42 U.S.C. 7401-7671q.
74 FR 56374, Oct. 30, 2009, unless otherwise noted.
(a) This part establishes mandatory greenhouse gas (GHG) reporting requirements for owners and operators of certain facilities that directly emit GHG as well as for certain suppliers. For suppliers, the GHGs reported are the quantity that would be emitted from combustion or use of the products supplied.
(b) Owners and operators of facilities and suppliers that are subject to this part must follow the requirements of this subpart and all applicable subparts of this part. If a conflict exists between a provision in subpart A and any other applicable subpart, the requirements of the applicable subpart shall take precedence.
(c) For facilities required to report under onshore petroleum and natural gas production under subpart W of this part, the terms
(a) The GHG reporting requirements and related monitoring, recordkeeping, and reporting requirements of this part apply to the owners and operators of any facility that is located in the United States or under or attached to the Outer Continental Shelf (as defined in 43 U.S.C. 1331) and that meets the requirements of either paragraph (a)(1), (a)(2), or (a)(3) of this section; and any supplier that meets the requirements of paragraph (a)(4) of this section:
(1)
(2)
(3)
(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
(4)
(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
(1) Calculate the annual emissions of CO
(2) For each general stationary fuel combustion unit, calculate the annual CO
(3) For miscellaneous uses of carbonate, calculate the annual CO
(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
(5) For purpose of determining if an emission threshold has been exceeded, include in the emissions calculation any CO
(c) To calculate GHG emissions for comparison to the 25,000 metric ton CO
(d) To calculate GHG quantities for comparison to the 25,000 metric ton CO
(e) To calculate GHG quantities for comparison to the 25,000 metric ton CO
(f) To calculate GHG quantities for comparison to the 25,000 metric ton
(1) Calculate the mass in metric tons per year of CO
(2) Convert the mass of each imported and each GHG exported from paragraph (f)(1) of this section to metric tons of CO
(3) Sum the total annual metric tons of CO
(g) If a capacity or generation reporting threshold in paragraph (a)(1) of this section applies, the owner or operator shall review the appropriate records and perform any necessary calculations to determine whether the threshold has been exceeded.
(h) An owner or operator of a facility or supplier that does not meet the applicability requirements of paragraph (a) of this section is not subject to this rule. Such owner or operator would become subject to the rule and reporting requirements, if a facility or supplier exceeds the applicability requirements of paragraph (a) of this section at a later time pursuant to § 98.3(b)(3). Thus, the owner or operator should reevaluate the applicability to this part (including the revising of any relevant emissions calculations or other calculations) whenever there is any change that could cause a facility or supplier to meet the applicability requirements of paragraph (a) of this section. Such changes include but are not limited to process modifications, increases in operating hours, increases in production, changes in fuel or raw material use, addition of equipment, and facility expansion.
(i) Except as provided in this paragraph, once a facility or supplier is subject to the requirements of this part, the owner or operator must continue for each year thereafter to comply with all requirements of this part, including the requirement to submit annual GHG reports, even if the facility or supplier does not meet the applicability requirements in paragraph (a) of this section in a future year.
(1) If reported emissions are less than 25,000 metric tons CO
(2) If reported emissions are less than 15,000 metric tons CO
(3) If the operations of a facility or supplier are changed such that all applicable processes and operations subject to paragraphs (a)(1) through (4) of this section cease to operate, then the owner or operator may discontinue complying with this part for the reporting 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 applicable processes and operations no later than March 31 of the year following such changes. If one or more processes or operations subject to paragraphs (a)(1) through (4) of this section at a facility or supplier cease to operate, but not all applicable processes or operations cease to operate, then the owner or operator is exempt from reporting for any such processes or operations in the reporting years following the reporting year in which cessation of the process or operation occurs, provided that the owner or operator submits a notification to the Administrator that announces the cessation of reporting for the process or operation no later than March 31 following the first reporting year in which the process or operation has ceased for an entire reporting year. Cessation of operations in the context of underground coal mines includes, but is not limited to, abandoning and sealing the facility. This paragraph (i)(3) does not apply to seasonal or other temporary cessation of operations. This paragraph (i)(3) does not apply to the municipal solid waste landfills source category (subpart HH of this subpart), or the industrial waste landfills source category (subpart TT of this part). The owner or operator must resume reporting for any future calendar year during which any of the GHG-emitting processes or operations resume operation.
(4) The provisions of paragraphs (i)(1) and (2) of this section apply to suppliers subject to subparts LL through QQ of this part by substituting the term “quantity of GHG supplied” for “emissions.” For suppliers, the provisions of paragraphs (i)(1) and (2) apply individually to each importer and exporter and individually to each petroleum refinery, fractionator of natural gas liquids, local natural gas distribution company, and producer of CO
(5) If the operations of a facility or supplier are changed such that a process or operation no longer meets the “Definition of Source Category” as specified in an applicable subpart, then the owner or operator may discontinue complying with any such subpart for the reporting years following the year in which change occurs, provided that the owner or operator submits a notification to the Administrator that announces the cessation of reporting for the process or operation no later than March 31 following the first reporting year in which such changes persist for an entire reporting year. The owner or operator must resume complying with this part for the process or operation starting in any future calendar year during which the process or operation meets the “Definition of Source Category” as specified in an applicable subpart.
(6) If an entire facility or supplier is merged into another facility or supplier that is already reporting GHG data under this part, then the owner or operator may discontinue complying with this part for the facility or supplier, provided that the owner or operator submits a notification to the Administrator that announces the discontinuation of reporting and the e-GGRT identification number of the reconstituted facility no later than March 31 of the year following such changes.
(j) Table A-2 of this subpart provides a conversion table for some of the common units of measure used in part 98.
The owner or operator of a facility or supplier that is subject to the requirements of this part must submit GHG reports to the Administrator, as specified in this section.
(a)
(b)
(1) For reporting year 2011, facilities with one or more of the subparts listed in paragraphs (b)(1)(i) through (b)(1)(xi) of this section and suppliers listed in paragraph (b)(1)(xii) of this section are required to submit their annual GHG report no later than September 28, 2012. Facilities and suppliers that are submitting their second annual GHG report in 2012 and that are reporting on one or more subparts listed in paragraphs (b)(1)(i) through (b)(1)(xii) of this section must notify EPA by March 31, 2012 that they are not required to submit their annual GHG report until September 28, 2012.
(i) Electronics Manufacturing (subpart I).
(ii) Fluorinated Gas Production (subpart L).
(iii) Magnesium Production (subpart T).
(iv) Petroleum and Natural Gas Systems (subpart W).
(v) Use of Electric Transmission and Distribution Equipment (subpart DD).
(vi) Underground Coal Mines (subpart FF).
(vii) Industrial Wastewater Treatment (subpart II).
(viii) Geologic Sequestration of Carbon Dioxide (subpart RR).
(ix) Manufacture of Electric Transmission and Distribution (subpart SS).
(x) Industrial Waste Landfills (subpart TT).
(xi) Injection of Carbon Dioxide (subpart UU).
(xii) Imports and Exports of Equipment Pre-charged with Fluorinated GHGs or Containing Fluorinated GHGs in Closed-cell Foams (subpart QQ).
(2) For a new facility or supplier that begins operation on or after January 1, 2010 and becomes subject to the rule in the year that it becomes operational, report emissions beginning with the first operating month and ending on December 31 of that year. Each subsequent annual report must cover emissions for the calendar year, beginning on January 1 and ending on December 31.
(3) For any facility or supplier that becomes subject to this rule because of a physical or operational change that is made after January 1, 2010, report emissions for the first calendar year in which the change occurs, beginning with the first month of the change and ending on December 31 of that year. For a facility or supplier that becomes subject to this rule solely because of an increase in hours of operation or level of production, the first month of the change is the month in which the increased hours of operation or level of production, if maintained for the remainder of the year, would cause the facility or supplier to exceed the applicable threshold. Each subsequent annual report must cover emissions for the calendar year, beginning on January 1 and ending on December 31.
(4) Unless otherwise stated, if the final day of any time period falls on a weekend or a federal holiday, the time period shall be extended to the next business day.
(c)
(1) Facility name or supplier name (as appropriate), and physical street address of the facility or supplier, including the city, State, and zip code. If the facility does not have a physical street address, then the facility must provide the latitude and longitude representing the geographic centroid or center point of facility operations in decimal degree format. This must be provided in a comma-delimited “latitude, longitude” coordinate pair reported in decimal degrees to at least four digits to the right of the decimal point.
(2) Year and months covered by the report.
(3) Date of submittal.
(4) For facilities, except as otherwise provided in paragraph (c)(12) of this section, report annual emissions of CO
(i) Annual emissions (excluding biogenic CO
(ii) Annual emissions of biogenic CO
(iii) Annual emissions from each applicable source category, expressed in metric tons of each applicable GHG listed in paragraphs (c)(4)(iii)(A) through (F) of this section.
(A) Biogenic CO
(B) CO
(C) CH
(D) N
(E) Each fluorinated GHG (as defined in § 98.6), except fluorinated gas production facilities must comply with § 98.126(a) rather than this paragraph (c)(4)(iii)(E). If a fluorinated GHG does not have a chemical-specific GWP in Table A-1 of this subpart, identify and report the fluorinated GHG group of which that fluorinated GHG is a member.
(F) For electronics manufacturing (as defined in § 98.90), each fluorinated heat transfer fluid (as defined in § 98.98) that is not also a fluorinated GHG as specified under (c)(4)(iii)(E) of this section. If a fluorinated heat transfer fluid does not have a chemical-specific GWP in Table A-1 of this subpart, identify and report the fluorinated GHG group of which that fluorinated heat transfer fluid is a member.
(G) For each reported fluorinated GHG and fluorinated heat transfer fluid, report the following identifying information:
(
(
(
(iv) Except as provided in paragraph (c)(4)(vii) of this section, emissions and other data for individual units, processes, activities, and operations as specified in the “Data reporting requirements” section of each applicable subpart of this part.
(v) Indicate (yes or no) whether reported emissions include emissions from a cogeneration unit located at the facility.
(vi) [Reserved]
(vii) The owner or operator of a facility is not required to report the data elements specified in Table A-6 of this subpart for calendar years 2010 through 2011 until March 31, 2013. The owner or operator of a facility is not required to report the data elements specified in Table A-7 of this subpart for calendar years 2010 through 2013 until March 31, 2015 (as part of the annual report for reporting year 2014), except as otherwise specified in Table A-7 of this subpart.
(viii) Applicable source categories means stationary fuel combustion
(5) For suppliers, report annual quantities of CO
(i) Total quantity of GHG aggregated for all GHG from all applicable supply categories in Table A-5 of this subpart and expressed in metric tons of CO
(ii) Quantity of each GHG from each applicable supply category in Table A-5 to this subpart, expressed in metric tons of each GHG. For each reported fluorinated GHG, report the following identifying information:
(A) Chemical name. If the chemical is not listed in Table A-1 of this subpart, then use the method of naming organic chemical compounds as recommended by the International Union of Pure and Applied Chemistry (IUPAC).
(B) The CAS registry number assigned by the Chemical Abstracts Registry Service. If a CAS registry number is not assigned or is not associated with a single fluorinated GHG, then report an identification number assigned by EPA's Substance Registry Services.
(C) Linear chemical formula.
(iii) Any other data specified in the “Data reporting requirements” section of each applicable subpart of this part.
(6) A written explanation, as required under § 98.3(e), if you change emission calculation methodologies during the reporting period.
(7) A brief description of each “best available monitoring method” used, the parameter measured using the method, and the time period during which the “best available monitoring method” was used, if applicable.
(8) Each parameter 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 parameter. Parameters include not only reported data elements, but any data element required for monitoring and calculating emissions.
(9) A signed and dated certification statement provided by the designated representative of the owner or operator, according to the requirements of § 98.4(e)(1).
(10) NAICS code(s) that apply to the facility or supplier.
(i)
(ii)
(11) Legal name(s) and physical address(es) of the highest-level United States parent company(s) of the owners (or operators) of the facility or supplier and the percentage of ownership interest for each listed parent company as of December 31 of the year for which data are being reported according to the following instructions:
(i) If the facility or supplier is entirely owned by a single United States company that is not owned by another company, provide that company's legal name and physical address as the United States parent company and report 100 percent ownership.
(ii) If the facility or supplier is entirely owned by a single United States company that is, itself, owned by another company (
(iii) If the facility or supplier is owned by more than one United States company (
(iv) If the facility or supplier is owned by a joint venture or a cooperative, the joint venture or cooperative is its own United States parent company. Provide the legal name and physical address of the joint venture or cooperative as the United States parent company, and report 100 percent ownership by the joint venture or cooperative.
(v) If the facility or supplier is entirely owned by a foreign company, provide the legal name and physical address of the foreign company's highest-level company based in the United States as the United States parent company, and report 100 percent ownership.
(vi) If the facility or supplier is partially owned by a foreign company and partially owned by one or more U.S. companies, provide the legal name and physical address of the foreign company's highest-level company based in the United States, along with the legal names and physical addresses of the other U.S. parent companies, and report the percent ownership of each of these companies.
(vii) If the facility or supplier is a federally owned facility, report “U.S. Government” and do not report physical address or percent ownership.
(viii) The facility or supplier must refer to the reporting instructions of the electronic GHG reporting tool regarding standardized conventions for the naming of a parent company.
(12) For the 2010 reporting year only, facilities that have “part 75 units” (
(i) Annual emissions aggregated for all GHG from all applicable source categories, expressed in metric tons of CO
(ii) Annual emissions of biogenic CO
(iii) Annual emissions from each applicable source category, expressed in metric tons of each applicable GHG listed in paragraphs (c)(12)(iii)(A) through (c)(12)(iii)(E) of this section.
(A) Biogenic CO
(B) CO
(C) CH
(D) N
(E) Each fluorinated GHG (including those not listed in Table A-1 of this subpart).
(13) An indication of whether the facility includes one or more plant sites that have been assigned a “plant code” (as defined under § 98.6) by either the Department of Energy's Energy Information Administration or by the EPA's Clean Air Markets Division.
(d)
(i) Monitoring methods currently used by the facility that do not meet the specifications of a relevant subpart.
(ii) Supplier data.
(iii) Engineering calculations.
(iv) Other company records.
(2)
(i)
(ii)
(A) A list of specific item of monitoring instrumentation for which the request is being made and the locations where each piece of monitoring instrumentation will be installed.
(B) Identification of the specific rule requirements (by rule subpart, section, and paragraph numbers) for which the instrumentation is needed.
(C) A description of the reasons why the needed equipment could not be obtained and installed before April 1, 2010.
(D) If the reason for the extension is that the equipment cannot be purchased and delivered by April 1, 2010, include supporting documentation such as the date the monitoring equipment was ordered, investigation of alternative suppliers and the dates by which alternative vendors promised delivery, backorder notices or unexpected delays, descriptions of actions taken to expedite delivery, and the current expected date of delivery.
(E) If the reason for the extension is that the equipment cannot be installed without a process unit shutdown, include supporting documentation demonstrating that it is not practicable to isolate the equipment and install the monitoring instrument without a full process unit shutdown. Include the date of the most recent process unit shutdown, the frequency of shutdowns for this process unit, and the date of the next planned shutdown during which the monitoring equipment can be installed. If there has been a shutdown or if there is a planned process unit shutdown between promulgation of this part and April 1, 2010, include a justification of why the equipment could not be obtained and installed during that shutdown.
(F) A description of the specific actions the facility will take to obtain and install the equipment as soon as reasonably feasible and the expected date by which the equipment will be installed and operating.
(iii)
(3)
(i) Facility name and physical street address including the city, state and zip code.
(ii) The year and months covered by the report.
(iii) Date of submittal.
(iv) Total facility GHG emissions aggregated for all stationary fuel combustion units calculated according to any method specified in § 98.33(a) and expressed in metric tons of CO
(v) For each stationary fuel combustion source that meets the criteria specified in § 98.36(f), report any facility operating data or process information used for the GHG emission calculations. A stationary fuel combustion source that does not meet the criteria specified in § 98.36(f) must either report the data specified in this paragraph (d)(3)(v) in the annual report or use verification software according to § 98.5(b) in lieu of reporting the data specified in this paragraph.
(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)
(f)
(g)
(1) A list of all units, operations, processes, and activities for which GHG emission were calculated.
(2) The data used to calculate the GHG emissions for each unit, operation, process, and activity, categorized by fuel or material type. These data include but are not limited to the following information in this paragraph (g)(2):
(i) The GHG emissions calculations and methods used. For data required by § 98.5(b) to be entered into verification software specified in § 98.5(b), maintain the entered data in the format generated by the verification software according to § 98.5(b).
(ii) Analytical results for the development of site-specific emissions factors.
(iii) The results of all required analyses for high heat value, carbon content, and other required fuel or feedstock parameters.
(iv) Any facility operating data or process information used for the GHG emission calculations.
(3) The annual GHG reports.
(4) Missing data computations. For each missing data event, also retain a record of the cause of the event and the corrective actions taken to restore malfunctioning monitoring equipment.
(5) A written GHG Monitoring Plan.
(i) At a minimum, the GHG Monitoring Plan shall include the elements listed in this paragraph (g)(5)(i).
(A) Identification of positions of responsibility (i.e., job titles) for collection of the emissions data.
(B) Explanation of the processes and methods used to collect the necessary data for the GHG calculations.
(C) Description of the procedures and methods that are used for quality assurance, maintenance, and repair of all continuous monitoring systems, flow meters, and other instrumentation used to provide data for the GHGs reported under this part.
(ii) The GHG Monitoring Plan may rely on references to existing corporate documents (e.g., standard operating procedures, quality assurance programs under appendix F to 40 CFR part 60 or appendix B to 40 CFR part 75, and other documents) provided that the elements required by paragraph (g)(5)(i) of this section are easily recognizable.
(iii) The owner or operator shall revise the GHG Monitoring Plan as needed to reflect changes in production processes, monitoring instrumentation, and quality assurance procedures; or to improve procedures for the maintenance and repair of monitoring systems to reduce the frequency of monitoring equipment downtime.
(iv) Upon request by the Administrator, the owner or operator shall make all information that is collected in conformance with the GHG Monitoring Plan available for review during an audit. Electronic storage of the information in the plan is permissible, provided that the information can be made available in hard copy upon request during an audit.
(6) The results of all required certification and quality assurance tests of continuous monitoring systems, fuel flow meters, and other instrumentation used to provide data for the GHGs reported under this part.
(7) Maintenance records for all continuous monitoring systems, flow meters, and other instrumentation used to provide data for the GHGs reported under this part.
(h)
(1) The owner or operator shall submit a revised annual GHG report within 45 days of discovering that an annual GHG report that the owner or operator previously submitted contains one or more substantive errors. The revised report must correct all substantive errors.
(2) The Administrator may notify the owner or operator in writing that an annual GHG report previously submitted by the owner or operator contains one or more substantive errors. Such notification will identify each such substantive error. The owner or operator shall, within 45 days of receipt of the notification, either resubmit the report that, for each identified substantive error, corrects the identified substantive error (in accordance with the applicable requirements of this part) or provide information demonstrating that the previously submitted report does not contain the identified substantive error or that the identified error is not a substantive error.
(3) A substantive error is an error that impacts the quantity of GHG emissions reported or otherwise prevents the reported data from being validated or verified.
(4) Notwithstanding paragraphs (h)(1) and (2) of this section, upon request by the owner or operator, the Administrator may provide reasonable extensions of the 45-day period for submission of the revised report or information under paragraphs (h)(1) and (2). If the Administrator receives a request for extension of the 45-day period, by email to an address prescribed by the Administrator prior to the expiration of the 45-day period, the extension request is deemed to be automatically granted for 30 days. The Administrator may grant an additional extension beyond the automatic 30-day extension if the owner or operator submits a request for an additional extension and the request is received by the Administrator prior to the expiration of the automatic 30-day extension, provided the request demonstrates that it is not practicable to submit a revised report
(5) The owner or operator shall retain documentation for 3 years to support any revision made to an annual GHG report.
(i)
(1) Except as otherwise provided in paragraphs (i)(4) through (i)(6) of this section, flow meters that measure liquid and gaseous fuel feed rates, process stream flow rates, or feedstock flow rates and provide data for the GHG emissions calculations shall be calibrated prior to April 1, 2010 using the procedures specified in this paragraph (i) when such calibration is specified in a relevant subpart of this part. Each of these flow meters shall meet the applicable accuracy specification in paragraph (i)(2) or (i)(3) of this section. All other measurement devices (
(i) All flow meters and other measurement devices that are subject to the provisions of this paragraph (i) must be calibrated according to one of the following: You may use the manufacturer's recommended procedures; an appropriate industry consensus standard method; or a method specified in a relevant subpart of this part. The calibration method(s) used shall be documented in the monitoring plan required under paragraph (g) of this section.
(ii) For facilities and suppliers that become subject to this part after April 1, 2010, all flow meters and other measurement devices (if any) that are required by the relevant subpart(s) of this part to provide data for the GHG emissions calculations shall be installed no later than the date on which data collection is required to begin using the measurement device, and the initial calibration(s) required by this paragraph (i) (if any) shall be performed no later than that date.
(iii) Except as otherwise provided in paragraphs (i)(4) through (i)(6) of this section, subsequent recalibrations of the flow meters and other measurement devices subject to the requirements of this paragraph (i) shall be performed at one of the following frequencies:
(A) You may use the frequency specified in each applicable subpart of this part.
(B) You may use the frequency recommended by the manufacturer or by an industry consensus standard practice, if no recalibration frequency is specified in an applicable subpart.
(2) Perform all flow meter calibration at measurement points that are representative of the normal operating
(3) For orifice, nozzle, and venturi flow meters, the initial quality assurance consists of in-situ calibration of the differential pressure (delta-P), total pressure, and temperature transmitters.
(i) Calibrate each transmitter at a zero point and at least one upscale point. Fixed reference points, such as the freezing point of water, may be used for temperature transmitter calibrations. Calculate the calibration error of each transmitter at each measurement point, using Equation A-3 of this subpart. The terms “R,” “A,” and “FS” in Equation A-3 of this subpart must be in consistent units of measure (
(ii) In cases where there are only two transmitters (
(A) You must demonstrate that measurements at the remote location(s) can, when appropriate correction factors are applied, reliably and accurately represent the actual temperature or total pressure at the flow meter under all expected ambient conditions.
(B) You must make all temperature and/or total pressure measurements in the demonstration described in paragraph (i)(3)(ii)(A) of this section with calibrated gauges, sensors, transmitters, or other appropriate measurement devices. At a minimum, calibrate each of these devices to an accuracy within the appropriate error range for the specific measurement technology, according to one of the following. You may calibrate using a manufacturer's specification or an industry consensus standard.
(C) You must document the methods used for the demonstration described in paragraph (i)(3)(ii)(A) of this section in the written GHG Monitoring Plan under paragraph (g)(5)(i)(C) of this section. You must also include the data from the demonstration, the mathematical correlation(s) between the remote readings and actual flow meter conditions derived from the data, and any supporting engineering calculations in the GHG Monitoring Plan. You must maintain all of this information in a format suitable for auditing and inspection.
(D) You must use the mathematical correlation(s) derived from the demonstration described in paragraph (i)(3)(ii)(A) of this section to convert the remote temperature or the total pressure readings, or both, to the actual temperature or total pressure at the flow meter, or both, on a daily basis. You shall then use the actual temperature and total pressure values to correct the measured flow rates to standard conditions.
(E) You shall periodically check the correlation(s) between the remote and actual readings (at least once a year), and make any necessary adjustments to the mathematical relationship(s).
(4) Fuel billing meters are exempted from the calibration requirements of this section and from the GHG Monitoring Plan and recordkeeping provisions of paragraphs (g)(5)(i)(C), (g)(6), and (g)(7) of this section, provided that the fuel supplier and any unit combusting the fuel do not have any common owners and are not owned by subsidiaries or affiliates of the same company. Meters used exclusively to measure the flow rates of fuels that are used for unit startup are also exempted from the calibration requirements of this section.
(5) For a flow meter that has been previously calibrated in accordance with paragraph (i)(1) of this section, an additional calibration is not required by the date specified in paragraph (i)(1) of this section if, as of that date, the previous calibration is still active (
(6) For units and processes that operate continuously with infrequent outages, it may not be possible to meet the April 1, 2010 deadline for the initial calibration of a flow meter or other measurement device without disrupting normal process operation. In such cases, the owner or operator may postpone the initial calibration until the next scheduled maintenance outage. The best available information from company records may be used in the interim. The subsequent required recalibrations of the flow meters may be similarly postponed. Such postponements shall be documented in the monitoring plan that is required under paragraph (g)(5) of this section.
(7) If the results of an initial calibration or a recalibration fail to meet the required accuracy specification, data from the flow meter shall be considered invalid, beginning with the hour of the failed calibration and continuing until a successful calibration is completed. You shall follow the missing data provisions provided in the relevant missing data sections during the period of data invalidation.
(j)
(2)
(3)
(ii) Any subsequent extensions to the original request must be submitted to the Administrator within 4 weeks of the owner or operator identifying the need to extend the request, but in any event no later than 4 weeks before the date for the planned process equipment or unit shutdown that was provided in the original or most recently approved request.
(4)
(i) Specific measurement device for which the request is being made and the location where each measurement device will be installed.
(ii) Identification of the specific rule requirements (by rule subpart, section, and paragraph numbers) requiring the measurement device.
(iii) A description of the reasons why the needed equipment could not be installed before April 1, 2010, or by the expiration date for the use of best available monitoring methods, in cases where an extension has been granted under § 98.3(d).
(iv) Supporting documentation showing that it is not practicable to isolate the process equipment or unit and install the measurement device without a full shutdown or a hot tap, and that there was no opportunity during 2010 to install the device. Include the date of the three most recent shutdowns for each relevant process equipment or unit, the frequency of shutdowns for each relevant process equipment or unit, and the date of the next planned process equipment or unit shutdown.
(v) Include a description of the proposed best available monitoring method for estimating GHG emissions during the time prior to installation of the meter.
(5)
(6)
(7)
(k)
(1) A facility or supplier that first becomes subject to part 98 due to a change in the GWP for one or more compounds in Table A-1 of this subpart, Global Warming Potentials, is not required to submit an annual GHG report for the reporting year during which the change in GWPs is published.
(2) A facility or supplier that was already subject to one or more subparts of part 98 but becomes subject to one or more additional subparts due to a change in the GWP for one or more compounds in Table A-1 of this subpart, is not required to include those subparts to which the facility is subject only due to the change in the GWP in the annual GHG report submitted for the reporting year during which the change in GWPs is published.
(3) Starting on January 1 of the year after the year during which the change in GWPs is published, facilities or suppliers identified in paragraphs (k)(1) or (2) of this section must start monitoring and collecting GHG data in compliance with the applicable subparts of part 98 to which the facility is subject due to the change in the GWP for the annual greenhouse gas report for that reporting year, which is due by March 31 of the following calendar year.
(4) A change in the GWP for one or more compounds includes the addition to Table A-1 of this subpart of either a chemical-specific or a default GWP that applies to a compound to which no chemical-specific GWP in Table A-1 of this subpart previously applied.
(l)
(1)
(i) Monitoring methods currently used by the facility that do not meet the specifications of a relevant subpart.
(ii) Supplier data.
(iii) Engineering calculations.
(iv) Other company records.
(2)
(i)
(ii)
(A) A list of specific items of monitoring instrumentation for which the request is being made and the locations where each piece of monitoring instrumentation will be installed.
(B) Identification of the specific rule requirements (by rule subpart, section, and paragraph numbers) for which the instrumentation is needed.
(C) A description of the reasons that the needed equipment could not be obtained and installed before April 1 of the year after the year during which the change in GWPs is published.
(D) If the reason for the extension is that the equipment cannot be purchased and delivered by April 1 of the year after the year during which the change in GWPs is published, 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 November 29 of the year during which the change in GWPs is published and April 1 of the year after the year during which the change in GWPs is published, include a justification of why the equipment could not be obtained and installed during that shutdown.
(F) A description of the specific actions the facility will take to obtain and install the equipment as soon as reasonably feasible and the expected date by which the equipment will be installed and operating.
(iii)
(a)
(b)
(c)
(d)
(e)
(1) Each such submission shall include the following certification statement signed by the designated representative or any alternate designated representative: “I am authorized to make this submission on behalf of the owners and operators of the facility or supplier, as applicable, for which the submission is made. I certify under penalty of law that I have personally examined, and am familiar with, the statements and information submitted in this document and all its attachments. Based on my inquiry of those individuals with primary responsibility for obtaining the information, I certify that the statements and information are to the best of my knowledge and belief true, accurate, and complete. I am aware that there are significant penalties for submitting false statements and information or omitting required statements and information, including the possibility of fine or imprisonment.”
(2) The Administrator will accept a GHG emission report or other submission for a facility or supplier under this part only if the submission is certified, signed, and submitted in accordance with this section.
(f)
(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
(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)
(h)
(i)
(1) Identification of the facility or supplier for which the certificate of representation is submitted.
(2) The name, organization name (company affiliation-employer), address, e-mail address (if any), telephone number, and facsimile transmission number (if any) of the designated representative and any alternate designated representative.
(3) A list of the owners and operators of the facility or supplier identified in paragraph (i)(1) of this section, provided that, if the list includes the operators of the facility or supplier and the owners with control of the facility or supplier, the failure to include any other owners shall not make the certificate of representation incomplete.
(4) The following certification statements by the designated representative and any alternate designated representative:
(i) “I certify that I was selected as the designated representative or alternate designated representative, as applicable, by an agreement binding on the owners and operators of the facility or supplier, as applicable.”
(ii) “I certify that I have all the necessary authority to carry out my duties and responsibilities under 40 CFR part 98 on behalf of the owners and operators of the facility or supplier, as applicable, and that each such owner
(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.
(6) A list of the subparts that the owners and operators anticipate will be included in the annual GHG report. The list of potentially applicable subparts is required only for an initial certificate of representation that is submitted after January 1, 2018 (
(j)
(k)
(l)
(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)
(2) In order to delegate his or her own authority, to one or more individuals, to submit an electronic submission to the Administrator in accordance with paragraph (m)(1) of this section, the designated representative or alternate designated representative must submit electronically to the Administrator a notice of delegation, in a format prescribed by the Administrator, that includes the following elements:
(i) The name, organization name (company affiliation-employer) address, e-mail address (if any), telephone number, and facsimile transmission number (if any) of such designated representative or alternate designated representative.
(ii) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of each such individual (referred to as an “agent”).
(iii) For each such individual, a list of the type or types of electronic submissions under paragraph (m)(1) of this section for which authority is delegated to him or her.
(iv) For each type of electronic submission listed in accordance with paragraph (m)(2)(iii) of this section, the facility or supplier for which the electronic submission may be made.
(v) The following certification statements by such designated representative or alternate designated representative:
(A) “I agree that any electronic submission to the Administrator that is by an agent identified in this notice of delegation and of a type listed, and for a facility or supplier designated, for such agent in this notice of delegation and that is made when I am a designated representative or alternate designated representative, as applicable, and before this notice of delegation is superseded by another notice of delegation under § 98.4(m)(3) shall be deemed to be an electronic submission certified, signed, and submitted by me.”
(B) “Until this notice of delegation is superseded by a later signed notice of delegation under § 98.4(m)(3), I agree to maintain an e-mail account and to notify the Administrator immediately of any change in my e-mail address unless all delegation of authority by me under § 98.4(m) is terminated.”
(vi) The signature of such designated representative or alternate designated representative and the date signed.
(3) A notice of delegation submitted in accordance with paragraph (m)(2) of this section shall be effective, with regard to the designated representative or alternate designated representative identified in such notice, upon receipt of such notice by the Administrator and until receipt by the Administrator of another such notice that was signed later by such designated representative or alternate designated representative, as applicable. The later signed notice of delegation may replace any previously identified agent, add a new agent, or eliminate entirely any delegation of authority.
