PART 98
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.  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.
§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 CO2e 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.
		(Eq. A-1)
Where:  
CO2e 	=	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 CO2e/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 quantities 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 and natural gas liquids 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 combined 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 quantities 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, GHG information required by the subparts listed in paragraphs (b)(1)(i) through (b)(1)(xii) of this section must be submitted no later than September 28, 2012.  This reporting date applies only to the data reporting requirements identified in the listed subparts and does not affect data reporting requirements of other subparts that apply to a facility or supplier.  
      (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) Imports and Exports of Equipment Pre - charged with Fluorinated GHGs or Containing Fluorinated GHGs in Closed - cell Foams (subpart QQ). 
      (ix) Geologic Sequestration of Carbon Dioxide (subpart RR). 
      (x) Manufacture of Electric Transmission and Distribution (subpart SS). 
      (xi) Industrial Waste Landfills (subpart TT).
      (xii) Injection of Carbon Dioxide (Subpart UU).
 

(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.
(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, and each fluorinated GHG (as defined in § 98.6) 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.
(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 (including those not listed in Table A-1 of this subpart).
 (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) 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. 
	(vii) The owner or operator of a facility is not required to report the data elements specified in Table A - 6 of this subpart for calendar year 2010 until September 30, 2011.
(viii) When applying paragraph (c)(4)(i) of this section to fluorinated GHGs, calculate and report CO2e for only those fluorinated GHGs listed in Table A - 1 of this subpart. 
	(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 of 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 facility or supplier'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 and do not report physical address or percent ownership.
 (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 nonparty 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).
(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 March 31, 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 CO2e. 
(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 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, at least two business days prior to the expiration of the 45-day period, and the Administrator does not respond to the request by the end of such period, the extension request is deemed to be automatically granted for 30 more days. During the automatic 30-day extension, the Administrator will determine what extension, if any, beyond the automatic extension is reasonable and will provide any such additional extension.
(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 CO2mass 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, ft[3] /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 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. 
§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.  Emissions from emergency events are not included. 


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 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 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 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 gas to the process measurement 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 and collect it at a common point, such as a vacuum pumping station. This includes all degasification wells and gob gas vent holes at the underground coal mine. Degasification systems include pre-mining, horizontal pre-mining, and post-mining systems.
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:
 
		(Eq. A-2)
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.
Fossil fuel-fired means powered by combustion of fossil fuel, alone or in combination with any other fuel, regardless of the percentage of fossil fuel consumed.
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 maintaining a process condition such as liquid level, pressure, delta-pressure and temperature. These are snap-acting or throttling devices that discharge 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.
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, 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 well or shaft means a well 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. This includes all ventilation shafts and wells at the underground coal mine.
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 the Federal 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), PO 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, 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, D.C. 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) The following material is available from the International SEMATECH Manufacturing Initiative, 2706 Montopolis Drive, Austin, Texas 78741, (512) 356-3500, 
http://ismi.sematech.org
(1) Guideline for Environmental Characterization of Semiconductor Process Equipment, International SEMATECH Manufacturing Initiative Technology Transfer #06124825A-ENG, December 22, 2006 (International SEMATECH #06124825A-ENG), IBR approved for §98.94(d), §98.94(d)(1), §98.94(e), §98.94(e)(1), §98.94(g)(1), §98.96(f)(4), and §98.97(b)(1). 
(2) Guidelines for Environmental Characterization of Semiconductor Equipment, International SEMATECH Technology Transfer #01104197A-XFR, December 4, 2001 (International SEMATECH #01104197A-XFR), IBR approved for §98.94(d), §98.94(d)(1), §98.94(e), §98.94(e)(1), §98.94(g)(2), §98.96(f)(4), and §98.97(b)(1).
(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, other than submittal of the annual GHG report; the certificate of representation; and other requests, notifications or communications that can be submitted through the electronic greenhouse gas reporting tool, 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 of Subpart A -- Global Warming Potentials (100-Year Time Horizon)
                                     Name
                                     CAS #
                               Chemical formula
                      Global warming potential (100 yr.)
Carbon dioxide
124-38-9
CO2
                                                                              1
Methane
74-82-8
CH4
                                                                             21
Nitrous oxide
10024-97-2
N2O
                                                                            310
HFC-23
75-46-7
CHF3
                                                                         11,700
HFC-32
75-10-5
CH2F2
                                                                            650
HFC-41
593-53-3
CH3F
                                                                            150
HFC-125
354-33-6
C2HF5
                                                                          2,800
HFC-134
359-35-3
C2H2F4
                                                                          1,000
HFC-134a
811-97-2
CH2FCF3
                                                                          1,300
HFC-143
430-66-0
C2H3F3
                                                                            300
HFC-143a
420-46-2
C2H3F3
                                                                          3,800
HFC-152
624-72-6
CH2FCH2F
                                                                             53
HFC-152a
75-37-6
CH3CHF2
                                                                            140
HFC-161
353-36-6
CH3CH2F
                                                                             12
HFC-227ea
431-89-0
C3HF7
                                                                          2,900
HFC-236cb
677-56-5
CH2FCF2CF3
                                                                          1,340
HFC-236ea
431-63-0
CHF2CHFCF3
                                                                          1,370
HFC-236fa
690-39-1
C3H2F6
                                                                          6,300
HFC-245ca
679-86-7
C3H3F5
                                                                            560
HFC-245fa
460-73-1
CHF2CH2CF3
                                                                          1,030
HFC-365mfc
406-58-6
CH3CF2CH2CF3
                                                                            794
HFC-43-10mee
138495-42-8
CF3CFHCFHCF2CF3
                                                                          1,300
Sulfur hexafluoride
2551-62-4
SF6
                                                                         23,900
Trifluoromethyl sulphur pentafluoride
373-80-8
SF5CF3
                                                                         17,700
Nitrogen trifluoride
7783-54-2
NF3
                                                                         17,200
PFC-14 (Perfluoromethane)
75-73-0
CF4
                                                                          6,500
PFC-116 (Perfluoroethane)
76-16-4
C2F6
                                                                          9,200
PFC-218 (Perfluoropropane)
76-19-7
C3F8
                                                                          7,000
Perfluorocyclopropane
931-91-9
c-C3F6
                                                                         17,340
PFC-3-1-10 (Perfluorobutane)
355-25-9
C4F10
                                                                          7,000
Perfluorocyclobutane
115-25-3
c-C4F8
                                                                          8,700
PFC-4-1-12 (Perfluoropentane)
678-26-2
C5F12
                                                                          7,500
PFC-5-1-14
(Perfluorohexane)
355-42-0
C6F14
                                                                          7,400
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-449sl (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
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 (m[3])
Cubic feet (ft[3])
35.31467
Cubic feet (ft[3])
Cubic meters (m[3])
0.028317
Gallons (liquid, US)
Liters (l)
3.78541
Liters (l)
Gallons (liquid, US)
0.26417
Barrels of Liquid Fuel (bbl)
Cubic meters (m[3])
0.15891
Cubic meters (m[3])
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 (m[3])
0.0037854
Liters (l)
Cubic meters (m[3])
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 (ft[2])
Acres
2.29568 x 10[-5]
Square meters (m[2])
Acres
2.47105 x 10[-4]
Square miles (mi[2])
Square kilometers (km[2])
2.58999
Degrees Celsius (ºC)
Degrees Fahrenheit (ºF)
ºC = (5/9) x ( ºF-32)
Degrees Fahrenheit (ºF)
Degrees Celsius (ºC)
ºF = (9/5) x ºC + 32
Degrees Celsius (ºC)
Kelvin (K)
K = ºC + 273.15
Kelvin (K)
Degrees Rankine (ºR)
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 of Subpart A of Part 98 -- Source Category List for §98.2(a)(1)
              Source Categories[a] Applicable 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 Categories[a] Applicable 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. 
      Electrical transmission and distribution equipment manufacture or refurbishment (subpart SS). 
      Injection of carbon dioxide	(subpart UU).
a  Source 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 Categories[a] Applicable 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 Categories[a] Applicable 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 Categoriesa Applicable 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[a] Applicable in 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 -- DATA ELEMENTS THAT ARE INPUTS TO EMISSION EQUATIONS AND FOR WHICH THE
REPORTING DEADLINE IS CHANGED TO AUGUST 31, 2011

Subpart
Rule Citation (40 CFR part 98)
Specific Data Elements for Which Reporting Date is Changed ("All" means that the date is changed for all data elements in the cited paragraph)
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(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)(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)(iv)(G)
All.
C
98.36(e)(2)(vi)(C)
Only stack gas flow rate and moisture content.
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)(ix)(D)
All.
C
98.36(e)(2)(ix)(E)
All.
C
98.36(e)(2)(ix)(F)
All.
C
98.36(e)(2)(x)(A)
All.
C
98.36(e)(2)(xi)
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.
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.
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.
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 CH4emission 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 coke burn-off quantity per cycle or measurement period, and 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, 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 CH4emission factor, units of measure for unit-specific CH4emission 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 CO2emission factor.
Y
98.256(j)(6)
Only CH4emission factor.
Y
98.256(j)(7)
Only carbon emission factor.
Y
98.256(j)(8)
Only CO2emission factor and carbon emission factor.
Y
98.256(j)(9)
Only CH4emission 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, CH4emission 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 gas generation rate data.
Y
98.256(p)(2)
Only quantity of materials loaded that have an equilibrium vapor-phase concentration of CH4of 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.
CC
98.296(b)(10)(vii)
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.
HH
98.346(a)
Only year in which landfill first accepted waste, last year the landfill accepted waste, capacity of the landfill, 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, methane correction factor (MCF) values, and fraction of DOC dissimilated (DOCF) values.
HH
98.346(d)(2)
All.
HH
98.346(e)
Only fraction of CH4in landfill gas.
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 primary destruction device, annual operating hours for the backup destruction device, destruction efficiency for the primary destruction device, and destruction efficiency for the backup destruction device.
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.
HH
98.346(i)(9)
Only CH4generation value.


Subpart W -- Petroleum and Natural Gas Systems
§98.230  Definition of the source category. 
(a)  This source category consists of the following industry segments:
(1)  Offshore petroleum and natural gas production.  Offshore petroleum and natural gas production is any platform structure, affixed temporarily or permanently to offshore submerged lands, that houses equipment to extract hydrocarbons from the ocean or lake floor and that processes and/or transfers such hydrocarbons to storage, transport vessels, or onshore.  In addition, offshore production includes secondary platform structures connected to the platform structure via walkways, storage tanks associated with the platform structure and floating production and storage offloading equipment (FPSO).  This source category does not include reporting of emissions from offshore drilling and exploration that is not conducted on production platforms.
(2)  Onshore petroleum and natural gas production. Onshore petroleum and natural gas production  means all equipment on a well pad or associated with a well pad (including compressors, generators, or storage facilities), and portable non-self-propelled equipment on a well pad or associated with a well pad (including well drilling and completion equipment, workover equipment, gravity separation equipment, auxiliary non-transportation-related equipment, and leased, rented or contracted equipment) used in the production, extraction, recovery, lifting, stabilization, separation or treating of petroleum and/or natural gas (including condensate).  This equipment also includes associated storage or measurement vessels and all enhanced oil recovery (EOR) operations using CO2, and all petroleum and natural gas production located on islands, artificial islands, or structures connected by a causeway to land, an island, or artificial island.  
(3)  Onshore natural gas processing.  Natural gas processing separates and recovers natural gas liquids (NGLs) and/or other non-methane gases and liquids from a stream of produced natural gas using equipment performing one or more of the following processes:  oil and condensate removal, water removal, separation of natural gas liquids, sulfur and carbon dioxide removal, fractionation of NGLs, or other processes, and also the capture of CO2 separated from natural gas streams.  This segment also includes all residue gas compression equipment owned or operated by the natural gas processing facility, whether inside or outside the processing facility fence.  This source category does not include reporting of emissions from gathering lines and boosting stations. This source category includes: 
(i) All processing facilities that fractionate.
(ii)  All processing facilities that do not fractionate with annual average throughput of 25 MMscf per day or greater. 
(4)  Onshore natural gas transmission compression. Onshore natural gas transmission compression means any stationary combination of compressors that move natural gas at elevated pressure from production fields or natural gas processing facilities in transmission pipelines to natural gas distribution pipelines or into storage.  In addition, transmission compressor station may include equipment for liquids separation, natural gas dehydration, and tanks for the storage of water and hydrocarbon liquids.  Residue (sales) gas compression operated by natural gas processing facilities are included in the onshore natural gas processing segment and are excluded from this segment.    This source category also does not include reporting of emissions from gathering lines and boosting stations  -  these sources are currently not covered by subpart W.
(5)  Underground natural gas storage.  Underground natural gas storage means subsurface storage, including depleted gas or oil reservoirs and salt dome caverns that store natural gas that has been transferred from its original location for the primary purpose of load balancing (the process of equalizing the receipt and delivery of natural gas); natural gas underground storage processes and operations (including compression, dehydration and flow measurement, and excluding transmission pipelines); and all the wellheads connected to the compression units located at the facility that inject and recover natural gas into and from the underground reservoirs.
(6)  Liquefied natural gas (LNG) storage.  LNG storage means onshore LNG storage vessels located above ground, equipment for liquefying natural gas, compressors to capture and re-liquefy boil-off-gas, re-condensers, and vaporization units for re-gasification of the liquefied natural gas.
(7)  LNG import and export equipment.  LNG import equipment means all onshore or offshore equipment that receives imported LNG via ocean transport, stores LNG, re-gasifies LNG, and delivers re-gasified natural gas to a natural gas transmission or distribution system.  LNG export equipment means all onshore or offshore equipment that receives natural gas, liquefies natural gas, stores LNG, and transfers the LNG via ocean transportation to any location, including locations in the United States.
(8)  Natural gas distribution.  Natural gas distribution means the distribution pipelines (not interstate transmission pipelines or intrastate transmission pipelines) and metering and regulating equipment at city gate stations, and excluding customer meters, that physically deliver natural gas to end users and is operated by a Local Distribution Company (LDC) that is regulated as a separate operating company by a public utility commission or that is operated as an independent municipally-owned distribution system.  This segment excludes customer meters and infrastructure and pipelines (both interstate and intrastate) delivering natural gas directly to major industrial users and "farm taps" upstream of the local distribution company inlet.
(b)  [Reserved]
§98.231  Reporting threshold.
(a)  You must report GHG emissions under this subpart if your facility contains petroleum and natural gas systems and the facility meets the requirements of §98.2(a)(2). Facilities must report emissions from the onshore petroleum and natural gas production industry segment only if emission sources specified in paragraph §98.232(c) emit 25,000 metric tons of CO2 equivalent or more per year.   Facilities must report emissions from the natural gas distribution industry segment only if emission sources specified in paragraph §98.232(i) emit 25,000 metric tons of CO2 equivalent or more per year.
 (b)  For applying the threshold defined in §98.2(a)(2), natural gas processing facilities must also include owned or operated residue gas compression equipment.

§98.232 GHGs to report. 
(a)  You must report CO2, CH4, and N2O emissions from each industry segment specified in paragraph (b) through (i) of this section, CO2, CH4, and N2O emissions from each flare as specified in paragraph (j) of this section, and stationary and portable combustion emissions as applicable as specified in paragraph (k) of this section.
(b)  For offshore petroleum and natural gas production, report CO2, CH4, and N2O emissions from equipment leaks, vented emission, and flare emission source types as identified in the data collection and emissions estimation study conducted by BOEMRE in compliance with 30 CFR 250.302 through 304. Offshore platforms do not need to report portable emissions. 
(c)  For an onshore petroleum and natural gas production facility, report CO2, CH4, and N2O emissions from only the following source types on a well pad or associated with a well pad:
(1)  Natural gas pneumatic device venting.
(2)  [Reserved]
(3)  Natural gas driven pneumatic pump venting.
(4)  Well venting for liquids unloading.
(5)  Gas well venting during well completions without hydraulic fracturing.
(6)  Gas well venting during well completions with hydraulic fracturing.
(7)  Gas well venting during well workovers without hydraulic fracturing.
(8)  Gas well venting during well workovers with hydraulic fracturing.
(9)  Flare stack emissions.
(10)  Storage tanks vented emissions from produced hydrocarbons.
(11)  Reciprocating compressor rod packing venting.
(12)  Well testing venting and flaring.
(13)  Associated gas venting and flaring from produced hydrocarbons.
(14)  Dehydrator vents.
(15)  [Reserved]
(16)  EOR injection pump blowdown.
(17)  Acid gas removal vents.
(18)  EOR hydrocarbon liquids dissolved CO2.
(19)  Centrifugal compressor venting.
(20)  [Reserved]
(21)  Equipment leaks from valves, connectors, open ended lines, pressure relief valves, pumps, flanges, and other equipment leak sources (such as instruments, loading arms, stuffing boxes, compressor seals, dump lever arms, and breather caps).
(22)  You must use the methods in §98.233(z) and report under this subpart the emissions of CO2, CH4, and N2O from stationary or portable fuel combustion equipment that cannot move on roadways under its own power and drive train, and that are located at an onshore production well pad.  Stationary or portable equipment are the following equipment which are integral to the extraction, processing or movement of oil or natural gas: well drilling and completion equipment, workover equipment, natural gas dehydrators, natural gas compressors, electrical generators, steam boilers, and process heaters. 
(d)  For onshore natural gas processing, report CO2, CH4 - , and N2O emissions from the following sources:
(1)  Reciprocating compressor rod packing venting.
(2)  Centrifugal compressor venting.
(3)  Blowdown vent stacks.
(4)  Dehydrator vents.
(5)  Acid gas removal vents.
(6)  Flare stack emissions.
(7)  Equipment leaks from valves, connectors, open ended lines, pressure relief valves, and meters. 
(e)  For onshore natural gas transmission compression, report CO2 and CH4 emissions from the following sources:
(1)  Reciprocating compressor rod packing venting.
(2)  Centrifugal compressor venting.
(3)  Transmission storage tanks.
(4)  Blowdown vent stacks.
(5)  Natural gas pneumatic device venting.
(6)  [Reserved]
(7)  Equipment leaks from valves, connectors, open ended lines, pressure relief valves, and meters. 
(f)  For underground natural gas storage, report CO2 and CH4 emissions from the following sources:
(1)  Reciprocating compressor rod packing venting.
(2)  Centrifugal compressor venting.
(3)  Natural gas pneumatic device venting.
(4)  [Reserved]
(5)  Equipment leaks from valves, connectors, open ended lines, pressure relief valves, and meters. 
(g)  For LNG storage, report CO2 and CH4 emissions from the following sources:
(1)  Reciprocating compressor rod packing venting.
(2)  Centrifugal compressor venting.
(3)  Equipment leaks from valves; pump seals; connectors; vapor recovery compressors, and other equipment leak sources.
(h)  LNG import and export equipment, report CO2 and CH4 emissions from the following sources: 
(1)  Reciprocating compressor rod packing venting.
(2)  Centrifugal compressor venting.
(3)  Blowdown vent stacks.
(4)  Equipment leaks from valves, pump seals, connectors, vapor recovery compressors, and other equipment leak sources.
(i)  For natural gas distribution, report CO2, and CH4, emissions from the following sources: 
(1)  Above ground meters and regulators at custody transfer city gate stations, including equipment leaks  from connectors, block valves, control valves, pressure relief valves, orifice meters, regulators, and open ended lines.  Customer meters are excluded.
(2)  Above ground meters and regulators at non-custody transfer city gate stations, including station equipment leaks.  Customer meters are excluded.
(3)  Below ground meters and regulators and vault equipment leaks.  Customer meters are excluded.
(4)  Pipeline main equipment leaks.
(5)  Service line equipment leaks.
(6)  Report under subpart W of this part the emissions of CO2, CH4, and N2O emissions from stationary fuel combustion sources following the methods in §98.233(z).
(j)  All applicable industry segments must report the CO2, CH4, and N2O emissions from each flare.  
(k)  Report under subpart C of this part (General Stationary Fuel Combustion Sources) the emissions of CO2, CH4, and N2O from each stationary fuel combustion unit by following the requirements of subpart C. Onshore petroleum and natural gas production facilities must report stationary and portable combustion emissions as specified in paragraph (c) of this section. Natural gas distribution facilities must report stationary combustion emissions as specified in paragraph (i) of this section.   
(l)  You must report under subpart PP of this part (Suppliers of Carbon Dioxide), CO2 emissions captured and transferred off site by following the requirements of subpart PP.
§98.233 Calculating GHG emissions. You must calculate and report the annual GHG emissions as prescribed in this section. For actual conditions, reporters must use average atmospheric conditions or typical operating conditions as applicable to the respective monitoring methods in this section.
(a)  Natural gas pneumatic device venting.  Calculate CH4 and CO2 emissions from continuous high bleed, continuous low bleed, and intermittent bleed natural gas pneumatic devices using Equation W-1 of this section. 

		(Eq. W-1)
Where:
Masss,i 	= 	Annual total mass GHG emissions in metric tons CO2e per year at standard conditions from a natural gas pneumatic device vent, for GHG i.
Count	= 	Total number of continuous high bleed, continuous low bleed, or intermittent bleed natural gas pneumatic devices of each type as determined in paragraph (a)(1) of this section.
EF 	= 	Population emission factors for natural gas pneumatic device venting listed in Tables W-1A, W-3, and W-4 of this subpart for onshore petroleum and natural gas production, onshore natural gas transmission compression, and underground natural gas storage facilities, respectively.
GHGi 	= 	For onshore petroleum and natural gas production facilities, concentration of GHG i, CH4 or CO2, in produced natural gas as defined in paragraph (u)(2)(i) of this section; for facilities listed in §98.230(a)(4) and (a)(5), GHGi equals 0.952 for CH4 and 1x10-2 for CO2.
Convi 	=	Conversion from standard cubic feet to metric tons CO2e; 0.000410 for CH4, and 0.00005357 for CO2.
24 * 365	=	Conversion to yearly emissions estimate.
 (1) For onshore petroleum and natural gas production, provide the total number of continuous high bleed, continuous low bleed, or intermittent bleed natural gas pneumatic devices of each type as follows:
(i)  In the first calendar year, for the total number of each type, you may count the total of each type, or count any percentage number of each type plus an engineering estimate based on best available data of the number not counted.
(ii)  In the second consecutive year, for the total number of each type, you may count the total of each type, or count any percentage number of each type plus an engineering estimate based on best available data of the number not counted.
(iii)  In the third consecutive calendar year, complete the count of all pneumatic devices, including any changes to equipment counted in prior years. 
(iv) For the calendar year immediately following the third consecutive calendar year, and for calendar years thereafter, facilities must update the total count of pneumatic devices and adjust accordingly to reflect any modifications due to changes in equipment.
(2)  For onshore natural gas transmission compression and underground natural gas storage, all natural gas pneumatic devices must be counted in the first year and updated every calendar year.
      (b)  [Reserved]
(c)  Natural gas driven pneumatic pump venting.  Calculate CH4 and CO2 emissions from natural gas driven pneumatic pump venting using Equation W-2 of this section. Natural gas driven pneumatic pumps covered in paragraph (e) of this section do not have to report emissions under paragraph (c) of this section.  
		(Eq. W-2)
Where:
Masss,i 	= 	Annual total mass GHG emissions in metric tons CO2e per year at standard conditions from all natural gas pneumatic pump venting, for GHG i.
Count	= 	Total number of natural gas pneumatic pumps.
EF 	= 	Population emission factors for natural gas pneumatic pump venting listed in Tables W-1A of this subpart for onshore petroleum and natural gas production.
GHGi 	= 	Concentration of GHG i, CH4 or CO2, in produced natural gas as defined in paragraph (u)(2)(i) of this section.
Convi 	= 	Conversion from standard cubic feet to metric tons CO2e; 0.000410 for CH4, and 0.00005357 for CO2.
24 * 365 = 	Conversion to yearly emissions estimate.
(d)  Acid gas removal (AGR) vents.  For AGR vent (including processes such as amine, membrane, molecular sieve or other absorbents and adsorbents), calculate emissions for CO2 only (not CH4) vented directly to the atmosphere or through a flare, engine (e.g. permeate from a membrane or de-adsorbed gas from a pressure swing adsorber used as fuel supplement), or sulfur recovery plant using any of the calculation methodologies described in paragraph (d) of this section.
(1)  Calculation Methodology 1.  If you operate and maintain a CEMS that measures CO2 emissions according to subpart C of this part, you must calculate CO2 emissions under this subpart by following the Tier 4 Calculation Methodology and all associated requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources).  If CEMS and/or volumetric flow rate monitor are not available, you may install a CEMS that complies with the Tier 4 Calculation Methodology in subpart C of this part (General Stationary Fuel Combustion).
(2)  Calculation Methodology 2.  If CEMS is not available but a vent meter is installed, use the CO2 composition and annual volume of vent gas to calculate emissions using Equation W-3 of this section.
	Ea,CO2 = VS * VolCO2	(Eq. W-3)
Where:
Ea,CO2 	=	Annual volumetric CO2 emissions at actual conditions, in cubic feet per year.
VS 	=	Total annual volume of vent gas flowing out of the AGR unit in cubic feet per year at actual conditions as determined by flow meter using methods set forth in §98.234(b).
VolCO2	=	Volume fraction of CO2 content in vent gas out of the AGR unit as determined in (d)(6) of this section.
(3)  Calculation Methodology 3.  If using CEMS or a vent meter is not an available, you may use the inlet or outlet gas flow rate of the acid gas removal unit to calculate emissions for CO2 using Equation W-4 of this section.
		(Eq. W-4)
Where:
Ea,CO2 	=	Annual volumetric CO2 emissions at actual condition, in cubic feet per year.
V 	=	Total annual volume of natural gas flow into or out of the AGR unit in cubic feet per year at actual condition as determined using methods specified in paragraph (d)(5) of this section.
α	=	Factor is 1 if the outlet stream flow is measured.  Factor is 0 if the inlet stream flow is measured.
VolI	=	Volume fraction of CO2 content in natural gas into the AGR unit as determined in paragraph (d)(7) of this section.
VolO	=	Volume fraction of CO2 content in natural gas out of the AGR unit as determined in paragraph (d)(8) of this section.
(4)  Calculation Methodology 4.  If CEMS or a vent meter is not installed, you may calculate emissions using any standard simulation software packages, such as AspenTech HYSYS[(R)] and API 4679 AMINECalc, that uses the Peng-Robinson equation of state, and speciates CO2 emissions. A minimum of the following determined for typical operating conditions over the calendar year by engineering estimate and process knowledge based on best available data must be used to characterize emissions:
(i)  Natural gas feed temperature, pressure, and flow rate.
(ii) Acid gas content of feed natural gas.
(iii)  Acid gas content of outlet natural gas.
(iv)  Unit operating hours, excluding downtime for maintenance or standby.
(v)  Exit temperature of natural gas.
(vi)  Solvent pressure, temperature, circulation rate, and weight.
(5)  Record the gas flow rate of the inlet and outlet natural gas stream of an AGR unit using a meter according to methods set forth in §98.234(b). If you do not have a continuous flow meter, either install a continuous flow meter or use an engineering calculation to determine the flow rate.
(6)  If continuous gas analyzer is not available on the vent stack, either install a continuous gas analyzer or take quarterly gas samples from the vent gas stream to determine VolCO2 according to methods set forth in §98.234(b).
(7)  If a continuous gas analyzer is installed on the inlet gas stream, then the continuous gas analyzer results must be used.  If continuous gas analyzer is not available, either install a continuous gas analyzer or take quarterly gas samples from the inlet gas stream to determine VolI according to methods set forth in §98.234(b).
(8)  Determine volume fraction of CO2 content in natural gas out of the AGR unit using one of the methods specified in paragraph (d)(8) of this section. 
(i)  If a continuous gas analyzer is installed on the outlet gas stream, then the continuous gas analyzer results must be used.  If a continuous gas analyzer is not available, you may install a continuous gas analyzer. 
(ii)  If a continuous gas analyzer is not available or installed, quarterly gas samples may be taken from the outlet gas stream to determine VolO according to methods set forth in §98.234(b).
(iii)  Use sales line quality specification for CO2 in natural gas.
(9)  Calculate CO2 volumetric emissions at standard conditions using calculations in paragraph (t) of this section.
(10)  Mass CO2 emissions shall be calculated from volumetric CO2 emissions using calculations in paragraph (v) of this section.
(11)  Determine if emissions from the AGR unit are recovered and transferred outside the facility.  Adjust the emission estimated in paragraphs (d)(1) through (d)(10) of this section downward by the magnitude of emission recovered and transferred outside the facility.
(e)  Dehydrator vents.  For dehydrator vents, calculate annual CH4, CO2 and N2O (when flared) emissions using any of the calculation methodologies described in paragraph (e)  of this section.
(1)  Calculation Methodology 1.  Calculate annual mass emissions from dehydrator vents with annual average daily throughput greater than or equal to 0.4 million standard cubic feet per day using a software program, such as AspenTech HYSYS(R) or GRI-GLYCalc, that uses the Peng-Robinson equation of state to calculate the equilibrium coefficient, speciates CH4 and CO2 emissions from dehydrators, and has provisions to include regenerator control devices, a separator flash tank, stripping gas and a gas injection pump or gas assist pump.  A minimum of the following parameters determined by engineering estimate based on best available data must be used to characterize emissions from dehydrators:
(i)  Feed natural gas flow rate.
(ii)  Feed natural gas water content.
(iii)  Outlet natural gas water content.
(iv)  Absorbent circulation pump type (natural gas pneumatic/ air pneumatic/ electric). 
(v)  Absorbent circulation rate.
(vi) Absorbent type: including triethylene glycol (TEG), diethylene glycol (DEG) or ethylene glycol (EG).
(vii)  Use of stripping natural gas.
(viii)  Use of flash tank separator (and disposition of recovered gas).
(ix)  Hours operated.
(x)  Wet natural gas temperature and pressure.
(xi) Wet natural gas composition.  Determine this parameter by selecting one of the methods described under paragraph  (e)(1)(xi)of this section.
(A)  Use the wet natural gas composition as defined in paragraph (u)(2)(i)or (u)(2)(ii) of this section.
(B)  If wet natural gas composition cannot be determined using paragraph (u)(2)(i) or (u)(2)(ii) of this section, select a representative analysis.
(C)  You may use an appropriate standard method published by a consensus-based standards organization if such a method exists or you may use an industry standard practice as specified in §98.234(b) to sample and analyze wet natural gas composition.
(D)  If only composition data for dry natural gas is available, assume the wet natural gas is saturated.  
(2)  Calculation Methodology 2.  Calculate annual CH4 and CO2 emissions from glycol dehydrators with annual average daily throughput less than 0.4 million cubic feet per day using Equation W-5 of this section:
		(Eq. W-5)
Where:
Es,i	=	Annual total volumetric GHG emissions (either CO2 or CH4) at standard conditions in cubic feet.
EFi	=	Population emission factors for glycol dehydrators in thousand standard cubic feet per dehydrator per year. Use 74.5 for CH4 and 3.26 for CO2 at 68°F and 14.7 psia or 73.4 for CH4 and 3.21 for CO2 at 60°F and 14.7 psia. 
Count	=	Total number of glycol dehydrators with throughput less than 0.4 million cubic feet. 
1000	=	Conversion of EFi in thousand standard cubic to cubic feet. 
(3)  Determine if dehydrator unit has vapor recovery. Adjust the emissions estimated in paragraphs (e)(1) or (e)(2) of this section downward by the magnitude of emissions captured.
(4)  Calculate annual emissions from dehydrator vents to flares or regenerator fire-box/fire tubes as follows:
(A)  Use the dehydrator vent volume and gas composition as determined in paragraphs (e)(1) and (e)(2) of this section.
(B)  Use the calculation methodology of flare stacks in paragraph (n) of this section to determine dehydrator vent emissions from the flare or regenerator combustion gas vent.
(5)  Dehydrators that use desiccant shall calculate emissions from the amount of gas vented from the vessel every time it is depressurized for the desiccant refilling process using Equation W-6 of this section.  Desiccant dehydrators covered in (e)(5) of this section do not have to report emissions under (i) of this section. 
	Es,n  =  (H*D[2]*P*P2*%G*365days/yr)	(Eq. W-6)
	      (4*P1*T*1,000cf/Mcf*100)

Where:
Es,n	=	Annual natural gas emissions at standard conditions in cubic feet. 
H	= 	Height of the dehydrator vessel (ft). 
D 	= 	Inside diameter of the vessel (ft). 
P1 	= 	Atmospheric pressure (psia). 
P2 	= 	Pressure of the gas (psia). 
P	= 	pi (3.14).
%G 	= 	Percent of packed vessel volume that is gas. 
T	= 	Time between refilling (days).
100	=	Conversion of %G to fraction.
(6)  Both CH4 and CO2 volumetric and mass emissions shall be calculated from volumetric natural gas emissions using calculations in paragraphs (u) and (v) of this section.
(f)  Well venting for liquids unloadings.  Calculate CO2 and CH4 emissions from  well venting for liquids unloading using one of the calculation methodologies described in paragraphs (f)(1), (f)(2) or (f)(3) of this section.  
(1)  Calculation Methodology 1.  For one well of each unique well tubing diameter and producing horizon/formation combination in each gas producing field (see §98.238 for the definition of Field) where gas wells are vented to the atmosphere to expel liquids accumulated in the tubing, a recording flow meter shall be installed on the vent line used to vent gas from the well (e.g. on the vent line off the wellhead separator or atmospheric storage tank) according to methods set forth in §98.234(b).  Calculate emissions from well venting for liquids unloading using Equation W-7 of this section.
		(Eq. W-7)
Where: 
Ea,n	=	Annual natural gas emissions at actual conditions in cubic feet. 
Th,t	=	Cumulative amount of time in hours of venting from all wells of the same tubing diameter (t) and producing horizon (h)/formation combination during the year.
FRh,t 	= 	Average flow rate in cubic feet per hour of the measured well venting for the duration of the liquids unloading, under actual conditions as determined in paragraph (f)(1)(i) of this section.
(i)  Determine the well vent average flow rate as specified under paragraph (f)(1)(i) of this section.
(A)  The average flow rate per hour of venting is calculated for each unique tubing diameter and producing horizon/formation combination in each producing field by averaging the recorded flow rates for the recorded time of one representative well venting to the atmosphere. 
(B)  This average flow rate is applied to all wells in the field that have the same tubing diameter and producing horizon/formation combination, for the number of hours of venting these wells.
(C)  A new average flow rate is calculated every other calendar year for each reporting field and horizon starting the first calendar year of data collection. 
(ii)  Calculate natural gas volumetric emissions at standard conditions using calculations in paragraph (t) of this section.
(2)  Calculation Methodology 2.  Calculate the total emissions  for well venting for liquids unloading using Equation W-8 of this section.
		(Eq. W-8)
Where:
Ea,n	=	Annual natural gas emissions at actual conditions, in cubic feet/year. 
W	=	Number of wells with well venting for liquids unloading at the facility. 
0.37x10[-3]	=	{3.14 (pi)/4}/{14.7*144} (psia converted to pounds per square feet).
CDW	=	Casing diameter for each well, in inches.
WDW	=	Well depth to first producing horizon for each well, in feet.
SPW	=	Shut-in pressure for each well, in pounds square inch atmosphere (psia).
VW	=	Number of vents per year per well.
SFRW 	= 	Average sales flow rate of each gas well in cubic feet per hour.
HRV,W 	=	Hours that each well was left open to the atmosphere during each unloading event. 
1.0	= 	Hours for average well to blowdown casing volume at shut-in pressure.
ZV,W	=	If HRV,W is less than 1.0 then ZV,W is equal to 0. If HRV,W is greater than or equal to 1.0 then ZV,W is equal to 1.

(i)  Calculate natural gas volumetric emissions at standard conditions using calculations in paragraph (t) of this section.
(ii)  [Reserved]
(3)  Calculation Methodology 3.  Calculate emissions from each well venting to the atmosphere for liquids unloading with plunger lift assist using Equation W-9 of this section.
	(Eq. W-9)
Where:
Ea,n	=	Annual natural gas emissions at actual conditions, in cubic feet/year. 
W	=	Number of wells with well venting for liquids unloading at the facility. 
0.37x10[-3]	=	{3.14 (pi)/4}/{14.7*144} (psia converted to pounds per square feet).
TDW	=	Tubing diameter for each well, in inches.
WDW	=	Tubing depth to plunger bumper for each well, in feet.
SPW	=	Sales line pressure for each well, in pounds per square inch atmospheric (psia).
NV	=	Number of vents per year per well.
SFRW 	= 	Average sales flow rate of each gas well in cubic feet per hour.
HRV,W 	=	Hours that each well was left open to the atmosphere during each unloading event. 
0.5	= 	Hours for average well to blowdown tubing volume at sales line pressure.
ZV,W	=	If HRV,W is less than 0.5 then ZV,W is equal to 0. If HRV,W is greater than or equal to 0.5 then ZV,W is equal to 1.

