1

Subpart A

—General Provisions §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 fossil fuel suppliers and industrial GHG suppliers. For suppliers, the GHGs reported are the quantity that would be emitted from combustion or use of the products supplied. (b) Owners and operators of facilities and suppliers that are subject to this part must follow the requireme nts of subpart A 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 subparts B through PP of this part 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 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:2 (1) A facility that contains any source category (as defined in subparts C through JJ of this part) that is listed in this paragraph (a)(1) in any calendar year starting in 2010. For these facilities, the annual GHG report must cover all source categories and GHGs for which calculation methodologies are provided in subparts C through JJ of this part. (i) Electricity generation (units that report CO 2 emissions year
- round through 40 CFR part 75). (ii) Adipic acid production. (iii) Aluminum production. (iv) Ammonia manufacturing. (v) Cement production. (vi) HCFC - 22 production. (vii) HFC
- 23 destruction processes that are not colloca ted with a HCFC
- 22 production facility and that destroy more than 2.14 metric tons of HFC
- 23 per year. (viii) Lime manufacturing. (ix) Nitric acid production. (x) Petrochemical production. (xi) Petroleum refineries. (xii) Phosphoric acid production. ( xiii) Silicon carbide production. (xiv) Soda ash production.3 (xv) Titanium dioxide production. (xvi) Municipal solid waste landfills that generate CH 4 in amounts equivalent to 25,000 metric tons CO 2 e or more per year, as determined according to subpart HH of this part. (xvii) Manure management systems with combined CH 4 and N 2 O emissions in amounts equivalent to 25,000 metric tons CO 2 e or more per year, as determined according to subpart JJ of this part. (2) A facility that contains any source catego ry (as defined in subparts C through JJ of this part) that is listed in this paragraph (a)(2) in any calendar year starting in 2010 and that emits 25,000 metric tons CO 2 e or more per year in combined emissions from stationary fuel combustion units, miscell aneous uses of carbonate, and all source categories that are listed in this paragraph. For these facilities, the annual GHG report must cover all source categories and GHGs for which calculation methodologies are provided in subparts C through JJ of this part. (i) Ferroalloy Production. (ii) Glass Production. (iii) Hydrogen Production. (iv) Iron and Steel Production.4 (v) Lead Production. (vi) Pulp and Paper Manufacturing. (vii) Zinc Production. (3) A facility that in any calendar year starting in 2 010 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 (as defined in subparts KK through PP of this part) that provides products listed in this paragraph (a)(4) in any calendar year starting in 2010. For these suppliers, the annual GHG report mu st cover all applicable products for which calculation methodologies are provided in subparts KK through PP of this part. (i) Coal
- to - liquids suppliers, as specified in this paragraph (i).5 (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 is equivalent to 25,000 metric tons CO 2 e or more. (ii) Petroleum product suppliers, as spec ified in this paragraph (ii): (A) All petroleum refineries that distill crude oil. (B) Importers of an annual quantity of petroleum products that is equivalent to 25,000 metric tons CO 2 e or
more. (C) Exporters of an annual quantity of petroleum products that is equivalent to 25,000 metric tons CO 2 e or
more. (iii) Natural gas and natural gas liquids suppliers, as specified in this paragraph (iii): (A) All natural gas fractionators. (B) Local natural gas distribution companies that deliver 460,000 thousand standard cubic feet or more of natural gas per year . (iv) Industrial greenhouse gas suppliers, as specified in this paragraph (iv): (A) All producers of industrial greenhouse gases.6 (B) Importers of industrial greenhouse gases with annual bulk imports of N 2 O, fluorinated GHG, and CO 2 that in combination are equivalent to 25,000 metric tons CO 2 e or
more. (C) Exporters of industrial greenhouse gases with annual bulk exports of N 2 O, fluorinated GHG, and CO 2 that in combination are equivalent to 2 5,000 metric tons CO 2 e or
more. (v) Carbon dioxide suppliers, as specified in this paragraph (v). (A) All producers of CO 2 . (B) Importers of CO 2 with annual bulk imports of N 2 O, fluorinated GHG, and CO 2 that in combination are equivalent to 25,000 metr ic tons CO 2 e or more. (C) Exporters of CO 2 with annual bulk exports of N 2 O, fluorinated GHG, and CO 2 that in combination are equivalent to 25,000 metric tons CO 2 e or more. (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 CO 2 e per year emission threshold in paragraph (a)(2) of this section, the owner or operator7

shall calculate annual CO 2 e emissions, as described in pa ragraphs (b)(1) through (b)(4) of this section. (1) Calculate the annual emissions of CO 2 , CH 4 , N 2 O,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 CO 2 emissions in metric tons using any of the four calculation methodologies specified in §98.33(a). Calculate the annual CH 4 and N 2 O 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 CH 4 and N 2 O from biomass combustion. (3) For miscellaneous uses of carbonate, calculate the annual CO 2 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 CO 2 e using Equation A
- 1 of this section.8 
  n 1 i i

GWP x i GHG e 2 CO (Eq. A
- 1) Where: CO 2 e = Carb on dioxide equivalent, metric tons/year. GHG i = Mass emissions of each greenhouse gas listed in

Table A
- 1 of this subpart, metric tons/year. GWP i = Global warming potential for each greenhouse gas

from Table A
- 1 of this subpart. n = The number of gree nhouse gases emitted. (5) For purpose of determining if an emission threshold has been exceeded, include in the emissions calculation any CO 2 that is captured for transfer off site. (c) To calculate GHG emissions for comparison to the 25,000 metric ton CO 2 e /year emission threshold for stationary fuel combustion under paragraph (a)(3) of this section, calculate CO 2 , CH 4 , and N 2 O emissions from each stationary fuel combustion unit by following the methods specified in paragraph (b)(2) of this section. The n, convert the emissions of each GHG to metric tons CO 2 e 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 CO 2 per year threshold for importers and exporters of coal
- to - liquid products under paragraph (a)(4)(i) of this section, calculate the mass in metric tons per year of CO 2 that would result from the complete9

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. Calculate the emissions using the methodology specified in subpart LL of this part. (e) To calculate GHG quantities for comparison to the 25,000 metric ton CO 2 e per year threshold for importers and exporters of petroleum products under paragraph (a)(4)(ii) of this section, calculate the mass in metric tons per year of CO 2 that would result from the complete combustion or oxidation of the volume of petroleum products and natural gas liquids that are imported during the reporting year and that are exported during the reporting year. Calculate the emissions using the methodology specified in subpart MM of this part. (f) To calculate GHG quantities for comparison to the 25,000 metric ton CO 2 e per year threshold under paragraph (a)(4) of this section for importers and exporters of industrial greenhouse gases and for importers and exporters of CO 2, the owner or operator shall calculate the mass in metric tons per year of CO 2 e imp orts and exports as described in paragraphs (f)(1) through (f)(3) of this section.10 (1) Calculate the mass in metric tons per year of CO 2 , N 2 O, and each fluorinated GHG that is imported and the mass in metric tons per year of CO 2 , N 2 O, and each fluorinat ed 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 CO 2 e using Equation A
- 1 of this s ection. (3) Sum the total annual metric tons of CO 2 e in paragraph (f)(2) of this section for all imported GHGs. Sum the total annual metric tons of CO 2 e 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 §98.3(b)(3), if a facility or supplier exceeds the app licability requirements of paragraph (a) of this section at a later time. Thus, the11

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 i n 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 a re less than 25,000 metric tons CO 2 e 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 later12

than March 31 of the year immediately following the fifth consecutive year of emissions less than 25,000 tons CO 2 e per year. The owner or opera tor 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 CO 2 e per year or more. (2) If reported emissions are less than 15,000 metric tons CO 2 e 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 CO 2 e 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 reporting13

if annual emissions in any future calendar year increase to 25,000 metric tons CO 2 e per year or more. (3) If the operations of a facility or suppli er 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. This paragraph (i)(2) does no t apply to seasonal or other temporary cessation of operations. This paragraph (i)(2) does not apply to facilities with municipal solid waste landfills. 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?14 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 sect ion, 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 must be submitted no later than March 31 of each calendar year for GHG emissions in the previous calendar year. (1) For an existing facility or supplier that began operation before January 1, 2010, report emissions for calendar year 2010 and each subsequent calendar year. (2) For a new facility or supplier that begins operation on or after January 1, 2010, 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 occu rs,15

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. (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) , facility or supplier ID number, 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, report annual emissi ons of CO 2, CH 4, N 2 O, and each fluorinated GHG (as defined in §98.6) as follows:16 ( i) Annual emissions ( including biogenic CO 2 ) aggregated for all GHG from all applicable source categories in subparts C through JJ of this part and expressed in me tric tons of CO 2 e calculated using Equation A- 1 of this subpart. (ii) Annual emissions of biogenic CO 2 aggregated for all applicable source categories in subparts C through JJ of this part in metric tons . Units that use the methodologies in part 75 of th is chapter to calculate CO 2 mass emissions are not required to separately report biogenic CO 2 emiss i ons , but may do so as an option . ( iii ) Annual emissions from each applicable source category in subparts C through JJ of this part, expressed in metric ton s of each applicable GHG listed in this paragraph (4)(iii)(A) through (4)(iii)(E). (A) Biogenic CO 2 . Units that use the methodologies in part 75 of this chapter to calculate CO 2 mass emissions are not required to separately report biogenic CO 2 emissions, but may do so as an option. (B) CO 2 ( including biogenic CO 2 ). (C) CH 4 . (D) N 2 O. (E) Each fluorinated GHG (including those not listed in Table A
- 1 of this subpart).17 (iv) 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. (5) For suppliers, report annual quantities of CO 2, CH 4, N 2 O, 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 subparts KK through PP of th is part and expressed in metric tons of CO 2 e calculated using Equation A
- 1 of this subpart. For fluorinated GHG s , calculate and report CO 2 e for only those fluorinated GHGs listed in Table A
- 1 of this subpart. (ii) Quantity of each GHG from each applicab le supply category in subparts KK through PP of this part, expressed in metric tons of each GHG. For fluorinated GHG, report emissions 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.18 (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 ava ilable monitoring method” used according to paragraph (d) of this section, the parameter measured using the method, and the time period during which the “best available monitoring method” was used. (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). (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 moni toring 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 calculation19

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 subp art. (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.20 (ii) Content of request . Requests must contain the followi ng 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 rul e 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 and21

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 pro cess 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 justifi cation 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 moni toring 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 the22

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 CO 2, CH 4, N 2 O, and CO 2 e. (v) Any facility operating data or process information used for the GHG emission calcula tions. (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 methodologies23

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 writ ten 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 t o 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. 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 inspection24

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
a ctivities 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 requ ired fuel or feedstock parameters. (iv) Any facility operating data or process information used for the GHG emission calculations. (3) The annual GHG reports.25 (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 (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 othe r 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 production26

processes, monitoring instrumentat ion, and quality assurance procedures; or to improve procedures for the maintenan ce 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 i nformation 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 f or 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 operat or 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.27 (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 otherwis e 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 days28

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 Administrato r 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 and a ccuracy 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 spec ifications 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 CO 2 mass emissions.29 (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 calculat ions , shall be calibrated pr ior 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; howeve r, 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 industry standards and manufacturer’s specifications. The30

procedures and methods used to quality
- assure the data from each measurement device shall be documented in the written Monitoring P lan, 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 P lan 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 th is section, subsequent31

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 operati ng 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 val ue.
100 x R A R CE   (Eq. A
- 2) Where:

CE = Calibration error (%)32

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 t ransmitter 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.
100 x FS A R CE   (Eq. A
- 3) Where:33
CE = Calibration error (%) R = Reference value A = Transmitter response to the reference value FS = Full
- sca le 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 sec tion ; 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:34 ( A ) You must demon strate 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 a ll temperature and /or total pressure measurements in the demonstration described in paragraph (i)(3)(i i ) (A) of this section with calibrated gauge s, 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 an industry consensus standards or a manufacturer’s specification . ( C ) You must document the methods used for the demonstration described in paragraph (i)(3)(i i ) (A) of this section in the written Monitoring P lan 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 Monitoring P lan. You must maintain a ll of this information in a format suitable for auditing and inspection .35 ( D ) You must use the mathematical correlation(s) derived from the demonstration described in paragraph (i)(3)(i i ) (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 calibrati on requirements of this section and from the Monitoring P lan and recordkeeping provisions of paragraphs (g)(5)(i)(C) 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 owne d by subsidiaries or affiliates of the same company. Meters used exclusively to measure the flow rates of fuels that are used for unit startup or ignition 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 this36

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 inter im. 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) I f the results of an initial calibration or a recalibration fail to meet the required accuracy37

specification, data from the flow meter shall be considered invalid, beginning with the hour of the failed calibration and continuing until a successful calibrati on is completed. You shall follow the missing data provisions provided in the relavant missing data sections during the period of data invalidation. (j) Measurement Device Installation . (1) General . If an owner or operator required to report under subp art 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 Administ rator 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 installi ng 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 device38

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 ava ilable 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 below. (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 subsquent 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 tha t was provided in the original request.39 (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 meas urement 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.40 (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 availabl e 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 whi ch 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 operato r 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 Ju ly 1, 2011 unless the extension request under this paragraph (j) is approved by the Administrator before July 1, 2011.41 (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, 20 13, 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 .42

§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 design ated 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.43 (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 ident ified 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 an y 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 repor t 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 certificat e 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 this44

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. (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 individual s 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 under45

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 i nclude 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 ide ntifying 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.46 (2) Except in this section, whenever the term “designated representative” is used in this part, the term shall be construed to i nclude 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 the47

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 repres entation 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 the48

following elements in a forma t 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 agreeme nt binding on the owners and operators of the facility or supplier, as applicable.”49 (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 facil ity 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 altern ate 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 Admin istrator shall50

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) Obje ctions 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 any51

designated representative or alternate designated representat ive. (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.52 (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 clause (iii), the facility or supplier for which the electronic submission may be made. (v) The following certi fication 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 faci lity 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.”53 (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.” (v) 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 s uch 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)(iv)(A) of this section and made in accordance with a notice of delegation
e ffective under paragraph (m)(3) of this section shall be deemed to be an electronic submission certified, signed,54

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 use d in this part shall have the same meaning given in the Clean Air Act and in this section. 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 thi s 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.55
AGA means the American Gas Association Agricultural byproducts means those parts of arable crops that are not used for the primary purpose of producing food. Agricultural byproducts include, but are not limited to, oat, corn and wheat straws, bagasse, peanut shells, rice and coconut husks, so ybean hulls, palm kernel cake, cottonseed and sunflower seed cake, and pomace. 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 means a type of liquid storage system component, either at manure management system or a wastewater treatment system, that is designed and operated56

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, the 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 . Argon - oxygen decarburization (AOD) vessel means any closed
-bottom, refractory
- lined converter vessel with submerged tuyeres through which gaseous mixtures containing argon and oxygen or nitrogen may be blown into molten steel for further refining to redu ce the carbon content of the steel. ASABE means the American Society of Agricultural and Biological Engineers.57
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). B 0 means the maximum CH 4 producing capacity of a waste stream, kg CH 4 /kg COD. Basic oxygen furnace means any refractory
- lined vessel i n which high
-purity oxygen is blown under pressure through a bath of molten iron, scrap metal, and fluxes to produce steel. bbl means barrel.58 Biodiesel means a mono - akyl ester derived from biomass and conforming to ASTM D6751
- 08, Standard Specification f or Biodiesel Fuel Blend Stock (B100) for Middle Distillate Fuels. Biogenic CO 2 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) and59

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 els ewhere. 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 but yl 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. 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 CO 2 suppliers, means the transfer of a product inside containers, including but not limite d 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 liquids60

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 pa raffinic straight
- chain hydrocarbon with molecular formula C 4 H 10 . Butylene , or n - Butylene, is an olefinic straight
- chain hydrocarbon with molecular formula C 4 H 8 . 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. Carbon dioxide equivalent or CO 2 e means the number of metric tons of CO 2 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 c arbon dioxide.61 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 loc ated 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 c onsidered part of the same CO 2 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 c arbon 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 CO 3 - 2
. Upon calcination, the carbonate radical decomposes to evolve carbon dioxide (CO 2 ). Common carbonates consumed in the mineral industry include calcium carbonate (CaCO 3 ) or62

calcite; magnesium carbonate (MgCO 3 ) or magnesite; and calcium
-magnesium carbonate (CaMg(CO 3 ) 2 ) or dolomite. Carbonate
-based mineral means any of the following minerals used in the manufacture of glass: calcium carbonate (CaCO 3 ), calcium magnesium carbonate (CaMg(CO 3 ) 2 ), and sodium carbonate (Na 2 CO 3 ). Carbonate
-based mineral mass fraction means the following: for limestone, the mass fraction of CaCO 3 in the limestone; for dolomite, the mass fraction of CaMg(CO 3 ) 2 in the dolomite; and for soda ash, the mass fraction of Na 2 CO 3 in the soda ash. Carbonate
-based raw material means any of the following materials used in the manufacture of glass: limestone, dolomite, and soda ash. 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 conti nuously 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,63

which are also referred to as thermal catalyti c 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. 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. 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 . Certified standards means calibration gases certified by the manufacturer of the calibration gases to be accurate64

to within 2 percent of the value on the label or calibration gases. CH 4 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 me ans 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 distribution65

company system and typically are used to measure local distribution company system sendout to customers. CO 2 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 specifi ed pursuant to 40 CFR part 136. 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 methods66

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 measu ring 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 segme nts, 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 circumfe rence 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 Americ an Industry Classification System 327213 (NAICS 327213). Continuous emission monitoring system or CEMS means the total equipment required to sample, analyze, measure, and provide, by means of readings recorded at least once67

every 15 minutes, a permanent re cord 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 o ther 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 Prote ction 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 excludes68

conventional blendstock for oxygenate blending (CBOB) as well as other blendstock. Crude oil means a mixture of hydrocarbons that exists in the liquid phase in the underground reservoir and remains liquid at atmospheric pressure after passing through surface separating facilities. Daily spread means a manure management system component in which manure is routi nely 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. Degradable organic carbon (DOC) means the fraction of the total mass of a waste material that can be biologically degraded. 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 c losed, batch system reactors. A delayed coking unit consists of the coke drums and ancillary equipment associated with a single fractionator. Density means the mass contained in a given unit volume (mass/volume).69 Destruction means, with respect to landfil ls 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. Destruction means, with respec t 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 Efficiency means the efficiency with which a destruction devi ce reduces the GWP
-weighted mass of greenhouse gases fed into the device, considering the GWP
weighted masses of both the greenhouse gases fed into the device and those exhausted from the device. The Destruction Efficiency is expressed in Equation A
- 2 of this section:

IN OUT e tCOe tCO DE 2

2 1

  (Eq. A
- 2) Where:70

DE = Destruction Efficiency tCO 2 e IN = The GWP
-weighted mass of GHGs fed into the destruction device tCO 2 e OUT = The GWP
-weighted mass of GHGs exhausted from the destruction device, including GHGs formed during the destruction process Destruction efficiency, or flaring destruction efficiency , refers to the fraction of the gas that leaves the flare partially or fully oxidized. Diesel

–Other is any distillate fuel oil not defined elsewhere, including Diese l Treated as Blendstock (DTAB). DIPE (diisopropyl ether , (CH 3 ) 2 CHOCH(CH 3 ) 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 fuels71

(Diesel Fuels No. 1, No. 2, and No. 4), and fuel oi ls (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). Distillat e 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. DOC f means the fraction of DOC that actually decomposes under the (presumably anaerobic) conditions within the landfill.72 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 ar cs 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 mechan ical 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 si tuations, for training of personnel under simulated emergency conditions, as part of emergency demand response procedures, or for standard performance73

testing procedures as required by law or by the generator manufacturer. A generator that serves as a bac k
- 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, (CH 3 ) 3COC 2 H) is an ether as described in "Oxygenates." Ethane is a paraffinic hydrocarbon with molecular formula C 2 H 6 . Ethanol is an anhydrous alcohol with molecular formula C 2 H 5OH. Ethylene is an olefinic hydrocarbon with molecular formula C 2 H 4 . 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) or74

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 transfe rs 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 princ ipal 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 such75

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 hydrocarbon s 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.76 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 incl ude, 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 to77

generate a low value fuel gas that is used as fuel in other combustion sources a t the refinery. Fluorinated greenhouse gas means sulfur hexafluoride (SF 6 ), nitrogen trifluoride (NF 3 ), and any fluorocarbon except for controlled substances as defined at 40 CFR part 82, subpart A and substances with vapor pressures of less than 1 mm of Hg absolute at 25 degrees C. With these exceptions, “fluorinated GHG” includes but is not limited to any hydrofluorocarbon, any perfluorocarbon, any fully fluorinated linear, branched or cyclic alkane, ether, tertiary amine or aminoether, any perfluoropolyether, and any hydrofluoropolyether. Fossil fuel means natural gas, petroleum, coal, or any form of solid, liquid, or gaseous fuel derived from such material, for purpose of creating useful heat . Fractionators means plants that produce fractionated natural gas liquids (NGLs) extracted from produced natural gas and separate the NGLs individual component products: ethane, propane, butanes and pentane
-plus (C5+). Plants that only process natural gas but do not fractionate NGLs further into component product s are not considered fractionators. Some fractionators do not process production gas, but instead fractionate bulk NGLs received from natural gas processors. Some fractionators both78

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, petrochemical plant, or similar industrial process unit, 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. Gas collection system or landfill gas collection system means a system of pipes used to collect landfill gas from different locations in the landfill 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.79
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. Gaseous fuel means a material that is in the gaseous state at standa rd 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 instantaneous80

release of one kilogram of a trace substance relative to that of one kilogram
- of a reference gas, i.e., CO 2 . GPA mean s the Gas Processors Association. Greenhouse gas or GHG means carbon dioxide (CO 2 ), methane (CH 4 ), nitrous oxide (N 2 O), sulfur hexafluoride (SF6), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and other fluorinated greenhouse gases as defined in this section. GTBA (gasoline
- grade tertiary butyl alcohol, (CH 3 ) 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 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 in to, or introduce into, any place subject to the jurisdiction of the United81

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 Mexi co 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, excl uding 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:82 (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 an y 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 o f 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. Isobutane is a paraffinic branch chain hydrocarbon with molecular formula C 4 H 10 .83 Isobutylene is an olefinic branch chain hydrocarbon with molecular formula C 4 H 8 . 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 o f 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, injection84

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. 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. 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 resi dues. Makeup chemicals means carbonate chemicals (e.g., sodium and calcium carbonates) that are added to the85

chemical recovery areas of chemical pulp mills to replace chemicals lost in the process. Manure composting means the biological oxidation of a soli d 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 amoun t 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,86

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 CH 4 producing capacity (B o ) 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 landfil l 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 correcti on factor of 1. Methanol (CH 3OH) 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 finished87

gasoline after oxygenate has been added t o 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), absorpti on 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 gas oline (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 million standard cubic feet.88
MTBE (methyl tertiary butyl ether, (CH 3 ) 3COCH 3 ) is an ether as described in "Oxygenates." Municipal solid waste landfill or MSW landfill means an ent ire 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, conditionall y 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 o r 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 simila r 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 faci lities. Institutional waste includes material discarded by schools, nonmedical waste discarded by hospitals, material discarded by non
manufacturing activities at prisons and government89

facilities, and material discarded by other similar establishments or facilities. Household, commercial/retail, and institutional waste does not include used oil, wood pellets, construction, renovation, and demolition wastes (which includes, but is not limited to, railroad ties and telephone poles), clean wood, industrial p rocess or manufacturing wastes, medical waste, or motor vehicles (including motor vehicle parts or vehicle fluff). Household, commercial/retail, and institutional wastes include yard waste, refuse
- derived fuel, and motor vehicle maintenance materials, limited to vehicle batteries and tires, except where a single waste stream consisting of tires is combusted in a unit. N 2 O means nitrous oxide. Naphthas (< 401 °F) is a generic term applied to a petroleum fraction with an approximate boiling range between 12 2 °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 is composed of at90

least 70 percent methane by volume or has a high heat value between 910 and 1150 Btu per standard cubic foot. 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 absorbe rs 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 as a feedstock 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, where91

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. 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 c ombustion 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 intended92

for use as a petrochemical feedstock and are not defined elsewhere. 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 leaseho ld 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 is93

not limited to, normal pentane, isopentane, hexanes
-plus (natural gasoline), and plant condensate. Pe rfluorocarbons 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 Feeds tocks 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 processing94

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. Pit storage below animal confinement (deep pits) means the colle ction 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 two95

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. Poul try 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 mea t 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 by96

the mean of the measurements plus or minus the specified level. Premium grade gas oline 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 categori es 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.97 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 CO 2 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 ga s stream that: (1) is discharged through a conveyance to the atmosphere either directly or after passing through a control device; (2) originates from a unit operation, including but not limited to reactors (including reformers, crackers, and furnaces,98

and separation equipment for products and recovered byproducts); and (3) 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 C 3H 8 . Propylene is an olefinic hydrocarbon with molecular formula C 3H 6 . 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 from99

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 materi al 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 de finition 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. 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 8 0.41, 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 the100

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 and101

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 l ime kiln means a unit with an inclined rotating drum that is used to produce a lime product from limestone by calcination.102 Safety device means a closure device such as a pressure relief valve, frangible disc, fusible plug, or any othe r 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, acc idental, 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 haz ardous materials. Semi
- refined petroleum product means all oils requiring further processing. Included in this category are unfinished oils which are produced by the partial103

refining of crude oil and include the following: naphthas and lighter oils; keros ene 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. SF 6 means sulfur hexafluoride. Shutdown means the cessation of operat ion of an emission source for any purpose.104 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 seri es 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 s lag. Solid byproducts means plant matter such as vegetable waste, animal materials/wastes, and other solid biomass, except for wood, wood waste, and sulphite lyes (black liquor).105 Solid storage is the storage of manure, typically for a period of several mon ths, 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. 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.106 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 operat ions 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 p ressure (STP) means 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 produced107

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 (H 2 S) and/or sulfur dioxide (SO 2 ) from a common source of sour gas at a petroleum ref inery. 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 plan t 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 sulfu r 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.108 Supplier means a producer, importer, or exporter of a fossil fuel or an industrial greenhouse gas. Taconite iron ore processing means an industrial process that separates and concentrat es 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, (CH 3 ) 2 (C 2 H 5 )COCH 3 ). 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 fluorinate d 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 its109

territories, cannot be re
-packaged, sort ed or otherwise changed in condition. Trona means the raw material (mineral) used to manufacture soda ash; hydrated sodium bicarbonate carbonate (e.g.Na2CO 3 .NaHCO 3 .2H 2 O). Ultimate analysis means the determination of the percentages of carbon, hydrogen, nit rogen, 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, and U.S. possessions and territories. 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 tran sport 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. Valve means any device for halti ng or regulating the flow of a liquid or gas through a passage, pipeline, inlet,110

outlet, or orifice; including, but not limited to, gate, globe, plug, ball, butterfly and needle valves. Vegetable Oil means oils extracted from vegetation that are generally used as a feedstock in making biodiesel. 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). Waste oil means a petroleum
- derived or synthetically
derived oil whose physical properties have changed as a result of storage, handling or use, such tha t the oil cannot be used for its original purpose. Waste 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). 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 serie s predominates. This includes all marketable wax, whether111

crude or refined, with a congealing point between 80 (or 85) and 240 °F and a maximum oil content of 50 weight percent. Wood residuals means wood waste recovered from three principal sources: muni cipal 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 process ing 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, and logging residues. Wool fiberglass means fibrous glass of random texture, including fiberglass insulation, and other products listed in NAICS 327993. You means an owner or operator subject to Part 98.112 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 Registe r. 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:113

http://www.archives.gov/federal_register/code_of_federal_re gulations/ibr_loc ations.html. (a) The following material is available for purchase from the Association of Fertilizer and Phosphate Chemists (AFPC), P. O. Box 1645, Bartow, Florida 33831, http://afpc.net. (1) Phosphate Mining States Methods Used and Adopted by the Asso ciation of Fertilizer and Phosphate Chemists AFPC Manual 10th Edition 2009
- Version 1.9, incorporation by reference (IBR) approved for §98.264(a) and §98.264(b). (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 Ave nue, New York, NY 10016
- 5990, (800) 843
- 2763, http://www.asme.org.114 (1) ASME MFC
- 3M

– 2004 Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and Venturi, incorporation by reference (IBR) approved for §98.344(c) and §98.364(e). (2) ASME MFC
- 4M

– 1986 (Reaffirmed 1997) Measurement of Gas Flow by Turbine Meters, IBR approved for §98.344(c), and §98.364(e). (3) [Reserved] (4) ASME MFC
- 6M

– 1998 Measurement of Fluid Flow in Pipes Using Vortex Flowmeters, IBR approved for §98.344(c) 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 §98.344(c) and §98.364(e). (6) [Reserved] (7) ASME MFC
- 11M
- 2006 Measurement of Fluid Flow by Means of Coriolis Mass Flowmeters, IBR approved for §98.344(c). (8) ASME MFC
- 14M
- 2003 Measurement of Fluid Flow Using Small Bore Precision Orifice Meters, IBR approved for §98.344(c) and §98.364(e). (9) [Reserved] (10) ASME MFC
- 18M
- 2001 Measurement of Fluid Flow Using Variable Area Meters, IBR approved for §98.344(c), and §98.364(e).115 (11) [Reserved] (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 §9 8.6. (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 §9 8.6. (6) ASTM D910
- 07a Standard Specification for Aviation Gasolines, IBR approved for §98.6. (7) [Reserved]116 (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), 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), §98.344(b), 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).117 (15) ASTM D2503
- 92 (Reapproved 2007) Standard Test Method for Relative Molecular Mass (Molecular Weight) of Hydrocarbons by Thermoelectri c Measurement of Vapor Pressure, IBR approved for §98.74(c). (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) St andard 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 Calculati on 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, Compressibility118

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 fo r §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 Hea ting Value of Gases in Natural Gas Range by Stoichiometric Combustion, IBR approved for §98.254(e). (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).119 (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) , §98.224(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 U sing Radiocarbon Analysis, IBR approved for §98.34(d), §98.34(e), and §98.36(e).120 (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 f rom 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) ASTM E1747
- 95 (Reapproved 2005) Standard Guide for Purity of Carbon Dioxide Used in Supercritical Fluid Applications, IBR approved for 98.424(b). (40) ASTM E1915
- 07a Standard Test Methods for Analysis of Metal Bearing Ores and Related Materials by121

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 Chroma tography, IBR approved for §98.164(b), §98.244(b), and §98.254(d), and §98.344(b). (43) ASTM D2503
- 92(2007) Standard Test Method for Relative Molecular Mass (Molecular Weight) of Hydrocarbons by Thermoelectric Measurement of Vapor Pressure, IBR approved for §98.254(d). (4 4 ) ASTM D2593
- 93(2009) Standard Test Method for Butadiene Purity and Hydrocarbon Impurities by Gas Chromatography , IBR approved for §98.244(b) . (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), and §98.344(b).122 (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 Glebe123

Road, Suite 800, Arlington, Virginia 22203, (7 03) 243
- 5463, http://www.l ime.org. (1) CO 2 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). (i) The following material is avail able 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 Fo r Weighing and Measuring Devices, NIST Handbook 44 (2009), incorporation by reference (IBR) approved for §98.244(b), §98.254(h), and §98.344(a). (j) The following material is available for purchase from the Technical Association of the Pulp and Paper Indu stry (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 Heat ing Value of Black Liquor, TAPPI, incorporation by reference (IBR) approved for §98.274(b).124 (k) The following material is available from the U.S. Environmental Pro t ection Agency, 1200 Pennsylvania Avenue, NW, Washington, D.C. 20460, (202) 272
- 0167, www.ep a.gov. (1) Protocol for Measuring Destruction or Removal Efficiency (DRE) of Fluorinated Greenhouse Gas Abatement Equipment in Electronics Manufacturing, Version 1, EPA
- 430
- R- 10
- 003 . §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
c onstitutes 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, shall be submitted to the following address:125 (a) For U.S. mail. D irector, 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 CO 2 1 Methane 74
- 82
- 8 CH 4 21 Nitrous oxide 10024
- 97
- 2 N 2O 310 HFC - 23 75
- 46
- 7 CHF 3 11,700 HFC - 32 75
- 10
- 5 CH 2 F 2 650 HFC - 41 593
- 53
- 3 CH 3 F 150 HFC - 125 3 54
- 33
- 6 C 2 HF 5 2,800 HFC - 134 359
- 35
- 3 C 2 H 2 F 4 1,000 HFC - 134a 811
- 97
- 2 CH 2 FCF 3 1,300 HFC - 143 430
- 66
- 0 C 2 H 3 F 3 300 HFC - 143a 420
- 46
- 2 C 2 H 3 F 3 3,800 HFC - 152 624
- 72
- 6 CH 2 FCH 2 F 53 HFC - 152a 75
- 37
- 6 CH 3CHF 2 140 HFC - 161 353
- 36
- 6 CH 3CH 2 F 12 HFC - 227ea 431
- 89
- 0 C 3HF 7 2,900 HFC - 236cb 677
- 56
- 5 CH 2 FCF 2 CF 3 1,340 HFC - 236ea 431
- 63
- 0 CHF 2 CHFCF 3 1,370 HFC - 236fa 690
- 39
- 1 C 3H 2 F 6 6,300 HFC - 245ca 679
- 86
- 7 C 3H 3 F 5 560 HFC - 245fa 460
- 73
- 1 CHF 2 CH 2 CF 3 1,030 HFC - 365mfc 406
- 58
- 6 CH 3CF 2 CH 2 CF 3 794 HFC - 43
- 10mee 138495
- 42
- 8 CF 3CFHC FHCF 2 CF 3 1,300 Sulfur hexafluoride 2551
- 62
- 4 SF 6 23,900126

Table A- 1 of Subpart A —Global Warming Potentials (100 -Year Time Horizon)

Name CAS # Chemical formula Global warming potential (100 yr.) Trifluoromethyl sulphur pentafluoride 373
- 80
- 8 SF 5CF 3 17,700 Nitrogen trifluoride 7783
- 54
- 2 NF 3 17,200 PFC - 14 (Perfluoromethane) 75
- 73
- 0 CF 4 6,500 PFC - 116 (Perfluoroethane) 76
- 16
- 4 C 2 F 6 9,200 PFC - 218 (Perfluoropropane) 76
- 19
- 7 C 3 F 8 7,000 Perfluorocyclopropane 931
- 91
- 9 c - C 3 F 6 17,340 PFC - 3
- 1
- 10 (Perfluorobutane) 355
- 25
- 9 C 4 F 10 7,000 Perfluorocyclobutane 115
- 25
- 3 c - C 4 F 8 8,700 PFC - 4
- 1
- 12 (Perfluoropentane) 678
- 26
- 2 C 5 F 12 7,500 PFC - 5
- 1
- 14 (Perfluorohexane) 355
- 42
- 0 C 6 F 14 7,400 PFC - 9
- 1
- 18 306
- 94
- 5 C 10 F 18 7,500 HCFE - 235da2 (Isoflurane) 26675
- 46
- 7 CHF 2 OCHClCF 3 350 HFE - 43
- 10pccc (H
- Galden 1040x) E1730133 CHF 2 OCF 2 OC 2 F 4 OCHF 2 1,870 HFE - 125 3822
- 68
- 2 CHF 2 OCF 3 14,900 HFE - 134 1691
- 17
- 4 CHF 2 OCHF 2 6,320 HFE - 143a 421
- 14
- 7 CH 3OCF 3 756 HFE - 227ea 2356
- 62
- 9 CF 3CHFOCF 3 1,540 HFE - 236ca12 (HG
- 10) 78522
- 47
- 1 CHF 2 OCF 2 OCHF 2 2,800 HFE - 236ea2 (Desflurane) 57041
- 67
- 5 CHF 2 OCHFCF 3 989 HFE - 236fa 20193
- 67
- 3 CF 3CH 2OCF 3 487 HFE - 245cb2 22410
- 44
- 2 CH 3OCF 2 CF 3 708 HFE - 245fa1 84011
- 15
- 4 CHF 2 CH 2OCF 3 286 HFE - 245fa2 1885
- 48
- 9 CHF 2 OCH 2 CF 3 659 HFE - 254cb2 425
- 88
- 7 CH 3OCF 2 CHF 2 359 HFE - 263fb2 460
- 43
- 5 CF 3CH 2OCH 3 11 HFE - 329mcc2 67490
- 36
- 2 CF 3CF 2OCF 2 CHF 2 919 HFE - 338mcf2 156053
- 88
- 2 CF 3CF 2OCH 2 CF 3 552 HFE - 338pcc13 (HG
- 01) 188690
- 78
- 0 CHF 2 OCF 2 CF 2OCHF 2 1,500 HFE - 347mcc3 28523
- 86
- 6 CH 3OCF 2 CF 2 CF 3 575 HFE - 347mcf2 E1730135 CF 3CF 2OCH 2 CHF 2 374 HFE - 347pcf2 406
- 78
- 0 CHF 2 CF 2OCH 2 CF 3 580 HFE - 356mec3 382
- 34
- 3 CH 3OCF 2 CHFCF 3 101 HFE - 356pcc3 160620
- 20
- 2 CH 3OCF 2 CF 2 CHF 2 110 HFE - 356pcf2 E1730137 CHF 2 CH 2OCF 2 CHF 2 265 HFE - 356pcf3 35042
- 99
- 0 CHF 2 OCH 2 CF 2 CHF 2 502127

Table A- 1 of Subpart A —Global Warming Potentials (100 -Year Time Horizon)

Name CAS # Chemical formula Global warming potential (100 yr.) HFE - 365mcf3 378
- 16
- 5 CF 3CF 2 CH 2 OCH 3 11 HFE - 374pc2 512
- 51
- 6 CH 3CH 2OCF 2 CHF 2 557 HFE - 449sl (HFE
- 7100) Chemical blend 163702
- 07
- 6 163702
- 08
- 7 C 4 F 9OCH 3

(CF 3 ) 2 CFCF 2OCH 3 297 HFE - 569sf2 (HFE
- 7200) Chemical blend 163702
- 05
- 4 163702
- 06
- 5 C 4 F 9OC 2 H 5

(CF 3 ) 2 CFCF 2OC 2 H 5 59 Sevoflurane 28523
- 86
- 6 CH 2 FOCH(CF 3 ) 2 345 HFE - 356mm1 13171
- 18
- 1 (CF 3 ) 2 CHOCH 3 27 HFE - 338mmz1 26103
- 08
- 2 CHF 2 OCH(CF 3 ) 2 380 (Octafluorotetramethy
lene)hydroxymethyl group NA X- (CF 2 ) 4 CH(OH)
-X 73 HFE - 347mmy1 22052
- 84
- 2 CH 3OCF(CF 3 ) 2 343 Bis(trifluoromethyl)
- methanol 920
- 66
- 1 (CF 3 ) 2 CHOH 195 2,2,3,3,3
- pentafluoropropanol 422
- 05
- 9 CF 3CF 2 CH 2 OH 42 PFPMIE NA CF 3OCF(CF 3 )CF 2 OCF 2 OC F 3 10,300 NA = not available Table A- 2 of Subpart A — 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) 2,0 00 Short tons Metric tons 0.90718 Metric tons Short tons 1.10231 Metric tons Kilograms (kg) 1,000 Cubic meters (m3 ) Cubic feet (ft 3 ) 35.31467 Cubic feet (ft 3 ) Cubic meters (m3 ) 0.028317 Gallons (liquid, US) Liters (l) 3.78541 Liters (l) Gallons (liquid, US) 0.26417 Barrels of Liquid Fuel (bbl) Cubic meters (m3 ) 0.15891 Cubic meters (m3 ) Barrels of Liquid Fuel (bbl) 6.289 Barrels of Liquid Fuel (bbl) Gallons (liquid, US) 42 Gallons (liquid, US) Barrels of Liquid Fuel (bbl) 0.023810 Gallons (liqui d, US) Cubic meters (m3 ) 0.0037854 Liters (l) Cubic meters (m3 ) 0.001128