(4) Any electronic submission covered by the certification in paragraph (m)(2)(v)(A) of this section and made in accordance with a notice of delegation effective under paragraph (m)(3) of this section shall be deemed to be an electronic submission certified, signed, and submitted by the designated representative or alternate designated representative submitting such notice of delegation.
(a) 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.
(b) For reporting year 2014 and thereafter, unless a later year is specified in the applicable recordkeeping section, you must enter into verification software specified by the Administrator the data specified in the verification software records provision in each applicable recordkeeping section. For each data element entered into the verification software, if the software produces a warning message for the data value and you elect not to revise the data value, you may provide an explanation in the verification software of why the data value is not being revised.
All terms used in this part shall have the same meaning given in the Clean Air Act and in this section.
(i) Small amounts of hydrocarbons that exist in gaseous phase in natural underground reservoirs but are liquid at atmospheric conditions (temperature and pressure) after being recovered from oil well (casing-head) gas in lease separators and are subsequently commingled with the crude stream without being separately measured. Lease condensate recovered as a liquid from natural gas wells in lease or field separation facilities and later mixed into the crude stream is also included.
(ii) Small amounts of non-hydrocarbons, such as sulfur and various metals.
(iii) Drip gases, and liquid hydrocarbons produced from tar sands, oil sands, gilsonite, and oil shale.
(iv) Petroleum products that are received or produced at a refinery and subsequently injected into a crude supply or reservoir by the same refinery owner or operator.
(2) Liquids produced at natural gas processing plants are excluded. Crude oil is refined to produce a wide array of petroleum products, including heating oils; gasoline, diesel and jet fuels; lubricants; asphalt; ethane, propane, and butane; and many other products used for their energy or chemical content.
(1) With respect to landfills and manure management, the combustion of methane in any on-site or off-site combustion technology. Destroyed methane includes, but is not limited to, methane combusted by flaring, methane destroyed by thermal oxidation, methane combusted for use in on-site energy or heat production technologies, methane that is conveyed through pipelines (including natural gas pipelines) for off-site combustion, and methane that is collected for any other on-site or off-site use as a fuel.
(2) With respect to fluorinated GHGs, the expiration of a fluorinated GHG to the destruction efficiency actually achieved. Such destruction does not result in a commercially useful end product.
(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.
(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.
(1) The Plant ID code assigned by the Department of Energy's Energy Information Administration. The Energy Information Administration Plant ID code is also referred to as the “ORIS code”, “ORISPL code”, “Facility ID”, or “Facility code”, among other names.
(2) If a Plant ID code has not been assigned by the Department of Energy's Energy Information Administration, then plant code means a code beginning with “88” assigned by the EPA's Clean Air Markets Division for electronic reporting.
(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.
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
(a)-(b) [Reserved]
(c) The following material is available for purchase from the ASM International, 9639 Kinsman Road, Materials Park, OH 44073, (440) 338-5151,
(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,
(1) ASME MFC-3M-2004 Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and Venturi, incorporation by reference (IBR) approved for § 98.124(m)(1), § 98.324(e), § 98.354(d), § 98.354(h), § 98.344(c) and § 98.364(e).
(2) ASME MFC-4M-1986 (Reaffirmed 1997) Measurement of Gas Flow by Turbine Meters, IBR approved for § 98.124(m)(2), § 98.324(e), § 98.344(c), § 98.354(h), and § 98.364(e).
(3) ASME MFC-5M-1985 (Reaffirmed 1994) Measurement of Liquid Flow in Closed Conduits Using Transit-Time Ultrasonic Flow Meters, IBR approved for § 98.124(m)(3) and § 98.354(d).
(4) ASME MFC-6M-1998 Measurement of Fluid Flow in Pipes Using Vortex Flowmeters, IBR approved for § 98.124(m)(4), § 98.324(e), § 98.344(c), § 98.354(h), and § 98.364(e).
(5) ASME MFC-7M-1987 (Reaffirmed 1992) Measurement of Gas Flow by Means of Critical Flow Venturi Nozzles, IBR approved for § 98.124(m)(5), § 98.324(e), § 98.344(c), § 98.354(h), and § 98.364(e).
(6) ASME MFC-9M-1988 (Reaffirmed 2001) Measurement of Liquid Flow in Closed Conduits by Weighing Method, IBR approved for § 98.124(m)(6).
(7) ASME MFC-11M-2006 Measurement of Fluid Flow by Means of Coriolis Mass Flowmeters, IBR approved for § 98.124(m)(7), § 98.324(e), § 98.344(c), and § 98.354(h).
(8) ASME MFC-14M-2003 Measurement of Fluid Flow Using Small Bore Precision Orifice Meters, IBR approved for § 98.124(m)(8), § 98.324(e), § 98.344(c), § 98.354(h), and § 98.364(e).
(9) ASME MFC-16-2007 Measurement of Liquid Flow in Closed Conduits with Electromagnetic Flow Meters, IBR approved for § 98.354(d).
(10) ASME MFC-18M-2001 Measurement of Fluid Flow Using Variable Area Meters, IBR approved for § 98.324(e), § 98.344(c), § 98.354(h), and § 98.364(e).
(e) The following material is available for purchase from the American Society for Testing and Material (ASTM), 100 Barr Harbor Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959, (800) 262-1373,
(1) ASTM C25-06 Standard Test Method for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime, incorporation by reference (IBR) approved for § 98.114(b), § 98.174(b), § 98.184(b), § 98.194(c), and § 98.334(b).
(2) ASTM C114-09 Standard Test Methods for Chemical Analysis of Hydraulic Cement, IBR approved for § 98.84(a), § 98.84(b), and § 98.84(c).
(3) ASTM D235-02 (Reapproved 2007) Standard Specification for Mineral Spirits (Petroleum Spirits) (Hydrocarbon Dry Cleaning Solvent), IBR approved for § 98.6.
(4) ASTM D240-02 (Reapproved 2007) Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter, IBR approved for § 98.254(e).
(5) ASTM D388-05 Standard Classification of Coals by Rank, IBR approved for § 98.6.
(6) ASTM D910-07a Standard Specification for Aviation Gasolines, IBR approved for § 98.6.
(7) [Reserved]
(8) ASTM D1826-94 (Reapproved 2003) Standard Test Method for Calorific (Heating) Value of Gases in Natural Gas Range by Continuous Recording Calorimeter, IBR approved for § 98.254(e).
(9) ASTM D1836-07 Standard Specification for Commercial Hexanes, IBR approved for § 98.6.
(10) ASTM D1945-03 Standard Test Method for Analysis of Natural Gas by Gas Chromatography, IBR approved for § 98.74(c), § 98.164(b), § 98.244(b), § 98.254(d), § 98.324(d), § 98.354(g), and § 98.344(b).
(11) ASTM D1946-90 (Reapproved 2006) Standard Practice for Analysis of Reformed Gas by Gas Chromatography, IBR approved for § 98.74(c), § 98.164(b), § 98.254(d), § 98.324(d), § 98.344(b), § 98.354(g), and § 98.364(c).
(12) ASTM D2013-07 Standard Practice for Preparing Coal Samples for Analysis, IBR approved for § 98.164(b).
(13) ASTM D2234/D2234M-07 Standard Practice for Collection of a Gross Sample of Coal, IBR approved for § 98.164(b).
(14) ASTM D2502-04 Standard Test Method for Estimation of Mean Relative Molecular Mass of Petroleum Oils From Viscosity Measurements, IBR approved for § 98.74(c).
(15) ASTM D2503-92 (Reapproved 2007) Standard Test Method for Relative Molecular Mass (Molecular Weight) of Hydrocarbons by Thermoelectric Measurement of Vapor Pressure, IBR approved for § 98.74(c) and § 98.254(d)(6).
(16) ASTM D2505-88 (Reapproved 2004)e1 Standard Test Method for Ethylene, Other Hydrocarbons, and Carbon Dioxide in High-Purity Ethylene by Gas Chromatography, IBR approved for § 98.244(b).
(17) ASTM D2597-94 (Reapproved 2004) Standard Test Method for Analysis of Demethanized Hydrocarbon Liquid Mixtures Containing Nitrogen and Carbon Dioxide by Gas Chromatography, IBR approved for § 98.164(b).
(18) ASTM D3176-89 (Reapproved 2002) Standard Practice for Ultimate Analysis of Coal and Coke, IBR approved for § 98.74(c), § 98.164(b), § 98.244(b), § 98.254(i), § 98.284(c), § 98.284(d), § 98.314(c), § 98.314(d), and § 98.314(f).
(19) ASTM D3238-95 (Reapproved 2005) Standard Test Method for Calculation of Carbon Distribution and Structural Group Analysis of Petroleum Oils by the n-d-M Method, IBR approved for § 98.74(c) and § 98.164(b).
(20) ASTM D3588-98 (Reapproved 2003) Standard Practice for Calculating Heat Value, Compressibility Factor, and Relative Density of Gaseous Fuels, IBR approved for § 98.254(e).
(21) ASTM D3682-01 (Reapproved 2006) Standard Test Method for Major and Minor Elements in Combustion Residues from Coal Utilization Processes, IBR approved for § 98.144(b).
(22) ASTM D4057-06 Standard Practice for Manual Sampling of Petroleum and Petroleum Products, IBR approved for § 98.164(b).
(23) ASTM D4177-95 (Reapproved 2005) Standard Practice for Automatic Sampling of Petroleum and Petroleum Products, IBR approved for § 98.164(b).
(24) ASTM D4809-06 Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method), IBR approved for § 98.254(e).
(25) ASTM D4891-89 (Reapproved 2006) Standard Test Method for Heating Value of Gases in Natural Gas Range by Stoichiometric Combustion, IBR approved for § 98.254(e) and § 98.324(d).
(26) ASTM D5291-02 (Reapproved 2007) Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants, IBR approved for § 98.74(c), § 98.164(b), § 98.244(b), and § 98.254(i).
(27) ASTM D5373-08 Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal, IBR approved for § 98.74(c), § 98.114(b), § 98.164(b), § 98.174(b), § 98.184(b), § 98.244(b), § 98.254(i), § 98.274(b), § 98.284(c), § 98.284(d), § 98.314(c), § 98.314(d), § 98.314(f), and § 98.334(b).
(28) [Reserved]
(29) ASTM D6060-96 (Reapproved 2001) Standard Practice for Sampling of Process Vents With a Portable Gas Chromatograph, IBR approved for § 98.244(b).
(30) ASTM D6348-03 Standard Test Method for Determination of Gaseous Compounds by Extractive Direct Interface Fourier Transform Infrared (FTIR) Spectroscopy, IBR approved for § 98.54(b), Table I-9 to subpart I of this part, § 98.224(b), and § 98.414(n).
(31) ASTM D6609-08 Standard Guide for Part-Stream Sampling of Coal, IBR approved for § 98.164(b).
(32) ASTM D6751-08 Standard Specification for Biodiesel Fuel Blend Stock (B100) for Middle Distillate Fuels, IBR approved for § 98.6.
(33) ASTM D6866-16 Standard Test Methods for Determining the Biobased Content of Solid, Liquid, and Gaseous Samples Using Radiocarbon Analysis, approved June 1, 2016, IBR approved for §§ 98.34(d) and (e), and 98.36(e).
(34) ASTM D6883-04 Standard Practice for Manual Sampling of Stationary Coal from Railroad Cars, Barges, Trucks, or Stockpiles, IBR approved for § 98.164(b).
(35) ASTM D7430-08ae1 Standard Practice for Mechanical Sampling of Coal, IBR approved for § 98.164(b).
(36) ASTM D7459-08 Standard Practice for Collection of Integrated Samples for the Speciation of Biomass (Biogenic) and Fossil-Derived Carbon Dioxide Emitted from Stationary Emissions Sources, IBR approved for § 98.34(d), § 98.34(e), and § 98.36(e).
(37) ASTM E359-00 (Reapproved 2005)e1 Standard Test Methods for Analysis of Soda Ash (Sodium Carbonate), IBR approved for § 98.294(a) and § 98.294(b).
(38) ASTM E1019-08 Standard Test Methods for Determination of Carbon, Sulfur, Nitrogen, and Oxygen in Steel, Iron, Nickel, and Cobalt Alloys by Various Combustion and Fusion Techniques, IBR approved for § 98.174(b).
(39) [Reserved]
(40) ASTM E1915-07a Standard Test Methods for Analysis of Metal Bearing Ores and Related Materials by Combustion Infrared-Absorption Spectrometry, IBR approved for § 98.174(b).
(41) ASTM E1941-04 Standard Test Method for Determination of Carbon in Refractory and Reactive Metals and Their Alloys, IBR approved for § 98.114(b), § 98.184(b), § 98.334(b).
(42) ASTM UOP539-97 Refinery Gas Analysis by Gas Chromatography, IBR approved for § 98.164(b), § 98.244(b), § 98.254(d), § 98.324(d), § 98.344(b), and § 98.354(g).
(43) ASTM D1941-91 (Reapproved 2007) Standard Test Method for Open Channel Flow Measurement of Water with the Parshall Flume, approved June 15, 2007, IBR approved for § 98.354(d).
(44) ASTM D5614-94 (Reapproved 2008) Standard Test Method for Open Channel Flow Measurement of Water with Broad-Crested Weirs, approved October 1, 2008, IBR approved for § 98.354(d).
(45) ASTM D6349-09 Standard Test Method for Determination of Major and Minor Elements in Coal, Coke, and Solid Residues from Combustion of Coal and Coke by Inductively Coupled Plasma—Atomic Emission Spectrometry, IBR approved for § 98.144(b).
(46) ASTM D2879-97 (Reapproved 2007) Standard Test Method for Vapor Pressure-Temperature Relationship and
(47) ASTM D7359-08 Standard Test Method for Total Fluorine, Chlorine and Sulfur in Aromatic Hydrocarbons and Their Mixtures by Oxidative Pyrohydrolytic Combustion followed by Ion Chromatography Detection (Combustion Ion Chromatography-CIC) (ASTM D7359), approved October 15, 2008, IBR approved for § 98.124(e)(2).
(48) ASTM D2593-93 (Reapproved 2009) Standard Test Method for Butadiene Purity and Hydrocarbon Impurities by Gas Chromatography, approved July 1, 2009, IBR approved for § 98.244(b)(4)(xi).
(49) ASTM D7633-10 Standard Test Method for Carbon Black—Carbon Content, approved May 15, 2010, IBR approved for § 98.244(b)(4)(xii).
(f) The following material is available for purchase from the Gas Processors Association (GPA), 6526 East 60th Street, Tulsa, Oklahoma 74143, (918) 493-3872,
(1) [Reserved]
(2) GPA 2261-00 Analysis for Natural Gas and Similar Gaseous Mixtures by Gas Chromatography, IBR approved for § 98.164(b), § 98.254(d), § 98.344(b), and § 98.354(g).
(g) The following material is available for purchase from the International Standards Organization (ISO), 1, ch. de la Voie-Creuse, Case postale 56, CH-1211 Geneva 20, Switzerland, + 41 22 749 01 11,
(1) ISO 3170: Petroleum liquids—Manual sampling—Third Edition 2004-02-01, IBR approved for § 98.164(b).
(2) ISO 3171: Petroleum Liquids—Automatic pipeline sampling—Second Edition 1988-12-01, IBR approved for § 98.164(b).
(3) [Reserved]
(4) ISO/CSAPR 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/CSAPR 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,
(1) CO
(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,
(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,
(1) T650 om-05 Solids Content of Black Liquor, TAPPI, incorporation by reference (IBR) approved for § 98.276(c) and § 98.277(d).
(2) T684 om-06 Gross Heating Value of Black Liquor, TAPPI, incorporation by reference (IBR) approved for § 98.274(b).
(k) The following material is available for purchase from Standard Methods, at
(1) Method 2540G Total, Fixed, and Volatile Solids in Solid and Semisolid Samples, IBR approved for § 98.464(b).
(2) [Reserved]
(l) The following material is available from the U.S. Department of
(1) PH16-V-1, Coal Mine Safety and Health General Inspection Procedures Handbook, June 2016, IBR approved for § 98.324(b).
(2) [Reserved]
(m) The following material is available from the U.S. Environmental Protection Agency, 1200 Pennsylvania Avenue, NW., Washington, DC 20460, (202) 272-0167,
(1) NPDES Compliance Inspection Manual, Chapter 5, Sampling, EPA 305-X-04-001, July 2004,
(2) U.S. EPA NPDES Permit Writers' Manual, Section 7.1.3, Sample Collection Methods, EPA 833-B-96-003, December 1996,
(3) Protocol for Measuring Destruction or Removal Efficiency (DRE) of Fluorinated Greenhouse Gas Abatement Equipment in Electronics Manufacturing, Version 1, EPA-430-R-10-003, March 2010 (EPA 430-R-10-003),
(4) Emissions Inventory Improvement Program, Volume II: Chapter 16, Methods for Estimating Air Emissions from Chemical Manufacturing Facilities, August 2007, Final,
(5) Protocol for Equipment Leak Emission Estimates, EPA-453/R-95-017, November 1995 (EPA-453/R-95-017),
(6) Tracer Gas Protocol for the Determination of Volumetric Flow Rate Through the Ring Pipe of the Xact Multi-Metals Monitoring System, also known as Other Test Method 24 (Tracer Gas Protocol), Eli Lilly and Company Tippecanoe Laboratories, September 2006,
(7) Approved Alternative Method 012: An Alternate Procedure for Stack Gas Volumetric Flow Rate Determination (Tracer Gas) (ALT-012), U.S. Environmental Protection Agency Emission Measurement Center, May 23, 1994,
(8) Protocol for Measurement of Tetrafluoromethane (CF
(9) AP 42, Section 5.2, Transportation and Marketing of Petroleum Liquids, July 2008, (AP 42, Section 5.2);
(10) Method 9060A, Total Organic Carbon, Revision 1, November 2004 (Method 9060A),
(11) Method 8031, Acrylonitrile By Gas Chromatography, Revision 0, September 1994 (Method 8031),
(12) Method 8021B, Aromatic and Halogenated Volatiles By Gas Chromatography Using Photoionization and/or Electrolytic Conductivity Detectors, Revision 2, December 1996 (Method 8021B).
(13) Method 8015C, Nonhalogenated Organics By Gas Chromatography, Revision 3, February 2007 (Method 8015C).
(14) AP 42, Section 7.1, Organic Liquid Storage Tanks, November 2006 (AP 42, Section 7.1),
(n)-(o) [Reserved]
(p) The following material is available for purchase from the American Association of Petroleum Geologists, 1444 South Boulder Avenue, Tulsa, Oklahoma 74119, (918) 584-2555,
(1) Geologic Note: AAPG-CSD Geologic Provinces Code Map: AAPG Bulletin, Prepared by Richard F. Meyer, Laure G. Wallace, and Fred J. Wagner, Jr., Volume 75, Number 10 (October 1991), pages 1644-1651, IBR approved for § 98.238.
(2) Alaska Geological Province Boundary Map, Compiled by the American Association of Petroleum Geologists Committee on Statistics of Drilling in cooperation with the USGS, 1978, IBR approved for § 98.238.
(q) The following material is available from the Energy Information Administration (EIA), 1000 Independence Ave., SW., Washington, DC 20585, (202) 586-8800,
(1) Oil and Gas Field Code Master List 2008, DOE/EIA0370(08), January 2009, IBR approved for § 98.238.
(2) [Reserved]
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.
All requests, notifications, and communications to the Administrator pursuant to this part must be submitted electronically and in a format as specified by the Administrator. For example, any requests, notifications and communications that can be submitted through the electronic GHG reporting tool, must be submitted through that tool. If not specified, requests, notifications or communications shall be submitted to the following address:
(a) For U.S. mail. Director, Climate Change Division, 1200 Pennsylvania Ave., NW., Mail Code: 6207J, Washington, DC 20460.
(b) For package deliveries. Director, Climate Change Division, 1310 L St, NW., Washington, DC 20005.
(a) Stationary fuel combustion sources are devices that combust solid, liquid, or gaseous fuel, generally for the purposes of producing electricity, generating steam, or providing useful heat or energy for industrial, commercial, or institutional use, or reducing the volume of waste by removing combustible matter. Stationary fuel combustion sources include, but are not limited to, boilers, simple and combined-cycle combustion turbines, engines, incinerators, and process heaters.
(b) This source category does not include:
(1) Portable equipment, as defined in § 98.6.
(2) Emergency generators and emergency equipment, as defined in § 98.6.
(3) Irrigation pumps at agricultural operations.
(4) Flares, unless otherwise required by provisions of another subpart of this part to use methodologies in this subpart.
(5) Electricity generating units that are subject to subpart D of this part.
(c) For a unit that combusts hazardous waste (as defined in § 261.3 of this chapter), reporting of GHG emissions is not required unless either of the following conditions apply:
(1) Continuous emission monitors (CEMS) are used to quantify CO
(2) Any fuel listed in Table C-1 of this subpart is also combusted in the unit. In this case, report GHG emissions from combustion of all fuels listed in Table C-1 of this subpart.
(d) You are not required to report GHG emissions from pilot lights. A pilot light is a small auxiliary flame that ignites the burner of a combustion device when the control valve opens.
You must report GHG emissions under this subpart if your facility contains one or more stationary fuel combustion sources and the facility meets the applicability requirements of either §§ 98.2(a)(1), 98.2(a)(2), or 98.2(a)(3).
You must report CO
You must calculate CO
(a)
(1)
(i) Use Equation C-1 except when natural gas billing records are used to quantify fuel usage and gas consumption is expressed in units of therms or million Btu. In that case, use Equation C-1a or C-1b, as applicable.
(ii) If natural gas consumption is obtained from billing records and fuel usage is expressed in therms, use Equation C-1a.
(iii) If natural gas consumption is obtained from billing records and fuel usage is expressed in mmBtu, use Equation C-1b.
(2)
(i) Equation C-2a of this section applies to any type of fuel listed in Table C-1 of the subpart, except for municipal solid waste (MSW). For MSW combustion, use Equation C-2c of this section.
(ii) The minimum required sampling frequency for determining the annual average HHV (
(A) If the results of fuel sampling are received monthly or more frequently, then for each unit with a maximum rated heat input capacity greater than or equal to 100 mmBtu/hr (or for a group of units that includes at least one unit of that size), the annual average HHV shall be calculated using Equation C-2b of this section. If multiple HHV determinations are made in any month, average the values for the month arithmetically.
(B) If the results of fuel sampling are received less frequently than monthly, or, for a unit with a maximum rated heat input capacity less than 100 mmBtu/hr (or a group of such units) regardless of the HHV sampling frequency, the annual average HHV shall either be computed according to paragraph (a)(2)(ii)(A) of this section or as
(iii) For units that combust municipal solid waste (MSW) and that produce steam, use Equation C-2c of this section. Equation C-2c of this section may also be used for any other solid fuel listed in Table C-1 of this subpart provided that steam is generated by the unit.
(3)
(i) For a solid fuel, use Equation C-3 of this section.
(ii) For a liquid fuel, use Equation C-4 of this section.
(iii) For a gaseous fuel, use Equation C-5 of this section.
(iv) Fuel flow meters that measure mass flow rates may be used for liquid or gaseous fuels, provided that the fuel density is used to convert the readings to volumetric flow rates. The density shall be measured at the same frequency as the carbon content. You must measure the density using one of the following appropriate methods. You may use a method published by a consensus-based standards organization, if such a method exists, or you may use industry standard practice. Consensus-based standards organizations include, but are not limited to, the following: ASTM International (100 Barr Harbor Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959, (800) 262-1373,
(v) The following default density values may be used for fuel oil, in lieu of using the methods in paragraph (a)(3)(iv) of this section: 6.8 lb/gal for No. 1 oil; 7.2 lb/gal for No. 2 oil; 8.1 lb/gal for No. 6 oil.
(4)
(i) This methodology requires a CO
(ii) When the CO
(iii) If the CO
(iv) An oxygen (O
(v) Each hourly CO
(vi) The hourly CO
(vii) If both biomass and fossil fuel are combusted during the year, determine and report the biogenic CO
(viii) If a portion of the flue gases generated by a unit subject to Tier 4 (
(A) At least once a year, use EPA Methods 2 and 3A, and (if necessary) Method 4 in appendices A-2 and A-3 to part 60 of this chapter to perform emissions testing at a set point that best represents normal, stable process operating conditions. A minimum of three one-hour Method 3A tests are required, to determine the CO
(B) Calculate a CO
(C) The results of each annual stack test shall be used in the GHG emissions calculations for the year of the test.
(D) If, for the majority of the operating hours during the year, the diverted stream is withdrawn at a steady rate at or near the tested set point (as evidenced by fan and damper settings and/or other parameters), you may use the calculated CO
(E) If the flow rate of the diverted stream varies significantly throughout the year, except as provided below, repeat the stack test and emission rate calculation procedures described in paragraphs (c)(4)(viii)(A) and (c)(4)(viii)(B) of this section at a minimum of two more set points across the range of typical operating conditions to develop a correlation between CO
(F) Calculate the annual CO
(G) Finally, add the CO
(H) The exact method and procedures used to estimate the CO
(5)
(i) For a unit that combusts only natural gas and/or fuel oil, is not subject to subpart D of this part, monitors and reports heat input data year-round according to appendix D to part 75 of this chapter, but is not required by the applicable part 75 program to report CO
(A) Use the hourly heat input data from appendix D to part 75 of this chapter, together with Equation G-4 in appendix G to part 75 of this chapter to determine the hourly CO
(B) Use Equations F-12 and F-13 in appendix F to part 75 of this chapter to calculate the quarterly and cumulative annual CO
(C) Divide the cumulative annual CO
(ii) For a unit that combusts only natural gas and/or fuel oil, is not subject to subpart D of this part, monitors and reports heat input data year-round according to § 75.19 of this chapter but is not required by the applicable part 75 program to report CO
(A) Calculate the hourly CO
(B) Sum the hourly CO
(C) Divide the cumulative annual CO
(iii) For a unit that is not subject to subpart D of this part, uses flow rate and CO
(A) Use Equation F-11 or F-2 (as applicable) in appendix F to part 75 of this chapter to calculate the hourly CO
(B) Use Equations F-12 and F-13 in appendix F to part 75 of this chapter to calculate the quarterly and cumulative annual CO
(C) Divide the cumulative annual CO
(iv) For units that qualify to use the alternative CO
(b)
(1) The Tier 1 Calculation Methodology:
(i) May be used for any fuel listed in Table C-1 of this subpart that is combusted in a unit with a maximum rated heat input capacity of 250 mmBtu/hr or less.
(ii) May be used for MSW in a unit of any size that does not produce steam, if the use of Tier 4 is not required.
(iii) May be used for solid, gaseous, or liquid biomass fuels in a unit of any size provided that the fuel is listed in Table C-1 of this subpart.
(iv) May not be used if you routinely perform fuel sampling and analysis for the fuel high heat value (HHV) or routinely receive the results of HHV sampling and analysis from the fuel supplier at the minimum frequency specified in § 98.34(a), or at a greater frequency. In such cases, Tier 2 shall be used. This restriction does not apply to paragraphs (b)(1)(ii), (b)(1)(v), (b)(1)(vi), and (b)(1)(vii) of this section.
(v) May be used for natural gas combustion in a unit of any size, in cases where the annual natural gas consumption is obtained from fuel billing records in units of therms or mmBtu.
(vi) May be used for MSW combustion in a small, batch incinerator that burns no more than 1,000 tons per year of MSW.
(vii) May be used for the combustion of MSW and/or tires in a unit, provided that no more than 10 percent of the unit's annual heat input is derived from those fuels, combined. Notwithstanding this requirement, if a unit combusts both MSW and tires and the reporter elects not to separately calculate and report biogenic CO
(viii) May be used for the combustion of a fuel listed in Table C-1 if the fuel is combusted in a unit with a maximum rated heat input capacity greater than 250 mmBtu/hr (or, pursuant to § 98.36(c)(3), in a group of units served by a common supply pipe, having at least one unit with a maximum rated heat input capacity greater than 250 mmBtu/hr), provided that both of the following conditions apply:
(A) The use of Tier 4 is not required.
(B) The fuel provides less than 10 percent of the annual heat input to the unit, or if § 98.36(c)(3) applies, to the group of units served by a common supply pipe.
(2) The Tier 2 Calculation Methodology:
(i) May be used for the combustion of any type of fuel in a unit with a maximum rated heat input capacity of 250 mmBtu/hr or less provided that the fuel is listed in Table C-1 of this subpart.
(ii) May be used in a unit with a maximum rated heat input capacity greater than 250 mmBtu/hr for the combustion of natural gas and/or distillate fuel oil.
(iii) May be used for MSW in a unit of any size that produces steam, if the use of Tier 4 is not required.
(3) The Tier 3 Calculation Methodology:
(i) May be used for a unit of any size that combusts any type of fuel listed in Table C-1 of this subpart (except for MSW), unless the use of Tier 4 is required.
(ii) Shall be used for a unit with a maximum rated heat input capacity greater than 250 mmBtu/hr that combusts any type of fuel listed in Table C-1 of this subpart (except MSW), unless either of the following conditions apply:
(A) The use of Tier 1 or 2 is permitted, as described in paragraphs (b)(1)(iii), (b)(1)(v), (b)(1)(viii), and (b)(2)(ii) of this section.
(B) The use of Tier 4 is required.
(iii) Shall be used for a fuel not listed in Table C-1 of this subpart if the fuel is combusted in a unit with a maximum rated heat input capacity greater than 250 mmBtu/hr (or, pursuant to § 98.36(c)(3), in a group of units served by a common supply pipe, having at least one unit with a maximum rated heat input capacity greater than 250 mmBtu/hr), provided that both of the following conditions apply:
(A) The use of Tier 4 is not required.
(B) The fuel provides 10% or more of the annual heat input to the unit or, if
(iv) Shall be used when specified in another applicable subpart of this part, regardless of unit size.
(4) The Tier 4 Calculation Methodology:
(i) May be used for a unit of any size, combusting any type of fuel. Tier 4 may also be used for any group of stationary fuel combustion units, process units, or manufacturing units that share a common stack or duct.
(ii) Shall be used if the unit meets all six of the conditions specified in paragraphs (b)(4)(ii)(A) through (b)(4)(ii)(F) of this section:
(A) The unit has a maximum rated heat input capacity greater than 250 mmBtu/hr, or if the unit combusts municipal solid waste and has a maximum rated input capacity greater than 600 tons per day of MSW.
(B) The unit combusts solid fossil fuel or MSW as the primary fuel.
(C) The unit has operated for more than 1,000 hours in any calendar year since 2005.
(D) The unit has installed CEMS that are required either by an applicable Federal or State regulation or the unit's operating permit.
(E) The installed CEMS include a gas monitor of any kind or a stack gas volumetric flow rate monitor, or both and the monitors have been certified, either in accordance with the requirements of part 75 of this chapter, part 60 of this chapter, or an applicable State continuous monitoring program.
(F) The installed gas or stack gas volumetric flow rate monitors are required, either by an applicable Federal or State regulation or by the unit's operating permit, to undergo periodic quality assurance testing in accordance with either appendix B to part 75 of this chapter, appendix F to part 60 of this chapter, or an applicable State continuous monitoring program.
(iii) Shall be used for a unit with a maximum rated heat input capacity of 250 mmBtu/hr or less and for a unit that combusts municipal solid waste with a maximum rated input capacity of 600 tons of MSW per day or less, if the unit meets all of the following three conditions:
(A) The unit has both a stack gas volumetric flow rate monitor and a CO
(B) The unit meets the conditions specified in paragraphs (b)(4)(ii)(B) through (b)(4)(ii)(D) of this section.
(C) The CO
(iv) May apply to common stack or duct configurations where:
(A) The combined effluent gas streams from two or more stationary fuel combustion units are vented through a monitored common stack or duct. In this case, Tier 4 shall be used if all of the conditions in paragraph (b)(4)(iv)(A)(1) of this section or if the conditions in paragraph (b)(4)(iv)(A)(2) of this section are met.
