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 requirements 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 collocated 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 category (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, miscellaneous 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 2010 meets all three of the conditions listed in this paragraph (a)(3) . For these facilities, the annual GHG report must cover emissions from stationary fuel combustion sources only. (i) The facility does not meet the requirements of either paragraph (a)(1) or (a)(2) of this section. (ii) The aggregate maximum rated heat input capacity of the stationary fuel combustion units at the facility is 30 mmBtu/hr or greater. (iii) The facility emits 25,000 metric tons CO 2 e 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 must 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 CO 2 e 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 specified 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) All local natural gas distribution companies. (iv) Industrial greenhouse gas suppliers, as specified in this paragraph (iv): (A) All producers of industrial greenhouse gases. (B) Importers of industrial greenhouse gases with annual bulk imports of N 2 O, fluorinated GHG, and CO 2 that in6
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 25,000 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 metric 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 operator shall calculate annual CO 2 e emissions, as described in paragraphs (b)(1) through (b)(4) of this section.7
(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.



  n 1i i GWP x i GHG e 2 CO (Eq. A-1)8

Where: CO 2 e = Carbon 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 greenhouse 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. Then, 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 complete combustion or oxidation of the quantity of coal-to-liquid9
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 imports and exports as described in paragraphs (f)(1) through (f)(3) of this section. (1) Calculate the mass in metric tons per year of CO 2 , N 2 O, and each fluorinated GHG that is imported and the mass10
in metric tons per year of CO 2 , N 2 O, and each fluorinated GHG that is exported during the year. Include only those gases listed in Table A-1 of this subpart. (2) Convert the mass of each imported and each GHG exported from paragraph (f)(1) of this section to metric tons of CO 2 e using Equation A-1 of this section. (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 applicability requirements of paragraph (a) of this section at a later time. Thus, the owner or operator should reevaluate the applicability to this part (including the revising of any relevant emissions11
calculations or other calculations) whenever there is any change that could cause a facility or supplier to meet the applicability requirements of paragraph (a) of this section. Such changes include but are not limited to process modifications, increases in operating hours, increases in production, changes in fuel or raw material use, addition of equipment, and facility expansion. (i) Except as provided in this paragraph, once a facility or supplier is subject to the requirements of this part, the owner or operator must continue for each year thereafter to comply with all requirements of this part, including the requirement to submit annual GHG reports, even if the facility or supplier does not meet the applicability requirements in paragraph (a) of this section in a future year. (1) If reported emissions are less than 25,000 metric
tons 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 later than March 31 of the year immediately following the fifth consecutive year of emissions less than 25,000 tons CO 2 e per12
year. The owner or operator must maintain the corresponding records required under §98.3(g) for each of the five consecutive years and retain such records for three years following the year that reporting was discontinued. The owner or operator must resume reporting if annual emissions in any future calendar year increase to 25,000 metric tons 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 reporting if annual emissions in any future calendar year increase to 25,000 metric tons CO 2 e per year or more.13
(3) If the operations of a facility or supplier are changed such that all applicable GHG-emitting processes and operations listed in paragraphs (a)(1) through (a)(4) of this section cease to operate, then the owner or operator is exempt from reporting in the years following the year in which cessation of such operations occurs, provided that the owner or operator submits a notification to the Administrator that announces the cessation of reporting and certifies to the closure of all GHG-emitting processes and operations. This paragraph (i)(2) does not 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? 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.14

(a) General . Except as provided in paragraph (d) of this section, follow the procedures for emission calculation, monitoring, quality assurance, missing data, recordkeeping, and reporting that are specified in each relevant subpart of this part. (b) Schedule . The annual GHG report 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 occurs, beginning with the first month of the change and ending on December 31 of that year. For a facility or supplier that becomes subject to this rule solely because of an increase15
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) and physical street address including the city, state, and zip code

. (2) Year and months covered by the report. (3) Date of submittal. (4) For facilities, report annual emissions of CO 2, CH 4, N 2 O, and each fluorinated GHG (as defined in §98.6) as follows: (i) Annual emissions (excluding biogenic CO 2 ) aggregated for all GHG from all applicable source categories in subparts C through JJ of this part and expressed in metric tons of CO 2 e calculated using Equation A-1 of this subpart.16
(ii) Annual emissions of biogenic CO 2 aggregated for all applicable source categories in subparts C through JJ of this part. (iii) Annual emissions from each applicable source category in subparts C through JJ of this part, expressed in metric tons of each GHG listed in this paragraph (4)(iii)(A) through (4)(iii)(E). (A) Biogenic CO 2 . (B) CO 2 (excluding 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). (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 PP17
of this part and expressed in metric tons of CO 2 e calculated using Equation A-1 of this subpart. (ii) Quantity of each GHG from each applicable 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. (6) A written explanation, as required under §98.3(e), if you change emission calculation methodologies during the reporting period. (7) A brief description of each “best available monitoring method” used 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.18
(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 monitoring methods for any parameter (e.g., fuel use, daily carbon content of feedstock by process line) that cannot reasonably be measured according to the monitoring and QA/QC requirements of a relevant subpart. The owner or operator must use the calculation methodologies and equations in the “Calculating GHG Emissions” sections of each relevant subpart, but may use the best available monitoring method for any parameter for which it is not reasonably feasible to acquire, install, and operate a required piece of monitoring equipment by January 1, 2010. Starting no later than April 1, 2010, the owner or operator must discontinue using best available methods and begin following all applicable monitoring and QA/QC requirements of this part, except as provided in paragraphs (d)(2) and (d)(3) of this section. Best available monitoring methods means any of the following methods specified in this paragraph:19
(i) Monitoring methods currently used by the facility that do not meet the specifications of an relevant subpart. (ii) Supplier data. (iii) Engineering calculations. (iv) Other company records. (2) Requests for extension of the use of best available monitoring methods . The owner or operator may submit a request to the Administrator to use one or more best available monitoring methods beyond March 31, 2010. (i) Timing of request . The extension request must be submitted to EPA no later than 30 days after the effective date of the GHG reporting rule. (ii) Content of request . Requests must contain the following information: (A) A list of specific item of monitoring instrumentation for which the request is being made and the locations where each piece of monitoring instrumentation will be installed. (B) Identification of the specific rule requirements (by rule subpart, section, and paragraph numbers) for which the instrumentation is needed. (C) A description of the reasons why the needed equipment could not be obtained and installed before April 1, 2010.20
(D) If the reason for the extension is that the equipment cannot be purchased and delivered by April 1, 2010, include supporting documentation such as the date the monitoring equipment was ordered, investigation of alternative suppliers and the dates by which alternative vendors promised delivery, backorder notices or unexpected delays, descriptions of actions taken to expedite delivery, and the current expected date of delivery. (E) If the reason for the extension is that the equipment cannot be installed without a process unit shutdown, include supporting documentation demonstrating that it is not practicable to isolate the equipment and install the monitoring instrument without a full process unit shutdown. Include the date of the most recent process unit shutdown, the frequency of shutdowns for this process unit, and the date of the next planned shutdown during which the monitoring equipment can be installed. If there has been a shutdown or if there is a planned process unit shutdown between promulgation of this part and April 1, 2010, include a justification of why the equipment could not be obtained and installed during that shutdown. (F) A description of the specific actions the facility will take to obtain and install the equipment as21
soon as reasonably feasible and the expected date by which the equipment will be installed and operating. (iii) Approval Criteria . To obtain approval, the owner or operator must demonstrate to the Administrator’s satisfaction that it is not reasonably feasible to acquire, install, and operate a required piece of monitoring equipment by April 1, 2010. The use of best available methods will not be approved beyond December 31, 2010. (3) Abbreviated emissions report for facilities containing only general stationary fuel combustion sources
. In lieu of the report required by paragraph (c) of this section, the owner or operator of an existing facility that is in operation on January 1, 2010 and that meets the conditions of §98.2 (a)(3) may submit an abbreviated GHG report for the facility for GHGs emitted in 2010. The abbreviated report must be submitted by March 31, 2011. An owner or operator that submits an abbreviated report must submit a full GHG report according to the requirements of paragraph (c) of this section beginning in calendar year 2011. 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.22
(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 calculations. (vi) A signed and dated certification statement provided by the designated representative of the owner or operator, according to the requirements of paragraph (e)(1) of this section. (e) Emission Calculations . In preparing the GHG report, you must use the calculation methodologies specified in the relevant subparts, except as specified in paragraph (d) of this section. For each source category, you must use the same calculation methodology throughout a reporting period unless you provide a written explanation of why a change in methodology was required. (f) Verification . To verify the completeness and accuracy of reported GHG emissions, the Administrator may review the certification statements described in paragraphs (c)(8) 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 selected23
reporting facilities. Nothing in this section prohibits the Administrator from using additional information to verify the completeness and accuracy of the reports. (g) Recordkeeping . An owner or operator that is required to report GHGs under this part must keep records as specified in this paragraph. Retain all required records for at least 3 years. The records shall be kept in an electronic or hard-copy format (as appropriate) and recorded in a form that is suitable for expeditious inspection and review. Upon request by the Administrator, the records required under this section must be made available to EPA. Records may be retained off site if the records are readily available for expeditious inspection and review. For records that are electronically generated or maintained, the equipment or software necessary to read the records shall be made available, or, if requested by EPA, electronic records shall be converted to paper documents. You must retain the following records, in addition to those records prescribed in each applicable subpart of this part: (1) A list of all units, operations, processes, and activities for which GHG emission were calculated. (2) The data used to calculate the GHG emissions for each unit, operation, process, and activity, categorized by24
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 sitespecific emissions factors. (iii) The results of all required analyses for high heat value, carbon content, and other required fuel or feedstock parameters. (iv) Any facility operating data or process information used for the GHG emission calculations. (3) The annual GHG reports. (4) Missing data computations. For each missing data event, also retain a record of the duration of the event, actions taken to restore malfunctioning monitoring equipment, the cause of the event, and the actions taken to prevent or minimize occurrence in the future. (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.25
(C) Description of the procedures and methods that are used for quality assurance, maintenance, and repair of all continuous monitoring systems, flow meters, and other instrumentation used to provide data for the GHGs reported under this part. (ii) The GHG Monitoring Plan may rely on references to existing corporate documents (e.g., standard operating procedures, quality assurance programs under appendix F to 40 CFR part 60 or appendix B to 40 CFR part 75, and other documents) provided that the elements required by paragraph (g)(5)(i) of this section are easily recognizable. (iii) The owner or operator shall revise the GHG Monitoring Plan as needed to reflect changes in production processes, monitoring instrumentation, and quality assurance procedures; or to improve procedures for the maintenace and repair of monitoring systems to reduce the frequency of monitoring equipment downtime. (iv) Upon request by the Administrator, the owner or operator shall make all information that is collected in conformance with the GHG Monitoring Plan available for review during an audit. Electronic storage of the information in the plan is permissible, provided that the information can be made available in hard copy upon request during an audit.26
(6) The results of all required certification and quality assurance tests of continuous monitoring systems, fuel flow meters, and other instrumentation used to provide data for the GHGs reported under this part. (7) Maintenance records for all continuous monitoring systems, flow meters, and other instrumentation used to provide data for the GHGs reported under this part. (h) Annual GHG report revisions . The owner or operator shall submit a revised report within 45 days of discovering or being notified by EPA of errors in an annual GHG report. The revised report must correct all identified errors. The owner or operator shall retain documentation for 3 years to support any revisions made to an annual GHG report. (i) Calibration Accuracy Requirements . The owner or operator of a facility or supplier that is subject to the requirements of this part must meet the calibration accuracy requirements of this paragraph (i). (1) Except as provided paragraphs (i)(4) through (i)(6) of this section, flow meters and other devices (e.g., belt scales) that measure data used to calculate GHG emissions shall be calibrated prior to April 1, 2010 using the procedures specified in this paragraph and each relevant subpart of this part. All measurement devices must27
be calibrated according to the manufacturer’s recommended procedures, an appropriate industry consensus standard, or a method specified in a relevant subpart of this part. All measurement devices shall be calibrated to an accuracy of 5 percent. For facilities and suppliers that become subject to this part after April 1, 2010, the initial calibration shall be conducted on the date that data collection is required to begin. Subsequent calibrations shall be performed at the frequency specified in each applicable subpart. (2) For flow meters, perform all calibrations at measurement points that are representative of normal operation of the meter. Except for the orifice, nozzle, and venturi flow meters described in paragraph (i)(3) of this section, calculate the calibration error at each measurement point using Equation A-2 of this section. The terms “R” and “A” in Equation A-2 must be expressed in consistent units of measure (e.g., gallons/minute, ft 3 /min). The calibration error at each measurement point shall not exceed 5.0 percent of the reference value.

100x R AR CE   (Eq. A-2) Where:28
CE = Calibration error (%) R = Reference value A = Flow meter response to the reference value (3) For orifice, nozzle, and venturi flow meters, the initial quality assurance consists of in-situ calibration of the differential pressure (delta-P), total pressure, and temperature transmitters. Calibrate each transmitter at a zero point and at least one upscale point. Fixed reference points, such as the freezing point of water, may be used for temperature transmitter calibrations. Calculate the calibration error of each transmitter at each measurement point, using Equation A-3 of this subpart. The terms “R”, “A”, and “FS” in Equation A-3 of this subpart must be in consistent units of measure (e.g., milliamperes, inches of water, psi, degrees). For each transmitter, the CE value at each measurement point shall not exceed 2.0 percent of full-scale. Alternatively, the results are acceptable if the sum of the calculated CE values for the three transmitters at each calibration level (i.e., at the zero level and at each upscale level) does not exceed 5.0 percent.

100x FS AR CE   (Eq. A-3) Where: CE = Calibration error (%)29

R = Reference value A = Transmitter response to the reference value FS = Full-scale value of the transmitter (4) Fuel billing meters are exempted from the calibration requirements of this section, provided that the fuel supplier and any unit combusting the fuel do not have any common owners and are not owned by subsidiaries or affiliates of the same company. (5) For a flow meter or other measurement device that has been previously calibrated in accordance with this part, an initial calibration is not required by the date specified in paragraph (i)(1) of this section if, as of the date required for the initial calibration, the previous calibration is still active (i.e., the device is not yet due for recalibration because the time interval between successive calibrations, as required by this part, has not elapsed). (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 removing the device from service and shipping it to a remote location, thereby disrupting normal process operation. In such cases, the owner or operator may postpone the initial30
calibration until the next scheduled maintenance outage, and may similarly postpone the subsequent recalibrations. Such postponements shall be documented in the monitoring plan that is required under §98.3(g)(5). §98.4 Authorization and Responsibilities of the Designated Representative. (a) General . Except as provided under paragraph (f) of this section, each facility, and each supplier, that is subject to this part, shall have one and only one designated representative, who shall be responsible for certifying, signing, and submitting GHG emissions reports and any other submissions for such facility and supplier respectively to the Administrator under this part. If the facility is required under any other part of title 40 of the Code of Federal Regulations to submit to the Administrator any other emission report that is subject to any requirement in 40 CFR part 75, the same individual shall be the designated representative responsible for certifying, signing, and submitting the GHG emissions reports and all such other emissions reports under this part. (b) Authorization of a designated representative
. The designated representative of the facility or supplier shall be an individual selected by an agreement binding on31
the owners and operators of such facility or supplier and shall act in accordance with the certification statement in paragraph (i)(4)(iv) of this section. (c) Responsibility of the designated representative
. Upon receipt by the Administrator of a complete certificate of representation under this section for a facility or supplier, the designated representative identified in such certificate of representation shall represent and, by his or her representations, actions, inactions, or submissions, legally bind each owner and operator of such facility or supplier in all matters pertaining to this part, notwithstanding any agreement between the designated representative and such owners and operators. The owners and operators shall be bound by any decision or order issued to the designated representative by the Administrator or a court. (d) Timing . No GHG emissions report or other submissions under this part for a facility or supplier will be accepted until the Administrator has received a complete certificate of representation under this section for a designated representative of the facility or supplier. Such certificate of representation shall be submitted at least 60 days before the deadline for submission of the32
facility’s or supplier’s initial emission report under this part. (e) Certification of the GHG emissions report . Each GHG emission report and any other submission under this part for a facility or supplier shall be certified, signed, and submitted by the designated representative or any alternate designated representative of the facility or supplier in accordance with this section and §3.10. (1) Each such submission shall include the following certification statement signed by the designated representative or any alternate designated representative: “I am authorized to make this submission on behalf of the owners and operators of the facility or supplier, as applicable, for which the submission is made. I certify under penalty of law that I have personally examined, and am familiar with, the statements and information submitted in this document and all its attachments. Based on my inquiry of those individuals with primary responsibility for obtaining the information, I certify that the statements and information are to the best of my knowledge and belief true, accurate, and complete. I am aware that there are significant penalties for submitting false statements and information or omitting required statements33
and information, including the possibility of fine or imprisonment.” (2) The Administrator will accept a GHG emission report or other submission for a facility or supplier under this part only if the submission is certified, signed, and submitted in accordance with this section. (f) Alternate designated representative . A certificate of representation under this section for a facility or supplier may designate one alternate designated representative, who shall be an individual selected by an agreement binding on the owners and operators, and may act on behalf of the designated representative, of such facility or supplier. The agreement by which the alternate designated representative is selected shall include a procedure for authorizing the alternate designated representative to act in lieu of the designated representative. (1) Upon receipt by the Administrator of a complete certificate of representation under this section for a facility or supplier identifying an alternate designated representative. (i) The alternate designated representative may act on behalf of the designated representative for such facility or supplier.34
(ii) Any representation, action, inaction, or submission by the alternate designated representative shall be deemed to be a representation, action, inaction, or submission by the designated representative. (2) Except in this section, whenever the term “designated representative” is used in this part, the term shall be construed to include the designated representative or any alternate designated representative. (g) Changing a designated representative or alternate designated representative . The designated representative or alternate designated representative identified in a complete certificate of representation under this section for a facility or supplier received by the Administrator may be changed at any time upon receipt by the Administrator of another later signed, complete certificate of representation under this section for the facility or supplier. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous designated representative or the previous alternate designated representative of the facility or supplier before the time and date when the Administrator receives such later signed certificate of representation shall be binding on the new designated representative and the owners and operators of the facility or supplier.35
(h) Changes in owners and operators . In the event an owner or operator of the facility or supplier is not included in the list of owners and operators in the certificate of representation under this section for the facility or supplier, such owner or operator shall be deemed to be subject to and bound by the certificate of representation, the representations, actions, inactions, and submissions of the designated representative and any alternate designated representative of the facility or supplier, as if the owner or operator were included in such list. Within 90 days after any change in the owners and operators of the facility or supplier (including the addition of a new owner or operator), the designated representative or any alternate designated representative shall submit a certificate of representation that is complete under this section except that such list shall be amended to reflect the change. If the designated representative or alternate designated representative determines at any time that an owner or operator of the facility or supplier is not included in such list and such exclusion is not the result of a change in the owners and operators, the designated representative or any alternate designated representative shall submit, within 90 days of making such determination, a certificate of representation36
that is complete under this section except that such list shall be amended to include such owner or operator. (i) Certificate of representation . A certificate of representation shall be complete if it includes the following elements in a format prescribed by the Administrator in accordance with this section: (1) Identification of the facility or supplier for which the certificate of representation is submitted. (2) The name, 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, as37
applicable, by an agreement binding on the owners and operators of the facility or supplier, as applicable.” (ii) “I certify that I have all the necessary authority to carry out my duties and responsibilities under 40 CFR part 98 on behalf of the owners and operators of the facility or supplier, as applicable, and that each such owner and operator shall be fully bound by my representations, actions, inactions, or submissions.” (iii) “I certify that the owners and operators of the facility or supplier, as applicable, shall be bound by any order issued to me by the Administrator or a court regarding the facility or supplier.” (iv) “If there are multiple owners and operators of the facility or supplier, as applicable, I certify that I have given a written notice of my selection as the ‘designated representative’ or ‘alternate designated representative’, as applicable, and of the agreement by which I was selected to each owner and operator of the facility or supplier." (5) The signature of the designated representative and any alternate designated representative and the dates signed. (j) Documents of agreement . Unless otherwise required by the Administrator, documents of agreement38
referred to in the certificate of representation shall not be submitted to the Administrator. The Administrator shall not be under any obligation to review or evaluate the sufficiency of such documents, if submitted. (k) Binding nature of the certificate of representation . Once a complete certificate of representation under this section for a facility or supplier has been received, the Administrator will rely on the certificate of representation unless and until a later signed, complete certificate of representation under this section for the facility or supplier is received by the Administrator. (l) Objections concerning a designated representative. (1) Except as provided in paragraph (g) of this section, no objection or other communication submitted to the Administrator concerning the authorization, or any representation, action, inaction, or submission, of the designated representative or alternate designated representative shall affect any representation, action, inaction, or submission of the designated representative or alternate designated representative, or the finality of any decision or order by the Administrator under this part.39
(2) The Administrator will not adjudicate any private legal dispute concerning the authorization or any representation, action, inaction, or submission of any designated representative or alternate designated representative. (m) Delegation by designated representative and alternate designated representative. (1) A designated representative or an alternate designated representative may delegate his or her own authority, to one or more individuals, to submit an electronic submission to the Administrator provided for or required under this part, except for a submission under this paragraph. (2) In order to delegate his or her own authority, to one or more individuals, to submit an electronic submission to the Administrator in accordance with paragraph (m) (1) of this section, the designated representative or alternate designated representative must submit electronically to the Administrator a notice of delegation, in a format prescribed by the Administrator, that includes the following elements: (i) The name, address, e-mail address (if any), telephone number, and facsimile transmission number (if40
any) of such designated representative or alternate designated representative. (ii) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of each such individual (referred to as an “agent”). (iii) For each such individual, a list of the type or types of electronic submissions under paragraph (m)(1) of this section for which authority is delegated to him or her. (iv) For each type of electronic submission listed in accordance with clause (iii), the facility or supplier for which the electronic submission may be made. (v) The following certification statements by such designated representative or alternate designated representative: (A) “I agree that any electronic submission to the Administrator that is by an agent identified in this notice of delegation and of a type listed, and for a facility or supplier designated, for such agent in this notice of delegation and that is made when I am a designated representative or alternate designated representative, as applicable, and before this notice of delegation is superseded by another notice of delegation under41
§98.4(m)(3) shall be deemed to be an electronic submission certified, signed, and submitted by me.” (B) “Until this notice of delegation is superseded by a later signed notice of delegation under §98.4(m)(3), I agree to maintain an e-mail account and to notify the Administrator immediately of any change in my e-mail address unless all delegation of authority by me under §98.4(m) is terminated.”. (vi) The signature of such designated representative or alternate designated representative and the date signed. (3) A notice of delegation submitted in accordance with paragraph (m)(2) of this section shall be effective, with regard to the designated representative or alternate designated representative identified in such notice, upon receipt of such notice by the Administrator and until receipt by the Administrator of another such notice that was signed later by such designated representative or alternate designated representative, as applicable. The later signed notice of delegation may replace any previously identified agent, add a new agent, or eliminate entirely any delegation of authority. (4) Any electronic submission covered by the certification in paragraph (m)(2)(iv)(A) of this section and made in accordance with a notice of delegation42
effective under paragraph (m)(3) of this section shall be deemed to be an electronic submission certified, signed, and submitted by the designated representative or alternate designated representative submitting such notice of delegation. §98.5 How is the report submitted? Each GHG report and certificate of representation for a facility or supplier must be submitted electronically in accordance with the requirements of §98.4 and in a format specified by the Administrator. §98.6 Definitions. All terms used in this part shall have the same meaning given in the Clean Air Act and in this section. Accuracy of a measurement at a specified level (e.g., one percent of full scale or one percent of the value measured) means that the mean of repeat measurements made by a device or technique are within 95 percent of the range bounded by the true value plus or minus the specified level. Acid Rain Program means the program established under title IV of the Clean Air Act, and implemented under parts 72 through 78 of this chapter for the reduction of sulfur dioxide and nitrogen oxides emissions.43

Administrator means the Administrator of the United States Environmental Protection Agency or the Administrator’s authorized representative.
AGA means the American Gas Association 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 operated to stabilize wastes using anaerobic microbial processes. Anaerobic lagoons may be designed for combined stabilization and storage with varying lengths of retention44
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.
ASABE means the American Society of Agricultural and Biological Engineers.
ASME means the American Society of Mechanical Engineers.
ASTM means the American Society of Testing and Materials. Asphalt means a dark brown-to-black cement-like material obtained by petroleum processing and containing bitumens as the predominant component. It includes crude asphalt as well as the following finished products: cements, fluxes, the asphalt content of emulsions Deleted: 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 reduce the carbon content of the steel.¶45
(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 in which high-purity oxygen is blown under pressure through a bath of molten iron, scrap metal, and fluxes to produce steel. bbl means barrel. Biodiesel means a mono-akyl ester derived from biomass and conforming to ASTM D6751-08, Standard Specification for Biodiesel Fuel Blend Stock (B100) for Middle Distillate Fuels. Biogenic 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.46

Biomass means non-fossilized and biodegradable organicmaterial originating from plants, animals or microorganisms, 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, includinggases and liquids recovered from the decomposition of nonfossilized and biodegradable organic material. Blast furnace means a furnace that is located at an integrated iron and steel plant and is used for the production of molten iron from iron ore pellets and other iron bearing materials. Blendstocks are petroleum products used for blending or compounding into finished motor gasoline. These include RBOB (reformulated blendstock for oxygenate blending) and CBOB (conventional blendstock for oxygenate blending), but exclude oxygenates, butane, and pentanes plus. Blendstocks -- Others are products used for blending or compounding into finished motor gasoline that are not defined elsewhere. Excludes Gasoline Treated as Blendstock (GTAB), Diesel Treated as Blendstock (DTAB), conventional blendstock for oxygenate blending (CBOB), reformulated blendstock for oxygenate blending (RBOB), oxygenates (e.g.47
fuel ethanol and methyl tertiary butyl ether), butane, and pentanes plus. Blowdown mean the act of emptying or depressuring a vessel. This may also refer to the discarded material such as blowdown water from a boiler or cooling tower. British Thermal Unit or Btu means the quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit at about 39.2 degrees Fahrenheit. Bulk , with respect to industrial GHG suppliers and CO2 suppliers, means the transfer of a product inside containers, including but not limited to tanks, cylinders, drums, and pressure vessels. Bulk natural gas liquid or NGL refers to mixtures of hydrocarbons that have been separated from natural gas as liquids through the process of absorption, condensation, adsorption, or other methods at lease separators and field facilities. Generally, such liquids consist of ethane, propane, butanes, and pentanes plus. Bulk NGL is sold to fractionators or to refineries and petrochemical plants where the fractionation takes place.
Butane , or n-Butane, is a paraffinic straight-chain hydrocarbon with molecular formula C 4 H 10 . Butylene , or n-Butylene, is an olefinic straight-chain hydrocarbon with molecular formula C 4 H 8 .48
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 carbon dioxide. Carbon dioxide production well facility means one or more carbon dioxide production wells that are located on one or more contiguous or adjacent properties, which are under the control of the same entity. Carbon dioxide production wells located on different oil and gas leases, mineral fee tracts, lease tracts, subsurface or surface unit areas, surface fee tracts, surface lease tracts, or49
separate surface sites, whether or not connected by a road, waterway, power line, or pipeline, shall be considered 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 carbon dioxide production well plus incidental associated substances either derived from the source materials and the capture process or extracted with the carbon dioxide. Carbon share means the percent of total mass that carbon represents in any product.. Carbonate means compounds containing the radical 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 ) or 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 ), sodium carbonate (Na 2 CO 3 ) , barium carbonate (BaCO 3 ), and potassium carbonate (K 2 CO 3 )
. Deleted: and50

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; for soda ash, the mass fraction of Na 2 CO 3 in the soda ash ; for barium carbonate, the mass fraction of
BaCO 3 in the barium carbonate; and for potassium carbonate, the mass fraction of K 2 CO 3 in the potassium carbonate
. Carbonate-based raw material means any of the following materials used in the manufacture of glass: limestone, dolomite, soda ash , barium carbonate, and potassium carbonate
. Catalytic cracking unit means a refinery process unit in which petroleum derivatives are continuously charged and hydrocarbon molecules in the presence of a catalyst are fractured into smaller molecules, or react with a contact material suspended in a fluidized bed to improve feedstock quality for additional processing and the catalyst or contact material is continuously regenerated by burning off coke and other deposits. Catalytic cracking units include both fluidized bed systems, which are referred to as fluid catalytic cracking units (FCCU), and moving bed systems, which are also referred to as thermal catalytic cracking units. The unit includes the riser, reactor, regenerator, air blowers, spent catalyst or contact material stripper, Deleted: and

Deleted: and51
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 accurate to within 2 percent of the value on the label or calibration gases.
CH 4 means methane.52
Chemical recovery combustion unit means a combustion device, such as a recovery furnace or fluidized-bed reactor where spent pulping liquor from sulfite or semi-chemical pulping processes is burned to recover pulping chemicals. Chemical recovery furnace means an enclosed combustion device where concentrated spent liquor produced by the kraft or soda pulping process is burned to recover pulping chemicals and produce steam. Includes any recovery furnace that burns spent pulping liquor produced from both the kraft and soda pulping processes. Chloride process means a production process where titanium dioxide is produced using calcined petroleum coke and chlorine as raw materials. City gate means a location at which natural gas ownership or control passes from one party to another, neither of which is the ultimate consumer. In this rule, in keeping with common practice, the term refers to a point or measuring station at which a local gas distribution utility receives gas from a natural gas pipeline company or transmission system. Meters at the city gate station measure the flow of natural gas into the local distribution company system and typically are used to measure local distribution company system sendout to customers.
CO 2 means carbon dioxide.53

Coal means all solid fuels classified as anthracite, bituminous, sub-bituminous, or lignite by the American Society for Testing and Materials Designation ASTM D388–05 Standard Classification of Coals by Rank (incorporated by reference, see §98.7).
COD means the chemical oxygen demand as determined using methods specified pursuant to 40 CFR part 136. Coke burn-off means the coke removed from the surface of a catalyst by combustion during catalyst regeneration. Coke burn-off also means the coke combusted in fluid coking unit burner. Cokemaking means the production of coke from coal in either a by-product coke oven battery or a non-recovery coke oven battery. Commercial Applications means executing a commercial transaction subject to a contract. A commercial application includes transferring custody of a product from one facility to another if it otherwise meets the definition. Company records means, in reference to the amount of fuel consumed by a stationary combustion unit (or by a group of such units), a complete record of the methods used, the measurements made, and the calculations performed to quantify fuel usage. Company records may include, but are not limited to, direct measurements of fuel consumption54
by gravimetric or volumetric means, tank drop measurements, and calculated values of fuel usage obtained by measuring auxiliary parameters such as steam generation or unit operating hours. Fuel billing records obtained from the fuel supplier qualify as company records.
Connector means to flanged, screwed, or other joined fittings used to connect pipe line segments, tubing, pipe components (such as elbows, reducers, “T’s” or valves) or a pipe line and a piece of equipment or an instrument to a pipe, tube or piece of equipment. A common connector is a flange. Joined fittings welded completely around the circumference of the interface are not considered connectors for the purpose of this part. Container glass means glass made of soda-lime recipe, clear or colored, which is pressed and/or blown into bottles, jars, ampoules, and other products listed in North American Industry Classification System 327213 (NAICS 327213). Continuous emission monitoring system or CEMS means the total equipment required to sample, analyze, measure, and provide, by means of readings recorded at least once every 15 minutes, a permanent record of gas concentrations, pollutant emission rates, or gas volumetric flow rates from stationary sources.55
Continuous glass melting furnace means a glass melting furnace that operates continuously except during periods of maintenance, malfunction, control device installation, reconstruction, or rebuilding. Conventional—Summer refers to finished gasoline formulated for use in motor vehicles, the composition and properties of which do not meet the requirements of the reformulated gasoline regulations promulgated by the U.S. Environmental Protection Agency under 40 CFR 80.40, but which meet summer RVP standards required under 40 CFR 80.27 or as specified by the state. Note: This category excludes conventional gasoline for oxygenate blending (CBOB) as well as other blendstock. Conventional—Winter refers to finished gasoline formulated for use in motor vehicles, the composition and properties of which do not meet the requirements of the reformulated gasoline regulations promulgated by the U.S. Environmental Protection Agency under 40 CFR 80.40 or the summer RVP standards required under 40 CFR 80.27 or as specified by the state. Note: This category excludes conventional blendstock for oxygenate blending (CBOB) as well as other blendstock. Crude oil means a mixture of hydrocarbons that exists in liquid phase in natural underground reservoir s and Deleted: the Deleted: the56
remains liquid at atmospheric pressure after passing through surface separating facilities. Depending upon the characteristics of the crude stream, it may also include any of the following: (1) Small amounts of hydrocarbons that exist in gaseous phase in natural underground reservoirs but are liquid at atmospheric pressure after being recovered from oil well (casinghead) gas in lease separators and are subsequently commingled with the crude stream without being separately measured. Lease condensate recovered as a liquid from natural gas wells in lease or field separation facilities and later mixed into the crude stream is also included. (2) Small amounts of nonhydrocarbons produced from oil, such as sulfur and various metals. (3) Drip gases, and liquid hydrocarbons produced from tar sands, oil sands, gilsonite, and oil shale. Liquids produced at natural gas processing plants are excluded. Crude oil is refined to produce a wide array of petroleum products, including heating oils; gasoline, diesel and jet fuels; lubricants; asphalt; ethane, propane, and butane; and many other products used for their energy or chemical
content.57
Daily spread means a manure management system component in which manure is routinely removed from a confinement facility and is applied to cropland or pasture within 24 hours of excretion. Day means any consistently designated 24 hour period during which an emission unit is operated. Decarburization vessel means any vessel used to further refine molten steel to reduce the carbon content of the steel. This definition includes vessels used for argon-oxygen decarburization, vacuum degassers, vacuum oxygen degassers, Rheinstahl-Heraus systems, and other decarburization vessels. 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 closed, 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).58
Destruction means, with respect to landfills and manure management, the combustion of methane in any on-site or off-site combustion technology. Destroyed methane includes, but is not limited to, methane combusted by flaring, methane destroyed by thermal oxidation, methane combusted for use in on-site energy or heat production technologies, methane that is conveyed through pipelines (including natural gas pipelines) for off-site combustion,and methane that is collected for any other on-site or offsite use as a fuel. Destruction means, with respect to fluorinated GHGs, the expiration of a fluorinated GHG to the destruction efficiency actually achieved. Such destruction does not result in a commercially useful end product. Destruction Efficiency means the efficiency with which a destruction device reduces the GWP-weighted mass ofgreenhouse gases fed into the device, considering the GWPweighted 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 etCO etCO DE 2 2 1  (Eq. A-2)
Where:59
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 Diesel 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, diesel fuels (Diesel Fuels No. 1, No. 2,60
and No. 4), and fuel oils (Fuel Oils No. 1, No. 2, and No. 4). Distillate Fuel No. 1 has a maximum distillation temperature of 550 °F at the 90 percent recovery point and a minimum flash point of 100 °F and includes fuels commonly known as Diesel Fuel No. 1 and Fuel Oil No. 1, but excludes kerosene. This fuel is further subdivided into categories of sulfur content: High Sulfur (greater than 500 ppm), Low Sulfur (less than or equal to 500 ppm and greater than 15 ppm), and Ultra Low Sulfur (less than or equal to 15 ppm). Distillate Fuel No. 2 has a minimum and maximum distillation temperature of 540 °F and 640 °F at the 90 percent recovery point, respectively, and includes fuels commonly known as Diesel Fuel No. 2 and Fuel Oil No. 2. This fuel is further subdivided into categories of sulfur content: High Sulfur (greater than 500 ppm), Low Sulfur (less than or equal to 500 ppm and greater than 15 ppm), and Ultra Low Sulfur (less than or equal to 15 ppm). Distillate Fuel No. 4 is a distillate fuel oil made by blending distillate fuel oil and residual fuel oil, with a minimum flash point of 131 °F.
DOC f means the fraction of DOC that actually decomposes under the (presumably anaerobic) conditions within the landfill.61
Dry lot means a manure management system component consisting of a paved or unpaved open confinement area without any significant vegetative cover where accumulating manure may be removed periodically. Electric arc furnace (EAF) means a furnace that produces molten alloy metal and heats the charge materials with electric arcs from carbon electrodes. Electric arc furnace steelmaking means the production of carbon, alloy, or specialty steels using an EAF. This definition excludes EAFs at steel foundries and EAFs used to produce nonferrous metals. Electrothermic furnace means a furnace that heats the charged materials with electric arcs from carbon electrodes. Emergency generator means a stationary combustion device, such as a reciprocating internal combustion engine or turbine that serves solely as a secondary source of mechanical or electrical power whenever the primary energy supply is disrupted or discontinued during power outages or natural disasters that are beyond the control of the owner or operator of a facility. An emergency generator operates only during emergency situations, for training of personnel under simulated emergency conditions, as part of emergency demand response procedures, or for standard performance62
testing procedures as required by law or by the generator manufacturer. A generator that serves as a back-up power source under conditions of load shedding, peak shaving, power interruptions pursuant to an interruptible power service agreement, or scheduled facility maintenance shall not be considered an emergency generator.Emergency equipment means any auxiliary fossil fuelpowered equipment, such as a fire pump, that is used only in emergency situations. ETBE (ethyl tertiary butyl ether, (CH 3 ) 3 COC 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 5 OH. 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) or63
that is used as a raw material for non-experimental furnaces. Export means to transport a product from inside the United States to persons outside the United States, excluding any such transport on behalf of the United States military including foreign military sales under the Arms Export Control Act. Exporter means any person, company or organization of record that transfers for sale or for other benefit, domestic products from the United States to another country or to an affiliate in another country, excluding any such transfers on behalf of the United States military or military purposes including foreign military sales under the Arms Export Control Act. An exporter is not the entity merely transporting the domestic products, rather an exporter is the entity deriving the principal benefit from the transaction. Facility means any physical property, plant, building, structure, source, or stationary equipment located on one or more contiguous or adjacent properties in actual physical contact or separated solely by a public roadway or other public right-of-way and under common ownership or common control, that emits or may emit any greenhouse gas. Operators of military installations may classify such64
installations as more than a single facility based on distinct and independent functional groupings within contiguous military properties. Feed means the prepared and mixed materials, which include but are not limited to materials such as limestone, clay, shale, sand, iron ore, mill scale, cement kiln dust and flyash, that are fed to the kiln. Feed does not include the fuels used in the kiln to produce heat to form the clinker product. Feedstock means raw material inputs to a process that are transformed by reaction, oxidation, or other chemical or physical methods into products and by-products. Supplemental fuel burned to provide heat or thermal energy is not a feedstock. Fischer-Tropsch process means a catalyzed chemical reaction in which synthesis gas, a mixture of carbon monoxide and hydrogen, is converted into liquid hydrocarbons of various forms. Flare means a combustion device, whether at ground level or elevated, that uses an open flame to burn combustible gases with combustion air provided by uncontrolled ambient air around the flame.65
Flat glass means glass made of soda-lime recipe and produced into continuous flat sheets and other products listed in NAICS 327211. Flowmeter means a device that measures the mass or volumetric rate of flow of a gas, liquid, or solid moving through an open or closed conduit (e.g. flowmeters include, but are not limited to, rotameters, turbine meters, coriolis meters, orifice meters, ultra-sonic flowmeters, and vortex flowmeters). Fluid coking unit means one or more refinery process units in which high molecular weight petroleum derivatives are thermally cracked and petroleum coke is continuously produced in a fluidized bed system. The fluid coking unit includes equipment for controlling air pollutant emissions and for heat recovery on the fluid coking burner exhaust vent. There are two basic types of fluid coking units: a traditional fluid coking unit in which only a small portion of the coke produced in the unit is burned to fuel the unit and the fluid coking burner exhaust vent is directed to the atmosphere (after processing in a CO boiler or other air pollutant control equipment) and a flexicoking unit in which an auxiliary burner is used to partially combust a significant portion of the produced petroleum coke to66
generate a low value fuel gas that is used as fuel in other combustion sources at 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, including for example, consumer products that are derived from such materials and are combusted. Fossil fuel-fired means powered by combustion of fossil fuel, alone or in combination with any other fuel, regardless of the percentage of fossil fuel consumed. Fractionators means plants that produce fractionated natural gas liquids (NGLs) extracted from produced natural gas and separate the NGLs individual component products: ethane, propane, butanes and pentane-plus (C5+). Plants that only process natural gas but do not fractionate NGLs67
further into component products are not considered fractionators. Some fractionators do not process production gas, but instead fractionate bulk NGLs received from natural gas processors. Some fractionators both process natural gas and fractionate bulk NGLs received from other plants. Fuel means solid, liquid or gaseous combustible material. Fuel gas means gas generated at a petroleum refinery, 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 by means of a fan68
or similar mechanical draft equipment to a single location for treatment (thermal destruction) or use. Landfill gas collection systems may also include knock-out or separator drums and/or a compressor. Landfill gas collection systems do not include “passive” systems, whereby landfill gas flows naturally to the surface of the landfill where an opening or pipe (vent) is installed to allow for natural gas flow. Gas-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 standard atmospheric temperature and pressure conditions and that is combusted to produce heat and/or
energy. Gasification means the conversion of a solid or liquid raw material into a gas. Gasoline – Other is any gasoline that is not defined elsewhere, including GTAB (gasoline treated as blendstock).69
Glass melting furnace means a unit comprising a refractory-lined vessel in which raw materials are charged and melted at high temperature to produce molten glass. Glass produced means the weight of glass exiting a glass melting furnace. Global warming potential or GWP means the ratio of the time-integrated radiative forcing from the instantaneous release of one kilogram of a trace substance relative to that of one kilogram- of a reference gas, i.e., CO 2 . GPA means 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 ) 3 COH), 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).70
High heat value or HHV means the high or gross heat content of the fuel with the heat of vaporization included. The water is assumed to be in a liquid state. Hydrofluorocarbons or HFCs means a class of GHGs consisting of hydrogen, fluorine, and carbon. Import means, to land on, bring into, or introduce into, any place subject to the jurisdiction of the United States whether or not such landing, bringing, or introduction constitutes an importation within the meaning of the customs laws of the United States, with the following exemptions: (1) Off-loading used or excess fluorinated GHGs or nitrous oxide of U.S. origin from a ship during servicing. (2) Bringing fluorinated GHGs or nitrous oxide into the U.S. from Mexico where the fluorinated GHGs or nitrous oxide had been admitted into Mexico in bond and were of U.S. origin. (3) Bringing fluorinated GHGs or nitrous oxide into the U.S. when transported in a consignment of personal or household effects or in a similar non-commercial situation normally exempted from U.S. Customs attention. (4) Bringing fluorinated GHGs or nitrous into U.S. jurisdiction exclusively for U. S. military purposes.71
Importer means any person, company, or organization of record that for any reason brings a product into the United States from a foreign country, excluding introduction into U.S. jurisdiction exclusively for United States military purposes. An importer is the person, company, or organization primarily liable for the payment of any duties on the merchandise or an authorized agent acting on their behalf. The term includes, as appropriate: (1) The consignee. (2) The importer of record. (3) The actual owner. (4) The transferee, if the right to draw merchandise in a bonded warehouse has been transferred. Indurating furnace means a furnace where unfired taconite pellets, called green balls, are hardened at high temperatures to produce fired pellets for use in a blast furnace. Types of indurating furnaces include straight gate and grate kiln furnaces. Industrial greenhouse gases means nitrous oxide or any fluorinated greenhouse gas. In-line kiln/raw mill means a system in a portland cement production process where a dry kiln system is integrated with the raw mill so that all or a portion of the kiln exhaust gases are used to perform the drying72
operation of the raw mill, with no auxiliary heat source used. In this system the kiln is capable of operating without the raw mill operating, but the raw mill cannot operate without the kiln gases, and consequently, the raw mill does not generate a separate exhaust gas stream. Isobutane is a paraffinic branch chain hydrocarbon with molecular formula C 4 H 10 . 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 of total mass, respectively), as well as all other grades of kerosene called range or stove oil. Excluded is kerosene-type jet fuel (see definition herein). Kerosene-Type Jet Fuel means a kerosene-based product used in commercial and military turbojet and turboprop aircraft. The product has a maximum distillation temperature of 400 °F at the 10 percent recovery point and a final maximum boiling point of 572 °F. Included are Jet A, Jet A-1, JP-5, and JP-8.73

