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Mandatory Reporting of Greenhouse Gases
PDF Version (285 pp, 6003K, About PDF) [Federal Register: April 10, 2009 (Volume 74, Number 68)] [Proposed Rules] [Page 16447-16731] From the Federal Register Online via GPO Access [wais.access.gpo.gov] [DOCID:fr10ap09-10] [[Page 16448]] ----------------------------------------------------------------------- ENVIRONMENTAL PROTECTION AGENCY 40 CFR Parts 86, 87, 89, 90, 94, 98, 600, 1033, 1039, 1042, 1045, 1048, 1051, 1054, and 1065 [EPA-HQ-OAR-2008-0508; FRL-8782-1] RIN 2060-A079 Mandatory Reporting of Greenhouse Gases AGENCY: Environmental Protection Agency (EPA). ACTION: Proposed rule. ----------------------------------------------------------------------- SUMMARY: EPA is proposing a regulation to require reporting of greenhouse gas emissions from all sectors of the economy. The rule would apply to fossil fuel suppliers and industrial gas suppliers, as well as to direct greenhouse gas emitters. The proposed rule does not require control of greenhouse gases, rather it requires only that sources above certain threshold levels monitor and report emissions. DATES: Comments must be received on or before June 9, 2009. There will be two public hearings. One hearing was held on April 6 and 7, 2009, in the Washington, DC, area (One Potomac Yard, 2777 S. Crystal Drive, Arlington, VA 22202). One hearing will be on April 16, 2009 in Sacramento, CA (Sacramento Convention Center, 1400 J Street, Sacramento, CA 95814). The April 16, 2009 hearing will begin at 9 a.m. local time. ADDRESSES: Submit your comments, identified by Docket ID No. EPA-HQ- OAR-2008-0508, by one of the following methods: • Federal eRulemaking Portal: http://www.regulations.gov. Follow the online instructions for submitting comments. • E-mail: a-and-r-Docket@epa.gov. • Fax: (202) 566-1741. • Mail: Environmental Protection Agency, EPA Docket Center (EPA/DC), Mailcode 6102T, Attention Docket ID No. EPA-HQ-OAR-2008-0508, 1200 Pennsylvania Avenue, NW., Washington, DC 20460. • Hand Delivery: EPA Docket Center, Public Reading Room, EPA West Building, Room 3334, 1301 Constitution Avenue, NW., Washington, DC 20004. Such deliveries are only accepted during the Docket's normal hours of operation, and special arrangements should be made for deliveries of boxed information. Instructions: Direct your comments to Docket ID No. EPA-HQ-OAR- 2008-0508. EPA's policy is that all comments received will be included in the public docket without change and may be made available online at http://www.regulations.gov, including any personal information provided, unless the comment includes information claimed to be CBI or other information whose disclosure is restricted by statute. Do not submit information that you consider to be CBI or otherwise protected through http://www.regulations.gov or e-mail. The http:// www.regulations.gov Web site is an ``anonymous access'' system, which means EPA will not know your identity or contact information unless you provide it in the body of your comment. If you send an e-mail comment directly to EPA without going through http://www.regulations.gov your e-mail address will be automatically captured and included as part of the comment that is placed in the public docket and made available on the Internet. If you submit an electronic comment, EPA recommends that you include your name and other contact information in the body of your comment and with any disk or CD-ROM you submit. If EPA cannot read your comment due to technical difficulties and cannot contact you for clarification, EPA may not be able to consider your comment. Electronic files should avoid the use of special characters, any form of encryption, and be free of any defects or viruses. Docket: All documents in the docket are listed in the http:// www.regulations.gov index. Although listed in the index, some information is not publicly available, e.g., CBI or other information whose disclosure is restricted by statute. Certain other material, such as copyrighted material, will be publicly available only in hard copy. Publicly available docket materials are available either electronically in http://www.regulations.gov or in hard copy at the Air Docket, EPA/ DC, EPA West, Room B102, 1301 Constitution Ave., NW., Washington, DC. This Docket Facility is open from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding legal holidays. The telephone number for the Public Reading Room is (202) 566-1744, and the telephone number for the Air Docket is (202) 566-1742. FOR FURTHER INFORMATION CONTACT: Carole Cook, Climate Change Division, Office of Atmospheric Programs (MC-6207J), Environmental Protection Agency, 1200 Pennsylvania Ave., NW., Washington, DC 20460; telephone number: (202) 343-9263; fax number: (202) 343-2342; e-mail address: GHGReportingRule@epa.gov. For technical information, contact the Greenhouse Gas Reporting Rule Hotline at telephone number: (877) 444- 1188; or e-mail: ghgmrr@epa.gov. To obtain information about the public hearings or to register to speak at the hearings, please go to http:// www.epa.gov/climatechange/emissions/ghgrulemaking.html. Alternatively, contact Carole Cook at 202-343-9263. SUPPLEMENTARY INFORMATION: Additional Information on Submitting Comments: To expedite review of your comments by Agency staff, you are encouraged to send a separate copy of your comments, in addition to the copy you submit to the official docket, to Carole Cook, U.S. EPA, Office of Atmospheric Programs, Climate Change Division, Mail Code 6207-J, Washington, DC, 20460, telephone (202) 343-9263, e-mail GHGReportingRule@epa.gov. Regulated Entities. The Administrator determines that this action is subject to the provisions of CAA section 307(d). See CAA section 307(d)(1)(V) (the provisions of section 307(d) apply to ``such other actions as the Administrator may determine.''). This is a proposed regulation. If finalized, these regulations would affect owners and operators of fuel and chemicals suppliers, direct emitters of GHGs and manufacturers of mobile sources and engines. Regulated categories and entities would include those listed in Table 1 of this preamble: Table 1--Examples of Affected Entities by Category ------------------------------------------------------------------------ Examples of affected Category NAICS facilities ------------------------------------------------------------------------ General Stationary Fuel .............. Facilities operating Combustion Sources. boilers, process heaters, incinerators, turbines, and internal combustion engines: 211 Extractors of crude petroleum and natural gas. 321 Manufacturers of lumber and wood products. 322 Pulp and paper mills. 325 Chemical manufacturers. 324 Petroleum refineries, and manufacturers of coal products. [[Page 16449]] 316, 326, 339 Manufacturers of rubber and miscellaneous plastic products. 331 Steel works, blast furnaces. 332 Electroplating, plating, polishing, anodizing, and coloring. 336 Manufacturers of motor vehicle parts and accessories. 221 Electric, gas, and sanitary services. 622 Health services. 611 Educational services. Electricity Generation......... 221112 Fossil-fuel fired electric generating units, including units owned by Federal and municipal governments and units located in Indian Country. Adipic Acid Production......... 325199 Adipic acid manufacturing facilities. Aluminum Production............ 331312 Primary Aluminum production facilities. Ammonia Manufacturing.......... 325311 Anhydrous and aqueous ammonia manufacturing facilities. Cement Production.............. 327310 Owners and operators of Portland Cement manufacturing plants. Electronics Manufacturing...... 334111 Microcomputers manufacturing facilities. 334413 Semiconductor, photovoltaic (solid- state) device manufacturing facilities. 334419 LCD unit screens manufacturing facilities. .............. MEMS manufacturing facilities. Ethanol Production............. 325193 Ethyl alcohol manufacturing facilities. Ferroalloy Production.......... 331112 Ferroalloys manufacturing facilities. Fluorinated GHG Production..... 325120 Industrial gases manufacturing facilities. Food Processing................ 311611 Meat processing facilities. 311411 Frozen fruit, juice, and vegetable manufacturing facilities. 311421 Fruit and vegetable canning facilities. Glass Production............... 327211 Flat glass manufacturing facilities. 327213 Glass container manufacturing facilities. 327212 Other pressed and blown glass and glassware manufacturing facilities. HCFC-22 Production and HFC-23 325120 Chlorodifluoromethane Destruction. manufacturing facilities. Hydrogen Production............ 325120 Hydrogen manufacturing facilities. Iron and Steel Production...... 331111 Integrated iron and steel mills, steel companies, sinter plants, blast furnaces, basic oxygen process furnace shops. Lead Production................ 331419 Primary lead smelting and refining facilities. 331492 Secondary lead smelting and refining facilities. Lime Production................ 327410 Calcium oxide, calcium hydroxide, dolomitic hydrates manufacturing facilities. Magnesium Production........... 331419 Primary refiners of nonferrous metals by electrolytic methods. 331492 Secondary magnesium processing plants. Nitric Acid Production......... 325311 Nitric acid manufacturing facilities. Oil and Natural Gas Systems.... 486210 Pipeline transportation of natural gas. 221210 Natural gas distribution facilities. 325212 Synthetic rubber manufacturing facilities. Petrochemical Production....... 32511 Ethylene dichloride manufacturing facilities. 325199 Acrylonitrile, ethylene oxide, methanol manufacturing facilities. 325110 Ethylene manufacturing facilities. 325182 Carbon black manufacturing facilities. Petroleum Refineries........... 324110 Petroleum refineries. Phosphoric Acid Production..... 325312 Phosphoric acid manufacturing facilities. Pulp and Paper Manufacturing... 322110 Pulp mills. 322121 Paper mills. 322130 Paperboard mills. Silicon Carbide Production..... 327910 Silicon carbide abrasives manufacturing facilities. Soda Ash Manufacturing......... 325181 Alkalies and chlorine manufacturing facilities. Sulfur Hexafluoride (SF6) from 221121 Electric bulk power Electrical Equipment. transmission and control facilities. Titanium Dioxide Production.... 325188 Titanium dioxide manufacturing facilities. Underground Coal Mines......... 212113 Underground anthracite coal mining operations. 212112 Underground bituminous coal mining operations. Zinc Production................ 331419 Primary zinc refining facilities. 331492 Zinc dust reclaiming facilities, recovering from scrap and/or alloying purchased metals. Landfills...................... 562212 Solid waste landfills. 221320 Sewage treatment facilities. 322110 Pulp mills. 322121 Paper mills. 322122 Newsprint mills. 322130 Paperboard mills. 311611 Meat processing facilities. 311411 Frozen fruit, juice, and vegetable manufacturing facilities. 311421 Fruit and vegetable canning facilities. Wastewater Treatment........... 322110 Pulp mills. 322121 Paper mills. 322122 Newsprint mills. 322130 Paperboard mills. [[Page 16450]] 311611 Meat processing facilities. 311411 Frozen fruit, juice, and vegetable manufacturing facilities. 311421 Fruit and vegetable canning facilities. 325193 Ethanol manufacturing facilities. 324110 Petroleum refineries. Manure Management.............. 112111 Beef cattle feedlots. 112120 Dairy cattle and milk production facilities. 112210 Hog and pig farms. 112310 Chicken egg production facilities. 112330 Turkey Production. 112320 Broilers and Other Meat type Chicken Production. Suppliers of Coal and Coal- 212111 Bituminous, and lignite based Products. coal surface mining facilities. 212113 Anthracite coal mining facilities. 212112 Underground bituminous coal mining facilities. Suppliers of Coal Based Liquids 211111 Coal liquefaction at Fuels. mine sites. Suppliers of Petroleum Products 324110 Petroleum refineries. Suppliers of Natural Gas and 221210 Natural gas NGLs. distribution facilities. 211112 Natural gas liquid extraction facilities. Suppliers of Industrial GHGs... 325120 Industrial gas manufacturing facilities. Suppliers of Carbon Dioxide 325120 Industrial gas (CO2). manufacturing facilities. Mobile Sources................. 336112 Light-duty vehicles and trucks manufacturing facilities. 333618 Heavy-duty, non-road, aircraft, locomotive, and marine diesel engine manufacturing. 336120 Heavy-duty vehicle manufacturing facilities. 336312 Small non-road, and marine spark-ignition engine manufacturing facilities. 336999 Personal watercraft manufacturing facilities. 336991 Motorcycle manufacturing facilities. ------------------------------------------------------------------------ Table 1 of this preamble is not intended to be exhaustive, but rather provides a guide for readers regarding facilities likely to be regulated by this action. Table 1 of this preamble lists the types of facilities that EPA is now aware could be potentially affected by this action. Other types of facilities not listed in the table could also be subject to reporting requirements. To determine whether your facility is affected by this action, you should carefully examine the applicability criteria found in proposed 40 CFR part 98, subpart A. If you have questions regarding the applicability of this action to a particular facility, consult the person listed in the preceding FOR FURTHER INFORMATION CONTACT section. Many facilities that would be affected by the proposed rule have GHG emissions from multiple source categories listed in Table 1 of this preamble. Table 2 of this preamble has been developed as a guide to help potential reporters subject to the mandatory reporting rule identify the source categories (by subpart) that they may need to (1) consider in their facility applicability determination, and (2) include in their reporting. For each source category, activity, or facility type (e.g., electricity generation, aluminum production), Table 2 of this preamble identifies the subparts that are likely to be relevant. The table should only be seen as a guide. Additional subparts may be relevant for a given reporter. Similarly, not all listed subparts would be relevant for all reporters. Table 2--Source Categories and Relevant Subparts ------------------------------------------------------------------------ Source category (and main applicable Subparts recommended for review subpart) to determine applicability ------------------------------------------------------------------------ General Stationary Fuel Combustion General Stationary Fuel Sources. Combustion. Electricity Generation................. General Stationary Fuel Combustion, Electricity Generation, Suppliers of CO2, Electric Power Systems. Adipic Acid Production................. Adipic Acid Production, General Stationary Fuel Combustion. Aluminum Production.................... General Stationary Fuel Combustion. Ammonia Manufacturing.................. General Stationary Fuel Combustion, Hydrogen, Nitric Acid, Petroleum Refineries, Suppliers of CO2. Cement Production...................... General Stationary Fuel Combustion, Suppliers of CO2. Electronics Manufacturing.............. General Stationary Fuel Combustion. Ethanol Production..................... General Stationary Fuel Combustion, Landfills, Wastewater Treatment. Ferroalloy Production.................. General Stationary Fuel Combustion. Fluorinated GHG Production............. General Stationary Fuel Combustion. Food Processing........................ General Stationary Fuel Combustion, Landfills, Wastewater Treatment. Glass Production....................... General Stationary Fuel Combustion. HCFC-22 Production and HFC-23 General Stationary Fuel Destruction. Combustion. Hydrogen Production.................... General Stationary Fuel Combustion, Petrochemicals, Petroleum Refineries, Suppliers of Industrial GHGs, Suppliers of CO2. Iron and Steel Production.............. General Stationary Fuel Combustion, Suppliers of CO2. Lead Production........................ General Stationary Fuel Combustion. Lime Manufacturing..................... General Stationary Fuel Combustion. [[Page 16451]] Magnesium Production................... General Stationary Fuel Combustion. Nitric Acid Production................. General Stationary Fuel Combustion, Adipic Acid. Oil and Natural Gas Systems............ General Stationary Fuel Combustion, Petroleum Refineries, Suppliers of Petroleum Products, Suppliers of Natural Gas and NGL, Suppliers of CO2. Petrochemical Production............... General Stationary Fuel Combustion, Ammonia, Petroleum Refineries. Petroleum Refineries................... General Stationary Fuel Combustion, Hydrogen, Landfills, Wastewater Treatment, Suppliers of Petroleum Products. Phosphoric Acid Production............. General Stationary Fuel Combustion. Pulp and Paper Manufacturing........... General Stationary Fuel Combustion, Landfills, Wastewater Treatment. Silicon Carbide Production............. General Stationary Fuel Combustion. Soda Ash Manufacturing................. General Stationary Fuel Combustion. Sulfur Hexafluoride (SF6) from General Stationary Fuel Electrical Equipment. Combustion. Titanium Dioxide Production............ General Stationary Fuel Combustion. Underground Coal Mines................. General Stationary Fuel Combustion, Suppliers of Coal. Zinc Production........................ General Stationary Fuel Combustion. Landfills.............................. General Stationary Fuel Combustion, Ethanol, Food Processing, Petroleum Refineries, Pulp and Paper. Wastewater Treatment................... General Stationary Fuel Combustion, Ethanol, Food Processing, Petroleum Refineries, Pulp and Paper. Manure Management...................... General Stationary Fuel Combustion. Suppliers of Coal...................... General Stationary Fuel Combustion, Underground Coal Mines. Suppliers of Coal-based Liquid Fuels... Suppliers of Coal, Suppliers of Petroleum Products. Suppliers of Petroleum Products........ General Stationary Fuel Combustion, Oil and Natural Gas Systems. Suppliers of Natural Gas and NGLs...... General Stationary Fuel Combustion, Oil and Natural Gas Systems, Suppliers of CO2. Suppliers of Industrial GHGs........... General Stationary Fuel Combustion, Hydrogen Production, Suppliers of CO2. Suppliers of Carbon Dioxide (CO2)...... General Stationary Fuel Combustion, Electricity Generation, Ammonia, Cement, Hydrogen, Iron and Steel, Suppliers of Industrial GHGs. Mobile Sources......................... General Stationary Fuel Combustion. ------------------------------------------------------------------------ Acronyms and Abbreviations. The following acronyms and abbreviations are used in this document. A/C air conditioning AERR Air Emissions Reporting Rule ANPR advance notice of proposed rulemaking ARP Acid Rain Program ASME American Society of Mechanical Engineers ASTM American Society for Testing and Materials BLS Bureau of Labor Statistics CAA Clean Air Act CAFE Corporate Average Fuel Economy CARB California Air Resources Board CBI confidential business information CCAR California Climate Action Registry CDX central data exchange CEMS continuous emission monitoring system(s) CERR Consolidated Emissions Reporting Rule cf cubic feet CFCs chlorofluorocarbons CFR Code of Federal Regulations CH4 methane CHP combined heat and power CO2 carbon dioxide CO2e CO2-equivalent COD chemical oxygen demand DE destruction efficiency DOD U.S. Department of Defense DOE U.S. Department of Energy DOT U.S. Department of Transportation DE destruction efficiency DRE destruction or removal efficiency ECOS Environmental Council of the States EGUs electrical generating units EIA Energy Information Administration EISA Energy Independence and Security Act of 2007 EO Executive Order EOR enhanced oil recovery EPA U.S. Environmental Protection Agency EU European Union FTP Federal Test Procedure FY2008 fiscal year 2008 GHG greenhouse gas GWP global warming potential HCFC-22 chlorodifluoromethane (or CHClF2) HCFCs hydrochlorofluorocarbons HCl hydrogen chloride HFC-23 trifluoromethane (or CHF3) HFCs hydrofluorocarbons HFEs hydrofluorinated ethers HHV higher heating value ICR information collection request IPCC Intergovernmental Panel on Climate Change ISO International Organization for Standardization kg kilograms LandGEM Landfill Gas Emissions Model LCD liquid crystal display LDCs local natural gas distribution companies LEDs light emitting diodes LNG liquified natural gas LPG liquified petroleum gas MEMS microelectricomechanical system mmBtu/hr millions British thermal units per hour MMTCO2e million metric tons carbon dioxide equivalent MSHA Mine Safety and Health Administration MSW municipal solid waste MW megawatts N2O nitrous oxide NAAQS national ambient air quality standard NACAA National Association of Clean Air Agencies NAICS North American Industry Classification System NEI National Emissions Inventory NESHAP national emission standards for hazardous air pollutants NF3 nitrogen trifluoride NGLs natural gas liquids NIOSH National Institute for Occupational Safety and Health NSPS new source performance standards NSR New Source Review NTTAA National Technology Transfer and Advancement Act of 1995 O3 ozone ODS ozone-depleting substance(s) OMB Office of Management and Budget ORIS Office of Regulatory Information Systems PFCs perfluorocarbons PIN personal identification number POTWs publicly owned treatment works PSD Prevention of Significant Deterioration PV photovoltaic QA quality assurance QA/QC quality assurance/quality control QAPP quality assurance performance plan RFA Regulatory Flexibility Act RFS Renewable Fuel Standard RGGI Regional Greenhouse Gas Initiative [[Page 16452]] RIA regulatory impact analysis SAE Society of Automotive Engineers SAR IPCC Second Assessment Report SBREFA Small Business Regulatory Enforcement Fairness Act SF6 sulfur hexafluoride SFTP Supplemental Federal Test Procedure SI international system of units SIP State Implementation Plan SSM startup, shutdown, and malfunction TCR The Climate Registry TOC total organic carbon TRI Toxic Release Inventory TSCA Toxics Substances Control Act TSD technical support document U.S. United States UIC underground injection control UMRA Unfunded Mandates Reform Act of 1995 UNFCCC United Nations Framework Convention on Climate Change USDA U.S. Department of Agriculture USGS U.S. Geological Survey VMT vehicle miles traveled VOC volatile organic compound(s) WBCSD World Business Council for Sustainable Development WCI Western Climate Initiative WRI World Resources Institute XML eXtensible Markup Language Table of Contents I. Background A. What Are GHGs? B. What Is Climate Change? C. Statutory Authority D. Inventory of U.S. GHG Emissions and Sinks E. How does this proposal relate to U.S. government and other climate change efforts? F. How does this proposal relate to EPA's Climate Change ANPR? G. How was this proposed rule developed? II. Summary of Existing Federal, State, and Regional Emission Reporting Programs A. Federal Voluntary GHG Programs B. Federal Mandatory Reporting Programs C. EPA Emissions Inventories D. Regional and State Voluntary Programs for GHG Emissions Reporting E. State and Regional Mandatory Programs for GHG Emissions Reporting and Reduction F. How the Proposed Mandatory GHG Reporting Program is Different From the Federal and State Programs EPA Reviewed III. Summary of the General Requirements of the Proposed Rule A. Who must report? B. Schedule for Reporting C. What do I have to report? D. How do I submit the report? E. What records must I retain? IV. Rationale for the General Reporting, Recordkeeping and Verification Requirements That Apply to All Source Categories A. Rationale for Selection of GHGs To Report B. Rationale for Selection of Source Categories To Report C. Rationale for Selection of Thresholds D. Rationale for Selection of Level of Reporting E. Rationale for Selecting the Reporting Year F. Rationale for Selecting the Frequency of Reporting G. Rationale for the Emissions Information to Report H. Rationale for Monitoring Requirements I. Rationale for Selecting the Recordkeeping Requirements J. Rationale for Verification Requirements K. Rationale for Selection of Duration of the Program V. Rationale for the Reporting, Recordkeeping and Verification Requirements for Specific Source Categories A. Overview of Reporting for Specific Source Categories B. Electricity Purchases C. General Stationary Fuel Combustion Sources D. Electricity Generation E. Adipic Acid Production F. Aluminum Production G. Ammonia Manufacturing H. Cement Production I. Electronics Manufacturing J. Ethanol Production K. Ferroalloy Production L. Fluorinated GHG Production M. Food Processing N. Glass Production O. HCFC-22 Production and HFC-23 Destruction P. Hydrogen Production Q. Iron and Steel Production R. Lead Production S. Lime Manufacturing T. Magnesium Production U. Miscellaneous Uses of Carbonates V. Nitric Acid Production W. Oil and Natural Gas Systems X. Petrochemical Production Y. Petroleum Refineries Z. Phosphoric Acid Production AA. Pulp and Paper Manufacturing BB. Silicon Carbide Production CC. Soda Ash Manufacturing DD. Sulfur Hexafluoride (SF6) from Electrical Equipment EE. Titanium Dioxide Production FF. Underground Coal Mines GG. Zinc Production HH. Landfills II. Wastewater Treatment JJ. Manure Management KK. Suppliers of Coal LL. Suppliers of Coal-Based Liquid Fuels MM. Suppliers of Petroleum Products NN. Suppliers of Natural Gas and Natural Gas Liquids OO. Suppliers of Industrial GHGs PP. Suppliers of Carbon Dioxide (CO2) QQ. Mobile Sources VI. Collection, Management, and Dissemination of GHG Emissions Data A. Purpose B. Data Collection C. Data Management D. Data Dissemination VII. Compliance and Enforcement A. Compliance Assistance B. Role of the States C. Enforcement VIII. Economic Impacts of the Proposed Rule A. How are compliance costs estimated? B. What are the costs of this proposed rule? C. What are the economic impacts of the proposed rule? D. What are the impacts of the proposed rule on small entities? E. What are the benefits of the proposed rule for society? IX. Statutory and Executive Order Reviews A. Executive Order 12866: Regulatory Planning and Review B. Paperwork Reduction Act C. Regulatory Flexibility Act (RFA) D. Unfunded Mandates Reform Act (UMRA) E. Executive Order 13132: Federalism F. Executive Order 13175: Consultation and Coordination With Indian Tribal Governments G. Executive Order 13045: Protection of Children From Environmental Health Risks and Safety Risks H. Executive Order 13211: Actions That Significantly Affect Energy Supply, Distribution, or Use I. National Technology Transfer and Advancement Act J. Executive Order 12898: Federal Actions To Address Environmental Justice in Minority Populations and Low-Income Populations I. Background The proposed rule would require reporting of annual emissions of carbon dioxide (CO2), methane (CH4), nitrous oxide (N2O), sulfur hexafluoride (SF6), hydrofluorocarbons (HFCs), perfluorochemicals (PFCs), and other fluorinated gases (e.g., nitrogen trifluoride and hydrofluorinated ethers (HFEs)). The proposed rule would apply to certain downstream facilities that emit GHGs (primarily large facilities emitting 25,000 tpy of CO2 equivalent GHG emissions or more) and to upstream suppliers of fossil fuels and industrial GHGs, as well as to manufacturers of vehicles and engines. Reporting would be at the facility level, except certain suppliers and vehicle and engine manufacturers would report at the corporate level. This preamble is broken into several large sections, as detailed above in the Table of Contents. Throughout the preamble we explicitly request comment on a variety of issues. The paragraph below describes the layout of the preamble and provides a brief summary of each section. We also highlight particular issues on which, as indicated later in the preamble, we would specifically be interested in receiving comments. The first section of this preamble contains the basic background information about greenhouse gases and climate change. It also describes the origin of this proposal, our legal authority and how this proposal relates to other efforts to address emissions of greenhouse gases. In this section we [[Page 16453]] would be particularly interested in receiving comment on the relationship between this proposal and other government efforts. The second section of this preamble describes existing Federal, State, Regional mandatory and voluntary GHG reporting programs and how they are similar and different to this proposal. Again, similar to the previous section, we would like comments on the interrelationship of this proposal and existing GHG reporting programs. The third section of this preamble provides an overview of the proposal itself, while the fourth section provides the rationale for each decision the Agency made in developing the proposal, including key design elements such as: (i) Source categories included, (ii) the level of reporting, (iii) applicability thresholds, (iv) reporting and monitoring methods, (v) verification, (vi) frequency and (vii) duration of reporting. Furthermore, in this section, EPA explains the distinction between upstream and downstream reporters, describes why it is necessary to collect data at multiple points, and provides information on how different data would be useful to inform different policies. As stated in the fourth section, we solicit comment on each design element of the proposal generally. The fifth section of this preamble looks at the same key design elements for each of the source categories covered by the proposal. Thus, for example, there is a specific discussion regarding appropriate applicability thresholds, reporting and monitoring methodologies and reporting and recordkeeping requirements for each source category. Each source category describes the proposed options for each design element, as well as the other options considered. In addition to the general solicitation for comment on each design element generally and for each source category, throughout the fifth section there are specific issues highlighted on which we solicit comment. Please refer to the specific source category of interest for more details. The sixth section of this preamble explains how EPA would collect, manage and disseminate the data, while the seventh section describes the approach to compliance and enforcement. In both sections the role of the States is discussed, as are requests for comment on that role. Finally, the eighth section provides the summary of the impacts and costs from the Regulatory Impact Analysis and the last section walks through the various statutory and executive order requirements applicable to rulemakings. A. What Are GHGs? The proposed rule would cover the major GHGs that are directly emitted by human activities. These include CO2, CH4, N2O, HFCs, PFCs, SF6, and other specified fluorinated compounds (e.g., HFEs) used in boutique applications such as electronics and anesthetics. These gases influence the climate system by trapping in the atmosphere heat that would otherwise escape to space. The GHGs vary in their capacity to trap heat. The GHGs also vary in terms of how long they remain in the atmosphere after being emitted, with the shortest-lived GHG remaining in the atmosphere for roughly a decade and the longest-lived GHG remaining for up to 50,000 years. Because of these long atmospheric lifetimes, all of the major GHGs become well mixed throughout the global atmosphere regardless of emission origin. Global atmospheric CO2 concentration increased about 35 percent from the pre-industrial era to 2005. The global atmospheric concentration of CH4 has increased by 148 percent from pre- industrial levels, and the N2O concentration has increased 18 percent. The observed increase in concentration of these gases can be attributed primarily to human activities. The atmospheric concentration of industrial fluorinated gases--HFCs, PFCs, SF6--and other fluorinated compounds are relatively low but are increasing rapidly; these gases are entirely anthropogenic in origin. Due to sheer quantity of emissions, CO2 is the largest contributor to GHG concentrations followed by CH4. Combustion of fossil fuels (e.g., coal, oil, gas) is the largest source of CO2 emissions in the U.S. The other GHGs are emitted from a variety of activities. These emissions are compiled by EPA in the Inventory of U.S. Greenhouse Gas Emissions and Sinks (Inventory) and reported to the UNFCCC \1\ on an annual basis.\2\ A more detailed discussion of the Inventory is provided in Section I.D below. --------------------------------------------------------------------------- \1\ For more information about the UNFCCC, please refer to: http://www.unfccc.int.See Articles 4 and 12 of the UNFCCC treaty. Parties to the Convention, by ratifying, ``shall develop, periodically update, publish and make available * * * national inventories of anthropogenic emissions by sources and removals by sinks of all greenhouse gases not controlled by the Montreal Protocol, using comparable methodologies * * *''. \2\ The U.S. submits the Inventory of U.S. Greenhouse Gas Emissions and Sinks to the Secretariat of the UNFCCC as an annual reporting requirement. The UNFCCC treaty, ratified by the U.S. in 1992, sets an overall framework for intergovernmental efforts to tackle the challenge posed by climate change. The U.S. has submitted the GHG inventory to the United Nations every year since 1993. The annual Inventory of U.S. Greenhouse Gas Emissions and Sinks is consistent with national inventory data submitted by other UNFCCC Parties, and uses internationally accepted methods for its emission estimates. --------------------------------------------------------------------------- Because GHGs have different heat trapping capacities, they are not directly comparable without translating them into common units. The GWP, a metric that incorporates both the heat-trapping ability and atmospheric lifetime of each GHG, can be used to develop comparable numbers by adjusting all GHGs relative to the GWP of CO2. When quantities of the different GHGs are multiplied by their GWPs, the different GHGs can be compared on a CO2e basis. The GWP of CO2 is 1.0, and the GWP of other GHGs are expressed relative to CO2. For example, CH4 has a GWP of 21, meaning each metric ton of CH4 emissions would have 21 times as much impact on global warming (over a 100-year time horizon) as a metric ton of CO2 emissions. The GWPs of the other gases are listed in the proposed rule, and range from the hundreds up to 23,900 for SF6.\3\ Aggregating all GHGs on a CO2e basis at the source level allows a comparison of the total emissions of all the gases from one source with emissions from other sources. --------------------------------------------------------------------------- \3\ EPA has chosen to use GWPs published in the IPCC SAR (furthermore referenced as ``SAR GWP values''). The use of the SAR GWP values allows comparability of data collected in this proposed rule to the national GHG inventory that EPA compiles annually to meet U.S. commitments to the UNFCCC. To comply with international reporting standards under the UNFCCC, official emission estimates are to be reported by the U.S. and other countries using SAR GWP values. The UNFCCC reporting guidelines for national inventories were updated in 2002 but continue to require the use of GWPs from the SAR. The parties to the UNFCCC have also agreed to use GWPs based upon a 100-year time horizon although other time horizon values are available. For those fluorinated compounds included in this proposal that not listed in the SAR, EPA is using the most recent available GWPs, either the IPCC Third Assessment Report or Fourth Assessment Report. For more specific information about the GWP of specific GHGs, please see Table A-1 in the proposed 40 CFR part 98, subpart A. --------------------------------------------------------------------------- For additional information about GHGs, climate change, climate science, etc. please see EPA's climate change Web site found at http://www.epa.gov/climatechange/. B. What Is Climate Change? Climate change refers to any significant changes in measures of climate (such as temperature, precipitation, or wind) lasting for an extended period. Historically, natural factors such as volcanic eruptions and changes in the amount of energy released from the sun have affected the earth's climate. Beginning in the late 18th century, human activities associated with the industrial revolution [[Page 16454]] have also changed the composition of the earth's atmosphere and very likely are influencing the earth's climate.\4\ The heating effect caused by the buildup of GHGs in our atmosphere enhances the Earth's natural greenhouse effect and adds to global warming. As global temperatures increase other elements of the climate system, such as precipitation, snow and ice cover, sea levels, and weather events, change. The term ``climate change,'' which encompasses these broader effects, is often used instead of ``global warming.'' --------------------------------------------------------------------------- \4\ IPCCC: Climate Change 2007: The Physical Science Basis, February 2, 2007 (http://www.ipcc.ch/
88,000 metric tons CO2e and ±26,000 metric tons CO2e, respectively. The reduction in uncertainty associated with moving from the Tier 2 to the Tier 3 approach, 62,000 metric tons CO2e, is as large as the emissions from many of the sources that would be subject to the rule. We concluded the extra burden to facilities of measuring the smelter-specific slope coefficients is justified by the considerable improvement in the precision of the reported emissions. --------------------------------------------------------------------------- \65\ The most common smelter technology in the U.S. is the center-worked prebake technology. The 2006 IPCC Guidelines provide a 95 percent confidence interval of ±6 percent for the center-worked prebake technology default slope coefficient. However, this range is not the range within which the slope coefficient from a single center-worked prebake technology has a 95 percent chance of falling. Instead, it is the range within which the true mean of all center-worked prebake technology slope factors has a 95 percent chance of falling. This appears to depart from the usual convention for expressing the uncertainties related to the use of default coefficients in the Guidelines. --------------------------------------------------------------------------- Measurement of Slope Coefficients. We propose that slope coefficients be measured using a method similar to the USEPA/ International Aluminum Institute Protocol for Measurement of Tetrafluoromethane and Hexafluoroethane from Primary Aluminum Production. The protocol establishes guidelines to ensure that measurements of smelter-specific slope-coefficients are consistent and accurate (e.g., representative of typical smelter operating conditions and emission rates). These guidelines include recommendations for documenting the frequency and duration of anode effects, measuring aluminum production, sampling design, measurement instruments and methods, calculations, QA/QC, and measurement frequency. During the past few years, multiple U.S. smelters have adopted changes to their production process which are likely to have changed their slope coefficients.\66\ These include the adoption of slotted anodes and improvements to process control algorithms. Although some U.S. smelters have recently updated their measurements of smelter- specific coefficients, others may not have. --------------------------------------------------------------------------- \66\ Aluminum Production TSD (EPA-HQ-OAR-2008-0508-006). --------------------------------------------------------------------------- We understand that two smelting companies in the U.S., Rio Tinto Alcan and Alcoa, have the necessary equipment and teams in-house to measure smelter-specific slope factors. These two companies account for 11 out of 15 of the operating smelters in the U.S. The remaining facilities would need to hire a consultant to conduct a measurement study once every three years to accurately determine their slope coefficients. The cost of hiring a consultant to conduct the measurement study is probably significantly lower than the capital, labor and O&M costs of the equipment, training, and maintenance required to conduct the measurements in-house. While the cost to implement a Tier 3 approach is significantly greater than the cost to implement a Tier 2 approach, the benefit of reduced uncertainty is considerable (approximately 40 percent), as noted above. We request comment on the proposal that all smelters be required to measure their smelter-specific slope coefficients at least once every three years. We considered, but are not proposing, to exempt ``high performing'' smelters, as defined by the 2006 IPCC Guidelines, from the requirement to measure their smelter-specific slope coefficients more [[Page 16491]] than once. The Guidelines define ``high-performing'' smelters as those that operate with less than 0.2 anode effect minutes per cell day or less than 1.4 millivolt overvoltage. The Guidelines state, ``no significant improvement can be expected in the overall facility GHG inventory by using the Tier 3 method rather than the Tier 2 method.'' (IPCC, page 4.53, footnote 1). However, EPA believes there is benefit to EPA and to industry of periodic evaluation of the correlation of the smelter-specific slope coefficient and actual emissions, even in situations of low anode effect minutes per cell day or overvoltage. The Overvoltage Method. Another Tier 3 method included in the IPCC Guidelines is the Overvoltage Method. This method relates PFC emissions to an overvoltage coefficient, anode effect overvoltage, current efficiency, and aluminum production. The overvoltage method was developed for smelters using the Pechiney technology. We request comment on whether any U.S. smelters are using the Pechiney technology and, if so, on whether these smelters should be permitted to use the Overvoltage Method. Proposed Method for Monitoring Process CO2 Emissions. If you are required to use an existing CEMS to meet the requirements outlined in proposed 40 CFR part 98, subpart C, you would be required to use CEMS to estimate stationary fuel combustion CO2 emissions. Where the CEMS capture all combustion- and process-related CO2 emissions you would be required to follow the calculation procedures, monitoring and QA/QC methods, missing data procedures, reporting requirements, and recordkeeping requirements of proposed 40 CFR part 98, subpart C to estimate process and stationary fuel combustion CO2 emissions from the industrial source. Also, refer to proposed 40 CR part 98, subpart C to estimate combustion-related CH4 and N2O. If your facility does not have stationary combustion, or if you do not currently have CEMS that meet the requirements outlined in proposed 40 CR part 98, subpart C, or where the CEMS would not adequately account for process CO2 emissions, the proposed monitoring method for process CO2 emissions is similar to the IPCC Tier 2 approach, which relies on industry defaults rather than smelter- specific values for concentrations of minor anode components. CO2 emitted during electrolysis. We propose to require that CO2 emitted during electrolysis be calculated based on metal production and net anode consumption using a mass balance approach that assumes all carbon from net anode consumption is ultimately emitted as CO2. Since the concentrations of the non-carbon components are small (typically less than one percent to five percent), facility-specific data on them is not as critical to the precision of emission estimates as is facility-specific data on net anode consumption. Tier 3 improves the accuracy of the results but the improvement in accuracy is not expected to exceed 5 percent per the 2006 IPCC Guidelines. Although we do not propose to require the use of the Tier 3 approach, we would allow and encourage smelter operators to use facility-specific data on anode non-carbon components when that data were available. For prebake cells, CO2 emissions are equal to net prebaked anode consumption per metric ton aluminum times total metal production times the percent weight of sulfur and ash content in the baked anode times the molecular mass of CO2. CO2 emissions from S[oslash]derberg cells are a function of total metal production, paste consumption, emissions of cyclohexane soluble matter, percent binder and sulfur content in paste, percent ash and hydrogen content in pitch, percent weight of sulfur and ash content in calcined coke, carbon in skimmed dust from S[oslash]derberg cells, and the carbon atomic mass ratio. The data reported by companies participating in EPA's Voluntary Aluminum Industrial Partnership has generally not included smelter- specific values for each of these variables. However, most participants in the Voluntary Aluminum Industrial Partnership have used either data on paste consumption (for S[oslash]derberg cells) or on net anode consumption (for Prebake cells), along with some smelter-specific data on impurities, to develop a hybrid IPCC Tier 2/3 estimate (i.e., combination of smelter-specific and default factors). CO2 emitted during anode baking. We propose that CO2 emitted during anode baking be calculated based on a mass balance approach involving chemical contents of the anodes and packing materials. No anode baking emissions occur when using S[oslash]derberg cells, since these cells are not baked before aluminum smelting, but rather, bake in the electrolysis cell during smelting. CO2 emissions from pitch volatiles combustion equal the initial weight from green anode minus hydrogen content minus baked anode production minus waste tar collected times the molecular weight of CO2. CO2 emissions from bake furnace packing material are a function of packing coke consumption times baked anode production times the percent weight sulfur and ash content in packing coke. As is the case for CO2 emitted during electrolysis, the IPCC Tier 2 approach for anode baking relies on industry-wide defaults for minor anode components, requiring smelter-specific data only for the initial weight of green anodes and for baked anode production. The IPCC Tier 3 approach requires smelter-specific values for all parameters. Again, the concentrations of minor components are small, limiting their impact on the estimate of CO2 emissions from anode baking. In addition, anode baking emissions account for approximately 10 percent of total CO2 process emissions, so reducing the uncertainty in this estimate would have only a minor impact on the overall CO2 process estimate. For EPA's Voluntary Aluminum Industrial Partnership program, many smelters report only some smelter-specific values for the concentrations of minor anode components. In light of these considerations, we propose to require the Tier 2 method for estimating CO2 emissions from anode baking, with the option to use facility-specific data on impurity concentrations when that data is available. Other Options Considered. We are not proposing IPCC's Tier 1 methodology for calculating PFC emissions. Although this methodology is simple, the default emission factors for PFCs have large uncertainties due to the variability in anode effect frequency and duration. Since 1990, all U.S. smelters have sharply reduced their anode effect frequency and duration; through 2006, average anode minutes per cell day have declined by approximately 85 percent, lowering U.S. smelter emission rates well below those of the IPCC Tier 1 defaults. Consequently, as discussed above, the Tier 3 methodology has been proposed. For CO2, we are not proposing IPCC's Tier 1 methodology for calculating emissions. The difference in uncertainty between emission estimates developed using IPCC Tier 1 and Tier 2/3 approaches for U.S. smelters is notably lower than the difference for the PFC estimates. However, as part of typical operations, facilities regularly monitor inputs to higher Tier methods (e.g., consumption of anodes); consequently, the incremental cost to use the IPCC Tier 2 or a Tier 2/3 hybrid estimate are small. [[Page 16492]] 4. Selection of Procedures for Estimating Missing Data Where anode effect minutes per cell day data points are missing, the average anode effect minutes per cell day of the remaining measurements within the same reporting period may be applied. These parameters are typically logged by the process control system as part of the operations of nearly all aluminium production facilities and the uncertainties in these data are low. It is likely that aluminum production levels would be well known, since businesses rely on accurate monitoring and reporting of production levels. The 2006 IPCC Guidelines specify an uncertainty of less than 1 percent in the data for the annual production of aluminum. The likelihood for missing data is low. For CO2 emissions, the uncertainty in recording anode consumption as baked anode consumption or coke consumption is estimated to be only slightly higher than for aluminium production, less than 2 percent per the 2006 IPCC Guidelines. This is also an important parameter in smelter operations and is routinely/continuously monitored. Again, the likelihood for missing data is low. 5. Selection of Data Reporting Requirements In addition to annual GHG emissions data, facilities would be required to submit annual aluminum production and smelter technology used. The following PFC-specific information would also be required to be reported on an annual basis: Anode effect minutes per cell-day, and anode effect frequency and duration. Smelters would also be required to submit smelter-specific slope coefficient; the last date when smelter- specific slope coefficient was measured; certification that measurements of slope coefficients were conducted in accordance with the method identified in proposed 40 CFR part 98, subpart F; and the parameters used by the smelter to measure the frequency and duration of anode effects. The following CO2-specific information would be reported on an annual basis: Anode consumption for pre-bake cells, paste consumption for S[oslash]derberg cells, and smelter-specific inputs to the CO2 process equations (e.g., levels of impurities) that were used in the calculation. Exact data elements required would vary depending on smelter technology. These records consist of values that are used to calculate the emissions and are necessary to enable verification that the GHG emissions monitoring and calculations were done correctly. 6. Selection of Records That Must Be Retained In addition to the data reported, we propose that facilities maintain records on monthly production by smelter, anode effect minutes per cell-day or anode effect overvoltage by month, facility specific emission coefficient linked to anode effect performance, and net anode consumption for Prebake cells or paste consumption for S[oslash]derberg cells. These records consist of data that would be used to calculate the GHG emissions and are necessary to verify that the emissions monitoring and calculations are done correctly. G. Ammonia Manufacturing 1. Definition of the Source Category Ammonia is a major industrial chemical that is mainly used as fertilizer, directly applied as anhydrous ammonia, or further processed into urea, ammonium nitrates, ammonium phosphates, and other nitrogen compounds. Ammonia also is used to produce plastics, synthetic fibers and resins, and explosives. Ammonia can be produced through three processes: Steam reforming, solid fuel gasification, and brine electrolysis. The production of ammonia typically uses conventional steam reforming or solid fuel gasification and generates both combustion and process-related greenhouse gas emissions. The production of ammonia through the brine electrolysis process does not produce process GHG emissions, although it releases GHGs from combustion of fuels to support the electrolysis process. We have not identified any facilities in the U.S. producing ammonia through the brine electrolysis process. Catalytic steam reforming of ammonia generates process-related CO2, primarily through the use of natural gas as a feedstock. One plant located in Kansas is manufacturing ammonia from petroleum coke feedstock. This and other natural gas-based and petroleum coke-based feedstock processes produce CO2 and hydrogen, the latter of which is used in the manufacture of ammonia. Not all of the CO2 produced in the manufacture of ammonia is emitted directly to the atmosphere. Both ammonia and CO2 are used as raw materials in the production of urea (CO(NH2)2), which is another type of nitrogenous fertilizer that contains carbon (C) and nitrogen (N). The carbon from ammonia production that is used to manufacture urea is assumed to be released into the environment as CO2 during urea use. Therefore, the majority of CO2 emissions associated with urea consumption are those that result from its use as a fertilizer. For CO2 collected and used onsite or transferred offsite, you must follow the methodology provided in proposed 40 CFR part 98, subpart PP (Suppliers of CO2). Some facilities produce for sale a combination of ammonia, methanol, and hydrogen. We propose that facilities report their process-related GHG emissions in the source category corresponding to the primary NAICS code for the facility. For example, a facility that primarily produces ammonia but also produces methanol would report in the ammonia manufacturing source category. Since CO2 is used to produce methanol, it does not get emitted directly into the atmosphere. These facilities would account for the CO2 used to produce methanol through the methodology provided in proposed 40 CFR part 98, subpart G (Ammonia Manufacturing). National emissions from ammonia manufacturing were estimated to be 14.6 million metric tons CO2 equivalent (<0.25 percent of U.S. GHG emissions in 2006). These emissions include both process related CO2 emissions and on-site stationary combustion emissions (CO2, CH4, and N2O) from 24 manufacturing facilities across the U.S. Process-related emissions account for 7.6 million metric tons CO2, or 52 percent of the total, while on-site stationary combustion emissions account for the remaining 7.0 million metric tons CO2 equivalent emissions. For additional background information on ammonia manufacturing, please refer to the Ammonia Manufacturing TSD (EPA-HQ-OAR-2008-0508-007). 2. Selection of Reporting Threshold In developing the reporting threshold for ammonia manufacturing, we considered emissions-based thresholds of 1,000 metric tons CO2e, 10,000 metric tons CO2e, 25,000 metric tons CO2e and 100,000 metric tons CO2e. Table G-1 of this preamble illustrates the emissions and facilities that would be covered under these various thresholds. [[Page 16493]] Table G-1. Threshold Analysis for Ammonia Manufacturing ---------------------------------------------------------------------------------------------------------------- Emissions covered Facilities covered Total Total number ----------------------------------------------- Threshold level metric tons CO2e/yr national of Metric emissions facilities tons CO2e/ Percent Number Percent yr ---------------------------------------------------------------------------------------------------------------- 1,000............................... 14,543,007 24 14,543,007 100 24 100 10,000.............................. 14,543,007 24 14,543,007 100 24 100 5,000............................... 14,543,007 24 14,543,007 100 24 100 100,000............................. 14,543,007 24 14,449,519 99 22 92 ---------------------------------------------------------------------------------------------------------------- Facility-level emissions estimates based on known plant capacities suggest that all known facilities, except two, exceed the 100,000 metric tons CO2e threshold. Where information was available, emission estimates were adjusted to account for CO2 consumption during urea production, and this was taken into account in the threshold analysis. In order to simplify the proposed rule and avoid the need for the source to calculate and report whether the facility exceeds the threshold value, we propose that all ammonia manufacturing facilities are required to report. For a full discussion of the threshold analysis, please refer to the Ammonia Manufacturing TSD (EPA-HQ-OAR-2008-0508-007). For specific information on costs, including unamortized first year capital expenditures, please refer to section 4 of the RIA and the RIA cost appendix. 3. Selection of Proposed Monitoring Methods Many domestic and international monitoring guidelines and protocols include methodologies for estimating both combustion and process- related emissions from ammonia manufacturing (e.g., 2006 IPCC Guidelines, U.S. Inventory, DOE 1605(b), and TCR). These methodologies coalesce around the following four options which we considered for quantifying emissions from ammonia manufacture: Option 1. The first method found in existing protocols estimates emissions by applying a default emission factor to total ammonia produced. This approach estimates only process-related emissions. This approach is consistent with IPCC Tier 1 and DOE 1605(b) ``C'' rated estimation methods. Option 2. A second method consists of performing a mass balance calculation using default carbon content values for feedstock (from the U.S. DOE). Using default carbon content for fuel would not provide the same level of accuracy as using facility-specific carbon contents. This approach is consistent with IPCC Tier 2, DOE 1605(b) and TCR's ``B'' rated estimation methods. Option 3. The third option is based on the IPCC Tier 3 method for determining CO2 emissions from ammonia manufacture. This method calculates emissions based on the monthly measurements of the total feedstock consumed (quantity of natural gas or other feedstock) and the monthly carbon content of the feedstock. All carbon in the feedstock is assumed to be oxidized to CO2. The accuracy and certainty of this approach is directly related to the accuracy of the feedstock usage and the carbon content of the feedstock. If the measurements or readings are made and verified according to established QA/QC methods, the resulting emission calculations are as accurate as possible. For CO2 collected and used onsite or transferred offsite, you must follow the methodology provided in proposed 40 CFR part 98, subpart PP of this part (Suppliers of CO2). This approach is also consistent with DOE's 1605(b) ``A'' rated method and TCR's ``A2'' rated estimation methods. Option 4. The fourth option is using CEMS to directly measure CO2 emissions. While this method does tend to provide the most accurate emissions measurements, it is likely the costliest of all the monitoring methods. Proposed Option. Under the proposed rule, if you are required to use an existing CEMS to meet the requirements outlined in proposed 40 CFR part 98, subpart C and the CEMS capture all combustion- and process-related CO2 emissions you would be required to follow requirements of proposed 40 CFR part 98, subpart C to estimate CO2 emissions from the industrial source. For facilities that do not currently have CEMS that meet the requirements outlined in proposed 40 CFR part 98, subpart C, or where the CEMS does not measure CO2 process emissions, the proposed monitoring method is Option 3. You would be required to follow the requirements of proposed 40 CFR part 98, subpart C to estimate CO2, CH4 and N2O emissions from stationary combustion. The proposed monitoring method is Option 3. Options 3 and 4 provide the most accurate estimates from site-specific conditions. Option 3 is consistent with current feedstock monitoring practices at facilities within this industry, thereby minimizing costs. For CO2 collected and used onsite or transferred offsite, you must follow the methodology provided in proposed 40 CFR part 98, subpart PP (Suppliers of CO2). In general, we decided against existing methodologies that relied on default emission factors or default values for carbon content of materials because the differences among facilities could not be discerned, and such default approaches are inherently inaccurate for site-specific determinations. The use of default values is more appropriate for sector-wide or national total estimates from aggregated activity data than for determining emissions from a specific facility. The various approaches to monitoring GHG emissions are elaborated in the Ammonia Manufacturing TSD (EPA-HQ-OAR-2008-0508-007). 4. Selection of Procedures for Estimating Missing Data The proposed rule requires the use of substitute data whenever a quality-assured value of a parameter that is used to calculate GHG emissions is unavailable, or ``missing.'' For missing feedstock supply rates, use the lesser of the maximum supply rate that the unit is capable of processing or the maximum supply rate that the meter can measure. There are no missing data procedures for carbon content. A re- test must be performed if the data from any monthly measurements are determined to be invalid. 5. Selection of Data Reporting Requirements We propose that facilities that estimate their process CO2 emissions under proposed 40 CFR part 98, subpart G, submit their process CO2 emissions data and the following additional data on an annual basis. These data are the basis for calculations and are needed for us to understand the emissions data and verify the reasonableness of the reported emissions. We propose facilities submit [[Page 16494]] the following data on an annual basis for each process unit: The total quantity of feedstock consumed for ammonia manufacturing, the monthly analyses of carbon content for each feedstock used in ammonia manufacturing. A full list of data to be reported is included in proposed 40 CFR part 98, subparts A and G. 6. Selection of Records That Must Be Retained We propose that each ammonia manufacturing facility maintain records of monthly carbon content analyses, and the method used to determine the quantity of feedstock used. These records consist of values that are directly used to calculate the emissions that are reported and are necessary to enable verification that the GHG emissions monitoring and calculations were done correctly. H. Cement Production 1. Definition of the Source Category Hydraulic Portland cement, the primary product of the cement industry, is a fine gray or white powder produced by heating a mixture of limestone, clay, and other ingredients at high temperature. Limestone is the single largest ingredient required in the cement- making process, and most cement plants are located near large limestone deposits. CO2 from the chemical process of cement production is the second largest source of industrial CO2 emissions in the U.S. During the cement production process, calcium carbonate (CaCO3) (usually from limestone and chalk) is combined with silica-containing materials (such as sand and shale) and is heated in a cement kiln at a temperature of about 1,450 [deg]C (2,400 [deg]F). The CaCO3 forms calcium oxide (or CaO) and CO2 in a process known as calcination or calcining. Very small amounts of carbonates other than CaCO3, such as magnesium carbonates and non-carbonate organic carbon may also be present in the raw materials, both of which contribute to generation of additional CO2. The product from the cement kiln is clinker, an intermediate product, and the CO2 generated as a by-product. The CO2 is released to the atmosphere. Additional CO2 emissions are generated with the formation of partially calcinated cement kiln dust. During clinker production, some of the clinker precursor materials (instead of forming clinker) are entrained in the flue gases exiting the kiln as non-calcinated, partially calcinated, or fully calcinated cement kiln dust \67\. Cement Kiln Dust is collected from the flue gas in dust collection equipment and can either be recycled back to the kiln or be sent offsite for disposal, depending on its quality. Organic carbon in raw materials is also emitted as CO2 as raw material is heated. --------------------------------------------------------------------------- \67\ Cement Production TSD (EPA-HQ-OAR-2008-0508-008). --------------------------------------------------------------------------- National GHG emissions from cement production were estimated to be 86.83 million metric tons CO2e in 2006. These emissions include both process-related emissions (CO2) and on-site stationary combustion emissions (CO2, CH4, and N2O) from 107 cement production facilities. Process-related emissions account for over half of emissions (45.7 million metric tons CO2), while on-site stationary combustion emissions account for the remaining 41.1 million metric tons CO2e emissions. For additional background information on cement production, please refer to the Cement Production TSD (EPA-HQ-OAR-2008-0508-008). 2. Selection of Reporting Threshold In developing the threshold for cement manufacturing, we considered emissions-based thresholds of 1,000 metric tons CO2e, 10,000 metric tons CO2e, 25,000 metric tons CO2e, and 100,000 metric tons CO2e. Table H-1 of this preamble illustrates the emissions and facilities that would be covered under these thresholds. Table H-1. Threshold Analysis for Cement Manufacturing ---------------------------------------------------------------------------------------------------------------- Emissions Covered Facilities Covered Total --------------------------------------------------- Threshold level metric tons national Total number Million CO2e/yr emissions of facilities metric tons Percent Number Percent (MMTCO2e) CO2e/yr ---------------------------------------------------------------------------------------------------------------- 1,000.......................... 86.83 107 86.83 100 107 100 10,000......................... 86.83 107 86.83 100 107 100 25,000......................... 86.83 107 86.83 100 107 100 100,000........................ 86.83 107 86.74 99.9 106 99.9 ---------------------------------------------------------------------------------------------------------------- All emissions thresholds examined covered over 99.9 percent of CO2e emissions from cement facilities. Only one plant out of 107 in the dataset would be excluded by a 100,000 metric tons CO2e threshold. All facilities would be included under a 25,000 metric tons CO2e threshold. Therefore, EPA is proposing that all cement production facilities are required to report. Having no threshold covers all of the cement production process emissions without increasing the number of facilities that must report and simplifies the rule. For a full discussion of the threshold analysis, please refer to the Cement Production TSD (EPA-HQ-OAR-2008-0508-008). For specific information on costs, including unamortized first year capital expenditures, please refer to section 4 of the RIA and the RIA cost appendix. 