate the plant (i.e., auxiliary control systems (except emissions thermal energy input to the affected loads); such uses include fuel handling control equipment), heat recovery equipment, pumps, fans, pollution EGU(s)) would not meaningfully impact system, fuel compressor, heater, and/or the emission rate calculation is control equipment, other electricity pump, post-combustion emission needs, and transformer losses as measured against the energy in the control technology, and any ancillary thermal output at SATP conditions. measured at the transmission side of the components and sub-components step up transformer (e.g., the point of Affected EGU(s) with meaningful energy comprising any simple cycle stationary in the condensate return (or other sale). combustion turbine, any combined Net energy output means: thermal energy input to the affected (1) The net electric or mechanical cycle combustion turbine, and any EGU) must measure the energy in the output from the affected EGU plus 100 combined heat and power combustion condensate and subtract that energy percent of the useful thermal output; or turbine based system plus any relative to SATP conditions from the (2) For combined heat and power integrated equipment that provides measured thermal output. electricity or useful thermal output to facilities where at least 20.0 percent of Valid data means quality-assured data the total gross or net energy output the combustion turbine engine, heat recovery system or auxiliary equipment. generated by continuous monitoring consists of electric or direct mechanical systems that are installed, operated, and output and at least 20.0 percent of the Stationary means that the combustion turbine is not self-propelled or intended maintained according to part 75 of this total gross or net energy output consists chapter. For CEMS, the initial of useful thermal output on a 12- to be propelled while performing its function. It may, however, be mounted certification requirements in § 75.20 of operating-month rolling average basis, this chapter and appendix A to part 75 the net electric or mechanical output on a vehicle for portability. A stationary combustion turbine that burns any solid of this chapter must be met before from the affected EGU divided by 0.95, quality-assured data are reported under plus 100 percent of the useful thermal fuel directly is considered a steam generating unit. this subpart; for on-going quality output. assurance, the daily, quarterly, and Operating month means a calendar Steam generating unit means any semiannual/annual test requirements in month during which any fuel is furnace, boiler, or other device used for sections 2.1, 2.2, and 2.3 of appendix B combusted in the affected EGU at any combusting fuel and producing steam to part 75 of this chapter must be met time. (nuclear steam generators are not Petroleum means crude oil or a fuel included) plus any integrated and the data validation criteria in derived from crude oil, including, but equipment that provides electricity or sections 2.1.5, 2.2.3, and 2.3.2 of not limited to, distillate and residual oil. useful thermal output to the affected appendix B to part 75 of this chapter Potential electric output means 33 EGU(s) or auxiliary equipment. apply. For fuel flow meters, the initial percent or the base load rating design System emergency means any certification requirements in section efficiency at the maximum electric abnormal system condition that the 2.1.5 of appendix D to part 75 of this production rate (e.g., CHP units with Regional Transmission Organizations chapter must be met before quality- condensing steam turbines will operate (RTO), Independent System Operators assured data are reported under this at maximum electric production), (ISO) or control area Administrator subpart (except for qualifying whichever is greater, multiplied by the determines requires immediate commercial billing meters under section base load rating (expressed in MMBtu/ automatic or manual action to prevent 2.1.4.2 of appendix D to part 75), and for h) of the EGU, multiplied by 106 Btu/ or limit loss of transmission facilities or on-going quality assurance, the MMBtu, divided by 3,413 Btu/KWh, generators that could adversely affect provisions in section 2.1.6 of appendix divided by 1,000 kWh/MWh, and the reliability of the power system and D to part 75 apply (except for qualifying multiplied by 8,760 h/yr (e.g., a 35 therefore call for maximum generation commercial billing meters). percent efficient affected EGU with a resources to operate in the affected area, Violation means a specified averaging 100 MW (341 MMBtu/h) fossil fuel heat or for the specific affected EGU to period over which the CO2 emissions input capacity would have a 306,000 operate to avert loss of load. rate is higher than the applicable MWh 12-month potential electric output Useful thermal output means the emissions standard located in Table 1 or capacity). thermal energy made available for use in 2 of this subpart. VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00149 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 64658 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 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 [Note: Numerical values of 1,000 or greater have a minimum of 3 significant figures and numerical values of less than 1,000 have a minimum of 2 significant figures] Affected EGU CO2 Emission standard Newly constructed steam generating unit or integrated gasification 640 kg CO2/MWh of gross energy output (1,400 lb CO2/MWh). combined cycle (IGCC). Reconstructed steam generating unit