Kiln means an oven, furnace, or heated enclosure used for thermally processing a mineral or mineral-based substance. Landfill means an area of land or an excavation in which wastes are placed for permanent disposal and that is not a land application unit, surface impoundment, injection well, or waste pile as those terms are defined under 40 CFR 257.2. Landfill gas means gas produced as a result of anaerobic decomposition of waste materials in the landfill. Landfill gas generally contains 40 to 60 percent methane on a dry basis, typically less than 1 percent non-methane organic chemicals, and the remainder being carbon dioxide. 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.74

Lubricants include all grades of lubricating oils, from spindle oil to cylinder oil to those used in greases. Petroleum lubricants may be produced from distillates or residues. Makeup chemicals means carbonate chemicals (e.g., sodium and calcium carbonates) that are added to the chemical recovery areas of chemical pulp mills to replace chemicals lost in the process. Manure composting means the biological oxidation of a solid waste including manure usually with bedding or another organic carbon source typically at thermophilic temperatures produced by microbial heat production. There are four types of composting employed for manure management: static, in vessel, intensive windrow and passive windrow. Static composting typically occurs in an enclosed channel, with forced aeration and continuous mixing. In vessel composting occurs in piles with forced aeration but no mixing. Intensive windrow composting occurs in windrows with regular turning for mixing and aeration. Passive windrow composting occurs in windrows with infrequent turning for mixing and aeration. Maximum rated heat input capacity means the hourly heat input to a unit (in mmBtu/hr), when it combusts the maximum amount of fuel per hour that it is capable of75
combusting on a steady state basis, as of the initial installation of the unit, as specified by the manufacturer. Maximum rated input capacity means the maximum charging rate of a municipal waste combustor unit expressed in tons per day of municipal solid waste combusted, calculated according to the procedures under 40 CFR 60.58b(j). Mcf means thousand cubic feet. Methane conversion factor means the extent to which the 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 landfill that remain aerobic. The methane correction factor can be considered the fraction of the total landfill waste volume that is ultimately disposed of in an anaerobic state. Managed landfills that have soil or other cover materials have a methane correction factor of 1. Methanol (CH 3 OH) 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 definition76
applies to the midgrade categories of Conventional-Summer,Conventional-Winter, Reformulated-Summer, and ReformulatedWinter. For midgrade categories of RBOB-Summer, RBOBWinter, CBOB-Summer, and CBOB-Winter, this definition refers to the expected octane rating of the finished gasoline after oxygenate has been added to the RBOB or
CBOB. Miscellaneous Products include all refined petroleum products not defined elsewhere. It includes, but is not limited to, naphtha-type jet fuel (Jet B and JP-4), petrolatum lube refining by-products (aromatic extracts and tars), absorption oils, ram-jet fuel, petroleum rocket fuels, synthetic natural gas feedstocks, waste feedstocks, and specialty oils. It excludes organic waste sludges, tank bottoms, spent catalysts, and sulfuric acid.
MMBtu means million British thermal units. Motor gasoline (finished) means a complex mixture of volatile hydrocarbons, with or without additives, suitably blended to be used in spark ignition engines. Motor gasoline includes conventional gasoline, reformulated gasoline, and all types of oxygenated gasoline. Gasoline also has seasonal variations in an effort to control ozone levels. This is achieved by lowering the Reid Vapor Pressure (RVP) of gasoline during the summer driving77
season. Depending on the region of the country the RVP is lowered to below 9.0 psi or 7.8 psi. The RVP may be further lowered by state regulations. Mscf means thousand standard cubic feet.
MTBE (methyl tertiary butyl ether, (CH 3 ) 3 COCH 3 ) is an ether as described in "Oxygenates." Municipal solid waste landfill or MSW landfill means an entire disposal facility in a contiguous geographical space where household waste is placed in or on land. An MSW landfill may also receive other types of RCRA Subtitle D wastes (40 CFR 257.2) such as commercial solid waste, nonhazardous sludge, conditionally exempt small quantity generator waste, and industrial solid waste. Portions of an MSW landfill may be separated by access roads, public roadways, or other public right-of-ways. An MSW landfill may be publicly or privately owned. Municipal solid waste or MSW means solid phase household, commercial/retail, and/or institutional waste, such as, but not limited to, yard waste and refuse.
N 2 O means nitrous oxide. Naphthas (< 401 °F) is a generic term applied to a petroleum fraction with an approximate boiling range between 122 °F and 400 °F. The naphtha fraction of crude Deleted: million78
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 its constituents include, but are not limited to, methane, heavier hydrocarbons and carbon dioxide. Natural gas may be field quality (which varies widely) or pipeline quality. For the purposes of this subpart, the definition of natural gas includes similarly constituted fuels such as field production gas, process gas, and fuel gas. 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 at lease separators and field facilities. 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.79

NIST means the United States National Institute of Standards and Technology. Nitric acid production line means a series of reactors and absorbers used to produce nitric acid. Nitrogen excreted is the nitrogen that is excreted by livestock in manure and urine. Non-crude feedstocks means any petroleum product or natural gas liquid that enters the refinery to be further refined or otherwise used on site , including supplemental fuel burned to provide heat or thermal energy
. Non-recovery coke oven battery means a group of ovens connected by common walls and operated as a unit, where coal undergoes destructive distillation under negative pressure to produce coke, and which is designed for the combustion of the coke oven gas from which by-products are not recovered. Oil-fired unit means a stationary combustion unit that derives more than 50 percent of its annual heat input from the combustion of fuel oil, and the remainder of its annual heat input from the combustion of natural gas or other gaseous fuels. Open-ended valve or Lines (OELs) means any valve, except pressure relief valves, having one side of the valve Deleted: as a feedstock80
seat in contact with process fluid and one side open to atmosphere, either directly or through open piping. Operating hours means the duration of time in which a process or process unit is utilized; this excludes shutdown, maintenance, and standby. Operational change means, for purposes of §98.3(b), a change in the type of feedstock or fuel used, a change in operating hours, or a change in process production rate. Operator means any person who operates or supervises a facility or supplier. Other Oils (> 401 °F) are oils with a boiling range equal to or greater than 401 °F that are generally intended for use as a petrochemical feedstock and are not defined elsewhere.
Owner means any person who has legal or equitable title to, has a leasehold interest in, or control of a facility or supplier, except a person whose legal or equitable title to or leasehold interest in the facility or supplier arises solely because the person is a limited partner in a partnership that has legal or equitable title to, has a leasehold interest in, or control of the facility or supplier shall not be considered an “owner” of the facility or supplier.81
Oxygenates means substances which, when added to gasoline, increase the oxygen content of the gasoline. Common oxygenates are ethanol, methyl tertiary butyl ether (MTBE), ethyl tertiary butyl ether (ETBE), tertiary amyl methyl ether (TAME), diisopropyl ether (DIPE), and methanol. Pasture/Range/Paddock means the manure from pasture and range grazing animals is allowed to lie as deposited, and is not managed. Pentanes Plus , or C5+, is a mixture of hydrocarbons that is a liquid at ambient temperature and pressure, and consists mostly of pentanes (five carbon chain) and higher carbon number hydrocarbons. Pentanes plus includes, but is not limited to, normal pentane, isopentane, hexanes-plus (natural gasoline), and plant condensate. Perfluorocarbons or PFCs means a class of greenhouse gases consisting on the molecular level of carbon and fluorine. Petrochemical means methanol, acrylonitrile, ethylene, ethylene oxide, ethylene dichloride, and any form of carbon black. Petrochemical Feedstocks means feedstocks derived from petroleum for the manufacture of chemicals, synthetic rubber, and a variety of plastics. This category is82 usually divided into naphthas less than 401 °F and other oils greater than 401 °F.
Petroleum means oil removed from the earth and the oil derived from tar sands and shale. Petroleum coke means a black solid residue, obtained mainly by cracking and carbonizing of petroleum derived feedstocks, vacuum bottoms, tar and pitches in processes such as delayed coking or fluid coking. It consists mainly of carbon (90 to 95 percent), has low ash content, and may be used as a feedstock in coke ovens. This product is also known as marketable coke or catalyst coke. Petroleum product means all refined and semi-refined products that are produced at a refinery by processing crude oil and other petroleum-based feedstocks, including petroleum products derived from co-processing biomass and petroleum feedstock together, but not including plastics or plastic products. Petroleum products may be combusted for energy use, or they may be used either for non-energy processes or as non-energy products. The definition of petroleum product for importers and exporters excludes

waxes. Pit storage below animal confinement (deep pits) means the collection and storage of manure typically below a slatted floor in an enclosed animal confinement facility.83
This usually occurs with little or no added water for periods less than one year. Portable means designed and capable of being carried or moved from one location to another. Indications of portability include but are not limited to wheels, skids, carrying handles, dolly, trailer, or platform. Equipment is not portable if any one of the following conditions exists: (1) The equipment is attached to a foundation. (2) The equipment or a replacement resides at the same location for more than 12 consecutive months. (3) The equipment is located at a seasonal facility and operates during the full annual operating period of the seasonal facility, remains at the facility for at least two years, and operates at that facility for at least three months each year. (4) The equipment is moved from one location to another in an attempt to circumvent the portable residence time requirements of this definition. Poultry manure with litter means a manure management system component that is similar to cattle and swine deep bedding except usually not combined with a dry lot or pasture. The system is typically used for poultry breeder flocks and for the production of meat type chickens (broiler) and other fowl.84
Poultry manure without litter means a manure management system component that may manage manure in a liquid form, similar to open pits in enclosed animal confinement facilities. These systems may alternatively be designed and operated to dry manure as it accumulates. The latter is known as a high-rise manure management system and is a form of passive windrow manure composting when designed and operated properly. Precision of a measurement at a specified level(e.g., one percent of full scale or one percent of the value measured) means that 95 percent of repeat measurements made by a device or technique are within the range bounded by the mean of the measurements plus or minus the specified level. Premium grade gasoline is gasoline having an antiknock index, i.e., octane rating, greater than 90. This definition applies to the premium grade categories ofConventional-Summer, Conventional-Winter, ReformulatedSummer, and Reformulated-Winter. For premium grade categories of RBOB-Summer, RBOB-Winter, CBOB-Summer, and CBOB-Winter, this definition refers to the expected octane rating of the finished gasoline after oxygenate has been added to the RBOB or CBOB.85
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 commonpressure relief device is but not limited to a springloaded 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. 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 and86
to manufacture either a final product or an intermediate used in the onsite production of other products. The process unit also includes the purification of recovered byproducts.
Process vent means means a gas stream that: (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, 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 3 H 8 . Propylene is an olefinic hydrocarbon with molecular formula C 3 H 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.87
Pushing means the process of removing the coke from the coke oven at the end of the coking cycle. Pushing begins when coke first begins to fall from the oven into the quench car and ends when the quench car enters the quench tower. Raw mill means a ball and tube mill, vertical roller mill or other size reduction equipment, that is not part of an in-line kiln/raw mill, used to grind feed to the appropriate size. Moisture may be added or removed from the feed during the grinding operation. If the raw mill is used to remove moisture from feed materials, it is also, by definition, a raw material dryer. The raw mill also includes the air separator associated with the raw mill.
RBOB-Summer (reformulated blendstock for oxygenate blending) means a petroleum product which, when blended with a specified type and percentage of oxygenate, meets the definition of Reformulated-Summer. RBOB-Winter (reformulated blendstock for oxygenate blending) means a petroleum product which, when blended with a specified type and percentage of oxygenate, meets the definition of Reformulated-Winter. Reformulated—Summer refers to finished gasoline formulated for use in motor vehicles, the composition and properties of which meet the requirements of the88
reformulated gasoline regulations promulgated by the U.S. Environmental Protection Agency under 40 CFR 80.40 and 40 CFR 80.41, and summer RVP standards required under 40 CFR 80.27 or as specified by the state. Reformulated gasoline excludes Reformulated Blendstock for Oxygenate Blending (RBOB) as well as other blendstock. Reformulated—Winter refers to finished gasoline formulated for use in motor vehicles, the composition and properties of which meet the requirements of the reformulated gasoline regulations promulgated by the U.S. Environmental Protection Agency under 40 CFR 80.40 and 40 CFR 80.41, but which do not meet summer RVP standards required under 40 CFR 80.27 or as specified by the state. Note: This category includes Oxygenated Fuels Program Reformulated Gasoline (OPRG). Reformulated gasoline excludes Reformulated Blendstock for Oxygenate Blending (RBOB) as well as other blendstock. Regular grade gasoline is gasoline having an antiknock index, i.e., octane rating, greater than or equal to 85 and less than 88. This definition applies to the regular grade categories of Conventional-Summer,Conventional-Winter, Reformulated-Summer, and ReformulatedWinter. For regular grade categories of RBOB-Summer, RBOBWinter, CBOB-Summer, and CBOB-Winter, this definition89
refers to the expected octane rating of the finished gasoline after oxygenate has been added to the RBOB or
CBOB. Rendered animal fat , or tallow, means fats extracted from animals which are generally used as a feedstock in making biodiesel. Research and development means those activities conducted in process units or at laboratory bench-scale settings whose purpose is to conduct research and development for new processes, technologies, or products and whose purpose is not for the manufacture of products for commercial sale, except in a de minimis manner. Residual Fuel Oil No. 5 (Navy Special) is a classification for the heavier fuel oil generally used in steam powered vessels in government service and inshore power plants. It has a minimum flash point of 131 °F. Residual Fuel Oil No. 6 (a.k.a. Bunker C) is a classification for the heavier fuel oil generally used for the production of electric power, space heating, vessel bunkering and various industrial purposes. It has a minimum flash point of 140 °F. Residuum is residue from crude oil after distilling off all but the heaviest components, with a boiling range greater than 1,000 °F.90

Road Oil is any heavy petroleum oil, including residual asphaltic oil used as a dust palliative and surface treatment on roads and highways. It is generally produced in six grades, from 0, the most liquid, to 5, the most viscous. Rotary lime kiln means a unit with an inclined rotating drum that is used to produce a lime product from limestone by calcination. Safety device means a closure device such as a pressure relief valve, frangible disc, fusible plug, or any other type of device which functions exclusively to prevent physical damage or permanent deformation to a unit or its air emission control equipment by venting gases or vapors directly to the atmosphere during unsafe conditions resulting from an unplanned, accidental, or emergency event. A safety device is not used for routine venting of gases or vapors from the vapor headspace underneath a cover such as during filling of the unit or to adjust the pressure in response to normal daily diurnal ambient temperature fluctuations. A safety device is designed to remain in a closed position during normal operations and open only when the internal pressure, or another relevant parameter, exceeds the device threshold setting applicable to the air emission control equipment as determined by the91
owner or operator based on manufacturer recommendations, applicable regulations, fire protection and prevention codes and practices, or other requirements for the safe handling of flammable, combustible, explosive, reactive, or hazardous materials. Semi-refined petroleum product means all oils requiring further processing. Included in this category are unfinished oils which are produced by the partial refining of crude oil and include the following: naphthas and lighter oils; kerosene and light gas oils; heavy gas oils; and residuum, and all products that require further processing or the addition of blendstocks. Sendout means, in the context of a local distribution company, the total deliveries of natural gas to customers over a specified time interval (typically hour, day, month, or year). Sendout is the sum of gas received through the city gate, gas withdrawn from on-system storage or peak shaving plants, and gas produced and delivered into the distribution system; and is net of any natural gas injected into on-system storage. It comprises gas sales, exchange, deliveries, gas used by company, and unaccounted for gas.Sendout is measured at the city gate station, and other onsystem receipt points from storage, peak shaving, and production.92

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 operation of an emission source for any purpose. Silicon carbide means an artificial abrasive produced from silica sand or quartz and petroleum coke. Sinter process means a process that produces a fused aggregate of fine iron-bearing materials suited for use in a blast furnace. The sinter machine is composed of a continuous traveling grate that conveys a bed of ore fines and other finely divided iron-bearing material and fuel (typically coke breeze), a burner at the feed end of the grate for ignition, and a series of downdraft windboxes along the length of the strand to support downdraft combustion and heat sufficient to produce a fused sinter product. Site means any combination of one or more graded pad sites, gravel pad sites, foundations, platforms, or the immediate physical location upon which equipment is physically located.93
Smelting furnace means a furnace in which lead-bearing materials, carbon-containing reducing agents, and fluxes are melted together to form a molten mass of material containing lead and slag. Solid storage is the storage of manure, typically for a period of several months, in unconfined piles or stacks. Manure is able to be stacked due to the presence of a sufficient amount of bedding material or loss of moisture by evaporation. Sour gas means any gas that contains significant concentrations of hydrogen sulfide. Sour gas may include untreated fuel gas, amine stripper off-gas, or sour water stripper gas. 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 be94
used as petrochemical and synthetic natural gas (SNG) feedstocks are excluded. Spent liquor solids means the dry weight of the solids in the spent pulping liquor that enters the chemical recovery furnace or chemical recovery combustion unit. Spent pulping liquor means the residual liquid collected from on-site pulping operations at chemical pulp facilities that is subsequently fired in chemical recovery furnaces at kraft and soda pulp facilities or chemical recovery combustion units at sulfite or semi-chemical pulp facilities. Standard conditions or standard temperature and pressure (STP) 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.95
Storage tank means a vessel (excluding sumps) that is designed to contain an accumulation of crude oil, condensate, intermediate hydrocarbon liquids, or produced water and that is constructed entirely of non-earthen materials (e.g., wood, concrete, steel, plastic) that provide structural support. Sulfur recovery plant means all process units which recover sulfur or produce sulfuric acid from hydrogen sulfide (H 2 S) and/or sulfur dioxide (SO 2 ) from a common source of sour gas at a petroleum refinery. The sulfur recovery plant also includes sulfur pits used to store the recovered sulfur product, but it does not include secondary sulfur storage vessels or loading facilities downstream of the sulfur pits. For example, a Claus sulfur recovery plant includes: reactor furnace and waste heat boiler, catalytic reactors, sulfur pits, and, if present, oxidation or reduction control systems, or incinerator, thermal oxidizer, or similar combustion device. Multiple sulfur recovery units are a single sulfur recovery plant only when the units share the same source of sour gas. Sulfur recovery units that receive source gas from completely segregated sour gas treatment systems are separate sulfur recovery plants.96
Supplemental fuel means a fuel burned within a petrochemical process that is not produced within the process itself. Supplier means a producer, importer, or exporter of a fossil fuel or an industrial greenhouse gas. Taconite iron ore processing means an industrial process that separates and concentrates iron ore from taconite, a low grade iron ore, and heats the taconite in an indurating furnace to produce taconite pellets that are used as the primary feed material for the production of iron in blast furnaces at integrated iron and steel plants.
TAME means tertiary amyl methyl ether, (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 fluorinated GHGs in the manufacturing of other chemicals for commercial purposes. Transformation does not include burning of nitrous oxide. Transshipment means the continuous shipment of nitrous oxide or a fluorinated GHG from a foreign state of origin through the United States or its territories to a second foreign state of final destination, as long as the shipment97
does not enter into United States jurisdiction. A transshipment, as it moves through the United States or its territories, cannot be re-packaged, sorted or otherwise changed in condition.
Trona means the raw material (mineral) used to manufacture soda ash; hydrated sodium bicarbonate carbonate (e.g.Na2CO 3 .NaHCO 3 .2H 2 O). Ultimate analysis means the determination of the percentages of carbon, hydrogen, nitrogen, sulfur, and chlorine and (by difference) oxygen in the gaseous products and ash after the complete combustion of a sample of an organic material. Unfinished oils are all oils requiring further processing, except those requiring only mechanical blending. United States means the 50 states, the District of Columbia, 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 transport to the refinery without intermediate storage in a storage tank at atmospheric pressures. Unstabilized crude oil is characterized by having a true vapor pressure of 5 pounds per square inch absolute (psia) or greater.98

Valve means any device for halting or regulating the flow of a liquid or gas through a passage, pipeline, inlet, outlet, or orifice; including, but not limited to, gate, globe, plug, ball, butterfly and needle valves. Vegetable Oil means oils extracted from vegetation that are generally used as a feedstock in making biodiesel. Volatile solids are the organic material in livestockmanure and consist of both biodegradable and nonbiodegradable fractions. Waelz kiln means an inclined rotary kiln in which zinc–containing materials are charged together with a carbon reducing agent (e.g., petroleum coke, metallurgical coke, or anthracite coal).
Waxes means a solid or semi-solid material at 77 °F consisting of a mixture of hydrocarbons obtained or derived from petroleum fractions, or through a Fischer-Tropsch type process, in which the straight chained paraffin series predominates. This includes all marketable wax, whether crude or refined, with a congealing point between 80 (or 85) and 240 °F and a maximum oil content of 50 weight percent. Wool fiberglass means fibrous glass of random texture, including fiberglass insulation, and other products listed in NAICS 327993.99

You means an owner or operator subject to Part 98. Zinc smelters means a facility engaged in the production of zinc metal, zinc oxide, or zinc alloy products from zinc sulfide ore concentrates, zinc calcine, or zinc-bearing scrap and recycled materials through the use of pyrometallurgical techniques involving the reduction and volatization of zinc-bearing feed materials charged to a furnace. §98.7 What standardized methods are incorporated by reference into this part? The materials listed in this section are incorporated by reference in the corresponding sections noted. These incorporations by reference were approved by the Director of Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. These materials are incorporated as they exist on the date of approval, and a notice of any change in the materials will be published in the Federal Register
. The materials are available for purchase at the corresponding address in this section. The materials are available for inspection at the EPA Docket Center, Public Reading Room, EPA West Building, Room 3334, 1301 Constitution Avenue, NW, Washington, DC, phone (202) 566- 1744 and at the National Archives and Records Administration (NARA). For information on the availability100
of this material at NARA, call 202-741-6030, or go to: http://www.archives.gov/federal_register/code_of_federal_re gulations/ibr_ locations.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) Association of Fertilizer and Phosphate Chemists Analytical Methods Manual 10th Edition, incorporation by reference (IBR) approved for §98.264(a) and §98.264(b). (2) [Reserved] (b) The following material is available for purchase from the American Gas Association (AGA), 400 North Capitol Street, N.W., 4 th Floor, Washington, DC 20001, (202) 824- 7000, http://www.aga.org. (1) AGA Report No. 3 Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids Part 1: General Equations & Uncertainty Guidelines (1990), incorporation by reference (IBR) approved for §98.34(b) and §98.244(b). (2) AGA Report No. 3 Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids Part 2: Specification and Installation Requirements (2000), IBR approved for §98.34(b) and §98.244(b). Deleted: Phosphate Mining States Methods Used and Adopted by the Association of Fertilizer and Phosphate Chemists AFPC Manual 10th Edition 2009 - Version 1.9,101
(3) AGA Report No. 11 Measurement of Natural Gas by Coriolis Meter (2003), IBR approved for §98.244(b) and §98.254(c). (4) AGA Transmission Measurement Committee Report No. 7 Measurement of Natural Gas by Turbine Meter (2006)/February, IBR approved for §98.34(b) and §98.244(b). (c) The following material is available for purchase from the ASM International, 9639 Kinsman Road, Materials Park, OH 44073, (440) 338-5151, http://www.asminternational.org. (1) ASM CS-104 UNS No. G10460 - Alloy Digest April 1985 (Carbon Steel of Medium Carbon Content), incorporation by reference (IBR) approved for §98.174(b). (2) [Reserved] (d) The following material is available for purchase from the American Society of Mechanical Engineers (ASME), Three Park Avenue, New York, NY 10016-5990, (800) 843-2763, http://www.asme.org. (1) ASME MFC-3M–2004 Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and Venturi, incorporation by reference (IBR) approved for §98.34(b), §98.244(b), §98.254(c), §98.344(c), and §98.364(e).102
(2) ASME MFC-4M–1986 (Reaffirmed 1997) Measurement of Gas Flow by Turbine Meters, IBR approved for §98.34(b), §98.244(b), §98.254(c), §98.344(c), and §98.364(e). (3) ASME MFC-5M–1985 (Reaffirmed 1994) Measurement of Liquid Flow in Closed Conduits Using Transit-Time Ultrasonic Flowmeters, IBR approved for §98.34(b) and §98.244(b). (4) ASME MFC-6M–1998 Measurement of Fluid Flow in Pipes Using Vortex Flowmeters, IBR approved for §98.34(b), §98.244(b), §98.254(c), §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 §98.34(b), §98.244(b), §98.254(c), §98.344(c), and §98.364(e). (6) ASME MFC-9M–1988 (Reaffirmed 2001) Measurement of Liquid Flow in Closed Conduits by Weighing Method, IBR approved for §98.34(b) and §98.244(b). (7) ASME MFC-11M-2006 Measurement of Fluid Flow by Means of Coriolis Mass Flowmeters, IBR approved for §98.244(b), §98.254(c), and §98.344(c). (8) ASME MFC-14M-2003 Measurement of Fluid Flow Using Small Bore Precision Orifice Meters, IBR approved for §98.244(b), §98.254(c), §98.344(c), and §98.364(e).103
(9) ASME MFC-16-2007 Measurement of Liquid Flow in Closed Conduits with Electromagnetic Flowmeters, IBR approved for §98.244(b). (10) ASME MFC-18M-2001 Measurement of Fluid Flow Using Variable Area Meters, IBR approved for §98.244(b), §98.254(c),§98.344(c), and §98.364(e). (11) ASME MFC-22-2007 Measurement of Liquid by Turbine Flowmeters, IBR approved for §98.244(b). (e) The following material is available for purchase from the American Society for Testing and Material (ASTM), 100 Barr Harbor Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959, (800) 262-1373, http://www.astm.org. (1) ASTM C25-06 Standard Test Method for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime, incorporation by reference (IBR) approved for §98.114(b), §98.174(b), §98.184(b), §98.194(c), and §98.334(b). (2) ASTM C114-09 Standard Test Methods for Chemical Analysis of Hydraulic Cement, IBR approved for §98.84(a), §98.84(b), and §98.84(c). (3) ASTM D235-02 (Reapproved 2007) Standard Specification for Mineral Spirits (Petroleum Spirits) (Hydrocarbon Dry Cleaning Solvent), IBR approved for §98.6.104
(4) ASTM D240-02 (Reapproved 2007) Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter, IBR approved for §98.34(a) and §98.254(e). (5) ASTM D388-05 Standard Classification of Coals by Rank, IBR approved for §98.6. (6) ASTM D910-07a Standard Specification for Aviation Gasolines, IBR approved for §98.6. (7) ASTM D1298-99 (Reapproved 2005) Standard Test Method for Density, Relative Density (Specific Gravity), or API Gravity of Crude Petroleum and Liquid Petroleum Products by Hydrometer Method, IBR approved for §98.33(a). (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 §98.34(a) and §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 §98.34(b), §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 Gas105
Chromatography, IBR approved for §98.34(b), §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 §98.34(b) and §98.74(c). (15) ASTM D2503-92 (Reapproved 2007) Standard Test Method for Relative Molecular Mass (Molecular Weight) of Hydrocarbons by Thermoelectric Measurement of Vapor Pressure, IBR approved for §98.34(b) and §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).106
(18) ASTM D3176-89 (Reapproved 2002) Standard Practice for Ultimate Analysis of Coal and Coke, IBR approved for §98.74(c), §98.164(b), §98.244(b), §98.254(i), §98.284(c), §98.284(d), §98.314(c), §98.314(d), and §98.314(f). (19) ASTM D3238-95 (Reapproved 2005) Standard Test Method for Calculation of Carbon Distribution and Structural Group Analysis of Petroleum Oils by the n-d-M Method, IBR approved for §98.34(b), §98.74(c), and §98.164(b). (20) ASTM D3588-98 (Reapproved 2003) Standard Practice for Calculating Heat Value, Compressibility Factor, and Relative Density of Gaseous Fuels, IBR approved for §98.34(a) and §98.254(e). (21) ASTM D3682-01 (Reapproved 2006) Standard Test Method for Major and Minor Elements in Combustion Residues from Coal Utilization Processes, IBR approved for §98.144(b). (22) ASTM D4057-06 Standard Practice for Manual Sampling of Petroleum and Petroleum Products, IBR approved for §98.164(b). (23) ASTM D4177-95 (Reapproved 2005) Standard Practice for Automatic Sampling of Petroleum and Petroleum Products, IBR approved for §98.164(b).107
(24) ASTM D4809-06 Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method), IBR approved for §98.34(a) and §98.254(e). (25) ASTM D4891-89 (Reapproved 2006), Standard Test Method for Heating Value of Gases in Natural Gas Range by Stoichiometric Combustion, IBR approved for §98.34(a) and §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 §98.34(b), §98.74(c), §98.164(b), §98.244(b), §98.254(i). (27) ASTM D5373-08 Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal, IBR approved for §98.34(b), §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) ASTM D5865-07a Standard Test Method for Gross Calorific Value of Coal and Coke, IBR approved for §98.34(a).108
(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) and §98.224(b). (31) ASTM D6609-08 Standard Guide for Part-Stream Sampling of Coal, IBR approved for §98.164(b). (32) ASTM D6751-08 Standard Specification for Biodiesel Fuel Blend Stock (B100) for Middle Distillate Fuels, IBR approved for §98.6. (33) ASTM D6866-08 Standard Test Methods for Determining the Biobased Content of Solid, Liquid, and Gaseous Samples Using Radiocarbon Analysis, IBR approved for §98.33(e), §98.34(d), §98.34(e), and §98.36(e). (34) ASTM D6883-04 Standard Practice for Manual Sampling of Stationary Coal from Railroad Cars, Barges, Trucks, or Stockpiles, IBR approved for §98.164(b). (35) ASTM D7430-08ae1 Standard Practice for Mechanical Sampling of Coal, IBR approved for §98.164(b). (36) ASTM D7459-08 Standard Practice for Collection of Integrated Samples for the Speciation of Biomass (Biogenic) and Fossil-Derived Carbon Dioxide Emitted from109
Stationary Emissions Sources, IBR approved for §98.33(e), §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 by Combustion Infrared-Absorption Spectrometry, IBR approved for §98.174(b). (41) ASTM E1941-04 Standard Test Method for Determination of Carbon in Refractory and Reactive Metals and Their Alloys, IBR approved for §98.114(b), §98.184(b), §98.334(b). (42) ASTM UOP539-97 Refinery Gas Analysis by Gas Chromatography, IBR approved for §98.164(b), §98.244(b), and §98.254(d), and §98.344(b).110
(43) ASTM D6349-09 Standard Test Method for Determination of Major and Minor Elements in Coal, Coke, and Solid Residues from Combustion of Coal and Coke by Inductively Coupled Plasma—Atomic Emission Spectrometry. (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) GPA 2172-09 Calculation of Gross Heating Value, Relative Density, Compressibility and Theoretical Hydrocarbon Liquid Content for Natural Gas Mixtures for Custody Transfer, IBR approved for §98.34(a). (2) GPA 2261-00 Analysis for Natural Gas and Similar Gaseous Mixtures by Gas Chromatography, IBR approved for §98.34(a), §98.164(b), §98.254(d), and §98.344(b). (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).111
(2) ISO 3171: Petroleum Liquids—Automatic pipeline sampling - Second Edition 1988-12-01, IBR approved for §98.164(b). (3) ISO 8316: Measurement of Liquid Flow in Closed Conduits— Method by Collection of the Liquid in a Volumetric Tank (1987-10-01) - First Edition, IBR approved for §98.244(b). (4) ISO/TR 15349-1: 1998, Unalloyed steel— Determination of low carbon content. Part 1: Infrared absorption method after combustion in an electric resistance furnace (by peak separation) (1998-10-15) - First Edition, IBR approved for §98.174(b). (5) ISO/TR 15349-3: 1998, Unalloyed steel— Determination of low carbon content. Part 3: Infrared absorption method after combustion in an electric resistance furnace (with preheating) (1998-10-15) - First Edition, IBR approved for §98.174(b). (h) The following material is available for purchase from the National Lime Association (NLA), 200 North Glebe Road, Suite 800, Arlington, Virginia 22203, (703) 243-5463, http://www.lime.org. (1) CO 2 Emissions Calculation Protocol for the Lime Industry—English Units Version, February 5, 2008 Revision—112
National Lime Association, incorporation by reference (IBR) approved for §98.194(c) and §98.194(e). (2) [Reserved] (i) The following material is available for purchase from the National Institute of Standards and Technology (NIST), 100 Bureau Drive, Stop 1070, Gaithersburg, MD 20899-1070, (800) 877-8339, http://www.nist.gov/index.html. (1) Specifications, Tolerances, and Other Technical Requirements For Weighing and Measuring Devices, NIST Handbook 44 (2009), incorporation by reference (IBR) approved for §98.244(b), §98.254(h), and §98.344(a). (2) [Reserved] (j) The following material is available for purchase from the Technical Association of the Pulp and Paper Industry (TAPPI), 15 Technology Parkway South, Norcross, GA 30092, (800) 332-8686, http://www.tappi.org. (1) T650 om-05 Solids Content of Black Liquor, TAPPI, incorporation by reference (IBR) approved for §98.276(c) and §98.277(d). (2) T684 om-06 Gross Heating Value of Black Liquor, TAPPI, incorporation by reference (IBR) approved for §98.274(b). §98.8 What are the compliance and enforcement provisions of this part?113
Any violation of any requirement of this part shall be a violation of the Clean Air Act, including section 114 (42 U.S.C. §7414). A violation includes but is not limited to failure to report GHG emissions, failure to collect data needed to calculate GHG emissions, failure to continuously monitor and test as required, failure to retain records needed to verify the amount of GHG emissions, and failure to calculate GHG emissions following the methodologies specified in this part. Each day of a violation constitutes a separate violation. §98.9 Addresses. All requests, notifications, and communications to the Administrator pursuant to this part, other than submittal of the annual GHG report, shall be submitted to the following address: (a) For U.S. mail. Director, Climate Change Division, 1200 Pennsylvania Ave., NW., Mail Code: 6207J, Washington, DC 20460. (b) For package deliveries. Director, Climate Change Division, 1310 L St, NW., Washington, DC 20005. **Table A-1 of Subpart A—Global Warming Potentials (100-Year Time Horizon)** 

**Name CAS # Chemical formula**  **Global warming**  **potential (100 yr.)**  Carbon dioxide 124-38-9 CO 2 1114
**Table A-1 of Subpart A—Global Warming Potentials (100-Year Time Horizon)** 

**Name CAS # Chemical formula**  **Global warming**  **potential (100 yr.)**  Methane 74-82-8 CH 4 21 Nitrous oxide 10024-97-2 N 2 O 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-125 354-33-6 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 3 CHF 2 140 HFC-161 353-36-6 CH 3 CH 2 F 12 HFC-227ea 431-89-0 C 3 HF 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 3 H 2 F 6 6,300 HFC-245ca 679-86-7 C 3 H 3 F 5 560 HFC-245fa 460-73-1 CHF 2 CH 2 CF 3 1,030 HFC-365mfc 406-58-6 CH 3 CF 2 CH 2 CF 3 794 HFC-43-10mee 138495-42-8 CF 3 CFHCFHCF 2 CF 3 1,300 Sulfur hexafluoride 2551-62-4 SF 6 23,900 Trifluoromethyl sulphur pentafluoride 373-80-8 SF 5 CF 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 1,870115
**Table A-1 of Subpart A—Global Warming Potentials (100-Year Time Horizon)** 

**Name CAS # Chemical formula**  **Global warming**  **potential (100 yr.)**  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 3 OCF 3 756 HFE-227ea 2356-62-9 CF 3 CHFOCF 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 3 CH 2 OCF 3 487 HFE-245cb2 22410-44-2 CH 3 OCF 2 CF 3 708 HFE-245fa1 84011-15-4 CHF 2 CH 2 OCF 3 286 HFE-245fa2 1885-48-9 CHF 2 OCH 2 CF 3 659 HFE-254cb2 425-88-7 CH 3 OCF 2 CHF 2 359 HFE-263fb2 460-43-5 CF 3 CH 2 OCH 3 11 HFE-329mcc2 67490-36-2 CF 3 CF 2 OCF 2 CHF 2 919 HFE-338mcf2 156053-88-2 CF 3 CF 2 OCH 2 CF 3 552 HFE-338pcc13 (HG-01) 188690-78-0 CHF 2 OCF 2 CF 2 OCHF 2 1,500 HFE-347mcc3 28523-86-6 CH 3 OCF 2 CF 2 CF 3 575 HFE-347mcf2 E1730135 CF 3 CF 2 OCH 2 CHF 2 374 HFE-347pcf2 406-78-0 CHF 2 CF 2 OCH 2 CF 3 580 HFE-356mec3 382-34-3 CH 3 OCF 2 CHFCF 3 101 HFE-356pcc3 160620-20-2 CH 3 OCF 2 CF 2 CHF 2 110 HFE-356pcf2 E1730137 CHF 2 CH 2 OCF 2 CHF 2 265 HFE-356pcf3 35042-99-0 CHF 2 OCH 2 CF 2 CHF 2 502 HFE-365mcf3 378-16-5 CF 3 CF 2 CH 2 OCH 3 11 HFE-374pc2 512-51-6 CH 3 CH 2 OCF 2 CHF 2 557 HFE-449sl (HFE-7100) Chemical blend 163702-07-6 163702-08-7 C 4 F 9 OCH 3 (CF 3 ) 2 CFCF 2 OCH 3 297 HFE-569sf2 (HFE-7200) Chemical blend 163702-05-4 163702-06-5 C 4 F 9 OC 2 H 5 (CF 3 ) 2 CFCF 2 OC 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(Octafluorotetramethylene)hydroxymethyl group NA X-(CF 2 ) 4 CH(OH)-X 73 HFE-347mmy1 22052-84-2 CH 3 OCF(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 3 CF 2 CH 2 OH 42

PFPMIE NA CF 3 OCF(CF 3 )CF 2 OCF 2 OC F 3 10,300 NA = not available **Table A-2 of Subpart A—Units of Measure Conversions.**116

**To convert from To Multiply by**  Kilograms (kg) Pounds (lbs) 2.20462 Pounds (lbs) Kilograms (kg) 0.45359 Pounds (lbs) Metric tons 4.53592 x 10 -4 Short tons Pounds (lbs) 2,000 Short tons Metric tons 0.90718 Metric tons Short tons 1.10231 Metric tons Kilograms (kg) 1,000 Cubic meters (m 3 ) Cubic feet (ft 3 ) 35.31467 Cubic feet (ft 3 ) Cubic meters (m 3 ) 0.028317 Gallons (liquid, US) Liters (l) 3.78541 Liters (l) Gallons (liquid, US) 0.26417 Barrels of Liquid Fuel (bbl) Cubic meters (m 3 ) 0.15891 Cubic meters (m 3 ) Barrels of Liquid Fuel (bbl) 6.289 Barrels of Liquid Fuel (bbl) Gallons (liquid, US) 42 Gallons (liquid, US) Barrels of Liquid Fuel (bbl) 0.023810 Gallons (liquid, US) Cubic meters (m 3 ) 0.0037854 Liters (l) Cubic meters (m 3 ) 0.001 Feet (ft) Meters (m) 0.3048 Meters (m) Feet (ft) 3.28084 Miles (mi) Kilometers (km) 1.60934 Kilometers (km) Miles (mi) 0.62137 Square feet (ft 2 ) Acres 2.29568 x 10 -5 Square meters (m 2 ) Acres 2.47105 x 10 -4 Square miles (mi 2 ) Square kilometers (km 2 ) 2.58999 Degrees Celsius (oC) Degrees Fahrenheit (oF) oC = (5/9) x ( oF32) 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 E—Adipic Acid Production** §98.50 Definition of Source Category.117
The adipic acid production source category consists of all adipic acid production facilities that use oxidation to produce adipic acid. §98.51 Reporting threshold. You must report GHG emissions under this subpart if your facility contains an adipic acid production process and the facility meets the requirements of either §98.2(a)(1) or (2). §98.52 GHGs to report. (a) You must report N 2 O process emissions at the facility level. (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 following the requirements of subpart C. §98.53 Calculating GHG emissions. (a) You must determine annual N 2 O emissions from adipic acid production 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.118
(2) Request 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 for the current reporting period using the procedures specified in paragraphs (b) through (h) of this section. (b) You must conduct an annual performance test according to paragraphs (b)(1) through (b)(3) of this section. (1) You must conduct the test on the waste gas stream from the nitric acid oxidation step of the process , referred to as the test point, according to the methods specified in §98.54(b) through ( f ). (2) You must conduct the performance test under normal process operating conditions. (3) You must measure the adipic acid production rate during the test and calculate the production rate for the test period in metric tons per hour. Deleted: factor

Deleted: using

Deleted: d

Deleted: and without using N 2 O abatement technology119
(c) Using the results of the performance test in paragraph (b) of this section, you must calculate a n emission factor for each adipic acid unit according to Equation E-1 of this section:

n P Q C EF n ON

NON 

#  

 

1 7 2

,2 1014.1 (Eq. E-1) Where: EF N2O ,N = Average facility-specific N 2 O emission factor for each adipic acid production unit (lb N 2 O generated/ton adipic acid produced). C N2O = N 2 O concentration per test run during the performance test (ppm N 2 O). 1.14x10 -7 = Conversion factor (lb/dscf-ppm N 2 O). Q = Volumetric flow rate of effluent gas per test run during the performance test (dscf/hr). P = Production rate per test run during the performance test (tons adipic acid produced/hr). n = Number of test runs. (d) If any N 2 O abatement technology “N” is located after your test point, you must determine the destruction efficiency according to paragraphs (d)(1), (d)(2), or (d)(3) of this section. (1) Use the manufacturer’s specified destruction efficiency. (2) Estimate the destruction efficiency through process knowledge. Examples of information that could constitute process knowledge include calculations based on Deleted: You must determine an N2O emissions factor to use in Equation E-2 of this section according to paragraphs (c)(1) or (c)(2) of this section. ¶ (1) You may request Administrator approval for an alternative method of determining N2O concentration according to the procedures in paragraphs (a)(2)(i) and (a)(2)(ii) of this section. Alternative methods include the use of N2O CEMs.¶ (2) Deleted: facility-specific Deleted: s Comment [A1]: This equation was amended to revise the term EF N2O,N Deleted: s
Deleted: text

Deleted: applicable,

Deleted: for each N 2 O abatement technology used at your facility120
material balances, process stoichiometry, or previous test results provided the results are still relevant to the current vent stream conditions. You must document how process knowledge 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 any N 2 O abatement technology “N” is located after your test point , you must determine the annual amount of adipic acid produced while N 2 O abatement technology “N” is operating according to §98.54(f). Then you must calculate the abatement factor for N 2 O abatement technology
“N” according to Equation E-2 of this section.

a Na N P P AF ,  (Eq. E-2)

Where: AF N = Abatement utilization factor of N 2 O abatement technology “N” (fraction of annual production that abatement technology is operating). P a ,N = Annual adipic acid production during which N 2 O abatement technology “N” was used (ton adipic acid produced)
. P a = Total annual adipic acid production (ton acid produced). (f) You must determine the annual amount of adipic acid produced according to §98.54(f)
. Deleted: applicable

Deleted: g

Deleted: each

Deleted: used at your facility. The abatement factor is calculated for each adipic acid facility

Deleted: Abate

Deleted: and the annual adipic acid production during which N2O abatement is operating121
(g) You must calculate N 2 O emissions according to paragraph (g)(1) or (g)(2) of this section for each adipic acid production unit and sum the unit level emissions to determine the emissions for the facility. (1) If any N 2 O abatement technology “N” is located after your test point, you must use the emissions factor (determined in Equation E-1 of this section) , the destruction efficiency (determined in paragraph (d) of this section), the annual adipic acid production (determined in paragraph (f) of this section), and the abatement utilization factor (determined in paragraph (e) of this section) , according to Equation E-3 a of this section: 

##    N N N aNNN AFDF PEF ON 1 20

2 2205 )) (1( (Eq. E-3 a )

Where: N 2 O = Annual N 2 O mass emissions from adipic acid production (metric tons). EF N2O N = N 2 O emissions factor for unit(s) on which N 2 O abatement technology “N” is operating (lb N 2 O generated/ton adipic acid produced). P a N = Annual adipic acid produced by unit(s) for which N 2 O abatement technology “N” is operating (tons). DF N = Destruction efficiency of N 2 O abatement technology “ N ” (percent of N 2 O removed from air stream). AF N = Abatement utilization factor of N 2 O abatement technology “ N ” (fraction of annual production for which N 2 O abatement technology “N” is operating). Deleted: annual adipic acid production process emissions of

Deleted: by multiplying

Deleted: using

Deleted: by the total annual adipic acid production and accounting for N2O abatement

Deleted: Facility-specific

Deleted: abatement device destruction efficiency,

Deleted: that122
2205 = Conversion factor (lb/metric ton). N = Number of different N 2 O abatement technologies. (2) If no N 2 O abatement technologies are located after your test point, you must use the emissions factor (determined using Equation E-1 of this section) and the annual adipic acid production (determined in paragraph (f) of this section) according to Equation E-3b of this section for each adipic acid production unit.