3. Selection of Proposed Monitoring Methods Many domestic and international GHG monitoring guidelines and protocols include methodologies for estimating process-related emissions from cement manufacturing (e.g., the 2006 IPCC Guidelines, U.S. Inventory, DOE 1605(b), CARB mandatory GHG emissions reporting program, EPA's Climate Leaders, the EU Emissions Trading System, and the Cement Sustainability Initiative Protocol). These [[Page 16495]] methodologies coalesce around four different options. Option 1. Apply a default emission factor to the total quantity of clinker produced at the facility. The quantity of clinker produced could be directly measured, or a clinker fraction could be applied to the total quantity of cement produced. Option 2. Apply site-specific emission factors to the quantity of clinker produced. Option 3. Measure the carbonate inputs to the furnace. Under this ``kiln input'' approach, emissions are calculated by weighing the mass of individual carbonate species sent to the kiln, multiplying by the emissions factor (relating CO2 emissions to carbonate content in the kiln feed), and subtracting for uncalcined cement kiln dust. Option 4. Direct measurement of emissions using CEMS. Proposed Option. Based on the agency's review of the above approaches, we propose two different methods for quantifying GHG emissions from cement manufacturing, depending on current emissions monitoring at the facility. CEMS Method. Under the proposed rule, if you are required to use an existing CEMS to meet the requirements outlined in proposed 40 CFR part 98, subpart C, you would be required to use CEMS to estimate CO2 emissions. Where the CEMS capture all combustion- and process-related CO2 emissions you would be required to follow the requirements of proposed 40 CFR part 98, subpart C to estimate all CO2 emissions from the industrial source. Also, refer to proposed 40 CFR part 98, subpart C (discussed in Section V.C of this preamble) to estimate combustion- related CH4 and N2O. Calculation Method (Option 2). For facilities that do not currently have CEMS that meet the requirements outlined in proposed 40 CFR part 98, subpart C, or where the CEMS would not adequately account for process emissions, we propose that these facilities calculate emissions following Option 2 outlined below. You would be required to follow the requirements of proposed 40 CFR part 98, subpart C to estimate emissions of CO2, CH4 and N2O from stationary combustion. The cement production section provides only those procedures for calculating and reporting process-related emissions. Under Option 2, we propose that facilities develop facility- specific emission factors relating CO2 emissions to clinker production for each individual kiln. The emission factor relating CO2 emissions to clinker production would be based on the percent of measured carbonate content in the clinker (measured on a monthly basis) and the fraction of calcination achieved. The clinker emission factor is then multiplied by the monthly clinker production to estimate monthly process-related CO2 emissions from cement production. Annual emissions are calculated by summing CO2 emissions over 12 months across all kilns at the facility. Most current protocols propose this method, but allow facilities to apply a national default emission factor. We propose the development of a facility-specific emission factor based on the understanding that facilities analyze the carbonate contents of their raw materials to the kiln on a frequent basis, either on a daily basis or every time there is a change in the raw material mix. Cement Kiln Dust. The CO2 emissions attributable to calcined material in the cement kiln dust not recycled back to the kiln must be added to the estimate of CO2 emissions from clinker production. To establish a cement kiln dust adjustment factor, we propose that facilities conduct a chemical analysis on a quarterly basis to estimate the plant-specific fraction of uncalcined carbonate in the cement kiln dust from each kiln, that is not recycled to the kiln each quarter. Again, this method provides reasonable accuracy and is highly consistent with the prevailing methods presented in existing protocols. TOC Content in Raw Materials. The CO2 emissions attributable to the TOC content in raw material must be added to the estimate of CO2 emissions from clinker production and cement kiln dust. We propose that facilities conduct an annual chemical analysis to determine the organic content of the raw material on an annual basis. The emissions are calculated from the TOC content by multiplying the organic content by the amount of raw material consumed annually. Other Options Considered. We considered three alternative options to estimate process-related emissions from cement production. The first method considered was to apply default emission factors to clinker production (either based on measurement of clinker, or by applying a clinker fraction to cement production). Applying default emission factors to clinker production is one of the most common approaches in existing protocols. However, we have determined that applying default emission factors to clinker production is more appropriate for national-level emissions estimates than facility-specific estimates, where data are readily available to develop site-specific emission factors. In some protocols, this method requires correcting for purchases and sales of clinker, such that a facility is only accounting for emissions from the clinker that is manufactured on site. This approach provides better emissions data than protocols where the method does not correct for clinker purchases and sales. In some protocols, the method requires reporters to start with cement production, estimate the clinker fraction, and then estimate the carbonate input used to produce the clinker. Conceptually, this might not be any different than the kiln input approach as the facility would ultimately have to identify and quantify the carbonate inputs to the kiln. The kiln input approach was considered, but not proposed, because it would not lead to significantly reduced uncertainty in the emissions estimate over the clinker based approach, where a site-specific emission factor is developed using periodic sampling of the carbonate mix into the kiln. The primary difference is the proposed clinker-based approach requires a monthly analysis of the degree of calcination achieved in the clinker in order to develop the facility-specific emissions factor, whereas the kiln input approach would require monthly monitoring of the inputs and outputs of the kiln. We concluded that although the kiln input does not improve certainty estimates significantly, it could potentially be more costly depending on the carbonate input sampling frequency. Early domestic and international guidance documents for estimating process CO2 emissions from cement production offered the option of applying a default emission factor to cement production (e.g. IPCC Tier 1, DOE 1605(b) ``C'' rated approach). This is no longer considered an acceptable method in national inventories therefore we did not consider it further for developing a mandatory GHG reporting rule. The various approaches to monitoring GHG emissions are elaborated in the Cement Production TSD (EPA-HQ-OAR-2008-0508-008). 4. Selection of Procedures for Estimating Missing Data For facilities with CEMs, we propose that facilities follow the missing data procedures in proposed 40 CFR part 98, subpart C, which are also discussed in Section V.C of this preamble. For facilities without CEMs, we propose that no missing data procedures would apply because the emission [[Page 16496]] factors used to estimate CO2 emissions from clinker and cement kiln dust production are derived from routine tests of carbonate contents. In the event data on carbonate content analysis is missing we propose that the facility undertake a new analysis of carbonate contents. We are not proposing any missing data allowance for clinker and cement kiln dust production data. The likelihood for missing input, clinker and cement kiln dust production data is low, as businesses closely track their purchase of production inputs, quantity of clinker produced, and quantity of cement kiln dust discarded. 5. Selection of Data Reporting Requirements We propose that facilities submit annual CO2 emissions from cement production, as well as any stationary fuel combustion emissions. In addition, facilities using CEMS would be required to follow the data reporting requirements in proposed 40 CFR part 98, subpart C. Facilities using the clinker-based approach would be required to report annual clinker production, annual cement kiln dust production, number of kilns, site-specific clinker emission factor, the total annual fraction of cement kiln dust recycled to the kiln, and the quantity of CO2 captured for use and the end use, if known. In addition, we propose that facilities submit their annual analysis of carbonate composition, the total annual fraction of calcination achieved (for each carbonate), organic carbon content of the raw material, and the amount of raw material consumed annually. These data, used as the basis of the calculations, are needed for EPA to understand the emissions data and verify reasonableness of the reported emissions. A full list of data to be reported is included in proposed 40 CFR part 98, subparts A and H. 6. Selection of Records That Must Be Retained In addition to the data reported, we propose that facilities using the clinker-based approach to calculate emissions keep records of monthly carbonate consumption, monthly cement production, monthly clinker production, results from monthly chemical analysis of carbonates, documentation of calculated site specific clinker emission factor, quarterly cement kiln dust production, total annual fraction calcination achieved, organic carbon content of the raw material, and the amount of raw material consumed annually. These records include values directly used to calculate the reported emissions; and these records are necessary to verify the estimated GHG emissions. A full list of records that must be retained onsite is included in proposed 40 CFR part 98, subparts A and H. I. Electronics Manufacturing 1. Definition of the Source Category The electronics industry uses multiple long-lived fluorinated GHGs such as PFCs, HFCs, SF6, and NF3 during manufacturing of semiconductors, liquid crystal displays (LCDs), microelectrical mechanical systems (MEMs), and photovoltaic cells (PV). We are also seeking comment below on the inclusion of light-emitting diodes (LEDs), disk readers and other products as part of the electronics manufacturing source category. The fluorinated gases (at room temperature) are used for plasma etching of silicon materials and cleaning deposition tool chambers. Additionally, semiconductor manufacturing employs fluorinated GHGs (typically liquids at room temperature) as heat transfer fluids. The most common fluorinated GHGs in use are HFC-23, CF4, C2F6, NF3 and SF6, although other compounds such as perfluoropropane (C3F8) and perfluorocyclobutane (c-C4F8) are also used (EPA, 2008a). Electronics manufacturers may also use N2O as the oxygen source for chemical vapor deposition of silicon oxynitride or silicon dioxide. Besides dielectric film etching and chamber cleaning, much smaller quantities of fluorinated gases are used to etch polysilicon films and refractory metal films like tungsten. Table I-1 of this preamble presents the fluorinated GHGs typically used during manufacture of each of these electronics devices. Table I-1. Fluorinated GHGs Used by the Electronics Industry ------------------------------------------------------------------------ Fluorinated GHGs used during Product type manufacture ------------------------------------------------------------------------ Electronics (e.g., Semiconductor, CF4, C2F6, C3F8, c-C4F8, c-C4F8O, MEMS, LCD, PV). C4F6, C5F8, CHF3, CH2F2, NF3, SF6, and Heat Transfer Fluids (CF3-(O-CF(CF3)-CF2)n-(O-CF2)m-O -CF3, CnF2n+2, CnF2n+1(O) CmF2m+1, CnF2nO, (CnF2n+1)3N)a. ------------------------------------------------------------------------ a IPCC Guidelines do not specify the fluorinated GHGs used by the MEMs industry. Literature reviews revealed that CF4, SF6, and the Bosch process (consisting of alternating steps of SF6 and c-C4F8) are used to manufacture MEMs. For further information, see the Electronics Manufacturing TSD (EPA-HQ-OAR-2008-0508-009). The etching process uses plasma-generated fluorine atoms, which chemically react with exposed dielectric film to selectively remove the desired portions of the film. The material removed as well as undissociated fluorinated gases flow into waste streams and, unless emission control systems are employed, into the atmosphere. Chambers used for depositing dielectric films are cleaned periodically using fluorinated and other gases. During the cleaning cycle the gas is converted to fluorine atoms in plasma, which etches away residual material from chamber walls, electrodes, and chamber hardware. Undissociated fluorinated gases and other products pass from the chamber to waste streams and, unless emission control systems are employed, into the atmosphere. In addition to emissions of unreacted gases, some fluorinated compounds can also be transformed in the plasma processes into different fluorinated GHGs which are then exhausted, unless abated, into the atmosphere. For example, when C2F6 is used in cleaning or etching, CF4 is generated and emitted as a process by-product. Fluorinated GHG liquids (at room temperature) such as fully fluorinated linear, branched or cyclic alkanes, ethers, tertiary amines and aminoethers, and mixtures thereof are used as heat transfer fluids at several semiconductor facilities to cool process equipment, control temperature during device testing, and solder semiconductor devices to circuit boards. The fluorinated heat transfer fluid's high vapor pressures can lead to evaporative losses during use.\68\ We are seeking comment on the extent of use and [[Continued on page 16497]] From the Federal Register Online via GPO Access [wais.access.gpo.gov]] [[pp. 16497-16546]] Mandatory Reporting of Greenhouse Gases [[Continued from page 16496]] [[Page 16497]] annual replacement quantities of fluorinated liquids as heat transfer fluids in other electronics sectors, such as their use for cooling or cleaning during LCD manufacture. --------------------------------------------------------------------------- \68\ Electronics Manufacturing TSD (EPA-HQ-OAR-2008-0508-009); 2006 IPCC Guidelines. --------------------------------------------------------------------------- Total U.S. Emissions. Emissions of fluorinated GHGs from an estimated 216 electronics facilities were estimated to be 6.1 million metric tons CO2e in 2006. Below is a breakdown of emissions by electronics product type. Semiconductors. Emissions of fluorinated GHGs, including heat transfer fluids, from 175 semiconductor facilities were estimated to be 5.9 million metric tons CO2e in 2006. Of the total estimated semiconductor emissions, 5.4 million metric tons CO2e are from etching/chamber cleaning and 0.5 million metric tons CO2e are from heat transfer fluid usage. Partners of the PFC Reduction/Climate Partnership for Semiconductors comprise approximately 80 percent of U.S. semiconductor production capacity. These partners have committed to reduce their emissions (exclusive of heat transfer fluid emissions) to 10 percent below their 1995 levels by 2010, and their emissions have been on a general decline toward attainment of this goal since 1999. MEMs. Emissions of fluorinated GHGs from 12 facilities were estimated to be 0.03 million metric tons CO2e in 2006. LCDs. Emissions of fluorinated GHGs from 9 facilities were estimated to be 0.02 million metric tons CO2e in 2006. PVs. Emissions of fluorinated GHGs from 20 PV facilities were estimated to be 0.07 million metric tons CO2e in 2006. We request comment on the number and capacity of thin film (i.e., amorphous silicon) and other PV manufacturing facilities in the U.S. using fluorinated GHGs. Emissions To Be Reported. This section details our proposed requirements for reporting fluorinated GHG and N2O emissions from the following processes and activities: (1) Plasma etching; (2) Chamber cleaning; (3) Chemical vapor deposition using N2O as the oxygen source; and (4) Heat transfer fluid use. Our understanding is that only semiconductor facilities use heat transfer fluids; we request comment on this assumption. For additional background information on the electronics industry, refer to the Electronics Manufacturing TSD (EPA-HQ-OAR-2008-0508-009). 2. Selection of Reporting Threshold For manufacture of semiconductors, LCDs, and MEMs, we are proposing capacity-based thresholds equivalent to an annual emissions threshold of 25,000 metric tons CO2e. For manufacture of PVs for which we have less information on use and emissions of fluorinated GHGs, we are proposing an emissions threshold of 25,000 metric tons of CO2e. We are seeking comment on the inclusion of LEDs, disk readers and other products in the electronics manufacturing source category. Given that the manufacturing process for these devices is similar to other electronics, we are specifically interested in seeking feedback on the level of emissions from their manufacturer and whether subjecting these products to an emissions threshold of 25,000 metric ton CO2e would be appropriate. In our analysis, we considered emission thresholds of 1,000 metric tons CO2e, 10,000 metric tons CO2e, 25,000 metric tons CO2e, and 100,000 metric tons CO2e per year. Table I-2 of this preamble shows emissions and facilities that would be captured by the respective emissions thresholds. Table I-2. Threshold Analysis for Electronics Industry -------------------------------------------------------------------------------------------------------------------------------------------------------- Emissions covered Facilities covered Total national Total number ---------------------------------------------------------------- Emission threshold level metric tons CO2e/yr emissions of facilities Metric tons CO2e/yr Percent Facilities Percent -------------------------------------------------------------------------------------------------------------------------------------------------------- 1,000.................................................. 5,984,462 216 5,972,909 99.8 173 80 10,000................................................. 5,984,462 216 5,840,411 98 118 55 25,000................................................. 5,984,462 216 5,708,283 95 96 44 100,000................................................ 5,984,462 216 4,708,283 79 54 25 -------------------------------------------------------------------------------------------------------------------------------------------------------- We selected the 25,000 metric tons CO2e per year threshold because this threshold maximizes emissions reporting, while excluding small facilities that do not contribute significantly to the overall GHG emissions. We propose to use a production-based threshold based on the rated capacities of facilities, as opposed to an emissions-based threshold, where possible, because it simplifies the applicability determination. Therefore, we derived production capacity thresholds that are approximately equivalent to metric tons CO2e using IPCC Tier 1 default emissions factors and assuming 100 percent capacity utilization. Where IPCC Tier 1 default factors were unavailable (i.e., MEMs), the emissions factor was estimated based on those of semiconductors for the relevant fluorinated GHGs. The proposed capacity-based thresholds are 1,000 m2 silicon for semiconductors; 4,000 m2 silicon for MEMs; and 236,000 m2 LCD for LCDs. Table I-3 of this preamble shows the estimated emissions and number of facilities that would report for each source under the proposed capacity-based thresholds. PV is not shown in the table because we are proposing an emissions threshold due to lack of information. Table I-3. Summary of Rule Applicability Under the Proposed Capacity-Based Thresholds -------------------------------------------------------------------------------------------------------------------------------------------------------- Total Emissions covered Facilities covered Capacity-based Total national emissions of --------------------------------------------------------------- Emissions source threshold facilities source (metric Metric tons tons CO2e) CO2e/yr Percent Facilities Percent -------------------------------------------------------------------------------------------------------------------------------------------------------- Semi-conductors................... 1,080 silicon m2.... 175 5,741,676 5,492,066 96 91 52 MEMs.............................. 1,020 silicon m2.... 12 146,115 96,164 66 2 17 LCD............................... 235,700 LCD m2...... 9 23,632 0 0 0 0 -------------------------------------------------------------------------------------------------------------------------------------------------------- [[Page 16498]] The proposed capacity-based thresholds are estimated to cover about 50 percent of semiconductor facilities and between 0 percent and 20 percent of the facilities manufacturing MEMs and LCDs. At the same time, the thresholds are expected to cover nearly 96 percent of fluorinated GHG emissions from semiconductor facilities, and 0 percent and 66 percent of fluorinated GHG emissions from facilities manufacturing LCDs and MEMs, respectively. Combined these emissions are estimated to account for close to 94 percent of fluorinated GHG emissions from electronics as a whole. We are proposing capacity-based thresholds for the electronics industry, where possible, because electronics manufacturers may employ emissions control equipment (e.g., thermal oxidizers, fluorinated GHG capture recycle systems) to lower their fluorinated GHG emissions. In addition, capacity-based thresholds would permit facilities to quickly determine whether or not they must report under this rule. When abatement equipment is used, electronics manufacturers often estimate their emissions using the manufacturer-published DRE for the equipment. However, abatement equipment may fail to achieve its rated DRE either because it is not being properly operated and maintained or because the DRE itself was incorrectly measured due to a failure to account for the effects of dilution. (For example, CF4 can be off by as much as a factor of 20 to 50 and C2F6 can be off by a factor of up to 10 because of failure to properly account for dilution.) In either event, the actual emissions from facilities employing abatement equipment may exceed estimates based on the rated DREs of this equipment and may therefore exceed the 25,000 metric tons CO2e threshold without the knowledge of the facility operators. Measuring and reporting emission control device performance is therefore important for developing an accurate estimate of emissions. As discussed below, we propose an emission estimation method that would account for destruction by abatement equipment only if facilities verified the performance of their abatement equipment using one of two methods. If facilities choose not to verify the performance of their abatement equipment, the estimation method would not account for any destruction by the abatement device. For additional background information on the threshold analysis, refer to the Electronics Manufacturing TSD (EPA-HQ-OAR-2008-0508-009). For specific information on costs, including unamortized first year capital expenditures, please refer to section 4 of the RIA and the RIA cost appendix. 3. Selection of Proposed Monitoring Methods a. Etching and Cleaning Emissions Fluorinated GHG Emissions. Under the proposed rule, large semiconductor facilities (defined as facilities with annual capacities of greater than 10,500 m\2\ silicon) would be required to estimate their fluorinated GHG emissions from etching and cleaning using an approach based on the IPCC Tier 3 method, and all other facilities would be required to use an approach based on the IPCC Tier 2b method. We have determined that large semiconductor facilities are already using Tier 3 methods and/or have the necessary data readily available either in-house or from suppliers to apply the highest tier method. The difference between the proposed approaches and the IPCC methods is that the proposed approaches include stricter requirements for quantifying the gas destroyed by abatement equipment, as described below. None of the IPCC methods require a standard protocol to estimate DREs of abatement equipment. Given that the actual DRE of the abatement equipment can be significantly smaller (by up to a factor of 50) compared to the manufacturer rated DRE, we are proposing verification of the DREs using a standard reporting protocol (Burton, 2007). Under the proposed rule, we estimate that 17 percent of all semiconductor manufacturing facilities would be required to report using an IPCC Tier 3 approach (equivalent to 29 facilities out of 175 total facilities) and that 56 percent of total semiconductor emissions (equivalent 3.4 million metric tons CO2e out of a total 5.9 million metric tons CO2e emissions) would be reported using the IPCC Tier 3 approach. Method for Large Facilities. The IPCC Tier 3 approach uses company- specific data on (1) gas consumption, (2) gas utilization, (3) by- product formation, and (4) DRE for all emission abatement processes at the facility. Information on gas consumption by process is often gathered as business as usual,\69\ and information on gas utilization, by-product formation, and DRE for each process is readily available from tool manufacturers and can also be experimentally measured on-site at the facility. We propose that the DRE for abatement equipment be experimentally measured using the protocol described below. --------------------------------------------------------------------------- \69\ In the RIA for this rulemaking, we have conservatively included the costs of gathering, consolidating, and checking process-specific gas consumption information. However, we believe that this information is already gathered in many cases for purposes of internal process control and/or emissions reporting under EPA's voluntary PFC Reduction Program for the Semiconductor Industry. --------------------------------------------------------------------------- The guidance prepared by International SEMATECH Technology Transfer #0612485A-ENG (December 2006) must be followed when preparing gas utilization and by-product formation measurements. We have determined that electronics manufacturers commonly track fluorinated GHG consumption using flow metering systems calibrated to ±1 percent or better accuracy. Thus the equation for estimating emissions does not account for cylinder heels. However, a facility may choose to estimate consumption by weighing fluorinated GHG cylinders when placed into and taken out of service, as is common practice by the magnesium industry. The use of the IPCC Tier 3 method and standard site-specific DRE measurement would provide the most certain and practical emission estimates for large facilities. The uncertainty associated with an IPCC Tier 3 approach is lower than any of the other IPCC approaches, and is on the order of ±30 percent at the 95 percent confidence interval. We estimate that the Tier 3 approach would not impose a significant burden on facilities because large semiconductor facilities are already using Tier 3 methods and/or have the necessary data to do so readily available, as noted above. Method for Other Semiconductor, LCD, MEMS, and PV Facilities. The IPCC Tier 2b approach is based on gas consumption by process type (i.e., etch or chamber clean) multiplied by default factors for utilization, by-product formation, and destruction. We are proposing that site-specific DRE measurements be used for quantifying the amount of gas destroyed. The DRE measurements would be determined using the protocol described below. The Tier 2b approach does not account for variation among individual processes or tools and, therefore, the estimated emissions have an uncertainty about twice as high as that of IPCC Tier 3 estimates. However, we have concluded that the IPCC Tier 3 method would be unduly burdensome to the estimated 146 facilities with annual production less than 10,500 m\2\ silicon. We estimate that the IPCC Tier 2b approach would not impose a significant burden on facilities because it requires only minimal fluorinated gas usage tracking by major production process type. These production input [[Page 16499]] data are readily available at all U.S. manufacturing facilities. N2O Emissions. We are proposing that electronics manufacturers use a simple mass-balance approach to estimate emissions of N2O during etching and chamber cleaning. This methodology assumes N2O is not converted or destroyed during etching or chamber cleaning, due to lack of N2O utilization data. We request comment on utilization factors for N2O during etching and chamber cleaning, and any data on N2O by-product formation. Verification of DRE. For facilities that employ abatement devices and wish to reflect the emission reductions due to these devices in their emissions estimates, two methods are proposed for verifying the DRE of the equipment. Either method may be followed. The first method would require facilities (or their equipment suppliers) to test the DRE of the equipment using an industry standard protocol, such as the one under development by EPA as part of the PFC Reduction/Climate Partnership for Semiconductors (not yet published). This draft protocol requires facilities to experimentally determine the effective dilution through the abatement device and to measure abatement DRE during actual or simulated process conditions. The second method would require facilities to buy equipment that has been tested by an independent third party (e.g., UL) using an industry standard protocol such as the one under development by EPA. Under this approach, manufacturers would pay the third party to select random samples of each model and test them. Because testing would not need to be obtained for every piece of equipment sold, this approach would probably be less expensive than in-house testing by electronics manufacturers, but it may not capture the full range of conditions under which the abatement equipment would actually be used. We believe that the proposed DRE measurement method is generally robust, but we are requesting comment on one aspect of that method. We are concerned that the DREs measured and calculated for CF4 may vary depending on the mix of input gases used in the electronics manufacturing process. The calculated DRE for CF4 may be influenced by the formation of CF4 from other PFCs during the destruction process itself, and different input gases have different CF4 byproduct formation rates. This means that a DRE for CF4 calculated using one set of input gases might over- or under-estimate CF4 emissions when applied to another set of input gases (or even the original set in different proportions). We request comment on the likelihood and potential severity of such errors and on how they might be avoided. Facilities pursuing either DRE verification method would also be required to use the equipment within the manufacturer's specified equipment lifetime, operate the equipment within manufacturer specified limits for the gas mix and exhaust flow rate intended for fluorinated GHG destruction, and maintain the equipment according to the manufacturer's guidelines. We request comment on these proposed requirements. b. Emissions of Heat Transfer Fluids We propose that electronics manufacturers use the IPCC Tier 2 approach, which is a mass-balance approach, to estimate the emissions of each fluorinated heat transfer fluid. The IPCC Tier 2 approach uses company-specific data and accounts for differences among facilities' heat transfer fluids (which vary in their GWPs), leak rates, and service practices. It has an uncertainty on the order of ±20 percent at the 95 percent confidence interval according to the 2006 IPCC Guidelines. The Tier 2 approach is preferable to the IPCC Tier 1 approach, which relies on a default emissions factor to estimate heat transfer fluid emissions and has relatively high uncertainty compared to the Tier 2 approach. c. Review of Existing Reporting Programs and Methodologies We reviewed the PFC Reduction/Climate Partnership for the Semiconductor Industry, U.S. GHG Inventory, 1605(b), EPA Climate Leaders, WRI, TRI, and the World Semiconductor Council methods for estimating etching and cleaning emissions. All of the methods draw from both the 2000 and 2006 IPCC Guidelines. Etching and Cleaning. For etching and cleaning emissions, we considered the 2006 IPCC Tier 1 and Tier 2a methods, as well as a Tier 2b/3 hybrid which would apply Tier 3 to the most heavily used fluorinated GHGs in all facilities. The Tier 1 approach is based on the surface area of substrate (e.g., silicon, LCD or PV-cell) produced during manufacture multiplied by a default gas-specific emission factor. The advantages of the Tier 1 approach lie in its simplicity. However, this method does not account for the differences among process types (i.e., etching versus cleaning), individual processes, or tools, leading to uncertainties in the default emission factors of up to 200 percent at the 95 percent confidence interval.\70\ Facilities routinely monitor gas consumption as part of business as usual, making it technically feasible to employ a method of at least IPCC Tier 2a complexity or higher without additional data collection efforts. --------------------------------------------------------------------------- \70\ This uncertainty refers only to semiconductors and LCDs. Tier 1 emission factor uncertainty for PV was not estimated in the 2006 IPCC Guidelines. --------------------------------------------------------------------------- The Tier 2a approach is based on the gas consumption multiplied by default factors for utilization, by-product formation, and destruction. The Tier 2a approach is relatively simple, given that gas consumption data is collected as part of business as usual. However, due to variation in gas utilization between etching and cleaning processes, the estimated emissions using Tier 2a have greater uncertainty than Tier 2b estimated emissions. Tier 2b/3 hybrid approach involves requiring Tier 3 reporting for all facilities, but only for the top three gases emitted at each facility. For all other gases, the Tier 2b approach would be required. The top three gases emitted, based on data in the Inventory of U.S. GHG Emissions and Sinks, are C2F6, CF4, and SF6 (EPA, 2008a). These top three gases accounted for approximately 80 percent of total fluorinated GHG emissions from semiconductor manufacturing during etching and chamber cleaning in 2006. The uncertainty associated with the Tier 2b/3 hybrid approach has not been determined, but is estimated to be between the uncertainty for a Tier 2b and Tier 3 approach. We did not select the Tier 1 and Tier 2a methods due to the greater uncertainty inherent in these approaches. Although the Tier 2b/3 hybrid approach would provide more accurate emissions estimates for small facilities, we concluded that the Tier 2b method with site-specific DRE measurements would provide sufficient accuracy without the additional monitoring and recordkeeping requirements of the Tier 3 method. We propose collecting emissions data from MEMS manufacturers meeting the threshold criterion although no IPCC default emission factors exist for MEMs and the IPCC emission factors for semiconductor and LCD manufacturing may not be reliable for MEMs. Therefore, we are seeking information on emissions and emission factors for both MEMs and LCD manufacturing. Heat Transfer Fluids. For heat transfer fluid emissions, we reviewed both the IPCC Tier 1 and IPCC Tier 2 approaches. The Tier 1 approach for heat transfer fluid emissions is based on the [[Page 16500]] utilization capacity of the semiconductor facility multiplied by a default emission factor. Although the Tier 1 approach has the advantages of simplicity, it is less accurate than the Tier 2 approach according to the 2006 IPCC Guidelines. 4. Selection of Procedures for Estimating Missing Data Where facility-specific process gas utilization rates and by- product gas formation rates are missing, facilities can estimate etching/cleaning emissions by applying defaults from the next lower Tier (e.g., IPCC Tier 2b or Tier 2a) to estimate missing data. However, facilities must limit their use of defaults from the next lower Tier to less than 5 percent of their emissions estimate. Default values for estimating DRE would not be permitted. DRE values must be estimated as zero in the absence of facility-specific DREs that have been measured using a standard protocol. Gas consumption is collected as business as usual and is not expected to be missing; therefore, it would not be permitted to revert to the Tier 1 approach for estimating emissions. When estimating heat transfer fluid emissions during semiconductor manufacture, the use of the mass-balance approach requires correct records for all inputs. Should the facility be missing records for a given input, it may be possible that the heat transfer fluid supplier has information in their records for the facility. 5. Selection of Data Reporting Requirements Owners and operators would be required to report GHG emissions for the facility, for all plasma etching processes, all chamber cleaning, all chemical vapor deposition processes, and all heat tranfer fluid use. Along with their emissions, facilities would be required to report the following: Method used (i.e., 2b or 3), mass of each gas fed into each process type, production capacity in terms of substrate surface area (e.g., silicon, PV-cell, LCD), factors used for gas utilization, by-product formation and their sources/uncertainties, emission control technology DREs and their uncertainties, fraction of gas fed into each process type with emissions, control technologies, description of abatement controls, inputs in the mass-balance equation (for heat transfer fluid emissions), example calculation, and emissions uncertainty estimate. These data form the basis of the calculations and are needed for us to understand the emissions data and verify the reasonableness of the reported emissions. 6. Selection of Records That Must Be Retained We propose that facilities keep records of the following: Data actually used to estimate emissions, records supporting values used to estimate emissions, the initial and any subsequent tests of the DRE of oxidizers, the initial and any subsequent tests to determine emission factors for process, and abatement device calibration/maintenance records. These records consist of values that are directly used to calculate the emissions that are reported and are necessary to enable verification that the GHG emissions monitoring and calculations are done correctly. J. Ethanol Production 1. Definition of the Source Category Ethanol is produced primarily for use as a fuel component, but is also used in industrial applications and in the manufacture of beverage alcohol. Ethanol can be produced from the fermentation of sugar, starch, grain, and cellulosic biomass feedstocks, or produced synthetically from ethylene or hydrogen and carbon monoxide. The sources of GHG emissions at ethanol production facilities that must be reported under the proposed rule are stationary fuel combustion, onsite landfills, and onsite wastewater treatment. Proposed requirements for stationary fuel combustion emissions are set forth in proposed 40 CFR part 98, subpart C. Proposed requirements for landfill emissions are set forth in Section V.HH of this preamble. Data is unavailable on landfilling at ethanol facilities, but it is our understanding that some of these facilities may have landfills with significant CH4 emissions. For more information on landfills at industrial facilities, please refer to the Ethanol Production TSD (EPA-HQ-OAR-2008-0508-010). EPA is seeking comment on available data sources for landfilling practices at ethanol production facilities. The wastewater generated at ethanol production facilities is handled in a variety of ways, with dry milling and wet milling facilities generally treating wastewaters differently. In 2006, CH4 emissions from wastewater treatment at ethanol production facilities were 68,200 metric tons CO2e. Proposed requirements for GHG emissions form wastewater treatment are set forth in Section V.II of this preamble. For more information on wastewater treatment at ethanol production facilities, please refer to the Ethanol Production TSD (EPA-HQ-OAR-2008-0508-010). As noted in Section IV.B of this preamble under the heading ``Reporting by fuel and industrial gas suppliers'', ethanol producers and other suppliers of biomass-based fuel are not required to report GHG emissions from their products under this proposal, and we seek comment on this approach. 2. Selection of Reporting Threshold The proposed threshold for reporting emissions from ethanol production facilities is 25,000 metric tons CO2e total emissions from stationary fuel combustion, landfills, and onsite wastewater treatment. Table J-1 of this preamble illustrates the emissions and facilities that would be covered under various thresholds. Table J-1. Threshold Analysis for Ethanol Production -------------------------------------------------------------------------------------------------------------------------------------------------------- Emissions covered Facilities covered Threshold level National emissions Total number ------------------------------------------------------------------------ mtCO2e of facilities mtCO2e/year Percent Number Percent -------------------------------------------------------------------------------------------------------------------------------------------------------- 1,000 mtCO2e......................... Not estimated........... 140 Not estimated........... Not estimated.......... >101 >72 10,000 mtCO2e........................ Not estimated........... 140 Not estimated........... Not estimated.......... >94 >67 25,000 mtCO2e........................ Not estimated........... 140 Not estimated........... Not estimated.......... >86 >61 100,000 mtCO2e....................... Not estimated........... 140 Not estimated........... Not estimated.......... >43 >31 -------------------------------------------------------------------------------------------------------------------------------------------------------- Data were unavailable to estimate emissions from landfills at ethanol refineries, or to estimate the combined wastewater treatment and stationary fuel combustion emissions at facilities. Data on stationary fuel combustion were used to estimate the minimum number of facilities that would meet each of the facility-level thresholds examined. The [[Page 16501]] 25,000 metric tons CO2e threshold results in a reasonable number of reporters, and is consistent with thresholds for other source categories. For more information on this analysis, please refer to the Ethanol Production TSD (EPA-HQ-OAR-2008-0508-010). EPA is seeking comment on the analysis and on alternative data sources for stationary combustion at ethanol production facilities. For specific information on costs, including unamortized first year capital expenditures, please refer to section 4 of the RIA and the RIA cost appendix. 3. Selection of Proposed Monitoring Methods Refer to Sections V.C, V.HH, and V.II of this preamble for monitoring methods for general stationary fuel combustion sources, landfills, and wastewater treatment occurring on-site at ethanol production facilities. 4. Selection of Procedures for Estimating Missing Data Refer to Sections V.C, V.HH, and V.II of this preamble for procedures for estimating missing data for general stationary fuel combustion sources, landfills, and industrial wastewater treatment occurring on-site at ethanol production facilities. 5. Selection of Data Reporting Requirements Refer to Sections V.C, V.HH, and V.II of this preamble for reporting requirements for general stationary fuel combustion sources, landfills, and industrial wastewater treatment occurring on-site at ethanol production facilities. In addition, you would be required to report the quantity of CO2e captured for use (if applicable) and the end use, if known. For more information on reporting requirements for CO2e capture, please refer to Section V.PP of this preamble. 6. Selection of Records That Must Be Maintained Refer to Sections V.C, V.HH, and V.GG of this preamble for recordkeeping requirements for stationary fuel combustion, landfills, and industrial wastewater treatment occurring on-site at ethanol production facilities. K. Ferroalloy Production 1. Definition of the Source Category A ferroalloy is an alloy of iron with at least one other metal such as chromium, silicon, molybdenum, manganese, or titanium. For this proposed rule, we are defining the ferroalloy production source category to consist of any facility that uses pyrometallurgical techniques to produce any of the following metals: ferrochromium, ferromanganese, ferromolybdenum, ferronickel, ferrosilicon, ferrotitanium, ferrotungsten, ferrovanadium, silicomanganese, or silicon metal. Ferroalloys are used extensively in the iron and steel industry to impart distinctive qualities to stainless and other specialty steels, and serve important functions during iron and steel production cycles. Silicon metal is included in the ferroalloy metals category due to the similarities between its production process and that of ferrosilicon. Silicon metal is used in alloys of aluminum and in the chemical industry as a raw material in silicon-based chemical manufacturing. The basic process used at U.S. ferroalloy production facilities is a batch process in which a measured mixture of metals, carbonaceous reducing agents, and slag forming materials are melted and reduced in an electric arc furnace. The carbonaceous reducing agents typically used are coke or coal. Molten alloy tapped from the electric arc furnace is casted into solid alloy slabs which are further mechanically processed for sale as product or disposed in landfills. Ferroalloy production results in both combustion and process- related GHG emissions. The major source of GHG emissions from a ferroalloy production facility are the process-related emissions from the electric arc furnace operations. These emissions, which consist primarily of CO2e with smaller amounts of CH4, result from the reduction of the metallic oxides and the consumption of the graphite (carbon) electrodes during the batch process. Total nationwide GHG emissions from ferroalloy production facilities operating in the U.S. were estimated to be approximately 2.3 million metric tons CO2e for the year 2006. Process-related GHG emissions were 2.0 million metric tons CO2e (86 percent of the total emissions). The remaining 0.3 million metric tons CO2e (14 percent of the total emissions) were combustion GHG emissions. Additional background information about GHG emissions from the ferroalloy production source category is available in the Ferroalloy Production TSD (EPA-HQ-OAR-2008-0508-011). 2. Selection of Reporting Threshold Ferroalloy production facilities in the U.S. vary in the specific types of alloy products produced. In developing the threshold for ferroalloy production facilities, we considered using annual GHG emissions-based threshold levels of 1,000 metric tons CO2e, 10,000 metric tons CO2e, 25,000 metric tons CO2e and 100,000 metric tons CO2e. Table K-1 of this preamble presents the estimated emissions and number of facilities that would be subject to GHG emissions reporting, based upon emission estimates using production capacity data for the nine U.S. facilities that produce either ferrosilicon, silicon metal, ferrochromium, ferromanganese, or silicomanganese alloys. We were unable to obtain production data for an estimated five additional facilities that produce ferromolybdenum and ferrotitanium alloys. Table K-1. Threshold Analysis for Ferroalloy Production Facilities -------------------------------------------------------------------------------------------------------------------------------------------------------- Total national Emissions covered Facilities covered emissions Total number ------------------------------------------------------------ Threshold level (metric tons CO2e/yr) (metric tons of facilities Metric tons CO2e/yr) CO2e/yr Percent Number Percent -------------------------------------------------------------------------------------------------------------------------------------------------------- 1,000...................................................... 2,343,990 9 2,343,990 100 9 100 10,000..................................................... 2,343,990 9 2,343,990 100 9 100 25,000..................................................... 2,343,990 9 2,343,990 100 9 100 100,000.................................................... 2,343,990 9 2,276,639 97 8 89 -------------------------------------------------------------------------------------------------------------------------------------------------------- Table K-1 of this preamble shows that all nine of the facilities would be required to report emissions at all thresholds except 100,000 metric tons CO2e, when considering combustion and process- related emissions. The rule could be simplified for these facilities by making the rule applicable to all ferroalloy production facilities. [[Page 16502]] However, because the threshold analysis did not include all of the facilities in the ferroalloy source category that potentially could be subject to the rule, we have decided that it is appropriate to include a reporting threshold level. The proposed threshold selected for reporting emissions from ferroalloy production facilities is 25,000 metric tons CO2e per year consistent with the threshold level being proposed for other source categories. This threshold level would avoid placing a reporting burden on any small specialty ferroalloy production facility which may operate as a small business while still requiring the reporting of GHG emissions from the ferroalloy production facilities releasing most of the GHG emissions in the source category. A full discussion of the threshold selection analysis is available in the Ferroalloy Production TSD (EPA-HQ-OAR- 2008-0508-011). For specific information on costs, including unamortized first year capital expenditures, please refer to section 4 of the RIA and the RIA cost appendix. 3. Selection of Proposed Monitoring Methods We reviewed existing methodologies used by the 2006 IPCC Guidelines for National Greenhouse Gas Inventories, Canadian Mandatory Greenhouse Gas Reporting Program, the Australian National Greenhouse Gas Reporting Program, and EU Emissions Trading System. In general, the methodologies used for estimating process related GHG emissions at the facility level coalesce around the following four options. Option 1. Apply a default emission factor to ferroalloy production. This is a simplified emission calculation method using only default emission factors to estimate process-related CO2 and CH4 emissions. The method requires multiplying the amount of each ferroalloy product type produced by the appropriate default emission factors from the 2006 IPCC Guidelines. Option 2. Perform a monthly carbon balance using measurements of the carbon content of specific process inputs and process outputs and the amounts of these materials consumed or produced during a specified reporting period. This option is applicable to estimating only CO2 emissions from an electric arc furnace, and is the IPCC Tier 3 approach and the higher order methods in the Canadian and Australian reporting programs. Implementation of this method requires you to determine the carbon contents of carbonaceous material inputs to and outputs from the electric arc furnaces. Facilities determine carbon contents through analysis of representative samples of the material or from information provided by the material suppliers. In addition, the quantities of these materials consumed and produced during production would be measured and recorded. To obtain the CO2 emissions estimate, the average carbon content of each input and output material is multiplied by the corresponding mass consumed and a conversion of carbon to CO2. The difference between the calculated total carbon input and the total carbon output is the estimated CO2 emissions to the atmosphere. This method assumes that all of the carbon is converted during the process. For estimating the CH4 emissions from the electric arc furnace, selection of this option for estimating CO2 emissions would still require using the Option 1 approach of applying default emission factors to estimate CH4 emissions. Option 3. Use CO2 emissions data from a stack test performed using U.S. EPA test methods to develop a site-specific process emissions factor which is then applied to quantity measurement data of feed material or product for the specified reporting period. This monitoring method is applicable to electric arc furnace configurations for which the GHG emissions are contained within a stack or vent. Using site-specific emissions factors based on short-term stack testing is appropriate for those facilities where process inputs (e.g., feed materials, carbonaceous reducing agents) and process operating parameters remain relatively consistent over time. Option 4. Use direct emission testing of CO2 emissions. For electric arc furnace configurations in which the process off-gases are contained within a stack or vent, direct measurement of the CO2 emissions can be made by continuously measuring the off- gas stream CO2 concentration and flow rate using a CEMS. Using a CEMS, the total CO2 emissions tabulated from the recorded emissions measurement data would be reported annually. If a ferroalloy production facility uses an open or semi-open electric arc furnace for which the CO2 emissions are not fully captured and contained within a stack or vent (i.e., a significant portion of the CO2 emissions escape capture by the hood and are release directly to the atmosphere), then another GHG emission estimation method other than direct measurement would be more appropriate. Proposed Option. Under the proposed rule, if you are required to use an existing CEMS to meet the requirements outlined in proposed 40 CFR part 98, subpart C, you would be required to use CEMS to estimate CO2 emissions. Where the CEMS capture all combustion- and process-related CO2 emissions you would be required to follow the requirements of proposed 40 CFR part 98, subpart C, to estimate CO2 emissions from the industrial source. Also, refer to proposed 40 CFR part 98, subpart C to estimate combustion- related CH4 and N2O. For facilities that do not currently have CEMS that meet the requirements outlined in proposed 40 CFR part 98, subpart C, or where CEMS would not adequately account for process emissions, the proposed monitoring method is Option 2. You would be required to follow the requirements of proposed 40 CFR part 98, subpart C to estimate emissions of CO2, CH4 and N2O from stationary combustion. This section of the preamble provides procedures only for calculating and reporting process-related emissions. Given the variability of the alloy products produced and carbonaceous reducing agents used at U.S. ferroalloy production facilities, we concluded that using facility-specific information under Option 2 is preferred for estimating CO2 emissions from electric arc furnaces. This method is consistent with IPCC Tier 3 methods and the preferred approaches for estimating emissions in the Canadian and Australian mandatory reporting programs. We consider the additional burden of the material measurements required for the carbon balance small in relation to the increased accuracy expected from using this site-specific information to calculate CO2 emissions. Emissions data collected under Option 3 would have the lowest uncertainty, expected to be less than 5 percent. For Option 2, the material-specific emission factors would be expected to be within 10 percent, which would provide less uncertainty overall than for Option 1, which may have uncertainty of 25 to 50 percent. The use of the default CO2 emission factors under Option 1 would be more appropriate for GHG estimates from aggregated process information on a sector-wide or nationwide basis than for determining GHG emissions from specific facilities. In comparison to the CO2 emissions levels from an electric arc furnace, the CH4 emissions compose a small fraction of the total GHG emissions from electric arc furnace operations at a ferroalloy production facility. The proposed Option 2 above doesn't account for CH4. Considering the amount that CH4 emissions contribute to the total GHG emissions and the absence of facility-specific methods in other reporting systems, we are proposing that facilities [[Page 16503]] use Option 1 and the IPCC default emission factors to estimate CH4 emissions from electric arc furnaces at ferroalloy production facilities. This method provides reasonable estimates of the magnitude of the CH4 emissions from the units without the need for owners or operator to conduct on-site CH4 emissions measurements. We also decided against Option 3 because of the potential for significant variations at ferroalloy production facilities in the characteristics and quantities of the electric arc furnace inputs (e.g., metal ores, carbonaceous reducing agents) and process operating parameters. A method using periodic, short-term stack testing would not be practical or appropriate for those ferroalloy production facilities where the electric arc furnace inputs and operating parameters do not remain relatively consistent over the reporting period. The various approaches to monitoring GHG emissions are elaborated in the Ferroalloy Production TSD (EPA-HQ-OAR-2008-0508-011). 4. Selection of Procedures for Estimating Missing Data In cases when an owner or operator calculates CO2 and CH4 emissions using a carbon balance or an emission factor, the proposed rule would require the use of substitute data whenever a quality-assured value of a parameter that is used to calculate GHG emissions is unavailable, or ``missing.'' If the carbon content analysis of carbon inputs or outputs is missing or lost, the substitute data value would be the average of the quality-assured values of the parameter immediately before and immediately after the missing data period. The likelihood for missing process input and output data is low, as businesses closely track their purchase of production inputs. In those cases when an owner or operator uses direct measurement by a CO2 CEMS, the missing data procedures would be the same as the Tier 4 requirements described for general stationary combustion sources in Section V.C of this preamble. 5. Selection of Data Reporting Requirements The proposed rule would require reporting of the total annual CO2 and CH4 emissions for each electric arc furnace at a ferroalloy production facility, as well as any stationary fuel combustion emissions. In addition we propose that additional information which forms the basis of the emissions estimates also be reported so that we can understand and verify the reported emissions. This additional information includes the total number of electric arc furnaces operated at the facility, the facility ferroalloy product production capacity, the annual facility production quantity for each ferroalloy product, the number of facility operating hours in calendar year, and quantities of carbon inputs and outputs if applicable. A complete list of data to be reported is included in the proposed 40 CFR part 98, subparts A and K. 6. Selection of Records That Must Be Retained Maintaining records of the information used to determine the reported GHG emissions are necessary to enable us to verify that the GHG emissions monitoring and calculations were done correctly. We propose that all affected facilities maintain records of product production quantities, and number of facility operating hours each month. If you use the carbon balance procedure, you would record for each carbon-containing input material consumed or used and output material produced the monthly material quantity, monthly average carbon content determined for material, and records of the supplier provided information or analyses used for the determination. If you use the CEMS procedure, you would maintain the CEMS measurement records. L. Fluorinated GHG Production 1. Definition of the Source Category This source category covers emissions of fluorinated GHGs that occur during the production of HFCs, PFCs, SF6, NF3, and other fluorinated GHGs such as fluorinated ethers. Specifically, it covers emissions that are never counted as ``mass produced'' under the proposed requirements for suppliers of industrial GHGs discussed in Section OO of this preamble. These emissions include fluorinated GHG products that are emitted upstream of the production measurement and fluorinated GHG byproducts that are generated and emitted either without or despite recapture or destruction.\71\ These emissions exclude generation and emissions of HFC-23 during the production of HCFC-22, which are discussed in Section O of this preamble. --------------------------------------------------------------------------- \71\ Byproducts that are emitted or destroyed at the production facility are excluded from the proposed definition of ``produce a fluorinated GHG.'' Any HFC-23 generated during the production of HCFC-22 is also excluded from this definition, even if the HFC-23 is recaptured. However, other fluorinated GHG byproducts that are recaptured for any reason would be considered to be ``produced.'' --------------------------------------------------------------------------- Emissions can occur from leaks at flanges and connections in the production line, during separation of byproducts and products, during occasional service work on the production equipment, and during the filling of tanks or other containers that are distributed by the producer (e.g., on trucks and railcars). Fluorinated GHG emissions from U.S. facilities producing fluorinated GHGs are estimated to range from 0.8 percent to 2 percent of the amount of fluorinated GHGs produced, depending on the facility. In 2006, 12 U.S. facilities produced over 350 million metric tons CO2e of HFCs, PFCs, SF6, and NF3. These facilities are estimated to have emitted approximately 5.3 million metric tons CO2e of HFCs, PFCs, SF6, and NF3, based on an emission rate of 1.5 percent. We estimate that an additional 6 facilities produced approximately 1 million metric tons CO2e of fluorinated anesthetics. At an emission rate of 1.5 percent, these facilities would emit approximately 15,000 metric tons CO2e of these anesthetics. The production of fluorinated gases causes both combustion and fluorinated GHG emissions. Fluorinated GHG production facilities would be required to follow the requirements of proposed 40 CFR part 98, subpart C to estimate emissions of CO2, CH4 and N2O from stationary fuel combustion. In addition, these facilities would be required to report their production of industrial GHGs under proposed 40 CFR part 98, subpart OO. This section of the preamble discusses only the procedures for calculating and reporting emissions of fluorinated GHGs. 2. Selection of Reporting Threshold We propose that owners and operators of facilities estimate and report fluorinated GHG and combustion emissions if those emissions together exceed 25,000 metric tons CO2e. In developing the threshold, we considered emissions thresholds of 1,000 metric tons CO2e, 10,000 metric tons CO2e, 25,000 metric tons CO2e and 100,000 metric tons CO2e and their capacity equivalents. Facility-specific emissions were estimated by multiplying an emission factor of 1.5 percent by the estimated production at each facility. The capacity thresholds were developed based on emissions of fluorinated GHGs, assuming full capacity utilization and an emission rate of 2 percent of production. Because EPA had little information on combustion-related emissions at fluorinated GHG production facilities, these emissions were not incorporated into the capacity thresholds or the threshold analysis. Table L-1 of this preamble illustrates the HFC, PFC, SF6, and NF3 emissions [[Page 16504]] and facilities that would be covered under these various thresholds. Table L-1. Threshold Analysis for Fluorinated GHG Emissions From Production of HFCs, PFCs, SF6, and NF3 -------------------------------------------------------------------------------------------------------------------------------------------------------- Total Emissions covered Facilities covered national --------------------------------------------------------------- Threshold level (metric tons CO2e/r) emissions Number of (metric tons facilities Metric tons Percent Number Percent CO2e) CO2e -------------------------------------------------------------------------------------------------------------------------------------------------------- Emission-Based Thresholds -------------------------------------------------------------------------------------------------------------------------------------------------------- 1,000................................................... 5,300,000 12 5,300,000 100 12 100 10,000.................................................. 5,300,000 12 5,300,000 100 12 100 25,000.................................................. 5,300,000 12 5,300,000 100 12 100 100,000................................................. 5,300,000 12 5,100,000 97 9 75 -------------------------------------------------------------------------------------------------------------------------------------------------------- Production Capacity-Based Thresholds -------------------------------------------------------------------------------------------------------------------------------------------------------- 50,000.................................................. 5,300,000 12 5,300,000 100 12 100 500,000................................................. 5,300,000 12 5,300,000 100 12 100 1,250,000............................................... 5,300,000 12 5,300,000 100 12 100 5,000,000............................................... 5,300,000 12 5,200,000 98 10 83 -------------------------------------------------------------------------------------------------------------------------------------------------------- As can be seen from the tables, most HFC, PFC, SF6, and NF3 production facilities would be covered by all emission- and capacity-based thresholds. Although we do not have facility- specific production information for producers of fluorinated anesthetics, we believe that few or none of these facilities are likely to have emissions above the proposed threshold. EPA requests comment on whether it should adopt a capacity-based threshold for this sector, and if so, what fluorinated GHG and combustion-related emission rates should be used to develop this threshold. Where EPA has reasonably good information on the relationship between production capacity and emissions, and where this relationship does not vary excessively from facility to facility, EPA is generally proposing capacity-based thresholds to make it easy for facilities to determine whether or not they must report. In this case, however, EPA has little data on combustion emissions and their likely magnitude compared to fluorinated GHG emissions from this source. As noted above, the capacity thresholds in Table L-1 of this preamble were developed based on a fluorinated GHG emission rate of 2 percent of production. While EPA believes that this emission rate is an upper-bound for fluorinated GHGs, neither the rate nor the thresholds account for combustion-related emissions. Thus, it is possible that the production capacities listed in Table L-1 of this preamble are inappropriately high. In the event that a capacity-based threshold were adopted, facilities would be required to multiply the production capacity of each production line by the GWP of the fluorinated GHG produced on that line. Facilities would then be required to sum the resulting CO2e capacities across all lines. Where more than one fluorinated GHG could be produced by a production line, yielding more than one possible production capacity for that line in CO2e terms, facilities would be required to use the highest possible production capacity (in CO2e terms) in their threshold calculations. A full discussion of the threshold selection analysis is available in the Fluorinated GHG Production TSD (EPA-HQ-OAR-2008-0508-012). For specific information on costs, including unamortized first year capital expenditures, please refer to section 4 of the RIA and the RIA cost appendix. 