Document ID: EPA-HQ-OAR-2012-0934-0130
Agency: epa
Document Type: Supporting & Related Material
Title: 
Posted Date: 2013-12-24T05:00Z

Subpart A -- General Provision
§ 98.1 Purpose and scope.
(a) This part establishes mandatory greenhouse gas (GHG) reporting requirements for owners and operators of certain facilities that directly emit GHG as well as for certain suppliers and industrial GHG suppliers. For suppliers, the GHGs reported are the quantity that would be emitted from combustion or use of the products supplied.
      (b) Owners and operators of facilities and suppliers that are subject to this part must follow the requirements of this subpart and all applicable subparts of this part. If a conflict exists between a provision in subpart A and any other applicable subpart, the requirements of the applicable subpart shall take precedence.
      (c) For facilities required to report under onshore petroleum and natural gas production under subpart W of this part, the terms Owner and Operator used in subpart A have the same definition as Onshore petroleum and natural gas production owner or operator, as defined in § 98.238 of this part.

§ 98.2 Who must report?
(a) The GHG reporting requirements and related monitoring, recordkeeping, and reporting requirements of this part apply to the owners and operators of any facility that is located in the United States or under or attached to the Outer Continental Shelf (as defined in 43 U.S.C. 1331) and that meets the requirements of either paragraph (a)(1), (a)(2), or (a)(3) of this section; and any supplier that meets the requirements of paragraph (a)(4) of this section:
(1) A facility that contains any source category that is listed in Table A - 3 of this subpart in any calendar year starting in 2010. For these facilities, the annual GHG report must cover stationary fuel combustion sources (subpart C of this part), miscellaneous use of carbonates (subpart U of this part), and all applicable source categories listed in Table A - 3 and Table A - 4 of this subpart.
(2) A facility that contains any source category that is listed in Table A - 4 of this subpart and that emits 25,000 metric tons CO 2 e or more per year in combined emissions from stationary fuel combustion units, miscellaneous uses of carbonate, and all applicable source categories that are listed in Table A - 3 and Table A - 4 of this subpart. For these facilities, the annual GHG report must cover stationary fuel combustion sources (subpart C of this part), miscellaneous use of carbonates (subpart U of this part), and all applicable source categories listed in Table A - 3 and Table A - 4 of this subpart.
(3) A facility that in any calendar year starting in 2010 meets all three of the conditions listed in this paragraph (a)(3). For these facilities, the annual GHG report must cover emissions from stationary fuel combustion sources only.
(i) The facility does not meet the requirements of either paragraph (a)(1) or (a)(2) of this section.
(ii) The aggregate maximum rated heat input capacity of the stationary fuel combustion units at the facility is 30 mmBtu/hr or greater.
(iii) The facility emits 25,000 metric tons CO2e or more per year in combined emissions from all stationary fuel combustion sources.
(4) A supplier that is listed in Table A - 5 of this subpart. For these suppliers, the annual GHG report must cover all applicable products for which calculation methodologies are provided in the subparts listed in Table A - 5 of this subpart.
(5) Research and development activities are not considered to be part of any source category defined in this part.
(b) To calculate GHG emissions for comparison to the 25,000 metric ton CO2e per year emission threshold in paragraph (a)(2) of this section, the owner or operator shall calculate annual CO2e emissions, as described in paragraphs (b)(1) through (b)(4) of this section.
(1) Calculate the annual emissions of CO2, CH4, N2O, and each fluorinated GHG in metric tons from all applicable source categories listed in paragraph (a)(2) of this section. The GHG emissions shall be calculated using the calculation methodologies specified in each applicable subpart and available company records. Include emissions from only those gases listed in Table A - 1 of this subpart.
(2) For each general stationary fuel combustion unit, calculate the annual CO2 emissions in metric tons using any of the four calculation methodologies specified in §98.33(a). Calculate the annual CH4 and N2O emissions from the stationary fuel combustion sources in metric tons using the appropriate equation in §98.33(c). Exclude carbon dioxide emissions from the combustion of biomass, but include emissions of CH4 and N2O from biomass combustion.
(3) For miscellaneous uses of carbonate, calculate the annual CO2 emissions in metric tons using the procedures specified in subpart U of this part.
(4) Sum the emissions estimates from paragraphs (b)(1), (b)(2), and (b)(3) of this section for each GHG and calculate metric tons of CO2e using Equation A - 1 of this section.
                                       
Where:
CO2 e	=	Carbon dioxide equivalent, metric tons/year.
GHGi	=	Mass emissions of each greenhouse gas listed in Table A - 1 of this subpart, metric tons/year.
GWPi	=	Global warming potential for each greenhouse gas from Table A - 1 of this subpart. 
n	=	The number of greenhouse gases emitted.
(5) For purpose of determining if an emission threshold has been exceeded, include in the emissions calculation any CO2 that is captured for transfer off site.
(c) To calculate GHG emissions for comparison to the 25,000 metric ton CO2 e/year emission threshold for stationary fuel combustion under paragraph (a)(3) of this section, calculate CO2, CH4, and N2O emissions from each stationary fuel combustion unit by following the methods specified in paragraph (b)(2) of this section. Then, convert the emissions of each GHG to metric tons CO2e per year using Equation A - 1 of this section, and sum the emissions for all units at the facility.
      (d) To calculate GHG quantities for comparison to the 25,000 metric ton CO2 per year threshold for importers and exporters of coal-to-liquid products under paragraph (a)(4) of this section, calculate the mass in metric tons per year of CO2 that would result from the complete combustion or oxidation of the quantity of coal-to-liquid products that are imported during the reporting year and that are exported during the reporting year. Compare the imported quantities and the exported quantities separately to the 25,000 metric ton CO2 per year threshold. Calculate the emissions using the methodology specified in subpart LL of this part.
      (e) To calculate GHG quantities for comparison to the 25,000 metric ton CO2e per year threshold for importers and exporters of petroleum products under paragraph (a)(4) of this section, calculate the mass in metric tons per year of CO2 that would result from the complete combustion or oxidation of the volume of petroleum products and natural gas liquids that are imported during the reporting year and that are exported during the reporting year. Compare the imported quantities and the exported quantities separately to the 25,000 metric ton CO2 per year  threshold. Calculate the emissions using the methodology specified in subpart MM of this part.
      (f) To calculate GHG quantities for comparison to the 25,000 metric ton CO2e per year threshold under paragraph (a)(4) of this section for importers and exporters of industrial greenhouse gases and for importers and exporters of CO2,the owner or operator shall calculate the mass in metric tons per year of CO2e imports and exports as described in paragraphs (f)(1) through (f)(3) of this section. Compare the imported quantities and the exported quantities separately to the 25,000 metric ton CO2 per year threshold.
(1) Calculate the mass in metric tons per year of CO2, N2O, and each fluorinated GHG that is imported and the mass in metric tons per year of CO2, N2O, and each fluorinated GHG that is exported during the year. Include only those gases listed in Table A - 1 of this subpart.
(2) Convert the mass of each imported and each GHG exported from paragraph (f)(1) of this section to metric tons of CO2e using Equation A - 1 of this section.
(3) Sum the total annual metric tons of CO2e in paragraph (f)(2) of this section for all imported GHGs. Sum the total annual metric tons of CO2e in paragraph (f)(2) of this section for all exported GHGs.
(g) If a capacity or generation reporting threshold in paragraph (a)(1) of this section applies, the owner or operator shall review the appropriate records and perform any necessary calculations to determine whether the threshold has been exceeded.
(h) An owner or operator of a facility or supplier that does not meet the applicability requirements of paragraph (a) of this section is not subject to this rule. Such owner or operator would become subject to the rule and reporting requirements, if a facility or supplier exceeds the applicability requirements of paragraph (a) of this section at a later time pursuant to §98.3(b)(3). Thus, the owner or operator should reevaluate the applicability to this part (including the revising of any relevant emissions calculations or other calculations) whenever there is any change that could cause a facility or supplier to meet the applicability requirements of paragraph (a) of this section. Such changes include but are not limited to process modifications, increases in operating hours, increases in production, changes in fuel or raw material use, addition of equipment, and facility expansion.
(i) Except as provided in this paragraph, once a facility or supplier is subject to the requirements of this part, the owner or operator must continue for each year thereafter to comply with all requirements of this part, including the requirement to submit annual GHG reports, even if the facility or supplier does not meet the applicability requirements in paragraph (a) of this section in a future year.
(1) If reported emissions are less than 25,000 metric tons CO2e per year for five consecutive years, then the owner or operator may discontinue complying with this part provided that the owner or operator submits a notification to the Administrator that announces the cessation of reporting and explains the reasons for the reduction in emissions. The notification shall be submitted no later than March 31 of the year immediately following the fifth consecutive year of emissions less than 25,000 tons CO2e per year. The owner or operator must maintain the corresponding records required under §98.3(g) for each of the five consecutive years and retain such records for three years following the year that reporting was discontinued. The owner or operator must resume reporting if annual emissions in any future calendar year increase to 25,000 metric tons CO2e per year or more.
(2) If reported emissions are less than 15,000 metric tons CO2e per year for three consecutive years, then the owner or operator may discontinue complying with this part provided that the owner or operator submits a notification to the Administrator that announces the cessation of reporting and explains the reasons for the reduction in emissions. The notification shall be submitted no later than March 31 of the year immediately following the third consecutive year of emissions less than 15,000 tons CO2e per year. The owner or operator must maintain the corresponding records required under §98.3(g) for each of the three consecutive years and retain such records for three years following the year that reporting was discontinued. The owner or operator must resume reporting if annual emissions in any future calendar year increase to 25,000 metric tons CO2e per year or more.
(3) If the operations of a facility or supplier are changed such that all applicable GHG-emitting processes and operations listed in paragraphs (a)(1) through (a)(4) of this section cease to operate, then the owner or operator is exempt from reporting in the years following the year in which cessation of such operations occurs, provided that the owner or operator submits a notification to the Administrator that announces the cessation of reporting and certifies to the closure of all GHG-emitting processes and operations no later than March 31 of the year following such changes. This paragraph (i)(3) does not apply to seasonal or other temporary cessation of operations. This paragraph (i)(3) does not apply to facilities with municipal solid waste landfills or industrial waste landfills, or to underground coal mines. The owner or operator must resume reporting for any future calendar year during which any of the GHG-emitting processes or operations resume operation.
(j) Table A - 2 of this subpart provides a conversion table for some of the common units of measure used in part 98.
§ 98.3 What are the general monitoring, reporting, recordkeeping and verification requirements of this part?
The owner or operator of a facility or supplier that is subject to the requirements of this part must submit GHG reports to the Administrator, as specified in this section.
(a) General. Except as provided in paragraph (d) of this section, follow the procedures for emission calculation, monitoring, quality assurance, missing data, recordkeeping, and reporting that are specified in each relevant subpart of this part.
(b) Schedule. The annual GHG report for reporting year 2010 must be submitted no later than September 30, 2011. The annual report for reporting years 2011 and beyond must be submitted no later than March 31 of each calendar year for GHG emissions in the previous calendar year, except as provided in paragraph (b)(1) of this section. 
      (1)For reporting year 2011, facilities with one or more of the subparts listed in paragraphs (b)(1)(i) through (b)(1)(xi) of this section and suppliers listed in paragraph (b)(1)(xii) of this section are required to submit their annual GHG report no later than September 28, 2012. Facilities and suppliers that are submitting their second annual GHG report in 2012 and that are  reporting on one or more subparts listed in paragraphs (b)(1)(i) through (b)(1)(xii) of this section must notify EPA by March 31, 2012 that they are not required to submit their annual GHG report until September 28, 2012. 
      (i) Electronics Manufacturing (subpart I).
      (ii) Fluorinated Gas Production (subpart L).
      (iii) Magnesium Production (subpart T).
      (iv) Petroleum and Natural Gas Systems (subpart W).
      (v) Use of Electric Transmission and Distribution Equipment (subpart DD).
      (vi) Underground Coal Mines (subpart FF).
      (vii) Industrial Wastewater Treatment (subpart II).
      (viii) Geologic Sequestration of Carbon Dioxide (subpart RR).
      (ix) Manufacture of Electric Transmission and Distribution (subpart SS).
      (x) Industrial Waste Landfills (subpart TT).
      (xi) Injection of Carbon Dioxide (subpart UU).
      (xii) Imports and Exports of Equipment Pre-charged with Fluorinated GHGs or Containing Fluorinated GHGs in Closed-cell  Foams (subpart QQ). 
      (2) For a new facility or supplier that begins operation on or after January 1, 2010 and becomes subject to the rule in the year that it becomes operational, report emissions beginning with the first operating month and ending on December 31 of that year. Each subsequent annual report must cover emissions for the calendar year, beginning on January 1 and ending on December 31.
(3) For any facility or supplier that becomes subject to this rule because of a physical or operational change that is made after January 1, 2010, report emissions for the first calendar year in which the change occurs, beginning with the first month of the change and ending on December 31 of that year. For a facility or supplier that becomes subject to this rule solely because of an increase in hours of operation or level of production, the first month of the change is the month in which the increased hours of operation or level of production, if maintained for the remainder of the year, would cause the facility or supplier to exceed the applicable threshold. Each subsequent annual report must cover emissions for the calendar year, beginning on January 1 and ending on December 31.
      (4) Unless otherwise stated, if the final day of any time period falls on a weekend or a federal holiday, the time period shall be extended to the next business day.
(c) Content of the annual report. Except as provided in paragraph (d) of this section, each annual GHG report shall contain the following information:
(1) Facility name or supplier name (as appropriate), and physical street address of the facility or supplier, including the city, State, and zip code. If the facility does not have a physical street address, then the facility must provide the latitude and longitude representing the geographic centroid or center point of facility operations in decimal degree format. This must be provided in a comma-delimited "latitude, longitude" coordinate pair reported in decimal degrees to at least four digits to the right of the decimal point.
(2) Year and months covered by the report.
(3) Date of submittal.
(4) For facilities, except as otherwise provided in paragraph (c)(12) of this section, report annual emissions of CO2, CH4, N2O, each fluorinated GHG (as defined in §98.6), and each fluorinated heat transfer fluid (as defined in §98.98) as follows.
(i) Annual emissions (excluding biogenic CO2) aggregated for all GHG from all applicable source categories, expressed in metric tons of CO2e calculated using Equation A - 1 of this subpart. For electronics manufacturing (as defined in §98.90), starting in reporting year 2012 the CO2e calculation must include each fluorinated heat fluid (as defined in §98.98) whether or not it is also a fluorinated GHG. 
(ii) Annual emissions of biogenic CO2 aggregated for all applicable source categories, expressed in metric tons.
(iii) Annual emissions from each applicable source category, expressed in metric tons of each applicable GHG listed in paragraphs (c)(4)(iii)(A) through (c)(4)(iii)(E) of this section.
(A) Biogenic CO2.
(B) CO2 (excluding biogenic CO2).
(C) CH4.
(D) N2O.
(E) Each fluorinated GHG (as defined in §98.6), including those not listed in Table A - 1 of this subpart.
(F) For electronics manufacturing (as defined in § 98.90), each fluorinated heat transfer fluid (as defined in § 98.98) that is not also a fluorinated GHG as specified under (c)(4)(iii)(E) of this section. This requirement applies beginning in reporting year 2012.
(iv) Except as provided in paragraph (c)(4)(vii) of this section, emissions and other data for individual units, processes, activities, and operations as specified in the "Data reporting requirements" section of each applicable subpart of this part.
(v) Indicate (yes or no) whether reported emissions include emissions from a cogeneration unit located at the facility.
(vi) When applying paragraph (c)(4)(i) of this section to fluorinated GHGs and fluorinated heat transfer fluids, calculate and report CO2e for only those fluorinated GHGs listed in Table A - 1 of this subpart.
(vii) The owner or operator of a facility is not required to report the data elements specified in Table A - 6 to this subpart for calendar years 2010 through 2011 until March 31, 2013. The owner or operator of a facility is not required to report the data elements specified in Table A - 7 to this subpart for calendar years 2010 through 2013 until March 31, 2015.
(viii) Applicable source categories means stationary fuel combustion sources (subpart C of this part), miscellaneous use of carbonates (subpart U of this part), and all of the source categories listed in Table A - 3 and Table A - 4 of this subpart present at the facility.
(5) For suppliers, report annual quantities of CO2, CH4, N2O, and each fluorinated GHG (as defined in §98.6) that would be emitted from combustion or use of the products supplied, imported, and exported during the year. Calculate and report quantities at the following levels:
(i) Total quantity of GHG aggregated for all GHG from all applicable supply categories in Table A - 5 of this subpart and expressed in metric tons of CO2e calculated using Equation A - 1 of this subpart. For fluorinated GHGs, calculate and report CO2e for only those fluorinated GHGs listed in Table A - 1 of this subpart.
(ii) Quantity of each GHG from each applicable supply category in Table A - 5 of this subpart, expressed in metric tons of each GHG. For fluorinated GHG, report quantities of all fluorinated GHG, including those not listed in Table A-1 to this subpart. 
(iii) Any other data specified in the "Data reporting requirements" section of each applicable subpart of this part.
(6) A written explanation, as required under §98.3(e), if you change emission calculation methodologies during the reporting period.
(7) A brief description of each "best available monitoring method" used, the parameter measured using the method, and the time period during which the "best available monitoring method" was used, if applicable.
(8) Each data element for which a missing data procedure was used according to the procedures of an applicable subpart and the total number of hours in the year that a missing data procedure was used for each data element.
(9) A signed and dated certification statement provided by the designated representative of the owner or operator, according to the requirements of §98.4(e)(1).
(10) NAICS code(s) that apply to the facility or supplier. 
(i) Primary NAICS code. Report the NAICS code that most accurately describes the reporting entity's primary product/activity/service. The primary product/activity/service is the principal source of revenue for the facility or supplier. A facility or supplier that has two distinct products/activities/services providing comparable revenue may report a second primary NAICS code.
(ii) Additional NAICS code(s). Report all additional NAICS codes that describe all product(s)/activity(s)/service(s) at the facility or supplier that are not related to the principal source of revenue.
(11) Legal name(s) and physical address(es) of the highest-level United States parent company(s) of the owners (or operators) of the facility or supplier and the percentage of ownership interest for each listed parent company as of December 31 of the year for which data are being reported according to the following instructions:
(i) If the facility or supplier is entirely owned by a single United States company that is not owned by another company, provide that company's legal name and physical address as the United States parent company and report 100 percent ownership.
(ii) If the facility or supplier is entirely owned by a single United States company that is, itself, owned by another company (e.g., it is a division or subsidiary of a higher-level company), provide the legal name and physical address of the highest-level company in the ownership hierarchy as the United States parent company and report 100 percent ownership.
(iii) If the facility or supplier is owned by more than one United States company (e.g., company A owns 40 percent, company B owns 35 percent, and company C owns 25 percent), provide the legal names and physical addresses of all the highest-level companies with an ownership interest as the United States parent companies, and report the percent ownership of each company.
(iv) If the facility or supplier is owned by a joint venture or a cooperative, the joint venture or cooperative is its own United States parent company. Provide the legal name and physical address of the joint venture or cooperative as the United States parent company, and report 100 percent ownership by the joint venture or cooperative.
(v) If the facility or supplier is entirely owned by a foreign company, provide the legal name and physical address of the foreign company's highest-level company based in the United States as the United States parent company, and report 100 percent ownership.
(vi) If the facility or supplier is partially owned by a foreign company and partially owned by one or more U.S. companies, provide the legal name and physical address of the foreign company's highest-level company based in the United States, along with the legal names and physical addresses of the other U.S. parent companies, and report the percent ownership of each of these companies.
(vii) If the facility or supplier is a federally owned facility, report "U.S. Government" and do not report physical address or percent ownership.
(viii) The facility or supplier must refer to the reporting instructions of the electronic GHG reporting tool regarding standardized conventions for the naming of a parent company. 
(12) For the 2010 reporting year only, facilities that have "part 75 units" (i.e. units that are subject to subpart D of this part or units that use the methods in part 75 of this chapter to quantify CO2 mass emissions in accordance with §98.33(a)(5)) must report annual GHG emissions either in full accordance with paragraphs (c)(4)(i) through (c)(4)(iii) of this section or in full accordance with paragraphs (c)(12)(i) through (c)(12)(iii) of this section. If the latter reporting option is chosen, you must report:
(i) Annual emissions aggregated for all GHG from all applicable source categories, expressed in metric tons of CO2e calculated using Equation A - 1 of this subpart. You must include biogenic CO2 emissions from part 75 units in these annual emissions, but exclude biogenic CO2 emissions from any non-part 75 units and other source categories.
(ii) Annual emissions of biogenic CO2,expressed in metric tons (excluding biogenic CO2 emissions from part 75 units), aggregated for all applicable source categories.
(iii) Annual emissions from each applicable source category, expressed in metric tons of each applicable GHG listed in paragraphs (c)(12)(iii)(A) through (c)(12)(iii)(E) of this section.
(A) Biogenic CO2 (excluding biogenic CO2 emissions from part 75 units).
(B) CO2. You must include biogenic CO2 emissions from part 75 units in these totals and exclude biogenic CO2 emissions from other non-part 75 units and other source categories.
(C) CH4.
(D) N2O.
(E) Each fluorinated GHG (including those not listed in Table A - 1 of this subpart).
(13) An indication of whether the facility includes one or more plant sites that have been assigned a "plant code" (as defined under §98.6) by either the Department of Energy's Energy Information Administration or by the EPA's Clean Air Markets Division. 
(d) Special provisions for reporting year 2010.
(1) Best available monitoring methods. During January 1, 2010 through March 31, 2010, owners or operators may use best available monitoring methods for any parameter (e.g., fuel use, daily carbon content of feedstock by process line) that cannot reasonably be measured according to the monitoring and QA/QC requirements of a relevant subpart. The owner or operator must use the calculation methodologies and equations in the "Calculating GHG Emissions" sections of each relevant subpart, but may use the best available monitoring method for any parameter for which it is not reasonably feasible to acquire, install, and operate a required piece of monitoring equipment by January 1, 2010. Starting no later than April 1, 2010, the owner or operator must discontinue using best available methods and begin following all applicable monitoring and QA/QC requirements of this part, except as provided in paragraphs (d)(2) and (d)(3) of this section. Best available monitoring methods means any of the following methods specified in this paragraph:
(i) Monitoring methods currently used by the facility that do not meet the specifications of an relevant subpart.
(ii) Supplier data.
(iii) Engineering calculations.
(iv) Other company records.
(2) Requests for extension of the use of best available monitoring methods. The owner or operator may submit a request to the Administrator to use one or more best available monitoring methods beyond March 31, 2010.
(i) Timing of request. The extension request must be submitted to EPA no later than 30 days after the effective date of the GHG reporting rule.
(ii) Content of request. Requests must contain the following information:
(A) A list of specific item of monitoring instrumentation for which the request is being made and the locations where each piece of monitoring instrumentation will be installed.
(B) Identification of the specific rule requirements (by rule subpart, section, and paragraph numbers) for which the instrumentation is needed.
(C) A description of the reasons why the needed equipment could not be obtained and installed before April 1, 2010.