2205

20 2 a N PEF ON   (Eq. E-3b) Where: N 2 O = Annual N 2 O mass emissions from adipic acid production (metric tons). EF N2O = N 2 O emissions factor (lb N 2 O generated/ton adipic acid produced). P a = Annual adipic acid produced (tons). 2205 = Conversion factor (lb/metric ton). (h) You must determine the amount of process N 2 O emissions that is sold or transferred off site (if applicable). You can determine the amount using existing process flow meters and N 2 O analyzers. §98.54 Monitoring and QA/QC requirements. (a) You must conduct a new performance test and calculate a new emissions factor for each adipic acid production unit according to the frequency specified in paragraphs (a)(1) through (a)(3) of this section. Deleted: ¶

Deleted: Facility-specific

Deleted: facility-specific123
(1) Conduct the performance test annually. The test must be conducted at a point during production that is representative of the average emissions from your process. You must document the methods used to determine the representative point. (2) Conduct the performance test when your adipic acid production process is changed either by altering the ratio of cyclohexanone to cyclohexanol or by installing abatement equipment. (3) If you requested Administrator approval for an alternative method of determining N 2 O emissions under §98.53(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, Measurement of Vapor Phase Organic and Inorganic Emissions by Extractive Fourier Transform Infrared (FTIR) Spectroscopy in 40 CFR part 63, Appendix A; (2) ASTM D6348-03 Standard Test Method for Determination of Gaseous Compounds by Extractive Direct Deleted: concentration124
Interface Fourier Transform Infrared (FTIR) Spectroscopy (incorporated by reference, see §98.7); or (3) An equivalent method, with Administrator approval. (c) You must determine the adipic acid production rate during the performance test according to paragraph (c)(1) or (c)(2) of this section. (1) Direct measurement (such as using flow meters or weigh scales). (2) Existing plant procedures used for accounting
purposes. (d) You must determine the volumetric flow rate during the performance test 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 specifications apply. For each test, the facility must prepare an emissions 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. Deleted: (s)

Deleted: conduct all required performance tests according to the methods in §98.54(b)125
(3) The production rate(s) during the performance test and how each production rate was determined. (e) You must determine the monthly amount of adipic acid produc ed and the monthly amount of adipic acid produc ed during which N2O abatementtechnology , located after the test point, is operating according to the methods in paragraphs (c)(1) or (c)(2) of this section. (f) You must determine the annual amount of adipic acid produc ed and the annual amount of adipic produc ed during which N 2 O abatement technology located after the test point is operating by summing the respective monthly adipic acid production quantities determined in paragraph (e) of this section
. §98.55 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 missing parameter shall be used in the calculations as specified in paragraphs (a) and (b) of this section. (a) For each missing value of monthly adipic acid 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). Deleted: tion quantity

Deleted: tion Deleted:

Deleted: tion quantity Deleted: tion quantity126
(b) For missing values related to the performance test, including emission factors, production rate, and N2O concentration, you must conduct a new performance test according to the procedures in §98.54 (a) through (d). §98.56 Data reporting requirements. In addition to the information required by §98.3(c), each annual report must contain the information specified in paragraphs (a) through (k) of this section at the facility level: (a) Annual process N 2 O emissions from adipic acid production (metric tons). (b) Annual adipic acid production (tons). (c) Annual adipic acid production during which N 2 O abatement technology (located after the test point) is operating (tons). (d) Annual process N 2 O emissions from adipic acid production facility that is sold or transferred off site (metric tons). (e) Number of abatement technologies (if applicable). (f) Types of abatement technologies used (if applicable). (g) Abatement technology destruction efficiency for each abatement technology (percent destruction).127
(h) Abatement utilization factor for each abatement technology (fraction of annual production that abatement technology is operating). (i) Number of times in the reporting year that missing data procedures were followed to measure adipic acid production (months). (j) If you conducted a performance test and calculated a site-specific emissions factor according to §98.53(a)(1), each annual report must also contain the information specified in paragraphs (j)(1) through (j)(7) of this section for each adipic acid production unit
. (1) Emission factor (lb N 2 O/ton adipic acid). (2) Test method used for performance test. (3) Production rate per test run during performance test (tons/hr). (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. (7) Number of times in the reporting year that a performance test had to be repeated (number). (k) If you requested Administrator approval for an alternative method of determining N 2 O emissions under Deleted: facility

Deleted: s

Deleted: concentration128
§98.53(a)(2), each annual report must also contain the information specified in paragraphs (k)(1) through (k)(4) of this section for each adipic acid production facility. (1) Name of alternative method. (2) Description of alternative method. (3) Request date. (4) Approval date. §98.57 Records that must be retained **.** In addition to the information required by §98.3(g), you must retain the records specified in paragraphs (a) through (h) of this section at the facility level: (a) Annual adipic acid production capacity (tons). (b) Records of significant changes to process. (c) Number of facility and unit operating hours in calendar year. (d) Documentation of how accounting procedures were used to estimate production rate. (e) Documentation of how process knowledge was used to estimate abatement technology destruction efficiency. (f) Performance test reports. (g) Measurements, records and calculations used to determine reported parameters. (h) Documentation of the procedures used to ensure the accuracy of the measurements of all reported Deleted: of N 2 O emissions129
parameters, including but not limited to, calibration 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. §98.58 Definitions. All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. **Subpart H—Cement Production** §98.80 Definition of the source category. The cement production source category consists of each kiln and each in-line kiln/raw mill at any portland cement manufacturing facility including alkali bypasses, and includes kilns and in-line kiln/raw mills that burn
hazardous waste. §98.81 Reporting threshold. You must report GHG emissions under this subpart if your facility contains a cement production process and the facility meets the requirements of either §98.2(a)(1) or (2). §98.82 GHGs to report. You must report: (a) CO 2 process emissions from calcination in each kiln.130

(b) CO 2 combustion emissions from each kiln. (c) CH 4 and N 2 O combustion emissions from each kiln. 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) CO 2 , CH 4 , and N 2 O emissions from each stationary combustion unit other than kilns. You must report these emissions under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C. §98.83 Calculating GHG emissions. You must calculate and report the annual process CO 2 emissions from each kiln using the procedure in paragraphs (a) and (b) of this section. (a) For each cement kiln that meets the conditions specified in §98.33(b)(4)(ii) or (b)(4)(iii), you must calculate and report under this subpart the combined process and combustion CO 2 emissions by operating and maintaining a CEMS to measure CO 2 emissions 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) For each kiln that is not subject to the requirements in paragraph (a) of this section, calculate131
and report the process and combustion CO 2 emissions from the kiln by using the procedure in either paragraph (c) or (d) of this section. (c) Calculate and report under this subpart the combined process and combustion CO 2 emissions by operating and maintaining a CEMS to measure CO 2 emissions 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). (d) Calculate and report process and combustion CO 2 emissions separately using the procedures specified in paragraphs (d)(1) through (d)(4) of this section. (1) Calculate CO 2 process emissions from all kilns at the facility using Equation H-1 of this section:



   k

m rm CO mCli CO CMF CO 1 2,2 2 (Eq. H-1)

Where: CO 2 CMF = Annual process emissions of CO 2 from cement manufacturing, metric tons. CO 2 Cli,m = Total annual emissions of CO 2 from clinker production from kiln m, metric tons. CO 2 rm = Total annual emissions of CO 2 from raw materials, metric tons. k = Total number of kilns at a cement manufacturing facility.132
(2) CO 2 emissions from clinker production . Calculate
CO 2 emissions from each kiln using Equations H-2 through H-5 of this section.

             

 

  r i iCKD EF i CKD p j jCli EF j Cli mCli CO 1 2205 2000 *)

, (*),( 1 2205 2000 *)

, (*),( ,2 (Eq. H-2)

Where: Cli, j = Quantity of clinker produced in month j from kiln m, tons. EF Cli,j = Kiln specific clinker emission factor for month j for kiln m, metric tons CO 2 /metric ton clinker computed as specified in Equation H-3 of this section. CKD, i = Cement kiln dust (CKD) not recycled to the kiln in quarter i from kiln m, tons. EF CKD,i = Kiln specific CKD emission factor for quarter i from kiln m, metric tons CO 2 /metric ton CKD computed as specified in Equation H-4 of this section. p = Number of months for clinker calculation, 12.
r = Number of quarters for CKD calculation, 4. 2000/2205 = Conversion factor to convert tons to metric tons. (i) Kiln-Specific Clinker Emission Factor . Calculatethe kiln-specific clinker emission factor using Equation H3 of this section.

MgO MR ncMgO Cli MgO Cli CaO MR ncCaO Cli CaO CLi EF *) ( *) ( Cli  

  (Eq. H-3) Where: Cli CaO = Monthly total CaO content of Clinker, wtfraction. Cli ncCaO = Monthly non-calcined CaO content of Clinker, wt-fraction. MR CaO = Molecular-weight Ratio of CO 2 /CaO = 0.785.133

Cli MgO = Monthly total MgO content of Clinker, wtfraction. Cli ncMgO = Monthly non-calcined MgO content of Clinker, wt-fraction. MR MgO = Molecular-weight Ratio of CO 2 /MgO = 1.092. Non-calcined CaO is CaO that remains in the clinker in the form of CaCO 3 and CaO in the clinker that entered the kiln as a non-carbonate species. Non-calcined MgO is MgO that remains in the clinker in the form of MgCO 3 and MgO in the clinker that entered the kiln as a non-carbonate species. (ii) Kiln-Specific CKD Emission Factor . Calculate the kiln-specific CKD emission factor for CKD not recycled to the kiln using Equation H-4 of this section.

MgO MR ncMgO CKD MgO CKD CaO MR ncCaO CKD CaO CKD EF *) ( *) ( CKD  

  (Eq. H-4) Where: CKD CaO = Quarterly total CaO content of CKD not recycled to the kiln, wt-fraction. CKD CaO = Quarterly non-calcined CaO content of CKD not recycled to the kiln, wt-fraction. MR CaO = Molecular-weight Ratio of CO2/CaO = 0.785. CKD MgO = Quarterly total MgO content of CKD not recycled to the kiln, wt-fraction. CKD MgO = Quarterly non-calcined MgO content of CKD not recycled to the kiln, wt-fraction. MR MgO = Molecular-weight Ratio of CO2/MgO = 1.092.
Non-calcined CaO is CaO that remains in the CKD in the form of CaCO 3 and CaO in the CKD that entered the kiln as a non-carbonate species. Non-calcined MgO is MgO that remains134
in the CKD in the form of MgCO 3 and MgO in the CKD that entered the kiln as a non-carbonate species. (3) CO 2 emissions from raw materials. Calculate CO 2 emissions from raw materials using Equation H-5 of this section:

2205 2000 12 44

, 1 2  

## 

 TOCrmrm CO m

i rm (Eq. H-5)
Where: rm = The amount of raw material i consumed annually, tons/yr (dry basis) or the amount of raw kiln feed consumed annually, tons/yr (dry basis)
. CO 2,rm = Annual CO 2 emissions from raw materials. TOCrm = Organic carbon content of raw material i or organic carbon content of combined raw kiln feed (dry basis), as determined in §98.84(c) or using a default factor of 0.2 percent of total raw material weight. M = Number of raw materials or 1 if calculating emissions based on combined raw kiln feed
. 44/12 = Ratio of molecular weights, CO 2 to carbon . 2000/2205 = Conversion factor to convert tons to metric tons. (4) Calculate and report under subpart C of this part (General Stationary Fuel Combustion Sources) the combustion
CO 2 emissions from the kiln according to the applicable requirements in subpart C. §98.84 Monitoring and QA/QC requirements. (a) You must determine the weight fraction of total CaO and total MgO in CKD not recycled to the kiln from each kiln using ASTM C114-09, Standard Test Methods for Chemical135
Analysis of Hydraulic Cement (incoporated by reference, see §98.7). The monitoring must be conducted quarterly for each kiln from a CKD sample drawn either as CKD is exiting the kiln or from bulk CKD storage. (b) You must determine the weight fraction of total CaO and total MgO in clinker from each kiln using ASTM C114- 09 Standard Test Methods for Chemical Analysis of Hydraulic Cement (incorporated by reference, see §98.7). The monitoring must be conducted monthly for each kiln from

a monthly clinker sample drawn from bulk clinker storage if storage is dedicated to the specific kiln, or from a monthly arithmetic average of daily clinker samples drawn from the clinker conveying systems exiting each kiln
. (c) The total organic carbon content (dry basis) of raw material s must be determined annually using ASTM C114- 09 Standard Test Methods for Chemical Analysis of Hydraulic Cement (incorporated by reference, see §98.7) or a similar industry standard practice or method approved for total organic carbon determination in raw mineral materials. The analysis must be conducted either on sample material drawn from bulk raw kiln feed storage or on sample material drawn from bulk raw material storage for each category of raw material (i.e., limestone, sand, shale, iron oxide, and alumina). Facilities that opt to use the default total Deleted: 07

Deleted: s

Deleted: each136
organic carbon factor provided in §98.83(d)(3), are not required to monitor for TOC. (d) The quantity of clinker produced monthly by each kiln must be determined by direct weight measurement of clinker using the same plant techniques used for accounting purposes, such as reconciling weigh hopper or belt weigh feeder measurements against inventory measurements. As an alternative, facilities may also determine clinker production by direct measurement of raw kiln feed and application of a kiln-specific feed-to-clinker factor. Facilities that opt to use a feed-to-clinker factor must verify the accuracy of this factor on a monthly basis. (e) The quantity of CKD not recycled to the kiln by each kiln must be determined quarterly by direct weight measurement using the same plant instruments used for accounting purposes, such as weigh hoppers, truck weigh scales, or belt weigh feeders. (f) The annual quantity of raw kiln feed or annual quantity of each category of raw materials consumed by the facility (e.g., limestone, sand, shale, iron oxide, and alumina) must be determined monthly by direct weight measurement using the same plant instruments used for accounting purposes, such as weigh hoppers, truck weigh scales, or belt weigh feeders. Deleted: instruments

Deleted: s

Deleted: s

Deleted: annually137
(g) The monthly non-calcined CaO and MgO that remains in the clinker in the form of CaCO 3 or that enters the kiln as a non-carbonate species may be assumed to be a default value of 0.0 or may be determined monthly by careful chemical analysis of feed material and clinker material from each kiln using well documented analytical and calculational methods or the appropriate industry standard practice. (h) The quarterly non-calcined CaO and MgO that remains in the CKD in the form of CaCO 3 or that enters the kiln as a non-carbonate species may be assumed to be a default value of 0.0 or may be determined quarterly by careful chemical analysis of feed material and CKD material from each kiln using well documented analytical and calculational methods or the appropriate industry standard practice. §98.85 Procedures for estimating missing data. A complete record of all measured parameters used in the GHG emissions calculations in §98.83 is required. Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter shall be used in the calculations. The owner or operator must document and keep records of the procedures used for all such estimates.138
(a) If the CEMS approach is used to determine combined process and combustion CO 2 emissions, the missing data procedures in §98.35 apply. (b) For CO 2 process emissions from cement manufacturing facilities calculated according to §98.83(d), if data on the carbonate content (of clinker or CKD), noncalcined content (of clinker or CKD) or the annual organic carbon content of raw materials are missing, facilities must undertake a new analysis. (c) For each missing value of monthly clinker production the substitute data value must be the best available estimate of the monthly clinker production based on information used for accounting purposes, or use the maximum tons per day capacity of the system and the number of days per month. (d) For each missing value of monthly raw material consumption the substitute data value must be the best available estimate of the monthly raw material consumption based on information used for accounting purposes (such as purchase records), or use the maximum tons per day raw material throughput of the kiln and the number of days per month. §98.86 Data reporting requirements.139
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 appropriate. (a) If a CEMS is used to measure CO 2 emissions, then you must report under this subpart the relevant information required by §98.36(e)(2)(vi) and the information listed in this paragraph(a): (1) Monthly clinker production from each kiln at the facility. (2) Monthly cement production from each kiln at the facility. (3) Number of kilns and number of operating kilns. (b) If a CEMS is not used to measure CO 2 emissions, then you must report the information listed in this paragraph (b) for each kiln: (1) Kiln identification number. (2) Monthly clinker production from each kiln. (3) Monthly cement production from each kiln. (4) Number of kilns kilns and number of operating kilns. (5) Quarterly quantity of CKD not recycled to the kiln for each kiln at the facility.140
(6) Monthly fraction of total CaO, total MgO, noncalcined CaO and non-calcined MgO in clinker for each kiln (as wt-fractions). (7) Method used to determine non-calcined CaO and non-calcined MgO in clinker.(8) Quarterly fraction of total CaO, total MgO, noncalcined CaO and non-calcined MgO in CKD not recycled to the kiln for each kiln (as wt-fractions). (9) Method used to determine non-calcined CaO and non-calcined MgO in CKD. (10) Monthly kiln-specific clinker CO 2 emission factors for each kiln (metric tons CO 2 /metric ton clinker produced). (11) Quarterly kiln-specific CKD CO 2 emission factors for each kiln (metric tons CO 2 /metric ton CKD produced). (12) Annual organic carbon content of raw kiln feed or annual organic carbon content of each raw material (wtfraction, dry basis). (13) Annual consumption of raw kiln feed or annual consumption of each raw material (dry basis). (14) Number of times missing data procedures were used to determine the following information: (i) Clinker production (number of months).141
(ii) Carbonate contents of clinker (number of months). (iii) Non-calcined content of clinker (number of months). (iv) CKD not recycled to kiln (number of quarters). (v) Non-calcined content of CKD (number of quarters) (vi) Organic carbon contents of raw materials (number of times). (vii) Raw material consumption (number of months). (15) Method used to determine the monthly clinker production from each kiln reported under (b)(2) of this section, including monthly kiln-specific clinker factors, if used. §98.87 Records that must be retained. (a) If a CEMS is used to measure CO 2 emisions, then in addition to the records required by §98.3(g), you must retain under this subpart the records required for the Tier 4 Calculation Methodology in §98.37. (1) [Reserved] (2) [Reserved] (3) Measurements, records and calculations used to determine reported parameters. (b) If a CEMS is not used to measure CO 2 emissions, then in addition to the records required by §98.3(g), you Deleted: Documentation ofmonthly calculated kilnspecific clinker CO 2 emission factor.¶ Deleted: Documentation ofquarterly calculated kilnspecific CKD CO 2 emission factor.¶142
must retain the records specified in paragraphs (a) through (b) of this section for each portland cement manufacturing facility. (1) Documentation of monthly calculated kiln-specific clinker CO 2 emission factor.(2) Documentation of quarterly calculated kilnspecific CKD CO 2 emission factor. (3) Measurements, records and calculations used to determine reported parameters. §98.88 Definitions. All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. **Subpart K—Ferroalloy Production** §98.110 Definition of the source category. The ferroalloy production source category consists of any facility that uses pyrometallurgical techniques to produce any of the following metals: ferrochromium, ferromanganese, ferromolybdenum, ferronickel, ferrosilicon, ferrotitanium, ferrotungsten, ferrovanadium, silicomanganese, or silicon metal. §98.111 Reporting threshold. You must report GHG emissions under this subpart if your facility contains a ferroalloy production process and143
the facility meets the requirements of either §98.2(a)(1) or (2). §98.112 GHGs to report. You must report: (a) Process CO 2 emissions from each electric arc furnace (EAF) used for the production of any ferroalloy listed in §98.110 , and process CH 4 emissions from each EAF that is used for the production of any ferroalloy listed in Table K-1 of this section
. (b) CO 2 , CH 4 , and N 2 O emissions from each stationary combustion unit following the requirements of subpart C of this part. You must report these emissions under subpart C of this part (General Stationary Fuel Combustion Sources). §98.113 Calculating GHG emissions. You must calculate and report the annual process CO 2 emissions from each EAF not subject to paragraph (c) of this section using the procedures in either paragraph (a) or (b) of this section . For each EAF also subject to annual process CH 4 emissions reporting, you must also calculate and report the annual process CH 4 emissions from the EAF using the procedures in paragraph (d) of this section
. (a) Calculate and report under this subpart the process CO 2 emissions by operating and maintaining CEMS144
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). (b) Calculate and report under this subpart the annual process CO 2 emissions using the procedure in either paragraph (b)(1) or (b)(2) of this section. (1) Calculate and report under this subpart the annual process CO 2 emissions from EAFs by operating and maintaining a CEMS according to the Tier 4 Calculation Methodology specified in §98.33(a)(4) and the applicable requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources). (2) Calculate and report under this subpart the annual process CO 2 emissions from the EAFs using the carbon mass balance procedure specified in paragraphs (b)(2)(i) and (b)(2)(ii) of this section. (i) For each EAF, determine the annual mass of carbon in each carbon-containing input and output material for the EAF and estimate annual process CO 2 emissions from the EAF using Equation K-1 of this section. Carbon-containing input materials include carbon electrodes and carbonaceous reducing agents. If you document that a specific input or output material contributes less than 1 percent of the145
total carbon into or out of the process, you do not have to include the material in your calculation using Equation K-1 of this section. 

#   

#       

#          

           

l l outgoing product non l outgoing product non k k outgoing product k outgoing product j h

ore ore m

m electrode electrode i
i agent reducing i agent reducing

C M C M M CM C M C M

h h m

1 - - 1 1 j flux j flux 1 1 1 CO2

2205 2000 12 44

- 2205 2000 12 44

- C 2205 2000 12 44 2205 2000 12 44 2205 2000 12 44 2205 2000 12 44 E

(Eq. K-1)

Where: E CO2 = Annual process CO 2 emissions from an individual EAF (metric tons). 44/12 = Ratio of molecular weights, CO 2 to carbon. 2000/2205 = Conversion factor to convert tons to metric tons. M reducing agent i = Annual mass of reducing agent i fed, charged, or otherwise introduced into the EAF (tons). C reducing agent i = Carbon content in reducing agent i (percent by weight, expressed as a decimal fraction). M electrode m = Annual mass of carbon electrode m consumed in the EAF (tons). C electrode m = Carbon content of the carbon electrode m (percent by weight, expressed as a decimal fraction). M ore h = Annual mass of ore h charged to the EAF (tons). C ore h = Carbon content in ore h (percent by weight, expressed as a decimal fraction).146

M flux j = Annual mass of flux material j fed, charged, or otherwise introduced into the EAF to facilitate slag formation (tons). C flux j = Carbon content in flux material j (percent by weight, expressed as a decimal fraction). M product k = Annual mass of alloy product k tapped from EAF (tons). C product k = Carbon content in alloy product k. (percent by weight, expressed as a decimal fraction). M non-product outgoing l = Annual mass of non-product outgoing material l removed from EAF (tons). C non-product outgoing l = Carbon content in non-product outgoing material l (percent by weight, expressed as a decimal fraction). (ii) Determine the combined annual process CO 2 emissions from the EAFs at your facility using Equation K-2 of this section. 

##   k

1 CO2 2 k ECO (Eq. K-2)
Where: CO 2 = Annual process CO 2 emissions from EAFs at facility used for the production of any ferroalloy listed in §98.110 (metric tons). E CO2 k = Annual process CO 2 emissions calculated from EAF k calculated using Equation K-1 of this section (metric tons). k = Total number of EAFs at facility used for the production of any ferroalloy listed in §98.110. (c) If GHG emissions from an EAF 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 the147
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. (d) For the EAFs at your facility used for the production of any ferroalloy listed in Table K-1 of this subpart, you must calculate and report the annual CH 4 emissions using the procedure specified in paragraphs (d)(1) and (2) of this section. (1) For each EAF, determine the annual CH 4 emissions using Equation K-3 of this section. 

#       

 i
i product i product CH 

## EFxxM E 1 4 

## 2005 2000 ( (Eq. K-3)
Where:
E CH4 = Annual process CH 4 emissions from an individual EAF (metric tons). M product i = Annual mass of alloy product i produced in the EAF (tons). 2000/2205 = Conversion factor to convert tons to metric tons. EF product i = CH 4 emission factor for alloy product i from Table K-1 in this subpart (kg of CH 4 emissions per metric ton of alloy product i ).148
(2) Determine the combined process CH 4 emissions from the EAFs at your facility using Equation K-4 of this section: 

##   j

1 j CH4 4 E CH (Eq. K-4)
Where: CH 4 = Annual process CH 4 emissions from EAFs at facility used for the production of ferroalloys listed in Table K-1 of this subpart (metric tons). E CH4 j = Annual process CH 4 emissions from EAF j calculated using Equation K-3 of this section (metric tons). j = Total number of EAFs at facility used for the production of ferroalloys listed in Table K-1 of this subpart. §98.114 Monitoring and QA/QC requirements. If you determine annual process CO 2 emissions using the carbon mass balance procedure in §98.113(b)(2), you must meet the requirements specified in paragraphs (a) and (b) of this section. (a) Determine the annual mass for each material used for the calculations of annual process CO 2 emissions using Equation K-1 of this subpart by summing the monthly mass for the material determined for each month of the calendar year. The monthly mass may be determined using plant instruments used for accounting purposes, including either direct measurement of the quantity of the material placed149
in the unit or by calculations using process operating information. (b) For each material identified in paragraph (a) of this section, you must determine the average carbon content of the material consumed, used, or produced in the calendar year using the methods specified in either paragraph (b)(1) or (b)(2) of this section. If you document that a specific process input or output contributes less than one percent of the total mass of carbon into or out of the process, you do not have to determine the monthly mass or annual carbon content of that input or output. (1) Information provided by your material supplier. (2) Collecting and analyzing at least three representative samples of the material inputs and outputs each year. The carbon content of the material must be analyzed at least annually using the standard methods (and their QA/QC procedures) specified in paragraphs (b)(2)(i) through (b)(2)(iii) of this section, as applicable. (i) ASTM E1941-04, Standard Test Method for Determination of Carbon in Refractory and Reactive Metals and Their Alloys (incorporated by reference, see §98.7) for analysis of metal ore and alloy product. (ii) ASTM D5373-08 Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and150
Nitrogen in Laboratory Samples of Coal (incorporated by reference, see §98.7), for analysis of carbonaceous reducing agents and carbon electrodes. (iii) ASTM C25-06, Standard Test Methods for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime (incorporated by reference, see §98.7) for analysis of flux materials such as limestone or dolomite. §98.115 Procedures for estimating missing data. A complete record of all measured parameters used in the GHG emissions calculations in §98.113 is required. Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter shall be used in the calculations as specified in the paragraphs (a) and (b) of this section. You must document and keep records of the procedures used for all such estimates. (a) If you determine CO 2 emissions for the EAFs at your facility using the carbon mass balance procedure in §98.113(b), 100 percent data availability is required for the carbon content of the input and output materials. You must repeat the test for average carbon contents of inputs according to the procedures in §98.114(b) if data are missing.151
(b) For missing records of the monthly mass of carbon-containing inputs and outputs, the substitute data value must be based on the best available estimate of the mass of the inputs and outputs from on all available process data or data used for accounting purposes, such as purchase records. (c) If you are required to calculate CH 4 emissions for an EAF at your facility as specified in §98.113(d), the estimate is based an annual quantity of certain alloy products, so 100 percent data availability is required. §98.116 Data reporting requirements. In addition to the information required by §98.3(c), each annual report must contain the information specified in paragraphs (a) through (e) of this section, as applicable: (a) Annual facility ferroalloy product production capacity (tons). (b) Annual production for each ferroalloy product identified in §98.110, from each EAF (tons)
. (c) Total number of EAFs at facility used for production of ferroalloy products. (d) If a CEMS is used to measure CO 2 emissions, then you must report under this subpart the relevant information required by §98. 36 for the Tier 4 Calculation Methodology Deleted: (tons) Deleted: as applicable

Deleted: reported in paragraph (a)(4) of this section

Deleted: 37152
and the following information specified in paragraphs (d)(1) through (d)(3) of this section. (1) Annual process CO 2 emissions (in metric tons) from each EAF used for the production of any ferroalloy product identified in §98.110
. (2) Annual process CH 4 emissions (in metric tons) from each EAF used for the production of any ferroalloy listed in Table K-1 of this subpart (metric tons). (3) Identification number of each EAF. (e) If a CEMS is not used to measure CO 2 process emissions, and the carbon mass balance procedure is used to determine CO 2 emissions according to the requirements in §98.113(b), then you must report the following information specified in paragraphs (e)(1) through (e)(7) of this section. (1) Annual process CO 2 emissions (in metric tons) from each EAF used for the production of any ferroalloy identified in §98.110 (metric tons). (2) Annual process CH 4 emissions (in metric tons) from each EAF used for the production of any ferroalloy listed in Table K-1 of this subpart (metric tons). (3) Identification number of each EAF. Deleted: listed in Table K-1 of this subpart (metric tons)

Deleted: listed in Table K-1 of this subpart153
(4) Annual material quantity for each material included for the calculation of annual process CO 2 emissions for each EAF. (5) Annual average of the carbon content determinations for each material included for the calculation of annual process CO 2 emissions for each EAF (percent by weight, expressed as a decimal fraction). (6) List the method used for the determination of carbon content for each material reported in paragraph (e)(5) of this section (e.g., supplier provided information, analyses of representative samples you collected). (7) If you use the missing data procedures in§98.115(b), you must report how monthly mass of carboncontaining inputs and outputs with missing data was determined and the number of months the missing data procedures were used. §98.117 Records that must be retained. In addition to the records required by §98.3(g), you must retain the records specified in paragraphs (a) through (d) of this section for each EAF, as applicable. (a) If a CEMS is used to measure CO 2 emissions according to the requirements in §98.113(a), then you must retain under this subpart the records required for the Tier154
4 Calculation Methodology in §98.37 and the information specified in paragraphs (a)(1) through (a)(3) of this section. (1) Monthly EAF production quantity for each ferroalloy product (tons). (2) Number of EAF operating hours each month. (3) Number of EAF operating hours in a calendar year. (b) If the carbon mass balance procedure is used to determine CO 2 emissions according to the requirements in §98.113(b)(2), then you must retain records for the information specified in paragraphs (b)(1) through (b)(5) of this section. (1) Monthly EAF production quantity for each ferroalloy product (tons). (2) Number of EAF operating hours each month. (3) Number of EAF operating hours in a calendar year. (4) Monthly material quantity consumed, used, or produced for each material included for the calculations of annual process CO 2 emissions (tons). (5) Average carbon content determined and records of the supplier provided information or analyses used for the determination for each material included for the calculations of annual process CO 2 emissions.155
(c) You must keep records that include a detailed explanation of how company records of measurements are used to estimate the carbon input and output to each EAF, including documentation of specific input or output materials excluded from Equation K-1 of this subpart that contribute less than 1 percent of the total carbon into or out of the process. You also must document the procedures used to ensure the accuracy of the measurements of materials fed, charged, or placed in an EAF including, but not limited to, calibration of weighing equipment 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. (d) If you are required to calculate CH 4 emissions for the EAF as specified in §98.113(d), you must maintain records of the total amount of each alloy product produced for the specified reporting period, and the appropriate alloy-product specific emission factor used to calculate the CH 4 emissions. §98.118 Definitions. All terms used of this subpart have the same meaning given in the Clean Air Act and subpart A of this part.156
**Table K-1 of Subpart K—Electric Arc Furnace (EAF) CH 4**  **Emission Factors. CH**  **4 Emission Factor**  **(kg CH 4**  **per metric ton product) EAF Operation**  **Alloy product produced in EAF**  **Batch Charging**  **Sprinkle Charging**  **a Sprinkle**  **Charging and >750°C**  **b** Silicon metal 1.5 1.2 0.7 Ferrosilicon 90% 1.4 1.1 0.6 Ferrosilicon 75% 1.3 1.0 0.5 Ferrosilicon 65% 1.3 1.0 0.5
a Sprinkle-charging is charging intermittently every minute. b Temperature measured in off-gas channel downstream of the furnace hood. **Subpart N—Glass Production** §98.140 Definition of the source category. (a) A glass manufacturing facility manufactures flat glass, container glass, pressed and blown glass, or wool fiberglass by melting a mixture of raw materials to produce molten glass and form the molten glass into sheets, containers, fibers, or other shapes. A glass manufacturing facility uses one or more continuous glass melting furnaces to produce glass. (b) A glass melting furnace that is an experimental furnace or a research and development process unit is not subject to this subpart. §98.141 Reporting threshold. You must report GHG emissions under this subpart if your facility contains a glass production process and the157
facility meets the requirements of either §98.2(a)(1) or (2). §98.142 GHGs to report. You must report: (a) CO 2 process emissions from each continuous glass melting furnace. (b) CO 2 combustion emissions from each continuous glass melting furnace. (c) CH 4 and N 2 O combustion emissions from each continuous glass melting furnace. 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) CO 2 , CH 4 , and N 2 O emissions from each stationary fuel combustion unit other than continuous glass melting furnaces. You must report these emissions under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C. §98.143 Calculating GHG emissions. You must calculate and report the annual process CO 2 emissions from each continuous glass melting furnace using the procedure in paragraphs (a) and (b) of this section. (a) For each continuous glass melting furnace that meets the conditions specified in §98.33(b)(4)(ii) or158
(iii), you must calculate and report under this subpart the combined process and combustion CO 2 emissions by operating and maintaining a CEMS to measure CO 2 emissions 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) For each continuous glass melting furnace that is not subject to the requirements in paragraph (a) of this section, calculate and report the process and combustion CO 2 emissions from the glass melting furnace by using either the procedure in paragraph (b)(1) of this section or the procedure in paragraphs (b)(2) through (b)(7) of this section, except as specified in paragraph (c) of this section. (1) Calculate and report under this subpart the combined process and combustion CO 2 emissions by operating and maintaining a CEMS to measure CO 2 emissions 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).159
(2) Calculate and report the process and combustion
CO 2 emissions separately using the procedures specified in paragraphs (b)(2)(i) through (b)(2)(vi) of this section. (i) For each carbonate-based raw material charged to the furnace, obtain from the supplier of the raw material the carbonate-based mineral mass fraction. (ii) Determine the quantity of each carbonate-based raw material charged to the furnace. (iii) Apply the appropriate emission factor for each carbonate-based raw material charged to the furnace, as shown in Table N-1 to this subpart. (iv) Use Equation N-1 of this section to calculate process mass emissions of CO 2 for each furnace: 

# 

  n

1i ii ii CO2 FEF) 2205 2000 M(MF E (Eq. N-1)
Where: E CO2 = Process emissions of CO 2 from the furnace (metric tons).

n = Number of carbonate-based raw materials charged to furnace. MF i = Annual average mass fraction of carbonatebased mineral i in carbonate-based raw material i (percentage, expressed as a decimal). M i = Annual amount of carbonate-based raw material i charged to furnace (tons). 2000/2205 = Conversion factor to convert tons to metric tons.160

EF i = Emission factor for carbonate-based raw material i (metric ton CO 2 per metric ton carbonate-based raw material as shown in Table N-1 to this subpart). F i = Fraction of calcination achieved for carbonate-based raw material i, assumed to be equal to 1.0 (percentage, expressed as a decimal). (v) You must calculate the total process CO 2 emissions from continuous glass melting furnaces at the facility using Equation N-2 of this section: 

# 

  k

i iCO ECO 1 2 2 (Eq. N-2)
Where: CO 2 = Annual process CO 2 emissions from glass manufacturing facility (metric tons). E CO 2i = Annual CO 2 emissions from glass melting furnace i (metric tons). k = Number of continuous glass melting furnaces. (vi) Calculate and report under subpart C of this part (General Stationary Fuel Combustion Sources) the combustion CO 2 emissions in the glass furnace according to the applicable requirements in subpart C. (c) As an alternative to data provided by the raw material supplier, a value of 1.0 can be used for the mass fraction (MF i ) of carbonate-based mineral i in Equation N-1 of this section. §98.144 Monitoring and QA/QC requirements.161

(a) You must measure annual amounts of carbonatebased raw materials charged to each continuous glass melting furnace from monthly measurements using plant instruments used for accounting purposes, such as calibrated scales or weigh hoppers. Total annual mass charged to glass melting furnaces at the facility shall be compared to records of raw material purchases for the year. (b) You must measure carbonate-based mineral mass fractions at least annually to verify the mass fraction data provided by the supplier of the raw material; such measurements shall be based on sampling and chemical analysis conducted by a certified laboratory using ASTM D3682-01 (Reapproved 2006) Standard Test Method for Major and Minor Elements in Combustion Residues from Coal Utilization Processes (incorporated by reference, see §98.7) or ASTM D6349-09 Standard Test Method for Determination of Major and Minor Elements in Coal, Coke, and Solid Residues from Combustion of Coal and Coke by Inductively Coupled Plasma—Atomic Emission Spectrometry (incorporated by reference, see §98.7)
. (c) You must determine the annual average massfraction for the carbonate-based mineral in each carbonatebased raw material by calculating an arithmetic average of162
the monthly data obtained from raw material suppliers or sampling and chemical analysis. (d) You must determine on an annual basis the calcination fraction for each carbonate consumed based on sampling and chemical analysis using an industry consensus standard. This chemical analysis must be conducted using an x-ray fluorescence test or other enhanced testing method published by an industry consensus standards organization (e.g., ASTM, ASME, API, etc.). §98.145 Procedures for estimating missing data. A complete record of all measured parameters used in the GHG emissions calculations is required (e.g., carbonate raw materials consumed, etc.). If the monitoring and quality assurance procedures in §98.144 cannot be followed and data is missing, you must use the most appropriate of the missing data procedures in paragraphs (a) and (b) of this section. You must document and keep records of the procedures used for all such missing value estimates. (a) For missing data on the monthly amounts of carbonate-based raw materials charged to any continuous glass melting furnace use the best available estimate(s) of the parameter(s), based on all available process data or data used for accounting purposes, such as purchase records.163
(b) For missing data on the mass fractions of carbonate-based minerals in the carbonate-based raw materials assume that the mass fraction of each carbonate based mineral is 1.0. §98.146 Data reporting requirements. 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. (a) If a CEMS is used to measure CO 2 emissions, then you must report under this subpart the relevant information required under §98.3 6 for the Tier 4 Calculation Methodology and the following information specified in paragraphs (a)(1) and (a)(2) of this section: (1) Annual quantity of each carbonate-based raw material charged to each continuous glass melting furnace and for all furnaces combined (tons). (2) Annual quantity of glass produced by each glass melting furnace and by all furnaces combined (tons). (b) If a CEMS is not used to determine CO 2 emissions from continuous glass melting furnaces, and process CO 2 emissions are calculated according to the procedures specified in §98.143(b), then you must report the following information as specified in paragraphs (b)(1) through (b)(9) of this section: Deleted: 7164
(1) Annual process emissions of CO 2 (metric tons) for each continuous glass melting furnace and for all furnaces combined. (2) Annual quantity of each carbonate-based raw material charged (tons) to each continuous glass melting furnace and for all furnaces combined. (3) Annual quantity of glass produced (tons) from each continuous glass melting furnace and from all furnaces combined. (4) Carbonate-based mineral mass fraction(percentage, expressed as a decimal) for each carbonatebased raw material charged to a continuous glass melting furnace. (5) Results of all tests used to verify thecarbonate-based mineral mass fraction for each carbonatebased raw material charged to a continuous glass melting furnace, as specified in paragraphs (b)(5)(i) through (b)(5)(iii) of this section. (i) Date of test. (ii) Method(s) and any variations used in the analyses. (iii) Mass fraction of each sample analyzed.165
(6) The fraction of calcination achieved for each carbonate-based raw material, if a value other than 1.0 is used to calculate process mass emissions of CO 2 . (7) Method used to determine fraction of calcination. (8) Total number of continuous glass melting furnaces. (9) The number of times in the reporting year that missing data procedures were followed to measure monthly quantities of carbonate-based raw materials or mass fraction of the carbonate-based minerals for any continuous glass melting furnace (months). §98.147 Records that must be retained. In addition to the information required by §98.3(g), you must retain the records listed in paragraphs (a), (b), and (c) of this section. (a) If a CEMS is used to measure emissions, then you must retain the records required under §98.37 for the Tier 4 Calculation Methodology and the following information specified in paragraphs (a)(1) and (a)(2) of this section: (1) Monthly glass production rate for each continuous glass melting furnace (tons). (2) Monthly amount of each carbonate-based raw material charged to each continuous glass melting furnace (tons). Deleted: (percentage, expressed as a decimal)

Deleted: any continuous glass melting furnace166
(b) If process CO 2 emissions are calculated according to the procedures specified in §98.143(b), you must retain the records in paragraphs (b)(1) through (b)(5) of this section. (1) Monthly glass production rate for each continuous glass melting furnace (metric tons). (2) Monthly amount of each carbonate-based raw material charged to each continuous glass melting furnace (metric tons). (3) Data on carbonate-based mineral mass fractions provided by the raw material supplier for all raw materials consumed annually and included in calculating process emissions in Equation N-1 of this subpart. (4) Results of all tests used to verify thecarbonate-based mineral mass fraction for each carbonatebased raw material charged to a continuous glass melting furnace, including the data specified in paragraphs (b)(4)(i) through (b)(4)(v) of this section. (i) Date of test. (ii) Method(s), and any variations of the methods, used in the analyses. (iii) Mass fraction of each sample analyzed. (iv) Relevant calibration data for the instrument(s) used in the analyses.167
(v) Name and address of laboratory that conducted the
tests. (5) The fraction of calcination achieved for each carbonate-based raw material (percentage, expressed as a decimal), if a value other than 1.0 is used to calculate process mass emissions of CO 2 . (c) All other documentation used to support the reported GHG emissions. §98.148 Definitions. All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. **Table N-1 to**  **Subpart N—CO 2**  **Emission Factors for Carbonate Based Raw Materials** 

Carbonate-Based Raw Material – Mineral CO 2 Emission Factor a Limestone – CaCO 3 0.440 Dolomite – CaMg(CO 3 ) 2 0.477 Sodium carbonate/soda ash – Na 2 CO 3 0.415 Barium carbonate – BaCO 3 0.223 Potassium carbonate - K 2 CO 3 0.318
a Emission factors in units of metric tons of CO 2 emitted per metric ton of carbonate-based raw material charged to the furnace. **Subpart O—HCFC-22 Production and HFC-23 Destruction** §98.150 Definition of the source category. The HCFC-22 production and HFC-23 destruction sourcecategory consists of HCFC-22 production processes and HFC23 destruction processes. (a) An HCFC-22 production process produces HCFC-22 (chlorodifluoromethane, or CHClF 2 ) from chloroform (CHCl 3 ) and hydrogen fluoride (HF). Deleted: **of**168
(b) An HFC-23 destruction process is any process in which HFC-23 undergoes destruction. An HFC-23 destruction process may or may not be co-located with an HCFC-22 production process at the same facility. §98.151 Reporting threshold. You must report GHG emissions under this subpart if your facility contains a HCFC-22 production or HFC-23 destruction process and the facility meets the requirements of either §98.2(a)(1) or (a)(2). §98.152 GHGs to report. (a) 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 following the requirements of subpart C. (b) You must report HFC-23 emissions from HCFC-22 production processes and HFC-23 destruction processes. §98.153 Calculating GHG emissions. (a) The mass of HFC-23 generated from each HCFC-22 production process shall be estimated by using one of two methods, as applicable: (1) Where the mass flow of the combined stream of HFC-23 and another reaction product (e.g., HCl) is measured, multiply the weekly (or more frequent) HFC-23 concentration measurement (which may be the average of more169
frequent concentration measurements) by the weekly (or more frequent) mass flow of the combined stream of HFC-23 and the other product. To estimate annual HFC-23 production, sum the weekly (or more frequent) estimates of the quantities of HFC-23 produced over the year. This calculation is summarized in Equation O-1 of this section: 

## 

   n

p p FcG 1 3

23 23 10** (Eq. O-1)
Where:
G 23 = Mass of HFC-23 generated annually (metric tons).
c 23 = Fraction HFC-23 by weight in HFC-23/other product stream. F p = Mass flow of HFC-23/other product stream during the period p (kg). p = Period over which mass flows and concentrations are measured. n = Number of concentration and flow measurement periods for the year. 10 -3 = Conversion factor from kilograms to metric tons. (2) Where the mass of only a reaction product other than HFC-23 (either HCFC-22 or HCl) is measured, multiply the ratio of the weekly (or more frequent) measurement of the HFC-23 concentration and the weekly (or more frequent) measurement of the other product concentration by the weekly (or more frequent) mass produced of the other product. To estimate annual HFC-23 production, sum the weekly (or more frequent) estimates of the quantities of170
HFC-23 produced over the year. This calculation is summarized in Equation O-2 of this section, assuming that the other product is HCFC-22. If the other product is HCl, HCl may be substituted for HCFC-22 in Equations O-2 and O-3 of this section.