3. Selection of Proposed Monitoring Methods In developing this proposed rule, we reviewed a number of protocols for estimating fluorinated GHG emissions from fluorocarbon production, such as the 2006 IPCC Guidelines. In general, these protocols present three methods. In the first approach, a default emission factor is applied to the total production of the plant. In the second approach, fluorinated GHG emissions are equated to the difference between the mass of reactants fed into the process and the sum of the masses of the main product and those of any by-products and/or wastes. In the third approach, the composition and mass flow rate of the gas streams actually vented to the atmosphere are monitored either continuously or during a period long enough to establish an emission factor. If you produce fluorinated GHGs, we are proposing that you monitor fluorinated GHG emissions using the second approach, known as the mass- balance or yield approach. There are two variants of the mass-balance approach. In the first variant, only some of the reactants and products, including the fluorinated GHG product, are considered. In the second variant, all of the reactants, products, and by-products are considered. Both variants are discussed in more detail in the Fluorinated GHG Production TSD (EPA-HQ-OAR-2008-0508-012). We are proposing that you monitor emissions using the first variant. In this approach, you would calculate the difference between the expected production of each fluorinated GHG based on the consumption of reactants and the measured production of that fluorinated GHG, accounting for yield losses related to byproducts (including intermediates permanently removed from the process) and wastes. Yield losses that could not be accounted for would be attributed to emissions of the fluorinated GHG product. This calculation would be performed for each reactant, and estimated emissions of the fluorinated GHG product would be equated to the average of the results obtained for each reactant. If fluorinated GHG byproducts were produced and were not completely recaptured or completely destroyed, you would also estimate emissions of each fluorinated GHG byproduct. To carry out this approach, you would daily weigh or meter each reactant fed into the process, the primary fluorinated GHG produced by the process, any reactants permanently removed from the [[Page 16505]] process (i.e., sent to the thermal oxidizer or other equipment, not immediately recycled back into the process), any byproducts generated, and any streams that contain the product or byproducts and that are recaptured or destroyed. For these measurements you would be required to use scales and/or flowmeters with an accuracy and precision of 0.2 percent of full scale. If monitored process streams included more than one component (product, byproducts, or other materials) in more than trace concentrations,\72\ you would be required to monitor concentrations of products and byproducts in these streams at least daily using equipment and methods (e.g., gas chromatography) with an accuracy and precision of 5 percent or better at the concentrations of the process samples. Finally, you would be required to perform daily mass balance calculations for each product produced. --------------------------------------------------------------------------- \72\ EPA is proposing to define ``trace concentration'' as any concentration less than 0.1 percent by mass of the process stream. --------------------------------------------------------------------------- In general, we understand that production facilities already perform these measurements and calculations to the proposed level of accuracy and precision in order to monitor their processes and yields. However, we request comment on this issue. We specifically request comment on the proposed scope and frequency of process stream concentration measurements. As noted above, concentration measurements would be triggered when products or byproducts occur in more than trace concentrations with other components in process streams (which include waste streams). However, it is possible that products or byproducts could occur in more than trace concentrations but still result in negligible yield losses (e.g., less than 0.2 percent). In this case, ignoring these losses may not significantly affect the accuracy of the overall GHG emission estimate. (This issue is discussed in more detail in the Fluorinated GHG Production TSD (EPA-HQ-OAR-2008-0508-012).) Similarly, decreasing the frequency of stream sampling may not have a significant impact on accuracy or precision if previous monitoring has shown that the concentrations of products and byproducts in process streams are stable or vary in a predictable and quantifiable way (e.g., seasonally due to differences in condenser cooling water temperature). EPA recognizes that the proposed mass-balance approach would assume that all yield losses that are not accounted for are attributable to emissions of the fluorinated GHG product. In some cases, the losses may be untracked emissions or other losses of reactants or fluorinated by- products. In general, EPA understands that reactant flows are measured at the inlet to the reactor; thus, any losses of reactant that occur between the point of measurement and the reactor are likely to be small. However, reactants that are recovered from the process, whether they are recycled back into it or removed permanently, may experience some losses that the proposed method does not account for. EPA requests comment on the extent to which such losses occur, and how these might be measured. Fluorocarbon by-products, according to the IPCC Guidelines, generally have ``radiative forcing properties similar to those of the desired fluorochemical.'' If this is always the case (with the exception of HFC-23 generated during production of HCFC-22, which is addressed in Section V.O of this preamble), then assuming by-product emissions are product emissions would not lead to large errors in estimating overall fluorinated GHG emissions. If the GWPs of emitted fluorinated by-products are sometimes significantly different from those of the fluorinated GHG product, and if the quantity of by-product emitted can be estimated (e.g., based on periodic or past sampling of process streams), then the quantity of emitted product could be adjusted to reflect this. EPA requests comment on whether it is necessary or practical to distinguish between emissions of fluorinated GHG products and emissions of fluorinated by-products, and if so, on the best approach for doing so. We also request comment on the proposed accuracy and precision requirements for flowmeters and scales. If a waste or by-product stream is significantly smaller than the reactant and product streams, a less precise measurement of this stream (e.g., 0.5 percent) may not have a large impact on the precision of the fluorinated GHG emission estimate and may therefore be acceptable. Similarly, if a measurement is repeated multiple times over the course of the reporting period, the precision of individual measurements could be relaxed without seriously compromising the precision of the monthly or annual estimates. One way of adding flexibility to the precision requirements would be to require that the error of the fluorinated GHG emissions estimate be no greater than some fraction of the yield, e.g., 0.3 percent, on a monthly basis. Facilities could achieve this level of precision however they chose. We request comment on this issue and on the accuracy, precision, and cost of the proposed approach as a whole. Analysis of Alternative Methods. EPA is not proposing the approach using the default emission factor. While this approach is simple, it is also highly imprecise; emissions in U.S. plants are estimated to vary from 0.8 percent to 2 percent of production, more than a factor of two.\73\ Thus, applying a default factor (1.5 percent, for example) is likely to significantly overestimate emissions at some plants while significantly underestimating them at others. --------------------------------------------------------------------------- \73\ Fluorinated GHG Production TSD (EPA-HQ-OAR-2008-0508-012). --------------------------------------------------------------------------- EPA is not proposing the second variant of the mass-balance approach. This variant is implemented by comparing the total mass of reactants to the total mass of monitored products and byproducts, without regard for chemical identity. The drawbacks of this variant are that it is not the method currently used by facilities to track their production, and it would count losses of non-GHG products (e.g., HCl) as GHG emissions. EPA requests comment on this understanding and on the potential usefulness and accuracy of the second variant of the mass- balance approach for estimating fluorinated GHG emissions. EPA is not proposing the third approach because it is our understanding that facilities do not routinely monitor their process vents, and therefore such monitoring is likely to be more expensive than the proposed mass-balance approach. However, the cost of monitoring may not be prohibitive, particularly if it is performed for a relatively short period of time for the purpose of developing an emission factor, similar to the approach for estimating smelter- specific slope coefficients for aluminum production.\74\ Moreover, if the vent monitoring approach reduces the uncertainty of the emissions measurement by even 10 percent relative to the mass-balance approach, this would reduce the absolute uncertainty at the typical production facility by 40,000 metric tons CO2e. (The extent to which uncertainty would be reduced would depend in part on the sensitivity and [[Page 16506]] precision of the vent concentration measurements.) --------------------------------------------------------------------------- \74\ Conversations with representatives of fluorocarbon producers indicate that robust emission factors could often be developed by monitoring emissions (and a related parameter, such as production) for one month under representative operating conditions. Where emissions vary seasonally (e.g., due to changes in condenser cooling water temperature), two separate monitoring periods of one month each would often suffice. However, the length and frequency of monitoring would depend on the variability of the process. --------------------------------------------------------------------------- For completeness, monitoring of process vents would need to be supplemented by monitoring of equipment leaks, whose emissions would not occur through process vents. To capture emissions from equipment leaks, we could require use of EPA Method 21 and the Protocol for Equipment Leak Estimates (EPA-453/R-95-017). The Protocol includes four methods for estimating equipment leaks. These are, from least to most accurate, the Average Emission Factor Approach, the Screening Ranges Approach, EPA Correlation Approach, and the Unit-Specific Correlation Approach. Most recent EPA leak detection and repair regulations require use of one of the Correlation Approaches in the Protocol. To use any approach other than the Average Emission Factor Approach, you would need to have (or develop) Response Factors relating concentrations of the target fluorinated GHG to concentrations of the gas with which the leak detector was calibrated. We understand that at least two fluorocarbon producers currently use methods in the Protocol to quantify their emissions of fluorinated GHGs with different levels of accuracy and precision.\75\ --------------------------------------------------------------------------- \75\ One producer estimates HFC and other fluorocarbon emissions by using the Average Emission Factor Approach. This approach simply assigns an average emission factor to each component without any evaluation of whether or how much that component is actually leaking. The second producer estimates emissions using the Screening Ranges Approach, which assigns different emission factors to components based on whether the concentrations of the target chemical are above or below 10,000 ppmv. This producer has developed a Response Factor for HCFC-22, which is present in the same streams as the HFC-23 whose leaks are being estimated. (HFC-23 emissions are discussed in Section O of this preamble.) --------------------------------------------------------------------------- We request comment on the accuracies and costs of the approaches in the Protocol as they would be applied to fluorinated GHG production. We also request comment on the significance of equipment leaks compared to process vents as a source of fluorinated GHG emissions. In addition, we request comment on whether we should require the vent monitoring approach, what sensitivity and precision would be appropriate for the vent concentration measurements, and on the increase in cost and improvements in accuracy and precision that would be associated with this approach relative to the proposed approach. Emissions from Evacuation of Returned Containers. We request comment on whether you should be required to measure and report fluorinated GHG emissions associated with the evacuation of cylinders or other containers that are returned to the facility containing either residual GHGs (heels) or GHGs that would be reclaimed or destroyed. We are not proposing to require reporting of these emissions because they are not associated with new production; instead, they are downstream emissions associated with earlier production.\76\ Requiring reporting of these emissions could therefore lead to double-counting.\77\ --------------------------------------------------------------------------- \76\ Emissions from the filling or refilling of containers with new product may or may not be covered by proposed 40 CFR part 98, subpart L, depending on where production is measured. If production is measured upstream of filling, then the emissions would not be covered by proposed 40 CFR part 98, subpart L. If production is measured downstream of filling, then the emissions would be covered by subpart L. \77\ However, this double-counting could be avoided if the emissions from returned cylinders were clearly distinguished from other production facility emissions in the emissions report. --------------------------------------------------------------------------- Nevertheless, according to the 2006 IPCC Guidelines, the overall emission rate of a production facility can increase by nearly an order of magnitude (up to 8 percent) if the residual GHG remaining in the cylinders is vented to the atmosphere. One method of tracking such emissions would be to subtract the quantities of GHG reclaimed (purified) and sold or otherwise sent back to users from the quantities of residual and used GHGs returned to the facility in cylinders by users. This approach would be similar to the mass-balance approach proposed for estimating SF6 emissions from users and manufacturers of electrical equipment. Emissions of Fluorinated GHGs Associated with Production of ODS. We request comment on whether you should be required to report emissions of fluorinated GHGs associated with production of ODS (other than emissions of HFC-23 associated with production of HCFC-22, which are discussed in Section O of this preamble). These emissions would be by- product emissions, for example of HFCs, since the definition of fluorinated GHGs excludes ODS. We specifically request comment on the likely magnitude of these emissions, both in absolute terms and relative to fluorinated GHG emissions from fluorinated GHG production. We believe that these emissions may occur due to the chemical similarities between HFCs, HCFCs, and CFCs and the common use of halogen replacement chemistry to produce them. Although production of HCFCs and CFCs is limited under the regulations implementing Title VI of the CAA, production of these substances for use as feedstocks is permitted to continue indefinitely. 4. Selection of Procedures for Estimating Missing Data In the event that a scale or flowmeter normally used to measure reactants, products, by-products, or wastes fails to meet an accuracy or precision test, malfunctions, or is rendered inoperable, we are proposing that facilities be required to estimate these quantities using other measurements where these data are available. For example, facilities that ordinarily measure production by metering the flow into the day tank could use the weight of product charged into shipping containers for sale and distribution as a substitute. It is our understanding that the types of flowmeters and scales used to measure fluorocarbon production (e.g., Coriolis meters) are generally quite reliable, and therefore that it should rarely be necessary to rely solely on secondary production measurements. In general, production facilities rely on accurate monitoring and reporting of the inputs and outputs of the production process. If concentration measurements are unavailable for some period, we are proposing that the facility use the average of the concentration measurements from just before and just after the period of missing data. There is one proposed exception to these requirements: If either method would result in a significant under- or overestimate of the missing parameter, then the facility would be required to develop an alternative estimate of the parameter and explain why and how it developed that estimate. We request comment on these proposed methods for estimating missing data. 5. Selection of Data Reporting Requirements Under the proposed rule, owners and operators of facilities producing fluorinated GHGs would be required to report both their fluorinated GHG emissions and the quantities used to estimate them, including the masses of the reactants, products, by-products, and wastes, and, if applicable, the quantities of any product in the by- products and/or wastes (if that product is emitted at the facility). We are proposing that owners and operators report annual totals of these quantities. Where fluorinated GHG production facilities have estimated missing data, you would be required to report the reason the data were missing, the length of time the data were missing, the method used to estimate the missing [[Page 16507]] data, and the estimates of those data. Where the missing data was estimated by a method other than one of those specified, the owner or operator would be required to report why the specified method would lead to a significant under- or overestimate of the parameter(s) and the rationale for the methods used to estimate the missing data. We propose that facilities report these data because the data are necessary to verify facilities' calculations of fluorinated GHG emissions. We request comment on these proposed reporting requirements. 6. Selection of Records That Must Be Retained Under the proposed rule, owners and operators of facilities producing fluorinated GHGs would be required to retain records documenting the data reported, including records of daily and monthly mass-balance calculations and calibration records for flowmeters, scales, and gas chromatographs. These records are necessary to verify that the GHG emissions monitoring and calculations were performed correctly. M. Food Processing 1. Definition of the Source Category Food processing facilities prepare raw ingredients for consumption by animals or humans. Many facilities in the meat and poultry, and fruit, vegetable, and juice processing industries have on-site wastewater treatment. This can include the use of anaerobic and aerobic lagoons, screening, fat traps and dissolved air flotation. These facilities can also include onsite landfills for waste disposal. In 2006, CH4 emissions from wastewater treatment at food processing facilities were 3.7 million metric tons CO2e, and CH4 emissions from onsite landfills were 7.2 million metric tons CO2e. Data are not available to estimate stationary fuel combustion-related GHG emissions at food processing facilities. Proposed requirements for stationary fuel combustion emissions are set forth in proposed 40 CFR part 98, subpart C. Wastewater GHG emissions are described and considered in Section V.II of this preamble. For more information on wastewater treatment at food processing facilities, please refer to the Food Processing TSD (EPA-HQ-OAR-2008-0508-013). Landfill GHG emissions are described and considered in Section V.HH of this preamble. For more information on landfills at food processing facilities, please refer to the Landfills TSD (EPA-HQ-OAR-2008-0508-034). The sources of GHG emissions at food processing facilities that must be reported under the proposed rule are stationary fuel combustion, onsite landfills and onsite wastewater treatment. 2. Selection of Reporting Threshold We considered using annual GHG emissions-based threshold levels of 1,000 metric tons CO2e, 10,000 metric tons CO2e, 25,000 metric tons CO2e and 100,000 metric tons CO2e for food processing facilities. The proposed threshold for reporting emissions from food processing facilities is 25,000 metric tons CO2e total emissions from combined stationary fuel combustion, on-site landfills, and on-site wastewater treatment. Table M-1 of this preamble illustrates the emissions and facilities that would be covered under these various thresholds. Table M-1. Threshold Analysis for Food Processing Facilities -------------------------------------------------------------------------------------------------------------------------------------------------------- Emissions covered Facilities covered --------------------------------------------------------------- Threshold National Total Metric tons CO2e/year Percent Number Percent -------------------------------------------------------------------------------------------------------------------------------------------------------- 1,000 mtCO2e............................................ NE 5,719 NE NE 802 14.0 10,000 mtCO2e........................................... NE 5,719 NE NE 170 3.0 25,000 mtCO2e........................................... NE 5,719 NE NE 100 1.7 100,000 mtCO2e.......................................... NE 5,719 NE NE 10 0.2 -------------------------------------------------------------------------------------------------------------------------------------------------------- NE = Not Estimated. Data were unavailable at the time of this analysis to estimate stationary combustion emissions onsite, or the co-location of landfills and wastewater treatment at food processing faculties. Facility coverage based on onsite wastewater GHG emissions and landfill GHG emissions was estimated as described in the Wastewater Treatment TSD and Landfills TSD (EPA-HQ-OAR-2008-0508-035) and (EPA-HQ-OAR-2008-0508- 034). We estimate that at the 25,000 metric tons CO2e threshold, a small percentage of facilities are covered by this rule, resulting in potentially a large percentage of emissions data reporting from this significant emissions source but avoiding small facilities. For specific information on costs, including unamortized first year capital expenditures, please refer to section 4 of the RIA and the RIA cost appendix. 3. Selection of Proposed Monitoring Methods Refer to Sections V.C, V.HH, and V.II of this preamble for monitoring methods for general stationary fuel combustion sources, landfills, and wastewater treatment, respectively, occurring on-site at food production facilities. 4. Selection of Procedures for Estimating Missing Data Refer to Sections V.C, V.HH, and V.II of this preamble for procedures for estimating missing data for general stationary fuel combustion sources, landfills, and wastewater treatment, respectively, occurring on-site at food processing facilities. 5. Selection of Data Reporting Requirements Refer to Sections V.C, V.HH, and V.II of this preamble for reporting requirements for general stationary fuel combustion, landfills, and wastewater treatment, respectively, occurring on-site at food processing facilities. In addition, you would be required to report the quantity of CO2 captured for use (if applicable) and the end use, if known. 6. Selection of Records That Must Be Maintained Refer to Sections V.C, V.HH, and V.II of this preamble for recordkeeping requirements for general stationary fuel combustion sources, landfills, and wastewater treatment, respectively, occurring on-site at food processing facilities. N. Glass Production 1. Definition of the Source Category Glass is a common commercial item that is produced by melting a mixture of [[Page 16508]] minerals and other substances, then cooling the molten materials in a manner that prevents crystallization. Glass is typically classified as container glass, flat (or window) glass, or pressed and blown glass. Pressed and blown glass includes textile fiberglass, which is used primarily as a reinforcement material in a variety of products, as well as other types of glass. Wool fiberglass, which is commonly used for insulation, is generally classified separately from textile fiberglass and other pressed and blown glass. However, for the purposes of GHG reporting, wool fiberglass production is included in the glass manufacturing source category. Glass can be produced using a variety of raw material formulations. Most commercial glass is made using a soda-lime glass formulation, which consists of silica (SiO2), soda (Na2O), and lime (CaO), with small amounts of alumina (Al2O3), magnesia (MgO), and other minor ingredients. Several specialty glasses, including fiberglass, are made using borosilicate or aluminoborosilicate recipes, which can consist primarily of silica and boric oxides, along with varying amounts of soda, lime, alumina, and other minor ingredients. Other formulations used in the production of specialty glasses include aluminosilicate and lead silicate formulations. Major carbonates used in the production of glass are limestone (CaCO3), dolomite (CaMg(CO3)2), and soda ash (Na2CO3). The use of these carbonates in the furnace during glass manufacturing results in a complex high- temperature reaction that leads to process-related GHG emissions. Glass manufacturers may also use recycled scrap glass (cullet) in the production of glass, thereby reducing the carbonate input to the process and resulting GHG emissions. National emissions from glass manufacturing were estimated to be 4.43 million metric tons CO2e (0.1 percent of U.S. GHG emissions) in 2005. These emissions include both process-related emissions (CO2) and on-site stationary combustion emissions (CO2, CH4, and N2O) from 374 glass manufacturing facilities across the U.S. and Puerto Rico. Process- related emissions account for 1.65 million metric tons CO2, or 37 percent of the total, while on-site stationary combustion sources account for the remaining 2.78 million metric tons CO2e emissions. For additional background information on glass manufacturing, refer to the Glass Manufacturing TSD (EPA-HQ-OAR-2008-0508-014). 2. Selection of Reporting Threshold In developing the threshold for glass manufacturing, we considered an emissions-based threshold of 1,000 metric tons CO2e, 10,000 metric tons CO2e, 25,000 metric tons CO2e, and 100,000 metric tons CO2e. Table N-1 of this preamble summarizes the emissions and number of facilities that would be covered under these various thresholds. Table N-1. Threshold Analysis for Glass Manufacturing -------------------------------------------------------------------------------------------------------------------------------------------------------- Total national Emissions covered Facilities covered emissions Total number --------------------------------------------------------------- Threshold level metric tons CO2e/yr metric tons of facilities Metric tons CO2e/yr CO2e/yr Percent Number Percent -------------------------------------------------------------------------------------------------------------------------------------------------------- 1,000................................................... 4,425,269 374 4,336,892 98 217 58 10,000.................................................. 4,425,269 374 4,012,319 91 158 42 25,000.................................................. 4,425,269 374 2,243,583 51 55 15 100,000................................................. 4,425,269 374 207,535 5 1 0.3 -------------------------------------------------------------------------------------------------------------------------------------------------------- The glass manufacturing industry is heterogeneous in terms of the types of facilities. There are some relatively large, emissions- intensive facilities, but small artisan shops are common as well. For example, at a 1,000 metric tons CO2e threshold, 98 percent of emissions would be covered, with only 58 percent of facilities being required to report. The proposed threshold for reporting emissions from glass manufacturing is 25,000 metric tons CO2e. We are proposing a 25,000 metric tons CO2e threshold to reduce the compliance burden on small businesses, while still including half of the GHG emissions from the industry. In comparison to the 100,000 metric tons CO2e threshold, the 25,000 metric tons CO2e threshold achieves reporting of 11 times more emissions while requiring less than 15 percent of the facilities to report. Compared to the 10,000 metric tons CO2e threshold, the 25,000 metric tons CO2e threshold captures more than half of those emissions, but only requires a third of the number of reporters. We consider this a significant coverage of the emissions, while impacting a relatively small portion of the industry. For a full discussion of the threshold analysis, please refer to the Glass Manufacturing TSD (EPA-HQ-OAR-2008-0508-014). For specific information on costs, including unamortized first year capital expenditures, please refer to section 4 of the RIA and the RIA cost appendix. 3. Selection of Proposed Monitoring Methods Many of the domestic and international GHG monitoring guidelines and protocols include methodologies for estimating process-related CO2 emissions from glass manufacturing (e.g., the 2006 IPCC Guidelines, U.S. Inventory, the Technical Guidelines for the DOE 1605(b), and the EU Emissions Trading System). These methodologies coalesce around four different options. Two options are output-based (production-based): One applies appropriate emission factors to the type of glass produced, and the other applies a default emission factor to total glass production. A third option is based on measuring the carbonate input to the furnace. The final option uses direct measurement to estimate emissions. Option 1. The first production-based option we considered applies a default emission factor to the total quantity of all glass produced, correcting for the amount of cullet supplied to the process. Option 2. The second production-based approach we considered applies default emission factors to each of the types of glass produced at the facility (e.g., container, flat, pressed and blown, and fiberglass). Option 3. The carbonate-input approach calculates emissions based on actual input data and the mass fractions of the carbonates that are volatilized and emitted as CO2. More specifically, this option considers the type, quantity, and mass fraction of carbonate inputs to the furnace and develops a facility-specific emission factor. Option 4. This approach directly measures emissions using a CEMS. CEMS can be used to measure both combustion-related and process-related CO2 emissions from glass melting [[Page 16509]] furnaces. These emissions generally are exhausted through a common furnace stack. Therefore, separate CEMS would not be needed to quantify both types of emissions from glass melting furnaces. Proposed Option. Under the proposed rule, if you are required to use an existing CEMS to meet the requirements outlined in proposed 40 CFR part 98, subpart C, you would be required to use CEMS to estimate CO2 emissions. Where the CEMS capture all combustion- and process-related CO2 emissions, you would be required to follow the requirements of proposed 40 CFR part 98, subpart C to estimate CO2 emissions from the industrial source. For facilities that do not currently have CEMS that meet the requirements outlined in proposed 40 CFR part 98, subpart C, or where the CEMS would not adequately account for process emissions, the proposed monitoring method would require estimating combustion emissions and process emissions separately. For combustion emissions, you would be required to follow the requirements of proposed 40 CFR part 98, subpart C to estimate emissions of CO2, CH4 and N2O from stationary combustion. For process emissions, the carbonate input approach (Option 3) is proposed. This section of the preamble provides only those procedures for calculating and reporting process-related emissions. To estimate process CO2 emissions from glass melting furnaces, we propose that facilities measure the type, quantity, and mass fraction of carbonate inputs to each furnace and apply the appropriate emission factors for the carbonates consumed. This method for determining process emissions is consistent with the IPCC Tier 3 method. The proposed rule distinguishes between carbonate-based minerals and carbonate-based raw materials used in glass production. Carbonate- based raw materials are fired in the furnace during glass manufacturing. These raw materials are typically limestone, which is primarily CaCO3; dolomite, which is primarily CaMg(CO3)CO2; and soda ash, which is primarily NaCO2CO3. Because it is the calcination of the mineral fraction of the raw material (e.g., CaCO3 fraction in limestone) that leads to CO2 emissions, the purity of the limestone or other carbonate input is important for emissions estimation. In order to assess the composition of the carbonate input, we propose that facilities use data from the raw material supplier to determine the carbonate-based mineral mass fraction of the carbonate- based raw materials charged to an affected glass melting furnace. As an alternative to using data provided by the supplier, facilities can assume a value of 1.0 for the mass fraction of the carbonate-based mineral in the carbonate-based raw material. We also propose that emissions are estimated under the assumption that 100 percent of the carbon in the carbonate-based raw materials is volatilized and released from the furnace as CO2. Using the carbonate-based mineral mass fractions, the carbonate-based raw material feed rates, and the emission factors, the mass emissions of CO2 emitted from a glass melting furnace can be determined. Using values of 1.0 for the carbonate-based mineral mass fractions is based on the assumption that the raw materials consist of 100 percent of the respective carbonate-based mineral (i.e., the limestone charged to the furnace consists of 100 percent CaCO3, the dolomite charged consists of 100 percent CaMg(CO3)2, and the soda ash consists of 100 percent Na3CO3). Using this assumption generally overestimates CO2 emissions. However, given the relative purity of the raw materials used to produce glass, this method provides accurate estimates of process CO2 emissions from glass melting furnaces, while avoiding the costs associated with sampling and analysis of the raw materials. We have concluded that the carbonate input method specified in the proposed option is more certain as it involves measuring the consumption of each carbonate material charged to a glass melting furnace. According to the 2006 IPCC Guidelines, the uncertainty involved in the proposed carbonate input approach is 1 to 3 percent; in contrast, the uncertainty with using the default emission factor and cullet ratio for the production-based approach is 60 percent. We considered use of a CO2 CEMS which does tend to provide the most accurate CO2 emissions measurements and can measure both the combustion- and process-related CO2 emissions. However, given the limited variability in the process inputs and outputs contributing to emissions from glass production, installation of CEMS would require significant additional burden to facilities given that few glass facilities currently have CO2 CEMS. We also considered, but decided not to propose, the production- based default emission factor-based approach referenced above for quantifying process-related CO2 emissions based on the quantity of glass produced. In general, the default emission factor method results in less certainty because the method involves multiplying production data by emission factors that are based on default assumptions regarding carbonate-based mineral content and degree of calcination. As part of normal business practices, glass manufacturing plants maintain the records that would be needed to calculate emissions under the proposed option. Given the greater accuracy associated with the input method and the minimal additional burden, we have determined that this requirement would not add additional burden to current practices at the facility, while providing accurate estimates of process-based CO2 emissions. The various approaches to monitoring GHG emissions are elaborated in the Glass Manufacturing TSD (EPA-HQ-OAR-2008-0508-014). 4. Selection of Procedures for Estimating Missing Data To estimate process emissions of CO2 based on carbonate input, data are needed on the carbonate chemical analysis of the carbonate-based raw materials and the carbonate-based raw material input rate (process feed rate). Glass manufacturing facilities must monitor raw material feed rate carefully in order to maintain product quality. Therefore, we do not expect missing data on raw material input to be an issue. However, if these data were missing, we propose requiring facilities to use average data from the previous and following months for the mass of carbonate-based raw materials charged to the furnace. Given that glass furnaces generally operate continuously at a relatively constant production rate, we do not expect much variation in the amounts of carbonates charged to the furnace from month to month. Furthermore, it would be unusual for a glass manufacturing plant to change its glass formulation. Therefore, we believe using average data from the previous and following months would provide a reliable estimate of raw materials charged. For missing data on carbonate-based mineral mass fractions, we propose requiring facilities to assume that the mass fraction of each carbonate-based mineral in the carbonate-based raw materials is 1.0. This assumption may result in a slight overestimate of emissions, but should still provide a reasonably accurate estimate of emissions for the period with missing data. 5. Selection of Data Reporting Requirements We propose that facilities report total annual emissions of CO2 from each affected continuous glass melting furnace, as well as any stationary fuel combustion emissions. The proposed [[Page 16510]] rule would also require facilities to report the quantity of each carbonate-based raw material charged to each continuous glass melting furnace in tons per year, and the quantity of glass produced by each continuous glass melting furnace. For facilities that calculate process emissions of CO2 based on the mass fractions of carbonate- based minerals, the proposed rule would require facilities to report those values. These data are requested because they provide the basis for calculating process-based CO2 emissions and are needed for us to understand the emissions data and verify the reasonableness of the reported emissions. The data on raw material composition and charge rates are needed to verify process-based emissions of CO2. The data on glass production are needed to verify that the reported quantities of raw materials charged to continuous furnaces are reasonable. The production data also can be used to identify potential outliers. A full list of data to be reported is included in proposed 40 CFR part 98, subparts A and N. 6. Selection of Records That Must Be Retained In addition to the data to be reported, we propose that facilities retain monthly records of the data used to calculate GHG emissions. This would include records of the amounts of each carbonate-based raw material charged to a continuous glass melting furnace and glass production (by type). This requirement would be consistent with current business practices and the reporting requirements for emissions of other pollutants for the glass manufacturing industry. The proposed rule also would require facilities to retain the results of all tests used to determine carbonate-based mineral mass fractions, as well as any other supporting information used in the calculation of GHG emissions. These data are directly used to calculate emissions that are reported and are necessary to enable verification that the GHG emissions monitoring and calculations were performed correctly. A full list of records that must be retained on site is included in proposed 40 CFR part 98, subparts A and N. O. HCFC-22 Production and HFC-23 Destruction 1. Definition of the Source Category This source category includes the generation, emissions, sales, and destruction of HFC-23. The source category includes facilities that produce HCFC-22, generating HFC-23 in the process. This source category also includes facilities that destroy HFC-23, which are sometimes, but not always, also facilities that produce HCFC-22. HFC-23 is generated during the production of HCFC-22. HCFC-22 is primarily employed in refrigeration and A/C systems and as a chemical feedstock for manufacturing synthetic polymers. Because HCFC-22 depletes stratospheric O3, its production for non-feedstock uses is scheduled to be phased out by 2020 under the CAA. Feedstock production, however, is permitted to continue indefinitely. HCFC-22 is produced by the reaction of chloroform (CHCl3) and hydrogen fluoride (HF) in the presence of a catalyst, SbClB5. In the reaction, the chlorine in the chloroform is replaced with fluorine, creating HCFC-22. Some of the HCFC-22 is over-fluorinated, producing HFC-23. Once separated from the HCFC-22, the HFC-23 may be vented to the atmosphere as an unwanted by- product, captured for use in a limited number of applications, or destroyed. 2006 U.S. emissions of HFC-23 from HCFC-22 production were estimated to be 13.8 million metric tons CO2e. This quantity represents a 13 percent decline from 2005 emissions and a 62 percent decline from 1990 emissions despite an 11 percent increase in HCFC-22 production since 1990. Both declines are primarily due to decreases in the HFC-23 emission rate. The ratio of HFC-23 emissions to HCFC-22 production has decreased from 0.022 to 0.0077 since 1990, a reduction of 66 percent. These decreases have occurred because an increasing fraction of U.S. HCFC-22 production capacity has adopted controls to reduce HFC-23 emissions. Three HCFC-22 production facilities operated in the U.S. in 2006, two of which used recapture and/or thermal oxidation to significantly lower their HFC-23 emissions. All three plants are part of a voluntary agreement to report and reduce their collective HFC-23 emissions. The production of HCFC-22 and destruction of HFC-23 causes both combustion and HFC-23 emissions. HCFC-22 production and HFC-23 destruction facilities are required to follow the requirements of proposed 40 CFR part 98, subpart C to estimate emissions of CO2, CH4 and N2O from stationary fuel combustion. This section of the preamble provides only those procedures for calculating and reporting generation, emissions, sales, and destruction of HFC-23. For additional background information on HCFC-22 production, please refer to the HCFC-22 Production and HFC-23 Destruction TSD (EPA-HQ-OAR- 2008-0508-015). 2. Selection of Reporting Threshold We propose that all facilities producing HCFC-22 be required to report under this rule. Facilities destroying HFC-23 but not producing HCFC-22 would be required to report if they destroyed more than 25,000 metric tons CO2e of HFC-23. For HCFC-22 production facilities, we considered emission-based thresholds of 1,000 metric tons CO2e, 10,000 metric tons CO2e, 25,000 metric tons CO2e and 100,000 metric tons CO2e and capacity-based thresholds equivalent to these. The capacity-based thresholds are shown in Table O-1 of this preamble, and are based on full utilization of HCFC-22 capacity and the emission rate given for older plants in the 2006 IPCC Guidelines. (One plant is relatively new, but the emission rate for older plants was used to be consistent and somewhat conservative.) Table O-1. Capacity-Based Thresholds -------------------------------------------------------------------------------------------------------------------------------------------------------- Total national Emissions covered Facilities covered emissions Total national --------------------------------------------------------------- Threshold level (HCFC-22 capacity in tons) (metric tons facilities Metric tons CO2e) CO2e/yr Percent Facilities Percent -------------------------------------------------------------------------------------------------------------------------------------------------------- 2....................................................... 13,848,483 3 13,848,483 100 3 100 21...................................................... 13,848,483 3 13,848,483 100 3 100 53...................................................... 13,848,483 3 13,848,483 100 3 100 214..................................................... 13,848,483 3 13,848,483 100 3 100 -------------------------------------------------------------------------------------------------------------------------------------------------------- [[Page 16511]] Our analysis showed that all of the facilities, which have capacities ranging from 18,000 to 100,000 metric tons of HCFC-22, exceeded all of the capacity-based thresholds by wide margins. The smallest plant exceeded the largest capacity-based threshold by a factor of 85. We are not presenting a table for emission-based thresholds because we do not have facility-specific emissions information. (Under the voluntary emission reduction agreement, total emissions from the three facilities are aggregated by a third party, who submits only the total to us.) Since two of the three facilities destroy or capture most or all of their HFC-23 by-product, one or both of them probably have emissions below at least some of the emission-based thresholds discussed above. However, if the thermal oxidizers malfunctioned, were not operated properly, or were unused for some other reason, emissions of HFC-23 from each of the plants could easily exceed all thresholds. Reporting is therefore important both for tracking the considerable emissions of facilities that do not use thermal oxidation and for verifying the performance of thermal oxidation where it is used. For this reason, we propose that all HCFC-22 manufacturers report their HFC-23 emissions. We are aware of one facility that destroys HFC-23 but does not produce HCFC-22. Although we do not know the precise quantity of HFC-23 destroyed by this facility, the Agency has concluded that the facility destroys a substantial share of the HFC-23 generated by the largest HCFC-22 production facility in the U.S. If the destruction facility destroys even one percent of this HFC-23, it is likely to destroy considerably more than the proposed threshold of 25,000 metric tons CO2e. For additional background information on the threshold analysis for HCFC-22 production, please refer to the HCFC-22 Production and HFC-23 Destruction TSD (EPA-HQ-OAR-2008-0508-015). For specific information on costs, including unamortized first year capital expenditures, please refer to section 4 of the RIA and the RIA cost appendix. 3. Selection of Proposed Monitoring Methods a. Review of Monitoring Methods In developing these proposed requirements, we reviewed several protocols and guidance documents, including the 2006 IPCC Guidelines, guidance developed under our voluntary program for HCFC-22 manufacturers, the WRI/WBCSD protocols, the TRI, the TSCA Inventory Update Rule, The DOE 1605(b) Voluntary Reporting Program, EPA Climate Leaders, and TRI. We also considered the findings and conclusions of a recent report that closely reviewed the methods that facilities use to estimate and assure the quality of their estimates of HCFC-22 production and HFC-23 emissions. As noted above, the production facilities currently estimate and report these quantities to us (across all three plants) under a voluntary agreement. The report, by RTI International, is entitled ``Verification of Emission Estimates of HFC-23 from the Production of HCFC-22: Emissions from 1990 through 2006'' and is available in the docket for this rulemaking. The 2008 Verification Report found that the estimation methods used by the three HCFC-22 facilities currently operating in the U.S. were all equivalent to IPCC Tier 3 methods. Under the Tier 3 methodology, facility-specific emissions are estimated based on direct measurement of the HFC-23 concentration and the flow rate of the streams, accounting for the use of emissions abatement devices (thermal oxidizers) where they are used. In general, Tier 3 methods for this source category yield far more accurate estimates than Tier 2 or Tier 1 methods. Even at the Tier 3 level, however, the emissions estimation methods used by the three facilities differed significantly in their levels of absolute uncertainty. The uncertainty of the one facility that does not thermally destroy its HFC-23 emissions dominates the uncertainty for the national emissions from this source category. In general, the methods proposed in this rule are very similar to the procedures already being undertaken by the facilities to estimate HFC-23 emissions and to assure the quality of these estimates. The differences (and the rationale for them) are discussed in the HCFC-22 Production and HFC-23 Destruction TSD (EPA-HQ-OAR-2008-0508-015). b. Proposed Monitoring Methods This section of the preamble includes two proposed monitoring methods for HCFC-22 production facilities and one for HFC-23 destruction facilities. The proposed monitoring methods differ for HCFC-22 facilities that do and do not use a thermal oxidizer connected to the HCFC-22 production equipment. All the monitoring methods rely on measurements of HFC-23 concentrations in process or emission streams and on measurements of the flow rates of those streams, although the proposed frequency of these measurements varies. Proposed Methods for Estimating HFC-23 Emissions from Facilities that Do Not Use a Thermal Oxidizer or Facilities that Use a Thermal Oxidizer that is Not Directly Connected to the HCFC-22 Production Equipment. Under the proposed rule, you would be required to: (1) Monitor the concentration of HFC-23 in the reaction product stream containing the HFC-23 (which could be either the HCFC-22 or the HCl product stream) on at least a daily basis. This proposed requirement is intended to account for day-to-day fluctuations in the rate at which HFC-23 is generated; this rate can vary depending on process conditions. (2) Monitor the mass flow of the product stream containing the HFC- 23 either directly or by weighing the other reaction product. The other product could be either HCFC-22 or HCl. Plants would be required to make or sum these measurements on at least a daily basis. If the HCFC- 22 or HCl product were measured significantly downstream of the reactor (e.g., at storage tanks or the shipping dock), facilities would be required to add a factor that accounted for losses to the measurement. This factor would be 1.5 percent or another factor that could be demonstrated, to the satisfaction of the Administrator, to account for losses. This adjustment is intended to account for upstream product losses, which are estimated to range from one to two percent. Without the adjustment, HCFC-22 production and therefore HFC-23 generation at affected facilities would be systematically underestimated (negatively biased). A one-to two-percent underestimate could translate into an underestimate of HFC-23 emissions of 100,000 metric tons CO2e or more for each affected facility. We request comment on this proposed approach for compensating for the negative bias caused by HCFC-22 emissions. We specifically request comment on the 1.5 percent factor, which is the midpoint of the one-to- two-percent range of product loss rates cited by the affected facility. We also request comment on what methods and data would be required to verify a loss rate other than 1.5 percent, if a facility wished to demonstrate a lower loss rate. One option would be a mass-balance approach using measurements with very fine precisions (e.g., 0.2 percent or better). (3) Facilities that do not use a thermal oxidizer connected to the HCFC-22 [[Page 16512]] production equipment would also be required to estimate the mass of HFC-23 produced either by multiplying the HFC-23 concentration measurement by the mass flow of the stream containing both the HFC-23 and the other product or by multiplying the ratio of the concentrations of HFC-23 and of the other product by the mass of the other product. (4) Facilities would also be required to measure the masses of HFC- 23 sold or sent to other facilities for destruction. This step would ensure that any losses of HFC-23 during filling of containers were included in the HFC-23 emission estimates for facilities that capture HFC-23 for use as a product or for transfer to a destruction facility. (5) Facilities would also be required to estimate the HFC-23 emitted by subtracting the masses of HFC-23 sold or sent for destruction from the mass of HFC-23 generated. This calculation assumes that all production that is not sold or sent to another facility for destruction is emitted. Such emissions may be the result of the packaging process; additional emissions can be attributed to the number of flanges in a line and other on-site equipment that is specific to each facility. Proposed Methods for Estimating HFC-23 Emissions from Plants that Use a Thermal Oxidizer Connected to the HCFC-22 Production Equipment. Under the proposed rule, you would be required to estimate HFC-23 emissions from equipment leaks, process vents, and the thermal oxidizer. To estimate emissions from leaks, you would be required to estimate the number of leaks using EPA Method 21 of 40 CFR part 60, Appendix A-7 and a leak definition of 10,000 ppmv. Leaks registering above and below 10,000 ppmv would be assigned different default emission rates, depending on the component and service (gas or light liquid). These leak rates would be drawn from Table 2-5 from the Protocol for Equipment Leak Estimates (EPA-453/R-95-017) and data on the concentration of HFC-23 in the process stream.\78\ (The relevant portions of Table 2-5 are included in the proposed regulatory text for this rule.) To estimate emissions from process vents, you would be required to use the results of annual emissions tests at process vents, adjusting for changes in HCFC-22 production rates since the measurements occurred. Tests would have to be conducted in accordance with EPA Method 18 of 40 CFR part 60, Appendix A-6, Measurement of Gaseous Organic Compounds by Gas Chromatography. Although HFC-23 emissions from process vents are believed to be quite low, this monitoring would ensure that any year-to-year variability in the emission rate was captured by the reporting. Finally, to estimate emissions from the thermal oxidizer, you would be required to apply the DE of the oxidizer to the mass of HFC-23 fed into the oxidizer. --------------------------------------------------------------------------- \78\ Although EPA recognizes that the proposed method for estimating emissions from equipment leaks is rather uncertain, EPA believes that the level of precision is not unreasonable given the small size of the HFC-23 emissions that would be estimated using the method. These emissions are estimated to account for a fraction of a percent of U.S. HFC-23 emissions from this source. --------------------------------------------------------------------------- Destruction. Under the proposed rule, if you use thermal oxidation to destroy HFC-23 you would be required to measure the quantities of HFC-23 fed into the oxidizer. You would also be required to account for any decreases in the DE of the oxidizer that occurred when the oxidizer was not operating properly (as defined in State or local permitting requirements and/or oxidizer manufacturer specifications). Finally, you would be required to perform annual HFC-23 concentration measurements by gas chromatography to confirm that emissions from the oxidizer were as low as expected based on the rated DE of the device. If emissions were found to be higher, then facilities would have the option of using the DE implied by the most recent measurements or of conducting more extensive measurements of the DE of the device. As discussed in the HCFC-22 Production and HFC-23 Destruction TSD (EPA-HQ-OAR-2008-0508-015), the initial testing and parametric monitoring that facilities currently perform on their oxidizers provides general assurance that the oxidizer is performing correctly. However, the proposed requirement to measure HFC-23 concentrations at the oxidizer outlet would provide additional assurance at relatively low cost. Even a one- or two-percent decline in the DE of the oxidizer could lead to emissions of over 100,000 metric tons CO2e, making this a particularly important factor to monitor accurately. Startups, shutdowns, and malfunctions. Under the proposed rule, if you produce HCFC-22 you would be required to account for HFC-23 production and emissions that occur as a result of startups, shutdowns, and malfunctions. This would be done either by recording HFC-23 production and emissions during these events, or documenting that these events do not result in significant HFC-23 production and/or emissions. Depending on the circumstances, startups, shutdowns, and malfunctions (including both the process equipment and any thermal oxidation equipment) can be significant sources of emissions, and the Agency believes that emissions during these process disturbances should therefore be tracked. Precision and Accuracy Requirements. We are proposing to require that HCFC-22 production facilities and HFC-23 destruction facilities monitor the masses that would be reported under this rule using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of 1.0 percent of full scale or better. Our understanding is that some HCFC-22 production facilities currently use devices with this level of accuracy and precision. However, flowmeters with considerably better precisions are available, e.g., 0.2 percent. We request comment on the option of requiring plants to use flowmeters or scales with an accuracy and precision of 0.2 percent or some other precision better than 1 percent. Given the large quantities of HFC-23 generated by each plant, this higher precision may be appropriate. We are also proposing to require that HCFC-22 production facilities and HFC-23 destruction facilities measure concentrations using equipment and methods with an accuracy and precision of 5 percent or better at the concentrations of the samples. Calibration Requirements. Under the proposed rule, if you produce HCFC-22 or destroy HFC-23 you would be required to perform the following activities to assure the quality of their measurements and estimates: (1) Calibrate gas chromatographs used to determine the concentration of HFC-23 by analyzing, on a monthly basis, certified standards with known HFC-23 concentrations that are in the same range (percent levels) as the process samples. This proposed requirement is intended to verify the accuracy and precision of gas chromatographs at the concentrations of interest; calibration at other concentrations does not verify this accuracy with the same level of assurance. The proposed requirement is similar to requirements in protocols for the use of gas chromatography, such as EPA Method 18, Measurement of Gaseous Organic Compound Emissions by Gas Chromatography. (2) Initially verify each weigh scale, flow meter, and combination of volumetric and density measurements used to measure quantities that are to be reported under this rule, and calibrate it thereafter at least every year. We request comment on these proposed requirements. [[Page 16513]] 4. Selection of Procedures for Estimating Missing Data We are proposing that in the cases when an upstream flow meter (i.e., near reactor outlet) is ordinarily used but is not available for some period, the facility can compensate by using downstream production measures (e.g., quantity shipped) and adding 1.5 percent to account for product losses. If HFC-23 concentration measurements are unavailable for some period, we propose that the facility use the average of the concentration measurements from just before and just after the period of missing data. There is one proposed exception to these requirements: If either method would result in a significant under- or overestimate of the missing parameter (e.g., because the monitoring failure was linked to a process disturbance that is likely to have significantly increased the HFC-23 generation rate), then the facility would be required to develop an alternative estimate of the parameter and explain why and how it developed that estimate. We request comment on these methods for estimating missing data. We also request comment on the option of estimating missing production data based on consumption of reactants, assuming complete stoichiometric conversion. 5. Selection of Data Reporting Requirements If you produce HCFC-22 and do not use a thermal oxidizer connected to the HCFC-22 production equipment, you would be required to report the total mass of the HFC-23 generated in metric tons, the mass of any HFC-23 packaged for sale in metric tons, the mass of any HFC-23 sent off site for destruction in metric tons, and the mass of HFC-23 emitted in metric tons. If you produce HCFC-22 and destroy HFC-23 using a thermal oxidizer connected to the HCFC-22 production equipment, you would be required to report the mass of HFC-23 emitted from the thermal oxidizer, the mass of HFC-23 emitted from process vents, and the mass of HFC-23 emitted from equipment leaks, in metric tons. In addition, if you produce HCFC-22 you would also be required to submit the following supplemental data, as applicable, for QA purposes: Annual HCFC-22 production, annual consumption of reactants (including factors to account for quantities that typically remain unreacted), by reactant, annual mass of materials other than HCFC-22 and HFC-23 (i.e., unreacted reactants, HCl and other byproducts) that are permanently removed from the process, and the method for tracking startups, shutdowns, and malfunctions and HFC-23 generation/emissions during these events. You would also be required to report the names and addresses of facilities to which any HFC-23 was sent for destruction, and the quantities sent to each. Where HCFC-22 production facilities have estimated missing data, you would be required to report the reason the data were missing, the length of time the data were missing, the method used to estimate the missing data, and the estimates of those data. Where the missing data was estimated by a method other than one of those specified, the owner or operator would be required to report why the specified method would lead to a significant under- or overestimate of the parameter(s) and the rationale for the methods used to estimate the missing data. If you destroy HFC-23, you would be required to report the mass of HFC-23 fed into the thermal oxidizer, the mass of HFC-23 destroyed, and the mass of HFC-23 emitted from the thermal oxidizer. You would also be required to submit the results of your annual HFC-23 concentration measurements at the outlet of the oxidizer. In addition, you would be required to submit a one-time report similar to that required under EPA's stratospheric protection regulations at 40 CFR 82.13(j). We propose that facilities report these data either because the data are necessary to verify facilities' calculations of HFC-23 generation, emissions, or destruction or because the data allow us to implement other QA checks (e.g., calculation of an HFC-23/HCFC-22 generation factor that can be compared across facilities and over time). We request comment on these proposed reporting requirements. 6. Selection of Records That Must Be Retained If you produce HCFC-22, you would be required to keep records of the data used to estimate emissions and records documenting the initial and periodic calibration of the gas chromatographs, scales, and flowmeters used to measure the quantities reported under this rule. If you destroy HFC-23, you would be required to keep records of information documenting your one-time and annual reports. These records are necessary to enable verification that the GHG emissions monitoring and calculations were performed correctly. P. Hydrogen Production 1. Definition of the Source Category Approximately nine million metric tons of hydrogen are produced in the U.S. annually. Hydrogen is used for industrial applications such as petrochemical production, metallurgy, and food processing. Some of the largest users of hydrogen are ammonia production facilities, petroleum refineries, and methanol production facilities. About 95 percent of all hydrogen produced in the U.S. today is made from natural gas via steam methane reforming. This process consists of two basic chemical reactions: (1) Reformation of the CH4 feedstock with high temperature steam supplied by burning natural gas to obtain a synthesis gas (CH4 + H2O = CO + 3H2); and (2) Using a water-gas shift reaction to form hydrogen and CO2 from the carbon monoxide produced in the first step (CO + H2O = CO2 + H22). Other processes used for hydrogen production include steam naptha reforming, coal or biomass gasification, partial oxidation of coal or hydrocarbons, autothermal reforming, electrolysis of water, recovery of byproduct hydrogen from electrolytic cells used to produce chlorine and other products, and dissociation of ammonia. Hydrogen is produced in large quantities at approximately 77 merchant hydrogen production facilities (which produce hydrogen to sell) and 145 captive hydrogen production facilities (which consume hydrogen at the site where it is produced, e.g. petroleum refineries, ammonia, and methanol facilities). Hydrogen is also produced in small quantities at numerous other locations. National emissions from hydrogen production were estimated to be approximately 60 million metric tons CO2 (1 percent of U.S. GHG emissions) annually. The source category covered by the hydrogen production subpart of the proposed rule is merchant hydrogen production. CO2 emissions from captive hydrogen production facilities at ammonia facilities, petrochemical facilities, and petroleum refineries are covered in proposed 40 CFR part 98, subparts G, X, and Y, respectively. For additional background information on hydrogen production, please refer to the Hydrogen Production TSD (EPA-HQ-OAR-2008-0508-016). 2. Selection of Reporting Threshold In developing the threshold for hydrogen production, we considered emissions-based thresholds of 1,000 [[Page 16514]] metric tons CO2e, 10,000 metric tons CO2e, 25,000 metric tons CO2e and 100,000 metric tons CO2e. This threshold is based on combined combustion and process CO2 emissions at the hydrogen production facility. In selecting a threshold, we considered emissions data from merchant hydrogen facilities only, which together account for an estimated 15.2 million metric tons CO2e in 2006. Table P-1 of this preamble illustrates the emissions and facilities that would be covered under these various thresholds. Table P-1. Threshold Analysis for Hydrogen Production ---------------------------------------------------------------------------------------------------------------- H2 Production Emissions covered Facilities covered CO2 Threshold level (metric tons capacity (tons --------------------------------------------------------------- CO2e/year) H2/year) Tons CO2e/year Percent Number Percent ---------------------------------------------------------------------------------------------------------------- No threshold.................... 0 15,226,620 100.0 77 100 1,000........................... 116 15,225,220 100.0 73 95 10,000.......................... 1,160 15,130,255 99.4 51 66 25,000.......................... 2,900 14,984,365 98.4 41 53 100,000......................... 11,600 14,251,265 93.6 30 39 ---------------------------------------------------------------------------------------------------------------- The hydrogen production industry is heterogeneous in terms of the types of facilities. There are some relatively large, emissions intensive facilities, but small facilities are common as well. At a 25,000 ton threshold, although 98.4 percent of emissions would be covered, only 53 percent of facilities would be required to report. The proposed threshold for reporting emissions from hydrogen production is 25,000 metric tons CO2e. We are proposing a 25,000 metric tons CO2e threshold to reduce the compliance burden on small businesses, while still including a majority of GHG emissions from the industry. For a full discussion of the threshold analysis, please refer to the Hydrogen Production TSD (EPA-HQ-OAR-2008-0508-016). For specific information on costs, including unamortized first year capital expenditures, please refer to section 4 of the RIA and the RIA cost appendix. 3. Selection of Proposed Monitoring Methods Several domestic and international GHG monitoring guidelines and protocols include methodologies for estimating process-related emissions from hydrogen production (e.g., the American Petroleum Institute Compendium, the DOE 1605(b), and the CARB Mandatory GHG Emissions Reporting Program). These methods coalesce around variants of two methods for merchant hydrogen production facilities: Direct measurement of CO2 emissions by CEMS, and the feedstock material balance method. Option 1. Direct measurement. The CEMS would capture both combustion and process-related CO2 emissions from a hydrogen facility. Facilities that do not currently employ a CEMS could voluntarily elect to install CEMS for reporting under this subpart. This approach is consistent with DOE's 1605(b) ``A'' rated method and the CARB Mandatory GHG Emissions Reporting Program. Option 2. Feedstock material balance method. This method accounts for the difference between the quantity and carbon content of all feedstock delivered to the facility and of all products leaving the facility. This approach is consistent with IPCC Tier 3 methods for similar processes (i.e., steam reformation in ammonia production), the DOE 1605(b) ``A'' rated method, and the CARB Mandatory GHG Emissions Reporting Program. Based on our review of the above approaches, we propose both methods for quantifying GHG emissions from hydrogen production, to be implemented depending on current circumstances at your facility. If you are required to use an existing CEMS to meet the requirements outlined in proposed 40 CFR part 98, subpart C, you would be required to use CEMS to estimate CO2 emissions. Where the CEMS capture combustion- and process-related CO2 emissions you would be required to follow the calculation procedures, monitoring and QA/QC methods, missing data procedures, reporting requirements, and recordkeeping requirements of proposed 40 CFR part 98, subpart C to estimate CO2 emissions from the industrial source. Also, refer to proposed 40 CFR part 98, subpart C to estimate combustion- related emissions from fuels not captured in the CEMS, as well as CH4 and N2O. For facilities that do not currently have CEMS that meet the requirements outlined in proposed 40 CFR part 98, subpart C, or where the CEMS does not measure process emissions, the proposed monitoring method is Option 2. You would be required to follow the calculation procedures, monitoring and QA/QC methods, missing data procedures, reporting requirements, and recordkeeping requirements of proposed 40 CFR part 98, subpart C to estimate combustion-related emissions from each hydrogen production unit and any other stationary combustion units. This section of the preamble provides only those procedures for calculating and reporting process-related CO2 emissions. For CO2 collected and used onsite or transferred offsite, you must follow the methodology provided in proposed 40 CFR part 98, subpart PP of this part (Suppliers of CO2). The feedstock material balance method entails measurements of the quantity and carbon content of all feedstock delivered to the facility and of all products leaving the facility, with the assumption that all the carbon entering the facility in the feedstock that is not captured and sold outside the facility is converted to CO2 and emitted. The quantity of feedstock consumed must be measured continuously using a flowmeter. The carbon fraction in the feedstock may be provided as part of an ultimate analysis performed by the supplier (e.g., the local gas utility in the case of natural gas feedstock). If the feedstock supplier does not provide the gas composition or ultimate analysis data, the facility would be required to analyze the carbon content of the feedstock on a monthly basis using the appropriate test method in proposed 40 CFR 98.7. We also considered three other methods for quantifying process- related emissions. The first method requires direct measurement of emissions by CEMS from all reporting facilities. The second method applies a constant proportionality factor, based on the facility's historical data on natural gas consumption, to the facility's hydrogen production rate. The third method we [[Page 16515]] considered applies a national default emission factor to the natural gas consumption rate at a facility. The first method would generally increase accuracy of reported data. We invite comment on the practicality of adopting the first method. In general, the latter two methods are less certain, as they involve multiplying production and feedstock consumption data by default emission factors based on purity assumptions. In contrast, the feedstock material balance method is more certain as it involves measuring the consumption and carbon content of the feedstock input. Because 95 percent of hydrogen is produced using steam methane reforming, and the carbon content of natural gas is always within 1 percent of the ratio: One mole of carbon per mole of natural gas, the local utility QA/QC requirements should be more than adequate. Given the increase in accuracy of the direct measurement and feedstock material balance methods coupled with the minimal additional burden for facilities that already employ CEMS, we propose that facilities utilize the direct measurement method where currently employed, and the feedstock material balance method for all facilities that do not employ CEMS. We have concluded that this requirement does not add additional burden to current practices at the facilities, thereby minimizing costs. The primary additional burden for facilities associated with this method would be in conducting a gas composition analysis of the feedstock on a monthly basis, in cases where this information is not provided by the supplier. The various approaches to monitoring GHG emissions are elaborated in the Hydrogen Production TSD (EPA-HQ-OAR-2008-0508-016). 