(D) If the reason for the extension is that the equipment cannot be purchased and delivered by April 1, 2010, include supporting documentation such as the date the monitoring equipment was ordered, investigation of alternative suppliers and the dates by which alternative vendors promised delivery, backorder notices or unexpected delays, descriptions of actions taken to expedite delivery, and the current expected date of delivery.
(E) If the reason for the extension is that the equipment cannot be installed without a process unit shutdown, include supporting documentation demonstrating that it is not practicable to isolate the equipment and install the monitoring instrument without a full process unit shutdown. Include the date of the most recent process unit shutdown, the frequency of shutdowns for this process unit, and the date of the next planned shutdown during which the monitoring equipment can be installed. If there has been a shutdown or if there is a planned process unit shutdown between promulgation of this part and April 1, 2010, include a justification of why the equipment could not be obtained and installed during that shutdown.
(F) A description of the specific actions the facility will take to obtain and install the equipment as soon as reasonably feasible and the expected date by which the equipment will be installed and operating.
(iii) Approval criteria. To obtain approval, the owner or operator must demonstrate to the Administrator's satisfaction that it is not reasonably feasible to acquire, install, and operate a required piece of monitoring equipment by April 1, 2010. The use of best available methods will not be approved beyond December 31, 2010.
(3) Abbreviated emissions report for facilities containing only general stationary fuel combustion sources. In lieu of the report required by paragraph (c) of this section, the owner or operator of an existing facility that is in operation on January 1, 2010 and that meets the conditions of §98.2(a)(3) may submit an abbreviated GHG report for the facility for GHGs emitted in 2010. The abbreviated report must be submitted by September 30, 2011. An owner or operator that submits an abbreviated report must submit a full GHG report according to the requirements of paragraph (c) of this section beginning in calendar year 2012. The abbreviated facility report must include the following information:
(i) Facility name and physical street address including the city, state and zip code.
(ii) The year and months covered by the report.
(iii) Date of submittal.
(iv) Total facility GHG emissions aggregated for all stationary fuel combustion units calculated according to any method specified in §98.33(a) and expressed in metric tons of CO2,CH4,N2O, and CO2 e.
(v) Any facility operating data or process information used for the GHG emission calculations.
(vi) A signed and dated certification statement provided by the designated representative of the owner or operator, according to the requirements of paragraph (e)(1) of this section.
(e) Emission calculations. In preparing the GHG report, you must use the calculation methodologies specified in the relevant subparts, except as specified in paragraph (d) of this section. For each source category, you must use the same calculation methodology throughout a reporting period unless you provide a written explanation of why a change in methodology was required.
(f) Verification. To verify the completeness and accuracy of reported GHG emissions, the Administrator may review the certification statements described in paragraphs (c)(9) and (d)(3)(vi) of this section and any other credible evidence, in conjunction with a comprehensive review of the GHG reports and periodic audits of selected reporting facilities. Nothing in this section prohibits the Administrator from using additional information to verify the completeness and accuracy of the reports.
	(g) Recordkeeping. An owner or operator that is required to report GHGs under this part must keep records as specified in this paragraph. Retain all required records for at least 3 years. Retain all required records for at least 3 years from the date of submission of the annual GHG report for the reporting year in which the record was generated. The records shall be kept in an electronic or hard-copy format (as appropriate) and recorded in a form that is suitable for expeditious inspection and review. Upon request by the Administrator, the records required under this section must be made available to EPA. Records may be retained off site if the records are readily available for expeditious inspection and review. For records that are electronically generated or maintained, the equipment or software necessary to read the records shall be made available, or, if requested by EPA, electronic records shall be converted to paper documents. You must retain the following records, in addition to those records prescribed in each applicable subpart of this part:
(1) A list of all units, operations, processes, and activities for which GHG emission were calculated.
(2) The data used to calculate the GHG emissions for each unit, operation, process, and activity, categorized by fuel or material type. These data include but are not limited to the following information in this paragraph (g)(2):
(i) The GHG emissions calculations and methods used.
(ii) Analytical results for the development of site-specific emissions factors.
(iii) The results of all required analyses for high heat value, carbon content, and other required fuel or feedstock parameters.
(iv) Any facility operating data or process information used for the GHG emission calculations.
(3) The annual GHG reports.
(4) Missing data computations. For each missing data event, also retain a record of the cause of the event and the corrective actions taken to restore malfunctioning monitoring equipment.
(5) A written GHG Monitoring Plan.
(i) At a minimum, the GHG Monitoring Plan shall include the elements listed in this paragraph (g)(5)(i).
(A) Identification of positions of responsibility (i.e., job titles) for collection of the emissions data.
(B) Explanation of the processes and methods used to collect the necessary data for the GHG calculations.
(C) Description of the procedures and methods that are used for quality assurance, maintenance, and repair of all continuous monitoring systems, flow meters, and other instrumentation used to provide data for the GHGs reported under this part.
(ii) The GHG Monitoring Plan may rely on references to existing corporate documents (e.g., standard operating procedures, quality assurance programs under appendix F to 40 CFR part 60 or appendix B to 40 CFR part 75, and other documents) provided that the elements required by paragraph (g)(5)(i) of this section are easily recognizable.
(iii) The owner or operator shall revise the GHG Monitoring Plan as needed to reflect changes in production processes, monitoring instrumentation, and quality assurance procedures; or to improve procedures for the maintenance and repair of monitoring systems to reduce the frequency of monitoring equipment downtime.
(iv) Upon request by the Administrator, the owner or operator shall make all information that is collected in conformance with the GHG Monitoring Plan available for review during an audit. Electronic storage of the information in the plan is permissible, provided that the information can be made available in hard copy upon request during an audit.
(6) The results of all required certification and quality assurance tests of continuous monitoring systems, fuel flow meters, and other instrumentation used to provide data for the GHGs reported under this part.
(7) Maintenance records for all continuous monitoring systems, flow meters, and other instrumentation used to provide data for the GHGs reported under this part.
(h) Annual GHG report revisions. (1) The owner or operator shall submit a revised annual GHG report within 45 days of discovering that an annual GHG report that the owner or operator previously submitted contains one or more substantive errors. The revised report must correct all substantive errors.
(2) The Administrator may notify the owner or operator in writing that an annual GHG report previously submitted by the owner or operator contains one or more substantive errors. Such notification will identify each such substantive error. The owner or operator shall, within 45 days of receipt of the notification, either resubmit the report that, for each identified substantive error, corrects the identified substantive error (in accordance with the applicable requirements of this part) or provide information demonstrating that the previously submitted report does not contain the identified substantive error or that the identified error is not a substantive error.
(3) A substantive error is an error that impacts the quantity of GHG emissions reported or otherwise prevents the reported data from being validated or verified.
(4) Notwithstanding paragraphs (h)(1) and (h)(2) of this section, upon request by the owner or operator, the Administrator may provide reasonable extensions of the 45-day period for submission of the revised report or information under paragraphs (h)(1) and (h)(2) of this section. If the Administrator receives a request for extension of the 45-day period, by e-mail to an address prescribed by the Administrator prior to the expiration of the 45-day period, the extension request is deemed to be automatically granted for 30 days. The Administrator may grant an additional extension beyond the automatic 30-day extension if the owner or operator submits a request for an additional extension and the request is received by the Administrator at least 5 business days prior to the expiration of the automatic 30-day extension, provided the request demonstrates that it is not practicable to submit a revised report or information under paragraphs (h)(1) and (h)(2) within 75 days. The Administrator will approve the extension request if the request demonstrates to the Administrator's satisfaction that it is not practicable to collect and process the data needed to resolve potential reporting errors identified pursuant to paragraphs (h)(1) or (h)(2) of this section within 75 days.
(5) The owner or operator shall retain documentation for 3 years to support any revision made to an annual GHG report.
(i) Calibration accuracy requirements. The owner or operator of a facility or supplier that is subject to the requirements of this part must meet the applicable flow meter calibration and accuracy requirements of this paragraph (i). The accuracy specifications in this paragraph (i) do not apply where either the use of company records (as defined in §98.6) or the use of "best available information" is specified in an applicable subpart of this part to quantify fuel usage and/or other parameters. Further, the provisions of this paragraph (i) do not apply to stationary fuel combustion units that use the methodologies in part 75 of this chapter to calculate CO2 mass emissions.
(1) Except as otherwise provided in paragraphs (i)(4) through (i)(6) of this section, flow meters that measure liquid and gaseous fuel feed rates, process stream flow rates, or feedstock flow rates and provide data for the GHG emissions calculations shall be calibrated prior to April 1, 2010 using the procedures specified in this paragraph (i) when such calibration is specified in a relevant subpart of this part. Each of these flow meters shall meet the applicable accuracy specification in paragraph (i)(2) or (i)(3) of this section. All other measurement devices (e.g., weighing devices) that are required by a relevant subpart of this part, and that are used to provide data for the GHG emissions calculations, shall also be calibrated prior to April 1, 2010; however, the accuracy specifications in paragraphs (i)(2) and (i)(3) of this section do not apply to these devices. Rather, each of these measurement devices shall be calibrated to meet the accuracy requirement specified for the device in the applicable subpart of this part, or, in the absence of such accuracy requirement, the device must be calibrated to an accuracy within the appropriate error range for the specific measurement technology, based on an applicable operating standard, including but not limited to manufacturer's specifications and industry standards. The procedures and methods used to quality-assure the data from each measurement device shall be documented in the written monitoring plan, pursuant to paragraph (g)(5)(i)(C) of this section.
(i) All flow meters and other measurement devices that are subject to the provisions of this paragraph (i) must be calibrated according to one of the following: You may use the manufacturer's recommended procedures; an appropriate industry consensus standard method; or a method specified in a relevant subpart of this part. The calibration method(s) used shall be documented in the monitoring plan required under paragraph (g) of this section.
(ii) For facilities and suppliers that become subject to this part after April 1, 2010, all flow meters and other measurement devices (if any) that are required by the relevant subpart(s) of this part to provide data for the GHG emissions calculations shall be installed no later than the date on which data collection is required to begin using the measurement device, and the initial calibration(s) required by this paragraph (i) (if any) shall be performed no later than that date.
(iii) Except as otherwise provided in paragraphs (i)(4) through (i)(6) of this section, subsequent recalibrations of the flow meters and other measurement devices subject to the requirements of this paragraph (i) shall be performed at one of the following frequencies:
(A) You may use the frequency specified in each applicable subpart of this part.
(B) You may use the frequency recommended by the manufacturer or by an industry consensus standard practice, if no recalibration frequency is specified in an applicable subpart.
(2) Perform all flow meter calibration at measurement points that are representative of the normal operating range of the meter. Except for the orifice, nozzle, and venturi flow meters described in paragraph (i)(3) of this section, calculate the calibration error at each measurement point using Equation A - 2 of this section. The terms "R" and "A" in Equation A - 2 must be expressed in consistent units of measure (e.g., gallons/minute, ft3 /min). The calibration error at each measurement point shall not exceed 5.0 percent of the reference value.
	
Where:
CE	=	Calibration error (%).
R	=	Reference value.
A	=	Flow meter response to the reference value.
(3) For orifice, nozzle, and venturi flow meters, the initial quality assurance consists of in-situ calibration of the differential pressure (delta-P), total pressure, and temperature transmitters.
(i) Calibrate each transmitter at a zero point and at least one upscale point. Fixed reference points, such as the freezing point of water, may be used for temperature transmitter calibrations. Calculate the calibration error of each transmitter at each measurement point, using Equation A - 3 of this subpart. The terms "R," "A," and "FS" in Equation A - 3 of this subpart must be in consistent units of measure (e.g., milliamperes, inches of water, psi, degrees). For each transmitter, the CE value at each measurement point shall not exceed 2.0 percent of full-scale. Alternatively, the results are acceptable if the sum of the calculated CE values for the three transmitters at each calibration level (i.e., at the zero level and at each upscale level) does not exceed 6.0 percent.
                                       
Where:
CE	=	Calibration error (%).
R	=	Reference value.
A	=	Transmitter response to the reference value.
FS	=	Full-scale value of the transmitter.
(ii) In cases where there are only two transmitters (i.e., differential pressure and either temperature or total pressure) in the immediate vicinity of the flow meter's primary element (e.g., the orifice plate), or when there is only a differential pressure transmitter in close proximity to the primary element, calibration of these existing transmitters to a CE of 2.0 percent or less at each measurement point is still required, in accordance with paragraph (i)(3)(i) of this section; alternatively, when two transmitters are calibrated, the results are acceptable if the sum of the CE values for the two transmitters at each calibration level does not exceed 4.0 percent. However, note that installation and calibration of an additional transmitter (or transmitters) at the flow monitor location to measure temperature or total pressure or both is not required in these cases. Instead, you may use assumed values for temperature and/or total pressure, based on measurements of these parameters at a remote location (or locations), provided that the following conditions are met:
(A) You must demonstrate that measurements at the remote location(s) can, when appropriate correction factors are applied, reliably and accurately represent the actual temperature or total pressure at the flow meter under all expected ambient conditions.
(B) You must make all temperature and/or total pressure measurements in the demonstration described in paragraph (i)(3)(ii)(A) of this section with calibrated gauges, sensors, transmitters, or other appropriate measurement devices. At a minimum, calibrate each of these devices to an accuracy within the appropriate error range for the specific measurement technology, according to one of the following. You may calibrate using a manufacturer's specification or an industry consensus standard.
(C) You must document the methods used for the demonstration described in paragraph (i)(3)(ii)(A) of this section in the written GHG Monitoring Plan under paragraph (g)(5)(i)(C) of this section. You must also include the data from the demonstration, the mathematical correlation(s) between the remote readings and actual flow meter conditions derived from the data, and any supporting engineering calculations in the GHG Monitoring Plan. You must maintain all of this information in a format suitable for auditing and inspection.
(D) You must use the mathematical correlation(s) derived from the demonstration described in paragraph (i)(3)(ii)(A) of this section to convert the remote temperature or the total pressure readings, or both, to the actual temperature or total pressure at the flow meter, or both, on a daily basis. You shall then use the actual temperature and total pressure values to correct the measured flow rates to standard conditions.
(E) You shall periodically check the correlation(s) between the remote and actual readings (at least once a year), and make any necessary adjustments to the mathematical relationship(s).
(4) Fuel billing meters are exempted from the calibration requirements of this section and from the GHG Monitoring Plan and recordkeeping provisions of paragraphs (g)(5)(i)(C), (g)(6), and (g)(7) of this section, provided that the fuel supplier and any unit combusting the fuel do not have any common owners and are not owned by subsidiaries or affiliates of the same company. Meters used exclusively to measure the flow rates of fuels that are used for unit startup are also exempted from the calibration requirements of this section.
(5) For a flow meter that has been previously calibrated in accordance with paragraph (i)(1) of this section, an additional calibration is not required by the date specified in paragraph (i)(1) of this section if, as of that date, the previous calibration is still active (i.e., the device is not yet due for recalibration because the time interval between successive calibrations has not elapsed). In this case, the deadline for the successive calibrations of the flow meter shall be set according to one of the following. You may use either the manufacturer's recommended calibration schedule or you may use the industry consensus calibration schedule.
(6) For units and processes that operate continuously with infrequent outages, it may not be possible to meet the April 1, 2010 deadline for the initial calibration of a flow meter or other measurement device without disrupting normal process operation. In such cases, the owner or operator may postpone the initial calibration until the next scheduled maintenance outage. The best available information from company records may be used in the interim. The subsequent required recalibrations of the flow meters may be similarly postponed. Such postponements shall be documented in the monitoring plan that is required under paragraph (g)(5) of this section.
(7) If the results of an initial calibration or a recalibration fail to meet the required accuracy specification, data from the flow meter shall be considered invalid, beginning with the hour of the failed calibration and continuing until a successful calibration is completed. You shall follow the missing data provisions provided in the relevant missing data sections during the period of data invalidation.
(j) Measurement device installation  -- (1) General. If an owner or operator required to report under subpart P, subpart X or subpart Y of this part has process equipment or units that operate continuously and it is not possible to install a required flow meter or other measurement device by April 1, 2010, (or by any later date in 2010 approved by the Administrator as part of an extension of best available monitoring methods per paragraph (d) of this section) without process equipment or unit shutdown, or through a hot tap, the owner or operator may request an extension from the Administrator to delay installing the measurement device until the next scheduled process equipment or unit shutdown. If approval for such an extension is granted by the Administrator, the owner or operator must use best available monitoring methods during the extension period.
(2) Requests for extension of the use of best available monitoring methods for measurement device installation. The owner or operator must first provide the Administrator an initial notification of the intent to submit an extension request for use of best available monitoring methods beyond December 31, 2010 (or an earlier date approved by EPA) in cases where measurement device installation would require a process equipment or unit shutdown, or could only be done through a hot tap. The owner or operator must follow-up this initial notification with the complete extension request containing the information specified in paragraph (j)(4) of this section.
(3) Timing of request. (i) The initial notice of intent must be submitted no later than January 1, 2011, or by the end of the approved use of best available monitoring methods extension in 2010, whichever is earlier. The completed extension request must be submitted to the Administrator no later than February 15, 2011.
(ii) Any subsequent extensions to the original request must be submitted to the Administrator within 4 weeks of the owner or operator identifying the need to extend the request, but in any event no later than 4 weeks before the date for the planned process equipment or unit shutdown that was provided in the original or most recently approved request.
(4) Content of the request. Requests must contain the following information:
(i) Specific measurement device for which the request is being made and the location where each measurement device will be installed.
(ii) Identification of the specific rule requirements (by rule subpart, section, and paragraph numbers) requiring the measurement device.
(iii) A description of the reasons why the needed equipment could not be installed before April 1, 2010, or by the expiration date for the use of best available monitoring methods, in cases where an extension has been granted under §98.3(d).
(iv) Supporting documentation showing that it is not practicable to isolate the process equipment or unit and install the measurement device without a full shutdown or a hot tap, and that there was no opportunity during 2010 to install the device. Include the date of the three most recent shutdowns for each relevant process equipment or unit, the frequency of shutdowns for each relevant process equipment or unit, and the date of the next planned process equipment or unit shutdown.
(v) Include a description of the proposed best available monitoring method for estimating GHG emissions during the time prior to installation of the meter.
(5) Approval criteria. The owner or operator must demonstrate to the Administrator's satisfaction that it is not reasonably feasible to install the measurement device before April 1, 2010 (or by the expiration date for the use of best available monitoring methods, in cases where an extension has been granted under paragraph (d) of this section) without a process equipment or unit shutdown, or through a hot tap, and that the proposed method for estimating GHG emissions during the time before which the measurement device will be installed is appropriate. The Administrator will not initially approve the use of the proposed best available monitoring method past December 31, 2013.
(6) Measurement device installation deadline. Any owner or operator that submits both a timely initial notice of intent and a timely completed extension request under paragraph (j)(3) of this section to extend use of best available monitoring methods for measurement device installation must install all such devices by July 1, 2011 unless the extension request under this paragraph (j) is approved by the Administrator before July 1, 2011.
(7) One time extension past December 31, 2013. If an owner or operator determines that a scheduled process equipment or unit shutdown will not occur by December 31, 2013, the owner or operator may re-apply to use best available monitoring methods for one additional time period, not to extend beyond December 31, 2015. To extend use of best available monitoring methods past December 31, 2013, the owner or operator must submit a new extension request by June 1, 2013 that contains the information required in paragraph (j)(4) of this section. The owner or operator must demonstrate to the Administrator's satisfaction that it continues to not be reasonably feasible to install the measurement device before December 31, 2013 without a process equipment or unit shutdown, or that installation of the measurement device could only be done through a hot tap, and that the proposed method for estimating GHG emissions during the time before which the measurement device will be installed is appropriate. An owner or operator that submits a request under this paragraph to extend use of best available monitoring methods for measurement device installation must install all such devices by December 31, 2013, unless the extension request under this paragraph is approved by the Administrator.
(k) Revised global warming potentials and special provision for reporting year 2013. This paragraph (k) applies to owners or operators of facilities or suppliers that first become subject to any subpart of part 98 due to an amendment to Table A-1 of this subpart.
(1) A facility or supplier that was not subject to any subpart of part 98 for reporting year 2012, but first becomes subject to any subpart of part 98 due to a change in the GWP for one or more compounds in Table A-1 of this subpart, Global Warming Potentials, is not required to submit an annual GHG report for reporting year 2013.
(2) A facility or supplier that is subject to a subpart of part 98 for reporting year 2012, but first becomes subject to any subpart of part 98 due to a change in the GWP for one or more compounds in Table A-1 of this subpart, is not required to include those subparts for which the facility is subject only due to the change in the GWP in the annual GHG report submitted for reporting year 2013. 
(3) Starting on January 1, 2014, facilities or suppliers identified in paragraphs (k)(1) or (k)(2) of this section must start monitoring and collecting GHG data in compliance with the applicable subparts of part 98 for which the facility is subject due to the change in the GWP for the annual greenhouse gas report for reporting year 2014, which is due by March 31, 2015. 
 (l) Special provision for best available monitoring methods in 2014. This paragraph (l) applies to owners or operators of facilities or suppliers that first become subject to any subpart of part 98 due to an amendment to Table A-1 of this subpart, Global Warming Potentials.
(1) Best available monitoring methods. From January 1, 2014 to March 31, 2014, owners or operators subject to this paragraph may use best available monitoring methods for any parameter (e.g., fuel use, feedstock rates) that cannot reasonably be measured according to the monitoring and QA/QC requirements of a relevant subpart. The owner or operator must use the calculation methodologies and equations in the "Calculating GHG Emissions" sections of each relevant subpart, but may use the best available monitoring method for any parameter for which it is not reasonably feasible to acquire, install, and operate a required piece of monitoring equipment by January 1, 2014. Starting no later than April 1, 2014, the owner or operator must discontinue using best available methods and begin following all applicable monitoring and QA/QC requirements of this part, except as provided in paragraph (l)(2) of this section. Best available monitoring methods means any of the following methods:
(i) Monitoring methods currently used by the facility that do not meet the specifications of a relevant subpart.
(ii) Supplier data.
(iii) Engineering calculations.
(iv) Other company records.
(2) Requests for extension of the use of best available monitoring methods. The owner or operator may submit a request to the Administrator to use one or more best available monitoring methods beyond March 31, 2014.
(i) Timing of request. The extension request must be submitted to EPA no later than January 31, 2014.
(ii) Content of request. Requests must contain the following information:
(A) A list of specific items of monitoring instrumentation for which the request is being made and the locations where each piece of monitoring instrumentation will be installed.
(B) Identification of the specific rule requirements (by rule subpart, section, and paragraph numbers) for which the instrumentation is needed.
(C) A description of the reasons that the needed equipment could not be obtained and installed before April 1, 2014.
(D) If the reason for the extension is that the equipment cannot be purchased and delivered by April 1, 2014, supporting documentation such as the date the monitoring equipment was ordered, investigation of alternative suppliers and the dates by which alternative vendors promised delivery, backorder notices or unexpected delays, descriptions of actions taken to expedite delivery, and the current expected date of delivery.
(E) If the reason for the extension is that the equipment cannot be installed without a process unit shutdown, include supporting documentation demonstrating that it is not practicable to isolate the equipment and install the monitoring instrument without a full process unit shutdown. Include the date of the most recent process unit shutdown, the frequency of shutdowns for this process unit, and the date of the next planned shutdown during which the monitoring equipment can be installed. If there has been a shutdown or if there is a planned process unit shutdown between [INSERT THE DATE OF PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER] and April 1, 2014, include a justification of why the equipment could not be obtained and installed during that shutdown.