3 22 1 22 23 23 10** 

 

##         

 P c c G n

p (Eq. O-2)

Where:
G 23 = Mass of HFC-23 generated annually (metric tons). c 23 = Fraction HFC-23 by weight in HCFC-22/HFC-23 stream. c 22 = Fraction HCFC-22 by weight in HCFC-22/HFC-23 stream. P 22 = Mass of HCFC-22 produced over the period p (kg), calculated using Equation O-3 of this section. p = Period over which masses and concentrations are measured. n = Number of concentration and mass measurement periods for the year. 10 -3 = Conversion factor from kilograms to metric tons. (b) The mass of HCFC-22 produced over the period p shall be estimated by using Equation O-3 of this section: )(* 22 22 22 UOLFP

  (Eq. O-3) Where:

P 22 = Mass of HCFC-22 produced over the period p (kg). O 22 = mass of HCFC-22 that is measured coming out of the Production process over the period p (kg). U 22 = Mass of used HCFC-22 that is added to the production process upstream of the output measurement over the period p (kg).171
LF = Factor to account for the loss of HCFC-22 upstream of the measurement. The value for LF shall be determined pursuant to §98.154(e). (c) For HCFC-22 production facilities that do not use a thermal oxidizer or that have a thermal oxidizer that is not directly connected to the HCFC-22 production equipment, HFC-23 emissions shall be estimated using Equation O-4 of this section: 

##   2323 23 23 23 23 IDODSGE     (Eq. O-4) Where:
E 23 = Mass of HFC-23 emitted annually (metric tons). G 23 = Mass of HFC-23 generated annually (metric tons). S 23 = Mass of HFC-23 sent off site for sale annually (metric tons). OD 23 = Mass of HFC-23 sent off site for destruction (metric tons). D 23 = Mass of HFC-23 destroyed on site (metric tons). I 23 = Increase in HFC-23 inventory = HFC-23 in storage at end of year – HFC-23 in storage at beginning of year (metric tons). (d) For HCFC-22 production facilities that use a thermal oxidizer connected to the HCFC-22 production equipment, HFC-23 emissions shall be estimated using Equation O-5 of this section:

D PVL EEEE    23 (Eq. O-5) Where:
E 23 = Mass of HFC-23 emitted annually (metric tons). E L = Mass of HFC-23 emitted annually from equipment leaks, calculated using Equation O-6 of this section (metric tons).172

E PV = Mass of HFC-23 emitted annually from process vents, calculated using Equation O-7 of this section (metric tons). E D = Mass of HFC-23 emitted annually from thermal oxidizer (metric tons), calculated using Equation O-8 of this section. (1) The mass of HFC-23 emitted annually from equipment leaks (for use in Equation O-5 of this section) shall be estimated by using Equation O-6 of this section: 

##   3 1 23 10** ** 

 

##    n

p LtLtGtGt t L NFNFc E (Eq. O-6)
Where:

E L = Mass of HFC-23 emitted annually from equipment leaks (metric tons).

c 23 = Fraction HFC-23 by weight in the stream(s) in the equipment. F Gt = The applicable leak rate specified in Table O-1 of this subpart for each source of equipment type and service t with a screening value greater than or equal to 10,000 ppmv (kg/hr/source). N Gt = The number of sources of equipment type and service t with screening values greater than or equal to 10,000 ppmv as determined according to §98.154(i). F Lt = The applicable leak rate specified in Table O-1 of this subpart for each source of equipment type and service t with a screening value of less than 10,000 ppmv (kg/hr/source). N Lt = The number of sources of equipment type and service t with screening values less than 10,000 ppmv as determined according to §98.154(j). p = One hour. n = Number of hours during the year during which equipment contained HFC-23. t = Equipment type and service as specified in Table O-1 of this subpart .173

10 -3 = Factor converting kg to metric tons. (2) The mass of HFC-23 emitted annually from process vents (for use in Equation O-5 of this section) shall be estimated by using Equation O-7 of this section:

3 1 10*** 

 

##         

 p n

p T p T PV l PR PR ER E (Eq. O-7)

Where:

E PV = Mass of HFC-23 emitted annually from process vents (metric tons). ER T = The HFC-23 emission rate from the process vents during the period of the most recent test (kg/hr). PR p = The HCFC-22 production rate during the period p (kg/hr). PR T = The HCFC-22 production rate during the most recent test period (kg/hr). l p = The length of the period p (hours). 10 -3 = Factor converting kg to metric tons. n = The number of periods in a year.
(3) The total mass of HFC-23 emitted from destruction devices shall be estimated by using Equation O-8 of this section:

23DD DFE

  (Eq. O-8) Where:

E D = Mass of HFC-23 emitted annually from the destruction device (metric tons). F D = Mass of HFC-23 fed into the destruction device annually (metric tons). D 23 = Mass of HFC-23 destroyed annually (metric tons).174

(4) For facilities that destroy HFC-23, the total mass of HFC-23 destroyed shall be estimated by using Equation O-9 of this section:
DE*FD

D23

 (Eq. O-9) Where:
D 23 = Mass of HFC-23 destroyed annually (metric tons). F D = Mass of HFC-23 fed into the destruction device annually (metric tons). DE = Destruction Efficiency of the destruction device (fraction). §98.154 Monitoring and QA/QC requirements. These requirements apply to measurements that are reported under this subpart or that are used to estimate reported quantities pursuant to §98.153.(a) The concentrations (fractions by weight) of HFC23 and HCFC-22 in the product stream shall be measured at least weekly using equipment and methods (e.g., gas chromatography) with an accuracy and precision of 5 percent or better at the concentrations of the process samples. (b) The mass flow of the product stream containing the HFC-23 shall be measured at least weekly using weigh scales, flowmeters, or a combination of volumetric and density measurements with an accuracy and precision of 1.0 percent of full scale or better.175
(c) The mass of HCFC-22 or HCl coming out of the production process shall be measured at least weekly using weigh scales, flowmeters, or a combination of volumetric and density measurements with an accuracy and precision of 1.0 percent of full scale or better. (d) The mass of any used HCFC-22 added back into the production process upstream of the output measurement in paragraph (c) of this section shall be measured (when being added) using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of 1.0 percent of full scale or better. If the mass in paragraph (c) 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 HCFC-22 for purposes of this paragraph (d) of this section and §98.153(b). (e) The loss factor LF in Equation O-3 of this subpart for the mass of HCFC-22 produced shall have the value 1.015 or another value that can be demonstrated, to the satisfaction of the Administrator, to account for losses of HCFC-22 between the reactor and the point of measurement at the facility where production is being estimated.176
(f) The mass of HFC-23 sent off site for sale shall be measured at least weekly (when being packaged) using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of 1.0 percent of full scale or better. (g) The mass of HFC-23 sent off site for destruction shall be measured at least weekly (when being packaged) using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of 1.0 percent of full scale or better. If the measured mass includes more than trace concentrations of materials other than HFC-23, the concentration of the fluorinated GHG shall be measured at least weekly using equipment and methods (e.g., gas chromatography) with an accuracy and precision of 5 percent or better at the concentrations of the process samples. This concentration (mass fraction) shall be multiplied by the mass measurement to obtain the mass of the HFC-23 sent to another facility for destruction. (h) The masses of HFC-23 in storage at the beginning and end of the year shall be measured using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of 1.0 percent of full scale or better.177
(i) The number of sources of equipment type t with screening values greater than or equal to 10,000 ppmv shall be determined using EPA Method 21 at 40 CFR part 60, appendix A-7, and defining a leak as follows: (1) A leak source that could emit HFC-23, and (2) A leak source at whose surface a concentration of fluorocarbons equal to or greater than 10,000 ppm is measured. (j) The number of sources of equipment type t with screening values less than 10,000 ppmv shall be the difference between the number of leak sources of equipment type t that could emit HFC-23 and the number of sources of equipment type t with screening values greater than or equal to 10,000 ppmv as determined under paragraph (h) of this section. (k) The mass of HFC-23 emitted from process vents shall be estimated at least monthly by incorporating the results of the most recent emissions test into Equation O- 7 of this subpart. HCFC-22 production facilities that use a destruction device connected to the HCFC-22 production equipment shall conduct emissions tests at process vents at least once every five years or after significant changes to the process. Emissions tests shall be conducted in accordance with EPA Method 18 at 40 CFR part 60, appendix Deleted: 6

Deleted: thermal oxidizer178
A-6, under conditions that are typical for the production process at the facility. The sensitivity of the tests shall be sufficient to detect an emission rate that would result in annual emissions of 200 kg of HFC-23 if sustained
over one year. (l) For purposes of Equation O-9 of this subpart, the destruction efficiency must be equated to the destruction efficiency determined during a new or previous performance test of the destruction device. HFC-23 destruction facilities shall conduct annual measurements of HFC-23 concentrations at the outlet of the destruction device in accordance with EPA Method 18 at 40 CFR part 60, appendix A-6. Three samples shall be taken under conditions that are typical for the production process and destruction device at the facility, and the average concentration of HFC-23 shall be determined. The sensitivity of the concentration measurement shall be sufficient to detect an outlet concentration equal to or less than the outlet concentration determined in the destruction efficiency performance test. If the concentration measurement indicates that the HFC-23 concentration is less than or equal to that measured during the performance test that is the basis for the destruction efficiency, continue to use the previously determined destruction efficiency. If the Deleted: thermal oxidizer179

concentration measurement indicates that the HFC-23 concentration is greater than that measured during the performance test that is the basis for the destruction efficiency, facilities shall either: (1) Substitute the higher HFC-23 concentration for that measured during the destruction efficiency performance test and calculate a new destruction efficiency, or (2) Estimate the mass emissions of HFC-23 from the destruction device based on the measured HFC-23 concentration and volumetric flow rate determined by measurement of volumetric flow rate using EPA Method 2, 2A, 2C,2D, or 2F at 40 CFR part 60, appendix A-1, or Method 26 at 40 CFR part 60, appendix A-2. Determine the mass rateof HFC-23 into the destruction device by measuring the HFC23 concentration and volumetric flow rate at the inlet or by a metering device for HFC-23 sent to the device. Determine a new destruction efficiency based on the mass flow rate of HFC-23 into and out of the destruction device. (m) HCFC-22 production facilities shall account for HFC-23 generation and emissions that occur as a result of startups, shutdowns, and malfunctions, either recording HFC-23 generation and emissions during these events, or documenting that these events do not result in significant HFC-23 generation and/or emissions.180
(n) The mass of HFC-23 fed into the destruction device shall be measured at least weekly using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of 1.0 percent of full scale or better. If the measured mass includesmore than trace concentrations of materials other than HFC23, the concentrations of the HFC-23 shall be measured at least weekly using equipment and methods (e.g., gas chromatography) with an accuracy and precision of 5 percent or better at the concentrations of the process samples. This concentration (mass fraction) shall be multiplied by the mass measurement to obtain the mass of the HFC-23 destroyed. (o) In their estimates of the mass of HFC-23 destroyed, HFC-23 destruction facilities 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 destruction device manufacturer specifications. (p) Calibrate all flow meters, weigh scales, andcombinations of volumetric and density measures using NISTtraceable standards and suitable methods published by a Deleted: oxidizer181
consensus standards organization (e.g., ASTM, ASME, ISO, or others). Recalibrate all flow meters, weigh scales, and combinations of volumetric and density measures at the minimum frequency specified by the manufacturer. (q) All gas chromatographs used to determine the concentration of HFC-23 in process streams shall be calibrated at least monthly through analysis of certifiedstandards (or of calibration gases prepared from a highconcentration certified standard using a gas dilution system that meets the requirements specified in Method 205 at 40 CFR part 51, appendix M) with known HFC-23 concentrations that are in the same range (fractions by mass) as the process samples. §98.155 Procedures for estimating missing data. (a) A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable (e.g., if a meter malfunctions during unit operation or if a required process sample is not taken), a substitute data value for the missing parameter shall be used in the calculations, according to the following requirements: (1) For each missing value of the HFC-23 or HCFC-22 concentration, the substitute data value shall be the182
arithmetic average of the quality-assured values of that parameter immediately preceding and immediately following the missing data incident. If, for a particular parameter, no quality-assured data are available prior to the missing data incident, the substitute data value shall be the first quality-assured value obtained after the missing data period. (2) For each missing value of the product stream mass flow or product mass, the substitute value of that parameter shall be a secondary product measurement where such a measurement is available. If that measurement is taken significantly downstream of the usual mass flow or mass measurement (e.g., at the shipping dock rather than near the reactor), the measurement shall be multiplied by 1.015 to compensate for losses. 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. §98.156 Data reporting requirements.183
(a) In addition to the information required by §98.3(c), the HCFC-22 production facility shall report the following information at the facility level: (1) Annual mass of HCFC-22 produced in metric tons. (2) Loss Factor used to account for the loss of HCFC– 22 upstream of the measurement. (3) Annual mass of reactants fed into the process in metric tons of reactant. (4) The mass (in metric tons) of materials other than HCFC-22 and HFC-23 (i.e., unreacted reactants, HCl and other by-products) that occur in more than trace concentrations and that are permanently removed from the
process. (5) The method for tracking startups, shutdowns, and malfunctions and HFC-23 generation/emissions during these
events. (6) The names and addresses of facilities to which any HFC-23 was sent for destruction, and the quantities of HFC-23 (metric tons) sent to each. (7) Annual mass of the HFC-23 generated in metric
tons. (8) Annual mass of any HFC-23 sent off site for sale in metric tons.184
(9) Annual mass of any HFC-23 sent off site for destruction in metric tons. (10) Mass of HFC-23 in storage at the beginning and end of the year, in metric tons. (11) Annual mass of HFC-23 emitted in metric tons. (12) Annual mass of HFC-23 emitted from equipment leaks in metric tons. (13) Annual mass of HFC-23 emitted from process vents in metric tons. (b) In addition to the information required by §98.3(c), facilities that destroy HFC-23 shall report the following for each HFC-23 destruction process: (1) Annual mass of HFC-23 fed into the destruction device
. (2) Annual mass of HFC-23 destroyed. (3) Annual mass of HFC-23 emitted from the destruction device
. (c) Each HFC-23 destruction facility shall report the concentration (mass fraction) of HFC-23 measured at the outlet of the destruction device during the facility’s annual HFC-23 concentration measurements at the outlet of the device
. (d) If the HFC-23 concentration measured pursuant to §98.154(l) is greater than that measured during the Deleted: thermal oxidizer

Deleted: thermal oxidizer

Deleted: results of

Deleted: destruction Deleted: , including:185
performance test that is the basis for the destruction efficiency(DE), the facility shall report the revised destruction efficiency calculated under §98.154(l) and the values used to calculate it, specifying whether §98.154(l)(1) or §98.154(l)(2) has been used for the calculation. Specifically, the facility shall report the following: (1) Flow rate of HFC-23 being fed into the destruction device in kg/hr. (2) Concentration (mass fraction) of HFC-23 at the outlet of the destruction device. (3) Flow rate at the outlet of the destruction device in kg/hr. ( 4 ) Emission rate (in kg/hr) calculated from paragraphs ( d )(2) and (d) (3) of this section. (5) Destruction efficiency (DE) calculated from paragraphs (d)(1) and (d)(4) of this section. (e) By March 31, 2011 or within 60 days of commencing HFC-23 destruction, HFC-23 destruction facilities shall submit a one-time report including the following information for each destruction process: (1) Destruction efficiency (DE). (2) The methods used to determine destruction efficiency. Deleted: d

Deleted: c Deleted: in kg/hr

Deleted: the186
(3) The methods used to record the mass of HFC-23 destroyed. (4) The name of other relevant federal or state regulations that may apply to the destruction process. (5) If any changes are made that affect HFC-23 destruction efficiency or the methods used to record volume destroyed, then these changes must be reflected in a revision to this report. The revised report must be submitted to EPA within 60 days of the change. §98.157 Records that must be retained. (a) In addition to the data required by §98.3(g), HCFC-22 production facilities shall retain the following records: (1) The data used to estimate HFC-23 emissions. (2) Records documenting the initial and periodic calibration of the gas chromatographs, weigh scales, volumetric and density measurements, and flowmeters used to measure the quantities reported under this rule, including the industry standards or manufacturer directions used for calibration pursuant to §98.154(p) and (q). (b) In addition to the data required by §98.3(g), the HFC-23 destruction facilities shall retain the following records:187
(1) Records documenting their one-time and annual reports in §98.156(b) through ( e ). (2) Records documenting the initial and periodic calibration of the gas chromatographs, weigh scales, volumetric and density measurements, and flowmeters used to measure the quantities reported under this subpart, including the industry standard practice or manufacturer directions used for calibration pursuant to §98.154(p) and (q). §98.158 Definitions. All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. **Table O-1 of Subpart O–Emission Factors for Equipment Leaks Emission Factor (kg/hr/source)**  **Equipment Type Service** ≥ 10,000 ppmv <10,000 ppmv Valves Gas 0.0782 0.000131 Valves Light liquid 0.0892 0.000165 Pump seals Light liquid 0.243 0.00187 Compressor seals Gas 1.608 0.0894 Pressure relief valves Gas 1.691 0.0447 Connectors All 0.113 0.0000810 Open-ended lines All 0.01195 0.00150 **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. Deleted: d188
(b) This source category 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 another facility if they are not owned by, or under the direct control of, the other facility’s 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 requirements of either §98.2(a)(1) or (a)(2). §98.162 GHGs to report. You must report: (a) CO 2 emissions from each hydrogen production process unit. (b) [Reserved] (c) CO 2 , CH 4 , and N 2 O emissions from each stationary combustion unit other than hydrogen production 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. Deleted: a petroleum refinery

Deleted: refinery

Deleted: process

Deleted: CO 2 , CH 4 and N 2 O combustion emissions from each hydrogen production process unit. You must calculate and report these combustion emissions under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C.189
§98.163 Calculating GHG emissions. You must calculate and report the annual CO 2 emissions from each hydrogen production process unit using the procedures specified in either paragraph (a) or (b) of this section. (a) Continuous Emissions Montoring Systems (CEMS)
. Calculate and report under this subpart the 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) Fuel and feedstock material balance approach. Calculate and report CO 2 emissions as the sum of the annual emissions associated with each fuel and feedstock 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 emissions from each gaseous fuel and feedstock according to Equation P-1 of this section:
001.0*)* 12 44 ( 1 2 MVC MW CC Fdstk CO n n k

n  

## 

 (Eq. P-1)

Where: CO 2 = Annual CO 2 emissions arising from fuel and feedstock consumption (metric tons/yr). Fdstk n = Volume of the gaseous fuel and feedstock used in month n (scf (at standard conditions of Deleted: process

Deleted: process

Deleted: process

Deleted: process

Deleted: process190 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 feedstock (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. (2) Liquid fuel and feedstock. You must calculate the annual CO 2 emissions from each liquid fuel and feedstock according to Equation P-2 of this section: 001.0*) 12 44 ( 1 2 nn k

n CCFdstk CO  

## 

 (Eq. P-2) Where: CO 2 = Annual CO 2 emissions arising from fuel and feedstock consumption (metric tons/yr). Fdstk n = 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. Deleted: process191
(3) Solid fuel and feedstock. You must calculate the annual CO 2 emissions from each solid fuel and feedstock according to Equation P-3 of this section: 001.0*) 12 44 ( 1 2 nn k

n CCFdstk CO  

## 

 (Eq.P-3) Where: CO 2 = Annual CO 2 emissions from fuel and feedstock consumption in metric tons per month (metric tons/yr). Fdstk n = 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. 44/12 = Ratio of molecular weights, CO 2 to carbon. 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 Deleted: process192
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 facility must comply with the monitoring and QA/QC procedures specified in §98.34(c). (b) If a CEMS is not used to measure GHG emissions, then you must: (1) Calibrate all oil and gas flow meters (except for gas billing meters), solids weighing equipment, and oil tank drop measurements (if used to determine liquid fuel and feedstock use volume) according to the calibration accuracy requirements in §98.3(i) of this part. (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), weekly sampling and analysis is required to determine the carbon content and molecular weight of the fuel and feedstock.193
(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). (4) Determine the carbon content of coal, coke, and other solid fuels and feedstocks at least 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 D1946-90 (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).194
(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 Liquid 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 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). (viii) ASTM D4057-06 Standard Practice for Manual Sampling of Petroleum and Petroleum 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).195
(xi) 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). (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).196
(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: (1) Fuel and feedstock consumption, when solid fuel and feedstock is combusted and a CEMS is not 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 with these devices must also be recorded, and the technical basis for these estimates must be provided.197
§98.165 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), 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 production, 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 substitutedata value must be the arithmetic average of the qualityassured 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 be198
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. (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), each annual report must contain the information specified in paragraphs (a) or (b) of this section, as appropriate , and (c) and (d) : (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 Calculation Methodology and the following information in this paragraph (a): (1) Unit identification number and annual CO 2 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. Deleted: process199
(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 emissions. (2) Monthly consumption of each fuel and feedstock used for hydrogen production and its type (scf of gaseous 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) Q uantity of CO 2 collected and transferred off site in either gas, liquid, or solid forms, following the requirements of subpart PP of this part. Deleted: process Deleted:

Deleted: Quarterly q

Deleted: (kg)200
(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 Records 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. (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 Q—Iron and Steel Production** §98.170 Definition of the source category. The iron and steel production source category includes facilities with any of the following processes: taconite iron ore processing, integrated iron and steel manufacturing, cokemaking not colocated with an integrated201
iron and steel manufacturing process, and electric arc furnace (EAF) steelmaking not colocated with an integrated iron and steel manufacturing process. Integrated iron and steel manufacturing means the production of steel from iron ore or iron ore pellets. At a minimum, an integrated iron and steel manufacturing process has a basic oxygen furnace for refining molten iron into steel. Each cokemaking process and EAF process located at a facility with an integrated iron and steel manufacturing process is part of the integrated iron and steel manufacturing facility. §98.171 Reporting threshold. You must report GHG emissions under this subpart if your facility contains an iron and steel production process and the facility meets the requirements of either §98.2(a)(1) or (2). §98.172 GHGs to report. (a) 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 following the requirements of subpart C except for flares. Stationary combustion units include, but are not limited to, by-product recovery coke oven battery combustion stacks, blast furnace stoves, boilers, process heaters, reheat furnaces, annealing furnaces, flame suppression,202
ladle reheaters, and other miscellaneous combustion

sources. (b) You must report CO 2 emissions from flares that burn blast furnace gas or coke oven gas according to the procedures in §98.253(b)(1) of subpart Y (Petroleum Refineries) of this part . When using the alternatives set forth in §98.253(b)(1)(ii)(B) and §98.253(b)(1)(iii)(C),
you must use the default CO 2 emission factors for coke oven gas and blast furnace gas from Table C-1 of subpart C in Equation s Y- 2 and Y-3 of subpart Y of this part. You must report CH 4 and N 2 O emissions from flares according to the requirements in §98.33(c)(2) using the emission factors for coke oven gas and blast furnace gas in Table C-2 of subpart C of this part. (c) You must report process CO 2 emissions from eachtaconite indurating furnace; basic oxygen furnace; nonrecovery coke oven battery combustion stack; coke pushing process; sinter process; EAF; decarburization vessel; and direct reduction furnace by following the procedures in this subpart. §98.173 Calculating GHG emissions. You must calculate and report the annual process CO 2 emissions from each taconite indurating furnace, basic oxygen furnace, non-recovery coke oven battery, sinter Deleted: except you

Deleted: 1

Deleted: argon-oxygen203
process, EAF, decarburization vessel, and direct reduction furnace using the procedures in either paragraph (a) or (b) of this section. Calculate and report the annual process
CO 2 emissions from the coke pushing process according to paragraph (c) 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 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 the process CO 2 emissions using the procedure in paragraph (b)(1) or (b)(2) of this section. (1) Carbon mass balance method . Calculate the annual mass emissions of CO 2 for the process as specified in paragraphs (b)(1)(i) through (b)(1)(vii) of this section. The calculations are based on the annual mass of inputs and outputs to the process and an annual analysis of the respective weight fraction of carbon as determined according to the procedures in §98.174(b). If you have a process input or output other than CO 2 in the exhaust gas that contains carbon that is not included in Equations Q-1 through Q-7 of this section, you must account for the Deleted: argon-oxygen204
carbon and mass rate of that process input or output in your calculations according to the procedures in §98.174(b)(5). (i) For taconite indurating furnaces, estimate CO 2 emissions using Equation Q-1 of this section. 

##                 ]* * *001.0** 001.0***)(*)[(* 12 44 2

R p o lfl gf g CRCPCO CF MVC MW CFCF CO sf s

      (Eq. Q-1)

Where:

CO 2 = Annual CO 2 mass emissions from the taconite indurating furnace (metric tons). 44/12 = Ratio of molecular weights, CO 2 to carbon. (F s ) = Annual mass of the solid fuel combusted (metric tons). (C sf ) = Carbon content of the solid fuel, from the fuel analysis (percent by weight, expressed as a decimal fraction, e.g., 95% = 0.95). (F g ) = Annual volume of the gaseous fuel combusted (scf). (C gf ) = Average carbon content of the gaseous fuel, from the fuel analysis results (kg C per kg of fuel).MW = Molecular weight of the gaseous fuel (kg/kgmole). MVC = Molar volume conversion factor (849.5 scf per kg-mole at standard conditions). 0.001 = Conversion factor from kg to metric tons. (F l ) = Annual volume of the liquid fuel combusted (gallons). (C lf ) = Carbon content of the liquid fuel, from the fuel analysis results (kg C per gallon of fuel). (O) = Annual mass of greenball (taconite) pellets fed to the furnace (metric tons).205

(C 0 ) = Carbon content of the greenball (taconite) pellets, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (P) = Annual mass of fired pellets produced by the furnace (metric tons). (C p ) = Carbon content of the fired pellets, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (R) = Annual mass of air pollution control residue collected (metric tons). (C R ) = Carbon content of the air pollution control residue, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (ii) For basic oxygen process furnaces, estimate CO 2 emissions using Equation Q-2 of this section. 

##                        ]* * * * * * *[* 12 44 2

R Slag Steel Carbon Flux Scrap Iron CRCSlag CSteel CCarbon CFlux CScrap CIron CO

       (Eq. Q-2)

Where: CO 2 = Annual CO 2 mass emissions from the basic oxygen furnace (metric tons). 44/12 = Ratio of molecular weights, CO 2 to carbon. (Iron) = Annual mass of molten iron charged to the furnace (metric tons). (C Iron ) = Carbon content of the molten iron, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (Scrap) = Annual mass of ferrous scrap charged to the furnace (metric tons). (C Scrap ) = Carbon content of the ferrous scrap, from the carbon analysis results (percent by weight, expressed as a decimal fraction).206
(Flux) = Annual mass of flux materials (e.g., limestone, dolomite) charged to the furnace (metric tons). (C Flux ) = Carbon content of the flux materials, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (Carbon) = Annual mass of carbonaceous materials (e.g., coal, coke) charged to the furnace (metric tons). (C Carbon ) = Carbon content of the carbonaceous materials, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (Steel) = Annual mass of molten raw steel produced by the furnace (metric tons). (C Steel ) = Carbon content of the steel, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (Slag) = Annual mass of slag produced by the furnace (metric tons). (C Slag ) = Carbon content of the slag, from the carbon analysis (percent by weight, expressed as a decimal fraction). (R) = Annual mass of air pollution control residue collected (metric tons). (C R ) = Carbon content of the air pollution control residue, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (iii) For non-recovery coke oven batteries, estimate
CO 2 emissions using Equation Q-3 of this section. 

##            ]* * *[* 12 44 2 R Coke Coal CRCCoke CCoal CO

   (Eq. Q-3) Where: CO 2 = Annual CO 2 mass emissions from the nonrecovery coke oven battery (metric tons). 44/12 = Ratio of molecular weights, CO 2 to carbon.207
(Coal) = Annual mass of coal charged to the battery (metric tons). (C Coal ) = Carbon content of the coal, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (Coke) = Annual mass of coke produced by the battery (metric tons). (C Coke ) = Carbon content of the coke, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (R) = Annual mass of air pollution control residue collected (metric tons). (C R ) = Carbon content of the air pollution control residue, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (iv) For sinter processes, estimate CO 2 emissions using Equation Q-4 of this section. 

##              ]* *Sinter * 001.0***[* 12 44

Sinter 2

R Feed gf g CRC CFeed MVC MW CF CO

    (Eq. Q-4)

Where:

CO 2 = Annual CO 2 mass emissions from the sinter process (metric tons). 44/12 = Ratio of molecular weights, CO 2 to carbon. (F g ) = Annual volume of the gaseous fuel combusted (scf). (C gf ) = Carbon content of the gaseous fuel, from the fuel analysis results (kg C per kg of fuel).MW = Molecular weight of the gaseous fuel (kg/kgmole). MVC = Molar volume conversion factor (849.5 scf per kg-mole at standard conditions). 0.001 = Conversion factor from kg to metric tons.208
(Feed) = Annual mass of sinter feed material (metric tons). (C Feed ) = Carbon content of the mixed sinter feed materials that form the bed entering the sintering machine, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (Sinter) = Annual mass of sinter produced (metric tons). (C Sinter ) = Carbon content of the sinter pellets, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (R) = Annual mass of air pollution control residue collected (metric tons). (C R ) = Carbon content of the air pollution control residue, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (v) For EAFs, estimate CO 2 emissions using Equation Q5 of this section. 

##                           R Slag Steel c Electrode f Scrap Iron
CRCSlag C SteelC Carbon C Electrode C Flux CScrap CIron CO

* * * * * * * *[* 12 44 2

        (Eq. Q-5)

Where: CO 2 = Annual CO 2 mass emissions from the EAF (metric tons). 44/12 = Ratio of molecular weights, CO 2 to carbon. (Iron) = Annual mass of direct reduced iron (if any) charged to the furnace (metric tons). (C Iron ) = Carbon content of the direct reduced iron, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (Scrap) = Annual mass of ferrous scrap charged to the furnace (metric tons).209

(C Scrap ) = Carbon content of the ferrous scrap, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (Flux) = Annual mass of flux materials (e.g., limestone, dolomite) charged to the furnace (metric tons). (C Flux ) = Carbon content of the flux materials, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (Electrode) = Annual mass of carbon electrode consumed (metric tons). (C Electrode ) = Carbon content of the carbon electrode, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (Carbon) = Annual mass of carbonaceous materials (e.g., coal, coke) charged to the furnace (metric tons). (C Carbon ) = Carbon content of the carbonaceous materials, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (Steel) = Annual mass of molten raw steel produced by the furnace (metric tons). (C Steel ) = Carbon content of the steel, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (Slag) = Annual mass of slag produced by the furnace (metric tons). (C Slag ) = Carbon content of the slag, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (R) = Annual mass of air pollution control residue collected (metric tons). (C R ) = Carbon content of the air pollution control residue, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (vi) For decarburization vessels, estimate CO 2 emissions using Equation Q-6 of this section. Deleted: argon-oxygen210 

##          R Steelout Steelin CR CCSteel CO *] [** 12 44 2    (Eq. Q-6) Where: CO 2 = Annual CO 2 mass emissions from the decarburization vessel (metric tons). 44/12 = Ratio of molecular weights, CO 2 to carbon. (Steel) = Annual mass of molten steel charged to the vessel (metric tons). (C Steelin ) = Carbon content of the molten steel before decarburization, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (C Steelout ) = Carbon content of the molten steel after decarburization, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (R) = Annual mass of air pollution control residue collected (metric tons). (C R ) = Carbon content of the air pollution control residue, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (vii) For direct reduction furnaces, estimate CO 2 emissions using Equation Q-7 of this section. 

##                        ]* * * * * 001.0***[* 12 44 2

R NM Iron Other Carbon Ore gfg

CRCNM CIron COther C Carbon COre MVC MW CF CO

   

   (Eq. Q-7)

Where: CO 2 = Annual CO 2 mass emissions from the direct reduction furnace (metric tons). 44/12 = Ratio of molecular weights, CO 2 to carbon. (F g ) = Annual volume of the gaseous fuel combusted (scf). Deleted: argon-oxygen211

(C gf ) = Carbon content of the gaseous fuel, from the fuel analysis results (kg C per kg of fuel).MW = Molecular weight of the gaseous fuel (kg/kgmole). MVC = Molar volume conversion factor (849.5 scf per kg-mole at standard conditions). 0.001 = Conversion factor from kg to metric tons. (Ore) = Annual mass of iron ore or iron ore pellets fed to the furnace (metric tons). (C Ore ) = Carbon content of the iron ore or iron ore pellets, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (Carbon) = Annual mass of carbonaceous materials (e.g., coal, coke) charged to the furnace (metric tons). (C Carbon ) = Carbon content of the carbonaceous materials, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (Other) = Annual mass of other materials charged to the furnace (metric tons). (C Other ) = Average carbon content of the other materials charged to the furnace, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (Iron) = Annual mass of iron produced (metric tons). (C Iron ) = Carbon content of the iron, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (NM) = Annual mass of non-metallic materials produced by the furnace (metric tons). (C NM ) = Carbon content of the non-metallic materials, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (R) = Annual mass of air pollution control residue collected (metric tons). (C R ) = Carbon content of the air pollution control residue, from the carbon analysis results212
(percent by weight, expressed as a decimal fraction). (2) Site-specific emission factor method. Conduct a performance test and measure CO 2 emissions from all exhaust stacks for the process and measure either the feed rate of materials into the process or the production rate during the test as described in paragraphs (b)(2)(i) through (b)(2)(iv) of this section. (i) You must measure the process production rate or process feed rate, as applicable, during the performance test according to the procedures in §98.174(c)(5) and calculate the average rate for the test period in metric tons per hour. (ii) You must calculate the hourly CO 2 emission rate using Equation Q-8 of this section and determine the average hourly CO 2 emission rate for the test.      