(i)  Calculate natural gas volumetric emissions at standard conditions using calculations in paragraph (t) of this section. 
(ii) [Reserved]
(4)  Both CH4 and CO2 volumetric and mass emissions shall be calculated from volumetric natural gas emissions using calculations in paragraphs (u) and (v) of this section.
(g)  Gas well venting during completions and workovers from hydraulic fracturing.  Calculate CH4, CO2 and N2O (when flared) annual emissions from gas well venting during completions involving hydraulic fracturing in wells and well workovers using Equation W-10 of this section. Both CH4 and CO2 volumetric and mass emissions shall be calculated from volumetric total gas emissions using calculations in paragraphs (u) and (v) of this section. 
	Ea,n  = (T * FR)  -  EnF - SG 	(Eq. W-10)
Where:
Ea,n	=	Annual volumetric total gas emissions in cubic feet at standard conditions from gas well venting during completions following hydraulic fracturing. 
T 	= 	Cumulative amount of time in hours of all well completion venting in a field during the year reporting.
FR	=	Average flow rate in cubic feet per hour, under actual conditions, converted to standard conditions, as required in paragraph (g)(1) of this section.
EnF	=	Volume of CO2 or N2 injected gas in cubic feet at standard conditions that was injected into the reservoir during an energized fracture job.  If the fracture process did not inject gas into the reservoir, then EnF is 0. If injected gas is CO2 then EnF is 0.
SG	=	Volume of natural gas in cubic feet at standard conditions that was recovered into a sales pipeline. If no gas was recovered for sales, SG is 0.

(1)  The average flow rate for gas well venting to the atmosphere or to a flare during well completions and workovers from hydraulic fracturing shall be determined using either of the calculation methodologies described in this paragraph (g)(1) of this section.
(i)  Calculation Methodology 1.  For one well completion in each gas producing field and for one well workover in each gas producing field, a recording flow meter (digital or analog) shall be installed on the vent line, ahead of a flare if used, to measure the backflow venting event according to methods set forth in §98.234(b). 
(A)  The average flow rate in cubic feet per hour of venting to the atmosphere or routed to a flare is determined from the flow recording over the period of backflow venting. 
(B)  The respective flow rates are applied to all well completions in the producing field and to all well workovers in the producing field for the total number of hours of venting of each of these wells. 
(C)  New flow rates for completions and workovers are measured every other calendar year for each reporting gas producing field and gas producing geologic horizon in each gas producing field starting in the first calendar year of data collection. 
(D)  Calculate total volumetric flow rate at standard conditions using calculations in paragraph (t) of this section.
(ii)  Calculation Methodology 2.  For one well completion in each gas producing field and for one well workover in each gas producing field, record the well flowing pressure upstream(and downstream in subsonic flow) of a well choke according to methods set forth in §98.234(b) to calculate intermittent well flow rate of gas during venting to the atmosphere or a flare. Calculate emissions using Equation W-11 of this section for subsonic flow or Equation W-12 of this section for sonic flow:
	 	(Eq. W-11)

Where:
FR	=	Average flow rate in cubic feet per hour, under subsonic flow conditions.
A	=	Cross sectional area of orifice (m[2]).
P1	=	Upstream pressure (psia).
Tu	=	Upstream temperature (degrees Kelvin).
P2	=	Downstream pressure (psia).
3430	=	Constant with units of m[2]/(sec[2] * K).
1.27*10[5]	=	Conversion from m[3]/second to ft[3]/hour.

		(Eq. W-12)
Where:
FR	=	Average flow rate in cubic feet per hour, under sonic flow conditions.
A		=	Cross sectional area of orifice (m[2]).
Tu		=	Upstream temperature (degrees Kelvin).
187.08	=	Constant with units of m[2]/(sec[2] * K).
1.27*10[5]	=	Conversion from m[3]/second to ft[3]/hour.
(A)  The average flow rate in cubic feet per hour of venting across the choke is calculated for one well completion in each gas producing field and for one well workover in each gas producing field by averaging the gas flow rates during venting to the atmosphere or routing to a flare. 
(B)  The respective flow rates are applied to all well completions in the gas producing field and to all well workovers in the gas producing field for the total number of hours of venting of each of these wells. 
(C)  Flow rates for completions and workovers in each field shall be calculated once every two years for each reporting gas producing field and geologic horizon in each gas producing field starting in the first calendar year of data collection. 
(D)  Calculate total volumetric flow rate at standard conditions using calculations in paragraph (t) of this section.
(2) The volume of CO2 or N2 injected into the well reservoir during energized hydraulic fractures will be measured using an appropriate meter as described in 98.234(b) or using receipts of gas purchases that are used for the energized fracture job. 
(i)  Calculate gas volume at standard conditions using calculations in paragraph (t) of this section.
(ii)  [Reserved]
(3) The volume of recovered completion gas sent to a sales line will be measured using existing company records.  If data does not exist on sales gas, then an appropriate meter as described in 98.234(b) may be used.
(i) Calculate gas volume at standard conditions using calculations in paragraph (t) of this section.
(ii)  [Reserved]
(4)  Both CH4 and CO2 volumetric and mass emissions shall be calculated from volumetric total emissions using calculations in paragraphs (u) and (v) of this section.
      (5)  Determine if the well completion or workover from hydraulic fracturing recovered gas with purpose designed equipment that separates saleable gas from the backflow, and sent this gas to a sales line (e.g. reduced emissions completion).
      (i)  Use the factor SG in Equation W-10 of this section, to adjust the emissions estimated in paragraphs (g)(1) through (g)(4) of this section by the magnitude of emissions captured using reduced emission completions as determined by engineering estimate based on best available data. 
      (ii)  [Reserved]
(6)  Calculate annual emissions from gas well venting during well completions and workovers from hydraulic fracturing to flares as follows:
(i)  Use the total gas well venting volume during well completions and workovers as determined in paragraph (g) of this section.
(ii)  Use the calculation methodology of flare stacks in paragraph (n) of this section to determine gas well venting during well completions and workovers using hydraulic fracturing emissions from the flare. This adjustment to emissions from completions using flaring versus completions without flaring accounts for the conversion of CH4 to CO2 in the flare.
(h)  Gas well venting during completions and workovers without hydraulic fracturing.  Calculate CH4, CO2 and N2O (when flared) emissions from each gas well venting during well completions and workovers not involving hydraulic fracturing and well workovers not involving hydraulic fracturing using Equation W-13 of this section:
		(Eq. W-13)
Where:
Es,n 	=	Annual natural gas emissions in standard cubic feet  from a gas well venting during well completions and workovers without hydraulic fracturing. 
Nwo	=	Number of workovers per field not involving hydraulic fracturing in the reporting year.
EFwo	=	Emission Factor for non-hydraulic fracture well workover venting in  standard cubic feet per workover. EFwo =   3114 standard cubic feet per well workover without hydraulic fracturing.
f	=	Total number of well completions without hydraulic fracturing in a field.
Vf	= 	Average daily gas production rate in standard cubic feet per hour of each well completion without hydraulic fracturing.  This is the total annual gas production volume divided by total number of hours the wells produced to the sales line. For completed wells that have not established a production rate, you may use the average flow rate from the first 30 days of production. In the event that the well is completed less than 30 days from the end of the calendar year, the first 30 days of the production straddling the current and following calendar years shall be used. 
Tf	= 	Time each well completion without hydraulic fracturing was venting in hours during the year.

(1)  Volumetric  emissions for both CH4 and CO2 shall be calculated from volumetric natural gas emissions using calculations in paragraphs (u)  of this section. Mass emissions for both CH4 and CO2 shall be calculated from volumetric natural gas emissions using calculations in paragraphs (v) of this section.
(2)  Calculate annual emissions from gas well venting during well completions and workovers not involving hydraulic fracturing to flares as follows:
(i)  Use the gas well venting volume during well completions and workovers as determined in paragraph (h) of this section.
(ii)  Use the calculation methodology of flare stacks in paragraph (n) of this section to determine gas well venting during well completions and workovers emissions without hydraulic fracturing from the flare.
(i)  Blowdown vent stacks. Calculate CO2 and CH4 blowdown vent stack emissions from depressurizing equipment to the atmosphere (excluding depressurizing to a flare, over-pressure relief, operating pressure control venting and blowdown of non-GHG gases; desiccant dehydrator blowdown venting before reloading is covered in paragraph (e)(5) of this section) as follows (Emissions from emergency events are not included.): 
(1)  Calculate the total volume (including pipelines, compressor case or cylinders, manifolds, suction bottles, discharge bottles, and vessels) between isolation valves determined by engineering estimate based on best available data.
(2)  If the total physical volume between isolation valves is greater than or equal to 50 cubic feet, retain logs of the number of blowdowns for each equipment type (including but not limited to compressors, vessels, pipelines, headers, fractionators, and tanks).  Blowdown volumes smaller than 50 standard cubic feet are exempt from reporting under paragraph (i) of this section.
(3)  Calculate the total annual venting emissions for each equipment type using Equation W-14 of this section:
		(Eq. W-14)
Where:
Es,n 	= 	Annual natural gas venting emissions at standard conditions from blowdowns in cubic feet.
N	= 	Number of repetitive blowdowns for each equipment type of a unique volume in calendar year.
Vv	=	Total physical volume of blowdown equipment chambers (including pipelines, compressors and vessels) between isolation valves in cubic feet.
C	=	Purge factor that is 1 if the equipment is not purged or zero if the equipment is purged using non-GHG gases.
Ts  	=	Temperature at standard conditions ([o]F).
Ta  	=	Temperature at actual conditions in the blowdown equipment chamber ([o]F).
Ps  	=	Absolute pressure at standard conditions (psia).
Pa  	=	Absolute pressure at actual conditions in the blowdown equipment chamber (psia).
(4)  Calculate both CH4 and CO2 volumetric and mass emissions using calculations in paragraph (u) and (v) of this section.
(5)  Calculate total annual venting emissions for all blowdown vent stacks by adding all standard volumetric and mass emissions determined in Equation W-14 and paragraph (i)(4) of this section.
(j)  Onshore production storage tanks.  Calculate CH4, CO2 and N2O (when flared) emissions from atmospheric pressure fixed roof storage tanks receiving hydrocarbon produced liquids from onshore petroleum and natural gas production facilities (including stationary liquid storage not owned or operated by the reporter), calculate annual CH4 and CO2 emissions using any of the calculation methodologies described in this paragraph (j). 
(1)  Calculation Methodology 1.  For separators with  annual average daily throughput of oil greater than or equal to 10 barrels per day.  Calculate annual CH4 and CO2 emissions from onshore production storage tanks using operating conditions in the last wellhead gas-liquid separator before liquid transfer to storage tanks.  Calculate flashing emissions with a software program, such as AspenTech HYSYS(R) or API 4697 E&P Tank, that uses the Peng-Robinson equation of state, models flashing emissions, and speciates CH4 and CO2 emissions that will result when the oil from the separator enters an atmospheric pressure storage tank.  A minimum of the following parameters determined for typical operating conditions over the year by engineering estimate and process knowledge based on best available data must be used to characterize emissions from liquid transferred to tanks.
(i)  Separator temperature.
(ii)  Separator pressure.
(iii)  Sales oil or stabilized oil API gravity. 
(iv)  Sales oil or stabilized oil production rate.
(v)  Ambient air temperature.
(vi)  Ambient air pressure.
(vii)  Separator oil composition and Reid vapor pressure. If this data is not available, determine these parameters by selecting one of the methods described under paragraph (j)(1) (vii) of this section.
(A)  If separator oil composition and Reid vapor pressure default data are provided with the software program, select the default values that most closely match your separator pressure first, and API gravity secondarily.
(B)  If separator oil composition and Reid vapor pressure data are available through your previous analysis, select the latest available analysis that is representative of produced crude oil or condensate from the field. 
(C)  Analyze a representative sample of separator oil in each field for oil composition and Reid vapor pressure using an appropriate standard method published by a consensus-based standards organization.
(2)  Calculation Methodology 2. Calculate annual CH4 and CO2 emissions from onshore production storage tanks for wellhead gas-liquid separators with annual average daily throughput of oil greater than or equal to 10 barrels per day by assuming that all of the CH4 and CO2 in solution at separator temperature and pressure is emitted from oil sent to storage tanks. You may use an appropriate standard method published by a consensus-based standards organization if such a method exists or you may use an industry standard practice as described in §98.234(b) to sample and analyze separator oil composition at separator pressure and temperature.
(3)  Calculation Methodology 3. For wells with annual average daily oil production greater than or equal to 10 barrels per day that flow directly to atmospheric storage tanks without passing through a wellhead separator, calculate annual CH4 and CO2 emissions by either of the methods in paragraph (j)(3) of this section:
(i)  If well production oil and gas compositions are available through your previous analysis, select the latest available analysis that is representative of produced oil and gas from the field and assume all of the CH4 and CO2 in both oil and gas are emitted from the tank.
(ii)  If well production oil and gas compositions are not available, use default oil and gas compositions in software programs, such as API 4697 E&P Tank, that most closely match your well production gas/oil ratio and API gravity and assume all of the CH4 and CO2 in both oil and gas are emitted from the tank. 
(4)  Calculation Methodology 4.  For wells with annual average daily oil production greater than or equal to 10 barrels per day that flow to a separator not at the well pad, calculate annual CH4 and CO2 emissions by either of the methods in paragraph (j)(4) of this section:
(i)  If well production oil and gas compositions are available through your previous analysis, select the latest available analysis that is representative of oil at separator pressure determined by best available data and assume all of the CH4 and CO2 in the oil is emitted from the tank.
(ii)  If well production oil composition is not available, use default oil composition in software programs, such as API 4697 E&P Tank, that most closely match your well production API gravity and pressure in the off-well pad separator determined by best available data. Assume all of the CH4 and CO2 in the oil phase is emitted from the tank.
(5)  Calculation Methodology 5. For well pad gas-liquid separators and for wells flowing off a well pad without passing through a gas-liquid separator with throughput less than 10 barrels per day use Equation W-15 of this section:

		(Eq. W-15)
Where:
Es,i	=	Annual total volumetric GHG emissions (either CO2 or CH4) at standard conditions in cubic feet.
EFi	=	Populations emission factor for separators or wells in thousand standard cubic feet per separator or well per year, for crude oil use 4.3 for CH4 and 2.9 for CO2 at 68°F and 14.7 psia, and for gas condensate use 17.8 for CH4 and 2.9 for CO2 at 68°F and 14.7 psia.
Count	=	Total number of separators or wells with throughput less than 10 barrels per day.
1000	=	Conversion to cubic feet
(6)  Determine if the storage tank receiving your separator oil has a vapor recovery system. 
(i)  Adjust the emissions estimated in paragraphs (j)(1) through (j)(5) of this section downward by the magnitude of emissions recovered using a vapor recovery system as determined by engineering estimate based on best available data.
(ii)  [Reserved]
 (7)  Determine if the storage tank receiving your separator oil is sent to flare(s).
(i)  Use your separator flash gas volume and gas composition as determined in this section.
(ii)  Use the calculation methodology of flare stacks in paragraph (n) of this section to determine your contribution to storage tank emissions from the flare.
(8)  Calculate emissions from occurrences of well pad gas-liquid separator liquid dump valves not closing during the calendar year by using Equation W-16 of this section.
		(Eq. W-16)
Where:
Es,i	=	Annual total volumetric GHG emissions at standard conditions from each storage tank in cubic feet.
En	=	Storage tank emissions as determined in Calculation Methodologies 1, 2, or 4 in paragraphs (j)(1), (j)(2) and (j)(4) of this section (with wellhead separators) in cubic feet per year. 
Tn	=	Total time the dump valve is not closing properly in the calendar year in hours. Tn is estimated by maintenance or operations records (records) such that when a record shows the valve to be open improperly, it is assumed the valve was open for the entire time period preceding the record starting at either the beginning of the calendar year or the previous record showing it closed properly within the calendar year. If a subsequent record shows it is closing properly, then assume from that time forward the valve closed properly until either the next record of it not closing properly or, if there is no subsequent record, the end of the calendar year. 
CFn	=	Correction factor for tank emissions for time period Tn is 3.87 for crude oil production.  Correction factor for tank emissions for time period Tn is 5.37 for gas condensate production.  Correction factor for tank emissions for time period Tn is 1.0 for periods when the dump valve is closed.
8,760	=	Conversion to hourly emissions.
		
(9)  Calculate both CH4 and CO2 mass emissions from volumetric natural gas emissions using calculations in paragraph (v) of this section.
(k)  Transmission storage tanks.  For condensate storage tanks, either water or hydrocarbon, without vapor recovery or thermal control devices in onshore natural gas transmission compression facilities calculate CH4, CO2 and N2O (when flared) annual emissions from compressor scrubber dump valve leakage as follows: 
(1)  Monitor the tank vapor vent stack annually for emissions using an optical gas imaging instrument according to methods set forth in §98.234(a)(1) for a duration of 5 minutes.  Or you may annually monitor leakage through compressor scrubber dump valve(s) into the tank using an acoustic leak detection device according to methods set forth in §98.234(a)(5).
(2)  If the tank vapors are continuous for 5 minutes, or the acoustic leak detection device detects a leak, then use one of the following two methods in paragraph (k)(2) of this section to quantify annual emissions: 
(i)  Use a meter, such as a turbine meter, to estimate tank vapor volumes according to methods set forth in §98.234(b).  If you do not have a continuous flow measurement device, you may install a flow measuring device on the tank vapor vent stack.
(ii)  Use an acoustic leak detection device on each scrubber dump valve connected to the tank according to the method set forth in §98.234(a)(5).
(iii)  Use the appropriate gas composition in paragraph (u)(2)(iii) of this section.
(3)  If the leaking dump valve(s) is fixed following leak detection, the annual emissions shall be calculated from the beginning of the calendar year to the time the valve(s) is repaired.
(4)  Calculate annual emissions from storage tanks to flares as follows:
(i)  Use the storage tank emissions volume and gas composition as determined in paragraphs (k)(1) through (k)(3) of this section.
(ii)  Use the calculation methodology of flare stacks in paragraph (n) of this section to determine storage tank emissions sent to a flare.
(l)  Well testing venting and flaring.  Calculate CH4, CO2 and N2O (when flared) well testing venting and flaring emissions as follows:
(1)  Determine the gas to oil ratio (GOR) of the hydrocarbon production from each well tested.
(2)  If GOR cannot be determined from your available data, then you must measure quantities reported in this section  according to one of the two procedures in paragraph (l)(2) of this section to determine GOR:
(i)  You may use an appropriate standard method published by a consensus-based standards organization if such a method exists. 
(ii)  Or you may use an industry standard practice as described in §98.234(b).
(3)  Estimate venting emissions using Equation W-17 of this section.
		(Eq. W-17)
Where:
Ea,n	=	Annual volumetric natural gas emissions from well testing in cubic feet under actual conditions.
GOR	=	Gas to oil ratio in cubic feet of gas per barrel of oil; oil here refers to hydrocarbon liquids produced of all API gravities.
FR	=	Flow rate in barrels of oil per day for the well being tested.
D	=	Number of days during the year, the well is tested.

(4)  Calculate natural gas volumetric emissions at standard conditions using calculations in paragraph (t) of this section.
(5)  Calculate both CH4 and CO2 volumetric and mass emissions from volumetric natural gas emissions using calculations in paragraphs (u) and (v) of this section.
(6)  Calculate emissions from well testing to flares as follows:
(i)  Use the well testing emissions volume and gas composition as determined in paragraphs (l)(1) through (3) of this section.
(ii)  Use the calculation methodology of flare stacks in paragraph (n) of this section to determine well testing emissions from the flare.
(m)  Associated gas venting and flaring.  Calculate CH4, CO2 and N2O (when flared) associated gas venting and flaring emissions not in conjunction with well testing (refer to paragraph (l): Well testing venting and flaring of this section) as follows:
(1)  Determine the GOR of the hydrocarbon production from each well whose associated natural gas is vented or flared. If GOR from each well is not available, the GOR from a cluster of wells in the same field shall be used. 
(2)  If GOR cannot be determined from your available data, then use one of the two procedures in paragraph (m)(2) of this section to determine GOR:
(i)  You may use an appropriate standard method published by a consensus-based standards organization if such a method exists.
(ii)  Or you may use an industry standard practice as described in §98.234(b).
(3)  Estimate venting emissions using Equation W-18 of this section.
		(Eq. W-18)
Where:
Ea,n	=	Annual volumetric natural gas emissions from associated gas venting under actual conditions, in cubic feet.
GOR	=	Gas to oil ratio in cubic feet of gas per barrel of oil; oil here refers to hydrocarbon liquids produced of all API gravities.
V	=	Volume of oil produced in barrels in the calendar year during which associated gas was vented or flared.
(4)  Calculate natural gas volumetric emissions at standard conditions using calculations in paragraph (t) of this section.
(5)  Calculate both CH4 and CO2 volumetric and mass emissions from volumetric natural gas emissions using calculations in paragraphs (u) and (v) of this section.
(6)  Calculate emissions from associated natural gas to flares as follows:
(i)  Use the associated natural gas volume and gas composition as determined in paragraph (m)(1) through (4) of this section.
(ii)  Use the calculation methodology of flare stacks in paragraph (n) of this section to determine associated gas emissions from the flare.
(n)  Flare stack emissions.  Calculate CO2, CH4, and N2O emissions from a flare stack as follows:
(1)  If you have a continuous flow measurement device on the flare, you must use the measured flow volumes to calculate the flare gas emissions.  If all of the flare gas is not measured by the existing flow measurement device, then the flow not measured can be estimated using engineering calculations based on best available data or company records.  If you do not have a continuous flow measurement device on the flare, you can install a flow measuring device on the flare or use engineering calculations based on process knowledge, company records, and best available data. 
(2)  If you have a continuous gas composition analyzer on gas to the flare, you must use these compositions in calculating emissions.  If you do not have a continuous gas composition analyzer on gas to the flare, you must use the appropriate gas compositions for each stream of hydrocarbons going to the flare as follows:
(i)  For onshore natural gas production, determine natural gas composition using (u)(2)(i) of this section.
(ii)  For onshore natural gas processing, when the stream going to flare is natural gas,  use the GHG mole percent in feed natural gas for all streams upstream of the de-methanizer or dew point control, and GHG mole percent in facility specific residue gas to transmission pipeline systems for all emissions sources downstream of the de-methanizer overhead or dew point control for onshore natural gas processing facilities.
(iii)  When the stream going to the flare is a hydrocarbon product stream, such as ethane, propane, butane, pentane-plus and mixed light hydrocarbons, then use a representative composition from the source for the stream determined by engineering calculation based on process knowledge and best available data.
(3)  Determine flare combustion efficiency from manufacturer.  If not available, assume that flare combustion efficiency is 98 percent.
(4)  Calculate GHG volumetric emissions at actual conditions using Equations W-19, W-20, and W-21 of this section.
		(Eq. W-19)
	 	(Eq. W-20)
		(Eq. W-21)
Where:
Ea,CH4(un-combusted)	=	Contribution of annual un-combusted CH4 emissions from flare stack in cubic feet, under actual conditions.
Ea,CO2(un-combusted)	=	Contribution of annual un-combusted CO2 emissions from flare stack in cubic feet, under actual conditions.
Ea,CO2(combusted)	=	Contribution of annual combusted CO2 emissions from flare stack in cubic feet, under actual conditions.
Va	=	Volume of gas sent to flare in cubic feet, during the year.
η	=	Fraction of gas combusted by a burning flare (default is 0.98).  For gas sent to an unlit flare, η is zero.
XCH4	= 	Mole fraction of CH4 in gas to the flare.
XCO2	= 	Mole fraction of CO2 in gas to the flare.
Yj 	=	Mole fraction of gas hydrocarbon constituents j (such as methane, ethane, propane, butane, and pentanes-plus).
Rj	=	Number of carbon atoms in the gas hydrocarbon constituent j: 1 for methane, 2 for ethane, 3 for propane, 4 for butane, and 5 for pentanes plus).
(5)  Calculate GHG volumetric emissions at standard conditions using calculations in paragraph (t) of this section.
(6)  Calculate both CH4 and CO2 mass emissions from volumetric CH4 and CO2 emissions using calculation in paragraph (v) of this section.
(7)  Calculate total annual emission from flare stacks by summing Equation W-40, Equation W-19, Equation W-20 and Equation W-21 of this section.	
(8)  Calculate N2O emissions from flare stacks using Equation W-40 in paragraph (z) of this section.
(9)  The flare emissions determined under paragraph (n) of this section must be corrected for flare emissions calculated and reported under other paragraphs of this section to avoid double counting of these emissions. 
(o)  Centrifugal compressor venting.  Calculate CH4, CO2 and N2O (when flared) emissions from both wet seal and dry seal centrifugal compressor vents as follows:  
(1)  For each centrifugal compressor covered by §98.232 (d)(2), (e)(2), (f)(2), (g)(2), and (h)(2) you must conduct an annual measurement in the operating mode in which it is found.  Measure emissions from all vents (including emissions manifolded to common vents) including wet seal oil degassing vents, unit isolation valve vents, and blowdown valve vents.  Record emissions from the following vent types in the specified compressor modes during the annual measurement.
      (i)  Operating mode, blowdown valve leakage through the blowdown vent, wet seal and dry seal compressors.
      (ii)  Operating mode, wet seal oil degassing vents.
      (iii)  Not operating, depressurized mode, unit isolation valve leakage through open blowdown vent, without blind flanges, wet seal and dry seal compressors. 
      (A)  For the not operating, depressurized mode, each compressor must be measured at least once in any three consecutive calendar years.  If a compressor is not operated and has blind flanges in place throughout the 3 year period, measurement is not required in this mode.  If the compressor is in standby depressurized mode without blind flanges in place and is not operated throughout the 3 year period, it must be measured in the standby depressurized mode.
      (2)  For wet seal oil degassing vents, determine vapor volumes sent to an atmospheric vent or flare, using a temporary meter such as a vane anemometer or permanent flow meter according to 98.234(b) of this section.  If you do not have a permanent flow meter, you may install a permanent flow meter on the wet seal oil degassing tank vent.
      (3)  For blowdown valve leakage and unit isolation valve leakage to open ended vents, you can use one of the following methods:  calibrated bagging or high volume sampler according to methods set forth in §98.234(c) and §98.234(d), respectively.  For through valve leakage, such as isolation valves, you may use an acoustic leak detection device according to methods set forth in §98.234(a).  If you do not have a flow meter, you may install a port for insertion of a temporary meter, or a permanent flow meter, on the vents.  
(4)  Estimate annual emissions using the flow measurement and Equation W-22 of this section.
                                  	(Eq. W-22)
Where:
Es,i,m	=	Annual GHG i (either CH4 or CO2) volumetric emissions at standard conditions, in cubic feet.
MTm	=	Measured gas emissions in standard cubic feet per hour.
Tm	=	Total time the compressor is in the mode for which Es,i is being calculated, in the calendar year in hours.
Mi,m	=	Mole fraction of GHG i in the vent gas; use the appropriate gas compositions in paragraph (u)(2) of this section.
Bm	=	Fraction of operating time that the vent gas is sent to vapor recovery or fuel gas as determined by keeping logs of the number of operating hours for the vapor recovery system and the time that vent gas is directed to the fuel gas system or sales.
(5)  Calculate annual emissions from each centrifugal compressor using Equation W-23 of this section.
		(Eq. W-23)
Where:
Es,i	=	Annual total volumetric GHG emissions at standard conditions from each centrifugal compressor in cubic feet.
EFm	=	Reporter emission factor for each mode m, in cubic feet per hour, from Equation W-24 of this section as calculated in paragraph 6. 
Tm	=	Total time in hours per year the compressor was in each mode, as listed in paragraph (o)(1)(i) through (o)(1)(iii).
GHGi	=	For onshore natural gas processing facilities, concentration of GHG i, CH4 or CO2, in produced natural gas or feed natural gas; for other facilities listed in §98.230(a)(4) through (a)(8),GHGi equals 1.
(6)  You shall use the flow measurements of operating mode wet seal oil degassing vent, operating mode blowdown valve vent and not operating depressurized mode isolation valve vent for all the reporter's compressor modes not measured in the calendar year to develop the following emission factors using Equation W-24 of this section for each emission source and mode as listed in paragraph (o)(1)(i) through (o)(1)(iii). 
		(Eq. W-24)
Where:
EFm	=	Reporter emission factors for compressor in the three modes m (as listed in paragraph (o)(1)(i) through (o)(1)(iii)) in cubic feet per hour.
MTm	=	Flow Measurements from all centrifugal compressor vents in each mode in (o)(1)(i) through (o)(1)(iii) of this section in cubic feet per hour.
Countm	=	Total number of compressors measured.
m	=	Compressor mode as listed in paragraph (o)(1)(i) through (o)(1)(iii). 
 (i)  The emission factors must be calculated annually. You must use all measurements from the current calendar year and the preceding two calendar years, totaling three consecutive calendar years of measurements in paragraph (o)(6) of this section.
(ii)  [Reserved]
(7)  Onshore petroleum and natural gas production shall calculate emissions from centrifugal compressor wet seal oil degassing vents as follows:
		(Eq. W-25)
Where:
Es,i	=	Annual total volumetric GHG emissions at standard conditions from centrifugal compressor wet seals in cubic feet.
Count	=	Total number of centrifugal compressors for the reporter.
EFi	=	Emission factor for GHG i.  Use 12.2 million standard cubic feet per year per compressor for CH4 and 538 thousand standard cubic feet per year per compressor for CO2 at 68°F and 14.7 psia or 12 million standard cubic feet per year per compressor for CH4 and 530 thousand standard cubic feet per year per compressor for CO2 at 60°F and 14.7 psia.

(8)  Calculate both CH4 and CO2 mass emissions from volumetric emissions using calculations in paragraph (v) of this section.
(9)  Calculate emissions from seal oil degassing vent vapors to flares as follows:
(i)  Use the seal oil degassing vent vapor volume and gas composition as determined in paragraphs (o)(5) of this section.
(ii)  Use the calculation methodology of flare stacks in paragraph (n) of this section to determine degassing vent vapor emissions from the flare.
(p)  Reciprocating compressor venting.  Calculate CH4 and CO2 emissions from all reciprocating compressor vents as follows.  For each reciprocating compressor covered in §98.232(d)(1), (e)(1), (f)(1), (g)(1), and (h)(1) you must conduct an annual measurement for each compressor in the mode in which it is found during the annual measurement, except as specified in paragraph (p)(9) of this section.  Measure emissions from (including emissions manifolded to common vents) reciprocating rod packing vents, unit isolation valve vents, and blowdown valve vents.  Record emissions from the following vent types in the specified compressor modes during the annual measurement as follows: 
      (1)  Operating or standby pressurized mode, blowdown vent leakage through the blowdown vent stack.
      (2)  Operating mode, reciprocating rod packing emissions.
      (3)  Not operating, depressurized mode, unit isolation valve leakage through the blowdown vent stack, without blind flanges. 
      (i)  For the not operating, depressurized mode, each compressor must be measured at least once in any three consecutive calendar years if this mode is not found in the annual measurement.  If a compressor is not operated and has blind flanges in place throughout the 3 year period, measurement is not required in this mode.  If the compressor is in standby depressurized mode without blind flanges in place and is not operated throughout the 3 year period, it must be measured in the standby depressurized mode.
      (ii)  [Reserved]
      (4)  If reciprocating rod packing and blowdown vent are connected to an open-ended vent line use one of the following two methods to calculate emissions:
(i)  Measure emissions from all vents (including emissions manifolded to common vents) including rod packing, unit isolation valves, and blowdown vents using either calibrated bagging or high volume sampler according to methods set forth in §98.234 (c) and §98.234(d), respectively.
(ii)  Use a temporary meter such as a vane anemometer or a permanent meter such as an orifice meter to measure emissions from all vents (including emissions manifolded to a common vent) including rod packing vents and unit isolation valve leakage through blowdown vents according to methods set forth in §98.234(b).  If you do not have a permanent flow meter, you may install a port for insertion of a temporary meter or a permanent flow meter on the vents.  For through-valve leakage to open ended vents, such as unit isolation valves on not operating, depressurized compressors and blowdown valves on pressurized compressors, you may use an acoustic detection device according to methods set forth in §98.234(a).
      (5)  If reciprocating rod packing is not equipped with a vent line use the following method to calculate emissions:
(i)  You must use the methods described in §98.234 (a) to conduct annual leak detection of equipment leaks from the packing case into an open distance piece, or from the compressor crank case breather cap or other vent with a closed distance piece.
(ii)  Measure emissions found in paragraph (p)(5)(i) of this section using an appropriate meter, or calibrated bag, or high volume sampler according to methods set forth in §98.234(b), (c), and (d), respectively.
(6)  Estimate annual emissions using the flow measurement and Equation W-26 of this section.
		(Eq. W-26)
Where:
Es,i,m	=	Annual GHG i (either CH4 or CO2) volumetric emissions at standard conditions, in cubic feet.
MTm	=	Measured gas emissions in standard cubic feet per hour.
Tm	=	Total time the compressor is in the mode for which Es,i,m is being calculated, in the calendar year in hours.
Mi,m	=	Mole fraction of GHG i in gas; use the appropriate gas compositions in paragraph (u)(2) of this section.
(7)  Calculate annual emissions from each reciprocating compressor using Equation W-27 of this section.
		(Eq. W-27)
Where:
Es,i	=	Annual total volumetric GHG emissions at standard conditions from each reciprocating compressor in cubic feet.
EFm	=	Reporter emission factor for each mode, m, in cubic feet per hour, from Equation W-28 of this section as calculated in paragraph (p)(7)(i) of this section. 
Tm	=	Total time in hours per year the compressor was in each mode, m, as listed in paragraph (p)(1) through (p)(3).
GHGi	=	For onshore natural gas processing facilities, concentration of GHG i, CH4 or CO2, in produced natural gas or feed natural gas; for other facilities listed in §98.230(a)(4) through (a)(8), GHGi equals 1.
m	=	Compressor mode as listed in paragraph (p)(1) through (p)(3). 