(F) A description of the specific actions the facility will take to obtain and install the equipment as soon as reasonably feasible and the expected date by which the equipment will be installed and operating.
(iii) Approval criteria. To obtain approval, the owner or operator must demonstrate to the Administrator's satisfaction that it is not reasonably feasible to acquire, install, and operate a required piece of monitoring equipment by April 1, 2014. The use of best available methods under this paragraph (l) will not be approved beyond December 31, 2014.

§ 98.4 Authorization and responsibilities of the designated representative.
(a) General. Except as provided under paragraph (f) of this section, each facility, and each supplier, that is subject to this part, shall have one and only one designated representative, who shall be responsible for certifying, signing, and submitting GHG emissions reports and any other submissions for such facility and supplier respectively to the Administrator under this part. If the facility is required under any other part of title 40 of the Code of Federal Regulations to submit to the Administrator any other emission report that is subject to any requirement in 40 CFR part 75, the same individual shall be the designated representative responsible for certifying, signing, and submitting the GHG emissions reports and all such other emissions reports under this part.
(b) Authorization of a designated representative. The designated representative of the facility or supplier shall be an individual selected by an agreement binding on the owners and operators of such facility or supplier and shall act in accordance with the certification statement in paragraph (i)(4)(iv) of this section.
(c) Responsibility of the designated representative. Upon receipt by the Administrator of a complete certificate of representation under this section for a facility or supplier, the designated representative identified in such certificate of representation shall represent and, by his or her representations, actions, inactions, or submissions, legally bind each owner and operator of such facility or supplier in all matters pertaining to this part, notwithstanding any agreement between the designated representative and such owners and operators. The owners and operators shall be bound by any decision or order issued to the designated representative by the Administrator or a court.
(d) Timing. No GHG emissions report or other submissions under this part for a facility or supplier will be accepted until the Administrator has received a complete certificate of representation under this section for a designated representative of the facility or supplier. Such certificate of representation shall be submitted at least 60 days before the deadline for submission of the facility's or supplier's initial emission report under this part.
(e) Certification of the GHG emissions report. Each GHG emission report and any other submission under this part for a facility or supplier shall be certified, signed, and submitted by the designated representative or any alternate designated representative of the facility or supplier in accordance with this section and §3.10 of this chapter.
(1) Each such submission shall include the following certification statement signed by the designated representative or any alternate designated representative: "I am authorized to make this submission on behalf of the owners and operators of the facility or supplier, as applicable, for which the submission is made. I certify under penalty of law that I have personally examined, and am familiar with, the statements and information submitted in this document and all its attachments. Based on my inquiry of those individuals with primary responsibility for obtaining the information, I certify that the statements and information are to the best of my knowledge and belief true, accurate, and complete. I am aware that there are significant penalties for submitting false statements and information or omitting required statements and information, including the possibility of fine or imprisonment."
(2) The Administrator will accept a GHG emission report or other submission for a facility or supplier under this part only if the submission is certified, signed, and submitted in accordance with this section.
(f) Alternate designated representative. A certificate of representation under this section for a facility or supplier may designate one alternate designated representative, who shall be an individual selected by an agreement binding on the owners and operators, and may act on behalf of the designated representative, of such facility or supplier. The agreement by which the alternate designated representative is selected shall include a procedure for authorizing the alternate designated representative to act in lieu of the designated representative.
(1) Upon receipt by the Administrator of a complete certificate of representation under this section for a facility or supplier identifying an alternate designated representative.
(i) The alternate designated representative may act on behalf of the designated representative for such facility or supplier.
(ii) Any representation, action, inaction, or submission by the alternate designated representative shall be deemed to be a representation, action, inaction, or submission by the designated representative.
(2) Except in this section, whenever the term "designated representative" is used in this part, the term shall be construed to include the designated representative or any alternate designated representative.
(g) Changing a designated representative or alternate designated representative. The designated representative or alternate designated representative identified in a complete certificate of representation under this section for a facility or supplier received by the Administrator may be changed at any time upon receipt by the Administrator of another later signed, complete certificate of representation under this section for the facility or supplier. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous designated representative or the previous alternate designated representative of the facility or supplier before the time and date when the Administrator receives such later signed certificate of representation shall be binding on the new designated representative and the owners and operators of the facility or supplier.
(h) Changes in owners and operators. In the event an owner or operator of the facility or supplier is not included in the list of owners and operators in the certificate of representation under this section for the facility or supplier, such owner or operator shall be deemed to be subject to and bound by the certificate of representation, the representations, actions, inactions, and submissions of the designated representative and any alternate designated representative of the facility or supplier, as if the owner or operator were included in such list. Within 90 days after any change in the owners and operators of the facility or supplier (including the addition of a new owner or operator), the designated representative or any alternate designated representative shall submit a certificate of representation that is complete under this section except that such list shall be amended to reflect the change. If the designated representative or alternate designated representative determines at any time that an owner or operator of the facility or supplier is not included in such list and such exclusion is not the result of a change in the owners and operators, the designated representative or any alternate designated representative shall submit, within 90 days of making such determination, a certificate of representation that is complete under this section except that such list shall be amended to include such owner or operator.
(i) Certificate of representation. A certificate of representation shall be complete if it includes the following elements in a format prescribed by the Administrator in accordance with this section:
(1) Identification of the facility or supplier for which the certificate of representation is submitted.
(2) The name, organization name (company affiliation-employer), address, e-mail address (if any), telephone number, and facsimile transmission number (if any) of the designated representative and any alternate designated representative.
(3) A list of the owners and operators of the facility or supplier identified in paragraph (i)(1) of this section, provided that, if the list includes the operators of the facility or supplier and the owners with control of the facility or supplier, the failure to include any other owners shall not make the certificate of representation incomplete.
(4) The following certification statements by the designated representative and any alternate designated representative:
(i) "I certify that I was selected as the designated representative or alternate designated representative, as applicable, by an agreement binding on the owners and operators of the facility or supplier, as applicable."
(ii) "I certify that I have all the necessary authority to carry out my duties and responsibilities under 40 CFR part 98 on behalf of the owners and operators of the facility or supplier, as applicable, and that each such owner and operator shall be fully bound by my representations, actions, inactions, or submissions."
(iii) "I certify that the owners and operators of the facility or supplier, as applicable, shall be bound by any order issued to me by the Administrator or a court regarding the facility or supplier."
(iv) "If there are multiple owners and operators of the facility or supplier, as applicable, I certify that I have given a written notice of my selection as the `designated representative' or `alternate designated representative', as applicable, and of the agreement by which I was selected to each owner and operator of the facility or supplier."
(5) The signature of the designated representative and any alternate designated representative and the dates signed.
(j) Documents of agreement. Unless otherwise required by the Administrator, documents of agreement referred to in the certificate of representation shall not be submitted to the Administrator. The Administrator shall not be under any obligation to review or evaluate the sufficiency of such documents, if submitted.
(k) Binding nature of the certificate of representation. Once a complete certificate of representation under this section for a facility or supplier has been received, the Administrator will rely on the certificate of representation unless and until a later signed, complete certificate of representation under this section for the facility or supplier is received by the Administrator.
(l) Objections Concerning a Designated Representative
(1) Except as provided in paragraph (g) of this section, no objection or other communication submitted to the Administrator concerning the authorization, or any representation, action, inaction, or submission, of the designated representative or alternate designated representative shall affect any representation, action, inaction, or submission of the designated representative or alternate designated representative, or the finality of any decision or order by the Administrator under this part.
(2) The Administrator will not adjudicate any private legal dispute concerning the authorization or any representation, action, inaction, or submission of any designated representative or alternate designated representative.
(m) Delegation by designated representative and alternate designated representative.
(1) A designated representative or an alternate designated representative may delegate his or her own authority, to one or more individuals, to submit an electronic submission to the Administrator provided for or required under this part, except for a submission under this paragraph.
(2) In order to delegate his or her own authority, to one or more individuals, to submit an electronic submission to the Administrator in accordance with paragraph (m)(1) of this section, the designated representative or alternate designated representative must submit electronically to the Administrator a notice of delegation, in a format prescribed by the Administrator, that includes the following elements:
(i) The name, organization name (company affiliation-employer) address, e-mail address (if any), telephone number, and facsimile transmission number (if any) of such designated representative or alternate designated representative.
(ii) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of each such individual (referred to as an "agent").
(iii) For each such individual, a list of the type or types of electronic submissions under paragraph (m)(1) of this section for which authority is delegated to him or her.
(iv) For each type of electronic submission listed in accordance with paragraph (m)(2)(iii) of this section, the facility or supplier for which the electronic submission may be made.
(v) The following certification statements by such designated representative or alternate designated representative:
(A) "I agree that any electronic submission to the Administrator that is by an agent identified in this notice of delegation and of a type listed, and for a facility or supplier designated, for such agent in this notice of delegation and that is made when I am a designated representative or alternate designated representative, as applicable, and before this notice of delegation is superseded by another notice of delegation under §98.4(m)(3) shall be deemed to be an electronic submission certified, signed, and submitted by me."
(B) "Until this notice of delegation is superseded by a later signed notice of delegation under §98.4(m)(3), I agree to maintain an e-mail account and to notify the Administrator immediately of any change in my e-mail address unless all delegation of authority by me under §98.4(m) is terminated."
(vi) The signature of such designated representative or alternate designated representative and the date signed.
(3) A notice of delegation submitted in accordance with paragraph (m)(2) of this section shall be effective, with regard to the designated representative or alternate designated representative identified in such notice, upon receipt of such notice by the Administrator and until receipt by the Administrator of another such notice that was signed later by such designated representative or alternate designated representative, as applicable. The later signed notice of delegation may replace any previously identified agent, add a new agent, or eliminate entirely any delegation of authority.
(4) Any electronic submission covered by the certification in paragraph (m)(2)(v)(A) of this section and made in accordance with a notice of delegation effective under paragraph (m)(3) of this section shall be deemed to be an electronic submission certified, signed, and submitted by the designated representative or alternate designated representative submitting such notice of delegation.
§ 98.5 How is the report submitted?
Each GHG report and certificate of representation for a facility or supplier must be submitted electronically in accordance with the requirements of §98.4 and in a format specified by the Administrator.
§ 98.6 Definitions.
All terms used in this part shall have the same meaning given in the Clean Air Act and in this section.
Absorbent circulation pump means a pump commonly powered by natural gas pressure that circulates the absorbent liquid between the absorbent regenerator and natural gas contactor.
Accuracy of a measurement at a specified level (e.g., one percent of full scale or one percent of the value measured) means that the mean of repeat measurements made by a device or technique are within 95 percent of the range bounded by the true value plus or minus the specified level.
Acid Rain Program means the program established under title IV of the Clean Air Act, and implemented under parts 72 through 78 of this chapter for the reduction of sulfur dioxide and nitrogen oxides emissions.
Administrator means the Administrator of the United States Environmental Protection Agency or the Administrator's authorized representative.
AGA means the American Gas Association
Agricultural by-products means those parts of arable crops that are not used for the primary purpose of producing food. Agricultural by-products include, but are not limited to, oat, corn and wheat straws, bagasse, peanut shells, rice and coconut husks, soybean hulls, palm kernel cake, cottonseed and sunflower seed cake, and pomace.
Air injected flare means a flare in which air is blown into the base of a flare stack to induce complete combustion of gas.
Alkali bypass means a duct between the feed end of the kiln and the preheater tower through which a portion of the kiln exit gas stream is withdrawn and quickly cooled by air or water to avoid excessive buildup of alkali, chloride and/or sulfur on the raw feed. This may also be referred to as the "kiln exhaust gas bypass."
Anaerobic digester means the system where wastes are collected and anaerobically digested in large containment vessels or covered lagoons. Anaerobic digesters stabilize waste by the microbial reduction of complex organic compounds to CO2 and CH4, which is captured and may be flared or used as fuel. Anaerobic digestion systems, include but are not limited to covered lagoon, complete mix, plug flow, and fixed film digesters.
Anaerobic lagoon, with respect to subpart JJ of this part, means a type of liquid storage system component that is designed and operated to stabilize wastes using anaerobic microbial processes. Anaerobic lagoons may be designed for combined stabilization and storage with varying lengths of retention time (up to a year or greater), depending on the climate region, volatile solids loading rate, and other operational factors.
Anode effect is a process upset condition of an aluminum electrolysis cell caused by too little alumina dissolved in the electrolyte. The anode effect begins when the voltage rises rapidly and exceeds a threshold voltage, typically 8 volts.
Anode Effect Minutes per Cell Day (24 hours) are the total minutes during which an electrolysis cell voltage is above the threshold voltage, typically 8 volts.
ANSI means the American National Standards Institute.
API means the American Petroleum Institute.
ASABE means the American Society of Agricultural and Biological Engineers.
ASME means the American Society of Mechanical Engineers.
ASTM means the American Society of Testing and Materials.
Asphalt means a dark brown-to-black cement-like material obtained by petroleum processing and containing bitumens as the predominant component. It includes crude asphalt as well as the following finished products: cements, fluxes, the asphalt content of emulsions (exclusive of water), and petroleum distillates blended with asphalt to make cutback asphalts.
Aviation Gasoline means a complex mixture of volatile hydrocarbons, with or without additives, suitably blended to be used in aviation reciprocating engines. Specifications can be found in ASTM Specification D910 - 07a, Standard Specification for Aviation Gasolines (incorporated by reference, see §98.7).
B0 means the maximum CH4 producing capacity of a waste stream, kg CH4 /kg COD.
Basic oxygen furnace means any refractory-lined vessel in which high-purity oxygen is blown under pressure through a bath of molten iron, scrap metal, and fluxes to produce steel.
bbl means barrel.
Biodiesel means a mono-akyl ester derived from biomass and conforming to ASTM D6751 - 08, Standard Specification for Biodiesel Fuel Blend Stock (B100) for Middle Distillate Fuels.
Biogenic CO2 means carbon dioxide emissions generated as the result of biomass combustion from combustion units for which emission calculations are required by an applicable part 98 subpart.
Biomass means non-fossilized and biodegradable organic material originating from plants, animals or micro-organisms, including products, by-products, residues and waste from agriculture, forestry and related industries as well as the non-fossilized and biodegradable organic fractions of industrial and municipal wastes, including gases and liquids recovered from the decomposition of non-fossilized and biodegradable organic material.
Blast furnace means a furnace that is located at an integrated iron and steel plant and is used for the production of molten iron from iron ore pellets and other iron bearing materials.
Blendstocks are petroleum products used for blending or compounding into finished motor gasoline. These include RBOB (reformulated blendstock for oxygenate blending) and CBOB (conventional blendstock for oxygenate blending), but exclude oxygenates, butane, and pentanes plus.
Blendstocks -- Others are products used for blending or compounding into finished motor gasoline that are not defined elsewhere. Excludes Gasoline Treated as Blendstock (GTAB), Diesel Treated as Blendstock (DTAB), conventional blendstock for oxygenate blending (CBOB), reformulated blendstock for oxygenate blending (RBOB), oxygenates (e.g. fuel ethanol and methyl tertiary butyl ether), butane, and pentanes plus.
Blowdown mean the act of emptying or depressuring a vessel. This may also refer to the discarded material such as blowdown water from a boiler or cooling tower.
Blowdown vent stack emissions mean natural gas and/or CO2 released due to maintenance and/or blowdown operations including compressor blowdown and emergency shut-down (ESD) system testing.
British Thermal Unit or Btu means the quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit at about 39.2 degrees Fahrenheit.
Bulk, with respect to industrial GHG suppliers and CO2 suppliers, means the transfer of a product inside containers, including but not limited to tanks, cylinders, drums, and pressure vessels.
Bulk natural gas liquid or NGL refers to mixtures of hydrocarbons that have been separated from natural gas as liquids through the process of absorption, condensation, adsorption, or other methods. Generally, such liquids consist of ethane, propane, butanes, and pentanes plus. Bulk NGL is sold to fractionators or to refineries and petrochemical plants where the fractionation takes place.
Butane, or n-Butane, is a paraffinic straight-chain hydrocarbon with molecular formula C4H10.
Butylene, or n-Butylene, is an olefinic straight-chain hydrocarbon with molecular formula C4H8.
By-product coke oven battery means a group of ovens connected by common walls, where coal undergoes destructive distillation under positive pressure to produce coke and coke oven gas from which by-products are recovered.
Calcination means the process of thermally treating minerals to decompose carbonates from ore.
Calculation methodology means a methodology prescribed under the section "Calculating GHG Emissions" in any subpart of part 98.
Calibrated bag means a flexible, non-elastic, anti-static bag of a calibrated volume that can be affixed to an emitting source such that the emissions inflate the bag to its calibrated volume. 
Carbon dioxide equivalent or CO2e means the number of metric tons of CO2 emissions with the same global warming potential as one metric ton of another greenhouse gas, and is calculated using Equation A - 1 of this subpart.
Carbon dioxide production well means any hole drilled in the earth for the primary purpose of extracting carbon dioxide from a geologic formation or group of formations which contain deposits of carbon dioxide.
Carbon dioxide production well facility means one or more carbon dioxide production wells that are located on one or more contiguous or adjacent properties, which are under the control of the same entity. Carbon dioxide production wells located on different oil and gas leases, mineral fee tracts, lease tracts, subsurface or surface unit areas, surface fee tracts, surface lease tracts, or separate surface sites, whether or not connected by a road, waterway, power line, or pipeline, shall be considered part of the same CO2 production well facility if they otherwise meet the definition.
Carbon dioxide stream means carbon dioxide that has been captured from an emission source (e.g. a power plant or other industrial facility) or extracted from a carbon dioxide production well plus incidental associated substances either derived from the source materials and the capture process or extracted with the carbon dioxide.
Carbon share means the percent of total mass that carbon represents in any product.
Carbonate means compounds containing the radical CO3−2. Upon calcination, the carbonate radical decomposes to evolve carbon dioxide (CO2). Common carbonates consumed in the mineral industry include calcium carbonate (CaCO3) or calcite; magnesium carbonate (MgCO3) or magnesite; and calcium-magnesium carbonate (CaMg(CO3)2) or dolomite.
Carbonate-based mineral means any of the following minerals used in the manufacture of glass: Calcium carbonate (CaCO3), calcium magnesium carbonate (CaMg(CO3)2), sodium carbonate (Na2CO3), barium carbonate (BaCO3), potassium carbonate (K2CO3), lithium carbonate (Li2CO3), and strontium carbonate (SrCO3).
Carbonate-based mineral mass fraction means the following: For limestone, the mass fraction of calcium carbonate (CaCO3) in the limestone; for dolomite, the mass fraction of calcium magnesium carbonate (CaMg(CO3)2) in the dolomite; for soda ash, the mass fraction of sodium carbonate (Na2CO3) in the soda ash; for barium carbonate, the mass fraction of barium carbonate (BaCO3) in the barium carbonate; for potassium carbonate, the mass fraction of potassium carbonate (K2CO3) in the potassium carbonate; for lithium carbonate, the mass fraction of lithium carbonate (Li2CO3); and for strontium carbonate, the mass fraction of strontium carbonate (SrCO3).
Carbonate-based raw material means any of the following materials used in the manufacture of glass: Limestone, dolomite, soda ash, barium carbonate, potassium carbonate, lithium carbonate, and strontium carbonate.
Catalytic cracking unit means a refinery process unit in which petroleum derivatives are continuously charged and hydrocarbon molecules in the presence of a catalyst are fractured into smaller molecules, or react with a contact material suspended in a fluidized bed to improve feedstock quality for additional processing and the catalyst or contact material is continuously regenerated by burning off coke and other deposits. Catalytic cracking units include both fluidized bed systems, which are referred to as fluid catalytic cracking units (FCCU), and moving bed systems, which are also referred to as thermal catalytic cracking units. The unit includes the riser, reactor, regenerator, air blowers, spent catalyst or contact material stripper, catalyst or contact material recovery equipment, and regenerator equipment for controlling air pollutant emissions and for heat recovery.
CBOB-Summer (conventional blendstock for oxygenate blending) means a petroleum product which, when blended with a specified type and percentage of oxygenate, meets the definition of Conventional-Summer.
CBOB-Winter (conventional blendstock for oxygenate blending) means a petroleum product which, when blended with a specified type and percentage of oxygenate, meets the definition of Conventional-Winter.
Cement kiln dust means non-calcined to fully calcined dust produced in the kiln or pyroprocessing line. Cement kiln dust is a fine-grained, solid, highly alkaline material removed from the cement kiln exhaust gas by scrubbers (filtration baghouses and/or electrostatic precipitators).
Centrifugal compressor means any equipment that increases the pressure of a process natural gas or CO2 by centrifugal action, employing rotating movement of the driven shaft.
Centrifugal compressor dry seal emissions mean natural gas or CO2 released from a dry seal vent pipe and/or the seal face around the rotating shaft where it exits one or both ends of the compressor case.
Centrifugal compressor dry seals mean a series of rings around the compressor shaft where it exits the compressor case that operates mechanically under the opposing forces to prevent natural gas or CO2 from escaping to the atmosphere.
Centrifugal compressor wet seal degassing vent emissions means emissions that occur when the high-pressure oil barriers for centrifugal compressors are depressurized to release absorbed natural gas or CO2. High-pressure oil is used as a barrier against escaping gas in centrifugal compressor shafts. Very little gas escapes through the oil barrier, but under high pressure, considerably more gas is absorbed by the oil. The seal oil is purged of the absorbed gas (using heaters, flash tanks, and degassing techniques) and recirculated. The separated gas is commonly vented to the atmosphere.
Certified standards means calibration gases certified by the manufacturer of the calibration gases to be accurate to within 2 percent of the value on the label or calibration gases.
CH4 means methane.
Chemical recovery combustion unit means a combustion device, such as a recovery furnace or fluidized-bed reactor where spent pulping liquor from sulfite or semi-chemical pulping processes is burned to recover pulping chemicals.
Chemical recovery furnace means an enclosed combustion device where concentrated spent liquor produced by the kraft or soda pulping process is burned to recover pulping chemicals and produce steam. Includes any recovery furnace that burns spent pulping liquor produced from both the kraft and soda pulping processes.
Chloride process means a production process where titanium dioxide is produced using calcined petroleum coke and chlorine as raw materials.
City gate means a location at which natural gas ownership or control passes from one party to another, neither of which is the ultimate consumer. In this rule, in keeping with common practice, the term refers to a point or measuring station at which a local gas distribution utility receives gas from a natural gas pipeline company or transmission system. Meters at the city gate station measure the flow of natural gas into the local distribution company system and typically are used to measure local distribution company system sendout to customers.
CO2 means carbon dioxide.
Coal means all solid fuels classified as anthracite, bituminous, sub-bituminous, or lignite by the American Society for Testing and Materials Designation ASTM D388 - 05 Standard Classification of Coals by Rank (incorporated by reference, see §98.7).
COD means the chemical oxygen demand as determined using methods specified pursuant to 40 CFR part 136.
Cogeneration unit means a unit that produces electrical energy and useful thermal energy for industrial, commercial, or heating or cooling purposes, through the sequential or simultaneous use of the original fuel energy.