(
(
(B) The combined effluent gas streams from a process or manufacturing unit and a stationary fuel combustion unit are vented through a monitored common stack or duct. In this case, Tier 4 shall be used if the combustion unit and the monitors installed at the common stack or duct meet the applicability criteria specified in paragraph (b)(4)(iv)(A)(
(C) The combined effluent gas streams from two or more manufacturing or process units are vented through a common stack or duct. In this case, if any of the units is required by an applicable subpart of this part to use Tier 4, the CO
(5) The Tier 4 Calculation Methodology shall be used:
(i) Starting on January 1, 2010, for a unit that is required to report CO
(ii) No later than January 1, 2011, for a unit that is required to report CO
(A) The certification tests are passed in sequence, with no test failures.
(B) No unscheduled maintenance or repair of the CEMS is performed during the certification test period.
(iii) No later than 180 days following the date on which a change is made that triggers Tier 4 applicability under paragraph (b)(4)(ii) or (b)(4)(iii) of this section (
(6) You may elect to use any applicable higher tier for one or more of the fuels combusted in a unit. For example, if a 100 mmBtu/hr unit combusts natural gas and distillate fuel oil, you may elect to use Tier 1 for natural gas and Tier 3 for the fuel oil, even though Tier 1 could have been used for both fuels. However, for units that use either the Tier 4 or the alternative calculation methodology specified in paragraph (a)(5)(iii) of this section, CO
(c)
(1) Use Equation C-8 of this section to estimate CH
(i) Use Equation C-8a to calculate CH
(ii) Use Equation C-8b to calculate CH
(2) Use Equation C-9a of this section to estimate CH
(3) Use Equation C-9b of this section to estimate CH
(4) Use Equation C-10 of this section for: units subject to subpart D of this part; units that qualify for and elect to use the alternative CO
(i) If only one type of fuel listed in Table C-2 of this subpart is combusted during the reporting year, substitute the cumulative annual heat input from combustion of the fuel into Equation C-10 of this section to calculate the annual CH
(ii) If more than one type of fuel listed in Table C-2 of this subpart is combusted during the reporting year, use Equation C-10 of this section separately for each type of fuel, except as provided in paragraph (c)(4)(ii)(B) of this section. Determine the appropriate values of (HI)
(A) For units in the Acid Rain Program and other units that report heat input data to EPA year-round according to part 75 of this chapter, obtain (HI)
(B) For a unit that uses CEMS to monitor hourly heat input according to part 75 of this chapter, the value of (HI)
(C) For Tier 4 units, use the best available information (
(D) Units in the Acid Rain Program and other units that report heat input data to EPA year-round according to part 75 of this chapter may use the best available information described in paragraph (c)(4)(ii)(C) of this section, to estimate (HI)
(5) When multiple fuels are combusted during the reporting year, sum the fuel-specific results from Equations C-8, C-8a, C-8b, C-9a, C-9b, or C-10 of this section (as applicable) to obtain the total annual CH
(6) Calculate the annual CH
(i) If the mass or volume of each component fuel in the blend is measured before the fuels are mixed and combusted, calculate and report CH
(ii) If the mass or volume of each component fuel in the blend is not measured before the fuels are mixed and combusted, a reasonable estimate of the percentage composition of the
(A) Multiply (% Fuel)
(B) Multiply the result from paragraph (c)(6)(ii)(A) of this section by the HHV of the fuel (default value or, if available, the measured annual average value), to obtain an estimate of the annual heat input from component “i”;
(C) Calculate the annual CH
(D) Sum the annual CH
(d)
(2) The total annual CO
(e)
(1) You may use Equation C-1 of this subpart to calculate the annual CO
(i) Company records.
(ii) The procedures in paragraph (e)(4) of this section.
(iii) The best available information for premixed fuels that contain biomass and fossil fuels (
(2) You may use the procedures of this paragraph if the following three conditions are met: First, a CO
(i) For each operating hour, use Equation C-12 of this section to determine the volume of CO
(ii) Sum all of the hourly V
(iii) Calculate the annual volume of CO
(iv) Subtract V
(v) Calculate the biogenic percentage of the annual CO
(vi) Calculate the annual biogenic CO
(A) Under paragraph (a)(4)(vi) of this section, for units using the Tier 4 Calculation Methodology.
(B) Under paragraph (a)(5)(iii)(B) of this section, for units using the alternative calculation methodology specified in paragraph (a)(5)(iii).
(C) From the electronic data report required under § 75.64 of this chapter, for units in the Acid Rain Program and other units using CEMS to monitor and report CO
(3) You must use the procedures in paragraphs (e)(3)(i) through (e)(3)(iii) of this section to determine the annual biogenic CO
(i) Use an applicable CO
(ii) Determine the relative proportions of biogenic and non-biogenic CO
(iii) Determine the annual biogenic CO
(iv) If the combustion of MSW and/or tires provides no more than 10 percent of the annual heat input to a unit, or if a small, batch incinerator combusts no more than 1,000 tons per year of MSW, you may estimate the annual biogenic CO
(A) Calculate the total annual CO
(B) Multiply the result from paragraph (e)(3)(iv)(A) of this section by the appropriate default factor to determine the annual biogenic CO
(4) If Equation C-1 or Equation C-2a of this section is selected to calculate the annual biogenic mass emissions for wood, wood waste, or other solid biomass-derived fuel, Equation C-15 of this section may be used to quantify biogenic fuel consumption, provided that all of the required input parameters are accurately quantified. Similar equations and calculation methodologies based on steam generation and boiler efficiency may be used, provided that they are documented in the GHG Monitoring Plan required by § 98.3(g)(5).
(5) For units subject to subpart D of this part and for units that use the methods in part 75 of this chapter to quantify CO
The CO
(a) For the Tier 2 Calculation Methodology:
(1) All fuel samples shall be taken at a location in the fuel handling system that provides a sample representative of the fuel combusted. The fuel sampling and analysis may be performed by either the owner or operator or the supplier of the fuel.
(2) The minimum required frequency of the HHV sampling and analysis for each type of fuel or fuel mixture (blend) is specified in this paragraph. When the specified frequency for a particular fuel or blend is based on a specified time period (
(i) For natural gas, semiannual sampling and analysis is required (
(ii) For coal and fuel oil, and for any other solid or liquid fuel that is delivered in lots, analysis of at least one representative sample from each fuel
(A) For coal, the “type” of fuel means the rank of the coal (
(B) The owner or operator shall document in the monitoring plan under § 98.3(g)(5) how the monthly sampling of each type of fuel is performed.
(iii) For liquid fuels other than fuel oil, and for gaseous fuels other than natural gas (including biogas), sampling and analysis is required at least once per calendar quarter. To the extent practicable, consecutive quarterly samples shall be taken at least 30 days apart.
(iv) For other solid fuels (except MSW), weekly sampling is required to obtain composite samples, which are then analyzed monthly.
(v) For fuel blends that are received already mixed, or that are mixed on-site without measuring the exact amount of each component, as described in paragraph (a)(3)(ii) of this section, determine the HHV of the blend as follows. For blends of solid fuels (except MSW), weekly sampling is required to obtain composite samples, which are analyzed monthly. For blends of liquid or gaseous fuels, sampling and analysis is required at least once per calendar quarter. More frequent sampling is recommended if the composition of the blend varies significantly during the year.
(3)
(i) If the fuels to be blended are received separately, and if the quantity (mass or volume) of each fuel is measured before the fuels are mixed and combusted, then, for each component of the blend, calculate the CO
(ii) If the fuel is received as a blend (
(A) Consider the blend to be the “fuel type,” measure its HHV at the frequency prescribed in paragraph (a)(2)(v) of this section, and determine the annual average HHV value for the blend according to § 98.33(a)(2)(ii).
(B) Calculate a heat-weighted CO
(C) Substitute into Equation C-2a of this subpart, the annual average HHV for the blend (from paragraph (a)(3)(ii)(A) of this section) and the calculated value of (EF)
(iii) Note that for the case described in paragraph (a)(3)(ii) of this section, if measured HHV values for the individual fuels in the blend or for the blend itself are not routinely received at the minimum frequency prescribed in paragraph (a)(2) of this section (or at a greater frequency), and if the unit qualifies to use Tier 1, calculate (HHV)
(iv) If the fuel blend described in paragraph (a)(3)(ii) of this section consists of a mixture of fuel(s) listed in Table C-1 of this subpart and one or more fuels not listed in Table C-1, calculate CO
(A) In Equation C-17, apply the term (Fuel)
(B) In Equation C-1, the term “Fuel” will be equal to the total mass or volume of the blended fuel combusted during the year multiplied by the sum of the mass or volume percentages of the Table C-1 fuels in the blend. For the example in paragraph (a)(3)(iv)(A) of this section, “Fuel” = (Annual volume of the blend combusted)(0.80).
(4) If, for a particular type of fuel, HHV sampling and analysis is performed more often than the minimum frequency specified in paragraph (a)(2) of this section, the results of all valid fuel analyses shall be used in the GHG emission calculations.
(5) If, for a particular type of fuel, valid HHV values are obtained at less than the minimum frequency specifed in paragraph (a)(2) of this section, appropriate substitute data values shall be used in the emissions calculations, in accordance with missing data procedures of § 98.35.
(6) You must use one of the following appropriate fuel sampling and analysis methods. The HHV may be calculated using chromatographic analysis together with standard heating values of the fuel constituents, provided that the gas chromatograph is operated, maintained, and calibrated according to the manufacturer's instructions. Alternatively, you may use a method published by a consensus-based standards organization if such a method exists, or you may use industry standard practice to determine the high heat values. Consensus-based standards organizations include, but are not limited to, the following: ASTM International (100 Barr Harbor Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959, (800) 262-1373,
(b) For the Tier 3 Calculation Methodology:
(1) You must calibrate each oil and gas flow meter according to § 98.3(i) and the provisions of this paragraph (b)(1).
(i) Perform calibrations using any of the test methods and procedures in this paragraph (b)(1)(i). The method(s) used shall be documented in the Monitoring Plan required under § 98.3(g)(5).
(A) You may use the calibration procedures specified by the flow meter manufacturer.
(B) You may use an appropriate flow meter calibration method published by a consensus-based standards organization, if such a method exists. Consensus-based standards organizations
(C) You may use an industry-accepted practice.
(ii) In addition to the initial calibration required by § 98.3(i), recalibrate each fuel flow meter (except as otherwise provided in paragraph (b)(1)(iii) of this section) according to one of the following. You may recalibrate annually, at the minimum frequency specified by the manufacturer, or at the interval specified by industry standard practice.
(iii) Fuel billing meters are exempted from the initial and ongoing calibration requirements of this paragraph and from the Monitoring Plan and recordkeeping requirements of §§ 98.3(g)(5)(i)(C), (g)(6), and (g)(7), provided that the fuel supplier and the unit combusting the fuel do not have any common owners and are not owned by subsidiaries or affiliates of the same company. Meters used exclusively to measure the flow rates of fuels that are only used for unit startup are also exempted from the initial and ongoing calibration requirements of this paragraph.
(iv) For the initial calibration of an orifice, nozzle, or venturi meter; in-situ calibration of the transmitters is sufficient. A primary element inspection (PEI) shall be performed at least once every three years.
(v) For the continuously-operating units and processes described in § 98.3(i)(6), the required flow meter recalibrations and, if necessary, the PEIs may be postponed until the next scheduled maintenance outage.
(vi) If a mixture of liquid or gaseous fuels is transported by a common pipe, you may either separately meter each of the fuels prior to mixing, using flow meters calibrated according to § 98.3(i), or consider the fuel mixture to be the “fuel type” and meter the mixed fuel, using a flow meter calibrated according to § 98.3(i).
(2) Oil tank drop measurements (if used to determine liquid fuel use volume) shall be performed according to any an appropriate method published by a consensus-based standards organization (e.g., the American Petroleum Institute).
(3) The carbon content and, if applicable, molecular weight of the fuels shall be determined according to the procedures in this paragraph (b)(3).
(i) All fuel samples shall be taken at a location in the fuel handling system that provides a sample representative of the fuel combusted. The fuel sampling and analysis may be performed by either the owner or operator or by the supplier of the fuel.
(ii) For each type of fuel, the minimum required frequency for collecting and analyzing samples for carbon content and (if applicable) molecular weight is specified in this paragraph. When the sampling frequency is based on a specified time period (
(A) For natural gas, semiannual sampling and analysis is required (
(B) For coal and fuel oil and for any other solid or liquid fuel that is delivered in lots, analysis of at least one representative sample from each fuel lot is required. For fuel oil, as an alternative to sampling each fuel lot, a sample may be taken upon each addition of oil to the storage tank. Flow proportional sampling, continuous drip sampling, or daily manual oil sampling
(
(
(C) For liquid fuels other than fuel oil and for biogas, sampling and analysis is required at least once per calendar quarter. To the extent practicable, consecutive quarterly samples shall be taken at least 30 days apart.
(D) For other solid fuels (except MSW), weekly sampling is required to obtain composite samples, which are then analyzed monthly.
(E) For gaseous fuels other than natural gas and biogas (
(F) For mixtures (blends) of solid fuels, weekly sampling is required to obtain composite samples, which are analyzed monthly. For blends of liquid fuels, and for gas mixtures consisting only of natural gas and biogas, sampling and analysis is required at least once per calendar quarter. For gas mixtures that contain gases other than natural gas (including biogas), daily sampling and analysis to determine the carbon content and molecular weight of the fuel is required if continuous, on-line equipment is in place to make these measurements. Otherwise, weekly sampling and analysis shall be performed.
(iii) If, for a particular type of fuel, sampling and analysis for carbon content and molecular weight is performed more often than the minimum frequency specified in paragraph (b)(3) of this section, the results of all valid fuel analyses shall be used in the GHG emission calculations.
(iv) If, for a particular type of fuel, sampling and analysis for carbon content and molecular weight is performed at less than the minimum frequency specified in paragraph (b)(3) of this section, appropriate substitute data values shall be used in the emissions calculations, in accordance with the missing data procedures of § 98.35.
(v) To calculate the CO
(A) Apply Equation C-3, C-4 or C-5 of this subpart (as applicable) to each component of the blend, if the mass or volume, the carbon content, and (if applicable), the molecular weight of each component are accurately measured prior to blending; or
(B) Consider the blend to be the “fuel type.” Then, at the frequency specified in paragraph (b)(3)(ii)(F) of this section, measure the carbon content and,
(4) You must use one of the following appropriate fuel sampling and analysis methods. The results of chromatographic analysis of the fuel may be used, provided that the gas chromatograph is operated, maintained, and calibrated according to the manufacturer's instructions. Alternatively, you may use a method published by a consensus-based standards organization if such a method exists, or you may use industry standard practice to determine the carbon content and molecular weight (for gaseous fuel) of the fuel. Consensus-based standards organizations include, but are not limited to, the following: ASTM International (100 Barr Harbor Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959, (800) 262-1373,
(c) For the Tier 4 Calculation Methodology, the CO
(1) For initial certification, you may use any one of the following three procedures in this paragraph.
(i) §§ 75.20(c)(2), (c)(4), and (c)(5) through (c)(7) of this chapter and appendix A to part 75 of this chapter.
(ii) The calibration drift test and relative accuracy test audit (RATA) procedures of Performance Specification 3 in appendix B to part 60 of this chapter (for the CO
(iii) The provisions of an applicable State continuous monitoring program.
(2) If an O
(3) For ongoing quality assurance, follow the applicable procedures in either appendix B to part 75 of this chapter, appendix F to part 60 of this chapter, or an applicable State continuous monitoring program. If appendix F to part 60 of this chapter is selected for on-going quality assurance, perform daily calibration drift assessments for both the CO
(4) For the purposes of this part, the stack gas volumetric flow rate monitor RATAs required by appendix B to part 75 of this chapter and the annual RATAs of the CERMS required by appendix F to part 60 of this chapter need only be done at one operating level, representing normal load or normal process operating conditions, both for initial certification and for ongoing quality assurance.
(5) If, for any source operating hour, quality assured data are not obtained with a CO
(6) For certain applications where combined process emissions and combustion emissions are measured, the CO
(7) Hourly average data from the CEMS shall be validated in a manner consistent with one of the following: §§ 60.13(h)(2)(i) through (h)(2)(vi) of this chapter; § 75.10(d)(1) of this chapter; or the hourly data validation requirements of an applicable State CEM regulation.
(d) Except as otherwise provided in § 98.33(b)(1)(vi) and (vii), when municipal solid waste (MSW) is either the primary fuel combusted in a unit or the only fuel with a biogenic component combusted in the unit, determine the biogenic portion of the CO
(e) For other units that combust combinations of biomass fuel(s) (or heterogeneous fuels that have a biomass component,
(f) The records required under § 98.3(g)(2)(i) shall include an explanation of how the following parameters are determined from company records
(1) Fuel consumption, when the Tier 1 and Tier 2 Calculation Methodologies are used, including cases where § 98.36(c)(4) applies.
(2) Fuel consumption, when solid fuel is combusted and the Tier 3 Calculation Methodology is used.
(3) Fossil fuel consumption when § 98.33(e)(2) applies to a unit that uses CEMS to quantify CO
(4) Sorbent usage, when § 98.33(d) applies.
(5) Quantity of steam generated by a unit when § 98.33(a)(2)(iii) applies.
(6) Biogenic fuel consumption and high heating value, as applicable, under §§ 98.33(e)(5) and (e)(6).
(7) Fuel usage for CH
(8) Mass of biomass combusted, for premixed fuels that contain biomass and fossil fuels under § 98.33(e)(1)(iii).
Whenever a quality-assured value of a required parameter is unavailable (e.g., if a CEMS malfunctions during unit operation or if a required fuel sample is not taken), a substitute data value for the missing parameter shall be used in the calculations.
(a) For all units subject to the requirements of the Acid Rain Program, and all other stationary combustion units subject to the requirements of this part that monitor and report emissions and heat input data year-round in accordance with part 75 of this chapter, the missing data substitution procedures in part 75 of this chapter shall be followed for CO
(b) For units that use the Tier 1, Tier 2, Tier 3, and Tier 4 Calculation Methodologies, perform missing data substitution as follows for each parameter:
(1) For each missing value of the high heating value, carbon content, or molecular weight of the fuel, substitute the arithmetic average of the quality-assured values of that parameter immediately preceding and immediately following the missing data incident. If the “after” value has not been obtained by the time that the GHG emissions report is due, you may use the “before” value for missing data substitution or the best available estimate of the parameter, based on all available process data (e.g., electrical load, steam production, operating hours). If, for a particular parameter, no quality-assured data 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 missing records of CO
(a) In addition to the facility-level information required under § 98.3, the annual GHG emissions report shall contain the unit-level or process-level data specified in paragraphs (b) through (f) of this section, as applicable, for each stationary fuel combustion source (e.g., individual unit, aggregation of units, common pipe, or common stack) except as otherwise provided in this paragraph (a). For the data specified in paragraphs (b)(9)(iii), (c)(2)(ix), (e)(2)(i), (e)(2)(ii)(A), (e)(2)(ii)(C), (e)(2)(ii)(D), (e)(2)(iv)(A), (e)(2)(iv)(C), (e)(2)(iv)(F), and (e)(2)(ix)(D) through (F) of this section, the owner or operator of a stationary fuel combustion source that does not meet the criteria specified in paragraph (f) of this section may elect either to report the data specified in this sentence in the annual report or to use verification software according to § 98.5(b) in lieu of reporting these data. If you elect to use this verification software, you must use the verification software according to § 98.5(b) for all of
(b)
(1) The unit ID number.
(2) A code representing the type of unit.
(3) Maximum rated heat input capacity of the unit, in mmBtu/hr.
(4) Each type of fuel combusted in the unit during the report year.
(5) The methodology (
(6) The methodology start date, for each fuel type.
(7) The methodology end date, for each fuel type.
(8) For a unit that uses Tiers 1, 2, or 3:
(i) The annual CO
(ii) Metric tons of biogenic CO
(9) For a unit that uses Tier 4:
(i) If the total annual CO
(ii) Report the total annual CO
(iii) An estimate of the heat input from each type of fuel listed in Table C-2 of this subpart that was combusted in the unit during the report year.
(iv) The annual CH
(10) Annual CO
(11) If applicable, the plant code (as defined in § 98.6).
(c)
(1)
(i) Group ID number, beginning with the prefix “GP”.
(ii) [Reserved]
(iii) Cumulative maximum rated heat input capacity of the group (mmBtu/hr). The cumulative maximum rated heat input capacity shall be determined as the sum of the maximum rated heat input capacities for all units in the group, excluding units less than 10 (mmBtu/hr).
(iv) The highest maximum rated heat input capacity of any unit in the group (mmBtu/hr).
(v) Each type of fuel combusted in the group of units during the reporting year.
(vi) Annual CO
(vii) The methodology (
(viii) The methodology start date, for each fuel type.
(ix) The methodology end date, for each fuel type.
(x) The calculated CO
(xi) If applicable, the plant code (as defined in § 98.6).
(2)
(i) Common stack or duct identification number, beginning with the prefix “CS”.
(ii) Number of units sharing the common stack or duct. Report “1” when the flue gas flowing through the common stack or duct includes combustion products and/or process off-gases, and all of the effluent comes from a single unit (
(iii) Combined maximum rated heat input capacity of the units sharing the common stack or duct (mmBtu/hr). This data element is required only when all of the units sharing the common stack are stationary fuel combustion units.
(iv) Each type of fuel combusted in the units during the year.
(v) The methodology (tier) used to calculate the CO
(vi) The methodology start date.
(vii) The methodology end date.
(viii) Total annual CO
(ix) An estimate of the heat input from each type of fuel listed in Table C-2 of this subpart that was combusted in the units sharing the common stack or duct during the report year.
(x) For each type of fuel listed in Table C-2 of this subpart that was combusted during the report year in the units sharing the common stack or duct during the report year, the annual CH
(xi) If applicable, the plant code (as defined in § 98.6).
(3)
(i) Common pipe identification number, beginning with the prefix “CP”.
(ii) Cumulative maximum rated heat input capacity of the units served by the common pipe (mmBtu/hr). The cumulative maximum rated heat input capacity shall be determined as the sum of the maximum rated heat input capacities for all units served by the common pipe, excluding units less than 10 (mmBtu/hr).
(iii) The highest maximum rated heat input capacity of any unit served by the common pipe (mmBtu/hr).
(iv) The fuels combusted in the units during the reporting year.
(v) The methodology used to calculate the CO
(vi) If the any of the units burns both fossil fuels and biomass, the annual CO
(vii) Annual CO
(viii) Methodology start date.
(ix) Methodology end date.
(x) If applicable, the plant code (as defined in § 98.6).
(4) The following alternative reporting option applies to facilities at which a common liquid or gaseous fuel supply is shared between one or more large combustion units, such as boilers or combustion turbines (including units subject to subpart D of this part and other units subject to part 75 of this chapter) and small combustion sources, including, but not limited to, space heaters, hot water heaters, and lab burners. In this case, you may simplify reporting by attributing all of the GHG emissions from combustion of the shared fuel to the large combustion unit(s), provided that:
(i) The total quantity of the fuel combusted during the report year in the units sharing the fuel supply is measured, either at the “gate” to the facility or at a point inside the facility, using a fuel flow meter, billing meter, or tank drop measurements (as applicable);
(ii) On an annual basis, at least 95 percent (by mass or volume) of the shared fuel is combusted in the large combustion unit(s), and the remainder is combusted in the small combustion sources. Company records may be used
(iii) The use of this reporting option is documented in the Monitoring Plan required under § 98.3(g)(5). Indicate in the Monitoring Plan which units share the common fuel supply and the method used to demonstrate that this alternative reporting option applies. For the small combustion sources, a description of the types of units and the approximate number of units is sufficient.
(d)
(i) Unit or stack identification numbers. Use exact same unit, common stack, common pipe, or multiple stack identification numbers that represent the monitored locations (
(ii) Annual CO
(iii) Annual CH
(iv) The total heat input from each fuel listed in Table C-2 that was combusted during the year (except as otherwise provided in § 98.33(c)(4)(ii)(B)), expressed in mmBtu.
(v) Identification of the Part 75 methodology used to determine the CO
(vi) Methodology start date.
(vii) Methodology end date.
(viii) Acid Rain Program indicator.
(ix) Annual CO
(x) If applicable, the plant code (as defined in § 98.6).
(2) For units that use the alternative CO
(i) Unit, stack, or pipe ID numbers. Use exact same unit, common stack, common pipe, or multiple stack identification numbers that represent the monitored locations (
(ii) For units that use the alternative methods specified in § 98.33(a)(5)(i) and (ii) to monitor and report heat input data year-round according to appendix D to part 75 of this chapter or § 75.19 of this chapter:
(A) Each type of fuel combusted in the unit during the reporting year.
(B) The methodology used to calculate the CO
(C) Methodology start date.
(D) Methodology end date.
(E) A code or flag to indicate whether heat input is calculated according to appendix D to part 75 of this chapter or § 75.19 of this chapter.
(F) Annual CO
(G) Annual heat input from each type of fuel listed in Table C-2 of this subpart that was combusted during the reporting year, expressed in mmBtu.
(H) Annual CH
(I) Annual CO
(J) If applicable, the plant code (as defined in § 98.6).
(iii) For units with continuous monitoring systems that use the alternative method for units with continuous monitoring systems in § 98.33(a)(5)(iii) to monitor heat input year-round according to part 75 of this chapter:
(A) Each type of fuel combusted during the reporting year.
(B) Methodology used to calculate the CO
(C) Methodology start date.
(D) Methodology end date.
(E) A code or flag to indicate that the heat input data is derived from CEMS measurements.
(F) The total annual CO
(G) Annual heat input from each type of fuel listed in Table C-2 of this subpart that was combusted during the reporting year, expressed in mmBtu.
(H) Annual CH
(I) Annual CO
(J) If applicable, the plant code (as defined in § 98.6).
(e)
(1) The applicable verification data specified in this paragraph (e) are not required to be kept on file or reported for units that meet any one of the three following conditions:
(i) Are subject to the Acid Rain Program.
(ii) Use the alternative methods for units with continuous monitoring systems provided in § 98.33(a)(5).
(iii) Are not in the Acid Rain Program, but are required to monitor and report CO
(2) For stationary combustion sources using the Tier 1, Tier 2, Tier 3, and Tier 4 Calculation Methodologies in § 98.33(a) to quantify CO
(i) For the Tier 1 Calculation Methodology, report:
(A) The total quantity of each type of fuel combusted in the unit or group of aggregated units (as applicable) during the reporting year, in short tons for solid fuels, gallons for liquid fuels and standard cubic feet for gaseous fuels, or, if applicable, therms or mmBtu for natural gas.
(B) If applicable, the moisture content used to calculate the wood and wood residuals wet basis HHV for use in Equations C-1 and C-8 of this subpart, in percent.
(ii) For the Tier 2 Calculation Methodology, report:
(A) The total quantity of each type of fuel combusted in the unit or group of aggregated units (as applicable) during each month of the reporting year. Express the quantity of each fuel combusted during the measurement period in short tons for solid fuels, gallons for liquid fuels, and scf for gaseous fuels.
(B) The frequency of the HHV determinations (e.g., once a month, once per fuel lot).
(C) The high heat values used in the CO
(D) If Equation C-2c of this subpart is used to calculate CO
(E) For each HHV used in the CO
(iii) For the Tier 2 Calculation Methodology, keep records of the methods
(iv) For the Tier 3 Calculation Methodology, report:
(A) The quantity of each type of fuel combusted in the unit or group of units (as applicable) during each month of the reporting year, in short tons for solid fuels, gallons for liquid fuels, and scf for gaseous fuels.
(B) The frequency of carbon content and, if applicable, molecular weight determinations for each type of fuel for the reporting year (e.g., daily, weekly, monthly, semiannually, once per fuel lot).
(C) The carbon content and, if applicable, gas molecular weight values used in the emission calculations (including both valid and substitute data values). For each calendar month of the reporting year in which carbon content and, if applicable, molecular weight determination is required, report a value of each parameter. If multiple values of a parameter are obtained in a given month, report the arithmetic average value for the month. Express carbon content as a decimal fraction for solid fuels, kg C per gallon for liquid fuels, and kg C per kg of fuel for gaseous fuels. Express the gas molecular weights in units of kg per kg-mole.
(D) The total number of valid carbon content determinations and, if applicable, molecular weight determinations made during the reporting year, for each fuel type.
(E) The number of substitute data values used for carbon content and, if applicable, molecular weight used in the annual GHG emissions calculations.
(F) The annual average HHV, when measured HHV data, rather than a default HHV from Table C-1 of this subpart, are used to calculate CH
(G) The value of the molar volume constant (MVC) used in Equation C-5 (if applicable).
(v) For the Tier 3 Calculation Methodology, keep records of the following:
(A) For liquid and gaseous fuel combustion, the dates and results of the initial calibrations and periodic recalibrations of the required fuel flow meters.
(B) For fuel oil combustion, the method from § 98.34(b) used to make tank drop measurements (if applicable).
(C) The methods used to determine the carbon content and (if applicable) the molecular weight of each type of fuel combusted.
(D) The methods used to calibrate the fuel flow meters).
(E) The date on which each fuel sample was taken, except where fuel sampling data are received from the fuel supplier. In that case, keep records of the dates on which the results of the fuel analyses for carbon content and (if applicable) molecular weight are received.
(vi) For the Tier 4 Calculation Methodology, report:
(A) The total number of source operating hours in the reporting year.
(B) The cumulative CO
(C) For CO
(vii) For the Tier 4 Calculation Methodology, keep records of:
(A) Whether the CEMS certification and quality assurance procedures of part 75 of this chapter, part 60 of this chapter, or an applicable State continuous monitoring program were used.
(B) The dates and results of the initial certification tests of the CEMS.
(C) The dates and results of the major quality assurance tests performed on the CEMS during the reporting year, i.e., linearity checks, cylinder gas audits, and relative accuracy test audits (RATAs).
(viii) If CO
(A) The total amount of sorbent used during the report year, in short tons.
(B) The molecular weight of the sorbent.
(C) The ratio (“R”) in Equation C-11 of this subpart.
(ix) For units that combust both fossil fuel and biomass, when biogenic CO
(A) The annual volume of CO
(B) The annual volume of CO
(C) The annual volume of CO
(D) The carbon-based F-factor used in Equation C-13 of this subpart, for each type of fossil fuel combusted, in scf CO
(E) The annual average HHV value used in Equation C-13 of this subpart, for each type of fossil fuel combusted, in Btu/lb, Btu/gal, or Btu/scf, as appropriate.
(F) The total quantity of each type of fossil fuel combusted during the reporting year, in lb, gallons, or scf, as appropriate.
(G) Annual biogenic CO
(x) When ASTM methods D7459-08 and D6866-16 (both incorporated by reference, see § 98.7) are used to determine the biogenic portion of the annual CO
(A) The results of each quarterly sample analysis, expressed as a decimal fraction (e.g., if the biogenic fraction of the CO
(B) The annual biogenic CO
(xi) When ASTM methods D7459-08 and D6866-16 (both incorporated by reference, see § 98.7) are used in accordance with § 98.34(e) to determine the biogenic portion of the annual CO
(3) Within 30 days of receipt of a written request from the Administrator, you shall submit explanations of the following:
(i) An explanation of how company records are used to quantify fuel consumption, if the Tier 1 or Tier 2 Calculation Methodology is used to calculate CO
(ii) An explanation of how company records are used to quantify fuel consumption, if solid fuel is combusted and the Tier 3 Calculation Methodology is used to calculate CO
(iii) An explanation of how sorbent usage is quantified.