To convert from To Multiply by 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 (m2 ) Acres 2.47105 x 10 - 4 Square miles (mi 2 ) Square kilometers (km2 ) 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 Subpart C—General Stationary Fuel Combustion Sources §98.30 Definition of the source category. (a) Stationary fuel combustion sources are devices that combust solid, liquid, or gaseous fuel, generally for the purposes of producing el ectricity, generating steam, or providing useful heat or energy for industrial, commercial, or institutional use, or reducing the volume of waste by removing combustible matter. Stationary fuel combustion sources include, but are not limited to, boilers, simple and combined
- cycle combustion turbines, engines, incinerators, and process heaters. (b) This source category does not include:129 (1) Portable equipment, as defined in §98.6. (2) Emergency generators and emergency equipment, as defined in §98.6. ( 3) Irrigation pumps at agricultural operations. (4) Flares, unless otherwise required by provisions of another subpart of this part to use methodologies in this subpart. (5) Electricity generating units that are subject to subpart D of thi s part. (c) For a unit that combusts hazardous waste (as defined in § 261.3 of this chapter ), reporting of GHG emissions is not required unless either of the following conditions apply: (1) Continuous emission monitors (CEMS) are used to quantify CO 2 mass emissions. (2) Any fuel listed in Table C
- 1 of this subpart is also combusted in the unit. In this case, report GHG emissions from combustion of all fuels listed in Table C
- 1 of this subpart. (d) You are not required to report GHG emissions from pilot lights . A pilot light is a small permanent auxiliary flame that ignites the burner of a combustion device when the control valve opens. §98.31 Reporting threshold.130 You must report GHG emissions under this subpart if your facility contains one or more stationary fuel combustion sources and the facility meets the applicability requirements of either §§98.2(a)(1), 98.2(a) (2), or 98.2(a) (3). §98.32 GHGs to report. You must report CO 2 , CH 4 , and N 2 O mass emissions from each stationary fuel combustion unit , except as otherwise indicated in this subpart . §98.33 Calculating GHG emissions. You must calculate CO 2 emissions according to paragraph (a) of this section, and calculate CH 4 and N 2 O emissions according to paragraph (c) of this section. (a) CO 2 emissions from fuel combustion . Calculate CO 2 mass emissions by using one of the four calculation methodologies in paragraph s (a) (1) through (a)(4) of this section, subject to the applicable conditions, requirements, and restrictions set forth i n paragraph (b) of this section. Alternatively, for units that meet the conditions of paragraph (a)(5) of this section, you may use CO 2 mass emissions calculation methods from part 75 of this chapter, as described in paragraph (a)(5) of this section . For units that combust both biomass and fossil fuels, you must calculate and report CO 2 emissions from the combustion131

of biomass separately using the methods in paragraph (e) of this section , except as otherwise provided in paragraph s (a)(5)(iv) and (e) of this section and in §98.36(d) . (1) Tier 1 Calculation Methodology . Calculate the annual CO 2 mass emissions for each type of fuel by using Equation C
- 1 or C - 1a of this section (as applicable) . (i) Use Equation C
- 1 except when natu ral gas billing records are used to quantify fuel usage and gas consumption is expressed in units of therms. In that case, use Equation C
- 1a. EF HHV Fuel x CO *

* * 10 1 3 2   (Eq. C
- 1) Where: CO 2 = Annual CO 2 mass emissions for the specific fuel

type (metric tons ). Fuel = Mass or volume of fuel combusted per year, from

company records as defined in §98.6 (express mass in short tons for solid fuel, volume in standard cubic feet for gaseous fuel, and volume in gallons for liquid fuel). HHV = Default high heat value of the fuel, from Table

C - 1 of this subpart (mmBtu per mass or mmBtu per volume, as applicable). EF = Fuel
- specific default CO 2 emission factor, from

Table C
- 1 of this subpart (kg CO 2 /mmBtu). 1 x 10 - 3 = Conversion factor from kilograms to metric tons. ( ii) If natural gas consumption is obtained from billing records and fuel usage is expressed in therms, use Equation C
- 1a.132 

##  

EF Gas x CO *

* 1
. 0 10 1 3 2   (Eq. C
- 1a) Where: CO 2 = Annual CO 2 mass emissions from natural gas

combustion (metric tons). Gas = Annua l natural gas consumption, from billing

records (therms). EF = Fuel
- specific default CO 2 emission factor for

natural gas, from Table C
- 1 of this subpart (kg CO 2 /mmBtu). 0.1 = Conversion factor from therms to mmBtu 1 x 10 - 3 = Conversion factor from kilo grams to metric tons. (2) Tier 2 Calculation Methodology . Calculate the annual CO 2 mass emissions for each type of fuel by using either Equation C2a or C2c of this section, as appropriate. (i) Equation C
- 2a of this section applies to any type of fuel listed in Table C
- 1 of the subpart, except for municipal solid waste (MSW). For MSW combustion, use Equation C
- 2c of this section. EF HHV Fuel x CO *

* * 10 1 3 2   (Eq. C
- 2a) Where: CO 2 = Annual CO 2 mass emissions for a specific fuel

type (metric tons). Fuel = Mass or volume of the fuel combusted during the

year, from company records as defined in §98.6 ( express mass in short tons for solid fuel, volume in standard cubic feet for gaseous fuel, and volume in gallons for liquid fuel ). HHV = Annual average high heat value of the fuel

(mmBtu per mass or volume). The average HHV shall be calculated according to the requirements of paragraph (a)(2)(ii) of this section.133

EF = Fuel
- specific default CO 2 emission factor, from

Table C
- 1 of this subpart (kg CO 2 /mmBtu). 1 x 10 - 3 = Conversion factor from kilograms to metric

tons. (ii) The minimum required sampling frequency for determining the annual average HHV (e.g., monthly, quarterly, semi
- annually, or by lot) is specified in §98.34. The method for computing the annual average HHV is a function of unit size and how frequently you perform or receive from the fuel supplier the results of fuel sampling for HHV. The method is specified in paragraph (a)( 2)(ii)(A) or (a)(2)(ii)(B) of this section, as applicable. (A) If the results of fuel sampling are received monthly or more frequently, then for each unit with a maximum rated heat input capacity greater than or equal to 100 mmBtu/hr (or for a group of un its that includes at least one unit of that size), the annual average HHV shall be calculated using Equation C
- 2b of this section. If multiple HHV determinations are made in any month, average the values for the month arithmetically.



##      

  

##  

  

 n

i i n
i i

i annual FuelFuel

HHV HHV

1 1 (Eq. C
- 2b)

Where:134

(HHV) annual = Weighted annual average high heat value of the

fuel (mmBtu per mass or volume). (HHV) i = Measured h igh heat value of the fuel, for month

“i” , or, if applicable, an appropriate substitute data value (mmBtu per mass or volume). (Fuel) i = Mass or volume of the fuel combusted during

month “i , ” from company records (express mass in short tons for solid fuel, volume in standard cubic feet for gaseous fuel, and volume in gallons for liquid fuel). n = Number of months in the year that the fuel is

burned in the unit. (B) If the results of fuel sampling are received less frequently than monthly, or, for a unit with a maximum rated heat input capacity less than 100 mmBtu/hr (or a group of such units) regardless of the HHV sampling frequency, the annual average HHV shall be computed as the arithmetic average HHV for all values for the year (including valid samples and substitute data values under § 98.35). (iii) For units that combust municipal solid waste (MSW) and that produ ce steam, use Equation C
- 2c of this section. Equation C
- 2c of this section may also be used for any other solid fuel listed in Table C
- 1 of this subpart provided that steam is generated by the unit.

EF B Steam x CO 

  3 2 10 1 (Eq. C
- 2c) Where:135

CO 2 = Annua l CO 2 mass emissions from MSW or solid

fuel combustion (metric tons). Steam = Total mass of steam generated by MSW or solid

fuel combustion during the reporting year (lb steam). B = Ratio of the boiler’s maximum rated heat input

capacity to its design rate d steam output capacity (mmBtu/lb steam). EF = Fuel
- specific default CO 2 emission factor,

from Table C
- 1 of this subpart (kg CO 2 /mmBtu). 1 x 10 - 3 = Conversion factor from kilograms to metric

tons. (3) Tier 3 Calculation Methodology . Calculate the
annua l CO 2 mass emissions for each fuel by using either Equation C3, C4, or C5 of this section, as appropriate. (i) For a solid fuel, use Equation C
- 3 of this section.
91
. 0 12 44 2 

   CC Fuel CO (Eq. C
- 3) Where: CO 2 = Annual CO 2 mass emissions from the combustion

of the specific solid fuel (metric tons). Fuel = Annual mass of the solid fuel combusted, from

company records as defined in §98.6 (short tons). CC = Annual average carbon content of the solid fuel

(percent by weight, expressed as a decimal fraction, e.g., 95% = 0.95). The annual average carbon content shall be determined using the same procedures as specified for HHV in paragraph (a)(2)(ii) of this section. 44/12 = Ratio of molecular weights, CO 2 to carbon. 0.91 = Conversion factor from short tons t o metric

tons.136 (ii) For a liquid fuel, use Equation C
- 4 of this section.
001
. 0 CC Fuel 12 44 CO 2 

   (Eq. C
- 4) Where: CO 2 = Annual CO 2 mass emissions from the combustion

of the specific liquid fuel (metric tons). Fuel = Annual volume of the liquid fuel combusted

(gallons). The volume of fuel combusted must be measured directly, using fuel flow meters calibrated according to §98.3(i). Fuel billing meters may be used for this purpose. Tank drop measurements may also be used. CC = Annual average carbon conte nt of the liquid

fuel (kg C per gallon of fuel). The annual average carbon content shall be determined using the same procedures as specified for HHV in paragraph (a)(2)(ii) of this section. 44/12 = Ratio of molecular weights, CO 2 to carbon. 0.001 = Conve rsion factor from kg to metric tons.
(iii) For a gaseous fuel, use Equation C
- 5 of this section.
001
. 0 12 44 2 

    MVC

MW CC Fuel CO (Eq. C
- 5) Where: CO 2 = Annual CO 2 mass emissions from combustion of

the specific gaseous fuel (metric tons). Fuel = Annual volume of the gaseous fuel combusted

(scf). The volume of fuel combusted must be measured directly, using fuel flow meters calibrated according to §98.3(i). Fuel billing meters may be used for this purpose. CC = Annual average carbon content of the gaseou s

fuel (kg C per kg of fuel). The annual137 average carbon content shall be determined using the same procedures as specified for HHV in paragraph (a)(2)(ii) of this section. MW = Annual average molecular weight of the gaseous

fuel (kg/kg
-mole). The annual average molecular weight shall be determined using the same procedures as specified for HHV in paragraph (a)(2)(ii) of this section. MVC = Molar volume conversion factor (849.5 scf per

kg
-mole at standard conditions, as defined in §98 .6). 44/12 = Ratio of molecular weights, CO 2 to carbon. 0.001 = Conversion factor from kg to metric tons. (iv) Fuel flow meters that measure mass flow rates may be used for liquid or gaseous fuels, provided that the fuel density is used to convert the re adings to volumetric flow rates. The density shall be measured at the same frequency as the carbon content . For liquid fuels, you must measure the density using one of the following appropriate methods. You may use a method published by a consensus standards organization, if such a method exists,
or you may use 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). The method(s)138

used shall be documented in the Monitoring P lan required under §98.3(g)(5). Alternatively, for fuel oil, you may use an applicable default density value provided in paragraph (a)(3)(v) of this section . For gaseous fuels, you may determine the density using any of the following methods. You may use a density meter calibrated according to the manufacturer’s instructions, a method published by a consensus standards organization, or an industry standard practice . Document the method used to determine the fuel density in the Monitoring P lan under §98.3(g)(5) . (v) The following default densit y values may be used for fuel oil, in lieu of using the ASTM method in paragraph (a)(3)(iv) of this section: 6.8 lb/gal for No. 1 oil; 7.2 lb/gal for No. 2 oil; 8.1 lb/gal for No. 6 oil. (4) Tier 4 Calculation Methodology . Calculate the annual CO 2 mass emissions from all fuels combusted in a unit, by using quality
- assured data from continuous emission monitoring systems (CEMS). (i) This methodology requires a CO 2 concentration monitor and a stack gas volumetric flow rate monitor, except as otherwise provided in paragraph (a)(4)(iv) of this section. Hourly measurements of CO 2 concentration and stack gas flow rate are converted to CO 2 mass emission rates in metric tons per hour.139 (ii) When the CO 2 concentration is measured on a wet basis, Equation C
- 6 of this section is used to calculate the hourly CO 2 emission rates: Q C x CO CO *

* 10 18
. 5 2

7 2   (Eq. C
- 6)
Where: CO 2 = CO 2 mass emission rate (metric tons/hr). C CO2 = Hourly average CO 2 concentration (% CO 2 ). Q = Hourly average stack gas volumetric flow

rate (scfh). 5.18 x 10 - 7 = Conversion factor (metric tons/scf/% CO 2 ). (iii) If the CO 2 concentration is measured on a dry basis, a correction for the stack gas moisture content is required. You shall either continuously monitor the stack gas moisture cont ent as described in §75.11(b)(2) of this chapter or use an appropriate default moisture percentage . For coal, wood, and natural gas combustion, you may use the default moisture values specified in §75.11(b)(1) of this chap ter. Alternatively, for any type of fuel, you may determine an appropriate site
- specific default moisture value (or values), using measurements made with EPA Method 4
- Determination Of Moisture Content In Stack Gases, in appendix A
- 3 to part 60 of this chapter. If this option is selected, the site
- specific moisture default value(s) must represent the fuel(s) or fuel blends that are combusted in the unit during normal, stable operation, and must account140

for any distinct difference(s) in the stack gas mois ture content associated with different process operating conditions. For each site
- specific default moisture percentage, at least nine Method 4 runs are required. Moisture data from the relative accuracy test audit (RATA) of a CEMS may be used for this purpose. Calculate each site
- specific default moisture value by taking the arithmetic average of the Method 4 runs. Each site
specific moisture default value shall be updated whenever the owner or operator believes the current value is non
representative, due to changes in unit or process operation, but in any event no less frequently than annually. Use the updated moisture value in the subsequent CO 2 emissions calculations. For each unit operating hour, a moisture correction must be applied to Equation C - 6 of this section as follows:      

  100

% 100 2 2 * 2 O

H CO CO (Eq. C
- 7) Where: CO 2 * = Hourly CO 2 mass emission rate, corrected for

moisture (metric tons/hr). CO 2 = Hourly CO 2 mass emission rate from Equation C
- 6 of

this section, uncorrected (metric tons/hr). %H 2 O = Hourly moisture percentage in the stack gas

(measured or default value, as appropriate).141 (iv) An oxygen (O 2 ) concentration monitor may be used in lieu of a CO 2 concentration monitor to determine the hourly CO 2 concentrations, in accordance with E quation F
- 14a or F - 14b (as applicable) in appendix F to part 75 of this chapter , if the effluent gas stream monitored by the CEMS consists solely of combustion products (i.e., no process CO 2 emissions or CO 2 emissions from sorbent are mixed with the combustion products) and if only fuels that are listed in Table 1 in section 3.3.5 of appendix F to part 75 of this chapter are combusted in the unit. If the O 2 monitoring option is selected, the F
- factors used in Equations F
- 14a and F
- 14b shall be determined according to section 3.3.5 or section 3.3.6 of appendix F to part 75 of this chapter , as applicable. If Equation F
- 14b is used, the hourly moisture percentage in the stack gas shall be determined in accordance with paragraph (a)(4)(iii ) of this section . (v) Each hourly CO 2 mass emission rate from Equation C - 6 or C
- 7 of this se ction is multiplied by the operating time to convert it from metric tons per hour to metric tons. The operating time is the fraction of the hour during which fuel is combusted (e.g., the unit operating time is 1.0 if the unit operates for the whole hour and is 0.5 if the unit operates for 30 minutes in the hour). For common stack configurations, the operating time is the142

fraction of the hour during which effluent gases flow through the common stack. (vi) The hourly CO 2 mass emissions are then summed
over each calendar quarter and the quarterly totals are summed to determine the annual CO 2 mass emissions. (vii) If both biomass and fossil fuel are combusted during the year, determine and report the biogenic CO 2 mass emissions separately, as described in paragraph (e) of this section. ( viii) If a portion of the flue gases generated by a unit subject to Tier 4 (e.g., a slip stream) is continuously diverted from the main flue gas exhaust system for the purpose of heat recovery or some other similar process, and then exhausts through a stack that is not equipped with the continuous emission monitors to measure CO 2 mass emissions, provided that the CO 2 concentration in the diverted stream is not altered in any way (e.g., by chemical reaction or dilution) before the diverted stream exits to the atmosphere, an estimate of the hourly average volumetric flow rate (scfh) of the diverted gas stream shall be made at the point where it exits the main exhaust system, by using the best available information (e.g., correl ations of operating parameters versus flow measurements made with EPA Method 2 in appendix A
- 2 to part143

60 of this chapter, engineering analysis, or other methods). Each hourly average volumetric flow rate (scfh) measured at the main flue gas stack shall then be added to the corresponding estimate of the hourly average flow rate of the diverted gas stream, to determine the total hourly average stack gas volumetric flow rate "Q", for use in Equation C
- 6 of this section. The method use to estimate the hourly flow rate of the diverted portion of the flue gas exhaust stream shall be documented in the Monitoring P lan required under §98.3(g)(5). (5) Alternative methods for certain units subject to Part 75 of this chapter . Certain units that are not subject to subpart D of this part and that report data to EPA according to part 75 of this chapter may qualify to use the alternative methods in this paragraph (a)(5), in lieu of using any of the four calculation methodology tiers. (i) For a unit that combusts only natural gas and/or fuel oil, is not subject to subpart D of this part , monitors and reports heat input data year
- round according to appendix D to part 75 of this chapter , but is not required by the applicable part 75 program to report CO 2 mass emissions data, calculate the annual CO 2 mass emissions for the purposes of this part as follows:144 (A) Use the hourly heat input data from appendix D to part 75 of this chapter , together with Equation G
- 4 in appendix G to part 75 of this chapter to determine the hourly CO 2 mass emission rates, in units of tons/hr; (B) Use Equations F
- 12 and F
- 13 in appendix F to part 75 of this chapterto cal culate the quarterly and cumulative annual CO 2 mass emissions, respectively, in units of short tons; and (C) Divide the cumulative annual CO 2 mass emissions value by 1.1 to convert it to metric tons. (ii) For a unit that combusts only natural gas and/or fuel oil, is not subject to subpart D of this part , monitors and reports heat input data year
- round according to § 75.19 of this chapter but is not required by the applicable part 75 program to report CO 2 mass emissions data, calculate the annual CO 2 mass emissions for the purposes of this part as follows: (A) Calculate the hourly CO 2 mass emissions, in units of short tons, using Equation LM
- 11 in § 75.19(c)(4)(iii) of this chapter . (B) Sum the hourly CO 2 mass emis sions values over the entire reporting year to obtain the cumulative annual CO 2 mass emissions, in units of short tons.145 (C) Divide the cumulative annual CO 2 mass emissions value by 1.1 to convert it to metric tons. (iii) For a unit that is not subject to subpart D of this part , uses flow rate and CO 2 (or O 2 ) CEMS to report heat input data year
- round according to part 75 of this chapter , but is not required by the applicable part 75 program to report CO 2 mass emissions da ta, calculate the annual CO 2 mass emissions as follows: (A) Use Equation F
- 11 or F
- 2 (as applicable) in appendix F to part 75 of this chapter to calculate the hourly CO 2 mass emission rates from the CEMS data. If an O 2 monitor is used, convert the hourly average O 2 readings to CO 2 using Equation F
- 14a or F
- 14b in appendix F to part 75 of this chapter (as applicable), before applying Equation F - 11 or F
- 2. (B) Use Equations F
- 12 and F
- 13 in appendix F to part 75 of this chapter to calculate the quarterly and cumulative annual CO 2 mass emissions, respectively, in units of short tons. (C) Divide the cumulative annual CO 2 mass emissions value by 1.1 to convert it to metric tons. ( iv ) For units that qualify to use the alternative CO 2 emissions calculation methods in paragraphs (a)(5)(i) through (a)(5)(iii) of this section, i f both biomass and146

fossil fuel are combusted during the year, separate calculation and reporting of the biogenic CO 2 mass emissions ( as described in paragraph (e) of this section ) is optional . (b) Use of the four tiers . Use of the four tiers of CO 2 emissions calculation methodologies described in paragraph (a) of this section is subject to the following conditions, requirements, and restrictions: (1) The Tier 1 Calculation Methodology: (i) May be used for any fuel listed in Table C
- 1 of this subpart that is combusted in a unit with a maximum rated heat input capacity of 250 mmBtu/hr or less. (ii) May be used for MSW in a unit of any size that does not produce steam, if the use of Tier 4 is not required. (iii) May be used for solid, gaseous, or liquid biomass fuels in a unit of any size provided that the fuel is listed in Table C
- 1 of this subpart. (iv) May not be used if you routinely perform fuel sampling and analysis for the fuel high heat value (HHV) or routinely receive the results of HHV sampling and analysis from the fuel supplier at the minimum frequency specified in §98.34(a), or at a greater frequency. In such cases,147

Tier 2 shall be used. This restriction does not apply to paragraphs (b)(1)(ii) and (b)(1)(v) of this section. (v) May be used for natural gas combustion in a unit of any size, in cases where the annual natural gas
consumption is obtained from fuel billing records in units of therms. (2) The Tier 2 Calculation Methodology: (i) May be used for the combustion of any type of fuel in a unit with a maximum rated heat input capacity of 250 mmBtu/hr or less provided that the fuel is listed in Table C
- 1 of this subpart. (ii) May be used in a unit with a maximum rated heat input capacity greater than 250 mmBtu/hr for the combustion of natural gas and /or distillate fuel oil. (iii) May be used for MSW in a unit of any size that produces steam, if the use of Tier 4 is not required. (3) The Tier 3 Calculation Methodology: (i) May be used for a unit of any size that combusts any type of fuel listed in Table C
- 1 of this subpart (except for MSW), unless the use of Tier 4 is required. (ii) Shall be used for a unit with a maximum rated heat input capacity greater than 250 mmBtu/hr that combusts any type of fuel listed in Table C
- 1 of this subpart148

(except MSW), unless either of the following conditions apply: (A) The use of Tier 1 or 2 is permitted, as described in paragraphs (b)(1)(iii) , (b)(1)(v), and (b)(2)(ii) of this section. (B) The use of Tier 4 is required. (iii) Shall be used for a fuel not listed in Table C
1 of this subpart if the fuel is combusted in a unit with a maximum rated heat input capacity greater than 250 mmBtu/hr (or, pursuant to §98.36(c)(3), in a group of units served by a common supply pipe, having at least one unit with a maximum rated heat input capa city greater than 250 mmBtu/hr), provided that both of the following conditions apply: (A) The use of Tier 4 is not required. (B) The fuel provides 10% or more of the annual heat input to the unit or, if §98.36(c)(3)applies, to the group of units served by a common supply pipe. (iv) Shall be used when specified in another applicable subpart of this part, regardless of unit size. (4) The Tier 4 Calculation Methodology: (i) May be used for a unit of any size, combusting any type of fuel. Tier 4 may als o be used for any group of149

stationary fuel combustion units, process units, or manufacturing units that share a common stack or duct. (ii) Shall be used if the unit meets all six of the conditions specified in paragraphs (b)(4)(ii)(A) through (b)(4)(ii)(F ) of this section: (A) The unit has a maximum rated heat input capacity greater than 250 mmBtu/hr, or if the unit combusts municipal solid waste and has a maximum rated input capacity greater than 600 tons per day of MSW. (B) The unit combusts solid fossil fuel or MSW as the primary fuel. (C) The unit has operated for more than 1,000 hours in any calendar year since 2005. (D) The unit has installed CEMS that are required either by an applicable Federal or State regulation or the unit’s operating permit. (E) The installed CEMS include a gas monitor of any kind or a stack gas volumetric flow rate monitor, or both and the monitors have been certified, either in accordance with the requirements of part 75 of this chapter , part 60 of this chapter, or an applicable State continuous monitoring program. (F) The installed gas or stack gas volumetric flow rate monitors are required, either by an applicable Federal150

or State regulation or by the unit’s operating permit, to undergo periodic quality assurance testing in accordance with either appendix B to part 75 of this chapter , appendix F to part 60 of this chapter , or an applicable State continuous monitoring program. (iii) Shall be used for a unit with a maximum r ated heat input capacity of 250 mmBtu/hr or less and for a unit that combusts municipal solid waste with a maximum rated input capacity of 600 tons of MSW per day or less, if the unit meets all of the following three conditions: (A) The unit has both a stack gas volumetric flow rate monitor and a CO 2 concentration monitor. (B) The unit meets the conditions specified in paragraphs (b)(4)(ii)(B) through (b)(4)(ii)(D) of this section. (C) The CO 2 and stack gas volumetric flow rate monitors meet the conditions specified in paragraphs (b)(4)(ii)(E) and (b)(4)(ii)(F) of this section. (iv) May apply to common stack or duct configurations where: (A) The combined effluent gas streams from two or more stationary fuel combustion units are vented through a
mon itored common stack or duct. In this case, Tier 4 shall be used if all of the conditions in paragraph151

(b)(4)(iv)(A)( 1 ) of this section or all of the conditions in paragraph (b)(4)(iv)(A)( 2 ) of this section are met. ( 1 ) At least one of the units meets the requirements of paragraphs (b)(4)(ii)(A) through (b)(4)(ii)(C) of this section, and the CEMS installed at the common stack (or duct) meet the requirements of paragraphs (b)(4)(ii)(D) through (b)(4)(ii)(F) of this section . ( 2 ) At least one of the units and the monitors installed at the common stack or duct meet the requirements of paragraph (b)(4)(iii) of this section. (B) The combined effluent gas streams from a process or manufacturing unit and a stationary fuel combustion unit are vented through a monitored common stack or duct. In this case, Tier 4 shall be used if the combustion unit and the monitors installed at the common stack or duct meet the applicability criteria specified in paragraph (b)(4)(iv)(A)( 1 ), or (b)(4)(iv)(A)( 2 ) of this section. (C) The combined effluent gas streams from two or more manufacturing or process units are vented through a common stack or duct. In this case, if any of the units is required by an applicable subpart of this part to use Tier 4, the CO 2 mass emissions ma y either be monitored at each individual unit, or the combined CO 2 mass emissions may be monitored at the common stack or duct. However, if it is152

not feasible to monitor the individual units, the combined CO 2 mass emissions shall be monitored at the common stack or duct. (5) The Tier 4 Calculation Methodology shall be used : (i) Starting on January 1, 2010, for a unit that is required to report CO 2 mass emissions beginning on that date, if all of the monitors needed to measure CO 2 mass emissi ons have been installed and certified by that date. (ii) No later than January 1, 2011, for a unit that is required to report CO 2 mass emissions beginning on January 1, 2010, if all of the monitors needed to measure CO 2 mass emissions have not been insta lled and certified by January 1, 2010. In this case, you may use Tier 2 or Tier 3 to report GHG emissions for 2010. However, if the required CEMS are certified some time in 2010, you need not wait until January 1, 2011 to begin using Tier 4. Rather, you may switch from Tier 2 or Tier 3 to Tier 4 as soon as CEMS certification testing is successfully completed. If this reporting option is chosen, you must document the change in CO 2 calculation methodology in the Monitoring Pl an required under §98.3(g) (5) and in the GHG emissions report under §98.3(c). Data recorded by the CEMS during a certification test period in 2010 may be used for reporting153

under this part, provided that the following two conditions are met: (A) The certification tests are passed in sequence, with no test failures . (B) No unscheduled maintenance or repair of the CEMS is performed during the certification test period. (iii) No later than 180 days following the date on which a change is made that triggers Tier 4 applicability under paragraph (b)(4)(ii) or (b)(4)(iii) of this section (e.g., a change in the primary fuel, manner of unit operation, or installed continuous monitoring equipment). (6) You may elect to use any applicable higher tier for one or more of the fuels combusted in a unit. For example, if a 100 mmBtu/hr unit combusts natural gas and distillate fuel oil, you may elect to use Tier 1 for natural gas and Tier 3 for the fuel oil, even though Tier 1 could have been used for both fuels. However, for units that use either the Tier 4 or the alternative calculation methodology specified in paragraph (a)(5) (iii) of this section, CO 2 emissions from the combustion of all fuels shall be based solely on CEMS measurements. (c) Calculation of CH 4 and N 2 O emissions from stationa ry combustion sources . You must calculate annual CH 4 and N 2 O mass emissions only for units that are required154

to report CO 2 emissions using the calculation methodologies of this subpart and for only those fuels that are listed in Table C
- 2 of this subpart. (1) Use Equation C
- 8 of this section to estimate CH 4 and N 2 O emissions for any fuels for which you use the Tier 1 or Tier 3 calculation methodologies for CO 2 . Use the same values for fuel consumption that you use for the Tier 1 or Tier 3 cal culation. EF HHV Fuel x O N or CH * * * 10 1 3 2 4 

 (Eq. C
- 8) Where: CH 4 or N 2 O = Annual CH 4 or N 2 O emissions from the

combustion of a particular type of fuel (metric tons). Fuel = Mass or volume of the fuel combusted, either

from company records or directly measured by a fuel flow meter, as applicable (mass or volume per year). HHV = Default high heat value of the fuel from Table

C - 1 of this subpart ; alternatively, for Tier 3, if actual HHV data are available for the reporting year, you may average these data using the p rocedures specified in paragraph (a)(2)(ii) of this section, and use the average value in Equation C
- 8 (mmBtu per mass or volume). EF = Fuel
- specific default emission factor for CH 4

or N 2 O, from Table C
- 2 of this subpart (kg CH 4 or N 2 O per mmBtu). 1 x 10 - 3 = Conversion factor from kilograms to metric

tons. (2) Use Equation C
- 9a of this section to estimate CH 4 and N 2 O emissions for any fuels for which you use the Tier 2155

Equation C
- 2a of this section to estimate CO 2 emissions. Use the same values for fuel consumption and HHV that you use for the Tier 2 calculation.

Fuel EF HHV x O N or CH * * * 10 1 3 2 4 

 (Eq. C
- 9a) Where: CH 4 or N 2 O = Annual CH 4 or N 2 O emissions from the combustion

of a particular type of fuel (metric tons). Fuel = Mass or volume o f the fuel combusted during the

reporting year. HHV = High heat value of the fuel, averaged for all

valid measurements for the reporting year (mmBtu per mass or volume). EF = Fuel
- specific default emission factor for CH 4

or N 2 O, from Table C
- 2 of this subpart (kg CH 4 or N 2 O per mmBtu). 1 x 10 - 3 = Conversion factor from kilograms to metric

tons. (3) Use Equation C
- 9b of this section to estimate CH 4 and N 2 O emissions for any fuels for which you use Equation C - 2c of this section to calculate the CO 2 emissi ons. Use the same values for steam generation and the ratio “B” that you use for Equation C
- 2c.
EF B Steam x O N or CH    3 2 4 10

1 (Eq. C
- 9b) Where : CH 4 or N 2 O = Annual CH 4 or N 2 O emissions from the

combustion of a solid fuel (metric tons). Steam = Total mass of st eam generated by solid fuel

combustion during the reporting year (lb steam).156

B = Ratio of the boiler’s maximum rated heat input

capacity to its design rated steam output (mmBtu/lb steam). EF = Fuel
- specific emission factor for CH 4 or N 2 O,

from Table C
- 2 of this subpart (kg CH 4 or N 2 O per mmBtu). 1 x 10 - 3 = Conversion factor from kilograms to metric

tons. (4) Use Equation C
- 10 of this section for : units subject to subpart D of this part ; units that qualify for and elect to use the alternative CO 2 mass emissions calculation methodologies described in paragraph (a)(5) of this section; , and units that use the Tier 4 Calculation Methodology. 

###   EF HI O N or CH A *

* 001
. 0 2 4  (Eq. C
- 10) Where: CH 4 or N 2 O = Annual CH 4 or N 2 O emissions from the

combustion of a particular type of fuel (metric tons). (HI) A = Cumulative annual heat input from combustion

of the fuel (mmBtu). EF = Fuel
- specific emission factor for CH 4 or N 2 O,

from Table C
- 2 of this section (kg CH 4 or N 2 O per mmBtu). 0.001 = Conversion factor from kg to metric tons. (i) If only one type of fuel listed in Table C
- 2 of this subpart is combusted during the reporting year , substitute the cumulative annual heat input from combustion of the fuel into Equati on C - 10 of this section to calculate the annual CH 4 or N 2 O emissions. For units in the Acid157

Rain Program and units that report heat input data to EPA year - round according to part 75 of this chapter, obtain the cumulative annual heat input directly from the electronic data reports required under §75.64 of this chapter. For Tier 4 units, use the best available information, as described in paragraph (c)(4)(ii)(C) of this section, to estimate the cumulative annual heat input (HI) A . (ii) If more than one t ype of fuel listed in Table C
2 of this subpart is combusted during the reporting year , use Equation C
- 10 of this section separately for each type of fuel , except as provided in paragraph (c)(4)(ii)(B) of this section. Determine the appropriate values of (HI) A as follows: (A) For units in the Acid Rain Program and other units that report heat input data to EPA year
- round according to part 75 of this chapter, obtain (HI) A for each type of fuel from the electronic data reports required
under §75.64 of this chapter, except as otherwise provided in paragraphs (c)(4)(ii)(B) and (c)(4)(ii)(D) of this section. (B) For a unit that uses CEMS to monitor hourly heat input according to part 75 of this chapter, the value of (HI) A obtained from the electronic data reports under §75.64 of this chapter may be attributed exclusively to the fuel158

with the highest F
- factor, when the reporting option in 3.3.6.5 of appendix F to part 75 of this chapter is selected and implemented. (C) For Tier 4 units, us e the best available information (e.g., fuel feed rate measurements, fuel heating values, engineering analysis) to estimate the value of (HI) A for each type of fuel. Instrumentation used to make these estimates is not subject to the calibration requiremen ts of §98.3(i) or to the QA requirements of §98.34. (D) Units in the Acid Rain Program and other units that report heat input data to EPA year
- round according to part 75 of this chapter may use the best available information described in paragraph (c)(4) (ii)(C) of this section, to estimate (HI) A for each fuel type, whenever fuel
- specific heat input values cannot be directly obtained from the electronic data reports under §75.64 of this chapter. (5) When multiple fuels are combusted during the reporting year, sum the fuel
- specific results from Equations C
- 8, C
- 9a, C
- 9b, or C
- 10 of this section (as applicable) to obtain the total annual CH 4 and N 2 O emissions, in metric tons.159 (6) Calculate the annual CH 4 and N 2 O mass emissions from the combustion of blende d fuels as follows: (i) If the mass or volume of each component fuel in the blend is measured before the fuels are mixed and combusted, calculate and report CH 4 and N 2 O emissions separately for each component fuel, using the applicable procedures in thi s paragraph (c). (ii) If the mass or volume of each component fuel in the blend is not measured before the fuels are mixed and combusted, a reasonable estimate of the percentage composition of the blend , based on best available information, is require d. Perform the following calculations for each component fuel, “i”, that is listed in Table C
- 2: (A) Multiply (% Fuel) i , the estimated mass or volume percentage (decimal fraction) of component fuel “i”, by the total annual mass or volume of the blended fuel combusted during the reporting year, to obtain an estimate of the annual consumption of component “i”; (B) Multiply the result from paragraph (c)(6)(ii)(A) of this section by the HHV of the fuel (default value or, if available, the measured annual aver age value), to obtain an estimate of the annual heat input from component “i”;160 (C) Calculate the annual CH 4 and N 2 O emissions from component “i”, using Equation C
- 8, C
- 9a, or C
- 10 of this section, as applicable; (D) Sum the annual CH 4 emissions across al l component fuels to obtain the annual CH 4 emissions for the blend. Similarly sum the annual N 2 O emissions across all component fuels to obtain the annual N 2 O emissions for the blend. Report these annual emissions totals. (d) Calculation of CO 2 from so rbent . (1) When a unit is a fluidized bed boiler, is equipped with a wet flue gas desulfurization system, or uses other acid gas emission controls with sorbent injection to remove acid gases , if the chemical reaction between the acid gas and the sorbent produces CO 2 emissions, use Equation C
- 11 of this section to calculate the CO 2 emissions from the sorbent, except when those CO 2 emissions
are monitored by CEMS . When a sorbent other than CaCO 3 is used, determine site
- specific values of R and MWS .        
 S CO MW MW R S CO 2 2 *

* * 91
. 0 (Eq. C
- 11) Where: CO 2 = CO 2 emitted from sorbent for the reporting year

(metric tons). S = Limestone or other sorbent used in the reporting

year, from company records (short tons).161

R = The number of moles of CO 2 released upon capture of

one mole of the acid gas species being removed (R = 1.00 when the sorbent is CaCO 3 and the targeted acid gas species is SO 2 ) . MWCO2 = Molecular weight of carbon dioxide (44). MWS = Molecular weight of sorbent (100 if calcium

carbonate). 0.91 = Conversion factor from short tons to metric tons (2) The total annual CO 2 mass emissions reported for the unit shall include the CO 2 emissions from the combustion process and the CO 2 emissions from the sorbent. (e) Biogenic CO 2 emissions from combustion of biomass with other fuels . Use the applicable procedures of this paragraph (e) to estimate biogenic CO 2 emissions from units that combust a combination of biomass and fossil fuels (i.e., either co
- fired or blended fuels) . Separate
reporting of biogenic CO 2 emissions from the combined combustion of biomass and fossil fuels is required for those biomass fuels listed in Table C
- 1 of this section and for municipal solid waste . In addition, when a biomass fuel that is not listed in Table C
- 1 is combusted in a unit that has a maximum rated heat input greater than 250 mmBtu/hr, if the biomass fuel accounts for 10% or more of the annual heat input to the unit, and if the unit does not use CEMS to quantify its annual CO 2 mass emissions, then, pursuant to §98.33(b)(3)(iii), Tier 3 must be used to162

determine the carbon content of the biomass fuel and to calculate the biogenic CO 2 emissions from combustion o f the fuel. Notwithstanding these requirements, separate reporting of biogenic CO 2 emissions is optional for units subject to subpart D of this part and for units that use the CO 2 mass emissions calculation methodologies in part 75 of this chapter, pursuant to paragraph (a)(5) of this section ; however, if the owner or operator opts to report biogenic CO 2 emissions separately for these units, the appropriate method(s) in this paragraph (e) shall be used . Separate reporting of biogenic CO 2 emissions from the combustion of tires is also optional, but may be reported by following the provisons of paragraph (e)(3) of this section . (1) You may use Equation C
- 1 of this subpart to calculate the annual CO 2 mass emissions from the combustion of the biomass fuels listed in Table C
- 1 of this subpart (except MSW and tires ) , in a unit of any size , including units equipped with a CO 2 CEMS, except when the use of Tier 2 is required as specified in paragraph (b)(1)(iv) of this section . Determine the quantity of biomass combusted using one of the following procedures in this paragraph (e)(1), as appropriate , and document the selected procedures in the Monitoring P lan under §98.3(g) :1 63 (i) C ompany records. (ii) The p rocedures in paragraph (e)(5 ) of this section. (iii) The best available information for premixed fuels that contain biomass and fossil fuels (e.g., liquid fuel mixtures containing biodiesel) . (2) You may use the procedures of this paragraph if the following three conditions are met: first, a CO 2 CEMS (or a surrogate O 2 monitor) and a stack gas f low rate monitor are used to determine the annual CO 2 mass emissions ( either according to part 75 of this chapter , the Tier 4 Calculation Methodology, or the alternative calculation methodology specified in paragraph (a)(5)(iii) of this section) ; second, neither MSW nor tires is combusted in the unit during the reporting year; and third, the CO 2 emissions consist solely of combustion products (i.e., no process or sorbent emissions included). (i) For each operating hour , use Equation C
- 12 of this section to determine the volume of CO 2 emitted. 