(i)  You shall use the flow meter readings from measurements of operating and standby pressurized blowdown vent, operating mode vents, not operating depressurized isolation valve vent for all the reporter's compressor modes not measured in the calendar year to develop the following emission factors using Equation W-28 of this section for each mode as listed in paragraph (p)(1) through (p)(3). 
		(Eq. W-28)
Where:
EFm	=	Reporter emission factors for compressor in the three modes, m, in cubic feet per hour.
MTm	=	Meter readings from all reciprocating compressor vents in each and mode, m, in cubic feet per hour.
Countm	=	Total number of compressors measured in each mode, m.
m	=	Compressor mode as listed in paragraph (p)(1) through (p)(3). 
(A)  You must combine emissions for blowndown vents, measured in the operating and standby pressurized modes.
(B)  The emission factors must be calculated annually. You must use all measurements from the current calendar year and the preceding two calendar years, totaling three consecutive calendar years of measurements.
(ii)  [Reserved]
(8)  Determine if the reciprocating compressor vent vapors are sent to a vapor recovery system. 
(i)  Adjust the emissions estimated in paragraphs (p)(7) of this section downward by the magnitude of emissions recovered using a vapor recovery system as determined by engineering estimate based on best available data.
(ii)  [Reserved]

(9)  Onshore petroleum and natural gas production shall calculate emissions from reciprocating compressors as follows:
		(Eq. W-29)
Where:
Es,i	=	Annual total volumetric GHG emissions at standard conditions from reciprocating compressors in cubic feet.
Count	=	Total number of reciprocating compressors for the reporter.
EFi	=	Emission factor for GHG i.  Use 9.63 thousand standard cubic feet per year per compressor for CH4 and 0.535 thousand standard cubic feet per year per compressor for CO2 at 68°F and 14.7 psia or 9.48 thousand standard cubic feet per year per compressor for CH4 and 0.527 thousand standard cubic feet per year per compressor for CO2. at 60°F and 14.7 psia.
(10)  Estimate CH4 and CO2 volumetric and mass emissions from volumetric natural gas emissions using the calculations in paragraphs (u) and (v) of this section.
(q)  Leak detection and leaker emission factors.  You must use the methods described in §98.234(a) to conduct leak detection(s) of equipment leaks from all sources listed in §98.232(d)(7), (e)(7), (f)(5), (g)(3), (h)(4), and (i)(1).  This paragraph (q) applies to emissions sources in streams with gas content greater than 10 percent CH4  plus CO2 by weight.  Emissions sources in streams with gas content less than 10 percent CH4 plus CO2 by weight do not need to be reported.  Tubing systems equal to or less than one half inch diameter are exempt from the requirements of this paragraph (q) and do not need to be reported.  If equipment leaks are detected for sources listed in this paragraph (q), calculate equipment leak emissions per source per reporting facility using Equation W-30 of this section for each source with equipment leaks.  
		(Eq. W-30)
Where:
Es,i	=	Annual total volumetric GHG emissions at standard conditions from each equipment leak source in cubic feet.
x	=	Total number of this type of emissions source found to be leaking during Tx.
EFs	=	Leaker emission factor for specific sources listed in Table W-2 through Table W-7 of this subpart.
GHGi	=	For onshore natural gas processing facilities, concentration of GHGi, CH4 or CO2, in the total hydrocarbon of the feed natural gas; for other facilities listed in §98.230(a)(4) through (a)(8), GHGi equals 1 for CH4 and 1.1 x 10[-2] for CO2. 
Tx	=	The total time the component was found leaking and operational, in hours. If one leak detection survey is conducted, assume the component was leaking for the entire calendar year. If multiple leak detection surveys are conducted, assume that the component found to be leaking has been leaking since the previous survey or the beginning of the calendar year. For the last leak detection survey in the calendar year, assume that all leaking components continue to leak until the end of the calendar year. 
(1)  You must select to conduct either one leak detection survey in a calendar year or multiple complete leak detection surveys in a calendar year.  The number of leak detection surveys selected must be conducted during the calendar year.
(2)  Calculate GHG mass emissions in carbon dioxide equivalent at standard conditions using calculations in paragraph (v) of this section.
(3)  Onshore natural gas processing facilities shall use the appropriate default leaker emission factors listed in Table W-2 of this subpart for equipment leaks detected from valves, connectors, open ended lines, pressure relief valves, and meters.
(4)  Onshore natural gas transmission compression facilities shall use the appropriate default leaker emission factors listed in Table W-3 of this subpart for equipment leaks detected from valves, connectors, open ended lines, pressure relief valves, and meters. 
(5)  Underground natural gas storage facilities for storage stations shall use the appropriate default leaker emission factors listed in Table W-4 of this subpart for equipment leaks detected from valves, connectors, open ended lines, pressure relief valves, and meters.
(6)  LNG storage facilities shall use the appropriate default leaker emission factors listed in Table W-5 of this subpart for equipment leaks detected from valves, pump seals, connectors, and other.
(7)  LNG import and export facilities shall use the appropriate default leaker emission factors listed in Table W-6 of this subpart for equipment leaks detected from valves, pump seals, connectors, and other.
(8)  Natural gas distribution facilities for above ground meters and regulators at city gate stations at custody transfer, shall use the appropriate default leaker emission factors listed in Table W-7 of this subpart for equipment leak detected from connectors, block valves, control valves, pressure relief valves, orifice meters, regulators, and open ended lines.
(r)  Population count and emission factors.  This paragraph applies to emissions sources listed in §98.232 (c)(21), (f)(5), (g)(3), (h)(4), (i)(2), (i)(3), (i)(4) and (i)(5), on streams with gas content greater than 10 percent CH4  plus CO2 by weight.  Emissions sources in streams with gas content less than 10 percent CH4 plus CO2 by weight do not need to be reported.  Tubing systems equal or less than one half inch diameter are exempt from the requirements of paragraph (r) of this section and do not need to be reported.  Calculate emissions from all sources listed in this paragraph using Equation W-31 of this section.
		(Eq. W-31)
Where:
Es,i	=	Annual volumetric GHG emissions at standard conditions from each equipment leak source in cubic feet.
Counts	=	Total number of this type of emission source at the facility.  Average component counts are provided by major equipment piece in Tables W-1B and Table W-1C of this subpart.  Use average component counts as appropriate for operations in Eastern and Western U.S., according to Table W-1D of this subpart.EFs	=	Population emission factor for the specific source, s listed in Table W-1A and Tables W-3 through Table W-7 of this subpart.  Use appropriate population emission factor for operations in Eastern and Western U.S., according to Table W-1D of this subpart.  EF for non-custody transfer city gate stations is determined in Equation W-32.
GHGi	=	For onshore petroleum and natural gas production facilities and onshore natural gas processing facilities, concentration of GHG i, CH4 or CO2, in produced natural gas or feed natural gas; for other facilities listed in §98.230(a)(4) through (a)(8),GHGi equals 1 for CH4 and 1.1 x 10[-2] for CO2.
Ts	=	Total time the specific source s associated with the equipment leak emission was operational in the calendar year, in hours.

(1)  Calculate both CH4 and CO2 mass emissions from volumetric emissions using calculations in paragraph (v) of this section.
(2)  Onshore petroleum and natural gas production facilities shall use the appropriate default population emission factors listed in Table W-1A of this subpart for equipment leaks from valves, connectors, open ended lines, pressure relief valves, pump, flanges, and other.  Major equipment and components associated with gas wells are considered gas service components in reference to Table 1-A of this subpart and major natural gas equipment in reference to Table W-1B of this subpart.    Major equipment and components associated with crude oil wells are considered crude service components in reference to Table 1-A of this subpart and major crude oil equipment in reference to Table W-1C of this subpart.  Where facilities conduct EOR operations the emissions factor listed in Table W-1A of this subpart shall be used to estimate all streams of gases, including recycle CO2 stream.  The component count can be determined using either of the methodologies described in this paragraph (r)(2).  The same methodology must be used for the entire calendar year.
(i)  Component Count Methodology 1.  For all onshore petroleum and natural gas production operations in the facility perform the following activities:
(A)  Count all major equipment listed in Table W-1B and Table W-1C of this subpart.
(B)  Multiply major equipment counts by the average component counts listed in Table W-1B and W-1C of this subpart for onshore natural gas production and onshore oil production, respectively. Use the appropriate factor in Table W-1A of this subpart for operations in Eastern and Western U.S. according to the mapping in Table W-1D of this subpart.
(ii)  Component Count Methodology 2.  Count each component individually for the facility.  Use the appropriate factor in Table W-1A of this subpart for operations in Eastern and Western U.S. according to the mapping in Table W-1D of this subpart.
(3)  Underground natural gas storage facilities for storage wellheads shall use the appropriate default population emission factors listed in Table W-4 of this subpart for equipment leak from connectors, valves, pressure relief valves, and open ended lines.
(4)  LNG storage facilities shall use the appropriate default population emission factors listed in Table W-5 of this subpart for equipment leak from vapor recovery compressors.
(5)  LNG import and export facilities shall use the appropriate default population emission factor listed in Table W-6 of this subpart for equipment leak from vapor recovery compressors.
(6)  Natural gas distribution facilities shall use the appropriate emission factors as described in paragraph (r)(6) of this section.
(i)  Below grade meters and regulators; mains; and services, shall use the appropriate default population emission factors listed in Table W-7 of this subpart. 
(ii)  Above grade meters and regulators at city gate stations not at custody transfer as listed in §98.232(i)(2), shall use the total volumetric GHG emissions at standard conditions for all equipment leak sources calculated in paragraph (q)(8) of this section to develop facility emission factors using Equation W-32 of this section.  The calculated facility emission factor from Equation W-32 of this section shall be used in Equation W-31 of this section.
		(Eq. W-32)
Where:
EF	=	Facility emission factor for a meter at above grade M&R at city gate stations not at custody transfer in cubic feet per meter per year.
Es,i	=	Annual volumetric GHG emissions at standard condition from all equipment leak sources at all above grade M&R city gate stations at custody transfer, from paragraph (q) of this section.
Count	=	Total number of meter runs at all above grade M&R city gate stations at custody transfer.
(s)  Offshore petroleum and natural gas production facilities.  Report CO2, CH4, and N2O emissions for offshore petroleum and natural gas production from all equipment leaks, vented emission, and flare emission source types as identified in the data collection and emissions estimation study conducted by BOEMRE in compliance with 30 CFR 250.302 through 304.
(1) Offshore production facilities under BOEMRE jurisdiction shall report the same annual emissions as calculated and reported by BOEMRE in data collection and emissions estimation study published by BOEMRE referenced in 30 CFR 250.302 through 304 (GOADS).
(i) For any calendar year that does not overlap with the most recent BOEMRE emissions study publication year, report the most recent BOEMRE reported emissions data published by BOEMRE referenced in 30 CFR 250.302 through 304 (GOADS).  Adjust emissions based on the operating time for the facility relative to the operating time in the most recent BOEMRE published study.
(ii)  [Reserved]
(2) Offshore production facilities that are not under BOEMRE jurisdiction shall use monitoring methods and calculation methodologies published by BOEMRE referenced in 30 CFR 250.302 through 304 to calculate and report emissions (GOADS).
(i) For any calendar year that does not overlap with the most recent BOEMRE emissions study publication, report the most recent reported emissions data with emissions adjusted based on the operating time for the facility relative to operating time in the previous reporting period.
(ii)  [Reserved]
(3) If BOEMRE discontinues or delays their data collection effort by more than 4 years, then offshore reporters shall once in every 4 years use the most recent BOEMRE data collection and emissions estimation methods to report emission from the facility sources.  
(4) For either first or subsequent year reporting, offshore facilities either within or outside of BOEMRE jurisdiction that were not covered in the previous BOEMRE data collection cycle shall use the most recent BOEMRE data collection and emissions estimation methods published by BOEMRE referenced in 30 CFR 250.302 through 304 to calculate and report emissions (GOADS) to report emissions.
(t)  Volumetric emissions.  Calculate volumetric emissions at standard conditions as specified in paragraphs (t)(1) or (2) of this section determined by engineering estimate based on best available data unless otherwise specified.  
(1)  Calculate natural gas volumetric emissions at standard conditions by converting actual temperature and pressure of natural gas emissions to standard temperature and pressure of natural gas using Equation W-33 of this section. 
		(Eq. W-33)
Where:
Es,n 	=	Natural gas volumetric emissions at standard temperature and pressure (STP) conditions in cubic feet.
Ea,n 	=	Natural gas volumetric emissions at actual conditions in cubic feet.
Ts  	=	Temperature at standard conditions ([o]F).
Ta  	=	Temperature at actual emission conditions ([o]F).
Ps  	=	Absolute pressure at standard conditions (psia).
Pa  	=	Absolute pressure at actual conditions (psia).

(2)  Calculate GHG volumetric emissions at standard conditions by converting actual temperature and pressure of GHG emissions to standard temperature and pressure using Equation W-34 of this section. 
	



s
a
a
s
i
a
i
s
P
T
P
T
E
E
*
67
.
459
*
67
.
459
*
,
,



	(Eq. W-34)Where:
Es,i 	=	GHG i volumetric emissions at standard temperature and pressure (STP) conditions in cubic feet.
Ea,i 	=	GHG i volumetric emissions at actual conditions in cubic feet.
Ts  	=	Temperature at standard conditions ([o]F).
Ta  	=	Temperature at actual emission conditions ([o]F).
Ps  	=	Absolute pressure at standard conditions (psia).
Pa  	=	Absolute pressure at actual conditions (psia).

(u)  GHG volumetric emissions.  Calculate GHG volumetric emissions at standard conditions as specified in paragraphs (u)(1) and (2) of this section determined by engineering estimate based on best available data unless otherwise specified.
(1)  Estimate CH4 and CO2 emissions from natural gas emissions using Equation W-35 of this section.
		(Eq. W-35)
Where:
Es,i	=	GHG i (either CH4 or CO2) volumetric emissions at standard conditions in cubic feet.
Es,n	=	Natural gas volumetric emissions at standard conditions in cubic feet.
Mi	=	Mole fraction of GHG i in the natural gas. 

(2)  For Equation W-35 of this section, the mole fraction, Mi, shall be the annual average mole fraction for each facility, as specified in paragraphs (u)(2)(i) through (vii) of this section.
(i)  GHG mole fraction in produced natural gas for onshore petroleum and natural gas production facilities.  If you have a continuous gas composition analyzer for produced natural gas, you must use these values for determining the mole fraction.  If you do not have a continuous gas composition analyzer, then you must use your most recent gas composition based on available sample analysis of the field.
(ii)  GHG mole fraction in feed natural gas for all emissions sources upstream of the de-methanizer or dew point control and GHG mole fraction in facility specific residue gas to transmission pipeline systems for all emissions sources downstream of the de-methanizer overhead or dew point control for onshore natural gas processing facilities.  If you have a continuous gas composition analyzer on feed natural gas, you must use these values for determining the mole fraction.  If you do not have a continuous gas composition analyzer, then annual samples must be taken according to methods set forth in §98.234(b).
(iii)  GHG mole fraction in transmission pipeline natural gas that passes through the facility for onshore natural gas transmission compression facilities. 
(iv)  GHG mole fraction in natural gas stored in underground natural gas storage facilities.  
(v)  GHG mole fraction in natural gas stored in LNG storage facilities.  
(vi)  GHG mole fraction in natural gas stored in LNG import and export facilities. 
(vii)  GHG mole fraction in local distribution pipeline natural gas that passes through the facility for natural gas distribution facilities. 
(v)  GHG mass emissions.  Calculate GHG mass emissions in carbon dioxide equivalent at standard conditions by converting the GHG volumetric emissions into mass emissions using Equation W-36 of this section.
		(Eq. W-36)
Where:
Masss,i	=	GHG i (either CH4 or CO2) mass emissions at standard conditions in metric tons CO2e.  
Es,i	=	GHG i (either CH4 or CO2) volumetric emissions at standard conditions, in cubic feet.
	=	Density of GHG i. Use 0.0520 kg/ft[3] for CO2 and N2O, and 0.0190 kg/ft[3] for CH4 at 68°F and 14.7 psia or 0.0530 kg/ft[3] for CO2 and N2O, and 0.0193 kg/ft[3] for CH4 at 60°F and 14.7 psia .
GWP	=	Global warming potential, 1 for CO2, 21 for CH4, and 310 for N2O.

(w)  EOR injection pump blowdown.  Calculate CO2 pump blowdown emissions as follows: 
(1)  Calculate the total volume in cubic feet (including pipelines, manifolds and vessels) between isolation valves.
(2)  Retain logs of the number of blowdowns per calendar year.
(3)  Calculate the total annual venting emissions using Equation W-37 of this section:

		(Eq. W-37)
Where:
Massc,i	=	Annual EOR injection gas venting emissions in metric tons at critical conditions "c" from blowdowns.
N	=	Number of blowdowns for the equipment in the calendar year.
Vv	=	Total volume in cubic feet of blowdown equipment chambers (including pipelines, manifolds and vessels) between isolation valves.
Rc	=	Density of critical phase EOR injection gas in kg/ft[3]. You may use an appropriate standard method published by a consensus-based standards organization if such a method exists or you may use an industry standard practice to determine density of super critical EOR injection gas.
GHGi	=	Mass fraction of GHGi in critical phase injection gas.
1 x 10[-3]	=	Conversion factor from kilograms to metric tons.
(x)  EOR hydrocarbon liquids dissolved CO2.  Calculate dissolved CO2 in hydrocarbon liquids produced through EOR operations as follows:
(1)  Determine the amount of CO2 retained in hydrocarbon liquids after flashing in tankage at STP conditions.  Annual samples must be taken according to methods set forth in §98.234(b) to determine retention of CO2 in hydrocarbon liquids immediately downstream of the storage tank.  Use the annual analysis for the calendar year.
(2)  Estimate emissions using Equation W-38 of this section.
	Masss,CO2 = Shl * Vhl	(Eq. W-38)
Where:
Masss,CO2 =		Annual CO2 emissions from CO2 retained in hydrocarbon liquids produced through EOR operations beyond tankage, in metric tons.
Shl	=	Amount of CO2 retained in hydrocarbon liquids in metric tons per barrel, under standard conditions.
Vhl	=	Total volume of hydrocarbon liquids produced at the EOR operations in barrels in the calendar year.

(y)  [Reserved] 
(z)  Onshore petroleum and natural gas production and natural gas distribution combustion emissions.  Calculate CO2 CH4, and N2O combustion-related emissions from stationary or portable equipment, except as specified in paragraph (z)(3) of this section, as follows:
(1)  If the fuel combusted in the stationary or portable equipment is listed in Table C-1 of subpart C of this part, or is a blend of fuels listed in Table C-1, use the Tier 1 methodology described in subpart C of this part (General Stationary Fuel Combustion Sources).  If the fuel combusted is natural gas and is pipeline quality and has a minimum high heat value of 950 Btu per standard cubic foot, then the natural gas emission factor and high heat values listed in Tables C-1 and C-2 of this part may be used.
(2)  For fuel combustion units that combust field gas or process vent gas, or any blend of field gas or process vent gas and fuels listed in Table C-1 of subpart C of this part, calculate combustion emissions as follows: 
(i)  If you have a continuous flow meter on the combustion unit, you must use the measured flow volumes to calculate the total flow of gas to the unit.  If you do not have a permanent flow meter on the combustion unit, you may install a permanent flow meter on the combustion unit, or use company records or engineering calculations based on best available data on heat duty or horsepower to estimate volumetric unit gas flow. 
(ii)  If you have a continuous gas composition analyzer on fuel to the combustion unit, you must use these compositions for determining the concentration of gas hydrocarbon constituent in the flow of gas to the unit.  If you do not have a continuous gas composition analyzer on gas to the combustion unit, you must use the appropriate gas compositions for each stream of hydrocarbons going to the combustion unit as specified in paragraph (u)(2)(i) of this section.
(iii)  Calculate GHG volumetric emissions at actual conditions using Equations W-39 of this section.
              			
		
		

		(Eq. W-39A)
		(Eq. W-39B)
Where:
Ea,CO2 	= 	Contribution of annual emissions from portable or stationary fuel combustion sources in cubic feet, under actual conditions.
Ea,CH4 	= 	Contribution of annual CH4 emissions from portable or stationary fuel combustion sources in cubic feet, under actual conditions.
η	=	Combustion efficiency for portable and stationary equipment determined based on engineering estimation. 

Va	=	Volume of gas sent to combustion unit in cubic feet, during the year.
Yj 	=	Concentration of gas hydrocarbon constituents j (such as methane, ethane, propane, butane, and pentanes plus) in gas sent to combustion unit.
YCH4	=    Concentration of methane constituent in gas sent to combustion unit.

YCO2	=    Concentration of CO2 constituent in gas sent to combustion unit.

Rj	=	Number of carbon atoms in the gas hydrocarbon constituent j; 1 for methane, 2 for ethane, 3 for propane, 4 for butane, and 5 for pentanes plus) in gas sent to combustion unit.

 
(iv)  Calculate GHG volumetric emissions at standard conditions using calculations in paragraph (t) of this section.
(v)  Calculate both combustion-related CH4 and CO2 mass emissions from volumetric CH4 and CO2 emissions using calculation in paragraph (v) of this section.
      (vi)  Calculate N2O mass emissions using Equation W-40 of this section.

		(Eq. W-40)
		

Where:
N2O 	= 	Annual N2O emissions from the combustion of a particular type of fuel (metric tons).
Fuel	=	Mass or volume of the fuel combusted (mass or volume per year, choose appropriately to be consistent with the units of HHV).
HHV 	=	For the high heat value for field gas or process vent gas, use 1.235 x 10[-3] mmBtu/scf for HHV
EF		=	Use 1.0 x 10[-4] kg N2O/mmBtu.
1 x 10[-3]		=	Conversion factor from kilograms to metric tons.





(3)  External fuel combustion sources with a rated heat capacity equal to or less than 5 mmBtu/hr do not need to report combustion emissions or include these emissions for threshold determination in §98.231(a).  You must report the type and number of each external fuel combustion unit.

§98.234  Monitoring and QA/QC requirements.
The GHG emissions data for petroleum and natural gas emissions sources must be quality assured as applicable as specified in this section. Offshore petroleum and natural gas production facilities shall adhere to the monitoring and QA/QC requirements as set forth in 30 CFR 250.
(a)  You must use any of the methods described as follows in this paragraph to conduct leak detection(s) of equipment leaks and through-valve leakage from all source types listed in §98.233(k), (o), (p) and (q) that occur during a calendar year, except as provided in paragraph (a)(4) of this section.  
(1)  Optical gas imaging instrument.  Use an optical gas imaging instrument for equipment leak detection in accordance with 40 CFR part 60, subpart A, §60.18(i)(1) and (2) of the Alternative work practice for monitoring equipment leaks.  Any emissions detected by the optical gas imaging instrument is a leak unless screened with Method 21 (40 CFR part 60, appendix A-7) monitoring, in which case 10,000 ppm or greater is designated a leak.  In addition, you must operate the optical gas imaging instrument to image the source types required by this subpart in accordance with the instrument manufacturer's operating parameters.
(2)  Method 21.  Use the equipment leak detection methods in 40 CFR part 60, appendix A-7, Method 21.  If using Method 21 monitoring, if an instrument reading of 10,000 ppm or greater is measured, a leak is detected.  Inaccessible emissions sources, as defined in 40 CFR part 60, are not exempt from this subpart.  Owners or operators must use alternative leak detection devices as described in paragraph(a)(1) of this section to monitor inaccessible equipment leaks or vented emissions. 
(3)  Infrared laser beam illuminated instrument.  Use an infrared laser beam illuminated instrument for equipment leak detection.  Any emissions detected by the infrared laser beam illuminated instrument is a leak unless screened with Method 21 monitoring, in which case 10,000 ppm or greater is designated a leak.  In addition, you must operate the infrared laser beam illuminated instrument to detect the source types required by this subpart in accordance with the instrument manufacturer's operating parameters.
(4)  Optical gas imaging instrument.  An optical gas imaging instrument must be used for all source types that are inaccessible and cannot be monitored without elevating the monitoring personnel more than 2 meters above a support surface. 
(5)  Acoustic leak detection device.  Use the acoustic leak detection device to detect through-valve leakage.  When using the acoustic leak detection device to quantify the through-valve leakage, you must use the instrument manufacturer's calculation methods to quantify the through-valve leak.  When using the acoustic leak detection device, if a leak of 3.1 scf per hour or greater is calculated, a leak is detected.  In addition, you must operate the acoustic leak detection device to monitor the source valves required by this subpart in accordance with the instrument manufacturer's operating parameters. 
(b)  You must operate and calibrate all flow meters, composition analyzers and pressure gauges used to measure quantities reported in §98.233 according to the procedures in §98.3(i) and the procedures in paragraph (b) of this section.  You may use an appropriate standard method published by a consensus-based standards organization if such a method exists or you may use an industry standard practice.  Consensus-based standards organizations include, but are not limited to, the following: ASTM International, the American National Standards Institute (ANSI), the American Gas Association (AGA), the American Society of Mechanical Engineers (ASME), the American Petroleum Institute (API), and the North American Energy Standards Board (NAESB).
(c)  Use calibrated bags (also known as vent bags) only where the emissions are at near-atmospheric pressures such that it is safe to handle and can capture all the emissions, below the maximum temperature specified by the vent bag manufacturer, and the entire emissions volume can be encompassed for measurement. 
(1)  Hold the bag in place enclosing the emissions source to capture the entire emissions and record the time required for completely filling the bag.  If the bag inflates in less than one second, assume one second inflation time.
(2)  Perform three measurements of the time required to fill the bag, report the emissions as the average of the three readings.
(3)  Estimate natural gas volumetric emissions at standard conditions using calculations in §98.233(t).
(4)  Estimate CH4 and CO2 volumetric and mass emissions from volumetric natural gas emissions using the calculations in §98.233(u) and (v).
(d)  Use a high volume sampler to measure emissions within the capacity of the instrument. 
(1)  A technician following manufacturer instructions shall conduct measurements, including equipment manufacturer operating procedures and measurement methodologies relevant to using a high volume sampler, including positioning the instrument for complete capture of the equipment leak without creating backpressure on the source.
(2)  If the high volume sampler, along with all attachments available from the manufacturer, is not able to capture all the emissions from the source then use anti-static wraps or other aids to capture all emissions without violating operating requirements as provided in the instrument manufacturer's manual. 
(3)  Estimate CH4 and CO2 volumetric and mass emissions from volumetric natural gas emissions using the calculations in §98.233(u) and (v).
(4)  Calibrate the instrument at 2.5 percent methane with 97.5 percent air and 100 percent CH4 by using calibrated gas samples and by following manufacturer's instructions for calibration.
(e)  Peng Robinson Equation of State means the equation of state defined by Equation W-41 of this section:
		(Eq. W-41)
Where:
p	=	Absolute pressure.
R	=	Universal gas constant.
T	=	Absolute temperature.
Vm	=	Molar volume.
	a = 
	b = 
	α = 
Where:

ω	=	Acentric factor of the species.
Tc	=	Critical temperature.
Pc	=	Critical pressure.

(f)  Special reporting provisions
(1)  Best available monitoring methods.  EPA will allow owners or operators to use best available monitoring methods for parameters in §98.233 Calculating GHG Emissions as specified in paragraphs (f)(2), (f)(3), and (f)(4) of this section.  If the reporter anticipates the potential need for best available monitoring for sources for which they need to petition EPA and the situation is unresolved at the time of the deadline, reporters should submit written notice of this potential situation to EPA by the specified deadline for requests to be considered.  EPA reserves the right to review petitions after the deadline but will only consider and approve late petitions which demonstrate extreme or unusual circumstances.  The Administrator reserves to right to request further information in regard to all petition requests.  The owner or operator must use the calculation methodologies and equations in §98.233 Calculating GHG Emissions.  Best available monitoring methods means any of the following methods specified in paragraph (f)(1) of this section: 
(i)  Monitoring methods currently used by the facility that do not meet the specifications of this subpart. 
(ii)  Supplier data.
(iii)  Engineering calculations. 
(iv)  Other company records. 
(2)  Best available monitoring methods for well-related emissions.  During January 1, 2011 through June 30, 2011, owners or operators may use best available monitoring methods for any well-related data that cannot reasonably be measured according to the monitoring and QA/QC requirements of this subpart, and only where required measurements cannot be duplicated due to technical limitations after June 30, 2011.  These well-related sources are:
(i)  Gas well venting during well completions and workovers with hydraulic fracturing as specified in §98.233(g).
(ii)  Well testing venting and flaring as specified in §98.233(l).
(3)  Best available monitoring methods for specified activity data.  During January 1, 2011 through June 30, 2011, owners or operators may use best available monitoring methods for activity data as listed below that cannot reasonably be obtained according to the monitoring and QA/QC requirements of this subpart, specifically for events that generate data that can be collected only between January 1, 2011 and June 30, 2011 and cannot be duplicated after June 30, 2011.  These sources are:
(i)  Cumulative hours of venting, days, or times of operation in §98.233(e), (f), (g), (h), (l), (o), (p), (q), and (r).
(ii)  Number of blowdowns, completions, workovers, or other events in §98.233(f), (g), (h), (i), and (w).
(iii)  Cumulative volume produced, volume input or output, or volume of fuel used in paragraphs §98.233(d), (e), (j), (k), (l), (m), (n), (x), (y), and (z).
(4)  Best available monitoring methods for leak detection and measurement.  The owner or operator may request use of best available monitoring methods between January 1, 2011 and December 31, 2011 for sources requiring leak detection and/or measurement.  These sources include:
(i)  Reciprocating compressor rod packing venting in onshore natural gas processing, onshore natural gas transmission compression, underground natural gas storage, LNG storage, and LNG import and export equipment as specified in §98.232 (d)(1), (e)(1), (f)(1), (g)(1), and (h)(1).
(ii)  Centrifugal compressor wet seal oil degassing venting in onshore natural gas processing, onshore natural gas transmission compression, underground natural gas storage, LNG storage, and LNG import and export equipment as specified in §98.232(d)(2), (e)(2), (f)(2), (g)(2), and (h)(2).
(iii)  Acid gas removal vent stacks in onshore petroleum and natural gas production and onshore natural gas processing as specified in §98.232(c)(17) and (d)(6).
(iv)  Equipment leak emissions from valves, connectors, open ended lines, pressure relief valves, block valves, control valves, compressor blowdown valves, orifice meters, other meters, regulators, vapor recovery compressors, centrifugal compressor dry seals, and/or other equipment leaks in onshore natural gas processing, onshore natural gas transmission compression, underground natural gas storage, LNG storage, LNG import and export equipment, and natural gas distribution as specified in §98.232 (d)(7), (e)(7), (f)(5), (g)(3), (h)(4), and (i)(1).
(v)  Condensate (oil and/or water) storage tanks in onshore natural gas transmission compression as specified in §98.232(e)(3).
(5)  Requests for 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.
(i)  No request or approval by the Administrator is necessary to use best available monitoring methods between January 1, 2011 and June 30, 2011 for the sources specified in paragraph (f)(2) of this section.
(ii)  No request or approval by the Administrator is necessary to use best available monitoring methods between January 1, 2011 and June 30, 2011 for the sources specified in paragraph (f)(3) of this section.
(iii)  Owners or operators must submit a request and receive approval by the Administrator to use best available monitoring methods between January 1, 2011 and December 31, 2011 for sources specified in paragraph (f)(4) of this section.
(A)  Timing of request.  The request to use best available monitoring methods for paragraph (f)(4) of this section must be submitted to EPA no later than April 30, 2011. 
(B)  Content of request.  Requests must contain the following information for sources listed in paragraph (f)(4) of this section:
(1)  A list of specific source types and specific equipment, monitoring instrumentation, and/or services for which the request is being made and the locations where each piece of monitoring instrumentation will be installed or monitoring service will be supplied.
(2)  Identification of the specific rule requirements (by subpart, section, and paragraph number) for which the instrumentation or monitoring service is needed.
(3)  Documentation which demonstrates that the owner or operator made all reasonable efforts to obtain the information, services or equipment necessary to comply with subpart W reporting requirements, including evidence of specific service or equipment providers contacted and why services or information could not be obtained during 2011.
(4)  A description of the specific actions the facility will take to obtain and/or install the equipment or obtain the monitoring service as soon as reasonably feasible and the expected date by which the equipment will be obtained and operating or service will be provided.
(C)  Approval criteria.  To obtain approval, the owner or operator must demonstrate to the Administrator's satisfaction that it does not own the required monitoring equipment, and it is not reasonably feasible to acquire, install, and operate a required piece of monitoring equipment or to obtain leak detection or measurement services in order to meet the requirements of this subpart for 2011.
(iv) EPA does not anticipate a need to approve the use of best available monitoring methods for sources not listed in paragraphs(f)(2), (f)(3), and (f)(4) of this section; however, EPA will review such requests if submitted in accordance with paragraph (f)(5)(iv)(A)-(C) of this section.
(A)  Timing of request.  The request to use best available monitoring methods for sources not listed in paragraphs (f)(2), (f)(3), and (f)(4) of this section must be submitted to EPA no later than April 30, 2011. 
(B)  Content of request.  Requests must contain the following information:
(1)  A list of specific source categories and parameters for which the owner or operator is seeking use of best available monitoring methods.
(2)  A description of the data collection methodologies that do not meet safety regulations, technical infeasibility, or specific laws or regulations that conflict with each specific source for which an owner or operator is requesting use of best available monitoring methodologies.   
(3)  A detailed explanation and supporting documentation of how and when the owner or operator will receive the services or equipment to comply with all subpart W reporting requirements.  
(C)  Approval criteria.  To obtain approval, the owner or operator must demonstrate to the Administrator's satisfaction that the owner or operator faces unique safety, technical or legal issues rendering them unable to   meet the requirements of this subpart for 2011.
(6)  Requests for extension of the use of best available monitoring methods through December 31, 2011 for sources in paragraph (f)(2) of this section.  The owner or operator may submit a request to the Administrator to use one or more best available monitoring methods described in paragraph (f)(2) of this section beyond June 30, 2011.  
(i)  Timing of request.  The extension request must be submitted to EPA no later than April 30, 2011.  
(ii)  Content of request.  Requests must contain the following information:
(A)  A list of specific source types and specific equipment, monitoring instrumentation, contract modifications, and/or services for which the request is being made and the locations where each piece of monitoring instrumentation will be installed, monitoring service will be supplied, or contracts will be modified. 
(B)  Identification of the specific rule requirements (by subpart, section, and paragraph number) for which the instrumentation, contract modification, or monitoring service is needed. 
(C)  A description and applicable correspondence outlining the diligent efforts of the owner or operator in obtaining the needed equipment or service and why they could not be obtained and installed in a period of time enabling completion of applicable requirements of this subpart within the 2011 calendar year. 
(D)  If the reason for the extension is that the owner or operator cannot collect data from a service provider or relevant organization in order for the owner or operator to meet requirements of this subpart for the 2011 calendar year, the owner or operator must demonstrate a good faith effort that it is not possible to obtain the necessary information, service or hardware which may include providing correspondence from specific service providers or other relevant entities to the owner or operator, whereby the service provider states that it is unable to provide the necessary data or services requested by the owner or operator that would enable the owner or operator to comply with subpart W reporting requirements by June 30, 2011.  
(E)  A description of the specific actions the owner or operator will take to comply with monitoring requirements in 2012 and beyond.
(iii)  Approval criteria.  To obtain approval, the owner or operator must demonstrate to the Administrator's satisfaction that it is not reasonably feasible to obtain the data necessary to meet the requirements of this subpart for the sources specified in paragraph (f)(2) of this section by June 30, 2011. 
(7)  Requests for extension of the use of best available monitoring methods through December 31, 2011 for sources in paragraph (f)(3) of this section.  The owner or operator may submit a request to the Administrator to use one or more best available monitoring methods described in paragraph (f)(3) of this section beyond June 30, 2011.  
(i)  Timing of request. The extension request must be submitted to EPA no later than April 30, 2011.  
(ii)  Content of request. Requests must contain the following information:
(A)  A list of specific source types for which data collection could not be implemented.
(B)  Identification of the specific rule requirements (by subpart, section, and paragraph number) for which the data collection could not be implemented. 
(C)  A description of the data collection methodologies that do not meet safety regulations, technical infeasibility, or specific laws or regulations that conflict with each specific source for which an owner or operator is requesting use of best available  monitoring methodologies for which data collection could not be implemented in the 2011 calendar year.
(iii)  Approval criteria. To obtain approval, the owner or operator must demonstrate to the Administrator's satisfaction that it is not reasonably feasible to implement the data collection for the sources described in paragraph (f)(3) of this section for the methods required in this subpart by June, 30, 2011.
(8)  Requests for extension of the use of best available monitoring methods beyond 2011 for sources listed in paragraphs (f)(2), (f)(3), (f)(4), (f)(5)(iv) of this section and other sources in this subpart.  EPA does not anticipate a need for approving the use of best available methods beyond December 31, 2011, except in extreme circumstances, which include safety, a requirement being technically infeasible or counter to other local, State, or Federal regulations.  
(i)  Timing of request.  The request to use best available monitoring methods for paragraphs (f)(2), (f)(3), (f)(4), (f)(5)(iv) of this section and sources not listed in paragraphs (f)(2), (f)(3), (f)(4), (f)(5)(iv) of this section must be submitted to EPA no later than September 30, 2011. 
(ii)  Content of request.  Requests must contain the following information: 
(iii)  A list of specific source categories and parameters for which the owner or operator is seeking use of best available monitoring methods.
(iv)  A description of the data collection methodologies that do not meet safety regulations, technical infeasibility, or specific laws or regulations that conflict with each specific source for which an owner or operator is requesting use of best available monitoring methodologies.   
(v)  A detailed explanation and supporting documentation of how and when the owner or operator will receive the services or equipment to comply with all of this subpart W reporting requirements.  
(C)  Approval criteria. To obtain approval, the owner or operator must demonstrate to the Administrator's satisfaction that the owner or operator faces unique safety, technical or legal issues rendering them unable to    meet the requirements of this subpart.