(iv) An explanation of how company records are used to quantify fossil fuel consumption in units that uses CEMS to quantify CO
(v) An explanation of how company records are used to measure steam production, when it is used to calculate CO
(4) Within 30 days of receipt of a written request from the Administrator, you shall submit the verification data and information described in paragraphs (e)(2)(iii), (e)(2)(v), and (e)(2)(vii) of this section.
(f) Each stationary fuel combustion source (e.g., individual unit, aggregation of units, common pipe, or common stack) subject to reporting under paragraph (b) or (c) of this section must indicate if both of the following two conditions are met:
(1) The stationary fuel combustion source contains at least one combustion unit connected to a fuel-fired electric generator owned or operated by an entity that is subject to regulation of customer billing rates by the public utility commission (excluding generators that are connected to combustion
(2) The stationary fuel combustion source is located at a facility for which the sum of the nameplate capacities for all electric generators specified in paragraph (f)(1) of this section is greater than or equal to 1 megawatt electric output.
In addition to the requirements of § 98.3(g), you must retain:
(a) The applicable records specified in §§ 98.34(f), 98.35(b), and 98.36(e).
(b)
(1) Mass of each solid fuel combusted (tons/year) (Equation C-1 of § 98.33).
(2) Volume of each liquid fuel combusted (gallons/year) (Equation C-1).
(3) Volume of each gaseous fuel combusted (scf/year) (Equation C-1).
(4) Annual natural gas usage (therms/year) (Equation C-1a of § 98.33).
(5) Annual natural gas usage (mmBtu/year) (Equation C-1b of § 98.33).
(6) Mass of each solid fuel combusted (tons/year) (Equation C-2a of § 98.33).
(7) Volume of each liquid fuel combusted (gallons/year) (Equation C-2a).
(8) Volume of each gaseous fuel combusted (scf/year) (Equation C-2a).
(9) Measured high heat value of each solid fuel, for month (which may be the arithmetic average of multiple determinations), or, if applicable, an appropriate substitute data value (mmBtu per ton) (Equation C-2b of § 98.33).
(10) Measured high heat value of each liquid fuel, for month (which may be the arithmetic average of multiple determinations), or, if applicable, an appropriate substitute data value (mmBtu per gallons) (Equation C-2b).
(11) Measured high heat value of each gaseous fuel, for month (which may be the arithmetic average of multiple determinations), or, if applicable, an appropriate substitute data value (mmBtu per scf) (Equation C-2b).
(12) Mass of each solid fuel combusted during month (tons) (Equation C-2b).
(13) Volume of each liquid fuel combusted during month (gallons) (Equation C-2b).
(14) Volume of each gaseous fuel combusted during month (scf) (Equation C-2b).
(15) Total mass of steam generated by municipal solid waste or each solid fuel combustion during the reporting year (pounds steam) (Equation C-2c of § 98.33).
(16) Ratio of the boiler's maximum rated heat input capacity to its design rated steam output capacity (MMBtu/pounds steam) (Equation C-2c).
(17) Annual mass of each solid fuel combusted (short tons/year) (Equation C-3 of § 98.33).
(18) Annual average carbon content of each solid fuel (percent by weight, expressed as a decimal fraction) (Equation C-3).
(19) Annual volume of each liquid fuel combusted (gallons/year) (Equation C-4 of § 98.33).
(20) Annual average carbon content of each liquid fuel (kg C per gallon of fuel) (Equation C-4).
(21) Annual volume of each gaseous fuel combusted (scf/year) (Equation C-5 of § 98.33).
(22) Annual average carbon content of each gaseous fuel (kg C per kg of fuel) (Equation C-5).
(23) Annual average molecular weight of each gaseous fuel (kg/kg-mole) (Equation C-5).
(24) Molar volume conversion factor at standard conditions, as defined in § 98.6 (scf per kg-mole) (Equation C-5).
(25) Identify for each fuel if you will use the default high heat value from Table C-1 of this subpart, or actual high heat value data (Equation C-8 of § 98.33).
(26) High heat value of each solid fuel (mmBtu/tons) (Equation C-8).
(27) High heat value of each liquid fuel (mmBtu/gallon) (Equation C-8).
(28) High heat value of each gaseous fuel (mmBtu/scf) (Equation C-8).
(29) Cumulative annual heat input from combustion of each fuel (mmBtu) (Equation C-10 of § 98.33).
(30) Total quantity of each solid fossil fuel combusted in the reporting year, as defined in § 98.6 (pounds) (Equation C-13 of § 98.33).
(31) Total quantity of each liquid fossil fuel combusted in the reporting year, as defined in § 98.6 (gallons) (Equation C-13).
(32) Total quantity of each gaseous fossil fuel combusted in the reporting year, as defined in § 98.6 (scf) (Equation C-13).
(33) High heat value of the each solid fossil fuel (Btu/lb) (Equation C-13).
(34) High heat value of the each liquid fossil fuel (Btu/gallons) (Equation C-13).
(35) High heat value of the each gaseous fossil fuel (Btu/scf) (Equation C-13).
(36) Fuel-specific carbon based F-factor per fuel (scf CO
(37) Moisture content used to calculate the wood and wood residuals wet basis HHV (percent), if applicable (Equations C-1 and C-8 of this subpart).
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
(a) The electricity generation source category comprises electricity generating units that are subject to the requirements of the Acid Rain Program and any other electricity generating units that are required to monitor and report to EPA CO
(b) This source category does not include portable equipment, emergency equipment, or emergency generators, as defined in § 98.6.
You must report GHG emissions under this subpart if your facility contains one or more electricity generating units and the facility meets the requirements of § 98.2(a)(1).
(a) For each electricity generating unit that is subject to the requirements of the Acid Rain Program or is otherwise required to monitor and report to EPA CO
(b) For each electricity generating unit that is not subject to the Acid Rain Program or otherwise required to monitor and report to EPA CO
(c) For each stationary fuel combustion unit that does not generate electricity, you must report under subpart C of this part (General Stationary Fuel Combustion Sources) the emissions of CO
(a) Except as provided in paragraph (b) of this section, continue to monitor and report CO
(1) Convert the cumulative annual CO
(2) Calculate and report annual CH
(b) Calculate and report biogenic CO
Follow the applicable quality assurance procedures for CO
Follow the applicable missing data substitution procedures in 40 CFR part 75 for CO
The annual report shall comply with the data reporting requirements specified in § 98.36(d)(1).
You shall comply with the recordkeeping requirements of §§ 98.3(g) and 98.37. Records retained under § 75.57(h) of this chapter for missing data events satisfy the recordkeeping requirements of § 98.3(g)(4) for those same events.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
The adipic acid production source category consists of all adipic acid production facilities that use oxidation to produce adipic acid.
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).
(a) You must report N
(b) You must report under subpart C of this part (General Stationary Fuel Combustion Sources) the emissions of CO
(a) You must determine annual N
(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
(i) If you received Administrator approval for an alternative method of determining N
(ii) You must notify the EPA of your use of a previously approved alternative method in your annual report.
(iii) Otherwise, you must submit the request within 45 days following promulgation of this subpart or within the first 30 days of each subsequent reporting year.
(iv) 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
(b) You must conduct an annual performance test according to paragraphs (b)(1) through (3) of this section.
(1) You must conduct the test on the vent stream from the nitric acid oxidation step of the process, referred to as
(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 tons per hour.
(c) Using the results of the performance test in paragraph (b) of this section, you must calculate an emission factor for each adipic acid unit according to Equation E-1 of this section:
(d) If the adipic acid production unit exhausts to any N
(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 was used to determine the destruction efficiency.
(3) Calculate the destruction efficiency by conducting an additional performance test on the vent stream following the N
(e) If the adipic acid production unit exhausts to any N
(f) You must determine the annual amount of adipic acid produced according to § 98.54(f).
(g) You must calculate N
(1) If one N
(2) If multiple N
(3) If multiple N
(4) If no N
(h) You must determine the emissions for the facility by summing the unit level emissions according to Equation E-4 of this section.
(i) You must determine the amount of process N
(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 (3) of this section.
(1) Conduct the performance test annually. The test must be conducted at a point during production that is representative of the average emissions rate 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
(b) You must measure the N
(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 Interface Fourier Transform Infrared (FTIR) Spectroscopy (incorporated by reference,
(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.
(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 produced. You must also determine the monthly amount of adipic acid produced during which N
(f) You must determine the annual amount of adipic acid produced. You must also determine the annual amount of adipic acid produced during which N
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).
(b) For missing values related to the performance test, including emission factors, production rate, and N
In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) through (n) of this section at the facility level.
(a) Annual process N
(b)-(c) [Reserved]
(d) Annual process N
(e) Number of abatement technologies (if applicable).
(f) Types of abatement technologies used and date of installation for each (if applicable).
(g) Abatement technology destruction efficiency for each abatement technology (percent destruction).
(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 (7) of this section for each adipic acid production unit.
(1) [Reserved]
(2) Test method used for performance test.
(3) [Reserved]
(4) N
(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
(1) Name of alternative method.
(2) Description of alternative method.
(3) Request date.
(4) Approval date.
(l) Fraction control factor for each abatement technology (percent of total emissions from the production unit that are sent to the abatement technology) if equation E-3c is used.
(m) If only cyclohexane is oxidized to produce adipic acid and the quantity is known, report the information specified in paragraph (m)(1) of this section. If materials other than cyclohexane are oxidized to produce adipic acid, report the information specified in paragraph (m)(2) of this section.
(1) Annual quantity of cyclohexane (tons) used to produce adipic acid.
(2) Annual quantity of cyclohexanone and cyclohexanol mixture (tons) used to produce adipic acid.
(n) Annual percent N
In addition to the information required by § 98.3(g), you must retain the records specified in paragraphs (a) through (i) 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 parameters, including but not limited to, calibration of weighing equipment,
(i)
(1) Annual adipic acid production from each adipic acid production unit (tons) (Equations E-2, E-3a, E-3b, E-3c, and E-3d of § 98.53).
(2) Production rate per test run during the performance test for each production unit test run (tons adipic acid produced/hr) (Equation E-1 of § 98.53).
(3) Annual adipic acid production per N
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
(a) A primary aluminum production facility manufactures primary aluminum using the Hall-Héroult manufacturing process. The primary aluminum manufacturing process comprises the following operations:
(1) Electrolysis in prebake and Søderberg cells.
(2) Anode baking for prebake cells.
(b) This source category does not include experimental cells or research and development process units.
You must report GHG emissions under this subpart if your facility contains an aluminum production process and the facility meets the requirements of either § 98.2(a)(1) or (a)(2).
You must report:
(a) Perfluoromethane (CF
(b) CO
(c) CO
(d) You must report under subpart C of this part (General Stationary Fuel Combustion Sources) the emissions of CO
(a) The annual value of each PFC compound (CF
(b) Use Equation F-2 of this section to estimate CF
(c) You must calculate and report the annual process CO
(d) Calculate and report under this subpart the process CO
(e) Use the following procedures to calculate CO
(1) For Prebake cells: you must calculate CO
(2) For Søderberg cells you must calculate CO
(f) Use the following procedures to calculate CO
(1) Use Equation F-7 of this section to calculate emissions from pitch volatiles combustion.
(2) Use Equation F-8 of this section to calculate emissions from bake furnace packing material.
(g) If process CO
(a) Effective December 31, 2010 for smelters with no prior measurement or effective December 31, 2012, for facilities with historic measurements, the smelter-specific slope coefficients, overvoltage emission factors, and weight fractions used in Equations F-2, F-3, and F-4 of this subpart must be measured in accordance with the recommendations of the EPA/IAI Protocol for Measurement of Tetrafluoromethane (CF
(b) The minimum frequency of the measurement and analysis is annually except as follows:
(1) Monthly for anode effect minutes per cell day (or anode effect overvoltage and current efficiency).
(2) Monthly for aluminum production.
(3) Smelter-specific slope coefficients, overvoltage emission factors, and weight fractions according to paragraph (a) of this section.
(c) Sources may use either smelter-specific values from annual measurements of parameters needed to complete the equations in § 98.63 (e.g., sulfur, ash, and hydrogen contents) or the default values shown in Table F-2 of this subpart.
A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable (e.g., if a meter malfunctions during unit operation or if a required sample measurement is not taken), a substitute data value for the missing parameter shall be used in the calculations, according to the following requirements:
(a) Where anode or paste consumption data are missing, CO
(b) For other parameters, use the average of the two most recent data points after the missing data.
In addition to the information required by § 98.3(c), you must report the following information at the facility level:
(a) [Reserved]
(b) Type of smelter technology used.
(c) The following PFC-specific information on an annual basis:
(1) Perfluoromethane emissions and perfluoroethane emissions from anode effects in all prebake and all Søderberg electrolysis cells combined.
(2) Anode effect minutes per cell-day (AE-mins/cell-day), anode effect frequency (AE/cell-day), anode effect duration (minutes). (Or anode effect overvoltage factor ((kg CF4/metric ton Al)/(mV/cell day)), potline overvoltage (mV/cell day), current efficiency (%)).
(3) Smelter-specific slope coefficients (or overvoltage emission factors) and the last date when the smelter-specific slope coefficients (or overvoltage emission factors) were measured.
(d) Method used to measure the frequency and duration of anode effects (or overvoltage).
(e) The following CO
(1) Annual anode consumption if using the method in § 98.63(g).
(2) Annual CO
(f) The following CO
(1) Annual paste consumption if using the method in § 98.63(g).
(2) Annual CO
(g) [Reserved]
(h) Exact data elements required will vary depending on smelter technology (e.g., point-feed prebake or Søderberg) and process control technology (e.g., Pechiney or other).
In addition to the information required by § 98.3(g), you must retain the following records:
(a) Monthly aluminum production in metric tons.
(b) Type of smelter technology used.
(c) The following PFC-specific information on a monthly basis:
(1) Perfluoromethane and perfluoroethane emissions from anode effects in prebake and Søderberg electolysis cells.
(2) Anode effect minutes per cell-day (AE-mins/cell-day), anode effect frequency (AE/cell-day), anode effect duration (minutes). (Or anode effect overvoltage factor ((kg CF
(3) Smelter-specific slope coefficients and the last date when the smelter-specific-slope coefficients were measured.
(d) Method used to measure the frequency and duration of anode effects (or to measure anode effect overvoltage and current efficiency).
(e) The following CO
(1) Annual anode consumption.
(2) Annual CO
(f) The following CO
(1) Annual paste consumption.
(2) Annual CO
(g) Smelter-specific inputs to the CO
(h) Exact data elements required will vary depending on smelter technology (e.g., point-feed prebake or Søderberg) and process control technology (e.g., Pechiney or other).
(i)
(1) Slope coefficient per potline per month (kg CF
(2) Anode effect minutes per cell-day per potline per month (AE-Mins/cell-day) (Equation F-2).
(3) Anode effect frequency per potline per month (AE/cell-day) (Equation F-2).
(4) Anode effect duration per potline per month (minutes) (Equation F-2).
(5) Metal production of aluminum per potline per month (metric tons) (Equation F-2).
(6) Overvoltage emission factor per potline per month (kg CF4/metric ton Al) (Equation F-3 of § 98.63).
(7) Metal production of aluminum per potline per month (metric tons) (Equation F-3).
(8) Weight fraction of C
(9) Net annual prebaked anode consumption (metric tons C/metric tons Al) (Equation F-5 of § 98.63).
(10) Annual metal production of aluminum (metric tons) (Equation F-5).
(11) Sulfur content in baked anode (weight percent) (Equation F-5).
(12) Ash content in baked anode (weight percent) (Equation F-5).
(13) Annual paste consumption (metric ton/metric ton Al) (Equation F-6 of § 98.63).
(14) Annual metal production of aluminum (metric tons) (Equation F-6).
(15) Annual emissions of cyclohexane soluble matter (kg/metric ton Al) (Equation F-6).
(16) Binder content of paste (weight percent) (Equation F-6).
(17) Sulfur content of pitch (weight percent) (Equation F-6).
(18) Ash content of pitch (weight percent) (Equation F-6).
(19) Hydrogen content of pitch (weight percent) (Equation F-6).
(20) Sulfur content in calcined coke (weight percent) (Equation F-6).
(21) Ash content in calcined coke (weight percent) (Equation F-6).
(22) Carbon in skimmed dust from Søderberg cells (metric ton C/metric ton Al) (Equation F-6).
(23) Initial weight of green anodes (metric tons) (Equation F-7 of § 98.63).
(24) Annual hydrogen content in green anodes (metric tons) (Equation F-7).
(25) Annual baked anode production (metric tons) (Equation F-7).
(26) Annual waste tar collected (metric tons) (Equation F-7).
(27) Annual packing coke consumption (metric tons/metric ton baked anode) (Equation F-8 of § 98.63).
(28) Annual baked anode production (metric tons) (Equation F-8).
(29) Sulfur content in packing coke (weight percent) (Equation F-8).
(30) Ash content in packing coke (weight percent) (Equation F-8).
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
The ammonia manufacturing source category comprises the process units listed in paragraphs (a) and (b) of this section.
(a) Ammonia manufacturing processes in which ammonia is manufactured from a fossil-based feedstock produced via steam reforming of a hydrocarbon.
(b) Ammonia manufacturing processes in which ammonia is manufactured through the gasification of solid and liquid raw material.
You must report GHG emissions under this subpart if your facility contains an ammonia manufacturing process and the facility meets the requirements of either § 98.2(a)(1) or (2).
You must report:
(a) CO
(b) CO
(c) CO
You must calculate and report the annual process CO
(a) Calculate and report under this subpart the process CO
(b) Calculate and report under this subpart process CO
(1)
(2)
(3)
(4) You must calculate the annual process CO
(5) You must determine the combined CO
(c) If GHG emissions from an ammonia manufacturing unit are vented through the same stack as any combustion unit or process equipment that reports CO
(a) You must continuously measure the quantity of gaseous or liquid feedstock consumed using a flow meter. The quantity of solid feedstock consumed can be obtained from company records and aggregated on a monthly basis.
(b) You must document the procedures used to ensure the accuracy of the estimates of feedstock consumption.
(c) You must determine monthly carbon contents and the average molecular weight of each feedstock consumed from reports from your supplier. As an alternative to using supplier information on carbon contents, you can also collect a sample of each feedstock on a monthly basis and analyze the carbon content and molecular weight of the fuel using any of the following methods listed in paragraphs (c)(1) through (c)(8) of this section, as applicable.
(1) ASTM D1945-03 Standard Test Method for Analysis of Natural Gas by Gas Chromatography (incorporated by reference,
(2) ASTM D1946-90 (Reapproved 2006) Standard Practice for Analysis of Reformed Gas by Gas Chromatography (incorporated by reference,
(3) ASTM D2502-04 (Reapproved 2002) Standard Test Method for Estimation of Mean Relative Molecular Mass of Petroleum Oils from Viscosity Measurements (incorporated by reference,
(4) ASTM D2503-92 (Reapproved 2007) Standard Test Method for Relative Molecular Mass (Molecular Weight) of Hydrocarbons by Thermoelectric Measurement of Vapor Pressure (incorporated by reference,
(5) ASTM D3238-95 (Reapproved 2005) Standard Test Method for Calculation of Carbon Distribution and Structural Group Analysis of Petroleum Oils by the n-d-M Method (incorporated by reference,
(6) ASTM D5291-02 (Reapproved 2007) Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants (incorporated by reference,
(7) ASTM D3176-89 (Reapproved 2002) Standard Practice for Ultimate Analysis of Coal and Coke (incorporated by reference,
(8) ASTM D5373-08 Standard Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference,
(d) Calibrate all oil and gas flow meters that are used to measure liquid and gaseous feedstock volumes and flow rates (except for gas billing meters) according to the monitoring and QA/QC requirements for the Tier 3 methodology in § 98.34(b)(1). Perform oil tank drop measurements (if used to quantify feedstock volumes) according to § 98.34(b)(2).
(e) For quality assurance and quality control of the supplier data, on an annual basis, you must measure the carbon contents of a representative sample of the feedstocks consumed using the appropriate ASTM Method as listed in paragraphs (c)(1) through (c)(8) of this section.
(f) You may use company records or an engineering estimate to determine the annual ammonia production and the annual methanol production.
(g) If CO
A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever the monitoring and quality assurance procedures in § 98.74 cannot be followed (e.g., if a meter malfunctions during unit operation), a substitute data value for the missing parameter shall be used in the calculations following paragraphs (a) and (b) of this section. You must document and keep records of the procedures used for all such estimates.
(a) For missing data on monthly carbon contents of feedstock, the substitute data value shall be the arithmetic average of the quality-assured values of that carbon content in the month preceding and the month immediately following the missing data incident. If no quality-assured data are available prior to the missing data incident, the substitute data value shall be the first quality-assured value for carbon content obtained in the month after the missing data period.
(b) For missing feedstock supply rates used to determine monthly feedstock consumption, you must determine the best available estimate(s) of the parameter(s), based on all available process data.
In addition to the information required by § 98.3(c), each annual report must contain the information specified
(a) If a CEMS is used to measure CO
(1) Annual quantity of each type of feedstock consumed for ammonia manufacturing (scf of feedstock or gallons of feedstock or kg of feedstock).
(2) Method used for determining quantity of feedstock used.
(3) Annual ammonia production (metric tons, sum of all process units reported within subpart G of this part).
(b) If a CEMS is not used to measure emissions, then you must report all of the following information in this paragraph (b):
(1) Annual CO
(2) Annual quantity of each type of feedstock consumed for ammonia manufacturing (scf of feedstock or gallons of feedstock or kg of feedstock).
(3) Method used for determining quantity of monthly feedstock used.
(4) Whether carbon content for each feedstock for month n is based on reports from the supplier or analysis of carbon content.
(5) If carbon content of feedstock for month n is based on analysis, the test method used.
(6) Sampling analysis results of carbon content of feedstock as determined for QA/QC of supplier data under § 98.74(e).
(7) Annual average carbon content of each type of feedstock consumed.
(8)-(11) [Reserved]
(12) Annual urea production (metric tons) and method used to determine urea production.
(13) Annual CO
(14) Annual ammonia production (metric tons, sum of all process units reported within subpart G).
(15) Annual quantity of methanol intentionally produced as a desired product, for each process unit (metric tons).
In addition to the records required by § 98.3(g), you must retain the following records specified in paragraphs (a) through (c) of this section for each ammonia manufacturing unit.
(a) If a CEMS is used to measure emissions, retain records of all feedstock purchases in addition to the requirements in § 98.37 for the Tier 4 Calculation Methodology.
(b) If a CEMS is not used to measure process CO
(1) Records of all analyses and calculations conducted for reported data as listed in § 98.76(b).
(2) Monthly records of carbon content of feedstock from supplier and/or all analyses conducted of carbon content.
(c)
(1) Volume of each gaseous feedstock used in month (scf of feedstock) (in Equation G-1 of § 98.73).
(2) Carbon content of each gaseous feedstock, for month (kg C per kg of feedstock) (in Equation G-1).
(3) Molecular weight of each gaseous feedstock per ammonia manufacturing unit with gaseous feedstock (kg/kg-mole) (Equation G-1).
(4) Volume of each liquid feedstock used in month (gallons of feedstock) (Equation G-2 of § 98.73).
(5) Carbon content of each liquid feedstock, for month (kg C per gallon of feedstock) (Equation G-2).
(6) Mass of each solid feedstock used in month (kg of feedstock) (Equation G-3 of § 98.73).
(7) Carbon content of each solid feedstock, for month (kg C per kg of feedstock) (Equation G-3).
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
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.
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).
You must report:
(a) CO
(b) CO
(c) CH
(d) CO
You must calculate and report the annual process CO
(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
(b) For each kiln that is not subject to the requirements in paragraph (a) of this section, calculate and report the process and combustion CO
(c) Calculate and report under this subpart the combined process and combustion CO
(d) Calculate and report process and combustion CO
(1) Calculate CO
(2)
(i)
(B) Non-calcined CaO is CaO that remains in the clinker in the form of CaCO
(ii)
(B) Non-calcined CaO is CaO that remains in the CKD in the form of CaCO
(3)
(4) Calculate and report under subpart C of this part (General Stationary Fuel Combustion Sources) the combustion CO
(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 Chemical 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 materials 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 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
(e) The quantity of CKD not recycled to the kiln generated by each kiln must be determined quarterly using the same plant techniques used for accounting purposes, such as direct weight measurement using 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.
(g) The monthly non-calcined CaO and MgO that remains in the clinker in the form of CaCO
(h) The quarterly non-calcined CaO and MgO that remains in the CKD in the form of CaCO
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.
(a) If the CEMS approach is used to determine combined process and combustion CO
(b) For CO
(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.
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
(1) Monthly clinker production from each kiln at the facility.
(2) Annual facility cement production.
(3) Number of kilns and number of operating kilns.
(b) If a CEMS is not used to measure CO
(1) Kiln identification number.
(2) [Reserved]
(3) Annual cement production at the facility.
(4) Number of kilns and number of operating kilns.
(5)-(6) [Reserved]
(7) Method used to determine non-calcined CaO and non-calcined MgO in clinker.
(8) [Reserved]
(9) Method used to determine non-calcined CaO and non-calcined MgO in CKD.
(10) [Reserved]
(11) Quarterly kiln-specific CKD CO
(12) [Reserved]
(13) Name of raw kiln feed or raw material.
(14) Number of times missing data procedures were used to determine the following information:
(i) Clinker production (number of months).
(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.
(16) Annual clinker production (metric tons).
(17) Annual average clinker CO
(18) Annual average CKD CO
(a) If a CEMS is used to measure CO
(b) If a CEMS is not used to measure CO
(1) Documentation of monthly calculated kiln-specific clinker CO
(2) Documentation of quarterly calculated kiln-specific CKD CO
(3) Measurements, records and calculations used to determine reported parameters.
(c)
(1) Identify per kiln per month if clinker is measured directly, or is calculated from raw feed (Equation H-2 of § 98.83 and the method in § 98.84(d)).
(2) Quantity of raw kiln feed in month from kiln (tons) (Equation H-2 and the method in § 98.84(d)).
(3) Kiln-specific factor per kiln per month (ton clinker per ton raw feed) (Equation H-2 and the method in § 98.84(d)).
(4) Quantity of clinker produced in month from kiln (tons) (Equation H-2 and the method in § 98.84(d)).
(5) Cement kiln dust (CKD) not recycled to the kiln in quarter from kiln (tons) (Equation H-2 and the method in § 98.84(d)).
(6) Monthly total CaO content of clinker per kiln (weight fraction) (Equation H-3 of § 98.83).
(7) Monthly non-calcined CaO content of clinker per kiln (weight fraction) (Equation H-3).
(8) Monthly total MgO content of clinker per kiln (weight fraction) (Equation H-3).
(9) Monthly non-calcined MgO content of clinker per kiln (weight fraction) (Equation H-3).
(10) Quarterly total CaO content of cement kiln dust not recycled to each
(11) Quarterly non-calcined CaO content of cement kiln dust not recycled to each kiln (weight fraction) (Equation H-4).
(12) Quarterly total MgO content of cement kiln dust not recycled to each kiln (weight fraction) (Equation H-4).
(13) Quarterly non-calcined MgO content of cement kiln dust not recycled to each kiln (weight fraction) (Equation H-4).
(14) The amount of each raw material consumed annually per kiln (tons/yr (dry basis)) (Equation H-5 of § 98.83).
(15) The amount of each raw kiln feed consumed annually per kiln (tons/yr (dry basis)) (Equation H-5).
(16) Organic carbon content of each raw material per kiln, as determined in § 98.84(c). Default value is 0.002 weight fraction (Equation H-5).
(17) Organic carbon content of combined raw kiln feed per kiln, as determined in § 98.84(c). Default value is 0.002 weight fraction (Equation H-5).
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
75 FR 74818, Dec. 1, 2010, unless otherwise noted.
(a) The electronics manufacturing source category consists of any of the production processes listed in paragraphs (a)(1) through (a)(5) of this section that use fluorinated GHGs or N
(1) Any electronics production process in which the etching process uses plasma-generated fluorine atoms and other reactive fluorine-containing fragments, that chemically react with exposed thin-films (e.g., dielectric, metals) or substrate (e.g., silicon) to selectively remove portions of material.
(2) Any electronics production process in which chambers used for depositing thin films are cleaned periodically using plasma-generated fluorine atoms and other reactive fluorine-containing fragments.
(3) Any electronics production process in which wafers are cleaned using plasma generated fluorine atoms or other reactive fluorine-containing fragments to remove residual material from wafer surfaces, including the wafer edge.
(4) Any electronics production process in which the chemical vapor deposition (CVD) process or other manufacturing processes use N
(5) Any electronics manufacturing production process in which fluorinated heat transfer fluids are used to cool process equipment, to control temperature during device testing, to clean substrate surfaces and other parts, and for soldering (e.g., vapor phase reflow).
(a) You must report GHG emissions under this subpart if electronics manufacturing production processes, as defined in § 98.90, are performed at your facility and your facility meets the requirements of either § 98.2(a)(1) or (a)(2). To calculate total annual GHG emissions for comparison to the 25,000 metric ton CO
(1) If you manufacture semiconductors or MEMS you must calculate annual production process emissions of
(2) If you manufacture LCDs, you must calculate annual production process emissions of each input gas i for threshold applicability purposes using the default emission factors shown in Table I-1 to this subpart and Equation I-2 of this subpart.
(3) If you manufacture PVs, you must calculate annual production process emissions of each input gas i for threshold applicability purposes using gas-appropriate GWP values shown in Table A-1 to subpart A of this part and Equation I-3 of this subpart.
(4) You must calculate total annual production process emissions for threshold applicability purposes using Equation I-4 of this subpart.
(b) You must calculate annual manufacturing capacity of a facility using Equation I-5 of this subpart.
(a) You must report emissions of fluorinated GHGs (as defined in § 98.6), N
(1) Fluorinated GHGs emitted.
(2)-(3) [Reserved]
(4) N
(5) Emissions of fluorinated heat transfer fluids.
(6) All fluorinated GHGs and N
(b) CO
(a) You must calculate total annual emissions of each fluorinated GHG emitted by electronics manufacturing production processes from each fab (as defined in § 98.98) at your facility, including each input gas and each by-product gas. You must use either default gas utilization rates and by-product formations rates according to the procedures in paragraph (a)(1), (a)(2), or (a)(6) of this section, as appropriate, or the stack test method according to paragraph (i) of this section, to calculate emissions of each input gas and each by-product gas.
(1) If you manufacture semiconductors, you must adhere to the procedures in paragraphs (a)(1)(i) through (iii) of this section. You must calculate annual emissions of each input gas and of each by-product gas using Equations I-6 and I-7 of this subpart, respectively. If your fab uses less than 50 kg of a fluorinated GHG in one reporting year, you may calculate emissions as equal to your fab's annual consumption for that specific gas as calculated in Equation I-11 of this subpart, plus any by-product emissions of that gas calculated under paragraph (a) of this section.
(i) You must calculate annual fab-level emissions of each fluorinated GHG used for the plasma etching/wafer cleaning process type using default utilization and by-product formation rates as shown in Table I-3 or I-4 of this subpart, and by using Equations I-8 and I-9 of this subpart.
(ii) You must calculate annual fab-level emissions of each fluorinated GHG used for each of the process sub-types associated with the chamber cleaning process type, including in-situ plasma chamber clean, remote plasma chamber clean, and in-situ thermal chamber clean, using default utilization and by-product formation rates as shown in Table I-3 or I-4 of this subpart, and by using Equations I-8 and I-9 of this subpart.
(iii) If default values are not available for a particular input gas and process type or sub-type combination in Tables I-3 or I-4, you must follow the procedures in paragraph (a)(6) of this section.
(2) If you manufacture MEMS, LCDs, or PVs, you must calculate annual fab-level emissions of each fluorinated GHG used for the plasma etching and chamber cleaning process types using default utilization and by-product formation rates as shown in Table I-5, I-6, or I-7 of this subpart, as appropriate, and by using Equations I-8 and I-9 of this subpart. If default values are not available for a particular input gas and process type or sub-type combination in Tables I-5, I-6, or I-7, you must follow the procedures in paragraph (a)(6) of this section. If your fab uses less than 50 kg of a fluorinated GHG in one reporting year, you may calculate emissions as equal to your fab's annual consumption for that specific gas as calculated in Equation I-11 of this subpart, plus any by-product emissions of that gas calculated under this paragraph (a).