   100 %100 ***1018.5 2 2 7 2 OH QCx CO CO (Eq. Q-8)
Where: CO 2 = CO 2 mass emission rate, corrected for moisture (metric tons/hr). 5.18 x 10 -7 = Conversion factor (metric tons/scf-% CO 2 ). C CO2 = Hourly CO 2 concentration, dry basis (% CO 2 ). Q = Hourly stack gas volumetric flow rate (scfh). %H 2 O = Hourly moisture percentage in the stack gas. (iii) You must calculate a site-specific emission factor for the process in metric tons of CO 2 per metric ton213
of feed or production, as applicable, by dividing the average hourly CO 2 emission rate during the test by the average hourly feed or production rate during the test. (iv) You must calculate CO2 emissions for the process by multiplying the emission factor by the total amount of feed or production, as applicable, for the reporting period. (c) You must determine emissions of CO 2 from the coke pushing process in mtCO 2 e by multiplying the metric tons of coal charged to the coke ovens during the reporting period by 0.008. (d) If GHG emissions from a taconite indurating furnace, basic oxygen furnace, non-recovery coke oven battery, sinter process, EAF, decarburization vessel, or direct reduction furnace 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 Deleted: argon-oxygen214
in subpart C of this part (General Stationary Fuel Combustion Sources). §98.174 Monitoring and QA/QC requirements. (a) If you operate and maintain a CEMS that measures
CO 2 emissions consistent with subpart C of this part, you must meet the monitoring and QA/QC requirements of §98.34(c). (b) If you determine CO 2 emissions using the carbon mass balance procedure in §98.173(b)(1), you must: (1) Except as provided in paragraph (b)(4) of this section, determine the mass of each process input and output other than fuels using the same plant instruments or procedures that are used for accounting purposes (such as weigh hoppers, belt weigh feeders, weighed purchased quantities in shipments or containers, combination of bulk density and volume measurements, etc.), record the totals for each process input and output for each calendar month, and sum the monthly mass to determine the annual mass for each process input and output. Determine the mass rate of fuels using the procedures for combustion units in §98.34. (2) Except as provided in paragraph (b)(4) of this section, determine the carbon content of each process input and output annually for use in the applicable equations in §98.173(b)(1) based on analyses provided by the supplier or215
by the average carbon content determined by collecting and analyzing at least three samples each year using the standard methods specified in paragraphs (b)(2)(i) through (b)(2)(vi) of this section as applicable. (i) ASTM C25-06, Standard Test Methods for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime (incorporated by reference, see §98.7) for limestone, dolomite, and slag. (ii) 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) for coal, coke, and other carbonaceous materials. (iii) ASTM E1915-07a, Standard Test Methods for Analysis of Metal Bearing Ores and Related Materials by Combustion Infrared-Absorption Spectrometry (incorporated by reference, see §98.7) for iron ore, taconite pellets, and other iron-bearing materials. (iv) 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 (incorporated by reference, see §98.7) for iron and ferrous scrap.216
(v) ASM CS-104 UNS No. G10460 - Alloy Digest April 1985 (Carbon Steel of Medium Carbon Content) (incorporated by reference, see §98.7); 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 (incorporated by reference, see §98.7); or 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 (incorporated by reference, see §98.7) as applicable for steel. (vi) For each process input that is a fuel, determine the carbon content and molecular weight (if applicable) using the applicable methods listed in §98.34. (3) For solid ferrous materials charged to basic oxygen process furnaces or EAFs that differ in carbon content, you may determine a weighted average carbon content based on the carbon content of each type of ferrous material and the average weight percent of each type that is used. Examples of these different ferrous materials include carbon steel, low carbon steel, stainless steel, high alloy steel, pig iron, iron scrap, and direct reduced iron.217
(4) If you document that a specific process input or output contributes less than one percent of the total mass of carbon into or out of the process, you do not have to determine the monthly mass or annual carbon content of that input or output. (5) Except as provided in paragraph (b)(4) of this section, you must determine the annual carbon content and monthly mass rate of any input or output that contains carbon that is not listed in the equations in §98.173(b)(1) using the procedures in paragraphs (b)(1) and (b)(2) of this section. (c) If you determine CO 2 emissions using the sitespecific emission factor procedure in §98.173(b)(2), you
must: (1) Conduct an annual performance test that is based on representative performance (i.e., performance based on normal operating conditions) of the affected process. (2) For the furnace exhaust from basic oxygen furnaces, EAFs, decarburization vessels, and direct reduction furnaces, sample the furnace exhaust for at least three complete production cycles that start when the furnace is being charged and end after steel or iron and slag have been tapped. For EAFs that produce both carbon steel and stainless or specialty (low carbon) steel, Deleted: argon-oxygen218
develop an emission factor for the production of both types of steel. (3) For taconite indurating furnaces, non-recovery coke batteries, and sinter processes, sample for at least 3 hours. (4) Conduct the stack test using EPA Method 3A at 40 CFR part 60, appendix A-2 to measure the CO 2 concentration, Method 2, 2A, 2C, 2D, or 2F at 40 CFR part 60, appendix A-1 or Method 26 at 40 CFR part 60, appendix A-2 to determine the stack gas volumetric flow rate, and Method 4 at 40 CFR part 60, at appendix A-3 to determine the moisture content of the stack gas. (5) Determine the mass rate of process feed or process production (as applicable) during the test using the same plant instruments or procedures that are used for accounting purposes (such as weigh hoppers, belt weigh feeders, combination of bulk density and volume measurements, etc.) (6) If your process operates under different conditions as part of normal operations in such a manner that CO 2 emissions change by more than 20 percent (e.g., routine changes in the carbon content of the sinter feed or change in grade of product), you must perform emission testing and develop separate emission factors for these219
different operating conditions and determine emissions based on the number of hours the process operates and the production or feed rate (as applicable) at each specific different condition. (7) If your EAF and decarburization vessel exhaust to a common emission control device and stack, you must sample each process in the ducts before the emissions are combined, sample each process when only one process is operating, or sample the combined emissions when both processes are operating and base the site-specific emission factor on the steel production rate of the EAF. (8) The results of a performance test must include the analysis of samples, determination of emissions, and raw data. The performance test report must contain all information and data used to derive the emission factor. (d) For a coke pushing process, determine the metric tons of coal charged to the coke ovens and record the totals for each pushing process for each calendar month. Coal charged to coke ovens can be measured using weigh belts or a combination of measuring volume and bulk density. §98.175 Procedures for estimating missing data. A complete record of all measured parameters used in the GHG emissions calculations in §98.173 is required. Deleted: argon-oxygen220
Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter shall be used in the calculations as specified in the paragraphs (a) and (b) of this section. You must follow the missing data procedures in §98.255(b) of subpart Y (Petroleum Refineries) of this part for flares burning coke oven gas or blast furnace gas. You must document and keep records of the procedures used for all such estimates. (a) For each missing data for the carbon content of inputs and outputs for facilities that estimate emissions using the carbon mass balance procedure in §98.173(b)(1) orfor facilities that estimate emissions using the sitespecific emission factor procedure in §98.173(b)(2); 100 percent data availability is required. You must repeat the test for average carbon contents of inputs and outputs according to the procedures in §98.174(b)(2). Similarly, you must repeat the test to determine the site-specific emission factor if data on the CO 2 emission rate, process production rate or process feed rate are missing. (b) For missing records of the monthly mass or volume of carbon-containing inputs and outputs using the carbon mass balance procedure in §98.173(b)(1), the substitute data value must be based on the best available estimate of221
the mass of the input or output material from all available process data or data used for accounting purposes. §98.176 Data reporting requirements. In addition to the information required by §98.3(c), each annual report must contain the information required in paragraphs (a) through ( h ) of this section for each coke pushing operation; taconite indurating furnace; basic oxygen furnace; non-recovery coke oven battery; sinter process; EAF; decarburization vessel; direct reduction furnace ; and flare burning coke oven gas or blast furnace
gas : (a) Unit identificatin number and annual CO 2 emissions (in metric tons. (b) Annual production quantity (in metric tons) for taconite pellets, coke, sinter, iron, and raw steel. (c) 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. (d) If a CEMS is not used to measure CO 2 emissions, then you must report for each process whether the emissions were determined using the carbon mass balance method in §98.173(b)(1) or the site-specific emission factor method in §98.173(b)(2). Deleted: f

Deleted: argon-oxygen Deleted: and

Deleted: 7222
(e) If you use the carbon mass balance method in §98.173(b)(1) to determine CO 2 emissions, you must report the following information for each process: (1) The carbon content of each process input and output used to determine CO 2 emissions. (2) Whether the carbon content was determined from information from the supplier or by laboratory analysis, and if by laboratory analysis, the method used. (3) The annual volume of each type of gaseous fuel ( reported separately for each type in standard cubic feet), the annual volume of each type of liquid fuel ( reported separately for each type in gallons), and the annual mass (in metric tons) of each other process inputs and outputs used to determine CO 2 emissions. (4) The molecular weight of gaseous fuels. (5) If you used the missing data procedures in §98.175(b), you must report how the monthly mass for each process input or output with missing data was determined and the number of months the missing data procedures were used. (f) If you used the site-specific emission factor method in §98.173(b)(2) to determine CO 2 emissions, you must report the following information for each process: Deleted: all223
(1) The measured average hourly CO 2 emission rate during the test(in metric tons per hour). (2) The average hourly feed or production rate (as applicable) during the test (in metric tons per hour). (3) The site-specific emission factor (in metric tons of CO 2 per metric ton of feed or production, as applicable). (4) The annual feed or production rate (as applicable) used to estimate annual CO 2 emissions (in metric tons). (g) The annual amount of coal charged to the coke ovens (in metric tons). (h) For flares burning coke oven gas or blast furnace gas, the information specified in §98.256(e) of subpart Y (Petroleum Refineries) of this part. §98.177 Records that must be retained. In addition to the records required by §98.3(g), you must retain the records specified in paragraphs (a) through (e) of this section, as applicable. Facilities that use CEMS to measure emissions must also retain records of the verification data required for the Tier 4 Calculatin Methodology in §98.36(e). (a) Records of all analyses and calculations conducted, including all information reported as required under §98.176.224
(b) When the carbon mass balance method is used to estimate emissions for a process, the monthly mass of each process input and output that are used to determine the annual mass. (c) Production capacity (in metric tons per year) for the production of taconite pellets, coke, sinter, iron, and raw steel. (d) Annual operating hours for each taconite indurating furnace, basic oxygen furnace, non-recovery coke oven batter y , sinter pro cess, electric arc furnace , decarburization vessel, and direct reduction furnace
. (e) Facilities must keep records that include a detailed explanation of how company records or measurements are used to determine all sources of carbon input and output and the metric tons of coal charged to the coke ovens (e.g., weigh belts, a combination of measuring volume and bulk density). You also must document the procedures used to ensure the accuracy of the measurements of fuel usage including, but not limited to, calibration of weighing equipment, fuel flow meters, coal usage including, but not limited to, calibration of weighing equipment and other measurement devices. The estimated accuracy of measurements made with these devices must also be recorded, Deleted: s

Deleted: ies Deleted: duction, blast furnaces, direct reduced iron furnaces, and Deleted: s225

and the technical basis for these estimates must be provided. §98.178 Definitions. All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. **Subpart S—Lime Manufacturing** §98.190 Definition of the source category. (a) Lime manufacturing plants (LMPs) engage in themanufacture of a lime product (e.g., calcium oxide, highcalcium quicklime, calcium hydroxide, hydrated lime, dolomitic quicklime, dolomitic hydrate, or other lime products) by calcination of limestone, dolomite, shells or other ca l careous substances as defined in 40 CFR 63.7081(a)(1). (b) This source category includes all LMPs unless the LMP is located at a kraft pulp mill, soda pulp mill, sulfite pulp mill, or only processes sludge containing calcium carbonate from water softening processes. The limemanufacturing source category consists of marketed and nonmarketed lime manufacturing facilities. (c) Lime kilns at pulp and paper manufacturing facilities must report emissions under subpart AA of this part (Pulp and Paper Manufacturing). §98.191 Reporting threshold.226
You must report GHG emissions under this subpart if your facility is a lime manufacturing plant as defined in §98.190 and the facility meets the requirements of either §98.2(a)(1) or (a)(2). §98.192 GHGs to report. You must report: (a) CO 2 process emissions from lime kilns. (b) CO 2 emissions from fuel combustion at lime kilns. (c) N 2 O and CH 4 emissions from fuel combustion at each lime kiln. You must report these emissions under 40 CFR part 98, subpart C (General Stationary Fuel Combustion Sources). (d) CO 2 , N 2 O, and CH 4 emissions from each stationary fuel combustion unit other than lime kilns. You must report these emissions under 40 CFR part 98, subpart C (General Stationary Fuel Combustion Sources). (e) CO 2 collected and transferred off site under 40 CFR part 98, following the requirements of subpart PP of this part (Suppliers of Carbon Dioxide (CO 2 )). §98.193 Calculating GHG emissions. You must calculate and report the annual process CO 2 emissions from all lime kilns combined using the procedure in paragraphs (a) and (b) of this section.227
(a) If all lime kilns meet the conditions specified in §98.33(b)(4)(ii) or (b)(4)(iii), you must calculate and report under this subpart the combined process and combustion CO 2 emissions by operating and maintaining a CEMS
to measure CO 2 emissions 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) If CEMS are not required to be used to determine
CO 2 emissions from all lime kilns under paragraph (a) of this section, then you must calculate and report the process and combustion CO 2 emissions from the lime kilns by using the procedures in either paragraph (b)(1) or (b)(2) of this section. (1) Calculate and report under this subpart the combined process and combustion CO 2 emissions by operating and maintaining a CEMS to measure CO 2 emissions from all lime kilns 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). (2) Calculate and report process and combustion CO 2 emissions separately using the procedures specified in paragraphs (b)(2)(i) through (b)(2)(v) of this section.228
(i) You must calculate a monthly emission factor for each type of lime produced using Equation S-1 of this section. Calcium oxide and magnesium oxide content must be analyzed monthly for each lime product type that is produced : 

#   2205 2000 *) () (

, , ,, ni MgO ni CaO niLIME MgO SR CaOSR EF  (Eq. S-1) Where: EF LIME,i,n = Emission factor for lime type i, for month n (metric tons CO 2 /ton lime). SR CaO = Stoichiometric ratio of CO 2 and CaO for calcium carbonate [see Table S-1 of this subpart] (metric tons CO 2 /metric tons CaO). SR MgO = Stoichiometric ratio of CO 2 and MgO for magnesium carbonate (See Table S-1 of this subpart) (metric tons CO 2 /metric tons MgO). CaO i,n = Calcium oxide content for lime type i, for month n, determined according to §98.194(c) (metric tons CaO/metric ton lime). MgO i,n = Magnesium oxide content for lime type i, for month n, determined according to §98.194(c) (metric tons MgO/metric ton lime). 2000/2205 = Conversion factor for tons to metric tons. (ii) You must calculate a monthly emission factor for each type of calcined byproduct/waste sold (including lime kiln dust) using Equation S-2 of this section: 

#   2205 2000 *) () (

,, ,, ,, niLKD MgO niLKD CaO niLKD MgO SR CaO SR EF   (Eq. S-2) Where: EF LKD,i,n = Emission factor for calcined lime byproduct/waste type i sold , for month n (metric tons CO 2 /ton lime byproduct). Deleted: metric

Deleted: sold229

SR CaO = Stoichiometric ratio of CO 2 and CaO for calcium carbonate (see Table S-1 of this subpart( (metric tons CO 2 /metric tons CaO). SR MgO = Stoichiometric ratio of CO 2 and MgO for magnesium carbonate (See Table S-1 of this subpart) (metric tons CO 2 /metric tons MgO). CaO LKD,i,n = Calcium oxide content for calcined lime byproduct/waste type i sold , for month n (metric tons CaO/metric ton lime). MgO LKD,i,n = Magnesium oxide content for calcined lime byproduct/waste type i sold , for month n (metric tons MgO/metric ton lime). 2000/2205 = Conversion factor for tons to metric tons. (iii) You must calculate the annual CO 2 emissions from each type of calcined byproduct/waste that is not sold (including lime kiln dust and scrubber sludge) using Equation S-3 of this section: 

#   2205 2000 **) () (

, , , , iwaste iwaste MgO iwaste CaO iwaste M MgO SR CaO SR E    

##  (Eq. S-3)

Where: E waste,i = Annual CO 2 emissions for calcined lime byproduct/waste type i that is not sold (metric tons CO 2 ). SR CaO = Stoichiometric ratio of CO 2 and CaO for calcium carbonate (see Table S-1 of this subpart) (metric tons CO 2 /metric tons CaO). SR MgO = Stoichiometric ratio of CO 2 and MgO for magnesium carbonate (See Table S-1 of this subpart) (metric tons CO 2 /metric tons MgO). CaO waste,i = Calcium oxide content for calcined lime byproduct/waste type i that is not sold (metric tons CaO/metric ton lime). MgO waste,i = Magnesium oxide content for calcined lime byproduct/waste type i that is not sold (metric tons MgO/metric ton lime). Deleted: sold

Deleted: sold Deleted:

Deleted: metric

Deleted: unsold

Deleted: unsold

Deleted: unsold230

M waste,i = Annual weight or mass of calcined byproducts/wastes for lime type i that is not sold (tons). 2000/2205 = Conversion factor for tons to metric tons.

(iv) You must calculate annual CO 2 process emissions for all kilns using Equation S-4 of this section: 

##    

        z

i iwaste t

i b

i n niLKD niLKD niLIME n niLIME CO E M EF M EF E 1 , 1 1 12

1 ,, ,, ,, 12

1 ,, ) ) ( 2 (Eq. S-4)
Where: E CO2 = Annual CO 2 process emissions from lime production from all kilns (metric tons/year). EF LIME,i,n = Emission factor for lime type i produced , in calendar month n (metric tons CO 2 /ton lime) from Equation S-1 of this section. M LIME,i,n = Weight or mass of lime type i produced in calendar month n (tons). EF LKD,i,n = Emission factor of calcined byproducts/wastes sold for lime type i in calendar month n, (metric tons CO 2 /ton byproduct/waste) from Equation S-2 of this section. M LKD,i,n = Monthly weight or mass of calcined byproducts/waste sold (such as lime kiln dust, LKD) for lime type i in calendar month n (tons). E waste,i = Annual CO 2 emissions for calcined lime byproduct/waste type i that is not sold (metric tons CO 2 ) from Equation S-3 of this section. t = Number of lime types produced b = Number of calcined byproducts/wastes that are sold z = Number of calcined byproducts/wastes that are not sold Deleted: unsold

Deleted: metric

Deleted: unsold231
(v) Calculate and report under subpart C of this part (General Stationary Fuel Combustion Sources) the combustion
CO 2 emissions from each lime kiln according to the applicable requirements in subpart C. §98.194 Monitoring and QA/QC requirements. (a) You must determine the total quantity of each type of lime product that is produced and each calcined byproduct/waste (such as lime kiln dust) that is sold. The quantities of each should be directly measured monthly with the same plant instruments used for accounting purposes, including but not limited to, calibrated weigh feeders, rail or truck scales, and barge measurements. The direct measurements of each lime product shall be reconciled annually with the difference in the beginning of and end of year inventories for these products, when measurements represent lime sold. (b) You must determine the annual quantity of each calcined byproduct/waste generated that is not sold by either direct measurement using the same instruments identified in paragraph (a) of this section or by using a calcined byproduct/waste generation rate. (c) You must determine the chemical composition (percent total CaO and percent total MgO) of each type of lime product that is produced and each type of calcined Deleted: type of lime232 byproduct/waste sold according to paragraph (c)(1) or (c)(2) of this section. You must determine the chemical composition of each type of lime product that is produced and each type of calcined byproduct/waste sold on a monthly basis. You must determine the chemical composition for each type of calcined byproduct/waste that is not sold on an annual basis. (1) ASTM C25-06 Standard Test Methods for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime (incorporated by reference-see §98.7). (2) The National Lime Association’s CO 2 Emissions Calculation Protocol for the Lime Industry English Units Version, February 5, 2008 Revision-National Lime Association (incorporated by reference see §98.7). (d) You must use the analysis of calcium oxide and magnesium oxide content of each lime product that is produced and that is collected during the same month as the production data in monthly calculations. (e) You must follow the quality assurance/quality control procedures (including documentation) in National Lime Association’s CO 2 Emissions Calculation Protocol for the Lime Industry-English Units Version, February 5, 2008 Revision-National Lime Association (incorporated by reference see §98.7).233
§98.195 Procedures for estimating missing data. For the procedure in §98.193(b)( 1 ), a complete record of all measured parameters used in the GHG emissions calculations is required (e.g., oxide content, quantity oflime products, etc.). Therefore, whenever a qualityassured value of a required parameter is unavailable, a substitute data value for the missing parameter shall be used in the calculations as specified in paragraphs (a) or (b) of this section. You must document and keep records of the procedures used for all such estimates. (a) For each missing value of the quantity of lime produced (by lime type), and quantity of calcined byproduct/waste produced and sold, the substitute data value shall be the best available estimate based on all available process data or data used for accounting
purposes. (b) For missing values related to the CaO and MgO content, you must conduct a new composition test according to the standard methods in §98.194 (c)(1) or (c)(2). §98.196 Data reporting requirements. In addition to the information required by §98.3(c), each annual report must contain the information specified in paragraphs (a) or (b) of this section, as applicable. Deleted: 2234
(a) If a CEMS is used to measure CO 2 emissions, then you must report under this subpart the relevant information required by §98.36 and the information listed in paragraphs (a)(1) through (a)(8) of this section. (1) Method used to determine the quantity of lime that is produced and sold. (2) Method used to determine the quantity of calcined lime byproduct/waste sold. (3) Beginning and end of year inventories for each lime product that is produced, by type
. (4) Beginning and end of year inventories for calcined lime byproducts/wastes sold, by type
. (5) Annual amount of calcined lime byproduct/waste sold, by type (tons). (6) Annual amount of lime product sold, by type (tons). (7) Annual amount of calcined lime byproduct/waste that is not sold, by type (tons). (8) Annual amount of lime product not sold, by type (tons). (b) If a CEMS is not used to measure CO 2 emissions, then you must report the information listed in paragraphs (b)(1) through (b)(17) of this section.235
(1) Annual CO 2 process emissions from all kilns combined (metric tons). (2) Monthly emission factors for each lime type produced
. (3) Monthly emission factors for each calcined byproduct/waste by lime type that is sold
. (4) Standard method used (ASTM or NLA testing method) to determine chemical compositions of each lime type produced and each calcined lime byproduct/waste type. (5) Monthly results of chemical composition analysis of each type of lime product produced and calcined byproduct/waste sold. (6) Annual results of chemical composition analysis of each type of lime byproduct/waste that is not sold. (7) Method used to determine the quantity of lime produced and/or lime sold. (8) Monthly amount of lime product sold, by type (tons). (9) Method used to determine the quantity of calcined lime byproduct/waste sold. (10) Monthly amount of calcined lime byproduct/waste sold, by type (tons). (11) Annual amount of calcined lime byproduct/waste that is not sold , by type (tons). Deleted: sold236
(12) Monthly weight or mass of each lime type produced (tons). (13) Beginning and end of year inventories for each lime product that is produced
. (14) Beginning and end of year inventories for calcined lime byproducts/wastes sold
. (15) Annual lime production capacity (tons) per facility. (16) Number of times in the reporting year that missing data procedures were followed to measure lime production (months) or the chemical composition of lime products sold (months). (17) Indicate whether CO 2 was used on-site (i.e. for use in a purification process). If CO 2 was used on-site, provide the information in paragraphs (b)(17)(i) and (b)(17)(ii) of this section. (i) The annual amount of CO 2 captured for use in the on-site process. (ii) The method used to determine the amount of CO 2 captured. §98.197 Records that must be retained. In addition to the records required by §98.3(g), you must retain the records specified in paragraphs (a) and (b) of this section.237
(a) Annual operating hours in calendar year. (b) Records of all analyses (e.g. chemical composition of lime products, by type) and calculations conducted. §98.198 Definitions. All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. **Table S-1 of Subpart S—Basic Parameters for the Calculation of Emission Factors for Lime Production**  Variable Stoichiometric ratio SR CaO 0.7848 SR MgO 1.0918 **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.238
(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 must 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 ( i ) of this section. (2) Request 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 for the current reporting period using the procedures specified in paragraph (a)(1) of this section. Deleted: h

Deleted: factor239
(b) You must conduct an annual performance test for each nitric acid train according to paragraphs (b)(1) through (b)(3) of this section. (1) You must conduct the performance test at the absorber tail gas vent , referred to as the test point, for each nitric acid train according to §98.224(b) through ( f ). (2) You must conduct the performance test under normal process operating conditions. (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) Using the results of the performance test in paragraph (b) of this section, you must calculate an average site-specific emission factor for each nitric acid train “t” according to Equation V-1 of this section:

n P Q C EF n ON

OtN 

##  

 

1 7 2

2 1014.1 (Eq. V-1) Where: EF N2Ot = 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). C N2O = N 2 O concentration for each test run during the performance test (ppm N 2 O). 1.14x10 -7 = Conversion factor (lb/dscf-ppm N 2 O). Q = Volumetric flow rate of effluent gas for each test run during the performance test (dscf/hr). Deleted: measure N 2 O emissions from

Deleted: using the methods specified in Deleted: d

Deleted: and without using N 2 O abatement technology (if applicable)

Deleted: 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) of 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)240
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 nitric acid train “t” exhausts to any N 2 O abatement technology “N” after the test point , you must determine the destruction efficiency for each N 2 O abatement technology “N” according to paragraphs (d)(1), (d)(2), or (d)(3) of this section. (1) Use the manufacturer’s specified destruction efficiency. (2) Estimate 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 relevant to the current vent stream conditions. You must document how 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 nitric acid train “t” exhausts to any N 2 O abatement technology “N” after the test point , you must determine the annual amount of nitric acid produced on Deleted: applicable

Deleted: applicable241

train “t” while N 2 O abatement technology “N” is operating according to §98.224(f). Then you must calculate the abatement utilization factor for each N 2 O abatement technology “N” for each nitric acid train “t” according to Equation V-2 of this section.

ta Nta Nt P P AF

, ,,

,  (Eq. V-2)

Where: AF t,N = Abatement utilization factor of N 2 O abatement technology “N” 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 ,N = Annual nitric acid production from nitric acid train “t” during which N 2 O abatement technology “N” was operational (ton acid produced, 100 percent acid basis). (f) [Reserved] (g) You must calculate N 2 O emissions for each nitric acid train “t” according to paragraph (g)(1) or (g)(2) of this section. (1) If nitric acid train “t” exhausts to any N 2 O abatement technology “N” after the test point, you must use the emissions factor (determined in Equation V-1 of this section) , the destruction efficiency (determined in paragraph (d) of this section), the annual nitric acid production (determined in paragraph (i) of this section), Deleted: g

Deleted:

. Deleted: The abatement factor is calculated

Deleted: N Deleted: t

Deleted: Deleted: Abate Deleted: used

Deleted: You must determine the annual amount of nitric acid produced 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).

Deleted: by multiplying

Deleted: by

Deleted: e242
and the abatement utilization factor (determined in paragraph (e) of this section) according to Equation V-3 a of this section: 

## 

   z

N NtNt tatN OtN AFDF PEF E 1 , , ,20 2205 ))*(1(**

2 (Eq. V-3 a )

Where: E N2Ot = N 2 O mass emissions per year for nitric acid train “t” (metric tons). EF N2Ot = 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). DF t ,N = 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). AF t ,N = Abatement utilization factor of N 2 O abatement technology “N” for nitric acid train “t” (fraction of annual production that N 2 O abatement technology is operating). 2204.63 = Conversion factor (lb/metric ton). z = Number of N 2 O abatement technologies on nitric acid train “t”
. (2) If nitric acid train “t” does not exhaust to any
N 2 O abatement technology after the test point, you must use the emissions factor (determined in Equation V-1 of this section), and the annual nitric acid production (determinedin paragraph (i) of this section) according to Equation V3b of this section:

2205 * ,20
2 tatN OtN PEF E  (Eq. V-3b) Deleted: f Deleted: the annual nitric acid production and accounting for N 2 O abatement,

Deleted: N

Deleted: N

Deleted: different

Deleted: e243

Where: E N2Ot = N 2 O mass emissions per year for nitric acid train “t” (metric tons). EF N2Ot = 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 nitric acid train “t” (ton acid produced, 100 percent acid basis). 2205 = Conversion factor (lb/metric ton). (h) You must determine the annual nitric acid production emissions combined from all nitric acid trains at your facility using Equation V-4 of this section: 

## 

  m

t OtN EON 1 2 2 (Eq. V-4)

Where: N 2 O = Annual process N 2 O emissions from nitric acid production facility (metric tons) E N2Ot = N 2 O mass emissions per year for nitric acid train “t” (metric tons). m = Number of nitric acid trains.
(i) You must determine the total annual amount of nitric acid produced on nitric acid train “t” for each nitric acid train (tons acid produced, 100 percent acid basis), according to §98.224(f). §98.224 Monitoring and QA/QC requirements. (a) You must conduct a new performance test according to a test plan as specified in paragraphs (a)(1) through (a)(3) of this section. Deleted: g Deleted:

Deleted: and calculate a new site-specific emissions factor244
(1) Conduct the performance test annually. The test should be conducted at a point during the campaign which is representative of the average emissions over the entire campaign. Facilities must document the methods used to determine the representative point of the campaign when the performance test is conducted. (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 determining N 2 O emissions 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 Emissions by Extractive Fourier Transform Infrared (FTIR) Spectroscopy. (2) ASTM D6348-03 Standard Test Method for Determination of Gaseous Compounds by Extractive Direct Deleted: concentration245
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 concentration (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 determine the volumetric flow rate during the performance test 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 specifications apply. For each test, the facility must prepare an emission factor determination report that must include the items in paragraphs (d)(1) through (d)(3) of this section. Deleted: conduct all performance tests246
(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 run and how it was determined. (e) You must determine the total monthly amount of nitric acid produc ed and the monthly amount of nitric acid produc ed while N 2 O abatement technology (located after the test point) 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 amount of nitric acid produc ed and the annual amount of nitric acid produc ed while N 2 O abatement technology (located after the test point) is operating for each train by summing the respective monthly nitric acid quantities determined in paragraph (e) of this section
. §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 missing Deleted: tion

Deleted: tion Deleted: during which

Deleted: tion Deleted: tion Deleted: during which

Deleted: production

Deleted: f247
parameter shall be used in the calculations as specified in paragraphs (a) and (b) of this section. (a) For each missing value of nitric acid 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 contain the information specified in paragraphs (a) through (o) of this section. (a) Train identification number. (b) Annual process N 2 O emissions from each nitric acid train (metric tons). (c) Annual nitric acid production 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)
. (e) Annual nitric acid production from the nitric acid facility (tons, 100 percent acid basis). Deleted: for each nitric acid production train248
(f) Number of nitric acid trains. (g) Number of different N 2 O abatement technologies per nitric acid train “t”
. (h) Abatement technologies used (if applicable). (i) Abatement technology destruction efficiency for 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 according to §98.223(a)(1), each annual report must also contain the information specified in paragraphs (m)(1) through (m)(7) of this section. (1) Emission factor calculated for each nitric acid train (lb N 2 O/ ton nitric acid, 100 percent acid basis). (2) Test method used for performance test. Deleted: (if applicable)

Deleted: for each nitric acid production facility249
(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 emissions 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. (o) Total pounds of synthetic fertilizer produced through and total nitrogen contained in that fertilizer. §98.227 Records that must be retained. In addition to the information required by §98.3(g), you must retain the records specified in paragraphs (a) Deleted: concentration250
through (g) of this section for each nitric acid production facility: (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, calibration 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 Z—Phosphoric Acid Production**251
§98.260 Definition of the source category. The phosphoric acid production source category consists of facilities with a wet-process phosphoric acidprocess line used to produce phosphoric acid. A wetprocess phosphoric acid process line is the production unit or units identified by an individual identification number in an operating permit and/or any process unit or group of process units at a facility reacting phosphate rock from a common supply source with acid. §98.261 Reporting threshold. You must report GHG emissions under this subpart if your facility contains a phosphoric acid production process and the facility meets the requirements of either §98.2(a)(1) or (a)(2). §98.262 GHGs to report. (a) You must report CO 2 process emissions from each wet-process phosphoric acid process line. (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 following the requirements of subpart C of this part. §98.263 Calculating GHG emissions. You must calculate and report the annual process CO 2 emissions from each wet-process phosphoric acid process252
line 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 a 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 the process CO 2 emissions using the procedures in paragraphs (b)(1) and (b)(2) of this section. (1) Calculate and report the process CO 2 emissions from each wet-process phosphoric acid process line using Equation Z-1 of this section:

12 44 * 2205 2000 *)*( 1 1 ,, 

## 

   b

i z

n inin m PIC E (Eq. Z-1)
Where: E m = Annual CO 2 mass emissions from a wet-process phosphoric acid process line m (metric tons). IC n,i = Inorganic carbon content of a grab sample batch of phosphate rock by origin i obtained during month n, from the carbon analysis results (percent by weight, expressed as a decimal fraction). P n,i = Mass of phosphate rock by origin i consumed in month n by wet-process phosphoric acid process line m (tons).

z = Number of months during which the process line m operates.253

b = Number of different types of phosphate rock in month, by origin. If the grab sample is a composite sample of rock from more than one origin, b=1. 2000/2205 = Conversion factor to convert tons to metric tons. 44/12 = Ratio of molecular weights, CO 2 to carbon.

(2) You must determine the total emissions from the facility using Equation Z-2 of this section: 

# 

  p

m m E CO 1 2 (Eq. Z-2)

Where: CO 2 = Annual process CO 2 emissions from phosphoric acid production facility (metric tons/year) E m = Annual process CO 2 emissions from wet-process phosphoric acid process line m (metric tons/year) p = Number of wet-process phosphoric acid process lines. (c) If GHG emissions from a wet-process phosphoric acid process line 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 Methodology254
in §98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part. §98.264 Monitoring and QA/QC requirements. (a) You must obtain a monthly grab sample of phosphate rock directly from the rock being fed to the process line before it enters the mill . Conduct the representative bulk sampling using the appropriate industry consensus standard or applicable standard method in the Association of Fertilizer and Phosphate Chemists Analytical Methods Manual 10th Edition (incorporated by reference, see §98.7). If phosphate rock is obtained from more than one origin in a month, you must obtain a sample from each origin of rock or obtain a composite representative sample. (b) You must determine the inorganic carbon content of each monthly grab sample of phosphate rock (consumed in the production of phosphoric acid) using the applicable standard method in the Association of Fertilizer and Phosphate Chemists Analytical Methods Manual 10th Edition (incorporated by reference, see §98.7). (c) You must determine the mass of phosphate rock consumed each month (by origin) in each wet-process phosphoric acid process line. You can use existing plant procedures that are used for accounting purposes (such as sales records) or you can use data from existing monitoring Deleted: Phosphate Mining States Methods Used and Adopted by the Deleted: AFPC Manual 10th Edition 2009 - Version 1.9

Deleted: Phosphate Mining States Methods Used and Adopted by the

Deleted: AFPC Manual 10th Edition 2009 - Version 1.9255
equipment that is used to measure total mass flow of phosphorous-bearing feed under 40 CFR part 60 or part 63. §98.265 Procedures for estimating missing data. A complete record of all measured parameters used in the GHG emissions calculations in §98.263(b) is required. Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter shall be used in the calculations as specified in paragraphs (a) and (b) of this section. You must document and keep records of the procedures used for all such estimates. (a) For each missing value of the inorganic carbon content of phosphate rock (by origin), you must use the appropriate default factor provided in Table Z-1 of this subpart. Alternatively, you must determine substitute data value by calculating the arithmetic average of the quality-assured values of inorganic carbon contents of phosphate rock of origin i from samples immediately preceding and immediately following the missing data incident. If no quality-assured data on inorganic carbon contents of phosphate rock of origin i are available prior to the missing data incident, the substitute data value shall be the first quality-assured value for inorganic Deleted: the256
carbon contents for phosphate rock of origin i obtained after the missing data period. (b) For each missing value of monthly mass consumption of phosphate rock (by origin), you must use the best available estimate based on all available process data or data used for accounting purposes. §98.266 Data reporting requirements. In addition to the information required by §98.3(c), each annual report must contain the information specified in paragraphs (a) through ( f ) of this section. (a) Annual phosphoric acid production by origin (as listed in Table Z-1 to this subpart) of the phosphate rock (tons). (b) Annual phosphoric acid permitted production capacity (tons). (c) Annual arithmetic average percent inorganic carbon in phosphate rock from monthly records (percent by weight, expressed as a decimal fraction)
. (d) Annual phosphate rock consumption from monthly measurement records by origin, (as listed in Table Z-1 to this subpart) (tons). (e) If you use a CEMS to measure CO 2 emissions, then you must report the information in paragraphs (e)(1) and (e)(2) of this section. Deleted: b257
(1) The identification number of each wet-process phosphoric acid process line. (2) The annual CO 2 emissions from each wet-process phosphoric acid process line (metric tons) and the relevant information required under 40 CFR 98.36 (e)(2)(vi) for the Tier 4 Calculation Methodology. (f) If you do not use a CEMS to measure emissions, then you must report the information in paragraphs (f)(1) through (f)( 9 ) of this section. (1) Identification number of each wet-process phosphoric acid process line. (2) Annual CO 2 emissions from each wet-process phosphoric acid process line (metric tons) as calculated by Equation Z-1 of this subpart. (3) Annual phosphoric acid permitted production capacity (tons) for each wet-process phosphoric acid process line (metric tons). (4) Method used to estimate any missing values ofinorganic carbon content of phosphate rock for each wetprocess phosphoric acid process line. (5) Monthly inorganic carbon content of phosphate rock for each wet-process phosphoric acid process line (percent by weight, expressed as a decimal fraction). Deleted: 8258
(6) Monthly mass of phosphate rock consumed by origin, (as listed in Table Z-1 of this subpart) in production for each wet-process phosphoric acid process line (tons). (7) Number of wet-process phosphoric acid process lines. (8) Number of times missing data procedures were used to estimate phosphate rock consumption (months) and inorganic carbon contents of the phosphate rock (months). (9) Annual process CO 2 emissions from phosphoric acid production facility (metric tons). §98.267 Records that must be retained. In addition to the records required by §98.3(g), you must retain the records specified in paragraphs (a) through (c) of this section for each wet-process phosphoric acid production facility. (a) Monthly mass of phosphate rock consumed by origin (as listed in Table Z-1 of this subpart) (tons). (b) Records of all phosphate rock purchases and/or deliveries (if vertically integrated with a mine). (c) Documentation of the procedures used to ensure the accuracy of monthly phosphate rock consumption by origin, (as listed in Table Z-1 of this subpart). §98.268 Definitions.259
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. **Table Z-1 of Subpart Z—Default Chemical Composition of Phosphate Rock by Origin**  **Origin Total Carbon**  **(percent by weight)** Central Florida 1.6 North Florida 1.76 North Carolina (Calcined) 0.76 Idaho (Calcined) 0.60 Morocco 1.56 **Subpart CC—Soda Ash Manufacturing** §98.290 Definition of the source category. (a) A soda ash manufacturing facility is any facility with a manufacturing line that produces soda ash by one of the methods in paragraphs (a) through (c) of this section: (1) Calcining trona. (2) Calcining sodium sesquicarbonate. (3) Using a liquid alkaline feedstock process that directly produces CO 2 . (b) In the context of the soda ash manufacturing sector, “calcining” means the thermal/chemical conversion of the bicarbonate fraction of the feedstock to sodium carbonate. §98.291 Reporting threshold. You must report GHG emissions under this subpart if your facility contains a soda ash manufacturing process and260
the facility meets the requirements of either §98.2(a)(1) or (a)(2). §98.292 GHGs to report. You must report: (a) CO 2 process emissions from each soda ash manufacturing line combined. (b) CO 2 combustion emissions from each soda ash manufacturing line. (c) CH 4 and N 2 O combustion emissions from each soda ash manufacturing line. 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) CO 2, CH 4 , and N 2 O emissions from each stationary combustion unit other than soda ash manufacturing lines. 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. §98.293 Calculating GHG emissions. You must calculate and report the annual process CO 2 emissions from each soda ash manufacturing line using the procedures specified in paragraph (a) or (b) of this section.261
(a) For each soda ash manufacturing line that meets the conditions specified in §98.33(b)(4)(ii) or (b)(4)(iii), you must calculate and report under this subpart the combined process and combustion CO 2 emissions by operating and maintaining a CEMS to measure CO 2 emissions 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) For each soda ash manufacturing line that is not subject to the requirements in paragraph (a) of this section, calculate and report the process CO 2 emissions from the soda ash manufacturing line by using the procedure in either paragraphs (b)(1), (b)(2), or (b)(3) of this section; and the combustion CO 2 emissions using the procedure in paragraph (b)(4) of this section. (1) Calculate and report under this subpart the combined process and combustion CO 2 emissions by operating and maintaining a CEMS to measure CO 2 emissions 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).262
(2) Use either Equation CC-1 or Equation CC-2 of this section to calculate annual CO 2 process emissions from each manufacturing line that calcines trona to produce soda ash: 

###    1 097.0 * 2205 2000 *]T*IC[E 12

1n n t n T k 

## 

  (Eq. CC-1) 

###   1 0.138 2205 2000 **]T*IC[E 12

1n n sa n sa k 

## 

  (Eq. CC-2)
Where: E k = Annual CO 2 process emissions from each manufacturing line, k (metric tons). (IC T ) n = Inorganic carbon content (percent by weight, expressed as a decimal fraction) in trona input, from the carbon analysis results for month n. This represents the ratio of trona to trona ore. (IC sa ) n = Inorganic carbon content(percent by weight, expressed as a decimal fraction) in soda ash output, from the carbon analysis results for month n. This represents the purity of the soda ash produced. (T t ) n = Mass of trona input in month n (tons). (T sa ) n = Mass of soda ash output in month n (tons). 2000/2205 = Conversion factor to convert tons to metric tons. 0.097/1 = Ratio of ton of CO 2 emitted for each ton of trona. 0.138/1 = Ratio of ton of CO 2 emitted for each ton of soda ash produced. (3) Site-specific emission factor method . Use Equations CC-3, CC-4, and CC-5 of this section to determine annual CO 2 process emissions from manufacturing lines that use the liquid alkaline feedstock process to produce soda ash. You must conduct an annual performance test and263

measure CO 2 emissions and flow rates at all process vents from the mine water stripper/evaporator for each manufacturing line and calculate CO 2 emissions as described in paragraphs (b)(3)(i) through (b)(3)(iv) of this section. (i) During the performance test, you must measure the process vent flow from each process vent during the test and calculate the average rate for the test period in metric tons per hour. (ii) Using the test data, you must calculate the hourly CO 2 emission rate using Equation CC-3 of this section:

4 9 2 2 1053.4*)60*(*]44*1059.2*)10000*[(    x Q x CER co CO (Eq. CC-3) Where: ER CO2 = CO 2 mass emission rate (metric tons/hour). C CO2 = Hourly CO 2 concentration (percent CO 2 ) as determined by §98.294(c). 10000 = Parts per million per percent 2.59 x 10 -9 = Conversion factor (pounds-mole/dscf/ppm). 44 = Pounds per pound-mole of carbon dioxide. Q = Stack gas volumetric flow rate per minute (dscfm). 60 = Minutes per hour 4.53 x 10 -4 = Conversion factor (metric tons/pound) (iii) Using the test data, you must calculate a CO 2 emission factor for the process using Equation CC-4 of this section:264

)1053.4*( 4 2 2



 xV ER EF

t CO CO (Eq. CC-4)

Where: EF CO2 = CO 2 emission factor (metric tons CO 2 /metric ton of process vent flow from mine water stripper/evaporator). ER CO2 = CO 2 mass emission rate (metric tons/hour). V t = Process vent flow rate from mine water stripper/evaporator during annual performance test (pounds/hour). 4.53 x 10 -4 = Conversion factor (metric tons/pound)
(iv) You must calculate annual CO 2 process emissions from each manufacturing line using Equation CC-5 of this section:

H VEFE a CO k *)453.0*(* 2  (Eq. CC-5) Where: E k = Annual CO 2 process emissions for each manufacturing line, k (metric tons). EF CO2 = CO 2 emission factor (metric tons CO 2 /metric ton of process vent flow from mine water stripper/evaporator). V a = Annual process vent flow rate from mine water stripper/evaporator (thousand pounds/hour). H = Annual operating hours for the each manufacturing line. 0.453 = Conversion factor (metric tons/thousand pounds). (4) Calculate and report under subpart C of this part (General Stationary Fuel Combustion Sources) the combustion265

CO 2 , CH 4 , and N 2 O emissions in the soda ash manufacturing line according to the applicable requirements in subpart C. §98.294 Monitoring and QA/QC requirements. Section 98.293 provides three different procedures for emission calculations. The appropriate paragraphs (a) through (c) should be used for the procedure chosen. (a) If you determine your emissions using §98.293(b)(2) (Equation CC-1 of this subpart) you must: (1) Determine the monthly inorganic carbon content of the trona from a weekly composite analysis for each soda ash manufacturing line, using a modified version of ASTM E359-00(Reapproved 2005)e1, Standard Test Methods for Analysis of Soda Ash (Sodium Carbonate) (incorporated by reference, see §98.7). ASTM E359-00(Reapproved 2005)e1 is designed to measure the total alkalinity in soda ash not in trona. The modified method referred to above adjusts the regular ASTM method to express the results in terms of trona. Although ASTM E359-00(Reapproved 2005)e1 uses manual titration, suitable autotitrators may also be used for this determination. (2) Measure the mass of trona input produced by each soda ash manufacturing line on a monthly basis using belt scales or methods used for accounting purposes. Deleted: of ASTM E359-00266
(3) Document the procedures used to ensure the accuracy of the monthly measurements of trona consumed. (b) If you calculate CO 2 process emissions based on soda ash production (§98.293(b)(2)Equation CC-2 of this subpart), you must: (1) Determine the inorganic carbon content of the soda ash (i.e., soda ash purity) using ASTM E359- 00(Reapproved 2005)e1 Standard Test Methods for Analysis of Soda Ash (Sodium Carbonate) (incorporated by reference, see §98.7). Although ASTM E359-00(Reapproved 2005)e1 uses manual titration, suitable autotitrators may also be used for this determination. (2) Measure the mass of soda ash produced by each soda ash manufacturing line on a monthly basis using belt scales, by weighing the soda ash at the truck or rail loadout points of your facility, or methods used for accounting purposes. (3) Document the procedures used to ensure the accuracy of the monthly measurements of soda ash produced. (c) If you calculate CO 2 emissions using the sitespecific emission factor method in §98.293(b)(3), you must: (1) Conduct an annual performance test that is based on representative performance (i.e., performance based on normal operating conditions) of the affected process.267
(2) Sample the stack gas and conduct three emissions test runs of 1 hour each. (3) Conduct the stack test using EPA Method 3A at 40 CFR part 60, appendix A-2 to measure the CO 2 concentration, Method 2, 2A, 2C, 2D, or 2F at 40 CFR part 60, appendix A-1 or Method 26 at 40 CFR part 60, appendix A-2 to determine the stack gas volumetric flow rate. All QA/QC procedures specified in the reference test methods and any associated performance specifications apply. For each test, the facility must prepare an emission factor determination report that must include the items in paragraphs (c)(3)(i) through (c)(3)(iii) of this section. (i) Analysis of samples, determination of emissions, and raw data. (ii) All information and data used to derive the emissions factor(s). (iii) You must determine the average process vent flow rate from the mine water stripper/evaporater during each test and document how it was determined. (4) You must also determine the the annual vent flow rate from the mine water stripper/evaporater from monthly information using the same plant instruments or procedures used for accounting purposes (i.e., volumetric flow meter). §98.295 Procedures for estimating missing data.268
For the emission calculation methodologies in §98.293(b)(2)and (b)(3), a complete record of all measured parameters used in the GHG emissions calculations is required (e.g., inorganic carbon content values, etc.). Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter shall be used in the calculations as specified in the paragraphs (a) through (d) of this section. You must document and keep records of the procedures used for all such missing value estimates. (a) For each missing value of the weekly composite of inorganic carbon content of either soda ash or trona, the substitute data value shall be the arithmetic average of the quality-assured values of inorganic carbon contents from the week immediately preceding and the week immediately following the missing data incident. If no quality-assured data on inorganic carbon contents are available prior to the missing data incident, the substitute data value shall be the first quality-assured value for carbon contents obtained after the missing data period. (b) For each missing value of either the monthly soda ash production or the trona consumption, the substitute data value shall shall be the best available estimate(s) of269
the parameter(s), based on all available process data or data used for accounting purposes. (c) For each missing value collected during the performance test (hourly CO 2 concentration, stack gas volumetric flow rate, or average process vent flow from mine water stripper/evaporator during performance test), you must repeat the annual performance test following the calculation and monitoring and QA/QC requirements under §§98.293(b)(3) and 98.294(c). (d) For each missing value of the monthly process vent flow rate from mine water stripper/evaporator, the subsititute data value shall be the best available estimate(s) of the parameter(s), based on all available process data or the lesser of the maximum capacity of the system or the maximum rate the meter can measure. §98.296 Data reporting requirements. In addition to the information required by §98.3(c), each annual report must contain the information specified in paragraphs (a) or (b) of this section, as appropriate for each soda ash manufacturing facility. (a) If a CEMS is used to measure CO 2 emissions, then you must report under this subpart the relevant information required under §98.36 and the following information in this paragraph (a):270
(1) Annual consumption of trona or liquid alkaline feedstock for each manufacturing line (tons). (2) Annual production of soda ash for each manufacturing line (tons). (3) Annual production capacity of soda ash for each manufacturing line (tons). (4) Identification number of each manufacturing line. (b) If a CEMS is not used to measure CO 2 emissions, then you must report the information listed in this paragraph (b): (1) Identification number of each manufacturing line. (2) Annual process CO 2 emissions from each soda ash manufacturing line (metric tons). (3) Annual production of soda ash for each manufacturing line (tons). (4) Annual production capacity of soda ash for each manufacturing line (tons). (5) Monthly consumption of trona or liquid alkaline feedstock for each manufacturing line (tons). (6) Monthly production of soda ash for each manufacturing line (tons). (7) Inorganic carbon content factor of trona or soda ash (depending on use of Equations CC-1 or CC-2 of this subpart) as measured by the applicable method in §98.294(b) Deleted: metric