##   h

h h h CO t

Q CO V *

* 100 % 2 2  (Eq. C
- 12) Where: VCO2h = Hourly volume of CO 2 emitted (scf). (%CO 2 ) h = Hourly average CO 2 concentration, measured by the

CO 2 concentration monitor, or, if applicable,164 calculated from the hourly average O 2 concentration (%CO 2 ). Qh = Hourly average stack gas volumetric flow rate,

measured by the stack gas volumetric flow rate monitor (scfh). t h = Source operating time (decimal fraction of the

hour during wh ich the source combusts fuel, i.e., 1.0 for a full operating hour, 0.5 for 30 minutes of operation, etc.). 100 = Conversion factor from percent to a decimal

fraction. (ii) Sum all of the hourly VCO2h values for the reporting year, to obtain Vtotal , the t otal annual volume of CO 2 emitted. (iii) Calculate the annual volume of CO 2 emitted from fossil fuel combustion using Equation C
- 13 of this section. If two or more types of fossil fuel are combusted during the year, perform a separate calculation with Equation C
- 13 of this section for each fuel and sum the results.

6 c ff 10 HHV

* F * Fuel V  (Eq. C
- 13) Where: Vff = Annual volume of CO 2 emitted from combustion of a

particular fossil fuel (scf). Fuel = Total quantity of the fossil fuel combusted in the

reporting year, from company records, as defined in §98.6 (lb for solid fuel, gallons for liquid fuel, and scf for gaseous fuel). F c = Fuel
- specific carbon based F
- factor, either a

default value from Table 1 in section 3.3.5 of appendix F to part 7 5 of this chapter, or a site
specific value determined under section 3.3.6 of appendix F to part 75 (scf CO 2 /mmBtu).165

HHV = High heat value of the fossil fuel, from fuel

sampling and analysis (annual average value in Btu/lb for solid fuel, Btu/gal f or liquid fuel and Btu/scf for gaseous fuel, sampled as specified (e.g., monthly, quarterly, semi
- annually, or by lot) in §98.34(a)(2)). The average HHV shall be calculated according to the requirements of paragraph (a)(2)(ii) of this section. 10 6 = Conversion factor, Btu per mmBtu. (iv) Subtract Vff from Vtotal to obtain Vbio , the annual volume of CO 2 from the combustion of biomass. (v) Calculate the biogenic percentage of the annual CO 2 emiss ions,expressed as a decimal fraction, using Equation C
- 14 of this section:

total bio V V Biogenic  % (Eq. C
- 14) (vi) Calculate the annual biogenic CO 2 mass emissions, in metric tons, by multiplying the results obtained from Equation C
- 14 of this section by the annual CO 2 mass emissions in metric tons, as determined: (A) Under paragraph (a)(4)(vi) of this section, for units using the Tier 4 Calculation Methodology. (B) Under paragraph (a)(5)(iii)(B) of this section, for units using the alternative calculation methodology specified in paragraph (a)(5)(iii). (C) From the electronic data report required under §75.64 of this chapter, for units in the Acid Rain Program and other units using CEMS to monitor and report CO 2 mass166

emissions according to part 75 of this chapter . However, before calculating the annual biogenic CO 2 mass emissions, multiply the cumulative annual CO 2 mass emissions by 0.91 to convert from short tons to metric tons. (3) You must use the procedures in paragraph s (e) (3) (i) through (e)(3)(iii) of this section to determine the annual biogenic CO 2 emissions from the combustion of MSW. These procedures also may be used for any unit that
co - fires biomass and fossil fuels, including units equipped with a CO 2 CEMS, and units for which optional separate reporting of biogenic CO 2 emissions from the combustion of tires is selected . (i) Use an applicable CO 2 emissions calculati on method in this section to quantify the total annual CO 2 mass emissions from the unit . ( ii ) Determine the relative proportions of biogenic and non
-biogenic CO 2 emissions in the flue gas on a quarterly basis using the method specified in §98.34(d) (for units that combust MSW as the primary fuel or as the only fuel with a biogenic component) or in §98.34(e) (for other units, including units that combust tires) . ( iii ) Determine the annual biogenic CO 2 mass emissions from the unit by multiplying the total annual CO 2 mass167

emissions by the annual average biogenic decimal fraction obtai ned from §98.34(d) or §98.34(e), as applicable . (4) [Reserved] (5) If Equation C
- 1 or Equation C
- 2a of this section is selected to calculate the annual biogenic mass emissions for wood, wood waste, or other solid biomass
- derived fuel, Equation C
- 15 of this section may be used to quantify biogenic fuel consumption, provided that all of the required input parameters are accurately quantified. Similar equations and calculation methodologies based on steam generation and boiler efficiency may be used, provided that they are documented in the GHG Monitoring Plan required by §98.3(g)(5).



##   

##    

   bio

bio nb p Eff

HHV HI S H Fuel 2000 *

  (Eq. C
- 15) Where: (Fuel) p = Quantity of biomass consumed during the

measurement period “p” (tons/year or tons/month, as applicable). H = Average enthalpy of the boiler steam for the

measurement period (Btu/lb). S = Total boiler steam production for the

measurement period (lb/month or lb/year, as applicable). (HI) nb = Heat input from co
- fired fossil fuels and

non -biomass
- derived fuels for the measurement period, based on company records of fuel usage and default or measured HHV168
values (Btu/month or Btu/year, as applicable). (HHV) bio = Default or measured high heat value of the

biomass fuel (Btu/lb). (Eff) bio = Percent efficiency of biomass
- to - energy

conversion, expressed as a decimal fraction. 2000 = Conversion factor (lb/ton). §98.34 Monitoring and QA/QC requirements. The CO 2 mass emissions data for stationary fuel combustion sources shall be monitored as follows: (a) For the Tier 2 Calculation Methodology: (1) All fuel samples shall be taken at a location in the fuel handling syst em that provides a sample representative of the fuel combusted. The fuel sampling and analysis may be performed by either the owner or operator or the supplier of the fuel. (2) The minimum required frequency of the HHV sampling and analysis for each type of fuel or fuel mixture (blend) is specified in this paragraph. When the specified frequency for a particular fuel or blend is based on a specified time period ( e . g ., week , month , quarter , or half
year ), fuel sampling and analysis i s required only for those time periods in which the fuel or blend is combusted . The owner or operator may perform fuel sampling and analysis more often than the minimum required frequency, in order to obtain a more representative annual average HHV.169 (i) For natural gas, semiannual sampling and analysis is required (i.e., twice in a calendar year, with consecutive samples taken at least four months apart). (ii) For coal and fuel oil, and for any other solid or liquid fuel that is delivered in lots, analysis of at least one representative sample from each fuel lot is required. For fuel oil, as an alternative to sampling each fuel lot, a sample may be taken upon each addition of oil to the unit’s storage tank . F low proportional sampling,
continuous drip sampling, or daily manual oil sampling may also be used, in lieu of sampling each fuel lot . For the purposes of this section, a fuel lot is defined as either: (A) A shipment or delivery of a single fuel (e.g., ship load, barge load, group of trucks, group of railroad cars, oil delivery via pipeline from a tank farm, etc.) ; or (B) If multiple deliveries of a particular type of fuel are received from the same supply source in a given calendar month, the deliveries for that month are consi dered, collectively, to comprise a fuel lot, requiring only one representative sample. (iii) For liquid fuels other than fuel oil, and for gaseous fuels other than natural gas (including biogas ), sampling and analysis is required at least once per170

calendar quarter. To the extent practicable, consecutive quarterly samples shall be taken at least 30 days apart. (iv) For other solid fuels (except MSW ) , weekly sampling is required to obtain composite samples, which are then analyzed monthly. (v) For fuel blends that are received already mixed, as described in paragraph (a)(3)(ii) of this section, determine the HHV of the blend as follows. For blends of solid fuels (except MSW), weekly sampl ing is required to obtain composite samples, which are analyzed monthly. For blends of liquid or gaseous fuels, sampling and analysis is required at least once per calendar quarter. More frequent sampling is recommended if the composition of the blend
va ries significantly during the year. (3) Special Considerations for Blending of Fuels. In situations where different types of fuel listed in Table C
1 of this subpart (for example, different ranks of coal or different grades of fuel oil) are in the same state of matter (i.e., solid, liquid, or gas), and are blended prior to combu stion, use the following procedures to determine the appropriate CO 2 emission factor and HHV for the blend. (i) If the fuels to be blended are received separately, and if the quantity (mass or volume) of each fuel is measured before the fuels are mixed and combusted,171

then, for each component of the blend, calculate the CO 2 mass emissions separately. Substitute into Equation C
- 2a of this subpart the total measured mass or volume of the component fuel (from company records), together with the appropriate default CO 2 emission factor from Table C
- 1, and the annual average HHV, calculated according to §98.33(a)(2)(ii). In this case, the fact tha t the fuels are blended prior to combustion is of no consequence . (ii) If the fuel is received as a blend (i.e., already mixed), a reasonable estimate of the relative proportions of the comp onents of the blend must be made, using the best available information (e.g., the approximate annual average mass or volume percentage of each fuel, based on the typical or expected range of values). Determine the appropriate CO 2 emission factor and HHV fo r use in Equation C
- 2a of this subpart, as follows: (A) Consider the blend to be the “fuel type,” measure its HHV at the frequency prescribed in paragraph (a)(2)(v) of this section, and determine the annual average HHV value for the blend according to §98 .33(a)(2)(ii). (B) Calculate a heat
-weighted CO 2 emission factor, (EF) B , for the blend, using Equation C
- 16 of this section. The heat
-weighting in Equation C
- 16 is provided by the172

default HHVs (from Table C
- 1) and the estimated mass or volume percentages of the components of the blend. (C) Substitute into Equation C
- 2a of this subpart, the annual average HHV for the blend (from paragraph (a)(3)(ii)(A) of this section) and the calculated value of (EF) B , along with the total mass or volume of the blend combusted during the reporting year, to determine the annual CO 2 mass emissions from combustion of the blend. 

##   

##  

B n
i i i i B HHV EF

Fuel HHV EF )

( )

( % ) ( ) ( 1 

## 

  ( Eq. C - 16) Where: (EF) B = Heat -weighted CO 2 emission factor for the blend

(kg CO 2 /mmBtu) (HHV) I = Default high heat value for fuel “i” in the

blend, from Table C
- 1 (mmBtu per mass or volume) (%Fuel) I = Estimated mass or volume percentage of fuel “i”

(mass % or volume %, as applicable, expressed as a decimal fraction; e.g., 25% = 0.25) (EF) I = Default CO 2 emission factor for fuel “i” from

Table C
- 1 (mmBtu per mass or volume) (HHV) B = Annual average high heat value for the blend,

calculated according to §98.33(a)(2)(ii) (mmBtu per mass or volume) (iii) Note that for the case described in paragraph (a)(3)(ii) of this sect ion, if measured HHV values for the individual fuels in the blend or for the blend itself are173

not routinely received at the minimum frequency prescribed in paragraph (a)(2) of this section (or at a greater frequency), and if the unit qualifies to use Tier 1, calculate (HHV) B * , the heat
-weighted default HHV for the blend, using Equation C
- 17 of this section. Then, use Equation C
- 16 of this section, replacing the term (HHV) B with (HHV) B * in the denominator, to determine the heat
weighted CO 2 emission factor for the blend. Finally, substitute into Equation C
- 1 of this subpart, the calculated values of (HHV) B * and (EF) B , along with the total mass or volume of the blend combusted during the reporting year, to determine the annual CO 2 mass emissions from combust ion of the blend. 

##   

##   

## 

  n
i i

i B Fuel HHV HHV 1

* %

) ( (Eq. C
- 17) Where: (HHV) B * = Heat -weighted default high heat value for the

blend (mmBtu per mass or Volume) (HHV) I = Default high heat value for fuel “i” in the

blend, from Table C
- 1 (mmBtu per mass or volume) (%Fuel) I = Estimated mass or volume percentage of fuel “i”

in the blend (mass % or volume %, as applicable, expressed as a decimal fraction) (iv) If the fuel blend described in paragraph (a)(3)(ii) of this section consists of a mixture of fuel(s) listed in Table C
- 1 of this subpart and one or more fuels174

not listed in Table C
- 1, calculate CO 2 and other GHG emissions only for the Table C
- 1 fuel(s), using the best available estimate of the mass or volume percentage(s) of the Table C
- 1 fuel(s) in the blend. In this case, Tier 1 shall be used, with the following modifications to Equations C
- 17 and C
- 1, to account for the fact that not all of the fuels in the blend are listed in Table C
- 1: (A) In Equation C
- 17, apply the term (Fuel) i only to the Table C
- 1 fuels. For each Table C
- 1 fuel, (Fuel) i will be the estimated mass or volume percentage of the fuel in the blend, divided by the sum of the mass or volume percentages of the Table C
- 1 fuels. For example, suppose that a blend consists of two Table C
- 1 fuels (“A” and “B”) and one fuel type (“C”) not listed in the Table, and that the volume percentages of fuels A, B, and C in the blend, expressed as decimal fractions, are, respectively, 0.50, 0.30, and 0.20. The term (Fuel) i in Equation C
- 17 for fuel A will be 0.50/(0.50 + 0.30) = 0.625, and for fuel B, (Fuel) i will be 0.30/(0.50 + 0.30) = 0.375. (B) In Equation C
- 1, the term “Fuel” will be equal to the total mass or volume of the blended fuel combusted during the year multiplied by the sum of the mass or vol ume percentages of the Table C
- 1 fuels in the blend. For the175

example in paragraph (a)(3)(iv)(A) of this section, “Fuel” = (Annual volume of the blend combusted)(0.80). (4) If, for a particular type of fuel, HHV sampling and analysis is performed more often than the minimum frequency specified in paragraphs (a)(2)of this section, the results of all valid fuel analyses shall be used in the GHG emission calculations. (5) If, for a particular type of fuel, valid HHV values are obtained at less than the minimum frequency specifed in paragraphs (a)(2) of this section, appropriate substitute data values shall be used in the emissions calculations, in accordance with missing data procedures of §98.35. (6) You must u se one of the following appropriate fuel sampling and analysis methods. You may use a method published by a consensus standards organization if such a method exists, or you may use industry consensus standard practice to determine the high heat values. Consensus
based standards organizations incl ude, 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).176

Alternatively, for gaseous fuels, the HHV may be calculated using chromatographic analysis together with standard heating values of the fuel constituents, provided that the gas chromatograph is operated, maintained, and calibrated according to the manufacturer’s instructions. The method(s) used shall be documented in the Monitoring P lan required unde r §98.3(g)(5). (b) For the Tier 3 Calculation Methodology: (1) You must calibrate each oil and gas flow meter according to §9 8.3(i) and the provisions of this paragraph (b) (1) . (i) Perform calibrations using any of the test methods and procedures in this paragraph (b)(1)(i) . The method(s) used shall be documented in the Monitoring P lan required under §98.3(g)(5). (A) You may use an appropriate flow meter calibration method published by a consensus standards organization, if such a method exists. Consensus
-based standards organizations include, but are not limited to, the following: ASTM International, the American National S tandards 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).177 (B) You may use the calibration procedures specified by the flow meter manufacturer. (C) You may use an industry
- accepted or industry
consensus standard calibration practice. (ii) In addition to the initial calibration required by §98.3(i), recalibrate each fuel flow meter (except as otherwise provided in paragraph (b)(1)(iii) of this section) either annually, at the minimum frequency specified by the manufa cturer, or at the interval specified by industry consensus standard practice . (iii) Fuel billing meters are exempted from the initial and ongoing calibration requirements of this paragraph and from the Monitoring P lan and recordkeeping requiremen ts of §98.3(g)(5)(i)(C) and (g)(7) , provided that the fuel supplier and the 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 only used for unit startup or ignition are also exempted from the initial and ongoing calibration requirements of this paragraph. (iv) For the initial calibration of an orifice, nozzle, or venturi meter; in
- situ calibration of the transmitter s is sufficient. A primary element inspection (PEI) shall be performed at least once every three years.178 (v) For the continuously
- operating units and processes described in §98.3(i)(6), the required flow meter recalibrations and, if necessary, the PEIs may be postponed until the next scheduled maintenance outage. (vi) If a mixture of liquid or gaseous fuels is transported by a common pipe , you may either separately meter each of the fuels prior to mixi ng , using flow meters calibrated according to §98.3(i), or consider the fuel mixture to be the “fuel type” and meter the mixed fuel, using a flow meter calibrated according to §98.3(i) . (2) Oil tank drop measurements (if used to determine liquid fuel use volume) shall be performed according to any an appropriate method published by a consensus
-based standards organization (e.g., the American Petroleum Institute). (3) The carbon content and, if applicable, molecular weight of the fuels shall be determined according to the procedures in paragraph (b)(3). (i) All fuel samples shall be taken at a location in the fuel handling system that provides a sample representative of the fuel combusted. The fuel s ampling and analysis may be performed by either the owner or operator or by the supplier of the fuel.179 (ii) For each type of fuel, the minimum required frequency for collect ing and analyzing samples for carbon content and (i f applicable) molecular weight is specified in this paragraph. When the sampling frequency is based on a specified time period (e.g., week , month , quarter , or half
- year ), fuel sampling and analysis is required for only those time periods in which the fuel is combusted . (A) For natural gas, semiannual sampling and analysis is required (i.e., twice in a calendar year, with consecutive samples taken at least four months apart). ( B) For coal and fuel oil and for any other solid or liquid fuel that is delivered in lots , analysis of at least one representative sample from each fuel lot is required. For fuel oil, as an alternative to sampling each fuel lot, a sample may be taken upn each addition of oil to the storage tank. Flow proportional sampling, continuous drip sampling, or daily manual oil sampling may also be used, in lieu of sampling each fuel lot. For the purposes of this section, a fuel lot is defined as either of the fo llowing : (1 ) A shipment or delivery of a single fuel (e.g., ship load, barge load, group of trucks, group of railroad cars, oil delivery via pipeline from a tank farm, etc.) . ( 2 ) If multiple deliveries of a particular type of fuel are received from the same supply source in a given180

calendar month, the deliveries for that month are considered, collectively, to comprise a fuel lot, requiring only one representative sample. (C) For liquid fuels other than fuel oil and for biogas; sampling and analysis is required at least once per calendar quarter. To the extent practicable, consecutive quarterly samples shall be taken at least 30 days apart. (D) For other solid fuels (except MSW) , weekly
s ampling is required to obtain composite samples, which are then analyzed monthly. (E) For gaseous fuels other than natural gas and biogas (e.g., process gas), daily sampling and analysis to determine the carbon content and molecular weight of the fuel is required if continuous, on
- line equipment , such as a gas chromatograph, is in place to make these measurements. Otherwise, weekly sampling and analysis shall be performed. (F) For mixtures (blends) of solid fuels, weekly sampli ng is required to obtain composite samples, which are analyzed monthly. For blends of liquid fuels, and for gas mixtures consisting only of natural gas and biogas, sampling and analysis is required at least once per calendar quarter. For gas mixtures tha t contain gases other than natural gas (including biogas), daily sampling181

and analysis to determine the carbon content and molecular weight of the fuel is required if continuous, on
- line equipment is in place to make these measurements. Otherwise, weekly sampling and analysis shall be performed. (iii) If, for a particular type of fuel, sampling and analysis for carbon content and molecular weight is performed more often than the minimum frequency specified in paragraph (b)(3) of this section, the results of all valid fuel analyses shall be used in the GHG emission calculations. (iv) If, for a particular type of fuel, sampling and analysis for carbon content and molecular weight is performed at less than the minimum frequency specifed in paragraph (b)(3) of this section, appropriate substitute data values shall be used in the emissions calculations, in accordance with the missing data procedures of §98.35. (v) To calculate the CO 2 mass emissions from combustion of a blend of fuels in the same state of mat ter (solid, liquid, or gas), you may either: (A) Apply Equation C
- 3, C
- 4 or C
- 5 of this subpart (as applicable) to each component of the blend, if the mass or volume, the carbon content, and (if applicable), the molecular weight of each component are accu rately measured prior to blending; or182 (B) Consider the blend to be the “fuel type”. Then, at the frequency specified in paragraph (b)(3)(ii)(F) of this section, measure the carbon content and, if applicable, the molecular weight of the blend and calcula te the annual average value of each parameter in the manner described in §98.33(a)(2)(ii). Also measure the mass or volume of the blended fuel combusted during the reporting year. Substitute these measured values into Equation C
- 3, C - 4, or C
- 5 of this subpart (as applicable). ( 4 ) You must use one of the following appropriate fuel sampling and analysis methods. You may use a method published by a consensus standards organization if such a method exists, or you may use industry consensus standard practice to determine the carbon content and molecular weight (for gaseous fuel) of the fuel. 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). Alternatively, the results of chromatographic analysis of the fuel may be used, provided that the gas chromatograph is operated, maintained, and calibrated according to the manufacturer’s183

instructions. The method(s) used shall be documented in the Monitoring Plan required under §98.3(g)(5). (c) For the T ier 4 Calculation Methodology, the CO 2 , flow rate , and (if applicable) moisture monitors must be certified prior to the applicable deadline specified in §98.33(b)(5). (1) For initial certification, you may use any one of the following three procedures in this paragraph. (i) Sections 75.20(c)(2) , (c) (4) , and (c)(5) though (c)(7) of this chapter and appendix A to part 75 of this chapter . (ii) The calibration drift test and relative accuracy test audit (RATA) procedures of Performance Spec ification 3 in appendix B to part 60 of this chapter (for the CO 2 concentration monitor) and Performance Specification 6 in appendix B to part 60 of this chapter (for the continuous emission rate monitoring system (CERMS)). (iii) The provisions of an app licable State continuous monitoring program. (2) If an O 2 concentration monitor is used to determine CO 2 concentrations, the applicable provisions of part 75 of this chapter , part 60 of this chapter , or an applicable State continuous monitor ing program shall be followed for initial certification and on
- going quality184

assurance, and all required RATAs of the monitor shall be done on a percent CO 2 basis. (3) For ongoing quality assurance, follow the applicable procedures in either appendix B to part 75 of this chapter , appendix F to part 60 of this chapter , or an applicable State continuous monitoring program. If appendix F to part 60 of this chapter is selected for on
going quality assurance, perform daily calibration drift assessments for both the CO 2 monitor (or surrogate O 2 monitor) and the flow rate monitor, conduct cylinder gas audits of the CO 2 concentration monitor in three of the four quarters of each year (except for non
- operating quarters), and perform annual RATAs of the CO 2 concentration monitor and the CERMS. (4) For the purposes of this part, the stack gas volumetric flow rate monitor RATAs required by appendix B to part 75 of this chapter and the annual RATAs of the CERMS required by appendix F t o part 60 of this chapter need only be done at one operating level, representing normal load or normal process operating conditions, both for initial certification and for ongoing quality
assurance. (5) If, for any source operating hour, quality
as sured data are not obtained with a CO 2 monitor (or185

surrogate O 2 monitor), flow rate monitor, or (if applicable) moisture monitor, use appropriate substitute data values in accordance with the missing data provisions of §98.35. (6) For certain application s where combined process emissions and combustion emissions are measured, the CO 2 concentrations in the flue gas may be considerably higher than for combustion emissions alone. In such cases, the span of the CO 2 monitor may, if necessary, be set higher than the specified levels in the applicable regulations. If the CO 2 span value is set higher than 20 percent CO 2 , the cylinder gas audits of the CO 2 monitor under appendix F to part 60 of this chapter may be performed at 40 to 60 percent and 80 to 100 perce nt of span, in lieu of the prescribed calibration levels of 5 to 8 percent CO 2 and 10 to 14 percent CO 2 . (7) Hourly average data from the CEMS shall be validated in a manner consistent with one of the following: §§60.13(h)(2)(i) through (h)(2)(vi) of thi s chapter; §75.10(d)(1) of this chapter; or the hourly data validation requirements of an applicable State CEM regulation. (d) When municipal solid waste (MSW) is either the primary fuel combusted in a unit or the only fuel with a biogenic component combusted in the unit , determine the biogenic portion of the CO 2 emissions using ASTM D6866
- 08186

Standard Test Methods for Determining the Biobased Content of Solid, Liquid, and Gaseous Samples Using Radiocarbon Analysis (incorporated by reference, see §98.7) and 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 (incorporated by reference, see §98.7). Pe rform the ASTM D7459
- 08 sampling and the ASTM D6866
- 08 analysis at least once in every calendar quarter in which MSW is combusted in the unit. Collect each gas sample during normal unit operating conditions for a t least 24 consecutive hours or for as long as is deemed necessary to obtain a representative sample . One suggested alternative sampling approach would be to collect an integrated sample by extract ing a small amount of flue gas (e.g., 1 to 5 cc) in each unit operating hour during the quarter. Separate the total annual CO 2 emissions into the biogenic and non
biogenic fraction s using the average proportion of biogenic emissions of all samples analyze d during the reporting year. Express the results as a decimal fraction (e.g., 0.30, if 30 percent of the CO 2 is biogenic). When MSW is the primary fuel for multiple units at the facility, and the units are fed from a common fuel source , testing at only one of the units is sufficient.187 (e) For other units that combust combination s of biomass fuel(s) (or heterogeneous fuels that have a biomass component, e.g., tires) and fossil (or other non
-biogenic) fuel (s) , in any proportions, ASTM D6866
- 08 and ASTM D7459
- 08 may be used to determine the biogenic portion of the CO 2 emi ssions. Perform the ASTM D7459
- 08 sampling and the ASTM D6866
- 08 analysis in every calendar quarter in which biomass and non
-biogenic fuels are co
- fired in the unit. Collect each gas sample using ASTM D7459
- 08 during normal unit operation for at least 24 consecutive hours or for as long as is necessary to obtain a repres entative sample . If the types of fuels combusted in the unit and their relative proportions are not consistent throughout the quarter, more frequent, periodic sampling of the flue gas should be
cons idered. For example, an integrated sample could be collected by extracting a small amount of the flue gas (e.g., 1 to 5 cc) in each unit operating hour of the quarter. If the primary fuel for multiple units at the facility consists of tires, and the unit s are fed from a common fuel source, testing at only one of the units is sufficient. (f) The records required under §98.3(g) (2)(i) shall include an explanation of how the following parameters are188

determined from company records (or, if applicable, from the best available information) : (1) Fuel consumption, when the Tier 1 and Tier 2 Calcula tion Methodologies are used , including cases whe re §98.36(c)(4) applies . (2) Fuel consumption, when solid fuel is combusted and the Tier 3 Calculation Methodology is used. (3) Fossil fuel consumption when §98.33(e) (2) applies to a unit that uses CEMS to quantify CO 2 emissions and that combusts both fossil and biomass fuels. (4) Sorbent usage, when §98.33(d) applies. (5) Quantity of steam generated by a unit when §98.33(a)(2) (iii) applies. (6) Biogenic fuel consumption under §98.33(e)(5). (7) Fuel usage for CH 4 and N 2 O emis s ions calculations under §98.33(c)(4)(ii). (8) Mass of biomass combusted, for premixed fuels that contain biomass and fossil fuels under §98.33(e)(1)(iii). §98.35 Procedures for estimating missing data. Whenever a quality
- assured value of a required parameter is unavailable (e.g., if a CEMS malfunctions during unit operation or if a required fuel sample is not189

taken), a substitute data value for the missing parameter shall be used in the cal culations. (a) For all units subject to the requirements of the Acid Rain Program, and all other stationary combustion units subject to the requirements of this part that monitor and report emissions and heat input data in accordance with part 75 of this chapter , the missing data substitution procedures in part 75 of this chapter shall be followed for CO 2 concentration, stack gas flow rate, fuel flow rate, high heating value, and fuel carbon content. (b) For units that use the Tier 1, Ti er 2, Tier 3, and Tier 4 Calculation Methodologies, perform missing data substitution as follows for each parameter: (1) For each missing value of the high heating value, carbon content, or molecular weight of the fuel, substitute the arithmetic average of the quality
- assured values of that parameter immediately preceding and immediately following the missing data incident. If the “after” value has not been obtained by the time that the GHG emissions report is due, you may use the “before” value for mis sing data substitution or the best available estimate of the parameter, based on all available process data (e.g., electrical load, steam production, operating hours). If, for a particular parameter, no quality
- assured data are190

available prior to the miss ing data incident, the substitute data value shall be the first quality
- assured value obtained after the missing data period. (2) For missing records of CO 2 concentration, stack gas flow rate, percent moisture, fuel usage, and sorbent usage, the substitute data value shall be the best available estimate of the parameter, based on all available process data (e.g., electrical load, steam production, operating hours, etc.). You must document and retain records of the procedures used for all such estimates. §98.36 Data reporting requirements. (a) In addition to the facility
- level information required under §98.3, the annual GHG emissions report shall contain the unit
- level or process
- level emissions data in paragraphs (b) through (d) of this section (as applicable) and the emissions verification data in paragraph (e) of this section. (b) Units that use the four tiers . You shall report the following information for stationary combustion units that use the Tier 1, Tier 2, Tier 3, or Tier 4 methodology in §98.33(a) to calculate CO 2 emissions, except as otherwise provided in paragraphs (c) and (d) of this section: (1) The unit ID number. (2) A code representing the type of unit.191 (3) Maximum rated heat input capacity of the unit, in mmBtu/hr for boilers and process heaters only and relevant units of measure for other combustion sources. (4) Each type of fuel combusted in the unit during the report year. (5) The methodology (i.e., tier ) used to calculate the CO 2 emissions for each type of fuel combusted ( i.e., Tier 1, 2, 3, or 4). (6) The methodology start date, for each fuel type. (7) The methodology end date, for each fuel type. ( 8 ) For a unit that uses Tiers 1, 2, or 3 : (i) The annual CO 2 mass emissions (including biogenic CO 2 ), and the annua l CH 4 , and N 2 O mass emissions for each type of fuel combusted during the reporting year , expressed in metric tons of each gas and in metric tons of CO 2 e ; and (ii) Metric tons of biogenic CO 2 emissions (if applicable) . ( 9 ) For a unit that uses Tier 4: ( i) If the total annual CO 2 mass emissions measured by the CEMS consists entirely of non
-biogenic CO 2 (i.e., CO 2 from fossil fuel combustion plus, if applicable, CO 2 from sorbent and/or process CO 2 ), report the total annual CO 2 mass emissions, expressed in metric tons. You are not192

required to report the combustion CO 2 emissions by fuel type . (ii) If the total annual CO 2 mass emissions measured by the CEMS includes both biogenic and non
-biogenic CO 2 , separately report the annual non
-biogenic CO 2 mass emissions and the annual CO 2 mass emissions from biomass combustion, each expressed in metric tons. You are not required to report the combustion CO 2 emissions by fuel type . (iii) An estimate of the heat input from each type of fuel listed in Table C
- 2 of this subpart that was combusted in the unit during the report year, and the annual CH 4 and N 2 O emissions for each of these fuel s , expressed i n metric tons of each gas and in metric tons of CO 2 e. ( 10 ) Annual CO 2 emissions from sorbent (if calculated using Equation C
- 11 of this subpart), expressed in metric tons. (c) Reporting alternatives for units using the four Tiers . You may use any of the applicable reporting alternatives o f this paragraph to simplify the unit
- level reporting required under paragraph (b) of this section: (1) Aggregation of units . If a facility contains two or more units (e.g., boilers or combustion turbines), each of which has a maximum rated heat input capacity of 250 mmBtu/hr or less, you may report the combined GHG emissions193

for the group of units in lieu of reporting GHG emissions from the individual units, provided that the use of Tier 4 is not required or elected for any of the units and the units use the same tier for any common fuels combusted. If this option is selected, the following information shall be reported instead of the information in paragraph (b) of this section: (i) Group ID number, beginning with the prefix “GP”. (ii) The number of unit s in the group. (iii) Cumulative maximum rated heat input capacity of the group (mmBtu/hr). (iv) The highest maximum rated heat input capacity of any unit in the group (mmBtu/hr). (v) Each type of fuel combusted in the group of units during the reporting year. (vi) Annual CO 2 mass emissions and annual CH 4 , and N 2 O mass emissions aggregated for each type of fuel combusted in the group of units during the report year, expressed in metric tons of each gas and in metric tons of CO 2 e. If any of the units burn both fossil fuels and biomass, report also the annual CO 2 emissions from combustion of all fossil fuels combined and annual CO 2 emissions from combustion of all biomass fuels combined, expressed in metric tons.194 (vii) The methodology (i.e., tier ) used to calculate the CO 2 mass emissions for each type of fuel combusted in the units (i.e., Tier 1, Tier 2, or Tier 3). (viii) The methodology start date, for each fuel type. (ix) The methodology end date, for each fuel type. ( x ) The calculated CO 2 mass emissions (if any) from sorbent expressed in metric tons . (2) Monitore d common stack or duct configurations . When the flue gases from two or more stationary fuel combustion units at a facility are combined together in a common stack or duct before exiting to the atmosphere and if CEMS are used to continuou sly monitor CO 2 mass emissions at the common stack or duct according to the Tier 4 Calculation Methodology, you may report the combined emissions from the units sharing the common stack or duct, in lieu of separately reporting the GHG emissions from the individual units. This monitoring and reporting alternative may also be used when process off
- gases or a mixture of combustion products and process gases are combined together in a common stack or duct before exiting to the atmosphere. Whenever the common stack or duct monitoring option is applied, the following information195

shall be reported instead of the information in paragraph (b) of this section: (i) Common stack or duct identification number, beginning with the prefix “CS”. (ii) Number of units sharing the common stack or duct. Report “1” when the flue gas flowing through the common stack or duct includes both combustion products and process off
- gases, and all of the effluent comes from a single unit (e.g., a furnace, kiln, or smelter). (iii) Combined maximum rated heat input capacity of the unit s sharing the common stack or duct (mmBtu/hr). This data element is required only when all of the units sharing the common stack are stationary fuel combustion units. (iv) Each type of fuel combusted in the units during the year . (v) The methodology (tier) used to calculate the CO 2 mass emissions, i.e., Tier 4. (vi) The methodology start date. (vii) The methodology end date. ( viii ) Total annual CO 2 mass emissions measured by the CEMS, expressed in metric tons. If any of the units burn both fossil fuels and biomass, separately report the annual
non -biogenic CO 2 mass emissions (i.e., CO 2 from fossil fuel196

combustion plus, if applicable, CO 2 from sorbent and/or process CO 2 ) and the annual CO 2 mass emissions from biomass combustion , each expressed in metric tons. ( ix ) An estimate of the heat input from each type of fuel listed in Table C
- 2 of this subpart that was combusted during the report year in the units sharing the common stack or duct during the report year, and, for each of these fuels, the annual CH 4 and N 2 O mass emissions from the units sharing the common st ack or duct, expressed in metric tons of each gas and in metric tons of CO 2 e. (3) Common pipe con figurations . When two or more liquid
- fired or gaseous
- fired stationary combustion units at a facility combust the same type of fuel and the fuel is fed to the individual units through a common supply line or pipe, you may report the combined emissions fr om the units served by the common supply line, in lieu of separately reporting the GHG emissions from the individual units, provided that the total amount of fuel combusted by the units is accurately measured at the common pipe or supply line using a fuel flow meter . For Tier 3 applications, the flow meter shall be calibrated in accordance with §98.34(b) . If a portion of the fuel measured at the main supply line is diverted to either: a flare; or another stationary fuel combu stion unit (or units), including units197

that use a CO 2 mass emissions calculation method in part 75 of this chapter; or a chemical or industrial process ( where it is used as a raw material but not combusted ) , and the remainder of the fuel is distributed to a group of combustion units for which you elect to use the common pipe reporting option, you may use company records to subtract out the diverted portion of the fuel from the fuel measured at the main supply line prior to performing the GHG emis sions calculations for the group of units using the common pipe option . If the diverted portion of the fuel is combusted, the GHG emissions from the dive rted portion shall be accounted for in accordance with the applicable provisions of this part. When the common pipe option is selected, the applicable tier shall be used based on the maximum rated heat input capacity of the largest unit served by the common pipe configuration , except where the applicable tier is based on criteria other than unit size. For example, if the maximum rated heat input capacity of the largest unit is greater than 250 mmBtu/hr, Tier 3 will apply, unless the fuel transported through the common pipe is natural gas or distillate oil, in which case Tier 2 may be used, in accordance with §98.33(b)(2)(ii) . As a second example, in accordance with §98.33(b)(1)(v), Tier 1 may be used regardless of unit size when natural gas is198

transported through the common pipe, if the annual fuel consumption is obtained from gas billing records in units of therms. When the common pipe reporting option is selected, the following information shall be reported instead of the information in paragraph (b) of this section: (i) Common pipe identification number, beginning with the prefix “CP”. (ii) The number of units served by the common pipe. (iii) The highest maximum rated heat input capacity of any unit served by the common pipe (mmBtu/hr). (iv) The fuels combusted in the units during the reporting year . (v) The methodology used to calculate the CO 2 mass emissions (i.e., Tier 1, Tier 2, or Tier 3). (vi) If the any of the units burns both fossil fuels and biomass, the annual CO 2 mass emissions from combustion of all fossil fuels and annual CO 2 emissions from combustion of all biomass fuels from the units served by the common pipe, expressed in metric tons. (vii) Annual CO 2 mass emissions and annual CH 4 and N 2 O emissions from ea ch fuel type for the units served by the common pipe, expressed in metric tons of each gas and in metric tons of CO 2 e.199 (viii) Methodology start date (ix) Methodology end date (4) The following alternative reporting option applies to situations where a common liquid or gaseous fuel supply is shared between one or more large combustion units, such as boilers or combustion turbines (including units subject to subpart D of this part); and small combustion sources on
- site, including but not limited to space heaters and hot water heaters . In this case, you may simplify reporting by attributing all of the GHG emissions from combustion of the shared fuel to the large combustion unit(s), provided that: (i) The total quantity of the fuel combusted during the report year in the units sharing the fuel supply is measured, either at the “ga te” to the facility or at a point inside the facility, using a fuel flow meter, billing meter, or tank drop measurements (as applicable); (ii) On an annual basis, at least 95 percent (by mass or volume) of the shared fuel is combusted in the large combus tion unit(s), and the remainder is combusted in the small combustion sources. Company records may be used to determine the percentage distribution of the shared fuel to the large and small units; and200 (iii) The use of this reporting option is documented i n the Monitoring P lan required under §98.3(g)(5). Indicate in the Monitoring P lan which units share the common fuel supply and the method used to demonstrate that this alternative reporting option applies. For the small combustion sources on
- site, a des cription of the types of units and the approximate number of units is sufficient. (d) Units subject to part 75 of this chapter . (1) For stationary combustion units that are subject to subpart D of this part , you shall report the following unit
- level information: (i) Unit or stack identification numbers. Use exact same unit, common stack, common pipe, or multiple stack identification numbers that represent the monitored locations (e.g., 1, 2, CS001, MS1A, CP001, etc.) that are reported under §75.64 of this chapter. (ii) Annual CO 2 emissions at each monitored location, expressed in both short t ons and metric tons. Reporting of biogenic CO 2 emissions under §98.3(c)(4)(ii) and §98.3(c)(4)(iii)(A) is optional. Subpart D units are not required to report biogenic CO 2 emissions under §§98.3(c)(4)(ii) and (c)(4)(iii)(A). ( iii ) Annual CH 4 and N 2 O emissions at each monitored location, for each fuel type listed in Table C
- 2 that was201

combusted during the year (except as otherwise provided in §98.33(c)(4)(ii)(B)), expressed in metric tons of CO 2 e. (iv) The total heat input from each fuel listed in Table C
- 2 that was combusted during the year (except as otherwise provided in §98.33(c)(4)(ii)(B)) , expressed in mmBtu. ( v ) Identification of the Part 75 methodology used to determine the CO 2 mass emissions. (vi) Methodology start date. (vii) Methodology end date. (viii) Acid Rain Program indicator. (ix) Annual CO 2 mass emissions from the combustion of biomass , expressed in metric tons of CO 2 e (optional). (2) For units that use the alternative CO 2 mass emissions calculation methods provided in §98.33(a)(5), you shall report the following unit
- level information: (i) Unit, stack, or pipe ID numbers. Use exact same unit, common stack, common pipe, or multiple stack identification numbers that represent the monitored locations (e.g., 1, 2, CS001, MS1A, CP001, etc.) that are reported under §75.64 of this chapter. (ii) For units that use the alternative methods specified in §98.33(a)(5)(i) and (ii) to monitor and report202

heat input data year
- round ac cording to appendix D to part 75 of this chapter or § 75.19 of this chapter : (A) Each type of fuel combusted in the unit during the reporting year. (B) The methodology used to calculate the CO 2 mass emissions for each fuel type. (C) Methodology start date. (D) Methodology end date. ( E ) A code or flag to indicate whether heat input is calculated according to appendix D to part 75 of this chapter or § 75.19 of this chapter . ( F ) Annual CO 2 emissions at each moni tored location, across all fuel types, expressed in metric tons of CO 2 e. (G) Annual heat input from each type of fuel listed in Table C
- 2 of this subpart that was combusted during the reporting year, expressed in mmBtu. (H) Annual CH 4 and N 2 O emisions a t each monitored location, from each fuel type listed in Table C
- 2 of this subpart that was combusted during the reporting year (except as otherwise provided in §98.33(c)(4)(ii)( D )) , expressed in metric tons CO 2 e. (I) Annual CO 2 mass emissions from the combustion of biomass, expressed in metric tons CO 2 e (optional).203 (iii) For units with continuous monitoring systems that use the alternative method for units with continuous monitoring systems in §98.33(a)(5)(iii) to monitor heat input year
- round according to part 75 of this chapter : (A) Each type of fuel combusted during the reporting year. (B) Methodology used to calculate the CO 2 mass emissions. (C) Methodology start date. (D) Methodology end date. ( E ) A code or flag to indicate that the hea t input data is derived from CEMS measurements. ( F ) The total annual CO 2 emissions at each monitored location, expressed in metric tons of CO 2 e. (G) Annual heat input from each type of fuel listed in Table C
- 2 of this subpart that was combusted during the reporting year, expressed in mmBtu. (H) Annual CH 4 and N 2 O emisions at each monitored location, from each fuel type listed in Table C
- 2 of this subpart that was combusted during the reporting year (except as otherwise provided in §98.33( c)(4)(ii)(B)) , expressed in metric tons CO 2 e. (I) Annual CO 2 mass emissions from the combustion of biomass, expressed in metric tons CO 2 e (optional).204 (e) Verification data . You must keep on file, in a format suitable for inspection and auditing, suffici ent data to verify the reported GHG emissions. This data and information must, where indicated in this paragraph (e), be included in the annual GHG emissions report. (1) The applicable verification data specified in this paragraph (e) are not required to be kept on file or reported for units that meet any one of the three following conditions: (i) Are subject to the Acid Rain Program. (ii) Use the alternative methods for units with continuous monitoring systems provided in §98.33(a)(5). (iii) Are not in the Acid Rain Program, but are required to monitor and report CO 2 mass emissions and heat input data year
- round, in accordance with part 75 of this chapter . (2) For stationary combustion sources using the Tier 1, Tier 2, Tier 3, and Tier 4 Ca lculation Methodologies in §98.33(a) to quantify CO 2 emissions, the following additional information shall be kept on file and included in the GHG emissions report, where indicated: (i) For the Tier 1 Calculation Methodology, report the total quantity of each type of fuel combusted in the unit or group of aggregated units (as applicable) during205

the reporting year, in short tons for solid fuels, gallons for liquid fuels and standard cubic feet or, if applicable, therms for gaseous fuels. (ii) For the Tier 2 Calculation Methodology, report: (A) The total quantity of each type of fuel combusted in the unit or group of aggregated units (as applicable) during each month of the reporting year. Express the quantity of each fuel combusted during the measurement period in short tons for solid fuels, gallons for liquid fuels, and scf for gaseous fuels. (B) The frequency of the HHV determinations (e.g., once a month, once per fuel lot). (C) The high heat values used in the CO 2 emissions calculations for each type of fuel combusted during the reporting year , in mmBtu per short ton for solid fuels, mmBtu per gallon for liquid fuels, and mmBtu per scf for gaseous fuels. Report a HHV value for each calendar month in which HHV determination is required. If multiple values are obtained in a given month, report the arithmetic average value for the month. Indicate whether each reported HHV is a measured value or a substitute data value. (D) If Equation C
- 2c of th is subpart is used to calculate CO 2 mass emissions, report the total quantity206