(3)-(5) [Reserved]
(6) If you are required, or elect, to perform calculations using default emission factors for gas utilization and by-product formation rates according to the procedures in paragraphs (a)(1) or (a)(2) of this section, and default values are not available for a particular input gas and process type or sub-type combination in Tables I-3, I-4, I-5, I-6, or I-7, you must use the utilization and by-product formation rates of zero and use Equations I-8 and I-9 of this subpart.
(b) You must calculate annual fab-level N
Where:
(1) You must use the factor for N
(2) You must use the factor for N
(c) You must calculate total annual input gas i consumption on a fab basis for each fluorinated GHG and N
(d) You must calculate disbursements of input gas i using fab-wide gas-specific heel factors, as determined in § 98.94(b), and by using Equation I-12 of this subpart. Where a gas supply system serves more than one fab, Equation I-12 is applied to that gas which has been apportioned to each fab served by that system using the apportioning factors determined in accordance with § 98.94(c).
(e) You must calculate the amount of input gas i consumed, on a fab basis, for each process sub-type or process type j, using Equation I-13 of this subpart. Where a gas supply system serves more than one fab, Equation I-13 is applied to that gas which has been apportioned to each fab served by that system using the apportioning factors determined in accordance with § 98.94(c). If you elect to calculate emissions using the stack test method in paragraph (i) of this section, you must calculate the amount of input gas i consumed on the applicable basis by using an appropriate apportioning factor. For example, when calculating fab-level emissions of each fluorinated GHG consumed using Equation I-21 of this section, you must substitute the term fij with the appropriate apportioning factor to calculate the total consumption of each fluorinated GHG in tools that are vented to stack systems that are tested.
(f) [Reserved]
(g) If you report controlled emissions pursuant to § 98.94(f), you must calculate the uptime of all the abatement systems for each combination of input gas or by-product gas, and process sub-type or process type, by using Equation I-15 of this subpart.
(h) If you use fluorinated heat transfer fluids, you must calculate the annual emissions of fluorinated heat transfer fluids on a fab basis using the mass balance approach described in Equation I-16 of this subpart.
(1) If you use a fluorinated chemical both as a fluorinated heat transfer fluid and in other applications, you may calculate and report either emissions from all applications or from only those specified in the definition of
(2) [Reserved]
(i)
(1)
(i) When you are calculating preliminary estimates for the purpose of this paragraph (i)(1), you must consider the subscript “j” in Equations I-8 and I-9, and I-13 of this subpart to mean “stack system” instead of “process sub-type or process type.” For the value of a
(ii) You must use representative data from the previous reporting year to estimate the consumption of input gas i as calculated in Equation I-13 of this subpart and the fraction of input gas i and by-product gas k destroyed in abatement systems for each stack system as calculated by Equations I-24A and I-24B of this subpart. If you were not required to submit an annual report under subpart I for the previous reporting year and data from the previous reporting year are not available, you may estimate the consumption of input gas i and the fraction of input gas i destroyed in abatement systems based on representative operating data from a period of at least 30 days in the current reporting year. When calculating the consumption of input gas i using Equation I-13 of this subpart, the term “f
(iii) You must use representative data from the previous reporting year to estimate the total uptime of all abatement systems for the stack system as calculated by Equation I-23 of this subpart, instead of using Equation I-15 of this subpart to calculate the average uptime factor. If you were not required to submit an annual report under subpart I for the previous reporting year and data from the previous reporting year are not available, you may estimate the total uptime of all abatement systems for the stack system based on representative operating data from a period of at least 30 days in the current reporting year.
(iv) If you anticipate an increase or decrease in annual consumption or emissions of any fluorinated GHG, or the number of tools connected to abatement systems greater than 10 percent for the current reporting year compared to the previous reporting year, you must account for the anticipated change in your preliminary estimate. You may account for such a change using a quantifiable metric (
(2)
(i) The sum of annual emissions of fluorinated GHGs from all of the combined stack systems that are not tested in the fab must be less than 10,000 metric ton CO
(ii) When all stack systems in the fab are ordered from lowest to highest emitting in metric ton CO
(iii) Fluorinated GHG emissions from each of the stack systems that is not tested can only be attributed to particular process tools during the test (that is, the stack system that is not tested cannot be used as an alternative emission point or bypass stack system from other process tools not attributed to the untested stack system).
(3)
(i) You must measure, and, if applicable, apportion the fab-specific fluorinated GHG consumption of the tools that are vented to the stack systems that are tested during the emission test as specified in § 98.94(j)(3). Calculate the consumption for each fluorinated GHG for the test period.
(ii) You must calculate the emissions of each fluorinated GHG consumed as an input gas using Equation I-17 of this subpart and each fluorinated GHG formed as a by-product gas using Equation I-18 of this subpart and the procedures specified in paragraphs (i)(3)(ii)(A) through (E) of this section. If a stack system is comprised of multiple stacks, you must sum the emissions from each stack in the stack system when using Equation I-17 or Equation I-18 of this subpart.
(A) If a fluorinated GHG is consumed during the sampling period, but emissions are not detected, use one-half of the field detection limit you determined for that fluorinated GHG according to § 98.94(j)(2) for the value of “X
(B) If a fluorinated GHG is consumed during the sampling period and detected intermittently during the sampling period, use the detected concentration for the value of “X
(C) If an expected or possible by-product, as listed in Table I-17 of this subpart, is detected intermittently during the sampling period, use the measured concentration for “X
(D) If a fluorinated GHG is not consumed during the sampling period and is an expected by-product gas as listed in Table I-17 of this subpart and is not detected during the sampling period, use one-half of the field detection limit you determined for that fluorinated GHG according to § 98.94(j)(2) for the value of “X
(E) If a fluorinated GHG is not consumed during the sampling period and is a possible by-product gas as listed in Table I-17 of this subpart, and is not detected during the sampling period, then assume zero emissions for that fluorinated GHG for the tested stack system.
(iii) You must calculate a fab-specific emission factor for each fluorinated GHG input gas consumed (in kg of fluorinated GHG emitted per kg of input gas i consumed) in the tools that vent to stack systems that are tested, as applicable, using Equation I-19 of this subpart. If the emissions of input gas i exceed the consumption of input gas i during the sampling period, then equate “E
(iv) You must calculate a fab-specific emission factor for each fluorinated GHG formed as a by-product (in kg of fluorinated GHG per kg of total fluorinated GHG consumed) in the tools vented to stack systems that are tested, as applicable, using Equation I-20 of this subpart. When calculating the by-product emission factor for an input gas for which emissions exceeded its consumption, exclude the consumption of that input gas from the term “∑(Activity
(v) You must calculate annual fab-level emissions of each fluorinated GHG consumed using Equation I-21 of this section.
(vi) You must calculate annual fab-level emissions of each fluorinated GHG by-product formed using Equation I-22 of this section.
(vii) When using the stack testing method described in this paragraph (i), you must calculate abatement system uptime on a fab basis using Equation I-23 of this subpart. When calculating abatement system uptime for use in Equation I-19 and I-20 of this subpart, you must evaluate the variables “Td
(viii) When using the stack testing option described in paragraph (i) of this section, you must calculate the weighted-average fraction of each fluorinated input gas i and each fluorinated byproduct gas k destroyed or removed in abatement systems for each fab f, as applicable, by using Equation I-24A (for input gases) and Equation I-24B (for by-product gases) of this subpart.
(4)
(i) Calculate emissions from consumption of each intermittent low-use fluorinated GHG as defined in § 98.98 of this subpart using the default utilization and by-product formation rates and equations specified in paragraph (i)(4) of this section. If a fluorinated GHG was not being used during the stack testing and does not meet the definition of intermittent low-use fluorinated GHG in § 98.98, then you must test the stack systems associated with the use of that fluorinated GHG at a time when that gas is in use at a magnitude that would allow you to determine an emission factor for that gas according to the procedures specified in paragraph (i)(3) of this section.
(ii) Calculate emissions from consumption of each fluorinated GHG used in tools vented to stack systems that meet the criteria specified in paragraphs (i)(2)(i) through (i)(2)(iii) of this section, and were not tested according to the procedures in paragraph (i)(3) of this section. Calculate emissions using the default utilization and by-product formation rates and equations specified in paragraph (i)(4) of this section. If you are using a fluorinated GHG not listed in Tables I-11, I-12, I-13, I-14, or I-15 of this subpart, then you must assume utilization and by-product formation rates of zero for that fluorinated GHG.
(5) To determine the total emissions of each fluorinated GHG from each fab under this stack testing option, you must sum the emissions of each fluorinated GHG determined from the procedures in paragraph (i)(3) of this section with the emissions of the same fluorinated GHG determined from the procedures in paragraph (i)(4) of this section. Sum the total emissions of each fluorinated GHG from all fabs at your facility to determine the facility-level emissions of each fluorinated GHG.
(a) [Reserved]
(b) For purposes of Equation I-12 of this subpart, you must estimate fab-wide gas-specific heel factors for each container type for each gas used, according to the procedures in paragraphs (b)(1) through (b)(5) of this section. This paragraph (b) does not apply to fluorinated GHGs or N
(1) Base your fab-wide gas-specific heel factors on the trigger point for change out of a container for each container size and type for each gas used. Fab-wide gas-specific heel factors must be expressed as the ratio of the trigger point for change out, in terms of mass, to the initial mass in the container, as determined by paragraphs (b)(2) and (3) of this section.
(2) The trigger points for change out you use to calculate fab-wide gas-specific heel factors in paragraph (b)(1) of this section must be determined by monitoring the mass or the pressure of your containers. If you monitor the pressure, convert the pressure to mass using the ideal gas law, as displayed in Equation I-25 of this subpart, with the
(3) The initial mass you use to calculate a fab-wide gas-specific heel factor in paragraph (b)(1) of this section may be based on the weight of the gas provided to you in gas supplier documents; however, you remain responsible for the accuracy of these masses and weights under this subpart.
(4) If a container is changed in an exceptional circumstance, as specified in paragraphs (b)(4)(i) and (ii) of this section, you must weigh that container or measure the pressure of that container with a pressure gauge, in place of using a heel factor to determine the residual weight of gas. When using mass-based trigger points for change out, you must determine if an exceptional circumstance has occurred based on the net weight of gas in the container, excluding the tare weight of the container.
(i) For containers with a maximum storage capacity of less than 9.08 kg (20 lbs) of gas, an exceptional circumstance is a change out point that differs by more than 50 percent from the trigger point for change out used to calculate your fab-wide gas-specific heel factor for that gas and container type.
(ii) For all other containers, an exceptional circumstance is a change out point that differs by more than 20 percent from the trigger point for change out used to calculate your fab-wide gas-specific heel factor for that gas and container type.
(5) You must re-calculate a fab-wide gas-specific heel factor if you execute a process change to modify the trigger point for change out for a gas and container type that differs by more than 5 percent from the previously used trigger point for change out for that gas and container type.
(c) You must develop apportioning factors for fluorinated GHG and N
(1) You must demonstrate that the fluorinated GHG and N
(2) You must demonstrate the accuracy of your fab-specific model by comparing the actual amount of input gas i consumed and the modeled amount of input gas i consumed in the fab, as follows:
(i) You must analyze actual and modeled gas consumption for a period when the fab is at a representative operating level (as defined in § 98.98) lasting at least 30 days but no more than the reporting year.
(ii) You must compare the actual gas consumed to the modeled gas consumed for one fluorinated GHG reported under this subpart for the fab. You must certify that the fluorinated GHG selected for comparison corresponds to the largest quantity, on a mass basis, of fluorinated GHG consumed at the fab during the reporting year for which you are required to apportion following the procedures specified in § 98.93(a),
(iii) You must demonstrate that the comparison performed for the largest quantity of gas(es), on a mass basis, consumed in the fab in paragraph (c)(2)(ii) of this section, does not result in a difference between the actual and modeled gas consumption that exceeds 20 percent relative to actual gas consumption, reported to two significant figures using standard rounding conventions.
(iv) If you are required to apportion gas consumption and you use the procedures in § 98.93(i) to calculate annual emissions from a fab, you must verify your apportioning factors using the procedures in paragraphs (c)(2)(ii) and (iii) of this section such that the time period specified in paragraph (c)(2)(i) of this section and the last day you perform the sampling events specified under § 98.93(i)(3) occur in the same accounting month.
(v) If your facility has multiple fabs with a single centralized fluorinated-GHG supply system, you must verify that your apportioning model can apportion fluorinated GHG consumption among the fabs by adhering to the procedures in paragraphs (c)(2)(ii) through (c)(2)(iv) of this section.
(3) As an alternative to developing apportioning factors for fluorinated GHG and N
(d)-(e) [Reserved]
(f) If your fab employs abatement systems and you elect to reflect emission reductions due to these systems, or if your fab employs abatement systems designed for fluorinated GHG abatement and you elect to calculate fluorinated GHG emissions using the stack test method under § 98.93(i), you must comply with the requirements of paragraphs (f)(1) through (3) of this section. If you use an average of properly measured destruction or removal efficiencies for a gas and process sub-type or process type combination, as applicable, in your emission calculations under § 98.93(a), (b), and/or (i), you must also adhere to procedures in paragraph (f)(4) of this section.
(1) You must certify and document that the abatement systems are properly installed, operated, and maintained according to the site maintenance plan for abatement systems that is developed and maintained in your records as specified in § 98.97(d)(9).
(2) You must calculate and document the uptime of abatement systems using Equation I-15 or I-23 of this subpart, as applicable.
(3) If you use default destruction and removal efficiency values in your emissions calculations under § 98.93(a), (b), and/or (i), you must certify and document that the abatement systems at your facility for which you use default destruction or removal efficiency values are specifically designed for fluorinated GHG or N
(4) If you do not use the default destruction or removal efficiency values in Table I-16 of this subpart to calculate and report controlled emissions, including situations in which your fab employs abatement systems not specifically designed for fluorinated GHG or N
(i) A properly measured destruction or removal efficiency value must be determined in accordance with EPA 430-R-10-003 (incorporated by reference, see § 98.7), or according to an alternative method approved by the Administrator (or authorized representative) as specified in paragraph (k) of this section. If you are measuring destruction or removal efficiency according to EPA 430-R-10-003 (incorporated by reference, see § 98.7), you may follow the alternative procedures specified in Appendix A to this subpart.
(ii) You must select and properly measure the destruction or removal efficiency for a random sample of abatement systems to include in a random sampling abatement system testing program in accordance with procedures in paragraphs (f)(4)(ii)(A) and (B) of this section.
(A) For the first 2 years for which your fab is required to report emissions of fluorinated GHG and N
(B) If testing of a randomly selected abatement system would be disruptive to production, you may replace that system with another randomly selected system for testing and return the system to the sampling pool for subsequent testing. Any one abatement system must not be replaced by another randomly selected system for more than three consecutive selections. When you have to replace a system in one year, you may select that specific system to be tested in one of the next two sampling years so that you may plan testing of that abatement system to avoid disrupting production.
(iii) If you elect to take credit for abatement system destruction or removal efficiency before completing testing on 20 percent of the abatement systems for that gas and process sub-type or process type combination, as applicable, you must use default destruction or removal efficiencies for a gas and process type combination. You must not use a default value from Table I-16 of this subpart for any abatement system not specifically designed for fluorinated GHG and N
(iv) If a measured destruction or removal efficiency is below the manufacturer-claimed fluorinated GHG or N
(v) If a measured destruction or removal efficiency is below the manufacturer-claimed fluorinated GHG or N
(vi) If your fab uses redundant abatement systems, you may account for the total abatement system uptime (that is, the time that at least one abatement system is in operational mode) calculated for a specific exhaust stream during the reporting year.
(g) You must adhere to the QA/QC procedures of this paragraph when calculating fluorinated GHG and N
(1)-(2) [Reserved]
(3) Follow the QA/QC procedures in accordance with those in EPA 430-R-10-003 (incorporated by reference, see § 98.7), or the applicable QA/QC procedures specified in an alternative method approved by the Administrator (or authorized representative) according to paragraph (k) of this section, when calculating abatement systems destruction or removal efficiencies. If you are measuring destruction or removal efficiency according to EPA 430-R-10-003 (incorporated by reference, see § 98.7), and you elect to follow the alternative procedures specified in Appendix A to this subpart according to paragraph (f)(4)(i) of this section, you must follow any additional QA/QC procedures specified in Appendix A to this subpart.
(4) As part of normal operations for each fab, the inventory of gas stored in containers at the beginning of the reporting year must be the same as the inventory of gas stored in containers at the end of the previous reporting year. You must maintain records documenting the year end and year beginning inventories under § 98.97(a).
(h) You must adhere to the QA/QC procedures of this paragraph (h) when calculating annual gas consumption for each fluorinated GHG and N
(1) Review all inputs to Equations I-11 and I-16 of this subpart to ensure that all inputs and outputs are accounted for.
(2) Do not enter negative inputs into the mass balance Equations I-11 and I-16 of this subpart and ensure that no negative emissions are calculated.
(3) Ensure that the inventory at the beginning of one reporting year is identical to the inventory at the end of the previous reporting year. You must maintain records documenting the year end and year beginning inventories under § 98.97(a) and (r).
(4) Ensure that the total quantity of gas i in containers in service at the end of a reporting year is accounted for as if the in-service containers were full for Equation I-11 of this subpart. Ensure also that the same quantity is accounted for in the inventory of input gas i stored in containers at the beginning of the subsequent reporting year.
(i) All flow meters, weigh scales, pressure gauges, and thermometers used to measure quantities that are monitored under this section or used in calculations under § 98.93 must meet the calibration and accuracy requirements specified in § 98.3(i).
(j)
(1)
(i) You must conduct an emission test during which the fab is operating at a representative operating level, as defined in § 98.98, and with the abatement systems connected to the stack system being tested operating with at least 90 percent uptime, averaged over all abatement systems, during the 8-hour (or longer) period for each stack system, or at no less than 90 percent of the abatement system uptime rate measured over the previous reporting year, averaged over all abatement systems.
(ii) You must measure for the expected and possible by-products identified in Table I-17 of this subpart and those fluorinated GHGs used as input fluorinated GHG in process tools vented to the stack system, except for any intermittent low-use fluorinated GHG as defined in § 98.98. You must calculate annual emissions of intermittent low-use fluorinated GHGs by adhering to the procedures in § 98.93(i)(4)(i).
(iii) If a fluorinated GHG being consumed in the reporting year was not being consumed during the stack testing and does not meet the definition of intermittent low-use fluorinated GHG in § 98.98, then you must test the stack systems associated with the use of that fluorinated GHG at a time when that gas is in use at a magnitude that would allow you to determine an emission factor for that gas. If a fluorinated GHG consumed in the reporting year was not being consumed during the stack testing and is no longer in use by your fab (e.g., use of the gas has become obsolete or has been discontinued), then you must calculate annual emissions for that fluorinated GHG according to the procedure specified in § 98.93(i)(4).
(iv) Although all applicable stack systems are not required to be tested simultaneously, you must certify that no significant changes in stack flow configuration occur between tests conducted for any particular fab in a reporting year. You must certify that no more than 10 percent of the total number of fluorinated GHG emitting process tools are connected or disconnected from a stack system during testing. You must also certify that no process tools that were in operation at the start of the test period have been
(2)
(3)
(i) Measure fluorinated GHG consumption using gas flow meters, scales, or pressure measurements. Measure the mass or pressure, as applicable, at the beginning and end of the sampling period and when containers are changed out. If you elect to measure gas consumption using pressure (i.e., because the gas is stored in a location above its critical temperature) you must estimate consumption as specified in paragraphs (j)(3)(i)(A) and (B) of this section.
(A) For each fluorinated GHG, you must either measure the temperature of the fluorinated GHG container(s) when the sampling periods begin and end and when containers are changed out, or measure the temperature of the fluorinated GHG container(s) every hour for the duration of the sampling period. Temperature measurements of the immediate vicinity of the containers (e.g., in the same room, near the containers) shall be considered temperature measurements of the containers.
(B) Convert the sampling period-beginning, sampling period-ending, and container change-out pressures to masses using Equation I-25 of this subpart, with the appropriate Z value selected based upon the properties of the gas (e.g., the Z value yielded by the Redlich, Kwong, Soave equation of state with appropriate values for that gas). Apply the temperatures measured at or nearest to the beginning and end of the sampling period and to the time(s) when containers are changed out, as applicable. For each gas, the consumption during the sampling period is the difference between the masses of the containers of that gas at the beginning and at the end of the sampling period, summed across containers, including containers that are changed out.
(ii) For each fluorinated GHG gas for which consumption is too low to be accurately measured during the sampling period using gas flow meters, scales, or pressure measurements as specified in paragraph (j)(3)(i) of this section, you must follow at least one of the procedures listed in paragraph (j)(3)(ii)(A) through (C) of this section to obtain a consumption measurement.
(A) Draw the gas from a single gas container if it is normally supplied from multiple containers connected by a shared manifold.
(B) Calculate consumption from pro-rated long-term consumption data (for
(C) Increase the duration of the sampling period for consumption measurement beyond the minimum duration specified in Table I-9 of this subpart.
(4)
(5)
(i)
(ii)
(B) The relative standard deviation for all single fluorinated GHGs that individually accounted for 5 percent or more of CO
(6)
(7)
(i) Notify the Administrator (or an authorized representative) of your intention to use the results of the previous emissions testing. You must include in the notification the data and results you intend to use for meeting either reporting or recordkeeping requirements, a description of the method, and any deviations from the requirements in paragraph (j)(2) of this section. Your description must include an explanation of how any deviations do not affect the quality of the data collected.
(ii) The Administrator will review the information submitted under paragraph (j)(7)(i) and determine whether the results of the previous emissions testing are adequate and issue an approval or disapproval of the use of the results within 120 days of the date on which you submit the notification specified in paragraph (j)(7)(i) of this section.
(iii) If the Administrator finds reasonable grounds to disapprove the results of the previous emissions testing, the Administrator may request that you provide additional information to support the use of the results of the previous emissions testing. Failure to respond to any request made by the Administrator does not affect the 120 day deadline specified in paragraph (j)(7)(ii) of this section.
(iv) Neither the approval process nor the failure to obtain approval for the use of results from previous emissions testing shall abrogate your responsibility to comply with the requirements of this subpart.
(8)
(i) Annual consumption of a fluorinated GHG used during the most recent emissions test (expressed in CO
(ii) A change in the consumption of an intermittent low-use fluorinated GHG (as defined in § 98.98) that was not used during the emissions test and not reflected in the fab-specific emission factor, such that it no longer meets the definition of an intermittent low-use fluorinated GHG.
(iii) A decrease by more than 10 percent in the fraction of tools with abatement systems, compared to the number during the most recent emissions test.
(iv) A change in the wafer size manufactured by the fab since the most recent emissions test.
(v) A stack system that formerly met the criteria specified under § 98.93(i)(2) for not being subject to testing no longer meets those criteria.
(vi) If a fluorinated GHG being consumed in the reporting year was not being consumed during the stack test and does not meet the definition of intermittent, low-use fluorinated GHG in § 98.98, then you must test the stack
(k) You may request approval to use an alternative stack test method and procedure or to use an alternative method to determine abatement system destruction or removal efficiency by adhering to the requirements in paragraphs (k)(1) through (6) of this section. An alternative method is any method of sampling and analyzing for a fluorinated GHG or N
(1) You may use an alternative method from that specified in this subpart provided that you:
(i) Notify the Administrator (or an authorized representative) of your intention to use an alternative method. You must include in the notification a site-specific test plan describing the alternative method and procedures (the alternative test plan), the range of test conditions over which the validation is intended to be applicable, and an alternative means of calculating the fab-level fluorinated GHG or N
(ii) Use Method 301 in appendix A of part 63 of this chapter to validate the alternative method. This may include the use of only portions of specific procedures of Method 301 if use of such procedures are sufficient to validate the alternative method; and
(iii) Submit the results of the Method 301 validation process along with the notification of intention and the rationale for not using the specified method.
(2) The Administrator will determine whether the validation of the proposed alternative method is adequate and issue an approval or disapproval of the alternative test plan within 120 days of the date on which you submit the notification and alternative test plan specified in paragraph (k)(1) of this section. If the Administrator approves the alternative test plan, you are authorized to use the alternative method(s) in place of the methods described in paragraph (f)(4)(i) of this section for measuring destruction or removal efficiency or paragraph (j) of this section for conducting the stack test, as applicable, taking into account the Administrator's comments on the alternative test plan. Notwithstanding the requirement in the preceding sentence, you may at any time prior to the Administrator's approval or disapproval proceed to conduct the stack test using the methods specified in paragraph (j) of this section or the destruction or removal efficiency determination specified in (f)(4)(i) of this section if you use a method specified in this subpart instead of the requested alternative. If an alternative test plan is not approved and you still want to use an alternative method, you must recommence the process to have an alternative test method approved starting with the notification of intent to use an alternative test method specified in paragraph (k)(1)(i) of this section.
(3) You must report the results of stack testing or destruction or removal efficiency determination using the alternative method and procedure specified in the approved alternative test plan. You must include in your report for an alternative stack test method and for an alternative abatement system destruction or removal efficiency determination the information specified in paragraph (j)(4) of this section, including all methods, calculations and data used to determine the fluorinated GHG emission factor or the abatement system destruction or removal efficiency. The Administrator will review the results of the test using the alternative methods and procedure and then approve or deny the use of the results of the alternative test method and procedure no later than 120 days after they are submitted to EPA.
(4) If the Administrator finds reasonable grounds to dispute the results obtained by an alternative method for
(5) Once the Administrator has approved the use of the alternative method for the purposes of determining fluorinated GHG emissions for specific fluorinated GHGs and types of stack systems or abatement system destruction or removal efficiency, that method may be used at any other facility for the same fluorinated GHGs and types of stack systems, or fluorinated GHGs and abatement systems, if the approved conditions apply to that facility. In granting approval, the Administrator may limit the range of test conditions and emission characteristics for which that approval is granted and under which the alternative method may be used without seeking approval under paragraphs (k)(1) through (4) of this section. The Administrator will specify those limitations, if any, in the approval of the alternative method.
(6) Neither the validation and approval process nor the failure to validate or obtain approval of an alternative method shall abrogate your responsibility to comply with the requirements of this subpart.
(a) Except as provided in paragraph (b) of this section, a complete record of all measured parameters used in the fluorinated GHG and N
(b) If you use fluorinated heat transfer fluids at your facility and are missing data for one or more of the parameters in Equation I-16 of this subpart, you must estimate fluorinated heat transfer fluid emissions using the arithmetic average of the emission rates for the reporting year immediately preceding the period of missing data and the months immediately following the period of missing data. Alternatively, you may estimate missing information using records from the fluorinated heat transfer fluid supplier. You must document the method used and values used for all missing data values.
In addition to the information required by § 98.3(c), you must include in each annual report the following information for each electronics manufacturing facility:
(a) Annual manufacturing capacity of each fab at your facility used to determine the annual manufacturing capacity of your facility in Equation I-5 of this subpart.
(b) For facilities that manufacture semiconductors, the diameter of wafers manufactured at each fab at your facility (mm).
(c) Annual emissions, on a fab basis as described in paragraph (c)(1) through (5) of this section.
(1) When you use the procedures specified in § 98.93(a) of this subpart, each fluorinated GHG emitted from each process type for which your fab is required to calculate emissions as calculated in Equations I-6 and I-7 of this subpart.
(2) When you use the procedures specified in § 98.93(a), each fluorinated GHG emitted from each process type or process sub-type as calculated in Equations I-8 and I-9 of this subpart, as applicable.
(3) N
(4) Each fluorinated heat transfer fluid emitted as calculated in Equation 1-16 of this subpart.
(5) When you use the procedures specified in § 98.93(i) of this subpart, annual emissions of each fluorinated GHG, on a fab basis.
(d) The method of emissions calculation used in § 98.93 for each fab.
(e) Annual production in terms of substrate surface area (
(f)-(l) [Reserved]
(m) For the fab-specific apportioning model used to apportion fluorinated GHG and N
(1) Identification of the quantifiable metric used in your fab-specific engineering model to apportion gas consumption for each fab, and/or an indication if direct measurements were used in addition to, or instead of, a quantifiable metric.
(2) The start and end dates selected under § 98.94(c)(2)(i).
(3) Certification that the gas(es) you selected under § 98.94(c)(2)(ii) for each fab corresponds to the largest quantity(ies) consumed, on a mass basis, of fluorinated GHG used at your fab during the reporting year for which you are required to apportion.
(4) The result of the calculation comparing the actual and modeled gas consumption under § 98.94(c)(2)(iii) and (iv), as applicable.
(5) If you are required to apportion fluorinated GHG consumption between fabs as required by § 98.94(c)(2)(v), certification that the gas(es) you selected under § 98.94(c)(2)(ii) corresponds to the largest quantity(ies) consumed on a mass basis, of fluorinated GHG used at your facility during the reporting year for which you are required to apportion.
(n)-(o) [Reserved]
(p) Inventory and description of all abatement systems through which fluorinated GHGs or N
(1) The number of abatement systems controlling emissions for each process sub-type, or process type, as applicable, for each gas used in the process sub-type or process type.
(2) The basis of the destruction or removal efficiency being used (default or site specific measurement according to § 98.94(f)(4)(i)) for each process sub-type or process type and for each gas.
(q) For all abatement systems through which fluorinated GHGs or N
(1) Certification that all abatement systems at the facility have been installed, maintained, and operated in accordance with the site maintenance plan for abatement systems that is developed and maintained in your records as specified in § 98.97(d)(9).
(2) If you use default destruction or removal efficiency values in your emissions calculations under § 98.93(a), (b), or (i), certification that the site maintenance plan for abatement systems for which emissions are being reported contains manufacturer's recommendations and specifications for installation, operation, and maintenance for each abatement system.
(3) If you use default destruction or removal efficiency values in your emissions calculations under § 98.93(a), (b), and/or (i), certification that the abatement systems for which emissions are being reported were specifically designed for fluorinated GHG or N
(4) For all stack systems for which you calculate fluorinated GHG emissions according to the procedures specified in § 98.93(i)(3), certification that you have included and accounted for all abatement systems and any respective downtime in your emissions calculations under § 98.93(i)(3).
(r) You must report an effective fab-wide destruction or removal efficiency value for each fab at your facility calculated using Equation I-26, I-27, and I-28 of this subpart, as appropriate.
(1) Use Equation I-27 of this subpart to calculate total unabated emissions, in metric tons CO
(2) Use Equation I-28 to calculate total unabated emissions, in metric ton CO
(s) Where missing data procedures were used to estimate inputs into the fluorinated heat transfer fluid mass balance equation under § 98.95(b), the number of times missing data procedures were followed in the reporting year and the method used to estimate the missing data.
(t)-(v) [Reserved]
(w) If you elect to calculate fab-level emissions of fluorinated GHG using the stack test methods specified in § 98.93(i), you must report the following in paragraphs (w)(1) and (2) for each stack system, in addition to the relevant data in paragraphs (a) through (v) of this section:
(1) The date of any stack testing conducted during the reporting year, and the identity of the stack system tested.
(2) An inventory of all stack systems from which process fluorinated GHG are emitted. For each stack system, indicate whether the stack system is among those for which stack testing was performed as per § 98.93(i)(3) or not performed as per § 98.93(i)(2).
(x) If the emissions you report under paragraph (c) of this section include emissions from research and development activities, as defined in § 98.6, report the approximate percentage of total GHG emissions, on a metric ton CO
(y) If your semiconductor manufacturing facility emits more than 40,000 metric ton CO
(1) The first report must be submitted with the annual GHG emissions report that is due no later than March 31, 2017, and subsequent reports must be delivered every 3 years no later than March 31 of the year in which it is due.