§98.235 Procedures for estimating missing data.
A complete record of all estimated and/or measured parameters used in the GHG emissions calculations is required.  If data are lost or an error occurs during annual emissions estimation or measurements, you must repeat the estimation or measurement activity for those sources as soon as possible, including in the subsequent calendar year if missing data are not discovered until after December 31 of the year in which data are collected, until valid data for reporting is obtained.  Data developed and/or collected in a subsequent calendar year to substitute for missing data cannot be used for that subsequent year's emissions estimation.  Where missing data procedures are used for the previous year, at least 30 days must separate emissions estimation or measurements for the previous year and emissions estimation or measurements for the current year of data collection. For missing data which are continuously monitored or measured, (for example flow meters), or for missing temperature or pressure data that are required under §98.236, the reporter may use best available data for use in emissions determinations.  The reporter must record and report the basis for the best available data in these cases.
§98.236  Data reporting requirements.
In addition to the information required by §98.3(c), each annual report must contain reported emissions and related information as specified in this section.
(a)  Report annual emissions separately for each of the industry segments listed in paragraphs (a)(1) through (8) of this section in metric tons CO2e per year at standard conditions.  For each segment, report emissions from each source type §98.232(a) in the aggregate, unless specified otherwise.  For example, an onshore natural gas production operation with multiple reciprocating compressors must report emissions from all reciprocating compressors as an aggregate number.
(1)  Onshore petroleum and natural gas production.
(2)  Offshore petroleum and natural gas production.
(3)  Onshore natural gas processing.
(4)  Onshore natural gas transmission compression.
(5)  Underground natural gas storage.
(6)  LNG storage.
(7)  LNG import and export.
(8)  Natural gas distribution.  Report each source in the aggregate for pipelines and for Metering and Regulating (M&R) stations.
(b)  Offshore petroleum and natural gas production is not required to report activity data and emissions for each aggregated source under §98.236 (c). Reporting requirements for offshore petroleum and natural gas production is set forth by BOEMRE in compliance with 30 CFR 250.302 through 304. 
(c)  For each aggregated source, unless otherwise specified, report activity data and emissions (in metric tons CO2e per year at standard conditions) for each aggregated source type as follows:
(1)  For natural gas pneumatic devices (refer to Equation W-1 of §98.233), report the following:  
(i)  Actual count and estimated count separately of natural gas pneumatic high bleed devices as applicable.
(ii)  Actual count and estimated count separately of natural gas pneumatic low bleed devices as applicable. 
(iii)  Actual count and estimated count separately of natural gas pneumatic intermittent bleed devices as applicable. 
(iv)  Report emissions collectively. 
(2)  For natural gas driven pneumatic pumps (refer to Equation W-2 of §98.233), report the following, 
(i)  Count of natural gas driven pneumatic pumps.
(ii)  Report emissions collectively. 
(3)  For each acid gas removal unit (refer to Equation W-3 and Equation W-4 of §98.233), report the following:
(i)  Total throughput off the acid gas removal unit using a meter or engineering estimate based on process knowledge or best available data in million cubic feet per year.
(ii)  For Calculation Methodology 1 and Calculation Methodology 2 of §98.233(d), fraction of CO2 content in the vent from the acid gas removal unit (refer to §98.233(d)(6)).
(iii)  For Calculation Methodology 3 of §98.233(d), volume fraction of CO2 content of natural gas into and out of the acid gas removal unit (refer to §98.233(d)(7) and (d)(8)).
(iv)	Report emissions from the AGR unit recovered and transferred outside the facility.
(v)  Report emissions individually. 
(4)  For dehydrators, report the following:
(i)  For each Glycol dehydrator with a throughput greater than or equal to 0.4 MMscfd (refer to §98.233(e)(1)), report the following: 
(A)  Glycol dehydrator feed natural gas flow rate in MMscfd, determined by engineering estimate based on best available data.
(B)  Glycol dehydrator absorbent circulation pump type.
(C)  Whether stripper gas is used in glycol dehydrator. 
(D)  Whether a flash tank separator is used in glycol dehydrator. 
(E)  Type of absorbent.
(F)  Total time the glycol dehydrator is operating in hours.
(G)  Temperature, in degrees Fahrenheit and pressure, in psig, of the wet natural gas.
(H)  Concentration of CH4 and CO2 in natural gas.
(I)  What vent gas controls are used (refer to §98.233(e)(3) and (e)(4)). 
(J)  Report vent and flared emissions individually. 
(ii)  For all glycol dehydrators with a throughput less than 0.4 MMscfd (refer to §98.233, Equation W-5 of §98.233), report the following:
(A)  Count of glycol dehydrators.
(B)  Whether any vent gas controls are used (refer to §98.233(e)(3) and (e)(4)).
(C)  Report vent emissions collectively. 
(iii)  For absorbent desiccant dehydrators (refer to Equation W-6 of §98.233), report the following:
(A)  Count of desiccant dehydrators.
(B)  Report emissions collectively. 
(5)  For well venting for liquids unloading (refer to Equations W-7, W-8 and W-9 of §98.233), report the following by field:
(i)  Count of wells vented to the atmosphere for liquids unloading.
(ii)  Count of plunger lifts.
(iii)  Cumulative number of unloadings vented to the atmosphere.
(iv)  Average flow rate of the measured well venting in cubic feet per hour (refer to §98.233(f)(1)(i)(A)).
(v)  Average casing diameter in inches.
(vi)  Report emissions collectively. 
(6)  For well completions and workovers, report the following for each field: 
(i)  For gas well completions and workovers with hydraulic fracturing (refer to Equation W-10 of §98.233):
(A)  Total count of completions in calendar year.
(B)  Average flow rate of the measured well completion venting in cubic feet per hour (refer to §98.233(g)(1)(i) or (g)(1)(ii)).
(C)  Total count of workovers in calendar year.
(D)  Average flow rate of the measured well workover venting in cubic feet per hour (refer to §98.233(g)(1)(i) or (g)(1)(ii)).
(E)  Total number of days of gas venting to the atmosphere during backflow for completion. 
(F)  Total number of days of gas venting to the atmosphere during backflow for workovers.
(G)  Report number of completions and workovers employing reduced emissions completions and engineering estimate based on best available data of the amount of gas recovered to sales.
(H)   Report vent emissions collectively. Report flared emissions collectively.
Report vent emissions collectively.  Report flared emissions collectively. 
(ii)  For gas well completions and workovers without hydraulic fracturing (refer to Equation W-13 of §98.233): 
(A)  Total count of completions in calendar year.
(B)  Total count of workovers in calendar year that flare gas or vent gas to the atmosphere.
(C)  Total number of days of gas venting to the atmosphere during backflow for completion. 
(D)  Report vent emissions collectively. Report flared emissions collectively.
(7)  For each blowdown vent stack (refer to Equation W-14 of §98.233), report the following:
(i)  Total number of blowdowns per unique volume type in calendar year. 
(ii)  Report emissions collectively per equipment type.  
(8)  For gas emitted from produced oil sent to atmospheric tanks: 
(i)  For wellhead gas-liquid separator with oil throughput greater than or equal to 10 barrels per day, using Calculation Methodology 1 and 2 of §98.233(j), report the following by field: 
(A)  Number of wellhead separators sending oil to atmospheric tanks.
(B)  Estimated average separator temperature, in degrees Fahrenheit, and estimated average pressure, in psig.
(C)  Estimated average sales oil stabilized API gravity, in degrees.
(D)  Count of hydrocarbon tanks at well pads.
(E)  Best estimate of count of stock tanks not at well pads receiving your oil.
(F)  Total volume of oil from all wellhead separators sent to tank(s) in barrels per year.
(G)  Count of tanks with emissions control measures, either vapor recovery system or flaring, for tanks at well pads.
(H)  Best estimate of count of stock tanks assumed to have emissions control measures not at well pads, receiving your oil.
(I)  Range of concentrations of flash gas, CH4 and CO2.
(J)  Report emissions individually for Calculation Methodology 1 and 2 of §98.233(j). 
(ii)  For wells with oil production greater than or equal to 10 barrels per day, using Calculation Methodology 3 and 4 of §98.233(j), report the following by field: 
(A)  Total volume of sales oil from all wells in barrels per year.
(B)  Total number of wells sending oil directly to tanks.
(C)  Total number of wells sending oil to separators off the well pads.
(D)  Sales oil API gravity range for (B) and (C) of this section, in degrees. 
(E)  Count of hydrocarbon tanks on wellpads
(F)  Count of hydrocarbon tanks, both on and off well pads assumed to have emissions control measures: either vapor recovery system or flaring of tank vapors.
(G)  Report emissions collectively for Calculation Methodology 3 and 4 of §98.233(j). 
(iii)  For wellhead gas-liquid separators and wells with throughput less than 10 barrels per day, using Calculation Methodology 5 of §98.233(j) Equation W-15 of §98.233), report the following:
(A)  Number of wellhead separators.
(B)  Number of wells without wellhead separators.
(C)  Total volume of oil production in barrels per year. 
(D)  Best estimate of fraction of production sent to tanks with assumed control measures: either vapor recovery system or flaring of tank vapors.
(E) Count of hydrocarbon tanks on well pads.
(F)  Report CO2  and CH4 emissions collectively. 
(iv)  If wellhead separator dump valve is functioning improperly during the calendar year (refer to Equation W-16 of §98.233), report the following:
(A)  Count of wellhead separators that dump valve factor is applied. 
(9)  For transmission tank emissions identified using optical gas imaging instrument per §98.234(a) (refer to §98.233(k)), or acoustic leak detection of scrubber dump valves report the following for each tank:
(i)  Report emissions individually.
(ii)  [Reserved]
(10)  For well testing (refer to Equation W-17 of §98.233), report the following for each basin:
(i)  Number of wells tested per basin in calendar year.
(ii)  Average gas to oil ratio for each basin.
(iii)  Average number of days the well is tested in a basin.
(iv)  Report emissions of the venting gas collectively.
(11)  For associated natural gas venting (refer to Equation W-18 of §98.233), report the following for each basin:
(i)  Number of wells venting or flaring associated natural gas in a calendar year.
(ii)  Average gas to oil ratio for each basin.
(iii)  Report emissions of the flaring gas collectively. 
(12)  For flare stacks (refer to Equation W-19, W-20, and W-21 of §98.233), report the following for each flare:
(i)  Whether flare has a continuous flow monitor.
(ii)  Volume of gas sent to flare in cubic feet per year.
(iii)  Percent of gas sent to un-lit flare determined by engineering estimate and process knowledge based on best available data and operating records.
(iv)  Whether flare has a continuous gas analyzer.
(v)  Flare combustion efficiency. 
(vi)  Report uncombusted and combusted CO2 and CH4 emissions separately. 
(13)  For each centrifugal compressor:
(i)  For compressors with wet seals in operational mode (refer to Equations W-22 through W-24 of §98.233), report the following for each degassing vent:
(A)  Number of wet seals connected to the degassing vent.
(B)  Fraction of vent gas recovered for fuel or sales or flared.
(C)  Annual throughput in million scf, use an engineering calculation based on best available data.
(D)  Type of meters used for making measurements.
(E)  Reporter emission factor for wet seal oil degassing vents in cubic feet per hour (refer to Equation W-24 of §98.233).
(F)  Total time the compressor is operating in hours. 
(G)  Report seal oil degassing vent emissions for compressors measured (refer to Equation W-22 of §98.233) and for compressors not measured (refer to Equation W-23 and Equation W-24 of §98.233).
(ii)  For wet and dry seal centrifugal compressors in operating mode, (refer to Equations W-22 through W-24 of §98.233), report the following:
(A)  Total time in hours the compressor is in operating mode.
(B)  Reporter emission factor for blowdown vents in cubic feet per hour (refer to Equation W-24 of §98.233).
(C)  Report blowdown vent emissions when in operating mode (refer to Equation W-23 and Equation W-24 of §98.233). 
(iii)  For wet and dry seal centrifugal compressors in not operating, depressurized mode (refer to Equations W-22 through W-24 of §98.233), report the following:
(A)  Total time in hours the compressor is in shutdown, depressurized mode.
(B)  Reporter emission factor for isolation valve emissions in shutdown, depressurized mode in cubic feet per hour (refer to Equation W-24 of §98.233).
(C)  Report the isolation valve leakage emissions in not operating, depressurized mode in cubic feet per hour (refer to Equation W-23 and Equation W-24 of §98.233).  
(iv)  Report total annual compressor emissions from all modes of operation (refer to Equation W-24 of §98.233).
(v)  For centrifugal compressors in onshore petroleum and natural gas production (refer to Equation W-25 of §98.233), report the following:
(A)  Count of compressors.
(B)  Report emissions (refer to Equation W-25 of §98.233) collectively. 
(14) For reciprocating compressors:
(i)  For reciprocating compressors rod packing emissions with or without a vent in operating mode, report the following:
(A)  Annual throughput in million scf, use an engineering calculation based on best available data. 
(B)  Total time in hours the reciprocating compressor is in operating mode.
(C)  Report rod packing emissions for compressors measured (refer to Equation W-26 of §98.233) and for compressors not measured (refer to Equation W-27 and Equation W-28 of §98.233).
(ii)  For reciprocating compressors blowdown vents not manifold to rod packing vents, in operating and standby pressurized mode (refer to Equations W-26 through W-28 of §98.233), report the following: 
(A)  Total time in hours the compressor is in standby, pressurized mode. 
(B)  Reporter emission factor for blowdown vents in cubic feet per hour (refer to §98.233, Equation W-28).
(C)  Report blowdown vent emissions when in operating and standby pressurized modes (refer to Equation W-27 and Equation W-28 of §98.233). 
(iii)  For reciprocating compressors in not operating, depressurized mode (refer to Equations W-26 through W-28 of §98.233), report the following:
(A)  Total time the compressor is in not operating, depressurized mode.
(B)  Reporter emission factor for isolation valve emissions in not operating, depressurized mode in cubic feet per hour (refer to Equation W-28 of §98.233).
(C)  Report the isolation valve leakage emissions in not operating, depressurized mode. 
(iv) Report total annual compressor emissions from all modes of operation (refer to Equation W-27 and Equation W-28 of §98.233).
(v)  For reciprocating compressors in onshore petroleum and natural gas production (refer to Equation W-29 of §98.233), report the following:
(A)  Count of compressors.
(B)  Report emissions collectively. 
(15)  For each equipment leak sources that uses emission factors for estimating emissions (refer to §98.233(q) and (r). 
(i)  For equipment leaks found in each leak survey (refer to §98.233(q)), report the following:
(A)  Total count of leaks found in each complete survey listed by date of survey and each type of leak source for which there is a leaker emission factor in Tables W-2, W-3, W-4, W-5, W-6, and W-7 of this subpart.
(B)  Concentration of CH4 and CO2 as described in Equation W-30 of §98.233.
(C)  Report CH4 and CO2 emissions (refer to Equation W-30 of §98.233) collectively by equipment type.
(ii)  For equipment leaks calculated using population counts and factors (refer to §98.233(r)), report the following:
(A)  For source categories §98.230(a)(3), (a)(4), (a)(5), (a)(6), and (a)(7), total count for each type of leak source in Tables W-2, W-3, W-4, W-5, and W-6 of this subpart for which there is a population emission factor, listed by major heading and component type.
(B)  For onshore production (refer to §98.230 paragraph (a)(2)), total count for each type of major equipment in Table W-1B and Table W-1C of this subpart, by field.
(C)  Report CH4 and CO2 emissions (refer to Equation W-31 of §98.233) collectively by equipment type.
(16)  For local distribution companies, report the following:
(i)  Number of custody transfer gate stations.
(ii)  Number of non-custody transfer gate stations.
(iii)  Custody transfer gate station meter run leak factor (refer to Equation W-32 of §98.233).
(iv) Number of below grade M&R stations with inlet pressure greater than 300 psig.
(v)  Number of below grade M&R stations with inlet pressure between 100 and 300 psig.
(vi) Number of below grate M&R stations with inlet pressure less than 100 psig. 
(vii) Number of miles of unprotected steel distribution mains.
(viii) Number of miles of protected steel distribution mains.
(ix) Number of miles of plastic distribution mains.
(x) Number of miles of cast iron distribution mains.
(xi) Number of unprotected steel distribution services.
(xii) Number of protected steel distribution services.
(xiii) Number of plastic distribution services. 
(xiv) Number of copper distribution services.
(xv) Total emissions from each natural gas distribution facility. 
(17)  For each EOR injection pump blowdown (refer to Equation W-37 of §98.233), report the following:
(i)  Pump capacity, in barrels per day.
(ii)  Volume of critical phase gas between isolation valves.
(iii)  Number of blowdowns per year.
(iv)  Critical phase EOR injection gas density.
(v)  Report emissions collectively. 
(18)  For EOR hydrocarbon liquids dissolved CO2 for each field (refer to Equation W-38 of §98.233), report the following:
(i)  Volume of crude oil produced in barrels per year.
(ii)  Amount of CO2 retained in hydrocarbon liquids in metric tons per barrel, under standard conditions. 
(iii)  Report emissions individually.
(19) For onshore petroleum and natural gas production and natural gas distribution combustion emissions, report the following:
(i) Cumulative number of external fuel combustion units with a rated heat capacity equal to or less than 5 mmBtu/hr, by type of unit.
(ii) Cumulative number of external fuel combustion units with a rated heat capacity larger than 5 mmBtu/hr, by type of unit.
(iii) Cumulative emissions from external fuel combustion units with a rated heat capacity larger than 5 mmBtu/hr, by type of unit.
(iv) Cumulative volume of fuel combusted in external fuel combustion units with a rated heat capacity larger than 5 mmBtu/hr, by fuel type.
(v)  Cumulative number of all internal combustion units, by type of unit. 
(vi)  Cumulative emissions from internal combustion units, by type of unit. 
(vii) Cumulative volume of fuel combusted in internal combustion units, by fuel type.
(d)  Report annual throughput as determined by engineering estimate based on best available data for each  industry segment listed in paragraphs (a)(1) through (a)(8) of this section. 
 
§98.237 Records that must be retained.
Monitoring Plans, as described in §98.3(g)(5), must be completed by April 1, 2011.  In addition to the information required by §98.3(g), you must retain the following records: 
(a)  Dates on which measurements were conducted.
(b)  Results of all emissions detected and measurements.
(c)  Calibration reports for detection and measurement instruments used.
(d)  Inputs and outputs of calculations or emissions computer model runs used for engineering estimation of emissions.
§98.238  Definitions.
Except as provided in this section, all terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
Acid gas means hydrogen sulfide (H2S) and/or carbon dioxide (CO2) contaminants that are separated from sour natural gas by an acid gas removal unit.
Acid gas removal unit (AGR) means a process unit that separates hydrogen sulfide and/or carbon dioxide from sour natural gas using liquid or solid absorbents or membrane separators.
Acid gas removal vent emissions mean the acid gas separated from the acid gas absorbing medium (e.g., an amine solution) and released with methane and other light hydrocarbons to the atmosphere or a flare.
Basin means geologic provinces as defined by the American Association of Petroleum Geologists (AAPG) 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) (incorporated by reference, see §98.7) and the Alaska Geological Province Boundary Map, Compiled by the American Association of Petroleum Geologists Committee on Statistics of Drilling in Cooperation with the USGS, 1978 (incorporated by reference, see §98.7).
Component means each metal to metal joint or seal of non-welded connection separated by a compression gasket, screwed thread (with or without thread sealing compound), metal to metal compression, or fluid barrier through which natural gas or liquid can escape to the atmosphere.
Compressor means any machine for raising the pressure of a natural gas or CO2 by drawing in low pressure natural gas or CO2 and discharging significantly higher pressure natural gas or CO2.
Condensate means hydrocarbon and other liquid, including both water and hydrocarbon liquids, separated from natural gas that condenses due to changes in the temperature, pressure, or both, and remains liquid at storage conditions. 
Engineering estimation, for purposes of subpart W, means an estimate of emissions based on engineering principles applied to measured and/or approximated physical parameters such as dimensions of containment, actual pressures, actual temperatures, and compositions.
Enhanced oil recovery (EOR) means the use of certain methods such as water flooding or gas injection into existing wells to increase the recovery of crude oil from a reservoir.  In the context of this subpart, EOR applies to injection of critical phase or immiscible carbon dioxide into a crude oil reservoir to enhance the recovery of oil. 
Equipment leak means those emissions which could not reasonably pass through a stack, chimney, vent, or other functionally-equivalent opening.
Equipment leak detection means the process of identifying emissions from equipment, components, and other point sources.
External combustion means fired combustion in which the flame and products of combustion are separated from contact with the process fluid to which the energy is delivered.  Process fluids may be air, hot water, or hydrocarbons.  External combustion equipment may include fired heaters, industrial boilers, and commercial and domestic combustion units.
Facility with respect to natural gas distribution for purposes of this subpart and for subpart A means the collection of all distribution pipelines, metering stations, and regulating stations that are operated by a Local Distribution Company (LDC) that is regulated as a separate operating company by a public utility commission or that are operated as an independent municipally-owned distribution system.
Facility with respect to onshore petroleum and natural gas production for purposes of this subpart and for subpart A means all petroleum or natural gas equipment on a well pad or associated with a well pad and CO2 EOR operations that are under common ownership or common control including leased, rented, or contracted activities by an onshore petroleum and natural gas production owner or operator and that are located in a single hydrocarbon basin as defined in §98.238.  Where a person or entity owns or operates more than one well in a basin, then all onshore petroleum and natural gas production equipment associated with all wells that the person or entity owns or operates in the basin would be considered one facility. 
Farm Taps are pressure regulation stations that deliver gas directly from transmission pipelines to generally rural customers. The gas may or may not be metered, but always does not pass through a city gate station. In some cases a nearby LDC may handle the billing of the gas to the customer(s). 
Field means oil and gas fields identified in the United States as defined by the Energy Information Administration Oil and Gas Field Code Master List 2008, DOE/EIA 0370(08) (incorporated by reference, see §98.7).
Flare stack emissions means CO2 and N2O from partial combustion of hydrocarbon gas sent to a flare plus CH4 emissions resulting from the incomplete combustion of hydrocarbon gas in flares.
Flare combustion efficiency means the fraction of hydrocarbon gas, on a volume or mole basis, that is combusted at the flare burner tip.
Gas well means a well completed for production of natural gas (including condensate) from one or more gas zones or reservoirs. Such wells contain no completions for the production of crude oil.
Internal combustion means the combustion of a fuel that occurs with an oxidizer (usually air) in a combustion chamber. In an internal combustion engine the expansion of the high-temperature and  - pressure gases produced by combustion applies direct force to a component of the engine, such as pistons, turbine blades, or a nozzle. This force moves the component over a distance, generating useful mechanical energy. Internal combustion equipment may include gasoline and diesel industrial engines, natural gas-fired reciprocating engines, and gas turbines.
Liquefied natural gas (LNG) means natural gas (primarily methane) that has been liquefied by reducing its temperature to -260 degrees Fahrenheit at atmospheric pressure.
LNG boil-off gas means natural gas in the gaseous phase that vents from LNG storage tanks due to ambient heat leakage through the tank insulation and heat energy dissipated in the LNG by internal pumps.
Offshore means seaward of the terrestrial borders of the United States, including waters subject to the ebb and flow of the tide, as well as adjacent bays, lakes or other normally standing waters, and extending to the outer boundaries of the jurisdiction and control of the United States under the Outer Continental Shelf Lands Act. 
      Oil well means a well completed for the production of crude oil from at least one oil zone or reservoir.
Onshore petroleum and natural gas production owner or operator means the person or entity who holds the permit to operate petroleum and natural gas wells on the drilling permit or an operating permit where no drilling permit is issued, which operates an onshore petroleum and/or natural gas production facility (as described in §98.230(a)(2).  Where petroleum and natural gas wells operate without a drilling or operating permit, the person or entity that pays the State or Federal business income taxes is considered the owner or operator.
Operating pressure means the containment pressure that characterizes the normal state of gas or liquid inside a particular process, pipeline, vessel or tank.
Pump means a device used to raise pressure, drive, or increase flow of liquid streams in closed or open conduits.
Pump seals means any seal on a pump drive shaft used to keep methane and/or carbon dioxide containing light liquids from escaping the inside of a pump case to the atmosphere.
Pump seal emissions means hydrocarbon gas released from the seal face between the pump internal chamber and the atmosphere.
Reservoir means a porous and permeable underground natural formation containing significant quantities of hydrocarbon liquids and/or gases. 
Residue Gas and Residue Gas Compression mean, respectively, production lease natural gas from which gas liquid products and, in some cases, non-hydrocarbon components have been extracted such that it meets the specifications set by a pipeline transmission company, and/or a distribution company; and the compressors operated by the processing facility, whether inside the processing facility boundary fence or outside the fence-line, that deliver the residue gas from the processing facility to a transmission pipeline.
Separator means a vessel in which streams of multiple phases are gravity separated into individual streams of single phase.
Transmission pipeline means high pressure cross country pipeline transporting saleable quality natural gas from production or natural gas processing to natural gas distribution pressure let-down, metering, regulating stations where the natural gas is typically odorized before delivery to customers.
Turbine meter means a flow meter in which a gas or liquid flow rate through the calibrated tube spins a turbine from which the spin rate is detected and calibrated to measure the fluid flow rate.
Vented emissions means intentional or designed releases of CH4 or CO2 containing natural gas or hydrocarbon gas (not including stationary combustion flue gas), including process designed flow to the atmosphere through seals or vent pipes, equipment blowdown for maintenance, and direct venting of gas used to power equipment (such as pneumatic devices).
Table W-1A to Subpart W of Part 98--Default Whole Gas Emission Factors for Onshore Petroleum and Natural Gas Production

                 Onshore petroleum and natural gas production
                     Emission Factor (scf/hour/component)
Eastern U.S.

Population Emission Factors - All Components, Gas Service[1]
 
Valve
                                                                          0.027
Connector
                                                                          0.004
Open-ended Line
                                                                          0.062
Pressure Relief Valve
                                                                          0.041
Low Continuous Bleed Pneumatic Device Vents[2]
                                                                           1.80
High Continuous Bleed Pneumatic Device Vents[2]
                                                                           48.1
Intermittent Bleed Pneumatic Device Vents[2]
                                                                           17.4
Pneumatic Pumps[3]
                                                                           13.3
Population Emission Factors - All Components, Light Crude Service[4]
 
Valve
                                                                           0.04
Flange
                                                                          0.002
Connector
                                                                          0.005
Open-ended Line
                                                                           0.04
Pump
                                                                           0.01
Other[5]
                                                                           0.23
Population Emission Factors - All Components, Heavy Crude Service[6]
 
Valve
                                                                         0.0004
Flange
                                                                         0.0007
Connector (other)
                                                                         0.0002
Open-ended Line
                                                                          0.004
Other[5]
                                                                          0.002
Western U.S.
                                                                               
Population Emission Factors - All Components, Gas Service[1]
                                                                               
Valve
                                                                          0.123
Connector
                                                                          0.017
Open-ended Line
                                                                          0.032
Pressure Relief Valve
                                                                          0.196
Low Continuous Bleed Pneumatic Device Vents[2]
                                                                           1.80
High Continuous Bleed Pneumatic Device Vents[2]
                                                                           48.1
Intermittent Bleed Pneumatic Device Vents[2]
                                                                           17.4
Pneumatic Pumps[3]
                                                                           13.3
Population Emission Factors - All Components, Light Crude Service[4]
                                                                               
Valve
                                                                           0.04
Flange
                                                                          0.002
Connector (other)
                                                                          0.005
Open-ended Line
                                                                           0.04
Pump
                                                                           0.01
Other[5]
                                                                           0.23
Population Emission Factors - All Components, Heavy Crude Service[6]
                                                                               
Valve
                                                                         0.0004
Flange
                                                                         0.0007
Connector (other)
                                                                         0.0002
Open-ended Line
                                                                          0.004
Other[5]
                                                                          0.002
[1] For multi-phase flow that includes gas, use the gas service emissions factors
[2] Emission Factor is in units of "scf/hour/device"
[3] Emission Factor is in units of "scf/hour/pump"
[4] Hydrocarbon liquids greater than or equal to 20˚API are considered "light crude"
[5] "Others" category includes instruments, loading arms, pressure relief valves, stuffing boxes, compressor seals, dump lever arms, and vents.
[6] Hydrocarbon liquids less than 20˚API are considered "heavy crude"

Table W-1B to Subpart W of Part 98--Default Average Component Counts for Major Onshore Natural Gas Production Equipment

Major Equipment
                                    Valves
                                  Connectors
                               Open-ended Lines
                            Pressure relief valves
Eastern U.S.
                                       
                                       
                                       
                                       
Wellheads
                                       8
                                      38
                                      0.5
                                       0
Separators
                                       1
                                       6
                                       0
                                       0
meters/piping
                                      12
                                      45
                                       0
                                       0
Compressors
                                      12
                                      57
                                       0
                                       0
In-line heaters
                                      14
                                      65
                                       2
                                       1
Dehydrators
                                      24
                                      90
                                       2
                                       2
Western U.S.
                                       
                                       
                                       
                                       
Wellheads
                                      11
                                      36
                                       1
                                       0
Separators
                                      34
                                      106
                                       6
                                       2
meters/piping
                                      14
                                      51
                                       1
                                       1
Compressors
                                      73
                                      179
                                       3
                                       4
In-line heaters
                                      14
                                      65
                                       2
                                       1
Dehydrators
                                      24
                                      90
                                       2
                                       2





Table W-1C to Subpart W of Part 98--Default Average Component Counts For Major Crude Oil Production Equipment

Major Equipment
Valves
Flanges
Connectors
Open-ended Lines
Other Components
Eastern U.S.





Wellhead
5
10
4
0
1
Separator
6
12
10
0
0
Heater-treater
8
12
20
0
0
Header
5
10
4
0
0
Western U.S.





Wellhead
5
10
4
0
1
Separator
6
12
10
0
0
Heater-treater
8
12
20
0
0
Header
5
10
4
0
0



Table W-1D of Subpart W of Part 98--Designation Of Eastern And Western U.S.

Eastern U.S.
Western U.S.
Connecticut
Alabama
Delaware
Alaska
Florida
Arizona
Georgia
Arkansas
Illinois
California
Indiana
Colorado
Kentucky
Hawaii
Maine
Idaho
Maryland
Iowa
Massachusetts
Kansas
Michigan
Louisiana
New Hampshire
Minnesota
New Jersey
Mississippi
New York
Missouri
North Carolina
Montana
Ohio
Nebraska
Pennsylvania
Nevada
Rhode Island
New Mexico
South Carolina
North Dakota
Tennessee
Oklahoma
Vermont
Oregon
Virginia
South Dakota
West Virginia
Texas
Wisconsin
Utah

Washington

Wyoming




Table W-2 to Subpart W of Part 98--Default Total Hydrocarbon Emission Factors for Onshore Natural Gas Processing 



                        Onshore natural gas processing
                     Emission Factor (scf/hour/component)
Leaker Emission Factors - Compressor Components, Gas Service
Valve[1]
                                                                          15.07
Connector
                                                                           5.68
Open-Ended Line
                                                                          17.54
Pressure Relief Valve
                                                                          40.27
Meter
                                                                          19.63
Leaker Emission Factors  -  Non-Compressor Components, Gas Service
Valve
                                                                           6.52
Connector
                                                                           5.80
Open-Ended Line
                                                                          11.44
Pressure Relief Valve
                                                                           2.04
Meter
                                                                           2.98
1 Valves include control valves, block valves and regulator valves.

 

Table W-3 to Subpart W of Part 98--Default Total Hydrocarbon Emission Factors for Onshore Natural Gas Transmission Compression


                 Onshore natural gas transmission compression
                     Emission Factor (scf/hour/component)
Leaker Emission Factors - Compressor Components, Gas Service
Valve[1]
                                                                          15.07
Connector
                                                                           5.68
Open-Ended Line
                                                                          17.54
Pressure Relief Valve
                                                                          40.27
Meter
                                                                          19.63
Leaker Emission Factors  -  Non-Compressor Components, Gas Service
Valve[1]
                                                                           6.52
Connector
                                                                           5.80
Open-Ended Line
                                                                          11.44
Pressure Relief Valve
                                                                           2.04
Meter
                                                                           2.98
Population Emission Factors  -  Gas Service
Low Continuous Bleed Pneumatic Device Vents[2]
                                                                           1.79
High Continuous Bleed Pneumatic Device Vents[2]
                                                                           20.1
Intermittent Bleed Pneumatic Device Vents[2]
                                                                           20.1
[1] Valves include control valves, block valves and regulator valves.
[2] Emission Factor is in units of "scf/hour/device"



Table W-4 to Subpart W of Part 98 -- Default Total Hydrocarbon Emission Factors for Underground Natural Gas Storage


Underground natural gas storage
Emission Factor (scf/hour/component)
Leaker Emission Factors - Storage Station, Gas Service 
Valve[1]
                                                                         15.07 
Connector
                                                                          5.68 
Open-Ended Line
                                                                         17.54 
Pressure Relief Valve
                                                                         40.27 
Meter
                                                                          19.63
Population Emission Factors - Storage Wellheads, Gas Service
Connector
                                                                          0.01 
Valve
                                                                           0.10
Pressure Relief Valve
                                                                           0.17
Open-ended Line
                                                                           0.03
Population Emission Factors - Other Components, Gas Service
Low Continuous Bleed Pneumatic Device Vents[2]
                                                                           1.79
High Continuous Bleed Pneumatic Device Vents[2]
                                                                           20.1
Intermittent Bleed Pneumatic Device Vents[2]
                                                                           20.1
[1] Valves include control valves, block valves and regulator valves. 
2 Emission Factor is in units of "scf/hour/device"

Table W-5 to Subpart W of Part 98 -- Default Methane Emission Factors for Liquefied Natural Gas (LNG) Storage

LNG Storage
Emission Factor (scf/hour/component)
Leaker Emission Factors - LNG Storage Components, LNG Service
Valve
                                                                           1.21
Pump Seal
                                                                           4.06
Connector
                                                                           0.35
Other[1]
                                                                           1.80
Population Emission Factors - LNG Storage Compressor, Gas Service
Vapor Recovery Compressor[2]
                                                                           4.23
[1] "other" equipment type should be applied for any equipment type other than connectors, pumps, or valves.
[2] Emission Factor is in units of "scf/hour/compressor"


Table W-6 to Subpart W of Part 98 -- Default Methane Emission Factors for LNG Import and Export Equipment

LNG import and export equipment
Emission Factor (scf/hour/component)
Leaker Emission Factors - LNG Terminals Components, LNG Service
Valve
                                                                           1.21
Pump Seal
                                                                           4.06
Connector
                                                                           0.35
Other[1]
                                                                           1.80
Population Emission Factors - LNG Terminals Compressor, Gas Service
Vapor Recovery Compressor[2]
                                                                           4.23
[1] "other" equipment type should be applied for any equipment type other than connectors, pumps, or valves.
[2] Emission Factor is in units of "scf/hour/compressor"

Table W-7 to Subpart W of Part 98 -- Default Methane Emission Factors for Natural Gas Distribution


                           Natural gas distribution
                     Emission Factor (scf/hour/component)
Leaker Emission Factors - Above Grade M&R at City Gate Stations[1] Components, Gas Service
Connector
                                                                           1.72
Block Valve
                                                                          0.566
Control Valve
                                                                           9.48
Pressure Relief Valve
                                                                          0.274
Orifice Meter
                                                                          0.215
Regulator
                                                                          0.784
Open-ended Line
                                                                         26.533
Population Emission Factors - Below Grade M&R[2] Components, Gas Service[3]
Below Grade M&R Station, Inlet Pressure > 300 psig
                                                                           1.32
Below Grade M&R Station, Inlet Pressure 100 to 300 psig
                                                                           0.20
Below Grade M&R Station, Inlet Pressure < 100 psig
                                                                           0.10
Population Emission Factors - Distribution Mains, Gas Service[4] 
Unprotected Steel
                                                                          12.77
Protected Steel
                                                                           0.36
Plastic
                                                                           1.15
Cast Iron
                                                                          27.67
Population Emission Factors - Distribution Services, Gas Service[5]
Unprotected Steel
                                                                           0.19
Protected Steel
                                                                           0.02
Plastic
                                                                          0.001
Copper
                                                                           0.03
[1] City gate stations at custody transfer and excluding customer meters
[2] Excluding customer meters
[3] Emission Factor is in units of "scf/hour/station"
[4] Emission Factor is in units of "scf/hour/mile"
5 Emission Factor is in units of "scf/hour/number of services"


Subpart FF  -  Underground Coal Mines
§98.320  Definition of the source category.
(a)  This source category consists of active underground coal mines, and any underground mines under development that have operational pre-mining degasification systems.  An underground coal mine is a mine at which coal is produced by tunneling into the earth to the coalbed, which is then mined with underground mining equipment such as cutting machines and continuous, longwall, and shortwall mining machines, and transported to the surface. Underground coal mines are categorized as active if any one of the following five conditions apply:
(1)  Mine development is underway.
(2)  Coal has been produced within the last 90 days.
(3)  Mine personnel are present in the mine workings.
(4)  Mine ventilation fans are operative. 
(5)  The mine is designated as an "intermittent" mine by the Mine Safety and Health Administration (MSHA).    
(b)  This source category includes the following:  
(1)  Each ventilation well or shaft, including both those wells and shafts where gas is emitted and those where gas is sold, used onsite, or otherwise destroyed (including by flaring).  
(2)  Each degasification system well or shaft, including degasification systems deployed before, during, or after mining operations are conducted in a mine area. This includes both those wells and shafts where gas is emitted, and those where gas is sold, used onsite, or otherwise destroyed (including by flaring).  
(c)  This source category does not include abandoned or closed mines, surface coal mines, or post-coal mining activities (e.g., storage or transportation of coal).
§98.321  Reporting threshold.
You must report GHG emissions under this subpart if your facility contains an active underground coal mine and the facility meets the requirements of §98.2(a)(1).
§98.322  GHGs to report.
(a)  You must report CH4 liberated from ventilation and degasification systems.  
(b)  You must report CH4 destruction from systems where gas is sold, used onsite, or otherwise destroyed (including by flaring).  
(c)  You must report net CH4 emissions from ventilation and degasification systems.  
(d)  You must report under this subpart the CO2 emissions from coal mine gas CH4 destruction occuring at the facility, where the gas is not a fuel input for energy generation or use (e.g., flaring).
(e)  You must report under subpart C of this part (General Stationary Fuel Combustion Sources) the CO2, CH4, and N2O emissions from each stationary fuel combustion unit by following the requirements of subpart C.  Report emissions from both the combustion of collected coal mine CH4 and any other fuels.   
(f)  An underground coal mine that is subject to this part because emissions from source categories described in Tables A-3, A-4 or A-5, or from stationary combustion (subpart C),  is not required to report emissions under subpart FF of this part unless the coal mine liberates 36,500,000 actual (acf) or more of methane per year from its ventilation system.
§98.323  Calculating GHG emissions.
(a)  For each ventilation shaft, vent hole, or centralized point into which CH4 from multiple shafts and/or vent holes are collected, you must calculate the quarterly CH4 liberated from the ventilation system using Equation FF-1 of this section.  You must measure CH4 content, flow rate, temperature, pressure, and moisture content of the gas using the procedures outlined in §98.324.
		(Eq. FF-1)
Where:
CH4V 	=	Quarterly CH4 liberated from a ventilation monitoring point (metric tons CH4).
V 		=	Volumetric flow rate for the quarter
		(cfm) based on sampling or a flow rate meter.  If a flow rate meter is used and the meter automatically corrects for temperature and pressure, replace "520°R/T x P/1 atm" with "1".
MCF 	=	Moisture correction factor for the measurement period, volumetric basis. 
	=	1 when V and C are measured on a dry basis or if both are measured on a wet basis.
	=	1-(fH2O)n when V is measured on a wet basis and C is measured on a dry basis.
	=	1/[1-(fH2O)] when V is measured on a dry basis and C is measured on a wet basis.
(fH2O)	=	Moisture content of the methane emitted during the measurement period, volumetric basis (cubic feet water per cubic feet emitted gas) 
C 	=	CH4 concentration of ventilation gas for the quarter (%). 
n	=	The number of days in the quarter where active ventilation of mining operations is taking place at the monitoring point.
0.0423	=	Density of CH4 at 520°R (60°F) and 1 atm (lb/scf).
520 [o]R	=	520 degrees Rankine.
T 	=	Temperature at which flow is measured (°R) for the quarter. 
P 	=	Pressure at which flow is measured (atm) for the quarter.  The annual average barometric pressure from the nearest NOAA weather service station may be used as a default.