Deleted: metric271
or (c) for each month (percent by weight expressed as a decimal fraction). (8) Whether CO 2 emissions for each manufacturing line were calculated using a trona input method as described in Equation CC-1 of this subpart, a soda ash output method asdescribed in Equation CC-2 of this subpart, or a sitespecific emission factor method as described in Equations CC-3 through CC-5 of this subpart. (9) Number of manufacturing lines located used to produce soda ash. (10) If you produce soda ash using the liquid alkaline feedstock process and use the site-specific emission factor method (§98.293(b)(3)) to estimate emissions then you must report the following relevant information for each manufacturing line or stack : (i) Stack gas volumetric flow rate during performance
test (dscfm)
. (ii) Hourly CO 2 concentration during performance test (percent CO 2 )
. (iii) CO 2 emission factor (metric tons CO 2 /metric tons of process vent flow from mine water stripper/evaporator). (iv) CO 2 mass emission rate during performance test (metric tons/hour). Deleted: per minute272
(v) Average process vent flow from mine water stripper/evaporater during performance test (pounds/hour). (vi) Annual process vent flow rate from mine stripper/evaporator (thousand pounds/hour). (vii) Annual operating hours for each manufacturing line used to produce soda ash using liquid alkaline feedstock (hours). (11) Number of times missing data procedures were used and for which parameter as specified in this paragraph (b)(11): (i) Trona or soda ash (number of months). (ii) Inorganic carbon contents of trona or soda ash (weeks). (iii) Process vent flow rate from mine water stripper/evaporator (number of months). §98.297 Records that must be retained. In addition to the records required by §98.3(g), you must retain the records specified in paragraphs (a) and (b) of this section for each soda ash manufacturing line. (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 specified in subpart C of this part and the information listed in this paragraph (a): Deleted: ¶ (iv) Stack gas volumetric flow rate during performance test(number of times).¶ (v) Hourly CO 2 concentration (number of times). ¶ (vi) Average vent process vent flow rate from mine stripper/evaporator during performance test (number of times).273
(1) Monthly production of soda ash (tons) (2) Monthly consumption of trona or liquid alkaline feedstock (tons) (3) Annual operating hours (hours). (b) If a CEMS is not used to measure emissions, then you must retain records for the information listed in this paragraph (b): (1) Records of all analyses and calculations conducted for determining all reported data as listed in §98.296(b). (2) If using Equation CC-1 or CC-2 of this subpart, weekly inorganic carbon content factor of trona or soda ash, depending on method chosen, as measured by the applicable method in §98.294(b)(percent by weight expressed as a decimal fraction). (3) Annual operating hours for each manufacturing line used to produce soda ash (hours). (4) You must document the procedures used to ensure the accuracy of the monthly trona consumption or soda ash prodcution measurements including, but not limited to, calibration of weighing equipment 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.274
(5) If you produce soda ash using the liquid alkaline feedstock process and use the site-specific emission factor method to estimate emissions (§98.293(b)(3)) then you must also retain the following relevant information: (i) Records of performance test results. (ii) You must document the procedures used to ensure the accuracy of the annual average vent flow measurements including, but not limited to, calibration of flow rate 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. §98.298 Definitions. All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. **Subpart EE—Titanium Dioxide Production** §98.310 Definition of the source category. The titanium dioxide production source category consists of facilities that use the chloride process to produce titanium dioxide. §98.311 Reporting threshold. You must report GHG emissions under this subpart if your facility contains a titanium dioxide production275
process and the facility meets the requirements of either §98.2(a)(1) or (a)(2). §98.312 GHGs to report. (a) You must report CO 2 process emissions from each chloride process line as required in this subpart. (b) You must report under 40 CFR 98, CO 2 , CH 4 , and N 2 0 emissions from each stationary combustion unit under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C. §98.313 Calculating GHG emissions. You must calculate and report the annual process CO 2 emissions for each chloride process line 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 a 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 the annual process CO 2 emissions for each chloride process line by determining the mass of calcined petroleum coke consumed in each line as specified in paragraphs (b)(1) through (b)(3) of this section. Use Equation EE-1 of this section276
to calulate annual combined process CO 2 emissions from all process lines and use Equation EE-2 of this section to calculate annual process CO 2 emissions for each process line. If your facility generates carbon-containing waste, use Equation EE-3 of this section to estimate the annual quantity of carbon-containing waste generated and its carbon contents according to §98.314(e) and (f): (1) You must calculate the annual CO 2 process emissions from all process lines at the facility using Equation EE-1 of this section: 

## 

  m

p p ECO 1 2 (Eq. EE-1)
Where: CO 2 = Annual CO 2 emissions from titanium dioxide production facility (metric tons/year). E p = Annual CO 2 emissions from chloride process line p (metric tons), determined using Equation EE-2 of this section. p = Process line. m = Number of separate chloride process lines located at the facility. (2) You must calculate the annual CO 2 process emissions from each process lines at the facility using Equation EE-2 of this section:

n n np p CCF C E * 2205 2000 ** 12 44 12

1 , 

# 

  (Eq. EE-2)
Where:277

E p = Annual CO 2 mass emissions from chloride process line p (metric tons). C p,n = Calcined petroleum coke consumption for process line p in month n (tons). 44/12 = Ratio of molecular weights, CO 2 to carbon. 2000/2205 = Conversion of tons to metric tons. CCF n = Carbon content factor for petroleum coke consumed in month n from the supplier or as measured by the applicable method incorporated by reference in §98.7 according to §98.314(c) (percent by weight expressed as a decimal fraction). n = Number of month. (3) If facility generates carbon-containing waste,you must calculate the total annual quantity of carboncontaining waste produced from all process lines using Equation EE-3 of this section and its carbon contents according to §98.314(e) and (f): 

## 

   12

1 , 1 1

n np m

p WCn TWC (Eq. EE-3)
Where: TWC = Annual production of carbon-containing waste from titanium dioxide production facility (tons). WC p,n = Production of carbon-containing waste in month n from chloride process line p (tons). p = Process line. m = Total number of process lines. n = Number of month. (c) If GHG emissions from a chloride process line are vented through the same stack as any combustion unit or278
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 CO 2 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. §98.314 Monitoring and QA/QC requirements. (a) You must measure your consumption of calcined petroleum coke using plant instruments used for accounting purposes including direct measurement weighing the petroleum coke fed into your process (by belt scales or a similar device) or through the use of purchase records. (b) You must document the procedures used to ensure the accuracy of monthly calcined petroleum coke consumption
measurements. (c) You must determine the carbon content of the calcined petroleum coke each month based on reports from the supplier. Alternatively, facilities can measure monthly carbon contents of the petroleum coke using ASTM D3176-89 (Reapproved 2002) Standard Practice for Ultimate279
Analysis of Coal and Coke (incorporated by reference, see §98.7) and 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). (d) For quality assurance and quality control of the supplier data, you must conduct an annual measurement of the carbon content from a representative sample of the petroleum coke consumed using ASTM D3176-89 and ASTM D5373- 08. (e) You must determine the quantity of carboncontaining waste generated from each titanium dioxide production line on a monthly basis using plant instruments used for accounting purposes including direct measurement weighing the carbon-containing waste not used during the process (by belt scales or a similar device) or through the use of sales records. (f) You must determine the carbon contents of the carbon-containing waste from each titanium production line on an annual basis by collecting and analyzing a representative sample of the material using ASTM D3176-89 and ASTM D5373-08. §98.315 Procedures for estimating missing data. Deleted: the

Deleted: dioxide280
For the petroleum coke input procedure in §98.313(b), a complete record of all measured parameters used in the GHG emissions calculations is required (e.g., carbon content values, etc.). Therefore, whenever the monitoring and quality assurance procedures in §98.315 cannot be followed, a substitute data value for the missing parameter shall be used in the calculations as specified in the paragraphs (a) through (c) of this section. You must document and keep records of the procedures used for all such estimates. (a) For each missing value of the monthly carbon content of calcined petroleum coke the substitute datavalue shall be the arithmetic average of the qualityassured values of carbon contents for the month immediately preceding and the month immediately following the missing data incident. If no quality-assured data on carbon contents are available prior to the missing data incident,the substitute data value shall be the first qualityassured value for carbon contents obtained after the missing data period. (b) For each missing value of the monthly calcined petroleum coke consumption and/or carbon-containing waste, the substitute data value shall be the best available estimate of the monthly petroleum coke consumption based on281
all available process data or information used for accounting purposes (such as purchase records). (c) For each missing value of the carbon content of carbon-containing waste, you must conduct a new analysis following the procedures in §98.314(f). §98.316 Data reporting requirements. In addition to the information required by §98.3(c), each annual report must contain the information specified in paragraphs (a) or (b) of this section, as applicable for each titanium dioxide production line. (a) If a CEMS is used to measure CO 2 emissions, then you must report the relevant information required under §98.36(e)(2)(vi) for the Tier 4 Calculation Methodology and the following information in this paragraph (a). (1) Identification number of each process line. (2) Annual consumption of calcined petroleum coke (tons). (3) Annual production of titanium dioxide (tons). (4) Annual production capacity of titanium dioxide (tons). (5) Annual production of carbon-containing waste (tons), if applicable.282
(b) If a CEMS is not used to measure CO 2 emissions, then you must report the information listed in this paragraph (b): (1) Identification number of each process line. (2) Annual CO 2 emissions from each chloride process line (metric tons/year). (3) Annual consumption of calcined petroleum coke for each process line (tons). (4) Annual production of titanium dioxide for each process line (tons). (5) Annual production capacity of titanium dioxide for each process line (tons). (6) Calcined petroleum coke consumption for each process line for each month (tons). (7) Annual production of carbon-containing waste for each process line (tons), if applicable. (8) Monthly production of titanium dioxide for each process line (tons). (9) Monthly carbon content factor of petroleum coke (percent by weight expressed as a decimal fraction). (10) Whether monthly carbon content of the petroleum coke is based on reports from the supplier or through self measurement using applicable ASTM standard methods. Deleted: from the supplier283
(11) Carbon content for carbon-containing waste for each process line (percent by weight expressed as a decimal fraction). (12) If carbon content of petroleum coke is based on self measurement, the ASTM standard methods used. (13) Sampling analysis results of carbon content of petroleum coke as determined for QA/QC of supplier data under §98.314(d) (percent by weight expressed as a decimal fraction). (14) Number of separate chloride process lines located at the facility. (15) The number of times in the reporting year that missing data procedures were followed to measure the carbon contents of petroleum coke (number of months); petroleum coke consumption (number of months); carbon-containing waste generated (number of months); and carbon contents of the carbon-containing waste (number of times during year). §98.317 Records that must be retained. In addition to the records required by §98.3(g), you must retain the records specified in paragraphs (a) and (b) of this section for each titanium dioxide production facility. (a) If a CEMS is used to measure CO 2 emissions, then you must retain under this subpart required for the Tier 4284
Calculation Methodology in §98.37 and the information listed in this paragraph (a): (1) Records of all calcined petroleum coke purchases. (2) Annual operating hours for each titanium dioxide process line. (b) If a CEMS is not used to measure CO 2 emissions, then you must retain records for the information listed in this paraghraph: (1) Records of all calcined petroleum coke purchases (tons). (2) Records of all analyses and calculations conducted for all reported data as listed in §98.316(b). (3) Sampling analysis results for carbon content of consumed calcined petroleum coke (percent by weight expressed as a decimal fraction). (4) Sampling analysis results for the carbon content of carbon containing waste (percent by weight expressed as a decimal fraction), if applicable. (5) Monthly production of carbon-containing waste (tons). (6) You must document the procedures used to ensure the accuracy of the monthly petroleum coke consumption and quantity of carbon-containing waste measurement including, but not limited to, calibration of weighing equipment and285
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. (7) Annual operating hours for each titanium dioxide process line (hours). §98.318 Definitions. All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. **Subpart GG—Zinc Production** §98.330 Definition of the source category. The zinc production source category consists of zinc smelters and secondary zinc recycling facilities. §98.331 Reporting threshold. You must report GHG emissions under this subpart if your facility contains a zinc production process and the facility meets the requirements of either §98.2(a)(1) or (2). §98.332 GHGs to report. You must report: (a) CO 2 process emissions from each Waelz kiln and electrothermic furnace used for zinc production. (b) CO 2 , CH 4 , and N 2 O combustion emissions from each Waelz kiln. You must calculate and report these emissions286
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 Waelz kilns. You must report these emissions under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C. §98.333 Calculating GHG emissions. You must calculate and report the annual process CO 2 emissions using the procedures specified in either paragraph (a) or (b) of this section. (a) Calculate and report under this subpart the process or combined process and combustion CO 2 emissions by operating and maintaining a 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). (b) Calculate and report under this subpart the process CO 2 emissions by following paragraphs (b)(1) and (b)(2) of this section. (1) For each Waelz kiln or electrothermic furnace at your facility used for zinc production, you must determine the mass of carbon in each carbon-containing material,287
other than fuel, that is fed, charged, or otherwise introduced into each Waelz kiln and electrothermic furnace at your facility for each year and calculate annual CO 2 process emissions from each affected unit at your facility using Equation GG-1 of this section. For electrothermic furnaces, carbon containing input materials include carbon eletrodes and carbonaceous reducing agents. For Waelz kilns, carbon containing input materials include carbonaceous reducing agents. If you document that a specific material contributes less than 1 percent of the total carbon into the process, you do not have to include the material in your calculation using Equation R-1 of §98.183.


### ( )( ) ( )( ) ( )( ) ( )( ) ]* + * + *+*[* 2205 2000 * 12 44 =E

CO2k

k carbon k k Electrode k k Flux k k Zinc k C

Carbon C Electrode CFlux CZinc (Eq. GG-1)

Where:
E CO2k = Annual CO 2 process emissions from individual Waelz kiln or electrothermic furnace “k” (metric tons). 44/12 = Ratio of molecular weights, CO 2 to carbon. 2000/2205 = Conversion factor to convert tons to metric tons. (Zinc) k = Annual mass of zinc bearing material charged to kiln or furnace ”k” (tons). (C Zinc ) k = Carbon content of the zinc bearing material, from the annual carbon analysis for kiln or furnace “k” (percent by weight, expressed as a decimal fraction).288

(Flux) k = Annual mass of flux materials (e.g., limestone, dolomite) charged to kiln or furnace “k” (tons). (C Flux ) k = Carbon content of the flux materials charged to kiln or furnace “k”, from the annual carbon analysis (percent by weight, expressed as a decimal fraction). (Electrode) k = Annual mass of carbon electrode consumed in furnace “k” (tons). (C Electrode ) k = Carbon content of the carbon electrode consumed in furnace “k”, from the annual carbon analysis (percent by weight, expressed as a decimal fraction). (Carbon) k = Annual mass of carbonaceous materials (e.g., coal, coke) charged to the kiln or furnace “k”(tons). (C Carbon ) k Carbon content of the carbonaceous materials charged to kiln or furnace, “k”, from the annual carbon analysis (percent by weight, expressed as a decimal fraction).
(2) You must determine the CO 2 emissions from all of the Waelz kilns or electrothermic furnaces at your facility using Equation GG-2 of this section. 

## 

  n

1k CO2 2 ECO k (Eq. GG-2)
Where: CO 2 = Annual combined CO 2 emissions from all Waelz kilns or electrothermic furnaces (tons). E CO2 k = Annual CO 2 emissions from each Waelz kiln or electrothermic furnace k calculated using Equation GG-1 of this section (tons). n = Total number of Waelz kilns or electrothermic furnaces at facility used for the zinc production. Deleted: kiln or

Deleted: kiln or289
(c) If GHG emissions from a Waelz kiln or electrothermic furnace 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. §98.334 Monitoring and QA/QC requirements. If you determine CO 2 emissions using the carbon input procedure in §98.333(b)(1)and (b)(2), you must meet the requirements specified in paragraphs (a) and (b) of this section.(a) Determine the mass of each solid carboncontaining input material consumed using facility instruments, procedures, or records used for accounting purposes including direct measurement weighing or through the use of purchase records same plant instruments or procedures that are used for accounting purposes (such as weigh hoppers, belt weigh feeders, weighed purchased290
quantities in shipments or containers, combination of bulk density and volume measurements, etc.). Record the total mass for the materials consumed each calendar month and sum the monthly mass to determine the annual mass for each input material. (b) For each input material identified in paragraph (a) of this section, you must determine the average carbon content of the material consumed or used in the calendar year using the methods specified in either paragraph (b)(1) or (b)(2) of this section. (1) Information provided by your material supplier. (2) Collecting and analyzing at least three representative samples of the material using the appropriate testing method. For each carbon-containing input material identified for which the carbon content is not provided by your material supplier, the carbon content of the material must be analyzed at least annually using the appropriate standard methods (and their QA/QC procedures), which are identified in paragraphs (b)(2)(i) through (b)(2)(iii) of this section, as applicable. If you document that a specific process input or output contributes less than one percent of the total mass of carbon into or out of the process, you do not have to291
determine the monthly mass or annual carbon content of that input or output. (i) Using ASTM E1941-04 Standard Test Method for Determination of Carbon in Refractory and Reactive Metals and Their Alloys (incorporated by reference, see §98.7), analyze zinc bearing materials. (ii) 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), analyze carbonaceous reducing agents and carbon electrodes. (iii) Using ASTM C25-06 Standard Test Methods for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime (incorporated by reference, see §98.7), analyze flux materials such as limestone or dolomite. §98.335 Procedures for estimating missing data. For the carbon input procedure in §98.333(b), a complete record of all measured parameters used in the GHG emissions calculations is required (e.g., raw materials carbon content values, etc.). Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter shall be used in the calculations as specified in paragraphs (a) and (b) of this section. You must document292
and keep records of the procedures used for all such estimates. (a) For missing records of the carbon content of inputs for facilities that estimate emissions using the carbon input procedure in §98.333(b); 100 percent data availability is required. You must repeat the test for average carbon contents of inputs according to the procedures in §98.335(b) if data are missing.(b) For missing records of the annual mass of carboncontaining inputs using the carbon input procedure in §98.333(b), the substitute data value must be based on the best available estimate of the mass of the input material from all available process data or information used for accounting purposes, such as purchase records. §98.336 Data reporting requirements. In addition to the information required by §98.3(c), each annual report must contain the information specified in paragraphs (a) or (b) of this section, as applicable, for each Waelz kiln or electrothermic furnace. (a) If a CEMS is used to measure CO 2 emissions, then you must report under this subpart the relevant information required for the Tier 4 Calculation Methodology in §98.3 6 and the information listed in this paragraph (a): (1) Annual zinc product production capacity (tons). Deleted: 7293
(2) Annual production quantity for each zinc product (tons). (3) Annual facility production quantity for each zinc product (tons). (4) Number of Waelz kilns at each facility used for zinc production. (5) Number of electrothermic furnaces at each facility used for zinc production. (b) If a CEMS is not used to measure CO 2 emissions, then you must report the information listed in this paragraph (b): (1) I dentification number and annual process CO 2 emissions from each individual Waelz kiln or electrothermic furnace (metric tons). (2) Annual zinc product production capacity (tons). (3) Annual production quantity for each zinc product (tons). (4) Number of Waelz kilns at each facility used for zinc production. (5) Number of electrothermic furnaces at each facility used for zinc production. (6) Annual mass of each carbon-containing input material charged to each kiln or furnace (including zinc bearing material, flux materials (e.g., limestone, Deleted: Kiln i294
dolomite), carbon electrode, and other carbonaceous materials (e.g., coal, coke)) (tons). (7) Carbon content of each carbon-containing input material charged to each kiln or furnace (including zinc bearing material, flux materials, and other carbonaceous materials) from the annual carbon analysis or from information provided by the material supplier for each kiln or furnace (percent by weight, expressed as a decimal fraction). (8) Whether carbon content of each carbon-containing input material charged to each kiln or furnace is based on reports from the supplier or through self measurement using applicable ASTM standard method. (9) If carbon content of each carbon-containing input material charged to each kiln or furnace is based on self measurement, the ASTM Standard Test Method used. (10) Carbon content of the carbon electrode used in each furnace from the annual carbon analysis or from information provided by the material supplier (percent by weight, expressed as a decimal fraction). (11) Whether carbon content of the carbon electrode used in each furnace is based on reports from the supplier or through self measurement using applicable ASTM standard method.295
(12) If carbon content of carbon electrode used in each furnace is based on self measurement, the ASTM standard method used. (13) If you use the missing data procedures in§98.335(b), you must report how the monthly mass of carboncontaining materials with missing data was determined and the number of months the missing data procedures were used. §98.337 Records that must be retained. In addition to the records required by §98.3(g), you must retain the records specified in paragraphs (a) through (b) of this section for each zinc production facility. (a) If a CEMS is used to measure emissions, then you must retain under this subpart the records required for the Tier 4 Calculation Methodology in §98.37 and the information listed in this paragraph (a): (1) Monthly facility production quantity for each zinc product (tons). (2) Annual operating hours for all Waelz kilns and electrothermic furnaces used in zinc production. (b) If a CEMS is not used to measure emissions, you must also retain the records specified in paragraphs (b)(1) through (b)(7) of this section. (1) Records of all analyses and calculations conducted for data reported as listed in §98.336(b).296
(2) Annual operating hours for Waelz kilns and electrothermic furnaces used in zinc production. (3) Monthly production quantity for each zinc product (tons). (4) Monthly mass of zinc bearing materials, flux materials (e.g., limestone, dolomite), and carbonaceous materials (e.g., coal, coke) charged to the kiln or furnace (tons). (5) Sampling and analysis records for carbon content of zinc bearing materials, flux materials (e.g., limestone, dolomite), carbonaceous materials (e.g., coal, coke), charged to the kiln or furnace (percent by weight, expressed as a decimal fraction). (6) Monthly mass of carbon electrode consumed in for each electrothermic furnace (tons). (7) Sampling and analysis records for carbon content of electrode materials. (8) You must keep records that include a detailed explanation of how company records of measurements are used to estimate the carbon input to each Waelz kiln or electrothermic furnace, as applicable to your facility, including documentation of any materials excluded from Equation GG-1 of this subpart that contribute less than 1 percent of the total carbon inputs to the process. You297
also must document the procedures used to ensure the accuracy of the measurements of materials fed, charged, or placed in an affected unit including, but not limited to, calibration of weighing equipment 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. §98.338 Definitions. All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. **Subpart HH—Municipal Solid Waste Landfills** §98.340 Definition of the source category. (a) This source category applies to municipal solid waste (MSW) landfills that accepted waste on or after January 1, 1980. (b) This source category does not include Resource Conservation and Recovery Act (RCRA) Subtitle C or Toxic Substances Control Act **(** TSCA) hazardous waste landfills, dedicated construction and demolition waste landfills, or industrial waste landfills. (c) This source category consists of the following sources at municipal solid waste (MSW) landfills: landfills, landfill gas collection systems, and landfill gas destruction devices (including flares).298
§98.341 Reporting threshold. You must report GHG emissions under this subpart if your facility contains a MSW landfill and the facility meets the requirements of §98.2(a)(1). §98.342 GHGs to report. (a) You must report CH 4 generation and CH 4 emissions from landfills. (b) You must report CH 4 destruction resulting from landfill gas collection and combustion systems. (c) 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 following the requirements of subpart C. §98.343 Calculating GHG emissions. (a) For all landfills subject to the reporting requirements of this subpart, calculate annual modeled CH 4 generation according to the applicable requirements in paragraphs (a)(1) through (a)(3) of this section. (1) Calculate annual modeled CH 4 generation using Equation HH-1 of this section. 

#   



       

  1 )()1( 4 12 16 T

Sx xTk xTk F x CH eeFDOC DOC MCFW G (Eq. HH-1)
Where:

G CH4 = Modeled methane generation rate in reporting year T (metric tons CH 4 ).299

x = Year in which waste was disposed. S = Start year of calculation. Use the year 1960 or the opening year of the landfill, whichever is more recent. T = Reporting year for which emissions are calculated. W x = Quantity of waste disposed in the landfill in year x from measurement data, tipping fee receipts , or other company records (metric tons, as received (wet weight)). MCF = Methane correction factor (fraction) . Use the default value of 1. DOC = Degradable organic carbon from Table HH-1 of this subpart or measurement data, if available [fraction (metric tons C/metric ton waste)]. DOC F = Fraction of DOC dissimilated (fraction) . Use the default value of 0.5. F = Fraction by volume of CH 4 in landfill gas from measurement data on a dry basis , if available (fraction); default is 0.5. k = Rate constant from Table HH-1 of this subpart (yr -1 ). Select the most applicable k value for the majority of the past 10 years (or operating life, whichever is shorter). (2) For years when material-specific waste quantity data are available, apply Equation HH-1 of this section for each waste quantity type and sum the CH 4 generation rates for all waste types to calculate the total modeled CH 4 generation rate for the landfill. Use the appropriate parameter values for k, DOC, MCF, DOC F , and F shown in Table HH-1 of this subpart. The annual quantity of each type of waste disposed must be calculated as the sum of the daily quantities of waste (of that type) disposed. You may use the bulk waste parameters for a portion of your waste Deleted: X Deleted: 50 years prior to the year of the emissions estimate,

Deleted: X

Deleted: L 0 = CH 4 generation potential (metric tons CH 4 /metric ton waste) = MCF×DOC×DOC F ×F×16/12. ¶ Deleted: ; Deleted: is

Deleted: ; Deleted: is

Deleted: or measurement data, if available300
materials when using the material-specific modeling approach for mixed waste streams that cannot be designated to a specific material type. For years when waste composition data are not available, use the bulk waste parameter values for k and DOC in Table HH-1 of this subpart for the total quantity of waste disposed in those
years. (3) Beginning in the first emissions monitoring year (2010 or later) and for each year thereafter, if scales are in place, you must determine the annual quantity of waste (in metric tons as received, i.e., wet weight) disposed of in the landfill using paragraph (a)(3)(i) of this section for all containers and for all vehicles, other than passenger cars or light duty pickup trucks, used to haul waste to the landfill. If scales are not in place, you must use paragraph (a)(3)(ii) of this section to determine the annual quantity of waste disposed. For waste hauled to the landfill in passenger cars or light duty pickup trucks, you may use either pargraph (a)(3)(i) or paragraph (a)(3)(ii) of this section to determine the annual quantity of waste disposed. The approach used to determine the annual quantity of waste disposed of must be documented in the monitoring plan. Deleted: L 0

Deleted:301
(i) Use direct mass measurements of each individual load received at the landfill using either of the following methods: (A) Weigh using mass scales each vehicle or container used to haul waste as it enters the landfill or disposal area; weigh using mass scales each vehicle or container after it has off-loaded the waste; determine the quantity of waste received from the individual load as the difference in the two mass measurements; and determine the annual quantity of waste received as the sum of all waste loads received during the year. Alternatively, you may determine annual quantity of waste by summing the weights of all vehicles and containers entering the landfill and subtracting from it the sum of all the weights of vehicles and containers after they have off-loaded the waste in the landfill. (B) Weigh using mass scales each vehicle or container used to haul waste as it enters the landfill or disposal area; determine a representative tare weight by vehicle or container type by weighing no less than 5 of each type of vehicle or container after it has off-loaded the waste; determine the quantity of waste received from the individual load as the difference between the measured weight in and the tare weight determined for that302 container/vehicle type; and determine the annual quantity of waste received as the sum of all waste loads received during the year. (ii) Determine the working capacity in units of mass for each type of container or vehicle used to haul waste to the landfill (e.g., using volumetric capacity and waste density measurements; direct measurement of a selected number of passenger vehicles and light duty pick-up trucks; or similar methods); record the number of loads received at the landfill by vehicle/container type; calculate the annual mass per vehicle/container type as the mass product of the number of loads of that vehicle/container multiplied by its working capacity; and calculate the annual quantity of waste received as the sum of the annual mass per vehicle/container type across all of the vehicle/container types used to haul waste to the landfill. ( 4 ) For years prior to the first emissions monitoring year, use methods in paragraph (a)(3) of this section when waste disposal quantity data are readily available. When waste disposal quantit y data are not readily available, W x shall be estimated using one of the applicable methods in paragraphs (a)( 4 )(i) through (a)( 4 )(iii) of this section. You must determine which method is most applicable to the conditions and disposal history of your facility
. Deleted: 3

Deleted: reporting for which

Deleted: ies

Deleted: 3 Deleted: 3303
Historical waste disposal quantities should only be determined once, as part of the first annual report, and the same values should be used for all subsequent annual reports, supplemented by the next year’s data on new waste disposal
. (i) Assume all prior year s waste disposal quantities are the same as the waste quantity in the first year for which waste quantities are available
. (ii) Use the estimated population served by the landfill in each year, the values for national average per capita waste generation, and fraction of generated waste disposed of in solid waste disposal sites found in Table HH-2 of this subpart, and calculate the waste quantity landfilled using Equation HH-2 of this section.

x x x WDR POPW   (Eq. HH-2) Where: W x = Quantity of waste placed in the landfill in year x (metric tons, wet basis). POP x = Population served by the landfill in year x from city population, census data, or other estimates (capita). W D R x = Average per capita waste disposal rate for year x from Table HH-2 of this subpart (metric tons per capita per year, wet basis; tons/cap/yr). (iii) Use a constant average waste disposal quantity calculated using Equation HH-3 of this section for each year the landfill was in operation (i.e., from the first Deleted: and use that method to estimate waste disposal quantities

Deleted:

Deleted: reporting

Deleted: of

Deleted: G Deleted: generation

Deleted: %SWDS = Percent of waste generated subsequently managed in solid waste disposal sites (i.e., landfills) for year x from Table HH-2 of this subpart.¶304

year accepting waste until the last year for which waste disposal data is unavailable, inclusive). 

##   1   YrOpen YrData LFC W

x (Eq. HH-3)
Where:
W x = Quantity of waste placed in the landfill in year x (metric tons, wet basis)
. LFC = Landfill capacity or, for operating landfills, capacity of the landfill used (or the total quantity of waste-in-place) at the end of the year prior to the year when waste disposal data are available from design drawings or engineering estimates (metric tons). YrData = Year in which the landfill last received waste or, for operating landfills, the year prior to the first reporting year when waste disposal data is first available from company records, or best available data. YrOpen = Year in which the landfill first received waste from company records or best available data. If no data are available for estimating YrOpen for a closed landfill, use 30 years as the default operating life of the landfill. (b) For landfills with gas collection systems, calculate the quantity of CH 4 destroyed according to the requirements in paragraphs (b)(1) and (b)(2) of this section. (1) If you continuously monitor the flow rate, CH 4 concentration, temperature, pressure, and , if necessary, moisture content of the landfill gas that is collected and routed to a destruction device (before any treatment equipment) using a monitoring meter specifically for CH 4 Deleted: A R Deleted: Annual average waste acceptance rate (metric tons per year) Deleted: currently305
gas, as specified in §98.344, you must use this monitoring system and calculate the quantity of CH 4 recovered for destruction using Equation HH-4 of this section. A fully integrated system that directly reports CH 4 content requires no other calculation than summing the results of all monitoring periods for a given year. 

##          1,000 0.454 atm 1

P T R520 0.0423 100%

C V R N

1n n

n n n 

## 

            n MC K (Eq. HH-4)

Where: R = Annual quantity of recovered CH 4 (metric tons CH 4 ). N = Total number of measurement periods in a year. Use daily averaging periods for continuous monitoring system and N=365 (or N=366 for leap years) . For weekly sampling, as provided in paragraph (b)(2) of this section, use N=52.

n = Index for measurement period. (V) n = Cumulative volumetric flow for the measurement period in actual cubic feet (acf). If the flow rate meter automatically corrects for temperature and pressure, replace “520°R/(T) n × (P) n /1 atm” with “1”. (K MC ) n = M oisture correction term for the measurement period, volumetric basis, as follows: (K MC ) n = 1 when (V) n and (C) n are both measured on a dry basis or if both are measured on a wet basis; (K MC ) n = [1-(f H2O ) n ] when (V) n is measured on a wet basis and (C) n is measured on a dry basis; and (K MC ) n = 1/[1-(f H2O ) n ] when (V) n is measured on a dry basis and (C) n is measured on a wet basis. (f H2O ) n = Average moisture content of landfill gas during the measurement period, volumetric Deleted: ( Deleted: )

Deleted: Daily average Deleted: rate Deleted: day n Deleted: m Deleted: If the CH 4 concentration is determined on a dry basis and the flow rate meter automatically corrects for moisture content, replace the term [1-(f H 20 ) n ] with 1. Deleted: (f H 2O ) n Deleted: Daily average m Deleted: content306
basis (cubic feet water per cubic feet landfill gas) (C CH4 ) n = A verage CH 4 concentration of landfill gas for the measurement period (volume %). 0.0423 = Density of CH 4 lb/cf at 520°R or 60°F and 1 atm. (T) n = Temperature at which flow is measured for the measurement period (°R). (P) n = Pressure at which flow is measured for the measurement period (atm). 0.454/1,000 = Conversion factor (metric ton/lb). (2) If you do not continuously monitor according to paragraph (b)(1) of this section, you must determine the flow rate, CH 4 concentration, temperature, pressure, and moisture content of the landfill gas that is collected and routed to a destruction device (before any treatment equipment) according to the requirements in paragraphs (b)(2)(i) through (b)(2)(iii) of this section and calculate the quantity of CH 4 recovered for destruction using Equation HH-4 of this section. (i) Continuously monitor gas flow rate and determine the cumulative volume of landfill gas each week and the cumulative volume of landfill gas each year that is collected and routed to a destruction device (before any treatment equipment). Under this option, the gas flow meter is not required to automatically correct for temperature, pressure, or, if necessary, moisture content. If the gas flow meter is not equipped with automatic Deleted: of landfill gas, volumetric basis (cubic feet water per cubic feet landfill gas). ¶ Deleted: Daily a Deleted: day n Deleted: , dry basis Deleted: If the CH 4 concentration is determined on a wet basis, replace the term [1-(f H 20 ) n ] with 1. Deleted: day n Deleted: day Deleted: n Deleted: 1,440 = Conversion factor (min/day). ¶

Deleted: at least weekly307
correction for temperature, pressure, or, if necessary, moisture content, you must determine these parameters as specified in paragraph (b)(2)(iii) of this section. (ii) Determine the CH 4 concentration in the landfill gas that is collected and routed to a destruction device (before any treatment equipment) in a location near or representative of the location of the gas flow meter once each calendar week, with at least three days between
measurements . (iii) If the gas flow meter is not equipped with automatic correction for temperature, pressure, or, if necessary, moisture content: (A) Determine the temperature and pressure in the landfill gas that is collected and routed to a destruction device (before any treatment equipment) in a location near or representative of the location of the gas flow meter once each calendar week, with at least three days between
measurements . (B) If the CH 4 concentration is determined on a dry basis and flow is determined on a wet basis or CH 4 concentration is determined on a wet basis and flow is determined on a dry basis, and the flow meter does not automatically correct for moisture content , determine the moisture content in the landfill gas that is collected and Deleted: no less than weekly

Deleted: ,

Deleted: no less than weekly308
routed to a destruction device (before any treatment equipment) in a location near or representative of the location of the gas flow meter once each calendar week, with at least three days between measurements. (c) For all landfills, c alculate CH 4 generation (adjusted for oxidation in cover materials) and actual CH 4 emissions (taking into account any CH 4 recovery, and oxidation in cover materials) according to the applicable methods in paragraphs (c)(1) through (c)(3) of this section. (1) Calculate CH 4 generation, adjusted for oxidation, from the modeled CH 4 (G CH4 from Equation HH-1 of this section) using Equation HH-5 of this section. OX)- (1 G MG CH4   (Eq. HH-5) Where:

MG = Methane generation, adjusted for oxidation, from the landfill in the reporting year (metric tons CH 4 ). G CH4 = Modeled methane generation rate in reporting year from Equation HH-1 of this section (metric tons CH 4 ). OX = Oxidation fraction. Use the default value of 0.1 (10%). (2) For landfills that do not have landfill gas collection systems, the CH 4 emissions are equal to the CH 4 Deleted: no less than weekly

Deleted: C309
generation (MG) calculated in Equation HH-5 of this section. (3) For landfills with landfill gas collection systems, calculate CH 4 emissions using the methodologies specified in paragraphs (c)(3)(i) and (c)(3)(ii) of this section. (i) Calculate CH 4 emissions from the modeled CH 4 generation and measured CH 4 recovery using Equation HH-6 of this section. 

##         

##   Dest CH4 fDE1ROX1R- G Emissions 
  

   (Eq. HH-6) Where: Emissions = Methane emissions from the landfill in the reporting year (metric tons CH 4 ). G CH4 = Modeled methane generation rate in reporting year from Equation HH-1 of this section or the quantity of recovered CH 4 from Equation HH-4 of this section, whichever is greater (metric tons CH 4 ). R = Quantity of recovered CH 4 from Equation HH-4 of this section (metric tons). OX = Oxidation fraction. Use the oxidation fraction default value of 0.1 (10%). DE = Destruction efficiency (lesser of manufacturer’s specified destruction efficiency and 0.99). If the gas is transported off-site for destruction, use DE = 1. f Dest = Fraction of hours the destruction device was operating (annual operating hours/8760 hoursper year). If the gas is destroyed in a backup flare (or simlar device) or if the gas is transported off-site for destruction, use f Dest = 1.310

(ii) Calculate CH 4 generation and CH 4 emissions using measured CH 4 recovery and estimated gas collection efficiency and Equations HH-7 and HH-8 of this section.
OX)- (1 fCE R MG Rec    (Eq. HH-7) 

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

   Dest Rec fDE1ROX1R fCE R Emissions (Eq. HH-8)

Where: MG = Methane generation, adjusted for oxidation, from the landfill in the reporting year (metric tons CH 4 ). Emissions = Methane emissions from the landfill in the reporting year (metric tons CH 4 ). R = Quantity of recovered CH 4 from Equation HH-4 of this section (metric tons CH 4 ). CE = Collection efficiency estimated at landfill, taking into account system coverage, operation, and cover system materials from Table HH-3 of this subpart. If area by soil cover type information is not available, use default value of 0.75 (CE4 in table HH-3 of this subpart) for all areas under active influence of the collection system. f Rec = Fraction of hours the recovery system was operating (annual operating hours/8760 hours per year). OX = Oxidation fraction. Use the oxidation fractions default value of 0.1 (10%). DE = Destruction efficiency, (lesser of manufacturer’s specified destruction efficiency and 0.99). If the gas is transported off-site for destruction, use DE = 1. f Dest = Fraction of hours the destruction device was operating (device operating hours/8760 hoursper year). If the gas is destroyed in a backup flare (or similar device) or if the gas is transported off-site for destruction, use f Dest = 1. §98.344 Monitoring and QA/QC requirements.311

(a) Mass measurement equipment used to determine t he quantity of waste landfilled on or after January 1, 2010 must meet the requirements for 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). (b) For landfills with gas collection systems, operate, maintain, and calibrate a gas composition monitor capable of measuring the concentration of CH 4 in the recovered landfill gas using one of the methods specified in paragraphs (b)(1) through (b)(6) of this section or as specified by the manufacturer. Gas composition monitors shall be calibrated prior to the first reporting year and recalibrated either annually or at the minimum frequency specified by the manufacturer, whichever is more frequent, or whenever the error in the midrange calibration check exceeds +/- 10 percent. (1) Method 18 at 40 CFR part 60, appendix A-6. (2) ASTM D1945-03, Standard Test Method for Analysis of Natural Gas by Gas Chromatography (incorporated by reference, see §98.7). Deleted: T

Deleted: be determined using mass measurement equipment Deleted: ing Deleted: commercial

Deleted: install,312
(3) ASTM D1946-90 (Reapproved 2006), Standard Practice for Analysis of Reformed Gas by Gas Chromatography (incorporated by reference, see §98.7). (4) GPA Standard 2261-00, Analysis for Natural Gas and Similar Gaseous Mixtures by Gas Chromatography. (5) UOP539-97 Refinery Gas Analysis by Gas Chromatography (incorporated by reference, see §98.7). (6) As an alternative to the gas chromatography methods provided in paragraphs (b)(1) through (b)(5) of this section, you may use total gaseous organic concentration analyzers and calculate the methane concentration following the requirements in paragraphs (b)(6)(i) through (b)(6)(iii) of this section. (i) Use Method 25A or 25B at 40 CFR part 60, appendix A-7 to determine total gaseous organic concentration. You must calibrate the instrument with methane and determine the total gaseous organic concentration as carbon (or as methane; K=1 in Equation 25A-1 of Method 25A at 40 CFR part 60, appendix A-7). (ii) Determine a non-methane organic carbon correction factor at the routine sampling location no less frequently than once a reporting year following the requirements in paragraphs (b)(6)(ii)(A) through (b)(6)(ii)(C) of this section.313
(A) Take a minimum of three grab samples of the landfill gas with a minimum of 20 minutes between samples and determine the methane composition of the landfill gas using one of the methods specified in paragraphs (b)(1) through (b)(5) of this section. (B) As soon as practical after each grab sample is collected and prior to the collection of a subsequent grab sample, determine the total gaseous organic concentration of the landfilll gas using either Method 25A or 25B at 40 CFR part 60, appendix A-7 as specified in paragaph (b)(6)(i) of this section. (C) Determine the arithmetic average methane concentration and the arithmetic average total gaseous organic concentration of the samples analyzed according to paragraphs (b)(6)(ii)(A) and (b)(6)(ii)(B) of this section, respectively, and calculate the non-methane organic carbon correction factor as the ratio of the average methane concentration to the average total gaseous organicconcentration. If the ratio exceeds 1, use 1 for the nonmethane organic carbon correction factor. (iii) Calculate the methane concentration as specified in Equation HH-9 of this section.