4. Selection of Procedures for Estimating Missing Data Sources using CEMS to comply with this rule would be required to comply with the missing data requirements of proposed 40 CFR part 98, subpart C. In the event that a facility lacks feedstock supply rates for a certain time period, we propose that facilities use the lesser of the maximum supply rate that the unit is capable of processing or the maximum supply rate that the meter can measure. In the event that a monthly value for carbon content is determined to be invalid, an additional sample must be collected and tested. The likelihood for missing data is small, since the fuel meter and carbon content data are needed for financial accounting purposes. 5. Selection of Data Reporting Requirements We propose that facilities submit their annual CO2, and N2O emissions data. Facilities that use CEMS must comply with the procedures specified in proposed 40 CFR 98.36(d)(iv). In addition, we propose that facilities submit the following data on an annual basis for each process unit. These data are needed for us to understand the emissions data and verify the reasonableness of the reported emissions, and are the basis of the feedstock material balance calculation. The data should include the total quantity of feedstock consumed for hydrogen production, the quantity of CO2 captured for use and the end use, if known, the monthly analyses of carbon content for each feedstock used in hydrogen production, the annual quantity of hydrogen produced, and the annual ammonia produced, if applicable. A full list of data to be reported is included in proposed 40 CFR part 98, subparts A and P. 6. Selection of Records That Must Be Retained We propose that each hydrogen production facility comply with the applicable recordkeeping requirements for stationary combustion units in proposed 40 CFR part 98, subpart C, which are also discussed in Section V.C of this preamble. Also, we propose that each hydrogen production facility maintain records of feedstock consumption and the method used to determine the quantity of feedstock consumption, QA/QC records (including calibration records and any records required by the QAPP), monthly carbon content analyses, and the method used to determine the carbon content. A full list of records that must be retained onsite is included in proposed 40 CFR part 98, subparts A and P. These records consist of values that are directly used to calculate the emissions that are reported and are necessary to enable verification that the GHG emissions monitoring and calculations were done correctly. Q. Iron and Steel Production 1. Definition of the Source Category The iron and steel industry in the U.S. is the third largest in the world, accounting for about 8 percent of the world's raw iron and steel production and supplying several industrial sectors, such as construction (building and bridge skeletons and supports), vehicle bodies, appliances, tools, and heavy equipment. In this proposed rule, we are defining the iron and steel production source category to be taconite iron ore processing facilities, integrated iron and steelmaking facilities, electric arc furnace steelmaking facilities that are not located at integrated iron and steel facilities, and cokemaking facilities that are not located at integrated iron and steel facilities. Coke, sinter, and electric arc furnace steel production operations at integrated iron and steel facilities are part of integrated iron and steel facilities. Direct reduced iron furnaces are located at and are part of electric arc furnace steelmaking facilities. Currently, there are 18 integrated iron and steel steelmaking facilities that make iron from iron ore and coke in a blast furnace and refine the molten iron (and some ferrous scrap) in a basic oxygen furnace to make steel. In addition, there are over 90 electric arc furnace steelmaking facilities that produce steel primarily from recycled ferrous scrap. There are also eight taconite iron ore (pellet) processing facilities, 18 cokemaking facilities, seven of which are co- located at integrated iron and steel facilities, and one direct reduced iron furnace located at an electric arc furnace steelmaking facility. The primary operation units that emit GHG emissions are blast furnace stoves (24 million metric tons CO2e/yr), taconite indurating furnaces, basic oxygen furnaces, electric arc furnaces (about 5 million metric tons CO2e/yr each), coke oven battery combustion stacks (6 million metric tons CO2e/yr), and sinter plants (3 million metric tons CO2e/yr). Smaller amounts of GHG emissions are produced by coke pushing (160,000 metric tons CO2e/yr) and direct reduced iron furnaces (140,000 metric tons CO2e/yr). Based on production in 2007, GHG emissions from the source category are estimated at about 85 million metric tons CO2e/yr or just over 1 percent of total U.S. GHG emissions. Emissions from both process units (47 million metric tons CO2e/yr) and miscellaneous combustion units (38 million metric tons CO2e/ yr) are significant. Small amounts of N2O and CH4 are also emitted during the combustion of different types of fuels. Although by-product recovery coke batteries and blast furnaces operations produce coke and pig iron, respectively, we are proposing that their emissions be reported as required for combustion units in proposed 40 CFR part 98, subpart C because the majority of their GHG emissions originate from fuel combustion. Emissions from the blast furnace operation occur primarily from the combustion of blast furnace gas and [[Page 16516]] natural gas in the blast furnace stoves. Emissions from by-product recovery coke batteries are generated from the combustion of coke oven gas in the coke battery's underfiring system. In addition to the blast furnace stoves and by-product coke battery underfiring systems, the other combustion units where fuel is the only source of GHG emissions include boilers, process heaters, reheat and annealing furnaces, flares, flame suppression systems, ladle reheaters, and other miscellaneous sources. Emissions from these other combustion sources in 2007 are estimated at 16.8 million metric tons CO2e/yr for integrated iron and steel facilities, 18.6 million metric tons CO2e/yr for electric arc furnace steelmaking facilities, and 2.7 million metric tons CO2e/yr for coke facilities not located at integrated iron and steel facilities. As noted, the proposed requirements for combustion units in proposed 40 CFR part 98, subpart C would apply for estimating the CO2, CH4, and N2O emissions from the following combustion units: • By-product recovery coke oven battery combustion stacks. • Blast furnace stoves. • Boilers. • Process heaters. • Reheat furnaces. • Annealing furnaces. • Flares. • Ladle reheaters. • Other miscellaneous combustion sources. Emissions from the remaining operation units are generated from the carbon in process inputs and in some cases, from fuel combustion in the process. The process-related CO2, CH4 and N2O emissions from the operation units listed below except for coke pushing would be reported according to the proposed requirements in this section: • Taconite indurating furnaces. • Nonrecovery coke oven battery combustion stacks. • Coke pushing. • Basic oxygen furnaces. • Electric arc furnaces. • Direct reduced iron furnaces. • Sinter plants. Emissions from nonrecovery coke batteries do not result from the combustion of a fuel input. In the nonrecovery battery, the volatiles that evolve as the coal is heated are ignited in the crown above the coal mass and in flues used to heat the oven. All of the combustible compounds distilled from the coal are burned, and the exhaust gases containing CO2 are emitted through the battery's combustion stack. For all types of coke batteries, a small amount of CO2 is formed when the incandescent coke is pushed from the oven, and prior to quenching with water, some of the coke burns. The CO2 emissions from taconite plants come primarily from the indurating furnaces where coal and/or natural gas are burned in the pelletizing process, and carbon in the process feed materials (iron ore, limestone, bentonite) is converted to CO2. The CO2 emissions from direct reduced iron furnaces result from the combustion of natural gas in the furnace and from the process inputs, primarily from the carbonaceous materials (such as coal or coke) that is mixed with iron ore. During steelmaking in the basic oxygen furnace, most of the GHGs result from blowing oxygen into the molten iron to produce steel by removing carbon, primarily as CO2. CO2 emissions also result from the addition of fluxing materials and other process inputs that may contain carbon. Emissions from electric arc furnaces are produced by the same mechanisms as for basic oxygen furnaces, and in addition, the consumption of carbon electrodes during the melting and refining stages contribute to CO2 emissions. Emissions of CH4 and N2O occur from the combustion of fuels in both combustion units and process units. For fuels that contain CH4, combustion of CH4 is not complete, and a small amount of CH4 is not burned and is emitted. In addition, a small amount of N2O can be formed as a by-product of combustion from the air (nitrogen and oxygen) that is required for combustion. Additional background information about GHG emissions from the iron and steel production source category is available in the Iron and Steel Production TSD (EPA-HQ-OAR-2008-0508-017). 2. Selection of Reporting Threshold In evaluating potential thresholds for iron and steel production, we considered emissions-based thresholds of 1,000 metric tons CO2e, 10,000 metric tons CO2e, 25,000 metric tons CO2e, and 100,000 metric tons CO2e per year. This threshold is based on combined combustion and process CO2 emissions at an iron and steel production facility. Table Q-1 of this preamble illustrates that the various thresholds do not have a significant effect on the amount of emissions that would be covered. To avoid placing a reporting burden on the smaller specialty stainless steel producers which may operate as small businesses while still requiring the reporting of GHG emissions from those facilities releasing most of the GHG emissions in this source category, we are proposing a threshold of 25,000 metric tons CO2e per year for reporting of emissions. This threshold level is consistent with the threshold level being proposed for other source categories with similar facility size characteristics. We are proposing that facilities emitting greater than 25,000 in the iron and steel production source category would be subject to the proposed rule because of the magnitude of their emissions. All integrated iron and steel facilities and taconite facilities exceed the highest emissions threshold considered. Most electric arc furnace facilities (with the possible exception of about 9 facilities) exceed the 25,000 metric tons CO2e emissions threshold. Requiring facilities that emit 25,000 metric tons CO2e a year or more to report would capture nearly 100 percent of the emissions without significantly increasing the number of affected facilities. For a full discussion of the threshold analysis, refer to the Iron and Steel Production TSD (EPA-HQ-OAR-2008-0508-017). For specific information on costs, including unamortized first year capital expenditures, please refer to section 4 of the RIA and the RIA cost appendix. Table Q-1. Threshold Analysis for Iron and Steel Production -------------------------------------------------------------------------------------------------------------------------------------------------------- Total national Emissions covered Facilities covered emissions Total number --------------------------------------------------------------- Threshold level metric tons CO2e (metric tons of facilities Metric tons CO2e) CO2e/yr Percent Number Percent -------------------------------------------------------------------------------------------------------------------------------------------------------- all in.................................................. 85,150,877 130 85,150,877 100 130 100 1,000................................................... 85,150,877 130 85,150,877 100 130 100 10,000.................................................. 85,150,877 130 85,141,500 100 128 98 25,000.................................................. 85,150,877 130 85,013,059 100 121 93 [[Page 16517]] 100,000................................................. 85,150,877 130 84,468,696 99.2 111 85 -------------------------------------------------------------------------------------------------------------------------------------------------------- 3. Selection of Proposed Monitoring Methods Many domestic and international GHG monitoring guidelines and protocols include methodologies for estimating emissions from process and combustion sources (e.g. 2006 IPCC Guidelines, U.S. Inventory, the WBCSD/WRI GHG protocol, DOE 1605(b), TCR, EU Emissions Trading System, the American Iron and Steel Institute Protocol, International Iron and Steel Institute Protocol, and Environment Canada's mandatory reporting guidelines). We considered these methodologies for measuring or estimating GHG emissions from the iron and steel source category. The following five options were considered for reporting process-related CO2 emissions from these sources. Option 1. Apply a default emission factor based on the type of process and an annual activity rate (e.g. quantity of raw steel, sinter, or direct reduced iron produced). This option is the same as the IPCC Tier 1 approach. Option 2. Perform a carbon balance of all inputs and outputs using default or typical values for the carbon content of the inputs and outputs. Facility production and other records would be used to determine the annual quantity of process inputs and outputs. CO2 emissions from the difference of carbon-in minus carbon- out, assuming all is converted to CO2, would be calculated. This option is the same as the IPCC Tier 2 approach, the WRI default approach, and the DOE 1605(b) approach that is rated ``B.'' It is similar to the approach recommended by American Iron and Steel Institute except that the carbon balance for Option 2 is based on the individual processes rather than the entire plant. Option 3. Perform a monthly carbon balance of all inputs and outputs using measurements of the carbon content of specific process inputs and process outputs and measure the mass rate of process inputs and process outputs. Calculate CO2 emissions from the difference of carbon-in minus carbon-out assuming all is converted to CO2. This is consistent with an IPCC Tier 3 approach (if direct measurements are not available), the WRI/WBCSD preferred approach, the approach used in the EU Emissions Trading System, and the DOE 1605(b) approach that is rated ``A.'' Option 4. Develop a site-specific emission factor based on simultaneous and accurate measurements of CO2 emissions and production rate or process input rate during representative operating conditions. Multiply the site-specific factor by the annual production rate or appropriate periodic production rate (or process input rate, as appropriate). This approach is included in Environment Canada's methodologies and might be considered a form of direct measurement consistent with the IPCC's Tier 3 approach. Option 5. Direct and continuous measurement of CO2 emissions using CEMS for CO2 concentration and stack gas volumetric flow rate based on the requirements in 40 CFR part 75. This is the IPCC Tier 3 approach (direct measurement). Proposed option. Under this proposed rule, if you are required to use an existing CEMS to meet the requirements outlined in proposed 40 CFR part 98, subpart C, you would be required to use CEMS to estimate CO2 emissions. Where the CEMS capture all combustion- and process-related CO2 emissions you would be required to follow the requirements of proposed 40 CFR part 98, subpart C to estimate CO2 emissions from the industrial source. Also, you would use proposed 40 CFR part 98, subpart C to estimate combustion- related CH4 and N2O. If you do not currently have CEMS that meet the requirements outlined in proposed 40 CFR part 98, subpart C, or where the CEMS would not adequately account for process emissions, we propose that Options 3, 4 or 5 could be implemented. You would be required to follow the requirements of proposed 40 CFR part 98, subpart C to estimate emissions of CO2, CH4 and N2O from stationary combustion. This section of the preamble provides procedures only for calculating and reporting process-related emissions. We identified Options 3, 4, and 5 as the approaches that have acceptable uncertainty for facility-specific estimates. All of these options would provide insight into different levels of emissions caused by facility-specific differences in feedstock or process operation. Options 3, 4, and 5 are forms of the IPCC's highest tier methodology (Tier 3), therefore, we propose these options as equal options. After consideration of public comments, we may promulgate one or more of the options or a combination based on the additional information that is provided. We considered but decided against Options 1 and 2 because the use of default values and lack of direct measurements results in a very high level of uncertainty in the emission estimates. These default approaches would not provide site-specific estimates of emissions that would reflect differences in feedstocks, operating conditions, fuel combustion efficiency, variability in fuels and other differences among facilities. In general, we decided against proposing existing methodologies that relied on default emission factors or default values for carbon content of materials because the differences among facilities described above could not be discerned, and such default approaches are inherently inaccurate for site-specific determinations. The use of default values is more appropriate for sector wide or national total estimates from aggregated activity data than for determining emissions from a specific facility. According to the IPCC's 2006 guidelines, the uncertainty associated with default emission factors for Options 1 and 2 is ±25 percent, and the uncertainty in the production data used with the default emission factor is ±10 percent, which results in a combined overall uncertainty greater than ±25 percent. If process-specific carbon contents and actual mass rate data for the process inputs and outputs are used (i.e., Option 3) or if direct measurements are used (i.e., Options 4 and 5), the guidelines state that the uncertainty associated with the emission estimates would be reduced. For Option 3, we are proposing that facilities may estimate process emissions based on a carbon balance that uses facility-specific information on the carbon content of process inputs and outputs and measurements of the mass rate of process inputs and outputs. Monthly determinations of the mass of process inputs and outputs other than [[Page 16518]] fuels would be required. These data are readily available for almost all process inputs and outputs on a monthly basis from purchasing, accounting, and production records that are routinely maintained by each facility. The mass rates of fuels would be measured according to the procedures for fuels in combustion units in proposed 40 CFR part 98, subpart C. The carbon content of each process input and output other than fuels would also be measured each month. A sample would be taken each week, composited for the monthly analysis, and sent to an independent laboratory for analysis of carbon content using the test methods in proposed 40 CFR part 98, subpart A. The carbon content of fuels would be determined using the procedures for fuels in combustion units in proposed 40 CFR part 98, subpart C. The CO2 emissions would be estimated each month using the carbon balance equations in the proposed rule and then summed to provide the totals for the quarter and for the year. While this proposed approach is consistent with how iron and steel production facilities are currently developing facility level GHG inventories, there are three components of this approach for which the Agency is requesting comment and supporting information. One issue is the ability to obtain accurate measurements of the process inputs and outputs, especially materials that are bulk solids and molten metal and slag. A second issue is the ability to obtain representative samples of the process inputs and outputs to determine the carbon content, especially for non-homogenous materials such as iron and steel scrap. The third issue is the level of uncertainty in the emission estimates for processes where there is a significant amount of carbon leaving the process with product (such as coke plants). These and other factors may result in an unacceptable level of uncertainty, especially for certain processes, when using the carbon balance approach to estimate emissions. While we are proposing that emissions from blast furnace stoves and coke battery combustion stacks be reported as would be required for combustion sources under proposed 40 CFR part 98, subpart C, we are also requesting comment on how the carbon balance approach (Option 3) could be implemented as an alternative monitoring option for the entire blast furnace operation and the entire coke plant operation at integrated iron and steel facilities. Comments should address the advantages, disadvantages, types and frequency of measurements that should be required, and whether (and if so, how) the emissions can be determined with reasonable certainty. Comments must demonstrate that the procedures produce results that are reproducible and clearly specify the sampling methods and QA procedures that would ensure accurate results. For the site-specific emission factor approach (Option 4), the owner or operator may conduct a performance test and determine CO2 emissions from all exhaust stacks for the process using EPA reference methods to continuously measure the CO2 concentration and stack gas volumetric flow rate during the test. In addition, either the feed rate of materials into the process or the production rate during the test would be measured. The performance test would be conducted under normal process operating conditions and at a production rate no less than 90 percent of the process rated capacity. For continuous processes (taconite indurating furnaces, non-recovery coke batteries, and sinter plants), the testing would cover at least nine hours of continuous operation. For batch or cyclic processes (basic oxygen furnaces, electric arc furnaces, and direct reduction furnaces), the testing would cover at least nine complete production cycles that start when the furnace is being charged and end after steel or iron and slag have been tapped. We are proposing testing for nine hours or nine production cycles, as applicable, because nine tests should provide a reasonable measure of variability (i.e., the standard deviation for nine production cycles or nine 1-hour runs). If an electric arc furnace is used to produce both carbon steel and low carbon steel (including stainless or specialty steel), separate emission factors would be developed for carbon steel and low carbon steel. The site-specific emission factor for the process would be calculated in metric tons CO2 per metric ton of feed or production, as applicable, by dividing the CO2 emission rate by the feed or production rate. The CO2 emissions for the process would be calculated by multiplying the emission factor by the total amount of feed or production, as applicable. A new performance test would be required each year to develop a new site-specific emission factor. Whenever there is a significant change in fuel type or mix, change in the process in a manner that affects energy efficiency by more than 10 percent, or a change in the process feed materials in a manner that changes the carbon content of the feed or fuel by more than 10 percent, a new performance test would be conducted and a new site- specific emission factor calculated. We are also requesting comment on the advantages and disadvantages of Option 4, along with supporting documentation. We have concluded that there may be situations in which the site-specific emission factor approach may result in an uncertainty lower than that associated with the carbon balance approach and provide more reasonable emission estimates. An example is nonrecovery coke plants, where a carbon balance approach may result in an unacceptably high level of uncertainty from subtracting two very large numbers (carbon in with coal and carbon out with coke) to estimate emissions that could instead be accurately and directly measured at the combustion stack. The primary sources of variability that affect CO2 emissions from process sources in general are the carbon content of the process inputs and fuel and any changes to the process that alter energy efficiency. For most processes, the carbon content of process inputs and fuels is consistent and stable, and if a process change alters energy efficiency, a re-test could be performed to develop a new emission factor that reflected the change. We are requesting comment and supporting information on the minimum time or number of production cycles needed for testing to develop a representative emission factor, and how often periodic re-testing should be required (e.g., annually, quarterly, or only when there is a process change). We are also requesting that any comments on Option 4 address how changes in process inputs, fuels, or process energy efficiency should be accounted for, such as requiring a re-test if the carbon content of inputs change by more than some specified percent, if the type or mix of fuel is changed, or if there is a significant change in fuel consumption due to a process change. We are also proposing that you may use direct measurements, noting that CEMS (Option 5) provide the lowest uncertainty of the three options. This approach overcomes many of the limitations associated with other options considered such as accounting for the variability in emissions due to changes in the process, feed materials, or fuel over time. It would be applied to stacks that are already equipped with sampling ports and access platforms; consequently, it is technically feasible and cost effective. For those emission sources already equipped with CEMS, we are proposing that they be modified (if necessary) and used to determine CO2 emissions for that emission source. We are proposing this requirement [[Page 16519]] because it provides direct emission measurements that have low uncertainty with only a minimal additional cost burden. We also request comment, along with supporting documentation, on the advantages and disadvantages of Option 5. We are also proposing that CH4 and N2O emissions from the combustion of fuels in both combustion units and process units be determined and reported. All of the fuels used at iron and steel production processes are included in the methodologies in proposed 40 CFR part 98, subpart C for N2O and CH4. Consequently, EPA is proposing to use the same methodology as in proposed 40 CFR part 98, subpart C for determining and reporting emissions of N2O and CH4 from both stationary combustion units and process units. Miscellaneous Emissions Sources. Emissions may also occur when the incandescent coke is pushed from the coke oven and transported to the quench tower where it is cooled (quenched) with water. A small portion of the coke burns during this process prior to quenching. We updated the coke oven section of the AP-42 \79\ compilation of emission factors in May 2008, and the update included an emission factor for CO2 emissions developed from 26 tests for particulate matter from pushing operations. The emissions factor (0.008 metric tons CO2e per metric ton of coal charged) was derived to account for emissions from the pushing emission control device and those escaping the capture system. We are proposing that coke facilities use the AP-42 emission factor to estimate CO2 emissions from coke pushing operations. --------------------------------------------------------------------------- \79\ See Compilation of Air Pollutant Emission Factors, Fifth Edition: http://www.epa.gov/ttn/chief/ap42/ch12/final/c12s02_may08.pdf. --------------------------------------------------------------------------- There are dozens of emission points and various types of fugitive emissions, not collected for emission through a stack, from the production processes and materials handling and transfer activities at integrated iron and steel facilities. These emissions from iron and steel plants have been of environmental interest primarily because of the particulate matter in the emissions. Examples include ladle metallurgy operations, desulfurization, hot metal transfer, sinter coolers, and the charging and tapping of furnaces. The information we have examined to date indicates that these emissions contribute very little to the overall GHG emissions from the iron and steel sector (probably on the order of one percent or less). For example, emissions of blast furnace gas may be emitted during infrequent process upsets (called ``slips'') when gas is vented for a short period or from leaks in the ductwork that handles the gas. However, the mass of GHG emissions is expected to be small because most of the carbon in blast furnace gas is from carbon monoxide, which is not a GHG. Fugitive emissions and emissions from control device stacks may also occur from blast furnace tapping, the charging and tapping of basic oxygen furnaces and electric arc furnaces, ladle metallurgy, desulfurization, etc. However, we have no information that indicates CO2 is generated from these operations, and a review of test reports from systems that capture these emissions show that CO2 concentrations are very low (at ambient air levels). Fugitive emissions containing CH4 may occur from leaks of raw coke oven gas from the coke oven battery during the coking cycle. However, the mass of these emissions is expected to be small based on the small number of leaks that are now allowed under existing Federal and State standards that regulate these emissions. In addition, since these emissions are not captured in a conveyance, there is no practical way to measure them. Consequently, we are not proposing that fugitive emissions be reported because we believe their GHG content is negligible and because there is no practical way of measuring them. However, we welcome public comment, along with supporting data and documentation, on whether fugitive emissions should be included, and if so, how these emissions can be estimated. 4. Selection of Procedures for Estimating Missing Data For process sources that use Option 3 (carbon balance) or Option 4 (site-specific emission factor), no missing data procedures would apply because 100 percent data availability would be required. For process sources that use Option 5 (direct measurement by CEMS), the missing data procedures would be the same as for units using Tier 4 in the general stationary fuel combustion source category in proposed 40 CFR part 98, subpart C. 5. Selection of Data Reporting Requirements We are proposing that facilities submit annual emission estimates for CO2 presented by calendar quarters for coke oven battery combustion stacks, coke pushing, blast furnace stoves, taconite indurating furnaces, electric arc furnaces, argon-oxygen decarburization vessel, direct reduced iron furnaces, and sinter plants. In addition we propose that facilities submit the following data to assist in checks for reasonableness and for other data quality considerations: Total mass for all process inputs and outputs when the carbon balance is used for specific processes by calendar quarters, site-specific emission factor for all processes for which the site- specific emission factor approach is used, annual production quantity for taconite pellets, coke, sinter, iron, raw steel by calendar quarters, annual production capacity for taconite pellets, coke, sinter, iron, raw steel, annual operating hours for taconite furnaces, coke oven batteries, sinter production, blast furnaces, direct reduced iron furnaces, and electric arc furnaces, and the quantity of CO2 captured for use and the end use, if known. A full list of data that would be reported is included in proposed 40 CFR part 98, subparts A and Q. 6. Selection of Records That Must Be Retained In addition to the recordkeeping requirements for general stationary fuel combustion sources, we propose that the following additional records be kept to assist in QA/QC and verification purposes: GHG emission estimates from the iron and steel production process by calendar quarter, monthly total for all process inputs and outputs when the carbon balance is used for specific processes, documentation of calculation of site-specific emission factor for all processes for which the site-specific emission factor approach is used, monthly analyses of carbon content, and monthly production quantity for taconite pellets, coke, sinter, iron, and raw steel. R. Lead Production 1. Definition of the Source Category Lead is a metal used to produce various products such as batteries, ammunition, construction materials, electrical components and accessories, and vehicle parts. For this proposed rule, we are defining the lead production source category to consist of primary lead smelters and secondary lead smelters. A primary lead smelter produces lead metal from lead sulfide ore concentrates through the use of pyrometallurgical processes. A secondary lead smelter produces lead and lead alloys from lead-bearing scrap metal. For the primary lead smelting process used in the U.S., lead sulfide ore concentrate is first fed to a sintering process to burn sulfur from the lead ore. The sinter is smelted with a [[Page 16520]] carbonaceous reducing agent in a blast furnace to produce molten lead bullion. From the furnace, the bullion is transferred to dross kettle furnaces to remove primarily copper and other metal impurities. Following further refining steps, the lead is cast into ingots or alloy products. The predominate feed materials processed at U.S. secondary lead smelters are used automobile batteries, but these smelters can also process other lead-bearing scrap materials including wheel balance weights, pipe, solder, drosses, and lead sheathing. These incoming lead scrap materials are first pre-treated to partially remove metal and nonmetal contaminants. The resulting lead scrap is smelted (U.S. secondary lead smelters typically use either a blast furnace or reverberatory furnace). The molten lead from the smelting furnace is refined in kettle furnaces, and then cast into ingots or alloy products. Lead production results in both combustion and process-related GHG emissions. Combustion-related CO2, CH4, and N2O emissions are generated from metallurgical process equipment used at primary and secondary lead smelters when natural gas or another fuel is burned in the unit to produce heat for drying, roasting, sintering, calcining, melting, or casting operations. Process-related CO2 emissions are released from the lead smelting process due to the addition of a carbonaceous reducing agent such as metallurgical coke or coal to the smelting furnace. The reduction of lead oxide to lead metal during the process produces the CO2 emissions. Currently there is one primary lead smelter operating in the U.S. There are 26 secondary lead smelters in the U.S. with widely varying annual lead production capacities ranging from approximately 1,000 metric tons to more than 100,000 metric tons. Total national GHG emissions from lead production in the U.S. were estimated to be approximately 0.9 million metric tons CO2e in 2006. These emissions include both on-site stationary combustion emissions (CO2, CH4, and N2O) and process- related emissions (CO2). The majority of these emissions were from the combustion of carbon-based fuels. Combustion GHG emissions were 0.6 million metric tons CO2e emissions (69 percent of the total emissions). The remaining 0.3 million metric tons CO2e (31 percent of the total emissions) were process- related GHG emissions. Additional background information about GHG emissions from the lead production source category is available in the Lead Production TSD (EPA-HQ-OAR-2008-0508-018). 2. Selection of Reporting Threshold In developing the threshold for lead production facilities, we considered using annual GHG emissions-based threshold levels of 1,000 metric tons CO2e, 10,000 metric tons CO2e, 25,000 metric tons CO2e and 100,000 metric tons CO2e. This threshold is based on combined combustion and process CO2 emissions at the lead production facility. Table R-1 of this preamble presents the estimated emissions and number of facilities that would be subject to GHG emissions reporting, based on existing facility lead production capacities, under these various threshold levels. Table R-1. Threshold Analysis for Lead Smelters -------------------------------------------------------------------------------------------------------------------------------------------------------- Emissions covered Facilities covered Total Nationwide --------------------------------------------------------------- Threshold level metric tons CO2e/yr nationwide number of metric tons Facility emissions facilities CO2e/yr Percent number Percent -------------------------------------------------------------------------------------------------------------------------------------------------------- 1,000................................................... 866,000 27 859,000 99 17 63 10,000.................................................. 866,000 27 853,000 98 16 59 25,000.................................................. 866,000 27 798,000 92 13 48 100,000................................................. 866,000 27 0 0 0 0 -------------------------------------------------------------------------------------------------------------------------------------------------------- Secondary lead smelters in the U.S. vary greatly in production capacity and include 10 small facilities with production capacities less than 4,000 tons per year. Table R-1 of this preamble shows approximately 92 percent of the GHG emissions that result from lead production are released from the one primary smelter and 12 secondary smelters that emit more than 25,000 metric tons CO2e annually. Of the facilities with annual GHG emissions below 25,000 metric tons CO2e, 10 secondary smelters are estimated to emit less than 1,000 metric tons CO2e annually. To avoid placing a reporting burden on the smaller secondary lead smelters which may operate as small businesses while still requiring the reporting of GHG emissions from those facilities releasing most of the GHG emissions in this source category, we are proposing a threshold of 25,000 metric tons CO2e per year for reporting of emissions. This threshold level is consistent with the threshold level being proposed for other source categories with similar facility size characteristics. More discussion of the threshold selection analysis is available in the Lead Production TSD (EPA-HQ-OAR-2008-0508-018). For specific information on costs, including unamortized first year capital expenditures, please refer to section 4 of the RIA and the RIA cost appendix. 3. Selection of Proposed Monitoring Methods We reviewed existing domestic and international GHG monitoring guidelines and protocols including the 2006 IPCC Guidelines for National Greenhouse Gas Inventories, U.S. GHG Inventory, the EU Emissions Trading System, the Canadian Mandatory Greenhouse Gas Reporting Program, and the Australian National Greenhouse Gas Reporting Program. These methods coalesce around the following four options for estimating process-related CO2 emissions from lead production facilities. A full summary of methods reviewed is available in the Lead Production TSD (EPA-HQ-OAR-2008-0508-018). Option 1. Apply a default emission factor for the process-related emissions to the facility's lead production rate. This is a simplified emission calculation method using only default emission factors to estimate process-related CO2 emissions. The method requires multiplying the amount of lead produced by the appropriate default emission factors from the 2006 IPCC Guidelines. This method is consistent with the IPCC Tier 1 method. Option 2. Perform monthly measurements of the carbon content of specific process inputs and measure the mass rate of these inputs. This is the IPCC Tier 3 approach and the higher order methods in the Canadian and Australian reporting programs. Implementation of this method requires owners and operators of affected lead smelters to determine the carbon [[Page 16521]] contents of materials added to the smelting furnace by analysis of representative samples collected of the material or from information provided by the material suppliers. In addition, you must measure and record the quantities of these input materials consumed during production. To obtain the process-related CO2 emission estimate, the material carbon content would be multiplied by the corresponding mass of the carbon-containing input material consumed and a conversion factor of carbon to CO2. This method assumes that all of the carbon is converted to CO2 during the reduction process. The facility owner or operator would determine the average carbon content of the material for each calendar month using information provided by the material supplier or by collecting a composite sample of material and sending it to an independent laboratory for chemical analysis. Option 3. Use CO2 emissions data from a stack test performed using EPA reference test methods to develop a site-specific process emissions factor which is then applied to quantity measurement data of feed material or product for the specified reporting period. This monitoring method is applicable to furnace configurations for which the GHG emissions are contained within a stack or vent. Using site-specific emissions factors based on short-term stack testing is appropriate for those facilities where process inputs (e.g., feed materials, carbonaceous reducing agents) and process operating parameters remain relatively consistent over time. Option 4. Use direct emission measurement of CO2 emissions. For furnace configurations in which the process off-gases are contained within a stack or vent, direct measurement of the CO2 emissions can be made by continuously measuring the off- gas stream CO2 concentration and flow rate using a CEMS. For a smelting furnace used for lead production where both combustion and process-related emissions are released by a source (e.g. blast furnace) emissions reported by using a CEMS would be total CO2 emissions including both combustion and process-related CO2 emissions. Proposed Option. Under this proposed rule, if you are required to use an existing CEMS to meet the requirements outlined in proposed 40 CFR part 98, subpart C, you would be required to use CEMS to estimate CO2 emissions. Where the CEMS capture all combustion- and process-related CO2 emissions you would be required to follow requirements of proposed 40 CFR part 98, subpart C to estimate CO2 emissions. Also, refer to proposed 40 CFR part 98, subpart C to estimate combustion-related CH4 and N2O. For facilities that do not currently have CEMS that meet the requirements outlined in proposed 40 CFR part 98, subpart C, or where CEMS would not adequately account for combustion and process related CO2 emissions, the proposed monitoring method for process- related CO2 from lead production is Option 2. You would be required to follow the calculation procedures, monitoring and QA/QC methods, missing data procedures, reporting requirements, and recordkeeping requirements of proposed 40 CFR part 98, subpart C to estimate emissions of CO2, CH4 and N2O from stationary combustion. This section of the preamble provides procedures only for calculating and reporting process-related emissions. We propose Option 2, due to the operating variations between the individual U.S. lead production facilities, including differences in equipment configurations, mix of lead feedstocks charged, and types of carbon materials used. Further, Option 2 would result in lower uncertainty as compared to applying a default emissions factor based approach to these units. Although we are not proposing to require you to directly measure process emissions, unless you meet the requirements of proposed 40 CFR part 98, subpart C and the CEMS account for both combustion and process-relate emissions, you could opt to use direct measurement of CO2 emissions as an alternative GHG emissions estimation method because it would best reflect actual operating practices at your facility, and therefore, reduce uncertainty. While we recognize that the costs for conducting direct measurements may be higher than other methods, we are proposing to include this alternative because it provides GHG emissions data that have low uncertainty. The additional cost burden may be acceptable to owners and operators with site- specific reasons for choosing this alternative. We decided not to propose the use of the default CO2 emission factors (Option 1) because their application is more appropriate for GHG estimates from aggregated process information on a sector-wide or nationwide basis than for determining GHG emissions from specific facilities. We considered the additional burden of the material measurements required for the carbon calculations under Option 2 small in relation to the increased accuracy expected from using this site-specific information to calculate the process-related CO2 emissions. We also decided not to propose Option 3 because of the potential for significant variations at lead smelters in the characteristics and quantities of the furnace inputs (e.g., lead scrap materials, carbonaceous reducing agents) and process operating parameters. A method using periodic, short-term stack testing would not be practical or appropriate for those lead smelters where the furnace inputs and operating parameters do not remain relatively consistent over the reporting period. Further details about the selection of the monitoring methods for GHG emissions is available in the Lead Production TSD (EPA-HQ-OAR-2008- 0508-018). 4. Selection of Procedures for Estimating Missing Data For smelting furnaces for which the owner or operator calculates process GHG emissions using site-specific carbonaceous input material data, the proposed rule requires the use of substitute data whenever a quality-assured value of a parameter that is used to calculate GHG emissions is unavailable, or ``missing.'' If the carbon content analysis of carbon inputs is missing or lost the substitute data value would be the average of the quality-assured values of the parameter immediately before and immediately after the missing data period. In those cases when an owner or operator uses direct measurement by a CO2 CEMS, the missing data procedures would be the same as the Tier 4 requirements described for general stationary fuel combustion sources in proposed 40 CFR part 98, subpart C. The likelihood for missing data is low, as businesses closely track their purchase of production inputs. 5. Selection of Data Reporting Requirements The proposed rule would require annual reporting of the total annual CO2 process-related emissions from each smelting furnace at lead production facilities, as well as any stationary fuel combustion emissions. In addition, we are proposing that additional information that forms the basis of the emissions estimates also be reported so that we can understand and verify the reported emissions. This addition information includes the total number of smelting furnaces operated at the facility, the facility lead product production capacity, the annual facility production quantity, annual quantity and type of carbon-containing input [[Page 16522]] materials consumed or used, annual weighted average carbon contents by material type, and the number of facility operating hours in the calendar year. A complete list of data to be reported is included in proposed 40 CFR part 98, subparts A and R. 6. Selection of Records That Must Be Retained Maintaining records of the information used to determine the reported GHG emissions is necessary to enable us to verify that the GHG emissions monitoring and calculations were done correctly. In addition to the information reported as described in Section V.R.5 of this preamble, we propose that all facilities estimating emissions according to the carbon input method maintain records of each carbon-containing input material consumed or used (other than fuel) the monthly material quantity, monthly average carbon content determined for material, and records of the supplier provided information or analyses used for the determination. If you use the CEMS procedure, you would maintain the CEMS measurement records according to the procedures in proposed 40 CFR part 98, subpart C. These records would be required to be maintained onsite for 5 years. A complete list of records to be retained is included in the proposed rule. S. Lime Manufacturing 1. Definition of the Source Category Lime is an important manufactured product with many industrial, chemical, and environmental applications. Its major uses are in steel making, flue gas desulfurization systems at coal-fired electric power plants, construction, and water purification. Lime is used for the following purposes: Metallurgical uses (36 percent), environmental uses (29 percent), chemical and industrial uses (21 percent), construction uses (13 percent), and to make dolomite refractories (1 percent). For U.S. operations, the term ``lime'' actually refers to a variety of chemical compounds. These compounds include calcium oxide (CaO), or high-calcium quicklime; calcium hydroxide (Ca(OH)2), or hydrated lime; dolomitic quicklime ((CaO[bul]MgO)); and dolomitic hydrate ((Ca(OH)2[bul]MgO) or (Ca(OH)2[bul]Mg(OH)2)). Lime manufacturing involves three main processes: Stone preparation, calcination, and hydration. During the calcination process, the carbonate in limestone is sufficiently heated and reduced to CO2 gas. In certain applications, lime reabsorbs CO2 during use thereby reducing onsite GHG emissions. National emissions from the lime industry were estimated to be 25.4 million metric tons CO2e in 2004 (or <0.4 percent of national emissions). These emissions include both process-related emissions and on-site stationary combustion emissions from 89 lime manufacturing facilities across the U.S. and Puerto Rico. Process- related emissions account for 14.3 million metric tons CO2e, or 56 percent of the total, while on-site stationary combustion emissions account for the remaining 11.1 million metric tons CO2e. For additional background information on lime manufacturing, please refer to the Lime Manufacturing TSD (EPA-HQ-OAR-2008-0508-019). 2. Selection of Reporting Threshold In developing the proposed reporting threshold for the lime manufacturing source category, we considered emissions-based thresholds of 1,000 metric tons CO2e, 10,000 metric tons CO2e, 25,000 metric tons CO2e and 100,000 metric tons CO2e. This threshold is based on combined combustion and process CO2 emissions at a lime production facility. Table S-1 of this preamble illustrates the emissions and facilities that would be covered under various thresholds. Table S-1. Threshold Analysis for Lime Manufacturing -------------------------------------------------------------------------------------------------------------------------------------------------------- Total national Emissions covered Facilities covered emissions Total number --------------------------------------------------------------- Threshold level metric tons CO2e/yr metric tons of facilities metric tons CO2e/yr CO2e/yr Percent Number Percent -------------------------------------------------------------------------------------------------------------------------------------------------------- 1,000................................................... 25,421,043 89 25,421,043 100 89 100 10,000.................................................. 25,421,043 89 25,396,036 99.9 86 97 25,000.................................................. 25,421,043 89 25,371,254 99.8 85 96 100,000................................................. 25,421,043 89 23,833,273 94 52 58 -------------------------------------------------------------------------------------------------------------------------------------------------------- The lime manufacturing sector consists primarily of large facilities and a few smaller facilities. All facilities, except four, exceed the 25,000 metric tons CO2e threshold. Consistent with National Lime Association recommendations, and in order to simplify the proposed rule and avoid the need to calculate and report whether the threshold value has been exceeded, we are proposing that all lime manufacturing facilities report GHG emissions. This captures 100 percent of emissions without significantly increasing the number of facilities that would have reported at 1,000, 10,000, or 25,000 metric ton thresholds. For a full discussion of the threshold analysis, please refer to the Lime Manufacturing TSD (EPA-HQ-OAR-2008- 0508-019). For specific information on costs, including unamortized first year capital expenditures, please refer to section 4 of the RIA and the RIA cost appendix. 3. Selection of Proposed Monitoring Methods Many domestic and international GHG monitoring guidelines and protocols include methodologies for estimating process-related emissions from lime manufacturing (e.g., the 2006 IPCC Guidelines, U.S. Inventory, DOE 1605(b), National Lime Association CO2 Protocol, and the EU Emissions Trading System). These methodologies can be summarized by the following two overall approaches to estimating emissions, based on measuring either the carbonate inputs to the kiln or production outputs of the lime manufacturing process. Input-based Options. We considered the IPCC Tier 3 method which requires facilities to estimate process emissions by measuring the quantity of carbonate inputs to the kiln(s) and applying the appropriate emission factors and calcination fractions to the carbonates consumed. In order to assess the composition of carbonate inputs, facilities would send samples of their inputs and lime kiln dust produced to an off-site laboratory for analysis on a monthly basis using ASTM C25-06, ``Standard Test Methods for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime'' (incorporated by reference, see proposed 40 CFR 98.7). For greater accuracy, facilities would [[Page 16523]] also estimate the calcination fraction of each carbonate consumed on a monthly basis. However, it is generally accepted that the calcination fraction of carbonates during lime production is 100 percent or very close to it. Output-based Options. We also considered three output-based methods for quantifying process-related emissions based on the quantity of lime produced. IPCC's Tier 1 method applies default emission factors to each of the three types of lime produced (high calcium lime, dolomitic lime, or hydraulic lime). The IPCC Tier 2 method applies a default emissions factor based on lime type to the corresponding quantity of all lime produced (by type), correcting for the amount of calcined byproduct/ waste product (such as lime kiln dust) produced in the process. The third output method, developed by the National Lime Association, improves upon the IPCC Tier 2 procedure. In this method, facilities multiply the amount of lime produced at each kiln and the amount of calcined byproducts/wastes at the kiln by an emission factor. The emission factor is derived based on facility specific chemical analysis of the CaO and magnesium oxide (MgO) content of the lime produced at the kiln. To assess the composition of the lime and calcined byproduct/waste product, facilities would send samples to an off-site laboratory for analysis on a monthly basis following the procedures described in the National Lime Association's method protocol, along with the procedures in ASTM C25-06, ``Standard Test Methods for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime'' (incorporated by reference, see proposed 40 CFR 98.7). This third output approach is also consistent with 1605(b)'s ``A'' rated approach and EU Emission Trading System's calculation B method. We compared the various methods for estimating process-related CO2 emissions. In general, the IPCC output methods are less certain, as they involve multiplying production data by emission and correction factors for lime kiln dust that are likely default values based on purity assumptions (i.e. the total CaO and MgO content of the lime products). In contrast, the input method is more certain as it involves measuring the consumption of each carbonate input and calculating purity fractions. According to the 2006 IPCC Guidelines, the uncertainty involved in the carbonate input approach for the IPCC Tier 3 method is 1 to 3 percent and the uncertainty involved in using the default emission factor and lime kiln dust correction factor for the Tier 1 and Tier 2 production-based approaches is 15 percent. However, IPCC states that the major source of uncertainty in the above approaches is the CaO content of the lime produced. Proposed Option. Under this proposed rule, if you are using an existing CEMS that meets the requirements outlined in proposed 40 CFR part 98, subpart C, you would be required to use CEMS to estimate CO2 emissions. Where the CEMS capture all combustion- and process-related CO2 emissions you would be required to follow the requirements of proposed 40 CFR part 98, subpart C to estimate both combustion and process CO2 emissions. Also, you would refer to proposed 40 CFR part 98, subpart C to estimate combustion-related CH4 and N2O emissions. Under this proposed rule, if you do not have CEMS that meet the conditions outlined in proposed 40 CFR part 98, subpart C, you would use the National Lime Association method in this section of the preamble to calculate process-related CO2 emissions. Refer to proposed 40 CFR part 98, subpart C specifically for procedures to estimate combustion-related CO2, CH4 and N2O emissions. We are proposing the National Lime Association's output-based procedure because this method is already in use by U.S. facilities and the improvement in accuracy compared to default approaches can be achieved at minimal additional cost. The measurement of production quantities is common practice in the industry and is usually measured through the use of scales or weigh belts so additional costs to the industry are not anticipated. The primary additional burden for facilities would include conducting a CaO and MgO analysis of each lime product on a monthly basis (to be averaged on an annual basis). However, approximately two thirds of the lime manufacturing facilities in the U.S. are already undertaking sampling efforts to meet reporting goals set forth by the National Lime Association. We request comment on the advantages and disadvantages of the IPCC Tier 3 method and supporting documentation. After consideration of public comments, we may promulgate the IPCC Tier 3 input-based procedure, the National Lime Association output-based procedure, or a combination based on additional information that is provided. The various approaches to monitoring GHG emissions are elaborated in the Lime Manufacturing TSD (EPA-HQ-OAR-2008-0508-019). 4. Selection of Procedures for Estimating Missing Data It is assumed that a facility would be able to supply facility- specific production data. Since the likelihood for missing data is low because businesses closely track production, 100 percent data availability is required for lime production (by type) in the proposed rule. If analysis for the CaO and MgO content of the lime product are unavailable or ``missing'', facility owners or operators would substitute a data value that is the average of the quality-assured values of the parameter immediately before and immediately after the missing data period. 5. Selection of Data Reporting Requirements We propose that in addition to stationary fuel combustion GHG emissions, you report annual CO2 emissions for each kiln. In addition, for each kiln we are proposing that facilities report the following data used as the basis of the calculations to assist in verification of estimates, checks for reasonableness, and other data quality considerations for process emissions: Annual lime production and production capacity, emission factor by lime type, and number of operating hours in the calendar year. A full list of data to be reported is included in proposed 40 CFR part 98, subparts A and S. 6. Selection of Records That Must be Retained Maintaining records of the information used to determine the reported GHG emissions are necessary to enable us to verify that the GHG emissions monitoring and calculations were done correctly. In addition to the data to be reported, we are proposing that the facilities maintain records of the calculation of emission factors, results of the monthly chemical composition analyses, total lime production for each kiln by month and type, total annual calcined byproducts/wastes produced by each kiln averaged from monthly data, and correction factor for byproducts/waste products for each kiln. A full list of records that must be retained onsite is included in proposed 40 CFR part 98, subparts A and S. T. Magnesium Production 1. Definition of the Source Category Magnesium is a high-strength and light-weight metal that is important for the manufacture of a wide range of products and materials, such as portable electronics, automobiles, and other machinery. The U.S. accounts for less than 10 percent of world primary [[Page 16524]] magnesium production but is a significant importer of magnesium and producer of cast parts. The production and processing of magnesium metal under common practice results in emissions of SF6. For further information, see the Magnesium Production TSD (EPA-HQ-OAR-2008- 0508-020). The magnesium metal production (primary and secondary) and casting industry typically uses SF6 as a cover gas to prevent the rapid oxidation and burning of molten magnesium in the presence of air. A dilute gaseous mixture of SF6 with dry air and/or CO2 is blown over molten magnesium metal to induce and stabilize the formation of a protective crust. A small portion of the SF6 reacts with the magnesium to form a thin molecular film of mostly magnesium oxide and magnesium fluoride. The amount of SF6 reacting in magnesium production and processing is under study but is presently assumed to be negligible. Thus, all SF6 used is presently assumed to be emitted into the atmosphere. Cover gas systems are typically used to protect the surface of a crucible of molten magnesium that is the source for a casting operation and to protect the casting operation itself (e.g., ingot casting). SF6 has been used in this application in most parts of the world for the last twenty years. Due to increasing awareness of the GWP of SF6, the magnesium industry has begun exploring climate- friendly alternative melt protection technologies. At this time the leading alternatives include HFC-134a, a fluorinated ketone (FK 5-1-12, C3F7C(O)C2F5), and dilute sulfur dioxide (SO2). The application of the fluorinated alternatives mentioned here may generate byproduct emissions of concern including PFCs. We are proposing that magnesium production and processing facilities report process emissions of SF6, HFC- 134a, FK 5-1-12, and CO2. Total U.S. emissions of SF6 from magnesium production and processing in the U.S. were estimated to be 3.2 metric tons CO2e in 2006. Primary and secondary production activities at 3 facilities accounted for about 64 percent of total emissions, or 2 metric tons CO2e. Approximately 20 magnesium die casting facilities in the U.S. accounted for more than 30 percent, or more than 0.9 metric tons CO2e of total magnesium-related SF6 emissions. Other smaller casting activities such as sand and permanent mold casting accounted for the remaining magnesium- related emissions of SF6. The term ``metal processed'' used here is defined as the mass of magnesium melted to cast or create parts. This should not be confused with the mass of finished magnesium parts because varying amounts of the metal may be lost as scrap when performing casting operations. 2. Selection of Reporting Threshold We considered emissions thresholds of 1,000 metric tons CO2e, 10,000 metric tons CO2e, 25,000 metric tons CO2e, and 100,000 metric tons CO2e as well as capacity based thresholds as shown in Tables T-1 and T-2 of this preamble. Table T-1. Threshold Analysis for Mg Production Based On Emissions -------------------------------------------------------------------------------------------------------------------------------------------------------- Total Emissions covered Facilities covered nationwide Nationwide --------------------------------------------------------------- Threshold level metric tons CO2e/yr emissions number of metric tons facilities Metric tons Percent Facilities Percent CO2e/Yr CO2e/yr -------------------------------------------------------------------------------------------------------------------------------------------------------- 1,000................................................... 3,200,000 13 2,954,559 92 13 100 10,000.................................................. 3,200,000 13 2,939,741 92 11 85 25,000.................................................. 3,200,000 13 2,939,741 92 11 85 100,000................................................. 3,200,000 13 2,872,982 90 9 69 -------------------------------------------------------------------------------------------------------------------------------------------------------- We believe that there are additional facilities than the 13 listed above, however, we do not have sufficient information to estimate emissions or production levels. Table T-2. Threshold Analysis for Mg Production Based On Mg Production Capacity -------------------------------------------------------------------------------------------------------------------------------------------------------- Total Emissions covered Facilities Covered nationwide --------------------------------------------------------------- Capacity threshold level Mg/yr emissions Number of metric tons facilities Metric tons Percent Facilities Percent CO2e/Yr CO2e/yr -------------------------------------------------------------------------------------------------------------------------------------------------------- 26...................................................... 3,200,000 13 2,954,559 92 13 100 262..................................................... 3,200,000 13 2,949,732 92 12 92 656..................................................... 