1,440 	=	Conversion factor (min/day).
0.454/1,000	=	Conversion factor (metric ton/lb). 
(1)  Consistent with MSHA inspections, the quarterly periods are: 
       (i)		January 1  -  March 31.
       (ii)		April 1 - June 30.
       (iii)	July 1 - September 30.
       (iv)		October 1 - December 31.

(2)  Values of V, , C, T, P, and fH2O, if applicable, must be based on measurements taken at least once each quarter with no fewer than 6 weeks between measurements.  If measurements are taken more frequently than once per quarter, then use  the average value for all measurements taken.  If continous measurements are taken, then use the average value over the time period of continuous monitoring. 
(3)  If a facility has more than one monitoring point, the facility must calculate total CH4 liberated from ventilation systems (CH4vTotal) as the sum of the CH4 from all ventilation monitoring points in the mine, as follows:
		(Eq. FF-2)
Where:
CH4VTotal 	=	Total quarterly CH4 liberated from ventilation    systems (metric tons CH4).
CH4V		=	Quarterly CH4 liberated from each ventilation monitoring point (metric tons CH4).
m		=  Number of ventilation monitoring points.

(b)  For each monitoring point in the degasification system (this could be at each degasification well and/or vent hole, or at more centralized points into which CH4 from multiple wells and/or vent holes are collected), you must calculate the weekly CH4 liberated from the mine using CH4 measured weekly or more frequently (including by CEMS) according to 98.234(c), CH4 content, flow rate, temperature, pressure, and moisture content, and Equation FF-3 of this section.
		(Eq. FF-3)
Where:
CH4D 	=	Weekly CH4 liberated from at the monitoring point(metric tons CH4). 
Vi 	=	Measured volumetric flow rate for the days in the week when the degasification system is in operation at that monitoring point, based on sampling or a flow rate meter (cfm).If a flow rate meter is used and the meter automatically corrects for temperature and pressure, replace "520°R/Ti x Pi/1 atm" with "1".
MCFi 	=	Moisture correction factor for the measurement period, volumetric basis. 
	=	1 when Vi and Ci are measured on a dry basis or if both are measured on a wet basis.
	=	1-(fH2O)i when Vi is measured on a wet basis and Ci is measured on a dry basis.
	=	1/[1-(fH2O)i] when Vi is measured on a dry basis and Ci is measured on a wet basis.
(fH2O)	=	Moisture content of the CH4 emitted during the measurement period, volumetric basis (cubic feet water per cubic feet emitted gas) 
Ci 	=	CH4 concentration of gas for the days in the week when the degasification system is in operation at that monitoring point (%).
n 	=	The number of days in the week that the system is operational at that measurement point. 
0.0423	=	Density of CH4 at 520°R (60°F) and 1 atm (lb/scf). 
520 [o]R	=	520 degrees Rankine.
Ti 	=	Temperature at which flow is measured (°R). 
Pi 	=	Pressure at which flow is measured (atm).
1,440 	=	Conversion factor (minutes/day). 
0.454/1,000	=	Conversion factor (metric ton/lb).

(1)  Values for V, C, T, P, and fH2O, if applicable, must be based on measurements taken at least once each calendar week with at least 3 days between measurements.  If measurements are taken more frequently than once per week, then use the average value for all measurements taken that week.  If continuous measurements are taken, then use the average values over the time period of continuous monitoring when the continuous monitoring equipment is properly functioning.
(2)  Quarterly total CH4 liberated from degasification systems for the mine should be determined as the sum of CH4 liberated determined at each of the monitoring points in the mine, summed over the number of weeks in the quarter, as follows:
	             	(Eq. FF-4)
Where:
CH4DTotal	=	Quarterly CH4 liberated from all degasification monitoring points (metric tons CH4).
CH4D	=	Weekly CH4 liberated from a degasification monitoring point (metric tons CH4).
m	=   Number of monitoring points.
w	=	Number of weeks in the quarter during which the degasification system is operated.
(c)  If gas from degasification system wells or ventilation shafts is sold, used onsite, or otherwise destroyed (including by flaring), you must calculate the quarterly CH4 destroyed for each destruction device and each point of offsite transport to a destruction device, using Equation FF-5 of this section.  You must measure CH4 content and flow rate according to the provisions in §98.324, and calculate the methane routed to the destruction device (CH4) using either Eq. FF-1 or Eq. FF-3, as applicable. 
	CH4Destroyed = CH4 x DE	(Eq. FF-5)
Where:
CH4Destroyed	=	Quarterly CH4 destroyed (metric tons). 
CH4 	=	Quarterly CH4 routed to the destruction device or offsite transfer point (metric tons).  
 DE          =	Destruction efficiency (lesser of manufacturer's specified destruction efficiency and 0.99). If the gas is transported off-site for destruction, use DE = 1. 

(1)  Calculate total CH4 destroyed as the sum of the methane destroyed at all destruction devices (onsite and offsite), using Equation FF-6 of this section.
		 (Eq. FF-6)
Where:
CH4DestroyedTotal	=	Quarterly total CH4 destroyed at the mine (metric tons CH4).
		=	Quarterly CH4 destroyed from each destruction device or offsite transfer point.
d		=	Number of onsite destruction devices and points of ofsite transport.


(d)  You must calculate the quarterly measured net CH4 emissions to the atmosphere using Equation FF-7 of this section.
	CH4 emitted (net) = CH4VTotal + CH4DTotal  -  CH4destroyedTotal	(Eq. FF-7)
Where: 
CH4 emitted (net)=	Quarterly CH4 emissions from the mine (metric tons).
CH4VTotal 	=	Quarterly sum of the CH4 liberated from all mine ventilation monitoring points (CH4V), calculated using Equation FF-2 of this section (metric tons).
CH4DTotal 	=	Quarterly sum of the CH4 liberated from all mine degasification monitoring points(CH4D), calculated using Equation FF-4 of this section (metric tons).
CH4DestroyedTotal	=	Quarterly sum of the measured CH4 destroyed from all mine ventilation and degasification systems, calculated using Equation FF-6 of this section (metric tons).

(e)  For the methane collected from degasification and/or ventilation systems that is destroyed on site and is not a fuel input for energy generation or use (those emissions are monitored and reported under Subpart C of this part), you must estimate the CO2 emissions using Equation FF-8 of this section. 
	CO2 = CH4Destroyedonsite * 44/16	(Eq. FF-8)
Where:
  CO2		=	Total quarterly CO2 emissions from CH4 destruction (metric tons).
  CH4Destroyedonsite	=	Quarterly sum of the CH4 destroyed, calculated as the sum of CH4 destroyed for each onsite, non-energy use, as calculated individually in Equation FF-5 of this section (metric tons).
  44/16		=	Ratio of molecular weights of CO2 to CH4.
§98.324  Monitoring and QA/QC requirements. 
(a)  For calendar year 2011 monitoring, the facility may submit a request to the Administrator to use one or more best available monitoring methods as listed in §98.3(d)(1)(i) through (iv).  The request must be submitted no later than [INSERT DATE 90 DAYS AFTER PUBLICATION IN THE FEDERAL REGISTER] and must contain the information in §98.3(d)(2)(ii).  To obtain approval, the request 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 January 1, 2011.  The use of best available monitoring methods will not be approved beyond December 31, 2011.      
(b)  For CH4 liberated from ventilation systems, determine whether CH4 will be monitored from each ventilation well and shaft, from a centralized monitoring point, or from a combination of the two options.  Operators are allowed flexibility for aggregating emissions from more than one ventilation well or shaft, as long as emissions from all are addressed, and the methodology for calculating total emissions documented.  Monitor by one of the following options:  
(1)  Collect quarterly or more frequent grab samples (with no fewer than 6 weeks between measurements) for methane concentration and make quarterly measurements of flow rate, temperature, pressure, and moisture content, if applicable..  The sampling and measurements must be made at the same locations as MSHA inspection samples are taken, and should be taken when the mine is operating under normal conditions.  You must follow MSHA sampling procedures as set forth in the MSHA Handbook entitled, General Coal Mine Inspection Procedures and Inspection Tracking System Handbook Number: PH-08-V-1, January 1, 2008 (incorporated by reference, see §98.7).  You must record the date of sampling, flow, temperature, pressure, and moisture
measurements, the methane concentration (percent), the bottle number of samples collected, and the location of the measurement or collection.  
(2)  Obtain results of the quarterly (or more frequent) testing performed by MSHA for the methane flowrate.  At the time and location of the MSHA sampling, make measurements of temperature, pressure and moisture content using the same procedures specified in paragraph (b)(1) of this section.  If the MSHA data for methane flow is provided in the units of actual cubic feet of methane per day, the methane flow data is inserted into Equation FF-1 of this section in place of the value for V and the variables MCF, C/100%, and 1440 are removed from the equation.
(3)  Monitor emissions through the use of one or more continuous emission monitoring systems (CEMS).  If operators use CEMS as the basis for emissions reporting, they must provide documentation on the process for using data obtained from their CEMS to estimate emissions from their mine ventilation systems. 
(c)  For CH4 liberated at degasification systems, determine whether CH4 will be monitored from each well and gob gas vent hole, from a centralized monitoring point, or from a combination of the two options.  Operators are allowed flexibility for aggregating emissions from more than one well or gob gas vent hole, as long as emissions from all are addressed, and the methodology for calculating total emissions is documented.  Monitor both gas volume and methane concentration by one of the following two options:   
(1)  Monitor emissions through the use of one or more continuous emissions monitoring systems (CEMS).  If operators use CEMS as the basis for emissions reporting, they must provide documentation on the process for using data obtained from their CEMS to estimate emissions from their mine ventilation systems.
(2)  Collect weekly (once each calendar week, with at least three days between measurements) or more frequent samples, for all degasification wells and gob gas vent holes.  Determine weekly or more frequent flow rates, methane concentration, temperature, and pressure from these degasification wells and gob gas vent holes.  Methane composition should be determined either by submitting samples to a lab for analysis, or from the use of methanometers at the degasification well site.  Follow the sampling protocols for sampling of methane emissions from ventilation shafts, as described in §98.324(b)(1).  You must record the date of sampling, flow, temperature, pressure, and moisture measurements, the methane concentration (percent), the bottle number of samples collected, and the location of the measurement or collection.  
(3)  If the CH4 concentration is determined on a dry basis and flow is determined on a wet basis or CH4 concentration is determined on a wet basis and flow is determined on a dry basis, and the flow meter does not automatically correct for moisture content, determine the moisture content in the gas in a location near or representative of the location of:
(i)  The gas flow meter at least once each calendar week; if measuring with CEMS. If only one measurement is made each calendar week, there must be at least three days between measurements; and  
(ii)	 The grab sample, if using grab samples, at the time of the sample.
(d)  Monitoring must adhere to one of the methods specified in paragraphs (d)(1) through (d)(2) of this section. 
    (1)        ASTM D1945-03, Standard Test Method for Analysis of Natural Gas by Gas Chromatography; ASTM D1946-90 (Reapproved 2006), Standard Practice for Analysis of Reformed Gas by Gas Chromatography; ASTM D4891-89 (Reapproved 2006), Standard Test Method for Heating Value of Gases in Natural Gas Range by Stoichiometric Combustion; or ASTM UOP539-97 Refinery Gas Analysis by Gas Chromatography (incorporated by reference, see §98.7).
    (2)       As an alternative to the gas chromatography methods provided in paragraph (d)(1) of this section, you may use gaseous organic concentration analyzers and a correction factor to calculate the CH4 concentration following the requirements in paragraphs (d)(2)(i) through (d)(2)(iii) of this section.
       (i)  Use Method 25A or 25B at 40 CFR part 60, appendix A-7 to determine gaseous organic concentration as required in §98.323 and in paragraphs (b) and (c) of this section.  You must calibrate the instrument with CH4 and determine the total gaseous organic concentration as carbon (or as CH4; K=1 in Equation 25A-1 of Method 25A at 40 CFR part 60, appendix A-7).
      (ii)  Determine a correction factor that will be used with the gaseoue organic concentrations measured in paragraph (i) of this section.  The correction factor must be determined at the routine sampling location no less frequently than once a reporting year following the requirements in paragraphs (d)(2)(ii)(A) through (d)(2)(ii)(C) of this section.
      (A)  Take a minimum of three grab samples of the gas with a minimum of 20 minutes between samples and determine the methane composition of the gas using one of the methods specified in paragraph (d)(1) of this section.
      (B)  As soon as practical after each grab sample is collected and prior to the collection of a subsequent grab sample, determine the gaseous organic concentration of the gas using either Method 25A or 25B at 40 CFR part 60, appendix A-7 as specified in paragraph (d)(2)(i) of this section.
      (C)  Determine the arithmetic average methane concentration and the arithmetic average gaseous organic concentration of the samples analyzed according to paragraphs (d)(2)(ii)(A) and (d)(2)(ii)(B) of this section, respectively, and calculate the non-methane organic carbon correction factor as the ratio of the average methane concentration to the average total gaseous organic concentration.  If the ratio exceeds 1, use 1 for the correction factor.
      (iii)  Calculate the CH4 concentration as specified in Equation FF-9 of this section.
      	CCH4 = fNMOC x CTGOC	(Eq. FF-9)
      Where:
      CCH4	=	Methane (CH4) concentration in the gas(volume %) for use in Equations FF-1 and FF-3 of this subpart.
      fNMOC 	=   Correction factor from the most recent determination of the correction factor as specified in paragraph (d)(2)(ii) of this section (unitless).
      CTGOC 	=	Gaseous organic carbon concentration measured using Method 25A or 25B at 40 CFR part 60, appendix A-7 during routine monitoring of the gas (volume %).
 

(e)  All flow meters and gas composition monitors that are used to provide data for the GHG emissions calculations shall be calibrated prior to the first reporting year, using the applicable methods specified in paragraphs (d) and (e)(1) through (e)(7) of this section.  Alternatively, calibration procedures specified by the flow meter manufacturer may be used. Flow meters and gas composition monitors  shall be recalibrated either annually or at the minimum frequency specified by the manufacturer  The operator shall operate, maintain, and calibrate a gas composition monitor capable of measuring the concentration of CH4 in the gas using one of the methods specified in paragraph (d) of this section.  The operator shall operate, maintain, and calibrate the flow meter using any of the following test methods or follow the procedures specified bythe flow meter manufacturer.  Flow meters must meet the accuracy requirements in §98.3(i).
(1)  ASME MFC - 3M - 2004, Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and Venturi (incorporated by reference, see §98.7).
(2)  ASME MFC - 4M - 1986 (Reaffirmed 1997), Measurement of Gas Flow by Turbine Meters (incorporated by reference, see §98.7).
(3)  ASME MFC - 6M - 1998, Measurement of Fluid Flow in Pipes Using Vortex Flowmeters (incorporated by reference, see §98.7).
(4)  ASME MFC - 7M - 1987 (Reaffirmed 1992), Measurement of Gas Flow by Means of Critical Flow Venturi Nozzles (incorporated by reference, see §98.7).
(5)  ASME MFC-11M-2006 Measurement of Fluid Flow by Means of Coriolis Mass Flowmeters (incorporated by reference, see §98.7).
(6)  ASME MFC-14M-2003 Measurement of Fluid Flow Using Small Bore Precision Orifice Meters (incorporated by reference, see §98.7).
(7)  ASME MFC-18M-2001 Measurement of Fluid Flow using Variable Area Meters (incorporated by reference, see §98.7).
(f)  For CH4 destruction, CH4 must be monitored at each onsite destruction device and each point of offsite transport for combustion using continuous monitors of gas routed to the device or point of offsite transport.
(g)  All temperature, pressure, and moisture content monitors must be operated and calibrated using the procedures and frequencies specified by the manufacturer. 
(h)  If applicable, the owner or operator shall document the procedures used to ensure the accuracy of gas flow rate, gas composition, temperature, pressure, and moisture content measurements. These procedures include, but are not limited to, calibration of flow meters, and other measurement devices.  The estimated accuracy of measurements, and the technical basis for the estimated accuracy shall be recorded.
§98.325  Procedures for estimating missing data.
(a)  A complete record of all measured parameters used in the GHG emissions calculations is required.  Therefore, whenever a quality-assured value of a required parameter is unavailable (e.g., if a meter malfunctions during unit operation or if a required fuel sample is not taken), a substitute data value for the missing parameter shall be used in the calculations, in accordance with paragraph (b) of this section.
(b)  For each missing value of CH4 concentration, flow rate, temperature, pressure, and moisture content for ventilation and degasification systems, the substitute data value shall be the arithmetic average of the quality-assured values of that parameter immediately preceding and immediately following the missing data incident.  If, for a particular parameter, no quality-assured data are available prior to the missing data incident, the substitute data value shall be the first quality-assured value obtained after the missing data period.
§98.326  Data reporting requirements. 
In addition to the information required by §98.3(c), each annual report must contain the following information for each mine: 
(a)  Quarterly CH4 liberated from each ventilation monitoring point (CH4Vm), (metric tons CH4).
(b)  Weekly CH4 liberated from each degasification system monitoring point (metric tons CH4).
(c)  Quarterly CH4 destruction at each ventilation and degasification system destruction device or point of offsite transport (metric tons CH4). 
(d)  Quarterly CH4 emissions (net) from all ventilation and degasification systems (metric tons CH4).
(e)  Quarterly CO2 emissions from on-site destruction of coal mine gas CH4, where the gas is not a fuel input for energy generation or use (e.g., flaring) (metric tons CO2).
(f)  Quarterly volumetric flow rate for each ventilation monitoring point (scfm), date and location of each measurement, and method of measurement (quarterly sampling or continuous monitoring,  used in Equation FF-1.
(g)  Quarterly CH4 concentration for each ventilation monitoring point, dates and locations of each measurement and method of measurement (sampling or continuous monitoring).
(h)  Weekly volumetric flow rate used to calculate CH4 liberated from degasification systems (cfm) and method of measurement (sampling or continuous monitoring), used in Equation FF-3.
(i)  Quarterly CEMS CH4 concentration (%) used to calculate CH4 liberated from degasification systems (average from daily data), or quarterly CH4 concentration data based on results from weekly sampling data)(C).
      (j) Weekly volumetric flow rate used to calculate CH4 destruction for each destruction device and each point of offsite transport (cfm).
(k)  Weekly CH4 concentration (%) used to calculate CH4 flow to each destruction device and each point of offsite transport (C).
(l)  Dates in quarterly reporting period where active ventilation of mining operations is taking place.
(m)  Dates in quarterly reporting period where degasification of mining operations is taking place.
(n)  Dates in quarterly reporting period when continuous monitoring equipment is not properly functioning, if applicable.
(o)  Temperatures (°R), pressure (atm), and moisture content used in Eq. FF-1 and FF-3, and the gaseous organic concentration correction factor, if Equation FF-9 was required.     
(p)  For each destruction device, a description of the device, including an indication of whether destruction occurs at the coal mine or off-site.  If destruction occurs at the mine, also report an indication of whether a back-up destruction device is present at the mine, the annual operating hours for the primary destruction device, the annual operating hours for the back-up destruction device (if present), and the destruction efficiencies assumed (percent). 
(q)  A description of the gas collection system (manufacturer, capacity, and number of wells) the surface area of the gas collection system (square meters), and the annual operating hours of the gas collection system. 
(r)  Identification information and description for each well and shaft, indication of whether the well or shaft is monitored individually, or as part of a centralized monitoring point.  Note which method (sampling or continuous monitoring) was used. 
(s)  For each centralized monitoring point, identification of the wells and shafts included in the point.  Note which method (sampling or continuous monitoring) was used. 
§98.327  Records that must be retained.
In addition to the information required by §98.3(g), you must retain the following records:
(a)  Calibration records for all monitoring equipment, including the method or manufacturer's specification used for calibration. 
(b)  Records of gas sales. 
(c)  Logbooks of parameter measurements. 
(d)  Laboratory analyses of samples.
§98.328  Definitions.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. 

Subpart II  -  Industrial Wastewater Treatment
§98.350  Definition of Source Category
(a)  This source category consists of anaerobic processes used to treat industrial wastewater and industrial wastewater treatment sludge at facilities that perform the operations listed in this paragraph.
(1)  Pulp and paper manufacturing.
(2)  Food processing.
(3)  Ethanol production.
(4)  Petroleum refining.
(b)  An anaerobic process is a procedure in which organic matter in wastewater, wastewater treatment sludge, or other material is degraded by micro-organisms in the absence of oxygen, resulting in the generation of CO2 and CH4.  This source category consists of the following:  anaerobic reactors, anaerobic lagoons, anaerobic sludge digesters, and biogas destruction devices (for example, burners, boilers, turbines, flares, or other devices). 
(1) An anaerobic reactor is an enclosed vessel used for anaerobic wastewater treatment (e.g., upflow anaerobic sludge blanket, fixed film).
(2) An anaerobic sludge digester is an enclosed vessel in which wastewater treatment sludge is degraded anaerobically.
(3) An anaerobic lagoon is a lined or unlined earthen basin used for wastewater treatment, in which oxygen is absent throughout the depth of the basin, except for a shallow surface zone.  Anaerobic lagoons are not equipped with surface aerators.  Anaerobic lagoons are classified as deep (depth more than 2 meters) or shallow (depth less than 2 meters).
(c)  This source category does not include municipal wastewater treatment plants or separate treatment of sanitary wastewater at industrial sites.
§98.351  Reporting threshold.
You must report GHG emissions under this subpart if your facility meets all of the conditions under paragraphs (a) or (b) of this section:
(a)  Petroleum Refineries and Pulp and Paper Manufacturing.
(1)  The facility is subject to reporting under subpart Y of this part (Petroleum Refineries) or subpart AA of this part (Pulp and Paper Manufacturing).
(2)  The facility meets the requirements of either §98.2(a)(1) or (2). 
(3)  The facility operates an anaerobic process to treat industrial wastewater and/or industrial wastewater treatment sludge.
(b)  Ethanol Production and Food Processing Facilities. 
(1)  The facility performs an ethanol production or food processing operation, as defined in §98.358 of this subpart.
(2)  The facility meets the requirements of §98.2(a)(2). 
(3)  The facility operates an anaerobic process to treat industrial wastewater and/or industrial wastewater treatment sludge.
§98.352  GHGs to report.
(a)  You must report CH4 generation, CH4 emissions, and CH4 recovered from treatment of industrial wastewater at each anaerobic lagoon and anaerobic reactor.
(b)  You must report CH4 emissions and CH4 recovered from each anaerobic sludge digester.
(c)  You must report CH4 emissions and CH4 destruction resulting from each biogas collection and biogas destruction device.  
(d)  You must report under subpart C of this part (General Stationary Fuel Combustion Sources) the emissions of CO2, CH4, and N2O from each stationary combustion unit associated with the biogas destruction device, if present, by following the requirements of subpart C of this part.  
§98.353  Calculating GHG emissions.
(a)  For each anaerobic reactor and anaerobic lagoon, estimate the annual mass of CH4 generated according to the applicable requirements in paragraphs (a)(1) through (a)(2) of this section. 
(1)  If you measure the concentration of organic material entering the anaerobic reactors or anaerobic lagoon using methods for the determination of chemical oxygen demand (COD), then estimate annual mass of CH4 generated using Equation II-1 of this section.  
		(Eq. II-1)
Where: 
CH4Gn 	=	Annual mass CH4 generated from the nth anaerobic wastewater treatment process (metric tons).
n	=	Index for processes at the facility, used in Equation II-7.
w	=	Index for weekly measurement period.
Floww 	=	Volume of wastewater sent to an anaerobic wastewater treatment process in week w (m[3]/week), measured as specified in §98.354(d).
CODw 	=	Average weekly concentration of chemical oxygen demand of wastewater entering an anaerobic wastewater treatment process (for week w)(kg/m[3]), measured as specified in §98.354(b) and (c). 
B0	=	Maximum CH4 producing potential of wastewater (kg CH4/kg COD), use the value 0.25.
MCF 	=	CH4 conversion factor, based on relevant values in Table II-1 of this subpart.
0.001	=	Conversion factor from kg to metric tons.

(2)  If you measure the concentration of organic material entering an anaerobic reactor or anaerobic lagoon using methods for the determination of 5-day biochemical oxygen demand (BOD5), then estimate annual mass of CH4 generated using Equation II-2 of this section.  
		(Eq. II-2)
Where: 
CH4Gn 	=	Annual mass of CH4 generated from the anaerobic wastewater treatment process (metric tons).
n	=	Index for processes at the facility, used in Equation II-7.
w	=	Index for weekly measurement period.
Floww 	=	Volume of wastewater sent to an anaerobic wastewater treatment process in week w(m[3]/week), measured as specified in §98.354(d).
BOD5,w 	=	Average weekly concentration of 5-day biochemical oxygen demand of wastewater entering an anaerobic wastewater treatment process for week w(kg/m[3]), measured as specified in §98.354(b) and (c). 
B0	=	Maximum CH4 producing potential of wastewater (kg CH4 /kg BOD5), use the value 0.6.
MCF 	=	CH4 conversion factor, based on relevant values in Table II-1 of this subpart.
0.001	=	Conversion factor from kg to metric tons. 

(b)  For each anaerobic reactor and anaerobic lagoon from which biogas is not recovered, estimate annual CH4 emissions using Equation II-3 of this section. 
	CH4En = CH4Gn	(Eq. II-3)
Where: 
CH4En 	=	Annual mass of CH4 emissions from the wastewater treatment process n from which biogas is not recovered (metric tons).
CH4Gn 	=	Annual mass of CH4 generated from the wastewater treatment process n, as calculated in Equation II-1 or II-2 of this section(metric tons).

(c)  For each anaerobic sludge digester, anaerobic reactor, or anaerobic lagoon from which some biogas is recovered, estimate the annual mass of CH4 recovered according to the requirements in paragraphs (c)(1) and (c)(2) of this section.  To estimate the annual mass of CH4 recovered, you must continuously monitor biogas flow rate and determine the volume of biogas each week and the cumulative volume of biogas each year that is collected and routed to a destruction device as specified in §98.354(h).  If the gas flow meter is not equipped with automatic correction for temperature, pressure, or, if necessary, moisture content, you must determine these parameters as specified in paragraph (c)(2)(ii) of this section. 
(1)  If you continuously monitor CH4 concentration (and if necessary, temperature, pressure, and moisture content required as specified in §98.354(f)) of the biogas that is collected and routed to a destruction device using a monitoring meter specifically for CH4 gas, as specified in §98.354(g), you must use this monitoring system and calculate the quantity of CH4 recovered for destruction using Equation II-4 of this section.  A fully integrated system that directly reports CH4 quantity requires only the summing of results of all monitoring periods for a given year.    
                                     Rn =
		(Eq. II-4)
Where:
Rn	=	Annual quantity of CH4 recovered from the nth anaerobic reactor, sludge digester, or lagoon (metric tons CH4/yr)
n	=	Index for processes at the facility, used in Equation II-7.
M	=	Total number of measurement periods in a year.  Use M=365 (M=366 for leap years) for daily averaging of continuous monitoring, as provided in paragraph(c)(1)of this section. Use M=52 for weekly sampling, as provided in paragraph(c)(2)of this section.
m	=	Index for measurement period.
Vm	=	Cumulative volumetric flow for the measurement period in actual cubic feet(acf).  If no biogas was recovered during a monitoring period, use zero. 
(KMC)m	=	Moisture correction term for the measurement period, volumetric basis. 
	=	1 when (V)m and (CCH4)m are measured on a dry basis or if both are measured on a wet basis.
	=	1-(fH2O)m when (V)m is measured on a wet basis and (CCH4)m is measured on a dry basis.
	=   1/[1-(fH2O)m] when (V)m is measured on a dry basis and (CCH4)m is measured on a wet basis.
(fH2O)m	=	Average moisture content of biogas during the measurment period, volumetric basis, (cubic feet water per cubic feet biogas).
(CCH4)m	=	Average CH4 concentration of biogas during the measurement period, (volume %).  
0.0423	=	Density of CH4 lb/cf at 520°R or 60°F and 1 atm. 
520 [o]R	=	520 degrees Rankine.
Tm	=	Average temperature at which flow is measured for the measurement period(°R). If the flow rate meter automatically corrects for temperature to 520° R, replace "520° R/Tm" with "1".
Pm	=	Average pressure at which flow is measured for the measurement period (atm). If the flow rate meter automatically corrects for pressure to 1 atm, replace "Pm/1" with "1".
0.454/1,000	=	Conversion factor (metric ton/lb).

(2)  If you do not continuously monitor CH4 concentration according to paragraph(c)(1) of this section, you must determine the CH4 concentration, temperature, pressure, and, if necessary, moisture content of the biogas that is collected and routed to a destruction device according to the requirements in paragraphs (c)(2)(i) through (c)(2)(ii) of this section and calculate the quantity of CH4 recovered for destruction using Equation II-4 of this section. 

(i)  Determine the CH4 concentration in the biogas that is collected and routed to a destruction device in a location near or representative of the location of the gas flow meter at least once each calendar week; if only one measurement is made each calendar week, there must be least three days between measurements.  For a given calendar week, you are not required to determine CH4 concentration if the cumulative volume of biogas for that calendar week, determined as specified in paragraph (c) of this section, is zero.  
(ii)  If the gas flow meter is not equipped with automatic correction for temperature, pressure, or, if necessary, moisture content: 
(A)  Determine the temperature and pressure in the biogas that is collected and routed to a destruction device in a location near or representative of the location of the gas flow meter at least once each calendar week; if only one measurement is made each calendar week, there must be at least three days between measurements. 
(B)  If the CH4 concentration is determined on a dry basis and biogas flow is determined on a wet basis, or CH4 concentration is determined on a wet basis and biogas flow is determined on a dry basis, and the flow meter does not automatically correct for moisture content, determine the moisture content in the biogas that is collected and routed to a destruction device in a location near or representative of the location of the gas flow meter at least once each calendar week that the cumulative biogas flow measured as specified in §98.354(h) is greater than zero; if only one measurement is made each calendar week, there must be at least three days between measurements. 
(d)  For each anaerobic sludge digester, anaerobic reactor, or anaerobic lagoon from which some quantity of biogas is recovered, you must estimate both the annual mass of CH4 that is generated, but not recovered, according to paragraph (d)(1) of this section and the annual mass of CH4 emitted according to paragraph (d)(2) of this section. 
(1) Estimate the annual mass of CH4 that is generated, but not recovered, using Equation II-5 of this section. 
		(Eq. II-5)
Where: 
CH4Ln 	=	Leakage at the anaerobic process n (metric tons CH4).   
n	=	Index for processes at the facility, used in Equation II-7.
Rn	=	Annual quantity of CH4 recovered from the nth anaerobic reactor, anaerobic lagoon, or anaerobic sludge digester, as calculated in Equation II-4 of this section (metric tons CH4).
CE	=	CH4 collection efficiency of anaerobic process n, as specified in Table II-2 of this subpart (decimal).

(2)  For each anaerobic sludge digester, anaerobic reactor, or anaerobic lagoon from which some quantity of biogas is recovered, estimate the annual mass of CH4 emitted using Equation II-6 of this section.
		(Eq. II-6)
  CH4En = CH4Ln + Rn (1− [ (DE1 ∗ fDest_1 )+ (DE2 ∗ fDest_2)])

Where:
CH4En	=	Annual quantity of CH4 emitted from the process n from which biogas is recovered (metric tons).
n	=	Index for processes at the facility, used in Equation II-7.
CH4Ln	=	Leakage at the anaerobic process n, as calculated in Equation II-5 of this section (metric tons CH4). 
Rn 	=	Annual quantity of CH4 recovered from the nth anaerobic reactor or anaerobic sludge digester, as calculated in Equation II-4 of this section (metric tons CH4).
DE1 	=	Primary destruction device CH4 destruction efficiency (lesser of manufacturer's specified destruction efficiency and 0.99).  If the biogas is transported offsite for destruction, use DE=1.
fDest_1	=	Fraction of hours the primary destruction device was operating (device operating hours/hours in the year).  If the biogas is transported offsite for destruction, use fDest=1. 
DE2 	=	Back-up destruction device CH4 destruction efficiency (lesser of manufacturer's specified destruction efficiency and 0.99).  
fDest_2	=	Fraction of hours the back-up destruction device was operating (device operating hours/hours in the year). 

(e)  Estimate the total mass of CH4 emitted from all  anaerobic processes from which biogas is not recovered (calcluated in Eq. II-3) and all anaerobic processes from which some biogas is recovered (calculated in Equation II-6) using Equation II-7 of this section.
		(Eq. II-7)
Where: 
CH4ET 	=	Annual mass CH4 emitted from all anaerobic processes at the facility (metric tons).
n	=	Index for processes at the facility.
CH4En	=	Annual mass of CH4 emissions from process n (metric tons).
j	=	Total number of processes from which methane is emitted. 