(2) The report must include the information described in paragraphs (y)(2)(i) through (v) of this section.
(i) It must describe how the gases and technologies used in semiconductor manufacturing using 200 mm and 300
(ii) It must describe the effect on emissions of the implementation of new process technologies and/or finer line width processes in 200 mm and 300 mm technologies, the introduction of new tool platforms, and the introduction of new processes on previously tested platforms.
(iii) It must describe the status of implementing 450 mm wafer technology and the potential need to create or update default emission factors compared to 300 mm technology.
(iv) It must provide any utilization and byproduct formation rates and/or destruction or removal efficiency data that have been collected in the previous 3 years that support the changes in semiconductor manufacturing processes described in the report. For any utilization or byproduct formation rate data submitted, the report must include the input gases used and measured, the utilization rates measured, the byproduct formation rates measured, the process type, the process subtype for chamber clean processes, the wafer size, and the methods used for the measurements. For any destruction or removal efficiency data submitted, the report must include the input gases used and measured, the destruction and removal efficiency measured, the process type, and the methods used for the measurements.
(v) It must describe the use of a new gas, use of an existing gas in a new process type or sub-type, or a fundamental change in process technology.
(3) If, on the basis of the information reported in paragraph (y)(2) of this section, the report indicates that GHG emissions from semiconductor manufacturing may have changed from those represented by the default utilization and by-product formation rates in Tables I-3 or I-4, or the default destruction or removal efficiency values in Table I-16 of this subpart, the report must lay out a data gathering and analysis plan focused on the areas of potential change. The plan must describe the elements in paragraphs (y)(3)(i) and (ii).
(i) The testing of tools to determine the potential effect on current utilization and by-product formation rates and destruction or removal efficiency values under the new conditions.
(ii) A planned analysis of the effect on overall facility emissions using a representative gas-use profile for a 200 mm, 300 mm, or 450 mm fab (depending on which technology is under consideration).
(4) Multiple semiconductor manufacturing facilities may submit a single consolidated 3-year report as long as the facility identifying information in § 98.3(c)(1) and the certification statement in § 98.3(c)(9) is provided for each facility for which the consolidated report is submitted.
(5) The Administrator will review the report received and determine whether it is necessary to update the default utilization rates and by-product formation rates in Tables I-3, I-4, I-11, and I-12 of this subpart and default destruction or removal efficiency values in Table I-16 of this subpart based on the following:
(i) Whether the revised default utilization and by-product formation rates and destruction or removal efficiency values will result in a projected shift in emissions of 10 percent or greater.
(ii) Whether new platforms, processes, or facilities that are not captured in current default utilization and by-product formation rates and destruction or removal efficiency values should be included in revised values.
(iii) Whether new data are available that could expand the existing data set to include new gases, tools, or processes not included in the existing data set (i.e. gases, tools, or processes for which no data are currently available).
(6) The Administrator will review the reports within 120 days and will notify you of a determination whether it is necessary to update any default utilization and by-product formation rates
In addition to the information required by § 98.3(g), you must retain the following records:
(a) All data used and copies of calculations made as part of estimating gas consumption and emissions, including all spreadsheets.
(b) [Reserved]
(c) Documentation for the fab-specific engineering model used to apportion fluorinated GHG and N
(1) A clear, detailed description of the fab-specific model, including how it was developed; the quantifiable metric used in the model; all sources of information, equations, and formulas, each with clear definitions of terms and variables; all apportioning factors used to apportion fluorinated GHG and N
(2) Sample calculations used for developing the gas apportioning factors (f
(3) If you develop apportioning factors through the use of direct measurement according to § 98.94(c)(3), calculations and data used to develop each gas apportioning factor.
(4) Calculations and data used to determine and document that the fab was operating at representative operating levels, as defined in § 98.98, during the apportioning model verification specified in § 98.94(c).
(d) For all abatement systems through which fluorinated GHGs or N
(1) Records of the information in paragraphs (d)(1)(i) though (iv) of this section:
(i) Documentation to certify that each abatement system or group of abatement systems is installed, maintained, and operated in accordance with the site maintenance plan for abatement systems that is specified in paragraph (d)(9) of this section.
(ii) Documentation from the abatement system supplier describing the abatement system's designed purpose and emission control capabilities for fluorinated GHG and N
(iii) If you use default destruction or removal efficiency values in your emissions calculations under § 98.93(a), (b), and/or (i), certification that the abatement systems for which emissions are being reported were specifically designed for fluorinated GHG and N
(iv) Certification that you have included and accounted for all abatement systems and any respective downtime in your emissions calculations under § 98.93(i)(3), as required under § 98.94(f)(3).
(2) Abatement system calibration and maintenance records.
(3) Where the default destruction or removal efficiency value is used, documentation from the abatement system supplier describing the equipment's designed purpose and emission control capabilities for fluorinated GHG and N
(4) Where properly measured site-specific destruction or removal efficiencies are used to report emissions, the information in paragraphs (d)(4)(i) though (vi) of this section:
(i) Dated certification by the technician who made the measurement that the destruction or removal efficiency is calculated in accordance with methods in EPA 430-R-10-003 (incorporated by reference, see § 98.7) and, if applicable Appendix A of this subpart, or an alternative method approved by the Administrator as specified in § 98.94(k), complete documentation of the results of any initial and subsequent tests, the final report as specified in EPA 430-R-10-003 (incorporated by reference, see § 98.7) and, if applicable, the records and documentation specified in Appendix A of this subpart including the information required in paragraph (b)(7) of Appendix A of this subpart, or a final report as specified in an alternative method approved by the Administrator as specified in § 98.94(k).
(ii) The average destruction or removal efficiency of the abatement systems operating during the reporting year for each process type and gas combination.
(iii) A description of the calculation used to determine the average destruction or removal efficiency for each process type and gas combination, including all inputs to the calculation.
(iv) The records of destruction or removal efficiency measurements for abatement systems for all tests that have been used to determine the site-specific destruction or removal efficiencies currently being used.
(v) A description of the method used for randomly selecting abatement systems for testing.
(vi) The total number of systems for which destruction or removal efficiency was properly measured for each process type and gas combination for the reporting year.
(5) In addition to the inventory specified in § 98.96(p), the information in paragraphs (d)(5)(i) through (iii) of this section:
(i) The number of abatement systems of each manufacturer, and model numbers, and the manufacturer's claimed fluorinated GHG and N
(ii) Records of destruction or removal efficiency measurements over the in-use life of each abatement system.
(iii) A description of the tool, with the process type or sub-type, for which the abatement system treats exhaust.
(6) Records of all inputs and results of calculations made accounting for the uptime of abatement systems used during the reporting year, in accordance with Equations I-15 or I-23 of this subpart, as applicable. The inputs should include an indication of whether each value for destruction or removal efficiency is a default value or a measured site-specific value.
(7) Records of all inputs and results of calculations made to determine the average weighted fraction of each gas destroyed or removed in the abatement systems for each stack system using Equations I-24A and I-24B of this subpart, if applicable. The inputs should include an indication of whether each value for destruction or removal efficiency is a default value or a measured site-specific value.
(8) Records of all inputs and the results of the calculation of the facility-wide emission destruction or removal efficiency factor calculated according to Equations I-26, I-27, and I-28 of this subpart.
(9) A site maintenance plan for abatement systems, which must be maintained on-site at the facility as part of the facility's GHG Monitoring Plan as described in § 98.3(g)(5), and be developed and implemented according to paragraphs (d)(9)(i) through (iii) of this section.
(i) The site maintenance plan for abatement systems must be based on the abatement system manufacturer's recommendations and specifications for installation, operation, and maintenance if you use default destruction and removal efficiency values in your emissions calculations under § 98.93(a), (b), and/or (i). If the manufacturer's recommendations and specifications for installation, operation, and maintenance are not available, you cannot use default destruction and removal efficiency values in your emissions calculations under § 98.93(a), (b), and/or (i). If you use an average of properly measured destruction or removal efficiencies determined in accordance with
(ii) The site maintenance plan for abatement systems must include a defined preventative maintenance process and checklist.
(iii) The site maintenance plan for abatement systems must include a corrective action process that you must follow whenever an abatement system is found to be not operating properly.
(e) Purchase records for gas purchased.
(f) Invoices for gas purchases and sales.
(g) Documents and records used to monitor and calculate abatement system uptime.
(h) GHG Monitoring Plans, as described in § 98.3(g)(5), must be completed by April 1, 2011. You must update your GHG Monitoring Plan to comply with § 98.94(c) consistent with the requirements in § 98.3(g)(5)(iii).
(i) Retain the following records for each fab for which you elect to calculate fab-level emissions of fluorinated GHG using the procedures specified in § 98.93(i)(3) or (4).
(1) Document all stack systems with emissions of fluorinated GHG that are less than 10,000 metric tons of CO
(2) For each stack system, identify the method used to calculate annual emissions; either § 98.93(i)(3) or (4).
(3) The identity and total annual consumption of each gas identified as an intermittent low use fluorinated GHG as specified in § 98.93(i)(4)(i) and defined in § 98.98.
(4) The emissions test data and reports (see § 98.94(j)(4)) and the calculations used to determine the fab-specific emission factor, including the actual fab-specific emission factor, the average hourly emission rate of each fluorinated GHG from the stack system during the test and the stack system activity rate during the test. The report must also contain any changes in the stack system configuration during or between tests in a reporting year.
(5) The fab-specific emission factor and the calculations and data used to determine the fab-specific emission factor for each fluorinated GHG and by-product, as calculated using Equations I-19 and I-20 of § 98.93(i)(3).
(6) Calculations and data used to determine annual emissions of each fluorinated GHG for each fab.
(7) Calculations and data used to determine and document that the fab was operating at representative operating levels, as defined in § 98.98, during the stack testing period.
(8) A copy of the certification that no significant changes in stack system flow configuration occurred between tests conducted for any particular fab in a reporting year, as required by § 98.94(j)(1)(iv) and any calculations and data supporting the certification.
(9) The number of tools vented to each stack system in the fab.
(j) If you report the approximate percentage of total GHG emissions from research and development activities under § 98.96(x), documentation for the determination of the percentage of total emissions of each fluorinated GHG and/or N
(k) Annual gas consumption for each fluorinated GHG and N
(l) All inputs used to calculate gas consumption in Equation I-11 of this
(m) Annual amount of each fluorinated GHG consumed for process sub-type, process type, stack system, or fab, as appropriate, and the annual amount of N
(n) Disbursements for each fluorinated GHG and N
(o) Fraction of each fluorinated GHG or N
(p) Fraction of each fluorinated GHG or N
(q) All inputs and results of calculations made accounting for the uptime of abatement systems used during the reporting year, or during an emissions sampling period, in accordance with Equations I-15 and/or I-23 of this subpart, as applicable.
(r) For fluorinated heat transfer fluid emissions, inputs to the fluorinated heat transfer fluid mass balance equation, Equation I-16 of this subpart, for each fluorinated heat transfer fluid used.
(s) Where missing data procedures were used to estimate inputs into the fluorinated heat transfer fluid mass balance equation under § 98.95(b), the estimates of those data.
Except as provided in this section, all of the terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. If a conflict exists between a definition provided in this subpart and a definition provided in subpart A, the definition in this subpart takes precedence for the reporting requirements in this subpart.
(1) In situ plasma process sub-type consists of the cleaning of thin-film production chambers, after processing
(2) Remote plasma process sub-type consists of the cleaning of thin-film production chambers, after processing substrates, with a fluorinated GHG cleaning reagent dissociated by a remotely located plasma source.
(3) In situ thermal process sub-type consists of the cleaning of thin-film production chambers, after processing substrates, with a fluorinated GHG cleaning reagent that is thermally dissociated into its cleaning constituents inside the chamber where thin films are produced.
(1) The fluorinated GHG is used by the fab but is not used during the period of stack testing for the fab/stack system.
(2) The emissions of the fluorinated GHG, estimated using the methods in § 98.93(i)(4) do not constitute more than 5 percent of the total fluorinated GHG emissions from the fab on a CO
(3) The sum of the emissions of all fluorinated GHGs that are considered intermittent low use gases does not exceed 10,000 metric tons CO
(4) The fluorinated GHG is not an expected or possible by-product identified in Table I-17 of this subpart.
If you are measuring destruction or removal efficiency of a point-of-use abatement device according to EPA 430-R-10-003 (incorporated by reference, see § 98.7) as specified in § 98.94(f)(4), you may follow the alternative procedures specified in paragraphs (a) through (c) of this appendix.
(a) In place of the Quadrupole Mass Spectrometry protocol requirements specified in section 2.2.4 of EPA 430-R-10-003 (incorporated by reference, see § 98.7), you must conduct mass spectrometry testing in accordance with the provisions in paragraph (a)(1) through (a)(15) of this appendix.
(1)
(2)
(3)
(4) Mass spectrometer parameters. The specific mass spectrometer operating conditions such as electron energy, secondary electron multiplier voltage, emission current, and ion focusing voltage must be selected according to the specifications provided by the mass spectrometer manufacturer, the mass spectrometer system manual, basic mass spectrometer textbook, or other such sources. The mass spectrometer responses to each of the target analytes must all be calibrated under the same mass spectrometer operating conditions.
(5)
(6)
(7)
(8)
(9)
(10)
(11)
(12)
(i) You must perform a qualitative mass calibration by running a standard (or by flowing chamber gases under non-process conditions) containing stable components such as Ar, Kr, and Xe that provide predominant signals at m/e values distributed throughout the mass range to be used. You must adjust the quadrupole mass filter as needed to align with the inert gas fragments.
(ii) You must quantitatively calibrate the quadrupole mass spectrometer for each analyte of interest. The analyte concentrations during calibration must include the expected concentrations in the process effluent. The calibration must be performed under the same operating conditions, such as inlet pressure, as when sampling process exhaust. If the calibration inlet pressure differs from the sampling inlet pressure then the relationship between inlet pressure and quadrupole mass spectrometer signal response must be empirically determined and applied to correct for any differences between calibration and process emissions monitoring data.
(iii) To determine the response time of the instrument to changes in a process, a process gas such as C
(iv) You must sample the process effluent through the quadrupole mass spectrometer and acquire data for the required amount of time to track the process, as determined in paragraph (a)(12)(iii) of this appendix. You
(v) You must repeat the quantitative calibration at the conclusion of sampling to identify any drifts in quadrupole mass spectrometer sensitivity. If drift is observed, you must use an internal standard to correct for changes in sensitivity.
(13)
(14)
(15)
(b) In place of the Fourier Transform Infrared Spectroscopy protocol requirements specified in section 2.2.4 of EPA 430-R-10-003 (incorporated by reference, see § 98.7), you may conduct Fourier Transform Infrared Spectroscopy testing in accordance with the provisions in paragraph (b)(1) through (17) of this appendix, including the laboratory study phase described in paragraphs (b)(1) through (7), and the field study phase described in paragraphs (b)(8) through (17) of this appendix.
(1)
(2)
(3)
(4)
(i) Reference spectra at the same absorbance level (to within 10 percent) of independently prepared samples must be recorded. The reference samples must be prepared from neat forms of the analyte or from gas
(ii) If a mercury cadmium telluride or other potentially non-linear detector (i.e., a detector whose response vs. total infrared power is not a linear function over the range of responses employed) is used for recording the reference spectra, you must correct for the effects of this type of response on the resulting concentration values. As needed, spectra of a calibration transfer standard must be recorded with the laboratory spectrometer system to verify the absorption pathlength and other aspects of the system performance. All reference spectral data must be recorded in interferometric form and stored digitally.
(5)
(6)
(7)
(8)
(9)
(10)
(11)
(12)
(13)
(14)
(15)
(16)
(17)
(i) The sampling lines employed should be as short as practically possible and not longer than those used in the field study.
(ii) Analyte spiking and reactivity checks are required after the installation of or major repair to the sampling system or major change in sample matrix. In these cases, perform three spiked/unspiked samples with calibration transfer standard or a surrogate analyte on a daily basis if time permits and gas standards are easy to obtain and get on-site.
(iii) Sampling and other operational data must be recorded and documented as during the field study, but only the interferometric data needed to sufficiently reproduce actual test and spiking data must be stored permanently. The format of this data does not need to be interferograms but may be absorbance spectra or single beams.
(c) When using the flow and dilution measurement protocol specified in section 2.2.6 of EPA 430-R-10-003 (incorporated by reference, see § 98.7), you may determine point-of-use abatement device total volume flow with the modifications specified in paragraphs (c)(1) through (3) of this appendix.
(1) You may introduce the non-reactive, non-native gas used for determining total volume flow and dilution across the point-of-use abatement device at a location in the exhaust of the point-of-use abatement device. For abatement systems operating in a mode where specific F-GHG are not readily abated, you may introduce the non-reactive, non-native gas used for determining total volume flow and dilution across the point-of-use abatement device prior to the point-of-use abatement system; in this case, the tracer must be more difficult to destroy than the target compounds being measured based on the thermal stability of the tracer and target.
(2) You may select a location for downstream non-reactive, non-native gas analysis that complies with the requirements in this paragraph (c)(2) of this appendix. The sampling location should be traversed with the sampling probe measuring the non-reactive, non-native gas concentrations to ensure homogeneity of the non-reactive gas and point-of-use abatement device effluent (i.e., stratification test). To test for stratification, measure the non-reactive, non-native gas concentrations at three points on a line passing through the centroidal area. Space the three points at 16.7, 50.0, and 83.3 percent of the measurement line. Sample for a minimum of twice the system response time, determined according to paragraph (c)(3) of this appendix, at each traverse point. Calculate the individual point and mean non-reactive, non-native gas concentrations. If the non-reactive, non-native gas concentration at each traverse point differs from the mean concentration for all traverse points by no more than ±5.0 percent of the mean concentration, the gas stream is considered unstratified and you may collect samples from a single point that most closely matches the mean. If the 5.0 percent criterion is not met, but the concentration at each traverse point differs from the mean concentration for all traverse points by no more than ±10.0 percent of the mean, you may take samples from two points and use the average of the two measurements. Space the two points at 16.7, 50.0, or 83.3 percent of the measurement line. If the concentration at each traverse point differs from the mean concentration for all traverse points by more than ±10.0 percent of the mean but less than 20.0 percent, take samples from three points at 16.7, 50.0, and 83.3 percent of the measurement line and use the average of the three measurements. If the gas stream is found to be stratified because the 20.0 percent criterion for a 3-point test is not met, locate and sample the non-reactive, non-native gas from traverse points for the test in accordance with Sections 11.2 and 11.3 of EPA Method 1 in 40 CFR part 60, Appendix A-1. A minimum of 40 non-reactive gas concentration measurements will be collected at three to five different injected non-reactive gas flow rates for determination of point-of-use abatement device effluent flow. The total volume flow of the point-of-use abatement device exhaust will be calculated consistent with the EPA 430-R-10-003 (incorporated by reference, see § 98.7) Equations 1 through 7.
(3) You must determine the measurement system response time according to paragraphs (c)(3)(i) through (iii) of this appendix.
(i) Before sampling begins, introduce ambient air at the probe upstream of all sample condition components in system calibration mode. Record the time it takes for the measured concentration of a selected compound (for example, carbon dioxide) to reach steady state.
(ii) Introduce nitrogen in the system calibration mode and record the time required for the concentration of the selected compound to reach steady state.
(iii) Observe the time required to achieve 95 percent of a stable response for both nitrogen and ambient air. The longer interval is the measurement system response time.
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.
You must report GHG emissions under this subpart if your facility contains a ferroalloy production process and the facility meets the requirements of either § 98.2(a)(1) or (2).
You must report:
(a) Process CO
(b) CO
You must calculate and report the annual process CO
(a) Calculate and report under this subpart the process CO
(b) Calculate and report under this subpart the annual process CO
(1) Calculate and report under this subpart the annual process CO
(2) Calculate and report under this subpart the annual process CO
(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
(ii) Determine the combined annual process CO
(c) If GHG emissions from an EAF are vented through the same stack as any combustion unit or process equipment that reports CO
(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
(1) For each EAF, determine the annual CH
(2) Determine the combined process CH
If you determine annual process CO
(a) Determine the annual mass for each material used for the calculations of annual process CO
(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
(ii) ASTM D5373-08 Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference,
(iii) ASTM C25-06, Standard Test Methods for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime (incorporated by reference,
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
(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
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) If a CEMS is used to measure CO
(c) Total number of EAFs at facility used for production of ferroalloy products.
(d) If a CEMS is used to measure CO
(1) Annual process CO
(2) Annual process CH
(3) Identification number of each EAF.
(e) If a CEMS is not used to measure CO
(1) Annual process CO
(2) Annual process CH
(3) Identification number for each material.
(4)-(5) [Reserved]
(6) List the method used for the determination of carbon content for each material included for the calculation of annual process CO
(7) If you use the missing data procedures in § 98.115(b), you must report
In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) through (e) of this section for each EAF, as applicable.
(a) If a CEMS is used to measure CO
(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
(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
(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
(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
(e)
(1) Carbon content in reducing agent (percent by weight, expressed as a decimal fraction) (Equation K-1 of § 98.113).
(2) Annual mass of reducing agent fed, charged, or otherwise introduced into the EAF (tons) (Equation K-1).
(3) Carbon content of carbon electrode (percent by weight, expressed as a decimal fraction) (Equation K-1).
(4) Annual mass of carbon electrode consumed in the EAF (tons) (Equation K-1).
(5) Carbon content in ore (percent by weight, expressed as a decimal fraction) (Equation K-1).
(6) Annual mass of ore charged to the EAF (tons) (Equation K-1).
(7) Carbon content in flux material (percent by weight, expressed as a decimal fraction) (Equation K-1).
(8) Annual mass of flux material fed, charged, or otherwise introduced into the EAF to facilitate slag formation (tons) (Equation K-1).
(9) Carbon content in alloy product (percent by weight, expressed as a decimal fraction) (Equation K-1).
(10) Annual mass of alloy product produced/tapped in the EAF (tons) (Equation K-1).
(11) Carbon content in non-product outgoing material (percent by weight, expressed as a decimal fraction) (Equation K-1).
(12) Annual mass of non-product outgoing material removed from EAF (tons) (Equation K-1).
(13) CH
All terms used of this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
75 FR 74831, Dec. 1, 2010, unless otherwise noted.
(a) The fluorinated gas production source category consists of processes that produce a fluorinated gas from any raw material or feedstock chemical, except for processes that generate HFC-23 during the production of HCFC-22.
(b) To produce a fluorinated gas means to manufacture a fluorinated gas from any raw material or feedstock chemical. Producing a fluorinated gas includes producing a fluorinated GHG as defined at § 98.410(b). Producing a fluorinated gas also includes the manufacture of a chlorofluorocarbon (CFC) or hydrochlorofluorocarbon (HCFC) from any raw material or feedstock chemical, including manufacture of a CFC or HCFC as an isolated intermediate for use in a process that will result in the transformation of the CFC or HCFC either at or outside of the production facility. Producing a fluorinated gas does not include the reuse or recycling of a fluorinated gas, the creation of HFC-23 during the production of HCFC-22, the creation of intermediates that are created and transformed in a single process with no storage of the intermediates, or the creation of fluorinated GHGs that are released or destroyed at the production facility before the production measurement in § 98.414(a).
You must report GHG emissions under this subpart if your facility contains a fluorinated gas production process that generates or emits fluorinated GHG and the facility meets the requirements of either § 98.2(a)(1) or (a)(2). To calculate GHG emissions for comparison to the 25,000 metric ton CO
(a) You must report CO
(b) You must report under subpart O of this part (HCFC-22 Production and HFC-23 Destruction) the emissions of HFC-23 from HCFC-22 production processes and HFC-23 destruction processes. Do not report the generation and emissions of HFC-23 from HCFC-22 production under this subpart.
(c)
(1) Each fluorinated gas production process.
(2) Each fluorinated gas transformation process that is not part of a fluorinated gas production process and where no fluorinated GHG reactant is produced at another facility.
(3) Each fluorinated gas transformation process that is not part of a fluorinated gas production process and where one or more fluorinated GHG reactants are produced at another facility.
(d)
(e)
(f)
(1) Each fluorinated gas destruction process that is not part of a fluorinated gas production process or a fluorinated gas transformation process and all such fluorinated gas destruction processes combined.
(2) Venting of residual fluorinated GHGs from containers returned from the field.
For fluorinated gas production and transformation processes, you must calculate the fluorinated GHG emissions from each process using the emission factor or emission calculation factor method specified in paragraphs (c), (d), and (e) of this section, as appropriate. For destruction processes that destroy fluorinated GHGs that were previously “produced” as defined at § 98.410(b), you must calculate emissions using the procedures in paragraph (f) of this section. For venting of residual gas from containers (
(a) [Reserved]
(b)
(c)
(1)
(i)
(A) U.S. Environmental Protection Agency, Emission Inventory Improvement Program, Volume II: Chapter 16, Methods for Estimating Air Emissions from Chemical Manufacturing Facilities, August 2007, Final (incorporated by reference, see § 98.7).
(B) You may determine the fluorinated GHG emissions from any process vent within the process using the procedures specified in § 63.1257(d)(2)(i) and (d)(3)(i)(B) of this chapter, except as specified in paragraphs (c)(1)(i)(B)(
(
(
(
(
(
(
(
(
(
(
(
(
(
(C) Commercial software products that follow chemical engineering principles (e.g., including the calculation methodologies in paragraphs (c)(1)(i)(A) and (c)(1)(i)(B) of this section).
(ii)
(A) Previous test results, provided the tests are representative of current operating practices of the process.
(B) Bench-scale or pilot-scale test data representative of the process operating conditions.
(C) Maximum flow rate, fluorinated GHG emission rate, concentration, or other relevant parameters specified or implied within a permit limit applicable to the process vent.
(D) Design analysis based on chemical engineering principles, measureable process parameters, or physical or chemical laws or properties.
(iii)
(A) The destruction efficiencies of the device that have been demonstrated for the fluorinated GHGs in the vent stream for periods when the process vent is vented to the destruction device.
(B) Any periods when the process vent is not vented to the destruction device.
(iv)
(v)
(vi) [Reserved]
(2)
(i) If the calculations under paragraph (c)(1) of this section, as well as any subsequent measurements and calculations under this subpart, indicate
(ii) If the continuous process vent does not meet the criteria in paragraph (c)(2)(i) of this section, then you must comply with the emission factor method specified in paragraph (c)(3) (Emission Factor approach) of this section.
(A) You must conduct emission testing for process-vent-specific emission factor development before the destruction device unless the calculations you performed under paragraph (c)(1)(iii) of this section indicate that the uncontrolled fluorinated GHG emissions that occur during periods when the process vent is not vented to the properly functioning destruction device are less than 10,000 metric tons CO
(B) Regardless of the level of uncontrolled emissions, the emission testing for process-vent-specific emission factor development may be conducted on the outlet side of a wet scrubber in place for acid gas reduction, if one is in place, as long as there is no appreciable reduction in the fluorinated GHG.
(3)
(i) Conduct a separate emissions test for operation under each operating scenario.
(ii) Conduct an emissions test for the operating scenario that is expected to have the largest emissions in terms of CO
(iii) You must measure the process activity, such as the process feed rate, process production rate, or other process activity rate, as applicable, during the emission test and calculate the rate for the test period, in kg (or another appropriate metric) per hour.
(iv) For continuous processes, you must calculate the hourly emission rate of each fluorinated GHG using Equation L-19 of this section and determine the hourly emission rate of each fluorinated GHG per process vent (and per operating scenario, as applicable) for the test run.
(v) You must calculate a site-specific, process-vent-specific emission factor for each fluorinated GHG for each process vent and each operating scenario, in kg of fluorinated GHG per process activity rate (e.g., kg of feed or production), as applicable, using Equation L-20 of this section. For continuous processes, divide the hourly fluorinated GHG emission rate during the test by the hourly process activity rate during the test runs.
(vi) If you conducted emissions testing after the destruction device, you must calculate the emissions of each fluorinated GHG for the process vent (and operating scenario, as applicable) using Equation L-21 of this section. You must also develop a process-vent-specific emission calculation factor based on paragraph (c)(4) of this section for the periods when the process vent is not venting to the destruction device.
(vii) If you conducted emissions testing before the destruction device, apply the destruction efficiencies of the device that have been demonstrated for the fluorinated GHGs in the vent stream to the fluorinated GHG emissions for the process vent (and operating scenario, as applicable), using Equation L-22 of this section. You may apply the destruction efficiency only to the portion of the process activity during which emissions are vented to the properly functioning destruction device (i.e., controlled).
(viii)
(ix) Sum the emissions of each fluorinated GHG from all process vents in each operating scenario and all operating scenarios in the process for the year to estimate the total process vent emissions of each fluorinated GHG from the process, using Equation L-24 of this section.
(4)
(i) You must calculate uncontrolled emissions of fluorinated GHG by individual process vent, E
(ii) You must calculate a site-specific, process-vent-specific emission calculation factor for each process vent, each operating scenario, and each fluorinated GHG, in kg of fluorinated GHG per activity rate (e.g., kg of feed or production) as applicable, using Equation L-25 of this section.
(iii) You must calculate emissions of each fluorinated GHG for the process vent (and operating scenario, as applicable) for the year by multiplying the process-vent-specific emission calculation factor by the total process activity, as applicable, for the year, using Equation L-26 of this section.
(iv) If the process vent is vented to a destruction device, apply the demonstrated destruction efficiency of the device to the fluorinated GHG emissions for the process vent (and operating scenario, as applicable), using Equation L-27 of this section. Apply the destruction efficiency only to the portion of the process activity that is vented to the properly functioning destruction device (i.e., controlled).
(v) Sum the emissions of each fluorinated GHG from all process vents in each operating scenario and all operating scenarios in the process for the year to estimate the total process vent emissions of each fluorinated GHG from the process, using Equation L-28 of this section.
(d)
(1) The emissions from equipment leaks must be calculated using any of the procedures in paragraphs (d)(1)(i), (d)(1)(ii), (d)(1)(iii), or (d)(1)(iv) of this section.
(i)
(ii)
(iii)
(iv)
(2) You must collect information on the number of each type of equipment; the service of each piece of equipment (gas, light liquid, heavy liquid); the concentration of each fluorinated GHG in the stream; and the time period each piece of equipment was in service. Depending on which approach you follow, you may be required to collect information for equipment on the associated screening data concentrations for greater than or equal to 10,000 ppmv and associated screening data concentrations for less than 10,000 ppmv; associated actual screening data concentrations; or associated screening data and leak rate data (i.e., bagging) used to develop a unit-specific correlation.
(3) Calculate and sum the emissions of each fluorinated GHG in metric tons per year for equipment pieces for each process, E
(e)
(2) Estimate annually the total mass of each fluorinated GHG emitted from each type of production or transformation process at the facility using Equation L-30 of this section. Develop separate totals for fluorinated gas production processes, transformation processes that transform fluorinated gases produced at the facility, and transformation processes that transform fluorinated gases produced at another facility.
(f)
(g)
(1)
(2)
(i)
(ii)
(iii)
(iv) Calculate annual emissions of each fluorinated GHG from venting of residual fluorinated GHG from containers using Equation L-34 of this section.
(h)
(a)
(1)
(2)
(b)
(c)
(1)
(2)
(3)
(4)
(i) You may sample emissions from each process in the ducts before the emissions are combined.
(ii) You may sample in the common duct or at the outlet of the destruction device when only one process is operating.
(iii) You may sample the combined emissions and use engineering calculations and assessments as specified in § 98.123(c)(4) to allocate the emissions to each manifolded process vent, provided the sum of the calculated fluorinated GHG emissions across the individual process vents is within 20 percent of the total fluorinated GHG emissions measured during the manifolded testing.