Coke burn-off means the coke removed from the surface of a catalyst by combustion during catalyst regeneration. Coke burn-off also means the coke combusted in fluid coking unit burner.
Cokemaking means the production of coke from coal in either a by-product coke oven battery or a non-recovery coke oven battery.
Commercial applications means executing a commercial transaction subject to a contract. A commercial application includes transferring custody of a product from one facility to another if it otherwise meets the definition.
Company records means, in reference to the amount of fuel consumed by a stationary combustion unit (or by a group of such units), a complete record of the methods used, the measurements made, and the calculations performed to quantify fuel usage. Company records may include, but are not limited to, direct measurements of fuel consumption by gravimetric or volumetric means, tank drop measurements, and calculated values of fuel usage obtained by measuring auxiliary parameters such as steam generation or unit operating hours. Fuel billing records obtained from the fuel supplier qualify as company records.
Connector means to flanged, screwed, or other joined fittings used to connect pipe line segments, tubing, pipe components (such as elbows, reducers, "T's" or valves) or a pipe line and a piece of equipment or an instrument to a pipe, tube or piece of equipment. A common connector is a flange. Joined fittings welded completely around the circumference of the interface are not considered connectors for the purpose of this part.
Container glass means glass made of soda-lime recipe, clear or colored, which is pressed and/or blown into bottles, jars, ampoules, and other products listed in North American Industry Classification System 327213 (NAICS 327213).
Continuous bleed means a continuous flow of pneumatic supply natural gas to the process control device (e.g. level control, temperature control, pressure control) where the supply gas pressure is modulated by the process condition, and then flows to the valve controller where the signal is compared with the process set-point to adjust gas pressure in the valve actuator.
Continuous emission monitoring system or CEMS means the total equipment required to sample, analyze, measure, and provide, by means of readings recorded at least once every 15 minutes, a permanent record of gas concentrations, pollutant emission rates, or gas volumetric flow rates from stationary sources.
Continuous glass melting furnace means a glass melting furnace that operates continuously except during periods of maintenance, malfunction, control device installation, reconstruction, or rebuilding.
Conventional-Summer refers to finished gasoline formulated for use in motor vehicles, the composition and properties of which do not meet the requirements of the reformulated gasoline regulations promulgated by the U.S. Environmental Protection Agency under 40 CFR 80.40, but which meet summer RVP standards required under 40 CFR 80.27 or as specified by the state.Note:This category excludes conventional gasoline for oxygenate blending (CBOB) as well as other blendstock.
Conventional-Winter refers to finished gasoline formulated for use in motor vehicles, the composition and properties of which do not meet the requirements of the reformulated gasoline regulations promulgated by the U.S. Environmental Protection Agency under 40 CFR 80.40 or the summer RVP standards required under 40 CFR 80.27 or as specified by the state.Note:This category excludes conventional blendstock for oxygenate blending (CBOB) as well as other blendstock.
Crude oil means a mixture of hydrocarbons that exists in liquid phase in natural underground reservoirs and remains liquid at atmospheric pressure after passing through surface separating facilities. (1) Depending upon the characteristics of the crude stream, it may also include any of the following:
(i) Small amounts of hydrocarbons that exist in gaseous phase in natural underground reservoirs but are liquid at atmospheric conditions (temperature and pressure) after being recovered from oil well (casing-head) gas in lease separators and are subsequently commingled with the crude stream without being separately measured. Lease condensate recovered as a liquid from natural gas wells in lease or field separation facilities and later mixed into the crude stream is also included.
(ii) Small amounts of non-hydrocarbons, such as sulfur and various metals.
(iii) Drip gases, and liquid hydrocarbons produced from tar sands, oil sands, gilsonite, and oil shale.
(iv) Petroleum products that are received or produced at a refinery and subsequently injected into a crude supply or reservoir by the same refinery owner or operator.
(2) Liquids produced at natural gas processing plants are excluded. Crude oil is refined to produce a wide array of petroleum products, including heating oils; gasoline, diesel and jet fuels; lubricants; asphalt; ethane, propane, and butane; and many other products used for their energy or chemical content.
Daily spread means a manure management system component in which manure is routinely removed from a confinement facility and is applied to cropland or pasture within 24 hours of excretion.
Day means any consistently designated 24 hour period during which an emission unit is operated.
Decarburization vessel means any vessel used to further refine molten steel with the primary intent of reducing the carbon content of the steel, including but not limited to vessels used for argon-oxygen decarburization and vacuum oxygen decarburization.
Deep bedding systems for cattle swine means a manure management system in which, as manure accumulates, bedding is continually added to absorb moisture over a production cycle and possibly for as long as 6 to 12 months. This manure management system also is known as a bedded pack manure management system and may be combined with a dry lot or pasture.
Degasification system means the entirety of the equipment that is used to drain gas from underground coal mines. This includes all degasification wells and gob gas vent holes at the underground coal mine. Degasification systems include gob and premine surface drainage wells, gob and premine in-mine drainage wells, and in-mine gob and premine cross-measure borehole wells.
Degradable organic carbon (DOC) means the fraction of the total mass of a waste material that can be biologically degraded.
Dehydrator means a device in which a liquid absorbent (including desiccant, ethylene glycol, diethylene glycol, or triethylene glycol) directly contacts a natural gas stream to absorb water vapor.
Dehydrator vent emissions means natural gas and CO2 released from a natural gas dehydrator system absorbent (typically glycol) reboiler or regenerator to the atmosphere or a flare, including stripping natural gas and motive natural gas used in absorbent circulation pumps.
Delayed coking unit means one or more refinery process units in which high molecular weight petroleum derivatives are thermally cracked and petroleum coke is produced in a series of closed, batch system reactors. A delayed coking unit consists of the coke drums and ancillary equipment associated with a single fractionator.
De-methanizer means the natural gas processing unit that separates methane rich residue gas from the heavier hydrocarbons (e.g., ethane, propane, butane, pentane-plus) in feed natural gas stream.
Density means the mass contained in a given unit volume (mass/volume).
Desiccant means a material used in solid-bed dehydrators to remove water from raw natural gas by adsorption or absorption. Desiccants include activated alumina, pelletized calcium chloride, lithium chloride and granular silica gel material. Wet natural gas is passed through a bed of the granular or pelletized solid adsorbent or absorbent in these dehydrators. As the wet gas contacts the surface of the particles of desiccant material, water is adsorbed on the surface or absorbed and dissolves the surface of these desiccant particles. Passing through the entire desiccant bed, almost all of the water is adsorbed onto or absorbed into the desiccant material, leaving the dry gas to exit the contactor.
Destruction means:
(1) With respect to landfills and manure management, the combustion of methane in any on-site or off-site combustion technology. Destroyed methane includes, but is not limited to, methane combusted by flaring, methane destroyed by thermal oxidation, methane combusted for use in on-site energy or heat production technologies, methane that is conveyed through pipelines (including natural gas pipelines) for off-site combustion, and methane that is collected for any other on-site or off-site use as a fuel.
(2) With respect to fluorinated GHGs, the expiration of a fluorinated GHG to the destruction efficiency actually achieved. Such destruction does not result in a commercially useful end product.
Destruction device, for the purposes of subparts II and TT of this part, means a flare, thermal oxidizer, boiler, turbine, internal combustion engine, or any other combustion unit used to destroy or oxidize methane contained in landfill gas or wastewater biogas.
Destruction efficiency means the efficiency with which a destruction device reduces the mass of a greenhouse gas fed into the device. Destruction efficiency, or flaring destruction efficiency, refers to the fraction of the gas that leaves the flare partially or fully oxidized. The destruction efficiency is expressed in Equation A - 2 of this section:
                                       
Where:
DE	=	Destruction Efficiency
tGHGiIN	=	The mass of GHG i fed into the destruction device
tGHGiOUT	=	The mass of GHG i exhausted from the destruction device
Diesel -- Other is any distillate fuel oil not defined elsewhere, including Diesel Treated as Blendstock (DTAB).
DIPE (diisopropyl ether, (CH3)2CHOCH(CH3)2) is an ether as described in "Oxygenates."
Direct liquefaction means the conversion of coal directly into liquids, rather than passing through an intermediate gaseous state.
Direct reduction furnace means a high temperature furnace typically fired with natural gas to produce solid iron from iron ore or iron ore pellets and coke, coal, or other carbonaceous materials.
Distillate fuel oil means a classification for one of the petroleum fractions produced in conventional distillation operations and from crackers and hydrotreating process units. The generic term distillate fuel oil includes kerosene, kerosene-type jet fuel, diesel fuels (Diesel Fuels No. 1, No. 2, and No. 4), and fuel oils (Fuel Oils No. 1, No. 2, and No. 4).
Distillate Fuel No.1 has a maximum distillation temperature of 550 °F at the 90 percent recovery point and a minimum flash point of 100 °F and includes fuels commonly known as Diesel Fuel No. 1 and Fuel Oil No. 1, but excludes kerosene. This fuel is further subdivided into categories of sulfur content: High Sulfur (greater than 500 ppm), Low Sulfur (less than or equal to 500 ppm and greater than 15 ppm), and Ultra Low Sulfur (less than or equal to 15 ppm).
Distillate Fuel No.2 has a minimum and maximum distillation temperature of 540 °F and 640 °F at the 90 percent recovery point, respectively, and includes fuels commonly known as Diesel Fuel No. 2 and Fuel Oil No. 2. This fuel is further subdivided into categories of sulfur content: High Sulfur (greater than 500 ppm), Low Sulfur (less than or equal to 500 ppm and greater than 15 ppm), and Ultra Low Sulfur (less than or equal to 15 ppm).
Distillate Fuel No.4 is a distillate fuel oil made by blending distillate fuel oil and residual fuel oil, with a minimum flash point of 131 °F.
DOCf means the fraction of DOC that actually decomposes under the (presumably anaerobic) conditions within the landfill.
Dry lot means a manure management system component consisting of a paved or unpaved open confinement area without any significant vegetative cover where accumulating manure may be removed periodically.
Electric arc furnace (EAF) means a furnace that produces molten alloy metal and heats the charge materials with electric arcs from carbon electrodes.
Electric arc furnace steelmaking means the production of carbon, alloy, or specialty steels using an EAF. This definition excludes EAFs at steel foundries and EAFs used to produce nonferrous metals.
Electrothermic furnace means a furnace that heats the charged materials with electric arcs from carbon electrodes.
Emergency generator means a stationary combustion device, such as a reciprocating internal combustion engine or turbine that serves solely as a secondary source of mechanical or electrical power whenever the primary energy supply is disrupted or discontinued during power outages or natural disasters that are beyond the control of the owner or operator of a facility. An emergency generator operates only during emergency situations, for training of personnel under simulated emergency conditions, as part of emergency demand response procedures, or for standard performance testing procedures as required by law or by the generator manufacturer. A generator that serves as a back-up power source under conditions of load shedding, peak shaving, power interruptions pursuant to an interruptible power service agreement, or scheduled facility maintenance shall not be considered an emergency generator.
Emergency equipment means any auxiliary fossil fuel-powered equipment, such as a fire pump, that is used only in emergency situations.
ETBE (ethyl tertiary butyl ether, (CH3)3COC2H) is an ether as described in "Oxygenates."
Ethane is a paraffinic hydrocarbon with molecular formula C2H6.
Ethanol is an anhydrous alcohol with molecular formula C2H5OH.
Ethylene is an olefinic hydrocarbon with molecular formula C2H4.
Ex refinery gate means the point at which a petroleum product leaves the refinery.
Experimental furnace means a glass melting furnace with the sole purpose of operating to evaluate glass melting processes, technologies, or glass products. An experimental furnace does not produce glass that is sold (except for further research and development purposes) or that is used as a raw material for non-experimental furnaces.
Export means to transport a product from inside the United States to persons outside the United States, excluding any such transport on behalf of the United States military including foreign military sales under the Arms Export Control Act.
Exporter means any person, company or organization of record that transfers for sale or for other benefit, domestic products from the United States to another country or to an affiliate in another country, excluding any such transfers on behalf of the United States military or military purposes including foreign military sales under the Arms Export Control Act. An exporter is not the entity merely transporting the domestic products, rather an exporter is the entity deriving the principal benefit from the transaction.
Facility means any physical property, plant, building, structure, source, or stationary equipment located on one or more contiguous or adjacent properties in actual physical contact or separated solely by a public roadway or other public right-of-way and under common ownership or common control, that emits or may emit any greenhouse gas. Operators of military installations may classify such installations as more than a single facility based on distinct and independent functional groupings within contiguous military properties.
Feed means the prepared and mixed materials, which include but are not limited to materials such as limestone, clay, shale, sand, iron ore, mill scale, cement kiln dust and flyash, that are fed to the kiln. Feed does not include the fuels used in the kiln to produce heat to form the clinker product.
Feedstock means raw material inputs to a process that are transformed by reaction, oxidation, or other chemical or physical methods into products and by-products. Supplemental fuel burned to provide heat or thermal energy is not a feedstock.
Fischer-Tropsch process means a catalyzed chemical reaction in which synthesis gas, a mixture of carbon monoxide and hydrogen, is converted into liquid hydrocarbons of various forms.
Flare means a combustion device, whether at ground level or elevated, that uses an open flame to burn combustible gases with combustion air provided by uncontrolled ambient air around the flame.
Flat glass means glass made of soda-lime recipe and produced into continuous flat sheets and other products listed in NAICS 327211.
Flowmeter means a device that measures the mass or volumetric rate of flow of a gas, liquid, or solid moving through an open or closed conduit (e.g. flowmeters include, but are not limited to, rotameters, turbine meters, coriolis meters, orifice meters, ultra-sonic flowmeters, and vortex flowmeters).
Fluid coking unit means one or more refinery process units in which high molecular weight petroleum derivatives are thermally cracked and petroleum coke is continuously produced in a fluidized bed system. The fluid coking unit includes equipment for controlling air pollutant emissions and for heat recovery on the fluid coking burner exhaust vent. There are two basic types of fluid coking units: A traditional fluid coking unit in which only a small portion of the coke produced in the unit is burned to fuel the unit and the fluid coking burner exhaust vent is directed to the atmosphere (after processing in a CO boiler or other air pollutant control equipment) and a flexicoking unit in which an auxiliary burner is used to partially combust a significant portion of the produced petroleum coke to generate a low value fuel gas that is used as fuel in other combustion sources at the refinery.
Fluorinated greenhouse gas means sulfur hexafluoride (SF6), nitrogen trifluoride (NF3), and any fluorocarbon except for controlled substances as defined at 40 CFR part 82, subpart A and substances with vapor pressures of less than 1 mm of Hg absolute at 25 degrees C. With these exceptions, "fluorinated GHG" includes but is not limited to any hydrofluorocarbon, any perfluorocarbon, any fully fluorinated linear, branched or cyclic alkane, ether, tertiary amine or aminoether, any perfluoropolyether, and any hydrofluoropolyether.
Fossil fuel means natural gas, petroleum, coal, or any form of solid, liquid, or gaseous fuel derived from such material, for purpose of creating useful heat.
Fractionators means plants that produce fractionated natural gas liquids (NGLs) extracted from produced natural gas and separate the NGLs individual component products: ethane, propane, butanes and pentane-plus (C5+). Plants that only process natural gas but do not fractionate NGLs further into component products are not considered fractionators. Some fractionators do not process production gas, but instead fractionate bulk NGLs received from natural gas processors. Some fractionators both process natural gas and fractionate bulk NGLs received from other plants.
Fuel means solid, liquid or gaseous combustible material.
Fuel gas means gas generated at a petroleum refinery or petrochemical plant and that is combusted separately or in any combination with any type of gas.
Fuel gas system means a system of compressors, piping, knock-out pots, mix drums, and, if necessary, units used to remove sulfur contaminants from the fuel gas (e.g., amine scrubbers) that collects fuel gas from one or more sources for treatment, as necessary, and transport to a stationary combustion unit. A fuel gas system may have an overpressure vent to a flare but the primary purpose for a fuel gas system is to provide fuel to the various combustion units at the refinery or petrochemical plant.
Furnace slag means a by-product formed in metal melting furnaces when slagging agents, reducing agents, and/or fluxes (e.g., coke ash, limestone, silicates) are added to remove impurities from the molten metal.
Gas collection system or landfill gas collection system means a system of pipes used to collect landfill gas from different locations in the landfill by means of a fan or similar mechanical draft equipment to a single location for treatment (thermal destruction) or use. Landfill gas collection systems may also include knock-out or separator drums and/or a compressor. A single landfill may have multiple gas collection systems. Landfill gas collection systems do not include "passive" systems, whereby landfill gas flows naturally to the surface of the landfill where an opening or pipe (vent) is installed to allow for natural gas flow.
Gas conditions mean the actual temperature, volume, and pressure of a gas sample.
Gas-fired unit means a stationary combustion unit that derives more than 50 percent of its annual heat input from the combustion of gaseous fuels, and the remainder of its annual heat input from the combustion of fuel oil or other liquid fuels.
Gas monitor means an instrument that continuously measures the concentration of a particular gaseous species in the effluent of a stationary source.
Gas to oil ratio (GOR) means the ratio of the volume of gas at standard temperature and pressure that is produced from a volume of oil when depressurized to standard temperature and pressure.
Gaseous fuel means a material that is in the gaseous state at standard atmospheric temperature and pressure conditions and that is combusted to produce heat and/or energy.
Gasification means the conversion of a solid or liquid raw material into a gas.
Gasoline -- Other is any gasoline that is not defined elsewhere, including GTAB (gasoline treated as blendstock).
Glass melting furnace means a unit comprising a refractory-lined vessel in which raw materials are charged and melted at high temperature to produce molten glass.
Glass produced means the weight of glass exiting a glass melting furnace.
Global warming potential or GWP means the ratio of the time-integrated radiative forcing from the instantaneous release of one kilogram of a trace substance relative to that of one kilogram- of a reference gas, i.e., CO2.
GPA means the Gas Processors Association.
Greenhouse gas or GHG means carbon dioxide (CO2), methane (CH4), nitrous oxide (N2O), sulfur hexafluoride (SF6), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and other fluorinated greenhouse gases as defined in this section.
GTBA (gasoline-grade tertiary butyl alcohol, (CH3)3COH), or t-butanol, is an alcohol as described in "Oxygenates."
Heavy Gas Oils are petroleum distillates with an approximate boiling range from 651 °F to 1,000 °F.
Heel means the amount of gas that remains in a shipping container after it is discharged or off-loaded (that is no more than ten percent of the volume of the container).
High-bleed pneumatic devices are automated, continuous bleed flow control devices powered by pressurized natural gas and used for maintaining a process condition such as liquid level, pressure, delta-pressure and temperature. Part of the gas power stream that is regulated by the process condition flows to a valve actuator controller where it vents continuously (bleeds) to the atmosphere at a rate in excess of 6 standard cubic feet per hour.
High heat value or HHV means the high or gross heat content of the fuel with the heat of vaporization included. The water is assumed to be in a liquid state.
Hydrofluorocarbons or HFCs means a class of GHGs consisting of hydrogen, fluorine, and carbon.
Import means, to land on, bring into, or introduce into, any place subject to the jurisdiction of the United States whether or not such landing, bringing, or introduction constitutes an importation within the meaning of the customs laws of the United States, with the following exemptions:
(1) Off-loading used or excess fluorinated GHGs or nitrous oxide of U.S. origin from a ship during servicing.
(2) Bringing fluorinated GHGs or nitrous oxide into the U.S. from Mexico where the fluorinated GHGs or nitrous oxide had been admitted into Mexico in bond and were of U.S. origin.
(3) Bringing fluorinated GHGs or nitrous oxide into the U.S. when transported in a consignment of personal or household effects or in a similar non-commercial situation normally exempted from U.S. Customs attention.
(4) Bringing fluorinated GHGs or nitrous into U.S. jurisdiction exclusively for U. S. military purposes.
Importer means any person, company, or organization of record that for any reason brings a product into the United States from a foreign country, excluding introduction into U.S. jurisdiction exclusively for United States military purposes. An importer is the person, company, or organization primarily liable for the payment of any duties on the merchandise or an authorized agent acting on their behalf. The term includes, as appropriate:
(1) The consignee.
(2) The importer of record.
(3) The actual owner.
(4) The transferee, if the right to draw merchandise in a bonded warehouse has been transferred.
Indurating furnace means a furnace where unfired taconite pellets, called green balls, are hardened at high temperatures to produce fired pellets for use in a blast furnace. Types of indurating furnaces include straight gate and grate kiln furnaces.
Industrial greenhouse gases means nitrous oxide or any fluorinated greenhouse gas.
In-line kiln/raw mill means a system in a portland cement production process where a dry kiln system is integrated with the raw mill so that all or a portion of the kiln exhaust gases are used to perform the drying operation of the raw mill, with no auxiliary heat source used. In this system the kiln is capable of operating without the raw mill operating, but the raw mill cannot operate without the kiln gases, and consequently, the raw mill does not generate a separate exhaust gas stream.
Intermittent bleed pneumatic devices mean automated flow control devices powered by pressurized natural gas and used for automatically maintaining a process condition such as liquid level, pressure, delta-pressure and temperature. These are snap-acting or throttling devices that discharge all or a portion of  the full volume of the actuator intermittently when control action is necessary, but does not bleed continuously.
Isobutane is a paraffinic branch chain hydrocarbon with molecular formula C4H10.
Isobutylene is an olefinic branch chain hydrocarbon with molecular formula C4H8.
Kerosene is a light petroleum distillate with a maximum distillation temperature of 400 °F at the 10-percent recovery point, a final maximum boiling point of 572 °F, a minimum flash point of 100 °F, and a maximum freezing point of −22 °F. Included are No. 1 - K and No. 2 - K, distinguished by maximum sulfur content (0.04 and 0.30 percent of total mass, respectively), as well as all other grades of kerosene called range or stove oil. Excluded is kerosene-type jet fuel (see definition herein).
Kerosene-type jet fuel means a kerosene-based product used in commercial and military turbojet and turboprop aircraft. The product has a maximum distillation temperature of 400 °F at the 10 percent recovery point and a final maximum boiling point of 572 °F. Included are Jet A, Jet A - 1, JP - 5, and JP - 8.
Kiln means an oven, furnace, or heated enclosure used for thermally processing a mineral or mineral-based substance.
Landfill means an area of land or an excavation in which wastes are placed for permanent disposal and that is not a land application unit, surface impoundment, injection well, or waste pile as those terms are defined under 40 CFR 257.2.
Landfill gas means gas produced as a result of anaerobic decomposition of waste materials in the landfill. Landfill gas generally contains 40 to 60 percent methane on a dry basis, typically less than 1 percent non-methane organic chemicals, and the remainder being carbon dioxide.
Liberated means released from coal and surrounding rock strata during the mining process. This includes both methane emitted from the ventilation system and methane drained from degasification systems.
Lime is the generic term for a variety of chemical compounds that are produced by the calcination of limestone or dolomite. These products include but are not limited to calcium oxide, high-calcium quicklime, calcium hydroxide, hydrated lime, dolomitic quicklime, and dolomitic hydrate.
Liquid/Slurry means a manure management component in which manure is stored as excreted or with some minimal addition of water to facilitate handling and is stored in either tanks or earthen ponds, usually for periods less than one year.