(i.e., pounds) of steam produced from MSW or solid fuel combustion during each month of the reporting year, and the ratio of the maximum rate heat input capacity to the design
ra ted steam output capacity of the unit, in mmBtu per lb of steam. (iii) For the Tier 2 Calculation Methodology, keep records of the methods used to determine the HHV for each type of fuel combusted and the date on which each fuel sample was taken , except where fuel sampling data are received from the fuel supplier. In that case, keep records of the dates on which the results of the fuel analyses for HHV are received . (iv) For the Tier 3 Calculation Methodology, report: (A) The quantity of each type o f fuel combusted in the unit or group of units (as applicable) during each month of the reporting year, in short tons for solid fuels, gallons for liquid fuels, and scf for gaseous fuels. (B) The frequency of carbon content and, if applicable, molecular weight determinations for each type of fuel for the reporting year (e.g., daily, weekly, monthly, semiannually, once per fuel lot). (C) The carbon content and, if applicable, gas molecular weight values used in the emission calculations (including both valid and substitute data values). For207

each calendar month of the reporting year in which carbon content and, if applicable, molecular weight determination is required, report a value of each parameter. If multiple values of a parameter are obtained in a given month, report the arithmetic average value for the month. Express carbon content as a decimal fraction for solid fuels, kg C per gallon for liquid fuels, and kg C per kg of fuel for gaseous fuels. Express the gas molecular weights in units of kg per kg
-mole. (D) The total number of valid carbon content determinations and, if applicable, molecular weight determinations made during the reporting year, for each fuel type. (E) The number of substitute data values used for carbon content and, if applicable, molecular weight us ed in the annual GHG emissions calculations. (F) The annual average HHV, when measured HHV data, rather than a default HHV from Table C
- 1 of this subpart, are used to calculate CH 4 and N 2 O emissions for a Tier 3 unit, in accordance with §98.33(c)(1). (v) For the Tier 3 Calculation Methodology, keep records of the following:208 (A) For liquid and gaseous fuel combustion, the dates and results of the initial calibrations and periodic recalibrations of the required fuel flow meters. (B) For fuel oil combusti on, the method from §98.34(b) used to make tank drop measurements (if applicable). (C) The methods used to determine the carbon content for each type of fuel combusted. (D) The methods used to calibrate the fuel flow meters). (E) The date on which each fuel sample was taken, except where fuel sampling data are received from the fuel supplier. In that case, keep records of the dates on which the results of the fuel analyses for carbon content and (if applicable) molecular weight are received. (vi) For the Tier 4 Calculation Methodology, report: (A) The total number of source operating hours in the reporting year. (B) The cumulative CO 2 mass emissions in each quarter of the reporting year, i.e., the sum of the hourly values calculated from Equation C
- 6 or C - 7 of this subpart (as applicable), in metric tons. (C) For CO 2 concentration, stack gas flow rate, and (if applicable) stack gas moisture content, the percentage209

of source operating hours in which a substitute data value of each parameter was used in the emissions calculations. (vii) For the Tier 4 Calculation Methodology, keep records of: (A) Whether the CEMS certification and quality assurance procedures of part 75 of this chapter , part 60 of this chapter , or an applicable State continuous monitoring program were used. (B) The dates and results of the initial certification tests of the CEMS. (C) The dates and results of the major quality assurance tests performed on the CEMS during the reporting year, i.e., linearity checks, c ylinder gas audits, and relative accuracy test audits (RATAs). (viii) If CO 2 emissions that are generated from acid gas scrubbing with sorbent injection are not captured using CEMS, report: (A) The total amount of sorbent used during the report year, in short tons. (B) The molecular weight of the sorbent. (C) The ratio (“R”) in Equation C
- 11 of this subpart. (ix) For units that combust both fossil fuel and biomass, when biogenic CO 2 is determi ned according to210

§98.33(e)(2), you shall report the following additional information, as applicable: (A) The annual volume of CO 2 emitted from the combustion of all fuels, i.e., Vtotal , in scf. (B) The annual volume of CO 2 emitted from the combustion of fossil fuels, i.e., Vff , in scf. If more than one type of fossil fuel was combusted, report the combustion volume of CO 2 for each fuel separately as well as the total. (C) The annual volume of CO 2 emitted from the combustion of biomass, i.e., Vbio , in s cf. (D) The carbon
-based F
- factor used in Equation C
- 13 of this subpart, for each type of fossil fuel combusted, in scf CO 2 per mmBtu. (E) The annual average HHV value used in Equation C
13 of this subpart, for each type of fossil fuel combusted, in Btu/ lb, Btu/gal, or Btu/scf, as appropriate. (F) The total quantity of each type of fossil fuel combusted during the reporting year, in lb, gallons, or scf, as appropriate. (G) Annual biogenic CO 2 mass emissions, in metric tons. (x) When ASTM methods D745 9
- 08 and D6866
- 08 are used to determine the biogenic portion of the annual CO 2211

emissions from MSW combustion, as described in §98.34(d), report: (A) The results of each quarterly sample analysis, expressed as a decimal fraction (e.g., if the biogenic frac tion of the CO 2 emissions from MSW combustion is 30 percent, report 0.30). ( B ) The annual biogenic CO 2 mass emissions from MSW combustion, in metric tons. (xi) When ASTM methods D7459
- 08 and D6866
- 08 are used in accordance with §98.34(e) to determine the biogenic portion of the annual CO 2 emissions from a unit that co
fires biogenic fuels (or partly
-biogenic fuels, including tires if you are electing to report biogenic CO 2 emissions from tire combustion) and non
-biogenic fuels, you shall report the results of each quar terly sample analysis, expressed as a decimal fraction (e.g., if the biogenic fraction of the CO 2 emissions is 30 percent, report 0.30). (3) Within 30 days of receipt of a written request from the Administrator, you shall submit explanations of the following: (i) An explanation of how company records are used to quantify fuel consumption, if the Tier 1 or Tier 2 Calculation Methodology is used to calculate CO 2 emissions.212 (ii) An explanation of how company records are used to quantify fuel consumption, i f solid fuel is combusted and the Tier 3 Calculation Methodology is used to calculate CO 2 emissions. (iii) An explanation of how sorbent usage is quantified. (iv) An explanation of how company records are used to quantify fossil fuel consumption in unit s that uses CEMS to quantify CO 2 emissions and combusts both fossil fuel and biomass. (v) An explanation of how company records are used to measure steam production, when it is used to calculate CO 2 mass emissions under §98.33(a)(2)(iii) or to quantify solid fuel usage under §98.33(c)(3). (4) Within 30 days of receipt of a written request from the Administrator, you shall submit the verification data and information described in paragraphs (e)(2)(iii), (e)(2)(v), and (e)(2)(vii) of this section. § 98. 37 Records That Must be Retained. In addition to the requirements of §98.3(g), you must retain the applicable records specified in §§98.34(f) and (g), 98.35(b), and 98.36(e). §98.38 Definitions.213 All terms used in this subpart have the same meaning give n in the Clean Air Act and subpart A of this part.
Table C- 1 to Subpart C— Default CO2 Emission Factors and High Heat Values for Various Types of Fuel

Fuel Type Default High Heat Value Default CO2 Emission Factor Coal and coke mmBtu/short ton kg CO2 /m mBtu Anthracite 25.09 103.54 Bituminous 24.93 93.40 Subbituminous 17.25 97.02 Lignite 14.21 96.36 Coke 24.80 102.04 Mixed (Commercial sector) 21.39 95.26 Mixed (Industrial coking) 26.28 93.65 Mixed (Industrial sector) 22.35 93.91 Mixed (Electric P ower sector) 19.73 94.38 Natural gas mmBtu/scf kg CO2 /mmBtu (Weighted U.S. Average) 1.028 x 10 - 3 53.02 Petroleum products mmBtu/gallon kg CO2 /mmBtu Distillate Fuel Oil No. 1 0.139 73.25 Distillate Fuel Oil No. 2 0.138 73.96 Distillate Fuel Oil No. 4 0.146 75.04 Residual Fuel Oil No. 5 0.140 72.93 Residual Fuel Oil No. 6 0.150 75.10 Waste Oil 0.135 74.00 Kerosene 0.135 75.20 Liquefied petroleum gases (LPG) 0.092 62.98 Propane 0.091 61.46 Propylene 0.091 65.95 Ethane 0.096 62.64 Ethanol 0.084 68.44 Ethylene 0.100 67.43 Isobutane 0.097 64.91 Isobutylene 0.103 67.74 Butane 0.101 65.15 Butylene 0.103 67.73 Naphtha (<401 deg F) 0.125 68.02 Natural Gasoline 0.110 66.83 Other Oil (>401 deg F) 0.139 76.22 Pentanes Plus 0.110 70.02 Petrochemical Feedstocks 0.129 70.97 Petroleum Coke 0.143 102.41 Special Naphtha 0.125 72.34 Unfinished Oils 0.139 74.49 Heavy Gas Oils 0.148 74.92 Lubricants 0.144 74.27 Motor Gasoline 0.125 70.22 Aviation Gasoline 0.120 69.25214

Table C- 1 to Subpart C— Default CO2 Emission Factors and High Heat Values for Various Types of Fuel

Fuel Type Default High Heat Value Default CO2 Emission Factor Kerosene - Type Jet Fuel 0.135 72.22 Asphalt and Road Oil 0.158 75.36 Crude Oil 0.138 74.49 Other fuels ( solid) mmBtu/short ton kg CO2 /mmBtu Municipal Solid Waste 9.95 1 90.7 Tires 26.87 85.97 Plastics 38.00 75.00 Petroleum Coke 30.00 102.41 Other fuels ( gaseous) mmBtu/scf kg CO2 /mmBtu Blast Furnace Gas 0.092 x 10 - 3 274.32 Coke Oven Gas 0.599 x 10 - 3 46.85 Propane Gas 2.516 x 10 - 3 61.46 Fuel Gas 2 1.388 x 10 - 3 59.00 Biomass fuels - solid mmBtu/short ton kg CO2 /mmBtu Wood and Wood Residuals 15.38 93.80 Agricultural Byproducts 8.25 118.17 Peat 8.00 111.84 Solid Byproducts 25.83 105.51 Biomass fuels - gaseous mmBtu/scf kg CO2 /mmBtu Biogas (Captured methane) 0.841 x 10 - 3 52.07 Biomass fuels - liquid m mBtu/gallon kg CO2 /mmBtu Ethanol 0.084 68.44 Biodiesel 0.128 73.84 Rendered Animal Fat 0.125 71.06 Vegetable Oil 0.120 81.55 1 Use of this default HHV is a llowed only for units that combust MSW, do not generate steam , and are allowed to use Tier 1. 2 Reporters subject to subpart X of this part that are complying with § 98.243(d) or s ubpart Y of this part may only use the default HHV and the default CO 2 emission factor for fuel gas combustion under the conditions prescribed in §98.24 3(d)(2)(i) and (d) (2)(ii) and §98.252(a)(1) and (a)(2), respectively. Otherwise, Tier 3 (Equation C
- 5) or Tier 4 must be used.

Table C- 2 to Subpart C— Default CH4 and N2O Emission Factors for Various Types of Fuel.

Fuel Type Default CH4 Emission Factor (kg CH4 /mmBtu) Default N2O Emission Factor ( kg N2O/mmBtu) Coal and Coke (All fuel types in Table C
- 1) 1.1 x 10 - 0 2 1.6 x 10 - 03 Natural Gas 1.0 x 10 - 03 1.0 x 10 - 04215

Fuel Type Default CH4 Emission Factor (kg CH4 /mmBtu) Default N2O Emission Factor ( kg N2O/mmBtu) Petroleum (All fuel types in Table C
- 1) 3.0 x 10 - 03 6.0 x 10 - 04 Municipal Solid Waste 3.2 x 10 - 02 4.2 x 10 - 03 Tires 3.2 x 10 - 02 4.2 x 10 - 03 Blast Furnace Gas 2.2 x 10 - 05 1.0 x 10 - 04 Coke Oven Gas 4.8 x 10 - 04 1.0 x 10 - 0 4 Biomass Fuels
- Solid (All fuel types in Table C
- 1) 3.2 x 10 - 02 4.2 x 10 - 03 Biogas 3.2 x 10 - 03 6.3 x 10 - 04 Biomass Fuels

– Liquid (All fuel types in Table C - 1) 1.1 x 10 - 03 1.1 x 10 - 04
Note : Those employing this table are assumed to fall under the IPCC definitions of the “Energy Industry” or “Manufacturing Industries and Construction”. In all fuels except for coal the values for these two categories are identical. For coal combustion, those who fall within the IPCC “Energy Industry” category may employ a value of 1 g of CH 4 /MMBtu. Subpart D—

Electricity Generation §98.40 Definition of the source category. (a) The electricity generation source category comprises electricity generating units that are subject to the requirements of the Acid Rain Program and any other electricity generating units that are required to monitor and report to EPA CO 2 mass emissions year
- round according to 40 CFR part 75. (b) This source category does not include portable equipment, emergency equipment, or emerge ncy generators, as defined in §98.6. §98.41 Reporting threshold. You must report GHG emissions under this subpart if your facility contains one or more electricity generating216

units and the facility meets the requirements of §98.2(a)(1). §98.42 GHGs to report. (a) For each electricity generating unit that is subject to the requirements of the Acid Rain Program or is otherwise required to monitor and report to EPA CO 2 emissions year
- round according to 40 CFR part 75, you must report under this subpart the annual mass emissions of CO 2 , N 2 O, and CH 4 by following the requirements of this subpart. (b) For each electricity generating unit that is not subject to the Acid Rain Program or otherwise required to monitor and report to EPA CO 2 emissions year
- round a ccording to 40 CFR part 75, you must report under subpart C of this part (General Stationary Fuel Combustion Sources) the emissions of CO 2 , CH 4 , and N 2 O by following the requirements of subpart C. (c) For each stationary fuel combustion unit that does not generate electricity, you must report under subpart C of this part (General Stationary Fuel Combustion Sources) the emissions of CO 2 , CH 4 , and N 2 O by following the requirements of subpart C of this part. §98.43 Calculating GHG emissions. Continue to moni tor and report CO 2 mass emissions as required under §75.13 or section 2.3 of apppendix G to 40217

CFR part 75, and §75.64. Calculate CO 2 , CH 4 , and N 2 O emissions as follows: (a) Convert the cumulative annual CO 2 mass emissions reported in the fourth quarter electronic data report required under §75.64 from units of short tons to metric tons. To convert tons to metric tons, divide by 1.1023. (b) Calculate and report annual CH 4 and N 2 O mass emissions under this subpart by following the applicable method spec ified in §98.33(c). §98.44 Monitoring and QA/QC requirements Follow the applicable quality assurance procedures for CO 2 emissions in appendices B, D, and G to 40 CFR part 75. §98.45 Procedures for estimating missing data. Follow the applicable missing data substitution procedures in 40 CFR part 75 for CO 2 concentration, stack gas flow rate, fuel flow rate, high heating value, and fuel carbon content. §98.46 Data reporting requirements. The annual report shall comply with the data reporting requirements specified in §98.36 (d)(1) . §98.47 Records that must be retained. You shall comply with the recordkeeping requirements of §§98.3(g) and 98.37. Records retained under §75.57(h) of this chapter for missing dat a events satisfy the218

recordkeeping requirements of §98.3(g)(4) for those same events. §98.48 Definitions. All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Subpart F

— Aluminum Production §98.60 De finition of the source category. (a) A primary aluminum production facility manufactures primary aluminum using the Hall
- Héroult manufacturing process. The primary aluminum manufacturing process comprises the following operations: (1) Electrolysis in prebake and Søderberg cells. (2) Anode baking for prebake cells. (b) This source category does not include experimental cells or research and development process units. §98.61 Reporting threshold. You must report GHG emissions under this subpart if your facility contains an aluminum production process and the facility meets the requirements of either §98.2(a)(1) or (a)(2). §98.62 GHGs to report. You must report:219 (a) Perfluoromethane (CF 4 ), and perfluoroethane (C 2 F 6 ) emissions from anode effects in all prebake and Søderberg elect rolysis cells. (b) CO 2 emissions from anode consumption during electrolysis in all prebake and Søderberg elect rolysis cells. (c) CO 2 emissions from on
- site anode baking. (d) You must report under subpart C of this part (General Stationary Fuel Combustion Sources) the emissions of CO 2 , N 2 O, and CH 4 emissions from each stationary fuel combustion unit by following the requirements of subpart C. §98.63 Calculating GHG emissions. (a) The annual value of each PFC compound (CF 4 , C 2 F 6 ) shall be estimated from the sum of monthly values using Equation F
- 1 of this section: 

##  

  12
1 m

m m PFC E E (Eq. F
- 1) Where: EPFC = Annual emissions of each PFC compoundfrom

aluminum production (metric tons PFC). E m = Emissions of the individual PFC compound from

aluminum production for the month “m” (metric tons PFC). (b) Use Equation F
- 2 of this section to estimate CF 4 emissions from anode effect duration or Equation F
- 3 of this section to estimate CF 4 emissions from overvoltage, and use Equation F
- 4 of this section to estimate C 2 F 6 emissions220

from anode effects from each prebake and Søderberg elect rolysis cell.

E CF4 = S CF4 × AEM × MP × 0.001 (Eq. F
- 2) Where: E CF4 = Monthly CF 4 emissions from aluminum pro duction

(metric tons CF 4 ). S CF4 = The slope coefficient ((kg CF 4 /metric ton Al)/(AE
Mins/cell
- day)). AEM = The anode effect minutes per cell
- day (AE
Mins/cell
- day). MP = Metal production (metric tons Al), where AEM

and MP are calculated monthly.

E CF4 = EFCF4 × MP × 0.001 (Eq. F
- 3) Where: E CF4 = Monthly CF 4 emissions from aluminum production

(metric tons CF 4 ). EFCF4 = The overvoltage emission factor (kg CF 4 /metric ton

Al). MP = Metal production (metric tons Al), where MP is

calculated monthly.

E C2F6 = E CF4 × FC2F6/CF4 × 0.001 (Eq. F
- 4) Where:
E C2F6 = Monthly C 2 F 6 emissions from aluminum production

(metric tons C 2 F 6 ). E CF4 = CF 4 emissions from aluminum production(kg CF 4 ). FC2F6/CF4 = The weight fraction of C 2 F 6 /CF 4 (kg C 2 F 6 /kg CF 4 ). 0.001 = Conversion fa ctor from kg to metric tons, where

E CF4 is calculated monthly. (c) You must calculate and report the annual process CO 2 emissions from anode consumption during electrolysis and221

anode baking of prebake cells using either the procedures in paragraph (d) of this section , the procedures in paragraphs (e) and (f) of this section , or the procedures in paragraph (g) of this section . (d) Calculate and report under this subpart the process CO 2 emissions by operating and maintaining CEMS according to the Tier 4 Calculation Methodology in §98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources). (e) Use the following procedures to calculate CO 2 emissions from anode consumption during electrol ysis: (1) For Prebake cells: you must calculate CO 2 emissions from anode consumption using Equation F
- 5 of this section:
E CO2 = NAC × MP ×([100

– S a– Ash a ] / 100) × (44/12) (Eq. F - 5) Where:
E CO2 = Annual CO 2 emissions from prebaked anode

consumption (met ric tons CO 2 ). NAC = Net annual prebaked anode consumption per metric

ton Al (metric tons C/metric tons Al). MP = Annual metal production (metric tons Al). S a = Sulfur content in baked anode (percent weight). Ash a = Ash content in baked anode(percent weight). 44/12 = Ratio of molecular weights, CO 2 to carbon.222 (2) For Søderberg cells you must calculate CO 2 emissions using Equation F
- 6 of this section:

E CO2 = (PC × MP

– [CSM × MP] / 1000

– BC / 100 × PC × MP × [S p + Ashp + Hp ] / 100

– [100
- BC] / 100 × PC × MP × [S c + Ash c ] / 100

– MP × CD) × (44/12) (Eq. F
- 6) Where: E CO2 = Annual CO 2 emissions from paste consumption

(metric ton CO 2 ). PC = Annual paste consumption (metric ton/metric ton

Al). MP = Annual metal production (metric ton Al). CSM = Annual emis sions of cyclohexane soluble matter

(kg/metric ton Al). BC = Binder content of paste (percent weight). S p = Sulfur content of pitch (percent weight). Ashp = Ash content of pitch (percent weight). Hp = Hydrogen content of pitch (percent weight). S c = Sulfur content in calcined coke (percent weight). Ash c = Ash content in calcined coke (percent weight). CD = Carbon in skimmed dust from Søderberg cells

(metric ton C/metric ton Al). 44/12 = Ratio of molecular weights, CO 2 to carbon. ( f ) Use the following pro cedures to calculate CO 2 emissions from anode baking of prebake cells: (1) Use Equation F
- 7 of this section to calculate emissions from pitch volatiles combustion.

E CO2PV = (GA

– Hw – BA

– WT) × (44/12) (Eq. F - 7)
Where: E CO2PV = Annual CO 2 emissions f rom pitch volatiles

combustion (metric tons CO 2 ).223

GA = Initial weight of green anodes (metric tons). Hw = Annual hydrogen content in green anodes (metric

tons). BA = Annual baked anode production (metric tons). WT = Annual waste tar collected (metric tons) . 44/12 = Ratio of molecular weights, CO 2 to carbon. (2) Use Equation F
- 8 of this section to calculate emissions from bake furnace packing material. E CO2PC = PCC × BA × ([100

– S pc – Ashpc ] / 100) × (44/12) (Eq. F - 8) Where:
E CO2PC = Annual CO 2 emissions from bake furnace packing

material (metric tons CO 2 ). PCC = Annual packing coke consumption (metric

tons/metric ton baked anode). BA = Annual baked anode production (metric tons). S pc = Sulfur content in packing coke (percent weight). Ashpc = Ash content i n packing coke (percent weight). 44/12 = Ratio of molecular weights, CO 2 to carbon. ( g ) If process CO 2 emissions from anode consumption during electrolysis or anode baking of prebake cells are vented through the same stack as any combustion unit or proces s equipment that reports CO 2 emissions using a CEMS that complies with the Tier 4 Calculation Methodology in subpart C of this part (General Stationary Fuel Combustion Sources), then the calculation methodology in paragraphs (d) and (e) of this section sha ll not be used to calculate those process emissions. The owner or operation shall report under this subpart the combined stack emissions224

according to the Tier 4 Calculation Methodology in §98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources). §98.64 Monitoring and QA/QC requirements. (a) Effective one year after publication of the rule for smelters with no prior measurement or effective three years after publication for facilities with historic measurements, the smelter
- specific slope coefficients , overvoltage emission factors, and weight fractions used in Equations F
- 2, F
- 3, and F
- 4 of this subpart must be measured in accordance with the recommendations of the EPA/IAI Protocol for Measurement of Tetrafluoromethane (CF 4 ) and Hexafluoroethane (C 2 F 6 ) Emissions from Primary Aluminum Production (2008), except the minimum frequency of measurement shall be every 10 years unless a change occurs in the control algorithm that affects the mix of types of anode effects or the nature of the anode effect termination routine. Facilities which operate at less than 0.2 anode effect minutes per cell day or operate with less than 1.4mV anode effect overvoltage can use either smelter
- specific slope co efficients or the technology specific default values in Table F
- 1 of this subpart.225 (b) The minimum frequency of the measurement and analysis is annually except as follows: (i) Monthly for anode effect minutes per cell day (or anode effect overvoltage and current efficiency). (ii) Monthly for aluminum production. (iii) Smelter
- specific slope coefficients, overvoltage emission factors, and weight fractions according to paragraph (a) of this section . (c) Sources may use either smelter
- specific values from annual measurements of parameters needed to complete the equations in §98.63 (e.g., sulfur, ash, and hydrogen contents) or the default values s hown in Table F
- 2 of this subpart. §98.65 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 measurement is not taken), a substitute data value for the missing parameter shall be used in the calculations, according to the following requirements:226 (a) Where anode or paste consumption data are missing, CO 2 emissions can be estimated from aluminum production per Equation F
- 8 of this section.

ECO 2 = EFp x MPp + EF s x MP s (Eq. F
- 8) Where: ECO 2 = CO 2 emissions from anode and/or paste consumption,

metric tons CO 2 . EFp = Prebake technology specific emission factor (1.6

metric tons CO 2 /metric ton aluminum produced). MPp = Metal production from prebake process (metric tons

Al). EF s = Søderberg technology specific emission factor (1.7

metric tons CO 2 /metric ton Al produced). MP s = Metal production from Søderberg process (metric

tons Al). (b) For other parameters, use the average of the two most recent data points after the missing data. §98.66 Data reporting requirements. In addition to the informa tion required by §98.3(c), you must report the following information at the facility level: (a) Annual aluminum production in metric tons. (b) Type of smelter technology used. (c) The following PFC
- specific information on an annual basis: (1) Perflu oromethane emissions and perfluoroethane emissions from anode effects in all prebake and all Søderberg elect rolysis cells combined.227 (2) Anode effect minutes per cell
- day (AE
-mins/cell
day), anode effect frequency (AE/cell
- day), anode effect duration (minutes). (Or anode effect overvoltage factor ((kg CF 4 /metric ton Al)/(mV/cell day)), potline overvoltage (mV/cell day), current efficiency (%).) (3) Smelter
- specific slope coefficients (or overvoltage emission factors) and the last date when the smelter
- spe cific
- slope coefficients (or overvoltage emission factors) were measured. (d) Method used to measure the frequency and duration of anode effects (or overvoltage). (e) The following CO 2 - specific information for prebake cells: (1) Annual anode consumption. (2) Annual CO 2 emissions from the smelter. (f) The following CO 2 - specific information for Søderberg cells: (1) Annual paste consumption. (2) Annual CO 2 emissions from the smelter. (g) Smelter
- specific inputs to the CO 2 process equations (e.g., l evels of sulfur and ash) that were used in the calculation, on an annual basis. (h) Exact data elements required will vary depending on smelter technology (e.g., point
- feed prebake or228

Søderberg) and process control technology (e.g., Pechiney or other). §98.67 Records that must be retained. In addition to the information required by §98.3(g), you must retain the following records: (a) Monthly aluminum production in metric tons. (b) Type of smelter technology used. (c) The following PFC
- specific in formation on a monthly basis: (1) Perfluoromethane and perfluoroethane emissions from anode effects in prebake and Søderberg elect rolysis cells. (2) Anode effect minutes per cell
- day (AE
-mins/cell
day), anode effect frequency (AE/cell
- day), anode effec t duration (minutes). (Or anode effect overvoltage factor ((kg CF 4 /metric ton Al)/(mV/cell day)), potline overvoltage (mV/cell day), current efficiency (%).)) (3) Smelter
- specific slope coefficients and the last date when the smelter
- specific
- slope coeff icients were measured. (d) Method used to measure the frequency and duration of anode effects (or to measure anode effect overvoltage and current efficiency).229 (e) The following CO 2 - specific information for prebake cells: (1) Annual anode consumption. ( 2) Annual CO 2 emissions from the smelter. (f) The following CO 2 - specific information for Søderberg cells: (1) Annual paste consumption. (2) Annual CO 2 emissions from the smelter. (g) Smelter
- specific inputs to the CO 2 process equations (e.g., levels of sulfur and ash) that were used in the calculation, on an annual basis. (h) Exact data elements required will vary depending on smelter technology (e.g., point
- feed prebake or Søderberg) and process control technology (e.g., Pechiney or other). §98.68 Definitions. All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Table F- 1 to Subpart F —Slope and Overvoltage Coefficients for the Calculation of PFC Emissions from Aluminum Production

Technology CF4 Slope

Coefficient [(kg CF4 /metric ton Al)/(AE Mins/cell -day)] CF4 Overvoltage Coefficient [(kg CF4 /metric ton Al)/(mV)] Weight

Fraction C2F6/CF4 [(kg C2F6/kg CF4 )]230

Technology CF4 Slope

Coefficient [(kg CF4 /metric ton Al)/(AE Mins/cell -day)] CF4 Overvoltage Coefficient [(kg CF4 /metric ton Al)/(mV)] Weight

Fraction C2F6/CF4 [(kg C2F6/kg CF4 )] Center Worked Prebake ( CWPB ) 0.143 1.16 0.121 Side Worked Prebake ( SWPB ) 0.272 3.65 0 .252 Vertical Stud Søderberg ( VSS ) 0.092 NA 0.053 Horizontal Stud Søderberg ( HSS ) 0.099 NA 0.085

Table F- 2 to Subpart F — Default Data Sources for Parameters Used for CO2 Emissions CO2 Emissions from Prebake Cells (CWPB and SWPB) Parameter Data Source MP: metal production (metric tons Al) Individual facility records NAC: net annual prebaked anode consumption per metric ton Al (metric tons C/metric tons Al) Individual facility records S a : sulfur content in baked anode (percent weight) 2.0 Ash a : ash content in baked anode(percent weight) 0.4 CO 2 Emissions from Søderberg Cells (VSS and HSS) Parameter Data Source MP: metal production (metric tons Al) Individual facility records PC: annual paste consumption (metric ton/metric ton Al) Individual fa cility records CSM: annual emissions of cyclohexane soluble matter (kg/metric ton Al) HSS: 4.0 VSS: 0.5 BC: binder content of paste (percent weight) Dry Paste: 24 Wet Paste: 27231

S p : sulfur content of pitch (percent weight) 0.6 Ashp : ash content o f pitch (percent weight) 0.2 Hp : hydrogen content of pitch (percent weight) 3.3 S c : sulfur content in calcined coke (percent weight) 1.9 Ash c : ash content in calcined coke (percent weight) 0.2 CD: carbon in skimmed dust from Søderberg cells (metric ton C/metric ton Al) 0.01 CO 2 Emissions from Pitch Volatiles Combustion ( CWPB and SWPB ) Parameter Data Source GA: initial weight of green anodes (metric tons) Individual facility records Hw : annual hydrogen content in green anodes (metric tons) 0.005 × GA BA: annual baked anode production (metric tons) Individual facility records WT: annual waste tar collected (metric tons) (a) Riedhammer furnaces (b) all other furnaces (a) 0.005 × GA (b) insignificant CO 2 Emissions from Bake Furnace Packing Materials (CWPB and SWPB) Parameter Data Source PCC: annual packing coke consumption (metric tons/metric ton baked anode) 0.015 BA: annual baked anode production (metric tons) Individual facility records S pc : sulfur content in packing co ke (percent weight) 2 Ashpc : ash content in packing coke (percent weight) 2.5 Subpart G

— Ammonia Manufacturing §98.70 Definition of Source Category. The ammonia manufacturing source category comprises the process units listed in paragraphs (a) and (b) o f this section.232 (a) Ammonia manufacturing processes in which ammonia is manufactured from a fossil
-based feedstock produced via steam reforming of a hydrocarbon. (b) Ammonia manufacturing processes in which ammonia is manufactured through the gasificati on of solid and liquid raw material. § 98.71 Reporting threshold. You must report GHG emissions under this subpart if your facility contains an ammonia manufacturing process and the facility meets the requirements of either §98.2(a)(1) or (2). §98.72 GHGs to report. You must report: (a) CO 2 process emissions from steam reforming of a hydrocarbon or the gasification of solid and liquid raw material, reported for each ammonia manufacturing process unit following the requirements of this subpart (CO 2 pro cess emissions reported under this subpart may include CO 2 that is later consumed on
- site for urea production, and therefore is not released to the ambient air from the ammonia manufacturing process unit) . (b) CO 2 , CH 4 , and N 2 O emissions from each station ary fuel combustion unit. You must report these emissions under subpart C of this part (General Stationary Fuel233

Combustion Sources), by following the requirements of subpart C , except that for ammonia manufacturing processes subpart C does not apply to an y CO 2 resulting from combustion of the waste recycle stream (commonly referred to as the purge gas stream) . (c) CO 2 emissions collected and transferred off site under subpart PP (Suppliers of CO 2 ), following the requirements of subpart PP. §98.73 Calcul ating GHG emissions. You must calculate and report the annual process CO 2 emissions from each ammonia manufacturing process unit using the procedures in either paragraph (a) or (b) of this section. (a) Calculate and report under this subpart the process CO 2 emissions by operating and maintaining CEMS according to the Tier 4 Calculation Methodology specified in §98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources). (b) Calculate and report under this subpart process CO 2 emissions using the procedures in paragraphs (b)(1) through (b)( 5 ) of this section for gaseous feedstock, liquid feedstock, or solid feedstock, as applicable.234 (1) Gaseous feedstock . You must calculate, from each ammonia manufacturing unit, the CO 2 process emissions from gaseous feedstock according to Equation G
- 1 of this section:


### 0.001 ) MVC MW CC Fdstk 12 44 ( CO n k n, 12
1 n k G, 2, 

###     

 

# ∑ (Eq. G
- 1) Where: CO 2,G ,k = Annual CO 2 emissions arising from gaseous

feedstock consumption (metric tons). Fdst kn = Volume of the gaseous feedstock used in month n

(scf of feedstock). CC n = Carbon content of the gaseous feedstock, for

month n, (kg C per kg of feedstock), determined according to 98.74(c). MW = Molecular weight of the gaseous feedstock

(kg/kg
-mole). MVC = Molar volume conversion factor (849.5 scf per

kg
-mole at standard conditions). 44/12 = Ratio of molecular weights, CO 2 to carbon. 0.001 = Conversion factor from kg to metric tons. k = Processing unit. n = Number of month (2) Liquid feedstock . You must calculate, from each ammonia manufacturing unit, the CO 2 process emissions from liquid feedstock according to Equation G
- 2 of this section:
0.001 ) CC Fdstk 12 44 ( CO n k n, 12
1 n k L, 2,    

 

## ∑ (Eq. G
- 2) Where: CO 2,L ,k = Annual CO 2 emissions arising from liquid

feedstock consumpt ion (metric tons).235

Fdstkn = Volume of the liquid feedstock used in month n

(gallons of feedstock). CC n = Carbon content of the liquid feedstock, for

month n, (kg C per gallon of feedstock) determined according to 98.74(c). 44/12 = Ratio of molecular we ights, CO 2 to carbon. 0.001 = Conversion factor from kg to metric tons. k = Processing unit. n = Number of month (3) Solid feedstock . You must calculate, from each ammonia manufacturing unit, the CO 2 process emissions from solid feedstock according to E quation G
- 3 of this section:
0.001 ) CC Fdstk 12 44 ( CO n k n, 12
1 n k S, 2,    

 

## ∑ (Eq. G
- 3) Where: CO 2,S ,k = Annual CO 2 emissions arising from solid

feedstock consumption (metric tons). Fdstkn = Mass of the solid feedstock used in month n (kg

of feedstock). CC n = Carbon content of the solid feedstock, for

month n, (kg C per kg of feedstock), determined according to 98.74(c). 44/12 = Ratio of molecular weights, CO 2 to carbon. 0.001 = Conversion factor from kg to metric tons. K = Processing unit.
n = Number of month. (4) You must ca lculate the annual process CO 2 emissions from each ammonia processing unit k at your facility summing emissions, as applicable from Equation G1, G
- 2, and G
- 3 of this section using Equation G
- 4.236

= E CO2 k CO 2,G + CO 2,S + CO 2,L (Eq. G
- 4) Where: E CO2 k = Annual CO 2 emissions from each ammonia

processing unit k (metric tons). k = Processing unit. (5) You must determine the combined CO 2 emissions from all ammonia processing units at your facility using Equation G- 5 of this section. 