(5)
(6)
(i)
(ii)
(7)
(8)
(d)
(1)
(2)
(3)
(4)
(5)
(e)
(1)
(i) Sample and velocity traverses. Acceptable methods include but are not limited to EPA Method 1 or 1A in Appendix A-1 of 40 CFR part 60.
(ii) Velocity and volumetric flow rates. Acceptable methods include but are not limited to EPA Method 2, 2A, 2B, 2C, 2D, 2F, or 2G in Appendix A-1 of 40 CFR part 60. Alternatives that may be used for determining flow rates include OTM-24 (incorporated by reference, see § 98.7) and ALT-012 (incorporated by reference, see § 98.7).
(iii) Non-fluorinated-GHG gas analysis. Acceptable methods include but are not limited to EPA Method 3, 3A, or 3B in Appendix A-1 of 40 CFR part 60.
(iv) Stack gas moisture. Acceptable methods include but are not limited to EPA Method 4 in Appendix A-1 of 40 CFR part 60.
(2)
(3)
(f)
(1)
(2)
(3)
(g)
(1)
(i) If perfluoromethane (CF
(ii) If sulfur hexafluoride (SF
(iii) If saturated perfluorocarbons other than CF
(iv) For all other fluorinated GHGs that are vented to the destruction device in any stream in more than trace concentrations, you must test and determine the destruction efficiency achieved for the most-difficult-to-destroy fluorinated GHG or surrogate vented to the destruction device. Examples of acceptable surrogates include the Class 1 compounds (ranked 1 through 34) in Appendix D, Table D-1 of “Guidance on Setting Permit Conditions and Reporting Trial Burn Results; Volume II of the Hazardous Waste Incineration Guidance Series,” January 1989, EPA Publication EPA 625/6-89/019. You can obtain a copy of this publication by contacting the Environmental Protection Agency, 1200 Pennsylvania Avenue, NW., Washington, DC 20460, (202) 272-0167,
(2)
(i) Conduct an emissions test every 10 years. In the calculations under § 98.123, apply the updated destruction efficiency to the destruction that occurs after the test.
(ii)
(3)
(4)
(h)
(i)
(j)
(k)
(l) Initial scoping speciations, emissions testing, emission factor development, emission calculation factor development, emission characterization development, and destruction efficiency determinations must be completed by February 29, 2012 for processes and operating scenarios that operate between December 31, 2010 and December 31, 2011. For other processes and operating scenarios, initial scoping
(m) Calibrate all flow meters, weigh scales, and combinations of volumetric and density measures using monitoring instruments traceable to the International System of Units (SI) through the National Institute of Standards and Technology (NIST) or other recognized national measurement institute. Recalibrate all flow meters, weigh scales, and combinations of volumetric and density measures at the minimum frequency specified by the manufacturer. Use any of the following applicable flow meter test methods or the calibration procedures specified by the flow meter, weigh-scale, or other volumetric or density measure manufacturer.
(1) ASME MFC-3M-2004 Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and Venturi (incorporated by reference, see § 98.7).
(2) ASME MFC-4M-1986 (Reaffirmed 1997) Measurement of Gas Flow by Turbine Meters (incorporated by reference, see § 98.7).
(3) ASME-MFC-5M-1985, (Reaffirmed 1994) Measurement of Liquid Flow in Closed Conduits Using Transit-Time Ultrasonic Flowmeters (incorporated by reference, see § 98.7).
(4) ASME MFC-6M-1998 Measurement of Fluid Flow in Pipes Using Vortex Flowmeters (incorporated by reference, see § 98.7).
(5) ASME MFC-7M-1987 (Reaffirmed 1992) Measurement of Gas Flow by Means of Critical Flow Venturi Nozzles (incorporated by reference, see § 98.7).
(6) ASME MFC-9M-1988 (Reaffirmed 2001) Measurement of Liquid Flow in Closed Conduits by Weighing Method (incorporated by reference, see § 98.7).
(7) ASME MFC-11M-2006 Measurement of Fluid Flow by Means of Coriolis Mass Flowmeters (incorporated by reference, see § 98.7).
(8) ASME MFC-14M-2003 Measurement of Fluid Flow Using Small Bore Precision Orifice Meters (incorporated by reference, see § 98.7).
(n) All analytical equipment used to determine the concentration of fluorinated GHGs, including but not limited to gas chromatographs and associated detectors, infrared (IR), fourier transform infrared (FTIR), and nuclear magnetic resonance (NMR) devices, must be calibrated at a frequency needed to support the type of analysis specified in the GHG Monitoring Plan as required under § 98.124(e)(3) and 93.3(g)(5). Quality assurance samples at the concentrations of concern must be used for the calibration. Such quality assurance samples must consist of or be prepared from certified standards of the analytes of concern where available; if not available, calibration must be performed by a method specified in the GHG Monitoring Plan.
(o) Special provisions for estimating 2011 and subsequent year emissions.
(1)
(i) Monitoring methods currently used by the facility that do not meet the specifications of this subpart.
(ii) Supplier data.
(iii) Engineering calculations or assessments.
(iv) Other company records.
(2)
(i)
(ii)
(A) A list of specific items of monitoring equipment and measurement services for which the request is being made and the locations (e.g., processes and vents) where each piece of monitoring equipment will be installed and where each measurement service will be provided.
(B) Identification of the specific rule requirements for which the monitoring equipment or measurement service is needed.
(C) A description of the reasons why the needed equipment could not be obtained, installed, or operated or why the needed measurement service could not be provided before July 1, 2011. The owner or operator must consider all of the data collection and emission calculation options outlined in the rule for a specific emissions source before claiming that a specific safety, technical, logistical, or legal barrier exists.
(D) If the reason for the extension is that the equipment cannot be purchased, delivered, or installed before July 1, 2011, include supporting documentation such as the date the monitoring equipment was ordered, investigation of alternative suppliers, the dates by which alternative vendors promised delivery or installation, backorder notices or unexpected delays, descriptions of actions taken to expedite delivery or installation, and the current expected date of delivery or installation.
(E) If the reason for the extension is that service providers were unable to provide necessary measurement services, include supporting documentation demonstrating that these services could not be acquired before July 1, 2011. This documentation must include written correspondence to and from at least two service providers stating that they will not be able to provide the necessary services before July 1, 2011.
(F) If the reason for the extension is that the process is operating continuously without process shutdown, include supporting documentation showing that it is not practicable to isolate the process equipment or unit and install the measurement device without a full shutdown or a hot tap, and that there is no opportunity before July 1, 2011 to install the device. Include the date of the three most recent shutdowns for each relevant process equipment or unit, the frequency of shutdowns for each relevant process equipment or unit, and the date of the next planned process equipment or unit shutdown.
(G) If the reason for the extension is that access to process streams, emissions streams, or destroyed streams, as applicable, could not be gained before July 1, 2011 for reasons other than the continuous operation of the process without shutdown, include illustrative documentation such as photographs and engineering diagrams demonstrating that access could not be gained.
(H) A description of the best available monitoring methods that will be used and how their results will be applied (i.e., which calculation method will be used) to develop the emission estimate. Where the proposed best available monitoring method is the use of current monitoring data in the mass-balance approach, include the estimated relative and absolute errors of the mass-balance approach using the current monitoring data.
(I) A description of the specific actions the owner or operator will take to comply with monitoring requirements by January 1, 2012.
(3)
(i)
(ii)
(iii)
(4)
(i)
(ii)
(A) The information outlined in paragraph (o)(2)(ii) of this section. For scoping speciations, emission factors, and emission characterizations, substitute March 1, 2013 for July 1, 2011 and substitute March 1, 2014 for January 1, 2012. For other parameters, substitute January 1, 2012 for July 1, 2011 and substitute January 1, 2013 for January 1, 2012.
(B) A detailed outline of the unique circumstances necessitating an extension, including specific data collection issues that do not meet safety regulations, technical infeasibility or specific laws or regulations that conflict with data collection. The owner or operator must consider all the data collection and emission calculation options outlined in the rule for a specific emissions source before claiming that a specific safety, technical or legal barrier exists.
(C) A detailed explanation and supporting documentation of how and when the owner or operator will receive the required data and/or services to comply with the reporting requirements of this subpart in the future.
(E) The Administrator reserves the right to require that the owner or operator provide additional documentation.
(iii)
(5)
(a) A complete record of all measured parameters used in the GHG emissions calculations in § 98.123 is required. Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter must be used in the calculations as specified in the paragraphs (b) and (c) of this section. You must document and keep records of the procedures used for all such estimates.
(b) For each missing value of the fluorinated GHG concentration or fluorine-containing compound concentration, the substitute data value must be the arithmetic average of the quality-assured values of that parameter immediately preceding and immediately following the missing data incident.
(c) For each missing value of the mass produced, fed into the production process, fed into the transformation process, or fed into destruction devices, the substitute value of that parameter must be a secondary mass measurement where such a measurement is available. For example, if the mass produced is usually measured with a flowmeter at the inlet to the day tank and that flowmeter fails to meet an accuracy or precision test, malfunctions, or is rendered inoperable, then the mass produced may be estimated by calculating the change in volume in the day tank and multiplying it by the density of the product. Where a secondary mass measurement is not available, the substitute value of the parameter must 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.
(a)
(1)
(2)
(i) Provide a number, letter, or other identifier for the process. This identifier must be consistent from year to year.
(ii) Indicate whether the process is a fluorinated gas production process, a fluorinated gas transformation process where no fluorinated GHG reactant is produced at another facility, or a fluorinated gas transformation process where one or more fluorinated GHG reactants are produced at another facility.
(iii) Indicate whether the process could be characterized as reaction, distillation, or packaging (include all that apply).
(iv) For each generically-identified process and each fluorinated GHG group, report the method(s) used to determine the mass emissions of that fluorinated GHG group from that process from vents (
(v) For each generically-identified process and each fluorinated GHG group, report the method(s) used to determine the mass emissions of that fluorinated GHG group from that process from equipment leaks, unless you used the mass balance method (for reporting years 2011, 2012, 2013, and 2014 only) for that process.
(3)
(4)
(i) For each fluorinated GHG with emissions of 1,000 metric tons of CO
(ii) For all other fluorinated GHGs emitted from production and transformation processes, you must report the total GWP-weighted emissions from production and transformation processes of those fluorinated GHGs by fluorinated GHG group, summed across the facility as a whole, in metric tons of CO
(5)
(6)
(b)
(1) If you calculated the relative and absolute errors under the former § 98.123(b)(1), the overall absolute and relative errors calculated for the process under the former § 98.123(b)(1), in metric tons CO
(2) The method used to estimate the total mass of fluorine in destroyed or recaptured streams (specify the former § 98.123(b)(4) or (15), as included in paragraph 1 of Appendix A of this subpart).
(c)
(1) [Reserved]
(2) [Reserved]
(3) For each fluorinated GHG group, the total GWP-weighted mass of all fluorinated GHGs in that group emitted from all process vents combined, in metric tons of CO
(4) For each fluorinated GHG group, the total GWP-weighted mass of all fluorinated GHGs in that group emitted from equipment leaks, in metric tons of CO
(d)
(1) The generically-identified process for which the data were missing.
(2) The reason the data were missing, the length of time the data were missing, and the method used to estimate the missing data.
(3) Estimates of the missing data for all missing data associated with data elements required to be reported in this section.
(e)
(f)
(1) [Reserved]
(2) Chemical identity of the fluorinated GHG(s) used in the performance test conducted to determine destruction efficiency, including surrogates, and information on why the surrogate is sufficient to demonstrate the destruction efficiency for each fluorinated GHG, consistent with requirements in § 98.124(g)(1), vented to the destruction device.
(3) Date of the most recent destruction device test.
(4) Name of all applicable Federal or State regulations that may apply to the destruction process.
(5) [Reserved]
(g)
(1) [Reserved]
(2) The mass of the fluorinated GHG emitted from the destruction device (metric tons).
(h)
(1) The mass of the residual fluorinated GHG vented from containers annually (metric tons).
(2) [Reserved]
(i)
(j)
(1)
(2)
(3)
(i) If you choose to use a default GWP rather than your best estimate of the GWP for fluorinated GHGs whose GWPs are not listed in Table A-1 of Subpart A of this part, use a default GWP of 10,000 for fluorinated GHGs that are fully fluorinated GHGs and use a default GWP of 2000 for other fluorinated GHGs.
(ii) Provide the total annual emissions across fluorinated GHGs for the entire facility, in metric tons of CO
(iii) Provide the total annual emissions across fluorinated GHGs for the entire facility, in metric tons of CO
(iv) Provide the total annual emissions across fluorinated GHGs for the entire facility, in metric tons of CO
(k)
In addition to the records required by § 98.3(g), you must retain the dated records specified in paragraphs (a) through (l) of this section, as applicable.
(a)
(2) Monthly and annual records, as applicable, of all analyses and calculations conducted as required under § 98.123, including the data monitored under § 98.124, and all information reported as required under § 98.126.
(3) Identify all fluorinated GHGs with emissions of 1,000 metric tons CO
(4) Calculations used to determine the total GWP-weighted emissions of fluorinated GHGs by fluorinated GHG group for each process, in metric tons CO
(b)
(c)
(1) The data and calculations used to estimate the absolute and relative errors associated with use of the mass-balance approach.
(2) The data and calculations used to estimate the mass of fluorine emitted from the process.
(3) The data and calculations used to determine the fractions of the mass emitted consisting of each reactant (FER
(d)
(1) Identify all continuous process vents with emissions of fluorinated GHGs that are less than 10,000 metric tons CO
(2) Identify all batch process vents.
(3) For each vent, identify the method used to develop the factor (i.e., emission factor by emissions test or emission calculation factor).
(4) The emissions test data and reports (see § 98.124(c)(5)) and the calculations used to determine the process-vent-specific emission factor, including the actual process-vent-specific emission factor, the average hourly emission rate of each fluorinated GHG from the process vent during the test and the process feed rate, process production rate, or other process activity rate during the test.
(5) The process-vent-specific emission calculation factor and the calculations used to determine the process-vent-specific emission calculation factor.
(6) The annual process production quantity or other process activity information in the appropriate units, along with the dates and time period during which the process was operating and dates and time periods the process vents are vented to the destruction device. As an alternative to date and time periods when process vents are vented to the destruction device, a facility may track dates and time periods that process vents by-pass the destruction device.
(7) Calculations used to determine annual emissions of each fluorinated GHG for each process and the total fluorinated GHG emissions for all processes, i.e., total for facility.
(e)
(1) Destruction efficiency (DE) determined for each fluorinated GHG whose destruction the facility reflects in § 98.123, in accordance with § 98.124(g)(1)(i) through (iv).
(2) Chemical identity of the fluorinated GHG(s) used in the performance test conducted to determine destruction efficiency, including surrogates, and information on why the surrogate is sufficient to demonstrate destruction efficiency for each fluorinated GHG, consistent with requirements in § 98.124(g)(1)(i) through (iv), vented to the destruction device.
(3) Mass flow rate of the stream containing the fluorinated GHG(s) or surrogate into the device during the test.
(4) Concentration (mass fraction) of each fluorinated GHG or surrogate in the stream flowing into the device during the test.
(5) Concentration (mass fraction) of each fluorinated GHG or surrogate at the outlet of the destruction device during the test.
(6) Mass flow rate at the outlet of the destruction device during the test.
(7) Test methods and analytical methods used to determine the mass flow rates and fluorinated GHG (or surrogate) concentrations of the streams flowing into and out of the destruction device during the test.
(8) Destruction device conditions that are normally monitored for device control, such as temperature, total mass flow rates into the device, and CO or O
(9) Name of all applicable Federal or State regulations that may apply to the destruction process.
(f)
(g)
(i) If you measure the contents of each container, maintain records of these measurements and the calculations used to estimate emissions of each fluorinated GHG from each container size and type.
(ii) If you develop and apply container heel factors to estimate emissions, maintain records of the measurements and calculations used to develop the heel factor for each fluorinated GHG and each container size and type and of the number of containers of each fluorinated GHG and of each container size and type returned to your facility.
(h)
(i)
(j) GHG Monitoring Plans, as described in § 98.3(g)(5), must be completed by April 1, 2011.
(k) For fluorinated GHGs whose GWPs are not listed in Table A-1 to subpart A of this part, maintain records of the GWPs used to calculate facility-wide CO
(l)
(1) The identity of the process vent (
(2) The equation used to estimate emissions from the process vent (Equations L-21, L-22, L-26, or L-27).
(3) The type of process activity used to estimate emissions from the process vent (
(4) The quantities of the process activity used to estimate controlled and uncontrolled emissions, respectively, for the process vent, Activity, Activity
(5) The site-specific, process-vent-specific emission factor, EF
(6) The site-specific, process-vent-specific emission calculation factor, ECF
(7) The site-specific, process-vent-specific emission factor(s), EF
(8) The site-specific, process-vent-specific emission calculation factor for the process vent, ECF
(9) Destruction efficiency, DE, of each destruction device for each fluorinated GHG whose destruction the facility reflects in § 98.123, in accordance with § 98.124(g)(1)(i) through (iv) (weight fraction) (Equations L-22, L-27, L-31).
(10) Emissions of each fluorinated GHG for equipment pieces for the process, E
(11) The mass of the fluorinated GHG previously produced and fed into the destruction device, RE
(12) If applicable, the heel factor, h
(13) If applicable, the number of containers of size and type j returned to
(14) If applicable, the full capacity of containers of size and type j containing fluorinated GHG f, F
(15) For fluorinated GHGs that do not have a chemical-specific GWP on Table A-1 of subpart A of this part, the fluorinated GHG group of which the fluorinated GHG is a member, as applicable (to permit look-up of global warming potential, GWP
Except as provided in this section, all of the terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. If a conflict exists between a definition provided in this subpart and a definition provided in subpart A, the definition in this subpart shall take precedence for the reporting requirements in this subpart.
(1) Each dual mechanical seal system is operated with the barrier fluid at a pressure that is at all times (except periods of startup, shutdown, or malfunction) greater than the pump or agitator stuffing box pressure; or
(2) Equipped with a barrier fluid degassing reservoir that is routed to a process or fuel gas system or connected by a closed-vent system to a control device; or
(3) Equipped with a closed-loop system that purges the barrier fluid into a process stream.
(1) Identified as a production process, a transformation process where no fluorinated GHG reactant is produced at another facility, or a transformation process where one or more fluorinated GHG reactants are produced at another facility;
(2) Further identified as a reaction, distillation, or packaging process, or a combination thereof; and
(3) Tagged with a discrete identifier, such as a letter or number, that remains constant from year to year.
(1) The vapor pressure of one or more of the compounds is greater than 0.3 kilopascals at 20 °C.
(2) The total concentration of the pure compounds constituents having a vapor pressure greater than 0.3 kilopascals at 20 °C is equal to or greater than 20 percent by weight of the total process stream.
(3) The fluid is a liquid at operating conditions.
Vapor pressures may be determined by standard reference texts or ASTM D-2879, (incorporated by reference, see § 98.7).
(1) A description of the process, the specific process equipment used, and the range of operating conditions for the process.
(2) An identification of related process vents, their associated emissions episodes and durations, and calculations and engineering analyses to show the annual uncontrolled fluorinated GHG emissions from the process vent.
(3) The control or destruction devices used, as applicable, including a description of operating and/or testing conditions for any associated destruction device.
(4) The process vents (including those from other processes) that are simultaneously routed to the control or destruction device(s).
(5) The applicable monitoring requirements and any parametric level that assures destruction or removal for all emissions routed to the control or destruction device.
1.
(b)
(1)
(i) Where the measured quantity is a mass, the error in the mass must be equated to the accuracy or precision (whichever is larger) of the flowmeter, scale, or combination of volumetric and density measurements at the flow rate or mass measured.
(ii) Where the measured quantity is a concentration of a stream component, the error of the concentration must be equated to the accuracy or precision (whichever is larger) with which you estimate the mean concentration of that stream component, accounting for the variability of the process, the frequency of the measurements, and the accuracy or precision (whichever is larger) of the analytical technique used to measure the concentration at the concentration measured. If the variability of process measurements is used to estimate the error, this variability shall be assumed to account both for the variability of the process and the precision of the analytical technique. Use standard statistical techniques such as the student's t distribution to estimate the error of the mean of the concentration measurements as a function of process variability and frequency of measurement.
(iii) Equation L-1 of this section provides the general formula for calculating the absolute errors of sums and differences where the sum, S, is the summation of variables measured, a, b, c, etc. (
(iv) Equation L-2 of this section provides the general formula for calculating the relative errors of sums and differences:
(v) Equation L-3 of this section provides the general formula for calculating the absolute errors of products (
(vi) Equation L-4 of this section provides the general formula for calculating the relative errors of products:
(vii) Calculate the absolute error of the emissions estimate in terms of CO
(viii) To estimate the annual CO
(2) The total mass of each fluorinated GHG emitted annually from each fluorinated gas production and each fluorinated GHG transformation process must be estimated by using Equation L-5 of this section.
(3) The total mass of fluorine emitted from process i over the period p must be estimated at least monthly by calculating the difference between the total mass of fluorine in the reactant(s) (or inputs, for processes that do not involve a chemical reaction) and the total mass of fluorine in the product (or outputs, for processes that do not involve a chemical reaction), accounting for the total mass of fluorine in any destroyed or recaptured streams that contain reactants, products, or by-products (or inputs or outputs). This calculation must be performed using Equation L-6 of this section. An element other than fluorine may be used in the mass-balance equation, provided the element occurs in all of the fluorinated GHGs fed into or generated by the process. In this case, the mass fractions of the element in the reactants, products, and by-products must be calculated as appropriate for that element.
(4) The mass of total fluorine in destroyed or recaptured streams containing fluorine-containing reactants, products, and by-products must be estimated at least monthly using Equation L-7 of this section unless you use the alternative approach provided in paragraph (b)(15) of this section.
(5) The mass of each fluorinated GHG removed from process i in stream j and destroyed over the period p (
(6) The mass of each fluorine-containing compound that is not a fluorinated GHG and that is removed from process i in stream j and destroyed over the period p (
(7) The mass of fluorine-containing by-product k removed from process i in stream l and recaptured over the period p must be estimated using Equation L-10 of this section:
(8) To estimate the terms FER
(i) If the calculations under paragraph (b)(1)(viii) of this section, or any subsequent measurements and calculations under this subpart, indicate that the process emits 25,000 metric tons CO
(ii) For other vents, including vents from processes that emit less than 25,000 metric tons CO
(iii) For fluorine emissions that are not accounted for by vent estimates, you must characterize emissions as specified in § 98.124(b)(6).
(9) The total mass of fluorine-containing reactant d emitted must be estimated at least monthly based on the total fluorine emitted and the fraction that consists of fluorine-containing reactants using Equation L-11 of this section. If the fluorine-containing reactant d is a non-GHG, you may assume that FER
(10) The total mass of fluorine-containing product emitted must be estimated at least monthly based on the total fluorine emitted and the fraction that consists of fluorine-containing products using Equation L-12 of this section. If the fluorine-containing product is a non-GHG, you may assume that FEP is zero.
(11) The total mass of fluorine-containing by-product k emitted must be estimated at least monthly based on the total fluorine emitted and the fraction that consists of fluorine-containing by-products using Equation L-13 of this section. If fluorine-containing by-product k is a non-GHG, you may assume that FEB
(12) The mass fraction of fluorine in reactant d must be estimated using Equation L-14 of this section:
(13) The mass fraction of fluorine in the product must be estimated using Equation L-15 of this section:
(14) The mass fraction of fluorine in by-product k must be estimated using Equation L-16 of this section:
(15) Alternative for determining the mass of fluorine destroyed or recaptured. As an alternative to using Equation L-7 of this section as provided in paragraph (b)(4) of this section, you may estimate at least monthly the total mass of fluorine in destroyed or recaptured streams containing fluorine-containing compounds (including all fluorine-containing reactants, products, and byproducts) using Equation L-17 of this section.
(16) Weighted average destruction efficiency. For purposes of Equation L-17 of this section, calculate the weighted average destruction efficiency applicable to a destroyed stream using Equation L-18 of this section.
2.
(b)
(1)
(i) Total mass of each fluorine-containing product produced. Account for any used fluorine-containing product added into the production process upstream of the output measurement as directed at §§ 98.413(b) and 98.414(b). For each product, the mass produced used for the mass-balance calculation must be the same as the mass produced that is reported under subpart OO of this part, where applicable.
(ii) Total mass of each fluorine-containing reactant fed into the process.
(iii) The mass removed from the process in each stream fed into the destruction device.
(iv) The mass removed from the process in each recaptured stream.
(2)
(i) The concentration (mass fraction) of the fluorine-containing product in each stream that is fed into the destruction device.
(ii) The concentration (mass fraction) of each fluorine-containing by-product in each stream that is fed into the destruction device.
(iii) The concentration (mass fraction) of each fluorine-containing reactant in each stream that is fed into the destruction device.
(iv) The concentration (mass fraction) of each fluorine-containing by-product in each stream that is recaptured (c
(3)
(i) The concentration (mass fraction) of total fluorine in each stream that is fed into the destruction device.
(ii) The concentration (mass fraction) of total fluorine in each stream that is recaptured.
(4)
(i)
(ii)
(iii)
(iv)
(A)
(B)
(v)
(5)
(i)
(ii)
(iii)
(6)
(7)
(8)
(i)
(ii)
(iii)
(iv)
(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.
You must report GHG emissions under this subpart if your facility contains a glass production process and the facility meets the requirements of either § 98.2(a)(1) or (2).
You must report:
(a) CO
(b) CO
(c) CH
(d) CO
You must calculate and report the annual process CO
(a) For each continuous glass melting furnace that meets the conditions specified in § 98.33(b)(4)(ii) or (iii), you must calculate and report under this subpart the combined process and combustion CO
(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
(1) Calculate and report under this subpart the combined process and combustion CO
(2) Calculate and report the process and combustion CO
(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
(v) You must calculate the total process CO
(vi) Calculate and report under subpart C of this part (General Stationary Fuel Combustion Sources) the combustion CO
(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
(a) You must measure annual amounts of carbonate-based 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) Unless you use the default value of 1.0, 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 using consensus standards that specify X-ray fluorescence. For measurements made in years prior to the emissions reporting year 2014, you may also use ASTM D3682-01 (Reapproved 2006) Standard Test Method for Major and Minor Elements in Combustion Residues from Coal Utilization Processes 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 (both incorporated by reference, see § 98.7).
(c) Unless you use the default value of 1.0, you must determine the annual average mass fraction for the carbonate-based mineral in each carbonate-based raw material by calculating an arithmetic average of the monthly data obtained from raw material suppliers or sampling and chemical analysis.
(d) Unless you use the default value of 1.0, 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. If performed, this chemical analysis must be conducted using an x-ray fluorescence test or other enhanced testing method published by an industry consensus standards organization (
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.
(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.
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
(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
(1) Annual process emissions of CO
(2) Annual quantity of each carbonate-based raw material charged (tons) to all furnaces combined.
(3) Annual quantity of glass produced (tons) from each continuous glass melting furnace and from all furnaces combined.
(4) [Reserved]
(5) Results of all tests, if applicable, used to verify the carbonate-based mineral mass fraction for each carbonate-based raw material charged to a continuous glass melting furnace, as specified in paragraphs (b)(5)(i) through (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.
(6) [Reserved]
(7) Method used to determine decimal fraction of calcination, unless you used the default value of 1.0.
(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).
In addition to the information required by § 98.3(g), you must retain the records listed in paragraphs (a) through (d) 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).
(b) If process CO
(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, if applicable.
(4) Results of all tests, if applicable, used to verify the carbonate-based mineral mass fraction for each carbonate-based raw material charged to a continuous glass melting furnace, including the data specified in paragraphs (b)(4)(i) through (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.
(v) Name and address of laboratory that conducted the tests.
(5) The decimal 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
(c) All other documentation used to support the reported GHG emissions.
(d)
(1) Annual average decimal mass fraction of carbonate-based mineral in each carbonate-based raw material for each continuous glass melting furnace (specify the default value, if used, or the value determined according to § 98.144) (percentage, expressed as a decimal) (Equation N-1 of § 98.143).
(2) Annual amount of each carbonate-based raw material charged to each continuous glass melting furnace (tons) (Equation N-1 of this subpart).
(3) Decimal fraction of calcination achieved for each carbonate-based raw material for each continuous glass melting furnace (specify the default value, if used, or the value determined according to § 98.144) (percentage, expressed as a decimal) (Equation N-1 of this subpart).
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
The HCFC-22 production and HFC-23 destruction source category consists of HCFC-22 production processes and HFC-23 destruction processes.
(a) An HCFC-22 production process produces HCFC-22 (chlorodifluoromethane, or CHClF
(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.
You must report GHG emissions under this subpart if your facility contains an HCFC-22 production or HFC-23 destruction process and the facility meets the requirements of either § 98.2(a)(1) or (a)(2).
(a) You must report under subpart C of this part (General Stationary Fuel Combustion Sources) the emissions of CO
(b) You must report HFC-23 emissions from HCFC-22 production processes and HFC-23 destruction processes.
(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 more 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:
(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 of 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.
(b) The mass of HCFC-22 produced over the period p shall be estimated by using Equation O-3 of this section:
(c) For HCFC-22 production facilities that do not use a destruction device or that have a destruction device that is not directly connected to the HCFC-22 production equipment, HFC-23 emissions shall be estimated using Equation O-4 of this section:
(d) For HCFC-22 production facilities that use a destruction device connected to the HCFC-22 production equipment, HFC-23 emissions shall be estimated using Equation O-5 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:
(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) The total mass of HFC-23 emitted from destruction devices shall be estimated by using Equation O-8 of this section:
(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:
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 HFC-23 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.
(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.
(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
(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.
(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 (i) 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 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 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 rate of HFC-23 into the destruction device by measuring the HFC-23 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
(n) The mass of HFC-23 fed into the destruction device shall be measured at least weekly using flow meters, 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 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, and combinations of volumetric and density measures using NIST-traceable standards and suitable methods published by a 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 certified standards (or of calibration gases prepared from a high-concentration 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.
(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 the arithmetic average of the quality-assured values of that parameter immediately preceding and immediately following the missing data incident. If, for a particular parameter, no quality-assured data are available prior to the missing data incident, the substitute data value shall be the first quality-assured value obtained after the missing data period.
(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.
(a) In addition to the information required by § 98.3(c), the HCFC-22 production facility shall report the following information for each HCFC-22 production process:
(1) Annual mass of HCFC-22 produced in metric tons.
(2) [Reserved]
(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)-(10) [Reserved]
(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)-(2) [Reserved]
(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. If the concentration of HFC-23 is below the detection limit of the measuring device, report the detection limit and that the concentration is below the detection limit.
(d) If the HFC-23 concentration measured pursuant to § 98.154(l) is greater than that measured during the performance test that is the basis for the destruction efficiency (DE), the facility shall report the method used to calculate the revised destruction efficiency, specifying whether § 98.154(l)(1) or (2) has been used for the calculation.
(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) [Reserved]
(2) The methods used to determine destruction efficiency.
(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.
(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:
(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).
(c)
(1) Factor to account for the loss of HCFC-22 upstream of the measurement over the period, determined pursuant to § 98.154(e) (Equation O-3 of § 98.153).
(2) Mass of HCFC-22 that is measured coming out of the production process over the period. A period can be one year (kg) (Equation O-3).
(3) Mass of used HCFC-22 that is added to the production process upstream of the output measurement over the period. A period can be one year (kg) (Equation O-3).
(4) Mass of HFC-23 generated annually per HCFC-22 production process (metric tons) (Equation O-4 of § 98.153).
(5) Mass of HFC-23 sent off site for sale annually per HCFC-22 production process (metric tons) (Equation O-4).
(6) Mass of HFC-23 sent off site for destruction annually per HCFC-22 production process (metric tons) (Equation O-4).
(7) Mass of HFC-23 destroyed on site per HCFC-22 production process (metric tons) (Equation O-4).