TGOC NMOC Cf   C

CH4 (Eq. HH-9) Where: Deleted: that is collected and routed to a destruction device (before any treatment equipment)

Deleted: specificed

Deleted: that is collected and routed to a destruction device (before any treatment equipment)314

C CH4 = Methane concentration in the landfill gas (volume %) for use in Equation HH-4
. f NMOC = Non-methane organic carbon correction factorfrom the most recent determination of the nonmethane organic carbon correction factor as specified in paragraph (b)(6)(ii) of this section (unitless). C TGOC = Total gaseous organic carbon concentration measured using Method 25A or 25B at 40 CFR part 60, appendix A-7 during routine monitoring of the landfill gas (volume %). (c) For landfills with gas collection systems, install, operate, maintain, and calibrate a gas flow meter capable of measuring the volumetric flow rate of the recovered landfill gas using one of the methods specified in paragraphs (c)(1) through (c)(8) of this section or as specified by the manufacturer. Each gas flow meter shall be recalibrated either biennially (every 2 years) or at the minimum frequency specified by the manufacturer. Except as provided in §98.343(b)(2)(i), each gas flow meter must be capable of correcting for the temperature and pressure and, if necessary , moisture content. (1) ASME MFC-3M-2004, Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and Venturi (incorporated by reference, see §98.7). Deleted: calibrated prior to the first year of reporting and

Deleted: the gas composition monitor determines CH 4 concentration on a dry basis315
(2) ASME MFC-4M-1986 (Reaffirmed 1997), Measurement of Gas Flow by Turbine Meters (incorporated by reference, see §98.7). (3) ASME MFC-6M-1998, Measurement of Fluid Flow in Pipes Using Vortex Flowmeters (incorporated by reference, see §98.7). (4) ASME MFC-7M-1987 (Reaffirmed 1992), Measurement of Gas Flow by Means of Critical Flow Venturi Nozzles (incorporated by reference, see §98.7). (5) ASME MFC-11M-2006 Measurement of Fluid Flow by Means of Coriolis Mass Flowmeters (incorporated by reference, see §98.7). The mass flow must be corrected to volumetric flow based on the measured temperature, pressure, and gas composition. (6) ASME MFC-14M-2003 Measurement of Fluid Flow Using Small Bore Precision Orifice Meters (incorporated by reference, see §98.7). (7) ASME MFC-18M-2001 Measurement of Fluid Flow using Variable Area Meters (incorporated by reference, see §98.7). (8) Method 2A or 2D at 40 CFR part 60, appendix A-1. (d) All temperature , pressure , and if necessary, moisture content monitors must be calibrated using the procedures and frequencies specified by the manufacturer. Deleted: and316
(e) The owner or operator shall document the procedures used to ensure the accuracy of the estimates of disposal quantities and, if applicable, gas flow rate, gas composition, temperature, pressure , and moisture content measurements. These procedures include, but are not limited to, calibration of weighing equipment, fuel flow meters, and other measurement devices. The estimated accuracy of measurements made with these devices shall also be recorded, and the technical basis for these estimates shall be provided. §98.345 Procedures for estimating missing data. A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable (e.g., if a meter malfunctions during unit operation or if a required fuel sample is not taken), a substitute data value for the missing parameter shall be used in the calculations, according to the requirements in paragraphs (a) through (c) of this section. (a) For each missing value of the CH 4 content, the substitute data value shall be the arithmetic average of the quality-assured values of that parameter immediately preceding and immediately following the missing data incident. If the “after” value is not obtained by the end Deleted: and317
of the reporting year, you may use the “before” value for the missing data substitution. If, for a particular parameter, no quality-assured data are available prior to the missing data incident, the substitute data value shall be the first quality-assured value obtained after the missing data period. (b) For missing gas flow rates, the substitute datavalue shall be the arithmetic average of the qualityassured values of that parameter immediately preceding 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 datasubstitution. If, for a particular parameter, no qualityassured data are available prior to the missing data incident, the substitute data value shall be the first quality-assured value obtained after the missing data period. (c) For missing daily waste disposal quantity data for disposal in reporting years, the substitute value shall be the average daily waste disposal quantity for that day of the week as measured on the week before and week after the missing daily data. §98.346 Data reporting requirements.318
In addition to the information required by §98.3(c), each annual report must contain the following information for each landfill. (a) A classification of the landfill as “open” (actively received waste in the reporting year) or “closed” (no longer receiving waste), the year in which the landfill first started accepting waste for disposal, the last year the landfill accepted waste (for open landfills, enter the estimated year of landfill closure), the capacity (in metric tons) of the landfill, an indication of whether leachate recirculation is used during the reporting year and its typical frequency of use over the past 10 years (e.g., used several times a year for the past 10 years, used at least once a year for the past 10 years, used occasionally but not every year over the past 10 years, not used) , an indication as to whether scales are present at the landfill, and the waste disposal quantity for each year of landfilling required to be included when using Equation HH-1 of this subpart (in metric tons, wet weight)
. (b) Method for estimating reporting year and historical waste disposal quantit ies , reason for its selection , and the range of years it is applied
. For years when waste quantity data are determined using the methods in §98.343(a)(3), report separately the quantity of waste Deleted: y Deleted: and319
determined using the methods in §98.343(a)(3)(i) and the quantity of waste determined using the methods in §98.343(a)(3)(ii). For historical waste disposal quantities that were not determined using the methods in §98.343(a)(3), provide the population served by the landfill for each year the Equation HH-2 of this subpart is applied, if applicable, or, for open landfills using Equation HH-3 of this subpart, provide the value of landfill capacity (LFC) used in the calculation. (c) Waste composition for each year of landfilling, if available, in percentage categorized as: (1) Municipal. (2) Biosolids or biological sludges. (3) Other, or more refined categories, such as those for which k rates are available in Table HH-1 of this subpart, and the method or basis for estimating waste composition. (d) For each waste type used to calculate CH 4 generation using Equation HH-1 of this subpart, you must report: (1) Degradable organic carbon (DOC) , methane correction factor (MCF), and fraction of DOC dissimilated (DOC F ) value s used in the calculations. (2) Decay rate (k) value used in the calculations.320
(e) Fraction of CH 4 in landfill gas (F) and an indication of whether the fraction of CH 4 was determined based on measured values or the default value. (f) The surface area of the landfill containing waste (in square meters), identification of the type of cover material used (as either organic cover, clay cover, sand cover, or other soil mixtures). If multiple cover types are used, the surface area associated with each cover type

. (g) The modeled annual methane generation rate for the reporting year (metric tons CH 4 ) calculated using Equation HH-1 of this subpart. (h) For landfills without gas collection systems, the annual methane emissions (i.e., the methane generation, adjusted for oxidation, calculated using Equation HH-5 of this subpart), reported in metric tons CH 4 , and an indication of whether passive vents and/or passive flares (vents or flares that are not considered part of the gas collection system as defined in §98.6) are present at this landfill
. (i) For landfills with gas collection systems, you must report: Deleted: the

Deleted: types

Deleted: applicable to the landfill, Deleted: and oxidation fraction for Deleted: used to calculate the average oxidation fraction, and the average oxidation fraction used in the calculations Deleted:321
(1) Total volumetric flow of landfill gas collected for destruction for the reporting year (cubic feet at 520°R or 60°F and 1 atm). (2) Annual average CH 4 concentration of landfill gas collected for destruction (percent by volume). (3) Monthly average temperature and pressure for each month at which flow is measured for landfill gas collected for destruction, or statement that temperature and/or
pressure is incorporated into internal calcuations run by the monitoring equipment. (4) An indication as to whether flow was measured on a wet or dry basis, an indication as to whether CH 4 concntration was measured on a wet or dry basis, and if required for Equation HH-4, m onthly average moisture
content for each month at which flow is measured for landfill gas collected for destruction.(5) An indication of whether destruction occurs at the landfill facility or off-site. If destruction occurs at the landfill facility, also report an indication of whether a back-up destruction device is present at the landfill, the annual operating hours for the primary destruction device, the annual operating hours for the back-up destruction device (if present), and the destruction efficiency used (percent). Deleted: M Deleted: pressure

Deleted: , or statement that temperature is incorporated into internal calcuations run by the monitoring equipment Deleted: ¶

Deleted: operting322
(6) Annual quantity of recovered CH 4 (metric tons CH 4 ) calculated using Equation HH-4 of this subpart. (7) A description of the gas collection system (manufacture r , capacity, and number of wells), the surface area (square meters) and estimated waste depth (meters) for each area specified in Table HH-3 of this subpart, the estimated gas collection system efficiency for landfills with this gas collection system, the annual operating hours of the gas collection system , and an indication of whether passive vents and/or passive flares (vents or flares that are not considered part of the gas collection system as defined in §98.6) are present at the landfill
. (8) Methane generation corrected for oxidation calculated using Equation HH-5 of this subpart, reported in metric tons CH 4 . (9) Methane generation (G CH4 ) value used as an input to Equation HH-6 of this subpart. Specify whether the value is modeled (G CH4 from HH-1 of this subpart or measured (R from Equation HH-4 of this subpart). (10) Methane generation corrected for oxidation calculated using Equation HH-7 of this subpart, reported in metric tons CH 4 . (11) Methane emissions calculated using Equation HH-6 of this subpart, reported in metric tons CH 4 . Deleted: , etc.

Deleted: and

Deleted:

Deleted:323
(12) Methane emissions calculated using Equation HH-8 of this subpart, reported in metric tons CH 4 . §98.347 Records that must be retained. In addition to the information required by §98.3(g), you must retain the calibration records for all monitoring equipment, including the method or manufacturer’s specification used for calibration. You must retain records of all measurements made to determine tare weights and working capacities by vehicle/containter type if these are used to determine the annual waste quantities. §98.348 Definitions. Except as specified in this section, a ll terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Dedicated construction and demolition landfill means a landfill that only receives materials generated from the construction or destruction of structures such as buildings, roads, and bridges. Destruction device means a flare, thermal oxidizer, boiler, turbine, internal combustion engine, or any other combustion unit used to destroy or oxidize methane contained in landfill gas. Industrial waste landfill means any landfill other than a municipal solid waste landfill, a RCRA Subtitle C Deleted: A324
hazardous waste landfill, or a TSCA hazardous waste landfill, in which industrial solid waste, such a RCRA Subtitle D wastes (nonhazardous industrial solid waste, defined in 40 CFR 257.2), commercial solid wastes, or conditionally exempt small quantity generator wastes, is placed. An industrial waste landfill includes all disposal areas at the facility. Solid waste has the meaning established by the Administrator pursuant to the Solid Waste Disposal Act [42 U.S.C.A. § 6901 et seq.] Working capacity means the maximum volume or mass of waste that is actually placed in the landfill from an individual or representative type of container (such as a tank, truck, or roll-off bin) used to convey wastes to the landfill, taking into account that the container may not be able to be 100 perceont filled and/or 100 percent emptied
for each load. **Table HH-1 to**  **Subpart HH—Emissions Factors, Oxidation Factors and Methods** 

**Factor Default value**  **Units Waste model-- bulk waste option**  k (precipitation plus recirculated leachate a <20 inches/year) 0.02 yr -1

k (precipitation plus recirculated leachate a 20-40 inches/year) 0.038 yr -1

k (precipitation plus recirculated leachate a 0.057 yr -1 Deleted: **of**

Deleted: and no leachate recirculation

Deleted: and no leachate recirculation325

**Factor Default value**  **Units** >40 inches/year)

DOC (bulk waste) 0.20 Weight fraction, wet basis

**Waste model—All MSW landfills** MCF 1 DOC F 0.5 F 0.5 **Waste model—MSW using waste composition option** DOC (food waste) 0.15 Weight fraction, wet basis DOC (garden) 0.2 Weight fraction, wet basis DOC (paper) 0.4 Weight fraction, wet basis DOC (wood and straw) 0.43 Weight fraction, wet basis DOC (textiles) 0.24 Weight fraction, wet basis DOC (diapers) 0.24 Weight fraction, wet basis DOC (sewage sludge) 0.05 Weight fraction, wet basis DOC (inerts, e.g. glass, plastics, metal, cement) 0.00 Weight fraction, wet basis DOC (bulk waste) 0.20 Weight fraction, wet basis k (food waste) 0.06 to 0.185 b yr -1 k (garden) 0.05 to 0. 10 b yr -1 k (paper) 0.04 to 0. 06 b yr -1 k (wood and straw) 0.02 to 0. 03 b yr -1 k (textiles) 0.04 to 0. 06 b yr -1 k (diapers) 0.05 to 0. 10 b yr -1 k (sewage sludge) 0.06 to 0. 185 b yr -1 k (inerts e.g. glass, plastics, metal, cement) 0.00 b yr -1

**Calculating methane generation and emissions** Deleted: or for landfill areas with leachate recirculation

Deleted: L 0 (Equivalent to DOC = 0.2028 when MCF=1, DOC F =0.5, and F=0.5)

Deleted: a Deleted: 10 a Deleted: 06 a Deleted: 03 a Deleted: 06 a Deleted: 10 a

Deleted: 185 a ... [1]326

**Factor Default value**  **Units** OX 0.1 DE 0.99

a Recirculated leachate (in inches/year) is the total volume of leachate recirculated divided by the area of the portion of the landfill containing waste with appropriate unit conversions. b Use the lesser value when the potential evapotranspiration rate exceeds the mean annual precipitation rate plus recirculated leachate. Use the greater value when the potential evapotranspiration rate does not exceed the mean annual precipitation rate plus recirculated leachate. **Table HH-2 to**  **Subpart HH—U.S. Per Capita Waste Disposal Rates** 

**Year Waste per capita**  ton/cap/yr 1960 0.63 1961 0.64 1962 0.64 1963 0.65 1964 0.65 1965 0.66 1966 0.66 1967 0.67 1968 0.68 1969 0.68 1970 0.69 1971 0.69 1972 0.70 1973 0.71 1974 0.71 1975 0.72 1976 0.73 1977 0.73 1978 0.74 1979 0.75 1980 0.75 1981 0.76 1982 0.77 1983 0.77 1984 0.78 1985 0.79 1986 0.79 1987 0.80 1988 0.80 1989 0. 83 1990 0.8 2 Deleted: a Deleted: and Deleted: recirculation is not used Deleted: or when Deleted: recirculation is used Deleted: **of** Deleted: 1950

Deleted: 85 Deleted: 4 ... [2]327

**Year Waste per capita**  ton/cap/yr 1991 0.7 6 1992 0.7 4 1993 0.7 6 1994 0.7 5 1995 0.7 0 1996 0. 68 1997 0. 69 1998 0. 75 1999 0. 75 2000 0.8 0 2001 0.9 1 2002 1.0 2 2003 1.0 2 2004 1.0 1 2005 0.98 2006 0.95 2007 0.95 2008 0.95 2009 0.95 **Table HH-3 to**  **Subpart HH—Landfill Gas Collection Efficiencies**  **Description Landfill Gas Collection**  **Efficiency** A1: Area with no waste in-place Not applicable; do not use this area in the calculation. A2: Area without active gas collection, regardless of cover type CE2: 0%.

A3: Area with daily soil cover and active gas collection CE3: 60%.

A4: Area with an intermediate soil cover , or a final sold cover not meeting the criteria for A5 below, and active gas collection CE4: 75%.

A5: Area with a final soil cover of 3 feet or thicker of clay and /or geomembrane cover system and active gas collection CE5: 95%.

Area weighted average collection efficiency for landfills CEave1 = (A2*CE2 + A3*CE3 + A4*CE4 + A5*CE5)/(A2+A3+A4+A5). Deleted: 1950 Deleted: 8 Deleted: 6 Deleted: 8 Deleted: 7 Deleted: 2 Deleted: 71 Deleted: 72 Deleted: 78 Deleted: 78 Deleted: 4 Deleted: 5 Deleted: 6 Deleted: 6 Deleted: 6 Deleted: 1.06 Deleted: 1.06

Deleted: **of**

Deleted: H2: Average depth of waste in area A2

Deleted: H3: Average depth of waste in area A3

Deleted: H4: Average depth of waste in area A4

Deleted: H5: Average depth of waste in area A5 ... [3]328
**Subpart LL—Suppliers of Coal-based Liquid Fuels** §98.380 Definition of the source category. This source category consists of producers, importers, and exporters of products listed in Table MM-1 of subpart MM that are coal-based (coal-to-liquid products).(a) A producer is the owner or operator of a coal-toliquids facility. A coal-to-liquids facility is any facility engaged in converting coal into liquid products using a process involving conversion of coal into gas and then into liquids (e.g., Fischer-Tropsch) or conversion of coal directly into liquids (i.e., direct liquefaction). (b) An importer or exporter shall have the same meaning given in §98.6. §98.381 Reporting threshold. Any supplier of coal-to-liquid products who meets the requirements of §98.2(a)(4) must report GHG emissions. §98.382 GHGs to report. You must report the CO 2 emissions that would result from the complete combustion or oxidation of fossil-fuel products (besides coal or crude oil) that you produce, use as feedstock, import, or export during the calendar year. Additionally, producers must report CO 2 emissions that would result from the complete combustion or oxidation of any biomass co-processed with fossil fuel-based feedstocks.329
§98.383 Calculating GHG emissions. You must follow the calculation methodologies of§98.393 as if they applied to the appropriate coal-toliquid product supplier (i.e., calculation methodologies for refiners apply to producers of coal-to-liquid products and calculation methodologies for importers and exporters of petroleum products apply to importers and exporters of coal-to-liquid products). (a) In calculation methodologies in §98.393 for petroleum products or petroleum-based products, suppliersof coal-to-liquid products shall also include coal-toliquid products.(b) In calculation methodologies in §98.393 for noncrude feedstocks or non-crude petroleum feedstocks, producers of coal-to-liquid products shall also include coal-to-liquid products that enter the facility to be further processed or otherwise used on site. (c) In calculation methodologies in §98.393 for petroleum feedstocks, suppliers of coal-to-liquid products shall also include coal and coal-to-liquid products that enter the facility to be further processed or otherwise used on site. §98.384 Monitoring and QA/QC requirements.330 You must follow the monitoring and QA/QC requirementsin §98.394 as if they applied to the appropriate coal-toliquid product supplier. Any monitoring and QA/QC requirement for petroleum products in §98.394 also applies to coal-to-liquid products. §98.385 Procedures for estimating missing data. You must follow the procedures for estimating missingdata in §98.395 as if they applied to the appropriate coalto-liquid product supplier. Any procedure for estimating missing data for petroleum products in §98.395 also applies to coal-to-liquid products. §98.386 Data reporting requirements. In addition to the information required by §98.3(c), the following requirements apply: (a) Producers shall report the following information for each coal-to-liquid facility: (1) For each product listed in Table MM-1 of subpart MM of this part that enters the coal-to-liquid facility to be further processed or otherwise used on site, report the annual quantity in metric tons or barrels by each quantity measurement standard method or other industry standard practice used. For natural gas liquids, quantity shall reflect the individual components of the product.331
(2) For each product listed in Table MM-1 of subpart MM of this part that enters the coal-to-liquid facility to be further processed or otherwise used on site, report the total annual quantity in metric tons or barrels. For natural gas liquids, quantity shall reflect the individual components of the product. (3) For each feedstock reported in paragraph (a)(2) that was produced by blending a fossil fuel-based product with a biomass-based product, report the percent of the volume reported in paragraph (a)(2) of this section that is fossil fuel-based. (4) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (a)(1) of this section. (5) For each product (leaving the coal-to-liquid facility) listed in Table MM-1 of subpart MM of this part, report the annual quantity in metric tons or barrels by each quantity measurement standard method or other industry standard practice used. For natural gas liquids, quantity shall reflect the individual components of the product. Those products that enter the facility, but are not reported in (a)(1), shall not be reported under this paragraph.332
(6) For each product (leaving the coal-to-liquid facility) listed in Table MM-1 of subpart MM of this part, report the total annual quantity in metric tons or barrels. For natural gas liquids, quantity shall reflect the individual components of the product. Those products that enter the facility, but are not reported in (a)(2), shall not be reported under this paragraph. (7) For each product reported in paragraph (a)(6) ofthis section that was produced by blending a fossil fuelbased product with a biomass-based product, report the percent of the volume reported in paragraph (a)(6) of this section that is fossil fuel-based. (8) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (a)(5) of this section. (9) For every feedstock reported in paragraph (a)(2) of this section for which Calculation Methodology 2 of subpart MM of this part was used to determine an emissions factor, report: (i) The number of samples collected according to §98.394(c). (ii) The sampling standard method used. (iii) The carbon share test results in percent mass. (iv) The standard method used to test carbon share.333

(v) The calculated CO 2 emissions factor. (10) For every non-solid feedstock reported in paragraph (a)(2) of this section for which Calculation Methodology 2 of subpart MM of this part was used to determine an emissions factor, report: (i) The density test results in metric tons per barrel. (ii) The standard method used to test density. (11) For every product reported in paragraph (a)(6) of this section for which Calculation Methodology 2 of this subpart was used to determine an emissions factor, report: (i) The number of samples collected according to §98.394(c). (ii) The sampling standard method used. (iii) The carbon share test results in percent mass. (iv) The standard method used to test carbon share. (v) The calculated CO 2 emissions factor. (12) For every non-solid product reported in paragraph (a)(6) of this section for which Calculation Methodology 2 of subpart MM of this part was used to determine an emissions factor, report: (i) The density test results in metric tons per barrel. (ii) The standard method used to test density.334
(13) For each specific type of biomass that enters the coal-to-liquid facility to be co-processed with fossil fuel-based feedstock to produce a product reported in paragraph (a)(6) of this section, report the annual quantity in metric tons or barrels by each quantity measurement standard method or other industry standard practice used. (14) For each specific type of biomass that enters the coal-to-liquid facility to be co-processed with fossil fuel-based feedstock to produce a product reported in paragraph (a)(6) of this section, report the total annual quantity in metric tons or barrels. (15) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (a)(3) of this section. (16) The CO 2 emissions in metric tons that would result from the complete combustion or oxidation of each feedstock reported in paragraph (a)(2) of this section, calculated according to §98.393(b) or (h). (17) The CO 2 emissions in metric tons that would result from the complete combustion or oxidation of each product (leaving the coal-to-liquid facility) reported in paragraph (a)(6) of this section, calculated according to §98.393(a) or (h).335
(18) Annual CO 2 emissions in metric tons that would result from the complete combustion or oxidation of eachtype of biomass feedstock co-processed with fossil fuelbased feedstocks reported in paragraph (a)(3) of this section, calculated according to §98.393(c). (19) Annual CO 2 emissions that would result from the complete combustion or oxidation of all products, calculated according to §98.393(d). (20) Annual quantity of bulk NGLs in metric tons or barrels received for processing during the reporting year. (b) In addition to the information required by §98.3(c), each importer shall report all of the following information at the corporate level: (1) For each product listed in Table MM-1 of subpart MM of this part, report the annual quantity in metric tons or barrels by each quantity measurement standard method or other industry standard practice used. For natural gas liquids, quantity shall reflect the individual components of the product. (2) For each product listed in Table MM-1 of subpart MM of this part, report the total annual quantity in metric tons or barrels. For natural gas liquids, quantity shall reflect the individual components of the product as listed in Table MM-1 of subpart MM of this part.336
(3) For each product reported in paragraph (b)(2) ofthis section that was produced by blending a fossil fuelbased product with a biomass-based product, report the percent of the volume reported in paragraph (b)(2) of this section that is fossil fuel-based. (4) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (b)(1) of this section. (5) For each product reported in paragraph (b)(2) of this section for which Calculation Methodology 2 of this subpart used was used to determine an emissions factor, report: (i) The number of samples collected according to §98.394(c) (ii) The sampling standard method used. (iii) The carbon share test results in percent mass. (iv) The standard method used to test carbon share. (v) The calculated CO 2 emissions factor in metric
tons. (6) For each non-solid product reported in paragraph (b)(2) of this section for which Calculation Methodology 2 of this subpart was used to determine an emissions factor, report:337
(i) The density test results in metric tons ber barrel. (ii) The standard method used to test density. (7) The CO 2 emissions in metric tons that would result from the complete combustion or oxidation of each imported product reported in paragraph (b)(2) of this section, calculated according to §98.393(a). (8) The total sum of CO 2 emissions that would result from the complete combution or oxidatio of all imported products, calculated according to §98.393(e). (c) In addition to the information required by §98.3(c), each exporter shall report all of the following information at the corporate level: (1) For each product listed in Table MM-1 of subpart MM of this part, report the annual quantity in metric tons or barrels by each quantity measurement standard method or other industry standard practice used. For natural gas liquids, quantity shall reflect the individual components of the product. (2) For each product listed in table MM-1 of subpart MM of this part, report the total annual quantity in metric tons or barrels. For natural gas liquids, quantity shall reflect the individual components of the product.338
(3) For each product reported in paragraph (c)(2) ofthis section that was produced by blending a fossil fuelbased product with a biomass-based product, report the percent of the volume reported in paragraph (c)(2) of this section that is fossil fuel-based. (4) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (c)(1) of this section. (5) For each product reported in paragraph (c)(2) of this section for which Calculation Methodology 2 of this subpart was used to determine an emissions factor, report: (i) The number of samples collected according to §98.394(c). (ii) The sampling standard method used. (iii) The carbon share test results in percent mass. (iv) The standard method used to test carbon share. (v) The calculated CO 2 emissions factor in metric
tons. (6) For each non-solid product reported in paragraph (c)(2) of this section for which Calculation Methodology 2 of this subpart used was used to determine an emissions factor, report: (i) The density test results in metric tons per barrel.339
(ii) The standard method used to test density. (7) The CO 2 emissions in metric tons that would result from the complete combustion or oxidation of each exported product reported in paragraph (c)(2) of this section, calculated according to §98.393(a). (8) Total sum of CO 2 emissions that would result from the complete combustion or oxidation of all exported products, calculated according to §98.393(e). §98.387 Records that must be retained. You must retain records according to the requirementsin §98.397 as if they applied to the appropriate coal-toliquid product supplier (e.g., retaining copies of all reports submitted to EPA under §98.386 and records to support information contained in those reports). Any records for petroleum products that are required to be retained in §98.397 are also required for coal-to-liquid products. §98.388 Definitions. All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. **Subpart MM—Suppliers of Petroleum Products** §98.390 Definition of the source category. This source category consists of petroleum refineries and importers and exporters of petroleum products and340
natural gas liquids as listed in Table MM-1 of this subpart. (a) A petroleum refinery for the purpose of this subpart is any facility engaged in producing petroleum products through the distillation of crude oil. (b) A refiner is the owner or operator of a petroleum refinery. (c) Importer has the same meaning given in §98.6 and includes any entity that imports petroleum products or natural gas liquids as listed in Table MM-1 of this subpart. Any blender or refiner of refined or semi-refined petroleum products shall be considered an importer if it otherwise satisfies the aforementioned definition. (d) Exporter has the same meaning given in §98.6 and includes any entity that exports petroleum products or natural gas liquids as listed in Table MM-1 of this subpart. Any blender or refiner of refined or semi-refined petroleum products shall be considered an exporter if it otherwise satisfies the aforementioned definition. §98.391 Reporting threshold. Any supplier of petroleum products who meets the requirements of §98.2(a)(4) must report GHG emissions. §98.392 GHGs to report.341
Suppliers of petroleum products must report the CO 2 emissions that would result from the complete combustion or oxidation of each petroleum product and natural gas liquid produced, used as feedstock, imported, or exported during the calendar year. Additionally, refiners must report CO 2 emissions that would result from the complete combustion or oxidation of any biomass co-processed with petroleum feedstocks. §98.393 Calculating GHG emissions. (a) Calculation for individual products produced, imported, or exported. (1) Except as provided in paragraph s (h) and (i) of this section, any refiner, importer, or exporter shall calculate CO 2 emissions from each individual petroleum product and natural gas liquid using Equation MM-1 of this section.

CO 2i = Product i * EF i (Eq. MM-1) Where: CO 2i = Annual CO 2 emissions that would result from the complete combustion or oxidation of each petroleum product or natural gas liquid “i” (metric tons). Product i = Annual volume of product “i” produced, imported, or exported by the reporting party (barrels). For refiners, this volume only includes products ex refinery gate , and excludes products that entered the refinery but are not reported under §98.396(a)(1) . For natural gas liquids, volumes shall reflect the342
individual components of the product as listed in Table MM-1 of this subpart. EF i = Product-specific CO 2 emission factor (metric tons CO 2 per barrel). (2) In the event that an individual petroleum product is produced as a solid rather than liquid any refiner, importer, or exporter shall calculate CO 2 emissions using Equation MM-1 of this section, where:

CO 2i = Annual CO 2 emissions that would result from the complete combustion or oxidation of each petroleum product “i” (metric tons). Product i = Annual mass of product “i” produced, imported, or exported by the reporting party (metric tons). For refiners, this mass only includes products ex refinery gate , and excludes products that entered the refinery but are not reported under §98.396(a)(1)
. EF i = Product-specific CO 2 emission factor (metric tons CO 2 per metric ton of product). (b) Calculation for individual products that enter a refinery as a non-crude feedstock. (1) Except as provided in paragraph s (h) and (i) of this section, any refiner shall calculate CO 2 emissions from each non-crude feedstock using Equation MM-2 of this section.

CO 2j = Feedstock j * EF j (Eq. MM-2) Where: CO 2j = Annual CO 2 emissions that would result from the complete combustion or oxidation of each non-crude feedstock “j” (metric tons). Feedstock j = Annual volume of a petroleum product or natural gas liquid “j” that enters the refinery to be further refined or otherwise343
used on site (barrels). For natural gas liquids, volumes shall reflect the individual components of the product as listed in table MM-1 of this subpart. EF j = Feedstock-specific CO 2 emission factor (metric tons CO 2 per barrel). (2) In the event that a non-crude feedstock enters a refinery as a solid rather than liquid, the refiner shall calculate CO 2 emissions using Equation MM-2 of this section, where:
CO 2j = Annual CO 2 emissions that would result from the complete combustion or oxidation of each non-crude feedstock “j” (metric tons). Feedstock j = Annual mass of a petroleum product “j” that enters the refinery to be further refined or otherwise used on site (metric tons). EF j = Feedstock-specific CO 2 emission factor (metric tons CO 2 per metric ton of feedstock). (c) Calculation for biomass co-processed with petroleum feedstocks. (1) Refiners shall calculate CO 2 emissions from each type of biomass that enters a refinery and is co-processed with petroleum feedstocks using Equation MM-3 of this section.

CO 2m = Biomass m * EF m (Eq. MM-3) Where: CO 2m = Annual CO 2 emissions that would result from the complete combustion or oxidation of each type of biomass “m” (metric tons). Biomass m = Annual volume of a specific type of biomass that enters the refinery and is co-processed with petroleum feedstocks to produce a344
petroleum product reported under paragraph (a) of this section (barrels). EF m = Biomass-specific CO 2 emission factor (metric tons CO 2 per barrel). (2) In the event that biomass enters a refinery as a solid rather than liquid and is co-processed with petroleum feedstocks, the refiner shall calculate CO 2 emissions from each type of biomass using Equation MM-3 of this section.

Where: CO 2m = Annual CO 2 emissions that would result from the complete combustion or oxidation of each type of biomass “m” (metric tons). Biomass m = Total annual mass of a specific type ofbiomass that enters the refinery to be coprocessed with petroleum feedstocks to produce a petroleum product reported under paragraph (a) of this section (metric tons). EF m = Biomass-specific CO 2 emission factor (metric tons CO 2 per metric ton of biomass). (d) Summary calculation for refinery products
. Refiners shall calculate annual CO 2 emissions from all products using Equation MM-4 of this section. 

###       

#   

   2m 2j 2i 2r 

### CO CO CO CO (Eq. MM-4) Where: CO 2r = Annual CO 2 emissions that would result from the complete combustion or oxidation of all petroleum products and natural gas liquids (ex refinery gate) minus non-crude feedstocks and any biomass to be co-processed with petroleum feedstocks. CO 2i = Annual CO 2 emissions that would result from the complete combustion or oxidation of each345
petroleum product or natural gas liquid “i” (metric tons). CO 2j = Annual CO 2 emissions that would result from thecomplete combustion or oxidation of each noncrude feedstock “j” (metric tons). CO 2m = Annual CO 2 emissions that would result from the complete combustion or oxidation of each type of biomass “m” (metric tons). (e) Summary calculation for importer and exporter products . Importers and exporters shall calculate annual
CO 2 emissions from all petroleum products and natural gas liquids imported or exported, respectively, using Equations MM-1 and MM-5 of this section. 

###   

#   2i 2x 

### CO CO (Eq. MM-5) Where: CO 2i = Annual CO 2 emissions that would result from the complete combustion or oxidation of each petroleum product or natural gas liquid “i” (metric tons). CO 2x = Annual CO 2 emissions that would result from the complete combustion or oxidation of all petroleum products and natural gas liquids.

(f) Emission factors for petroleum products and natural gas liquids . The emission factor (EF i,j ) for each petroleum product and natural gas liquid shall be determined using either of the calculation methods described in paragraphs (f)(1) or (f)(2) of this section. The same calculation method must be used for the entire quantity of the product for the reporting year. For346
refiners, the quantity of a product that enters a refinery (i.e., a non-crude feedstock) is considered separate from the quantity of a product ex refinery gate. (1) Calculation Method 1
. To determine the emission factor (i.e., EF i in Equation MM-1) f or solid products, multiply the default carbon share factor (i.e., percent carbon by mass) in column B of Table MM–1 of this subpart for the appropriate product by 44/12 . For all other products, use the default CO 2 emission factor listed in column C of Table MM-1 of this subpart for the appropriate product. (2) Calculation Method 2. (i) For solid products, develop emission factors according to Equation MM-6 of this section using a value of 1 for density and direct measurements of carbon share according to methods set forth in §98.394(c). For all other products, develop emission factors according to Equation MM-6 of this section using direct measurements of density and carbon share according to methods set forth in §98.394(c).

EF i,j = Density * Carbon Share * (44/12) (Eq. MM-6) Where: EF i,j = Emission factor of the petroleum product or natural gas liquid (metric tons CO 2 per barrel or per metric ton of product). Deleted: F

Deleted: use the default carbon share factor (i.e., percent carbon by mass) in column B of Table MM-1 of this subpart for the appropriate product347
Density = Density of the petroleum product or naturalgas liquid (metric tons per barrel for nonsolid products, 1 for solid products). Carbon share = Percent of total mass that carbon represents in the petroleum product or natural gas liquid, expressed as a fraction (e.g., 75% would be expressed as 0.75 in the above equation). 44/12 = Conversion factor for carbon to carbon dioxide. (ii) If you use a standard method that involves gas chromatography to determine the percent mass of each component in a product, calculate the product’s carbon share using Equation MM-7 of this section.

Carbon Share = ∑ (%Composition i...n * %Mass i...n) (Eq. MM-7) Where:

Carbon Share = Percent of total mass that carbon represents in the petroleum product or natural gas liquid. %Composition i...n = Percent of total mass that each molecular component in the petroleum product or natural gas liquid represents as determined by the procedures in the selected standard method. %Mass i...n = Percent of total mass that carbon represents in each molecular component of the petroleum product or natural gas liquid. (g) Emission factors for biomass co-processed with petroleum feedstocks . Refiners shall use the most appropriate default CO 2 emission factor (EF m ) for biomass in348
Table MM-2 of this subpart to calculate CO 2 emissions in paragraph (c) of this section. (h) Special procedures for blended biomass-based fuels . In the event that some portion of a petroleumproduct is biomass-based and was not derived by coprocessing biomass and petroleum feedstocks together (i.e.,the petroleum product was produced by blending a petroleumbased product with a biomass-based fuel), the reporting party shall calculate emissions for the petroleum product according to one of the methods in paragraphs (h)(1) through (h)(4) of this section, as appropriate. (1) A reporter using Calculation Methodology 1 to determine the emission factor of a petroleum product shall calculate the CO 2 emissions associated with that product using Equation MM-8 of this section in place of Equation MM-1 of this section.

CO 2i = Product i * EF i * %Vol i (Eq. MM-8) Where: CO 2i = Annual CO 2 emissions that would result from the complete combustion or oxidation of each petroleum product “i” (metric tons). Product i = Annual volume of each petroleum product “i” produced, imported, or exported by the reporting party (barrels). For refiners, this volume only includes products ex refinery gate. EF i = Petroleum product-specific CO 2 emission factor (metric tons CO 2 per barrel) from Table MM-1 of this subpart.349

%Vol i = Percent volume of product “i” that is petroleum-based, not including any denaturant that may be present in any ethanol product, expressed as a fraction (e.g., 75% would be expressed as 0.75 in the above equation). (2) A refinery using Calculation Methodology 1 ofthis subpart to determine the emission factor of a noncrude petroleum feedstock shall calculate the CO 2 emissions associated with that feedstock using Equation MM-9 of this section in place of Equation MM-2 of this section.

CO 2j = Feedstock j * EF j * %Vol j (Eq. MM-9) Where: CO 2j = Annual CO 2 emissions that would result from thecomplete combustion or oxidation of each noncrude feedstock “j” (metric tons). Feedstock j = Annual volume of each petroleum product “j” that enters the refinery as a feedstock to be further refined or otherwise used on site (barrels). EF j = Non-crude petroleum feedstock-specific CO 2 emission factor (metric tons CO 2 per barrel). %Vol j = Percent volume of feedstock “j” that is petroleum-based, not including any denaturant that may be present in any ethanol product, expressed as a fraction (e.g., 75% would be expressed as 0.75 in the above equation). (3) Calculation Method 2 procedures for products. (i) A reporter using Calculation Methodology 2 of this subpart to determine the emission factor of a petroleum product that does not contain denatured ethanol must calculate the CO 2 emissions associated with that Deleted: 2.5% of the volume of any ethanol productblended into a petroleumbased product to represent the Deleted: in

Deleted: i

Deleted: 2.5% of the volume of any ethanol productblended with the petroleumbased product to represent the Deleted: in350
product using Equation MM-10 of this section in place of Equation MM-1 of this section.

CO 2i = (Product i * EF i )-(Product i * EF m * %Vol m ) (Eq. MM-10)

Where: CO 2i = Annual CO 2 emissions that would result from the complete combustion or oxidation of each product “i” (metric tons). Product i = Annual volume of each petroleum product “i” produced, imported, or exported by the reporting party (barrels). For refiners, this volume only includes products ex refinery gate. EF i = Product-specific CO 2 emission factor (metric tons CO 2 per barrel). EF m = Default CO 2 emission factor from Table MM-2 of this subpart that most closely represents the component of product “i” that is biomass-based. %Vol m = Percent volume of petroleum product “i” that is biomass-based, expressed as a fraction (e.g., 75% would be expressed as 0.75 in the above equation). (ii) In the event that a petroleum product contains denatured ethanol, importers and exporters must follow Calculation Method 1 procedures in paragraph (h)(1); and refineries must sample the petroleum portion of the blended biomass-based fuel prior to blending and calculate CO 2 emissions using Equation MM-10a of this section.

CO 2i = Product p * EF i (Eq. MM-10a) Where: CO 2i = Annual CO 2 emissions that would result from the complete combustion or oxidation of each biomass-blended fuel “i” (metric tons). Deleted: not including 2.5% of the volume of any ethanol product blended with the petroleum-based product, which represents the denaturant in that ethanol product,351

Product p = Annual volume of the petroleum-based portion of each biomass blended fuel “i” produced by the refiner (barrels). EF i = Petroleum product-specific CO 2 emission factor (metric tons CO 2 per barrel). (4) Calculation Method 2 procedures for non-crude feedstocks. (i) A refiner using Calculation Method 2 of this subpart to determine the emission factor of a non-crude petroleum feedstock that does not contain denatured ethanol must calculate the CO 2 emissions associated with that feedstock using Equation MM-11 of this section in place of Equation MM-2 of this section.

CO 2j = (Feedstock j * EF j )-(Feedstock j * EF m * %Vol m )(Eq. MM-11)

Where:

CO 2j = Annual CO 2 emissions that would result from the complete combustion or oxidation of each non-crude feedstock “j” (metric tons). Feedstock j = Annual volume of each petroleum product “j” that enters the refinery to be further refined or otherwise used on site (barrels). EF j = Feedstock-specific CO 2 emission factor (metric tons CO 2 per barrel). EF m = Default CO 2 emission factor from Table MM-2 of this subpart that most closely represents the component of petroleum product “j” that is biomass-based. %Vol m = Percent volume of non-crude feedstock “j” that is biomass-based, expressed as a fraction (e.g., 75% would be expressed as 0.75 in the above equation). Deleted: ology

Deleted: i

Deleted: not including 2.5% of the volume of any ethanol product blended with the petroleum-based product, which represents the denaturant in that ethanol product,352
(ii) In the event that a non-crude feedstock contains denatured ethanol, refiners must follow Calculation Method 1 procedures in paragraph (h)(2) of this section. (i) Optional procedures for blended products that do not contain biomass. (1) In the event that a reporter produces, imports, or exports a blended product that does not include biomass, the reporter may calculate emissions for the blended product according to the method in paragraph (i)(2) of this section. In the event that a refiner receives a blended non-crude feedstock that does not include biomass, the refiner may calculate emission for the blended non-crude feedstock according to the method in paragraph (i)(3) of this section. The procedures in this section may be used only if all of the following criteria are met: (i) The reporter knows the relative proportion of each component of the blend (i.e., the mass or volume percentage). (ii) Each component of blended product “i” or blended non-crude feedstock “j” meets the strict definition of a product listed in Table MM-1. (iii) The blended product or non-crude feedstock is not comprised entirely of natural gas liquids. (iv) The reporter uses Calculation Method 1.353
(v) Solid components are blended only with other solid components. (2) The reporter must calculate emissions for the blended product using Equation MM-12 of this section in place of Equation MM-1 of this section.

CO 2i = ]* [

... ... nini EF Component Blending 

##  (Eq. MM-12)

Where: CO 2i = Annual CO 2 emissions that would result from the complete combustion or oxidation of a blended product ”i" (metric tons). Blending Component i...n = Annual volume or mass of each blending component that is blended (barrels or metric tons). EF i...n = CO 2 emission factors specific to each blending component (metric tons CO 2 per barrel or per metric ton of product).

n = Number of blending components blended into blended product ”i”. (3) For refineries, the reporter must calculate emissions for the blended non-crude feedstock using Equation MM-13 of this section in place of Equation MM-2 of this section.