3,200,000 13 2,949,732 92 12 92 2,622................................................... 3,200,000 13 2,780,717 87 9 69 -------------------------------------------------------------------------------------------------------------------------------------------------------- We believe that there are additional facilities than the 13 listed above, however, we do not have sufficient information to estimate emissions or production levels. Under the proposed rule, magnesium metal production and parts casting facilities would have to report their total GHG emissions if those emissions exceeded 25,000 metric tons CO2e. This threshold covers all currently identified operating U.S. primary and secondary magnesium producers and most die casters, accounting for over 99 percent of emissions from these source categories. The proposed emissions threshold of 25,000 metric tons CO2e is equal to emissions of 1,046 kg of SF6; 19,231 kg of HFC-134a; or 25,000,000 kg of CO2 or FK 5-1-2. Other emission threshold options that we considered were 1,000 metric tons CO2e, 10,000 metric tons CO2e, and 100,000 metric tons CO2e. The 10,000 metric tons CO2e emission threshold yielded results identical to those of the proposed option. We also considered capacity-based thresholds of 26, 262, 656, and 2,622 metric tons, based on 100 percent capacity utilization and an SF6 emission rate of 1.6 kg SF6 per metric ton of magnesium produced or processed. This emission factor represents the sum of (1) the average of the emission factors reported for secondary production and die casting through our magnesium Partnership (excluding outliers), and (2) [[Page 16525]] the standard deviation of those emission factors. The 1.6 kg-per-ton factor is higher than most, though not all, of the emission factors reported, which ranged from 0.7 to 7 kg/ton Mg in 2006. The resulting capacity thresholds yielded results very similar to those of the emission-based thresholds. The emissions based threshold was selected over the capacity based threshold for several reasons. The emissions based threshold is simple to evaluate because magnesium production and processing facilities can use readily available data regarding consumption of SF6 and would also possess similar data for alternatives such as HFC-134a as these are phased-in over time. To determine whether they exceeded the thresholds, magnesium facilities would multiply the total consumption of each of these gases by a GWP-unit conversion factor that could be compared to the 25,000 metric ton threshold. The equation for this calculation is provided in the proposed regulatory text. The emissions-based threshold of 25,000 metric tons CO2e also takes into account the variability in cover gas identities, usage rates, and process conditions. Alternatives to SF6 have considerably lower GWPs than SF6. In facilities where SF6 is used, the usage rate can vary by an order of magnitude depending on the casting process and operating conditions. Therefore, cover gas emissions are not well predicted by production capacity. Because emissions of each cover gas are assumed to equal use, and facilities are expected to track gas use in the ordinary course of business, facilities should have little difficulty determining whether or not they must report under this rule. For a full discussion of the threshold analysis, please refer to the Magnesium Production TSD (EPA- HQ-OAR-2008-0508-020). For specific information on costs, including unamortized first year capital expenditures, please refer to section 4 of the RIA and the RIA cost appendix. 3. Selection of Proposed Monitoring Methods We reviewed a wide range of protocols and guidance in developing this proposal, including the 2006 IPCC Guidelines, EPA's SF6 Emission Reduction Partnership for the Magnesium Industry, the U.S. GHG Inventory, DOE 1605(b), EPA's Climate Leaders Program, and TCR. The methods described in these protocols and guidance were similar to the methods described by the IPCC Guidelines and the U.S. GHG Inventory methodology. These methods range from a Tier 1 approach, based on default consumption factors per unit Mg produced or processed, to a Tier 3 approach based on facility-specific measured emissions data. Under this proposed rule, if you are required to use an existing CEMS to meet the requirements outlined in proposed 40 CFR part 98, subpart C, you would be required to use CEMS to estimate CO2 emissions. Where the CEMS capture all combustion- and process-related CO2 emissions you would be required to follow the calculation procedures, monitoring and QA/QC methods, missing data procedures, reporting requirements, and recordkeeping requirements of proposed 40 CFR part 98, subpart C to estimate CO2 emissions. Also, refer to proposed 40 CFR part 98, subpart C to estimate combustion-related CH4 and N2O emissions. For facilities that do not currently have CEMS that meet the requirements outlined in proposed 40 CFR part 98, subpart C, or where the CEMS would not adequately account for process emissions, you would be required to follow the proposed monitoring method discussed below. The proposed method outlined below accounts for process-related SF6, HFC-134a, FK 5-1-12, and CO2 emissions. Refer to proposed 40 CFR part 98, subpart C specifically for procedures to estimate combustion-related CO2, CH4 and N2O emissions. The proposed method for monitoring SF6, HFC-134a, FK 5- 1-12, and CO2 cover gas emissions from magnesium production and processing is similar to the Tier 2 approach in the 2006 IPCC Guidelines for magnesium production. This approach is based on facility-specific information on cover gas consumption and assumes that all gases consumed are emitted. This methodology applies to any cover gas that is a GHG, including SF6, CO2, HFC-134a and FK 5-1-12. We propose three options for measuring gas consumption: 1. Weighing gas cylinders as they are brought into and out of service allowing a facility to accurately track the actual mass of gas used. 2. Using a mass flow meter to continuously measure the mass of global warming gases used. 3. Performing a facility level mass balance for all global warming gases used at least once annually. Using this approach, a facility would review its gas purchase records and inventory to determine actual mass of gas used and subtract a 10 percent default heel factor to account for residual gas in cylinders returned to the gas suppliers. When weighing cylinders to determine cover gas consumption, facilities would weigh all gas cylinders that are returned to the gas supplier, or have the gas supplier weigh the cylinders, to determine the residual gas still in the cylinder. The weight of residual gas would be subtracted from the weight of gas delivered to determine gas consumption. Gas suppliers can provide detailed monthly spreadsheets with exact residual gas amounts returned. Facilities would be required to follow several procedures to ensure the quality of the consumption data. These procedures could be readily adopted, or would be based on information that is already collected for other reasons. Facilities would be required to track specific cylinders leaving and entering storage with check-out and weigh-in sheets and procedures. Scales used for weighing cylinders and mass flow meters would need to be accurate to within 1 percent of true mass, and would be periodically calibrated. Facilities would calculate the facility usage rate, compare it to known default emission rates and historical data for the facility, and investigate any anomalies in the facility usage rate. Finally, facilities would need to have procedures to ensure that all production lines have provided information to the manager compiling the emissions report, if this is not already handled through an electronic inventory system. We are not proposing IPCC's Tier 1 or 3 methodologies for calculating emissions. Although the Tier 1 methodology is straightforward, the default consumption factor for the SF6 usage rate is significantly uncertain due to the variability in production processes and operating conditions. The Tier 3 methodology of conducting facility-specific measurements of emissions to account for potential cover gas destruction and byproduct formation is the most accurate, but also poses significant economic challenges for implementation because of the cost of direct emission measurements. 4. Selection of Procedures for Estimating Missing Data In general, it is unlikely that cover gas consumption data would be missing. Facilities are expected to know the quantities of cover gas that they consume because facility operations rely on accurate monitoring and tracking of costs. Facilities would possess invoices from gas suppliers during a given year and many facilities currently track the weight of SF6 consumed by weighing individual cylinders prior to replacement. However, where cover gas consumption information is missing, we [[Page 16526]] propose that facilities estimate emissions by multiplying production by the average cover gas usage rate (kg gas per ton of magnesium produced or processed) from the most recent period when operating conditions were similar to those for the period for which the data are missing, i.e., using the same cover gas concentrations and flow rates and, if applicable, casting parts of a similar size. 5. Selection of Data Reporting Requirements Facilities would be required to report total facility GHG emissions and emissions by process type: Primary production, secondary production, die casting, or other type of casting. For total facility and process emissions, emissions would be reported in metric tons of SF6, HFC-134a, FK 5-1-12, and CO2 (used as a carrier gas). Along with their total emissions from cover gas use, facilities would be required to submit supplemental data (as well as the supplemental data required in the combustion and calcination sections) including the type of production processes (e.g., primary, secondary, die casting), mass of magnesium produced or processed in metric tons for each process type, cover gas flow rate and composition, and mass of any CO2 used as a carrier gas during reporting period. If data were missing, facilities would be required to report the length of time the data were missing, the method used to estimate emissions in their absence, and the quantity of emissions thereby estimated. Facilities would also submit an explanation for any significant change in emission rate. Examples could include installation of new melt protection technology that would account for reduced emissions in any given year, or occurrence or repair of leaks in the cover gas delivery system. These non-emissions data need to be reported because they are needed to understand the nature of the facilities for which data are being reported and for verifying the reasonableness of the reported data. 6. Selection of Records That Must Be Retained We are proposing that magnesium producers and processors be required to keep records documenting adherence to the QA/QC requirements specified in the proposed rule. These records would include: Check-out and weigh-in sheets and procedures for cylinders; accuracy certifications and calibration records for scales; residual gas amounts in cylinders sent back to suppliers; and invoices for gas purchases and sales. These records are being specified because they are the values that are used to calculate the GHG emissions that are reported. They are necessary to verify that the GHG emissions monitoring and calculations were done correctly and accurately. U. Miscellaneous Uses of Carbonates 1. Definition of the Source Category Limestone (CaCO3), dolomite (CaMg(CO3)2) and other carbonates are inputs used in a number of industries. The most common applications of limestone are used as a construction aggregate (78 percent of specified national consumption in 2006), the chemical and metallurgy industries (18 percent), and other specialized applications (three percent). The breakdown of reported specified dolomite national consumption was similar to that of limestone, with the majority being used as a construction aggregate, and a lesser but still significant percent used in chemical and metallurgical applications. For some of these applications, the carbonates undergo a calcination process in which the carbonate is sufficiently heated, generating CO2 as a by-product. Examples of such emissive applications include limestone used as a flux or purifier in metallurgical furnaces, as a sorbent in flue gas desulfurization systems for utility and industrial plants, and as a raw material in the production of mineral wool or magnesium. Non-emissive applications include limestone used in producing poultry grit and asphalt filler. The use of limestone, dolomite and other carbonates is purely an industrial process source of emissions. Emissions from the use of carbonates in the manufacture of cement, ferroalloys, glass, iron and steel, lead, lime, pulp and paper, and zinc are elaborated in proposed 40 CFR part 98, subparts H, K, N, Q, R, S, AA and GG, since they are relatively significant emitters. Facilities that include only these source categories would not need to follow the methods presented in this section to estimate emissions from the miscellaneous use of carbonates. The methods presented in this section should be used by facilities that use carbonates in source categories other than those listed above, but which are covered by the proposed rule. As estimated in the U.S. GHG Inventory, national process emissions from other limestone and dolomite uses (i.e., excluding cement, lime, and glass manufacturing) were 7.9 million metric tons CO2e in 2006 (0.1 percent of U.S. emissions). CH4 and N2O are not released from the calcination of carbonates. For additional background information on the use of limestone, dolomite and other carbonates, please refer to the Miscellaneous Uses of Carbonates TSD (EPA-HQ-OAR-2008-0508-021). 2. Selection of Reporting Threshold A separate threshold analysis is not proposed for uses of limestone, dolomite and other carbonates as these emissions occur in a large number of facilities across a range of industries. We propose that facilities with source categories identified in proposed 40 CFR 98.2(a)(1) or (a)(2) consuming limestone, dolomite and other carbonates calculate the relevant emissions from their facility, including emissions from calcination of carbonates, to determine whether they surpass the proposed threshold for that industry. Data were not available to quantify emissions from the calcination of carbonates across all industries; therefore, these emissions were considered where appropriate in the thresholds analysis for the respective industries. 3. Selection of Proposed Monitoring Methods Many domestic and international GHG monitoring guidelines and protocols include methodologies for estimating process-related emissions from the use of limestone, dolomite and other carbonates (e.g., the 2006 IPCC Guidelines, U.S. Inventory, DOE 1605(b), the EU Emissions Trading System, and the Australian National Greenhouse Gas Reporting Program). These methodologies all rely on measuring the consumption of carbonate inputs, but differ in their use of default values. The range of default values reflect differing assumptions of the carbonate weight fraction in process inputs; for example, the 2006 IPCC Guidelines Tier 1 and 2 assume that carbonate inputs are 95 percent pure (i.e., 95 percent of the mass consumed is carbonate), whereas the Australian Program assumes a default purity of 90 percent for limestone, 95 percent for dolomite, and 100 percent for magnesium carbonate. We propose that facilities estimate process emissions by measuring the type and quantity of carbonate input to a kiln or furnace and applying the appropriate emissions factors for the carbonates consumed. In order to assess the composition of the carbonate input, we propose that facilities send samples of each carbonate consumed to an off-site laboratory for a chemical analysis of [[Page 16527]] the carbonate weight fraction on an annual basis. Emission factors are based on stoichiometry and are presented in Table U-1 of this preamble. You would also be required to determine the calcination fraction for each of the carbonate-based minerals consumed, using an appropriate test method. The calcination fraction is the fraction of carbonate that is volatilized in the process. A calcination fraction of 1.0 could over estimate CO2 emissions. You would refer to proposed 40 CFR part 98, subpart C specifically for procedures to estimate combustion- related CO2, CH4 and N2O emissions. Table U-1. CO2 Emission Factors for Common Carbonates ------------------------------------------------------------------------ CO2 emission factor (metric tons Mineral name--carbonate ons CO2/metric tons on carbonate) ------------------------------------------------------------------------ Limestone--CaCO3........................................ 0.43971 Magnesite--MgCO3........................................ 0.52197 Dolomite--CaMg(CO3)2.................................... 0.47732 Siderite--FeCO3......................................... 0.37987 Ankerite--Ca(Fe,Mg,Mn)(CO3)2............................ * 0.44197 Rhodochrosite--MnCO3.................................... 0.38286 Sodium Carbonate/Soda Ash--Na2CO3....................... 0.41492 ------------------------------------------------------------------------ * This is an average of the range provided by the 2006 IPCC Guidelines. We also considered but decided not to propose simplified methods (similar to IPCC Tier 1 and 2) for quantifying process-related emissions from this source, which assumes that limestone and dolomite are the only carbonates consumed, and allow for the use of default fractions of the two carbonates (85 percent for limestone and 15 percent for dolomite). Default factors do not account for variability in relative carbonate consumption by other sources and therefore inaccurately estimate emissions. The various approaches to monitoring GHG emissions are elaborated in the Miscellaneous Uses of Carbonates TSD (EPA-HQ-OAR-2008-0508-021). 4. Selection of Procedures for Estimating Missing Data We propose that 100 percent data availability is required. If chemical analysis on the fraction calcination of carbonates consumed were lost or missing, the analysis would have to be repeated. It is assumed that a facility would be able to supply facility-specific carbonate consumption data. The likelihood for missing data is low, as businesses closely track production inputs. 5. Selection of Data Reporting Requirements We propose that facilities report annual CO2 emissions from carbonate consumption. In addition, we are proposing that facilities submit the following data which are the basis of the emission calculation and are needed for us to understand the emissions data and assess the reasonableness of the reported emissions: annual carbonate consumption (in metric tons, by carbonate) and the total fraction of calcination achieved (for each carbonate). A full list of data to be reported is included in proposed 40 CFR part 98, subparts A and U. 6. Selection of Records That Must Be Retained We propose that facilities retain records on monthly carbonate consumption (by type), annual records on the fraction of calcination achieved (by carbonate type), and results of the annual chemical analysis. These records provide values that are directly used to calculate the emissions that are reported and are necessary to allow determination of whether the GHG emissions monitoring and calculations were done correctly. A full list of records that must be retained onsite is included in proposed 40 CFR part 98, subparts A and U. V. Nitric Acid Production 1. Definition of the Source Category Nitric acid is an inorganic chemical that is used in the manufacture of nitrogen-based fertilizers, adipic acid, and explosives. Nitric acid is also used for metal etching and processing of ferrous metals. A nitric acid production facility uses oxidation, condensation, and absorption to produce a weak nitric acid (30 to 70 percent in strength). The production process begins with the stepwise catalytic oxidation of ammonia (NH3) through nitric oxide (NO) to nitrogen dioxide (NO2) at high temperatures. Then the NO2 is absorbed in and reacted with water (H2O) to form nitric acid (HNO3). According to a facility-level inventory for 2006, there are 45 nitric acid production facilities operating in 25 States with a total of 65 process lines. These facilities represent the best available data at the time of this rulemaking. Using the facility-level inventory, production levels for 2006 have been estimated at 6.6 million metric tons of nitric acid and indicate an estimated 17.7 million metric tons CO2e of process-related emissions (this represents the CO2 equivalent of N2O emissions, which is the primary process-related GHG). Nitric Acid process emissions were estimated in the U.S. GHG Inventory at 15.4 million metric tons CO2e in 2006 or 0.2 percent of total U.S. GHG emissions. The main reason for the difference in estimates is that the methodology of the U.S. Inventory assumed 20 percent of the nitric acid facilities were using nonselective catalytic reduction as an N2O abatement technology. The facility-level analysis showed that only five percent of the nitric acid facilities are using nonselective catalytic reduction. Stationary combustion emissions were not estimated at the source category level in the U.S. GHG Inventory. Stationary combustion emissions at nitric acid facilities may be associated with other chemical production processes as well (such as adipic acid production, phosphoric acid production, or ammonia manufacturing). For additional background information on nitric acid production, please refer to the Nitric Acid Production TSD (EPA-HQ-OAR-2008-0508-022). 2. Selection of Reporting Threshold In developing the proposed threshold for nitric acid production, we considered emissions-based thresholds of 1,000 metric tons CO2e, 10,000 metric tons CO2e, 25,000 metric tons CO2e and 100,000 metric tons CO2e. Table V-1 of this preamble illustrates the emissions and facilities that would be covered under these various thresholds. Table V-1. Threshold Analysis for Nitric Acid Production ---------------------------------------------------------------------------------------------------------------- Process N2O emissions covered Facilities covered (metric tons CO2e/yr) -------------------------------- N2O emission threshold (metric tons CO2e) -------------------------------- Number Percent Number Percent ---------------------------------------------------------------------------------------------------------------- 1,000.......................................... 17,731,650 100 45 100 10,000......................................... 17,723,576 99.9 44 97.8 [[Page 16528]] 25,000......................................... 17,706,259 99.9 43 95.6 100,000........................................ 17,511,444 98.8 40 88.9 ---------------------------------------------------------------------------------------------------------------- We are proposing all nitric acid facilities report in order to simplify the rule and avoid the need for each facility to calculate and report whether it exceeds the threshold value. Facility-level emissions estimates based on plant production suggests that all known facilities, except two, exceed the 25,000 metric tons CO2e threshold. When facility-level production data were not known, capacity data were used along with a utilization factor of 70 percent. The utilization factor is based on total 2006 nitric acid production from the U.S. Census Bureau and capacity estimates from publicly available sources. This analysis, however, only took into account process-related emissions, as combustion-related emissions were not available. Had combustion-related emissions been included, it is probable that additional facilities would have been covered at each threshold. An ``all in'' threshold captures 100 percent of emissions without significantly increasing the number of facilities required to report. Finally, the cost of reporting using the proposed monitoring method does not vary significantly between the four different emissions based thresholds. For a full discussion of the threshold analysis, please refer to the Nitric Acid Production TSD (EPA-HQ-OAR-2008-0508-022). For specific information on costs, including unamortized first year capital expenditures, please refer to section 4 of the RIA and the RIA cost appendix. 3. Selection of Proposed Monitoring Methods Many domestic and international GHG monitoring guidelines and protocols include methodologies for estimating these emissions (e.g. 2006 IPCC Guidelines, U.S. GHG Inventory, DOE 1605(b), TCR, and EPA NSPS). These methodologies coalesce around the five options discussed below. Option 1. Apply default emission factors to total facility production of nitric acid using the Tier 1 approach established by the IPCC. The emissions are calculated using the total production of nitric acid and the highest international default emission factor available in the 2006 IPCC Guidelines, based on technology type. It also assumes no abatement of N2O emissions. Option 2. Apply default emission factors on a site-specific basis using the Tier 2 approach established by the IPCC. This approach is also consistent with the DOE 1605(b) ``B'' rated approach. These emission factors are dependent on the type of nitric acid process used, the type of abatement technology used, and the production activity. The process-related N2O emissions are then estimated by multiplying the emission factor by the production level of nitric acid (on a 100 percent acid basis). Option 3. Follow the Tier 3 approach established by IPCC using periodic direct monitoring of N2O emissions to determine the relationship between nitric acid production and the amount of N2O emissions; i.e., develop a site-specific emissions factor. The site-specific emission factor would be determined from an annual measurement or a single annual stack test. The site-specific emissions factor developed from this test and production rate (activity level) is used to calculate N2O emissions. After the initial test, annual testing of N2O emissions would be required each year to estimate the emission factor and applied to production to estimate emissions. The yearly testing would assist in verifying the emission factor. Testing would also be required whenever the production rate is changed by more than 10 percent from the production rate measured during the most recent performance test. Option 4. Follow the approach used by the Nitric Acid NSPS (40 CFR part 60, subpart G). This option would require monitoring NOX emissions on a continuous basis and measuring N2O emissions to establish a site-specific emission factor that relates NOX emissions to N2O emissions. The emission factor would then be used to estimate N2O emissions based on continuous reading of NOX emissions. Periodic measurement would also be required to verify the emission factor over time. Testing would also be required whenever the production rate is changed by more than 10 percent from the production rate measured during the most recent performance test. Option 5. Follow the Tier 3 approach established by IPCC using continuous monitoring. Use CEMS to directly measure N2O concentration and flow rate to directly determine N2O emissions. CEMS that measure N2O emissions directly are available, but the nitric acid industry is currently using only NOX CEMS. Proposed Option. We are proposing Option 3 to quantify N2O process emissions from all nitric acid facilities. You would be required to follow the requirements in proposed 40 CFR part 98, subpart C to estimate emissions of CO2, CH4 and N2O from stationary combustion. We identified Options 3, 4, and 5 as the approaches providing the highest certainty and the best site-specific estimates. These three options span the range of types of methodologies currently used that do not apply default values. These options all use site-specific approaches that would provide insight into different levels of emissions caused by site-specific differences in process operation and abatement technologies. Option 3 requires an annual test of N2O emissions and the establishment of a site-specific emissions factor that relates N2O emissions with the nitric acid production rate. Options 4 and 5 are similar in that both use continuous monitoring to calculate N2O emissions. Option 5 directly measures the N2O emissions. Option 4 uses continuous measurement of NOX emissions to estimate a site-specific emission factor that relates NOX emissions to N2O emissions. The emission factor is then used to estimate N2O emissions based on continuous readings of NOX emissions. Option 5 would provide the highest certainty of the three options and capture the smallest changes in N2O emissions over time, but N2O CEMS are not currently in use in the industry and there is no existing EPA method for certifying N2O CEMS. Option 3 and Option 4 use site-specific emission factors so the margin of error is much lower than using default emission factors. Option 4 would require the use of NOX CEMS that are already in use by [[Page 16529]] many nitric acid facilities to automatically capture and record any changes in NOX emissions over time. However, NOX CEMS only capture emissions of NO and NO2 and not N2O. Therefore they would not be useful in the estimation of N2O emissions from nitric acid production facilities. Although the amount of NOX and N2O emissions from nitric acid production may be directly related, direct measurement of NOX does not automatically correlate to the amount of N2O in the same exhaust stream. Periodic testing of N2O emissions (Option 3) would not indicate changes in emissions over short periods of time, but does offer direct measurement of the GHG. We request comment, along with supporting documentation, on the advantages and disadvantages of using Options 3, 4 and 5. After consideration of public comments, EPA may promulgate one or more of these options or a combination based on the additional information that is provided. We decided not to propose Options 1 and 2 because the use of default values and lack of direct measurements results in a high level of uncertainty. Although different default emissions factors have been developed for different processes (e.g., low pressure, high pressure) and abatement techniques, the use of these default values is more appropriate for sector wide or national total estimates than for determining emissions from a specific facility. Site-specific emission factors are more appropriate for reflecting differences in process design and operation. The various approaches to monitoring GHG emissions are elaborated in the Nitric Acid Production TSD (EPA-HQ-OAR-2008-0508-022). 4. Selection of Procedures for Estimating Missing Data For process sources that use a site-specific emission factor, no missing data procedures would apply because the site-specific emission factor is derived from an annual performance test and used in each calculation. The emission factor would be multiplied by the production rate, which is readily available. If the test data is missing or lost, the test would have to be repeated. Therefore, 100 percent data availability would be required. 5. Selection of Data Reporting Requirements We propose that facilities report annual N2O emissions (in metric tons) from each nitric acid production line. In addition, we propose that facilities submit the following data to understand the emissions data and verify the reasonableness of the reported emissions. The data should include annual nitric acid production capacity, annual nitric acid production, type of nitric acid production process used, number of operating hours in the calendar year, the emission rate factor used, abatement technology used (if applicable), abatement technology efficiency, and abatement utilization factor. Capacity, actual production, and operating hours would be helpful in determining the potential for growth in the nitric acid industry. The production rate can be determined through sales records or by direct measurement using flow meters or weigh scales. This industry generally measures the production rate as part of normal operating procedures. A list of abatement technologies would be helpful in assessing how widespread the use of abatement is in the nitric acid source category, cataloging any new technologies that are being used, and documenting the amount of time that the abatement technologies are being used. A full list of data to be reported is included in proposed 40 CFR part 98, subparts A and V. 6. Selection of Records That Must Be Retained We propose that facilities maintain records of significant changes to process, N2O abatement technology used, abatement technology efficiency, abatement utilization factor (percent of time that abatement system is operating), annual testing of N2O emissions, calculation of the site-specific emission rate factor, and annual production of nitric acid. A full list of records that must be retained onsite is included in proposed 40 CFR part 98, subparts A and V. W. Oil and Natural Gas Systems 1. Definition of the Source Category The U.S. petroleum and natural gas industry encompasses hundreds of thousands of wells, hundreds of processing facilities, and over a million miles of transmission and distribution pipelines. This section of the preamble identifies relevant facilities and outlines methods and procedures for calculating and reporting fugitive emissions (as defined in this section) of CH4 and CO2 from the petroleum and natural gas industry. Methods and reporting procedures for emissions resulting from natural gas or crude oil combustion in prime movers such as compressors are covered under Section V.C of this preamble. The natural gas segment involves production, processing, transmission and storage, and distribution of natural gas. The U.S. also receives, stores, and processes imported liquefied natural gas (LNG) at LNG import terminals. The petroleum segment involves crude oil production, transportation and refining. The relevant facilities covered in this section are offshore petroleum and natural gas production facilities, onshore natural gas processing facilities (including gathering/boosting stations), onshore natural gas transmission compression facilities, onshore natural gas storage facilities, LNG storage facilities, and LNG import facilities. Fugitive emissions from petroleum refineries are proposed for inclusion in the rulemaking, but these emissions are addressed in the petroleum refinery section (Section V.Y) of this preamble. Under this section of the preamble, we seek comment on methods for reporting fugitive emissions data from: On-shore petroleum and natural gas production and natural gas distribution facilities. For this rulemaking, fugitive emissions from the petroleum and natural gas industry are defined as unintentional equipment emissions and intentional or designed releases of CH4-and/or CO2-containing natural gas or hydrocarbon gas (not including combustion flue gas) from emissions sources including, but not limited to, open ended lines, equipment connections or seals to the atmosphere. In the context of this rule, fugitive emissions also mean CO2 emissions resulting from combustion of natural gas in flares. These emissions are hereafter collectively referred to as ``fugitive emissions'' or ``emissions''. We seek comment on the proposed definition of fugitives, which is derived from the definition of fugitive emissions outlined in the 2006 IPCC Guidelines for National GHG Inventories, and is often used in the development of GHG inventories. We acknowledge that there are multiple definitions for fugitives, for example, defining the term fugitives to include ``those emissions which could not reasonably pass through a stack, chimney, vent, or other functionally-equivalent opening''. According to the 2008 U.S. Inventory, total fugitive emissions of CH4 and CO2 from the natural gas and petroleum industry were 160 metric tons CO2e in 2006. The breakdown of these fugitive emissions is shown in Table W-1 of this preamble. [[Page 16530]] Table W-1. Fugitive Emissions From Petroleum and Natural Gas Systems (2006) ------------------------------------------------------------------------ Fugitive Fugitive Sector CH4 CO2 (MMTCO2e) (MMTCO2e) ------------------------------------------------------------------------ Natural Gas Systems\1\........................ 102.4 28.5 Petroleum Systems............................. 28.4 0.3 ------------------------------------------------------------------------ \1\ Emissions account for Natural Gas STAR Partner Reported Reductions. Natural gas system fugitive CH4 emissions resulted from onshore and offshore natural gas production facilities (27 percent); onshore natural gas processing facilities (12 percent); natural gas transmission and underground natural gas storage, including LNG import and LNG storage facilities (37 percent); and natural gas distribution facilities (24 percent). Natural gas segment fugitive CO2 emissions were primarily from onshore natural gas processing facilities (74 percent), followed by onshore and offshore natural gas production facilities (25 percent), and less than 1 percent each from natural gas transmission and underground natural gas storage and distribution facilities.\80\ --------------------------------------------------------------------------- \80\ The distribution of CO2 emissions is slightly misleading due to current U.S. Inventory convention which assumes that all CO2 from natural gas processing facilities is emitted. In fact, approximately 7,000 metric tons CO2e is captured and used for EOR. --------------------------------------------------------------------------- Petroleum segment fugitive CH4 emissions are primarily associated with onshore and offshore crude oil production facilities (>97 percent of emissions) and petroleum refineries (2 percent) and are negligible in crude oil transportation facilities (<0.5 percent). Petroleum segment fugitive CO2 emissions are only estimated for onshore and offshore production facilities. With over 160 different sources of fugitive CH4 and CO2 emissions in the petroleum and natural gas industry, identifying those sources most relevant for a reporting program was a challenge. We developed a decision tree analysis and undertook a systematic review of each emissions source category included in the Inventory of U.S. GHG Emissions and Sinks. In determining the most relevant fugitive emissions sources for inclusion in this reporting program, we applied the following criteria: the coverage of fugitive emissions for the source category as a whole, the coverage of fugitive emissions per unit of the source category, feasibility of a viable monitoring method, including direct measurement and engineering estimations, and an administratively manageable number of reporting facilities. Another factor we considered in assessing the applicability of certain petroleum and natural gas industry fugitive emissions in a mandatory reporting program is the definition of a facility. In other words, what physically constitutes a facility? This definition is important to determine who the reporting entity would be, and to ensure that delineation is clear and double counting of fugitive emissions is minimized. For some segments of the industry, identifying the facility is clear since there are physical boundaries and ownership structures that lend themselves to identifying scope of reporting and responsible reporting entities (e.g., onshore natural gas processing facilities, natural gas transmission compression facilities, and offshore petroleum and natural gas facilities). In other segments of the industry, such as the pipelines between compressor stations, and more particularly onshore petroleum and natural gas production, such distinctions are not straightforward. In defining a facility, we reviewed current definitions used in the CAA and ISO definitions, consulted with industry, and reviewed current regulations relevant to the industry. The full results of our assessment can be found in the Oil and Natural Gas Systems TSD (EPA-HQ-OAR-2008-0508-023). Following is a brief discussion of the proposed selected and excluded sources based on our analysis. Additional information can be found in the Oil and Natural Gas Systems TSD (EPA-HQ-OAR-2008-0508- 023). This section of the preamble addresses only fugitive emissions. Combustion-related emissions are discussed in Section V.C of this preamble. Offshore Petroleum and Natural Gas Production Facilities. Offshore petroleum and natural gas production includes both shallow and deep water wells in both U.S. State and Federal waters. These offshore facilities house equipment to extract hydrocarbons from the ocean floor and transport it to storage or transport vessels or onshore. Fugitive emissions result from sources housed on the platforms. In 2006, offshore petroleum and natural gas production fugitive CO2 and CH4 emissions accounted for 5.6 million metric tons CO2e. The primary sources of fugitive emissions from offshore petroleum and natural gas production are from valves, flanges, open-ended lines, compressor seals, platform vent stacks, and other source components. Flare stacks account for the majority of fugitive CO2 emissions. Offshore petroleum and natural gas production facilities are proposed for inclusion due to the fact that this represents approximately 4 percent of emissions from the petroleum and natural gas industry, ``facilities'' are clearly defined, and major fugitive emissions sources can be characterized by direct measurement or engineering estimation. Onshore Natural Gas Processing Facilities. Natural gas processing includes gathering/ boosting stations that dehydrate and compress natural gas to be sent to natural gas processing facilities, and natural gas processing facilities that remove NGLs and various other constituents from the raw natural gas. The resulting ``pipeline quality'' natural gas is injected into transmission pipelines. Compressors are used within gathering/ boosting stations and also natural gas processing facilities to adequately pressurize the natural gas so that it can pass through all of the processes into the transmission pipeline. Fugitive CH4 emissions from reciprocating and centrifugal compressors, including centrifugal compressor wet and dry seals, reciprocating compressor rod packing, and all other compressor fugitive emissions, are the primary CH4 emission source from this segment. The majority of fugitive CO2 emissions come from acid gas removal vent stacks, which are designed to remove CO2 and hydrogen sulfide, when present, from natural gas. While these are the major fugitive emissions sources in natural gas processing facilities, if other potential fugitive sources such as flanges, open-ended lines and threaded fittings are present at your facility you would need to account for them if reporting under proposed 40 CFR part 98, subpart W. For this subpart you would assume no capture of CO2 because capture and [[Page 16531]] transfer of CO2 offsite would be calculated in accordance with Section V.PP of this preamble and reported separately. Onshore natural gas processing facilities are proposed for inclusion due to the fact that these operations represent a significant emissions source, approximately 25 percent of emissions from the natural gas segment. ``Facilities'' are easily defined and major fugitive emissions sources can be characterized by direct measurement or engineering estimation. Onshore Natural Gas Transmission Compression Facilities and Underground Natural Gas Storage Facilities. Natural gas transmission compression facilities move natural gas throughout the U.S. natural gas transmission system. Natural gas is also injected and stored in underground formations during periods of low demand (e.g., spring or fall) and withdrawn, processed, and distributed during periods of high demand (e.g., winter or summer). Storage compressor stations are dedicated to gas injection and extraction at underground natural gas storage facilities. Fugitive CH4 emissions from reciprocating and centrifugal compressors, including centrifugal compressor wet and dry seals, reciprocating compressor rod packing, and all other compressor fugitive emissions, are the primary CH4 emission source from natural gas transmission compression stations and underground natural gas storage facilities. Dehydrators are also a significant source of fugitive CH4 emissions from underground natural gas storage facilities. While these are the major fugitive emissions sources in natural gas transmission, other potential fugitive sources include, but are not limited to, condensate tanks, open-ended lines and valve seals. Transmission compression facilities and underground natural gas storage facilities are proposed for inclusion due to the fact that these operations represent a significant emissions source, approximately 24 percent of emissions from the natural gas segment; ``facilities'' are easily defined, and major fugitive sources can be characterized by direct measurement or engineering estimation. LNG Import and LNG Storage Facilities. The U.S. imports natural gas in the form of LNG, which is received, stored, and, when needed, processed and compressed at LNG import terminals. LNG storage facilities liquefy and store natural gas from transmission pipelines during periods of low demand (e.g., spring or fall) and vaporize for send out during periods of high demand (e.g., summer and winter) Fugitive CH4 and CO2 emissions from reciprocating and centrifugal compressors, including centrifugal compressor wet and dry seals, reciprocating compressor rod packing, and all other compressor fugitive emissions, are the primary CH4 and CO2 emission source from LNG storage facilities and LNG import facilities. Process units at these facilities can include compressors to liquefy natural gas (at LNG storage facilities), re- condensers, vaporization units, tanker unloading equipment (at LNG import terminals), transportation pipelines, and/or pumps. LNG storage facilities and LNG import facilities are proposed for inclusion due to the fact that fugitive emissions from these operations represent approximately 1 percent of emissions from natural gas systems. LNG storage ``facilities'' are defined as facilities that store liquefied natural gas in above ground storage tanks. LNG import terminal ``facilities'' are defined as facilities that receive imported LNG, store it in storage tanks, and release re-gasified natural gas for transportation. Onshore Petroleum and Natural Gas Production. Similar to offshore petroleum and natural gas production, the onshore petroleum and natural gas production segment uses wells to draw raw natural gas, crude oil, and associated gas from underground formations. The most dominant sources of fugitive CH4 and CO2 emissions include, but are not limited to, natural gas driven pneumatic valve and pump devices, field crude oil and condensate storage tanks, chemical injection pumps, releases and flaring during well completion and workovers, and releases and flaring of associated gas. We considered proposing the reporting of fugitive CH4 and CO2 emissions from onshore petroleum and natural gas production in the rule. Onshore petroleum and natural gas production is responsible for the largest share of fugitive CH4 and CO2 emissions from petroleum and natural gas industry (27 percent of total emissions). However, this segment is not proposed for inclusion primarily due to the unique difficulty in defining a ``facility'' in this sector and correspondingly determining who would be responsible for reporting. Given the significance of fugitive emissions from the onshore petroleum and natural gas production, we would like to take comment on whether we should consider inclusion of this source category in the future. Specifically, we would like to take comment on viable ways to define a facility for onshore oil and gas production and to determine the responsible reporter. In addition, the Agency also requests comment on the merits and/or concerns with the corporate basin level reporting approach under consideration for onshore oil and gas production, as outlined below. One approach we are considering for including onshore petroleum and natural gas production fugitive emissions in this reporting rule is to require corporations to report emissions from all onshore petroleum and natural gas production assets at the basin level. In such a case, all operators in a basin would have to report their fugitive emissions from their operations at the basin-level. For such a basin-level facility definition, we may propose reporting of only the major fugitive emissions sources; i.e., natural gas driven pneumatic valve and pump devices, well completion releases and flaring, well blowdowns, well workovers, crude oil and condensate storage tanks, dehydrator vent stacks, and reciprocating compressor rod packing. Under this scenario, we might suggest that all operators would be subject to reporting, perhaps exempting small businesses, as defined by the Small Business Administration. This approach could substantially reduce the reporting complexity and require individual companies that produce crude oil and/or natural gas in each basin to be responsible for reporting emissions from all of their onshore petroleum and natural production operations in that basin, including from rented sources, such as compressors. In cases where hydrocarbons or emissions sources are jointly owned by more than one company, each company would report emissions equivalent to its portion of ownership. We considered other options in defining a facility such as individual wellheads or aggregating all emissions sources prior to compression as a facility. However, such definitions result in complex reporting requirements and are difficult to implement. We are seeking comments on reporting of the major fugitive emissions sources by corporations at the basin level for onshore petroleum and natural gas production. Petroleum and Natural Gas Pipeline Segments. Natural gas transmission involves high pressure, large diameter pipelines that transport gas long distances from field production and natural gas processing facilities to natural gas distribution pipelines or large volume customers such as power [[Page 16532]] plants or chemical plants. Crude oil transportation involves pump stations to move crude oil through pipelines and loading and unloading crude oil tanks, marine vessels, and rails. The majority of fugitive emissions from the transportation of natural gas occur at the compressor stations, which are already proposed for inclusion in the rule and discussed above. We do not propose to include reporting of fugitive emissions from natural gas pipeline segments between compressor stations, or crude oil pipelines in the rulemaking due to the dispersed nature of the fugitive emissions, the difficulty in defining pipelines as a facility, and the fact that once fugitives are found, they are generally fixed quickly, not allowing time for monitoring and direct measurement of the fugitives. Natural Gas Distribution. In the natural gas distribution segment, high-pressure gas from natural gas transmission pipelines enter ``city gate'' stations, which reduce the pressure and distribute the gas through primarily underground mains and service lines to individual end users. Distribution system CH4 and CO2 emissions result mainly from fugitive emissions from gate stations (metering and regulating stations) and vaults (regulator stations), and fugitive emissions from underground pipelines. At gate stations and vaults, fugitive CH4 emissions primarily come from valves, open- ended lines, connectors, and natural gas driven pneumatic valve devices. Although fugitive emissions from a single vault, gate station or segment of pipeline in the natural gas distribution segment may not be significant, collectively these fugitive emissions sources contribute a significant share of fugitive emissions from natural gas systems. We do not propose to include the natural gas distribution segment of the natural gas industry in this rulemaking due to the dispersed nature of the fugitive emissions and difficulty in defining a facility such that there would be an administratively manageable number of reporters. One approach to address the concern with defining a facility for distribution would be to require corporate-level reporting of fugitive emissions from major sources by distribution companies. We seek comment on this and other ways of reporting fugitive emissions from the distribution sector. Crude Oil Transportation. Crude oil is commonly transported by barge, tanker, rail, truck, and pipeline from production operations and import terminals to petroleum refineries or export terminals. Typical equipment associated with these operations are storage tanks and pumping stations. The major sources of CH4 and CO2 fugitive emissions include releases from tanks and marine vessel loading operations. We do not propose to include the crude oil transportation segment of the petroleum and natural gas industry in this rulemaking due to its small contribution to total petroleum and natural gas fugitive emissions, accounting for much less than 1 percent, and the difficulty in defining a facility. 2. Selection of Reporting Threshold We propose that facilities with emissions greater than 25,000 metric tons CO2e per year be subject to reporting. This threshold is applicable to all oil and natural gas system facilities covered by this subpart: Offshore petroleum and natural gas production facilities, onshore natural gas processing facilities, including gathering/boosting stations; natural gas transmission compression facilities, underground natural gas storage facilities; LNG storage facilities; and LNG import facilities. To identify the most appropriate threshold level for reporting of fugitive emissions, we conducted analyses to determine fugitive emissions reporting coverage and facility reporting coverage at four different levels of threshold; 1,000 metric tons CO2e per year, 10,000 metric tons CO2e per year, 25,000 metric tons CO2e per year, and 100,000 metric tons CO2e per year. Table W-2 of this preamble provides coverage of emissions and number of facilities reporting at each threshold level for all the industry segments under consideration for this rule. Table W-2. Threshold Analysis for Fugitive Emissions From the Petroleum and Natural Gas Industry -------------------------------------------------------------------------------------------------------------------------------------------------------- Total Total emissions covered Facilities covered national by thresholds \s\ ------------------------- emissions Total number Threshold -------------------------- Source category #a (metric of facilities level (metric tons CO2e tons CO2e Percent Number Percent per year) per year) -------------------------------------------------------------------------------------------------------------------------------------------------------- Offshore Petroleum & Gas Production Facilities............ 10,162,179 2,525 1,000 9,783,496 96 1,021 40 10,000 6,773,885 67 156 6 25,000 5,138,076 51 50 2 100,000 3,136,185 31 4 0.5 Natural Gas Processing Facilities......................... 50,211,548 566 1,000 50,211,548 100 566 100 10,000 49,207,852 98 394 70 25,000 47,499,976 95 287 51 100,000 39,041,555 78 125 22 Natural Gas Transmission Compression Facilities........... 73,198,355 1,944 1,000 73,177,039 100 1,659 85 10,000 71,359,167 97 1311 67 25,000 63,835,288 87 874 45 100,000 30,200,243 41 216 11 Underground Natural Gas Storage Facilities................ 11,719,044 398 1,000 11,702,256 100 346 87 10,000 10,975,728 94 197 49 25,000 9,879,247 84 131 33 100,000 5,265,948 45 35 9 LNG Storage Facilities.................................... 1,956,435 157 1,000 1,940,203 99 54 34 10,000 1,860,314 95 39 25 25,000 1,670,427 85 29 18 100,000 637,477 33 3 2 LNG Import Facilities..................................... 1,896,626 5 1,000 1,896,626 100 5 100 [[Page 16533]] 10,000 1,895,153 99.9 4 80 25,000 1,895,153 99.9 4 80 100,000 1,895,153 99.9 4 80 -------------------------------------------------------------------------------------------------------------------------------------------------------- \a\ The emissions include fugitive CH4 and CO2 and combusted CO2, N2O, and CH4 gases. The emissions for each industry segment do not match the 2008 U.S. Inventory either because of added details in the estimation methodology or use of a different methodology than the U.S. Inventory. For additional discussion, refer to the Oil and Natural Gas Systems TSD (EPA-HQ-OAR-2008-0508-023). A proposed threshold of 25,000 metric tons CO2e applied to only those emissions sources listed in Table W-2 of this preamble captures approximately 81 percent of fugitive CH4 and CO2 emissions from the entire oil and natural gas industry, while capturing only a small fraction of total facilities. For additional information, please refer to the Oil and Natural Gas Systems TSD (EPA-HQ-OAR-2008-0508-023). For specific information on costs, including unamortized first year capital expenditures, please refer to section 4 of the RIA and the RIA cost appendix. 3. Selection of Proposed Monitoring Methods Many domestic and international GHG monitoring guidelines and protocols include methodologies for estimating fugitive emissions from oil and natural gas operations, including the 2006 IPCC Guidelines, U.S. GHG Inventory, DOE 1605(b), and corporate industry protocols developed by the American Petroleum Institute, the Interstate Natural Gas Association of America, and the American Gas Association. The methodologies proposed vary by the emissions source, for example fugitive emissions versus vented emissions, versus emissions from flares (all of which are considered ``fugitive'' emissions in this rulemaking). Generally, approaches range from direct measurement (e.g., high volume samplers), to engineering equations (where applicable), to simple emission factor approaches based on national default factors. Proposed Option. We propose that facilities would be required to detect fugitive emissions from the identified emissions sources proposed in this rulemaking, and then quantify emissions using either engineering equations or direct measurement. Fugitive emissions from all affected emissions sources at the facility, whether in operating condition or on standby, would have to be monitored on an annual basis. The proposed monitoring method would depend on the fugitive emissions sources in the facility to be monitored. Each fugitive emissions source would be required to be monitored using one of the two monitoring methods: (1) Direct measurement or (2) engineering estimation. Table W-3 of this preamble provides the proposed fugitive emissions source and corresponding monitoring methods. General guidance on the monitoring methods is given below. Table W-3. Source Specific Monitoring Methods and Emissions Quantification ------------------------------------------------------------------------ Emissions Emission source Monitoring method quantification type methods ------------------------------------------------------------------------ Acid Gas Removal Vent Stacks Engineering Simulation software. estimation. Blowdown Vent Stacks........ Engineering Gas law and estimation. temperature, pressure, and volume between isolation valves. Centrifugal Compressor Dry Direct measurement.. (1) High volume Seals. sampler, or (2) Calibrated bag, or (3) Meter. Centrifugal Compressor Wet Direct measurement.. (1) High volume Seals. sampler, or (2) Calibrated bag, or (3) Meter. Compressor Fugitive Direct measurement.. (1) High volume Emissions. sampler, or (2) Calibrated bag, or (3) Meter. Dehydrator Vent Stacks...... Engineering Simulation software. estimation. Flare Stacks................ Engineering Velocity meter and estimation and mass/volume direct measurement. equations. Natural Gas Driven Pneumatic (1) Engineering (1) Manufacturer Pumps. estimation, or (2) data, equipment Direct measurement. counts, and amount of chemical pumped, or (2) Calibrated bag. Natural Gas Driven Pneumatic (1) Engineering (1) Manufacturer Manual Valve Actuator estimation, or (2) data and actuation Devices. Direct measurement. logs, or (2) Calibrated bag. Natural Gas Driven Pneumatic (1) Engineering (1) Manufacturer Valve Bleed Devices. estimation, or (2) data and equipment Direct measurement. counts, or (2) High volume sampler, or (3) Calibrated bag, or (4) Meter. Non-pneumatic Pumps......... Direct measurement.. High volume sampler. Offshore Platform Pipeline Direct measurement.. High volume sampler. Fugitive Emissions. Open-ended Lines............ Direct measurement.. (1) High volume sampler, or (2) Calibrated bag, or (3) Meter. Pump Seals.................. Direct measurement.. (1) High volume sampler, or (2) Calibrated bag, or (3) Meter. Facility Fugitive Emissions. Direct measurement.. High volume sampler. [[Page 16534]] Reciprocating Compressor Rod Direct measurement.. (1) High volume Packing. sampler, or (2) Calibrated bag, or (3) Meter. Storage Tanks............... (1) Engineering (1) Meter, or (2) estimation and Simulation direct measurement, software, or (3) or (2) Engineering Vasquez-Beggs estimation. Equation. ------------------------------------------------------------------------ a. Direct Measurement Fugitive emissions detection and measurement are both required in cases where direct measurement is being proposed. Infrared fugitive emissions detection instruments are capable of detecting fugitive CH4 emissions, or Toxic Vapor Analyzers or Organic Vapor Analyzers can be used by the operator to detect fugitive natural gas emissions. These instruments detect the presence of hydrocarbons in the natural gas fugitive emissions stream. They do not detect any pure CO2 fugitive emissions. However, because all the sources proposed for monitoring have natural gas fugitive emissions that have CH4 as one of its constituents, there is no need for a separate detection instrument for separately detecting CO2 fugitive emissions. The only exception to this is fugitive emissions from acid gas removal vent stacks where the predominant constituent of the fugitive emissions is CO2. Engineering estimation is proposed for this source, and therefore there is no need for detection of fugitive emissions from acid gas removal vent stacks. In the Oil and Natural Gas Systems TSD (EPA-HQ-OAR-2008-0508-023), we describe a particular method based on practicality of application. For example, using Toxic Vapor Analyzers or Organic Vapor Analyzers on very large facilities is not as cost effective as infrared fugitive emissions detection instruments. We propose that irrespective of the method used for fugitive natural gas emissions detection, the survey for detection must be comprehensive. This means that, on an annual basis, the entire population of emissions sources proposed for fugitive emissions reporting has to be surveyed at least once. When selecting the appropriate emissions detection instrument, it is important to note that certain instruments are best suited for particular applications and circumstances. For example, some optical infrared fugitive emissions detection instruments may not perform well in certain weather conditions or with certain colored backgrounds. Infrared fugitive emissions detection instruments are able to scan hundreds of source components at once, allowing for efficient detection of emissions at large facilities; however, infrared fugitive emissions detection instruments are typically much more expensive than other options. Organic Vapor Analyzers and Toxic Vapor Analyzers are not able to detect fugitive emissions from many components as quickly; however, for small facilities this may provide a less costly alternative to infrared fugitive emissions detection without requiring overly burdensome labor to perform a comprehensive fugitive emissions survey. We propose that operators choose the instrument from the choices provided in the proposed rule that is best suited for their circumstance. Further information is contained in the Oil and Natural Gas Systems TSD (EPA-HQ-OAR-2008-0508-023). For direct measurement, we have proposed that high volume samplers, meters (such as rotameters, turbine meters, hot wire anemometers, and others), and/or calibrated bags be designated for use. However, if fugitive emissions exceed the maximum range of the proposed monitoring instrument, you would be required to use a different instrument option that can measure larger magnitude emissions levels. For example, if a high volume sampler is pegged by a fugitive emissions source, then fugitive emissions would be required to be directly measured using either calibrated bagging or a meter. In the Oil and Natural Gas Systems TSD (EPA-HQ-OAR-2008-0508-023), we discuss multiple options for measurement where the range of emissions measurement instruments is seen as an issue. CH4 and CO2 fugitive emissions from the natural gas fugitive emissions stream can be calculated using the composition of natural gas. b. Engineering Estimation Engineering estimation has been proposed for calculating CH4 and CO2 fugitive emissions from sources where the variable in the emissions magnitude on an annual basis is the number of times the source releases fugitive CH4 and CO2 emissions to the atmosphere. For example, when a compressor is taken offline for maintenance, the volume of fugitive CH4 and CO2 emissions that are released is the same during each release and the only variable is the number of times the compressor is taken offline. Also, engineering estimates have been proposed where safety concerns prohibit the use of direct measurement methods. For example, sometimes the temperature of the fugitive emissions stream for glycol dehydrator vent stacks is too high for operators to safely measure fugitive emissions. Based on these principles, we propose that direct measurement is mandatory unless there is a demonstrated and documented safety concern or frequency of fugitive emission releases is the only variable in emissions, at which time engineering estimates can be applied. c. Alternative Monitoring Methods Considered Before proposing the monitoring methods discussed above, we considered four additional measurement methods. The use of Method 21 or the use of activity and emission factors were considered for fugitive emissions detection and measurement. Although Toxic Vapor Analyzers and Organic Vapor Analyzers were considered but not proposed for fugitive emissions direct measurement they are acceptable for fugitive emissions detection. Method 21. This is the reference method for equipment leak detection and repair regulations for volatile organic carbon (VOC) emissions under several 40 CFR part 60 emission standards. Method 21 of 40 CFR part 60 Appendix A-7 determines a concentration at a point or points of emissions expressed in parts per million concentration of combustible hydrocarbon in the air stream of the instrument probe. This concentration is then compared to the ``action level'' in the referenced 40 CFR part 60 regulation to determine if a leak is present. Although Method 21 was not developed for this purpose, it may allow for better emission estimation than the overall average emission factors that have been published for equipment leaks. Quantification of air emissions from equipment leaks is generally done using EPA published guidelines which correlate the measured concentration to a VOC mass emission rate based on extensive measurements of air emissions from leaking equipment. The [[Page 16535]] correlations are statistically determined for a very large population of similar components, but not very accurate for single leaks or small populations. Therefore, Method 21 was not found suitable for fugitive emissions measurement under this reporting rule. However, we are seeking comments on this conclusion, and whether Method 21 should be permitted as a viable alternative method to estimate emissions for sources where it is currently required for VOC emissions. Activity Factor and Emissions Factor for All Sources. Fugitive CH4 emissions factors for all of the fugitive emissions sources proposed for inclusion in the rule are available in a study that was conducted in 1992.81 82 There have been no subsequent comparable studies published to replace or revise the fugitive emissions estimates available from this study. However, some petroleum and natural gas industry operations have changed significantly with the introduction of new technologies and improved operating and maintenance practices to mitigate fugitive emissions. These are not reflected in the fugitive emissions factors available. Also, in many cases the fugitive emissions factors are not representative of emission levels for individual sources or are not relevant to certain operations because the estimates were based on limited or no field data. Hence, they are not representative of the entire country or specific petroleum and natural gas facilities and fugitive emissions sources such as tanks and wells. Therefore, we did not propose this method for estimation of the fugitive emissions for reporting. --------------------------------------------------------------------------- \81\ EPA/GRI (1996) Methane Emissions from the Natural Gas Industry. Harrison, M., T. Shires, J. Wessels, and R. Cowgill, (eds.). Radian International LLC for National Risk Management Research Laboratory, Air Pollution Prevention and Control Division, Research Triangle Park, NC. EPA-600/R-96-080a. \82\ EPA (1999) Estimates of Methane Emissions from the U.S. Oil Industry (Draft Report). Prepared by ICF International. Office of Air and Radiation, U.S. Environmental Protection Agency. October 1999. --------------------------------------------------------------------------- Default fugitive CO2 emissions factors are available only for whole segments of the industry (e.g., natural gas processing), and are not available for individual sources. Further, these are international default factors, which have a high uncertainty associated with them and are not appropriate for facility-level reporting. Mass Balance for Quantification. We considered, but decided not to propose, the use of a mass balance approach for quantifying emissions. This approach would take into account the volume of gas entering a facility and the amount exiting the facility, with the difference assumed to be emitted to the atmosphere. This is most often discussed for emissions estimation from the transportation segment of the industry. For transportation, the mass balance is often not recommended because of the uncertainties surrounding meter readings and the large volumes of throughput relative to fugitive emissions. We are seeking feedback on the use of a mass balance approach and the applicability to each sector of the oil and gas industry (production, processing, transmission, and distribution) as a potential alternative to component level leak detection and quantification. Toxic Vapor Analyzers and Organic Vapor Analyzers for Emissions Measurement. Toxic Vapor Analyzer and Organic Vapor Analyzer instruments quantify the concentration of combustible hydrocarbon from the fugitive emission in the air stream, but do not directly quantify the volumetric or mass emissions. The instrument probe rarely ingests all of the natural gas from a fugitive emissions source. Therefore, these instruments are used primarily for fugitive emissions leak detection. For the proposed rule, fugitive CH4 emissions detection by more cost-effective detection technologies such as infrared fugitive emissions detection instruments in conjunction with direct measurement methodologies such as the high volume sampler, meters and calibrated bags is deemed a better overall approach to fugitive emissions quantification than the labor intensive Organic Vapor Analyzers and Toxic Vapor Analyzers, which do not quantify volumetric or mass fugitive emissions. d. Outstanding Issues on Which We Seek Comments The proposed rule does not indicate a particular threshold for detection above which emissions measurement is required. This is because the different emissions detection instruments proposed have different levels and types of detection capabilities. Hence the magnitude of actual emissions can only be determined after measurement. This, however, does not serve the purpose of this rule in limiting burden on emissions reporting. A facility can have hundreds of small emissions (as low as 3 grams per hour) and it might not be practical to measure all such small emissions for reporting. To address this issue we intend to incorporate one of the following two approaches in the final rule. The first approach would provide performance standards for fugitive emissions detection instruments and usage such that all instruments follow a common minimum detection threshold. We may propose the use of the Alternate Work Practice to Detect Leaks from Equipment standards for infrared fugitive emissions detection instruments being developed by EPA. In such a case all detected emissions from components subject to this rule would require measurement and reporting. The second approach would provide an emissions threshold above which the source would be identified as an ``emitter'' for emissions detection using Organic Vapor Analyzers or Toxic Vapor Analyzers. When using infrared fugitive emissions detection instruments all sources subject to this rule that have emissions detected would require emissions quantification. Alternatively, the operator would be given a choice of first detecting emissions sources using the infrared detection instrument and then verifying for measurement status using the emissions definition for Organic Vapor Analyzers or Toxic Vapor Analyzers. We are seeking comments on using the two options discussed above for determining emission sources requiring measurement of emissions. Some fugitive emissions by nature occur randomly within the facility. Therefore, there is no way of knowing when a particular source started emitting. This proposed rule requires annual fugitive emissions detection and measurement. The emissions detected and measured would be assumed to continue throughout the reporting year, unless no emissions detection is recorded at an earlier and/or later point in the reporting period. We recognize that this may not necessarily be true in all cases and that emissions reported would be higher than actual. Therefore, we are seeking comments on how this issue can be resolved without resulting in additional reporting burden to the facilities. The petroleum and natural gas industry is already implementing voluntary fugitive emissions detection and repair programs. Such voluntary programs are useful, but pose an accounting challenge with respect to emissions reporting for this rule. The proposed rule requires annual detection and measurement of fugitive emissions. This approach does not preclude any facility from performing emissions detection and repair prior to the official detection, measurement, and reporting of emissions for this rule. We are seeking comments on how to avoid under-reporting of emissions as a result of a preliminary, ``un- official'' emissions [[Page 16536]] survey and repair exercise ahead of the ``official'' annual survey. Fugitive emissions from a compressor are a function of the mode in which the compressor is operating. Typically, a compressor station consists of several compressors with one (or more) of them on standby based on system redundancy requirements and peak delivery capacity. Fugitive emissions at compressors in standby mode are significantly different than those from compressors that are operating. The rule proposes annual direct measurement of fugitive emissions. This may not adequately account for the different modes in which a particular compressor is operating through the reporting period. We are soliciting input on a method to measure emissions from each mode in which the compressor is operating, and the period of time operated in that mode, that would minimize reporting burden. Specifically, given the variability of these measured emissions, EPA requests comment on whether engineering estimates or other alternative methods that account for total emissions from compressors, including open ended lines, could address this issue of operating versus standby mode. The fugitive emissions measurement instruments (i.e. high volume sampler, calibrated bags, and meters) proposed for this rule measure natural gas emissions. CH4 and CO2 emissions are required to be estimated from the natural gas mass emissions using natural gas composition appropriate for each facility. For this purpose, the proposed rule requires that facilities use existing gas composition estimates to determine CH4 and CO2 components of the natural gas emissions (flare stack and storage tank fugitive emissions are an exception to this general rule). We have determined that these gas composition estimates are available from facilities reporting to this rule. We are seeking comments on whether this is a practical assumption. In the absence of gas composition, an alternative proposal would be to require the periodic measurement of the required gas composition for speciation of the natural gas mass emissions into CH4 and CO2 mass emissions. 