Low-bleed pneumatic devices mean automated flow control devices powered by pressurized natural gas and used for maintaining a process condition such as liquid level, pressure, delta-pressure and temperature. Part of the gas power stream that is regulated by the process condition flows to a valve actuator controller where it vents continuously (bleeds) to the atmosphere at a rate equal to or less than six standard cubic feet per hour.
Lubricants include all grades of lubricating oils, from spindle oil to cylinder oil to those used in greases. Petroleum lubricants may be produced from distillates or residues.
Makeup chemicals means carbonate chemicals (e.g., sodium and calcium carbonates) that are added to the chemical recovery areas of chemical pulp mills to replace chemicals lost in the process.
Manure composting means the biological oxidation of a solid waste including manure usually with bedding or another organic carbon source typically at thermophilic temperatures produced by microbial heat production. There are four types of composting employed for manure management: Static, in vessel, intensive windrow and passive windrow. Static composting typically occurs in an enclosed channel, with forced aeration and continuous mixing. In vessel composting occurs in piles with forced aeration but no mixing. Intensive windrow composting occurs in windrows with regular turning for mixing and aeration. Passive windrow composting occurs in windrows with infrequent turning for mixing and aeration.
Maximum rated heat input capacity means the hourly heat input to a unit (in mmBtu/hr), when it combusts the maximum amount of fuel per hour that it is capable of combusting on a steady state basis, as of the initial installation of the unit, as specified by the manufacturer.
Maximum rated input capacity means the maximum charging rate of a municipal waste combustor unit expressed in tons per day of municipal solid waste combusted, calculated according to the procedures under 40 CFR 60.58b(j).
Mcf means thousand cubic feet.
Methane conversion factor means the extent to which the CH4 producing capacity (Bo) is realized in each type of treatment and discharge pathway and system. Thus, it is an indication of the degree to which the system is anaerobic.
Methane correction factor means an adjustment factor applied to the methane generation rate to account for portions of the landfill that remain aerobic. The methane correction factor can be considered the fraction of the total landfill waste volume that is ultimately disposed of in an anaerobic state. Managed landfills that have soil or other cover materials have a methane correction factor of 1.
Methanol (CH3OH) is an alcohol as described in "Oxygenates."
Midgrade gasoline has an octane rating greater than or equal to 88 and less than or equal to 90. This definition applies to the midgrade categories of Conventional-Summer, Conventional-Winter, Reformulated-Summer, and Reformulated-Winter. For midgrade categories of RBOB-Summer, RBOB-Winter, CBOB-Summer, and CBOB-Winter, this definition refers to the expected octane rating of the finished gasoline after oxygenate has been added to the RBOB or CBOB.
Miscellaneous products include all refined petroleum products not defined elsewhere. It includes, but is not limited to, naphtha-type jet fuel (Jet B and JP - 4), petrolatum lube refining by-products (aromatic extracts and tars), absorption oils, ram-jet fuel, petroleum rocket fuels, synthetic natural gas feedstocks, waste feedstocks, and specialty oils. It excludes organic waste sludges, tank bottoms, spent catalysts, and sulfuric acid.
MMBtu means million British thermal units.
Motor gasoline (finished) means a complex mixture of volatile hydrocarbons, with or without additives, suitably blended to be used in spark ignition engines. Motor gasoline includes conventional gasoline, reformulated gasoline, and all types of oxygenated gasoline. Gasoline also has seasonal variations in an effort to control ozone levels. This is achieved by lowering the Reid Vapor Pressure (RVP) of gasoline during the summer driving season. Depending on the region of the country the RVP is lowered to below 9.0 psi or 7.8 psi. The RVP may be further lowered by state regulations.
Mscf means thousand standard cubic feet.
MTBE (methyl tertiary butyl ether, (CH3)3COCH3) is an ether as described in "Oxygenates."
Municipal solid waste landfill or MSW landfill means an entire disposal facility in a contiguous geographical space where household waste is placed in or on land. An MSW landfill may also receive other types of RCRA Subtitle D wastes (40 CFR 257.2) such as commercial solid waste, nonhazardous sludge, conditionally exempt small quantity generator waste, and industrial solid waste. Portions of an MSW landfill may be separated by access roads, public roadways, or other public right-of-ways. An MSW landfill may be publicly or privately owned.
Municipal solid waste or MSW means solid phase household, commercial/retail, and/or institutional waste. Household waste includes material discarded by single and multiple residential dwellings, hotels, motels, and other similar permanent or temporary housing establishments or facilities. Commercial/retail waste includes material discarded by stores, offices, restaurants, warehouses, non-manufacturing activities at industrial facilities, and other similar establishments or facilities. Institutional waste includes material discarded by schools, nonmedical waste discarded by hospitals, material discarded by non-manufacturing activities at prisons and government facilities, and material discarded by other similar establishments or facilities. Household, commercial/retail, and institutional wastes include yard waste, refuse-derived fuel, and motor vehicle maintenance materials. Insofar as there is separate collection, processing and disposal of industrial source waste streams consisting of used oil, wood pallets, construction, renovation, and demolition wastes (which includes, but is not limited to, railroad ties and telephone poles), paper, clean wood, plastics, industrial process or manufacturing wastes, medical waste, motor vehicle parts or vehicle fluff, or used tires that do not contain hazardous waste identified or listed under 42 U.S.C. §6921, such wastes are not municipal solid waste. However, such wastes qualify as municipal solid waste where they are collected with other municipal solid waste or are otherwise combined with other municipal solid waste for processing and/or disposal.
Municipal wastewater treatment plant means a series of treatment processes used to remove contaminants and pollutants from domestic, business, and industrial wastewater collected in city sewers and transported to a centralized wastewater treatment system such as a publicly owned treatment works (POTW).
N2O means nitrous oxide.
Naphthas (<401°F) is a generic term applied to a petroleum fraction with an approximate boiling range between 122 °F and 400 °F. The naphtha fraction of crude oil is the raw material for gasoline and is composed largely of paraffinic hydrocarbons.
Natural gas means a naturally occurring mixture of hydrocarbon and non-hydrocarbon gases found in geologic formations beneath the earth's surface, of which the principal constituent is methane. Natural gas may be field quality or pipeline quality.
Natural gas driven pneumatic pump means a pump that uses pressurized natural gas to move a piston or diaphragm, which pumps liquids on the opposite side of the piston or diaphragm.
Natural gas liquids (NGLs) means those hydrocarbons in natural gas that are separated from the gas as liquids through the process of absorption, condensation, adsorption, or other methods. Generally, such liquids consist of ethane, propane, butanes, and pentanes plus. Bulk NGLs refers to mixtures of NGLs that are sold or delivered as undifferentiated product from natural gas processing plants.
Natural gasoline means a mixture of liquid hydrocarbons (mostly pentanes and heavier hydrocarbons) extracted from natural gas. It includes isopentane.
NIST means the United States National Institute of Standards and Technology.
Nitric acid production line means a series of reactors and absorbers used to produce nitric acid.
Nitrogen excreted is the nitrogen that is excreted by livestock in manure and urine.
Non-crude feedstocks means any petroleum product or natural gas liquid that enters the refinery to be further refined or otherwise used on site.
Non-recovery coke oven battery means a group of ovens connected by common walls and operated as a unit, where coal undergoes destructive distillation under negative pressure to produce coke, and which is designed for the combustion of the coke oven gas from which by-products are not recovered.
North American Industry Classification System (NAICS) code(s) means the six-digit code(s) that represents the product(s)/activity(s)/service(s) at a facility or supplier as listed in the Federal Register and defined in "North American Industrial Classification System Manual 2007," available from the U.S. Department of Commerce, National Technical Information Service, Alexandria, VA 22312, phone (703) 605 - 6000 or (800) 553 - 6847. http://www.census.gov/eos/www/naics/. 
Oil-fired unit means a stationary combustion unit that derives more than 50 percent of its annual heat input from the combustion of fuel oil, and the remainder of its annual heat input from the combustion of natural gas or other gaseous fuels.
Open-ended valve or lines (OELs) means any valve, except pressure relief valves, having one side of the valve seat in contact with process fluid and one side open to atmosphere, either directly or through open piping.
Operating hours means the duration of time in which a process or process unit is utilized; this excludes shutdown, maintenance, and standby.
Operational change means, for purposes of §98.3(b), a change in the type of feedstock or fuel used, a change in operating hours, or a change in process production rate.
Operator means any person who operates or supervises a facility or supplier.
Other oils (> 401 °F) are oils with a boiling range equal to or greater than 401 °F that are generally intended for use as a petrochemical feedstock and are not defined elsewhere.
Outer Continental Shelf means all submerged lands lying seaward and outside of the area of lands beneath navigable waters as defined in 43 U.S.C. 1331, and of which the subsoil and seabed appertain to the United States and are subject to its jurisdiction and control.
Owner means any person who has legal or equitable title to, has a leasehold interest in, or control of a facility or supplier, except a person whose legal or equitable title to or leasehold interest in the facility or supplier arises solely because the person is a limited partner in a partnership that has legal or equitable title to, has a leasehold interest in, or control of the facility or supplier shall not be considered an "owner" of the facility or supplier.
Oxygenates means substances which, when added to gasoline, increase the oxygen content of the gasoline. Common oxygenates are ethanol, methyl tertiary butyl ether (MTBE), ethyl tertiary butyl ether (ETBE), tertiary amyl methyl ether (TAME), diisopropyl ether (DIPE), and methanol.
Pasture/Range/Paddock means the manure from pasture and range grazing animals is allowed to lie as deposited, and is not managed.
Pentanes plus, or C5+, is a mixture of hydrocarbons that is a liquid at ambient temperature and pressure, and consists mostly of pentanes (five carbon chain) and higher carbon number hydrocarbons. Pentanes plus includes, but is not limited to, normal pentane, isopentane, hexanes-plus (natural gasoline), and plant condensate.
Perfluorocarbons or PFCs means a class of greenhouse gases consisting on the molecular level of carbon and fluorine.
Petrochemical means methanol, acrylonitrile, ethylene, ethylene oxide, ethylene dichloride, and any form of carbon black.
Petrochemical feedstocks means feedstocks derived from petroleum for the manufacture of chemicals, synthetic rubber, and a variety of plastics. This category is usually divided into naphthas less than 401 °F and other oils greater than 401 °F.
Petroleum means oil removed from the earth and the oil derived from tar sands and shale.
Petroleum coke means a black solid residue, obtained mainly by cracking and carbonizing of petroleum derived feedstocks, vacuum bottoms, tar and pitches in processes such as delayed coking or fluid coking. It consists mainly of carbon (90 to 95 percent), has low ash content, and may be used as a feedstock in coke ovens. This product is also known as marketable coke or catalyst coke.
Petroleum product means all refined and semi-refined products that are produced at a refinery by processing crude oil and other petroleum-based feedstocks, including petroleum products derived from co-processing biomass and petroleum feedstock together, but not including plastics or plastic products. Petroleum products may be combusted for energy use, or they may be used either for non-energy processes or as non-energy products. The definition of petroleum product for importers and exporters excludes waxes.
Physical address, with respect to a United States parent company as defined in this section, means the street address, city, state and zip code of that company's physical location.
Pit storage below animal confinement (deep pits) means the collection and storage of manure typically below a slatted floor in an enclosed animal confinement facility. This usually occurs with little or no added water for periods less than one year.
Plant code means either of the following: 
(1) The Plant ID code assigned by the Department of Energy's Energy Information Administration. The  Energy Information Administration Plant ID code is also referred to as the "ORIS code", "ORISPL code", "Facility ID", or "Facility code", among other names.
(2) If a Plant ID code has not been assigned by the  Department of Energy's Energy Information Administration, then plant code means a code beginning with "88" assigned by the EPA's Clean Air Markets Division for electronic reporting.  
Portable means designed and capable of being carried or moved from one location to another. Indications of portability include but are not limited to wheels, skids, carrying handles, dolly, trailer, or platform. Equipment is not portable if any one of the following conditions exists:
(1) The equipment is attached to a foundation.
(2) The equipment or a replacement resides at the same location for more than 12 consecutive months.
(3) The equipment is located at a seasonal facility and operates during the full annual operating period of the seasonal facility, remains at the facility for at least two years, and operates at that facility for at least three months each year.
(4) The equipment is moved from one location to another in an attempt to circumvent the portable residence time requirements of this definition.
Poultry manure with litter means a manure management system component that is similar to cattle and swine deep bedding except usually not combined with a dry lot or pasture. The system is typically used for poultry breeder flocks and for the production of meat type chickens (broiler) and other fowl.
Poultry manure without litter means a manure management system component that may manage manure in a liquid form, similar to open pits in enclosed animal confinement facilities. These systems may alternatively be designed and operated to dry manure as it accumulates. The latter is known as a high-rise manure management system and is a form of passive windrow manure composting when designed and operated properly.
Precision of a measurement at a specified level (e.g., one percent of full scale or one percent of the value measured) means that 95 percent of repeat measurements made by a device or technique are within the range bounded by the mean of the measurements plus or minus the specified level.
Premium grade gasoline is gasoline having an antiknock index, i.e., octane rating, greater than 90. This definition applies to the premium grade categories of Conventional-Summer, Conventional-Winter, Reformulated-Summer, and Reformulated-Winter. For premium grade categories of RBOB-Summer, RBOB-Winter, CBOB-Summer, and CBOB-Winter, this definition refers to the expected octane rating of the finished gasoline after oxygenate has been added to the RBOB or CBOB.
Pressed and blown glass means glass which is pressed, blown, or both, into products such as light bulbs, glass fiber, technical glass, and other products listed in NAICS 327212.
Pressure relief device or pressure relief valve or pressure safety valve means a safety device used to prevent operating pressures from exceeding the maximum allowable working pressure of the process equipment. A common pressure relief device is but not limited to a spring-loaded pressure relief valve. Devices that are actuated either by a pressure of less than or equal to 2.5 psig or by a vacuum are not pressure relief devices.
Primary fuel means the fuel that provides the greatest percentage of the annual heat input to a stationary fuel combustion unit.
Process emissions means the emissions from industrial processes (e.g., cement production, ammonia production) involving chemical or physical transformations other than fuel combustion. For example, the calcination of carbonates in a kiln during cement production or the oxidation of methane in an ammonia process results in the release of process CO2 emissions to the atmosphere. Emissions from fuel combustion to provide process heat are not part of process emissions, whether the combustion is internal or external to the process equipment.
Process unit means the equipment assembled and connected by pipes and ducts to process raw materials and to manufacture either a final product or an intermediate used in the onsite production of other products. The process unit also includes the purification of recovered byproducts.
Process vent means means a gas stream that: Is discharged through a conveyance to the atmosphere either directly or after passing through a control device; originates from a unit operation, including but not limited to reactors (including reformers, crackers, and furnaces, and separation equipment for products and recovered byproducts); and contains or has the potential to contain GHG that is generated in the process. Process vent does not include safety device discharges, equipment leaks, gas streams routed to a fuel gas system or to a flare, discharges from storage tanks.
Propane is a paraffinic hydrocarbon with molecular formula C3H8.
Propylene is an olefinic hydrocarbon with molecular formula C3H6.
Pulp mill lime kiln means the combustion units (e.g., rotary lime kiln or fluidized bed calciner) used at a kraft or soda pulp mill to calcine lime mud, which consists primarily of calcium carbonate, into quicklime, which is calcium oxide.
Pushing means the process of removing the coke from the coke oven at the end of the coking cycle. Pushing begins when coke first begins to fall from the oven into the quench car and ends when the quench car enters the quench tower.
Raw mill means a ball and tube mill, vertical roller mill or other size reduction equipment, that is not part of an in-line kiln/raw mill, used to grind feed to the appropriate size. Moisture may be added or removed from the feed during the grinding operation. If the raw mill is used to remove moisture from feed materials, it is also, by definition, a raw material dryer. The raw mill also includes the air separator associated with the raw mill.
RBOB-Summer (reformulated blendstock for oxygenate blending) means a petroleum product which, when blended with a specified type and percentage of oxygenate, meets the definition of Reformulated-Summer.
RBOB-Winter (reformulated blendstock for oxygenate blending) means a petroleum product which, when blended with a specified type and percentage of oxygenate, meets the definition of Reformulated-Winter.
Reciprocating compressor means a piece of equipment that increases the pressure of a process natural gas or CO2 by positive displacement, employing linear movement of a shaft driving a piston in a cylinder.
Reciprocating compressor rod packing means a series of flexible rings in machined metal cups that fit around the reciprocating compressor piston rod to create a seal limiting the amount of compressed natural gas or CO2 that escapes to the atmosphere.
Re-condenser means heat exchangers that cool compressed boil-off gas to a temperature that will condense natural gas to a liquid.
Reformulated-Summer refers to finished gasoline formulated for use in motor vehicles, the composition and properties of which meet the requirements of the reformulated gasoline regulations promulgated by the U.S. Environmental Protection Agency under 40 CFR 80.40 and 40 CFR 80.41, and summer RVP standards required under 40 CFR 80.27 or as specified by the state. Reformulated gasoline excludes Reformulated Blendstock for Oxygenate Blending (RBOB) as well as other blendstock.
Reformulated-Winter refers to finished gasoline formulated for use in motor vehicles, the composition and properties of which meet the requirements of the reformulated gasoline regulations promulgated by the U.S. Environmental Protection Agency under 40 CFR 80.40 and 40 CFR 80.41, but which do not meet summer RVP standards required under 40 CFR 80.27 or as specified by the state.Note:This category includes Oxygenated Fuels Program Reformulated Gasoline (OPRG). Reformulated gasoline excludes Reformulated Blendstock for Oxygenate Blending (RBOB) as well as other blendstock.
Regular grade gasoline is gasoline having an antiknock index, i.e., octane rating, greater than or equal to 85 and less than 88. This definition applies to the regular grade categories of Conventional-Summer, Conventional-Winter, Reformulated-Summer, and Reformulated-Winter. For regular grade categories of RBOB-Summer, RBOB-Winter, CBOB-Summer, and CBOB-Winter, this definition refers to the expected octane rating of the finished gasoline after oxygenate has been added to the RBOB or CBOB.
Rendered animal fat, or tallow, means fats extracted from animals which are generally used as a feedstock in making biodiesel.
Research and development means those activities conducted in process units or at laboratory bench-scale settings whose purpose is to conduct research and development for new processes, technologies, or products and whose purpose is not for the manufacture of products for commercial sale, except in a de minimis manner.
Residual Fuel Oil No. 5 (Navy Special) is a classification for the heavier fuel oil generally used in steam powered vessels in government service and inshore power plants. It has a minimum flash point of 131 °F.
Residual Fuel Oil No. 6 (a.k.a. Bunker C) is a classification for the heavier fuel oil generally used for the production of electric power, space heating, vessel bunkering and various industrial purposes. It has a minimum flash point of 140 °F.
Residuum is residue from crude oil after distilling off all but the heaviest components, with a boiling range greater than 1,000 °F.
Road oil is any heavy petroleum oil, including residual asphaltic oil used as a dust palliative and surface treatment on roads and highways. It is generally produced in six grades, from 0, the most liquid, to 5, the most viscous.
Rotary lime kiln means a unit with an inclined rotating drum that is used to produce a lime product from limestone by calcination.
Safety device means a closure device such as a pressure relief valve, frangible disc, fusible plug, or any other type of device which functions exclusively to prevent physical damage or permanent deformation to a unit or its air emission control equipment by venting gases or vapors directly to the atmosphere during unsafe conditions resulting from an unplanned, accidental, or emergency event. A safety device is not used for routine venting of gases or vapors from the vapor headspace underneath a cover such as during filling of the unit or to adjust the pressure in response to normal daily diurnal ambient temperature fluctuations. A safety device is designed to remain in a closed position during normal operations and open only when the internal pressure, or another relevant parameter, exceeds the device threshold setting applicable to the air emission control equipment as determined by the owner or operator based on manufacturer recommendations, applicable regulations, fire protection and prevention codes and practices, or other requirements for the safe handling of flammable, combustible, explosive, reactive, or hazardous materials.
Sales oil means produced crude oil or condensate measured at the production lease automatic custody transfer (LACT) meter or custody transfer tank gauge.
Semi-refined petroleum product means all oils requiring further processing. Included in this category are unfinished oils which are produced by the partial refining of crude oil and include the following: Naphthas and lighter oils; kerosene and light gas oils; heavy gas oils; and residuum, and all products that require further processing or the addition of blendstocks.
Sendout means, in the context of a local distribution company, the total deliveries of natural gas to customers over a specified time interval (typically hour, day, month, or year). Sendout is the sum of gas received through the city gate, gas withdrawn from on-system storage or peak shaving plants, and gas produced and delivered into the distribution system; and is net of any natural gas injected into on-system storage. It comprises gas sales, exchange, deliveries, gas used by company, and unaccounted for gas. Sendout is measured at the city gate station, and other on-system receipt points from storage, peak shaving, and production.
Sensor means a device that measures a physical quantity/quality or the change in a physical quantity/quality, such as temperature, pressure, flow rate, pH, or liquid level.
SF6 means sulfur hexafluoride.
Shutdown means the cessation of operation of an emission source for any purpose.
Silicon carbide means an artificial abrasive produced from silica sand or quartz and petroleum coke.
Sinter process means a process that produces a fused aggregate of fine iron-bearing materials suited for use in a blast furnace. The sinter machine is composed of a continuous traveling grate that conveys a bed of ore fines and other finely divided iron-bearing material and fuel (typically coke breeze), a burner at the feed end of the grate for ignition, and a series of downdraft windboxes along the length of the strand to support downdraft combustion and heat sufficient to produce a fused sinter product.
Site means any combination of one or more graded pad sites, gravel pad sites, foundations, platforms, or the immediate physical location upon which equipment is physically located.
Smelting furnace means a furnace in which lead-bearing materials, carbon-containing reducing agents, and fluxes are melted together to form a molten mass of material containing lead and slag.
Solid by-products means plant matter such as vegetable waste, animal materials/wastes, and other solid biomass, except for wood, wood waste, and sulphite lyes (black liquor).
Solid storage is the storage of manure, typically for a period of several months, in unconfined piles or stacks. Manure is able to be stacked due to the presence of a sufficient amount of bedding material or loss of moisture by evaporation.
Sour gas means any gas that contains significant concentrations of hydrogen sulfide. Sour gas may include untreated fuel gas, amine stripper off-gas, or sour water stripper gas.
Sour natural gas means natural gas that contains significant concentrations of hydrogen sulfide (H2S)and/or carbon dioxide (CO2) that exceed the concentrations specified for commercially saleable natural gas delivered from transmission and distribution pipelines.
Special naphthas means all finished products with the naphtha boiling range (290 ° to 470 °F) that are generally used as paint thinners, cleaners or solvents. These products are refined to a specified flash point. Special naphthas include all commercial hexane and cleaning solvents conforming to ASTM Specification D1836 - 07, Standard Specification for Commercial Hexanes, and D235 - 02 (Reapproved 2007), Standard Specification for Mineral Spirits (Petroleum Spirits) (Hydrocarbon Dry Cleaning Solvent), respectively. Naphthas to be blended or marketed as motor gasoline or aviation gasoline, or that are to be used as petrochemical and synthetic natural gas (SNG) feedstocks are excluded.