CO 2i = ]* [

... ... nini EF Component Blending 

##  (Eq. MM-13)

Where: CO 2j = Annual CO 2 emissions that would result from the complete combustion or oxidation of a354
blended non-crude feedstock ”j” (metric tons). Blending Component i...n = Annual volume or mass of each blending component that is blended (barrels or metric tons). EF i...n = CO 2 emission factors specific to each blending component (metric tons CO 2 per barrel or per metric ton of product).

n = Number of blending components blended into blended non-crude feedstock “j”. (4) For refineries, if a blending component “k” used in paragraph (i)(2) of this section enters the refinery before blending as non-crude feedstock: (i) The emissions that would result from the complete combustion or oxidation of non-crude feedstock “k” must still be calculated separately using Equation MM-2 of this section and applied in Equation MM-4 of this section. (ii) The quantity of blending component “k” appliedin Equation MM-12 of this section and the quantity of noncrude feedstock “k” applied in Equation MM-2 of this section must be determined using the same method or practice. §98.394 Monitoring and QA/QC requirements. (a) Determination of quantity. (1) The quantity of petroleum products, natural gas liquids, biomass, and crude oil shall be determined as follows:355
(i) Where an appropriate standard method published by a consensus-based standards organization exists, such a method shall be used. 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, industry standard practices shall be followed. (iii) For products that are liquid at 60 degrees Fahrenheit and one standard atmosphere, all measurements ofquantity shall be temperature-adjusted and pressureadjusted to these conditions. For all other products, reporters shall use appropriate standard conditions specified in the standard method; if temperature and pressure conditions are not specified in the standard method or if a reporter uses an industry standard practice to determine quantity, the reporter shall use appropriate standard conditions according to established industry practices.356
(2) All measurement equipment (including, but not limited to, flow meters and tank gauges) used for compliance with this subpart shall be appropriate for the standard method or industry standard practice followed under paragraph (a)(1)(i) or (a)(1)(ii) of this section. (b) Equipment Calibration. (1) All measurement equipment shall be calibrated prior to its first use for reporting under this subpart, using an appropriate standard method published by a consensus based standards organization or according to the equipment manufacturer’s directions. (2) Measurement equipment shall be recalibrated at the minimum frequency specified by the standard method used or by the equipment manufacturer’s directions. (c) Procedures for Calculation Methodology 2 of this subpart. (1) Reporting parties shall collect one sample of each petroleum product or natural gas liquid on any day of each calendar month of the reporting year in which the quantity of that product was measured in accordance with the requirements of this subpart. For example, if a given product was measured as entering the refinery continuously throughout the reporting year, twelve samples of that product shall be collected over the reporting year, one on357
any day of each calendar month of that year. If a given product was only measured from April 15 through June 10 of the reporting year, a refiner would collect three samples during that year, one during each of the calendar months of April, May and June on a day when the product was measured as either entering or exiting the refinery. Each sample shall be collected using an appropriate standard method published by a consensus-based standards organization. (2) Mixing and handling of samples shall be performed using an appropriate standard method published by a consensus-based standards organization. (3) Density measurement. (i) For all products that are not solid, reporters shall test for density using an appropriate standard method published by a consensus-based standards organization. (ii) The density value for a given petroleum product shall be generated by either making a physical composite of all of the samples collected for the reporting year and testing that single sample or by measuring the individual samples throughout the year and defining the representative density value for the sample set by numerical means, i.e., a mathematical composite. If a physical composite is chosen as the option to obtain the density value, the reporter shall submit each of the individual samples358
collected during the reporting year to the laboratory responsible for generating the composite sample. (iii) For physical composites, the reporter shall handle the individual samples and the laboratory shall mix them in accordance with an appropriate standard method published by a consensus-based standards organization. (iv) All measurements of density shall be temperature-adjusted and pressure-adjusted to the conditions assumed for determining the quantities of the product reported under this subpart. (4) Carbon share measurement. (i) Reporters shall test for carbon share using an appropriate standard method published by a consensus-based standards organization. (ii) If a standard method that involves gas chromatography is used to determine the percent mass of each component in a product, the molecular formula for each component shall be obtained from the information provided in the standard method and the atomic mass of each element in a given molecular component shall be obtained from the periodic table of the elements. (iii) The carbon share value for a given petroleum product shall be generated by either making a physical composite of all of the samples collected for the reporting359
year and testing that single sample or by measuring the individual samples throughout the year and defining the representative carbon share value for the sample set by numerical means, i.e., a mathematical composite. If a physical composite is chosen as the option to obtain the carbon share value, the reporter shall submit each of the individual samples collected during the reporting year to the laboratory responsible for generating the composite sample. (iv) For physical composites, the reporter shall handle the individual samples and the laboratory shall mix them in accordance with an appropriate standard method published by a consensus-based standards organization. (d) Measurement of API gravity and sulfur content of crude oil. (1) A representative s ample or multiple representative samples of each batch of crude oil shall be taken according to an appropriate standard method published by a consensus-based standards organization. (2) Samples shall be handled according to an appropriate standard method published by a consensus-based standards organization. (3) API gravity shall be measured using an appropriate standard method published by a consensus-based Deleted: S Deleted: s360
standards organization. The weighted average API gravity for each batch shall be calculated by multiplying the volume associated with each representative sample by the API gravity, adding these values for all the samples, and then dividing that total value by the volume of the batch. (4) Sulfur content shall be measured using an appropriate standard method published by a consensus-based standards organization. The weighted average sulfur content for each batch shall be calculated by multiplying the volume associated with each representative sample by the sulfur content, adding these values for all the samples, and then dividing that total value by the volume of the batch. (5) All measurements shall be temperature-adjusted and pressure-adjusted to the conditions assumed for determining the quantities of crude oil reported under this subpart. §98.395 Procedures for estimating missing data. (a) Determination of quantity . Whenever the quality assurance procedures in §98.394(a) cannot be followed to measure the quantity of one or more petroleum products, natural gas liquids, types of biomass, feedstocks, or crude oil batches during any period (e.g., if a meter361
malfunctions), the following missing data procedures shall be used: (1) For quantities of a product that are purchased or sold, a period of missing data shall be substituted using a reporter’s established procedures for billing purposes in that period as agreed to by the party selling or purchasing the product. (2) For quantities of a product that are not purchased or sold but of which the custody is transferred, a period of missing data shall be substituted using a reporter’s established procedures for tracking purposes in that period as agreed to by the party involved in custody transfer of the product. (b) Determination of emission factor . Whenever any of the procedures in §98.394(c) cannot be followed to develop an emission factor for any reason, Calculation Methodology 1 of this subpart must be used in place of Calculation Methodology 2 of this subpart for the entire reporting year. (c) Determination of API gravity and sulfur content of crude oil . For missing data on sulfur content or API gravity, the substitute data value shall be the arithmetic average of the quality-assured values of API gravity or sulfur content in the batch preceding and the batch362
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 values for API gravity and sulfur content obtained from the batch after the missing data period. §98.396 Data reporting requirements. In addition to the information required by §98.3(c), the following requirements apply: (a) Refiners shall report the following information for each facility: (1) For each petroleum product or natural gas liquid listed in table MM-1 of this subpart that enters the refinery to be further refined or otherwise used on site, report the annual quantity in metric tons or barrels by each quantity measurement standard method or other industry standard practice used. For natural gas liquids, quantity shall reflect the individual components of the product. (2) For each petroleum product or natural gas liquid listed in Table MM-1 of this subpart that enters the refinery to be further refined or otherwise used on site, report the annual quantity in metric tons or barrels. For natural gas liquids, quantity shall reflect the individual components of the product.363
(3) For each feedstock reported in paragraph (a)(2)of this section that was produced by blending a petroleumbased product with a biomass-based product, report the percent of the volume reported in paragraph (a)(2) of this section that is petroleum-based (excluding any denaturant that may be present in any ethanol product)
. (4) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (a)(1) of this section. (5) For each petroleum product and natural gas liquid (ex refinery gate) listed in Table MM-1 of this subpart, report the annual quantity in metric tons or barrels by each quantity measurement standard method or other industry standard practice used. For natural gas liquids, quantity shall reflect the individual components of the product. Petroleum products and natural gas liquids that enter the refinery, but are not reported in (a)(1), shall not be reported under this paragraph. (6) For each petroleum product and natural gas liquid (ex refinery gate) listed in Table MM-1 of this subpart, report the annual quantity in metric tons or barrels. For natural gas liquids, quantity shall reflect the individual components of the product. Petroleum products and natural364
gas liquids that enter the refinery, but are not reported in (a)(2), shall not be reported under this paragraph. (7) For each product reported in paragraph (a)(6) ofthis section that was produced by blending a petroleumbased product with a biomass-based product, report the percent of the volume reported in paragraph (a)(6) of this section that is petroleum-based (excluding any denaturant that may be present in any ethanol product)
. (8) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (a)(5) of this section. (9) For every feedstock reported in paragraph (a)(2) of this section for which Calculation Methodology 2 of this subpart was used to determine an emissions factor, report: (i) The number of samples collected according to §98.394(c) (ii) The sampling standard method used. (iii) The carbon share test results in percentmass. (iv) The standard method used to test carbon share. (v) The calculated CO 2 emissions factor in metric
tons. (10) For every non-solid feedstock reported in paragraph (a)(2) of this section for which Calculation365
Methodology 2 of this subpart was used to determine an emissions factor, report: (i) The density test results in metric tons per barrel. (ii) The standard method used to test density. (11) For every petroleum product and natural gas liquid reported in paragraph (a)(6) of this section for which Calculation Methodology 2 of this subpart was used to determine an emissions factor, report: (i) The number of samples collected according to §98.394(c). (ii) The sampling standard method used. (iii) The carbon share test results in percentmass. (iv) The standard method used to test carbon share. (v) The calculated CO 2 emissions factor in metric tons
CO 2 per barrel or per metric ton of product. (12) For every non-solid petroleum product and natural gas liquid reported in paragraph (a)(6) for which Calculation Method 2 was used to determine an emissions factor, report: (i) The density test results in metric tons per barrel. (ii) The standard method used to test density.366
(13) For each specific type of biomass that enters the refinery to be co-processed with petroleum feedstocks to produce a petroleum product reported in paragraph (a)(6) of this section, report the annual quantity in metric tons or barrels by each quantity measurement standard method or other industry standard practice used. (14) For each specific type of biomass that enters the refinery to be co-processed with petroleum feedstocks to produce a petroleum product reported in paragraph (a)(6) of this section, report the annual quantity in metric tons or barrels. (15) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (a)(13) of this section. (16) The CO 2 emissions in metric tons that would result from the complete combustion or oxidation of each petroleum product and natural gas liquid (ex refinery gate) reported in paragraph (a)(6) of this section, calculated according to §98.393(a) or (h). (17) The CO 2 emissions in metric tons that would result from the complete combustion or oxidation of each feedstock reported in paragraph (a)(2) of this section, calculated according to §98.393(b) or (h).367
(18) The CO 2 emissions in metric tons that would result from the complete combustion or oxidation of each type of biomass feedstock co-processed with petroleum feedstocks reported in paragraph (a)(13) of this section, calculated according to §98.393(c). (19) The sum of CO 2 emissions that would result from the complete combustion or oxidation of all products, calculated according to §98.393(d). (20) All of the following information for all crude oil feedstocks used at the refinery: (i) Batch volume in barrels. (ii) Weighted average API gravity of the batch at the point of entry at the refinery. (iii) Weighted average s ulfur content of the batch at the point of entry at the refinery. (iv) Country of origin of the batch, if known. (21) The quantity of bulk NGLs in metric tons or barrels received for processing during the reporting year. (b) In addition to the information required by §98.3(c), each importer shall report all of the following information at the corporate level: (1) For each petroleum product and natural gas liquid listed in Table MM-1 of this subpart, report the annual quantity in metric tons or barrels by each quantity Deleted: S368
measurement standard method or other industry standard practice used. For natural gas liquids, quantity shall reflect the individual components of the product. (2) For each petroleum product and natural gas liquid listed in Table MM-1 of this subpart, report the annual quantity in metric tons or barrels. For natural gas liquids, quantity shall reflect the individual components of the product as listed in Table MM-1 of this subpart. (3) For each product reported in paragraph (b)(2) ofthis section that was produced by blending a petroleumbased product with a biomass-based product, report the percent of the volume reported in paragraph (b)(2) of this section that is petroleum-based (excluding any denaturant that may be present in any ethanol product)
. (4) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (b)(1) of this section. (5) For each product reported in paragraph (b)(2) of this section for which Calculation Methodology 2 of this subpart used was used to determine an emissions factor, report: (i) The number of samples collected according to §98.394(c) (ii) The sampling standard method used.369
(iii) The carbon share test results in percent mass. (iv) The standard method used to test carbon share. (v) The calculated CO 2 emissions factor in metric tons
CO 2 per barrel or per metric ton of product. (6) For each non-solid product reported in paragraph (b)(2) of this section for which Calculation Methodology 2 of this subpart was used to determine an emissions factor, report: (i) The density test results in metric tons per barrel. (ii) The standard method used to test density. (7) The CO 2 emissions in metric tons that would result from the complete combustion or oxidation of each imported petroleum product and natural gas liquid reported in paragraph (b)(2) of this section, calculated according to §98.393(a). (8) The sum of CO 2 emissions that would result from the complete combustion oxidation of all imported products, calculated according to §98.393(e). (c) In addition to the information required by §98.3(c), each exporter shall report all of the following information at the corporate level: (1) For each petroleum product and natural gas liquid listed in Table MM-1 of this subpart, report the annual370
quantity in metric tons or barrels by each quantity measurement standard method or other industry standard practice used. For natural gas liquids, quantity shall reflect the individual components of the product. (2) For each petroleum product and natural gas liquid listed in Table MM-1 of this subpart, report the annual quantity in metric tons or barrels. For natural gas liquids, quantity shall reflect the individual components of the product. (3) For each product reported in paragraph (c)(2) ofthis section that was produced by blending a petroleumbased product with a biomass-based product, report the percent of the volume reported in paragraph (c)(2) of this section that is petroleum based (excluding any denaturant that may be present in any ethanol product)
. (4) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (c)(1) of this section. (5) For each product reported in paragraph (c)(2) of this section for which Calculation Methodology 2 of this subpart was used to determine an emissions factor, report: (i) The number of samples collected according to §98.394(c). (ii) The sampling standard method used.371
(iii) The carbon share test results in percentmass. (iv) The standard method used to test carbon share. (v) The calculated CO 2 emissions factor in metric tons
CO 2 per barrel or per metric ton of product. (6) For each non-solid product reported in paragraph (c)(2) of this section for which Calculation Methodology 2 of this subpart used was used to determine an emissions factor, report: (i) The density test results in metric tons per barrel. (ii) The standard method used to test density. (7) The CO 2 emissions in metric tons that would result from the complete combustion or oxidation of for each exported petroleum product and natural gas liquid reported in paragraph (c)(2) of this section, calculated according to §98.393(a). (8) The sum of CO 2 emissions that would result from the complete combustion or oxidation of all exported products, calculated according to §98.393(e). (d) Blended non-crude feedstock and products. (1) Refineries, exporters, and importers must reportthe following information for each blended product and noncrude feedstock where emissions were calculated according to §98.393(i):372
(i) Volume or mass of each blending component. (ii) The CO 2 emissions in metric tons that would result from the complete combustion or oxidation of eachblended non-crude feedstock or product, using Equation MM12 or Equation MM-13 of this section. (2) For a product that enters the refinery to be further refined or otherwise used on site that is a blended non-crude feedstock, refiners must meet the reporting requirements of paragraphs (a)(1) and (a)(2) of this section by reflecting the individual components of the blended non-crude feedstock. (3) For a product that is produced, imported, or exported that is a blended product, refiners, importers, and exporters must meet the reporting requirements of paragraphs (a)(5), (a)(6), (b)(1), (b)(2), (c)(1), and (c)(2) of this section, as applicable, by reflecting the individual components of the blended product. §98.397 Records that must be retained. (a) All reporters shall retain copies of all reports submitted to EPA under §98.396. In addition, all reporters shall maintain sufficient records to support information contained in those reports, including but not limited to information on the characteristics of their feedstocks and products.373
(b) Reporters shall maintain records to support quantities that are reported under this subpart, including records documenting any estimations of missing data and the number of calendar days in the reporting year for which substitute data procedures were followed. For all quantities of petroleum products, natural gas liquids, biomass, and feedstocks, reporters shall maintain metering, guaging, and other records normally maintained in the course of business to document product and feedstock flows including the date of initial calibration and the frequency of recalibration for the measurement equipment used (c) Reporters shall retain laboratory reports, calculations and worksheets used to estimate the CO 2 emissions of the quantities of petroleum products, natural gas liquids, biomass, and feedstocks reported under this subpart. (d) Reporters shall maintain laboratory reports, calculations and worksheets used in the measurement of density and carbon share for any petroleum product or natural gas liquid for which CO 2 emissions were calculated using Calculation Methodology 2. ( e ) Estimates of missing data shall be documented and records maintained showing the calculations. Deleted: (e) Reporters shall maintain laboratory reports, calculations and worksheets used in the measurement of API gravity and sulfur content for every crude oil batch reported under this subpart.¶ Deleted: f374

( f ) Reporters described in this subpart shall also retain all records described in §98.3(g). §98.398 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. Batch means up to a calendar month of crude oil volume from a single country of origin or up to a calendar month of crude oil volume for which the country of origin is unknown
. **Table MM-1 of Subpart MM—Default Factors for Petroleum Products and Natural Gas Liquids**  **1,2**

**Products Column A:**  **Density (metric**  **tons/bbl) Column B:**  **Carbon Share**  **(% of mass)**  **Column C: Emission Factor** 

**(metric tons**

**CO 2**  **/bbl) Finished Motor Gasoline**  Conventional - Summer Regular 0.1181 86.66 0.3753 Midgrade 0.1183 86.63 0.3758 Premium 0.1185 86.61 0.3763 Conventional - Winter Regular 0.1155 86.50 0.3663 Midgrade 0.1161 86.55 0.3684 Premium 0.1167 86.59 0.3705 Reformulated - Summer Regular 0.1167 86.13 0.3686 Midgrade 0.1165 86.07 0.3677 Premium 0.1164 86.00 0.3670 Reformulated - Winter Regular 0.1165 86.05 0.3676 Midgrade 0.1165 86.06 0.3676 Premium 0.1166 86.06 0.3679 Gasoline—Other 0.1185 86.61 0.3763 **Blendstocks** Deleted: g

Deleted: All375

**Products Column A:**  **Density (metric**  **tons/bbl) Column B:**  **Carbon Share**  **(% of mass)**  **Column C: Emission Factor** 

**(metric tons**

**CO 2**  **/bbl)** CBOB—Summer Regular 0.1181 86.66 0.3753 Midgrade 0.1183 86.63 0.3758 Premium 0.1185 86.61 0.3763 CBOB—Winter Regular 0.1155 86.50 0.3663 Midgrade 0.1161 86.55 0.3684 Premium 0.1167 86.59 0.3705 RBOB—Summer Regular 0.1167 86.13 0.3686 Midgrade 0.1165 86.07 0.3677 Premium 0.1164 86.00 0.3670 RBOB—Winter Regular 0.1165 86.05 0.3676 Midgrade 0.1165 86.06 0.3676 Premium 0.1166 86.06 0.3679 Blendstocks—Other 0.1185 86.61 0.3763 **Oxygenates** Methanol 0.1268 37.48 0.1743 GTBA 0.1257 64.82 0.2988 MTBE 0.1181 68.13 0.2950 ETBE 0.1182 70.53 0.3057 TAME 0.1229 70.53 0.3178 DIPE 0.1156 70.53 0.2990 **Distillate Fuel Oil** Distillate No. 1 Ultra Low Sulfur 0.1346 86.40 0.4264 Low Sulfur 0.1346 86.40 0.4264 High Sulfur 0.1346 86.40 0.4264 Distillate No. 2 Ultra Low Sulfur 0.1342 87.30 0.4296 Low Sulfur 0.1342 87.30 0.4296 High Sulfur 0.1342 87.30 0.4296 Distillate Fuel Oil No. 4 0.1452 86.47 0.4604 Residual Fuel Oil No. 5 (Navy Special) 0.1365 85.67 0.4288 Residual Fuel Oil No. 6 (a.k.a. Bunker C) 0.1528 84.67 0.4744 Kerosene-Type Jet Fuel 0.1294 86.30 0.4095 Kerosene 0.1346 86.40 0.4264376

**Products Column A:**  **Density (metric**  **tons/bbl) Column B:**  **Carbon Share**  **(% of mass)**  **Column C: Emission Factor** 

**(metric tons**

**CO 2**  **/bbl)** Diesel—Other 0.1452 86.47 0.4604 **Petrochemical Feedstocks** Naphthas (< 401°F) 0.1158 84.11 0.3571 Other Oils (> 401°F) 0.1390 87.30 0.4450 **Unfinished Oils** Heavy Gas Oils 0.1476 85.80 0.4643 Residuum 0.1622 85.70 0.5097 **Other Petroleum Products and Natural Gas Liquids** Aviation Gasoline 0.1120 85.00 0.3490 Special Naphthas 0.1222 84.76 0.3798 Lubricants 0.1428 85.80 0.4492 Waxes 0.1285 85.30 0.4019 Petroleum Coke 0.1818 92.28 0.6151 Asphalt and Road Oil 0.1634 83.47 0.5001 Still Gas 0.1405 77.70 0.4003 Ethane 0.0866 79.89 0.2537 Ethylene 0.0903 85.63 0.2835 Propane 0.0784 81.71 0.2349 Propylene 0.0803 85.63 0.2521 Butane 0.0911 82.66 0.2761 Butylene 0.0935 85.63 0.2936 Isobutane 0.0876 82.66 0.2655 Isobutylene 0.0936 85.63 0.2939 Pentanes Plus 0.1055 83.63 0.3235 Miscellaneous Products 0.1380 85.49 0.4326 1. In the case of products blended with some portion of biomass-based fuel, the carbon share in Table MM-1 of this subpart represents only the petroleum-based components. 2. Products that are derived entirely from biomass should not be reported, butproducts that were derived from both biomass and a petroleum product (i.e., coprocessed) should be reported as the petroleum product that it most closely represents. **Table MM-2 of Subpart MM—Default Factors for Biomass-Based Fuels and Biomass** 

**Biomass-Based Fuel and Biomass**  **Column A: Density**  **(metric tons/bbl)**  **Column B: Carbon**  **Share (% of**  **mass) Column C:**  **Emission Factor (metric tons CO**  **2 /bbl)** 377

**Biomass-Based Fuel and Biomass**  **Column A: Density**  **(metric tons/bbl)**  **Column B: Carbon**  **Share (% of**  **mass) Column C:**  **Emission Factor (metric tons CO**  **2 /bbl)** 

Ethanol (100%) 0.1267 52.14 0.2422 Biodiesel (100%, methyl ester) 0.1396 77.30 0.3957
Rendered Animal Fat 0.1333 76.19 0.3724 Vegetable Oil 0.1460 76.77 0.4110
**Subpart NN—Suppliers of Natural Gas and Natural Gas Liquids** §98.400 Definition of the source category. This supplier category consists of natural gas liquids fractionators and local natural gas distribution companies. (a) Natural gas liquids fractionators are installations that fractionate natural gas liquids (NGLs) into their consitutent liquid products (ethane, propane, normal butane, isobutane or pentanes plus) for supply to downstream facilities. (b) Local Distribution Companies (LDCs)are companies that own or operate distribution pipelines, not interstate pipelines or intrastate pipelines, that physically deliver natural gas to end users and that are regulated as separate operating companies by State public utility commissions or that operate as independent municipally-owned distribution systems.378
(c) This supply category does not consist of the following facilities: (1) Field gathering and boosting stations. (2) Natural gas processing plants that separate NGLs from natural gas and produce bulk or y-grade NGLs but do not fractionate these NGLs into their constituent products. (3) Facilities that meet the definition of refineries and report under subpart MM of this part. (4) Facilities that meet the definition of petrochemical plants and report under subpart X of this part. §98.401 Reporting threshold. Any supplier of natural gas and natural gas liquids that meets the requirements of §98.2(a)(4) must report GHG emissions. §98.402 GHGs to report. (a) NGL fractionators must report the CO 2 emissions that would result from the complete combustion or oxidation of the annual quantity of ethane, propane, normal butane, isobutane, and pentanes plus that is produced and sold or delivered to others. (b) LDCs must report the CO 2 emissions that would result from the complete combustion or oxidation of the379
annual volumes of natural gas provided to end-users on their distribution systems. §98.403 Calculating GHG emissions. (a) LDCs and fractionators shall, for each individual product reported under this part, calculate the estimated
CO 2 emissions that would result from the complete combustion or oxidation of the products supplied using either of Calculation Methodology 1 or 2 of this subpart: (1) Calculation Methodology 1 . NGL fractionators shall estimate CO 2 emissions that would result from the complete combustion or oxidation of the product(s) supplied using Equation NN-1 of this section. LDCs shall estimate
CO 2 emissions that would result from the complete combustion or oxidation of the product received at the city gate using Equation NN-1. For each product, use the default value for higher heating value and CO 2 emission factor in Table NN-1 of this subpart. Alternatively, for each product, a reporter-specific higher heating value and CO 2 emission factor may be used, in place of one or both defaults provided they are developed using methods outlined in §98.404. For each product, you must use the same volume unit throughout the equation.

hh 3 2i EF*HHV*Fuel*10x1CO h 

## 

  (Eq. NN-1)380

Where: CO 2i = Annual CO 2 mass emissions that would result from the combustion or oxidation of each product “h” for redelivery to all recipients (metric tons). Fuel h = Total annual volume of product “h” supplied (volume per year, in thousand standard cubic feet ( Mscf ) for natural gas and bbl for NGLs). HHV h = Higher heating value of product “h” supplied (MMBtu/ Mscf or MMBtu/bbl). EF h = CO 2 emission factor of product "h" (kg CO 2 /MMBtu). 1 x 10 -3 = Conversion factor from kilograms to metric tons (MT/kg).

(2) Calculation Methodology 2 . NGL fractionators shall estimate CO 2 emissions that would result from the complete combustion or oxidation of the product(s) supplied using Equation NN-2 of this section. LDCs shall estimate
CO 2 emissions that would result from the complete combustion or oxidation of the product received at the city gate using Equation NN-2. For each product, use the default CO 2 emission factor found in Table NN-2 of this subpart. Alternatively, for each product, a reporter-specific CO 2 emission factor may be used in place of the default factor, provided it is developed using methods outlined in §98.404. For each product, you must use the same volume unit throughout the equation. 

#   h h h EFFuel * CO 2i (Eq. NN-2)381

Where: CO 2i = Annual CO 2 mass emissions that would result from the combustion or oxidation of each product “h” (metric tons) Fuel h = Total annual volume of product “h” supplied (bbl or Mscf per year) EF h = CO 2 emission factor of product "h" (MT CO 2 /bbl, or MT CO 2 /Mscf)
(b) Each LDC shall follow the procedures below. (1) For natural gas that is received for redelivery to downstream gas transmission pipelines and other local distribution companies, use eEquation NN-3 of this section and the default values for the CO 2 emission factors found inTable NN-2 of this subpart. Alternatively, reporterspecific CO2 emission factors may be used, provided they are developed using methods outlined in §98.404.

EF*Fuel CO 2j  (Eq. NN-3) Where: CO 2j = Annual CO 2 mass emissions that would result from the combustion or oxidation of natural gas for redelivery to transmission pipelines or other LDCs (metric tons). Fuel = Total annual volume of natural gas supplied (Mscf per year). EF = Fuel-specific CO 2 emission factor (MT CO 2 /Mscf).

(2) For natural gas delivered to each meter registering a supply equal to or greater than 460,000 Mscf per year, use Equation NN-4 of this section and the default382

values for the CO2 emission factors found in Table NN-2 of this subpart. Alternatively, reporter-specific CO2 emission factors may be used, provided they are developed using methods outlined in §98.404.



### EF*Fuel CO 2k 

###  (Eq. NN-4) Where: CO 2k = Annual CO 2 mass emissions that would result from the combustion or oxidation of natural gas received by end-users that receive a supply equal to or greater than 460,000 Mscf per year (metric tons). Fuel = Total annual volume of natural gas supplied (Mscf per year). EF = Fuel-specific CO 2 emission factor (MT CO 2 /Mscf). (3) For natural gas received by the LDC at the city gate that is injected into on-system storage, and/or liquefied and stored, use Equation NN-5 of this section and the default value for the CO 2 emission factors found inTable NN-2 of this subpart. Alternatively, a reporterspecific CO 2 emission factor may be used, provided it is developed using methods outlined in §98.404.


### EF*]Fuel Fuel CO 2 1 2l 

###   [ (Eq. NN-5) Where: CO 2l = Annual CO 2 mass emissions that would result from the combustion or oxidation of the net natural gas that is liquefied and/or stored and not used for deliveries by the LDC within the reported year (metric tons).383

Fuel 1 = Total annual volume of natural gas received by the LDC at the city gate and stored on-system or liquefied and stored in the report i ng year (Mscf per year). Fuel 2 = Total annual volume of natural gas that is used for deliveries in the reporting year that was not otherwise accounted for in Equation NN-1 or NN-2 of this section (Mscf per year). This primarily includes natural gas previously stored on-system or liquefied and stored that is removed from storage and used for deliveries to customers or other LDCs by the LDC within the reporting year. This also includes natural gas that bypassed the city gate and was delivered directly to LDC systems from producers or natural gas processing plants from local production. EF = Fuel-specific CO 2 emission factor (MT CO 2 /Mscf).
(4) Calculate the total CO 2 emissions that would result from the complete combustion or oxidation of the annual supply of natural gas to end-users using Equation NN-6 of this section. 

#    

    2l 2k 2j i 2 

### CO CO CO CO CO 2 (Eq. NN-6) Where: CO 2 = Annual CO 2 mass emissions that would result from the combustion or oxidation of natural gas delivered to LDC customers not covered in paragraph (b)(2) of this section (metric tons). CO 2i = Annual CO 2 mass emissions that would result from the combustion or oxidation of natural gas received at the city gate as calculated in paragraph (a)(1) or (a)(2) of this section (metric tons). CO 2j = Annual CO 2 mass emissions that would result from the combustion or oxidation of natural gas delivered to transmission pipelines or other LDCs as calculated in paragraph (b)(1) of this section (metric tons).384

CO 2k = Annual CO 2 mass emissions that would result from the combustion or oxidation of natural gas received by end-users that receive a supply equal to or greater than 460,000 Mscf per year as calculated in paragraph (b)(2) of this section (metric tons). CO 2l = Annual CO 2 mass emissions that would result from the combustion or oxidation of natural gas received by the LDC and liquefied and/or stored but not used for deliveries within the reported year as calculated in paragraph (b)(3) of this section (metric tons). (c) Each NGL fractionator shall follow the following procedures. (1) For fractionated NGLs received by the reporter from other NGL fractionators, you shall use Equation NN-7 of this section and the default values for the CO 2 emission factors found in Table NN-2 of this subpart. Alternatively, reporter-specific CO 2 emission factors may be used, provided they are developed using methods outlined in §98.404. 

#   g gg 2m EF*Fuel CO (Eq. NN-7)

Where: CO 2m = Annual CO 2 mass emissions that would result from the combustion or oxidation of each fractionated NGL product "g" received from other fractionators (metric tons). Fuel g = Total annual volume of each NGL product "g" received (bbls). EF g = Fuel-specific CO 2 emission factor of NGL product “g” (MT CO 2 /bbl).385

(2) Calculate the total CO2 equivalent emissions that would result from the combustion or oxidation of fractionated NGLs supplied less the quantity received by other fractionators using Equation NN-8 of this section.

2m 2i 2 

### COCOCO

  (Eq. NN-8) Where: CO 2 = Annual CO 2 mass emissions that would result from the combustion or oxidation of fractionated NGLs delivered to customers or on behalf of customers (metric tons). CO 2i = Annual CO 2 mass emissions that would result from the combustion or oxidation of fractionated NGLs delivered to all customers or on behalf of customers as calculated in paragraph (a)(1) or (a)(2) of this section (metric tons). CO 2m = Annual CO 2 mass emissions that would result from the combustion or oxidation of fractionated NGLs received from other fractionators and calculated in paragraph (c)(1) of this section (metric tons). §98.404 Monitoring and QA/QC requirements. (a) Determination of quantity. (1) NGL fractionators and LDCs shall determine the quantity of NGLs and natural gas using methods in common use in the industry for billing purposes as audited under existing Sarbanes Oxley regulationn. (i) Where an appropriate standard method published by a consensus-based standards organization exists, such a method shall be used. Consensus-based standards organizations include, but are not limited to, the386
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, industry standard practices shall be followed. (2) NGL fractionators and LDCs shall base the minimum frequency of the product quantity measurements, to be summed to the annual quantity reported, on the reporter’s standard practices for commercial operations. (i) For NGL fractionators the minimum frequency of measurements shall be the measurements taken at custody transfers summed to the annual reportable volume. (ii) For natural gas the minimum frequency of measurement shall be based on the LDC’s standard measurement schedules used for billing purposes and summed to the annual reportable volume. (3) NGL fractionators shall use measurement for NGLs at custody tranfer meters or at such meters that are used to determine the NGL product slate delivered from the fractionation facility.387
(4) If a NGL fractionator supplies a product not listed in Table NN-1 of this subpart that is a mixture orblend of two or more products listed in Tables NN-1 and NN2 of this subpart, the NGL fractionator shall report the quantities of the constituents of the mixtures or blends separately. (5) For an LDC using Equation NN-1 or NN-2 of this subpart, the point(s) of measurement for the natural gas volume supplied shall be the LDC city gate meter(s). (i) If the LDC makes its own quantity measurements according to established business practices, its own measurements shall be used. (ii) If the LDC does not make its own quantity measurements according to established business practices, it shall use its delivering pipeline invoiced measurements for natural gas deliveries to the LDC city gate, used in determining daily system sendout. (6) An LDC using Equation NN-3 of this subpart shall measure natural gas at the custody transfer meters. (7) An LDC using Equation NN-4 of this subpart shall measure natural gas at the customer meters. The reporter shall consider the volume delivered through a single particluar meter at a single particular location as the volume delivered to an individual end-user.388
(8) An LDC using Equation NN-5 of this subpart shall measure natural gas as follows: (i) Fuel 1 shall be measured at the on-system storage injection meters and/or at the meters measuring natural gas to be liquefied. (ii) Fuel 2 shall be measured at the meters used for measuring on-system storage withdrawals and/or LNG vaporization injection. If Fuel 2 is from a source other than storage, the appropriate meter shall be used to measure the quantity. (9) An LDC shall measure all natural gas under the following standard industry temperature and pressure conditions: cubic foot of gas at a temperature of 60 degrees Fahrenheit and at an absolute pressure of fourteen and seventy-three hundredths (14.73) pounds per square inch. (b) Determination of higher heating values (HHV). (1) When a reporter uses the default HHV provided in this section to calculate Equation NN-1 of this subpart, the appropriate value shall be taken from Table NN-1 of this subpart. (2) When a reporter uses a reporter-specific HHV to calculate Equation NN-1 of this subpart, an appropriate standard test published by a consensus-based standards389
organization shall be used. Consensus-based standards organizations include, but are not limited to, the following: AGA and GPA. (i) If an LDC makes its own HHV measurements according to established business practices, then its own measurements shall be used. (ii) If an LDC does not make its own measurements according to established business practices, it shall use its delivering pipeline measurements. (c) Determination of emission factor (EF). (1) When a reporter used the default EF provided in this section to calculate Equation NN-1 of this subpart, the appropriate value shall be taken from Table NN-1 of this subpart. (2) When a reporter used the default EF provided in this section to calculate Equation NN-2, NN-3, NN-4, NN-5, or NN-7 of this subpart, the appropriate value shall be taken from Table NN-2 of this subpart. (3) When a reporter uses a reporter-specific EF, the reporter shall use an appropriate standard method published by a consensus-based standards organization to conductcompositional analysis necessary to determine reporterspecific CO 2 emission factors. Consensus-based standards390
organizations include, but are not limited to, the following: AGA and GPA. (d) Equipment Calibration. (1) Equipment used to measure quantities in Equations NN-1, NN-2, and NN-5 of this subpart shall be calibrated prior to its first use for reporting under this subpart, using a suitable standard method published by a consensus based standards organization or according to the equipment manufacturer’s directions. (2) Equipment used to measure quantities in Equations NN-1, NN-2, and NN-5 of this subpart shall be recalibrated at the frequency specified by the standard method used or by the manufacturer’s directions. §98.405 Procedures for estimating missing data. (a) Whenever a quality-assured value of the quantity of natural gas liquids or natural gas supplied during any period is unavailable (e.g., if a flow meter malfunctions), a substitute data value for the missing quantity measurement must be used in the calculations according to paragraphs (b) and (c) of this section. (b) Determination of quantity. (1) NGL fractionators shall substitute meter records provided by pipeline(s) for all pipeline receipts of NGLs; by manifests for deliveries made to trucks or rail cars; or391
metered quantities accepted by the entities purchasing the output from the fractionator whether by pipeline or by truck or rail car. In cases where the metered data from the receiving pipeline(s) or purchasing entities are not available, fractionators may substitute estimates based on contract quantities required to be delivered under purchase or delivery contracts with other parties. (2) LDCs shall either substitute their delivering pipeline metered deliveries at the city gate or substitute nominations and scheduled delivery quantities for the period when metered values of actual deliveries are not available. (c) Determination of HHV and EF. (1) Whenever an LDC that makes its own HHV measurements according to established business practices cannot follow the quality assurance procedures for developing a reporter-specific HHV, as specified in §98.404, during any period for any reason, the reporter shall use either its delivering pipeline measurements or the default HHV provided in Table NN-1 of this part for that period. (2) Whenever an LDC that does not make its own HHV measurements according to established business practices or an NGL fractionator cannot follow the quality assurance392
procedures for developing a reporter-specific HHV, as specified in §98.404, during any period for any reason, the reporter shall use the default HHV provided in Table NN-1 of this part for that period. (3) Whenever a NGL fractionator cannot follow thequality assurance procedures for developing a reporterspecific HHV, as specified in §98.404, during any period for any reason, the NGL fractionator shall use the default HHV provided in Table NN-1 of this part for that period. (4) Whenever a reporter cannot follow the quality assurance procedures for developing a reporter-specific EF, as specified in §98.404, during any period for any reason, the reporter shall use the default EF provided in §98.408 for that period. §98.406 Data reporting requirements. (a) In addition to the information required by §98.3(c), the annual report for each NGL fractionator covered by this rule shall contain the following information. (1) Annual quantity (in barrels) of each NGL product supplied to downstream facilities in the following product categories: ethane, propane, normal butane, isobutane, and pentanes plus.393
(2) Annual quantity (in barrels) of each NGL product received from other NGL fractionators in the following product categories: ethane, propane, normal butane, isobutane, and pentanes plus. (3) Annual volumes in Mscf of natural gas received for processing. (4) Annual quantity (in barrels) of y-grade, bulk NGLs received from others for fractionation. (5) Annual quantity (in barrels) of propane that the NGL fractionator odorizes at the facility and delivers to others. (6) Annual CO 2 emissions (metric tons) that would result from the complete combustion or oxidation of the quantities in paragraphs ( a )(1) and ( a )(2) of this section, calculated in accordance with §98.403(a) and (c)(1). (7) Annual CO 2 mass emissions (metric tons) that would result from the combustion or oxidation of fractionated NGLs supplied less the quantity received by other fractionators, calculated in accordance with §98.403(c)(2). (8) The specific industry standard used to measure each quantity reported in paragraph (a)(1) of this section. (9) If the NGL fractionator developed reporterspecific EFs or HHVs, report the following for each product type : Deleted: b Deleted: b

Deleted: LNG394
(i) The specific industry standard(s) used to develop reporter-specific higher heating value(s) and/or emission factor(s), pursuant to §98.404 (b)(2) and (c)(3). (ii) The developed HHV(s). (iii) The developed EF(s). (b) In addition to the information required by §98.3(c), the annual report for each LDC shall contain the following information. (1) Annual volume in Mscf of natural gas received by the LDC at its city gate stations for redelivery on the LDC’s distribution system, including for use by the LDC. (2) Annual volume in Mscf of natural gas placed into storage. (3) Annual volume in Mscf of vaporized liquefied natural gas (LNG) produced at on-system vaporization facilities for delivery on the distribution system that is not accounted for in paragraph (b)(1) of this section. (4) Annual volume in Mscf of natural gas withdrawn from on-system storage (that is not delivered to the city gate) for delivery on the distribution system. (5) Annual volume in Mscf of natural gas delivered directly to LDC systems from producers or natural gas processing plants from local production.395
(6) Annual volume in Mscf of natural gas delivered to downstream gas transmission pipelines and other local distribution companies. (7) Annual volume in Mscf of natural gas delivered by LDC to each meter registering supply equal to or greater than 460,000 Mcsf during the calendar year. (8) The total annual CO 2 mass emissions (metric tons) associated with the volumes in paragraphs (b)(1) through (b)(7) of this section, calculated in accordance with §98.403(a) and (b)(1) through (b)(3). (9) Annual CO 2 emissions (metric tons) that would result from the complete combustion or oxidation of the annual supply of natural gas to end-users registering less than 460,000 Mcsf, calculated in accordance with §98.403(b)(4). (10) The specific industry standard used to develop the volume reported in paragraph (b)(1) of this section. (11) If the LDC developed reporter-specific EFs or HHVs, report the following: (i) The specific industry standard(s) used to develop reporter-specific higher heating value(s) and/or emission factor(s), pursuant to §98.404 (b)(2) and (c)(3). (ii) The developed HHV(s). (iii) The developed EF(s).396
(12) The customer name, address, and meter number of each meter reading used to report in paragraph (b)(7) of this section. (i) If known, report the EIA identification number of each LDC customer. (ii) [Reserved] (13) The annual volume in Mscf of natural gas delivered by the local distribution company to each of the following end-use categories. For definitions of these categories, refer to EIA Form 176 (Annual Report of Natural Gas and Supplemental Gas Supply & Disposition) and Instructions. (i) Residential consumers. (ii) Commercial consumers. (iii) Industrial consumers. (iv) Electricity generating facilities. (c) Each reporter shall report the number of days in the reporting year for which substitute data procedures were used for the following purpose: (1) To measure quantity. (2) To develop HHV(s). (3) To develop EF(s). §98.407 Records that must be retained.397
In addition to the information required by §98.3(g), each annual report must contain the following information: (a) Records of all meter readings and documentation to support volumes of natural gas and NGLs that are reported under this part. (b) Records documenting any estimates of missing metered data and showing the calculations of the values used for the missing data. (c) Calculations and worksheets used to estimate CO 2 emissions for the volumes reported under this part. (d) Records related to the large end-users identified in §98.406(b)( 7 ). (e) Records relating to measured Btu content or carbon content showing specific industry standards used to develop reporter-specific higher heating values and emission factors. (f) Records of such audits as required by Sarbanes Oxley regulations on the accuracy of measurements of volumes of natural gas and NGLs delivered to customers or on behalf of customers. §98.408 Definitions. All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Deleted: daily

Deleted: 6398

**Table NN-1 to**  **Subpart NN—Default Factors for Calculation Methodology 1 of this Subpart**  **Fuel Default High Heating**  **Value Factor Default CO**  **2 Emission**  **Factor (kg CO 2**  **/MMBtu)** Natural Gas 1.02 8 MMBtu/Mscf 53.02 Propane 3.8 22 MMBtu/bbl 6 1.46 Normal butane 4. 242 MMBtu/bbl 6 5.15 Ethane 4.032 MMBtu/bbl 62.64 Isobutane 4.074 MMBtu/bbl 6 4.91 Pentanes plus 4.620 MMBtu/bbl 70.02
**Table NN-2 to**  **Subpart NN—Lookup Default Values for Calculation Methodology 2 of this Subpart**  **Fuel Unit Default CO**  **2 Emission**  **Value (MT CO**  **2 /Unit)**  Natural Gas Mscf 0. 055 Propane Barrel 0.2 35 Normal butane Barrel 0.2 76 Ethane Barrel 0. 253 Isobutane Barrel 0.2 66 Pentanes plus Barrel 0.3 24 Deleted: **of**

Deleted: 7 Deleted: 36 Deleted: 3.02 Deleted: 326 Deleted: 4.93 Deleted: 3.082 Deleted: 59.58 Deleted: 3.974 Deleted: 5.08 Deleted: 66.90 Deleted: **of**

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### L 0 

### (Equivalent to DOC = 0.2028 when MCF=1, DOC F 

### =0.5, and F=0.5) 0.067 metric tons CH 4 

### / metric ton waste

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