§98.354  Monitoring and QA/QC requirements. 
(a) For calendar year 2011 monitoring, the facility may submit a request to the Administrator to use one or more best available monitoring methods as listed in §98.3(d)(1)(i) through (iv).  The request must be submitted no later than [INSERT DATE 90 DAYS AFTER PUBLICATION IN THE FEDERAL REGISTER] and must contain the information in §98.3(d)(2)(ii).  To obtain approval, the request 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 January 1, 2011.  The use of best available monitoring methods will not be approved beyond December 31, 2011.      
(b) You must determine the concentration of organic material in wastewater treated anaerobically using analytical methods for COD or BOD5 specified in 40 CFR part 136.3 Table 1B.  For the purpose of determining concentrations of wastewater influent to the anaerobic wastewater treatment process, samples may be diluted to the concentration range of the approved method, but the calculated concentration of the undiluted wastewater must be used for calcuations and reporting required by this subpart.
(c)  You must collect samples representing wastewater influent to the anaerobic wastewater treatment process, following all preliminary and primary treatment steps (e.g., after grit removal, primary clarfication, oil-water separation, dissolved air flotation, or similar solids and oil separation processes).  You must collect and analyze samples for COD or BOD5 concentration at least once each calendar week that the anaerobic wastewater treatment process is operating; if only one measurement is made each calendar week, there must be at least three days between measurements. You must collect a sample that represents the average COD or BOD5 concentration of the waste stream over a 24-hour  sampling period.  You must collect a minimum of four sample aliquots per 24-hour period and composite the aliquots for analysis.  Collect a flow-proportional composite sample (either constant time interval between samples with sample volume proportional to stream flow, or constant sample volume with time interval between samples proportional to stream flow).  Follow sampling procedures and techniques presented in Chapter 5, Sampling, of the "NPDES Compliance Inspection Manual," (incorporated by reference, see §98.7) or Section 7.1.3, Sample Collection Methods, of the "U.S. EPA NPDES Permit Writers' Manual," (incorporated by reference, see §98.7) .
(d)  You must measure the flowrate of wastewater entering anaerobic wastewater treatment process at least once each calendar week that the process is operating; if only one measurement is made each calendar week, there must be at least three days between measurements.  You must measure the flowrate for the 24-hour period for which you collect samples analyzed for COD or BOD5 concentration.  The flow measurement location must correspond to the location used to collect samples analyzed for COD or BOD5 concentration.   You must measure the flowrate using one of the methods specified in paragraphs (d)(1) through (d)(5) of this section or as specified by the manufacturer.  
(1)  ASME MFC - 3M - 2004 Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and Venturi (incorporated by reference, see §98.7). 
(2)  ASME MFC - 5M - 1985 (Reaffirmed 1994) Measurement of Liquid Flow in Closed Conduits Using Transit-Time Ultrasonic Flowmeters (incorporated by reference, see §98.7).  
(3)  ASME MFC - 16 - 2007 Measurement of Liquid Flow in Closed Conduits with Electromagnetic Flowmeters (incorporated by reference, see §98.7).
(4)  ASTM D1941-91 (Reapproved 2007) Standard Test Method for Open Channel Flow Measurement of Water with the Parshall Flume, approved June 15, 2007, (incorporated by reference, see §98.7).
(5)  ASTM D5614-94 (Reapproved 2008) Standard Test Method for Open Channel Flow Measurement of Water with Broad-Crested Weirs, approved October 1, 2008, (incorporated by reference, see §98.7).
(e)  All wastewater flow measurement devices must be calibrated prior to the first year of reporting and recalibrated either biennially (every 2 years) or at the minimum frequency specified by the manufacturer.  Wastewater flow measurement devices must be calibrated using the procedures specified by the device manufacturer.
(f)  For each anaerobic process (such as anaerobic reactor, sludge digester, or lagoon) from which biogas is recovered, you must make the measurements or determinations specified in paragrahps (f)(1) through(f)(3)of this section.
(1) You must continuously measure the biogas flow rate as specified in paragraph (h) of this section and determine the cumulative volume of biogas recovered.  
(2)You must determine the CH4 concentration of the recovered biogas as specified in paragraph (g) of this section at a location near or representative of the location of the gas flow meter.  You must determine CH4 concentration either continuously or intermittently.  If you determine the concentration intermittently, you must determine the concentration at least once each calendar week that the cumulative biogas flow measured as specified in paragraph (h) of this section is greater than zero, with at least three days between measurements.  
(3)As specified in §98.353(c) and paragraph (h) of this section, you must determine temperature, pressure, and moisture content as necessary to accurately determine the biogas flow rate and CH4 concentration.  You must determine temperature and pressure if the gas flow meter or gas composition monitor do not automatically correct for temperature or pressure.  You must measure moisture content of the recovered biogas if the biogas flow rate is measured on a wet basis and the CH4 concentration is measured on a dry basis.  You must also measure the moisture content of the recovered biogas if the biogas flow rate is measured on a dry basis and the CH4 concentration is measured on a wet basis. 
(g)  For each anaerobic process (such as an anaerobic reactor, sludge digester, or lagoon) from which biogas is recovered, operate, maintain, and calibrate a gas composition monitor capable of measuring the concentration of CH4 in the recovered biogas using one of the methods specified in paragraphs (g)(1)through(g)(6) of this section or as specified by the manufacturer. 
(1)  Method 18 at 40 CFR part 60, appendix A-6.
(2)  ASTM D1945-03, Standard Test Method for Analysis of Natural Gas by Gas Chromatography (incorporated by reference, see §98.7).
(3)  ASTM D1946-90 (Reapproved 2006), Standard Practice for Analysis of Reformed Gas by Gas Chromatography (incorporated by reference, see §98.7).
(4)  GPA Standard 2261-00, Analysis for Natural Gas and Similar Gaseous Mixtures by Gas Chromatography (incorporated by reference, see §98.7).
(5)  ASTM UOP539-97 Refinery Gas Analysis by Gas Chromatography (incorporated by reference, see §98.7).
(6)  As an alternative to the gas chromatography methods provided in paragraphs(g)(1) through (g)(5) of this section, you may use total gaseous organic concentration analyzers and calculate the CH4 concentration following the requirements in paragraphs (g)(6)(i) through (g)(6)(iii) of this section.
(i)  Use Method 25A or 25B at 40 CFR part 60, appendix A-7 to determine total gaseous organic concentration.  You must calibrate the instrument with CH4 and determine the total gaseous organic concentration as carbon (or as CH4; K=1 in Equation 25A-1 of Method 25A at 40 CFR part 60, appendix A-7).
(ii)  Determine a non-methane organic carbon correction factor at the routine sampling location no less frequently than once a reporting year following the requirements in paragraphs (g)(6)(ii)(A) through (g)(6)(ii)(C) of this section.
(A)  Take a minimum of three grab samples of the biogas with a minimum of 20 minutes between samples and determine the methane composition of the biogas using one of the methods specified in paragraphs (g)(1) through (g)(5) of this section.
(B)  As soon as practical after each grab sample is collected and prior to the collection of a subsequent grab sample, determine the total gaseous organic concentration of the biogas using either Method 25A or 25B at 40 CFR part 60, appendix A-7 as specified in paragraph (g)(6)(i) of this section.
(C)  Determine the arithmetic average methane concentration and the arithmetic average total gaseous organic concentration of the samples analyzed according to paragraphs (g)(6)(ii)(A) and (g)(6)(ii)(B) of this section, respectively, and calculate the non-methane organic carbon correction factor as the ratio of the average methane concentration to the average total gaseous organic concentration.  If the ratio exceeds 1, use 1 for the non-methane organic carbon correction factor.
(iii)  Calculate the CH4 concentration as specified in Equation II-8 of this section.
	CCH4 = fNMOC x CTGOC	(Eq. II-8)
Where:
CCH4	=	Methane (CH4) concentration in the biogas(volume %) for use in Equation II-4 of this subpart.
fNMOC 	=   Non-methane organic carbon correction factor from the most recent determination of the non-methane organic carbon correction factor as specified in paragraph (g)(6)(ii) of this section (unitless).
CTGOC 	=	Total gaseous organic carbon concentration measured using Method 25A or 25B at 40 CFR part 60, appendix A-7 during routine monitoring of the biogas (volume %).

(h)  For each anaerobic process (such as an anaerobic reactor, sludge digester, or lagoon) from which biogas is recovered, install, operate, maintain, and calibrate a gas flow meter capable of continuously measuring the volumetric flow rate of the recovered biogas using one of the methods specified in paragraphs (h)(1) through (h)(8) of this section or as specified by the manufacturer.  Recalibrate each gas flow meter either biennially (every 2 years) or at the minimum frequency specified by the manufacturer.  Except as provided in §98.353(c)(2)(iii), each gas flow meter must be capable of correcting for the temperature and pressure and, if necessary, moisture content.
(1)  ASME MFC-3M-2004, Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and Venturi (incorporated by reference, see §98.7).
(2)  ASME MFC-4M-1986 (Reaffirmed 1997), Measurement of Gas Flow by Turbine Meters (incorporated by reference, see §98.7).
(3)  ASME MFC-6M-1998, Measurement of Fluid Flow in Pipes Using Vortex Flowmeters (incorporated by reference, see §98.7).
(4)  ASME MFC-7M-1987 (Reaffirmed 1992), Measurement of Gas Flow by Means of Critical Flow Venturi Nozzles (incorporated by reference, see §98.7).
(5)  ASME MFC-11M-2006 Measurement of Fluid Flow by Means of Coriolis Mass Flowmeters (incorporated by reference, see §98.7).  The mass flow must be corrected to volumetric flow based on the measured temperature, pressure, and biogas composition.
(6)  ASME MFC-14M-2003 Measurement of Fluid Flow Using Small Bore Precision Orifice Meters (incorporated by reference, see §98.7).
(7)  ASME MFC-18M-2001 Measurement of Fluid Flow using Variable Area Meters (incorporated by reference, see §98.7).
(8)  Method 2A or 2D at 40 CFR part 60, appendix A-1.
(i)  All temperature, pressure, and, moisture content monitors required as specified in paragraph (f) of this section must be calibrated using the procedures and frequencies where specified by the device manufacturer, if not specified use an industry accepted or industry standard practice.
(j)  All equipment (temperature, pressure, and moisture content monitors and gas flow meters and gas composition monitors) must be maintained as specified by the manufacturer.
(k)  If applicable, the owner or operator must document the procedures used to ensure the accuracy of measurements of COD or BOD5 concentration, wastewater flow rate, biogas flow rate, biogas composition, temperature, pressure, and moisture content.  These procedures include, but are not limited to, calibration of gas flow meters, and other measurement devices.  The estimated accuracy of measurements made with these devices must also be recorded, and the technical basis for these estimates must be documented.
§98.355  Procedures for estimating missing data
A complete record of all measured parameters used in the GHG emissions calculations is required.  Therefore, whenever a quality-assured value of a required parameter is unavailable (e.g., if a meter malfunctions during unit operation or if a required sample is not taken), a substitute data value for the missing parameter must be used in the calculations, according to the following requirements in paragraphs (a) through (c) of this section:
(a)  For each missing weekly value of COD or BOD5 or wastewater flow entering an anaerobic wastewater treatment process, the substitute data value must be the arithmetic average of the quality-assured values of those parameters for the week immediately preceding and the week immediately following the missing data incident. 
(b)  For each missing value of the CH4 content or biogas flow rates, the substitute data value must be the arithmetic average of the quality-assured values of that parameter immediately preceding and immediately following the missing data incident. 
(c)  If, for a particular parameter, no quality-assured data are available prior to the missing data incident, the substitute data value must be the first quality-assured value obtained after the missing data period.  If, for a particular parameter, the "after" value is not obtained by the end of the reporting year, you may use the last quality-assured value obtained "before" the missing data period for the missing data substitution.  You must document and keep records of the procedures you use for all such estimates. 
§98.356  Data reporting requirements. 
In addition to the information required by §98.3(c), each annual report must contain the following information for each wastewater treatment system.  
(a)  A description or diagram of the industrial wastewater treatment system, identifying the processes used to treat industrial wastewater and industrial wastewater treatment sludge.  Indicate how the processes are related to each other and identify the anaerobic processes.   Provide a unique identifier for each anaerobic process, indicate the average depth in meters of each anaerobic lagoon, and indicate whether biogas generated by each anaerobic process is recovered.  The anaerobic processes must be identified as:
(1)  Anaerobic reactor.
(2)  Anaerobic deep lagoon (depth more than 2 meters).
(3)  Anaerobic shallow lagoon (depth less than 2 meters).
(4)  Anaerobic sludge digester.
(b)  For each anaerobic wastewater treatment process (reactor, deep lagoon, or shallow lagoon) you must report:
(1)  Weekly average COD or BOD5 concentration of wastewater entering each anaerobic wastewater treatment process, for each week the anaerobic process was operated.
(2)  Volume of wastewater entering each anaerobic wastewater treatment process for each week the anaerobic process was operated.
(3)  Maximum CH4 production potential (B0) used as an input to Equation II-1 or II-2 of this subpart, from Table II-1. 
(4)  Methane conversion factor (MCF) used as an input to Equation II-1 or II-2 of this subpart, from Table II-1. 
(5)  Annual mass of CH4 generated by each anaerobic wastewater treatment process, calculated using Equation II-1 or II-2 of this subpart. 
(c)  For each anaerobic wastewater treatment process from which biogas is not recovered, you must report the annual CH4 emissions, calculated using Equation II-3 of this subpart. 
(d)  For each anaerobic wastewater treatment process and anaerobic sludge digester from which some biogas is recovered, you must report:
(1)  Annual quantity of CH4 recovered from the anaerobic process calculated using Equation II-4 of this subpart.
(2)  Total weekly volumetric biogas flow for each week (up to 52 weeks/year) that biogas is collected for destruction.
(3)  Weekly average CH4 concentration for each week that biogas is collected for destruction.
(4)  Weekly average biogas temperature for each week at which flow is measured for biogas collected for destruction, or statement that temperature is incorporated into monitoring equipment internal calcultations.
(5)  Whether flow was measured on a wet or dry basis, whether CH4 concentration was measured on a wet or dry basis, and if required for Equation II-4 of this subpart, weekly average moisture content for each week at which flow is measured for biogas collected for destruction, or statement that moisture content is incorporated into monitoring equipment internal calculations.
(6)  Weekly average biogas pressure for each week at which flow is measured for biogas collected for destruction, or statement that pressure is incorporated into monitoring equipment internal calcultations.
(7)  CH4 collection efficiency (CE) used in Equation II-5 of this subpart.
(8)  Whether destruction occurs at the facility or offsite.  If destruction occurs at the facility, also report whether a back-up destruction device is present at the facility, the annual operating hours for the primary destruction device, the annual operating hours for the back-up destruction device (if present), the destruction efficiency for the primary destruction device, and the destruction efficiency for the back-up destruction device (if present). 
(9)  For each anaerobic process from which some biogas is recovered, you must report the annual CH4 emissions, as calculated by Equation II-6 of this subpart. 
(e) The total mass of CH4 emitted from all anaerobic processes from which biogas is not recovered (calcluated in Equation II-3 of this supbart) and from all anaerobic processes from which some biogas is recovered (calculated in Equation II-6 of this subpart) using Equation II-7 of this subpart.
§98.357  Records that must be retained. 
In addition to the information required by §98.3(g), you must retain the calibration records for all monitoring equipment, including the method or manufacturer's specification used for calibration.  
§98.358  Definitions.
Except as provided below, all terms used in this subpart have the same meaning given in the CAA and subpart A of this part.
Biogas means the combination of CO2, CH4, and other gases produced by the biological breakdown of organic matter in the absence of oxygen. 
Ethanol production means an operation that produces ethanol from the fermentation of sugar, starch, grain, or cellulosic biomass feedstocks, or the production of ethanol synthetically from petrochemical feedstocks, such as ethylene or other chemicals.
Food processing means an operation used to manufacture or process meat, poultry, fruits, and/or vegtables as defined under NAICS 3116 (Meat Product Manufacturing) or NAICS 3114 (Fruit and Vegetable Preserving and Specialty Food Manufacturing).  For information on NAICS codes, see http://www.census.gov/eos/www/naics/.
Industrial wastewater means water containing wastes from an industrial process.  Industrial wastewater includes water which comes into direct contact with or results from the storage, production, or use of any raw material, intermediate product, finished product, by-product, or waste product.  Examples of industrial wastewater include, but are not limited to, paper mill white water, wastewater from equipment cleaning, wastewater from air pollution control devices, rinse water, contaminated stormwater, and contaminated cooling water. 
Industrial wastewater treatment sludge means solid or semi-solid material resulting from the treatment of industrial wastewater, including but not limited to biosolids, screenings, grit, scum, and settled solids.
Wastewater treatment system means the collection of all processes that treat or remove pollutants and contaminants, such as soluble organic matter, suspended solids, pathogenic organisms, and chemicals from wastewater prior to its reuse or discharge from the facility.

Table II-1 of Subpart II -- Emission Factors
                                    Factors
                                 Default value
                                     Units
B0  -  for facilities monitoring COD
                                     0.25
Kg CH4/kg COD
B0  -  for facilities monitoring BOD5
                                     0.60
Kg CH4/kg BOD5
MCF  -  anaerobic reactor 
                                      0.8
Fraction
MCF  -  anaerobic deep lagoon (depth more than 2 m)
                                      0.8
Fraction
MCF  -  anaerobic shallow lagoon (depth less than 2 m)
                                      0.2
Fraction

Table II-2 of Subpart II -- Collection Efficiencies of Anaerobic Processes
                            Anaerobic Process Type
                                  Cover Type
                         Methane Collection Efficiency
Covered anaerobic lagoon (biogas capture)
Bank to bank, impermeable
                                     0.975

Modular, impermeable
                                     0.70
Anaerobic sludge digester; anaerobic reactor
Enclosed Vessel
                                     0.99

Subpart OO -- Suppliers of Industrial Greenhouse Gases
§ 98.410   Definition of the source category.
(a) The industrial gas supplier source category consists of any facility that produces a fluorinated GHG or nitrous oxide, any bulk importer of fluorinated GHGs or nitrous oxide, and any bulk exporter of fluorinated GHGs or nitrous oxide.
(b) To produce a fluorinated GHG means to manufacture a fluorinated GHG from any raw material or feedstock chemical. Producing a fluorinated GHG includes the manufacture of a fluorinated GHG as an isolated intermediate for use in a process that will result in its transformation either at or outside of the production facility. Producing a fluorinated GHG also includes the creation of a fluorinated GHG (with the exception of HFC - 23) that is captured and shipped off site for any reason, including destruction. Producing a fluorinated GHG does not include the reuse or recycling of a fluorinated GHG, the creation of HFC - 23 during the production of HCFC - 22, the creation of intermediates that are created and transformed in a single process with no storage of the intermediates, or the creation of fluorinated GHGs that are released or destroyed at the production facility before the production measurement at §98.414(a).
(c) To produce nitrous oxide means to produce nitrous oxide by thermally decomposing ammonium nitrate (NH4NO3). Producing nitrous oxide does not include the reuse or recycling of nitrous oxide or the creation of by-products that are released or destroyed at the production facility.
[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79167, Dec. 17, 2010]
§ 98.411   Reporting threshold.
Any supplier of industrial greenhouse gases who meets the requirements of §98.2(a)(4) must report GHG emissions.
§ 98.412   GHGs to report.
You must report the GHG emissions that would result from the release of the nitrous oxide and each fluorinated GHG that you produce, import, export, transform, or destroy during the calendar year.
§ 98.413   Calculating GHG emissions.
(a) Calculate the total mass of each fluorinated GHG or nitrous oxide produced annually, except for amounts that are captured solely to be shipped off site for destruction, by using Equation OO - 1 of this section:

P = Mass of fluorinated GHG or nitrous oxide produced annually.
Pp= Mass of fluorinated GHG or nitrous oxide produced over the period "p".
 (b) Calculate the total mass of each fluorinated GHG or nitrous oxide produced over the period "p" by using Equation OO - 2 of this section:

Where:
Pp= Mass of fluorinated GHG or nitrous oxide produced over the period "p" (metric tons).
Op= Mass of fluorinated GHG or nitrous oxide that is measured coming out of the production process over the period p (metric tons).
Up= Mass of used fluorinated GHG or nitrous oxide that is added to the production process upstream of the output measurement over the period "p" (metric tons).
(c) Calculate the total mass of each fluorinated GHG or nitrous oxide transformed by using Equation OO - 3 of this section:

Where:
T = Mass of fluorinated GHG or nitrous oxide transformed annually (metric tons).
FT= Mass of fluorinated GHG fed into the transformation process annually (metric tons).
ET= The fraction of the fluorinated GHG or nitrous oxide fed into the transformation process that is transformed in the process (metric tons).
(d) Calculate the total mass of each fluorinated GHG destroyed by using Equation OO - 4 of this section:

Where:
D = Mass of fluorinated GHG destroyed annually (metric tons).
FD= Mass of fluorinated GHG fed into the destruction device annually (metric tons).
DE = Destruction efficiency of the destruction device (fraction).
§ 98.414   Monitoring and QA/QC requirements.
(a) The mass of fluorinated GHGs or nitrous oxide coming out of the production process shall be measured using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of one percent of full scale or better. If the measured mass includes more than one fluorinated GHG, the concentrations of each of the fluorinated GHGs, other than low-concentration constituents, shall be measured as set forth in paragraph (n) of this section. For each fluorinated GHG, the mean of the concentrations of that fluorinated GHG (mass fraction) measured under paragraph (n) of this section shall be multiplied by the mass measurement to obtain the mass of that fluorinated GHG coming out of the production process.
(b) The mass of any used fluorinated GHGs or used nitrous oxide added back into the production process upstream of the output measurement in paragraph (a) of this section shall be measured using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of one percent of full scale or better. If the mass in paragraph (a) of this section is measured by weighing containers that include returned heels as well as newly produced fluorinated GHGs, the returned heels shall be considered used fluorinated GHGs for purposes of this paragraph (b) of this section and §98.413(b).
(c) The mass of fluorinated GHGs or nitrous oxide fed into the transformation process shall be measured using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of one percent of full scale or better.
(d) The fraction of the fluorinated GHGs or nitrous oxide fed into the transformation process that is actually transformed shall be estimated considering yield calculations or quantities of unreacted fluorinated GHGs or nitrous oxide permanently removed from the process and recovered, destroyed, or emitted.
(e) The mass of fluorinated GHG or nitrous oxide sent to another facility for transformation shall be measured using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of one percent of full scale or better.
(f) The mass of fluorinated GHG sent to another facility for destruction shall be measured using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of one percent of full scale or better. If the measured mass includes more than trace concentrations of materials other than the fluorinated GHG, the concentration of the fluorinated GHG shall be estimated considering current or previous representative concentration measurements and other relevant process information. This concentration (mass fraction) shall be multiplied by the mass measurement to obtain the mass of the fluorinated GHG sent to another facility for destruction.
(g) You must estimate the share of the mass of fluorinated GHGs in paragraph (f) of this section that is comprised of fluorinated GHGs that are not included in the mass produced in §98.413(a) because they are removed from the production process as by-products or other wastes.
(h) You must measure the mass of each fluorinated GHG that is fed into the destruction device and that was previously produced as defined at §98.410(b). Such fluorinated GHGs include but are not limited to quantities that are shipped to the facility by another facility for destruction and quantities that are returned to the facility for reclamation but are found to be irretrievably contaminated and are therefore destroyed. You must use flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of one percent of full scale or better. If the measured mass includes more than trace concentrations of materials other than the fluorinated GHG being destroyed, you must estimate the concentrations of the fluorinated GHG being destroyed considering current or previous representative concentration measurements and other relevant process information. You must multiply this concentration (mass fraction) by the mass measurement to obtain the mass of the fluorinated GHG fed into the destruction device.
(i) Very small quantities of fluorinated GHGs that are difficult to measure because they are entrained in other media such as destroyed filters and destroyed sample containers are exempt from paragraphs (f) and (h) of this section.
(j) [Reserved]
(k) For purposes of Equation OO - 4 of this subpart, the destruction efficiency can be equated to the destruction efficiency determined during a previous performance test of the destruction device or, if no performance test has been done, the destruction efficiency provided by the manufacturer of the destruction device.
(l) In their estimates of the mass of fluorinated GHGs destroyed, fluorinated GHG production facilities that destroy fluorinated GHGs shall account for any temporary reductions in the destruction efficiency that result from any startups, shutdowns, or malfunctions of the destruction device, including departures from the operating conditions defined in state or local permitting requirements and/or oxidizer manufacturer specifications.
(m) Calibrate all flow meters, weigh scales, and combinations of volumetric and density measures that are used to measure or calculate quantities that are to be reported under this subpart prior to the first year for which GHG emissions are reported under this part. Calibrations performed prior to the effective date of this rule satisfy this requirement. Recalibrate all flow meters, weigh scales, and combinations of volumetric and density measures at the minimum frequency specified by the manufacturer. Use NIST-traceable standards and suitable methods published by a consensus standards organization (e.g., ASTM, ASME, ISO, or others).
(n) If the mass coming out of the production process includes more than one fluorinated GHG, you shall measure the concentrations of all of the fluorinated GHGs, other than low-concentration constituents, as follows:
(1) Analytical Methods. Use a quality-assured analytical measurement technology capable of detecting the analyte of interest at the concentration of interest and use a procedure validated with the analyte of interest at the concentration of interest. Where standards for the analyte are not available, a chemically similar surrogate may be used. Acceptable analytical measurement technologies include but are not limited to gas chromatography (GC) with an appropriate detector, infrared (IR), fourier transform infrared (FTIR), and nuclear magnetic resonance (NMR). Acceptable methods include EPA Method 18 in appendix A - 1 of 40 CFR part 60; EPA Method 320 in appendix A of 40 CFR part 63; the 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) (incorporated by reference, see §98.7); ASTM D6348 - 03 Standard Test Method for Determination of Gaseous Compounds by Extractive Direct Interface Fourier Transform Infrared (FTIR) Spectroscopy (incorporated by reference, see §98.7); or other analytical methods validated using EPA Method 301 in appendix A of 40 CFR part 63 or some other scientifically sound validation protocol. The validation protocol may include analytical technology manufacturer specifications or recommendations.
(2) Documentation in GHG Monitoring Plan. Describe the analytical method(s) used under paragraph (n)(1) of this section in the site GHG Monitoring Plan as required under §98.3(g)(5). At a minimum, include in the description of the method a description of the analytical measurement equipment and procedures, quantitative estimates of the method's accuracy and precision for the analytes of interest at the concentrations of interest, as well as a description of how these accuracies and precisions were estimated, including the validation protocol used.
(3) Frequency of measurement. Perform the measurements at least once by February 15, 2011 if the fluorinated GHG product is being produced on December 17, 2010. Perform the measurements within 60 days of commencing production of any fluorinated GHG product that was not being produced on December 17, 2010. Repeat the measurements if an operational or process change occurs that could change the identities or significantly change the concentrations of the fluorinated GHG constituents of the fluorinated GHG product. Complete the repeat measurements within 60 days of the operational or process change.
(4) Measure all product grades. Where a fluorinated GHG is produced at more than one purity level ( e.g., pharmaceutical grade and refrigerant grade), perform the measurements for each purity level.
(5) Number of samples. Analyze a minimum of three samples of the fluorinated GHG product that have been drawn under conditions that are representative of the process producing the fluorinated GHG product. If the relative standard deviation of the measured concentrations of any of the fluorinated GHG constituents (other than low-concentration constituents) is greater than or equal to 15 percent, draw and analyze enough additional samples to achieve a total of at least six samples of the fluorinated GHG product.
(o) All analytical equipment used to determine the concentration of fluorinated GHGs, including but not limited to gas chromatographs and associated detectors, IR, FTIR and NMR devices, shall be calibrated at a frequency needed to support the type of analysis specified in the site GHG Monitoring Plan as required under §§98.414(n) and 98.3(g)(5) of this part. Quality assurance samples at the concentrations of concern shall be used for the calibration. Such quality assurance samples shall consist of or be prepared from certified standards of the analytes of concern where available; if not available, calibration shall be performed by a method specified in the GHG Monitoring Plan.
(p) Isolated intermediates that are produced and transformed at the same facility are exempt from the monitoring requirements of this section.
(q) Low-concentration constituents are exempt from the monitoring and QA/QC requirements of this section.
[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79167, Dec. 17, 2010]
§ 98.415   Procedures for estimating missing data.
(a) A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable (e.g., if a meter malfunctions), a substitute data value for the missing parameter shall be used in the calculations, according to paragraph (b) of this section.
(b) For each missing value of the mass produced, fed into the production process (for used material being reclaimed), fed into the transformation process, fed into destruction devices, sent to another facility for transformation, or sent to another facility for destruction, the substitute value of that parameter shall be a secondary mass measurement where such a measurement is available. For example, if the mass produced is usually measured with a flowmeter at the inlet to the day tank and that flowmeter fails to meet an accuracy or precision test, malfunctions, or is rendered inoperable, then the mass produced may be estimated by calculating the change in volume in the day tank and multiplying it by the density of the product. Where a secondary mass measurement is not available, the substitute value of the parameter shall be an estimate based on a related parameter. For example, if a flowmeter measuring the mass fed into a destruction device is rendered inoperable, then the mass fed into the destruction device may be estimated using the production rate and the previously observed relationship between the production rate and the mass flow rate into the destruction device.
§ 98.416   Data reporting requirements.
In addition to the information required by §98.3(c), each annual report must contain the following information:
(a) Each fluorinated GHG or nitrous oxide production facility shall report the following information:
(1) Mass in metric tons of each fluorinated GHG or nitrous oxide produced at that facility by process, except for amounts that are captured solely to be shipped off site for destruction.
(2) Mass in metric tons of each fluorinated GHG or nitrous oxide transformed at that facility, by process.
(3) Mass in metric tons of each fluorinated GHG that is destroyed at that facility and that was previously produced as defined at §98.410(b). Quantities to be reported under this paragraph (a)(3) of this section include but are not limited to quantities that are shipped to the facility by another facility for destruction and quantities that are returned to the facility for reclamation but are found to be irretrievably contaminated and are therefore destroyed.
(4) [Reserved]
(5) Total mass in metric tons of each fluorinated GHG or nitrous oxide sent to another facility for transformation.
(6) Total mass in metric tons of each fluorinated GHG sent to another facility for destruction, except fluorinated GHGs that are not included in the mass produced in §98.413(a) because they are removed from the production process as by-products or other wastes. Quantities to be reported under this paragraph (a)(6) could include, for example, fluorinated GHGs that are returned to the facility for reclamation but are found to be irretrievably contaminated and are therefore sent to another facility for destruction.
(7) Total mass in metric tons of each fluorinated GHG that is sent to another facility for destruction and that is not included in the mass produced in §98.413(a) because it is removed from the production process as a byproduct or other waste.
(8)[Reserved]
(9) [Reserved]
(10) Mass in metric tons of any fluorinated GHG or nitrous oxide fed into the transformation process, by process. 
(11) Mass in metric tons of each fluorinated GHG that is fed into the destruction device and that was previously produced as defined at §98.410(b). Quantities to be reported under this paragraph (a)(11) of this section include but are not limited to quantities that are shipped to the facility by another facility for destruction and quantities that are returned to the facility for reclamation but are found to be irretrievably contaminated and are therefore destroyed.
(12) Mass in metric tons of each fluorinated GHG or nitrous oxide that is measured coming out of the production process, by process.
(13) Mass in metric tons of each used fluorinated GHGs or nitrous oxide added back into the production process (e.g., for reclamation), including returned heels in containers that are weighed to measure the mass in §98.414(a), by process.
(14) Names and addresses of facilities to which any nitrous oxide or fluorinated GHGs were sent for transformation, and the quantities (metric tons) of nitrous oxide and of each fluorinated GHG that were sent to each for transformation.
(15) Names and addresses of facilities to which any fluorinated GHGs were sent for destruction, and the quantities (metric tons) of each fluorinated GHG that were sent to each for destruction.
(16) Where missing data have been estimated pursuant to §98.415, the reason the data were missing, the length of time the data were missing, the method used to estimate the missing data, and the estimates of those data.
(b) By March 31, 2011 or within 60 days of commencing fluorinated GHG destruction, whichever is later, a fluorinated GHG production facility or importer that destroys fluorinated GHGs shall submit a one-time report containing the following information for each destruction process:
(1) Destruction efficiency (DE).
(2) Methods used to determine the destruction efficiency.
(3) Methods used to record the mass of fluorinated GHG destroyed.
(4) Chemical identity of the fluorinated GHG(s) used in the performance test conducted to determine DE.
(5) Name of all applicable federal or state regulations that may apply to the destruction process.
(6) If any process changes affect unit destruction efficiency or the methods used to record mass of fluorinated GHG destroyed, then a revised report must be submitted to reflect the changes. The revised report must be submitted to EPA within 60 days of the change.
(c) Each bulk importer of fluorinated GHGs or nitrous oxide shall submit an annual report that summarizes its imports at the corporate level, except for shipments including less than twenty-five kilograms of fluorinated GHGs or nitrous oxide, transshipments, and heels that meet the conditions set forth at §98.417(e). The report shall contain the following information for each import:
(1) Total mass in metric tons of nitrous oxide and each fluorinated GHG imported in bulk, including each fluorinated GHG constituent of the fluorinated GHG product that makes up between 0.5 percent and 100 percent of the product by mass.
(2) Total mass in metric tons of nitrous oxide and each fluorinated GHG imported in bulk and sold or transferred to persons other than the importer for use in processes resulting in the transformation or destruction of the chemical.
(3) Date on which the fluorinated GHGs or nitrous oxide were imported.
(4) Port of entry through which the fluorinated GHGs or nitrous oxide passed.
(5) Country from which the imported fluorinated GHGs or nitrous oxide were imported.
(6) Commodity code of the fluorinated GHGs or nitrous oxide shipped.
(7) Importer number for the shipment.
(8) Total mass in metric tons of each fluorinated GHG destroyed by the importer.
(9) If applicable, the names and addresses of the persons and facilities to which the nitrous oxide or fluorinated GHGs were sold or transferred for transformation, and the quantities (metric tons) of nitrous oxide and of each fluorinated GHG that were sold or transferred to each facility for transformation.
(10) If applicable, the names and addresses of the persons and facilities to which the fluorinated GHGs were sold or transferred for destruction, and the quantities (metric tons) of each fluorinated GHG that were sold or transferred to each facility for destruction.
(d) Each bulk exporter of fluorinated GHGs or nitrous oxide shall submit an annual report that summarizes its exports at the corporate level, except for shipments including less than twenty-five kilograms of fluorinated GHGs or nitrous oxide, transshipments, and heels. The report shall contain the following information for each export:
(1) Total mass in metric tons of nitrous oxide and each fluorinated GHG exported in bulk.
(2) Names and addresses of the exporter and the recipient of the exports.
(3) Exporter's Employee Identification Number.
(4) Commodity code of the fluorinated GHGs and nitrous oxide shipped.
(5) Date on which, and the port from which, fluorinated GHGs and nitrous oxide were exported from the United States or its territories.
(6) Country to which the fluorinated GHGs or nitrous oxide were exported.
(e) By March 31, 2011, or within 60 days of commencing fluorinated GHG production, whichever is later, a fluorinated GHG production facility shall submit a one-time report describing the following information:
(1) The method(s) by which the producer in practice measures the mass of fluorinated GHGs produced, including the instrumentation used (Coriolis flowmeter, other flowmeter, weigh scale, etc.) and its accuracy and precision.
(2) The method(s) by which the producer in practice estimates the mass of fluorinated GHGs fed into the transformation process, including the instrumentation used (Coriolis flowmeter, other flowmeter, weigh scale, etc.) and its accuracy and precision.
(3) The method(s) by which the producer in practice estimates the fraction of fluorinated GHGs fed into the transformation process that is actually transformed, and the estimated precision and accuracy of this estimate.
(4) The method(s) by which the producer in practice estimates the masses of fluorinated GHGs fed into the destruction device, including the method(s) used to estimate the concentration of the fluorinated GHGs in the destroyed material, and the estimated precision and accuracy of this estimate.
(5) The estimated percent efficiency of each production process for the fluorinated GHG produced.
(f) By March 31, 2011, all fluorinated GHG production facilities shall submit a one-time report that includes the concentration of each fluorinated GHG constituent in each fluorinated GHG product as measured under §98.414(n). If the facility commences production of a fluorinated GHG product that was not included in the initial report or performs a repeat measurement under §98.414(n) that shows that the identities or concentrations of the fluorinated GHG constituents of a fluorinated GHG product have changed, then the new or changed concentrations, as well as the date of the change, must be reflected in a revision to the report. The revised report must be submitted to EPA by the March 31st that immediately follows the measurement under §98.414(n).
(g) Isolated intermediates that are produced and transformed at the same facility are exempt from the reporting requirements of this section.
(h) Low-concentration constituents are exempt from the reporting requirements of this section.
[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79168, Dec. 17, 2010]
§ 98.417   Records that must be retained.
(a) In addition to the data required by §98.3(g), the fluorinated GHG production facility shall retain the following records:
(1) Dated records of the data used to estimate the data reported under §98.416.
(2) Records documenting the initial and periodic calibration of the analytical equipment (including but not limited to GC, IR, FTIR, or NMR), weigh scales, flowmeters, and volumetric and density measures used to measure the quantities reported under this subpart, including the manufacturer directions or industry standards used for calibration pursuant to §98.414(m) and (o).
(3)  Dated records of the total mass in metric tons of each reactant fed into the F - GHG or nitrous oxide production process, by process.
(4) Dated records of the total mass in metric tons of the reactants, by-products, and other wastes permanently removed from the F - GHG or nitrous oxide production process, by process. 
(b) In addition to the data required by paragraph (a) of this section, any fluorinated GHG production facility that destroys fluorinated GHGs shall keep records of test reports and other information documenting the facility's one-time destruction efficiency report in §98.416(b).
(c) In addition to the data required by §98.3(g), the bulk importer shall retain the following records substantiating each of the imports that they report:
(1) A copy of the bill of lading for the import.
(2) The invoice for the import.
(3) The U.S. Customs entry form.
(d) In addition to the data required by §98.3(g), the bulk exporter shall retain the following records substantiating each of the exports that they report:
(1) A copy of the bill of lading for the export and
(2) The invoice for the export.
(e) Every person who imports a container with a heel that is not reported under §98.416(c) shall keep records of the amount brought into the United States that document that the residual amount in each shipment is less than 10 percent of the volume of the container and will:
(1) Remain in the container and be included in a future shipment.
(2) Be recovered and transformed.
(3) Be recovered and destroyed.
(4) Be recovered and included in a future shipment.
(f) Isolated intermediates that are produced and transformed at the same facility are exempt from the recordkeeping requirements of this section.
(g) Low-concentration constituents are exempt from the recordkeeping requirements of this section.
[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79168, Dec. 17, 2010]
§ 98.418   Definitions.
Except as provided below, all of the terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. If a conflict exists between a definition provided in this subpart and a definition provided in subpart A, the definition in this subpart shall take precedence for the reporting requirements in this subpart.
Isolated intermediate means a product of a process that is stored before subsequent processing. An isolated intermediate is usually a product of chemical synthesis. Storage of an isolated intermediate marks the end of a process. Storage occurs at any time the intermediate is placed in equipment used solely for storage.
Low-concentration constituent means, for purposes of fluorinated GHG production and export, a fluorinated GHG constituent of a fluorinated GHG product that occurs in the product in concentrations below 0.1 percent by mass. For purposes of fluorinated GHG import, low-concentration constituent means a fluorinated GHG constituent of a fluorinated GHG product that occurs in the product in concentrations below 0.5 percent by mass. Low-concentration constituents do not include fluorinated GHGs that are deliberately combined with the product ( e.g., to affect the performance characteristics of the product).