## ∑ n
1 = k CO2 2 E = CO k (Eq. G
- 5) Where: CO 2 = Annual combined CO 2 emissions from all ammonia

processing units (metric tons) (CO 2 process emissions reported under this subpart may include CO 2 that is later consumed on - site for urea production , and therefore is not release d to the ambient air from the ammonia manufacturing process unit(s) ) . E CO2 k = Annual CO 2 emissions from each ammonia

processing unit (metric tons). k = Processing unit. n = Total number of ammonia processing units. (c) If GHG emissions from an ammonia manufacturing unit are vented through the same stack as any combustion unit or process equipment that reports CO 2 emissions using a CEMS that complies with the Tier 4 Calculation Methodology in subpart C of this part (General Stationary Fuel Combustion Sources), then the calculation methodology in237

paragraph (b) of this section shall not be used to calculate process emissions. The owner or operator shall report under this subpart the combined stack emissions
a ccording to the Tier 4 Calculation Methodology in §98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part. §98.74 Monitoring and QA/QC requirements. (a) You must continuously measure the quantity of gaseous or liquid feedstock c onsumed using a flow meter. The quantity of solid feedstock consumed can be obtained from company records and aggregated on a monthly basis. (b) You must document the procedures used to ensure the accuracy of the estimates of feedstock consumption. (c) You must determine monthly carbon contents and the average molecular weight of each feedstock consumed from reports from your supplier. As an alternative to using supplier information on carbon contents, you can also collect a sample of each feedstock on a monthly basis and analyze the carbon content and molecular weight of the fuel using any of the following methods listed in paragraphs (c)(1) through (c)(8) of this section, as applicable. (1) ASTM D1945
- 03 Standard Test Method for Analysis of Natural Gas by Gas Chromatography (incorporated by reference, see §98.7).238 (2) ASTM D1946
- 90 (Reapproved 2006) Standard Practice for Analysis of Reformed Gas by Gas Chromatography (incorporated by reference, see §98.7). (3) ASTM D2502
- 04 (Reapproved 2002) Standard Test Method for Estimation of Mean Relative Molecular Mass of Petroleum Oils from Viscosity Measurements (incorporated by reference, see §98.7). (4) ASTM D2503
- 92 (Reapproved 2007) Standard Test Method for Relative Molecular Mass (Molecular Weight) of Hydrocarbons by Thermoelectric Measurement of Vapor Pressure (incorporated by reference, see §98.7). (5) 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 (incorporated by reference, see §98.7). (6) ASTM D5291
- 02 (Reapproved 2007) Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants (incorporated by reference, see §98.7). (7) AS TM D3176
- 89 (Reapproved 2002) Standard Practice for Ultimate Analysis of Coal and Coke (incorporated by reference, see §98.7). (8) ASTM D5373
- 08 Standard Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in239

Laboratory Samples of Coa l (incorporated by reference, see §98.7). (d) Calibrate all oil and gas flow meters that are used to measure liquid and gaseous feedstock volumes and flow rates (except for gas billing meters) according to the monitoring and QA/QC requirements for the Tier 3 methodology in §98.34(b) (1) . Perform oil tank drop measurements (if used to quantify feedstock volumes) according to §98.34(b)(2). (e) For quality assurance and quality control of the supplier data, on an annual bas is, you must measure the carbon contents of a representative sample of the feedstocks consumed using the appropriate ASTM Method as listed in paragraphs (c)(1) through (c)(8) of this section. (f) [Reserved] (g) If CO 2 from ammonia production is used to produce urea at the same facility, you must determine the quantity of urea produced using methods or plant instruments used for accounting purposes (such as sales records). You must document the procedures used to ensure the accuracy of the estimates of urea produced. §98.75 Procedures for estimating missing data.240 A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever the monitoring and quality assurance procedures in §98.74 cannot be followed (e.g., if a meter malfunctions during unit operation), a substitute data value for the missing parameter shal l be used in the calculations following paragraphs (a) and (b) of this section. You must document and keep records of the procedures used for all such estimates. (a) For missing data on monthly carbon contents of feedstock , the substitute data value shall be the arithmetic average of the quality
- assured values of that carbon content in the month preceding and the month immediately following the missing data incident. If no quality
- assured data are available prior to the missing data incident, the substitute data value shall be the first quality
- assured value for carbon content obtained in the month after the missing data period. (b) For missing feedstock supply rates used to determine monthly feedstock consumption , you must determine the best available estimate(s) of the parameter(s), based on all available process data. §98.76 Data reporting requirements.241 In addition to the information required by §98.3(c), each annual report must contain the information specified in paragraphs (a) and (b) of this section, as applicable for each ammonia manufacturing process unit. (a) If a CEMS is used to measure CO 2 emissions, then you must report the relevant information required under §98.3 6 for the Tier 4 Calculation Methodology and the following information in this paragraph (a): (1) Annual quantity of each type of feedstock consumed for ammonia manufacturing (scf of feedstock or gallons of feedstock or kg of feedstock). (2) Method used for determining quantity of feedstock used. (b) If a CEMS is not used to measure emissions, then you must report the following information: (1) Annual CO 2 process emissions (metric tons) for each ammonia manufacturing process uni t. (2) Monthly quantity of each type of feedstock consumed for ammonia manufacturing for each ammonia processing unit (scf of feedstock or gallons of feedstock or kg of feedstock). (3) Method used for determining quantity of monthly feedstock used.242 (4) Whether carbon content for each feedstock for month n is based on reports from the supplier or analysis of carbon content. (5) If carbon content of feedstock for month n is based on analysis, the test method used. (6) Sampling analysis results of carbon content of feedstock as determined for QA/QC of supplier data under §98.74(e). (7) If a facility uses gaseous feedstock, the carbon content of the gaseous feedstock, for month n, (kg C per kg of feedstock). (8) If a facility uses gaseous fe edstock, the molecular weight of the gaseous feedstock (kg/kg
-mole). (9) If a facility uses gaseous feedstock, the molar volume conversion factor of the gaseous feedstock (scf per kg
-mole). (10) If a facility uses liquid feedstock, the carbon content of the liquid feedstock, for month n, (kg C per gallon of feedstock). (11) If a facility uses solid feedstock, the carbon content of the solid feedstock, for month n, (kg C per kg of feedstock). ( 12 ) Annual urea production (metric tons) and method used to determine urea production.243 ( 13 ) CO 2 from the steam reforming of a hydrocarbon or the gasification of solid and liquid raw material at the ammonia manufacturing process unit used to produce urea and the method used to determine the CO 2 consumed in urea production. §98.77 Records that must be retained. In addition to the records required by §98. 3(g), you must retain the following records specified in paragraphs (a) and (b) of this section for each ammonia manufacturing unit. (a) If a CEMS is used to measure emissions, retain records of all feedstock purchases in addition to the requirements in § 98.37 for the Tier 4 Calculation Methodology. (b) If a CEMS is not used to measure process CO 2 emissions, you must also retain the records specified in paragraphs (b)(1) through (b)(2) of this section: (1) Records of all analyses and calculations conduct ed for reported data as listed in §98.76(b). (2) Monthly records of carbon content of feedstock from supplier and/or all analyses conducted of carbon content. §98.78 Definitions.244 All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Subpart P

— Hydrogen Production §98.160 Definition of the source category. (a) A hydrogen production source category consists of facilities that produce hydrogen gas sold as a product to other entities. (b) This source c ategory comprises process units that produce hydrogen by reforming, gasification, oxidation, reaction, or other transformations of feedstocks. (c) This source category includes merchant hydrogen production facilities located within a petroleum refinery if they are not owned by, or under the direct control of, the refinery owner and operator. §98.161 Reporting threshold. You must report GHG emissions under this subpart if your facility contains a hydrogen production process and the facility meets the requ irements of either §98.2(a)(1) or (a)(2). §98.162 GHGs to report. You must report: (a) CO 2 process emissions from each hydrogen production process unit.245 (b) CO 2 , CH 4 and N 2 O combustion emissions from each hydrogen production process unit. You must cal culate and report these combustion emissions under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C. (c) CO 2 , CH 4 , and N 2 O emissions from each stationary combustion unit other than hydrogen pr oduction process units. You must calculate and report these emissions under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C. (d) For CO 2 collected and transferred off site, you must follow the requirements of subpart PP of this part. §98.163 Calculating GHG emissions. You must calculate and report the annual process CO 2 emissions from each hydrogen production process unit using the procedures specified in either paragraph (a) or (b) of this s ection. (a) Continuous Emissions Montoring Systems (CEMS) . Calculate and report under this subpart the process CO 2 emissions by operating and maintaining CEMS according to the Tier 4 Calculation Methodology specified in §98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources).246 (b) Fuel and feedstock material balance approach . Calculate and report process CO 2 emissions as the sum of the annual emissions associated with each fuel and fe edstock used for hydrogen production by following paragraphs (b)(1) through (b)(3) of this section. (1) Gaseous fuel and feedstock . You must calculate the annual CO 2 process emissions from gaseous fuel and feedstock according to Equation P
- 1 of this sect ion:
001
. 0 * ) * 12 44 ( 1 2 MVC MW CC Fdstk CO n n k

n    

## 

 (Eq. P
- 1)
Where: CO 2 = Annual CO 2 process emissions arising from

fuel and feedstock consumption (metric tons/yr). Fdstkn = Volume of the gaseous fuel and feedstock

used in month n (scf (at standard conditions of 68 °F and atmospheric pressure) of fuel and feedstock). CC n = Average carbon content of the gaseous fuel

and feedstock, from the results of one or more analyses for month n (kg carbon per kg of fuel and feedstock). MW = Molecular weight of the gaseous fuel and

feeds tock (kg/kg
-mole). MVC = Molar volume conversion factor (849.5 scf

per kg
-mole at standard conditions). k = Months in the year. 44/12 = Ratio of molecular weights, CO 2 to carbon. 0.001 = Conversion factor from kg to metric tons.247 (2) Liquid fuel and fe edstock . You must calculate the annual CO 2 process emissions from liquid fuel and feedstock according to Equation P
- 2 of this section: 001
. 0 * ) 12 44 ( 1 2 n n k

n CC Fdstk CO 

  

## 

 (Eq. P
- 2) Where: CO 2 = Annual CO 2 emissions arising from fuel and

feedstock consumption (metric tons/yr). Fdstkn = Volume of the liquid fuel and feedstock used in

month n (gallons of fuel and feedstock). CC n = Average carbon content of the liquid fuel and

feedstock, from the results of one or more analyses for month n (kg carbon per gallon of fuel and feedstock). k = Months in the year. 44/12 = Ratio of molecular weights, CO 2 to carbon. 0.001 = Conversion factor from kg to metric tons. (3) Solid fuel and feedstock . You must calculate the annual CO 2 process emissions from solid fuel and feeds tock according to Equation P
- 3 of this section: 001
. 0 * ) 12 44 ( 1 2 n n k

n CC Fdstk CO 

  

## 

 ( Eq.P - 3 ) Where: CO 2 = Annual CO 2 emissions from fuel and feedstock

consumption in metric tons per month (metric tons/yr). Fdstkn = Mass of solid fuel and feedstock used in month

n (kg of fuel and feedstock). CC n = Average carbon content of the solid fuel and

feedstock, from the results of one or more analyses for month n (kg carbon per kg of fuel and feedstock). k = Months in the year.248

44/12 = Ratio of molecular weights, CO 2 to carb on. 0.001 = Conversion factor from kg to metric tons. (c) If GHG emissions from a hydrogen production process unit are vented through the same stack as any combustion unit or process equipment that reports CO 2 emissions using a CEMS that complies with the Tier 4 Calculation Methodology in subpart C of this part (General Stationary Fuel Combustion Sources), then the calculation methodology in paragraph (b) of this section shall not be used to calculate process emissions. The owner or operator shall report under this subpart the combined stack emissions according to the Tier 4 Calculation Methodology in §98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources). §98.164 Monitoring and QA/QC requirements. The GHG emissions data for hydrogen production process units must be quality
- assured as specified in paragraphs (a) or (b) of this section, as appropriate for each process unit: (a) If a CEMS is used to measure GHG emissions, then the faci lity must comply with the monitoring and QA/QC procedures specified in §98.34(c).249 (b) If a CEMS is not used to measure GHG emissions, then you must: (1) Calibrate all oil and gas flow meters that are used to measure liquid and gaseous feedstock volumes (except for gas billing meters) according to the monitoring and QA/QC requireme nts for the Tier 3 methodology in §98.34(b)(1) . Perform oil tank drop measurements (if used to quantify liquid fuel or feedstock consumption) according to §98.34(b)(2). Calibrate all solids weighing equipment according to the procedures in §98.3(i). (2) Determine the carbon content and the molecular weight annually of standard gaseous hydrocarbon fuels and feedstocks having consistent composition (e.g., natural gas). For other gaseous fuels and feedstocks (e.g., biogas, refinery gas, or process gas), wee kly sampling and analysis is required to determine the carbon content and molecular weight of the fuel and feedstock. (3) Determine the carbon content of fuel oil, naphtha, and other liquid fuels and feedstocks at least monthly, except annually for standard liquid hydrocarbon fuels and feedstocks having consistent composition, or upon delivery for liquid fuels delivered by bulk transport (e.g., by truck or rail).250 (4) Determine the carbon content of coal, coke, and other solid fuels and feedstocks at le ast monthly, except annually for standard solid hydrocarbon fuels and feedstocks having consistent composition, or upon delivery for solid fuels delivered by bulk transport (e.g., by truck or rail). (5) You must use the following applicable methods to determine the carbon content for all fuels and feedstocks, and molecular weight of gaseous fuels and feedstocks. (i) ASTM D1945
- 03 Standard Test Method for Analysis of Natural Gas by Gas Chromatography (incorporated by reference, see §98.7). (ii) ASTM D 1946
- 90 (Reapproved 2006), Standard Practice for Analysis of Reformed Gas by Gas Chromatography (incorporated by reference, see §98.7). (iii) ASTM D2013
- 07 Standard Practice of Preparing Coal Samples for Analysis (incorporated by reference, see §98.7). (iv) ASTM D2234/D2234M
- 07 Standard Practice for Collection of a Gross Sample of Coal (incorporated by reference, see §98.7). (v) ASTM D2597
- 94 (Reapproved 2004) Standard Test Method for Analysis of Demethanized Hydrocarbon Liquid251

Mixtures Containing Nitrogen and Carbon Dioxide by Gas Chromatography (incorporated by reference, see §98.7). (vi) ASTM D3176
- 89 (Reapproved 2002), Standard Practice for Ultimate Analysis of Coal and Coke (incorporated by reference, see §98.7). (vii) ASTM D3238
- 95 (Reapproved 2 005), Standard Test Method for Calculation of Carbon Distribution and Structural Group Analysis of Petroleum Oils by the n
- d
-M Method (incorporated by reference, see §98.7). (viii) ASTM D4057
- 06 Standard Practice for Manual Sampling of Petroleum and Petro leum Products (incorporated by reference, see §98.7). (ix) ASTM D4177
- 95 (Reapproved 2005) Standard Practice for Automatic Sampling of Petroleum and Petroleum Products (incorporated by reference, see §98.7). (x) ASTM D5291
- 02 (Reapproved 2007), Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants (incorporated by reference, see §98.7). (xi) ASTM D5373
- 08 Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Ni trogen in Laboratory Samples of Coal (incorporated by reference, see §98.7).252 (xii) ASTM D6609
- 08 Standard Guide for Part
- Stream Sampling of Coal (incorporated by reference, see §98.7). (xiii) ASTM D6883
- 04 Standard Practice for Manual Sampling of Stationary Coal from Railroad Cars, Barges, Trucks, or Stockpiles (incorporated by reference, see §98.7). (xiv) ASTM D7430
- 08ae1 Standard Practice for Mechanical Sampling of Coal (incorporated by reference, see §98.7). (xv) ASTM UOP539
- 97 Refinery Gas Analysis by Gas Chromatography (incorporated by reference, see §98.7). (xvi) GPA 2261

– 00 Analysis for Natural Gas and Similar Gaseous Mixtures by Gas Chromatography (incorporated by reference, see §98.7). (xvii) ISO 3170: Petroleum Liquids
-- Manual sampling

– Third Edition (incorporated by reference, see §98.7). (xviii) ISO 3171: Petroleum Liquids
-- Automatic pipeline sampling

– Second Edition (incorporated by reference, see §98.7). (c) For units using the calculation methodologies described in this section, the records required under §98.3(g) must include both the company records and a detailed explanation of how company records are used to estimate the following:253 (1) Fuel and feedstock consumption, when solid fuel and feedstock is combusted and a CEMS is n ot used to measure GHG emissions. (2) Fossil fuel consumption, when, pursuant to §98.33(e), the owner or operator of a unit that uses CEMS to quantify CO 2 emissions and that combusts both fossil and biogenic fuels separately reports the biogenic portion of the total annual CO 2 emissions. (3) Sorbent usage, if the methodology in §98.33(d) is used to calculate CO 2 emissions from sorbent. (d) The owner or operator must document the procedures used to ensure the accuracy of the estimates of fuel and feedstock usage and sorbent usage (as applicable) in paragraph (b) of this section, including, but not limited to, calibration of weighing equipment, fuel and feedstock flow meters, and other measurement devices. The estimated accuracy of measurements made wi th these devices must also be recorded, and the technical basis for these estimates must be provided. §98.165 Procedures for estimating missing data. A complete record of all measured parameters used in the GHG emissions calculations is required. There fore, whenever a quality
- assured value of a required parameter is unavailable (e.g., if a meter malfunctions during unit254

operation), a substitute data value for the missing parameter must be used in the calculations as specified in paragraphs (a), (b), and (c) of this section: (a) For each missing value of the monthly fuel and feedstock consumption, the substitute data value must be the best available estimate of the fuel and feedstock consumption, based on all available process data (e.g., hydrogen produc tion, electrical load, and operating hours). You must document and keep records of the procedures used for all such estimates. (b) For each missing value of the carbon content or molecular weight of the fuel and feedstock, the substitute data value must be the arithmetic average of the quality
assured values of carbon contents or molecular weight of the fuel and feedstock immediately preceding and immediately following the missing data incident. If no quality
- assured data on carbon contents or molecular weight of the fuel and feedstock are available prior to the missing data incident, the substitute data value must be the first quality
- assured value for carbon contents or molecular weight of the fuel and feedstock obtained after the missing data period. You must document and keep records of the procedures used for all such estimates.255 (c) For missing CEMS data, you must use the missing data procedures in §98.35. §98.166 Data reporting requirements. In addition to the information required by §98.3(c),
e ach annual report must contain the information specified in paragraphs (a) or (b) of this section, as appropriate: (a) If a CEMS is used to measure CO 2 emissions, then you must report the relevant information required under §98.36 for the Tier 4 Calculat ion Methodology and the following information in this paragraph (a): (1) Unit identification number and annual CO 2 process emissions. (2) Annual quantity of hydrogen produced (metric tons) for each process unit and for all units combined. (3) Annual quantity of ammonia produced (metric tons), if applicable, for each process unit and for all units combined. (b) If a CEMS is not used to measure CO 2 emissions, then you must report the following information for each hydrogen production process unit: (1) Unit identification number and annual CO 2 process emissions. (2) Monthly consumption of each fuel and feedstock used for hydrogen production and its type (scf of gaseous256

fuels and feedstocks, gallons of liquid fuels and feedstocks, kg of solid fuels and feedstocks). (3) Annual quantity of hydrogen produced (metric tons). (4) Annual quantity of ammonia produced, if applicable (metric tons). (5) Monthly analyses of carbon content for each fuel and feedstock used in hydrogen production (kg carbon/kg of gaseous and solid fuels and feedstocks, (kg carbon per gallon of liquid fuels and feedstocks). (6) Monthly analyses of the molecular weight of gaseous fuels and feedstocks (kg/kg
-mole) used, if any. (c) Quarterly quantity of CO 2 collected and transferred off site in either gas, liquid, or solid forms (kg), following the requirements of subpart PP of this part. (d) Annual quantity of carbon other than CO 2 collected and transferred off site in either gas, liquid, or solid forms (kg carbon). §98.167 Rec ords that must be retained. In addition to the information required by §98.3(g), you must retain the records specified in paragraphs (a) through (b) of this section for each hydrogen production facility.257 (a) If a CEMS is used to measure CO 2 emissions, then you must retain under this subpart the records required for the Tier 4 Calculation Methodology in §98.37. (b) If a CEMS is not used to measure CO 2 emissions, then you must retain records of all analyses and calculations conducted as listed in §§98.166 (b), (c), and (d). §98.168 Definitions. All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Subpart V

— Nitric Acid Production §98.220 Definition of Source Category. A nitric acid production facility uses one or more trains to produce weak nitric acid (30 to 70 percent in strength). A nitric acid train produces weak nitric acid through the catalytic oxidation of ammonia. §98.221 Reporting threshold. You must report GHG emissions under this subpart if your facility contains a nitric acid train and the facility meets the requirements of either §98.2(a)(1) or (a)(2). §98.222 GHGs to report. (a) You must report N 2 O process emissions from each nitric acid production train as required by this subpart.258 (b) You must report under subpart C of this part (General Stationary Fuel Combustion Sources) the emissions of CO 2 , CH 4 , and N 2 O from each stationary combustion unit by following the requirements of subpart C . §98.223 Calculating GHG emissions. (a) You mus t determine annual N 2 O process emissions from each nitric acid train according to paragraphs (a)(1) or (a)(2) of this section. (1) Use a site
- specific emission factor and production data according to paragraphs (b) through (h) of this section. (2) Reques t Administrator approval for an alternative method of determining N 2 O emissions according to paragraphs (a)(2)(i) and (a)(2)(ii) of this section. (i) You must submit the request within 45 days following promulgation of this subpart or within the first 30 days of each subsequent reporting year. (ii) If the Administrator does not approve your requested alternative method within 150 days of the end of the reporting year, you must determine the N 2 O emissions factor for the current reporting period using the p rocedures specified in paragraph (a)(1) of this section.259 (b) You must conduct an annual performance test according to paragraphs (b)(1) through (b)(3) of this section. (1) You must measure N 2 O emissions from the absorber tail gas vent for each nitric ac id train using the methods specified in §98.224(b) through (d). (2) You must conduct the performance test under normal process operating conditions and without using N 2 O abatement technology (if applicable). (3) You must measure the production rate during the performance test and calculate the production rate for the test period in metric tons (100 percent acid basis) per hour. (c) You must determine an N 2 O emissions factor to use in Equation V
- 3 of this section according to paragraphs (c)(1) or (c)(2) o f this section. (1) You may request Administrator approval for an alternative method of determining N 2 O concentration according to the procedures in paragraphs (a)(2)(i) and (a)(2)(ii) of this section. Alternative methods include the use of N 2 O CEMs. (2) Using the results of the performance test in paragraph (b) of this section, you must calculate an260

average site
- specific emission factor for each nitric acid train “t” according to Equation V
- 1 of this section:

nP Q C EF n O N
Ot N 

##  

 

  1 7 2
2 10

14
. 1 (Eq. V
- 1) Where: EFN2Ot = Average site
- specific N 2 O emissions factor for

nitric acid train “t” (lb N 2 O generated/ton nitric acid produced, 100 percent acid basis). CN2O = N 2 O concentration for each test run during the

performance test (ppm N 2 O). 1.14x10 - 7= Conversion fa ctor (lb/dscf
-ppm N 2 O). Q = Volumetric flow rate of effluent gas for each

test run during the performance test (dscf/hr). P = Production rate for each test run during the

performance test (tons nitric acid produced per hour, 100 percent acid basis).
n = Number of test runs. (d) If applicable, you must determine the destruction efficiency for each N 2 O abatement technology according to paragraphs (d)(1), (d)(2), or (d)(3) of this section. (1) Use the manufacturer’s specified destruction efficiency. (2) Est imate the destruction efficiency through process knowledge. Examples of information that could constitute process knowledge include calculations based on material balances, process stoichiometry, or previous test results provided the results are still rel evant to the current vent stream conditions. You must document how261

process knowledge (if applicable) was used to determine the destruction efficiency. (3) Calculate the destruction efficiency by conducting an additional performance test on the emissions stream following the N 2 O abatement technology. (e) If applicable, you must determine the abatement factor for each N 2 O abatement technology. The abatement factor is calculated for each nitric acid train according to Equation V
- 2 of this section.

t a Abate t a t N P P AF  (Eq. V
- 2)
Where: AFN t = Abatement factor of N 2 O abatement technology

at nitric acid train “t” (fraction of annual production that abatement technology is operating). P a t = Total annual nitric acid production from

nitric acid train “t” (ton acid produced, 100 percent acid basis). P a t Abate = Annual nitric acid production from

nitric acid train “t” during which N 2 O abatement was used (ton acid produced, 100 percent acid basis). (f) You must determine the annual amount of nitric acid produ ced and the annual amount of nitric acid produced while each N 2 O abatement technology is operating from each nitric acid train (100 percent basis). (g) You must calculate N 2 O emissions for each nitric acid train by multiplying the emissions factor (determined262

in Equation V
- 1 of this section) by the annual nitric acid production and accounting for N 2 O abatement, according to Equation V
- 3 of this section:



# 

   z N t N t N t a t N Ot N AF DF P EF E 1 20 63
. 2204 ))

* ( 1 ( * *
2 (Eq. V
- 3) Where: E N2Ot = N 2 O mass emissions per year for nitric acid

train “t” ( metric tons). EFN2Ot = Average site
- specific N 2 O emissions factor

for nitric acid train ”t” (lb N 2 O generated/ton acid produced, 100 percent acid basis). P a t = Annual nitric acid production from the train

“t” (ton acid produced, 100 percent acid basis). DFN t = Destruction efficiency of N 2 O abatement

technology N that is used on nitric acid train “t” (percent of N 2 O removed from air stream). AFN t = Abatement factor of N 2 O abatement technology

for nitric acid train “t” (fraction of annual production that abatement technology is operating). 2204.63 = Conversion factor (lb/metric ton).
z = Number of different N 2 O abatement technologies. (h) You must determine the annual nitric acid production emissions combined from all nitric acid trains at your facility u sing Equation V
- 4 of this section: 

## 

  m
t Ot N E O N 1 2 2 (Eq. V
- 4) Where: N 2 O = Annual process N 2 O emissions from nitric

acid production facility (metric tons)263

E N2Ot = N 2 O mass emissions per year for nitric acid

train “t” (metric tons). m = Number of nitri c acid trains. §98.224 Monitoring and QA/QC requirements. (a) You must conduct a new performance test and calculate a new site
- specific emissions factor according to a test plan as specified in paragraphs (a)(1) through (a)(3) of this section. (1) Conduct the performance test annually. (2) Conduct the performance test when your nitric acid production process is changed, specifically when abatement equipment is installed. (3) If you requested Administrator approval for an alternative method of determi ning N 2 O concentration under §98.223(a)(2), you must conduct the performance test if your request has not been approved by the Administrator within 150 days of the end of the reporting year in which it was submitted. (b) You must measure the N 2 O concentration during the performance test using one of the methods in paragraphs (b)(1) through (b)(3) of this section. (1) EPA Method 320 at 40 CFR part 63, appendix A, Measurement of Vapor Phase Organic and Inorganic Emissions264

by Extractive Fourier Transform I nfrared (FTIR) Spectroscopy. (2) ASTM D6348
- 03 Standard Test Method for Determination of Gaseous Compounds by Extractive Direct Interface Fourier Transform Infrared (FTIR) Spectroscopy (incorporated by reference in §98.7). (3) An equivalent method, with Administrator approval. (c) You must determine the production rate(s) (100 percent basis) from each nitric acid train during the performance test according to paragraphs (c)(1) or (c)(2) of this section. (1) Direct measurement of production and concentra tion (such as using flow meters, weigh scales, for production and concentration measurements). (2) Existing plant procedures used for accounting purposes (i.e. dedicated tank
- level and acid concentration measurements). (d) You must conduct all performan ce tests in conjunction with the applicable EPA methods in 40 CFR part 60, appendices A
- 1 through A
- 4. Conduct three emissions test runs of 1 hour each. All QA/QC procedures specified in the reference test methods and any associated performance specifica tions apply. For each test, the265

facility must prepare an emission factor determination report that must include the items in paragraphs (d)(1) through (d)(3) of this section. (1) Analysis of samples, determination of emissions, and raw data. (2) All information and data used to derive the emissions factor(s). (3) The production rate during each test and how it was determined. (e) You must determine the monthly nitric acid production and the monthly nitric acid production during which N 2 O abatement t echnology is operating from each nitric acid train according to the methods in paragraphs (c)(1) or (c)(2) of this section. (f) You must determine the annual nitric acid production and the annual nitric acid production during which N 2 O abatement technolo gy is operating for each train by summing the respective monthly nitric acid production quantities. §98.225 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, a substitute data value for the missing266

parameter shall be used in the calculations as specified in paragraphs (a) and (b) of this section. (a) For each missing value of nitric ac id production, the substitute data shall be the best available estimate based on all available process data or data used for accounting purposes (such as sales records). (b) For missing values related to the performance test, including emission factors, production rate, and N 2 O concentration, you must conduct a new performance test according to the procedures in §98.224 (a) through (d). §98.226 Data reporting requirements. In addition to the information required by §98.3(c), each annual report must cont ain the information specified in paragraphs (a) through (o) of this section for each nitric acid production train. (a) Train identification number. (b) Annual process N 2 O emissions from each nitric acid train (metric tons). (c) Annual nitric acid produc tion from each nitric acid train (tons, 100 percent acid basis). (d) Annual nitric acid production from each nitric acid train during which N 2 O abatement technology is operating (ton acid produced, 100 percent acid basis)267 (e) Annual nitric acid production from the nitric acid facility (tons, 100 percent acid basis). (f) Number of nitric acid trains. (g) Number of abatement technologies (if applicable). (h) Abatement technologies used (if applicable). (i) Abatement technology destruction efficiency fo r each abatement technology (percent destruction). (j) Abatement utilization factor for each abatement technology (fraction of annual production that abatement technology is operating). (k) Type of nitric acid process used for each nitric acid train (low , medium, high, or dual pressure). (l) Number of times in the reporting year that missing data procedures were followed to measure nitric acid production (months). (m) If you conducted a performance test and calculated a site
- specific emissions factor ac cording to §98.223(a)(1), each annual report must also contain the information specified in paragraphs (m)(1) through (m)(7) of this section for each nitric acid production facility. (1) Emission factor calculated for each nitric acid train (lb N 2 O/ ton n itric acid, 100 percent acid basis). (2) Test method used for performance test.268 (3) Production rate per test run during performance test (tons nitric acid produced/hr, 100 percent acid basis). (4) N 2 O concentration per test run during performance test (ppm N 2 O). (5) Volumetric flow rate per test run during performance test (dscf/hr). (6) Number of test runs during performance test. (7) Number of times in the reporting year that a performance test had to be repeated (number). (n) If you requested Administrator approval for an alternative method of determining N 2 O concentration under §98.223(a)(2), each annual report must also contain the information specified in paragraphs (n)(1) through (n)(4) of this section for each nitric acid production facility. (1) Name of alternative method. (2) Description of alternative method. (3) Request date. (4) Approval date. §98.227 Records that must be retai ned. In addition to the information required by §98.3(g), you must retain the records specified in paragraphs (a) through (g) of this section for each nitric acid production facility:269 (a) Records of significant changes to process. (b) Documentation of how process knowledge was used to estimate abatement technology destruction efficiency (if applicable). (c) Performance test reports. (d) Number of operating hours in the calendar year for each nitric acid train (hours). (e) Annual nitric acid permitted production capacity (tons). (f) Measurements, records, and calculations used to determine reported parameters. (g) Documentation of the procedures used to ensure the accuracy of the measurements of all reported parameters, including but not limited to, c alibration of weighing equipment, 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 provided. §98.228 Definitions. All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Subpart X

—Petrochemical Production §98.240 Definition of the source category.270 (a) The petrochemical production source category consists of all processes that produce acrylonitrile, carbon black, ethylene, ethylene dichloride, ethylene oxide, or methanol, except as specified in paragraphs (b) through ( g ) of this section. The source category includes processes that produce the petrochemical as an intermediate in the onsite production of other chemicals as well as processes that produce the petrochemical as an end product for sale or shipment offsite. (b) A process that produces a petrochemical as a byproduct is not part of the petrochemical production
sou rce category. (c) A facility that makes methanol, hydrogen, and/or ammonia from synthesis gas is part of the petrochemical source category if the annual mass of methanol produced exceeds the individual annual mass production levels of both hydrogen recove red as product and ammonia. The facility is part of subpart P of this part (Hydrogen Production) if the annual mass of hydrogen recovered as product exceeds the individual annual mass production levels of both methanol and ammonia. The facility is part
o f subpart G of this part (Ammonia Manufacturing) if the annual mass of ammonia produced exceeds the individual271

annual mass production levels of both hydrogen recovered as product and methanol. (d) A direct chlorination process that is operated independent ly of an oxychlorination process to produce ethylene dichloride is not part of the petrochemical production source category. (e) A process that produces bone black is not part of the petrochemical source category. (f) A process that produces a petrochemi cal from bio
based feedstock is not part of the petrochemical production source category. (g) A process that solely distills or recycles waste solvent that contains a petrochemical is not part of the petrochemical production source category. §98.241 Rep orting threshold. You must report GHG emissions under this subpart if your facility contains a petrochemical process as specified in §98.240, and the facility meets the requirements of either §98.2(a)(1) or (2). §98.242 GHGs to report. You must report the information in paragraphs (a) through (c) of this section: (a) CO 2 CH 4 , and N 2 O process emissions from each petrochemical process unit. Process emissions include CO 2272

generated by reaction in the process and by combustion of process off
- gas in stationa ry combustion units and flares. (1) If you comply with §98.243(b) or (d), report under this subpart the calculated CO 2 , CH 4 , and N 2 O emissions for each stationary combustion source and flare that burns any amount of petrochemical process off
- gas. If you comply with §98.243(b), also report under this subpart the measured CO 2 emissions from process vents routed to stacks that are not associated with stationary combustion units. (2) If you comply with §98.243(c), report under this subpart the calculated CO 2 emissions for each petrochemical process unit. (b) CO 2 , CH 4 , and N 2 O combustion emissions from stationary combustion units . (1) If you comply with §98.243(b) or (d), report these emissions from stationary combustion units that are associa ted with petrochemical process units and burn only supplemental fuel under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C. (2) If you comply with §98.243(c), report CO 2 , CH 4 , and N 2 O combusti on emissions under subpart C of this part (General Stationary Fuel Combustion Sources) by following273

the requirements of subpart C only for the combustion of supplemental fuel. Determine the applicable Tier in subpart C of this part (General Stationary Fue l Combustion Sources) based on the maximum rated heat input capacity of the stationary combustion source. (c) CO 2 captured. You must report the mass of CO 2 captured under, subpart PP of this part (Suppliers of Carbon Dioxide (CO 2 ) by following the requ irements of subpart PP. §98.243 Calculating GHG emissions. (a) If you route all process vent emissions and emissions from combustion of process off
- gas to one or more stacks and use CEMS on each stack to measure CO 2 emissions (except flare stacks), the n you must determine process
based GHG emissions in accordance with paragraph (b) of this section. Otherwise, determine process
-based GHG emissions in accordance with the procedures specified in paragraph (c) or (d) of this section. (b) Continuous emiss ion monitoring system (CEMS) . Route all process vent emissions and emissions from combustion of process off
- gas to one or more stacks and determine CO 2 emissions from each stack (except flare stacks) according to the Tier 4 Calculation Methodology requirements in subpart C of this part. For each stack274

(except flare stacks) that includes emissions from combustion of petrochemical process off
- gas, calculate CH 4 and N 2 0 emissions in accordance with subpart C of this part (use the Tier 3 methodology , emi ssion factors for “Petroleum” in Table C
- 2 of subpart C of this part , and either the default high heat value for fuel gas in Table C
1 of subpart C of this part or a calculated HHV, as allowed in Equation C
- 8 of subpart C of this part ). For each flare, ca lculate CO 2 , CH 4 , and N 2 O emissions using the methodology specified in §98.253(b)(1) through (b)(3). (c) Mass balance for each petrochemical process unit . Calculate the emissions of CO 2 from each process unit, for each calendar month as described in par agraphs (c)(1) through (c)(5) of this section. (1) For each gaseous and liquid feedstock and product, measure the volume or mass used or produced each calendar month with a flow meter by following the procedures specified in §98.244(b)(2). Alternatively, for liquids, you may calculate the volume used or collected in each month based on measurements of the liquid level in a storage tank at least once per month (and just prior to each change in direction of the level of the liquid) following the procedures specified in §98.244(b)(3). Fuels275

used for combustion purposes are not considered to be feedstocks. (2) For each solid feedstock and product, measure the mass used or produced each calendar month by following the procedures specified in §98.244(b)(1). (3 ) Collect a sample of each feedstock and product at least once per month and determine the carbon content of each sample according to the procedures in §98.244(b)(4). Alternatively, you may use the results of analyses conducted by a fuel or feedstock supplier, provided the sampling and analysis is conducted at least once per month using any of the procedures specified in §98.244(b)(4). If multiple valid carbon content measurements are made during the monthly measurement period, average them arithmeticall y. (4) If you determine that the monthly average concentration of a specific compound in a feedstock or product is greater than 99.5 percent by volume (or mass for liquids and solids), then as an alternative to the sampling and analysis specified in paragraph (c)(3) of this section, you may calculate the carbon content assuming 100 percent of that feedstock or product is the specific compound during periods of normal operation. You must maintain records of any determination made in accordance with this276

pa ragraph (c)(4) along with all supporting data, calculations, and other information. This alternative may not be used for products during periods of operation when off
- specification product is produced. You must reevaluate determinations made under this p aragraph (c)(4) after any process change that affects the feedstock or product composition. You must keep records of the process change and the corresponding composition determinations. If the feedstock or product composition changes so that the average monthly concentration falls below 99.5 percent, you are no longer permitted to use this alternative method. (5) Calculate the CO 2 mass emissions for each petrochemical process unit using Equations X
- 1 through X
- 4 of this section. (i) Gaseous feedstocks and products . Use Equation X
1 of this section to calculate the net annual carbon input or output from gaseous feedstocks and products. Note that the result will be a negative value if there are no gaseous feedstocks in the process but there are gaseous p roducts.



###     

##     ]] ) ( * * ) ( * * [ [
, , , , 12
1 1 MVC MW CC P MVC MW CC F C i p n i gp n i gp i f n i gf n i gf n k

or j
i g   

##  

  (Eq. X
- 1) Where: C g = Annual net contribution to calculated emissions

from carbon (C) in gaseous materials (kilograms/year, kg/yr). (Fgf ) i,n = Volume of gaseous feedstock i introduced in

month “n” (standard cubic feet, sc f).277

(CC gf ) i,n = Average carbon content of the gaseous feedstock

i for month “n” (kg C per kg of feedstock). (MW f ) i = Molecular weight of gaseous feedstock i (kg/kg
mole). MVC = Molar volume conversion factor (849.5 scf per

kg
-mole at 68 °F and 14.7 pounds per square inch absolute or 836.6 scf/kg
-mole at 60 °F and 14.7 pounds per square inch absolute ). (P gp ) i,n = Volume of gaseous product i produced in month

“n” (scf). (CC gp ) i,n = Average carbon content of gaseous product i,

including streams containing CO 2 recovered for sale or use in another process, for month “n” (kg C per kg of product). (MWp ) i = Molecular weight of gaseous product i (kg/kg
mole). j = Number of feedstocks. k = Number of products. (ii) Liquid feedstocks and products . Use Equation X
2 of this section to calculate the net carbon input or output from liquid feedstocks and products. Note that the result will be a negative value if there are no liquid feedstocks in the process but there are liquid products. 

###     

##     ]] * * [ [
, , , , 12
1 1 n i lp n i lp n i lf n i lf n k

or j
i l CC P CC F C

  

##  

  (Eq. X
- 2) Where: C l = Annual net contribution to calculated emissions

from carbon in liquid materials, including liquid organic wastes (kg/yr). (F lf ) i,n = Volume or mass of liquid feedstock i introduced

in month “n” (gallons or kg). (CC lf ) i,n = Average carbon content of liquid feedstock i

for month “n” (kg C per gallon or kg of feedstock). (P lp ) i,n = Volume or mass of liquid product i produced in

month “n” (gallons or kg).278

(CC lp ) i,n = Average carbon content of liquid product i,

including organ ic liquid wastes, for month “n” (kg C per gallon or kg of product). j = Number of feedstocks. k = Number of products. (iii) Solid feedstocks and products . Use Equation X
3 of this section to calculate the net annual carbon input or output from solid feedstocks and products. Note that the result will be a negative value if there are no solid feedstocks in the process but there are solid products.