or IGCC that has base load rating 910 kg of CO2 per MWh of gross energy output (2,000 lb CO2/MWh). of 2,100 GJ/h (2,000 MMBtu/h) or less. Reconstructed steam generating unit or IGCC that has a base load rat- 820 kg of CO2 per MWh of gross energy output (1,800 lb CO2/MWh). ing greater than 2,100 GJ/h (2,000 MMBtu/h). Modified steam generating unit or IGCC ...... A unit-specific emission limit determined by the unit’s best historical an- nual 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 great- er 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 TUR- BINES THAT COMMENCED CONSTRUCTION AFTER JANUARY 8, 2014 AND RECONSTRUCTION AFTER JUNE 18, 2014 (NET ENERGY OUTPUT-BASED STANDARDS APPLICABLE AS APPROVED BY THE ADMINISTRATOR) [Note: Numerical values of 1,000 or greater have a minimum of 3 significant figures and numerical values of less than 1,000 have a minimum of 2 significant figures] Affected EGU CO2 Emission standard Newly constructed or reconstructed stationary combustion turbine that 450 kg of CO2 per MWh of gross energy output (1,000 lb CO2/MWh); supplies more than its design efficiency or 50 percent, whichever is or less, times its potential electric output as net-electric sales on both a 470 kilograms (kg) of CO2 per megawatt-hour (MWh) of net energy 12-operating month and a 3-year rolling average basis and combusts output (1,030 lb/MWh). more than 90% natural gas on a heat input basis on a 12-operating- month rolling average basis. Newly constructed or reconstructed stationary combustion turbine that 50 kg CO2 per gigajoule (GJ) of heat input (120 lb CO2/MMBtu). supplies its design efficiency or 50 percent, whichever is less, times its potential electric output or less as net-electric sales on either a 12-operating month or a 3-year rolling average basis and combusts more than 90% natural gas on a heat input basis on a 12-operating- month rolling average basis. Newly constructed and reconstructed stationary combustion turbine that 50 kg CO2/GJ of heat input (120 lb/MMBtu) to 69 kg CO2/GJ of heat combusts 90% or less natural gas on a heat input basis on a 12-op- input (160 lb/MMBtu) as determined by the procedures in § 60.5525. erating-month rolling average basis. TABLE 3 TO SUBPART TTTT OF PART 60—APPLICABILITY OF SUBPART A OF PART 60 (GENERAL PROVISIONS) TO SUBPART TTTT General provisions Subject of citation Applies to subpart Explanation citation TTTT § 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 re- quired. § 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 (3) and to keep records of mal- functions 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 re- No. quirements. § 60.12 ...... Circumvention ...... Yes. § 60.13 ...... Monitoring requirements ...... No ...... All monitoring is done according to part 75. VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00150 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64659 TABLE 3 TO SUBPART TTTT OF PART 60—APPLICABILITY OF SUBPART A OF PART 60 (GENERAL PROVISIONS) TO SUBPART TTTT—Continued General provisions Subject of citation Applies to subpart Explanation citation TTTT § 60.14 ...... Modification ...... Yes (steam gener- ating units and IGCC facilities). No (stationary combustion tur- bines. § 60.15 ...... Reconstruction ...... Yes. § 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 GHG cost adjustment required under The revisions and additions read as PROGRAMS paragraph (b)(2)(v) of this section. follows: * * * * * ■ § 71.2 Definitions. 4. The authority citation for part 70 (v) GHG cost adjustment. The amount * * * * * continues to read as follows: calculated in paragraph (b)(2)(i) of this Regulated pollutant (for fee Authority: 42 U.S.C. 7401, et seq. section shall be increased by the GHG calculation), which is used only for cost adjustment determined as follows: ■ 5. In § 70.2, the definition of purposes of § 71.9(c), means any For each activity identified in the ‘‘Regulated pollutant (for presumptive ‘‘regulated air pollutant’’ except the following table, multiply the number of fee calculation)’’ is amended by: following: ■ a. Revising the introductory text; activities performed by the permitting authority by the burden hours per * * * * * ■ b. Removing ‘‘or’’ from the end of (4) Greenhouse gases. paragraph (2); activity, and then calculate a total * * * * * ■ c. Removing the period at the end of number of burden hours for all ■ paragraph (3) and adding ‘‘; or’’ in its activities. Next, multiply the burden 9. Section 71.9 is amended by: ■ place; and hours by the average cost of staff time, a. Revising paragraphs (c)(1), (c)(2)(i), ■ d. Adding paragraph (4). including wages, employee benefits and (c)(3), and (c)(4); and ■ The revision and additions read as overhead. b. Adding paragraph (c)(8). follows: The revisions and addition read as Burden follows: § 70.2 Definitions. hours Activity per § 71.9 Permit fees. * * * * * activity Regulated pollutant (for presumptive * * * * * (c) * * * fee calculation), which is used only for GHG completeness determina- (1) For part 71 programs that are purposes of § 70.9(b)(2), means any tion (for initial permit or up- administered by EPA, each part 71 regulated air pollutant except the dated application) ...... 43 source shall pay an annual fee which is following: GHG evaluation for a permit modification or related permit the sum of: * * * * * action ...... 7 (i) $32 per ton (as adjusted pursuant (4) Greenhouse gases. GHG evaluation at permit re- to the criteria set forth in paragraph * * * * * newal ...... 