4. Selection of Procedures for Estimating Missing Data The proposal requires data collection for a single source a minimum of once a year. If data are lost or an error occurs during fugitive emissions direct measurement, the operator should carry out the direct measurement a second time to obtain the relevant data point(s). Similarly, engineering estimates must account for relevant source counts and frequency of fugitive emissions releases throughout the year. There should not be any missing data for estimating fugitive emissions from petroleum and natural gas systems. 5. Selection of Data Reporting Requirements We propose that fugitive emissions from the petroleum and natural gas industry be reported on an annual basis. The reporting should be at a facility level with fugitive emissions being reported at the source type level. Fugitive emissions from each source type could be reported at an aggregated level. In other words, process unit-level reporting would not be required. For example, a facility with multiple reciprocating compressors could report fugitive emissions from all reciprocating compressors as an aggregate number. Since the proposed monitoring method is fugitive emissions detection and measurement at the source level, we determined that reporting at an aggregate source type level is feasible. Fugitive emissions from all sources proposed for monitoring, whether in operating condition or on standby, would have to be reported. Any fugitive emissions resulting from standby sources would be separately identified from the aggregate fugitive emissions. The reporting facility would be required to report the following information to us as a part of the annual fugitive emissions reporting: fugitive emissions monitored at an aggregate source level for each reporting facility, assuming no carbon capture and transfer offsite; the quantity of CO2 captured for use and the end use, if known; fugitive emissions from standby sources; and activity data for each aggregate source type level. Additional data are proposed to be reported to support verification: Engineering estimate of total component count; total number of compressors and average operating hours per year for compressors, if applicable; minimum, maximum and average throughput per year; specification of the type of any control device used, including flares; and detection and measurement instruments used. For offshore petroleum and natural gas production facilities, the number of connected wells, and whether they are producing oil, gas, or both is proposed to be reported. For compressors specifically, we proposed that the total number of compressors and average operating hours per year be reported. A full list of data to be reported is included in proposed 40 CFR part 98, subparts A and W. 6. Selection of Records That Must Be Retained The reporting facility shall retain relevant information associated with the monitoring and reporting of fugitive emissions to us, as follows; throughput of the facility when the fugitive emissions direct measurement was conducted, date(s) of measurement, detection and measurement instruments used, if any, results of the leak detection survey, and inputs and outputs to calculations or simulation software runs where the proposed monitoring method requires engineering estimation. A full list of records to be retained is included inproposed 40 CFR part 98, subparts A and W. X. Petrochemical Production 1. Definition of the Source Category The petrochemical industry consists of numerous processes that use fossil fuel or petroleum refinery products as feedstocks. For this proposed GHG reporting rule, the reporting of process-related emissions in the petrochemical industry is limited to the production of acrylonitrile, carbon black, ethylene, ethylene dichloride, ethylene oxide, and methanol. The petrochemicals source category includes production of all forms of carbon black (e.g., furnace black, thermal black, acetylene black, and lamp black) because these processes use petrochemical feedstocks; bone black is not considered to be a form of carbon black because it is not produced from petrochemical feedstocks. The rule focuses on these six processes because production of GHGs from these processes has been recognized by the IPCC to be significant compared to other petrochemical processes. Facilities producing other types of petrochemicals are not subject to proposed 40 CFR part 98, subpart X of this reporting rule but may be subject to 40 CFR part 98, subpart C, General Stationary Fuel Combustion Sources, or other subparts. There are 88 facilities operating petrochemical processes in the U.S., and 9 of these operate either two or three types of petrochemical processes (e.g., ethylene and ethylene oxide). We estimate petrochemical production accounts for approximately 55 million metric tons CO2e. Total GHG emissions relevant to the petrochemical industry primarily include process-based emissions and emissions from combustion sources. Process-based emissions may be released to the atmosphere from process vents, equipment leaks, aerobic biological treatment systems, and in some cases, combustion source vents. CH4 may also be a process-based [[Page 16537]] emission from processes where CH4 is a feedstock (e.g., when methanol is produced from synthesis gas that is derived from reforming natural gas, some CH4 passes through the process without being converted and is emitted). Emissions from the burning of process off-gas to supply energy to the process are also process-based emissions because the organic compounds being burned are derived from the feedstock chemical. These emissions are included with other process-based emissions if the mass balance monitoring method (described in Section V.X.3 of this preamble) is used to estimate process-based emissions, but they are included with combustion source emissions if CEMS are used to measure emissions from all stacks. Combustion source emissions include CO2, CH4, and N2O emissions from combustion of either supplemental fuel alone (under the mass balance option) or combustion of both supplemental fuels and process off-gas (under the CEMS option). This difference in approach for emissions from the combustion of off- gas is necessary to avoid either double counting or not counting these emissions, particularly if off-gas and supplemental fuel are mixed in a fuel gas system. CH4 emissions from onsite wastewater treatment systems (if anaerobic) are another possible source of GHG emissions from the petrochemical industry, but these emissions are expected to be small because anaerobic wastewater treatment is not common at petrochemical facilities. CH4 emissions from onsite wastewater treatment systems would be estimated and reported according to the proposed procedures in proposed 40 CFR part 98, subpart II. The ratio of process-based emissions to supplemental fuel combustion emissions varies among the various petrochemical processes. For example, process-based emissions dominate for acrylonitrile, ethylene, and ethylene oxide processes. Both process-based and supplemental fuel combustion emissions are important for carbon black and methanol processes. Emissions from supplemental fuel combustion predominate for ethylene dichloride processes. Equipment leak and wastewater emissions are both estimated to be less than 1 percent of the total emissions from petrochemical production. For further discussion see the Petrochemical Production TSD (EPA- HQ-OAR-2008-0508-024). 2. Selection of Reporting Threshold We propose that every facility which includes within its boundaries methanol, acrylonitrile, ethylene, ethylene oxide, ethylene dichloride, or carbon black production be subject to the requirements of this proposed rule. In developing the proposed threshold for petrochemical facilities, we considered emissions-based thresholds of 1,000 metric tons CO2e, 10,000 metric tons CO2e, 25,000 metric tons CO2e and 100,000 metric tons CO2e. Table X-1 of this preamble illustrates the emissions and number of facilities that would be covered under the four threshold options. Table X-1. Threshold Analysis for Petrochemical Production -------------------------------------------------------------------------------------------------------------------------------------------------------- Total National Emissions covered Facilities covered Emissions, Total number --------------------------------------------------------------- Threshold level metric tons CO2e/yr metric tons of facilities Metric tons Number of CO2e/yr CO2e/yr Percent facilities Percent -------------------------------------------------------------------------------------------------------------------------------------------------------- 1,000................................................... 54,830,000 88 54,830,000 100 88 100 10,000.................................................. 54,830,000 88 54,820,000 99.98 87 98.9 25,000.................................................. 54,830,000 88 54,820,000 99.98 87 98.9 100,000................................................. 54,830,000 88 54,440,000 99.7 84 95.5 -------------------------------------------------------------------------------------------------------------------------------------------------------- The emissions presented in Table X-1 of this preamble are the total emissions associated solely with the production of methanol, acrylonitrile, ethylene, ethylene oxide, ethylene dichloride, or carbon black, not the total emissions from petrochemical facilities. An estimate of the total emissions was difficult to develop because many of these facilities contain multiple source categories. For example, some petrochemical operations occur at petroleum refineries. Other petrochemical manufacturing facilities produce chemicals such as ammonia or hydrogen that are also subject to reporting. In addition, numerous chemical manufacturing facilities produce other chemicals in addition to one or more of the petrochemicals; these facilities may have combustion sources associated with these other chemical manufacturing processes that are separate from the combustion sources for petrochemical processes. Based on this analysis, 87 of the 88 petrochemical facilities have estimated combustion and process-based GHG emissions that exceed the 25,000 metric tons CO2e/yr threshold, and 1 facility has estimated GHG emissions less than 10,000 metric tons CO2e/ yr. The facility with estimated GHG emissions less than 10,000 metric tons CO2e/yr is a carbon black facility. Considering that the threshold analysis did not include all types of emissions occurring at petrochemical facilities, and the large percentage of facilities that were above the various thresholds even when these emissions were excluded, EPA proposes that all facilities producing at least one of the petrochemicals report. This would simplify the rule and likely achieve the same result as having a 25,000 metric tons CO2e threshold. For a full discussion of the threshold analysis, please refer to the Petrochemical Production TSD (EPA-HQ-OAR-2008-0508-024). For specific information on costs, including unamortized first year capital expenditures, please refer to section 4 of the RIA and the RIA cost appendix. 3. Selection of Proposed Monitoring Methods We reviewed existing domestic and international GHG monitoring guidelines and protocols including the 2006 IPCC Guidelines and DOE 1605(b). Protocols included methods for both CO2 and CH4. From this review, we developed the following three options that share a number of features with the three Tiers presented by IPCC: Option 1. Apply default emission factors based on the type of process and site-specific activity data (e.g., measured or estimated annual production rate). This option is the same as the IPCC Tier 1 approach. Option 2. Perform a carbon balance to estimate CO2 emissions derived from carbon in feedstocks. Inputs to the carbon balance would be the flow and carbon content of each feedstock, and outputs would be the flow and carbon content of each product/byproduct. Organic liquid wastes that are collected for shipment offsite would also be considered an output in the carbon [[Page 16538]] balance. The difference between carbon inputs and outputs is assumed to be CO2 emissions. This includes all unconverted CH4 feedstock that is emitted. In addition, all CO2 that is recovered for sale or other use is considered an emission for the purposes of reporting for petrochemical processes. However, the volume of CO2 would be accounted for separately using the procedures in proposed 40 CFR part 98, subpart PP. This option would require continuous monitoring of liquid and gaseous flows using flow meters, measurement of solid feedstock and product flows using scales or other weighing devices, and determination of the carbon content of each feedstock and product/byproduct at least once per week. Supplemental fuel is not considered to be a feedstock because these fuels do not mix with process fluids (except in the furnace of a carbon black process) and would be calculated consistent with the monitoring methods in proposed 40 CFR part 98, subpart C. In addition to using the carbon balance to estimate process-based CO2 emissions, this option would require the petrochemical facility owner to estimate CO2, CH4, and N2O emissions from the combustion of supplemental fuels using the monitoring methods in proposed 40 CFR part 98, subpart C, and to estimate CH4 emissions from onsite wastewater treatment using the monitoring methods in proposed 40 CFR part 98, subpart II. Option 3. Direct and continuous measurement of CO2 emissions from each stack (process vent or combustion source) using a CEMS for CO2 concentration and a stack gas volumetric flow rate monitor. This option also would require the petrochemical facility owner to use engineering analyses to estimate flow and carbon content of gases discharged to flares using the same procedures described in Section V.Y.3 of this preamble for petroleum refineries. Just as at petroleum refineries, flares at petrochemical facilities are used to control a variety of emissions releases. In addition, the flow and composition of gas flared can change significantly. Therefore, the Agency is proposing the same methodology for petrochemical flares as for flares at petroleum refineries. Please refer to the petroleum refineries section (Section V.Y.3 of this preamble) for a discussion of the rationale for these procedures. We request comment on this approach as well as on descriptions of differences in operating conditions for flares at petrochemical facilities and refineries that would warrant specification of different methodologies for estimating emissions. In addition to measuring CO2 emissions from process vents and estimating CO2 emissions from flares, this option would require the petrochemical facility owner to calculate CH4 and N2O emissions from combustion sources using the monitoring methods in proposed 40 CFR part 98, subpart C, and to calculate CH4 emissions from onsite wastewater treatment systems using the monitoring methods in proposed 40 CFR part 98, subpart II. Proposed Options. Under this proposed rule, if you operate and maintain an existing CEMS that measures total CO2 from process vents and combustion sources, you would be required to follow requirements of proposed 40 CFR part 98, subpart C to estimate CO2 emissions from your facility. In such a circumstance, you also would be required to estimate CO2, CH4 and N2O emissions from flares. If you do not operate and maintain an existing CEMS that measures total CO2 from process vents and combustion sources for your facility, the proposed rule permits the use of either Options 2 or 3 since they account for process-based emissions, combustion source emissions, and wastewater treatment system emissions. Process-based CO2 emissions are estimated using procedures in proposed 40 CFR part 98, subpart X; combustion emissions (CO2, CH4, and N2O) and wastewater emissions (CH4) are calculated using methods in proposed 40 CFR part 98, subparts C and II, respectively. As discussed earlier, emissions from combustion of process off-gas are calculated with other process- based emissions (only CO2 emissions) under Option 2, but they are estimated using methods for combustion sources under Option 3 (CO2, CH4, and N2O emissions). Option 2 offers greater flexibility and a lower cost of compliance than Option 3. However it also has a higher measurement uncertainty. Option 3 is expected to have the lowest measurement uncertainty. However, using CEMS to monitor all emissions at petrochemical facilities would be relatively costly. For emissions estimates produced using Option 2, the uncertainty in these estimates is expected to be relatively low for most petrochemical processes. For ethylene dichloride and ethylene processes, the uncertainty of the carbon balance approach may be higher since it is influenced by the measurements of inputs and outputs at the facility and the percentage of carbon in the final product. Uncertainty may be high where the percentage of carbon in the product is close to 100 percent (since subtracting one large number for process output from another large number for process input results in relatively large uncertainty in the difference, even if the uncertainty in the two large numbers is low). For the petrochemical processes, we have decided that Option 2 is reasonable for purposes of this proposed rulemaking. However, direct measurement may provide improved emissions estimates. Option 1 was not proposed because the use of default values and lack of direct measurement results in a high level of uncertainty. These default approaches would not provide site-specific estimates of emissions that would reflect differences in feedstocks, operating conditions, catalyst selectivity, thermal/energy efficiencies, and other differences among plants. The use of default values is more appropriate for sector wide or national total estimates from aggregated activity data than for determining emissions from a specific facility. We request comment on how to improve the emission estimates developed using the carbon balance approach (Option 2), including whether the uncertainty in the estimated emissions can be reduced (and if so, by how much), the advantages, disadvantages, types and frequency of other measurements that could be required, costs of alternatives, how the uncertainty of alternatives is estimated, and the QA procedures that should be followed to assure accurate measurement. For further discussion of our assumptions on the uncertainty of emissions estimates see the Petrochemical Production TSD (EPA-HQ-OAR-2008-0508-024). Additional Issues and Requests for Comments. EPA is interested in public comment on four additional issues. Fugitive emissions from petrochemical production facilities have been of environmental interest primarily because of the VOC emissions. As noted above, we have concluded that fugitive CO2 and CH4 emissions contribute very little to the overall GHG emissions from the petrochemical production sector, and non- CH4 hydrocarbon losses assumed to be CO2 emissions overstate the emissions only slightly. Consequently, the Agency is not proposing that fugitive emissions be reported. Second, Option 2 assumes all carbon entering the process is released as CO2 and does not account for potential CH4 emissions, nor are N2O emissions estimated in this approach. EPA [[Page 16539]] believes CH4 and N2O emissions are small. Third, EPA is aware that a limited number of petrochemical facilities may produce petrochemicals as well as one or more other chemicals that are part of another source category (e.g.production of hydrogen for sale and the petrochemical methanol from synthesis gas created by steam reforming of CH4). We consider these ``integrated processes'' and request comment on whether the procedures for the affected source categories are clear and adequate for addressing emissions from integrated facilities. Fourth, we are proposing several methods for measuring the volume, carbon content and composition of feedstocks and products. There may be additional peer-reviewed and published measurement methodologies. Public comment on each of these four issues is welcomed. Where applicable, supporting data and documentation on how emissions should be included, and if so, how these emissions can be estimated, including the advantages, disadvantages, types and frequency of measurements that could be required, costs of alternatives, how the uncertainty of alternatives is estimated, and the QA procedures that should be followed to assure accurate measurement. 4. Selection of Procedures for Estimating Missing Data The missing data procedures in proposed 40 CFR part 98, subpart C for combustion units are proposed for facilities that use CEMS to estimate emissions from both combustion sources and process vents. Similarly, if the mass balance option is used, the same procedures that apply to missing data for fuel measurements in proposed 40 CFR part 98, subpart C would also apply to missing flow and carbon content measurements of feedstocks and products. Specifically, the substitute data value for missing carbon content, CO2 concentration, or stack gas moisture content values would be the average of the quality- assured values of the parameter immediately before and immediately after the missing data period. The substitute data value for missing feedstock, product, or stack gas flows would be the best available estimate based on all available process data. 5. Selection of Data Reporting Requirements Where CEMS are used, the reporting requirements specified in proposed 40 CFR part 98, subpart C would apply. Where the carbon balance method is used, we propose that the following information be reported: Identification of the process, annual CO2 emissions for each type of petrochemical produced and each process unit, the methods used to determine flows and carbon contents, the emissions calculation methodology, quantity of feedstocks consumed, quantity of each product and byproduct produced, carbon contents of each feedstock and product, information on the number of actual versus substitute data points, and the quantity of CO2 captured for use. In addition, owners and operators would report information related to all equipment calibrations; measurements, calculations, and other data; certifications; and any other QA procedures used to assess the uncertainty in emissions estimates. The data to be reported under the proposed rule form the basis of the emissions calculations and are needed for us to understand the emissions data and verify reasonableness of the reported emissions. The Agency requests comment on the types of QA procedures that are most commonly conducted or recommended and the information that would be most useful in assessing uncertainty of the emissions estimates. 6. Selection of Records That Must Be Retained Petrochemical production facilities would be required to keep records of the information specified in proposed 40 CFR 98.3, as applicable. Under the carbon balance option, a facility also would be required to keep records of all feedstock and product flows and carbon content determinations. If a petrochemical production facility complies with the CEMS option, the additional records for CEMS listed in proposed 40 CFR 98.37 would also be required for all CEMS, including CEMS on process stacks that are not associated with combustion sources. These records document values that are directly used to calculate the emissions that are reported and are necessary to enable verification that the GHG emissions monitoring and calculations were done correctly. Y. Petroleum Refineries 1. Definition of the Source Category Petroleum refineries are facilities engaged in producing gasoline, kerosene, distillate fuel oils, residual fuel oils, lubricants, asphalt (bitumen), or other products through distillation of petroleum or through redistillation, cracking, or reforming of unfinished petroleum derivatives. There are 150 operating petroleum refineries in the U.S. and its territories. Emissions from petroleum refineries account for approximately 205 million metric tons CO2e, representing approximately 3 percent of the U.S. nationwide GHG emissions. Most of these emissions are CO2 emissions from fossil fuel combustion. While the U.S. GHG Inventory does not separately report onsite fuel consumption at petroleum refineries, it estimates that approximately 0.6 million metric tons CO2e of CH4 are emitted as fugitives per year from petroleum refineries in the U.S. Most CO2 emissions at a refinery are combustion-related, accounting for approximately 67 percent of CO2 emissions at a refinery. The combustion of catalyst coke in catalyst cracking units is also a significant contributor to the CO2 emissions (approximately 25 percent) from petroleum refineries. Combustion of excess or waste fuel gas in flares contributes approximately 2 percent of the refinery's overall CO2 emissions. As such, the Agency proposes that the emissions from these sources must be reported. Process emissions of CO2 also occur from the sulfur recovery plant, because the amine solutions used to remove hydrogen sulfide (H2S) from the refinery's fuel gas adsorb CO2. The stripped sour gas from the amine adsorbers is fed to the sulfur recovery plant; the CO2 contained in this stream is subsequently released to the atmosphere. Most refineries have on-site sulfur recovery plants; however, a few refineries send their sour gas to neighboring sulfur recovery or sulfuric acid production facilities. The quantity of CO2 contained in the sour gas sent for off-site sulfur recovery operations is considered an emission under this regulation. There are a variety of GHG emission sources at the refinery, which include: Asphalt blowing, delayed coking unit depressurization and coke cutting, coke calcining, blowdown systems, process vents, process equipment leaks, storage tanks, loading operations, land disposal, wastewater treatment, and waste disposal. To fully account for the refinery's GHG emissions, we propose that the emissions from these sources must also be reported. Based on the emission sources at petroleum refineries, GHGs to report under proposed 40 CFR part 98, subpart Y are limited to CO2, CH4, and N2O. Table Y-1 of this preamble summarizes the GHGs to be reported by emission source at the refinery. [[Page 16540]] Table Y-1. GHGs to Report Under 40 CFR Part 98, Subpart Y ------------------------------------------------------------------------ Subpart of proposed 40 CFR part 98 where Emission source GHGs to report emissions reporting methodologies addressed ------------------------------------------------------------------------ Stationary combustion sources... CO2, CH4, and N2O. Subpart C. Coke burn-off emissions from CO2, CH4, and N2O. Subpart Y. catalytic cracking units, fluid coking units, catalytic reforming units, and coke calcining units. Flares.......................... CO2, CH4, and N2O. Subpart Y. Hydrogen plant vent............. CO2 and CH4....... Subpart P. Petrochemical processes......... CO2 and CH4....... Subpart X. Sulfur recovery plant, on-site CO2............... Subpart Y. and off-site. On-site wastewater treatment CO2 and CH4....... Subpart II. system. On-site land disposal unit...... CH4............... Subpart HH. Fugitive Emissions.............. CO2, CH4, and N2O. Subpart Y. Delayed coking units............ CH4............... Subpart Y. ------------------------------------------------------------------------ 2. Selection of Reporting Threshold Four options were considered as reporting thresholds for petroleum refineries. Table Y-2 of this preamble illustrates the emissions and number of facilities that would be covered under the four options. Table Y-2. Threshold Analysis for Petroleum Refining ---------------------------------------------------------------------------------------------------------------- Emissions covered Facilities covered ----------------------------------------------------- Option/threshold level Million metric tons Percent Number Percent CO2e/year ---------------------------------------------------------------------------------------------------------------- 1,000 metric tons CO2e.................................... 204.75 100 150 100 10,000 metric tons CO2e................................... 204.74 99.995 149 99.3 25,000 metric tons CO2e................................... 204.69 99.97 146 97.3 100,000 metric tons CO2e.................................. 203.75 99.51 128 85.3 ---------------------------------------------------------------------------------------------------------------- We are proposing that all petroleum refineries should report. This approach would ensure full reporting of emissions, affect an insignificant number of additional sources compared to the 25,000 metric tons CO2e threshold, and would add minimal additional burden to the reporting facilities. All U.S. refineries must report their fuel consumption to the EIA, so there is limited additional burden to estimate their GHG emissions. Furthermore, due to the importance of the petroleum refining industry to our nation's energy needs as well as the overall U.S. GHG inventory, it is important to obtain the best information available for this source category. We estimate that 4 refineries did not exceed a reporting threshold of 25,000 metric tons CO2e in 2006 and invite public comment on this matter. For a full discussion of the threshold analysis, please refer to the Petroleum Refineries TSD (EPA-HQ-OAR-2008-0508-025). For specific information on costs, including unamortized first year capital expenditures, please refer to section 4 of the RIA and the RIA cost appendix. 3. Selection of Proposed Monitoring Methods We considered monitoring methods that are used or recommended for use from several sources including international groups, U.S. agencies, State agencies, and petroleum refinery trade organizations. For most emission sources, three general levels of monitoring options were evaluated: (1) Use of engineering calculations and/or default factors; (2) monitoring of process parameters (such as fuel consumption quantities and carbon content); and (3) direct emission measurement using CEMS for all emissions sources at a refinery. Under this proposed rule, if you are required to use an existing CEMS to meet the requirements outlined in proposed 40 CFR part 98, subpart C, you would be required to use CEMS to estimate CO2 emissions. Where the CEMS capture all combustion- and process-related CO2 emissions you would be required to follow the calculation procedures, monitoring and QA/QC methods, missing data procedures, reporting requirements, and recordkeeping requirements of proposed 40 CFR part 98, subpart C to estimate CO2 emissions. Also, refer to proposed 40 CFR part 98, subpart C to estimate combustion-related CH4 and N2O emissions. For facilities that do not currently have CEMS that meet the requirements outlined in proposed 40 CFR part 98, subpart C, or where the CEMS would not adequately account for process emissions, the proposed monitoring method is Option 2. Option 2 accounts for process- related CO2 emissions. Simplified methods for estimating fugitive CH4 emissions are provided below. Refer to proposed 40 CFR part 98, subpart C specifically for procedures to estimate combustion-related CH4 and N2O emissions. You would be required to follow the calculation procedures, monitoring and QA/QC methods, missing data procedures, reporting requirements, and recordkeeping requirements of proposed 40 CFR part 98, subpart HH to estimate emissions from landfills, proposed 40 CFR part 98, subpart II to estimate emissions from wastewater and proposed 40 CFR part 98, subpart P to estimate emissions from hydrogen production (non-merchant hydrogen plants only). Specifically, for fluid catalytic cracking units and fluid coking units that already have CEMS in place, we [[Page 16541]] propose to require refineries to report CO2 emissions using these CEMS. For the sources that contribute significantly to the overall GHG emissions from the refinery, as defined below, we propose monitoring of process parameters (Option 2). The Agency requests comment on the feasibility of allowing smaller emission sources at the refinery to employ less certain (Option 1) methods as a way to reduce the costs and burden of measurement and verification under this proposed rule. Providing this flexibility would result in lower costs but greater uncertainty around some portions of a facility's emissions estimates. The selected monitoring methods for this proposed rule generally follow those used in other reporting rules as well as those recommended in the American Petroleum Institute's Compendium of Greenhouse Gas Emissions Estimation Methodologies for the Oil and Gas Industry (hereafter referred to as ``the API Compendium''). More detail regarding the selection of the proposed monitoring options for specific emission sources follows. Coke burn-off. The proposed methods for estimating GHG emissions from coke burn-off in the catalytic cracking unit, fluid coking unit, and catalytic reforming unit generally follow the methods presented in the API Compendium for coke burn-off. Fluid catalytic cracking units and fluid coking units are large CO2 emission sources, accounting for over 25 percent of the GHG emissions from petroleum refineries. Most of these units are expected to monitor gas composition for process control or for compliance with applicable monitoring provisions under 40 CFR part 60, subparts J and Ja and under 40 CFR part 63, subpart UUU. Given the magnitude of the GHG emissions from catalytic cracking units and fluid coking units, direct monitoring for CO2 emissions (i.e., continuous monitoring of CO2 concentration and flow rate at the final exhaust stack) is believed to provide greater certainty in the emission estimate. However, compositional analysis monitoring in the regenerator or fluid coking burner exhaust vent prior to the combustion of other fuels (such as auxiliary fuel fired to a CO boiler) may be used when direct monitoring for CO2 emissions is not already employed. An equation is provided in the rule for calculating the vent stream flow rate based on the compositional analysis data rather than requiring a continuous flow monitor; this equation is allowed in other petroleum refinery rules (40 CFR part 60, subparts J and Ja; 40 CFR part 63, subpart UUU) as an alternative to continuous flow monitoring. An engineering approach for estimating coke burn-off rates and calculating CO2 emissions using default carbon content for petroleum coke was considered. However, as most catalytic cracking units already must have the compositional monitors in-place due to other petroleum refinery rules and because catalytic cracking unit coke burn-off is a significant contributor to the overall GHG emissions from petroleum refineries, we are not proposing an engineering calculation for the catalytic cracking units. However, comment is requested on the engineering methods available to estimate coke burn-off rates, the uncertainty of the methods, and the measurements or parameters and enhanced QA that can be used to verify the engineering emission estimates and their certainty. The amount of coke burned in catalytic reforming units is estimated to be about 1 percent of the amount of coke burned in catalytic cracking units or fluid coking units; therefore, a simplified method is provided for estimating coke burn-off emissions for catalytic reforming units that do not monitor gas composition in the coke burn-off exhaust vent. Flares. Specific monitoring provisions are provided for flares. As the composition of gas flared can change significantly, we considered proposing continuous flow and composition monitors (or heating value monitors) on all flares. For example, in California, both the South Coast and Bay Area Air Quality Management Districts require these monitors for refineries located in their districts. However, a significant fraction of flares is not expected to have these monitoring systems installed. Further, since flares are projected to contribute only about 2 percent of a typical refinery's CO2 emissions, it would be costly to improve the monitoring systems for flare emission estimates. The use of the default CO2 emission factor for refinery fuel gas was also considered. The default emission factor is expected to be reasonable during normal refinery operations, but is highly uncertain during periods of start-up, shutdown, or malfunction. Consequently, a hybrid method is proposed that allows the use of a default CO2 emission factor for refinery fuel gas during periods of normal refinery operations and specific engineering analysis of GHG emissions during periods of high flare volumes associated with start-up, shutdown, or malfunction. As with stationary combustion sources, default emission factors for refinery gas are proposed to calculate CH4 and N2O emissions from flares. Sulfur Recovery Plants. For sulfur recovery plants at the petroleum refinery and for instances where sour gas is sent off-site for sulfur recovery, direct carbon content measurement in the sour gas feed to the sulfur recovery plant is the preferred monitoring approach. However, a site-specific or default carbon content method is also provided. It is anticipated that monitoring systems would be in place at most refineries, as monitoring of the sour gas feed is important in the operation of the sulfur recovery plant. The monitoring data for carbon content and flow rate must be used if they are available. The alternative default carbon content method is provided because the emissions from this source are relatively small, 1 to 2 percent for a given facility, and because only small, non-Claus sulfur recovery plants are not expected to monitor the flow and composition of the sour gas. We are proposing that only CO2 emissions would need to be reported for the sulfur recovery plant process-related emissions. Coke Calcining. For coke calcining units at the petroleum refinery, direct CO2 measurement is the preferred monitoring approach. However, a carbon balance approach is proposed similar to the approach included in The Aluminum Sector Greenhouse Gas Protocol \83\ for units that do not have CEMS. This is because coke calcining is a small source of GHG emissions, less than 1 percent for a given facility. CH4 and N2O emissions are calculated from the coke calcining CO2 process emissions using the default emission factors for petroleum coke combustion (the same equations as proposed for calculating CH4 and N2O emissions from coke burn-off). --------------------------------------------------------------------------- \83\ International Aluminum Institute. 2006. The Aluminum Sector Greenhouse Gas Protocol (Addendum to the WRI/WBCSD Greenhouse Gas Protocol). pp. 31-32. Available at: http://www.world-aluminium.org/ Downloads/Publications/Download. 2 percent. For previous years, where data are unavailable on waste disposal quantities, estimate the waste quantities according to the requirements in paragraphs (a)(4)(i) and (ii) of this section. (i) Calculate the average waste disposal rate per unit of production for the first applicable reporting year using Equation HH-2 of this section. [GRAPHIC] [TIFF OMITTED] TP10AP09.145 Where: WDF = Average waste disposal factor determined on the first year of reporting (metric tons per production unit). The average waste disposal factor should not be re-calculated in subsequent reporting years. N = Number of years for which disposal and production data are available. Wn = Quantity of waste placed in the industrial landfill in year n (metric tons). Pn = Quantity of product produced in year n (production units). (ii) Calculate the waste disposal quantities for historic years in which direct waste disposal measurements are not available using historical production data and Equation HH-3 of this section. [GRAPHIC] [TIFF OMITTED] TP10AP09.146 Where: X = Historic year in which waste was disposed. Wx = Projected quantity of waste placed in the landfill in year X (metric tons). WDF = Average waste disposal factor from Equation HH-1 of this section (metric tons per production unit). Px = Production quantity for the facility in year X from company records (production units). (b) For landfills with gas collection systems, calculate the quantity of CH4 destroyed according to the requirements in paragraphs (b)(1) through (4) of this section. (1) Measure continuously the flow rate, CH4 concentration, temperature, and pressure, of the collected landfill gas (before any treatment equipment) using a monitoring meter specifically for CH4 gas, as specified in Sec. 98.344. (2) Calculate the quantity of CH4 recovered for destruction using Equation HH-4 of this section. [[Page 16701]] [GRAPHIC] [TIFF OMITTED] TP10AP09.147 Where: R = Annual quantity of recovered CH4 (metric tons CH4). Vn = Daily average volumetric flow rate for day n (acfm). Cn = Daily average CH4 concentration of landfill gas for day n (%, wet basis). 0.0423 = Density of CH4 lb/scf (at 520[deg]R or 60[deg]F and 1 atm). Tn = Temperature at which flow is measured for day n ([deg]R). Pn = Pressure at which flow is measured for day n (atm). 1,440 = Conversion factor (min/day). 0.454/1,000 = Conversion factor (metric ton/lb). (c) Calculate CH4 generation (adjusted for oxidation in cover materials) and actual CH4 emissions (taking into account any CH4 recovery, and oxidation in cover materials) according to the applicable methods in paragraphs (d)(1) through (4) of this section. (1) Calculate CH4 generation, adjusted for oxidation, from the modeled CH4 (GCH4 from Equation HH-1) using Equation HH-5 of this section. [GRAPHIC] [TIFF OMITTED] TP10AP09.148 Where: MG = Methane generation from the landfill in the reporting year, adjusted for oxidation (metric tons CH4). GCH4 = Modeled methane generation rate in reporting year from Equation HH-1 of this section (metric tons CH4). OX = Oxidation fraction default rate is 0.1 (10%). (2) For landfills that do not have landfill gas collection systems, the CH4 emissions are equal to the CH4 generation calculated in Equation HH-5 of this section. (3) For landfills with landfill gas collection systems, calculate CH4 emissions using the methodologies specified in paragraphs (c)(3)(i) and (ii) of this section. (i) Calculate CH4 emissions from the modeled CH4 generation and measured CH4 recovery using Equation HH-6 of this section. [GRAPHIC] [TIFF OMITTED] TP10AP09.149 Where: Emissions = Methane emissions from the landfill in the reporting year (metric tons CH4). GCH4 = Modeled methane generation rate in reporting year from Equation HH-1 of this section or the quantity of recovered CH4 from Equation HH-4 of this section, whichever is greater (metric tons CH4). R = Quantity of recovered CH4 from Equation HH-4 of this section (metric tons). OX = Oxidation fraction default rate is 0.1 (10%). DE = Destruction efficiency (lesser of manufacturer's specified destruction efficiency and 0.99) (ii) Calculate CH4 generation and CH4 emissions using measured CH4 recovery and estimated gas collection efficiency and Equations HH-7 and HH-8, of this section. [GRAPHIC] [TIFF OMITTED] TP10AP09.150 [GRAPHIC] [TIFF OMITTED] TP10AP09.151 Where: MG = Methane generation from the landfill in the reporting year (metric tons CH4). Emissions = Methane emissions from the landfill in the reporting year (metric tons CH4). R = Quantity of recovered CH4 from Equation HH-4 of this section (metric tons CH4). CE = Collection efficiency estimated at landfill, taking into account system coverage, operation, and cover system materials. (Default is 0.75). OX = Oxidation fraction (default rate is 0.1 (10%)). DE = Destruction efficiency, (lesser of manufacturer's specified destruction efficiency and 0.99). Sec. 98.344 Monitoring and QA/QC requirements. (a) The quantity of waste landfilled must be determined using mass measurement equipment meeting the requirements for commercial weighing equipment as described in ``Specifications, Tolerances, and Other Technical Requirements For Weighing and Measuring Devices'' NIST Handbook 44, 2008. (b) The quantity of landfill gas CH4 destroyed must be determined using ASTM D1945-03 (Reapproved 2006), Standard Test Method for Analysis of Natural Gas by Gas Chromatography; ASTM D1946-90 (Reapproved 2006), Standard Practice for Analysis of Reformed Gas by Gas Chromatography; ASTM D4891-89 (Reapproved 2006), Standard Test Method for Heating Value of Gases in Natural Gas Range by Stoichiometric Combustion; or UOP539-97 Refinery Gas Analysis by Gas Chromatography (incorporated by reference, see Sec. 98.7). (c) All fuel flow meters and gas composition monitors shall be calibrated prior to the first reporting year, using ASTM D1945-03 (Reapproved 2006), Standard Test Method for Analysis of Natural Gas by Gas Chromatography; ASTM D1946-90 (Reapproved 2006), Standard Practice for Analysis of Reformed Gas by Gas Chromatography; ASTM D4891-89 (Reapproved 2006), Standard Test Method for Heating Value of Gases in Natural Gas Range by Stoichiometric Combustion; or UOP539-97 Refinery Gas Analysis by Gas Chromatography (incorporated by reference, see Sec. 98.7). Alternatively, calibration procedures specified by the flow meter manufacturer may be used. Fuel flow meters, and gas composition monitors shall be recalibrated either annually or at the minimum frequency specified by the manufacturer. (d) All temperature and pressure monitors must be calibrated using the procedures and frequencies specified by the manufacturer. (e) The owner or operator shall document the procedures used to ensure the accuracy of the estimates of disposal [[Page 16702]] quantities and, if applicable, gas flow rate, gas composition, temperature, and pressure measurements. These procedures include, but are not limited to, calibration of weighing equipment, fuel flow meters, and other measurement devices. The estimated accuracy of measurements made with these devices shall also be recorded, and the technical basis for these estimates shall be provided. Sec. 98.345 Procedures for estimating missing data. A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality- assured value of a required parameter is unavailable (e.g., if a meter malfunctions during unit operation or if a required fuel sample is not taken), a substitute data value for the missing parameter shall be used in the calculations, according to the requirements in paragraphs (a) through (c) of this section. (a) For each missing value of the CH4 content, the substitute data value shall be the arithmetic average of the quality- assured values of that parameter immediately preceding and immediately following the missing data incident. If, for a particular parameter, no quality-assured data are available prior to the missing data incident, the substitute data value shall be the first quality-assured value obtained after the missing data period. (b) For missing gas flow rates, the substitute data value shall be the arithmetic average of the quality-assured values of that parameter immediately preceding and immediately following the missing data incident. If, for a particular parameter, no quality-assured data are available prior to the missing data incident, the substitute data value shall be the first quality-assured value obtained after the missing data period. (c) For missing daily waste disposal data for disposal in reporting years, the substitute value shall be the average daily waste disposal quantity for that day of the week as measured on the week before and week after the missing daily data. Sec. 98.346 Data reporting requirements. In addition to the information required by Sec. 98.3(c), each annual report must contain the following information for each landfill. (a) Waste disposal for each year of landfilling. (b) Method for estimating waste disposal. (c) Waste composition, if available, in percentage categorized as-- (1) Municipal, (2) Construction and demolition, (3) Biosolids or biological sludges, (4) Industrial, inorganic, (5) Industrial, organic, (6) Other, or more refined categories, such as those for which k rates are available in Table HH-1 of this subpart. (d) Method for estimating waste composition. (e) Fraction of CH4 in landfill gas based on measured values if the landfill has a gas collection system or a default. (f) Oxidation fraction used in the calculations. (g) Degradable organic carbon (DOC) used in the calculations. (h) Decay rate k used in the calculations. (i) Fraction of DOC dissimilated used in the calculations. (j) Methane correction factor used in the calculations. (k) Annual methane generation and methane emissions (metric tons/ year) according to the methodologies in Sec. 98.343(c)(1) through (3). Landfills with gas collection system must separately report methane generation and emissions according to the methodologies in Sec. 98.343(c)(3)(i) and (ii) and indicate which values are calculated using the methodologies in Sec. 98.343(c)(ii). (l) Landfill design capacity. (m) Estimated year of landfill closure. (n) Total volumetric flow of landfill gas for landfills with gas collection systems. (o) CH4 concentration of landfill gas for landfills with gas collection systems. (p) Monthly average temperature at which flow is measured for landfills with gas collection systems. (q) Monthly average pressure at which flow is measured for landfills with gas collection systems. (r) Destruction efficiency used for landfills with gas collection systems. (s) Methane destruction for landfills with gas collection systems (total annual, metric tons/year). (t) Estimated gas collection system efficiency for landfills with gas collection systems. (u) Methodology for estimating gas collection system efficiency for landfills with gas collection systems. (v) Cover system description. (w) Number of wells in gas collection system. (x) Acreage and quantity of waste covered by intermediate cap. (y) Acreage and quantity of waste covered by final cap. (z) Total CH4 generation from landfills. (aa) Total CH4 emissions from landfills. Sec. 98.347 Records that must be retained. In addition to the information required by Sec. 98.3(g), you must retain the calibration records for all monitoring equipment. Sec. 98.348 Definitions. All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Table HH-1 of Subpart HH--Emissions Factors, Oxidation Factors and Methods ------------------------------------------------------------------------ Factor Default value Units ------------------------------------------------------------------------ Waste model--bulk waste option ------------------------------------------------------------------------ k (precipitation <20 inches/ 0.02................ yr-1 year). k (precipitation 20-40 0.038............... yr-1 inches/year). k (precipitation >40 inches/ 0.057............... yr-1 year). L0 (Equivalent to DOC = 0.067............... metric tons CH4/ 0.2028 when MCF=1, metric ton waste. DOCF=0.5, and F=0.5). ------------------------------------------------------------------------ Waste model--All MSW and industrial waste landfills ------------------------------------------------------------------------ MCF......................... 1................... .................... DOCF........................ 0.5................. .................... F........................... 0.5................. .................... ------------------------------------------------------------------------ [[Page 16703]] Waste model--MSW using waste composition option ------------------------------------------------------------------------ DOC (food waste)............ 0.15................ Weight fraction, wet basis. DOC (garden)................ 0.2................. Weight fraction, wet basis. DOC (paper)................. 0.4................. Weight fraction, wet basis. DOC (wood and straw)........ 0.43................ Weight fraction, wet basis. DOC (textiles).............. 0.24................ Weight fraction, wet basis. DOC (diapers)............... 0.24................ Weight fraction, wet basis. DOC (sewage sludge)......... 0.05................ Weight fraction, wet basis. DOC (bulk waste)............ 0.20................ Weight fraction, wet basis. k (food waste).............. 0.06 to 0.185 \a\... yr-1 k (garden).................. 0.05 to 0.10 \a\.... yr-1 k (paper)................... 0.04 to 0.06 \a\.... yr-1 k (wood and straw).......... 0.02 to 0.03 \a\.... yr-1 k (textiles)................ 0.04 to 0.06 \a\.... yr-1 k (diapers)................. 0.05 to 0.10 \a\.... yr-1 k (sewage sludge)........... 0.06 to 0.185 \a\... yr-1 ------------------------------------------------------------------------ Waste model--Industrial waste landfills ------------------------------------------------------------------------ DOC (food processing)....... 0.15................ Weight fraction, wet basis. DOC (pulp and paper)........ 0.2................. Weight fraction, wet basis. k (food processing)......... 0.185............... yr-1 k (pulp and paper).......... 0.06................ yr-1 ------------------------------------------------------------------------ Calculating methane generation and emissions ------------------------------------------------------------------------ OX.......................... 0.1................. DE.......................... 0.99................ ------------------------------------------------------------------------ \a\ Use the lesser value when the potential evapotranspiration rate exceeds the mean annual precipitation rate and the greater value when it does not. Table HH-2 of Subpart HH--U.S. Per Capita Waste Disposal Rates ------------------------------------------------------------------------ Waste per Year capita ton/cap/ % to SWDS yr ------------------------------------------------------------------------ 1940.................................... 0.64 100 1941.................................... 0.64 100 1942.................................... 0.64 100 1943.................................... 0.64 100 1944.................................... 0.63 100 1945.................................... 0.64 100 1946.................................... 0.64 100 1947.................................... 0.63 100 1948.................................... 0.63 100 1949.................................... 0.63 100 1950.................................... 0.63 100 1951.................................... 0.63 100 1952.................................... 0.63 100 1953.................................... 0.63 100 1954.................................... 0.63 100 1955.................................... 0.63 100 1956.................................... 0.63 100 1957.................................... 0.63 100 1958.................................... 0.63 100 1959.................................... 0.63 100 1960.................................... 0.63 100 1961.................................... 0.64 100 1962.................................... 0.64 100 1963.................................... 0.65 100 1964.................................... 0.65 100 1965.................................... 0.66 100 1966.................................... 0.66 100 1967.................................... 0.67 100 1968.................................... 0.68 100 1969.................................... 0.68 100 1970.................................... 0.69 100 1971.................................... 0.69 100 1972.................................... 0.70 100 1973.................................... 0.71 100 [[Page 16704]] 1974.................................... 0.71 100 1975.................................... 0.72 100 1976.................................... 0.73 100 1977.................................... 0.73 100 1978.................................... 0.74 100 1979.................................... 0.75 100 1980.................................... 0.75 100 1981.................................... 0.76 100 1982.................................... 0.77 100 1983.................................... 0.77 100 1984.................................... 0.78 100 1985.................................... 0.79 100 1986.................................... 0.79 100 1987.................................... 0.80 100 1988.................................... 0.80 100 1989.................................... 0.85 84 1990.................................... 0.84 77 1991.................................... 0.78 76 1992.................................... 0.76 72 1993.................................... 0.78 71 1994.................................... 0.77 67 1995.................................... 0.72 63 1996.................................... 0.71 62 1997.................................... 0.72 61 1998.................................... 0.78 61 1999.................................... 0.78 60 2000.................................... 0.84 61 2001.................................... 0.95 63 2002.................................... 1.06 66 2003.................................... 1.06 65 2004.................................... 1.06 64 2005.................................... 1.06 64 2006.................................... 1.06 64 ------------------------------------------------------------------------ Subpart II--Wastewater Treatment Sec. 98.350 Definition of source category. (a) A wastewater treatment system is the collection of all processes that treat or remove pollutants and contaminants, such as soluble organic matter, suspended solids, pathogenic organisms, and chemicals from waters released from industrial processes. This source category applies to on-site wastewater treatment systems at pulp and paper mills, food processing plants, ethanol production plants, petrochemical facilities, and petroleum refining facilities. (b) This source category does not include centralized domestic wastewater treatment plants. Sec. 98.351 Reporting threshold. You must report GHG emissions under this subpart if your facility contains a wastewater treatment process and the facility meets the requirements of either Sec. 98.2(a)(1) or (2). Sec. 98.352 GHGs to report. (a) You must report annual CH4 emissions from anaerobic wastewater treatment processes. (b) You must report annual CO2 emissions from oil/water separators at petroleum refineries. (c) You must report CO2, CH4, and N2O emissions from the combustion of fuels in stationary combustion devices and fuels used in flares by following the requirements of subpart C of this part. For flares, calculate the CO2 emissions only from pilot gas and other auxiliary fuels combusted in the flare, as specified in subpart C of this part. Do not include CO2 emissions resulting from the combustion of anaerobic digester gas. Sec. 98.353 Calculating GHG emissions. (a) Estimate the annual CH4 mass emissions from systems other than digesters using Equation II-1 of this section. The value of flow and COD must be determined in accordance with the monitoring requirements specified in Sec. 98.354. The flow and COD should reflect the wastewater treated anaerobically on site in anaerobic systems such as lagoons. [GRAPHIC] [TIFF OMITTED] TP10AP09.152 Where: CH4 = Annual CH4 mass emissions from the wastewater treatment system (metric tons). Flown = Volumetric flow rate of wastewater sent to an anaerobic treatment system in month n (m\3\/month). COD = Average monthly value for chemical oxygen demand of wastewater entering anaerobic treatment systems other than digesters (kg/m\3\). B0 = Maximum CH4 producing potential of wastewater (kg CH4/kg COD), default is 0.25. [[Page 16705]] MCF = CH4 conversion factor, based on relevant values in Table II-1. 0.001 = Conversion factor from kg to metric tons. (b) For each petroleum refining facility having an on-site oil/ water separator, estimate the annual CO2 mass emissions using Equation II-2 using measured values for the volume of wastewater treated, and default values for emission factors by separator type from Table II-1 of this subpart. The flow should reflect the wastewater treated in the oil/water separator. [GRAPHIC] [TIFF OMITTED] TP10AP09.153 Where: CO2 = Annual emissions of CO2 from oil/water separators (metric tons/yr). EFsep = Emissions factor for the type of separator (kg NMVOC/m\3\ wastewater treated). VH20 = Volumetric flow rate of wastewater treated through oil/water separator in month m (m\3\/month). C = Carbon fraction in NMVOC (default = 0.6). 44/12 = Conversion factor for carbon to carbon dioxide. 0.001 = Conversion factor from kg to metric tons. (c) For each anaerobic digester, estimate the annual mass of CH4 destroyed using Equations II-3 and II-4 of this section. [GRAPHIC] [TIFF OMITTED] TP10AP09.154 Where: CH4d = Annual quantity of CH4 destroyed (kg/ yr). CH4AD = Annual quantity of CH4 generated by anaerobic digester, as calculated in Equation II-4 of this section (metric tons CH4). DE = CH4 destruction efficiency from flaring or burning in engine (lesser of manufacturer's specified destruction efficiency and 0.99). [GRAPHIC] [TIFF OMITTED] TP10AP09.155 Where: CH4AD = Annual quantity of CH4 generated by anaerobic digestion (metric tons CH4/yr). Vn = Daily average volumetric flow rate for day n, as determined from daily monitoring specified in Sec. 98.354 (acfm). Cn = Daily average CH4 concentration of digester gas for day n, as determined from daily monitoring specified in Sec. 98.354 (%, wet basis). 