Spent liquor solids means the dry weight of the solids in the spent pulping liquor that enters the chemical recovery furnace or chemical recovery combustion unit.
Spent pulping liquor means the residual liquid collected from on-site pulping operations at chemical pulp facilities that is subsequently fired in chemical recovery furnaces at kraft and soda pulp facilities or chemical recovery combustion units at sulfite or semi-chemical pulp facilities.
Standard conditions or standard temperature and pressure (STP), for the purposes of this part, means either 60 or 68 degrees Fahrenheit and 14.7 pounds per square inch absolute.
Steam reforming means a catalytic process that involves a reaction between natural gas or other light hydrocarbons and steam. The result is a mixture of hydrogen, carbon monoxide, carbon dioxide, and water.
Still gas means any form or mixture of gases produced in refineries by distillation, cracking, reforming, and other processes. The principal constituents are methane, ethane, ethylene, normal butane, butylene, propane, and propylene.
Storage tank means a vessel (excluding sumps) that is designed to contain an accumulation of crude oil, condensate, intermediate hydrocarbon liquids, or produced water and that is constructed entirely of non-earthen materials (e.g., wood, concrete, steel, plastic) that provide structural support.
Sulfur recovery plant means all process units which recover sulfur or produce sulfuric acid from hydrogen sulfide (H2S) and/or sulfur dioxide (SO2) from a common source of sour gas at a petroleum refinery. The sulfur recovery plant also includes sulfur pits used to store the recovered sulfur product, but it does not include secondary sulfur storage vessels or loading facilities downstream of the sulfur pits. For example, a Claus sulfur recovery plant includes: Reactor furnace and waste heat boiler, catalytic reactors, sulfur pits, and, if present, oxidation or reduction control systems, or incinerator, thermal oxidizer, or similar combustion device. Multiple sulfur recovery units are a single sulfur recovery plant only when the units share the same source of sour gas. Sulfur recovery units that receive source gas from completely segregated sour gas treatment systems are separate sulfur recovery plants.
Supplemental fuel means a fuel burned within a petrochemical process that is not produced within the process itself.
Supplier means a producer, importer, or exporter in any supply category included in Table A-5 of this subpart, as defined by the corresponding subpart of this part. 
Sweet gas is natural gas with low concentrations of hydrogen sulfide (H2S) and/or carbon dioxide (CO2) that does not require (or has already had) acid gas treatment to meet pipeline corrosion-prevention specifications for transmission and distribution.
Taconite iron ore processing means an industrial process that separates and concentrates iron ore from taconite, a low grade iron ore, and heats the taconite in an indurating furnace to produce taconite pellets that are used as the primary feed material for the production of iron in blast furnaces at integrated iron and steel plants.
TAME means tertiary amyl methyl ether, (CH3)2(C2H5)COCH3).
Trace concentrations means concentrations of less than 0.1 percent by mass of the process stream.
Transform means to use and entirely consume (except for trace concentrations) nitrous oxide or fluorinated GHGs in the manufacturing of other chemicals for commercial purposes. Transformation does not include burning of nitrous oxide.
Transshipment means the continuous shipment of nitrous oxide or a fluorinated GHG from a foreign state of origin through the United States or its territories to a second foreign state of final destination, as long as the shipment does not enter into United States jurisdiction. A transshipment, as it moves through the United States or its territories, cannot be re-packaged, sorted or otherwise changed in condition.
Trona means the raw material (mineral) used to manufacture soda ash; hydrated sodium bicarbonate carbonate (e.g., Na2CO3.NaHCO3.2H2O).
Ultimate analysis means the determination of the percentages of carbon, hydrogen, nitrogen, sulfur, and chlorine and (by difference) oxygen in the gaseous products and ash after the complete combustion of a sample of an organic material.
Unfinished oils are all oils requiring further processing, except those requiring only mechanical blending.
United States means the 50 States, the District of Columbia, the Commonwealth of Puerto Rico, American Samoa, the Virgin Islands, Guam, and any other Commonwealth, territory or possession of the United States, as well as the territorial sea as defined by Presidential Proclamation No. 5928.
United States parent company(s) means the highest-level United States company(s) with an ownership interest in the facility or supplier as of December 31 of the year for which data are being reported.
Unstabilized crude oil means, for the purposes of this part, crude oil that is pumped from the well to a pipeline or pressurized storage vessel for transport to the refinery without intermediate storage in a storage tank at atmospheric pressures. Unstabilized crude oil is characterized by having a true vapor pressure of 5 pounds per square inch absolute (psia) or greater.
Used oil means a petroleum-derived or synthetically-derived oil whose physical properties have changed as a result of handling or use, such that the oil cannot be used for its original purpose. Used oil consists primarily of automotive oils (e.g., used motor oil, transmission oil, hydraulic fluids, brake fluid, etc.) and industrial oils (e.g., industrial engine oils, metalworking oils, process oils, industrial grease, etc).
Valve means any device for halting or regulating the flow of a liquid or gas through a passage, pipeline, inlet, outlet, or orifice; including, but not limited to, gate, globe, plug, ball, butterfly and needle valves.
Vapor recovery system means any equipment located at the source of potential gas emissions to the atmosphere or to a flare, that is composed of piping, connections, and, if necessary, flow-inducing devices, and that is used for routing the gas back into the process as a product and/or fuel.
Vaporization unit means a process unit that performs controlled heat input to vaporize LNG to supply transmission and distribution pipelines or consumers with natural gas.
Vegetable oil means oils extracted from vegetation that are generally used as a feedstock in making biodiesel.
Ventilation hole or shaft means a vent hole or shaft employed at an underground coal mine to serve as the outlet or conduit to move air from the ventilation system out of the mine.
Ventilation system means a system that is used to control the concentration of methane and other gases within mine working areas through mine ventilation, rather than a mine degasification system. A ventilation system consists of fans that move air through the mine workings to dilute methane concentrations. 
Volatile solids are the organic material in livestock manure and consist of both biodegradable and non-biodegradable fractions.
Waelz kiln means an inclined rotary kiln in which zinc-containing materials are charged together with a carbon reducing agent (e.g., petroleum coke, metallurgical coke, or anthracite coal).
Waxes means a solid or semi-solid material at 77 °F consisting of a mixture of hydrocarbons obtained or derived from petroleum fractions, or through a Fischer-Tropsch type process, in which the straight chained paraffin series predominates. This includes all marketable wax, whether crude or refined, with a congealing point between 80 (or 85) and 240 °F and a maximum oil content of 50 weight percent.
Well completions means the process that allows for the flow of petroleum or natural gas from newly drilled wells to expel drilling and reservoir fluids and test the reservoir flow characteristics, steps which may vent produced gas to the atmosphere via an open pit or tank. Well completion also involves connecting the well bore to the reservoir, which may include treating the formation or installing tubing, packer(s), or lifting equipment, steps that do not significantly vent natural gas to the atmosphere. This process may also include high-rate flowback of injected gas, water, oil, and proppant used to fracture or re-fracture and prop open new fractures in existing lower permeability gas reservoirs, steps that may vent large quantities of produced gas to the atmosphere.
Well workover means the process(es) of performing one or more of a variety of remedial operations on producing petroleum and natural gas wells to try to increase production. This process also includes high-rate flowback of injected gas, water, oil, and proppant used to re-fracture and prop-open new fractures in existing low permeability gas reservoirs, steps that may vent large quantities of produced gas to the atmosphere.
Wellhead means the piping, casing, tubing and connected valves protruding above the earth's surface for an oil and/or natural gas well. The wellhead ends where the flow line connects to a wellhead valve. Wellhead equipment includes all equipment, permanent and portable, located on the improved land area (i.e. well pad) surrounding one or multiple wellheads.
Wet natural gas means natural gas in which water vapor exceeds the concentration specified for commercially saleable natural gas delivered from transmission and distribution pipelines. This input stream to a natural gas dehydrator is referred to as "wet gas."
Wood residuals means materials recovered from three principal sources: Municipal solid waste (MSW); construction and demolition debris; and primary timber processing. Wood residuals recovered from MSW include wooden furniture, cabinets, pallets and containers, scrap lumber (from sources other than construction and demolition activities), and urban tree and landscape residues. Wood residuals from construction and demolition debris originate from the construction, repair, remodeling and demolition of houses and non-residential structures. Wood residuals from primary timber processing include bark, sawmill slabs and edgings, sawdust, and peeler log cores. Other sources of wood residuals include, but are not limited to, railroad ties, telephone and utility poles, pier and dock timbers, wastewater process sludge from paper mills, trim, sander dust, and sawdust from wood products manufacturing (including resinated wood product residuals), and logging residues.
Wool fiberglass means fibrous glass of random texture, including fiberglass insulation, and other products listed in NAICS 327993.
Working capacity, for the purposes of subpart TT of this part, means the maximum volume or mass of waste that is actually placed in the landfill from an individual or representative type of container (such as a tank, truck, or roll-off bin) used to convey wastes to the landfill, taking into account that the container may not be able to be 100 percent filled and/or 100 percent emptied for each load.
You means an owner or operator subject to Part 98.
Zinc smelters means a facility engaged in the production of zinc metal, zinc oxide, or zinc alloy products from zinc sulfide ore concentrates, zinc calcine, or zinc-bearing scrap and recycled materials through the use of pyrometallurgical techniques involving the reduction and volatization of zinc-bearing feed materials charged to a furnace.
§ 98.7 What standardized methods are incorporated by reference into this part?
The materials listed in this section are incorporated by reference in the corresponding sections noted. These incorporations by reference were approved by the Director of Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. These materials are incorporated as they exist on the date of approval, and a notice of any change in the materials will be published in theFederal Register.The materials are available for purchase at the corresponding address in this section. The materials are available for inspection at the EPA Docket Center, Public Reading Room, EPA West Building, Room 3334, 1301 Constitution Avenue, NW., Washington, DC, phone (202) 566 - 1744 and at the National Archives and Records Administration (NARA). For information on the availability of this material at NARA, call 202 - 741 - 6030, or go to: http://www.archives.gov/federal_register/code_of_federal_regulations/ibr_locations.html.
(a) [Reserved]
(b) [Reserved]
(c) The following material is available for purchase from the ASM International, 9639 Kinsman Road, Materials Park, OH 44073, (440) 338 - 5151, http://www.asminternational.org.
(1) ASM CS - 104 UNS No. G10460 -- Alloy Digest April 1985 (Carbon Steel of Medium Carbon Content), incorporation by reference (IBR) approved for §98.174(b).
(2) [Reserved]
(d) The following material is available for purchase from the American Society of Mechanical Engineers (ASME), Three Park Avenue, New York, NY 10016 - 5990, (800) 843 - 2763, http://www.asme.org.
(1) ASME MFC - 3M - 2004 Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and Venturi, incorporation by reference (IBR) approved for §98.124(m)(1), §98.324(e), §98.354(d), §98.354(h), §98.344(c) and §98.364(e).
(2) ASME MFC - 4M - 1986 (Reaffirmed 1997) Measurement of Gas Flow by Turbine Meters, IBR approved for §98.124(m)(2), §98.324(e), §98.344(c), §98.354(h), and §98.364(e).
(3) ASME MFC - 5M - 1985 (Reaffirmed 1994) Measurement of Liquid Flow in Closed Conduits Using Transit-Time Ultrasonic Flow Meters, IBR approved for §98.124(m)(3) and §98.354(d).
(4) ASME MFC - 6M - 1998 Measurement of Fluid Flow in Pipes Using Vortex Flowmeters, IBR approved for §98.124(m)(4), §98.324(e), §98.344(c), §98.354(h), and §98.364(e).
(5) ASME MFC - 7M - 1987 (Reaffirmed 1992) Measurement of Gas Flow by means of Critical Flow Venturi Nozzles, IBR approved for §98.124(m)(5), §98.324(e), §98.344(c), §98.354(h), and §98.364(e).
(6) ASME MFC - 9M - 1988 (Reaffirmed 2001) Measurement of Liquid Flow in Closed Conduits by Weighing Method, IBR approved for §98.124(m)(6).
(7) ASME MFC - 11M - 2006 Measurement of Fluid Flow by means of Coriolis Mass Flowmeters, IBR approved for §98.124(m)(7), §98.324(e), §98.344(c), and §98.354(h).
(8) ASME MFC - 14M - 2003 Measurement of Fluid Flow Using Small Bore Precision Orifice Meters, IBR approved for §98.124(m)(8), §98.324(e), §98.344(c), §98.354(h), and §98.364(e).
(9) ASME MFC - 16 - 2007 Measurement of Liquid Flow in Closed Conduits with Electromagnetic Flow Meters, IBR approved for §98.354(d).
(10) ASME MFC - 18M - 2001 Measurement of Fluid Flow Using Variable Area Meters, IBR approved for §98.324(e), §98.344(c), §98.354(h), and §98.364(e).
(e) The following material is available for purchase from the American Society for Testing and Material (ASTM), 100 Barr Harbor Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428 - B2959, (800) 262 - 1373, http://www.astm.org.
(1) ASTM C25 - 06 Standard Test Method for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime, incorporation by reference (IBR) approved for §98.114(b), §98.174(b), §98.184(b), §98.194(c), and §98.334(b).
(2) ASTM C114 - 09 Standard Test Methods for Chemical Analysis of Hydraulic Cement, IBR approved for §98.84(a), §98.84(b), and §98.84(c).
(3) ASTM D235 - 02 (Reapproved 2007) Standard Specification for Mineral Spirits (Petroleum Spirits) (Hydrocarbon Dry Cleaning Solvent), IBR approved for §98.6.
(4) ASTM D240 - 02 (Reapproved 2007) Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter, IBR approved for §98.254(e).
(5) ASTM D388 - 05 Standard Classification of Coals by Rank, IBR approved for §98.6.
(6) ASTM D910 - 07a Standard Specification for Aviation Gasolines, IBR approved for §98.6.
(7) [Reserved]
(8) ASTM D1826 - 94 (Reapproved 2003) Standard Test Method for Calorific (Heating) Value of Gases in Natural Gas Range by Continuous Recording Calorimeter, IBR approved for §98.254(e).
(9) ASTM D1836 - 07 Standard Specification for Commercial Hexanes, IBR approved for §98.6.
(10) ASTM D1945 - 03 Standard Test Method for Analysis of Natural Gas by Gas Chromatography, IBR approved for §98.74(c), §98.164(b), §98.244(b), §98.254(d), §98.324(d), §98.354(g), and §98.344(b).
(11) ASTM D1946 - 90 (Reapproved 2006) Standard Practice for Analysis of Reformed Gas by Gas Chromatography, IBR approved for §98.74(c), §98.164(b), §98.254(d), §98.324(d), §98.344(b), §98.354(g), and §98.364(c).
(12) ASTM D2013 - 07 Standard Practice for Preparing Coal Samples for Analysis, IBR approved for §98.164(b).
(13) ASTM D2234/D2234M - 07 Standard Practice for Collection of a Gross Sample of Coal, IBR approved for §98.164(b).
(14) ASTM D2502 - 04 Standard Test Method for Estimation of Mean Relative Molecular Mass of Petroleum Oils From Viscosity Measurements, IBR approved for §98.74(c).
(15) ASTM D2503 - 92 (Reapproved 2007) Standard Test Method for Relative Molecular Mass (Molecular Weight) of Hydrocarbons by Thermoelectric Measurement of Vapor Pressure, IBR approved for §98.74(c) and §98.254(d)(6).
(16) ASTM D2505 - 88 (Reapproved 2004)e1 Standard Test Method for Ethylene, Other Hydrocarbons, and Carbon Dioxide in High-Purity Ethylene by Gas Chromatography, IBR approved for §98.244(b).
(17) ASTM D2597 - 94 (Reapproved 2004) Standard Test Method for Analysis of Demethanized Hydrocarbon Liquid Mixtures Containing Nitrogen and Carbon Dioxide by Gas Chromatography, IBR approved for §98.164(b).
(18) ASTM D3176 - 89 (Reapproved 2002) Standard Practice for Ultimate Analysis of Coal and Coke, IBR approved for §98.74(c), §98.164(b), §98.244(b), §98.254(i), §98.284(c), §98.284(d), §98.314(c), §98.314(d), and §98.314(f).
(19) ASTM D3238 - 95 (Reapproved 2005) Standard Test Method for Calculation of Carbon Distribution and Structural Group Analysis of Petroleum Oils by the n-d-M Method, IBR approved for §98.74(c) and §98.164(b).
(20) ASTM D3588 - 98 (Reapproved 2003) Standard Practice for Calculating Heat Value, Compressibility Factor, and Relative Density of Gaseous Fuels, IBR approved for §98.254(e).
(21) ASTM D3682 - 01 (Reapproved 2006) Standard Test Method for Major and Minor Elements in Combustion Residues from Coal Utilization Processes, IBR approved for §98.144(b).
(22) ASTM D4057 - 06 Standard Practice for Manual Sampling of Petroleum and Petroleum Products, IBR approved for §98.164(b).
(23) ASTM D4177 - 95 (Reapproved 2005) Standard Practice for Automatic Sampling of Petroleum and Petroleum Products, IBR approved for §98.164(b).
(24) ASTM D4809 - 06 Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method), IBR approved for §98.254(e).
(25) ASTM D4891 - 89 (Reapproved 2006) Standard Test Method for Heating Value of Gases in Natural Gas Range by Stoichiometric Combustion, IBR approved for §98.254(e) and §98.324(d).
(26) ASTM D5291 - 02 (Reapproved 2007) Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants, IBR approved for §98.74(c), §98.164(b), §98.244(b), and §98.254(i).
(27) ASTM D5373 - 08 Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal, IBR approved for §98.74(c), §98.114(b), §98.164(b), §98.174(b), §98.184(b), §98.244(b), §98.254(i), §98.274(b), §98.284(c), §98.284(d), §98.314(c), §98.314(d), §98.314(f), and §98.334(b).
(28) [Reserved]
(29) ASTM D6060 - 96 (Reapproved 2001) Standard Practice for Sampling of Process Vents With a Portable Gas Chromatograph, IBR approved for §98.244(b).
(30) ASTM D6348 - 03 Standard Test Method for Determination of Gaseous Compounds by Extractive Direct Interface Fourier Transform Infrared (FTIR) Spectroscopy, IBR approved for §98.54(b), §98.124(e)(2), §98.224(b), and §98.414(n).
(31) ASTM D6609 - 08 Standard Guide for Part-Stream Sampling of Coal, IBR approved for §98.164(b).
(32) ASTM D6751 - 08 Standard Specification for Biodiesel Fuel Blend Stock (B100) for Middle Distillate Fuels, IBR approved for §98.6.
(33) ASTM D6866 - 08 Standard Test Methods for Determining the Biobased Content of Solid, Liquid, and Gaseous Samples Using Radiocarbon Analysis, IBR approved for §98.34(d), §98.34(e), and §98.36(e).
(34) ASTM D6883 - 04 Standard Practice for Manual Sampling of Stationary Coal from Railroad Cars, Barges, Trucks, or Stockpiles, IBR approved for §98.164(b).
(35) ASTM D7430 - 08ae1 Standard Practice for Mechanical Sampling of Coal, IBR approved for §98.164(b).
(36) ASTM D7459 - 08 Standard Practice for Collection of Integrated Samples for the Speciation of Biomass (Biogenic) and Fossil-Derived Carbon Dioxide Emitted from Stationary Emissions Sources, IBR approved for §98.34(d), §98.34(e), and §98.36(e).
(37) ASTM E359 - 00 (Reapproved 2005)e1 Standard Test Methods for Analysis of Soda Ash (Sodium Carbonate), IBR approved for §98.294(a) and §98.294(b).
(38) ASTM E1019 - 08 Standard Test Methods for Determination of Carbon, Sulfur, Nitrogen, and Oxygen in Steel, Iron, Nickel, and Cobalt Alloys by Various Combustion and Fusion Techniques, IBR approved for §98.174(b).
(39) [Reserved]
(40) ASTM E1915 - 07a Standard Test Methods for Analysis of Metal Bearing Ores and Related Materials by Combustion Infrared-Absorption Spectrometry, IBR approved for §98.174(b).
(41) ASTM E1941 - 04 Standard Test Method for Determination of Carbon in Refractory and Reactive Metals and Their Alloys, IBR approved for §98.114(b), §98.184(b), §98.334(b).
(42) ASTM UOP539 - 97 Refinery Gas Analysis by Gas Chromatography, IBR approved for §98.164(b), §98.244(b), §98.254(d), §98.324(d), §98.344(b), and §98.354(g).
(43) ASTM D1941 - 91 (Reapproved 2007) Standard Test Method for Open Channel Flow Measurement of Water with the Parshall Flume, approved June 15, 2007, IBR approved for §98.354(d).
(44) ASTM D5614 - 94 (Reapproved 2008) Standard Test Method for Open Channel Flow Measurement of Water with Broad-Crested Weirs, approved October 1, 2008, IBR approved for §98.354(d).
(45) ASTM D6349 - 09 Standard Test Method for Determination of Major and Minor Elements in Coal, Coke, and Solid Residues from Combustion of Coal and Coke by Inductively Coupled Plasma -- Atomic Emission Spectrometry, IBR approved for §98.144(b).
(46) ASTM D2879 - 97 (Reapproved 2007) Standard Test Method for Vapor Pressure-Temperature Relationship and Initial Decomposition Temperature of Liquids by Isoteniscope (ASTM D2879), approved May 1, 2007, IBR approved for §98.128.
(47) ASTM D7359 - 08 Standard Test Method for Total Fluorine, Chlorine and Sulfur in Aromatic Hydrocarbons and Their Mixtures by Oxidative Pyrohydrolytic Combustion followed by Ion Chromatography Detection (Combustion Ion Chromatography-CIC) (ASTM D7359), approved October 15, 2008, IBR approved for §98.124(e)(2).
(48) ASTM D2593 - 93 (Reapproved 2009) Standard Test Method for Butadiene Purity and Hydrocarbon Impurities by Gas Chromatography, approved July 1, 2009, IBR approved for §98.244(b)(4)(xi).
(49) ASTM D7633 - 10 Standard Test Method for Carbon Black -- Carbon Content, approved May 15, 2010, IBR approved for §98.244(b)(4)(xii).
(f) The following material is available for purchase from the Gas Processors Association (GPA), 6526 East 60th Street, Tulsa, Oklahoma 74143, (918) 493 - 3872, http://www.gasprocessors.com.
(1) [Reserved]
(2) GPA 2261 - 00 Analysis for Natural Gas and Similar Gaseous Mixtures by Gas Chromatography, IBR approved for §98.164(b), §98.254(d), §98.344(b), and §98.354(g).
(g) The following material is available for purchase from the International Standards Organization (ISO), 1, ch. de la Voie-Creuse, Case postale 56, CH - 1211 Geneva 20, Switzerland, +41 22 749 01 11, http://www.iso.org/iso/home.htm.
(1) ISO 3170: Petroleum liquids -- Manual sampling -- Third Edition 2004 - 02 - 01, IBR approved for §98.164(b).
(2) ISO 3171: Petroleum Liquids -- Automatic pipeline sampling -- Second Edition 1988 - 12 - 01, IBR approved for §98.164(b).