##         

#    

       

  12
1 , , , , 1 *

*
n n i sp n i sp n i sf n i sf k or j
i s CC P CC F C (Eq. X
- 3) Where: C s = Annual net contribution to calculated emissions

from carbon in so lid materials (kg/yr). (F sf ) i,n = Mass of solid feedstock i introduced in month

“n” (kg). (CC sf ) i,n = Average carbon content of solid feedstock i for

month “n” (kg C per kg of feedstock). (P sp ) i,n = Mass of solid product i produced in month “n”

(kg). (CC sp ) i,n = Average carbon content of solid product i in

month “n” (kg C per kg of product). j = Number of feedstocks. k = Number of products. (iv) Annual emissions . Use the results from Equations X
- 1 through X
- 3 of this section, as applicable, in Equation X
- 4 of this section to calculate annual CO 2 emissions. 

##  

s C C C CO l g    *

12 44 * 001
. 0 2 (Eq. X
- 4)279

Where: CO 2 = Annual CO 2 mass emissions from process

operations and process off
- gas combustion (metric tons/year). 0.001 = Conversion factor from kg to metric tons. 44 = Molecular weight of CO 2 (kg/kg
-mole). 12 = Atomic weight of carbon (C) (kg/kg
-mole). (d) Optional combustion methodology for ethylene production processes . For each ethylene production process, calculate GHG emissions from each combustion unit that burns fuel that contains any off
- gas from the ethylene process as specified in paragraphs (d)(1) through (d)(5) of this section. (1) Except as specified in paragraphs (d)(2) and (d)(5) of this section, calculate CO 2 emissions using the Tier 3 or Tier 4 methodology in subpart C of this part . (2) You may use e ither Equation C
- 1 or Equation C
- 2a in subpart C of this part to calculate CO 2 emissions from combustion of any ethylene process off
- gas streams that meet either of the conditions in paragraphs (d)(2)(i) or (d)(2)(ii) of this section (for any default values in the calculation, use the defaults for fuel gas in Table C
- 1 of subpart C of this part). Follow the otherwise applicable procedures in subpart C to calculate emissions from
c ombustion of all other fuels in the combustion unit.280 (i) The annual average flow rate of fuel gas ( that contains ethylene process off
- gas ) in the fuel gas line to the combustion unit, prior to any split to individual burners or ports, does not exceed 3 4 5 standard cubic feet per minute at 6 0 °F and 14.7 pounds per square inch absolute , and a flow meter is not installed at any point in the line supplying fuel gas or an upstream common pipe. Calculate the annual average flow rate using company records assuming total flow is evenly distributed over 525,600 minutes per year. (ii) The combustion unit has a maximum rated heat input capacity of less than 30 MMBtu/hr, and a flow meter is not installed at any point in the line supplying fuel gas (that contains ethyle ne process off
- gas) or an upstream common pipe. (3) Except as specified in paragraph (d)(5) of this section, calculate CH 4 and N 2 O emissions using the applicable procedures in §98.33(c) for the same tier methodology that you used for calculating CO 2 emissions. ( i) For all gaseous fuels that contain ethylene process off
- gas, use the emission factors for “Petroleum” in Table C
- 2 of subpart C of this part (General Stationary Fuel Combustion Sources) .281 (ii) For Tier 3, use either the default high heat val ue for fuel gas in Table C
- 1 of subpart C of this part or a calculated HHV, as allowed in Equation C
- 8 of subpart C of this part . (4) You are not required to use the same Tier for each stationary combustion unit that burns ethylene process off
- gas. (5 ) For each flare, calculate CO 2 , CH 4 , and N 2 O emissions using the methodology specified in §98.253(b)(1) through (b)(3). §98.244 Monitoring and QA/QC requirements. (a) If you use CEMS to determine emissions from process vents, you must comply with the p rocedures specified in §98.34(c). (b) If you use the mass balance methodology in §98.243(c), use the procedures specified in paragraphs (b)(1) through (b)(4) of this section to determine feedstock and product flows and carbon contents. (1) Operate , maintain , and calibrate belt scales or other weighing devices as described in Specifications, Tolerances, and Other Technical Requirements For Weighing and Measuring Devices NIST Handbook 44 (2009) (incorporated by reference, see §98.7) or follow procedures specified by the measurement device manufacturer. You must recalibrate282

each weighing device at one of the following frequencies. You may recalibrate either biennially (i.e., once every two years) or at the minimum frequency specified by the manufacturer. (2) Operate and maintain all flow meters used for gas and liquid feedstocks and products according to the manufacturer’s recommended procedures. You must c alibrate each of these flow meters according to one of the following . You may use either an industry consensus standard method or methods specified by the flow meter manufacturer . Each flow meter must meet the applicable accuracy specification in §98.3(i), except as otherwise specified in §98.3(i)(4) through (i)(6). You must
recalibrate each flow meter according to one of the following frequencies. You may recalibrate either biennially , at the minimum frequency spe cified by the manufacturer , or at the interval specified by the industry consensus standard practice used . (3) You must perform tank level measurements (if used to determine feedstock or product flows) according to one of the following methods. You may use any standard method published by a consensus -based standards organization (e.g., ASTM, API, etc.) or you may use industry standard practice.283 (4) Use any applicable methods specified in paragraphs (b)(4)(i) through (b)(4)(x iii ) of this section to det ermine the carbon content or composition of feedstocks and products and the average molecular weight of gaseous feedstocks and products. Calibrate instruments in accordance with paragraphs (b)(4)(i) through (b)(4)(x iii ),
as applicable. For coal used as a feedstock, the samples for carbon content determinations shall be taken at a location that is representative of the coal feedstock used during the corresponding monthly period. For carbon black products, samples shall be ta ken of each grade or type of product produced during the monthly period. Samples of coal feedstock or carbon black product for carbon content determinations may be either grab samples collected and analyzed monthly or a composite of samples collected more frequently and analyzed monthly. Analyses conducted in accordance with methods specified in paragraphs (b)(4)(i) through (b)(4)(x iii ) of this section may be performed by the owner or operator, by an independent laboratory, or by the supplier of a feedsto ck. (i) ASTM D1945
- 03, Standard Test Method for Analysis of Natural Gas by Gas Chromatography (incorporated by reference, see §98.7).284 (ii) ASTM D6060
- 96 (Reapproved 2001) Standard Practice for Sampling of Process Vents With a Portable Gas Chromatograph ( incorporated by reference, see §98.7). (iii) ASTM D2505
- 88(Reapproved 2004)e1 Standard Test Method for Ethylene, Other Hydrocarbons, and Carbon Dioxide in High
- Purity Ethylene by Gas Chromatography (incorporated by reference, see §98.7). (iv) ASTM UOP539
- 97 Refinery Gas Analysis by Gas Chromatography (incorporated by reference, see §98.7). (v) ASTM D3176
- 89 (Reapproved 2002) Standard Practice Method for Ultimate Analysis of Coal and Coke (incorporated by reference, see §98.7). (vi) ASTM D5291
- 02 (Reapproved 2007) Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants (incorporated by reference, see §98.7). (vii) ASTM D5373
- 08 Standard Test Methods for Instrumental Determination of Carb on, Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference, see §98.7). (viii) Methods 8031, 8021, or 8015 in “Test Methods for Evaluating Solid Waste, Physical/Chemical Methods,” EPA Publication No. SW
- 846, Third Edition, September 1986, as amended by Update I, November 15, 1992.285 (ix) Method 18 at 40 CFR part 60, appendix A
- 6. (x) Performance Specification 9 in 40 CFR part 60, appendix B for continuous online gas analyzers. The 7
- day calibration error test period must be comple ted prior to the effective date of the rule. (xi) ASTM D2593
- 93 (Reapproved 2009) Standard Test Method for Butadiene Purity and Hydrocarbon Impurities by Gas Chromatography, (incorporated by reference, see §98.7) , effective as of January 1, 2010 . (xii) An industry standard practice for carbon black feedstock oils and carbon black products , effective as of January 1, 2010 . (xiii) Modifications of existing analytical methods or other analytical methods that are applicable to your process provided tha t the methods listed in §98.244 (b)(4)(i) through §98.244(b)(4)(xi i ) are not appropriate because the relevant compounds cannot be detected, the quality control requirements are not technically feasible, or use of the method would be unsafe , effective as of Janua ry 1, 2010 . §98.245 Procedures for estimating missing data. For missing feedstock flow rates, product flow rates, and carbon contents, use the same procedures as for missing286

flow rates and carbon contents for fuels as specified in §98.35. §98.246 Data reporting requirements. In addition to the information required by §98.3(c), each annual report must contain the information specified in paragraphs (a), (b), or (c) of this section, as appropriate for each process unit. (a) If you use the mass balance methodology in §98.243(c), you must report the information specified in paragraphs (a)(1) through (a) (11) of this section for each type of petrochemical produced, reported by process unit. (1) The petrochemical process unit ID number or other appropriate descriptor. (2) The type of petrochemical produced, names of other products, and names of carbon
- containing feedstocks. (3) Annual CO 2 emissions calculated using Equation X
- 4 of this subpart. (4) Each of the monthly volume, mass, and carbon content values used in Equations X
- 1 through X
- 3 of this subpart (i.e., the directly measured values, substitute values, or the calculated values based on other measured data such as tank levels or gas composition) and the molecular weights for gaseous feedstocks and products used in Equation X
- 1 of this subpart , and the temperture (in °F)287

at which the gaseous feedstock and product volumes used in Equation X
- 1 of this subpart were determined . Indicate whether you used the alternative to sampling and analysis specified in §98.243(c)(4). (5) Annual quantity of each type of petrochemical produced from each process unit (metric tons). (6) Name of each method listed in §98.244 used to determine a measured parameter (or description of manufacturer’s recommended method). (7 ) [Reserved] (8) Identification of each combustion unit that burned both process off
- gas and supplemental fuel. (9) If you comply with the alternative to sampling and analysis specified in §98.243(c)(4), the amount of time during which off
- specification product was produced, the volume or mass of off
- specification product produced, and if applicable, the date of any process change that reduce d the composition to less than 99.5 percent. (10) You may elect to report the flow and carbon content of wastewater, and you may elect to report the annual mass of carbon released in fugitive emissions and in process vents that are not controlled with a combustion device. These values may be estimated based on engineering288

analyses. These values are not to be used in the mass balance calculation. (11) If you determine carbon content or composition of a feedstock or product using a method under §98.244(b)(4)(xii i ), report the information listed in paragraphs (a)(11)(i) through (a)(11)(iii) of this section. Include the information in paragraph (a)(11)(i) of this section in each annual report. Include the information in paragraphs ( a)(11)(ii) and (a)(11)(iii) of this section only in the first applicable annual report, and provide any changes to this information in subsequent annual reports. (i) Name or title of the analytical method. (ii) A copy of the method. If the method is a
modification of a method listed in §98.244(b)(4)(i) through (xi i ), you may provide a copy of only the sections that differ from the listed method. (iii) An explanation of why an alternative to the methods listed in §98.244(b)(4)(i) through (x i i) is needed. (b) If you measure emissions in accordance with §98.243(b), then you must report the information listed in paragraphs (b)(1) through (b)( 8 ) of this section. (1) The petrochemical process unit ID or other appropriate descriptor, and the type of petrochemical produced.289 ( 2 ) For CEMS used on stacks for stationary combustion units, report the relevant information required under §98.36 for the Tier 4 ca lculation methodology. Section 98.36(b)(9)(iii) does not apply for the purposes of this subpart. ( 3 ) For CEMS used on stacks that are not used for stationary combustion units, report the information required under §98.36(e)(2)(vi) . (4) The CO 2 emissions from each stack and the combined CO 2 emissions from all stacks (except flare stacks) that handle process vent emissions and emission s from stationary combustion units that burn process off
- gas for the petrochemical process unit. For each stationary combustion unit (or group of combustion units monitored with a single CO 2 CEMS) that burns petrochemical process off
- gas , provide
an estimate based on engineering judgment of the fraction of the total emissions that is attributable to combustion of off
- gas from the petrochemical process unit. (5) For stationary combustion units that burn process off
- gas from the petrochemical process unit, report the information related to CH 4 and N 2 O emissions as specified in paragraphs (b)(5)(i) through (b)(5)(iv) of this section. (i) The CH 4 and N 2 O emissions from each stack that is monitored with a CO 2 CEMS, expressed in metric tons of each290

gas and in metric tons of CO 2 e. For each stack provide an estimate based on engineering judgment of the fraction of the total emissions that is attributable to combustion of off
- gas from the petrochemical process unit. (ii) The combined CH 4 and N 2 O emissions from all stationary combustion units , expressed in metric tons of each gas and in metric tons of CO 2 e. (iii) The quantity of each type of fuel used in Equation C
- 8 in §98.33(c) for each stationary combustion unit or group of units (as applicable) during the reporting year, expressed in short tons for solid fuels, gallons for liquid fuels, and scf for gaseous fuels. (iv) The HHV (either default or annual average from measured data) used in Equation C
- 8 in §98.33(c) for each stationary combustion unit or group of combustion units (as applicable) . (6) ID or other appropriate descriptor of each stationary combustion unit that burns process off
- gas. (7) Information listed in §98. 256(e) of subpart Y of this part for each flare that burns process off
- gas. (8) Annual quantity of each type of petrochemical produced from each process unit (metric tons). (c) If you comply with the combustion methodology specified in §98.243(d), you mu st report under this subpart2 91

the information listed in paragraphs (c)(1) through (c)( 5 ) of this section. (1) The ethylene process unit ID or other appropriate descriptor. ( 2 ) For each stationary combustion unit that burns ethylene process off
- gas (or group of stationary sources with a common pipe), except flares, the relevant information listed in §98.36 for the applicable Tier methodology. For each stationary combustion unit or group of units (as applicable) that burns e thylene process off
gas, provide an estimate based on engineering judgment of the fraction of the total emissions that is attributable to combustion of off
- gas from the ethylene process unit. ( 3 ) Information listed in §98.256(e) of subpart Y of this part for each flare that burns ethylene process off
gas. ( 4 ) Name and annual quantity of each feedstock. ( 5 ) Annual quantity of ethylene produced from each process unit (metric tons). §98.247 Records that must be retained. In addition to the recordkeeping requirements in §98.3(g), you must retain the records specified in paragraphs (a) through (c) of this section, as app licable.292 (a) If you comply with the CEMS measurement methodology in §98.243(b), then you must retain under this subpart the records required for the Tier 4 Calculation Methodology in §98.37 , records of the procedures used to develop estimates of the fract ion of total emissions attributable to combustion of petrochemical process off
- gas as required in §98.246(b), and records of any annual average HHV calculations . (b) If you comply with the mass balance methodology in §98.243(c), then you must retain records of the information listed in paragraphs (b)(1) through (b)( 4 ) of this section. (1) Results of feedstock or product composition determinations conducted in accordance with §98.243(c)(4). (2) Start and end times and calculated carbon contents for time periods when off
- specification product is produced, if you comply with the alternative methodology in §98.243(c)(4) for determining carbon content of feedstock or product. (3) A part of the monitoring plan required under §98.3(g)(5), record the estimated accuracy of measurement devices and the technical basis for these estimates. (4) The dates and results (e.g., percent calibration error) of the calibrations of each measurement device.293 (c) If you comply with the combustion methodology in §98.243(d), then you must retain under this subpart the records required for the applicable Tier Calculation Methodologies in §98.37. If you comply with §98.243(d)(2), you must also keep records of the annual average flow calculations. §98.248 Definitions . Except as specified 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. Product, as used in §98.243, means each of the following carbon
- containing outputs from a process: the petrochemical, recovered byproducts, and liquid organic wastes that are not incinerated onsite. Product does not include process vent emissions, fugitive emissions, or wastewater. Subpart Y

—Petroleum Refineries §98.250 Definition of Source Category. (a) A petroleum refinery is any facility engaged in producing gasoline, gasoline blending stocks, naphtha, kerosene, distillate fuel oils, residual fuel oils, lubricants, or asphalt (bitumen) through distillation of petroleum or through redistillation, cracking, or reforming294

of unfinished petroleum derivatives, except as provided in paragraph (b) of this section. (b) For the purposes of this subpart, facilities that distill only pipeline transmix (off
- spec material created when different specification products mi x during pipeline transportation) are not petroleum refineries, regardless of the products produced. (c) This source category consists of the following sources at petroleum refineries: catalytic cracking units; fluid coking units; delayed coking units; c atalytic reforming units; coke calcining units; asphalt blowing operations; blowdown systems; storage tanks; process equipment components (compressors, pumps, valves, pressure relief devices, flanges, and connectors) in gas service; marine vessel, barge, t anker truck, and similar loading operations; flares; sulfur recovery plants; and non
merchant hydrogen plants (i.e., hydrogen plants that are owned or under the direct control of the refinery owner and operator). §98.251 Reporting threshold. You must repo rt GHG emissions under this subpart if your facility contains a petroleum refineries process and the facility meets the requirements of either §98.2(a)(1) or (a)(2).295

§98.252 GHGs to report. You must report: (a) CO 2 , CH 4 , and N 2 O combustion emissions from stationary combustion units and from each flare. Calculate and report the emissions from stationary combustion units under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C, except for emissions from combustion of fuel gas. For CO 2 emissions from combustion of fuel gas, use either E quation C
- 5 in subpart C of this part or the Tier 4 methodology in subpart C of this part , unless either of the conditions in paragraphs (a)(1) or (2 ) of this section are met, in which case use either Equations C
- 1 or C
- 2a in subpart C of this part . For CH 4 and N 2 O emissions from combustion of fuel gas, use the applicable procedures in § 98.33(c) for the same tier methodology that was used for calculat ing CO 2 emissions. ( Use the default CH 4 and N 2 O emission factors for “Petroleum (All fuel types in Table C
1)” in Table C
- 2 of this part. For Tier 3, use either the default high heat value for fuel gas in Table C
- 1 of subpart C of this part or a calculat ed HHV, as allowed in Equation C
- 8 of subpart C of this part. ) You may aggregate units, monitor common stacks, or monitor common (fuel) pipes as provided in §98.36(c) when calculating and296

reporting emissions from stationary combustion units. Calculate and report the emissions from flares under this subpart. (1) The annual average fuel gas flow rate in the fuel gas line to the combustion unit, prior to any split to individual burners or ports, does not exceed 3 4 5 standard cubic feet per minute at 6 0 oF and 14.7 pounds per square inch absolute and either of the conditions in paragraph (a)(1)(i) or (ii) of this section exist . Calculate the annual average flow rate using company records assuming total flow is evenly distributed over 525,600 minutes per year. (i) A flow meter is not installed at any point in the line supplying fuel gas or an upstream common pipe. (ii) The fuel gas line contains only vapors from loading or unloading, waste or wastewater handling, and remediation activities that are combusted in a thermal oxidizer or thermal incinerator. (2) The combustion unit has a maximum rated heat input capacity of less than 30 MMBtu/hr and either of the following conditions exist: (i) A flow meter is not installed at any point in the line supplying fuel gas or an upsteam common pipe ; or297 (ii) The fuel gas line contains only vapors from loading or unloading, waste or wastewater handling, and remediation activities that are combusted in a thermal oxidizer or thermal incinerator. (b) CO 2 , CH 4 , and N 2 O coke burn
- off emissions from each catalytic cracking unit, fluid coking unit, and catalytic reforming unit under this subpart. (c) CO 2 emissions from sour gas sent off site for sulfur recovery operations under this subpart. You must follow the calculation me thodologies from §98.253(f)and the monitoring and QA/QC methods, missing data procedures, reporting requirements, and recordkeeping requirements of this subpart. (d) CO 2 process emissions from each on
- site sulfur recovery plant under this subpart. (e) CO 2 , CH 4 , and N 2 O emissions from each coke calcining unit under this subpart. (f) CO 2 and CH 4 emissions from asphalt blowing operations under this subpart. (g) CH 4 emissions from equipment leaks, storage tanks, loading operations, delayed coking units, and uncontrolled blowdown systems under this subpart.298 (h) CO 2 , CH 4 , and N 2 O emissions from each process vent not specifically included in paragraphs (a) through (g) of this section under this subpart. (i) CO 2 emissions from non
-merchant hydrogen production process units (not including hydrogen produced from catalytic reforming units) under this subpart. You must follow the calculation methodologies, monitoring and QA/QC methods, missing data procedures, reporting requirements, and recordkeeping requirements of subpart P of this part. §98.253 Calculating GHG emissions. (a) Calculate GHG emissions required to be reported in §98.252(b) through (i) using the applicable methods in paragraphs (b) through (n) of this section. (b) For flares, calculat e GHG emissions according to the requirements in paragraphs (b)(1) through (b)(3) of this section. (1) Calculate the CO 2 emissions according to the applicable requirements in paragraphs (b)(1)(i) through (b)(1)(iii) of this section. (i) Flow measurement . If you have a continuous flow monitor on the flare, you must use the measured flow rates when the monitor is operational and the flow rate is within the calibrated range of the measurement device to calculate299

the flare gas flow. If you do not have a con tinuous flow monitor on the flare and for periods when the monitor is not operational or the flow rate is outside the calibrated range of the measurement device, you must use engineering calculations, company records, or similar estimates of volumetric fla re gas flow. (ii) Heat value or carbon content measurement . If you have a continuous higher heating value monitor or gas composition monitor on the flare or if you monitor these parameters at least weekly, you must use the measured heat value or carbon c ontent value in calculating the CO 2 emissions from the flare using the applicable methods in paragraphs (b)(1)(ii)(A) and (b)(1)(ii)(B). (A) If you monitor gas composition, calculate the CO 2 emissions from the flare using either Equation Y
- 1 a or Equation Y - 1b of this section. If daily or more frequent measurement data are available, you must use daily values when using Equation Y
- 1 a or Equation Y
- 1b of this section; otherwise, use weekly values.

###                       

     

## 

 n
p p p p CC MVC MW Flare CO 1 2 12

44 001
. 0 98
. 0 (Eq.Y
- 1 a )

Where:300

CO 2 = Annual CO 2 emissions for a specific fuel type

(metric tons/year). 0.98 = Assumed combustion efficiency of a flare. 0.001 = Unit conversion factor (metric tons per

kilogram, mt/kg). n = Number of measurement periods. The minimum

value for n is 52 (for weekly measurements); the maximum value for n is 366 (for daily measurements during a leap year). p = Measurement period index. 44 = Molecular weight of CO 2 (kg/kg
-mole). 12 = Atomic weight of C (kg/kg
-mole). (Flare) p = Volume of flare gas combusted during

measurement period (standard cubic feet per period, scf/period). If a mass flow meter is used, measure flare gas flow rate in kg/period and replace the term “(MW) p /MVC” with “1”. (MW) p = Average molecular weight of the flare gas

combusted during measurement period (kg/kg
mole). If measurements are taken more frequently than daily, use the arithmetic average of measurement values within the day to calculate a daily average. MVC = Molar volume conversion factor (849.5 scf/kg
mole at 68 oF and 14.7 pounds per square inch absolute ( psia ) or 836.6 scf/kg
-mole at 60 oF and 14.7 psia ). (CC) p = Average carbon content of the flare gas

combusted during measurement period (kg C per kg flare gas). If measurements are taken more frequently than daily, use the arithmetic average o f measurement values within the day to calculate a daily average. 

###       

##  

                               n
p y

x x p x p p CMN C CO MVC Flare CO 1 1 2 2 % 100 % 98
. 0 % 100 % 001
. 0 44 (Eq.Y
- 1b)

Where:301

CO 2 = Annual CO 2 emissions for a specific fuel type

(metric tons/year). n = Number of measurement periods. The minimum

value for n is 52 (for weekl y measurements); the maximum value for n is 366 (for daily measurements during a leap year). p = Measurement period index. (Flare) p = Volume of flare gas combusted during

measurement period (standard cubic feet per period, scf/period). If a mass flow mete r is used, you must determine the average molecular weight of the flare gas during the measurement period and convert the mass flow to a volumetric flow. 44 = Molecular weight of CO 2 (kg/kg
-mole). MVC = Molar volume conversion factor (849.5 scf/kg
mole at 68oF and 14.7 psia or 836.6 scf/kg
mole at 60oF and 14.7 psia). 0.001 = Unit conversion factor (metric tons per

kilogram, mt/kg). (%CO 2 ) p = Mole percent CO 2 concentration in the flare

gas stream during the measurement period (mole percent = percent by volume). y = Number of carbon
- containing compounds other

than CO 2 in the flare gas stream.
x = Index for carbon
- containing compounds other

than CO 2 . 0.98 = Assumed combustion efficiency of a flare (mole

CO 2 per mole carbon). (%C x ) p = Mole percent concentration of compound “x” in

the flare gas stream during the measurement period (mole percent = percent by volume) CMNx = Carbon mole number of compound “x” in the

flare gas stream (mole carbon atoms per mole compound). E.g., CMN for ethane (C 2 H 6 ) is 2; CMN for propane (C 3H 8 ) is 3. (B) If you monitor heat content but do not monitor gas composition, calculate the CO 2 emissions from the flare302

using Equation Y
- 2 of this section. If daily or more frequent measurement data are available, you must use daily values when using Equation Y
- 2 of this section; otherwise, use weekly values. 

##    



#   

 

    n
p p

p EmF HHV Flare CO 1 2 001

. 0 98
. 0 (Eq.Y
- 2) Where:
CO 2 = Annual CO 2 emissions for a specific fuel type

(metric tons/year). 0.98 = Assumed combustion efficiency of a flare. 0.001 = Unit conversion factor (metric tons per

kilogram, mt/kg). n = Number of measurement periods. The minimum

value for n is 52 (for weekly measurements); the maximum value for n is 366 (for daily measurements during a leap year). p = Measurement period index. (Flare) p = Volume of flare gas combusted during

measurement period (million (MM) scf/period). If a mass flow meter is used, you must also measure molecular weight and convert the mass flow to a volumetric flow as follows: Flare[MMscf] = 0.000001 × Flare[kg] × MVC/(MW) p , where MVC is the molar volume conversion factor (849.5 scf/kg
-mole) and (MW) p is the average molecular weight of the flare gas combusted during measurement period (kg/kg
-mole). (HHV) p = Higher heating value for the flare gas

combusted during measurement period (British thermal units per scf, Btu/scf = MMBtu/MMscf). If measurements are taken more frequently than daily, use the arithmetic average of measurement values within the day to calculate a daily average.303

EmF = Default CO 2 emission factor of 60 kilograms

CO 2 /MMBtu (HHV basis). (iii) Alternative to heat value or carbon content measurements . If you do not measure the higher heating value or carbon content of the flare gas at least weekly, determine the quantity of gas discharged to the flare separately for periods of routine flare operation and for periods of start
- up, shutdown, or malfunction, and calculate the CO 2 emissions as specified in paragraphs (b)(1)(iii)(A) through (b)(1)(iii)(C) of this section. (A) For periods of start
- up, shutdown, or malfunction, use engineering calculations and process knowledge to estimate the carbon content of the flared gas for each start
- up, shutdown, or malfunction event exceeding 500,000 scf/day. (B) For periods of normal operation, use the average heating va lue measured for the fuel gas for the heating value of the flare gas. If heating value is not measured, the heating value may be estimated from historic data or engineering calculations. (C) Calculate the CO 2 emissions using Equation Y
- 3 of this section.                     

        

### 

 n
p p p p SSM Norm CC MVC MW Flare EmF HHV Flare CO 1 2 12 44 001
. 0 98
. 0 (Eq.Y
- 3) Where:304

CO 2 = Annual CO 2 emissions for a specific fuel type

(metric tons/year). 0.98 = Assumed combustion efficiency of a flare. 0.001 = Unit conversion factor (metric tons per

kilogram, mt/kg). Flare Norm = Annual volume o f flare gas combusted during

normal operations from company records, (million (MM) standard cubic feet per year, MMscf/year). HHV = Higher heating value for fuel gas or flare gas

from company records (British thermal units per scf, Btu/scf = MMBtu/MMscf). EmF = Default CO 2 emission factor for flare gas of

60 kilograms CO 2 /MMBtu (HHV basis). n = Number of start
- up, shutdown, and malfunction

events during the reporting year exceeding 500,000 scf/day. p = Start - up, shutdown, and malfunction event

index. 44 = Molecular weight of CO 2 (kg/kg
-mole). 12 = Atomic weight of C (kg/kg
-mole). (Flare SSM ) p = Volume of flare gas combusted during indexed

start - up, shutdown, or malfunction event from engineering calculations, (scf/event). (MW) p = Average molecular weight of the flare gas,

from the analysis results or engineering calculations for the event (kg/kg
-mole). MVC = Molar volume conversion factor (849.5 scf/kg
mole at 68 oF and 14.7 psia or 836.6 scf/kg
mole at 60 oF and 14.7 psia ). (CC) p = Average carbon content of the flare gas, from

analysis results or engineering calculations for the event (kg C per kg flare gas). (2) Calculate CH 4 using Equation Y
- 4 of this section.

4 2 CH4 2 4 44 16 98
. 0 02
. 0 EmF EmF CO CH CH f CO 

           (Eq. Y
- 4)305

Where:
CH 4 = Annual methane emissions from flared gas

(metric t ons CH 4 /year). CO 2 = Emission rate of CO 2 from flared gas

calculated in paragraph (b)(1) of this section (metric tons/year). EmFCH4 = Default CH 4 emission factor for

“PetroleumProducts” from Table C
- 2 of subpart C of this part (General Stationary Fuel Combustion Sources) (kg CH 4 /MMBtu). EmF = Default CO 2 emission factor for flare gas of

60 kg CO 2 /MMBtu (HHV basis). 0.02/0.98 = correction factor for flare combustion

efficiency. 16/44 = correction factor ratio of the molecular

weight of CH 4 to CO 2 f CH4 = Wei ght fraction of carbon in the flare gas

prior to combustion that is contributed by methane from measurement values or engineering calculations (kg C in methane in flare gas/kg C in flare gas); default is 0.4. (3) Calculate N 2 O emissions using Equation Y
- 5 of this section.         EmF

EmF CO O N N2O

2 2 (Eq. Y
- 5) Where:
N 2 O = Annual nitrous oxide emissions from flared gas

(metric tons N 2 O/year). CO 2 = Emission rate of CO 2 from flared gas calculated in

paragraph (b)(1) of this section (metric tons/year). EmFN2O = De fault N 2 O emission factor for

“PetroleumProducts” from Table C
- 2 of subpart C of this part (General Stationary Fuel Combustion Sources)(kg N 2 O/MMBtu).306

EmF = Default CO 2 emission factor for flare gas of 60 kg

CO 2 /MMBtu (HHV basis). (c) For catalytic cracki ng units and traditional fluid coking units, calculate the GHG emissions using the applicable methods described in paragraphs (c)(1) through (c)(5) of this section. (1) If you operate and maintain a CEMS that measures CO 2 emissions according to subpart C of this part (General Stationary Fuel Combustion Sources), you must calculate and report CO 2 emissions as provided in paragraphs (c)(1)(i) and (c)(1)(ii) of this section. Other catalytic cracking units and traditional fluid coking units must either instal l a CEMS that complies with the Tier 4 Calculation Methodology in subpart C of this part (General Stationary Combustion Souces), or follow the requirements of paragraphs (c)(2) or (3) of this section. (i) Calculate CO 2 emissions by following the Tier 4 Calculation Methodology specified in §98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources). (ii) For catalytic cracking units whose process emissions are discharged through a combine d stack with other CO 2 emissions (e.g., co
-mingled with emissions from a CO boiler ) you must also calculate the other CO 2 emissions using the applicable methods for the applicable subpart307

(e.g., subpart C of this part in the case of a CO boiler) . Calculate the process emissions from the catalytic cracking unit or fluid coking unit as the difference in the CO 2 CEMS emissions and the calculated emissions associated with the additional units discharging through the combined stack. (2) For catalytic cracking units and fluid coking units with rated capacities greater than 10,000 barrels per stream day (bbls/sd) that do not use a continuous CO 2 CEMS for the final exhaust stack, you must continuously or no less frequently than hourly monitor the O 2 , CO 2 , and (if necessary) CO concentrations in the exhaust stack from the catalytic cracking unit regene rator or fluid coking unit burner prior to the combustion of other fossil fuels and calculate the CO 2 emissions according to the requirements of paragraphs (c)(2)(i) through (c)(2)(iii) of this section: (i) Calculate the CO 2 emissions from each catalytic cracking unit and fluid coking unit using Equation Y
- 6 of this section. 

##    



## 

            n
p p

p r MVC

CO CO Q CO 1 2 2 001
. 0 44 % 100 % % (Eq. Y
- 6) Where:
CO 2 = Annual CO 2 mass emissions (metric tons/year). Q r = Volumetric flow rate of exhaust gas from the

fluid catalytic cracking unit regenerator o r fluid coking unit burner prior to the combustion308 of other fossil fuels (dry standard cubic feet per hour, dscfh). %CO 2 = Hourly average percent CO 2 concentration in the

exhaust gas stream from the fluid catalytic cracking unit regenerator or fluid coking unit burner (percent by volume

– dry basis). %CO = Hourly average percent CO concentration in the

exhaust gas stream from the fluid catalytic cracking unit regenerator or fluid coking unit burner (percent by volume

– dry basis). When there is no post
- combustion device, assume %CO to be zero. 44 = Molecular weight of CO 2 (kg/kg
-mole). MVC = Molar volume conversion factor (849.5 scf/kg
mole at 68 oF and 14.7 psia or 836.6 scf/kg
-mole at 60 oF and 14.7 psia ). 0.001 = Conversion factor (metric ton/kg). n = Number of hours in calendar year. (ii) Either continuously monitor the volumetric flow rate of exhaust gas from the fluid catalytic cracking unit regenerator or fluid coking unit burner prior to the combustion of other fossil fuels or calculate the volumetr ic flow rate of this exhaust gas stream using either Equation Y
- 7 a or Equation Y
- 7b of this section.



#  

2 2 % % % 100 *

) % 100 ( * 79 O

CO CO Q O Q Q oxy oxy a r



   
 (Eq. Y
- 7 a ) Where: Q r = Volumetric flow rate of exhaust gas from the

fluid catalytic cracking unit regenerator or fluid coking unit burner prior to the combustion of other fossil fuels (dscfh). Q a = Volumetric flow rate of air to the fluid

catalytic cracking unit regenerator or fluid309 coking unit burner, as determined from control room instrumentation (dscfh). Q oxy = Volumetric flow rate of oxygen enriched air to

the fluid catalytic cracking unit regenerator or fluid coking unit burner as determined from control room instrumentation (dscfh). %O 2 = Hourly average percent oxygen concentration in

exhaust gas stream from the fluid catalytic cracking unit regene rator or fluid coking unit burner (percent by volume

– dry basis). %O oxy = O 2 concentration in oxygen enriched gas stream

inlet to the fluid catalytic cracking unit regenerator or fluid coking unit burner based on oxygen purity specifications of the oxygen supply used for enrichment (percent by volume

– dry basis). %CO 2 = Hourly average percent CO 2 concentration in the

exhaust gas stream from the fluid catalytic cracking unit regenerator or fluid coking unit burner (percent by volume

– dry basis). %CO = Hou rly average percent CO concentration in the

exhaust gas stream from the fluid catalytic cracking unit regenerator or fluid coking unit burner (percent by volume

– dry basis). When no auxiliary fuel is burned and a continuous CO monitor is not required under 40 CFR part 63 subpart UUU, assume %CO to be zero. 

#  

exhaust oxy oxy a r N Q

N Q Q

, 2 , 2 % *

) (% * 1
. 78 
 (Eq. Y
- 7b)
Where: Q r = Volumetric flow rate of exhaust gas from the

fluid catalytic cracking unit regenerator or fluid coking unit burner prior to the combustion of other foss il fuels (dscfh). Q a = Volumetric flow rate of air to the fluid

catalytic cracking unit regenerator or fluid coking unit burner, as determined from control room instrumentation (dscfh).310

Q oxy = Volumetric flow rate of oxygen enriched air to

the fluid catalytic cracking unit regenerator or fluid coking unit burner as determined from control room instrumentation (dscfh). %N 2,oxy = N 2 concentration in oxygen enriched gas stream

inlet to the fluid catalytic cracking unit regenerator or fluid coking unit burner b ased on measured value or maximum N 2 impurity specifications of the oxygen supply used for enrichment (percent by volume

– dry basis). %N 2,exhaust = Hourly average percent N 2 concentration in the

exhaust gas stream from the fluid catalytic cracking unit re generator or fluid coking unit burner (percent by volume

– dry basis ) . (iii) If you have a CO boiler that uses auxiliary fuels or combusts materials other than catalytic cracking unit or fluid coking unit exhaust gas, you must determine the CO 2 emissions resulting from the combustion of these fuels or other materials following the requirements in subpart C and report those emissions by following the requirements of subpart C of this part. (3) For catalytic cracking units and fluid coking units with rated capacities of 10,000 barrels per stream day (bbls/sd) or less that do not use a continuous CO 2 CEMS for the final exhaust stack, comply with the requirements in paragraphs (c)(3)(i) of this section or paragraphs (c)(3)(ii) and (c)(3)(iii) of this section, as applicable. (i) If you continuously or no less frequently than daily monitor the O 2 , CO 2 , and (if necessary) CO concentrations in the exhaust stack from the catalytic311

cracking unit regenerator or fluid coking unit burner prior to the combustion of other fossil fuels, you must calculate the CO 2 emissions according to the requirements of paragraphs (c)(2)(i) through (c)(2)(iii) of this section, except that daily averages are allowed and the summation can be performed on a daily basis. (ii) If you do n ot monitor at least daily the O 2 , CO 2 , and (if necessary) CO concentrations in the exhaust stack from the catalytic cracking unit regenerator or fluid coking unit burner prior to the combustion of other fossil fuels, calculate the CO 2 emissions from each c atalytic cracking unit and fluid coking unit using Equation Y
- 8 of this section. 