Subpart RR -- Geologic Sequestration of Carbon Dioxide
§98.440  Definition of the source category.
(a)  The geologic sequestration of carbon dioxide (CO2) source category comprises any well or group of wells that inject a CO2 stream for long-term containment in subsurface geologic formations. 
(b)  This source category includes all wells permitted as Class VI under the Underground Injection Control program. 
(c)  This source category does not include a well or group of wells where a CO2 stream is being injected in subsurface geologic formations to enhance the recovery of oil or natural gas unless one of the following applies:
(1)  The owner or operator injects the CO2 stream for long-term containment in subsurface geologic formations and has chosen to submit a proposed monitoring, reporting, and verification (MRV) plan to EPA and received an approved plan from EPA.
(2)  The well is permitted as Class VI under the Underground Injection Control program. 
(d)  Exemption for research and development projects.  Research and development projects shall receive an exemption from reporting under this subpart for the duration of the research and development activity.
(1)  Process for obtaining an exemption. If you are a research and development project, you must submit the information in paragraph (d)(2) of this section to EPA by the time you would be otherwise required to submit an MRV plan under §98.448. EPA will use this information to verify that the project is a research and development project.
(2) Content of submission. A submission in support of an exemption as a research and development project must contain the following information:
(i) The planned duration of CO2 injection for the project.
(ii) The planned annual CO2 injection volumes during this time period. 
(iii) The research purposes of the project. 
(iv) The source and type of funding for the project.
(v) The class and duration of Underground Injection Control permit or, for an offshore facility not subject to the Safe Drinking Water Act, a description of the legal instrument authorizing geologic sequestration. 
(3) Determination by the Administrator. 
(i) The Administrator shall determine if a project meets the definition of research and development project within 60 days of receipt of the submission of a request for exemption.  In making this determination, the Administrator shall take into account any information you submit demonstrating that the planned duration of CO2 injection for the project and the planned annual CO2 injection volumes during the duration of the project are consistent with the purpose of the research and development project.
(ii) Any appeal of the Administrator's determination is subject to the provisions of part 78 of this chapter.  
(iii) A project that the Administrator determines is not eligible for an exemption as a research and development project must submit a proposed MRV plan to EPA within 180 days of the Administrator's determination.  You may request one extension of up to an additional 180 days in which to submit the proposed MRV plan.
§98.441  Reporting threshold.
(a)  You must report under this subpart if any well or group of wells within your facility injects any amount of CO2 for long-term containment in subsurface geologic formations.  There is no threshold.
(b)  Request for discontinuation of reporting. The requirements of §98.2(i) do not apply to this subpart.  Once a well or group of wells is subject to the requirements of this subpart, the owner or operator must continue for each year thereafter to comply with all requirements of this subpart, including the requirement to submit annual reports, until the Administrator has issued a final decision on an owner or operator's request to discontinue reporting.
(1)  Timing of request.  The owner or operator of a facility may submit a request to discontinue reporting any time after the well or group of wells is plugged and abandoned in accordance with applicable requirements.    
(2)  Content of request.  A request for discontinuation of reporting must contain either paragraph (b)(2)(i) or (b)(2)(ii) of this section.
(i)  For wells permitted as Class VI under the Underground Injection Control program, a copy of the applicable Underground Injection Control program Director's authorization of site closure.
(ii)  For all other wells, and as an alternative for wells permitted as Class VI under the Underground Injection Control program, a demonstration that current monitoring and model(s) show that the injected CO2 stream is not expected to migrate in the future in a manner likely to result in surface leakage.   
(3)  Notification.  The Administrator will issue a final decision on the request to discontinue reporting within a reasonable time.  Any appeal of the Administrator's final decision is subject to the provisions of part 78 of this chapter.
§98.442  GHGs to report.
You must report:
(a)  Mass of CO2 received.
(b)  Mass of CO2 injected into the subsurface. 
(c)  Mass of CO2 produced.
(d)  Mass of CO2 emitted by surface leakage.
(e)  Mass of CO2 emissions from equipment leaks and vented emissions of CO2from surface equipment located between the injection flow meter and the injection wellhead.
(f)  Mass of CO2 emissions from equipment leaks and vented emissions of CO2 from surface equipment located between the production flow meter and the production wellhead.
(g)  Mass of CO2 sequestered in subsurface geologic formations.
(h)  Cumulative mass of CO2 reported as sequestered in subsurface geologic formations in all years since the facility became subject to reporting requirements under this subpart.
§98.443  Calculating CO2 geologic sequestration.
You must calculate the mass of CO2 received using CO2 received equations (Equations RR-1 to RR-3 of this section), unless you follow the procedures in §98.444(a)(4).  You must calculate CO - 2 sequestered using injection equations (Equations RR-4 to RR-6 of this section), production/recycling equations (Equations RR-7 to RR-9 of this section), surface leakage equations (Equation RR-10 of this section), and sequestration equations (Equations RR-11 and RR-12 of this section).  For your first year of reporting, you must calculate CO2 sequestered starting from the date set forth in your approved MRV plan.  
(a)  You must calculate and report the annual mass of CO2 received by pipeline using the procedures in paragraphs (a)(1) or (a)(2) of this section and the procedures in paragraph (a)(3) of this section, if applicable.
(1)  For a mass flow meter, you must calculate the total annual mass of CO2 in a CO2 stream received in metric tons by multiplying the mass flow by the CO2 concentration in the flow, according to Equation RR-1 of this section.  You must collect these data quarterly.  Mass flow and concentration data measurements must be made in accordance with §98.444.
	CO2T,r = 	(Eq. RR-1)
Where:   
CO2T,r	=	Net annual mass of CO2 received through flow meter r (metric tons). 
Qr,p 	=	Quarterly mass flow through a receiving flow meter r in quarter p (metric tons). 
Sr,p 	=	Quarterly mass flow through a receiving flow meter r that is redelivered to another facility without being injected into your well in quarter p (metric tons). 
CCO2,p,r 	=	Quarterly CO2 concentration measurement in flow for flow meter r in quarter p (wt. percent CO2, expressed as a decimal fraction).
p	=	Quarter of the year.
r	=	Receiving flow meter. 
(2)  For a volumetric flow meter, you must calculate the total annual mass of CO2 in a CO2 stream received in metric tons by multiplying the volumetric flow at standard conditions by the CO2 concentration in the flow and the density of CO2 at standard conditions, according to Equation RR-2 of this section.  You must collect these data quarterly.  Volumetric flow and concentration data measurements must be made in accordance with §98.444.
	CO2T,r = 	(Eq. RR-2)
Where:  
CO2T,r	=	Net annual mass of CO2 received through flow meter r (metric tons). 
Qr,p 	=	Quarterly volumetric flow through a receiving flow meter r in quarter p at standard conditions (standard cubic meters).
Sr,p 	=	Quarterly volumetric flow through a receiving flow meter r that is redelivered to another facility without being injected into your well in quarter p (standard cubic meters).
D	=	Density of CO2 at standard conditions (metric tons per standard cubic meter): 0.0018682. 
CCO2,p,r 	=	Quarterly CO2 concentration measurement in flow for flow meter r in quarter p (vol. percent CO2, expressed as a decimal fraction).
p	=	Quarter of the year.
r	=	Receiving flow meter. 
(3)  If you receive CO2 through more than one flow meter, you must sum the mass of all CO2 received in accordance with the procedure specified in Equation RR-3 of this section. 
	CO2 = 	(Eq. RR-3)
Where:  
CO2	=	Total net annual mass of CO2 received (metric tons). 
CO2T,r	=	Net annual mass of CO2 received (metric tons) as calculated in Equation RR-1 or RR-2 for flow meter r. 
r	=	Receiving flow meter. 
(b)  You must calculate and report the annual mass of CO2 received in containers using the procedures in paragraphs (b)(1) or (b)(2) of this section. 
(1)  If you are measuring the mass of contents in a container under the provisions of §98.444(a)(2)(i), you must calculate the CO2 received for injection in containers using Equation RR-1 of this section.
Where:  
CO2T,r	=	Net annual mass of CO2 received in containers r (metric tons). 
CCO2,p,r 	=	Quarterly CO2 concentration measurement of contents in containers r in quarter p (wt. percent CO2, expressed as a decimal fraction).
Qr,p 	=	Quarterly mass of contents in containers r in quarter p (metric tons). 
Sr,p 	=	Quarterly mass of contents in containers r redelivered to another facility without being injected into your well in quarter p (metric tons). 
p	=	Quarter of the year.
r	=	Containers. 
(2)  If you are measuring the volume of contents in a container under the provisions of §98.444(a)(2)(ii), you must calculate the CO2 received for injection in containers using Equation RR-2 of this section.
Where:  
CO2T,r	=	Net annual mass of CO2 received in containers r (metric tons).
CCO2,p,r 	=	Quarterly CO2 concentration measurement of contents in containers r in quarter p (vol. percent CO2, expressed as a decimal fraction).
Qr,p 	=	Quarterly volume of contents in containers r in quarter p (standard cubic meters).
Sr,p 	=	Quarterly mass of contents in containers r redelivered to another facility without being injected into your well in quarter p (metric tons). 
D	=	Density of the CO2 received in containers at standard conditions (metric tons per standard cubic meter):0.0018682.  
p	=	Quarter of the year.
r	=	Containers. 
(c)  You must report the annual mass of CO2 injected in accordance with the procedures specified in paragraphs (c)(1) through (c)(3) of this section.
(1)  If you use a mass flow meter to measure the flow of an injected CO2 stream, you must calculate annually the total mass of CO2 (in metric tons) in the CO2 stream injected each year in metric tons by multiplying the mass flow by the CO2 concentration in the flow, according to Equation RR-4 of this section.  Mass flow and concentration data measurements must be made in accordance with §98.444. 
	CO2,u = 	(Eq. RR-4)
Where:  
CO2,u	=	Annual CO2 mass injected (metric tons) as measured by flow meter u.
Qp,u 	=	Quarterly mass flow rate measurement for flow meter u in quarter p (metric tons per quarter).
CCO2,p,u 	=	Quarterly CO2 concentration measurement in flow for flow meter u in quarter p (wt. percent CO2, expressed as a decimal fraction).
p	=	Quarter of the year.
u	=	Flow meter.
(2)  If you use a volumetric flow meter to measure the flow of an injected CO2 stream, you must calculate annually the total mass of CO2 (in metric tons) in the CO2 stream injected each year in metric tons by multiplying the volumetric flow at standard conditions by the CO2 concentration in the flow and the density of CO2 at standard conditions, according to Equation RR-5 of this section.  Volumetric flow and concentration data measurements must be made in accordance with §98.444.
	CO2,u = 	(Eq. RR-5)
Where:  
CO2,u	=	Annual CO2 mass injected (metric tons) as measured by flow meter u.
Qp,u 	=	Quarterly volumetric flow rate measurement for flow meter u in quarter p at standard conditions (standard cubic meters per quarter).
D	=	Density of CO2 at standard conditions (metric tons per standard cubic meter): 0.0018682.
CCO2,p,u 	=	CO2 concentration measurement in flow for flow meter u in quarter p (vol. percent CO2, expressed as a decimal fraction).
p	=	Quarter of the year. 
u	=	Flow meter.
(3)  To aggregate injection data for all wells covered under this subpart, you must sum the mass of all CO2 injected through all injection wells in accordance with the procedure specified in Equation RR-6 of this section. 
	CO2I = 	(Eq. RR-6)
Where:  
CO2I	=	Total annual CO2 mass injected (metric tons) through all injection wells. 
CO2,u	=	Annual CO2 mass injected (metric tons) as measured by flow meter u. 
u	=	Flow meter.
(d)  You must calculate the annual mass of CO2 produced from oil or gas production wells or from other fluid wells for each separator that sends a stream of gas into a recycle or end use system in accordance with the procedures specified in paragraphs (d)(1) through (d)(3) of this section.  You must account for any CO2 that is produced and not processed through a separator.  You must account only for wells that produce the CO2 that was injected into the well or wells covered by this source category.
(1)  For each gas-liquid separator for which flow is measured using a mass flow meter, you must calculate annually the total mass of CO2 produced from an oil or other fluid stream in metric tons that is separated from the fluid by multiplying the mass gas flow by the CO2 concentration in the gas flow, according to Equation RR-7 of this section.  You must collect these data quarterly.  Mass flow and concentration data measurements must be made in accordance with §98.444.
	CO2,w = 	(Eq. RR-7)
Where:  
CO2,w	=	Annual CO2 mass produced (metric tons) through separator w. 
Qp,w 	=	Quarterly gas mass flow rate measurement for separator w in quarter p (metric tons). 
CCO2,p,w 	=	Quarterly CO2 concentration measurement in flow for separator w in quarter p (wt. percent CO2, expressed as a decimal fraction).
p	=	Quarter of the year.
w	=	Separator.
(2)  For each gas-liquid separator for which flow is measured using a volumetric flow meter, you must calculate annually the total mass of CO2 produced from an oil or other fluid stream in metric tons that is separated from the fluid by multiplying the volumetric gas flow at standard conditions by the CO2 concentration in the gas flow and the density of CO2 at standard conditions, according to Equation RR-8 of this section.  You must collect these data quarterly.  Volumetric flow and concentration data measurements must be made in accordance with §98.444.
	CO2,w = 	(Eq. RR-8)
Where:  
CO2,w	=	Annual CO2 mass produced (metric tons) through separator w. 
Qp,w 	=	Volumetric gas flow rate measurement for separator w in quarter p at standard conditions (standard cubic meters).
D	=	Density of CO2 at standard conditions (metric tons per standard cubic meter): 0.0018682.
CCO2,p,w 	=	CO2 concentration measurement in flow for separator w in quarter p (vol. percent CO2, expressed as a decimal fraction).
p	=	Quarter of the year.
w	=	Separator.
(3)  To aggregate production data, you must sum the mass of all of the CO2 separated at each gas-liquid separator in accordance with the procedure specified in Equation RR-9 of this section.  You must assume that the total CO2 measured at the separator(s) represents a percentage of the total CO2 produced.  In order to account for the percentage of CO2 produced that is estimated to remain with the produced oil or other fluid, you must multiply the quarterly mass of CO2 measured at the separator(s) by a percentage estimated using a methodology in your approved MRV plan.  If fluids containing CO2 from injection wells covered under this source category are produced and not processed through a gas-liquid separator, the concentration of CO2 in the produced fluids must be measured at a flow meter located prior to reinjection or reuse using methods in §98.444(f)(1).  The considerations you intend to use to calculate CO2 from produced fluids for the mass balance equation must be described in your approved MRV plan in accordance with §98.448(d)(5).
	CO2P = (1+X) * 	(Eq. RR-9)
Where:  
CO2P	=	Total annual CO2 mass produced (metric tons) through all separators in the reporting year. 
CO2,w	=	Annual CO2 mass produced (metric tons) through separator w in the reporting year. 
X	= 	Entrained CO2 in produced oil or other fluid divided by the CO2 separated through all separators in the reporting year (weight percent CO2, expressed as a decimal fraction).
w	=	Separator.
(e)  You must report the annual mass of CO2 that is emitted by surface leakage in accordance with your approved MRV plan.  You must calculate the total annual mass of CO2 emitted from all leakage pathways in accordance with the procedure specified in Equation RR-10 of this section.
	CO2E = 	(Eq. RR-10)
Where:  
CO2E	=	Total annual CO2 mass emitted by surface leakage (metric tons) in the reporting year. 
CO2,x	=	Annual CO2 mass emitted (metric tons) at leakage pathway x in the reporting year. 
x	=	Leakage pathway.  
(f)  You must report the annual mass of CO2 that is sequestered in subsurface geologic formations in the reporting year in accordance with the procedures specified in paragraphs (f)(1) and (f)(2) of this section. 
(1)  If you are actively producing oil or natural gas or if you are producing any other fluids, you must calculate the annual mass of CO2 that is sequestered in the underground subsurface formation in the reporting year in accordance with the procedure specified in Equation RR-11 of this section.
	CO2 = CO2I - CO2P  -  CO2E  -   - CO2FI  -  CO2FP	(Eq. RR-11)
Where:  
CO2	=	Total annual CO2 mass sequestered in subsurface geologic formations (metric tons) at the facility in the reporting year. 
CO2I	=	Total annual CO2 mass injected (metric tons) in the well or group of wells covered by this source category in the reporting year.
CO2P	=	Total annual CO2 mass produced (metric tons) in the reporting year.
CO2E	=	Total annual CO2 mass emitted (metric tons) by surface leakage in the reporting year.
CO2FI	=	Total annual CO2 mass emitted (metric tons) from equipment leaks and vented emissions of CO2 from equipment located on the surface between the flow meter used to measure injection quantity and the injection wellhead, for which a calculation procedure is provided in subpart W of this part.
CO2FP	=	Total annual CO2 mass emitted (metric tons) from equipment leaks and vented emissions of CO2 from equipment located on the surface between the production wellhead and the flow meter used to measure production quantity, for which a calculation procedure is provided in subpart W of this part.
(2)  If you are not actively producing oil or natural gas or any other fluids, you must calculate the annual mass of CO2 that is sequestered in subsurface geologic formations in the reporting year in accordance with the procedures specified in Equation RR-12 of this section.
	CO2 = CO2I  -  CO2E  -  CO2FI	(Eq. RR-12)
Where:  
CO2	=	Total annual CO2 mass sequestered in subsurface geologic formations (metric tons) at the facility in the reporting year. 
CO2I	=	Total annual CO2 mass injected (metric tons) in the well or group of wells covered by this source category in the reporting year.
CO2E	=	Total annual CO2 mass emitted (metric tons) by surface leakage in the reporting year.
CO2FI	=	Total annual CO2 mass emitted (metric tons) from equipment leaks and vented emissions of CO2 from equipment located on the surface between the flow meter used to measure injection quantity and the injection wellhead.
§98.444  Monitoring and QA/QC requirements.
(a)  CO2 received.
(1)  Except as provided in paragraph (a)(4) of this section, you must determine the quarterly flow rate of CO2 received by pipeline by following the most appropriate of the following procedures:
(i)  You may measure flow rate at the receiving custody transfer meter prior to any subsequent processing operations at the facility and collect the flow rate quarterly. 
(ii)  If you took ownership of the CO2 in a commercial transaction, you may use the quarterly flow rate data from the sales contract if it is a one-time transaction or from invoices or manifests if it is an ongoing commercial transaction with discrete shipments.
(iii)  If you inject CO2 received from a production process unit that is part of your facility, you may use the quarterly CO2 flow rate that was measured at the equivalent of a custody transfer meter following procedures provided in subpart PP of this part.  To be the equivalent of a custody transfer meter, a meter must measure the flow of CO2 being transported to an injection well to the same degree of accuracy as a meter used for commercial transactions.
(2)  Except as provided in paragraph (a)(4) of this section, you must determine the quarterly mass or volume of contents in all containers if you receive CO2 in containers by following the most appropriate of the following procedures:
(i)  You may measure the mass of contents of containers summed quarterly using weigh bills, scales, or load cells. 
(ii)  You may determine the volume of the contents of containers summed quarterly.
(iii)  If you took ownership of the CO2 in a commercial transaction, you may use the quarterly mass or volume of contents from the sales contract if it is a one-time transaction or from invoices or manifests if it is an ongoing commercial transaction with discrete shipments.
(3)  Except as provided in paragraph (a)(4) of this section, you must determine a quarterly concentration of the CO2 received that is representative of all CO2 received in that quarter by following the most appropriate of the following procedures:
(i)  You may sample the CO2 stream at least once per quarter at the point of receipt and measure its CO2 concentration.
(ii)  If you took ownership of the CO2 in a commercial transaction for which the sales contract was contingent on CO2 concentration, and if the supplier of the CO2 sampled the CO2 stream in a quarter and measured its concentration per the sales contract terms, you may use the CO2 concentration data from the sales contract for that quarter.
(iii)  If you inject CO2 from a production process unit that is part of your facility, you may report the quarterly CO2 concentration of the CO2 stream supplied that was measured following the procedures provided in subpart PP of this part. 
(4)  If the CO2 you receive is wholly injected and is not mixed with any other supply of CO2, you may report the annual mass of CO2 injected that you determined following the requirements under paragraph (b) of this section as the total annual mass of CO2 received instead of using Equation RR-1 or RR-2 of this subpart to calculate CO2 received.
(5)  You must assume that the CO2 you receive meets the definition of a CO2 stream unless you can trace it through written records to a source other than a CO2 stream. 
(b)  CO2 injected.
(1)  You must select a point or points of measurement at which the CO2 stream(s) is representative of the CO2 stream(s) being injected.  You may use as the point or points of measurement the location(s) of the flow meter(s) used to comply with the flow monitoring and reporting provisions in your Underground Injection Control permit.
(2)  You must measure flow rate of CO2 injected with a flow meter and collect the flow rate quarterly.
(3)  You must sample the injected CO2 stream at least once per quarter immediately upstream or downstream of the flow meter used to measure flow rate of that CO2 stream and measure the CO2 concentration of the sample.
(c)  CO2 produced.
(1)  The point of measurement for the quantity of CO2 produced from oil or other fluid production wells is a flow meter directly downstream of each separator that sends a stream of gas into a recycle or end use system. 
(2)  You must sample the produced gas stream at least once per quarter immediately upstream or downstream of the flow meter used to measure flow rate of that gas stream and measure the CO2 concentration of the sample.
(3)  You must measure flow rate of gas produced with a flow meter and collect the flow rate quarterly.  
(d)  CO2 emissions from equipment leaks and vented emissions of CO2. If you have equipment located on the surface between the flow meter used to measure injection quantity and the injection wellhead or between the flow meter used to measure production quantity and the production wellhead, you must follow the monitoring and QA/QC requirements specified in subpart W of this part for the equipment.
(e)  Measurement devices.
(1)  All flow meters must be operated continuously except as necessary for maintenance and calibration.
(2)  You must calibrate all flow meters used to measure quantities reported in §98.446 according to the calibration and accuracy requirements in §98.3(i).
(3)  You must operate all measurement devices according to one of the following.  You may use an appropriate standard method published by a consensus-based standards organization if such a method exists or an industry standard practice.  Consensus-based standards organizations include, but are not limited to, the following: ASTM International, the American National Standards Institute (ANSI), the American Gas Association (AGA), the American Society of Mechanical Engineers (ASME), the American Petroleum Institute (API), and the North American Energy Standards Board (NAESB).  
(4)  You must ensure that any flow meter calibrations performed are National Institute of Standards and Technology (NIST) traceable.
(f)  General.  
(1)  If you measure the concentration of any CO2 quantity for reporting, you must measure according to one of the following.  You may use an appropriate standard method published by a consensus-based standards organization if such a method exists or an industry standard practice.
(2)  You must convert all measured volumes of CO2 to the following standard industry temperature and pressure conditions for use in Equations RR-2, RR-5 and RR-8 of this subpart:  standard cubic meters at a temperature of 60 degrees Fahrenheit and at an absolute pressure of 1 atmosphere.
(3)  For 2011, you may follow the provisions of §98.3(d)(1) through (2) for best available monitoring methods only for parameters required by paragraphs (a) and (b) of §98.443 rather than follow the monitoring requirements of paragraph (a) of this section.  For purposes of this subpart, any reference to the year 2010 in §98.3(d)(1) through (2) shall mean 2011.
§98.445  Procedures for estimating missing data.
A complete record of all measured parameters used in the GHG quantities calculations is required.  Whenever the monitoring procedures cannot be followed, you must use the following missing data procedures:
(a)  A quarterly flow rate of CO2 received that is missing must be estimated as follows:
(1)  Another calculation methodology listed in §98.444(a)(1) must be used if possible. 
(2)  If another method listed in §98.444(a)(1) cannot be used, a quarterly flow rate value that is missing must be estimated using a representative flow rate value from the nearest previous time period.
(b)  A quarterly mass or volume of contents in containers received that is missing must be estimated as follows:
(1)  Another calculation methodology listed in §98.444(a)(2) must be used if possible. 
(2)  If another method listed in §98.444(a)(2) cannot be used, a quarterly mass or volume value that is missing must be estimated using a representative mass or volume value from the nearest previous time period. 
(c)  A quarterly CO2 concentration of a CO2 stream received that is missing must be estimated as follows:
(1)  Another calculation methodology listed in §98.444(a)(3) must be used if possible. 
(2)  If another method listed in §98.444(a)(3) cannot be used, a quarterly concentration value that is missing must be estimated using a representative concentration value from the nearest previous time period.
(d)  A quarterly quantity of CO2 injected that is missing must be estimated using a representative quantity of CO2 injected from the nearest previous period of time at a similar injection pressure.
(e)  For any values associated with CO2 emissions from equipment leaks and vented emissions of CO2 from surface equipment at the facility that are reported in this subpart, missing data estimation procedures should be followed in accordance with those specified in subpart W of this part.
(f)  The quarterly quantity of CO2 produced from subsurface geologic formations that is missing must be estimated using a representative quantity of CO2 produced from the nearest previous period of time. 
(g)  You must estimate the mass of CO2 emitted by surface leakage that is missing as required by your approved MRV plan.
(h)  You must estimate other missing data as required by your approved MRV plan.
§98.446  Data reporting requirements.
In addition to the information required by §98.3(c), report the information listed in this section.  
(a)  If you receive CO2 by pipeline, report the following for each receiving flow meter:
(1)  The total net mass of CO2 received (metric tons) annually.  
(2)  If a volumetric flow meter is used to receive CO2 report the following unless you reported yes to paragraph (a)(4) of this section:
(i)  The volumetric flow through a receiving flow meter at standard conditions (in standard cubic meters) in each quarter.
(ii)  The volumetric flow through a receiving flow meter that is redelivered to another facility without being injected into your well (in standard cubic meters) in each quarter.
(iii)  The CO2 concentration in the flow (volume percent CO2 expressed as a decimal fraction) in each quarter. 
(3)  If a mass flow meter is used to receive CO2 report the following unless you reported yes to paragraph (a)(4) of this section: 
(i)  The mass flow through a receiving flow meter (in metric tons) in each quarter.
(ii)  The mass flow through a receiving flow meter that is redelivered to another facility without being injected into your well (in metric tons) in each quarter.
(iii)  The CO2 concentration in the flow (weight percent CO2 expressed as a decimal fraction) in each quarter. 
(4)  If the CO2 received is wholly injected and not mixed with any other supply of CO2, report whether you followed the procedures in §98.444(a)(4).  
(5)  The standard or method used to calculate each value in paragraphs (a)(2) through (a)(3) of this section.
(6)  The number of times in the reporting year for which substitute data procedures were used to calculate values reported in paragraphs (a)(2) through (a)(3) of this section.
(7)  Whether the flow meter is mass or volumetric.
(8)  A numerical identifier for the flow meter.
(b)  If you receive CO2 in containers, report:
(1)  The mass (in metric tons) or volume at standard conditions (in standard cubic meters) of contents in containers received in each quarter.
(2)  The concentration of CO2 of contents in containers (volume or wt. percent CO2 expressed as a decimal fraction) in each quarter.
(3)  The mass (in metric tons) or volume (in standard cubic meters) of contents in containers that is redelivered to another facility without being injected into your well in each quarter.
(4)  The net mass of CO2 received (in metric tons) annually. 
(5)  The standard or method used to calculate each value in paragraphs (b)(1) and (b)(2) of this section. 
(6)  The number of times in the reporting year for which substitute data procedures were used to calculate values reported in paragraphs (b)(1) and (b)(2) of this section.
(c)  If you use more than one receiving flow meter, report the total net mass of CO2 received (metric tons) through all flow meters annually.
(d)  The source of the CO2 received according to the following categories:
(1)  CO2 production wells.
(2)  Electric generating unit.
(3)  Ethanol plant.
(4)  Pulp and paper mill.
(5)  Natural gas processing.
(6)  Gasification operations.
(7)  Other anthropogenic source.
(8)  Discontinued enhanced oil and gas recovery project.
(9)  Unknown. 
(e)  Report the date that you began collecting data for calculating total amount sequestered according to §98.448(a)(7) of this subpart.   
(f)  Report the following.  If the date specified in paragraph (e) of this section is during the reporting year for this annual report, report the following starting on the date specified in paragraph (e) of this section.
 (1)  For each injection flow meter (mass or volumetric), report:
(i)  The mass of CO2 injected (metric tons) annually.
(ii)  The CO2 concentration in flow (volume or weight percent CO2 expressed as a decimal fraction) in each quarter.
(iii)  If a volumetric flow meter is used, the volumetric flow rate at standard conditions (in standard cubic meters) in each quarter.  
(iv)  If a mass flow meter is used, the mass flow rate (in metric tons) in each quarter.
(v)  A numerical identifier for the flow meter.
(vi)  Whether the flow meter is mass or volumetric.  
(vii)  The standard used to calculate each value in paragraphs (f)(1)(ii) through (f)(1)(iv) of this section.
(viii)  The number of times in the reporting year for which substitute data procedures were used to calculate values reported in paragraphs (f)(1)(ii) through (f)(1)(iv) of this section.
(ix)  The location of the flow meter.
(2)  The total CO2 injected (metric tons) in the reporting year as calculated in Equation RR-6 of this subpart.
(3)  For CO2 emissions from equipment leaks and vented emissions of CO2, report the following: 
(i)  The mass of CO2 emitted (in metric tons) annually from equipment leaks and vented emissions of CO2 from equipment located on the surface between the flow meter used to measure injection quantity and the injection wellhead.
(ii)  The mass of CO2 emitted (in metric tons) annually from equipment leaks and vented emissions of CO2 from equipment located on the surface between the production wellhead and the flow meter used to measure production quantity. 
(4)  For each separator flow meter (mass or volumetric), report: 
(i)  CO2 mass produced (metric tons) annually. 
(ii)  CO2 concentration in flow (volume or weight percent CO2 expressed as a decimal fraction) in each quarter.
(iii)  If a volumetric flow meter is used, volumetric flow rate at standard conditions (standard cubic meters) in each quarter.  
(iv)  If a mass flow meter, mass flow rate (metric tons) in each quarter.  
(v)  A numerical identifier for the flow meter.
(vi)  Whether the flow meter is mass or volumetric.    
(vii)  The standard used to calculate each value in paragraphs (f)(4)(ii) through (f)(4)(iv) of this section.
(viii)  The number of times in the reporting year for which substitute data procedures were used to calculate values reported in paragraphs (f)(4)(ii) through (f)(4)(iv) of this section.
(5)  The entrained CO2 in produced oil or other fluid divided by the CO2 separated through all separators in the reporting year (weight percent CO2 expressed as a decimal fraction) used as the value for X in Equation RR-9 of this subpart and as determined according to your EPA-approved MRV plan. 
(6)  Annual CO2 produced in the reporting year as calculated in Equation RR-9 of this subpart.
(7)  For each leakage pathway through which CO2 emissions occurred, report:
(i)  A numerical identifier for the leakage pathway.
(ii)  The CO2 (metric tons) emitted through that pathway in the reporting year. 
(8)  Annual CO2 mass emitted (metric tons) by surface leakage in the reporting year as calculated by Equation RR-10 of this subpart.
(9)  Annual CO2 (metric tons) sequestered in subsurface geologic formations in the reporting year as calculated by Equation RR-11 or RR-12 of this subpart.
(10)  Cumulative mass of CO2 (metric tons) reported as sequestered in subsurface geologic formations in all years since the well or group of wells became subject to reporting requirements under this subpart.
(11)  Date that the most recent MRV plan was approved by EPA and the MRV plan approval number that was issued by EPA.
(12)  An annual monitoring report that contains the following components: 
(i)  A narrative history of the monitoring efforts conducted over the previous calendar year, including a listing of all monitoring equipment that was operated, its period of operation, and any relevant tests or surveys that were conducted. 
(ii)  A description of any changes to the monitoring program that you concluded were not material changes warranting submission of a revised MRV plan under §98.448(d).
(iii)  A narrative history of any monitoring anomalies that were detected in the previous calendar year and how they were investigated and resolved. 
(iv)  A description of any surface leakages of CO2, including a discussion of all methodologies and technologies involved in detecting and quantifying the surface leakages and any assumptions and uncertainties involved in calculating the amount of CO2 emitted.   
(13)  If a well is permitted under the Underground Injection Control program, for each injection well, report:
(i)  The well identification number used for the Underground Injection Control permit.
(ii)  The Underground Injection Control permit class.
(14)  If an offshore well is not subject to the Safe Drinking Water Act, for each injection well, report any well identification number and any identification number used for the legal instrument authorizing geologic sequestration.
§98.447  Records that must be retained.
(a)  You must follow the record retention requirements specified by §98.3(g).  In addition to the records required by §98.3(g), you must retain the records specified in paragraphs (a)(1) through (7) of this section, as applicable.  You must retain all required records for at least 3 years.
(1)  Quarterly records of CO2 received, including mass flow rate of contents of containers (mass or volumetric) at standard conditions and operating conditions, operating temperature and pressure, and concentration of these streams.
(2)  Quarterly records of produced CO2, including mass flow or volumetric flow at standard conditions and operating conditions, operating temperature and pressure, and concentration of these streams. 
(3)  Quarterly records of injected CO2 including mass flow or volumetric flow at standard conditions and operating conditions, operating temperature and pressure, and concentration of these streams.
(4)  Annual records of information used to calculate the CO2 emitted by surface leakage from leakage pathways. 
(5)  Annual records of information used to calculate the CO2 emitted from equipment leaks and vented emissions of CO2 from equipment located on the surface between the flow meter used to measure injection quantity and the injection wellhead. 
(6)  Annual records of information used to calculate the CO2 emitted from equipment leaks and vented emissions of CO2 from equipment located on the surface between the production wellhead and the flow meter used to measure production quantity.
(7)  Any other records as specified for retention in your EPA-approved MRV plan.
(b)  You must complete your monitoring plans, as described in §98.3(g)(5), by April 1 of the year you begin collecting data.
§98.448  Geologic sequestration monitoring, reporting, and verification (MRV) plan. 
(a)  Contents of MRV plan.  You must develop and submit to the Administrator a proposed MRV plan for monitoring, reporting, and verification of geologic sequestration at your facility.  Your proposed MRV plan must contain the following components:
(1)  Delineation of the maximum monitoring area and the active monitoring areas.  The first period for your active monitoring area will begin from the date determined in your MRV plan through the date at which the plan calls for the first expansion of the monitoring area.  The length of each monitoring period can be any time interval chosen by you that is greater than 1 year.
(2)  Identification of potential surface leakage pathways for CO2 in the maximum monitoring area and the likelihood, magnitude, and timing, of surface leakage of CO2 through these pathways.
(3)  A strategy for detecting and quantifying any surface leakage of CO2.
(4)  A strategy for establishing the expected baselines for monitoring CO2 surface leakage. 
(5)  A summary of the considerations you intend to use to calculate site-specific variables for the mass balance equation.  This includes, but is not limited to, considerations for calculating CO2 emissions from equipment leaks and vented emissions of CO2 between the injection flow meter and injection well and/or the production flow meter and production well, and considerations for calculating CO2 in produced fluids. 
(6)  If a well is permitted under the Underground Injection Control program, for each injection well, report the well identification number used for the Underground Injection Control permit and the Underground Injection Control permit class.  If the well is not yet permitted, and you have applied for an Underground Injection Control permit, report the well identification numbers in the permit application. If an offshore well is not subject to the Safe Drinking Water Act, for each injection well, report any well identification number and any identification number used for the legal instrument authorizing geologic sequestration.  If you are submitting your Underground Injection Control permit application as part of your proposed MRV plan, you must notify EPA when the permit has been approved.  If you are an offshore facility not subject to the Safe Drinking Water Act, and are submitting your application for the legal instrument authorizing geologic sequestration as part of your proposed MRV plan, you must notify EPA when the legal instrument authorizing geologic sequestration has been approved.
(7)  Proposed date to begin collecting data for calculating total amount sequestered according to equation RR-11 or RR-12 of this subpart.  This date must be after expected baselines as required by paragraph (a)(4) of this section are established and the leakage detection and quantification strategy as required by paragraph (a)(3) of this section is implemented in the initial AMA.
(b)  Timing.  You must submit a proposed MRV plan to EPA according to the following schedule:  
(1)  You must submit a proposed MRV plan to EPA by June 30, 2011 if you were issued a final Underground Injection Control permit authorizing the injection of CO2 into the subsurface on or before December 31, 2010.  You will be allowed to request one extension of up to an additional 180 days in which to submit your proposed MRV plan.
(2)  You must submit a proposed MRV plan to EPA within 180 days of receiving a final Underground Injection Control permit authorizing the injection of CO2 into the subsurface.  If your facility is an offshore facility not subject to the Safe Drinking Water Act, you must submit a proposed MRV plan to EPA within 180 days of receiving authorization to begin geologic sequestration of CO2.  You will be allowed to request one extension of the submittal date of up to an additional 180 days.  
(3)  If you are injecting a CO2 stream in subsurface geologic formations to enhance the recovery of oil or natural gas and you are not permitted as Class VI under the Underground Injection Control program, you may opt to submit an MRV plan at any time.
(4)  If EPA determines that your proposed MRV plan is incomplete, you must submit an updated MRV plan within 45 days of EPA notification, unless otherwise specified by EPA.
(c)  Final MRV plan.  The Administrator will issue a final MRV plan within a reasonable period of time.  The Administrator's final MRV plan is subject to the provisions of part 78 of this chapter.  Once the MRV plan is final and no longer subject to administrative appeal under part 78 of this chapter, you must implement the plan starting on the day after the day on which the plan becomes final and is no longer subject to such appeal.
(d)  MRV plan revisions.  You must revise and submit the MRV plan within 180 days to the Administrator for approval if any of the following in paragraphs (d)(1) through (d)(4) of this section applies.  You must include the reason(s) for the revisions in your submittal.  
(1)  A material change was made to monitoring and/or operational parameters that was not anticipated in the original MRV plan.  Examples of material changes include but are not limited to: large changes in the volume of CO2 injected; the construction of new injection wells not identified in the MRV plan; failures of the monitoring system including monitoring system sensitivity, performance, location, or baseline; changes to surface land use that affects baseline or operational conditions; observed plume location that differs significantly from the predicted plume area used for developing the MRV plan; a change in the maximum monitoring area or active monitoring area; or a change in monitoring technology that would result in coverage or detection capability different from the MRV plan. 
(2)  A change in the permit class of your Underground Injection Control permit.
(3)  If you are notified by EPA of substantive errors in your MRV plan or monitoring report.
(4)  You choose to revise your MRV plan for any other reason in any reporting year.  
(e)  Revised MRV plan.  The requirements of paragraph (c) of this section apply to any submission of a revised MRV plan.  You must continue reporting under your currently approved plan while awaiting approval of a revised MRV plan.  
(f)  Format.  Each proposed MRV plan or revision and each annual report must be submitted electronically in a format specified by the Administrator.
(g)  Certificate of representation.  You must submit a certificate of representation according to the provisions in §98.4 at least 60 days before submission of your MRV plan, your research and development exemption request, your MRV plan submission extension request, or your initial annual report under this part, whichever is earlier.
§98.449  Definitions.
Except as provided below, all terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. 
Active monitoring area is the area that will be monitored over a specific time interval from the first year of the period (n) to the last year in the period (t).  The boundary of the active monitoring area is established by superimposing two areas: 
(1)  The area projected to contain the free phase CO2 plume at the end of year t, plus an all around buffer zone of one-half mile or greater if known leakage pathways extend laterally more than one-half mile.
(2)  The area projected to contain the free phase CO2 plume at the end of year t+5.  
CO2 received means the CO2 stream that you receive to be injected for the first time into a well on your facility that is covered by this subpart. CO2 received includes, but is not limited to, a CO2 stream from a production process unit inside your facility and a CO2 stream that was injected into a well on another facility, removed from a discontinued enhanced oil or natural gas or other production well, and transferred to your facility.
Equipment leak means those emissions that could not reasonably pass through a stack, chimney, vent, or other functionally-equivalent opening. 
Expected baseline is the anticipated value of a monitored parameter that is compared to the measured monitored parameter.   
Maximum monitoring area means the area that must be monitored under this regulation and is defined as equal to or greater than the area expected to contain the free phase CO2 plume until the CO2 plume has stabilized plus an all-around buffer zone of at least one-half mile.  
Research and development project means a project for the purpose of investigating practices, monitoring techniques, or injection verification, or engaging in other applied research, that will enable safe and effective long-term containment of a CO2 stream in subsurface geologic formations, including research and short duration CO2 injection tests conducted as a precursor to long-term storage.
Separator means a vessel in which streams of multiple phases are gravity separated into individual streams of single phase.
Surface leakage means the movement of the injected CO2 stream from the injection zone to the surface, and into the atmosphere, indoor air, oceans, or surface water.  
Underground Injection Control permit means a permit issued under the authority of Part C of the Safe Drinking Water Act at 42 U.S.C. 300h et seq.
Underground Injection Control program means the program responsible for regulating the construction, operation, permitting, and closure of injection wells that place fluids underground for storage or disposal for purposes of protecting underground sources of drinking water from endangerment pursuant to Part C of the Safe Drinking Water Act at 42 U.S.C. 300h et seq.
Vented emissions means intentional or designed releases of CH4 or CO2 containing natural gas or hydrocarbon gas (not including stationary combustion flue gas), including process designed flow to the atmosphere through seals or vent pipes, equipment blowdown for maintenance, and direct venting of gas used to power equipment (such as pneumatic devices).
Subpart TT  -  Industrial Waste Landfills
§98.460  Definition of the source category.
      (a) This source category applies to industrial waste landfills that accepted waste on or after January 1, 1980, and that are located at a facility whose total landfill design capacity is greater than or equal to 300,000 metric tons.  
(b)	An industrial waste landfill is a landfill other than a municipal solid waste landfill, a RCRA Subtitle C hazardous waste landfill, or a TSCA hazardous waste landfill, in which industrial solid waste, such as RCRA Subtitle D wastes (non-hazardous industrial solid waste, defined in 40 CFR 257.2), commercial solid wastes, or conditionally exempt small quantity generator wastes, is placed.  An industrial waste landfill includes all disposal areas at the facility.  
(c)  This source category does not include:
(1)  Construction and demolition waste landfills.   
(2)  Industrial waste landfills that only receive one or more of the following inert waste materials:
(i)  Coal combustion or incinerator ash (e.g., fly ash).
(ii)  Cement kiln dust.
(iii)  Rocks and/or soil from excavation and construction and similar activities.
(iv)  Glass.
(v)  Non-chemically bound sand (e.g., green foundry sand).
(vii)  Clay, gypsum, or pottery cull.
(viii)  Bricks, mortar, or cement.
(ix)  Furnace slag.
(x)  Materials used as refractory (e.g., alumina, silicon, fire clay, fire brick).
(xi)  Plastics (e.g., polyethylene, polypropylene, polyethylene terephthalate, polystyrene, polyvinyl chloride).
(xii)  Other waste material that has a volatile solids concentration of 0.5 weight percent (on a dry basis) or less. 
(d)  This source category consists of the following sources at industrial waste landfills:  Landfills, gas collection systems at landfills, and destruction devices for landfill gases (including flares).
§98.461  Reporting threshold.
You must report GHG emissions under this subpart if your facility contains an industrial waste landfill meeting the criteria in §98.460 and the facility meets the requirements of §98.2(a)(2).  For the purposes of §98.2(a)(2), the emissions from the industrial waste landfill are to be determined using the methane generation corrected for oxidation as determined using Equation TT-6 of this subpart times the global warming potential for methane in Table A-1 of subpart A of this part.  
§98.462  GHGs to report.
(a)  You must report CH4 generation and CH4 emissions from industrial waste landfills.
(b)  You must report CH4 destruction resulting from landfill gas collection and destruction devices, if present.
(c)  You must report under subpart C of this part (General Stationary Fuel Combustion Sources) the emissions of CO2, CH4, and N2O from each stationary combustion unit associated with the landfill gas destruction device, if present, by following the requirements of subpart C of this part.  
§98.463  Calculating GHG emissions.
(a)  For each industrial waste landfill subject to the reporting requirements of this subpart, calculate annual modeled CH4 generation according to the applicable requirements in paragraphs (a)(1) through (a)(3) of this section.  Apply Equation TT-1 of this section for each waste stream disposed of in the landfill and sum the CH4 generation rates for all waste streams disposed of in the landfill to calculate the total annual modeled CH4 generation rate for the landfill.
(1)  Calculate annual modeled CH4 generation using Equation TT-1 of this section.
		(Eq. TT-1)
Where:

GCH4	=	Modeled methane generation in reporting year T (metric tons CH4).
X	= 	Year in which waste was disposed. 
S 	=	Start year of calculation.  Use the year 1960 or the opening year of the landfill, whichever is more recent. 
T 	=	Reporting year for which emissions are calculated. 
Wx  	=	Quantity of waste disposed in the industrial waste landfill in year X from measurement data and/or other company records (metric tons, as received (wet weight)). 
DOCx 	=	Degradable organic carbon for waste disposed in year X from Table TT-1 of this subpart or from measurement data [as specified in paragraph (a)(3) of this section], if available [fraction (metric tons C/metric ton waste)]. 
DOCF  	=	Fraction of DOC dissimilated (fraction); use the default value of 0.5. 
MCF 	=	Methane correction factor (fraction).  Use the default value of 1 unless there is active aeration of waste within the landfill during the reporting year.  If there is active aeration of waste within the landfill during the reporting year, use either the default value of 1 or select an alternative value no less than 0.5 based on site-specific aeration parameters.
F 	=	Fraction by volume of CH4 in landfill gas (fraction, dry basis, corrected to 0% oxygen).  If you have a gas collection system, use the annual average CH4 concentration from measurement data for the current reporting year; otherwise, use the default value of 0.5. 
k 	=	Decay rate constant from Table TT-1 of this subpart (yr[-1]).  Select the most applicable k value for the majority of the past 10 years (or operating life, whichever is shorter).

(2)  Waste stream quantities.  Determine annual waste quantities as specified in paragraphs (a)(2)(i) through (ii) of this section for each year starting with January 1, 1960 or the year the landfills first accepted waste if after January 1, 1960, up until the most recent reporting year.  The choice of method for determining waste quantities will vary according to the availability of historical data.  Beginning in the first emissions reporting year (2011 or later) and for each year thereafter, use the procedures in paragraph (a)(2)(i) of this section to determine waste stream quantities.  These procedures should also be used for any year prior to the first emissions reporting year for which the data are available.  For other historical years, use paragraph (a)(2)(i) of this section, where waste disposal records are available, and use the procedures outlined in paragraph (a)(2)(ii) of this section when waste disposal records are unavailable, to determine waste stream quantities.  Historical disposal quantities deposited (i.e, prior to the first year in which monitoring begins) should only be determined once, as part of the first annual report, and the same values should be used for all subsequent annual reports, supplemented by the next year's data on new waste disposal.   
(i)  Determine the quantity of waste (in metric tons as received, i.e., wet weight) disposed of in the landfill separately for each waste stream by any one or a combination of the following methods.
(A)  Direct mass measurements.
(B)  Direct volume measurements multiplied by waste stream density determined from periodic density measurement data or process knowledge.
(C)  Mass balance procedures, determining the mass of waste as the difference between the mass of the process inputs and the mass of the process outputs. 
(D)  The number of loads (e.g., trucks) multiplied by the mass of waste per load based on the working capacity of the container or vehicle.   
(ii)  Determine the historical disposal quantities for landfills using the Waste Disposal Factor approach in paragraphs (a)(2)(ii)(A) and (B) of this section when historical production or processing data are available.  If production or processing data are available for a given year, you must use Equation TT-3 of this section for that year.  Determine historical disposal quantities using the method specified in paragraph (a)(2)(ii)(C) of this section when historical production or processing data are not available, and for waste streams received from an off-site facility when historical disposal quantities cannot be determined using the methods specified in paragraph (a)(2)(i) of this section. 
(A)  Determining Waste Disposal Factor:  For each waste stream disposed of in the landfill, calculate the average waste disposal rate per unit of production or unit throughput using all available waste quantity data and corresponding production or processing rates for the process generating that waste or, if appropriate, the facility, using Equation TT-2 of this section. 
		(Eq. TT-2)
Where:

WDF	=	Average waste disposal factor as determined for the first annual report required for this industrial waste landfill (metric tons per production unit).  
X	=	Year in which waste was disposed.  Include only those years for which disposal and production data are both available; the years do not need to be sequential.
Y1	=	First year in which disposal and production/throughput data are both available.
Y2	=	First year for which GHG emissions from this industrial waste landfill must be reported.
N	=	Number of years for which disposal and production/throughput data are both available. 
Wx	=	Quantity of waste placed in the industrial waste landfill in year X from measurement data and/or other company records (metric tons, as received (wet weight)).
Px	=	Quantity of product produced or feedstock entering the process or facility in year X from measurement data and/or other company records (production units).  You must use the same basis for all years in the calculation.  That is, Px must be determined based on production (quantity of product produced) for all "N" years or Px must be determined based on throughput (quantity of feedstock) for all "N" years.

(B)  Calculate waste:  For each waste stream disposed of in the landfill, calculate the waste disposal quantities for historic years in which direct waste disposal measurements are not available using historical production data and Equation TT-3 of this section.   
		(Eq. TT-3)
Where:
X	=	Historic year in which waste was disposed. 
Wx  	=	Calculated quantity of waste placed in the landfill in year X (metric tons). 
WDF	=	Average waste disposal factor from Equation TT-2 of this section (metric tons per production unit).
Px	=	Quantity of product produced or feedstock entering the process or facility in year X from measurement data and/or other company records (production units). You must use the same basis for Px (either production only or throughput only) as used to determine WDF in Equation TT-2 of this section.  

(C)  For any year in which historic production or processing data are not available such that historic waste quantities cannot be estimated using Equation TT-3 of this section, calculate an average annual bulk waste disposal quantity using Equation TT-4 of this section.  
		(Eq. TT-4)
Where:

Wx	=	Quantity of waste placed in the landfill in year X (metric tons, wet basis).  This annual bulk waste disposal quantity applies for all years from "YrOpen" to "YrData" inclusive.
LFC	=	Capacity of the landfill used (or the total quantity of waste-in-place) at the end of the "YrData" from design drawings or engineering estimates (metric tons). For closed landfills for which waste quantity data are not available, use the landfill's design capacity.
YrData	=	The year prior to the year when waste disposal data are first available from company records or from Equation TT-3 of this section.  For landfills for which waste quantity data are not available, the year in which the landfill last received waste.
YrOpen	=	Year 1960 or the year in which the landfill first received waste from company records, whichever is more recent.  If no data are available for estimating YrOpen for a closed landfill, use 1960 as the default "YrOpen" for the landfill.  

(3)  Degradable organic content (DOC).  For any year, X, in Equation TT-1 of this section, use either the applicable default DOC values provided in Table TT-1 of this subpart or determine values for DOCx as specified in paragraphs (a)(3)(i) through (iv) of this section.  When developing historical waste quantity data, you may use default DOC values from Table TT-1 of this subpart for certain years and determined values for DOCx for other years.  The historical values for DOC or DOCx must be developed only for the first annual report required for the industrial waste landfill; and used for all subsequent annual reports (e.g., if DOC for year x=1990 was determined to be 0.15 in the first reporting year, you must use 0.15 for the 1990 DOC value for all subsequent annual reports). 
(i)  For the first year in which GHG emissions from this industrial waste landfill must be reported, determine the DOCx value of each waste stream disposed of in the landfill no less frequently than once per quarter using the methods specified in §98.464(b).  Calculate annual DOCx for each waste stream as the arithmetic average of all DOCx values for that waste stream that were measured during the year.
(ii)  For subsequent years (after the first year in which GHG emissions from this industrial waste landfill must be reported), either use the DOCx of each waste stream calculated for the most recent reporting year for which DOC values were determined according to paragraph (a)(3)(i) of this section, or determine new DOC values for that year following the requirements in paragraph (a)(3)(i) of this section.  You must determine new DOC values following the requirements in paragraph (a)(3)(i) of this section if changes in the process operations occurred during the previous reporting year that can reasonably be expected to alter the characteristics of the waste stream, such as the water content or volatile solids concentration.  Should changes to the waste stream occur, you must revise the GHG Monitoring Plan as required in §98.3(g)(5)(iii) and report the new DOCx value according to the requirements of §98.466.
(iii)  If DOCx measurement data for each waste stream are available according to the methods specified in §98.464(b) for years prior to the first year in which GHG emissions from this industrial waste landfill must be reported, determine DOCx for each waste stream as the arithmetic average of all DOCx values for that waste stream that were measured in Year X.  A single measurement value is acceptable for determining DOCx for years prior to the first reporting year.
(iv)  For historical years for which DOCx measurement data, determined according to the methods specified in §98.464(b), are not available, determine the historical values for DOCx using the applicable methods specified in paragraphs (a)(3)(iv)(A) and (B) of this section.  Determine these historical values for DOCx only for the first annual report required for this industrial waste landfill; historical values for DOCx calculated for this first annual report should be used for all subsequent annual reports.
(A)  For years in which waste stream-specific disposal quantities are determined (as required in paragraphs (a)(2) (ii)(A) and (B) of this section), calculate the average DOC value for a given waste stream as the arithmetic average of all DOC measurements of that waste stream that follow the methods provided in §98.464(b), including any measurement values for years prior to the first reporting year and the four measurement values required in the first reporting year.  Use the resulting waste-specific average DOC value for all applicable years (i.e., years in which waste stream-specific disposal quantities are determined) for which direct DOC measurement data are not available.  
(B)  For years for which bulk waste disposal quantities are determined according to paragraphs (a)(2)(ii)(C) of this section, calculate the weighted average bulk DOC value according to the following:  calculate the average DOC value for each waste stream as the arithmetic average of all DOC measurements of that waste stream that follows the methods provided in §98.464(b) (generally, this will include only the DOC values determined in the first year in which GHG emissions from this industrial waste landfill must be reported); calculate the average annual disposal quantity for each waste stream as the arithmetic average of the annual disposal quantities for each year in which waste stream-specific disposal quantities have been determined; and calculate the bulk waste DOC value using Equation TT-5 of this section.  Use the bulk waste DOC value as DOCx for all years for which bulk waste disposal quantities are determined according to paragraphs (a)(2)(ii)(C) of this section.   
		(Eq. TT-5)
Where:

DOCbulk	=	Degradable organic content value for bulk historical waste placed in the landfill (mass fraction).
N	=	Number of different waste streams placed in the landfill
n	=	Index for waste stream
DOCave,n	=	Average degradable organic content value for waste stream "n" based on available measurement data (mass fraction).
Wave,n	=	Average annual quantity of waste stream "n" placed in the landfill for years in which waste stream-specific disposal quantities have been determined (metric tons per year, wet basis).

(b)  For each landfill, calculate CH4 generation (adjusted for oxidation in cover materials) and CH4 emissions (taking into account any CH4 recovery, if applicable, and oxidation in cover materials) according to the applicable methods in paragraphs (b)(1) through (b)(3) of this section.
(1)  For each landfill, calculate CH4 generation, adjusted for oxidation, from the modeled CH4 (GCH4 from Equation TT-1 of this section) using Equation TT-6 of this section.
		(Eq. TT-6)
Where: 

MG 	=	Methane generation, adjusted for oxidation, from the landfill in the reporting year (metric tons CH4).
GCH4	=	Modeled methane generation rate in reporting year from Equation TT-1 of this section (metric tons CH4).
OX 	=	Oxidation fraction.  Use the default value of 0.1 (10 percent).

(2)  For landfills that do not have landfill gas collection systems operating during the reporting year, the CH4 emissions are equal to the CH4 generation (MG) calculated in Equation TT-6 of this section.
(3)  For landfills with landfill gas collection systems in operation during any portion of the reporting year, perform all of the calculations specified in paragraphs (b)(3)(i) through (iv) of this section. 
(i)  Calculate the quantity of CH4 recovered according to the requirements at §98.343(b).
(ii)  Calculate CH4 emissions using the Equation HH-6 of §98.343(c)(3)(i), except use GCH4 determined using Equation TT-1 of this section in Equation HH-6 of §98.343(c)(3)(i).
(iii)  Calculate CH4 generation (MG) from the quantity of CH4 recovered using Equation HH-7 of §98.343(c)(3)(ii).
(iv)  Calculate CH4 emissions from the quantity of CH4 recovered using Equation HH-8 of §98.343(c)(3)(ii).
§98.464  Monitoring and QA/QC requirements. 
(a) For calendar year 2011 monitoring, the facility may submit a request to the Administrator to use one or more best available monitoring methods as listed in §98.3(d)(1)(i) through (iv).  The request must be submitted no later than [INSERT DATE 90 DAYS AFTER PUBLICATION IN THE FEDERAL REGISTER] and must contain the information in §98.3(d)(2)(ii).  To obtain approval, the request 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 January 1, 2011.  The use of best available monitoring methods will not be approved beyond December 31, 2011.       
(b) For each waste stream received during the reporting year for which you choose to determine volatile solids concentration for the purposes of paragraph §98.460(c)(2)(xii) or choose to determine a landfill-specific DOCx for use in Equation TT-1 of this subpart, you must collect and test a representative sample of that waste stream using the methods specified in paragraphs (b)(1) through (b)(4) of this section.
(1)  Develop and follow a sampling plan to collect a representative sample of each waste stream (as received at the landfill) for which testing is elected.
(2)  Determine the percent total solids and the percent volatile solids of each sample following Standard Method 2540G "Total, Fixed, and Volatile Solids in Solid and Semisolid Samples" (incorporated by reference; see §98.7).  
(3)  For the purposes of paragraph §98.460(c)(2)(xii),  the volatile solids concentration (weight percent on a dry basis) 
			


				
		is the percent volatile solids determined using Standard Method 2540G "Total, Fixed, and Volatile Solids in Solid and Semisolid Samples" (incorporated by reference; see §98.7). 
		

(4)  Calculate the waste stream-specific DOCx value using Equation TT-7 of this section.
	  	(Eq. TT-7) 
Where: 

DOCx			=	Degradable organic content of waste stream in Year X (weight fraction, wet basis)
FDOC			=	Fraction of the volatile residue that is degradable organic carbon (weight fraction).  Use a default value of 0.6.
% Volatile Solidsx	=	Percent volatile solids determined using Standard Method 2540G Total, "Fixed, and Volatile Solids in Solid and Semisolid Samples" (incorporated by reference; see §98.7) for Year X [milligrams (mg) volatile solids per 100 mg dried solids]. 
% Total Solidsx	=	Percent total solids determined using Standard Method 2540G "Total, Fixed, and Volatile Solids in Solid and Semisolid Samples" (incorporated by reference; see §98.7) for Year X (mg dried solids per 100 mg wet waste).


(c)  For each waste stream for which you choose to determine volatile solids concentration for the purposes of paragraph §98.460(c)(2)(xii), and that was historically managed in the landfill but was not received during the first reporting year, you must determine volatile solids concentration of the waste stream as initially placed in the landfill using the methods specified in paragraph (c)(1) or (c)(2) of this section, as applicable.
(1)  If you can identify a similar waste stream to the waste stream that was historically managed in the landfill, you must determine the volatile solids concentration of the similar waste stream using the procedures in paragraphs (b)(1) through (b)(3) of this section.
(2)  If you cannot identify a similar waste stream to the waste stream that was historically managed in the landfill, you may determine the volatile solids concentration of the historically managed waste stream using process knowledge.  You must document the basis for volatile solids concentration as determined through process knowledge.  
(d)  For landfills with gas collection systems, operate, maintain, and calibrate a gas composition monitor capable of measuring the concentration of CH4 according to the requirements specified at §98.344(b).
(e)  For landfills with gas collection systems, install, operate, maintain, and calibrate a gas flow meter capable of measuring the volumetric flow rate of the recovered landfill gas according to the requirements specified at §98.344(c).    
(f)  For landfills with gas collection systems, all temperature, pressure, and if applicable, moisture content monitors must be calibrated using the procedures and frequencies specified by the manufacturer. 
      (g)  For landfills electing to measure the fraction by volume of CH4 in landfill gas (F), follow the requirements in paragraphs (g)(1) and (g)(2) of this section. 
      (1)  Use a gas composition monitor capable of measuring the concentration of CH4 on a dry basis that is properly operated, calibrated, and maintained according to the requirements specified at §98.344(b).  You must either use a gas composition monitor that is also capable of measuring the O2 concentration correcting for excess (infiltration) air or you must operate, maintain, and calibrate a second monitor capable of measuring the O2 concentration on a dry basis according to the manufacturer's specifications.  
      (2)  Use Equation TT-8 of this section to correct the measured CH4 concentration to 0% oxygen.  If multiple CH4 concentration measurements are made during the reporting year, determine F separately for each measurement made during the reporting year, and use the results to determine the arithmetic average value of F for use in Equation TT-1 of this part. 		
			 	(Eq. TT-8)
Where:
F	=	Fraction by volume of CH4 in landfill gas (fraction, dry basis, corrected to 0% oxygen);
CCH4	=	measured CH4 concentration in landfill gas (volume %, dry basis);
20.9c	=	defined O2 correction basis, (volume %, dry basis);
20.9	=	O2 concentration in air (volume %, dry basis); and
%O2	=	measured O2 concentration in landfill gas (volume %, dry basis).

(h) The facility shall document the procedures used to ensure the accuracy of the estimates of disposal quantities and, if the industrial waste landfill has a gas collection system, gas flow rate, gas composition, temperature, pressure, and moisture content measurements.  These procedures include, but are not limited to, calibration of weighing equipment, fuel flow meters, and other measurement devices.  The estimated accuracy of measurements made with these devices shall also be recorded, and the technical basis for these estimates shall be provided.
§98.465  Procedures for estimating missing data.
(a)  A complete record of all measured parameters used in the GHG emissions calculations is required.  Therefore, whenever a quality-assured value of a required parameter is unavailable (e.g., if a meter malfunctions during unit operation or if a required fuel sample is not taken), a substitute data value for the missing parameter shall be used in the calculations, in accordance with paragraph (b) of this section.
(b)  For industrial waste landfills with gas collection systems, follow the procedures for estimating missing data specified in §98.345(a) and (b). 
§98.466  Data reporting requirements. 
In addition to the information required by §98.3(c), each annual report must contain the following information for each landfill.  
(a)  Report the following general landfill information: 
(1)  A classification of the landfill as "open" (actively received waste in the reporting year) or "closed" (no longer receiving waste). 
(2)  The year in which the landfill first started accepting waste for disposal. 
(3)  The last year the landfill accepted waste (for open landfills, enter the estimated year of landfill closure). 
(4)  The capacity (in metric tons) of the landfill.
(5)  An indication of whether leachate recirculation is used during the reporting year and its typical frequency of use over the past 10 years (e.g., used several times a year for the past 10 years, used at least once a year for the past 10 years, used occasionally but not every year over the past 10 years, not used).
(b)  Report the following waste characterization and modeling information:
(1)  The number of waste steams (including "Other Industrial Solid Waste (not otherwise listed)") for which Equation TT-1 of this subpart is used to calculate modeled CH4 generation.
(2)  A description of each waste stream (including the types of materials in each waste stream) for which Equation TT-1 of this subpart is used to calculate modeled CH4 generation.
(3)  The fraction of CH4 in the landfill gas, F, (volume fraction, dry basis, corrected to 0% oxygen) for the reporting year and an indication as to whether this was the default value or a value determined through measurement data.  
(4)  The methane correction factor (MCF) value used in the calculations.  If an MCF value other than the default of 1 is used, provide a description of the aeration system, including aeration blower capacity, the fraction of the landfill containing waste affected by the aeration, the total number of hours during the year the aeration blower was operated, and other factors used as a basis for the selected MCF value.
(c)  For each waste stream identified in paragraph (b) of this section, report the following information:
(1)  The decay rate (k) value used in the calculations. 
(2)  The method(s) for estimating historical waste disposal quantities and the range of years for which each method applies.  
(3)  If Equation TT-2 of this subpart is used, provide: 
(i)  The total number of years (N) for which disposal and production data are both available. 
(ii)  The year, the waste disposal quantity and production quantity for each year used in Equation TT-2 of this subpart to calculate the average waste disposal factor (WDF).
(iii) The average waste disposal factor (WDF) calculated for the waste stream.  
(4)  If Equation TT-4 of this subpart is used, provide:
(i)  The value of landfill capacity (LFC). 
(ii)  YrData. 
(iii) YrOpen.  
(d)  For each year of landfilling starting with the "Start Year" (S) and each year thereafter up to the current reporting year, report the following information:
(1) The calendar year for which the following data elements apply.  
(2) The quantity of waste (Wx) disposed of in the landfill (metric tons, wet weight) for the specified year for each waste stream identified in paragraph (b) of this section.
(3)  The degradable organic carbon (DOCx) value (mass fraction) for the specified year and an indication as to whether this was the default value from Table TT-1 of this subpart or a value determined through sampling and calculation for each waste stream identified in paragraph (b) of this section. 

(e)  Report the following information describing the landfill cover material:
(1)  The type of cover material used (as either organic cover, clay cover, sand cover, or other soil mixtures).  
(2)  For each type of cover material used, the 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. 
(f)  The modeled annual methane generation (GCH4) for the reporting year (metric tons CH4) calculated using Equation TT-1 of this subpart.
(g)  For landfills without gas collection systems, provide:
(1) The annual methane emissions (i.e., the methane generation (MG), adjusted for oxidation, calculated using Equation TT-6 of this subpart), reported in metric tons CH4. 
(2) An indication of whether passive vents and/or passive flares (vents or flares that are not considered part of the gas collection system as defined in §98.6) are present at this landfill.
(h)  For landfills with gas collection systems, in addition to the reporting requirements in paragraphs (a) through (f) of this section, you must report according to §98.346(i). 
§98.467  Records that must be retained. 
In addition to the information required by §98.3(g), you must retain the calibration records for all monitoring equipment, including the method or manufacturer's specification used for calibration, and all total and volatile solids concentration measurement data used for the purposes of paragraph §98.460(c)(2)(xii) or used to determine landfill-specific DOCx values.   
§98.468  Definitions.
Except as provided below, all terms used in this subpart have the same meaning given in the CAA and subpart A of this part.
Construction and demolition (C&D) waste landfill means a solid waste disposal facility subject to the requirements of subparts A or B of part 257 of this chapter that receives construction and demolition waste and does not receive hazardous waste (defined in § 261.3 of this chapter) or industrial solid waste (defined in § 258.2 of this chapter) or municipal solid waste (defined in § 98.6 of this part) other than residential lead-based paint waste.  A C&D waste landfill typically receives any one or more of the following types of solid wastes: roadwork material, excavated material, demolition waste, construction/renovation waste, and site clearance waste.
Design capacity means the maximum amount of solid waste a landfill can accept, as indicated in terms of volume or mass in the most recent permit issued by the State, local, or Tribal agency responsible for regulating the landfill, plus any in-place waste not accounted for in the most recent permit.  If the owner or operator chooses to convert the design capacity from volume to mass to determine its design capacity, the calculation must include a site specific density, which must be recalculated annually. 

Solid waste has the meaning established by the Administrator pursuant to the Solid Waste Disposal Act (42 U.S.C.A. 6901 et seq.).
Waste stream means industrial solid waste material that is generated by a specific manufacturing process or client.  For wastes generated at the facility that includes the industrial waste landfill, a waste stream is the industrial solid waste material generated by a specific processing unit at that facility.  For industrial solid wastes that are received from off-site facilities, a waste stream can be defined as each waste shipment or group of waste shipments received from a single client or group of clients that produce industrial solid wastes with similar waste properties.
Table TT-1 of Subpart TT -- Default DOC and Decay Rate Values for Industrial Waste Landfills
                              Industry/Waste Type
                       DOC (weight fraction, wet basis)
                                       k
                           [dry climate[a]] (yr[-1])
                                       k
                        [moderate climate[a]] (yr[-1])
                                       k
                           [wet climate[a]] (yr[-1])
Food Processing
                                                                           0.22
                                                                           0.06
                                                                           0.12
                                                                           0.18
Pulp and Paper
                                                                           0.20
                                                                           0.02
                                                                           0.03
                                                                           0.04
Wood and Wood Product
                                                                           0.43
                                                                           0.02
                                                                           0.03
                                                                           0.04
Construction and Demolition
                                                                           0.08
                                                                           0.02
                                                                           0.03
                                                                           0.04
Inert Waste [i.e., wastes listed in §98.460(c)(2)]
                                                                              0
                                                                              0
                                                                              0
                                                                              0
Other Industrial Solid Waste (not otherwise listed)
                                                                           0.20
                                                                           0.02
                                                                           0.04
                                                                           0.06
[a] The applicable climate classification is determined based on the annual rainfall plus the recirculated leachate application rate.  Recirculated leachate application rate (in inches/year) is the total volume of leachate recirculated from company records or engineering estimates and applied to the landfill divided by the area of the portion of the landfill containing waste [with appropriate unit conversions]. 
   (1)    Dry climate = precipitation plus recirculated leachate less than 20 inches/year 
   (2)    Moderate climate = precipitation plus recirculated leachate from 20 to 40 inches/year (inclusive) 
   (3)    Wet climate = precipitation plus recirculated leachate greater than 40 inches/year
Alternatively, landfills that use leachate recirculation can elect to use the k value for wet climate rather than calculating the recirculated leachate rate.