0.0423 = Density of CH4 lb/scf (at 520 [deg]R or 60 [deg]F and 1 atm). Tn = Temperature at which flow is measured for day n ([deg]R). Pn = Pressure at which flow is measured for day n (atm). Sec. 98.354 Monitoring and QA/QC requirements. (a) The quantity of COD treated anaerobically must be determined using analytical methods for industrial wastewater pollutants and must be conducted in accordance with the methods specified in 40 CFR part 136. (b) All flow meters must be calibrated using the procedures and frequencies specified by the device manufacturer. (c) For anaerobic treatment systems, facilities must monitor the wastewater flow and COD no less than once per week. The sample location must represent the influent to anaerobic treatment for the time period that is monitored. The flow sample must correspond to the location used to measure the COD. Facilities must collect 24-hour flow-weighted composite samples, unless they can demonstrate that the COD concentration and wastewater flow into the anaerobic treatment system does not vary. In this case, facilities must collect 24-hour time- weighted composites to characterize changes in wastewater due to production fluctuations, or a grab sample if the influent flow is equalized resulting in little variability. (d) For oil/water separators, facilities must monitor the flow no less than once per week. The sample location must represent the influent to oil/water separator for the time period that is monitored. (e) The quantity of gas destroyed must be determined using any of the oil and gas flow meter test methods incorporated by reference in Sec. 98.7. (f) All gas flow meters and gas composition monitors shall be calibrated prior to the first reporting year, using a suitable method published by a consensus standards organization (e.g., ASTM, ASME, API, AGA, or others). Alternatively, calibration procedures specified by the flow meter manufacturer may be used. Gas flow meters and gas composition monitors shall be recalibrated either annually or at the minimum frequency specified by the manufacturer. (g) All temperature and pressure monitors must be calibrated using the procedures and frequencies specified by the device manufacturer. (h) All equipment (temperature and pressure monitors and gas flow meters and gas composition monitors) shall be maintained as specified by the manufacturer. (i) If applicable, the owner or operator shall document the procedures used to ensure the accuracy of gas flow rate, gas composition, temperature, and pressure measurements. These procedures include, but are not limited to, calibration fuel flow meters, and other measurement devices. The estimated accuracy of measurements made with these devices shall also be recorded, and the technical basis for these estimates shall be provided. Sec. 98.355 Procedures for estimating missing data. A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality- assured value of a required parameter is unavailable (e.g., if a meter malfunctions during unit operation or if a required fuel sample is not taken), a substitute data value for the missing parameter shall be used in the calculations, according to the following requirements in paragraphs (a) and (b) of this section: (a) For each missing monthly value of COD or wastewater flow treated, the substitute data value shall be the arithmetic average of the quality-assured values of those parameters for the weeks immediately preceding and immediately following the missing data incident. For each missing value of the CH4 content or gas flow rates, the substitute data value shall be the arithmetic average of the quality-assured values of that parameter immediately preceding and [[Page 16706]] immediately following the missing data incident. (b) If, for a particular parameter, no quality-assured data are available prior to the missing data incident, the substitute data value shall be the first quality-assured value obtained after the missing data period. Sec. 98.356 Data reporting requirements. In addition to the information required by Sec. 98.3(c), each annual report must contain the following information for the wastewater treatment system. (a) Type of wastewater treatment system. (b) Percent of wastewater treated at each system component. (c) COD. (d) Influent flow rate. (e) B0. (f) MCF. (g) Methane emissions. (h) Type of oil/water separator (petroleum refineries). (i) Emissions factor for the type of separator (petroleum refineries). (j) Carbon fraction in NMVOC (petroleum refineries). (k) CO2 emissions (petroleum refineries). (l) Total volumetric flow of digester gas (facilities with anaerobic digesters). (m) CH4 concentration of digester gas (facilities with anaerobic digesters). (n) Temperature at which flow is measured (facilities with anaerobic digesters). (o) Pressure at which flow is measured (facilities with anaerobic digesters). (p) Destruction efficiency used (facilities with anaerobic digesters). (q) Methane destruction (facilities with anaerobic digesters). (r) Fugitive methane (facilities with anaerobic digesters). Sec. 98.357 Records that must be retained. In addition to the information required by Sec. 98.3(g), you must retain the calibration records for all monitoring equipment. Sec. 98.358 Definitions. All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Table II-1 of Subpart II--Emission Factors ------------------------------------------------------------------------ Default Factors value Units ------------------------------------------------------------------------ B0............................... 0.25 Kg CH4/kg COD. MCF--anaerobic deep lagoon, 0.8 Fraction. anaerobic reactor (e.g., upflow anaerobic sludge blanket, fixed film). MCF--anaerobic shallow lagoon 0.2 Fraction. (less than 2 m). MCF--centralized aerobic 0 Fraction. treatment system, well managed. MCF--Centralized aerobic 0.3 Fraction. treatment system, not well managed (overloaded). Anaerobic digester for sludge.... 0.8 Fraction. C fraction in NMOC............... 0.6 Fraction. EF sep--Gravity Type (Uncovered). 1.11E-01 Kg NMVOC/m\3\ wastewater EF sep--Gravity Type (Covered)... 3.30E-03 Kg NMVOC/m\3\ wastewater. EF sep--Gravity Type--(Covered 0 Kg NMVOC/m\3\ and Connected to a Destruction wastewater. Device). DAF or IAF--uncovered............ 4.00E-34 Kg NMVOC/m\3\ wastewater. DAF or IAF--covered.............. 1.20E-44 Kg NMVOC/m\3\ wastewater. DAF or IAF--covered and connected 0 Kg NMVOC/m\3\ to a destruction device. wastewater. ------------------------------------------------------------------------ DAF = dissolved air flotation type. IAF = induced air flotation type. Subpart JJ--Manure Management Sec. 98.360 Definition of the source category. (a) This source category consists of manure management systems for livestock manure. (b) A manure management system is as a system that stabilizes or stores livestock manure in one or more of the following system components: uncovered anaerobic lagoons, liquid/slurry systems, storage pits, digesters, drylots, solid manure storage, feedlots and other dry lots, high rise houses for poultry production (poultry without litter), poultry production with litter, deep bedding systems for cattle and swine, and manure composting. This definition of manure management system encompasses the treatment of wastewaters from manure. (c) This source category does not include components at a livestock operation unrelated to the stabilization or storage of manure such as daily spread or pasture/range/paddock systems. Sec. 98.361 Reporting threshold. You must report GHG emissions under this subpart if your facility contains a manure management system and the facility meets the requirements of either Sec. 98.2(a)(1) or (2). Sec. 98.362 GHGs to report. (a) You must report annual aggregate CH4 and N2O emissions for each of the following manure management system (MMS) components at the facility: (1) Liquid/slurry systems such as tanks and ponds. (2) Storage pits. (3) Uncovered anaerobic lagoons used for stabilization or storage or both. (4) Digesters, including covered anaerobic lagoons. (5) Solid manure storage including feedlots and other dry lots, high rise houses for caged laying hens, broiler and turkey production on litter, and deep bedding systems for cattle and swine. (6) Manure composting. (b) You must report CO2, CH4, and N2O emissions from the combustion of supplemental fuels used in flares by following the requirements of subpart C of this part. For flares, calculate the CO2 emissions only from pilot gas and other auxiliary fuels combusted in the flare, as specified in subpart C of this part. Do not include CO2 emissions resulting from the combustion of digester gas in flares. (c) A facility that is subject to this rule only because of emissions from manure management systems is not required to report emissions from fuels used in stationary combustion devices other than flares. [[Page 16707]] Sec. 98.363 Calculating GHG emissions. (a) For manure management systems except digesters, estimate the annual CH4 emissions using Equation JJ-1. [GRAPHIC] [TIFF OMITTED] TP10AP09.156 Where: TVS = Total volatile solids excreted by animal type, calculated using Equation JJ-2 of this section (kg/day). VSMMS = Percent of manure that is managed in each MMS (decimal) (assumed to be equivalent to the amount of VS in each system). B0 = Maximum CH4-producing capacity, as specified in Table JJ-1 of this section (m\3\ CH4/kg VS). MCFMMS = CH4 conversion factor for MMS, as specified in Table JJ-2 of this section (decimal). [GRAPHIC] [TIFF OMITTED] TP10AP09.187 Where: TVS = Total volatile solids excreted per animal type (kg/day). %TVS = Annual average percent total volatile solids by animal type, as determined from monthly manure monitoring as specified in Sec. 98.364 (decimal). Population = Average annual animal population (head). TAM = Typical animal mass, using either default values in Table JJ-1 of this section or farm-specific data (kg/head). MER = Manure excretion rate, using either default values in Table JJ-1 of this section or farm-specific data (kg manure/day/1,000 kg animal mass). (b) For each digester, estimate the annual CH4 flow to the combustion device using Equation JJ-3 of this section, the amount of CH4 destroyed using Eq JJ-4 of this section, and the amount of CH4 leakage using Equation JJ-5 of this section. [GRAPHIC] [TIFF OMITTED] TP10AP09.157 Where: CH4D = Methane flow to digester combustion device (metric tons CH4/yr) Vn = Daily average volumetric flow rate for day n, as determined from daily monitoring as specified in Sec. 98.364 (acfm). Cn = Daily average CH4 concentration of digester gas for day n, as determined from daily monitoring as specified in Sec. 98.364 (%, wet basis) 0.0423 = Density of CH4 lb/scf (at 520 [deg]R or 60 [deg]F and 1 atm). Tn = Temperature at which flow is measured for day n([deg]R). Pn = Pressure at which flow is measured for day n (atm). [GRAPHIC] [TIFF OMITTED] TP10AP09.158 Where: CH4D = Annual quantity of CH4 flow to digester combustion device, as calculated in Equation JJ-4 of this section (metric tons CH4). DE = CH4 destruction efficiency from flaring or burning in engine (lesser of manufacturer's specified destruction efficiency and 0.99). OH = Number of hours combustion device is functioning in reporting year. Hours = Hours in reporting year. [GRAPHIC] [TIFF OMITTED] TP10AP09.159 CH4D = Annual quantity of CH4 combusted by digester, as calculated in Equation JJ-4 of this section (metric tons CH4). CE = CH4 collection efficiency of anaerobic digester, as specified in Table JJ-3 of this section (decimal). (c) For each manure management system type, estimate the annual N2O emissions using Equation JJ-6 of this section. [GRAPHIC] [TIFF OMITTED] TP10AP09.160 [[Page 16708]] Where: Nex = Total nitrogen excreted per animal type, calculated using Equation JJ-7 of this section (kg/day). Nex,MMS = Percent of manure that is managed in each MMS (decimal) (assumed to be equivalent to the amount of Nex in each system). EFMMS = Emission factor for MMS, as specified in Table JJ-4 of this section (kg N2O-N/kg N). [GRAPHIC] [TIFF OMITTED] TP10AP09.161 Where: Nex = Total nitrogen excreted per animal type (kg/day). NManure = Annual average percent of nitrogen present in manure by animal type, as determined from monthly manure monitoring, as specified in Sec. 98.364 (decimal). Population = Average annual animal population (head). TAM = Typical animal mass, using either default values in Table JJ-1 of this section or farm-specific data (kg/head). MER = Manure excretion rate, using either default values in Table JJ-1 of this section or farm-specific data (kg manure/day/1,000 kg animal mass). (d) Estimate the annual total annual emissions using Equation JJ-8 of this section. [GRAPHIC] [TIFF OMITTED] TP10AP09.162 Where: CH4 emissions = From Equation JJ-1 of this section. CH4 flow to digester combustion device = From Equation JJ-3 of this section. CH4 destruction of digester = From Equation JJ-4 of this section. CH4 leakage of digester = From Equation JJ-5 of this section. 21 = Global Warming Potential of CH4. Direct N2O emissions = from Equation JJ-6 of this section. 310 = Global Warming Potential of N2O. Sec. 98.364 Monitoring and QA/QC requirements. (a) Perform a one-time analysis on your operation to determine the percent of total manure by weight that is managed in each on-site manure management system. (b) Determine the annual average percent total volatile solids by animal type, (%TVS) by analysis of a representative sample using Method 160.4 (Residue, Volatile) as described in Methods for Chemical Analysis of Water and Wastes, EPA-600/4-79/020, Revised March 1983. The laboratory performing the analyses should be certified for analysis of waste for National Pollutant Discharge Elimination System compliance reporting. The sample analyzed should be a representative composite of freshly excreted manure from each animal type contributing to the manure management system. Total volatile solids of manure must be sampled and analyzed monthly. (c) Determine the annual average percent of nitrogen present in manure by animal type (NManure) by analysis of a representative sample using Method 351.3 as described in Methods for Chemical Analysis of Water and Wastes, EPA-600/4-79-020, Revised March 1983. The laboratory performing the analyses should be certified for analysis of waste for National Pollutant Discharge Elimination System compliance reporting. The sample analyzed should be a representative composite of freshly excreted manure from each animal type contributing to the manure management system. Sample collection and analysis must be monthly. (d) The flow and CH4 concentration of gas from digesters must be determined using ASTM D1945-03 (Reapproved 2006), Standard Test Method for Analysis of Natural Gas by Gas Chromatography; ASTM D1946-90 (Reapproved 2006), Standard Practice for Analysis of Reformed Gas by Gas Chromatography; ASTM D4891-89 (Reapproved 2006), Standard Test Method for Heating Value of Gases in Natural Gas Range by Stoichiometric Combustion; or UOP539-97 Refinery Gas Analysis by Gas Chromatography (incorporated by reference in Sec. 98.7). (e) All temperature and pressure monitors must be calibrated using the procedures and frequencies specified by the manufacturer. (f) All gas flow meters and gas composition monitors shall be calibrated prior to the first reporting year, using a suitable method published by a consensus standards organization (e.g., ASTM, ASME, API, AGA, or others). Alternatively, calibration procedures specified by the flow meter manufacturer may be used. Gas flow meters and gas composition monitors shall be recalibrated either annually or at the minimum frequency specified by the manufacturer. (g) All equipment (temperature and pressure monitors and gas flow meters and gas composition monitors) shall be maintained as specified by the manufacturer. (h) If applicable, the owner or operator shall document the procedures used to ensure the accuracy of gas flow rate, gas composition, temperature, and pressure measurements. These procedures include, but are not limited to, calibration of fuel flow meters, and other measurement devices. The estimated accuracy of measurements made with these devices shall also be recorded, and the technical basis for these estimates shall be provided. Sec. 98.365 Procedures for estimating missing data. (a) A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality- assured value of a required parameter is unavailable (e.g., if a meter malfunctions during unit operation or if a required fuel sample is not taken), a substitute data value for the missing parameter shall be used in the calculations, according to the requirements in paragraph (b) of this section. (b) For missing gas flow rates, volatile solids, or nitrogen or methane content data, the substitute data value shall be the arithmetic average of the quality-assured values of that parameter immediately preceding and immediately following the missing data incident. If, for a particular parameter, no quality-assured data are available prior to the missing data incident, the substitute data value shall be the first quality-assured value obtained after the missing data period. Sec. 98.366 Data reporting requirements. In addition to the information required by Sec. 98.3(c), each annual report [[Page 16709]] must contain the following information for each manure management system component: (a) Type of manure management system component. (b) Animal population (by animal type). (c) Monthly total volatile solids content of excreted manure. (d) Percent of manure handled in each manure management system component. (e) B0 value used. (f) Methane conversion factor used. (g) Average animal mass (for each type of animal). (h) Monthly nitrogen content of excreted manure. (i) N2O emission factor selected. (j) CH4 emissions (k) N2O emissions. (l) Total annual volumetric biogas flow (for systems with digesters). (m) Average annual CH4 concentration (for systems with digesters). (n) Temperature at which gas flow is measured (for systems with digesters). (o) Pressure at which gas flow is measured (for systems with digesters). (p) Destruction efficiency used (for systems with digesters). (q) Methane destruction (for systems with digesters). (r) Methane generation from the digesters. Sec. 98.367 Records that must be retained. In addition to the information required by Sec. 98.3(g), you must retain the calibration records for all monitoring equipment. Sec. 98.368 Definitions. All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Table JJ-1 of Subpart JJ--Waste Characteristics Data ------------------------------------------------------------------------ Maximum Animal Manure methane group excretion generation Animal group typical rate (kg/ potential, animal mass day/1000 kg Bo (m3 CH4/ (kg) animal kg VS mass) added) ------------------------------------------------------------------------ Dairy Cows....................... 604 80.34 0.24 Dairy Heifers.................... 476 85 0.17 Feedlot Steers................... 420 51.2 0.33 Feedlot Heifers.................. 420 51.2 0.33 Market Swine <60 lbs............. 16 106 0.48 Market Swine 60-119 lbs.......... 41 63.4 0.48 Market Swine 120-179 lbs......... 68 63.4 0.48 Market Swine >180 lbs............ 91 63.4 0.48 Breeding Swine................... 198 31.8 0.48 Feedlot Sheep.................... 25 40 0.36 Goats............................ 64 41 0.17 Horses........................... 450 51 0.33 Hens >/= 1 yr.................... 1.8 60.5 0.39 Pullets.......................... 1.8 45.6 0.39 Other Chickens................... 1.8 60.5 0.39 Broilers......................... 0.9 80 0.36 Turkeys.......................... 6.8 43.6 0.36 ------------------------------------------------------------------------ [[Page 16710]] [GRAPHIC] [TIFF OMITTED] TP10AP09.163 Table JJ-3 of Subpart JJ--Collection Efficiencies of Anaerobic Digesters ------------------------------------------------------------------------ Methane System type Cover type collection efficiency ------------------------------------------------------------------------ Covered anaerobic lagoon.......... Bank to bank, 0.975 impermeable. (biogas capture).................. Modular, impermeable 0.70 Complete mix, fixed film, or plug Enclosed Vessel..... 0.99 flow digester. ------------------------------------------------------------------------ Table JJ-4 of Subpart JJ--Nitrous Oxide Emission Factors (kg N2O-N/kg Kjdl N) ------------------------------------------------------------------------ N2O Waste management system emission factor ------------------------------------------------------------------------ Aerobic Treatment (forced aeration)........................ 0.005 Aerobic Treatment (natural aeration)....................... 0.01 Digester................................................... 0 Uncovered Anaerobic Lagoon................................. 0 Cattle Deep Bed (active mix)............................... 0.07 Cattle Deep Bed (no mix)................................... 0.01 Manure Composting (in vessel).............................. 0.006 Manure Composting (intensive).............................. 0.1 Manure Composting (passive)................................ 0.01 Manure Composting (static)................................. 0.006 [[Page 16711]] Deep Pit................................................... 0.002 Dry Lot.................................................... 0.02 Liquid/Slurry.............................................. 0.005 Poultry with bedding....................................... 0.001 Poultry without bedding.................................... 0.001 Solid Storage.............................................. 0.005 ------------------------------------------------------------------------ Subpart KK--Supplies of Coal Sec. 98.370 Definition of the source category. (a) This source category comprises coal mines, coal importers, coal exporters, and waste coal reclaimers. (b) Coal mine means any active U.S. coal mine engaged in the production of coal within the U.S. during the calendar year regardless of the rank of coal produced, e.g., bituminous, sub-bituminous, lignite, anthracite. Any coal mine categorized as an active coal mine by MSHA is included. (c) Coal importer has the same meaning given in Sec. 98.6 and includes any U.S. coal mining company, wholesale coal dealer, retail coal dealer, or other organization that imports coal into the U.S. ``Importer'' includes the person primarily liable for the payment of any duties on the merchandise or an authorized agent acting on his or her behalf. (d) Coal exporter has the same meaning given in Sec. 98.6 and includes any U.S. coal mining company, wholesale coal dealer, retail coal dealer, or other organization that exports coal from the U.S. (e) Waste coal reclaimer means any U.S. facility that reclaims or recovers waste coal from waste coal piles from previous mining operations and sells or delivers to an end-user. Sec. 98.371 Reporting threshold. Any supplier of coal who meets the requirements of Sec. 98.2(a)(4) must report GHG emissions. Sec. 98.372 GHGs to report. You must report the CO2 emissions that would result from the complete combustion or oxidation of coal supplied during the calendar year. Sec. 98.373 Calculating GHG emissions. (a) For coal mines producing 100,000 short tons of coal or more annually, the estimate of CO2 emissions shall be calculated using either Calculation Methodology 1 or Calculation Methodology 2 of this subpart. (b) For coal mines producing less than 100,000 short tons of coal annually, and for coal exporters, coal importers, and waste coal reclaimers; CO2 emissions shall be calculated using either Calculation Methodology 1, 2, or 3 of this subpart. (c) For Calculation Methodology 1, 2, and 3 of this subpart, emissions of CO2 shall be calculated using Equation KK-1 of this section. The difference between Calculation Methodology 1, 2, and 3 of this subpart, is the method for determining the carbon content in coal, as specified in paragraphs (d), (e), and (f) of this section: [GRAPHIC] [TIFF OMITTED] TP10AP09.164 Where: CO2 = Annual CO2 mass emissions from the combustion of coal (metric tons/yr). 44/12 = Ratio of molecular weights, CO2 to carbon. Mass = Quantity of coal produced from company records (short tons/yr). Carbon = Annual weighted average fraction of carbon in the coal (decimal value). 0.907 = Conversion factor from short tons to metric tons. (d) For coal mines using Calculation Methodology 1 of this subpart, the annual weighted average of the mass fraction of carbon in the coal shall be based on daily measurements and calculated using Equation KK-2 of this section. For importers, exporters, and waste coal reclaimers using Methodology 1 of this subpart, measurements of each shipment can be used in place of daily measurements: [GRAPHIC] [TIFF OMITTED] TP10AP09.165 Where: Carbon = Annual mass fraction of coal carbon (dimensionless). Xi = Daily or per shipment mass fraction of carbon in coal for day i measured by ultimate analysis (decimal value). Yi = Amount of coal supplied on day i(short tons) as measured. n = Number of operating days per year. S = Total coal supplied during the year (short tons). (e) For coal mines using Calculation Methodology 2 of this subpart, the annual weighted average of the mass fraction of carbon in the coal shall be calculated on the basis of daily measurements of the gross calorific value (GCV) of the coal and a statistical relationship between carbon content and GCV (higher heating value). For importers, exporters, and waste coal reclaimers using Calculation Methodology 2 of this subpart, measurements of each shipment can be used in place of daily measurements. (1) Equation KK-3 shall be used to determine the weighted annual average GCV of the coal, and the individual daily or per shipment values shall be determined according to the monitoring methodology for gross calorific values in Sec. 98.374(f). (2) The statistical relationship between GCV and carbon content shall be established according to the requirements in Sec. 98.374(f). (3) The estimated annual weighted average of the mass fraction of carbon in the coal shall be calculated by applying the slope coefficient, determined according to the requirements of Sec. 98.374(f)(4), to the weighted annual average GCV of the coal determined according to Equation KK-3 of this section. (f) For coal mines using Calculation Methodology 3 of this subpart, the annual weighted average of the mass fraction of carbon in the coal shall be calculated on the basis of daily measurements of GCV of the coal and a default fraction of carbon in coal from Table KK-1 of this subpart. For importers, exporters, and waste coal reclaimers using Methodology 3 of this subpart, measurements of each shipment can be used in place of daily measurements. (1) Equation KK-3 shall be used to determine the weighted annual average [[Page 16712]] GCV of the coal, and the individual daily or per shipment values shall be determined according to the monitoring methodology for gross calorific values in Sec. 98.374(g). (2) The estimated annual weighted average of the mass fraction of carbon in the coal shall be identified from Table KK-1 of this subpart using annual weighted GCV of the coal determined according to Equation KK-3 of this section. (g) For Calculation Methodologies 2 and 3 of this subpart, the weighted annual average gross calorific value (GCV) or higher heating value of the coal shall be calculated using Equation KK-3 of this section: [GRAPHIC] [TIFF OMITTED] TP10AP09.166 Where: GCV = the weighted annual average gross calorific value or higher heating value of the coal (Btu/lb). zi = Daily or per shipment GCV or HHV of coal for day i measured by proximate analysis (decimal value). yi = Amount of coal supplied on day i (short tons) as measured. n = Number of operating days per year. S = Total coal supplied during the year (short tons). Sec. 98.374 Monitoring and QA/QC requirements. (a) The most current version of the NIST Handbook published by Weights and Measures Division, National Institute of Standards and Technology shall be used as the standard practice for all coal weighing. (b) For all coal mines, the quantity of coal shall be determined as the total mass of coal in short tons sold and removed from the facility during the calendar year. (c) For coal importers, the quantity of coal shall be determined as the total mass of coal in short tons imported into the U.S. during the calendar year, as reported to U.S. Customs. (d) For coal exporters, the quantity of coal shall be determined as the total mass of coal in short tons sold and exported from the U.S., as reported to U.S. Customs. (e) For waste coal reclaimers, the quantity of coal shall be determined as the total mass of coal in short tons sold for use as reported to state agencies. (f) For reporters using Calculation Methodology 1 of this subpart, the carbon content shall be determined as follows: (1) Representative coal samples shall be collected daily or per shipment using ASTM D4916-04, D6609-07, D6883-04, D7256/D7256M-06a, or D7430-08 from coal loaded on the conveyor belt. (2) Daily or per shipment coal carbon content shall be determined using ASTM D5373 (Test Methods for Instrumental Determination of Carbon Hydrogen and Nitrogen in Laboratory Samples of Coal and Coke). (g) For reporters using Calculation Methodology 2 of this subpart, the carbon content shall be determined as follows: (1) Representative samples of coal shall be collected daily or per shipment using ASTM D4916-04, D6609-07, D6883-04, D7256/D7256M-06a, or D7430-08. (2) Coal gross calorific value (GCV) shall be determined on the set of samples collected in paragraph (f)(1) of this section using ASTM D5865-07a, ``Standard Test Method for Gross Calorific Value of Coal and Coke to record the heat content of the coal produced. (3) Coal carbon content shall be determined at a minimum once each month on one set of daily or per shipment samples collected in paragraph (f)(1) of this section using ASTM D5373 (Test Methods for Instrumental Determination of Carbon Hydrogen and Nitrogen in Laboratory Samples of Coal and Coke). (4) The individual samples for which both carbon content and GCV were determined according to paragraphs (f)(2) and (f)(3) of this section respectively, shall be used to establish a statistical relationship between the heat content and the carbon content of the coal produced. The owner or operator shall statistically plot the correlation of Btu/lb of coal vs. percent carbon (as a decimal value), where the x-axis is Btu/lb coal and the y-axis is percent carbon (as decimal value), then fit a line to the data points, then calculate the slope and the coefficient of determination, and the R-square (R\2\) of that line using the Btu/lb and percent carbon. (5) Calculation Methodology 2 of this subpart can be used only if all of the following four conditions are met: (i) At least 12 samples per reporting year from 12 different months of data must be used to construct the correlation graph. (ii) The correlation graph must be constructed using all paired data points from the first reporting year and all subsequent reporting years. (iii) There must be a linear relationship between percent carbon and Btu/lb of coal. (iv) For the second and subsequent years, R-square (R\2\) must be greater than or equal to 0.90. This R-square requirement does not apply during the first reporting year. (6) If all of the conditions specified in paragraph (f)(5) of this section are met, the weighted annual average gross calorific value or higher heating value (Btu/lb) calculated according to Equation KK-3 of this section shall be used to determine the corresponding annual average coal carbon content using the correlation graph plotted according to paragraph (f)(4) of this section. (h) Reporters complying with Calculation Methodology 3 of this subpart shall determine gross calorific value of the coal by collecting representative daily or per shipment samples of coal using either ASTM D4916-04, D6609-07, D6883-04, D7256/D7256M-06a, or D7430-08; and testing using ASTM D5865-07a, ``Standard Test Method for Gross Calorific Value of Coal and Coke to record the heat content of the coal produced.'' (i) Coal exporters shall calculate carbon content for each shipment of coal using information on the carbon content of the exported coal provided by the source mine, according to Calculation Methodology 1, 2, or 3 of this subpart, as appropriate. (j) Coal importers shall calculate carbon content for each shipment of coal using Calculation Methodology 1, 2, or 3 of this subpart. (k) Waste coal reclaimers shall calculate carbon content for each shipment of coal using Calculation Methodology 1, 2, or 3 of this subpart. (l) Each owner or operator using mechanical coal sampling systems shall perform quality assurance and quality control according to ASTM D4702-07 and ASTM D6518-07. Sec. 98.375 Procedures for estimating missing data. (a) A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality- assured value of a required parameter is unavailable, a substitute data value for the missing parameter shall be used in the calculations. (b) Whenever a quality-assured value for coal production during any time period is unavailable, you must use the average of the parameter values recorded immediately before and after the missing data period in the calculations. (c) Facilities using Calculation Methodology 1 of this subpart shall develop the statistical relationship between GCV and carbon content according to Sec. 98.274(e), and use this statistical relationship to estimate daily carbon content for any day for which [[Page 16713]] measured carbon content is not available. (d) Facilities, importers and exporters using Calculation Methodology 2 or 3 of this subpart shall estimate the missing GCV values based on a weighted average value for the previous seven days. (e) Estimates of missing data shall be documented and records maintained showing the calculations. Sec. 98.376 Data reporting requirements. In addition to the information required by Sec. 98.3(c), each annual report must contain the following information. (a) Each coal mine owner or operator shall report the following information for each coal mine: (1) The name and MSHA ID number of the mine. (2) The name of the operating company. (3) Annual CO2 emissions. (4) By rank, the total annual quantity in tons of coal produced. (5) The annual weighted carbon content of the coal as calculated according to Sec. 98.373. (6) If Calculation Methodology 1 of this subpart was used to determine CO2 mass emissions, you must report daily mass fraction of carbon in coal measured by ultimate analysis and daily amount of coal supplied. (7) If Calculation Methodology 2 of this subpart was used to determine CO2 mass emissions, you must report: (i) All of the data used to construct the carbon vs. Btu/lb correlation graph. (ii) Slope of the correlation line. (iii) The R-squared (R\2\) value of the correlation. (8) If Calculation Methodology 3 of this subpart was used to determine CO2 mass emissions, you must report daily GCV of coal measured by proximate analysis and daily amount of coal supplied. (b) Coal importers shall report the following information at the corporate level: (1) The total annual quantity in tons of coal imported into the U.S. by the importer, by rank, and country of origin. (2) Annual CO2 emissions. (3) The annual weighted carbon content of the coal as calculated according to Sec. 98.373. (4) If Calculation Methodology 1 of this subpart was used to determine CO2 mass emissions, you must report mass fraction of carbon in coal per shipment measured by ultimate analysis and amount of coal supplied per shipment. (5) If Calculation Methodology 2 of this subpart was used to determine CO2 mass emissions, you must report: (i) All of the data used to construct the carbon vs. Btu/lb correlation graph. (ii) Slope of the correlation line. (iii) The R-squared (R\2\) value of the correlation. (6) If Calculation Methodology 3 of this subpart was used to determine CO2 mass emissions, you must report GCV in coal per shipment measured by proximate analysis and amount of coal supplied per shipment. (d) Coal exporters shall report the following information at the corporate level: (1) The total annual quantity in tons of coal exported from the U.S. by rank and by coal producing company and mine. (2) Annual CO2 emissions. (3) The annual weighted carbon content of the coal as calculated according to Sec. 98.373. (4) If Calculation Methodology 1 of this subpart was used to determine CO2 mass emissions, you must report mass fraction of carbon in coal per shipment measured by ultimate analysis and amount of coal supplied per shipment. (5) If Calculation Methodology 2 of this subpart was used to determine CO2 mass emissions, you must report: (i) All of the data used to construct the carbon vs. Btu/lb correlation graph. (ii) Slope of the correlation line. (iii) The R-squared (R\2\) value of the correlation. (6) If Calculation Methodology 3 of this subpart was used to determine CO2 mass emissions, you must report GCV in coal per shipment measured by proximate analysis and amount of coal supplied per shipment. (e) Waste coal reclaimers shall report the following information for each reclamation site: (1) By rank, the total annual quantity in tons of waste coal produced. (2) Mine and state of origin if waste coal is reclaimed from mines that are no longer operating. (3) Annual CO2 emissions. (4) The annual weighted carbon content of the coal as calculated according to Sec. 98.373. (5) If Calculation Methodology 1 of this subpart was used to determine CO2 mass emissions, you must report mass fraction of carbon in coal per shipment measured by ultimate analysis and amount of coal supplied per shipment. (6) If Calculation Methodology 2 of this subpart was used to determine CO2 mass emissions, you must report: (i) All of the data used to construct the carbon vs. Btu/lb correlation graph. (ii) Slope of the correlation line. (iii) The R-squre (R \2\) value of the correlation. (7) If Calculation Methodology 3 of this subpart was used to determine CO2 mass emissions, you must report GCV in coal per shipment measured by proximate analysis and amount of coal supplied per shipment. Sec. 98.377 Records that must be retained. In addition to the records required by Sec. 98.3(g), you must retain the following information: (a) A complete record of all measured parameters used in the reporting of fuel quantities, including all sample results and documentation to support quantities that are reported under this part. (b) Records documenting all calculations of missing data. (c) Calculations and worksheets used to estimate the CO2 emissions. (d) Calibration records of any instruments used on site and calibration records of scales or other equipment used to weigh coal. Sec. 98.378 Definitions. All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Table KK-1 of Subpart KK--Default Carbon Content of Coal for Method 3 (CO2 lbs/MMBtu1) ------------------------------------------------------------------------ Mass fraction Weighted annual average GCV of coal Btu/lb\1\ of carbon in coal (decimal) ------------------------------------------------------------------------ 2,000................................................... 0.1140 2,250................................................... 0.1283 2,500................................................... 0.1425 2,750................................................... 0.1568 3,000................................................... 0.1710 3,250................................................... 0.1853 3,500................................................... 0.1995 3,750................................................... 0.2138 4,000................................................... 0.2280 4,250................................................... 0.2423 4,500................................................... 0.2565 4,750................................................... 0.2708 5,000................................................... 0.2850 5,250................................................... 0.2993 5,500................................................... 0.3135 5,750................................................... 0.3278 6,000................................................... 0.3420 6,250................................................... 0.3563 6,500................................................... 0.3705 6,750................................................... 0.3848 7,000................................................... 0.3990 7,250................................................... 0.4133 7,500................................................... 0.4275 7,750................................................... 0.4418 8,000................................................... 0.4560 8,250................................................... 0.4703 8,500................................................... 0.4845 8,750................................................... 0.4988 9,000................................................... 0.5130 9,250................................................... 0.5273 9,500................................................... 0.5415 9,750................................................... 0.5558 10,000.................................................. 0.5700 10,250.................................................. 0.5843 10,500.................................................. 0.5985 10,750.................................................. 0.6128 [[Page 16714]] 11,000.................................................. 0.6270 11,250.................................................. 0.6413 11,500.................................................. 0.6555 11,750.................................................. 0.6698 12,000.................................................. 0.6840 12,250.................................................. 0.6983 12,500.................................................. 0.7125 12,750.................................................. 0.7268 13,000.................................................. 0.7410 13,250.................................................. 0.7553 13,500.................................................. 0.7695 13,750.................................................. 0.7838 14,000.................................................. 0.7980 14,250.................................................. 0.8123 14,500.................................................. 0.8265 14,750.................................................. 0.8408 15,000.................................................. 0.8550 15,250.................................................. 0.8693 15,500.................................................. 0.8835 ------------------------------------------------------------------------ \1\ Based on high heating values. Subpart LL--Suppliers of Coal-based Liquid Fuels Sec. 98.380 Definition of the source category. This source category consists of producers, importers, and exporters of coal-based liquids. (a) A producer is the owner or operator of a coal-to-liquids facility. A coal-to-liquids facility is any facility engaged in coverting coal into liquid fuels such as gasoline and diesel using the Fischer-Tropsch process or an alternative process, involving conversion of coal into gas and then into liquids or conversion of coal directly into liquids (direct liquefaction). (b) An importer or exporter shall have the same meaning given in Sec. 98.6. Sec. 98.381 Reporting threshold. Any supplier of coal-based liquid fuels who meets the requirements of Sec. 98.2(a)(4) must report GHG emissions. Sec. 98.382 GHGs to report. You must report the CO2 emissions that would result from the complete combustion or oxidation of coal-based liquids during the calendar year. Sec. 98.383 Calculating GHG emissions. (a) Coal-to-liquid producers, importers and exporters must calculate CO2 emissions using Equation LL-1 of this section. [GRAPHIC] [TIFF OMITTED] TP10AP09.167 Where: CO2 = Annual CO2 mass emissions from the combustion of fuel (metric tons). Producti = Total annual volume (in standard barrels) of a coal-based liquid fuel ``i'' produced, imported, or exported. EFi = CO2 emission factor (metric tons CO2 per barrel) specific to liquid fuel ``i''. (b) The emission factor (EF) for each type of coal-based liquid shall be determined using either of the calculation methodologies described in paragraphs (a) and (b) of this section. The same calculation methodology must be used for the entire volume of the product for the reporting year. (1) Calculation Methodology 1. Use the default CO2 emission factor listed in column C of Table MM-1 of subpart MM (Suppliers of Petroleum Products) that most closely represents the coal-based liquid. (2) Calculation Methodology 2. Develop a CO2 emission factor according to Equation LL-2 of this section using direct measurement of density and carbon share according to methods set forth in Sec. 98.394(c) or a combination of direct measurement and the default factor listed in columns A or B of Table MM-1 of subpart MM that most closely represents the coal-based liquid. [GRAPHIC] [TIFF OMITTED] TP10AP09.168 Where: EF = Emission factor of coal-based liquid (metric tons CO2 per barrel). Density = Density of coal-based liquid (metric tons per barrel). Wt% = Percent of total mass that carbon represents in coal-based liquid. Sec. 98.384 Monitoring and QA/QC requirements. (a) Producers must measure the quantity of coal-based liquid fuels using procedures for flow meters as described in subpart MM of this part. (b) Importers and exporters must determine the quantity of coal- based liquid fuels using sales contract information on the volume imported or exported during the reporting period. (1) The quantity of coal-based liquid fuels must be measured using sales contract information. (2) The minimum frequency of the measurement of quantities of coal- based liquid fuels shall be the number of sales contracts executed in the reporting period. (c) All flow meters and product monitors shall be calibrated prior to use for reporting, using a suitable method published by a consensus standards organization (e.g., ASTM, ASME, API, NAESB, or others). Alternatively, calibration procedures specified by the flow meter manufacturer may be used. Fuel flow meters shall be recalibrated either annually or at the minimum frequency specified by the manufacturer. (d) Reporters shall take the following steps to ensure the quality and accuracy of the data reported under these rules: (1) For all volumes of coal-based liquid fuels, reporters shall maintain meter and such other records as are normally maintained in the course of business to document fuel flows. (2) For all estimates of CO2 mass emissions, reporters shall maintain calculations and worksheets used to calculate the emissions. Sec. 98.385 Procedures for estimating missing data. (a) A complete record of all measured parameters used in the reporting of fuel volumes and the calculations of CO2 mass emissions is required. Therefore, whenever a quality-assured measurement of the quantity of coal-based liquid fuels is unavailable a substitute data value for the missing quantity measurement shall be calculated and used in the calculations. (b) For coal-to-liquids facilities, the last quality assured reading shall be [[Page 16715]] used. If substantial variation in the flow rate is observed or if a quality assured measurement of quantity is unavailable for any other reason, the average of the last and the next quality assured reading shall be used to calculate a substitute measurement of quantity. (c) Calculation of substitute data shall be documented and records maintained showing the calculations. Sec. 98.386 Data reporting requirements. In addition to the information required by Sec. 98.3(c), each annual report must contain the following information: (a) Producers shall report the following information for each facility: (1) The total annual volume of each coal-based liquid supplied to the economy (in standard barrels). (2) The total annual CO2 emissions in metric tons associated with each coal-based liquid supplied to the economy, calculated according to Sec. 98.383(a). (b) Importers shall report the following information at the corporate level: (1) The total annual volume of each imported coal-based liquid (in standard barrels). (2) The total annual CO2 emissions in metric tons associated with each imported coal-based liquid, calculated according to Sec. 98.383(a). (c) Exporters shall report the following information at the corporate level: (1) The total annual volume of each exported coal-based liquid (in standard barrels). (2) The total annual CO2 emissions in metric tons associated with each exported coal-based liquid, calculated according to Sec. 98.383(a). Sec. 98.387 Records that must be retained. Reporters shall retain copies of all reports submitted to EPA. Reporters shall maintain records to support volumes that are reported under this part, including records documenting any calculation of substitute measured data. Reporters shall also retain calculations and worksheets used to estimate the CO2 equivalent of the volumes reported under this part. These records shall be retained for five (5) years similar to 40 CFR part 80 fuels compliance reporting program. Sec. 98.388 Definitions. All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Subpart MM--Suppliers of Petroleum Products Sec. 98.390 Definition of the source category. This source category consists of petroleum refineries and importers and exporters of petroleum products. (a) A petroleum refinery is any facility engaged in producing gasoline, kerosene, distillate fuel oils, residual fuel oils, lubricants, asphalt (bitumen) or other products through distillation of petroleum or through redistillation, cracking, or reforming of unfinished petroleum derivatives. (b) A refiner is the owner or operator of a petroleum refinery. (c) Importer has the same meaning given in Sec. 98.6 and includes any blender or refiner of refined or semi-refined petroleum products. (d) Exporter has the same meaning given in Sec. 98.6 and includes any blender or refiner of refined or semi-refined petroleum products. Sec. 98.391 Reporting threshold. Any supplier of petroleum products who meets the requirements of Sec. 98.2(a)(4) must report GHG emissions. Sec. 98.392 GHGs to report. You must report the CO2 emissions that would result from the complete combustion or oxidation of each petroleum product and natural gas liquid produced, used as feedstock, imported, or exported during the calendar year. Additionally, if you are a refiner, you must report CO2 emissions that would result from the complete combustion or oxidation of any biomass co-processed with petroleum feedstocks. Sec. 98.393 Calculating GHG emissions. (a) Except as provided in paragraph (g) of this section, any refiner, importer, or exporter shall calculate CO2 emissions from each individual petroleum product and natural gas liquid using Equation MM-1 of this section. [GRAPHIC] [TIFF OMITTED] TP10AP09.169 Where: CO2i = Annual potential CO2 emissions from the complete combustion or oxidation of each petroleum product or natural gas liquid ``i'' (metric tons). Producti = Total annual volume of product ``i'' produced, imported, or exported by the reporting party (barrels). For refiners, this volume only includes products ex refinery gate. EFi = Product-specific CO2 emission factor (metric tons CO2 per barrel). (b) Except as provided in paragraph (g) of this secton, any refiner shall calculate CO2 emissions from each non-crude feedstock using Equation MM-2 of this section. [GRAPHIC] [TIFF OMITTED] TP10AP09.170 Where: CO2j = Annual potential CO2 emissions from the complete combustion or oxidation of each non-crude feedstock ``j'' (metric tons). Feedstockj = Total annual volume of a petroleum product or natural gas liquid ``j'' that enters the refinery as a feedstock to be further refined or otherwise used on site (barrels). Any waste feedstock (see definitions) that enters the refinery must also be included. EFj = Feedstock-specific CO2 emission factor (metric tons CO2 per barrel). (c) Refiners shall calculate CO2 emissions from all biomass co-processed with petroleum feedstocks using Equation MM-3 of this section. [GRAPHIC] [TIFF OMITTED] TP10AP09.171 Where: CO2m = Annual potential CO2 emissions from the complete combustion or oxidation of biomass ``m'' (metric tons). Biomassm = Total annual volume of a specific type of biomass that enters the refinery to be co-processed with petroleum feedstocks to produce a petroleum product reported under paragraph (a) of this section (barrels). EFm = Biomass-specific CO2 emission factor (metric tons CO2 per barrel). (d) Refiners shall calculate total CO2 emissions from all products using Equation MM-4 of this section. [[Page 16716]] [GRAPHIC] [TIFF OMITTED] TP10AP09.172 Where: CO2r = Total annual potential CO2 emissions from the complete combustion or oxidation of all petroleum products and natural gas liquids (ex refinery gate) minus non-crude feedstocks and any biomass to be co-processed with petroleum feedstocks. CO2i = Annual potential CO2 emissions from the complete combustion or oxidation of each petroleum product or natural gas liquid ``i'' (metric tons). CO2j = Annual potential CO2 emissions from the complete combustion or oxidation of each non-crude feedstock ``j'' (metric tons). CO2m = Annual potential CO2 emissions from the complete combustion or oxidation of biomass ``m'' (metric tons). (e) Importers and exporters shall calculate total CO2 emissions from all petroleum products and natural gas liquids imported or exported, respectively, using Equations MM-1 and MM-5 of this section. [GRAPHIC] [TIFF OMITTED] TP10AP09.173 Where: CO2i = Annual potential CO2 emissions from the complete combustion or oxidation of each petroleum product or natural gas liquid ``i'' (metric tons). CO2x = Total annual potential CO2 emissions from the complete combustion or oxidation of all petroleum products and natural gas liquids. (f) Except as provided in paragraph (g) of this section, the emission factor (EF) for each petroleum product and natural gas liquid shall be determined using either of the calculation methodologies described in paragraphs (f)(1) or (f)(2) of this section. The same calculation methodology must be used for the entire volume of the product for the reporting year. (1) Calculation Methodology 1. Use the appropriate default CO2 emission factors listed in column C of Tables MM-1 and MM-2 of this subpart. (2) Calculation Methodology 2. Develop emission factors according to Equation MM-6 of this section using direct measurements of density and carbon share according to methods set forth in Sec. 98.394(c) or a combination of direct measurements and default factors listed in columns A and B of Tables MM-1 and MM-2 of this subpart. [GRAPHIC] [TIFF OMITTED] TP10AP09.174 Where: EF = Emission factor of petroleum or natural gas product or non- crude feedstock (metric tons CO2 per barrel). Density = Density of petroleum product or natural gas liquid or non- crude feedstock (metric tons per barrel). Wt% = Percent of total mass that carbon represents in petroleum product or natural gas liquid or non-crude feedstock. 44/12 = Conversion factor for carbon to carbon dioxide. (g) In the event that some portion of a petroleum product or feedstock is biomass-based and was not derived by co-processing biomass and petroleum feedstocks together (i.e., the petroleum product or feedstock was produced by blending a petroleum-based product with a biomass-based product), the reporting party shall calculate emissions for the petroleum product or feedstock according to one of the methods in paragraph (g)(1) or (2) of this section, as appropriate. (1) A reporting party using Calculation Methodology 1 of this subpart to determine the emission factor of a petroleum product shall calculate the CO2 emissions associated with that product using Equation MM-7 of this section in place of Equation MM-1 of this section. [GRAPHIC] [TIFF OMITTED] TP10AP09.175 Where: CO2i = Annual potential CO2 emissions from the complete combustion or oxidation of petroleum product ``i'' (metric tons). Producti = Total annual volume of petroleum product ``i'' produced, imported, or exported by the reporting party (barrels). For refiners, this volume only includes products ex refinery gate. EFi = Petroleum product-specific CO2 emission factor (metric tons CO2 per barrel) from MM-1. %Voli = Percent volume of product ``i'' that is petroleum-based. (2) A refinery using Calculation Methodology 1 of this subpart to determine the emission factor of a non-crude petroleum feedstock shall calculate the CO2 emissions associated with that feedstock using Equation MM-8 in place of Equation MM-2 of this section. [GRAPHIC] [TIFF OMITTED] TP10AP09.176 Where: CO2j = Annual potential CO2 emissions from the complete combustion or oxidation of each non-crude feedstock ``j'' (metric tons). Feedstockj = Total annual volume of a petroleum product ``j'' that enters the refinery as a feedstock to be further refined or otherwise used on site (barrels). EFj = Non-crude petroleum feedstock-specific CO2 emission factor (metric tons CO2 per barrel). %Volj = Percent volume of feedstock ``j'' that is petroleum-based. (3) A reporter using Calculation Methodology 2 of this subpart to determine the emission factor of a petroleum product must calculate the CO2 emissions associated with that product using Equation MM-9 of this section in place of Equation MM-1 of this section. [[Page 16717]] [GRAPHIC] [TIFF OMITTED] TP10AP09.177 Where: CO2i = Annual potential CO2 emissions from the complete combustion or oxidation of product ``i'' (metric tons). Producti = Total annual volume of petroleum product ``i'' produced, imported, or exported by the reporting party (barrels). For refiners, this volume only includes products ex refinery gate. EFi = Product-specific CO2 emission factor (metric tons CO2 per barrel). EFm = Default CO2 emission factor from Table MM-3 that most closely represents the component of product ``i'' that is biomass-based. %Volm = Percent volume of petroleum product ``i'' that is biomass-based. (4) A refiner using Calculation Methodology 2 of this subpart to determine the emission factor of a non-crude petroleum feedstock must calculate the CO2 emissions associated with that feedstock using Equation MM-10 in place of Equation MM-2 of this section. [GRAPHIC] [TIFF OMITTED] TP10AP09.178 Where: CO2j = Annual potential CO2 emissions from the complete combustion or oxidation of non-crude feedstock ``j'' (metric tons). Feedstockj = Total annual volume of non-crude feedstock ``j'' that enters the refinery as a feedstock to be further refined or otherwise used on site (barrels). Any waste feedstock (see definitions) that enters the refinery must also be included. EFj = Feedstock-specific CO2 emission factor (metric tons CO2 per barrel). EFm = Default CO2 emission factor from Table MM-3 of subpart MM that most closely represents the component of product ``i'' that is biomass-based. %Volm = Percent volume of non-crude feedstock ``j'' that is biomass-based. (h) Refiners shall use the most appropriate default CO2 emission factor (EFm) for biomass in Table MM-3 to calculate CO2 emissions in paragraph (c) of this section. Sec. 98.394 Monitoring and QA/QC requirements. (a) The quantity of petroleum products, natural gas liquids, biomass, and all feedstocks shall be determined using either a flow meter or tank gauge, depending on the reporters existing equipment and preferences. (1) For flow meters any one of the following test methods can be used to determine quantity: (i) Ultra-sonic flow meter: AGA Report No. 9 (2007) (ii) Turbine meters: American National Standards Institute, ANSI/ ASME MFC-4M-1986 (iii) Orifice meters: American National Standards Institute, AINSI/ API 2530 (also called AGA-3) (1991) (iv) Coriolis meters: ASME MFC-11 (2006) (2) For tank gauges any one of the following test methods can be used to determine quantity: (i) API-2550: Measurements and Calibration of Petroleum Storage Tanks (1965) (ii) API MPMS 2.2: A Manual of Petroleum Measurement Standards (1995) (iii) API-653: Tank Inspection, Repair, Alteration and Reconstruction, 3rd edition (2008) (b) All flow meters and tank gauges shall be calibrated prior to use for reporting, using a suitable method published by a consensus standards organization (e.g., ASTM, ASME, API, or NAESB). Alternatively, calibration procedures specified by the flow meter manufacturer may be used. Product flow meters and tank gauges shall be recalibrated either annually or at the minimum frequency specified by the manufacturer, whichever is more frequent. (c) For Calculation Methodology 2 of this subpart, samples of each petroleum product and natural gas liquid shall be taken each month for the reporting year. The composite sample shall be tested at the end of the reporting year using ASTM D1298 (2003), ASTM D1657-02 (2007), ASTM D4052-96 (2002)el, ASTM D5002-99 (2005), or ASTM D5004-89 (2004)el for density, as appropriate, and ASTM D5291 (2005) or ASTM D6729-(2004)el for carbon share, as appropriate (see Technical Support Document). Reporters must sample seasonal gasoline each month of the season and then test the composite sample at the end of the season. Sec. 98.395 Procedures for estimating missing data. Whenever a metered or quality-assured value of the quantity of petroleum products, natural gas liquids, biomass, or feedstocks during any period is unavailable, a substitute data value for the missing quantity measurement shall be used in the calculations contained in Sec. 98.393. (a) For marine-imported and exported refined and semi-refined products, the reporting party shall attempt to reconcile any differences between ship and shore volume readings. If the reporting party is unable to reconcile the readings, the higher of the two volume values shall be used for emission calculation purposes. (b) For pipeline imported and exported refined and semi-refined products, the last valid volume reading based on the company's established procedures for purposes of product tracking and billing shall be used. If the pipeline experiences substantial variations in flow rate, the average of the last valid volume reading and the next valid volume reading shall be used for emission calculation purposes. (c) For petroleum refineries, the last valid volume reading based on the facility's established procedures for purposes of product tracking and billing shall be used. If substantial variation in the flow rate is observed, the average of the last and the next valid volume reading shall be used for emission calculation purposes. Sec. 98.396 Data reporting requirements. In addition to the information required by Sec. 98.3(c), the following requirements apply. (a) Refiners shall report the following information for each facility: (1) CO2 emissions in metric tons for each petroleum product and natural gas liquid (ex refinery gate), calculated according to Sec. 98.393(a) or (g). (2) CO2 emissions in metric tons for each petroleum product or natural gas liquid that enters the refinery annually as a feedstock to be further refined or otherwise used on site, calculated according to Sec. 98.393(b) or (g). (3) CO2 emissions in metric tons from each type of biomass feedstock co-processed with petroleum feedstocks, calculated according to Sec. 98.393(c). (4) The total sum of CO2 emissions from all products, calculated according to Sec. 98.393(d). (5) The total volume of each petroleum product and natural gas liquid associated with the CO2 emissions reported in paragraphs (a)(1) [[Page 16718]] and (2) of this section, seperately, and the volume of the biomass- based component of each petroleum product reported in this paragraph that was produced by blending a petroleum-based product with a biomass- based product. If a determination cannot be made whether the material is a petroleum product or a natural gas liquid, it shall be reported as a petroleum product. (6) The total volume of any biomass co-processed with a petroleum product associated with the CO2 emissions reported in paragraph (a)(3) of this section. (7) The measured density and/or mass carbon share for any petroleum product or natural gas liquid for which CO2 emissions were calculated using Calculation Methodology 2 of this subpart, along with the selected method from Sec. 98.394(c) and the calculated EF. (8) The total volume of each distillate fuel oil product or feedstock reported in paragraph (a)(5) of this section that contains less than 15 ppm sulfur content and is free from marker solvent yellow 124 and dye solvent red 164. (9) All of the following information for all crude oil feedstocks used at the refinery: (i) Batch volume (in standard barrels). (ii) API gravity of the batch. (iii) Sulfur content of the batch. (iv) Country of origin of the batch. (b) In addition to the information required by Sec. 98.3(c), each importer shall report all of the following information at the corporate level: (1) CO2 emissions in metric tons for each imported petroleum product and natural gas liquid, calculated according to Sec. 98.393(a). (2) Total sum of CO2 emissions, calculated according to Sec. 98.393(e). (3) The total volume of each imported petroleum product and natural gas liquid associated with the CO2 emissions reported in paragraph (b)(1) of this section as well as the volume of the biomass- based component of each petroleum product reported in this paragraph that was produced by blending a petroleum-based product with a biomass- based product. If you cannot determine whether the material is a petroleum product or a natural gas liquid, you shall report it as a petroleum product. (4) The measured density and/or mass carbon share for any imported petroleum product or natural gas liquid for which CO2 emissions were calculated using Calculation Methodology 2 of this subpart, along with the selected method from Sec. 98.394(c) and the calculated EF. (5) The total volume of each distillate fuel oil product reported in paragraph (b)(1) of this section that contains less than 15 ppm sulfur content and is free from marker solvent yellow 124 and dye solvent red 164. (c) In addition to the information required by Sec. 98.3(c), each exporter shall report all of the following information at the corporate level: (1) CO2 emissions in metric tons for each exported petroleum product and natural gas liquid, calculated according to Sec. 98.393(a). (2) Total sum of CO2 emissions, calculated according to Sec. 98.393(e). (3) The total volume of each exported petroleum product and natural gas liquid associated with the CO2 emissions reported in paragraph (c)(1) of this section as well as the volume of the biomass- based component of each petroleum product reported in this paragraph that was produced by blending a petroleum-based product with a biomass- based product. If you cannot determine whether the material is a petroleum product or a natural gas liquid, you shall report it as a petroleum product. (4) The measured density and/or mass carbon share for any petroleum product or natural gas liquid for which CO2 emissions were calculated using Calculation Methodology 2 of this subpart, along with the selected method from Sec. 98.394(c) and the calculated EF. (5) The total volume of each distillate fuel oil product reported in paragraph (c)(1) of this section that contains less than 15 ppm sulfur content and is free from marker solvent yellow 124 and dye solvent red 164. Sec. 98.397 Records that must be retained. (a) Any reporter described in Sec. 98.391 shall retain copies of all reports submitted to EPA under Sec. 98.396. In addition, any reporter under this subpart shall maintain sufficient records to support information contained in those reports, including but not limited to information on the characteristics of their feedstocks and products. (b) Reporters shall maintain records to support volumes that are reported under this part, including records documenting any estimations of missing metered data. For all volumes of petroleum products, natural gas liquids, biomass, and feedstocks, reporters shall maintain meter and other records normally maintained in the course of business to document product and feedstock flows. (c) Reporters shall also retain laboratory reports, calculations and worksheets used to estimate the CO2 emissions of the volumes reported under this part. (d) Estimates of missing data shall be documented and records maintained showing the calculations. (e) Reporters described in this subpart shall also retain all records described in Sec. 98.3(g). Sec. 98.398 Definitions. All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Table MM-1 of Subpart MM--Default CO2 Factors for Petroleum Products 1, 2 ---------------------------------------------------------------------------------------------------------------- Column C: emission Column A: factor density Column B: (metric tons Refined and semi-refined petroleum products (metric tons/ carbon share CO2/bbl) bbl) (% of mass) [Column A * Column B/100 * 44/12] ---------------------------------------------------------------------------------------------------------------- Motor Gasoline \3\ ---------------------------------------------------------------------------------------------------------------- Conventional--Summer........................................ 0.12 86.96 0.38 Conventional--Winter........................................ 0.12 86.96 0.37 Reformulated--Summer........................................ 0.12 86.60 0.37 Reformulated--Winter........................................ 0.12 86.60 0.37 Finished Aviation Gasoline.................................. 