##   12 44 001
. 0 2 

    CC CBF Q CO unit (Eq. Y
- 8) Where:
CO 2 = Annual CO 2 mass emissions (metric tons/year). Qunit = Annual throughput of unit from company records

(barrels (bbls) per year, bb l/yr). CBF = Coke burn
- off factor from engineering

calculations (kg coke per barrel of feed); default for catalytic cracking units = 7.3; default for fluid coking units = 11. 0.001 = Conversion factor (metric ton/kg). CC = Carbon content of coke based on measurement or

engineering estimate (kg C per kg coke); default = 0.94. 44/12 = Ratio of molecular weight of CO 2 to C (kg CO 2

per kg C).312 (iii) If you have a CO boiler that uses auxiliary fuels or combusts materials other than catalytic cracking unit or fl uid coking unit exhaust gas, you must determine the CO 2 emissions resulting from the combustion of these fuels or other materials following the requirements in subpart C of this part (General Stationary Fuel Combustion Sources) and report those emissions b y following the requirements of subpart C of this part. (4) Calculate CH 4 emissions using either unit specific measurement data, a unit
- specific emission factor based on a source test of the unit, or Equation Y
- 9 of this section.        
 1 2 2 4 EmF

EmF * CO CH (Eq . Y - 9) Where:
CH 4 = Annual methane emissions from coke burn
- off

(metric tons CH 4 /year). CO 2 = Emission rate of CO 2 from coke burn
- off calculated

in paragraphs (c)(1), (c)(2), (e)(1), (e)(2), (g)(1), or (g)(2) of this section, as applicable (metric tons/yea r). EmF 1 = Default CO 2 emission factor for petroleum coke

from Table C
- 1 of subpart C of this part (General Stationary Fuel Combustion Sources) (kg CO 2 /MMBtu). EmF 2 = Default CH 4 emission factor for

”PetroleumProducts” from Table C
- 2 of subpart C of this part (General Stationary Fuel Combustion Sources) (kg CH 4 /MMBtu). (5) Calculate N 2 O emissions using either unit specific measurement data, a unit
- specific emission factor based on313

a source test of the unit, or Equation Y
- 10 of this section.        
 1 3 2 2 EmF

EmF * CO O N (Eq. Y
- 10) Where:
N 2 O = Annual nitrous oxide emissions from coke burn
- off

(mt N 2 O/year). CO 2 = Emission rate of CO 2 from coke burn
- off calculated

in paragraphs (c)(1), (c)(2), (e)(1), (e)(2), (g)(1), or (g)(2) of this section, as applicable (metric tons/year). EmF 1 = Default CO 2 emission factor for petroleum coke

from Table C
- 1 of subpart C of this part (General Stationary Fuel Combustion Sources) (kg CO 2 /MMBtu). EmF 3 = Default N 2 O emission factor for

”PetroleumProducts” from Table C
- 2 of subpart C o f this part (kg N 2 O/MMBtu). (d) For fluid coking units that use the flexicoking design, the GHG emissions from the resulting use of the low value fuel gas must be accounted for only once. Typically, these emissions will be accounted for using the methods described in subpart C of this part (General Stationary Fuel Combustion Sources). Alternatively, you may use the methods in paragraph (c) of this section provided that you do not otherwise account for the subsequent combustion of this low value fuel gas. (e) For catalytic reforming units, calculate the CO 2 emissions using the applicable methods described in314

paragraphs (e)(1) through (e)(3) of this section and calculate the CH 4 and N 2 O emissions using the methods described in paragraphs (c)(4) and (c)(5) of this section, respectively. (1) If you operate and maintain a CEMS that measures CO 2 emissions according to subpart C of this part (General Stationary Fuel Combustion Sources), you must calculate CO 2 emissions as provided in paragraphs (c)(1)(i) and ( c)(1)(ii) of this section. Other catalytic reforming units must either install a CEMS that complies with the Tier 4 Calculation Methodology in subpart C of this part, or follow the requirements of paragraph (e)(2) or (e)(3) of this section. (2) If you continuously or no less frequently than daily monitor the O 2 , CO 2 , and (if necessary) CO concentrations in the exhaust stack from the catalytic reforming unit catalyst regenerator prior to the combustion of other fossil fuels, you must calculate the CO 2 emis sions according to the requirements of paragraphs (c)(2)(i) through (c)(2)(iii) of this section. (3) Calculate CO 2 emissions from the catalytic reforming unit catalyst regenerator using Equation Y
- 11 of this section.315 

#          

   n
n

Q CC CB CO 1 2 001
. 0 12 44 (Eq. Y
- 11) Where : CO 2 = Annual CO 2 emissions (metric tons/year). CB Q = Coke burn
- off quantity per regeneration cycle or

measurement period from engineering estimates (kg coke/cycle or kg coke/measurement period ). n = Number of regeneration cycles or measurement

periods i n the calendar year. CC = Carbon content of coke based on measurement or

engineering estimate (kg C per kg coke); default = 0.94. 44/12 = Ratio of molecular weight of CO 2 to C (kg CO 2 per

kg C). 0.001 = Conversion factor (metric ton/kg). (f) For on
- site sulfur recovery plants and for sour gas sent off site for sulfur recovery , calculate and report CO 2 process emissions from sulfur recovery plants according to the requirements in paragraphs (f)(1) through (f)(5) of this section , or, for non
- Claus sulfur re covery plants, according to the requirements in paragraph (j) of this section regardless of the concentration of CO 2 in the vented gas stream . Combustion emissions from the sulfur recovery plant (e.g., from fuel combustion in the Claus burner or the tail gas treatment incinerator) must be reported under subpart C of this part (General Stationary Fuel Combustion Sources). For the purposes of this subpart, the sour gas stream for which monitoring is required according to316

paragraphs (f)(2) through (f)(5) of this section is not considered a fuel. (1) If you operate and maintain a CEMS that measures CO 2 emissions according to subpart C of this part, you must calculate CO 2 emissions under this subpart by following the Tier 4 Calculation Methodology specified in §98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources). You must monitor fuel use in the Claus burner, tail gas incinerator, or other combustion sources that discharge via the final exhaust stack from the sulfur recovery plant and calculate the combustion emissions from the fuel use according to subpart C of this part. Calculate the process emissions from the sulfur recovery plant as the difference in the CO 2 CEMS emissions and the c alculated combustion emissions associated with the sulfur recovery plant final exhaust stack. Other sulfur recovery plants must either install a CEMS that complies with the Tier 4 Calculation Methodology in subpart C, or follow the requirements of paragraphs (f)(2) through (f)(5) of this section , or (for
non - Claus sulfur recovery plants only) follow the requirements in paragraph (j) of this section to determine CO 2 emissions for the sulfur recovery plant .317 (2) Flow measurement. If you have a continuous flow monitor on the sour gas feed to the sulfur recovery plant, you must use the measured flow rates when the monitor is operational to calculate the sour gas flow rate. If you do not have a continuous flow monitor on the sour gas feed to the sulfur recovery plant, you must use engineering calculations, company records, or similar estimates of volumetric sour gas flow. (3) Carbon content. If you have a continuous gas composition monitor capable of measuring carbon content on the sour gas feed to the sul fur recovery plant or if you monitor gas composition for carbon content on a routine basis, you must use the measured carbon content value. Alternatively, you may develop a site
- specific carbon content factor using limited measurement data or engineering estimates or use the default factor of 0.20. (4) Calculate the CO 2 emissions from each sulfur recovery plant using Equation Y
- 12 of this section.
001
. 0 * * 44 * 2 C SG MF MVC F CO  (Eq. Y
- 12) Where:
CO 2 = Annual CO 2 emissions (metric tons/year). F SG = Volumetric flow rate of sour gas feed (including

sour water stripper gas) to the sulfur recovery plant (scf/year).318

44 = Molecular weight of CO 2 (kg/kg
-mole). MVC = Molar volume conversion factor (849.5 scf/kg
-mole

at 68 oF and 14.7 psia or 836.6 scf/kg
-mole at 60 oF and 14.7 psia ). MFC = Mole fraction of carbon in the sour gas to the

sulfur recovery plant (kg
-mole C/kg
-mole gas); default = 0.20. 0.001 = Conversion factor, kg to metric tons (5) If tail gas is recycled to the front of the sulfur recovery plant and the recycled flow rate and carbon content is included in the measured data under paragraphs (f)(2) and (f)(3) of this section, respectively, then the annual CO 2 emissions calculated in paragraph (f)(4) of this section must be corrected to avoid double counting these emissions. You may use engineering estimates to perform this correction or assume that the corrected CO 2 emissions are 95 percent of the uncorrected value calculated using Equation Y
- 12 of this section. (g) For coke calcining units, calculate GHG emissions according to the applicable provisions in paragraphs (g)(1) through (g)(3) of this section. (1) If you operate and maintain a CEMS that measures CO 2 emissions according to subpart C of this part, you must calculate and report CO 2 emissions under this subpart by fol lowing the Tier 4 Calculation Methodology specified in §98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion319

Sources). You must monitor fuel use in the coke calcining unit that discharges via the final exhaust stack from the coke calcining unit and calculate the combustion emissions from the fuel use according to subpart C of this part. Calculate the process emissions from the coke calcining unit as the difference in the CO 2 CEMS emissions and the calculated combustion emissions associated with the coke calcining unit final exhaust stack. Other coke calcining units must either install a CEMS that complies with the Tier 4 Calculation Methodology in subpart C of this part, or follow the requirements of paragraph (g)(2) of this section. (2) Calculate the CO 2 emissions from the coke calcining unit using Equation Y
- 13 of this section. 

##     MPC dust out GC in CC

M M CC M CO *

* * 12 44 2 

  (Eq. Y
- 13) Where:
CO 2 = Annual CO 2 emissions (metric tons/year). Min = Annual mass of green coke fed to the coke

calcining unit from facility records (metric tons/year). CC GC = Average mass fraction carbon content of green

coke from facility measurement data (metric ton carbon/metric ton green coke). Mout = Annual mass of marketable petroleum coke

produced by the c oke calcining unit from facility records (metric tons petroleum coke/year).320

Mdust = Annual mass of petroleum coke dust removed from

the process through the dust collection system of the coke calcining unit from facility records (metric ton pet roleum coke dust/year) . For coke calcining units that recycle the collected dust, the mass of coke dust removed from the process is the mass of coke dust collected less the mass of coke dust recycled to the process. CCMPC = Average mass fraction carbon content of

marketable petroleum coke produced by the coke calcining unit from facility measurement data (metric ton carbon/metric ton petroleum coke). 44 = Molecular weight of CO 2 (kg/kg
-mole). 12 = Atomic weight of C (kg/kg
-mole). (3) For all coke calcining units, use the CO 2 emissions from the coke calcining unit calculated in paragraphs (g)(1) or (g)(2), as applicable, and calculate CH 4 using the methods described in paragraph (c)(4) of this section and N 2 O emissions using the methods described in paragraph (c)(5) of this section. (h) For asphalt blowing operations, calculate CO 2 and CH 4 emissions according to the requirements in paragraph (j) of this section regardless of the CO 2 and CH 4 concentrations or according to the applicable provisions in paragraphs (h)(1) and (h)(2) of this section. (1) For uncontrolled asphalt blowing operations or asphalt blowing operations controlled by vapor scrubbing, calculate CO 2 and CH 4 emissions using Equations Y
- 14 and Y
15 of this section, respectively.321 

##  

2
. 2 CO

AB AB EF Q CO   (Eq. Y
- 14) Where:
CO 2 = Annual CO 2 emissions from uncontrolled asphalt

blowing (metric tons CO 2 /year). QAB = Quantity of asphalt blown (million barrels per

year, MMbbl/year). EFAB,CO2 = Emission factor for CO 2 from uncontrolled asphalt

blowing from facility
- specific test data (metric tons CO 2 /MMbbl asphalt blown); default = 1,100.



##   4 , 4 CH

AB AB EF Q CH   (Eq. Y
- 15) Where:
CH 4 = Annual methane emissions from uncontrolled

asphalt blowing (metric tons CH 4 /year). QAB = Quantity of asphalt blown (milli on barrels per

year, MMbbl/year). EFAB,CH4 = Emission factor for CH 4 from uncontrolled asphalt

blowing from facility
- specific test data (metric tons CH 4 /MMbbl asphalt blown); default = 580. (2) For asphalt blowing operations controlled by thermal oxidizer or flare, calculate CO 2 using either Equation Y - 16 a or Equation Y
- 16b of this section and calculate CH 4 emissions using Equation Y - 17 of this section, provided these emissions are not already included in the flare emission s calculated in paragraph (b) of this section or in the stationary combustion unit emissions required under subpart C of this part (General Stationary Fuel Combustion Sources).           12 44 98
. 0 2 AB

AB CEF Q CO (Eq. Y
- 16 a )322

Where:
CO 2 = Annual CO 2 emissions from controlled asphalt

blowing (metric tons CO 2 /year). 0.98 = Assumed combustion efficiency of thermal oxidizer

or flare. QAB = Quantity of asphalt blown (MMbbl/year). CEFAB = Carbon emission factor from asphalt blowing from

facility
- specific test data (metric tons C/MMbbl asphalt blown); default = 2,750. 44 = Molecular weight of CO 2 (kg/kg
-mole). 12 = Atomic weight of C (kg/kg
-mole).              



           2 , 2 , 2 12 44 98
. 0 CO AB AB CO AB AB EF CEF EF Q CO (Eq. Y
- 16b) Where:
CO 2 = Annual CO 2 emissions from controlled asphalt

blowing (metric tons CO 2 /year). QAB = Quantity of asphalt blown (MMbbl/year). 0.98 = Assumed combustion efficiency of thermal oxidizer

or flare. EFAB,CO2 = Emission factor for CO 2 from uncontrolled asphalt

blowing from facility
- specific test data (metric tons CO 2 /MMbbl asphalt blown); default = 1,100. CEFAB = Carbon emission factor from asphalt blowing from

facility
- specific test data (metric tons C/MMbbl asphalt blown); default = 2,750. 44 = Molecular weight of CO 2 (kg/kg
-mole). 12 = Atomic weight of C (kg/kg
-mole). 

##   4 , 4 02
. 0 CH AB AB EF Q CH 

  (Eq. Y
- 17) Where:
CH 4 = Annual methane emissions from controlled asphalt

blowing (metric tons CH 4 /year).323

0.02 = Fraction of methane uncombusted in thermal

oxidizer or flare based on assumed 98% combustion efficiency. QAB = Quantity of asphalt blown (million barrels per

year, MMbbl/year). EFAB,CH4 = Emission factor for CH 4 from uncontrolled asphalt

blowing from facility
- specific test data (metric tons CH 4 /MMbbl asphalt blown); default = 580. (i) For delayed coking units, calculate the CH 4 emissions from the depre ssurization of the coking unit vessel (i.e., the "coke drum") to atmosphere using either of the methods provided in paragraphs (i)(1) or (i)(2), provided no water or steam is added to the vessel once it is vented to the atmosphere. You must use the method in paragraph (i)(1) of this section if you add water or steam to the vessel after it is vented to the atmosphere. (1) Use the process vent method in paragraph (j) of this section to calculate the CH 4 emissions from the depressurization of the coke drum o r vessel regardless of the CH 4 concentration and also calculate the CH 4 emissions from the subsequent opening of the vessel for coke cutting operations using Equation Y - 18 of this section. If you have coke drums or vessels of different dimensions, use the process vent method in paragraph (j) of this section and Equation Y
- 18 for each set of coke drums or vessels of the same size and sum the resultant emissions across each set324

of coke drums or vessels to calculate the CH 4 emissions for all delayed coking un its.



##                     001
. 0 16 4 7
. 14 7
. 14 4 2 4 CH void CV MF MVC D f P H N CH  (Eq. Y
- 18) Where:
CH 4 = Annual methane emissions from the delayed coking

unit vessel opening (metric ton/year). N = Cumulative number of vessel openings for all

delayed coking unit vessels of the same dimensions during the year. H = Height of coking unit vessel (feet). P CV = Gauge pressure of the coking vessel when opened

to the atmosphere prior to coke cutting or, if the alternative method provided in paragraph (i)(2) of this section is used, gauge pressure of the coking vessel when depressurization gases are first routed to the atmosphere (pounds per square inch gauge, psig) 14.7 = Assumed atmospheric pressure (pounds per square

inch, psi) fvoid = Volumetric void fraction of coking vessel prior

to steaming (cf gas/cf of vessel); default = 0.6. D = Diameter of coking unit vessel (feet). 16 = Molecular weight of CH 4 (kg/kg
-mole). MVC = Molar volume conversion factor (849.5 scf/ kg
mole at 68 oF and 14.7 psia or 836.6 scf/kg
-mole at 60 oF and 14.7 psia ). MFCH4 = Mole fraction of methane in coking vessel gas

(kg
-mole CH 4 /kg
-mole gas, wet basis); default value is 0.01. 0.001 = Conversion factor (metric ton/kg). (2) Calculate the CH 4 emissions from the depressurization vent and subsequent opening of the vessel for coke cutting operations using Equation Y - 18 of this325

section and the pressure of the coking vessel when the depressurization gases are first routed to the atmosphere. If you have coke drums or vessels of different dimensions, use Equation Y
- 18 for each set of coke drums or ves sels of the same size and sum the resultant emissions across each set of coke drums or vessels to calculate the CH 4 emissions for all delayed coking units. (j) For each process vent not covered in paragraphs (a) through (i) of this section that can be rea sonably expected to contain greater than 2 percent by volume CO 2 or greater than 0.5 percent by volume of CH 4 or greater than 0.01 percent by volume (100 parts per million) of N 2 O, calculate GHG emissions using the Equation Y
- 19 of this section. You must use Equation Y
- 19 of this section to calculate CH 4 emissions for catalytic reforming unit depressurization and purge vents when methane is used as the purge gas or if you elected this method as an alternative to the methods in paragraphs (f), (h) , or (k ) of this section. 

##      



## 

       

    N
p p x p x p x VT MVC MW MF VR E 1 001
. 0 (Eq. Y
- 19) Where:
E x = Annual emissions of each GHG from process vent

(metric ton/yr). N = Number of venting events per year.326

P = Index of venting events. (VR) p = Average volumetric flow rate of process gas

during the event (scf per hour) from measurement data, process knowledge, or engineering estimates . (MFx ) p = Mole fraction of GHG x in process vent during

the event (kg
-mol of GHG x/kg
-mol vent gas) from measurement data, process knowledge, or engineering estimates . MWx = Molecular weight of GHG x (kg/kg
-mole); use 44

for CO 2 or N 2 O and 16 for CH 4 . MVC = Molar volume conversion factor (849.5 scf/kg
mole at 68 oF and 14.7 psia or 836.6 scf/kg
-mole at 60 oF and 14.7 psia ). (VT) p = Venting time for the event, (hours). 0.001 = Conversion factor (metric ton/kg) (k) For uncontrolled blowdown systems, you must calculate CH4 emissions either using the methods for process vents in paragraph (j) of this section regardless of the CH 4 concentration or using Equation Y-20 of this section. Blowdown systems where the uncondensed gas stream is routed to a flare or similar control device is considered to be controlled and is not required to estimate emissions under this paragraph (k).       

   001
. 0 16 Re 4 MVC

EF Q CH BD

f (Eq. Y
- 20) Where:
CH 4 = Methane emission rate from blowdown systems (mt

CH 4 /year). QRef = Quantity of crude oil plus the quantity of

intermediate products received from off site that are processed at the facility (MMbbl/year).327

EFBD = Methane emi ssion factor for uncontrolled blown

systems (scf CH 4 /MMbbl); default is 137,000. 16 = Molecular weight of CH 4 (kg/kg
-mole). MVC = Molar volume conversion factor (849.5 scf/kg
mole at 68 oF and 14.7 psia or 836.6 scf/kg
-mole at 60 oF and 14.7 psia ). 0.001 = Conversion factor (metric ton/kg). (l) For equipment leaks, calculate CH 4 emissions using the method specified in either paragraph (l)(1) or (l)(2) of this section. (1) Use process
- specific methane composition data (from measurement data or process knowledge) and any of the emission estimation procedures provided in the Protocol for Equipment Leak Emissions Estimates (EPA
- 453/R
- 95
- 017, NTIS PB96
- 175401). (2) Use Equation Y
- 21 of this section. 

##   FGS H PU PU CD N N N N N CH           6 3
. 4 1
. 0 2
. 0 4
. 0 2 2 1 4 (Eq. Y
- 21) Where:
CH 4 = Annual methane emissions from equipment leaks

(metric tons/year) NCD = Number of atmospheric crude oil distillation

columns at the facility. N PU1 = Cumulative number of catalytic cracking units,

coking units (delayed or fluid), hydrocracking, and full
- range distillation columns (including depropanizer and debutanizer distillation columns) at the facility. N PU2 = Cumulative number of hydrotreating/hydrorefining

units, catalytic reforming units, and visbreaking units at the facility. NH2 = Total number of hydrogen plants a t the facility.328

N FGS = Total number of fuel gas systems at the facility. (m) For storage tanks, except as provided in paragraph (m)( 4 ) of this section, calculate CH 4 emissions using the applicable methods in paragraphs (m)(1) through (m)( 3 ) of this section. (1) For storage tanks other than those processing unstabilized crude oil, you must either calculate CH 4 emissions from storage tanks that have a vapor
-phase methane concentration of 0.5 volume percent or more using tank
- specific methane compositi on data (from measurement data or product knowledge) and the AP
- 42 emission estimation methods provided in Section 7.1 of the AP
- 42: “Compilation of Air Pollutant Emission Factors, Volume 1: Stationary Point and Area Sources”, including TANKS Model (Version 4.09D) or similar programs, or estimate CH 4 emissions from storage tanks using Equation Y
- 22 of this section. 

#   f Q CH Re 4 1
. 0   (Eq. Y
- 22) Where:
CH 4 = Annual methane emissions from storage tanks

(metric tons/year). 0.1 = Default emission factor for storage tanks (metric

ton CH 4 /MMbbl). QRef = Quantity of crude oil plus the quantity of

intermediate products received from off site that are processed at the facility (MMbbl/year).329 (2) For storage tanks that process unstabilized crude oil, calculate CH 4 emissions from the storage of unstabilized crude oil using either tank
- specific methane composition data (from measurement data or product knowledge) and direct measurement of the gas generation rate or by using Equation Y
- 23 of this section.
001
. 0 16 ) 000 , 995 ( 4 4        MVC

MF P Q CH CH un (Eq. Y
- 23) Where:
CH 4 = Annual methane emissions from storage tanks

(metric tons/year). Qun = Quantity of unstabilized crude oil received at

the facility (MMbbl/year). ΔP = Pressure differential from the previous storage

pressure to atmospheric pressure (pounds per square inch, psi). MFCH4 = Average mole fraction of CH 4 in vent gas from the

unstabilized crude oil storage tank s from facility measurements (kg
-mole CH 4 /kg
-mole gas); use 0.27 as a default if measurement data are not available. 995,0 00 = Correlation Equation factor (scf gas per MMbbl

per psi) 16 = Molecular weight of CH 4 (kg/kg
-mole). MVC = Molar volume conversion factor (849.5 scf/kg
mole at 68 oF and 14.7 psia or 836.6 scf/kg
-mole at 60 oF and 14.7 psia ). 0.001 = Conversion factor ( metric ton/kg). (3) You do not need to calculate CH 4 emissions from storage tanks that meet any of the following descriptions:330 (i) Units permanently attached to conveyances such as trucks, trailers, rail cars, barges, or ships; (ii) Pressure vessels designed to operate in excess of 204.9 kilopascals and without emissions to the atmosphere; (iii) Bottoms receivers or sumps; (iv) Vessels storing wastewater; or (v) Reactor vessels associated with a manufacturing process unit. (n) For crude oil, intermediate, or product loading operations for which the vapor -phase concentration of methane is 0.5 volume percent or more, calculate CH 4 emissions from loading operations using vapor -phase methane composition data (from measureme nt data or process knowledge) and the emission estimation procedures provided in Section 5.2 of the AP
- 42: “Compilation of Air Pollutant Emission Factors, Volume 1: Stationary Point and Area Sources.” For loading operations in which the vapor -phase concentration of methane is less than 0.5 volume percent, you may assume zero methane emissions. §98.254 Monitoring and QA/QC requirements. (a) Fuel flow meters, gas composition monitors, and heating value monitors that are associated with sources that use a CEMS to measure CO 2 emissions according to331

subpart C of this part or that are associated with stationary combustion sources must meet the applicable monitoring and QA/QC requirements in §98.34. (b) All gas flow meters, gas composition monitors, and heating value monitors that are used to provide data for the GHG emissions calculations in this subpart for sources other than those subject to the requirements in paragraph (a) of this section shall be calibrated according to the procedures in the applicable methods specified in paragraphs (c) through ( g ) of this section or the procedures specified by the manufacturer . In the case of gas flow meters, all gas flow meters must meet the calibration accuracy requirements in §98.3(i). You must
recalibrate each gas flow meter according to one of the following frequencies. You may recalibrate either biennially (every two years) , at the minimum frequency specified by the manufacturer , or at the interval spec ified by the industry consensus standard practice used . You must
recalibrate each gas composition monitor and heating value monitor according to one of the following frequencies. You may recalibrate either annually , at the minimum frequency specified by the manufacturer , or at the interval specified by the industry consensus standard practice used .332 (c) For flare or sour gas flow meters, operate , calibrate, and maintain the flow meter according to one of the following. You may use a method published by a
consensus -based standards organization or the procedures specified by the flow meter manufacturer. Consensus -based standards include, but are not limited to, the following: ASTM Int ernational, the American Society of Mechanical Engineers (ASME), and the American Gas Association (AGA). (d) Except as provided in paragraph (g) of this section, determine gas composition and, if re quired, average molecular weight of the gas using any of the following methods. Alternatively, the results of chromatographic analysis of the fuel may be used, provided that the gas chromatograph is operated, maintained, and calibrated according to the manufacturer’s instructions; and the methods used for operation, maintenance, and calibration of the gas chromatograph are documented in the written Monitoring P lan for the unit under §98.3(g)(5). (1) Method 18 at 40 CFR part 60, appendix A
- 6. (2) ASTM D1 945
- 03 Standard Test Method for Analysis of Natural Gas by Gas Chromatography (incorporated by reference, see §98.7).333 (3) ASTM D1946
- 90 (Reapproved 2006) Standard Practice for Analysis of Reformed Gas by Gas Chromatography (incorporated by reference, see §98.7). (4) GPA 2261

– 00 Analysis for Natural Gas and Similar Gaseous Mixtures by Gas Chromatography (incorporated by reference, see §98.7). (5) UOP539
- 97 Refinery Gas Analysis by Gas Chromatography (incorporated by reference, see §98.7). (6) ASTM D250 3
- 92 (Reapproved 2007) Standard Test Method for Relative Molecular Mass (Molecular Weight) of Hydrocarbons by Thermoelectric Measurement of Vapor Pressure (incorporated by reference, see §98.7). (e) Determine flare gas higher heating value using any of the following methods. Alternatively, the results of chromatographic analysis of the fuel may be used, provided that the gas chromatograph is operated, maintained, and calibrated according to the manufacturer’s instructions; and the methods used for opera tion, maintenance, and calibration of the gas chromatograph are documented in the written Monitoring P lan for the unit under §98.3(g)(5). (1) ASTM D4809
- 06 Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precis ion Method) (incorporated by reference, see §98.7).334 (2) ASTM D240
- 02 (Reapproved 2007) Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter (incorporated by reference, see §98.7). (3) ASTM D1826
- 94 (Reapproved 2003 ) Standard Test Method for Calorific (Heating) Value of Gases in Natural Gas Range by Continuous Recording Calorimeter (incorporated by reference, see §98.7). (4) ASTM D3588
- 98 (Reapproved 2003) Standard Practice for Calculating Heat Value, Compressibilit y Factor, and Relative Density of Gaseous Fuels (incorporated by reference, see §98.7). (5) ASTM D4891
- 89 (Reapproved 2006) Standard Test Method for Heating Value of Gases in Natural Gas Range by Stoichiometric Combustion (incorporated by reference, see § 98.7). (f) For gas flow meters used to comply with the requirements in §98.253(c)(2)(ii) or §98.253(j) , install, operate, calibrate, and maintain each gas flow meter according to the requirements in 40 CFR 63.1572(c) and the following requirements. (1) Locate the flow monitor at a site that provides representative flow rates . Avoid locations where there is swirling flow or abnormal veloc ity distributions due to upstream and downstream disturbances.335 (2) [Reserved] (3) Use a continuous monitoring system capable of correcting for the temperature, pressure, and moisture content to output flow in dry standard cubic feet (standard conditions as defined in §98.6). (g) For exhaust gas CO 2 /CO/O 2 compositi on monitors used to comply with the requirements in §98.253(c)(2), install, operate, calibrate, and maintain exhaust gas composition monitors according to the the requirements in 40 CFR 60.105a(b)(2) or 40 CFR 63.1572( c ) or according to the manufacturer’s specifications and requirements. (h) Determine the mass of petroleum coke as required by Equation Y
- 13 of this subpart using mass measurement equipment meeting the requirements for commercial weighing equipment as described in Specifications, Tolerances, and Other Technical Requirements For Weighing and Measuring Devices, NIST Handbook 44 (2009) (incorporated by reference, see §98.7). Calibrate the measurement device according to the procedures specified by NIST handbook 44
or the procedures specified by the manufacturer . Recalibrate either biennially or at the minimum frequency specified by the manufacturer. (i) Determine the carbon content of petroleum coke as required by Equation Y
- 13 of this subpart using any one of336

the following methods. Calibrate the measurement device according to procedures specified by the method or procedures specified by the measurement device manufacturer. (1) ASTM D3176
- 89 (Reapproved 2002) Standard Practice for Ultimate Analysis of Coal and Coke (i ncorporated by reference, see §98.7). (2) ASTM D5291
- 02 (Reapproved 2007) Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants (incorporated by reference, see §98.7). (3) ASTM D5373
- 08 Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference, see §98.7). (j) Determine the quantity of petroleum process streams using company records. These quantitie s include the quantity of asphalt blown, quantity of crude oil plus the quantity of intermediate products received from off site, and the quantity of unstabilized crude oil received at the facility. (k) The owner or operator shall document the procedures used to ensure the accuracy of the estimates of fuel usage, gas composition, and heating value including337

but 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. §98.255 Procedures for estimating missing data. A complete record of all measured parameters used in the GHG emissions calculations is required (e.g., concentrations, flow rates, fuel heating values, carbon content values). Therefore, whenever a quality
- assured value o f a required parameter is unavailable (e.g., if a CEMS 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. (a) For stationary combustion sourc es, use the missing data procedures in subpart C of this part. (b) For each missing value of the heat content, carbon content, or molecular weight of the fuel, substitute the arithmetic average of the quality
- assured values of that parameter immediately p receding and immediately following the missing data incident. If the “after” value is not obtained by the end of the reporting year, you may use the “before” value for the missing data substitution. If, for a particular parameter, no quality
- assured data are338

available prior to the missing data incident, the substitute data value shall be the first quality
- assured value obtained after the missing data period. (c) For missing CO 2 , CO, O 2 , CH 4 , or N 2 O concentrations, gas flow rate, and percent moisture, the substitute data values shall be the best available estimate(s) of the parameter(s), based on all available process data (e.g., processing rates, operating hours, etc.). The owner or operator shall document and keep records of the procedures used for all such estimates. (d) For hydrogen plants, use the missing data procedures in subpart P of this part. §98.256 Data reporting requirements. In addition to the reporting requirements of §98.3(c), you must report the information specified in paragraphs (a) through (q) of this section. (a) For combustion sources, follow the data reporting requirements under subpart C of this part (General Stationary Fuel Combustion Sources). (b) For hydrogen plants, follow the data reporting requirements under subpart P of this part (Hydrogen Production). (c) [Reserved] (d) [Reserved]339 (e) For flares, owners and operators shall report: (1) The flare ID number (if applicable). (2) A description of the type of flare (steam assisted, air
- assisted). (3) A description of the flare service (general facility flare, unit flare, emergency only or back
- up flare). (4) The calculated CO 2 , CH 4 , and N 2 O annual emissions for each flare, expressed in metric tons of each pollutant emitted. (5) A description of the method used to calcu late the CO 2 emissions for each flare (e.g., reference section and equation number). (6) If you use Equation Y
- 1 a of this subpart, an indication of whether daily or weekly measurement periods are used, the annual volume of flare gas combusted (in scf/yea r) and the annual average molecular weight (in kg/kg
-mole) , the molar volume conversion factor (in scf/kg
mole), and annual average carbon content of the flare gas (in kg carbon per kg flare gas). (7) If you use Equation Y
- 1b of this subpart, an indication of whether daily or weekly measurement periods are used, the annual volume of flare gas combusted (in scf/year), the molar volume conversion factor (in scf/kg
-340

mole), the annual average CO 2 concentration (volume or mole percent), the number of carbon cont aining compounds other than CO 2 in the flare gas stream, and for each of the carbon containing compounds other than CO 2 in the flare gas stream: (i) The annual average concentration of the compound (volume or mole percent) . (ii) The carbon mole number of the compound (moles carbon per mole compound). ( 8 ) If you use Equation Y
- 2 of this subpart , an indication of whether daily or weekly measurement periods are used , the annual volume of flare gas combusted (in million (MM) scf/year) and the annual average higher heating value of the flare gas (in MMBtu per MMscf). ( 9 ) If you use Equation Y
- 3 of this subpart, the annual volume of flare gas combusted (in MMscf/year) during normal operations, the annual average higher heating value of the flare gas (in MMBtu/MMscf), the number of SSM events exceeding 500,000 scf/day, the volume of gas flared (in scf/event) , the average molecular weight (in kg/kg
-mole) , the molar volume conversion factor (in scf/kg
-mole), and carbon content of the flare gas (in kg carbon per kg flare) for each SSM event over 500,000 scf/day.341 ( 10 ) The fraction of carbon in the flare gas contributed by methane used in Equation Y
- 4 of this subpart and the basis for its value. (f) For catalytic cracking units, traditional fluid coking units, and catalytic reforming units, owners and operators shall report: (1) The unit ID number (if applicable). (2) A description of the type of unit (fluid catalytic cracking unit, thermal catalytic cracking unit, traditional fluid coking unit, or catal ytic reforming unit). (3) Maximum rated throughput of the unit, in bbl/stream day. (4) The calculated CO 2 , CH 4 , and N 2 O annual emissions for each unit, expressed in metric tons of each pollutant emitted. (5) A description of the method used to calculate the CO 2 emissions for each unit (e.g., reference section and equation number). (6) If you use a CEMS, the relevant information required under §98.36 for the Tier 4 Calculation Methodology, the CO 2 annual emissions as measured by the CEMS (unadj usted to remove CO 2 combustion emissions associated with additional units , if present) and the342

process CO 2 emissions as calculated according to §98.253(c)(1)(ii). Report the CO 2 annual emissions associated with sources other than those from the coke burn
- off in the applicable subpart (e.g., subpart C of this part in the case of a CO boiler). (7) If you use E quation Y
- 6 of this subpart, the annual average exhaust gas flow rate, %CO 2 , %CO , and the molar volume conversion factor (in scf/kg
-mole) . (8) If you use Equation Y
- 7 a of this subpart, the annual average flow rate of inlet air and oxygen
- enriched air, %O 2 , %O oxy , %CO 2 , and %CO. (9) If you use Equation Y
- 7b of this subpart, the annual average flow rate of inlet air and oxygen
- enriched air, %N 2,oxy , and %N 2,exhaust . ( 10 ) If you use Equation Y
- 8 of this subpart, the coke burn
- off factor, annual throughput of unit, and the average carbon content of coke and the basis for the value. ( 11 ) Indicate whether you use a measured value, a unit
- specific emission factor, or a default emission factor for CH 4 emissions. If you use a unit
- specific emission facto r for CH 4 , report the unit
- specific emission factor for CH 4 , the units of measure for the unit
- specific factor, the activity data for calculating emissions (e.g., if the343

emission factor is based on coke burn
- off rate, the annual quantity of coke burned), and the basis for the factor. ( 12 ) Indicate whether you use a measured value, a unit
- specific emission factor, or a default emission factor for N 2 O emissions. If you use a unit
- specific emission factor for N 2 O, report the unit
- specific emission factor for N 2 O, the units of measure for the unit
- specific factor, the activity data for calculating emissions (e.g., if the emission factor is based on coke burn
- off rate, the annual quantity of coke burned), and the b asis for the factor. ( 13 ) If you use Equation Y
- 11 of this subpart, the number of regeneration cycles or measurement periods during the reporting year, the average coke burn
- off quantity per cycle or measurement period , and the average carbon content of the coke. (g) For fluid coking unit of the flexicoking type, the owner or operator shall report: (1) The unit ID number (if applicable). (2) A description of the type of unit. (3) Maximum rated throughput of the unit, in bbl/stream day. (4) Indic ate whether the GHG emissions from the low heat value gas are accounted for in subpart C of this part or §98.253(c).344 (5) If the GHG emissions for the low heat value gas are calculated at the flexicoking unit, also report the calculated annual CO 2 , CH 4 , and N 2 O emissions for each unit, expressed in metric tons of each pollutant emitted, and the applicable equation input parameters specified in paragraphs (f)(7) through (f)( 13 ) of this section. (h) For sulfur recovery plants and for emissions from sour gas sent off
- site for sulfur recovery, the owner and operator shall report: (1) The plant ID number (if applicable). (2) Maximum rated throughput of each independent sulfur recovery plant, in metric tons sulfur produced/stream day , a description of the type of sulfur recovery plant, and an indication of the method used to calculate CO 2 annual emissions for the sulfur recovery plant (e.g., CO 2 CEMS, Equation Y
- 12, or process vent method in § 98.253(j)) . (3) The calculated CO 2 annual emissions for each sulfu r recovery plant, expressed in metric tons. The calculated annual CO 2 emissions from sour gas sent off
- site for sulfur recovery, expressed in metric tons. (4) If you use Equation Y
- 12 of this subpart, the annual volumetric flow to the sulfur recovery plant (in scf/year) , the molar volume conversion factor (in scf/kg
-345

mole), and the annual average mole fraction of carbon in the sour gas (in kg
-mole C/kg
-mole gas). (5) If you recycle tail gas to the front of the sulfur recovery plant, indicate whether the recycled flow rate and carbon content are included in the measured data under §98.253(f)(2) and (3). Indicate whether a correction for CO 2 emissions in the tail gas was used in Equation Y
- 12. If so, then report the value of the correction, the annual
vo lume of recycled tail gas (in scf/year) and the annual average mole fraction of carbon in the tail gas (in kg
-mole C/kg
-mole gas). Indicate whether you used the default (95%) or a unit specific correction, and if used, report the approach used. (6) If you use a CEMS, the relevant information required under §98.36 for the Tier 4 Calculation Methodology, the CO 2 annual emissions as measured by the CEMS and the annual process CO 2 emissions calculated according to §98.253(f)(1). Report the CO 2 annual emissions associated with fuel combustion subpart C of this part (General Stationary Fuel Combustion Sources). (7) If you use the process vent method in § 98.253(j) for a non
- Claus sulfur recovery plant, the relevant information required under paragraph (l)(5) of this section.346 (i) For coke calcining units, the owner and operator shall report: (1) The unit ID number (if applicable). (2) Maximum rated throughput of the unit, in metric tons coke calcined/stream day. (3) The calculated CO 2 , CH 4 , and N 2 O annual emissions for each unit, expressed in metric tons of each pollutant emitted. (4) A description of the method used to calculate the CO 2 emissions for each unit (e.g., reference section and equation number). (5) If you use Equation Y
- 13 of this subp art, annual mass and carbon content of green coke fed to the unit, the annual mass and carbon content of marketable coke produced, the annual mass of coke dust removed from the process through dust collection systems , and an indication of whether coke dust is recycled to the unit (e.g., all dust is recycled, a portion of the dust is recycled, or none of the dust is recycled) . (6) If you use a CEMS, the relevant information required under §98.36 for the Tier 4 Calculation Methodol ogy, the CO 2 annual emissions as measured by the CEMS and the annual process CO 2 emissions calculated according to §98.253(g)(1). Report the CO 2 annual emissions347

associated with fuel combustion under subpart C of this part (General Stationary Fuel Combus tion Sources). (7) Indicate whether you use a measured value, a unit
- specific emission factor or a default for CH 4 emissions. If you use a unit
- specific emission factor for CH 4 , the unit
- specific emission factor for CH 4 , the units of measure for the unit
- specific factor, the activity data for calculating emissions (e.g., if the emission factor is based on coke burn
- off rate, the annual quantity of coke burned), and the basis for the factor. (8) Indicate whether you use a measured value, a unit
- specific emission factor, or a default emission factor for N 2 O emissions. If you use a unit
- specific emission factor for N 2 O, report the unit
- specific emission factor for N 2 O, the units of measure for the unit
- specific factor, the activity data for calculating emissions (e.g., if the emission factor is based on coke burn
- off rate, the annual quantity of coke burned), and the basis for the factor. . (j) For asphalt blowing operations, the owner or operator shall report: (1) The unit ID number (if applicable). (2) The quantity of asphalt blown (in Million bbl) at the unit in the reporting year.348 (3) The type of control device used to reduce methane (and other organic) emissions from the unit. (4) The calculated annual CO 2 and CH 4 emissions for each unit, expressed in metric tons of each pollutant emitted. (5) If you use Equation Y
- 14 of this subpart, the CO 2 emission factor used and the basis for the value. (6) If you use Equation Y
- 15 of this subpart, the CH 4 emission factor used and the basis for the value. (7) If you use Equation Y
- 16 a of this subpart, the carbon emission factor used and the basis for the value. (8) If you use Equation Y
- 16b of this subpart, the CO 2 emission factor used and the basis for its value and the carbon emission factor used and the basis for its value. ( 9 ) If you use Equation Y
- 17 of this subpart, the CH 4 emission factor used and the basis for the value. (k) For delayed coking units, the owner or operator shall report: (1) The cumulative annual CH 4 emissions (in metric tons of CH 4 ) for all delayed coking units at the facility. (2) A description of the method us ed to calculate the CH 4 emissions for each unit (e.g., reference section and equation number).349 (3) The total number of delayed coking units at the facility, the total number of delayed coking drums at the facility, and for each coke drum or vessel: the dimensions, the typical gauge pressure of the coking drum when first vented to the atmosphere, typical void fraction, the typical drum outage (i.e. the unfilled distance from the top of the drum, in feet), the molar volume conversion factor (in scf/kg
-mole), and annual number of coke
- cutting cycles. (4) For each set of coking drums that are the same dimensions: the number of coking drums in the set, the height and diameter of the coke drums (in feet), the cumulative number of vessel openings for all delayed coking drums in the set, the typical venting pressure (in psig), void fraction (in cf gas/cf of vessel), and the mole fraction of methane in coking gas (in kg
-mole CF 4 /kg
-mole gas, wet basis). (5) The basis for the volumetric void fraction of the coke ve ssel prior to steaming and the basis for the mole fraction of methane in the coking gas. (l) For each process vent subject to §98.253(j), the owner or operator shall report: (1) The vent ID number (if applicable).350 (2) The unit or operation associated with the emissions. (3) The type of control device used to reduce methane (and other organic) emissions from the unit, if applicable. (4) The calculated annual CO 2 , CH 4 , and N 2 O emissions for each vent, expressed in metric tons of each pollutant emitted. (5) The annual volumetric flow discharged to the atmosphere (in scf), and an indication of the measurement or estimation method, annual average mole fraction of each GHG above the concentration threshold or otherwise required to be reported and an indic ation of the measurement or estimation method, the molar volume conversion factor (in scf/kg
-mole), and for intermittent vents, the number of venting events and the cumulative venting time. (m) For uncontrolled blowdown systems, the owner or operator shal l report: ( 1 ) An indication of whether the uncontrolled blowdown emission are reported under §98.253(k) or §98.253(j) or a statement that the facility does not have any uncontrolled blowdown systems. ( 2 ) The cumulative annual CH 4 emissions (in metric tons of CH 4 ) for uncontrolled blowdown systems.351 ( 3 ) For uncontrolled blowdown systems reporting under §98.253(k), the total quantity (in Million bbl) of crude oil plus the quantity of intermediate products received from off
- site that are processed at the facility in the reporting year , the methane emission factor used for uncontrolled blowdown systems , the basis for the value , and the molar volume conversion factor (in scf/kg
-mole) . (4) For uncontrolled blowdown systems reporting under §98.253(j), the relevant information required under paragraph (l)(5) of this section. (n) For equipment leaks, the owner or operator shall report: (1) The cumulative CH 4 emissions (in metric tons of each pollutant emitted) for all equipment leak sources. (2) The method used to calculate the reported equipment leak emissions. (3) The number of each type of emission source listed in Equation Y
- 21 of this subpart at the facility. (o) For storage tanks, the owner or operator shall report: (1) The cumulative annual CH 4 emissions (in metric tons of CH 4 ) for all storage tanks, except for those used to process unstabilized crude oil.352 (2) For storage tanks other than those processing unstabilized crude oil: (i) The method used to calculate the reported storage tank emissions for storage tanks other than those processing unstabilized crude ( Section 7 .1 of the AP
- 42: “Compilation of Air Pollutant Emission Factors, Volume 1: Stationary Point and Area Sources”, including TANKS Model (Version 4.09D) or similar programs, or Equation Y
- 22 of this section , other) . ( ii ) The total quantity (in MMbbl) of crude oil plus the quantity of intermediate products received from off
site that are processed at the facility in the reporting year. ( 3 ) The cumulative CH 4 emissions (in metric tons of CH 4 ) for storage tanks used to process unstabilize d crude oil or a statement that the facility did not receive any unstabilized crude oil during the reporting year . ( 4 ) For storage tanks that process unstabilized crude oil: (i) The method used to calculate the reported unstabilized crude oil storage t ank emissions . ( ii ) The quantity of unstabilized crude oil received during the calendar year (in MMbbl) . (iii) The average pressure differential (in psi) .353 (iv) The molar volume conversion factor ( in scf/kg
mole) . (v) The average mole fraction of CH 4 in vent gas from unstabilized crude oil storage tank s and the basis for the mole fraction . ( vi ) If you did not use Equation Y
- 23, the tank
specific methane composition data and the gas generation rate data used to estimate the cumulative CH4 emissions for storage tanks used to process unstabilized crude oil . (p) For loading operations, the owner or operator shall report: (1) The cumulative annual CH 4 emissions (in metric tons of each pollutant emitted) for loading operations. (2) The quantity and types of materials loaded by vessel type (barge, tanker, marine vessel, etc.) that have an equilibrium vapor -phase concentration of methane of 0.5 volume percent or greater, and the type of vessels in which the material is loaded. (3) The type of control system used to reduce emissions from the loading of material with an equilibrium vapor -phase concentration of methane of 0.5 volume percent or greater, if any (submerged loading, vapor balancing, etc.).354 (q) Name of each method listed in §98.254 or a description of manufacturer's recommended method used to determine a measured parameter. §98.257 Records that must be retained. In addition to the records required by §98.3(g), you must retain the records of all parameters monitored under §98.255. If you comply with the combustion methodology in §98.252(a), then you must retain under this subpart the records required for the Tier 3 and/or Tier 4 Calculation Methodologies in §98.37 and you must keep records of the annual average flow calculations. §98.258 Definitions. All terms used in this subpart have the same meaning given in the Clean Air Act and subpar t A of this part. Subpart AA