10 (n)(1) of this section) times the total tons ■ 6. Section 70.9 is amended by revising of the actual emissions of each regulated paragraph (b)(2)(i), and adding * * * * * pollutant (for fee calculation) emitted paragraph (b)(2)(v) to read as follows: from the source, including fugitive PART 71—FEDERAL OPERATING emissions; and § 70.9 Fee determination and certification. PERMIT PROGRAMS (ii) Any GHG fee adjustment required * * * * * under paragraph (c)(8) of this section. ■ (b) * * * 7. The authority citation for part 71 (2) * * * (2)(i) The Administrator will presume continues to read as follows: (i) Where the EPA has not suspended that the fee schedule meets the Authority: 42 U.S.C. 7401, et seq. its part 71 fee collection pursuant to requirements of paragraph (b)(1) of this paragraph (c)(2)(ii) of this section, the ■ section if it would result in the 8. In § 71.2, the definition of annual fee for each part 71 source shall collection and retention of an amount ‘‘Regulated pollutant (for fee be the sum of: not less than $25 per year [as adjusted calculation)’’ is amended by: (A) $24 per ton (as adjusted pursuant pursuant to the criteria set forth in ■ a. Removing ‘‘or’’ from the end of to the criteria set forth in paragraph paragraph (b)(2)(iv) of this section] paragraph (2); (n)(1) of this section) times the total tons times the total tons of the actual ■ b. Removing the period at the end of of the actual emissions of each regulated emissions of each regulated pollutant paragraph (3) and adding ‘‘; or’’ in its pollutant (for fee calculation) emitted (for presumptive fee calculation) place; and from the source, including fugitive emitted from part 70 sources and any ■ b. Adding paragraph (4). emissions; and VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00151 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2 64660 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations (B) Any GHG fee adjustment required agency proportions of total effort PART 98—MANDATORY under paragraph (c)(8) of this section. (expressed as a percentage of total effort) GREENHOUSE GAS REPORTING * * * * * needed to administer the part 71 (3) For part 71 programs that are program, 1 ¥ E ¥ D represents the ■ 10. The authority citation for part 98 administered by EPA with contractor contractor’s effort, and C represents the is revised to read as follows: assistance, the per ton fee shall vary contractor assistance cost on a per ton Authority: 42 U.S.C. 7401–7671q. depending on the extent of contractor basis. C shall be computed using the ■ 11. Section 98.426 is amended by involvement and the cost to EPA of formula for contractor assistance cost adding paragraph (h) to read as follows: contractor assistance. The EPA shall found in paragraph (c)(3) of this section establish a per ton fee that is based on and shall be zero if contractor assistance § 98.426 Data reporting requirements. the contractor costs for the specific part is not utilized. In addition, each part 71 * * * * * 71 program that is being administered, source shall pay a GHG fee adjustment (h) If you capture a CO2 stream from using the following formula: for each activity as required under × ¥ × an electricity generating unit that is Cost per ton = (E 32) + [(1 E) $C] paragraph (c)(8) of this section. subject to subpart D of this part and Where E represents EPA’s proportion * * * * * transfer CO2 to any facilities that are of total effort (expressed as a percentage subject to subpart RR of this part, you (8) GHG fee adjustment. The annual of total effort) needed to administer the must: part 71 program, 1 ¥ E represents the fee shall be increased by a GHG fee (1) Report the facility identification contractor’s effort, and C represents the adjustment for any source that has number associated with the annual GHG contractor assistance cost on a per ton initiated an activity listed in the report for the subpart D facility; basis. C shall be computed by using the following table since the fee was last (2) Report each facility identification following formula: paid. The GHG fee adjustment shall be number associated with the annual GHG C = [ B + T + N] divided by 12,300,000 equal to the set fee provided in the table reports for each subpart RR facility to Where B represents the base cost for each activity that has been initiated which CO2 is transferred; and (contractor costs), where T represents since the fee was last paid: (3) Report the annual quantity of CO2 travel costs, and where N represents in metric tons that is transferred to each nonpersonnel data management and Activity Set fee subpart RR facility. tracking costs. In addition, each part 71 ■ GHG completeness determina- 12. Section 98.427 is amended by source shall pay a GHG fee adjustment tion (for initial permit or up- adding paragraph (d) to read as follows: for each activity as required under dated application) ...... $2,236 § 98.427 Records that must be retained. paragraph (c)(8) of this section. GHG evaluation for a permit (4) For programs that are delegated in modification or related permit * * * * * part, the fee shall be computed using the action ...... 364 (d) Facilities subject to § 98.426(h) following formula: GHG evaluation at permit re- must retain records of CO2 in metric Cost per ton = (E × 32) + (D × 24) + [(1 newal ...... 520 tons that is transferred to each subpart ¥ E ¥ D) × $C] RR facility. Where E and D represent, * * * * * [FR Doc. 2015–22837 Filed 10–22–15; 8:45 am] respectively, the EPA and delegate BILLING CODE 6560–50–P VerDate Sep<11>2014 18:25 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00152 Fmt 4701 Sfmt 9990 E:\FR\FM\23OCR2.SGM 23OCR2 mstockstill on DSK4VPTVN1PROD with RULES2