0.11 85.00 0.35 ---------------------------------------------------------------------------------------------------------------- [[Page 16719]] Blendstocks ---------------------------------------------------------------------------------------------------------------- RBOB........................................................ 0.12 86.60 0.38 CBOB........................................................ 0.12 85.60 0.37 Others...................................................... 0.11 84.00 0.34 ---------------------------------------------------------------------------------------------------------------- Oxygenates ---------------------------------------------------------------------------------------------------------------- Methanol.................................................... 0.13 37.50 0.17 GTBA........................................................ 0.12 64.90 0.29 t-butanol................................................... 0.12 64.90 0.29 MTBE........................................................ 0.12 68.20 0.29 ETBE........................................................ 0.12 70.50 0.30 TAME........................................................ 0.12 70.50 0.31 DIPE........................................................ 0.12 70.60 0.30 Kerosene-Type Jet Fuel...................................... 0.13 86.30 0.41 Naptha-Type Jet Fuel........................................ 0.12 85.80 0.39 Kerosene.................................................... 0.13 86.01 0.41 ---------------------------------------------------------------------------------------------------------------- Distillate Fuel Oil ---------------------------------------------------------------------------------------------------------------- Diesel No. 1................................................ 0.13 86.40 0.43 Diesel No. 2................................................ 0.13 86.34 0.43 Diesel No. 4................................................ 0.15 86.47 0.46 Fuel Oil No. 1.............................................. 0.13 86.40 0.43 Fuel Oil No. 2.............................................. 0.13 86.34 0.43 Fuel Oil No. 4.............................................. 0.15 86.47 0.46 Residual Fuel Oil No. 5 (Navy Special)...................... 0.14 85.81 0.43 Residual Fuel Oil No. 6 (a.k.a. Bunker C)................... 0.16 85.68 0.49 ---------------------------------------------------------------------------------------------------------------- Petrochemical Feedstocks ---------------------------------------------------------------------------------------------------------------- Naphthas (< 401 [deg]F).................................... 0.12 84.11 0.36 Other Oils (> 401 [deg]F)................................... 0.13 86.34 0.43 Special Naphthas............................................ 0.12 84.76 0.38 Lubricants.................................................. 0.14 85.80 0.45 Waxes....................................................... 0.13 85.29 0.40 Petroleum Coke.............................................. 0.07 92.28 0.23 Asphalt and Road Oil........................................ 0.16 83.47 0.50 Still Gas................................................... 0.07 24.40 0.06 Ethane...................................................... 0.06 80.00 0.17 Ethylene.................................................... 0.09 85.71 0.28 Propane..................................................... 0.08 81.80 0.24 Propylene................................................... 0.08 85.71 0.26 Butane...................................................... 0.09 82.80 0.28 Butylene.................................................... 0.11 85.71 0.35 Isobutane................................................... 0.09 82.80 0.27 Isobutylene................................................. 0.09 85.71 0.29 Pentanes Plus............................................... 0.11 83.70 0.32 Miscellaneous Products...................................... 0.14 85.49 0.43 Unfinished Oils............................................. 0.14 85.49 0.43 Naphthas.................................................... 0.12 85.70 0.37 Kerosenes................................................... 0.13 85.80 0.41 Heavy Gas Oils.............................................. 0.15 85.80 0.46 Residuum.................................................... 0.16 85.70 0.51 Waste Feedstocks............................................ 0.14 85.70 0.45 ---------------------------------------------------------------------------------------------------------------- \1\ In the case of transportation fuels blended with some portion of biomass-based fuel, the carbon share in Table MM-1 represents only the petroleum-based components. \2\ Products that are derived entirely from biomass should not be reported, but products that were derived from both biomass and a petroleum product (i.e., co-processed) should be reported as the petroleum product that it most closely represents. [[Page 16720]] Table MM-2 of Subpart MM--Default CO2 Factors for Natural Gas Liquids ---------------------------------------------------------------------------------------------------------------- Column C: computed emission Column A: Column B: factor Natural gas liquids density carbon share (tonnes CO2/ tonnes/barrel (% of mass) bbl) [Column A * Column B/ 100 * 44/12] ---------------------------------------------------------------------------------------------------------------- C2+............................................................. 0.08 81.79 0.24 C4+............................................................. 0.10 83.15 0.30 C5+............................................................. 0.11 83.70 0.32 C6+............................................................. 0.11 84.04 0.34 ---------------------------------------------------------------------------------------------------------------- Table MM-3 of Subpart MM--Default CO2 Factors for Biomass-based Fuel and Biomass Feedstock ------------------------------------------------------------------------ Column A: emission Biomass products and feedstock factor (tonnes CO2/ bbl) ------------------------------------------------------------------------ Ethanol (100%).......................................... 0.23 Biodiesel (100%, methyl ester).......................... 0.40 Rendered Animal Fat..................................... 0.37 Vegetable Oil........................................... 0.41 ------------------------------------------------------------------------ Subpart NN--Suppliers of Natural Gas and Natural Gas Liquids Sec. 98.400 Definition of the source category. This supplier category consists of natural gas processing plants and local natural gas distribution companies. (a) Natural Gas Processing Plants are installations designed to separate and recover natural gas liquids (NGLs) or other gases and liquids from a stream of produced natural gas through the processes of condensation, absorption, adsorption, refrigeration, or other methods and to control the quality of natural gas marketed. This does not include field gathering and boosting stations. (b) Local Distribution Companies are companies that own or operate distribution pipelines, not interstate pipelines or intrastate pipelines, that physically deliver natural gas to end users and that are regulated as separate operating companies by State public utility commissions or that operate as independent municipally-owned distribution systems. Sec. 98.401 Reporting threshold. Any supplier of natural gas and natural gas liquids that meets the requirements of Sec. 98.2(a)(4) must report GHG emissions. Sec. 98.402 GHGs to report. (a) Natural gas processing plants must report the CO2 emissions that would result from the complete combustion or oxidation of the annual quantity of propane, butane, ethane, isobutane and bulk NGLs sold or delivered for use off site. (b) Local distribution companies must report the CO2 emissions that would result from the complete combustion or oxidation of the annual volumes of natural gas provided to end-users. Sec. 98.403 Calculating GHG emissions. (a) For each type of fuel or product reported under this part, calculate the estimated CO2 equivalent emissions using either of Calculation Methodology 1 or 2 of this subpart: (1) Calculation Methodology 1. Estimate CO2 emissions using Equation NN-1. For Equation NN-1, use the default values for higher heating values and CO2 emission factors in Table NN-1 to this subpart. Alternatively, reporter-specific higher heating values and CO2 emission factors may be used, provided they are developed using methods outlined in Sec. 98.404. For Equation NN-2 of this section, use the default values for the CO2 emission factors found in Table NN-2 of this subpart. Alternatively, reporter- specific CO2 emission factors may be used, provided they are developed using methods outlined in Sec. 98.404. [GRAPHIC] [TIFF OMITTED] TP10AP09.179 Where: CO2 = Annual potential CO2 mass emissions from the combustion of fuel (metric tons). Fuel = Total annual volume of fuel or product (volume per year, typically in Mcf for gaseous fuels and bbl for liquid fuels). HHV = Higher heat value of the fuel supplied (MMBtu/Mcf or MMBtu/bbl). EF = Fuel-specific CO2 emission factor (kg CO2/MMBtu). 1 x 10-3 = Conversion factor from kilograms to metric tons (MT/kg). (2) Calculation Methodology 2. Estimate CO2 emissions using Equation NN-2. [GRAPHIC] [TIFF OMITTED] TP10AP09.180 Where: CO2 = Annual CO2 mass emissions from the combustion of fuel supplied (metric tons) Fuel = Total annual volume of fuel or product supplied (bbl or Mcf per year) EF = Fuel-specific CO2 emission factor (MT CO2/bbl, or MT CO2/Mcf) Sec. 98.404 Monitoring and QA/QC requirements. (a) The quantity of natural gas liquids and natural gas must be determined [[Page 16721]] using any of the oil and gas flow meter test methods that are in common use in the industry and consistent with the Gas Processors Association Technical Manual and the American Gas Association Gas Measurement Committee reports. (b) The minimum frequency of the measurements of quantities of natural gas liquids and natural gas shall be based on the industry standard practices for commercial operations. For natural gas liquids these are measurements taken at custody transfers summed to the annual reportable volume. For natural gas these are daily totals of continuous measurements, and summed to the annual reportable volume. (c) All flow meters and product or fuel composition monitors shall be calibrated prior to the first reporting year, using a suitable method published by the American Gas Association Gas Measurement Committee reports on flow metering and heating value calculations and the Gas Processors Association standards on measurement and heating value. Alternatively, calibration procedures specified by the flow meter manufacturer may be used. Fuel flow meters shall be recalibrated either annually or at the minimum frequency specified by the manufacturer. (d) Reporter-specific emission factors or higher heating values shall be determined using industry standard practices such as the American Gas Association (AGA) Gas Measurement Committee Report on heating value and the Gas Processors Association (GPA) Technical Standards Manual for NGL heating value; and ASTM D-2597-94 and ASTM D- 1945-03 for compositional analysis necessary for estimating CO2 emission factors. Sec. 98.405 Procedures for estimating missing data. (a) A complete record of all measured parameters used in the reporting of fuel volumes and in the calculations of CO2 mass emissions is required. Therefore, whenever a quality-assured value of the quantity of natural gas liquids or natural gas during any period is unavailable (e.g., if a flow meter malfunctions), a substitute data value for the missing quantity measurement must be used in the calculations according to paragraphs (b) and (c) of this section. (b) For NGLs, natural gas processing plants shall substitute meter records provided by pipeline(s) for all pipeline receipts of NGLs; by manifests for deliveries made to trucks or rail cars; or metered quantities accepted by the entities purchasing the output from the processing plant whether by pipeline or by truck or rail car. In cases where the metered data from the receiving pipeline(s) or purchasing entities are not available, natural gas processors may substitute estimates based on contract quantities required to be delivered under purchase or delivery contracts with other parties. (c) Natural gas local distribution companies may substitute the metered quantities from the delivering pipelines for all deliveries into the distribution system. In cases where the pipeline metered delivery data are not available, local distribution companies may substitute their pipeline nominations and scheduled quantities for the period when metered values of actual deliveries are not available. (d) Estimates of missing data shall be documented and records maintained showing the calculations of the values used for the missing data. Sec. 98.406 Data reporting requirements. (a) In addition to the information required by Sec. 98.3(c), the annual report for each natural gas processing plant must contain the following information. (1) The total annual quantity in barrels of NGLs produced for sale or delivery on behalf of others in the following categories: Propane, natural butane, ethane, and isobutane, and all other bulk NGLs as a single category. (2) The total annual CO2 mass emissions associated with the volumes in paragraph (a)(1) of this section and calculated in accordance with Sec. 98.403. (b) In addition to the information required by Sec. 98.3(c), the annual report for each local distribution company must contain the following information. (1) The total annual volume in Mcf of natural gas received by the local distribution company for redelivery to end users on the local distribution company's distribution system. (2) The total annual CO2 mass emissions associated with the volumes in paragraph (b)(1) of this section and calculated in accordance with Sec. 98.403. (3) The total natural gas volumes received for redelivery to downstream gas transmission pipelines and other local distribution companies. (4) The name and EPA and EIA identification code of each individual covered facility, and the name and EIA identification code of any other end-user for which the local gas distribution company delivered greater than or equal to 460,000 Mcf during the calendar year, and the total natural gas volumes actually delivered to each of these end-users. (5) The annual volume in Mcf of natural gas delivered by the local distribution company to each of the following end-use categories. For definitions of these categories, refer to EIA Form 176 and Instructions. (i) Residential consumers. (ii) Commercial consumers. (iii) Industrial consumers. (iv) Electricity generating facilities. (6) The total annual CO2 mass emissions associated with the volumes in paragraph (b)(5) of this section and calculated in accordance with Sec. 98.403. Sec. 98.407 Records that must be retained. In addition to the information required by Sec. 98.3(g), each annual report must contain the following information: (a) Records of all daily meter readings and documentation to support volumes of natural gas and NGLs that are reported under this part. (b) Records documenting any estimates of missing metered data. (c) Calculations and worksheets used to estimate CO2 emissions for the volumes reported under this part. (d) Records related to the large end-users identified in Sec. 98.406(b)(4). (e) Records relating to measured Btu content or carbon content. Sec. 98.408 Definitions. All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Table NN-1 of Subpart NN--Default Factors for Calculation Methodology 1 of this Subpart ------------------------------------------------------------------------ Default CO2 Default high heating emission Fuel value factor factor (kg CO2/MMBtu) ------------------------------------------------------------------------ Natural Gas........................ 1.027 MMBtu/Mcf....... 53.02 Propane............................ 3.836 MMBtu/bbl....... 63.02 Butane............................. 4.326 MMBtu/bbl....... 64.93 [[Page 16722]] Ethane............................. 3.082 MMBtu/bbl....... 59.58 Isobutane.......................... 3.974 MMBtu/bbl....... 65.08 Natural Gas Liquids................ 4.140 MMBtu/bbl....... 63.20 ------------------------------------------------------------------------ Table NN-2 of Subpart NN--Lookup Default Values for Calculation Methodology 2 of this Subpart ------------------------------------------------------------------------ Default CO2 emission Fuel Unit value (MT CO2/Unit) ------------------------------------------------------------------------ Natural Gas........................ Mcf................... 0.054452 Propane............................ Barrel................ 0.241745 Butane............................. Barrel................ 0.280887 Ethane............................. Barrel................ 0.183626 Isobutane.......................... Barrel................ 0.258628 Natural Gas Liquids................ Barrel................ 0.261648 ------------------------------------------------------------------------ Subpart OO--Suppliers of Industrial Greenhouse Gases Sec. 98.410 Definition of the source category. (a) The industrial gas supplier source category consists of any facility that produces a fluorinated GHG or nitrous oxide, any bulk importer of fluorinated GHGs or nitrous oxide, and any bulk exporter of fluorinated GHGs or nitrous oxide. (b) To produce a fluorinated GHG means to manufacture a fluorinated GHG from any raw material or feedstock chemical. Producing a fluorinated GHGs does not include the reuse or recycling of a fluorinated GHG or the generation of HFC-23 during the production of HCFC-22. (c) To produce nitrous oxide means to produce nitrous oxide by thermally decomposing ammonium nitrate (NH4NO3). Producing nitrous oxide does not include the reuse or recycling of nitrous oxide or the creation of by-products that are released or destroyed at the production facility. Sec. 98.411 Reporting threshold. Any supplier of industrial greenhouse gases who meets the requirements of Sec. 98.2(a)(4) must report GHG emissions. Sec. 98.412 GHGs to report. You must report the GHG emissions that would result from the release of the nitrous oxide and each fluorinated GHG that you produce, import, export, transform, or destroy during the calendar year. Sec. 98.413 Calculating GHG emissions. (a) The total mass of each fluorinated GHG or nitrous oxide produced annually shall be estimated by using Equation OO-1 of this section: [GRAPHIC] [TIFF OMITTED] TP10AP09.181 Where: P = Mass of fluorinated GHG or nitrous oxide produced annually. Pp = Mass of fluorinated GHG or nitrous oxide produced over the period ``p''. (b) The total mass of each fluorinated GHG or nitrous oxide produced over the period ``p'' shall be estimated by using Equation OO- 2 of this section: [GRAPHIC] [TIFF OMITTED] TP10AP09.182 Where: Pp = Mass of fluorinated GHG or nitrous oxide produced over the period ``p'' (metric tons). Op = Mass of fluorinated GHG or nitrous oxide that is measured coming out of the production process over the period p (metric tons). Up = Mass of used fluorinated GHG or nitrous oxide that is added to the production process upstream of the output measurement over the period ``p'' (metric tons). (c) The total mass of each fluorinated GHG or nitrous oxide transformed shall be estimated by using Equation OO-3 of this section: [GRAPHIC] [TIFF OMITTED] TP10AP09.183 Where: T = Mass of fluorinated GHG or nitrous oxide transformed annually (metric tons). FT = Mass of fluorinated GHG fed into the transformation process annually (metric tons). R = Mass of residual, unreacted fluorinated GHG or nitrous oxide that is permanently removed from the transformation process (metric tons). (d) The total mass of each fluorinated GHG destroyed shall be estimated by using Equation OO-4 of this section: [GRAPHIC] [TIFF OMITTED] TP10AP09.184 Where: D = Mass of fluorinated GHG destroyed annually (metric tons). FD = Mass of fluorinated GHG fed into the destruction device annually (metric tons). DE = Destruction efficiency of the destruction device (fraction). Sec. 98.414 Monitoring and QA/QC requirements. (a) The mass of fluorinated GHGs or nitrous oxide coming out of the production process shall be measured at least daily using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of 0.2 percent of full scale or better. (b) The mass of any used fluorinated GHGs or used nitrous oxide added back into the production process upstream of the output measurement in paragraph (a) of this section shall be measured at least daily (when being added) using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of 0.2 percent of full scale or better. (c) The mass of fluorinated GHGs or nitrous oxide fed into transformation processes shall be measured at least daily using flowmeters, weigh scales, or a combination of volumetric and density [[Page 16723]] measurements with an accuracy and precision of 0.2 percent of full scale or better. (d) If unreacted fluorinated GHGs or nitrous oxide are permanently removed (recovered, destroyed, or emitted) from the transformation process, the mass removed shall be measured using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of 0.2 percent of full scale or better. If the measured mass includes more than trace concentrations of materials other than the unreacted fluorinated GHG or nitrous oxide, the concentration of the unreacted fluorinated GHG or nitrous oxide shall be measured at least daily using equipment and methods (e.g., gas chromatography) with an accuracy and precision of 5 percent or better at the concentrations of the process samples. This concentration (mass fraction) shall be multiplied by the mass measurement to obtain the mass of the fluorinated GHG or nitrous oxide permanently removed from the transformation process. (e) The mass of fluorinated GHG or nitrous oxide sent to another facility for transformation shall be measured at least daily using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of 0.2 percent of full scale or better. (f) The mass of fluorinated GHG sent to another facility for destruction shall be measured at least daily using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of 0.2 percent of full scale or better. If the measured mass includes more than trace concentrations of materials other than the fluorinated GHG, the concentration of the fluorinated GHG shall be measured at least daily using equipment and methods (e.g., gas chromatography) with an accuracy and precision of 5 percent or better at the concentrations of the process samples. This concentration (mass fraction) shall be multiplied by the mass measurement to obtain the mass of the fluorinated GHG sent to another facility for destruction. (g) The mass of fluorinated GHGs fed into the destruction device shall be measured at least daily using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of 0.2 percent of full scale or better. If the measured mass includes more than trace concentrations of materials other than the fluorinated GHG being destroyed, the concentrations of fluorinated GHG being destroyed shall be measured at least daily using equipment and methods (e.g., gas chromatography) with an accuracy and precision of 5 percent or better at the concentrations of the process samples. This concentration (mass fraction) shall be multiplied by the mass measurement to obtain the mass of the fluorinated GHG destroyed. (h) For purposes of Equation OO-4, the destruction efficiency can initially be equated to the destruction efficiency determined during a previous performance test of the destruction device or, if no performance test has been done, the destruction efficiency provided by the manufacturer of the destruction device. Fluorinated GHG production facilities that destroy fluorinated GHGs shall conduct annual measurements of mass flow and fluorinated GHG concentrations at the outlet of the thermal oxidizer in accordance with EPA Method 18 at 40 CFR part 60, appendix A-6. Tests shall be conducted under conditions that are typical for the production process and destruction device at the facility. The sensitivity of the emissions tests shall be sufficient to detect emissions equal to 0.01 percent of the mass of fluorinated GHGs being fed into the destruction device. If the test indicates that the actual DE of the destruction device is lower than the previously determined DE, facilities shall either: (1) Substitute the DE implied by the most recent emissions test for the previously determined DE in the calculations in Sec. 98.413, or (2) Perform more extensive performance testing of the DE of the oxidizer and use the DE determined by the more extensive testing in the calculations in Sec. 98.413. (i) In their estimates of the mass of fluorinated GHGs destroyed, designated representatives of fluorinated GHG production facilities that destroy fluorinated GHGs shall account for any temporary reductions in the destruction efficiency that result from any startups, shutdowns, or malfunctions of the destruction device, including departures from the operating conditions defined in state or local permitting requirements and/or oxidizer manufacturer specifications. (j) All flowmeters, weigh scales, and combinations of volumetric and density measurements that are used to measure or calculate quantities that are to be reported under this subpart shall be calibrated using suitable NIST-traceable standards and suitable methods published by a consensus standards organization (e.g., ASTM, ASME, ASHRAE, or others). Alternatively, calibration procedures specified by the flowmeter, scale, or load cell manufacturer may be used. Calibration shall be performed prior to the first reporting year. After the initial calibration, recalibration shall be performed at least annually or at the minimum frequency specified by the manufacturer, whichever is more frequent. (k) All gas chromatographs that are used to measure or calculate quantities that are to be reported under this subpart shall be calibrated at least monthly through analysis of certified standards with known concentrations of the same chemical(s) in the same range(s) (fractions by mass) as the process samples. Calibration gases prepared from a high-concentration certified standard using a gas dilution system that meets the requirements specified in Test Method 205, 40 CFR Part 51, Appendix M may also be used. Sec. 98.415 Procedures for estimating missing data. (a) A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality- assured value of a required parameter is unavailable (e.g., if a meter malfunctions), a substitute data value for the missing parameter shall be used in the calculations, according to the following requirements: (1) For each missing value of the mass produced, fed into the production process (for used material being reclaimed), fed into transformation processes, fed into destruction devices, sent to another facility for transformation, or sent to another facility for destruction, the substitute value of that parameter shall be a secondary mass measurement. For example, if the mass produced is usually measured with a flowmeter at the inlet to the day tank and that flowmeter fails to meet an accuracy or precision test, malfunctions, or is rendered inoperable, then the mass produced may be estimated by calculating the change in volume in the day tank and multiplying it by the density of the product. (2) For each missing value of fluorinated GHG concentration, except the annual destruction device outlet concentration measurement specified in Sec. 98.414(h), the substitute data value shall be the arithmetic average of the quality-assured values of that parameter immediately preceding and immediately following the missing data incident. If, for a particular parameter, no quality-assured data are available prior to the missing data incident, the substitute data value shall be the first quality- [[Page 16724]] assured value obtained after the missing data period. There are no missing value allowances for the annual destruction device outlet concentration measurement. A re-test must be performed if the data from the annual destruction device outlet concentration measurement are determined to be unacceptable or not representative of typical operations. (3) Notwithstanding paragraphs (a)(1) and (2) of this section, if the owner or operator has reason to believe that the methods specified in paragraphs (a)(1) and (2) of this section are likely to significantly under- or overestimate the value of the parameter during the period when data were missing, the designated representative of the fluorinated GHG production facility shall develop his or her best estimate of the parameter, documenting the methods used, the rationale behind them, and the reasons why the methods specified in paragraphs (a)(1) and (2) of this section would probably lead to a significant under- or overestimate of the parameter. EPA may reject the alternative estimate and replace it with an estimate based on the applicable method in paragraph (a)(1) or (2) if EPA does not agree with the rationale or method for the alternative estimate. Sec. 98.416 Data reporting requirements. In addition to the information required by Sec. 98.3(c), each annual report must contain the following information: (a) Each fluorinated GHG or nitrous oxide production facility shall report the following information at the facility level: (1) Total mass in metric tons of each fluorinated GHG or nitrous oxide produced at that facility. (2) Total mass in metric tons of each fluorinated GHG or nitrous oxide transformed at that facility. (3) Total mass in metric tons of each fluorinated GHG destroyed at that facility. (4) Total mass in metric tons of any fluorinated GHG or nitrous oxide sent to another facility for transformation. (5) Total mass in metric tons of any fluorinated GHG sent to another facility for destruction. (6) Total mass in metric tons of each reactant fed into the production process. (7) Total mass in metric tons of each non-GHG reactant and by- product permanently removed from the process. (8) Mass of used product added back into the production process (e.g., for reclamation). (9) Names and addresses of facilities to which any nitrous oxide or fluorinated GHGs were sent for transformation, and the quantities (metric tons) of nitrous oxide and of each fluorinated GHG that were sent to each for transformation. (10) Names and addresses of facilities to which any fluorinated GHGs were sent for destruction, and the quantities (metric tons) of nitrous oxide and of each fluorinated GHG that were sent to each for destruction. (11) Where missing data have been estimated pursuant to Sec. 98.415, the reason the data were missing, the length of time the data were missing, the method used to estimate the missing data, and the estimates of those data. Where the missing data have been estimated pursuant to Sec. 98.415(a)(3), the report shall explain the rationale for the methods used to estimate the missing data and why the methods specified in Sec. 98.415(a)(1) and (2) would lead to a significant under- or overestimate of the parameters. (b) A fluorinated GHG production facility that destroys fluorinated GHGs shall report the results of the annual fluorinated GHG concentration measurements at the outlet of the destruction device, including: (1) Flow rate of fluorinated GHG being fed into the destruction device in kg/hr. (2) Concentration (mass fraction) of fluorinated GHG at the outlet of the destruction device. (3) Flow rate at the outlet of the destruction device in kg/hr. (4) Emission rate calculated from (b)(2) and (b)(3) in kg/hr. (c) A fluorinated GHG production facility that destroys fluorinated GHGs shall submit a one-time report containing the following information: (1) Destruction efficiency (DE) of each destruction unit. (2) Test methods used to determine the destruction efficiency. (3) Methods used to record the mass of fluorinated GHG destroyed. (4) Chemical identity of the fluorinated GHG(s) used in the performance test conducted to determine DE. (5) Name of all applicable federal or state regulations that may apply to the destruction process. (6) If any process changes affect unit destruction efficiency or the methods used to record mass of fluorinated GHG destroyed, then a revised report must be submitted to reflect the changes. The revised report must be submitted to EPA within 60 days of the change. (d) A bulk importer of fluorinated GHGs or nitrous oxide shall submit an annual report that summarizes their imports at the corporate level, except for transshipments and heels. The report shall contain the following information for each import: (1) Total mass in metric tons of nitrous oxide and each fluorinated GHG imported in bulk. (2) Total mass in metric tons of nitrous oxide and each fluorinated GHG imported in bulk and sold or transferred to persons other than the importer for use in processes resulting in the transformation or destruction of the chemical. (3) Date on which the fluorinated GHGs or nitrous oxide were imported. (4) Port of entry through which the fluorinated GHGs or nitrous oxide passed. (5) Country from which the imported fluorinated GHGs or nitrous oxide were imported. (6) Commodity code of the fluorinated GHGs or nitrous oxide shipped. (7) Importer number for the shipment. (8) If applicable, the names and addresses of the persons and facilities to which the nitrous oxide or fluorinated GHGs were sold or transferred for transformation, and the quantities (metric tons) of nitrous oxide and of each fluorinated GHG that were sold or transferred to each facility for transformation. (9) If applicable, the names and addresses of the persons and facilities to which the nitrous oxide or fluorinated GHGs were sold or transferred for destruction, and the quantities (metric tons) of nitrous oxide and of each fluorinated GHG that were sold or transferred to each facility for destruction. (e) A bulk exporter of fluorinated GHGs or nitrous oxide shall submit an annual report that summarizes their exports at the corporate level, except for transshipments and heels. The report shall contain the following information for each export: (1) Total mass in metric tons of nitrous oxide and each fluorinated GHG exported in bulk. (2) Names and addresses of the exporter and the recipient of the exports. (3) Exporter's Employee Identification Number. (4) Quantity exported by chemical in metric tons of chemical. (5) Commodity code of the fluorinated GHGs and nitrous oxide shipped. (6) Date on which, and the port from which, fluorinated GHGs and nitrous oxide were exported from the United States or its territories. (7) Country to which the fluorinated GHGs or nitrous oxide were exported. Sec. 98.417 Records that must be retained. (a) In addition to the data required by Sec. 98.3(g), the designated representative of a fluorinated GHG production facility shall retain the following records: [[Page 16725]] (1) Dated records of the data used to estimate the data reported under Sec. 98.416, and (2) Records documenting the initial and periodic calibration of the gas chromatographs, weigh scales, flowmeters, and volumetric and density measures used to measure the quantities reported under this subpart, including the industry standards or manufacturer directions used for calibration pursuant to Sec. 98.414(j) and (k). (b) In addition to the data required by paragraph (a) of this section, the designated representative of a fluorinated GHG production facility that destroys fluorinated GHGs shall keep records of test reports and other information documenting the facility's one-time destruction efficiency report and annual destruction device outlet reports in Sec. 98.416(b) and (c). (c) In addition to the data required by Sec. 98.3(g), the designated representative of a bulk importer shall retain the following records substantiating each of the imports that they report: (1) A copy of the bill of lading for the import. (2) The invoice for the import. (3) The U.S. Customs entry form. (d) In addition to the data required by Sec. 98.3(g), the designated representative of a bulk exporter shall retain the following records substantiating each of the exports that they report: (1) A copy of the bill of lading for the export and (2) The invoice for the import. (e) Every person who imports a container with a heel shall keep records of the amount brought into the United States that document that the residual amount in each shipment is less than 10 percent of the volume of the container and will: (1) Remain in the container and be included in a future shipment. (2) Be recovered and transformed. (3) Be recovered and destroyed. Sec. 98.418 Definitions. All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Subpart PP--Suppliers of Carbon Dioxide Sec. 98.420 Definition of the source category. (a) The carbon dioxide (CO2) supplier source category consists of the following: (1) Production process units that capture a CO2 stream for purposes of supplying CO2 for commercial applications. Capture refers to the separation and removal of CO2 from a manufacturing process; fuel combustion source; or a waste, wastewater, or water treatment process. (2) Facilities with CO2 production wells. (3) Importers or exporters of bulk CO2. (b) This source category does not include the following: (1) Geologic sequestration (long term storage) of CO2. (2) Injection and subsequent production and/or processing of CO2 for enhanced oil and gas recovery. (3) Above ground storage of CO2. (4) Transportation or distribution of CO2 via pipelines, vessels, motor carriers, or other means. (5) Purification, compression, or processing of CO2. (6) CO2 imported or exported in equipment. Sec. 98.421 Reporting threshold. Any supplier of CO2 who meets the requirements of Sec. 98.2(a)(4) must report GHG emissions. Sec. 98.422 GHGs to report. You must report the mass of carbon dioxide captured from production process units, the mass of carbon dioxide extracted from carbon dioxide production wells, and the mass of carbon dioxide imported and exported regardless of the degree of impurities in the carbon dioxide stream. Sec. 98.423 Calculating GHG emissions. (a) Facilities with production process units must calculate quarterly the total mass of carbon dioxide in a carbon dioxide stream in metric tons captured, prior to any subsequent purification, processing, or compressing, based on multiplying the mass flow by the composition data, according to Equation PP-1 of this section. Mass flow and composition data measurements are made in accordance with Sec. 98.424. [GRAPHIC] [TIFF OMITTED] TP10AP09.185 Where: CO2 = CO2 mass emission (metric tons per year). CCO2 = Quarterly average CO2 concentration in flow (wt. % CO2). Q = Quarterly mass flow rate (metric tons per quarter). (b) CO2 production well facilities must calculate quarterly the total mass of carbon dioxide in a carbon dioxide stream from wells in metric tons, prior to any subsequent purification, processing, or compressing, based on multiplying the mass flow by the composition data, according to Equation PP-1. Mass flow and composition data measurements are made in accordance with Sec. 98.424. (c) Importers or exporters of a carbon dioxide stream must calculate quarterly the total mass of carbon dioxide imported or exported in metric tons, based on multiplying the mass flow by the composition data, according to Equation PP-1. Mass flow and composition data measurements are made in accordance with Sec. 98.424. The quantities of CO2 imported or exported in equipment, such as fire extinguishers, need not be calculated or reported. Sec. 98.424 Monitoring and QA/QC requirements. (a) Facilities with production process units that capture a carbon dioxide stream must measure on a quarterly basis using a mass flow meter the mass flow of the CO2 stream captured. If production process units do not have mass flow meters installed to measure the mass flow of the CO2 stream captured, measurements shall be based on the mass flow of gas transferred off site using a mass flow meter. In either case, sampling also must be conducted on at least a quarterly basis to determine the composition of the captured or transferred CO2 stream. (b) Carbon dioxide production well facilities must measure on a quarterly basis the mass flow of the CO2 stream extracted using a mass flow meter. If the CO2 production wells do not have mass flow meters installed to measure the mass flow of the CO2 stream extracted, measurements shall be based on mass flow of gas transferred off site using a mass flow meter. In either case, sampling must be conducted on at least a quarterly basis to determine the composition of the extracted or transferred carbon dioxide. (c) Importers or exporters of bulk CO2 must measure on a quarterly basis the mass flow of the CO2 stream imported or exported using a mass flow meter and must conduct sampling on at least a quarterly basis to determine the composition of the imported or exported CO2 stream. If the importer of a CO2 stream does not have mass flow meters installed to measure the mass flow of gas imported, the measurements shall be based on the mass flow of the imported CO2 stream transferred off site or used in on-site processes, as measured by mass flow meters. If an exporter of a CO2 stream does not have mass flow meters installed to measure the mass flow exported, the measurements shall be based on the mass flow of the CO2 stream received for export, as measured by mass flow meters. In all cases, sampling on at least a quarterly basis also must be conducted to determine the composition of the CO2 stream. [[Page 16726]] (d) Mass flow meter calibrations must be NIST traceable. (e) Methods to measure the composition of the carbon dioxide captured, extracted, transferred, imported, or exported must conform to applicable chemical analytical standards. Acceptable methods include U.S. Food and Drug Administration food-grade specifications for carbon dioxide (see 21 CFR 184.1250) and ASTM standard E-1745-95 (2005). Sec. 98.425 Procedures for estimating missing data. (a) Missing quarterly monitoring data on mass flow of CO2 streams captured, extracted, imported, or exported shall be substituted with the greater of the following values: (1) Quarterly CO2 mass flow of gas transferred off site measured during the current reporting year. (2) Quarterly or annual average values of the monitored CO2 mass flow from the past calendar year. (b) Missing monitoring data on the mass flow of the CO2 stream transferred off site shall be substituted with the quarterly or annual average values from off site transfers from the past calendar year. (c) Missing data on composition of the CO2 stream captured, extracted, transferred, imported, or exported may be substituted for with quarterly or annual average values from the past calendar year. Sec. 98.426 Data reporting requirements. In addition to the information required by Sec. 98.3(c), each annual report must contain the following information. (a) Each facility with production process units or CO2 production wells must report the following information: (1) Total annual mass in metric tons and the weighted average composition of the CO2 stream captured, extracted, or transferred in either gas, liquid, or solid forms. (2) Annual quantities in metric tons transferred to the following end use applications by end-use, if known: (i) Food and beverage. (ii) Industrial and municipal water/wastewater treatment. (iii) Metal fabrication, including welding and cutting. (iv) Greenhouse uses for plant growth. (v) Fumigants (e.g., grain storage) and herbicides. (vi) Pulp and paper. (vii) Cleaning and solvent use. (viii) Fire fighting. (ix) Transportation and storage of explosives. (x) Enhanced oil and natural gas recovery. (xi) Long-term storage (sequestration). (xii) Research and development. (b) CO2 importers and exporters must report the information in paragraphs (a)(1) and (a)(2) at the corporate level. Sec. 98.427 Records that must be retained. In addition to the records required by Sec. 98.3(g), you must retain the records specified in paragraphs (a) through (c) of this section. (a) The owner or operator of a facility containing production process units must retain quarterly records of captured and transferred CO2 streams and composition. (b) The owner or operator of a carbon dioxide production well facility must maintain quarterly records of the mass flow of the extracted and transferred CO2 stream and composition. (c) Importers or exporters of CO2 must retain quarterly records of the mass flow and composition of CO2 streams imported or exported. Sec. 98.428 Definitions. All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. PART 600--[AMENDED] 27. The authority citation for part 600 continues to read as follows: Authority: 49 U.S.C. 32901-23919q, Pub. L. 109-58. Subpart A--[Amended] 28. Section 600.006-08 is amended by revising paragraph (c) introductory text and adding paragraph (c)(5) to read as follows: Sec. 600.006-08 Data and information requirements for fuel economy vehicles. * * * * * (c) The manufacturer shall submit the following data: * * * * * (5) Starting with the 2011 model year, the data submitted according to paragraphs (c)(1) through (c)(4) of this section shall include CO2, N2O, and CH4 in addition to fuel economy. Use the procedures specified in 40 CFR part 1065 as needed to measure N2O and CH4. Round the test results as follows: (i) Round CO2 to the nearest 1 g/mi. (ii) Round N2O to the nearest 0.001 g/mi. (iii) Round CH4 to the nearest 0.001g/mi. * * * * * PART 1033--[AMENDED] 29. The authority citation for part 1033 continues to read as follows: Authority: 42 U.S.C. 7401-7671q. Subpart C--[Amended] 30. Section 1033.205 is amended by revising paragraph (d)(8) to read as follows: Sec. 1033.205 Applying for a certificate of conformity. * * * * * (d) * * * (8)(i) All test data you obtained for each test engine or locomotive. As described in Sec. 1033.235, we may allow you to demonstrate compliance based on results from previous emission tests, development tests, or other testing information. Include data for NOX, PM, HC, CO, and CO2. (ii) Starting in the 2011 model year, report measured N2O and CH4 as described in Sec. 1033.235. Small manufacturers/remanufacturers may omit this requirement. * * * * * 31. Section 1033.235 is amended by adding paragraph (i) to read as follows: Sec. 1033.235 Emission testing required for certification. * * * * * (i) Starting in the 2011 model year, measure N2O, and CH4 with each low-hour certification test using the procedures specified in 40 CFR part 1065. Small manufacturers/ remanufacturers may omit this requirement. Use the same units and modal calculations as for your other results to report a single weighted value for CO2, N2O, and CH4. Round the final values as follows: (1) Round CO2 to the nearest 1 g/kW-hr. (2) Round N2O to the nearest 0.001 g/kW-hr. (3) Round CH4 to the nearest 0.001g/kW-hr. Subpart J--[Amended] 32. Section 1033.905 is amended by adding the abbreviations CH4 and N2O in alphanumeric order to read as follows: Sec. 1033.905 Symbols, acronyms, and abbreviations. * * * * * * * * * * * * CH4 methane. * * * * * * * N2O nitrous oxide. * * * * * * * PART 1039--[AMENDED] 33. The authority citation for part 1039 continues to read as follows: Authority: 42 U.S.C. 7401-7671q. [[Page 16727]] Subpart C--[Amended] 34. Section 1039.205 is amended by revising paragraph (r) to read as follows: Sec. 1039.205 What must I include in my application? * * * * * (r) Report test results as follows: (1) Report all test results involving measurement of pollutants for which emission standards apply. Include test results from invalid tests or from any other tests, whether or not they were conducted according to the test procedures of subpart F of this part. We may ask you to send other information to confirm that your tests were valid under the requirements of this part and 40 CFR part 1065. (2) Starting in the 2011 model year, report measured CO2 , N2O, and CH4 as described in Sec. 1039.235. Small-volume engine manufacturers may omit this requirement. * * * * * 35. Section 1039.235 is amended by adding paragraph (g) to read as follows: Sec. 1039.235 What emission testing must I perform for my application for a certificate of conformity? * * * * * (g) Starting in the 2011 model year, measure CO2, N2O, and CH4 with each low-hour certification test using the procedures specified in 40 CFR part 1065. Small-volume engine manufacturers may omit this requirement. These measurements are not required for NTE testing. Use the same units and modal calculations as for your other results to report a single weighted value for each constituent. Round the final values as follows: (1) Round CO2 to the nearest 1 g/kW-hr. (2) Round N2O to the nearest 0.001 g/kW-hr. (3) Round CH4 to the nearest 0.001g/kW-hr. Subpart I--[Amended] 36. Section 1039.805 is amended by adding the abbreviations CH4 and N2O in alphanumeric order to read as follows: Sec. 1039.805 What symbols, acronyms, and abbreviations does this part use? * * * * * * * * * * * * CH4 methane. * * * * * * * N2O nitrous oxide. * * * * * * * PART 1042--[AMENDED] 37. The authority citation for part 1042 continues to read as follows: Authority: 42 U.S.C. 7401-7671q. Subpart C--[Amended] 38. Section 1042.205 is amended by revising paragraph (r) to read as follows: Sec. 1042.205 Application requirements. * * * * * (r) Report test results as follows: (1) Report all test results involving measurement of pollutants for which emission standards apply. Include test results from invalid tests or from any other tests, whether or not they were conducted according to the test procedures of subpart F of this part. We may ask you to send other information to confirm that your tests were valid under the requirements of this part and 40 CFR part 1065. (2) Starting in the 2011 model year, report measured CO2, N2O, and CH4 as described in Sec. 1042.235. Small-volume engine manufacturers may omit this requirement. * * * * * 39. Section 1042.235 is amended by adding paragraph (g) to read as follows: Sec. 1042.235 Emission testing required for a certificate of conformity. * * * * * (g) Starting in the 2011 model year, measure CO2, N2O, and CH4 with each low-hour certification test using the procedures specified in 40 CFR part 1065. Small-volume engine manufacturers may omit this requirement. These measurements are not required for NTE testing. Use the same units and modal calculations as for your other results to report a single weighted value for each constituent. Round the final values as follows: (1) Round CO2 to the nearest 1 g/kW-hr. (2) Round N2O to the nearest 0.001 g/kW-hr. (3) Round CH4 to the nearest 0.001g/kW-hr. Subpart J--[Amended] 40. Section 1042.905 is amended by adding the abbreviations CH4 and N2O in alphanumeric order to read as follows: Sec. 1042.905 Symbols, acronyms, and abbreviations. * * * * * * * * * * * * CH4 methane. * * * * * * * N2O nitrous oxide. * * * * * * * PART 1045--[AMENDED] 41. The authority citation for part 1045 continues to read as follows: Authority: 42 U.S.C. 7401-7671q. Subpart C--[Amended] 42. Section 1045.205 is amended by revising paragraph (q) to read as follows: Sec. 1045.205 What must I include in my application? * * * * * (q) Report test results as follows: (1) Report all test results involving measurement of pollutants for which emission standards apply. Include test results from invalid tests or from any other tests, whether or not they were conducted according to the test procedures of subpart F of this part. We may ask you to send other information to confirm that your tests were valid under the requirements of this part and 40 CFR parts 1060 and 1065. (2) Starting in the 2011 model year, report measured CO2, N2O, and CH4 as described in Sec. 1045.235. Small-volume engine manufacturers may omit this requirement. * * * * * 43. Section 1045.235 is amended by adding paragraph (g) to read as follows: Sec. 1045.235 What emission testing must I perform for my application for a certificate of conformity? * * * * * (g) Measure CO2, N2O, and CH4 with each low-hour certification test using the procedures specified in 40 CFR part 1065. Small-volume engine manufacturers may omit this requirement. These measurements are not required for NTE testing. Use the same units and modal calculations as for your other results to report a single weighted value for each constituent. Round the final values as follows: (1) Round CO2 to the nearest 1 g/kW-hr. (2) Round N2O to the nearest 0.001 g/kW-hr. (3) Round CH4 to the nearest 0.001g/kW-hr. PART 1048--[AMENDED] 44. The authority citation for part 1048 continues to read as follows: Authority: 42 U.S.C. 7401-7671q. Subpart C--[Amended] 45. Section 1048.205 is amended by revising paragraph (s) to read as follows: [[Page 16728]] Sec. 1048.205 What must I include in my application? * * * * * (s) Report test results as follows: (1) Report all test results involving measurement of pollutants for which emission standards apply. Include test results from invalid tests or from any other tests, whether or not they were conducted according to the test procedures of subpart F of this part. We may ask you to send other information to confirm that your tests were valid under the requirements of this part and 40 CFR part 1065. (2) Starting in the 2011 model year, report measured CO2, N2O, and CH4 as described in Sec. 1048.235. Small-volume engine manufacturers may omit this requirement. * * * * * 46. Section 1048.235 is amended by adding paragraph (g) to read as follows: Sec. 1048.235 What emission testing must I perform for my application for a certificate of conformity? * * * * * (g) Starting in the 2011 model year, measure CO2, N2O, and CH4 with each low-hour certification test using the procedures specified in 40 CFR part 1065. Small-volume engine manufacturers may omit this requirement. These measurements are not required for measurements using field-testing procedures. Use the same units and modal calculations as for your other results to report a single weighted value for each constituent. Round the final values as follows: (1) Round CO2 to the nearest 1 g/kW-hr. (2) Round N2O to the nearest 0.001 g/kW-hr. (3) Round CH4 to the nearest 0.001g/kW-hr. Subpart I--[Amended] 47. Section 1048.805 is amended by adding the abbreviations CH4 and N2O in alphanumeric order to read as follows: Sec. 1048.805 What symbols, acronyms, and abbreviations does this part use? * * * * * * * * * * * * CH4 methane. * * * * * * * N2O nitrous oxide. * * * * * * * PART 1051--[AMENDED] 48. The authority citation for part 1051 continues to read as follows: Authority: 42 U.S.C. 7401-7671q. Subpart C--[Amended] 49. Section 1051.205 is amended by revising paragraph (p) to read as follows: Sec. 1051.205 What must I include in my application? * * * * * (p) Report test results as follows: (1) Report all test results involving measurement of pollutants for which emission standards apply. Include test results from invalid tests or from any other tests, whether or not they were conducted according to the test procedures of subpart F of this part. We may ask you to send other information to confirm that your tests were valid under the requirements of this part and 40 CFR parts 86 and 1065. (2) Starting in the 2011 model year, report measured CO2, N2O, and CH4 as described in Sec. 1051.235. Small-volume manufacturers may omit this requirement. * * * * * 50. Section 1051.235 is amended by adding paragraph (i) to read as follows: Sec. 1051.235 What emission testing must I perform for my application for a certificate of conformity? * * * * * (i) Starting in the 2011 model year, measure CO2, N2O, and CH4 with each low-hour certification test using the procedures specified in 40 CFR part 1065. Small-volume manufacturers may omit this requirement. Use the same units and modal calculations as for your other results to report a single weighted value for each constituent. Round the final values as follows: (1) Round CO2 to the nearest 1 g/kW-hr or 1 g/km, as appropriate. (2) Round N2O to the nearest 0.001 g/kW-hr or 0.001 g/ km, as appropriate. (3) Round CH4 to the nearest 0.001g/kW-hr or 0.001 g/km, as appropriate. Subpart I--[Amended] 51. Section 1051.805 is amended by adding the abbreviations CH4 and N2O in alphanumeric order to read as follows: Sec. 1051.805 What symbols, acronyms, and abbreviations does this part use? * * * * * * * * * * * * CH4 methane. * * * * * * * N2O nitrous oxide. * * * * * * * PART 1054--[AMENDED] 52. The authority citation for part 1054 continues to read as follows: Authority: 42 U.S.C. 7401-7671q. Subpart C--[Amended] 53. Section 1054.205 is amended by revising paragraph (p) to read as follows: Sec. 1054.205 What must I include in my application? * * * * * (p) Report test results as follows: (1) Report all test results involving measurement of pollutants for which emission standards apply. Include test results from invalid tests or from any other tests, whether or not they were conducted according to the test procedures of subpart F of this part. We may ask you to send other information to confirm that your tests were valid under the requirements of this part and 40 CFR parts 1060 and 1065. (2) Starting in the 2011 model year, report measured CO2, N2O, and CH4 as described in Sec. 1054.235. Small-volume engine manufacturers may omit this requirement. * * * * * 54. Section 1054.235 is amended by adding paragraph (g) to read as follows: Sec. 1054.235 What exhaust emission testing must I perform for my application for a certificate of conformity? * * * * * (g) Measure CO2, N2O, and CH4 with each low-hour certification test using the procedures specified in 40 CFR part 1065. Small-volume engine manufacturers may omit this requirement. Use the same units and modal calculations as for your other results to report a single weighted value for each constituent. Round the final values as follows: (1) Round CO2 to the nearest 1 g/kW-hr. (2) Round N2O to the nearest 0.001 g/kW-hr. (3) Round CH4 to the nearest 0.001 g/kW-hr. 55. A new part 1064 is added to subchapter U of chapter I to read as follows: PART 1064--VEHICLE TESTING PROCEDURES Subpart A--Applicability and general provisions Sec. 1064.1 Applicability. Subpart B--Air Conditioning Systems 1064.201 Method for calculating emissions due to air conditioning leakage. [[Page 16729]] Authority: 42 U.S.C. 7401-7671q. Subpart A--Applicability and General Provisions Sec. 1064.1 Applicability. (a) This part describes procedures that apply to testing we require for 2011 and later model year light-duty vehicles, light-duty trucks, and medium-duty personal vehicles (see 40 CFR part 86). (b) See 40 CFR part 86 for measurement procedures related to exhaust and evaporative emissions. Subpart B--Air Conditioning Systems Sec. 1064.201 Method for calculating emissions due to air conditioning leakage. Determine a refrigerant leakage rate from vehicle-based air conditioning units as described in this section. (a) Emission totals. Calculate an annual rate of refrigerant leakage from an air conditioning system using the following equation: Grams/YRTOT = Grams/YRRP + Grams/YRSP + Grams/YRFH + Grams/YRMC + Grams/YRC Where: Grams/YRRP = Emission rate for rigid pipe connections as described in paragraph (b) of this section. Grams/YRSP = Emission rate for service ports and refrigerant control devices as described in paragraph (c) of this section. Grams/YRFH = Emission rate for flexible hoses as described in paragraph (d) of this section. Grams/YRMC = Emission rate for heat exchangers, mufflers, receiver/driers, and accumulators as described in paragraph (e) of this section. Grams/YRC = Emission rate for compressors as described in paragraph (f) of this section. (b) Fittings. Determine the emission rate for rigid pipe connections using the following Equation: Grams/YRRP = 0.00522 [middot] [(125 [middot] SO) + (75 [middot] SCO) + (50 [middot] MO) + (10 [middot] SW) + (5 [middot] SWO) + (MG)] Where: SO = The number of single O-ring connections. SCO = The number of single captured O-ring connections. MO = The number of multiple O-ring connections. SW = The number of seal washer connections. SWO = The number of seal washer with O-ring connections. MG = The number of metal gasket connections. (c) Service ports and refrigerant control devices. Determine the emission rate for service ports and refrigerant control devices using the following Equation: Grams/YRSP = (0.3 [middot] HSSP) + (0.2 [middot] LSSP) + (0.2 [middot] STV) + (0.2 [middot] TXV) Where: HSSP = The number of high side service ports. LSSP = The number of low side service ports. STV = The total number of switches, transducers, and expansion valves. TXV = The number of TXV refrigerant control devices. (d) Flexible hoses. Determine the permeation emission rate for each segment of flexible hose using the following Equation, then add those values to calculate a total emission rate for the system: Grams/YRFH = 0.00522 [middot] (3.14159 [middot] ID [middot] L [middot] ER) Where: ID = Inner diameter of hose, in millimeters. L = Length of hose, in millimeters. ER = Emission rate per unit internal surface area of the hose, in g/ mm\2\. Select the appropriate value from the following table: ------------------------------------------------------------------------ ER ----------------------------------- Material/configuration High-pressure Low-pressure side side ------------------------------------------------------------------------ Rubber.............................. 0.0216 0.0144 Standard barrier or veneer hose..... 0.0054 0.0036 Ultra-low permeation barrier or 0.00225 0.00167 veneer hose........................ ------------------------------------------------------------------------ (e) Heat exchangers, mufflers, receiver/driers, and accumulators. Use an emission rate of 0.5 grams per year as a combined value for all heat exchangers, mufflers, receiver/driers, and accumulators (Grams/ YRMC). (f) Compressors. Determine the emission rate for compressors using the following equation: Grams/YRC = 0.00522 [middot] [(300 [middot] OHS) + (200 [middot] MHS) + (150 [middot] FAP) + (100 [middot] GHS) + (1500/SSL)] Where: OHS = The number of O-ring housing seals. MHS = The number of molded housing seals. FAP = The number of fitting adapter plates. GHS = The number of gasket housing seals. SSL = The number of lips on shaft seal (for belt-driven compressors only). PART 1065--[AMENDED] 56. The authority citation for part 1065 continues to read as follows: Authority: 42 U.S.C. 7401-7671q. Subpart C--[Amended] 57. A new Sec. 1065.257 is added to subpart C to read as follows: Sec. 1065.257 Nondispersive N2O infrared analyzer. (a) Application. Use a nondispersive infrared (NDIR) analyzer to measure N2O concentrations in diluted exhaust for batch sampling. Batch sampling may be performed in a single bag covering all phases of the test procedure. (b) Component requirements. We recommend that you use an NDIR analyzer that meets the specifications in Table 1 of Sec. 1065.205. Note that your NDIR-based system must meet the calibration and verification in Sec. 1065.357 and it must also meet the linearity verification in Sec. 1065.307. You may use an NDIR analyzer that has compensation algorithms that are functions of other gaseous measurements and the engine's known or assumed fuel properties. The target value for any compensation algorithm is 0.0 % (that is, no bias high and no bias low), regardless of the uncompensated signal's bias. (c) Artifact formation, SO2, and H2O removal. SO2, NOX, and H2O have been shown to react in the sample bag to form N2O. SO2 and H2O must therefore be sequentially removed from the sample gas before the sample enters the bag. SO2 can be neutralized from the sample gas by passing the sample through a sorbent cartridge packed with 120 cc of a 10:1 ratio of 18-20 mesh sand and Ca(OH)2. This sorbent works only in the presence of H2O so the H2O sorbent cartridge must be located downstream of the SO2 sorbent cartridge. H2O can be removed by passing the sample through a sorbent cartridge packed with 120 cc of P2O5. 58. A new Sec. 1065.357 is added to subpart D to read as follows: Sec. 1065.357 CO and Co2 interference verification for N2O NDIR analyzers. (a) Scope and frequency. If you measure CO using an NDIR analyzer, [[Page 16730]] verify the amount of CO and Co2 interference after initial analyzer installation and after major maintenance. (b) Measurement principles. CO and Co2 can positively interfere with an NDIR analyzer by causing a response similar to N2O. If the NDIR analyzer uses compensation algorithms that utilize measurements of other gases to meet this interference verification, simultaneously conduct these other measurements to test the compensation algorithms during the analyzer interference verification. (c) System requirements. A N2O NDIR analyzer must have combined CO and Co2 interference that is within 2 percent of the flow-weighted mean concentration of N2O expected at the standard, though we strongly recommend a lower interference that is within ±1 percent. (d) Procedure. Perform the interference verification as follows: (1) Start, operate, zero, and span the N2O NDIR analyzer as you would before an emission test. (2) Introduce a CO span to the analyzer. (3) Allow time for the analyzer response to stabilize. Stabilization time may include time to purge the transfer line and to account for analyzer response. (4) While the analyzer measures the sample's concentration, record its output for 30 seconds. Calculate the arithmetic mean of this data. (5) Scale the CO interference by multiplying this mean value (from paragraph (d)(7) of this section) by the ratio of expected CO to span gas CO concentration. In other words, estimate the flow-weighted mean dry concentration of CO expected during testing, and then divide this value by the concentration of CO in the span gas used for this verification. Then multiply this ratio by the mean value recorded during this verification (from paragraph (d)(7) of this section). (6) Repeat the steps in paragraphs (d)(2) through (5) of this section, but with a CO2 analytical gas mixture instead of CO and without humidifying the sample through the distilled water in a sealed vessel. (7) Add together the CO and CO2-scaled result of paragraphs (d)(5) and (6) of this section. (8) The analyzer meets the interference verification if the result of paragraph (d)(7) of this section is within ±2 percent of the flow-weighted mean concentration of N2O expected at the standard. (e) Exceptions. The following exceptions apply: (1) You may omit this verification if you can show by engineering analysis that for your N2O sampling system and your emission calculations procedures, the combined CO, CO2, and H2O interference for your N2O NDIR analyzer always affects your brake-specific N2O emission results within ±0.5 percent of the applicable N2O standard. (2) You may use a N2O NDIR analyzer that you determine does not meet this verification, as long as you try to correct the problem and the measurement deficiency does not adversely affect your ability to show that engines comply with all applicable emission standards. Subpart H--[Amended] 59. Section 1065.750 is amended by revising paragraph (a)(1)(ii) and adding paragraph (a)(3)(xi) to read as follows: Sec. 1065.750 Analytical gases. * * * * * (a) * * * (1) * * * (ii) Contamination as specified in the following table: Table 1 of Sec. 1065.750--General Specifications for Purified Gases ------------------------------------------------------------------------ Purified synthetic Constituent air \1\ Purified N2\1\ ------------------------------------------------------------------------ THC (C1 equivalent)............. <0.05 μmol/mol. <0.05 μmol/mol CO.............................. <1 μmol/mol.... <1 μmol/mol. CO2............................. <10 μmol/mol... <10 μmol/mol. O2.............................. 0.205 to 0.215 mol/ <2 μmol/mol. mol. NOX............................. <0.02 μmol/mol. <0.02 μmol/mol. N2O............................. <0.05 μmol/mol. <0.05 μmol/mol. ------------------------------------------------------------------------ \1\ We do not require these levels of purity to be NIST-traceable. * * * * * (3) * * * (xi) N2O, balance purified N2. * * * * * Subpart K--[Amended] 60. Section 1065.1001 is amended by revising the definition for ``Oxides of nitrogen'' to read as follows: Sec. 1065.1001 Definitions. * * * * * Oxides of nitrogen means NO and NO2 as measured by the procedures specified in Sec. 1065.270. Oxides of nitrogen are expressed quantitatively as if the NO is in the form of NO2, such that you use an effective molar mass for all oxides of nitrogen equivalent to that of NO2. * * * * * 61. Section 1065.1005 is amended by adding items to the table in paragraph (b) in alphanumeric order to read as follows: Sec. 1065.1005 Symbols, abbreviations, acronyms, and units of measure. * * * * * (b) * * * [[Page 16731]] ------------------------------------------------------------------------ Symbol Species ------------------------------------------------------------------------ * * * * * * * Ca(OH)2................................ calcium hydroxide * * * * * * * P2O5................................... phosphorous pentoxide * * * * * * * SO2.................................... sulfur dioxide * * * * * * * ------------------------------------------------------------------------ * * * * * [FR Doc. E9-5711 Filed 4-9-09; 8:45 am] BILLING CODE 6560-50-P