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Mandatory Reporting of Greenhouse Gases
Note: EPA no longer updates this information, but it may be useful as a reference or resource.
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