(3) [Reserved]
(4) ISO/TR 15349 - 1: 1998, Unalloyed steel -- Determination of low carbon content. Part 1: Infrared absorption method after combustion in an electric resistance furnace (by peak separation) (1998 - 10 - 15) -- First Edition, IBR approved for §98.174(b).
(5) ISO/TR 15349 - 3: 1998, Unalloyed steel -- Determination of low carbon content. Part 3: Infrared absorption method after combustion in an electric resistance furnace (with preheating) (1998 - 10 - 15) -- First Edition, IBR approved for §98.174(b).
(h) The following material is available for purchase from the National Lime Association (NLA), 200 North Glebe Road, Suite 800, Arlington, Virginia 22203, (703) 243 - 5463, http://www.lime.org.
(1) CO2 emissions Calculation Protocol for the Lime Industry -- English Units Version, February 5, 2008 Revision -- National Lime Association, incorporation by reference (IBR) approved for §98.194(c) and §98.194(e).
(2) [Reserved]
(i) The following material is available for purchase from the National Institute of Standards and Technology (NIST), 100 Bureau Drive, Stop 1070, Gaithersburg, MD 20899 - 1070, (800) 877 - 8339, http://www.nist.gov/index.html.
(1) Specifications, Tolerances, and Other Technical Requirements For Weighing and Measuring Devices, NIST Handbook 44 (2009), incorporation by reference (IBR) approved for §98.244(b), §98.254(h), and §98.344(a).
(2) [Reserved]
(j) The following material is available for purchase from the Technical Association of the Pulp and Paper Industry (TAPPI), 15 Technology Parkway South, Norcross, GA 30092, (800) 332 - 8686, http://www.tappi.org.
(1) T650 om-05 Solids Content of Black Liquor, TAPPI, incorporation by reference (IBR) approved for §98.276(c) and §98.277(d).
(2) T684 om-06 Gross Heating Value of Black Liquor, TAPPI, incorporation by reference (IBR) approved for §98.274(b).
(k) The following material is available for purchase from Standard Methods, at http://www.standardmethods.org, (877) 574 - 1233; or, through a joint publication agreement from the American Public Health Association (APHA), P.O. Box 933019, Atlanta, GA 31193 - 3019, (888) 320 - APHA (2742), http://www.apha.org/publications/pubscontact/. 
(1) Method 2540G Total, Fixed, and Volatile Solids in Solid and Semisolid Samples, IBR approved for §98.464(b).
(2) [Reserved]
(l) The following material is available from the U.S. Department of Labor, Mine Safety and Health Administration, 1100 Wilson Boulevard, 21st Floor, Arlington, VA 22209 - 3939, (202) 693 - 9400, http://www.msha.gov. 
(1) General Coal Mine Inspection Procedures and Inspection Tracking System, Handbook Number: PH - 08 - V - 1, January 1, 2008, IBR approved for §98.324(b).
(2) [Reserved]
(m) The following material is available from the U.S. Environmental Protection Agency, 1200 Pennsylvania Avenue, NW., Washington, DC 20460, (202) 272 - 0167, http://www.epa.gov. 
(1) NPDES Compliance Inspection Manual, Chapter 5, Sampling, EPA 305 - X - 04 - 001, July 2004, http://www.epa.gov/compliance/monitoring/programs/cwa/npdes.html, IBR approved for §98.354(c).
(2) U.S. EPA NPDES Permit Writers' Manual, Section 7.1.3, Sample Collection Methods, EPA 833 - B - 96 - 003, December 1996, http://www.epa.gov/npdes/pubs/owm0243.pdf, IBR approved for §98.354(c).
(3) Protocol for Measuring Destruction or Removal Efficiency (DRE) of Fluorinated Greenhouse Gas Abatement Equipment in Electronics Manufacturing, Version 1, EPA - 430 - R - 10 - 003, March 2010 (EPA 430 - R - 10 - 003), http://www.epa.gov/semiconductor-pfc/documents/dre_protocol.pdf, IBR approved for §98.94(f)(4)(i), §98.94(g)(3), §98.97(d)(4), §98.98, §98.124(e)(2), and §98.414(n)(1).
(4) Emissions Inventory Improvement Program, Volume II: Chapter 16, Methods for Estimating Air Emissions from Chemical Manufacturing Facilities, August 2007, Final, http://www.epa.gov/ttnchie1/eiip/techreport/volume02/index.html, IBR approved for §98.123(c)(1)(i)(A).
(5) Protocol for Equipment Leak Emission Estimates, EPA - 453/R - 95 - 017, November 1995 (EPA - 453/R - 95 - 017), http://www.epa.gov/ttnchie1/efdocs/equiplks.pdf, IBR approved for §98.123(d)(1)(i), §98.123(d)(1)(ii), §98.123(d)(1)(iii), and §98.124(f)(2).
(6) Tracer Gas Protocol for the Determination of Volumetric Flow Rate Through the Ring Pipe of the Xact Multi-Metals Monitoring System, also known as Other Test Method 24 (Tracer Gas Protocol), Eli Lilly and Company Tippecanoe Laboratories, September 2006, http://www.epa.gov/ttn/emc/prelim/otm24.pdf, IBR approved for §98.124(e)(1)(ii).
(7) Approved Alternative Method 012: An Alternate Procedure for Stack Gas Volumetric Flow Rate Determination (Tracer Gas) (ALT - 012), U.S. Environmental Protection Agency Emission Measurement Center, May 23, 1994, http://www.epa.gov/ttn/emc/approalt/alt-012.pdf, IBR approved for §98.124(e)(1)(ii).
(8) Protocol for Measurement of Tetrafluoromethane (CF4) and Hexafluoroethane (C2F6) Emissions from Primary Aluminum Production (2008), http://www.epa.gov/highgwp/aluminum-pfc/documents/measureprotocol.pdf, IBR approved for §98.64(a).
(9) AP 42, Section 5.2, Transportation and Marketing of Petroleum Liquids, July 2008, (AP 42, Section 5.2); http://www.epa.gov/ttn/chief/ap42/ch05/final/c05s02.pdf; in Chapter 5, Petroleum Industry, of AP 42, Compilation of Air Pollutant Emission Factors, 5th Edition, Volume I, IBR approved for §98.253(n).
(10) Method 9060A, Total Organic Carbon, Revision 1, November 2004 (Method 9060A), http://www.epa.gov/osw/hazard/testmethods/sw846/pdfs/9060a.pdf; in EPA Publication No. SW - 846, "Test Methods for Evaluating Solid Waste, Physical/Chemical Methods," Third Edition, IBR approved for §98.244(b)(4)(viii).
(11) Method 8031, Acrylonitrile By Gas Chromatography, Revision 0, September 1994 (Method 8031), http://www.epa.gov/osw/hazard/testmethods/sw846/pdfs/8031.pdf; in EPA Publication No. SW - 846, "Test Methods for Evaluating Solid Waste, Physical/Chemical Methods," Third Edition, IBR approved for §98.244(b)(4)(viii).
(12) Method 8021B, Aromatic and Halogenated Volatiles By Gas Chromatography Using Photoionization and/or Electrolytic Conductivity Detectors, Revision 2, December 1996 (Method 8021B). http://www.epa.gov/osw/hazard/testmethods/sw846/pdfs/8021b.pdf; in EPA Publication No. SW - 846, "Test Methods for Evaluating Solid Waste, Physical/Chemical Methods," Third Edition, IBR approved for §98.244(b)(4)(viii).
(13) Method 8015C, Nonhalogenated Organics By Gas Chromatography, Revision 3, February 2007 (Method 8015C). http://www.epa.gov/osw/hazard/testmethods/sw846/pdfs/8015c.pdf; in EPA Publication No. SW - 846, "Test Methods for Evaluating Solid Waste, Physical/Chemical Methods," Third Edition, IBR approved for §98.244(b)(4)(viii).
(14) AP 42, Section 7.1, Organic Liquid Storage Tanks, November 2006 (AP 42, Section 7.1), http://www.epa.gov/ttn/chief/ap42/ch07/final/c07s01.pdf; in Chapter 7, Liquid Storage Tanks, of AP 42, Compilation of Air Pollutant Emission Factors, 5th Edition, Volume I, IBR approved for §98.253(m)(1) and §98.256(o)(2)(i).
(n) [Reserved]

(o) [Reserved]
(p) The following material is available for purchase from the American Association of Petroleum Geologists, 1444 South Boulder Avenue, Tulsa, Oklahoma 74119, (918) 584 - 2555, http://www.aapg.org. 
(1) Geologic Note: AAPG - CSD Geologic Provinces Code Map: AAPG Bulletin, Prepared by Richard F. Meyer, Laure G. Wallace, and Fred J. Wagner, Jr., Volume 75, Number 10 (October 1991), pages 1644 - 1651, IBR approved for §98.238.
(2) Alaska Geological Province Boundary Map, Compiled by the American Association of Petroleum Geologists Committee on Statistics of Drilling in cooperation with the USGS, 1978, IBR approved for §98.238.
(q) The following material is available from the Energy Information Administration (EIA), 1000 Independence Ave., SW., Washington, DC 20585, (202) 586 - 8800, http://www.eia.doe.gov/pub/oil_gas/natural_gas/data_publications/field_code_master_list/current/pdf/fcml_all.pdf. 
(1) Oil and Gas Field Code Master List 2008, DOE/EIA0370(08), January 2009, IBR approved for §98.238.
(2) [Reserved]
§ 98.8 What are the compliance and enforcement provisions of this part?
Any violation of any requirement of this part shall be a violation of the Clean Air Act, including section 114 (42 U.S.C. 7414). A violation includes but is not limited to failure to report GHG emissions, failure to collect data needed to calculate GHG emissions, failure to continuously monitor and test as required, failure to retain records needed to verify the amount of GHG emissions, and failure to calculate GHG emissions following the methodologies specified in this part. Each day of a violation constitutes a separate violation.
§ 98.9 Addresses.
All requests, notifications, and communications to the Administrator pursuant to this part, must be submitted electronically and in a format as specified by the Administrator.  For example, any requests, notifications and communications that can be submitted through the electronic GHG reporting tool, must be submitted through that tool.  If not specified, requests, notifications or communications shall be submitted to the following address:
(a) For U.S. mail. Director, Climate Change Division, 1200 Pennsylvania Ave., NW., Mail Code: 6207J, Washington, DC 20460.
(b) For package deliveries. Director, Climate Change Division, 1310 L St, NW., Washington, DC 20005.
Table A - 1 to Subpart A of Part 98 -- Global Warming Potentials
[100-Year Time Horizon]
                                     Name
                                    CAS No.
                               Chemical formula
                      Global warming potential
(100 yr.)
Carbon dioxide
                                                                   124 - 38 - 9
CO2 
                                                                              1
Methane
                                                                    74 - 82 - 8
CH4 
                                                                          25[a]
Nitrous oxide
                                                                 10024 - 97 - 2
N2O
                                                                         298[a]
HFC - 23
                                                                    75 - 46 - 7
CHF3
                                                                      14,800[a]
HFC - 32
                                                                    75 - 10 - 5
CH2F2
                                                                         675[a]
HFC - 41
                                                                   593 - 53 - 3
CH3F
                                                                          92[a]
HFC - 125
                                                                   354 - 33 - 6
C2HF5
                                                                       3,500[a]
HFC - 134
                                                                   359 - 35 - 3
C2H2F4
                                                                       1,100[a]
HFC - 134a
                                                                   811 - 97 - 2
CH2FCF3
                                                                       1,430[a]
HFC - 143
                                                                   430 - 66 - 0
C2H3F3
                                                                         353[a]
HFC - 143a
                                                                   420 - 46 - 2
C2H3F3
                                                                       4,470[a]
HFC - 152
                                                                   624 - 72 - 6
CH2FCH2F
                                                                             53
HFC - 152a
                                                                    75 - 37 - 6
CH3CHF2
                                                                         124[a]
HFC - 161
                                                                   353 - 36 - 6
CH3CH2F
                                                                             12
HFC - 227ea
                                                                   431 - 89 - 0
C3HF7
                                                                       3,220[a]
HFC - 236cb
                                                                   677 - 56 - 5
CH2FCF2CF3
                                                                          1,340
HFC - 236ea
                                                                   431 - 63 - 0
CHF2CHFCF3
                                                                          1,370
HFC - 236fa
                                                                   690 - 39 - 1
C3H2F6
                                                                       9,810[a]
HFC - 245ca
                                                                   679 - 86 - 7
C3H3F5
                                                                         693[a]
HFC - 245fa
                                                                   460 - 73 - 1
CHF2CH2CF3
                                                                          1,030
HFC - 365mfc
                                                                   406 - 58 - 6
CH3CF2CH2CF3
                                                                            794
HFC - 43 - 10mee
                                                                138495 - 42 - 8
CF3CFHCFHCF2CF3
                                                                       1,640[a]
Sulfur hexafluoride
                                                                  2551 - 62 - 4
SF6 
                                                                      22,800[a]
Trifluoromethyl sulphur pentafluoride
                                                                   373 - 80 - 8
SF5CF3
                                                                         17,700
Nitrogen trifluoride
                                                                  7783 - 54 - 2
NF3
                                                                         17,200
PFC - 14 (Perfluoromethane)
                                                                    75 - 73 - 0
CF4
                                                                       7,390[a]
PFC - 116 (Perfluoroethane)
                                                                    76 - 16 - 4
C2F6
                                                                      12,200[a]
PFC - 218 (Perfluoropropane)
                                                                    76 - 19 - 7
C3F8
                                                                       8,830[a]
Perfluorocyclopropane
                                                                   931 - 91 - 9
C-C3F6
                                                                         17,340
PFC - 3 - 1 - 10 (Perfluorobutane)
                                                                   355 - 25 - 9
C4F10
                                                                       8,860[a]
Perfluorocyclobutane
                                                                   115 - 25 - 3
C-C4F8
                                                                      10,300[a]
PFC - 4 - 1 - 12 (Perfluoropentane)
                                                                   678 - 26 - 2
C5F12
                                                                       9,160[a]
PFC - 5 - 1 - 14
(Perfluorohexane)
                                                                   355 - 42 - 0
C6F14
                                                                       9,300[a]
PFC - 9 - 1 - 18
                                                                   306 - 94 - 5
C10F18
                                                                          7,500
HCFE - 235da2 (Isoflurane)
                                                                 26675 - 46 - 7
CHF2OCHClCF3
                                                                            350
HFE - 43 - 10pccc (H - Galden 1040x)
                                                                       E1730133
CHF2OCF2OC2F4OCHF2
                                                                          1,870
HFE - 125
                                                                  3822 - 68 - 2
CHF2OCF3
                                                                         14,900
HFE - 134
                                                                  1691 - 17 - 4
CHF2OCHF2
                                                                          6,320
HFE - 143a
                                                                   421 - 14 - 7
CH3OCF3
                                                                            756
HFE - 227ea
                                                                  2356 - 62 - 9
CF3CHFOCF3
                                                                          1,540
HFE - 236ca12 (HG - 10)
                                                                 78522 - 47 - 1
CHF2OCF2OCHF2
                                                                          2,800
HFE - 236ea2 (Desflurane)
                                                                 57041 - 67 - 5
CHF2OCHFCF3
                                                                            989
HFE - 236fa
                                                                 20193 - 67 - 3
CF3CH2OCF3
                                                                            487
HFE - 245cb2
                                                                 22410 - 44 - 2
CH3OCF2CF3
                                                                            708
HFE - 245fa1
                                                                 84011 - 15 - 4
CHF2CH2OCF3
                                                                            286
HFE - 245fa2
                                                                  1885 - 48 - 9
CHF2OCH2CF3
                                                                            659
HFE - 254cb2
                                                                   425 - 88 - 7
CH3OCF2CHF2
                                                                            359
HFE - 263fb2
                                                                   460 - 43 - 5
CF3CH2OCH3
                                                                             11
HFE-329mcc2
67490-36-2
CF3CF2OCF2CHF2
                                                                            919
HFE - 338mcf2
                                                                156053 - 88 - 2
CF3CF2OCH2CF3
                                                                            552
HFE - 338pcc13 (HG - 01)
                                                                188690 - 78 - 0
CHF2OCF2CF2OCHF2
                                                                          1,500
HFE - 347mcc3
                                                                 28523 - 86 - 6
CH3OCF2CF2CF3
                                                                            575
HFE - 347mcf2
                                                                       E1730135
CF3CF2OCH2CHF2
                                                                            374
HFE - 347pcf2
                                                                   406 - 78 - 0
CHF2CF2OCH2CF3
                                                                            580
HFE - 356mec3
                                                                   382 - 34 - 3
CH3OCF2CHFCF3
                                                                            101
HFE - 356pcc3
                                                                160620 - 20 - 2
CH3OCF2CF2CHF2
                                                                            110
HFE - 356pcf2
                                                                       E1730137
CHF2CH2OCF2CHF2
                                                                            265
HFE - 356pcf3
                                                                 35042 - 99 - 0
CHF2OCH2CF2CHF2
                                                                            502
HFE - 365mcf3
                                                                   378 - 16 - 5
CF3CF2CH2OCH3
                                                                             11
HFE - 374pc2
                                                                   512 - 51 - 6
CH3CH2OCF2CHF2
                                                                            557
HFE - 449s1 (HFE - 7100)
Chemical blend
                                                163702 - 07 - 6
163702 - 08 - 7
C4F9OCH3
(CF3)2CFCF2OCH3
                                                                            297
HFE - 569sf2 (HFE - 7200)
Chemical blend
                                                163702 - 05 - 4
163702 - 06 - 5
C4F9OC2H5
(CF3)2CFCF2OC2H5
                                                                             59
Sevoflurane
                                                                 28523 - 86 - 6
CH2FOCH(CF3)2
                                                                            345
HFE - 356mm1
                                                                 13171 - 18 - 1
(CF3)2CHOCH3
                                                                             27
HFE - 338mmz1
                                                                 26103 - 08 - 2
CHF2OCH(CF3)2
                                                                            380
(Octafluorotetramethy-lene)hydroxymethyl group
                                                                             NA
X-(CF2)4CH(OH)-X
                                                                             73
HFE - 347mmy1
                                                                 22052 - 84 - 2
CH3OCF(CF3)2
                                                                            343
Bis(trifluoromethyl)-methanol
                                                                   920 - 66 - 1
(CF3)2CHOH
                                                                            195
2,2,3,3,3-pentafluoropropanol
                                                                   422 - 05 - 9
CF3CF2CH2OH
                                                                             42
PFPMIE
                                                                             NA
CF3OCF(CF3)CF2OCF2OCF3
                                                                         10,300
a The GWP for this compound is different than the GWP in the version of Table A-1 to subpart A of part 98 published on October 30, 2009.
NA  -  Not available

Table A - 2 to Subpart A of Part 98 -- Units of Measure Conversions
                                To convert from
                                      To
                                  Multiply by
Kilograms (kg)
Pounds (lbs)
2.20462
Pounds (lbs)
Kilograms (kg)
0.45359
Pounds (lbs)
Metric tons
4.53592 x 10−4
Short tons
Pounds (lbs)
2,000
Short tons
Metric tons
0.90718
Metric tons
Short tons
1.10231
Metric tons
Kilograms (kg)
1,000
Cubic meters (m3)
Cubic feet (ft3)
35.31467
Cubic feet (ft3)
Cubic meters (m3)
0.028317
Gallons (liquid, US)
Liters (l)
3.78541
Liters (l)
Gallons (liquid, US)
0.26417
Barrels of Liquid Fuel (bbl)
Cubic meters (m3)
0.15891
Cubic meters (m3)
Barrels of Liquid Fuel (bbl)
6.289
Barrels of Liquid Fuel (bbl)
Gallons (liquid, US)
42
Gallons (liquid, US)
Barrels of Liquid Fuel (bbl)
0.023810
Gallons (liquid, US)
Cubic meters (m3)
0.0037854
Liters (l)
Cubic meters (m3)
0.001
Feet (ft)
Meters (m)
0.3048
Meters (m)
Feet (ft)
3.28084
Miles (mi)
Kilometers (km)
1.60934
Kilometers (km)
Miles (mi)
0.62137
Square feet (ft2)
Acres
2.29568 x 10−5
Square meters (m2)
Acres
2.47105 x 10−4
Square miles (mi2)
Square kilometers (km2)
2.58999
Degrees Celsius (°C)
Degrees Fahrenheit (°F)
°C = (5/9) x (°F −32)
Degrees Fahrenheit (°F)
Degrees Celsius (°C)
°F = (9/5) x °C + 32
Degrees Celsius (°C)
Kelvin (K)
K = °C + 273.15
Kelvin (K)
Degrees Rankine (°R)
1.8
Joules
Btu
9.47817 x 10−4
Btu
MMBtu
1 x 10−6
Pascals (Pa)
Inches of Mercury (in Hg)
2.95334 x 10−4
Inches of Mercury (inHg)
Pounds per square inch (psi)
0.49110
Pounds per square inch (psi)
Inches of Mercury (in Hg)
2.03625

Table A - 3 to Subpart A -- Source Category List for §98.2(a)(1)
             Source CategoriesaApplicable in 2010 and Future Years
Electricity generation units that report CO2 mass emissions year round through 40 CFR part 75 (subpart D).
Adipic acid production (subpart E).
Aluminum production (subpart F).
Ammonia manufacturing (subpart G).
Cement production (subpart H).
HCFC - 22 production (subpart O).
HFC - 23 destruction processes that are not collocated with a HCFC - 22 production facility and that destroy more than 2.14 metric tons of HFC - 23 per year (subpart O).
Lime manufacturing (subpart S).
Nitric acid production (subpart V).
Petrochemical production (subpart X).
Petroleum refineries (subpart Y).
Phosphoric acid production (subpart Z).
Silicon carbide production (subpart BB).
Soda ash production (subpart CC).
Titanium dioxide production (subpart EE).
Municipal solid waste landfills that generate CH4 in amounts equivalent to 25,000 metric tons CO2e or more per year, as determined according to subpart HH of this part.
Manure management systems with combined CH4 and N2O emissions in amounts equivalent to 25,000 metric tons CO2e or more per year, as determined according to subpart JJ of this part.
       Additional Source CategoriesaApplicable in 2011 and Future Years
Electrical transmission and distribution equipment use at facilities where the total nameplate Capacity of SF6 and PFC containing equipment exceeds 17,820 pounds, as determined under §98.301 (subpart DD).
Underground coal mines liberating 36,500,000 actual cubic feet of CH4 or more per year (subpart FF).
        Geologic sequestration of carbon dioxide (subpart RR).
Electrical transmission and distribution equipment manufacture or refurbishment (subpart SS).
Injection of carbon dioxide (subpart UU).
aSource categories are defined in each applicable subpart.
Table A - 4 to Subpart A of Part 98 -- Source Category List for §98.2(a)(2)
             Source CategoriesaApplicable in 2010 and Future Years
Ferroalloy production (subpart K).
Glass production (subpart N).
Hydrogen production (subpart P).
Iron and steel production (subpart Q).
Lead production (subpart R).
Pulp and paper manufacturing (subpart AA).
Zinc production (subpart GG).
       Additional Source CategoriesaApplicable in 2011 and Future Years
        Electronics manufacturing (subpart I)
        Fluorinated gas production (subpart L)
Magnesium production (subpart T).
Petroleum and Natural Gas Systems (subpart W)
Industrial wastewater treatment (subpart II).