—Pulp and Paper Manufacturing § 98.270 Definition of Source Category. (a) The pulp and paper manufacturing source category consists of facilities that produce market pulp (i.e., stand
- alone pulp facilities), manufacture pulp and paper (i.e., integrated facilities), produce paper products from purchased pulp, produce secondary fiber from recycled paper, convert paper into paperboard products (e.g., containers), or operate coating and laminating processes.355 (b) The emission units for which GHG emissions must be reported are listed in paragraphs (b)(1) through (b)(5) of this section: (1) Chemical recovery furnaces at kraft and soda mills (including recovery furnaces that burn spent pulping liquor produced by both the kraft and semichemical process). (2) Chemical recovery combustion units at sulfite facilities. (3) Chemical recovery combustion units at stand
- alone semichemical facilities. (4) Pulp mill lime kilns at kraft and soda facilities. (5) Systems for adding makeup chemic als (CaCO 3 , Na 2 CO 3 ) in the chemical recovery areas of chemical pulp mills. §98.271 Reporting threshold. You must report GHG emissions under this subpart if your facility contains a pulp and paper manufacturing process and the facility meets the requiremen ts of either §98.2(a)(1) or (a)(2). §98.272 GHGs to report. You must report the emissions listed in paragraphs (a) through (f) of this section:356 (a) CO 2 , biogenic CO 2 , CH 4 , and N 2 O emissions from each kraft or soda chemical recovery furnace. (b) CO 2 , bio genic CO 2 , CH 4 , and N 2 O emissions from each sulfite chemical recovery combustion unit. (c) CO 2 , biogenic CO 2 , CH 4 , and N 2 O emissions from each stand
- alone semichemical chemical recovery combustion unit. (d) CO 2 , biogenic CO 2 , CH 4 , and N 2 O emissions from each kraft or soda pulp mill lime kiln. (e) CO 2 emissions from addition of makeup chemicals (CaCO 3 , Na 2 CO 3 ) in the chemical recovery areas of chemical pulp mills. (f) CO 2 , CH 4 , and N 2 O combustion emissions from each stationary combustion unit. You must calculate and report these emissions under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C. §98.273 Calculating GHG emissions. (a) For each chemical recovery furnace located at a kraft or s oda facility, you must determine CO 2 , biogenic CO 2 , CH 4 , and N 2 O emissions using the procedures in paragraphs (a)(1) through (a)(3) of this section. CH 4 and N 2 O emissions must be calculated as the sum of emissions from combustion of fossil fuels and combu stion of biomass in spent liquor solids.357 (1) Calculate fossil fuel
-based CO 2 emissions from direct measurement of fossil fuels consumed and default emissions factors according to the Tier 1 methodology for stationary combustion sources in §98.33(a)(1). A higher tier from §98.33(a) may be used to calculate fossil fuel
based CO 2 emissions if the respective monitoring and QA/QC requirements described in §98.34 are met. (2) Calculate fossil fuel
-based CH 4 and N 2 O emissions from direct measurement of fossil fuels consumed, default or site
- specific HHV, and default emissions factors and convert to metric tons of CO 2 equivalent according to the methodology for stationary combustion sources in §98.33(c). (3) Calculate biogenic CO 2 emissions and emissions of CH 4 and N 2 O from biomass using measured quantities of spent liquor solids fired, site
- specific HHV, and default or site
- specific emissions factors, according to Equation AA
- 1 of this section:
EF HHV Solids * * ) 18
. 907
. 0 ( , , 2 4 2   biomass from O N or CH CO (Eq.AA
- 1) Where: CO 2 , CH 4 , or N 2 O, from Biomass = Biogenic CO 2 emissions or emissions of CH 4 or N 2 O from spent liquor solids combustion (metric tons per year). Solids = Mass of spent liquor solids combusted (short tons per year) determined according to § 98.274(b).358

HHV = Annual high heat value of the spent liquor solids (mmBtu per kilogram) determined according to 98.274(b). EF = Default emission factor for CO 2 , CH 4 , or N 2 O, from Table AA
- 1 of this subpart (kg CO 2 , CH 4 , or N 2 O per mmBtu). 0.90718 = Conversion factor from short tons to met ric tons. (b) For each chemical recovery combustion unit located at a sulfite or stand
- alone semichemical facility, you must determine CO 2 , CH 4 , and N 2 O emissions using the procedures in paragraphs (b)(1) through (b)(4) of this section: (1) Calculate fos sil CO 2 emissions from fossil fuels from direct measurement of fossil fuels consumed and default emissions factors according to the Tier 1 Calculation Methodology for stationary combustion sources in §98.33(a)(1). A higher tier from §98.33(a) may be used to calculate fossil fuel
-based CO 2 emissions if the respective monitoring and QA/QC requirements described in §98.34 are met. (2) Calculate CH 4 and N 2 O emissions from fossil fuels from direct measurement of fossil fuels consumed, default or site
- specific HHV, and default emissions factors and convert to metric tons of CO 2 equivalent according to the methodology for stationary combustion sources in §98.33(c).359 (3) Calculate biogenic CO 2 emissions using measured quantities of spent liquor solids fired and the carbon content of the spent liquor solids, according to Equation AA- 2 of this section:
) CC Solids 12 44 90718

. 0 ( 2 

   CO Biogenic (Eq. AA
- 2) Where: Biogenic CO 2 = Annual CO 2 mass emissions for spent liquor solids combustion (metric tons per year). Solids = Mass of the spent liquor solids combusted (short tons per year) determined according to § 98.274(b). CC = Annual carbon content of the spent liquor solids, determined according to § 98.274(b) (percent by weight, expressed as a decimal fraction, e.g., 95% = 0.95). 44/1 2 = Ratio of molecular weights, CO 2 to carbon. 0.90718 = Conversion from short tons to metric tons (4) Calculate CH 4 and N 2 O emissions from biomass using Equation AA
- 1 of this section and the default CH 4 and N 2 O emissions factors for kraft facilities in Table AA
- 1 of this subpart and convert the CH 4 or N 2 O emissions to metric tons of CO 2 equivalent by multiplying each annual CH 4 and N 2 O emissions total by the appropriate global warming potential (GWP) factor from Table A
- 1 of subpart A of this part. (c) For each pulp mill lime kiln located at a kraft or soda facility, you must determine CO 2, CH 4 , and N 2 O360

emissions using the procedures in paragraphs (c)(1) through (c)(3) of this section: (1) Calculate CO 2 emissions from fossil fuel from direct measuremen t of fossil fuels consumed and default HHV and default emissions factors, according to the Tier 1 Calculation Methodology for stationary combustion sources in §98.33(a)(1 ) . A higher tier from §98.33(a) may be used to calculate fossil fuel
-based CO 2 emissions if the respective monitoring and QA/QC requirements described in §98.34 are met. (2) Calculate CH 4 and N 2 O emissions from fossil fuel from direct measurement of fossil fuels consumed, default or site
- specific HHV, and default emissions factors and convert to metric tons of CO 2 equivalent according to the methodology for stationary combustion sources in §98.33(c); use the default HHV listed in Table C
- 1 of subpart C and the default CH 4 and N 2 O emissions factors listed in Table AA- 2 of this subpart. (3) Biogenic CO 2 emissions from conversion of CaCO 3 to CaO are included in the biogenic CO 2 estimates calculated for the chemical recovery furnace in paragraph (a)(3) of this section. (d) For makeup chemical use, you must calculate CO 2 emissions by using direct or indirect measurement of the361

quantity of chemicals added and ratios of the molecular weights of CO 2 and the makeup chemi cals, according to Equation AA
- 3 of this section:
ton metric kg M M CO CO Na CaCO / 1000 * 99
. 105 44 100 44 * )

( ) ( 2 3 2 3         (Eq. AA
- 3) Where: CO 2 = CO 2 mass emissions from makeup chemicals

(kilograms/yr). M (CaCO 3 ) = Make
- up quantity of CaCO 3 used for the

reporting year (metric tons per year). M (NaCO 3 ) = Ma ke
- up quantity of Na 2 CO 3 used for the

reporting year (metric tons per year). 44 = Molecular weight of CO 2 . 100 = Molecular weight of CaCO 3 . 105.99 = Molecular weight of Na 2 CO 3 . §98.274 Monitoring and QA/QC requirements. (a) Each facility subject to this subpart must quality assure the GHG emissions data according to the applicable requirements in §98.34. All QA/QC data must be available for inspection upon request. (b) Fuel properties needed to perform the calculations in Equations AA
- 1 and AA
- 2 of this subpart must be determined according to paragraphs (b)(1) through (b)(3) of this section. (1) High heat values of black liquor must be determined no less than annually using T684 om

– 06 Gross Heating Value of Black Liquor, TAPPI (incorporated by refe rence, see §98.7). If measurements are performed more362

frequently than annually, then the high heat value used in Equation AA
- 1 of this subpart must be based on the average of the representative measurements made during the year. (2) The annual mass of spent liquor solids must be determined using either of the methods specified in paragraph (b)(2)(i) or (b)(2)(ii). (i) Measure the mass of spent liquor solids annually (or more frequently) using T
- 650 om

– 05 Solids Content of Black Liquor, TAPPI (incorporate d by reference in §98.7). If measurements are performed more frequently than annually, then the mass of spent liquor solids used in Equation AA
- 1 of this subpart must be based on the average of the representative measurements made during the year. (ii) Determine the annual mass of spent liquor solids based on records of measurements made with an online measurement system that determines the mass of spent liquor solids fired in a chemical recovery furnace or chemical recovery combustion unit. (3) Carbon analyses for spent pulping liquor must be determined no less than annually using ASTM D5373
- 08 Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference, see §98.7). If
measurements using ASTM D5373
- 08 are performed more363

frequently than annually, then the spent pulping liquor carbon content used in Equation AA
- 2 of this subpart must be based on the average of the representative measurements made during the year. (c) Each facility must keep records that include a detailed explanation of how company records of measurements are used to estimate GHG emissions. The owner or operator must also document the procedures used to ensure the accuracy of the measurements of fuel, spe nt liquor solids, and makeup chemical usage, including, but not limited to calibration of weighing equipment, fuel flow meters, and other measurement devices. The estimated accuracy of measurements made with these devices must be recorded and the technica l basis for these estimates must be provided. The procedures used to convert spent pulping liquor flow rates to units of mass (i.e., spent liquor solids firing rates) also must be documented. (d) Records must be made available upon request for verificat ion of the calculations and measurements. §98.275 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 unit364

operation or if a required sample is not taken), a substitute data value for the missing parameter shall be used in the calculations, according to the requirements of paragraphs (a) through (c) of this section: (a) There are no missing data procedures for measurements of heat content and carbon content of spent pulping liquor. A re
- test must be performed if the data from any annual measurements are determined to be invalid. (b) For missing measu rements of the mass of spent liquor solids or spent pulping liquor flow rates, use the lesser value of either the maximum mass or fuel flow rate for the combustion unit, or the maximum mass or flow rate that the fuel meter can measure. (c) For the use of makeup chemicals (carbonates), the substitute data value shall be the best available estimate of makeup chemical consumption, based on available data (e.g., past accounting records, production rates). The owner or operator shall document and keep records of the procedures used for all such estimates. §98.276 Data reporting requirements. In addition to the information required by §98.3(c) and the applicable information required by §98.36 , each annual report must contain the information in paragraphs (a) through ( k ) of this section as applicable:365 (a) Annual emissions of CO 2 , biogenic CO 2 , CH 4 , biogenic CH 4 N 2 O, and biogenic N 2 O (metric tons per year). (b) Annual quantities fossil fuels by type used in chemical recovery furnaces and chemical recovery combu stion units in short tons for solid fuels, gallons for liquid fuels and scf for gaseous fuels. (c) Annual mass of the spent liquor solids combusted (short tons per year), and basis for determining the annual mass of the spent liquor solids combusted (whether based on T650 om
- 05 Solids Content of Black Liquor, TAPPI (incorporated by reference, see §98.7) or an online measurement system). (d) The high heat value (HHV) of the spent liquor solids used in Equation AA
- 1 of this subpart (mmBtu per kilogram). (e) The default emission factor for CO 2 , CH 4 , or N 2 O, used in Equation AA
- 1 of this subpart (kg CO 2 , CH 4 , or N 2 O per mmBtu). (f) The carbon content (CC) of the spent liquor solids, used in Equation AA
- 2 of this subpart (percent by weight, expressed as a dec imal fraction, e.g., 95% = 0.95). (g) Annual quantities of fossil fuels by type used in pulp mill lime kilns in short tons for solid fuels, gallons for liquid fuels and scf for gaseous fuels.366 (h) Make
- up quantity of CaCO 3 used for the reporting year (met ric tons per year) used in Equation AA
- 3 of this subpart. (i) Make
- up quantity of Na 2 CO 3 used for the reporting year (metric tons per year) used in Equation AA
- 3 of this subpart. (j) Annual steam purchases(pounds of steam per year). (k) Annual production of pulp and/or paper products produced (metric tons). §98.277 Records that must be retained. In addition to the information required by §98.3(g), you must retain the records in paragraphs (a) through (f) of this section. (a) GHG emission estimates (i ncluding separate estimates of biogenic CO 2 ) for each emissions source listed under §98.270(b). (b) Annual analyses of spent pulping liquor HHV for each chemical recovery furnace at kraft and soda facilities. (c) Annual analyses of spent pulping liquor c arbon content for each chemical recovery combustion unit at a sulfite or semichemical pulp facility. (d) Annual quantity of spent liquor solids combusted in each chemical recovery furnace and chemical recovery367

combustion unit, and the basis for detemining the annual quantity of the spent liquor solids combusted (whether based on T650 om

– 05 Solids Content of Black Liquor, TAPPI (incorporated by reference, see §98.7) or an online measurement system). If an online measurement system is used, you must retain records of the calaulations used to determine the annual quantity of spent liquor solids combusted from the continuous measurements. (e) Annual steam purchases. (f) Annual quantities of makeup chemicals used. §98.278 Definitions. All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Table AA- 1 of Subpart AA

—Kraft Pulping Liquor Emissions Factors for Biomass -Based CO2 , CH4 , and N2O.
Wood Furnish Biomass -Based Emissions Factors (kg/mmBtu HHV) CO2a CH4 N2O North American Softwood 94.4 0.030 0.005 North American Hardwood 93.7 Bagasse 95.5 Bamboo 93.7 Straw 95.1 a Includes emissions from both the recovery furnace and pulp mill lime kiln. Table AA- 2 of Subpart AA

—Kraft Lime Kiln and Calciner Emissions Factors for Fossil Fuel -Based CH4 and N2O
Fuel Fossil Fuel -Based Emissions Factors (kg/mmBtu HHV)

Kraft Lime Kilns Kraft Calciners

CH4 N2O CH4 N2O Residual Oil 0.0027 0 0.0027 0.0003368

Distillate Oil 0 .0004 Natural Gas 0.0001 Biogas 0.0001 Petroleum coke NAa NAa a. Emission factors for kraft calciners are not available. 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 fluorin ated 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 fluorinat ed 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 and369

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 (NH 4NO 3 ). 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. §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, o r 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: 

# 

  n
p p P P 1 (Eq. OO
- 1)370

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 fluorina ted GHG or nitrous oxide produced over the period “p” by using Equation OO
- 2 of this section:

p p p U O P

  (Eq. OO
- 2) 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” (metri c tons). (c) Calculate the total mass of each fluorinated GHG or nitrous oxide transformed by using Equation OO
- 3 of this section:

T T E F T *  (Eq. OO
- 3) Where: T = Mass of fluorinated GHG or nitrous oxide

transformed annually (metric tons). F T = Mass of fluorinated GHG fed into the transformation

process annually (metric tons). E T = 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 to tal mass of each fluorinated GHG destroyed by using Equation OO
- 4 of this section:371
DE F D D *  (Eq. OO
- 4) Where: D = Mass of fluorinated GHG destroyed annually

(metric tons). F D = Mass of fluorinated GHG fed into the destruction

device annuall y (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, wei gh 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, othe r 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 i n paragraph (a) of this372

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 fluor inated 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 frac tion 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 proce ss 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 of373

volumetric and density measurements with an accu racy 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 accurac y 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 mu st 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 quant ities374

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 mu st estimate the concentrations of 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 destroyed. (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 previous375

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, fluorina ted 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).376 (n) If the ma ss 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 anal ytical 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 Elect ronics 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);377

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 de scription 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 thes e accuracies and precisions were estimated, including the validation protocol used. (3) Frequency of measurement . Perform the measurements at least once by [INSERT DATE 60 DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER] if the fluorinated GHG p roduct is being produced on [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER] . Perform the measurements within 60 days of commencing production of any fluorinated GHG product that was not being produced on [INSERT DATE OF PUBLICATION IN THE FEDERAL RE GISTER] .378

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 frequency379

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 o r 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. §98.415 Procedures for estimating missing data. (a) A complete record of a ll 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 into380

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 multiplyi ng 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:381 (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 f acility, 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 be382

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 fa cility 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) Total mass in metric tons of each reactant fed into the F
- GHG or nitrous oxide production process, by process. (9) Total mass in metric tons of the reactants, by
products, and other wastes permanently removed from the F
GHG or nitrous ox ide production process, by process. (10) For transformation processes that do not produce an F - GHG or nitrous oxide, 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 section383

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 wei ghed 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 nitrous oxide and 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 of384

time the data were missing, the method used to estimate the missing data, and the estimates of those data. (b) A fluorinated GHG production facil ity or importer that destroys fluorinated GHGs shall submit a one
- time report containing the following information: (1) Destruction efficiency (DE) of each destruction unit. (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 fluorinated385

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
o r 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.386 (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 nitrou s 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 nitrous oxide or fluorinated GHGs were sold or transferred for de struction, and the quantities (metric tons) of nitrous oxide and 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 summar izes 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.387 (4) Commodity code of the fluorina ted 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 April 1, 2011, 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 use d (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.388 (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 fluorina ted 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 facili ties 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 i n 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 da te 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).389 (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. §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 analyt ical 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 industry standards or manufacturer directions used f or calibration pursuant to §98.414( m ) and ( o ). (b) In addition to the data required by paragraph (a) of this section, the fluorinated GHG production facility that destroys fluorinated GHGs shall keep records of test reports and other information documen ting the facility’s
one - time destruction efficiency report and annual destruction device outlet reports in §98.416(b) and (e).390 (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 substan tiating each of the exports that they report: (1) A copy of the bill of lading for the export and (2) The invoice for the import. (e) Every person who imports a container with a heel that is not reported under §98.416(c) shall keep records of the amoun t 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.391 (g) Low
- concentration constituents are exempt from the recordkeeping requirements of this section. §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 confli ct 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 fluorin ated 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
-392

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 PP

—Suppliers of Carbon Dioxide §98.420 Definition of the source category. (a) The carbon dioxide (CO 2 ) supplier source category consists of the following: (1) Facilities with production process units that capture a CO 2 stream for purposes of supplying CO 2 for commercial applications or that capture and maintain custody of a CO 2 stream in order to sequester or otherwise inject it underground. Capture refers to the initial separation and removal of CO 2 from a manufacturing process or any other process. (2) Facilities with CO 2 production wells that extract or produce a CO 2 stream for purposes of supplying CO 2 for commercial applications or tha t extract and maintain custody of a CO 2 stream in order to sequester or otherwise inject it underground. (3) Importers or exporters of bulk CO 2 . (b) This source category is focused on upstream supply. It does not cover: (1) Storage of CO 2 above ground or in geologic formations.393 (2) Use of CO 2 in enhanced oil and gas recovery. (3) Transportation or distribution of CO 2. (4) Purification, compression, or processing of CO 2. (5) On
- site use of CO 2 captured on site. (c) This source category does not include CO 2 imported or exported in equipment, such as fire estinguishers. §98.421 Reporting threshold. Any supplier of CO 2 who meets the requirements of §98.2(a)(4) of subpart A of this part must report the mass of CO 2 captured, extracted, imported, or exported. §98.422 GHGs to report. (a) Mass of CO 2 captured from production process unit s . (b) Mass of CO 2 extracted from CO 2 production wells. (c) Mass of CO 2 imported. (d) Mass of CO 2 exported. §98.423 Calculating CO 2 Supply. (a) Except as allowed in paragraph (b) of this section, c alculate the annual mass of CO 2 captured, extracted, imported, or exported through each flow meter in accordance with the procedures specified in either paragraph (a)(1) or (a)(2) of this section. If multiple flow meters are used, you shall calculate the annual mass394

of CO 2 for all flow meters according to the procedures specified in paragraph (a)(3) of this section. (1) For each mass flow meter, you shall calculate quarterly the mass of CO 2 in a CO 2 stream in metric tons by multiplying the mass flow by the composition data, according to Equation PP
- 1 of this section. Mass flow and composition data measurements shall be made in accordance
with §98.424 of this subpart.
CO 2 ,u = u p CO p u p C Q

, , 2 * 4
1 , 

# 

 (Eq. PP
- 1) Where: CO 2,u = Annual mass of CO 2 (metric tons) through flow

meter u. C CO2,p,u = Quarterly CO 2 concentration measurement in flow

for flow meter u in quarter p (wt. %CO 2 ). Qp,u = Quarterly mass flow rate measurement for flow

meter u in quarter p (metric tons). p = Quarter of the year.
u = Flow meter. (2) For each volumetric flow meter, you shall calculate quarterly the mass of CO 2 in a CO 2 stream in metric tons by multiplying the volumetric flow by the concentration and density data, according to Equation PP
- 2 of this section. Volumetric flow, concentration and density data measurements shall be made in accordanc e with §98.424 of this section.395

CO 2 ,u = p CO p p p C D Q

, 2 * * 4
1 

# 

 (Eq. PP
- 2) Where: CO 2,u = Annual mass of CO 2 (metric tons) through flow

meter u. C CO2 ,p = Quarterly CO 2 concentration measurement in flow

for flow meter u in quarter p (wt. % CO 2 ). Qp = Quarterly volumetric flow rate measurement for

flow meter u in quarter p (standard cubic meters). Dp = Quarterly CO 2 stream density measurement for

flow meter u in quarter p (metric tons per standard cubic meter) . p = Quarter of the year.
u = Flow meter. (3) To aggregate data, sum the mass of CO 2 for all flow meters in accordance with Equation PP
- 3 of this section.
CO 2 = 

# 

 U
1 p u

2, CO (Eq. PP
- 3) Where: CO 2 = Annual mass of CO 2 (metric tons) through all

flow meters. CO 2,u = Annual mass of CO 2 (metric tons) through flow

meter u.
u = Flow meter. (b) As an alternative to paragraphs (a)(1) through (3) of this section for CO 2 that is supplied in containers, calculate the annual mass of CO 2 supplied in containers396

delivered by each CO 2 stream in accordance with the procedures specified in either paragraph (b)(1) or (b)(2) of this section. If multiple CO 2 streams are used to deliver CO 2 to containers, you shall calculate the annual mass of CO 2 supplied in containers delivered by all CO 2 streams according to the procedures specified in paragraph (b)(3) of this section. (1) For each CO 2 stream that delivers CO 2 to containers, for which mass is measured, you shall calculate CO 2 supply in containers using Equation PP
- 1 of this section. Where: CO 2 ,u = Annual mass of CO 2 (metric tons) supplied in

containers delivered by CO 2 stream u. C CO2,p,u = Quarterly CO 2 concentration measurement of CO 2

stream u that delivers CO 2 to containers in quarter p (wt. %CO 2 ). Qp,u = Quarterly mass of contents supplie d in all

containers delivered by CO 2 stream u in quarter p (metric tons). p = Quarter of the year. u = CO 2 stream that delivers to containers. (2) For each CO 2 stream that delivers to containers, for which volume is measured, you shall calculate CO 2 supply in containers using Equation PP
- 2 of this section. Where: CO 2,u = Annual mass of CO 2 (metric tons) supplied in

containers delivered by CO 2 stream u.397

C CO2,p,u = Quarterly CO 2 concentration measurement of CO 2

stream u that delivers CO 2 to containers in quarter p (vol. %CO 2 ). Qp = Quarterly volume of contents supplied in all

containers delivered by CO 2 stream u in quarter p (metric tons) (standard cubic meters). Dp = Quarterly CO 2 stream density determination for

CO 2 stream u in quarter p (metric tons per standard cubic meter). p = Quarter of the year. u = CO 2 stream that delivers to containers. (3) To aggregate data, sum the mass of CO 2 supplied in containers delivered by all CO 2 streams in accordance with Equation PP
- 3 of this section. Where: CO 2 = Annual mass of CO 2 (metric tons) supplied in

containers delivered by all CO 2 streams. CO 2,u = Annual mass of CO 2 (metric tons) supplied in

containers delivered by CO 2 stream u. u = CO 2 stream that delivers to containers. ( c ) Importers or exporte rs that import or export CO 2 in containers shall calculate the total mass of CO 2 imported or exported in metric tons based on summing the mass in each CO 2 container using weigh bills, scale s, or load cells according to Equation PP
- 4 of this section.
CO 2 = 

# Q

I
p 

# 

1 (Eq. PP
- 4) Where: CO 2 = Annual mass of CO 2 (metric tons).398

Q = Annual mass in all CO 2 containers imported or

exported during the reporting year (metric tons). §9 8.424 Monitoring and QA/QC requirements. (a) Determination of quantity. (1) Reporters following the procedures in paragraph (a) of § 98.423 shall determine quantity using a flow meter or meters located in accordance with this paragraph. (i) If the CO 2 stream is segregated such that only a portion is captured for commercial application or for injection, you must locate the flow meter after the point of segregation. (ii) Reporters that have a mass flow meter or volumetric flow meter installed to measure the flow of a CO 2 stream that meets the requirements of paragraph (i) of this section shall base calculations in §98.423 of this subpart on the installed mass flow or volumetric flow meters. ( iii ) Reporters that do not have a mass flow meter or volume tric flow meter installed to measure the flow of the CO 2 stream that meets the requirements of paragraph (i) of this section shall base calculations in §98.423 of this subpart on the flow of gas transferred off site using a mass flow meter or a volumetric flow meter located at the point of off
- site transfer.399 (2) Reporters following the procedures in paragraph (b) of §98.423 shall determine quantity in accordance with this paragraph. (i) Reporters that supply CO 2 in containers using weigh bills, scales, or load cells shall measure the mass of contents of each CO 2 container to which the CO 2 stream delivered, sum the mass of contents supplied in all containers to which the CO 2 stream delivered during each quarter, sample the CO 2 stream delivering CO 2 to containers on a quarterly basis to determine the composition of the CO 2 stream, and apply E quation PP
- 1. (ii) Reporters that supply CO 2 in containers using loaded container volumes shall measure the volume of contents of each CO 2 container to which the CO 2 stream delivered, sum the volume of contents supplied in all containers to which the CO 2 stream delivered during each quarter, sample the CO 2 stream on a quarterly basis to determine the composition of the CO 2 stream, determine the density quarterly, and apply E quation PP
- 2. (3) Importers or exporters that import or export CO 2 in containers shall measure the mass in each CO 2 container using weigh bills, scales, or load cells and sum the mass in all containers imported or exported during the reporting year.400 (4) All flow meters, scales, and load cells used to measure quantities that are reported in §98.423 of this subpart shall be operated and calibrated according to the following procedure: (i) You shall use an appropriate standard method published by a c onsensus -based standards organization if such a method exists. 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). (ii) Where no appropriate standard method developed by a consensus
-based standards organization exists, you shall follow industry standard practices. (iii) You must ensure that any flow meter calibrations performed are NIST traceable. (5) Reporters using Equation PP
- 2 of this subpart shall determine the density of the CO 2 stream on a quarterly bas is in order to calculate the mass of the CO 2 stream according to one of the following procedure s : (i) You shall use an appropriate standard method published by a consensus
-based standards organization to401

measure density if such a method exists. 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 Petro leum Institute (API), and the North American Energy Standards Board (NAESB). (ii) You shall follow industry standard practices. (b) Determination of con centration. (1) Reporters using Equation PP
- 1 or PP
- 2 of this subpart shall sample the CO 2 stream on a quarterly basis to determine the composition of the CO 2 stream. (2) Methods to measure the composition of the CO 2 stream must conform to applicable chemical analytical standards. Acceptable methods include U.S. Food and Drug Administration food
- grade specifications for CO 2 (see 21 CFR 184.12 4 0) and ASTM standard E1747
- 95(Reapproved 2005) Standard Guide for Purity of Carbon Dioxide Used in Supercriti cal Fluid Applications (incorporated by reference, see §98.7 of subpart A of this part). (c) If you measure the flow of the CO 2 stream with a volumetric flow meter, you shall convert all measured volumes of carbon dioxide to the following standard industr y temperature and pressure conditions: standard402

cubic meters at a temperature of 60 degrees Fahrenheit and at an absolute pressure of 1 atmosphere. If you apply the density value for CO 2 at standard conditions, you must use must use 0.0018704 metric tons per standard cubic meter. §98.425 Procedures for estimating missing data. (a) Whenever the quality assurance procedures in §98.424(a) (2) of this subpart cannot be followed to measure quarterly mass flow or volumetric flow of CO 2 , the most appropriate of the following missing data procedures shall be followed: (1) A quarterly CO 2 mass flow or volumetric flow value that is missing may be substituted with a quarterly value measured during another quarter of the current reporting year. (2) A quarterly CO 2 mass flow or volumetric flow value that is missing may be substituted with a quarterly value measured during the same quarter from the past reporting year. (3) If a mass or volumetric flow meter is installed to measure the CO 2 stream, you may substitute data from a mass or volumetric flow meter measuring the CO 2 stream transferred for any period during which the installed meter is inoperable.403 (4) The mass or volumetric flow used for purposes of product tracking and billing according to the reporter’s est ablished procedures may be substituted for any period during which measurement equipment is inoperable. (b) Whenever the quality assurance procedures in §98.424(b) of this subpart cannot be followed to determine concentration of the CO 2 stream, the most appropriate of the following missing data procudures shall be followed: (1) A quarterly concentration value that is missing may be substituted with a quarterly value measured during another quarter of the current reporting year. (2) A quarterly concentra tion value that is missing may be substituted with a quarterly value measured during the same quarter from the previous reporting year. (3) The concentration used for purposes of product tracking and billing according to the reporter’s established procedu res may be substituted for any quarterly value. (c) Missing data on density of the CO 2 stream shall be substituted with quarterly or annual average values from the previous calendar year. (d) Whenever the quality assurance procedures in §98.424(a) (2) of this subpart cannot be followed to measure quarterly quantity of CO 2 in containers, the most404

appropriate of the following missing data procedures shall be followed: (1) A quarterly quantity of CO 2 in containers that is missing may be substituted with a qu arterly value measured during another representative quarter of the current reporting year. (2) A quarterly quantity of CO 2 in containers that is missing may be substituted with a quarterly value measured during the same quarter from the past reporting year. (3) The quarterly quantity of CO 2 in containers recorded for purposes of product tracking and billing according to the reporter’s established procedures may be substituted for any period during which measurement equipment is inoperable. §98.426 Dat a reporting requirements. In addition to the information required by §98.3(c) of subpart A of this part, the annual report shall contain the following information, as applicable: (a) If you use Equation PP
- 1 of this subpart, report the following informati on for each mass flow meter or CO 2 stream that delivers CO 2 to containers : (1) Annual mass in metric tons of CO 2. (2) Quarterly mass in metric tons of CO 2. (3) Quarterly concentration of the CO 2 stream.405 (4) The standard used to measure CO 2 concent ration. (5) The location of the flow meter in your process chain in relation to the points of CO 2 stream capture, deyhdration, compression, and other processing. (b) If you use Equation PP
- 2 of this subpart, report the following information for each vol umetric flow meter or CO 2 stream that delivers CO 2 to containers : (1) Annual mass in metric tons of CO 2. (2) Quarterly volume in standard cubic meters of CO 2. (3) Quarterly concentration of the CO 2 stream. (4) Quarterly density of the CO 2 st ream. (5) The method used to measure density. (6) The standard used to measure CO 2 concentration. (7) The location of the flow meter in your process chain in relation to the points of CO 2 stream capture, deyhdration, compression, and other processing. (c) If you use Equation PP
- 3 of this subpart report the annual CO 2 mass in metric tons from all flow meters and CO 2 streams that delivers CO 2 to containers . (d) If you use Equation PP
- 4 of this subpart, report at the corporate level the annual mass of CO 2 in metric tons in all CO 2 containers that are imported or exported. (e) Each reporter shall report the following information:406 (1) The type of equipment used to measure the total flow of the CO 2 stream or the total mass or volume in CO 2 containers. (2) The standard used to operate and calibrate the equipment reported in (e)(1) of this section. (3) The number of days in the reporting year for which substitute data procedures were used for the following purpose: (i) To measure quantity. (ii) To measure concentration. (iii) To measure density. (f) Report the aggregated annual quantity of CO 2 in metric tons that is transferred to each of the following end use applications, if known: (i) Food and beverage. (ii) Industrial and municipal water/wastewater treatment. (iii) Metal fabrication, including welding and cutting. (iv) Greenhouse uses for plant growth. (v) Fumigants (e.g., grain storage) and herbicides. (vi) Pulp and paper. (vii) Cleaning and solvent use. (viii) Fire fighting.407 (ix) Transporta tion and storage of explosives. (x) Enhanced oil and natural gas recovery. (xi) Long
- term storage (sequestration). (xii) Research and development. (xiii) Other. (g) Each production process unit that captures a CO 2 stream for purposes of supplying CO 2 for commercial applications or in order to sequester or otherwise inject it underground when custody of the CO 2 is maintained shall report the percentage of that stream, if any, that is biomass
-based during the reporting year. §98.427 Records that must be retained. In addition to the records required by §98.3(g) of subpart A of this part, you must retain the records specified in paragraphs (a) through (c) of this section, as applicable. (a) The owner or operator of a facility containing production process units must retain quarterly records of captured or transferred CO 2 streams and composition. (b) The owner or operator of a CO 2 production well facility must maintain quarterly records of the mass flow or volumetric flow of the extracted or transferred CO 2 stream and concentration and density if volumetric flow meters are used.408 (c) Importers or exporters of CO 2 must retain annual records of the mass flow, volumetric flow, and mass of CO 2 imported or exported. §98.428 Definitions. All terms used in th is subpart have the same meaning given in the Clean Air Act and subpart A of this part.