Industrial waste landfills (subpart TT).
[a]Source categories are defined in each applicable subpart.
Table A - 5 to Subpart A of Part 98 -- Supplier Category List for §98.2(a)(4)
            Supplier CategoriesaApplicable in 2010 and Future Years
Coal-to-liquids suppliers (subpart LL):
(A) All producers of coal-to-liquid products.
(B) Importers of an annual quantity of coal-to-liquid products that is equivalent to 25,000 metric tons CO2e or more.
(C) Exporters of an annual quantity of coal-to-liquid products that is equivalent to 25,000 metric tons CO2e or more.
Petroleum product suppliers (subpart MM):
(A) All petroleum refineries that distill crude oil.
(B) Importers of an annual quantity of petroleum products and natural gas liquids that is equivalent to 25,000 metric tons CO2e or more.
(C) Exporters of an annual quantity of petroleum products and natural gas liquids that is equivalent to 25,000 metric tons CO2e or more.
Natural gas and natural gas liquids suppliers (subpart NN):
(A) All fractionators.
(B) Local natural gas distribution companies that deliver 460,000 thousand standard cubic feet or more of natural gas per year.
Industrial greenhouse gas suppliers (subpart OO):
(A) All producers of industrial greenhouse gases.
(B) Importers of industrial greenhouse gases with annual bulk imports of N2O, fluorinated GHG, and CO2 that in combination are equivalent to 25,000 metric tons CO2e or more.
(C) Exporters of industrial greenhouse gases with annual bulk exports of N2O, fluorinated GHG, and CO2 that in combination are equivalent to 25,000 metric tons CO2e or more.
Carbon dioxide suppliers (subpart PP):
(A) All producers of CO2.
(B) Importers of CO2 with annual bulk imports of N2O, fluorinated GHG, and CO2 that in combination are equivalent to 25,000 metric tons CO2e or more.
(C) Exporters of CO2 with annual bulk exports of N2O, fluorinated GHG, and CO2 that in combination are equivalent to 25,000 metric tons CO2e or more.
      Additional Supplier Categories Applicableain 2011 and Future Years
      Importers and exporters of fluorinated greenhouse gases contained in pre-charged equipment or closed-cell foams (subpart QQ):
(A) Importers of an annual quantity of fluorinated greenhouse gases contained in pre-charged equipment or closed-cell foams that is equivalent to 25,000 metric tons CO2e or more.
(B) Exporters of an annual quantity of fluorinated greenhouse gases contained in pre-charged equipment or closed-cell foams that is equivalent to 25,000 metric tons CO2e or more.
[a]Suppliers are defined in each applicable subpart.
Table A - 6 to Subpart A of Part 98 -- Data Elements That Are Inputs to Emission Equations and for Which the Reporting Deadline Is March 31, 2013
                                    Subpart
                        Rule citation
(40 CFR part 98)
Specific data elements for which reporting date is March 31, 2013 ("All" means all data elements in the cited paragraph are not required to be reported until March 31, 2013)
C
98.36(d)(1)(iv)
All.
C
98.36(d)(2)(ii)(G)
All.
C
98.36(d)(2)(iii)(G)
All.
C
98.36(e)(2)(iv)(G)
All.
C
98.36(e)(2)(viii)(A)
All.
C
98.36(e)(2)(viii)(B)
All.
C
98.36(e)(2)(viii)(C)
All.
C
98.36(e)(2)(x)(A)
All.
C
98.36(e)(2)(xi)
All.
DD
98.306(a)(2)
All.
DD
98.306(a)(3)
All.
DD
98.306(d)
All.
DD
98.306(e)
All.
DD
98.306(f)
All.
DD
98.306(g)
All.
DD
98.306(h)
All.
DD
98.306(i)
All.
DD
98.306(j)
All.
DD
98.306(k)
All.
DD
98.306(l)
All.
FF
98.326(a)
All.
FF
98.326(b)
All.
FF
98.326(c)
All.
FF
98.326(f)
Only quarterly volumetric flow rate.
FF
98.326(g)
Only quarterly CH4 concentration.
FF
98.326(h)
Only weekly volumetric flow used to calculate CH4 liberated from degasification systems.
FF
98.326(j)
All.
FF
98.326(k)
All.
FF
98.326(o)
All.
FF
98.326(p)
Only assumed destruction efficiency for the primary destruction device and assumed destruction efficiency for the backup destruction device.
HH
98.346(a)
Only year in which landfill first accepted waste, last year the landfill accepted waste (if used as an input in Equation HH - 3), capacity of the landfill (if used as an input in Equation HH - 3), and waste disposal quantity for each year of landfilling.
HH
98.346(b)
Only quantity of waste determined using the methods in §98.343(a)(3)(i), quantity of waste determined using the methods in §98.343(a)(3)(ii), population served by the landfill for each year, and the value of landfill capacity (LFC) used in the calculation.
HH
98.346(c)
All.
HH
98.346(d)(1)
Only degradable organic carbon (DOC) value, and fraction of DOC dissimilated (DOCF) values.
HH
98.346(d)(2)
All.
HH
98.346(e)
Only fraction of CH4 in landfill gas and methane correction factor (MCF) values.
HH
98.346(f)
Only surface area associated with each cover type.
HH
98.346(g)
All.
HH
98.346(i)(5)
Only annual operating hours for the destruction devices located at the landfill facility, and the destruction efficiency for the destruction devices associated with that measurement location.
HH
98.346(i)(6)
All.
HH
98.346(i)(7)
Only surface area specified in Table HH - 3, estimated gas collection system efficiency, and annual operating hours of the gas collection system for each measurement location.
HH
98.346(i)(9)
Only CH4 generation value.
II
98.356(b)(1)
All.
II
98.356(b)(2)
All.
II
98.356(b)(3)
All.
II
98.356(b)(4)
All.
II
98.356(b)(5)
All.
II
98.356(d)(1)
All.
II
98.356(d)(7)
All.
II
98.356(d)(8)
Only annual operating hours for the primary destruction device, annual operating hours for the backup destruction device, destruction efficiency of the primary destruction device, and destruction efficiency of the backup destruction device.
SS
98.456(a)
All.
SS
98.456(b)
All.
SS
98.456(c)
All.
SS
98.456(d)
All.
SS
98.456(e)
All.
SS
98.456(f)
All.
SS
98.456(g)
All.
SS
98.456(h)
All.
SS
98.456(i)
All.
SS
98.456(j)
All.
SS
98.456(m)
All.
SS
98.456(n)
All.
SS
98.456(o)
All.
SS
98.456(q)
All.
SS
98.456(r)
All.
SS
98.456(s)
All.
SS
98.456(t)
Only for any missing data the substitute parameters used to estimate emissions in their absence.
TT
98.466(a)(2)
All.
TT
98.466(a)(3)
Only last year the landfill accepted waste (for closed landfills using Equation TT - 4).
TT
98.466(a)(4)
Only capacity of the landfill in metric tons (for closed landfills using Equation TT - 4).
TT
98.466(b)(3)
Only fraction of CH4 in landfill gas
TT
98.466(b)(4)
Only the methane correction factor (MCF) value used in the calculations

TT
98.466(c)(4)(i)
All.
TT
98.466(c)(4)(ii)
All.
TT
98.466(c)(4)(iii)
All.
TT
98.466(d)(2)
All.
TT
98.466(d)(3)
Only degradable organic carbon (DOCx) value for each waste stream used in calculations.
TT
98.466(e)(2)
Only surface area (in square meters) at the start of the reporting year for the landfill sections that contain waste and that are associated with the selected cover type (for facilities using a landfill gas collection system).
TT
98.466(f)
All.

Table A - 7 to Subpart A of Part 98 -- Data Elements That Are Inputs to Emission Equations and for Which the Reporting Deadline Is March 31, 2015
                                    Subpart
                        Rule citation
(40 CFR part 98)
Specific data elements for which reporting date is March 31, 2015 ("All" means all data elements in the cited paragraph are not required to be reported until March 31, 2015)
A
98.3(d)(3)(v)
All.
C
98.36(b)(9)(iii)
Only estimate of the heat input.
C
98.36(c)(2)(ix)
Only estimate of the heat input from each type of fuel listed in Table C - 2.
C
98.36(e)(2)(i)
All.
C
98.36(e)(2)(ii)(A)
All.
C
98.36(e)(2)(ii)(C)
Only HHV value for each calendar month in which HHV determination is required.
C
98.36(e)(2)(ii)(D)
All.
C
98.36(e)(2)(iv)(A)
All.
C
98.36(e)(2)(iv)(C)
All.
C
98.36(e)(2)(iv)(F)
All.
C
98.36(e)(2)(ix)(D)
All.
C
98.36(e)(2)(ix)(E)
All.
C
98.36(e)(2)(ix)(F)
All.
E
98.56(b)
All.
E
98.56(c)
All.
E
98.56(g)
All.
E
98.56(h)
All.
E
98.56(j)(1)
All.
E
98.56(j)(3)
All.
E
98.56(j)(4)
All.
E
98.56(j)(5)
All.
E
98.56(j)(6)
All.
E
98.56(l)
All.
F
98.66(a)
All.
F
98.66(c)(2)
All.
F
98.66(c)(3)
Only smelter-specific slope coefficients and overvoltage emission factors.
F
98.66(e)(1)
Only annual anode consumption (No CEMS).
F
98.66(f)(1)
Only annual paste consumption (No CEMS).
F
98.66(g)
All.
G
98.76(b)(2)
All.
G
98.76(b)(7)
All.
G
98.76(b)(8)
All.
G
98.76(b)(9)
All.
G
98.76(b)(10)
All.
G
98.76(b)(11)
All.
H
98.86(b)(2)
All.
H
98.86(b)(5)
All.
H
98.86(b)(6)
All.
H
98.86(b)(8)
All.
H
98.86(b)(10)
All.
H
98.86(b)(11)
All.
H
98.86(b)(12)
All.
H
98.86(b)(13)
All.
H
98.86(b)(15)
Only monthly kiln-specific clinker factors (if used) for each kiln.
I
98.96(f)(1)
All.
I
98.96(g)
Only annual consumption of the gas (excluding annual consumption of gases for which the reporter did not calculate emissions using Equations I - 6, I - 7, I - 8, I - 9, and I - 10 of subpart L).
I
98.96(h)
All.
I
98.96(i)
All.
I
98.96(j)
All.
I
98.96(k)
All.
I
98.96(l)
All.
I
98.96(n)
All.
I
98.96(o)
All.
I
98.96(q)(2)
Only inputs and results of calculations made accounting for the uptime of abatement systems used during the reporting year.
I
98.96(q)(3)
All.
I
98.96(q)(5)(iv)
Only inputs used to calculate the class average.
I
98.96(r)
All.
I
98.96(s)
Only estimates of inputs into the heat transfer fluid mass balance equation.
K
98.116(b)
Only annual production by product from each EAF (No CEMS).
K
98.116(e)(4)
All.
K
98.116(e)(5)
All.
L
98.126(b)(1)
Only data used in calculating the absolute errors and data used in calculating the relative errors.
L
98.126(b)(2)
All.
L
98.126(b)(6)
Only mass of each fluorine-containing reactant fed into the process.
L
98.126(b)(7)
Only mass of each fluorine-containing product produced by the process.
L
98.126(b)(8)(i)
Only mass of each fluorine-containing product that is removed from the process and fed into the destruction device.
L
98.126(b)(8)(ii)
Only mass of each fluorine-containing by-product that is removed from the process and fed into the destruction device.
L
98.126(b)(8)(iii)
Only mass of each fluorine-containing reactant that is removed from the process and fed into the destruction device.
L
98.126(b)(8)(iv)
Only mass of each fluorine-containing by-product that is removed from the process and recaptured.
L
98.126(b)(8)(v)
All.
L
98.126(b)(9)(i)
All.
L
98.126(b)(9)(ii)
All.
L
98.126(b)(9)(iii)
All.
L
98.126(b)(10)
All.
L
98.126(b)(11)
All.
L
98.126(b)(12)
All.
L
98.126(c)(1)
Only quantity of the process activity used to estimate emissions.
L
98.126(c)(2)
All.
L
98.126(d)
Only estimate of missing data.
L
98.126(f)(1)
All.
L
98.126(g)(1)
All.
L
98.126(h)(2)
All.
N
98.146(b)(2)
Only annual quantity of carbonate based-raw material charged to each continuous glass melting furnace.
N
98.146(b)(4)
All.
N
98.146(b)(6)
All.
O
98.156(a)(2)
All.
O
98.156(a)(7)
All.
O
98.156(a)(8)
All.
O
98.156(a)(9)
All.
O
98.156(a)(10)
All.
O
98.156(b)(1)
All.
O
98.156(b)(2)
All.
O
98.156(d)(1)
All.
O
98.156(d)(2)
All.
O
98.156(d)(3)
All.
O
98.156(d)(4)
All.
O
98.156(d)(5)
All.
O
98.156(e)(1)
All.
P
98.166(b)(2)
All.
P
98.166(b)(5)
All.
P
98.166(b)(6)
All.
Q
98.176(b)
Only annual quantity taconite pellets, coke, iron, and raw steel (No CEMS).
Q
98.176(e)(1)
All.
Q
98.176(e)(3)
All.
Q
98.176(e)(4)
All.
Q
98.176(f)(1)
All.
Q
98.176(f)(2)
All.
Q
98.176(f)(3)
All.
Q
98.176(f)(4)
All.
Q
98.176(g)
All.
R
98.186(b)(6)
All.
R
98.186(b)(7)
All.
S
98.196(b)(2)
All.
S
98.196(b)(3)
All.
S
98.196(b)(5)
All.
S
98.196(b)(6)
All.
S
98.196(b)(8)
All.
S
98.196(b)(10)
All.
S
98.196(b)(11)
All.
S
98.196(b)(12)
All.
U
98.216(b)
All.
U
98.216(e)(1)
All.
U
98.216(e)(2)
All.
U
98.216(f)(1)
All.
U
98.216(f)(2)
All.
V
98.226(c)
All.
V
98.226(d)
All.
V
98.226(i)
All.
V
98.226(j)
All.
V
98.226(m)(1)
All.
V
98.226(m)(3)
All.
V
98.226(m)(4)
All.
V
98.226(m)(5)
All.
V
98.226(m)(6)
All.
V
98.226(p)
All.
W
98.236(c)(1)(i)
All.
W
98.236(c)(1)(ii)
All.
W
98.236(c)(1)(iii)
All.
W
98.236(c)(2)(i)
All.
W
98.236(c)(3)(i)
All.
W
98.236(c)(3)(ii)
Only Calculation Methodology 2
W
98.236(c)(3)(iii)
All.
W
98.236(c)(3)(iv)
All.
W
98.236(c)(4)(i)(A)
All.
W
98.236(c)(4)(i)(B)
All.
W
98.236(c)(4)(i)(C)
All.
W
98.236(c)(4)(i)(D)
All.
W
98.236(c)(4)(i)(E)
All.
W
98.236(c)(4)(i)(F)
All.
W
98.236(c)(4)(i)(G)
All.
W
98.236(c)(4)(i)(H)
All.
W
98.236(c)(4)(ii)(A)
All.
W
98.236(c)(5)(i)(D)
All.
W
98.236(c)(5)(ii)(C)
All.
W
98.236(c)(6)(i)(B)
All.
W
98.236(c)(6)(i)(D)
All.
W
98.236(c)(6)(i)(E)
All.
W
98.236(c)(6)(i)(F)
All.
W
98.236(c)(6)(i)(G)
Only the amount of natural gas required.
W
98.236(c)(6)(i)(H)
Only the amount of natural gas required.
W
98.236(c)(6)(ii)(A)
All.
W
98.236(c)(6)(ii)(B)
All.
W
98.236(c)(7)(i)(A)
Only for Equation W-14A.
W
98.236(c)(8)(i)(F)
All.
W
98.236(c)(8)(i)(K)
All.
W
98.236(c)(8)(ii)(A)
All.
W
98.236(c)(8)(ii)(H)
All.
W
98.236(c)(8)(iii)(A)
All.
W
98.236(c)(8)(iii)(B)
All.
W
98.236(c)(8)(iii)(G)
All.
W
98.236(c)(12)(ii)
All.
W
98.236(c)(12)(v)
All.
W
98.236(c)(13)(i)(E)
All.
W
98.236(c)(13)(i)(F)
All.
W
98.236(c)(13)(ii)(A)
All.
W
98.236(c)(13)(ii)(B)
All.
W
98.236(c)(13)(iii)(A)
All.
W
98.236(c)(13)(iii)(B)
All.
W
98.236(c)(13)(v)(A)
All.
W
98.236(c)(14)(i)(B)
All.
W
98.236(c)(14)(ii)(A)
All.
W
98.236(c)(14)(ii)(B)
All.
W
98.236(c)(14)(iii)(A)
All.
W
98.236(c)(14)(iii)(B)
All.
W
98.236(c)(14)(v)(A)
All.
W
98.236(c)(15)(ii)(A)
All.
W
98.236(c)(15)(ii)(B)
All.
W
98.236(c)(16)(vii)
All.
W
98.236(c)(16)(viii)
All.
W
98.236(c)(16)(ix)
All.
W
98.236(c)(16)(x)
All.
W
98.236(c)(16)(xi)
All.
W
98.236(c)(16)(xii)
All.
W
98.236(c)(16)(xiii)
All.
W
98.236(c)(16)(xiv)
All.
W
98.236(c)(16)(xv)
All.
W
98.236(c)(16)(xvi)
All.
W
98.236(c)(17)(ii)
All.
W
98.236(c)(17)(iii)
All.
W
98.236(c)(17)(iv)
All.
W
98.236(c)(18)(i)
All.
W
98.236(c)(18)(ii)
All.
W
98.236(c)(19)(iv)
All.
W
98.236(c)(19)(vii)
All.
X
98.246(a)(4)
Only monthly volume values, monthly mass values, monthly carbon content values, molecular weights for gaseous feedstocks, molecular weights for gaseous products, and indication of whether the alternative method in §98.243(c)(4) was used.
X
98.246(b)(5)(iii)
All.
X
98.246(b)(5)(iv)
All.
Y
98.256(e)(6)
Only molar volume conversion factor for each flare.
Y
98.256(e)(7)
Only molar volume conversion factor for each flare.
Y
98.256(e)(7)(ii)
All.
Y
98.256(e)(9)
Only annual volume of flare gas combusted, annual average higher heating value of the flare gas, volume of gas flared, average molecular weight, carbon content of the flare, and molar volume conversion factor if using Eq. Y - 3.
Y
98.256(e)(10)
Only fraction of carbon in the flare gas contributed by methane.
Y
98.256(f)(7)
Only molar volume conversion factor.
Y
98.256(f)(10)
Only coke burn-off factor, annual throughput of unit, and average carbon content of coke.
Y
98.256(f)(11)
Only units of measure for the unit-specific CH4 emission factor, activity data for calculating emissions, and unit-specific emission factor for CH4.
Y
98.256(f)(12)
Only unit-specific emission factor for N2O, units of measure for the unit-specific N2O emission factor, and activity data for calculating emissions.
Y
98.256(f)(13)
Only average carbon content of coke.
Y
98.256(h)(4)
All.
Y
98.256(h)(5)
Only value of the correction, annual volume of recycled tail gas (if used to calculate recycling correction factor), and annual average mole fraction of carbon in the tail gas (if used to calculate recycling correction factor).
Y
98.256(i)(5)
Only annual mass of green coke fed, carbon content of green coke fed, annual mass of marketable coke produced, carbon content of marketable coke produced, and annual mass of coke dust removed from the process.
Y
98.256(i)(7)
Only the unit-specific CH4 emission factor, units of measure for unit-specific CH4 emission factor, and activity data for calculating emissions.
Y
98.256(i)(8)
Only units of measure for the unit-specific factor, activity data used for calculating emissions, and site-specific emissions factor.
Y
98.256(j)(2)
All.
Y
98.256(j)(5)
Only CO2 emission factor.
Y
98.256(j)(6)
Only CH4 emission factor.
Y
98.256(j)(7)
Only carbon emission factor.
Y
98.256(j)(8)
Only CO2 emission factor and carbon emission factor.
Y
98.256(j)(9)
Only CH4 emission factor.
Y
98.256(k)(3)
Only dimensions of coke drum or vessel, typical gauge pressure of the coking drum, typical void fraction of coke drum or vessel, annual number of coke-cutting cycles of coke drum or vessel, and molar volume conversion factor for each coke drum or vessel.
Y
98.256(k)(4)
Only height and diameter of the coke drums, cumulative number of vessel openings for all delayed coking drums, typical venting pressure, void fraction, mole fraction of methane in coking gas.
Y
98.256(l)(5)
Only molar volume conversion factor.
Y
98.256(m)(3)
Only total quantity of crude oil plus the quantity of intermediate products received from off-site, CH4 emission factor used, and molar volume conversion factor.
Y
98.256(n)(3)
All (if used in Equation Y - 21 to calculate emissions from equipment leaks).
Y
98.256(o)(2)(ii)
All.
Y
98.256(o)(4)(ii)
All.
Y
98.256(o)(4)(iii)
All.
Y
98.256(o)(4)(iv)
All.
Y
98.256(o)(4)(v)
All.
Y
98.256(o)(4)(vi)
Only tank-specific methane composition data and annual gas generation volume.

Y
98.256(p)(2)
Only quantity of materials loaded that have an equilibrium vapor-phase concentration of CH4 of 0.5 volume percent or greater.
Z
98.266(f)(5)
All.
Z
98.266(f)(6)
All.
AA
98.276(b)
All.
AA
98.276(c)
Only annual mass of the spent liquor solids combusted.
AA
98.276(d)
All.
AA
98.276(e)
All.
AA
98.276(f)
All.
AA
98.276(g)
All.
AA
98.276(h)
All.
AA
98.276(i)
All.
BB
98.286(b)(1)
All.
BB
98.286(b)(4)
All.
BB
98.286(b)(6)
All.
CC
98.296(b)(5)
Only monthly consumption of trona or liquid alkaline feedstock (for facilities using Equation CC - 1).
CC
98.296(b)(6)
Only monthly production of soda ash for each manufacturing line(for facilities using Equation CC - 2).
CC
98.296(b)(7)
All.
CC
98.296(b)(10)(i)
All.
CC
98.296(b)(10)(ii)
All.
CC
98.296(b)(10)(iii)
All.
CC
98.296(b)(10)(iv)
All.
CC
98.296(b)(10)(v)
All.
CC
98.296(b)(10)(vi)
All.
EE
98.316(b)(6)
All.
EE
98.316(b)(9)
All.
GG
98.336(b)(6)
All.
GG
98.336(b)(7)
All.
GG
98.336(b)(10)
All.
II
98.356(d)(2)
All (if conducting weekly sampling).
II
98.356(d)(3)
All (if conducting weekly sampling).
II
98.356(d)(4)
Only weekly average temperature (if conducting weekly sampling).
II
98.356(d)(5)
Only weekly average moisture content (if conducting weekly sampling).
II
98.356(d)(6)
Only weekly average pressure (if conducting weekly sampling).
TT
98.466(c)(3)(i)
All.
TT
98.466(c)(3)(ii)
Only waste disposal quantity and production quantity.
TT
98.466(c)(3)(iii)
All.