(8) HFC-23 in storage at end of year per HCFC-22 production process (metric tons) (Equation O-4).
(9) HFC-23 in storage at beginning of year per HCFC-22 production process (metric tons) (Equation O-4).
(10) Mass of HFC-23 fed into each destruction device annually per HCFC-22 production process (metric tons) (Equation O-9 of § 98.153 and the calculation method in either § 98.154(l)(1) or (2)).
(11) Identify if each destruction efficiency for each HCFC-22 production process is entered directly, or is calculated using § 98.154(l)(1), or is calculated using § 98.154(l)(2) (Equation O-9 and the calculation method in either § 98.154(l)(1) or (2)).
(12) Destruction efficiency of each destruction device for each HCFC-22 production process (decimal fraction) (Equation O-9 and the calculation method in either § 98.154(l)(1) or (2)).
(13) Volumetric flow rate at the inlet of each destruction device for each HCFC-22 production process from previous test (kg/hr) (Equation O-9 and the calculation method in either § 98.154(l)(1) or (2)).
(14) Volumetric flow rate at the inlet of destruction device during test for each HCFC-22 production process (kg/hr) (Equation O-9 and the calculation method in either § 98.154(l)(1) or (2)).
(15) Concentration of HFC-23 at the inlet of destruction device for each HCFC-22 production process from previous test (weight fraction) (Equation O-9 and the calculation method in either § 98.154(l)(1) or (2)).
(16) Concentration of HFC-23 at the inlet of destruction device for each HCFC-22 production process during test (weight fraction) (Equation O-9 and the calculation method in either § 98.154(l)(1) or (2)).
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
(a) A hydrogen production source category consists of facilities that produce hydrogen gas sold as a product to other entities.
(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.
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).
You must report:
(a) CO
(b) [Reserved]
(c) CO
(d) For CO
You must calculate and report the annual CO
(a)
(b)
(1)
(2)
(3)
(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
At 81 FR 89257, Dec. 9, 2016, § 98.163 was amended by revising parameter “CO
(b) * * *
(3) * * *
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 that are used to measure liquid and gaseous fuel and feedstock volumes (except for gas billing meters) according to the monitoring and QA/QC requirements for the Tier 3 methodology in § 98.34(b)(1). Perform oil tank drop measurements (if used to quantify liquid fuel or feedstock consumption) according to § 98.34(b)(2). Calibrate all solids weighing equipment according to the procedures in § 98.3(i).
(2) Determine the carbon content and the molecular weight annually of standard gaseous hydrocarbon fuels and feedstocks having consistent composition (
(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 and feedstocks delivered by bulk transport (
(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 and feedstocks delivered by bulk transport (
(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. Alternatively, you may use the results of chromatographic analysis of the fuel and feedstock, provided that the chromatograph is operated, maintained, and calibrated according to the manufacturer's instructions; and the methods used for operation, maintenance, and calibration of the chromatograph are documented in the written monitoring plan for the unit under § 98.3(g)(5).
(i) ASTM D1945-03 Standard Test Method for Analysis of Natural Gas by Gas Chromatography (incorporated by reference,
(ii) ASTM D1946-90 (Reapproved 2006), Standard Practice for Analysis of Reformed Gas by Gas Chromatography (incorporated by reference,
(iii) ASTM D2013-07 Standard Practice of Preparing Coal Samples for Analysis (incorporated by reference,
(iv) ASTM D2234/D2234M-07 Standard Practice for Collection of a Gross Sample of Coal (incorporated by reference,
(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,
(vi) ASTM D3176-89 (Reapproved 2002), Standard Practice for Ultimate Analysis of Coal and Coke (incorporated by reference,
(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,
(viii) ASTM D4057-06 Standard Practice for Manual Sampling of Petroleum and Petroleum Products (incorporated by reference,
(ix) ASTM D4177-95 (Reapproved 2005) Standard Practice for Automatic Sampling of Petroleum and Petroleum Products (incorporated by reference,
(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,
(xi) ASTM D5373-08 Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference,
(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,
(xiv) ASTM D7430-08ae1 Standard Practice for Mechanical Sampling of Coal (incorporated by reference,
(xv) ASTM UOP539-97 Refinery Gas Analysis by Gas Chromatography (incorporated by reference,
(xvi) GPA 2261-00 Analysis for Natural Gas and Similar Gaseous Mixtures by Gas Chromatography (incorporated by reference,
(xvii) ISO 3170: Petroleum Liquids—Manual sampling—Third Edition (incorporated by reference,
(xviii) ISO 3171: Petroleum Liquids—Automatic pipeline sampling—Second Edition (incorporated by reference,
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 substitute data value must be the arithmetic average of the quality-assured values of carbon contents or molecular weight of the fuel and feedstock immediately preceding and immediately following the missing data incident. If no quality-assured data on carbon contents or molecular weight of the fuel and feedstock are available prior to the missing data incident, the substitute data value must be the first quality-assured value for carbon contents or molecular weight of the fuel and feedstock obtained after the missing data period. You must document and keep records of the procedures used for all such estimates.
(c) For missing CEMS data, you must use the missing data procedures in § 98.35.
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 paragraphs (c) through (e) of this section:
(a) If a CEMS is used to measure CO
(1) Unit identification number and annual CO
(2) Annual quantity of hydrogen produced (metric tons) for each process unit.
(3) Annual quantity of ammonia produced (metric tons), if applicable, for each process unit.
(b) If a CEMS is not used to measure CO
(1) Unit identification number and annual CO
(2) [Reserved]
(3) Annual quantity of hydrogen produced (metric tons).
(4) Annual quantity of ammonia produced, if applicable (metric tons).
(5)-(6) [Reserved]
(7) Name and annual quantity (metric tons) of each carbon-containing fuel and feedstock.
(c) Quantity of CO
(d) Annual quantity of carbon other than CO
(e) Annual methanol production (metric tons) for each process unit.
At 81 FR 89258, Dec. 9, 2016, § 98.166 was amended by revising paragraphs (b)(4), (d), and (e), effective Jan. 1, 2019. For the convenience of the user, the revised text is set forth as follows:
(b) * * *
(4) Annual quantity of ammonia intentionally produced as a desired product, if applicable (metric tons).
(d) Annual quantity of carbon other than CO
(e) Annual quantity of methanol intentionally produced as a desired product, if applicable, (metric tons) for each process unit.
In addition to the information required by § 98.3(g), you must retain the records specified in paragraphs (a) through (e) of this section for each hydrogen production facility.
(a) If a CEMS is used to measure CO
(b) If a CEMS is not used to measure CO
(c) For units using the calculation methodologies described in § 98.163(b), 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
(3) Sorbent usage, if the methodology in § 98.33(d) is used to calculate CO
(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 § 98.163(b), 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.
(e)
(1) Indicate whether the monthly consumption of each gaseous fuel or feedstock is measured as mass or volume (Equation P-1 of § 98.163).
(2) Monthly volume of the gaseous fuel or feedstock (scf at standard conditions of 68 °F and atmospheric pressure) (Equation P-1).
(3) Monthly mass of the gaseous fuel or feedstock (kg of fuel or feedstock) (Equation P-1).
(4) Average monthly carbon content of the gaseous fuel or feedstock (kg C per kg of fuel or feedstock) (Equation P-1).
(5) Average monthly molecular weight of the gaseous fuel or feedstock (kg/kg-mole) (Equation P-1).
(6) Indicate whether the monthly consumption of each liquid fuel or feedstock is measured as mass or volume (Equation P-2 of § 98.163).
(7) Monthly volume of the liquid fuel or feedstock (gallons of fuel or feedstock) (Equation P-2).
(8) Monthly mass of the liquid fuel or feedstock (kg of fuel or feedstock) (Equation P-2).
(9) Average monthly carbon content of the liquid fuel or feedstock (kg C per gallon of fuel or feedstock) (Equation P-2).
(10) Average monthly carbon content of the liquid fuel or feedstock (kg C per kg of fuel or feedstock) (Equation P-2).
(11) Monthly mass of solid fuel or feedstock (kg of fuel and feedstock) (Equation P-3 of § 98.163).
(12) Average monthly carbon content of the solid fuel or feedstock (kg C per kg of fuel and feedstock) (Equation P-3).
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
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 collocated with an integrated iron and steel manufacturing process, direct reduction furnaces not collocated with an integrated iron and steel manufacturing process, and electric arc furnace (EAF) steelmaking not collocated 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.
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).
(a) You must report under subpart C of this part (General Stationary Fuel Combustion Sources) the emissions of CO
(b) You must report CO
(c) You must report process CO
You must calculate and report the annual process CO
(a) Calculate and report under this subpart the process CO
(b) Calculate and report under this subpart the process CO
(1)
(i) For taconite indurating furnaces, estimate CO
(ii) For basic oxygen process furnaces, estimate CO
(iii) For non-recovery coke oven batteries, estimate CO
(iv) For sinter processes, estimate CO
(v) For EAFs, estimate CO
(vi) For decarburization vessels, estimate CO
(vii) For direct reduction furnaces, estimate CO
(2)
(i) You must measure the process production rate or process feed rate, as applicable, during the performance test according to the procedures in
(ii) You must calculate the hourly CO
(iii) You must calculate a site-specific emission factor for the process in metric tons of CO
(iv) You must calculate CO
(c) You must determine emissions of CO
(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 a stack equipped with a CEMS that complies with the Tier 4 methodology in subpart C of this part, or through the same stack as any combustion unit or process equipment that reports CO
(a) If you operate and maintain a CEMS that measures CO
(b) If you determine CO
(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. No determination of the mass of steel output from decarburization vessels is required.
(2) Except as provided in paragraph (b)(4) of this section, determine the carbon content of each process input
(i) ASTM C25-06, Standard Test Methods for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime (incorporated by reference,
(ii) ASTM D5373-08 Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference,
(iii) ASTM E1915-07a, Standard Test Methods for Analysis of Metal Bearing Ores and Related Materials by Combustion Infrared-Absorption Spectrometry (incorporated by reference,
(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,
(v) ASM CS-104 UNS No. G10460—Alloy Digest April 1985 (Carbon Steel of Medium Carbon Content) (incorporated by reference,
(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.
(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
(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)(i) For the 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, develop an emission factor for the production of both types of steel.
(ii) For the exhaust from continuously charged EAFs, sample the exhaust for a period spanning at least three hours. For EAFs that produce both carbon steel and stainless or specialty (low carbon) steel, 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
(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
(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.
A complete record of all measured parameters used in the GHG emissions calculations in § 98.173 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 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) Except as provided in § 98.174(b)(4), 100 percent data availability is required for the carbon content of inputs and outputs for facilities that estimate emissions using the carbon mass balance procedure in § 98.173(b)(1) or facilities that estimate emissions using the site-specific emission factor procedure in § 98.173(b)(2).
(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 of the mass of the input or output material from all available process data or data used for accounting purposes.
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. For reporting year 2010, the information required in paragraphs (a) through (h) of this section is not required for decarburization vessels that are not argon-oxygen decarburization vessels. For reporting year 2011 and each subsequent reporting year, the information
(a) Unit identification number and annual CO
(b) If a CEMS is used to measure CO
(c) If a CEMS is used to measure CO
(d) If a CEMS is not used to measure CO
(e) If you use the carbon mass balance method in § 98.173(b)(1) to determine CO
(1) [Reserved]
(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)-(4) [Reserved]
(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.
(6) The information specified in paragraphs (e)(6)(i) through (vi) of this section aggregated for all process units for which CO
(i) The annual mass (metric tons) of all gaseous, liquid, and solid fuels (combined) used in process units for which CO
(ii) The annual mass (metric tons) of all non-fuel material inputs (combined) specified in Equations Q-1 through Q-7 of § 98.173, calculated as specified in Equation Q-10 of this section.
(iii) The annual mass (metric tons) of all solid and liquid products and byproducts (combined) specified in Equations Q-1 through Q-7 of § 98.173, calculated as specified in Equation Q-11 of this section.
(iv) The weighted average carbon content of all gaseous, liquid, and solid fuels (combined) included in Equation Q-9 of this section, calculated as specified in Equation Q-12 of this section.
(v) The weighted average carbon content of all non-fuel inputs to all process units (combined) included in Equation Q-10 of this section, calculated as specified in Equation Q-13 of this section.
(vi) The weighted average carbon content of all solid and liquid products and byproducts from all process units (combined) included in Equation Q-11 of this section, calculated as specified in Equation Q-14 of this section.
(f) If you used the site-specific emission factor method in § 98.173(b)(2) to determine CO
(1) The measured average hourly CO
(2)-(4) [Reserved]
(g) [Reserved]
(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.
In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) through (f) 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 Calculating Methodology in § 98.36(e).
(a) Records of all analyses and calculations conducted, including all information reported as required under § 98.176.
(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, except that no determination of the mass of steel output from decarburization vessels is required.
(c) Production capacity (in metric tons per year) for the production of
(d) Annual operating hours for each taconite indurating furnace, basic oxygen furnace, non-recovery coke oven battery, sinter process, 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, and the technical basis for these estimates must be provided.
(f)
(1) The data in paragraphs (f)(1)(i) through (xxv) of this section for each applicable taconite indurating furnace for which the carbon mass balance method of reporting is used.
(i) Annual mass of each solid fuel (metric tons) (Equation Q-1 of § 98.173).
(ii) Carbon content of each solid fuel, from the fuel analysis (expressed as a decimal fraction) (Equation Q-1).
(iii) Annual volume of each gaseous fuel (scf) (Equation Q-1).
(iv) Average carbon content of each gaseous fuel, from the fuel analysis results (kg C per kg of fuel) (Equation Q-1).
(v) Molecular weight of each gaseous fuel (kg/kg-mole) (Equation Q-1).
(vi) Annual volume of each liquid fuel (gallons) (Equation Q-1).
(vii) Carbon content of each liquid fuel, from the fuel analysis results (kg C per gallon of fuel) (Equation Q-1).
(viii) Annual mass of the greenball (taconite) pellets fed to the furnace (metric tons) (Equation Q-1).
(ix) Carbon content of the greenball (taconite) pellets, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-1).
(x) Annual mass of fired pellets produced by the furnace (metric tons) (Equation Q-1).
(xi) Carbon content of the fired pellets, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-1).
(xii) Annual mass of air pollution control residue collected (metric tons) (Equation Q-1).
(xiii) Carbon content of the air pollution control residue, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-1).
(xiv) Annual mass of each other solid input containing carbon fed to each furnace (metric tons) (Equation Q-1).
(xv) Carbon content of each other solid input containing carbon fed to each furnace (expressed as a decimal fraction) (Equation Q-1).
(xvi) Annual mass of each other solid output containing carbon produced by each furnace (metric tons) (Equation Q-1).
(xvii) Carbon content of each other solid output containing carbon (expressed as a decimal fraction) (Equation Q-1).
(xviii) Annual mass of each other gaseous input containing carbon fed to each furnace (metric tons) (Equation Q-1).
(xix) Carbon content of each other gaseous input containing carbon fed to each furnace (expressed as a decimal fraction) (Equation Q-1).
(xx) Annual mass of each other gaseous output containing carbon produced by each furnace (metric tons) (Equation Q-1).
(xxi) Carbon content of each other gaseous output containing carbon produced by each furnace (expressed as a decimal fraction) (Equation Q-1).
(xxii) Annual mass of each other liquid input containing carbon fed to each furnace (metric tons) (Equation Q-1).
(xxiii) Carbon content of each other liquid input containing carbon fed to each furnace (expressed as a decimal fraction) (Equation Q-1).
(xxiv) Annual mass of each other liquid output containing carbon produced by each furnace (metric tons) (Equation Q-1).
(xxv) Carbon content of each other liquid output containing carbon produced by each furnace (expressed as a decimal fraction) (Equation Q-1).
(2) The data in paragraphs (f)(2)(i) through (xxvi) of this section for each applicable basic oxygen process furnace for which the carbon mass balance method of reporting is used.
(i) Annual mass of molten iron charged to the furnace (metric tons) (Equation Q-2 of § 98.173).
(ii) Carbon content of the molten iron charged to the furnace, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-2).
(iii) Annual mass of ferrous scrap charged to the furnace (metric tons) (Equation Q-2).
(iv) Carbon content of the ferrous scrap charged to the furnace, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-2).
(v) Annual mass of the flux materials (e.g., limestone, dolomite) charged to the furnace (metric tons) (Equation Q-2).
(vi) Carbon content of the flux materials charged to the furnace, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-2).
(vii) Annual mass of the carbonaceous materials (e.g., coal, coke) charged to the furnace (metric tons) (Equation Q-2).
(viii) Carbon content of the carbonaceous materials charged to the furnace, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-2).
(ix) Annual mass of molten raw steel produced by the furnace (metric tons) (Equation Q-2).
(x) Carbon content of the steel produced by the furnace, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-2).
(xi) Annual mass of slag produced by the furnace (metric tons) (Equation Q-2).
(xii) Carbon content of the slag produced by the furnace, from the carbon analysis (expressed as a decimal fraction) (Equation Q-2).
(xiii) Annual mass of air pollution control residue collected for the furnace (metric tons) (Equation Q-2).
(xiv) Carbon content of the air pollution control residue collected for the furnace, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-2).
(xv) Annual mass of each other solid input containing carbon fed to each furnace (metric tons) (Equation Q-2).
(xvi) Carbon content of each other solid input containing carbon fed to each furnace (expressed as a decimal fraction) (Equation Q-2).
(xvii) Annual mass of each other solid output containing carbon produced by each furnace (metric tons) (Equation Q-2).
(xviii) Carbon content of each other solid output containing carbon (expressed as a decimal fraction) (Equation Q-2).
(xix) Annual mass of each other gaseous input containing carbon fed to each furnace (metric tons) (Equation Q-2).
(xx) Carbon content of each other gaseous input containing carbon fed to each furnace (expressed as a decimal fraction) (Equation Q-2).
(xxi) Annual mass of each other gaseous output containing carbon produced by each furnace (metric tons) (Equation Q-2).
(xxii) Carbon content of each other gaseous output containing carbon produced by each furnace (expressed as a decimal fraction) (Equation Q-2).
(xxiii) Annual mass of each other liquid input containing carbon fed to each furnace (metric tons) (Equation Q-2).
(xxiv) Carbon content of each other liquid input containing carbon fed to each furnace (expressed as a decimal fraction) (Equation Q-2).
(xxv) Annual mass of each other liquid output containing carbon produced by each furnace (metric tons) (Equation Q-2).
(xxvi) Carbon content of each other liquid output containing carbon produced by each furnace (expressed as a decimal fraction) (Equation Q-2).
(3) The data in paragraphs (f)(3)(i) through (xviii) of this section for each applicable non-recovery coke oven battery for which the carbon mass balance method of reporting is used.
(i) Annual mass of coal charged to the battery (metric tons) (Equation Q-3 of § 98.173).
(ii) Carbon content of the coal, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-3).
(iii) Annual mass of coke produced by the battery (metric tons) (Equation Q-3).
(iv) Carbon content of the coke, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-3).
(v) Annual mass of air pollution control residue collected (metric tons) (Equation Q-3).
(vi) Carbon content of the air pollution control residue, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-3).
(vii) Annual mass of each other solid input containing carbon fed to each battery (metric tons) (Equation Q-3).
(viii) Carbon content of each other solid input containing carbon fed to each battery (expressed as a decimal fraction) (Equation Q-3).
(ix) Annual mass of each other solid output containing carbon produced by each battery (metric tons) (Equation Q-3).
(x) Carbon content of each other solid output containing carbon (expressed as a decimal fraction) (Equation Q-3).
(xi) Annual mass of each other gaseous input containing carbon fed to each battery (metric tons) (Equation Q-3).
(xii) Carbon content of each other gaseous input containing carbon fed to each battery (expressed as a decimal fraction) (Equation Q-3).
(xiii) Annual mass of each other gaseous output containing carbon produced by each battery (metric tons) (Equation Q-3).
(xiv) Carbon content of each other gaseous output containing carbon produced by each battery (expressed as a decimal fraction) (Equation Q-3).
(xv) Annual mass of each other liquid input containing carbon fed to each battery (metric tons) (Equation Q-3).
(xvi) Carbon content of each other liquid input containing carbon fed to each battery (expressed as a decimal fraction) (Equation Q-3).
(xvii) Annual mass of each other liquid output containing carbon produced by each battery (metric tons) (Equation Q-3).
(xviii) Carbon content of each other liquid output containing carbon produced by each battery (expressed as a decimal fraction) (Equation Q-3).
(4) The data in paragraphs (f)(4)(i) through (xxi) of this section for each applicable sinter process for which the carbon mass balance method of reporting is used.
(i) Annual volume of the gaseous fuel (scf) (Equation Q-4 of § 98.173).
(ii) Carbon content of the gaseous fuel, from the fuel analysis results (kg C per kg of fuel) (Equation Q-4).
(iii) Molecular weight of the gaseous fuel (kg/kg-mole) (Equation Q-4).
(iv) Annual mass of sinter feed material (metric tons) (Equation Q-4).
(v) Carbon content of the mixed sinter feed materials that form the bed entering the sintering machine, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-4).
(vi) Annual mass of sinter produced (metric tons) (Equation Q-4).
(vii) Carbon content of the sinter pellets, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-4).
(viii) Annual mass of air pollution control residue collected (metric tons) (Equation Q-4).
(ix) Carbon content of the air pollution control residue, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-4).
(x) Annual mass of each other solid input containing carbon fed to each sinter process (metric tons) (Equation Q-4).
(xi) Carbon content of each other solid input containing carbon fed to each sinter process (expressed as a decimal fraction) (Equation Q-4).
(xii) Annual mass of each other solid output containing carbon produced by each sinter process (metric tons) (Equation Q-4).
(xiii) Carbon content of each other solid output containing carbon (expressed as a decimal fraction) (Equation Q-4).
(xiv) Annual mass of each other gaseous input containing carbon fed to each sinter process (metric tons) (Equation Q-4).
(xv) Carbon content of each other gaseous input containing carbon fed to each sinter process (expressed as a decimal fraction) (Equation Q-4).
(xvi) Annual mass of each other gaseous output containing carbon produced by each sinter process (metric tons) (Equation Q-4).
(xvii) Carbon content of each other gaseous output containing carbon produced by each sinter process (expressed as a decimal fraction) (Equation Q-4).
(xviii) Annual mass of each other liquid input containing carbon fed to each sinter process (metric tons) (Equation Q-4).
(xix) Carbon content of each other liquid input containing carbon fed to each sinter process (expressed as a decimal fraction) (Equation Q-4).
(xx) Annual mass of each other liquid output containing carbon produced by each sinter process (metric tons) (Equation Q-4).
(xxi) Carbon content of each other liquid output containing carbon produced by each sinter process (expressed as a decimal fraction) (Equation Q-4).
(5) The data in paragraphs (f)(5)(i) through (xxxi) of this section for each applicable electric arc furnace for which the carbon mass balance method of reporting is used.
(i) Annual mass of direct reduced iron (if any) charged to the furnace (metric tons) (Equation Q-5 of § 98.173).
(ii) Carbon content of the direct reduced iron, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-5)
(iii) Annual mass of ferrous scrap charged to the furnace (metric tons) (Equation Q-5).
(iv) Carbon content of the ferrous scrap, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-5).
(v) Annual mass of flux materials (e.g., limestone, dolomite) charged to the furnace (metric tons) (EquationQ-5).
(vi) Carbon content of the flux materials, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-5).
(vii) Annual mass of carbon electrode consumed (metric tons) (Equation Q-5).
(viii) Carbon content of the carbon electrode, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-5).
(ix) Annual mass of carbonaceous materials (e.g., coal, coke) charged to the furnace (metric tons) (Equation Q-5).
(x) Carbon content of the carbonaceous materials, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-5).
(xi) Annual mass of molten raw steel produced by the furnace (metric tons) (Equation Q-5).
(xii) Carbon content of the steel, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-5).
(xiii) Annual volume of the gaseous fuel (scf at 60F and 1 atm) (Equation Q-5).
(xiv) Average carbon content of the gaseous fuel, from the fuel analysis results (kg C per kg of fuel) (Equation Q-5).
(xv) Molecular weight of the gaseous fuel (kg/kg-mole) (Equation Q-5).
(xvi) Annual mass of slag produced by the furnace (metric tons) (Equation Q-5).
(xvii) Carbon content of the slag, from the carbon analysis (expressed as a decimal fraction) (Equation Q-5).
(xviii) Annual mass of air pollution control residue collected (metric tons) (Equation Q-5).
(xix) Carbon content of the air pollution control residue, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-5).
(xx) Annual mass of each other solid input containing carbon fed to each furnace (metric tons) (Equation Q-5).
(xxi) Carbon content of each other solid input containing carbon fed to each furnace (expressed as a decimal fraction) (Equation Q-5).
(xxii) Annual mass of each other solid output containing carbon produced by each furnace (metric tons) (Equation Q-5).
(xxiii) Carbon content of each other solid output containing carbon (expressed as a decimal fraction) (Equation Q-5).
(xxiv) Annual mass of each other gaseous input containing carbon fed to each furnace (metric tons) (Equation Q-5).
(xxv) Carbon content of each other gaseous input containing carbon fed to each furnace (expressed as a decimal fraction) (Equation Q-5).
(xxvi) Annual mass of each other gaseous output containing carbon produced by each furnace (metric tons) (Equation Q-5).
(xxvii) Carbon content of each other gaseous output containing carbon produced by each furnace (expressed as a decimal fraction) (Equation Q-5).
(xxviii) Annual mass of each other liquid input containing carbon fed to each furnace (metric tons) (Equation Q-5).
(xxix) Carbon content of each other liquid input containing carbon fed to each furnace (expressed as a decimal fraction) (Equation Q-5).
(xxx) Annual mass of each other liquid output containing carbon produced by each furnace (metric tons) (Equation Q-5).
(xxxi) Carbon content of each other liquid output containing carbon produced by each furnace (expressed as a decimal fraction) (Equation Q-5).
(6) The data in paragraphs (f)(6)(i) through (xvii) of this section for each applicable decarburization vessel for which the carbon mass balance method of reporting is used.
(i) Annual mass of molten steel charged to the vessel (metric tons) (Equation Q-6 of § 98.173).
(ii) Carbon content of the molten steel before decarburization, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-6).
(iii) Carbon content of the molten steel after decarburization, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-6).
(iv) Annual mass of air pollution control residue collected (metric tons) (Equation Q-6).
(v) Carbon content of the air pollution control residue, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-6).
(vi) Annual mass of each other solid input containing carbon fed to each decarburization vessel (metric tons) (Equation Q-6).
(vii) Carbon content of each other solid input containing carbon fed to each decarburization vessel (expressed as a decimal fraction) (Equation Q-6).
(viii) Annual mass of each other solid output containing carbon produced by each decarburization vessel (metric tons) (Equation Q-6).
(ix) Carbon content of each other solid output containing carbon (expressed as a decimal fraction) (Equation Q-6).
(x) Annual mass of each other gaseous input containing carbon fed to each decarburization vessel (metric tons) (Equation Q-6).
(xi) Carbon content of each other gaseous input containing carbon fed to each decarburization vessel (expressed as a decimal fraction) (Equation Q-6).
(xii) Annual mass of each other gaseous output containing carbon produced by each decarburization vessel (metric tons) (Equation Q-6).
(xiii) Carbon content of each other gaseous output containing carbon produced by each decarburization vessel (expressed as a decimal fraction) (Equation Q-6).
(xiv) Annual mass of each other liquid input containing carbon fed to each decarburization vessel (metric tons) (Equation Q-6).
(xv) Carbon content of each other liquid input containing carbon fed to each decarburization vessel (expressed as a decimal fraction) (Equation Q-6).
(xvi) Annual mass of each other liquid output containing carbon produced by each decarburization vessel (metric tons) (Equation Q-6).
(xvii) Carbon content of each other liquid output containing carbon produced by each decarburization vessel (expressed as a decimal fraction) (Equation Q-6).
(7) The data in paragraphs (f)(7)(i) through (xxvii) of this section for each applicable direct reduction furnace for which the carbon mass balance method of reporting is used.
(i) Annual volume of the gaseous fuel (scf at 68F and 1 atm) (Equation Q-7 of § 98.173).
(ii) Average carbon content of the gaseous fuel, from the fuel analysis results (kg C per kg of fuel) (Equation Q-7).
(iii) Molecular weight of the gaseous fuel (kg/kg-mole) (Equation Q-7).
(iv) Annual mass of iron ore or iron pellets fed to the furnace (metric tons) (Equation Q-7).
(v) Carbon content of the iron ore or iron pellets, from the carbon analysis (expressed as a decimal fraction) (Equation Q-7).
(vi) Annual mass of carbonaceous materials (e.g., coal, coke) charged to the furnace (metric tons) (Equation Q-7).
(vii) Carbon content of the carbonaceous materials, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-7).
(viii) Annual mass of each other material charged to the furnace (metric tons) (Equation Q-7).
(ix) Average carbon content of each other material charged to the furnace, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-7).
(x) Annual mass of iron produced (metric tons) (Equation Q-7).
(xi) Carbon content of the iron produced, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-7).
(xii) Annual mass of non-metallic materials produced by the furnace (metric tons) (Equation Q-7).
(xiii) Carbon content of the non-metallic materials produced, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-7).
(xiv) Annual mass of air pollution control residue collected (metric tons) (Equation Q-7).
(xv) Carbon content of the air pollution control residue collected, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-7).
(xvi) Annual mass of each other solid input containing carbon fed to each furnace (metric tons) (Equation Q-7).
(xvii) Carbon content of each other solid input containing carbon fed to each furnace (expressed as a decimal fraction) (Equation Q-7).
(xviii) Annual mass of each other solid output containing carbon produced by each furnace (metric tons) (Equation Q-7).
(xix) Carbon content of each other solid output containing carbon (expressed as a decimal fraction) (Equation Q-7).
(xx) Annual mass of each other gaseous input containing carbon fed to each furnace (metric tons) (Equation Q-7).
(xxi) Carbon content of each other gaseous input containing carbon fed to each furnace (expressed as a decimal fraction) (Equation Q-7).
(xxii) Annual mass of each other gaseous output containing carbon produced by each furnace (metric tons) (Equation Q-7).
(xxiii) Carbon content of each other gaseous output containing carbon produced by each furnace (expressed as a decimal fraction) (Equation Q-7).
(xxiv) Annual mass of each other liquid input containing carbon fed to each furnace (metric tons) (Equation Q-7).
(xxv) Carbon content of each other liquid input containing carbon fed to each furnace (expressed as a decimal fraction) (Equation Q-7).
(xxvi) Annual mass of each other liquid output containing carbon produced by each furnace (metric tons) (Equation Q-7).
(xxvii) Carbon content of each other liquid output containing carbon produced by each furnace (expressed as a decimal fraction) (Equation Q-7).
(8) The data in paragraphs (f)(8)(i) and (ii) of this section for each process unit for which the site-specific emission factor method was used.
(i) Average hourly feed or production rate, as applicable, during the test (metric tons/hour) (as used in § 98.173(b)(2)(iii)).
(ii) Annual total feed or production, as applicable (metric tons) (as used in § 98.173(b)(2)(iv)).
(9) Total coal charged to the coke ovens for each process (metric tons/year)(as used in § 98.173(c)).
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
The lead production source category consists of primary lead smelters and secondary lead smelters. A primary lead smelter is a facility engaged in the production of lead metal from lead sulfide ore concentrates through the use of pyrometallurgical techniques. A secondary lead smelter is a facility at which lead-bearing scrap materials (including but not limited to, lead-acid batteries) are recycled by smelting into elemental lead or lead alloys.
You must report GHG emissions under this subpart if your facility contains a lead production process and the facility meets the requirements of either § 98.2(a)(1) or (a)(2).
You must report:
(a) Process CO
(b) CO
(c) CH
(d) CO
You must calculate and report the annual process CO
(a) For each smelting furnace that meets the conditions specified in § 98.33(b)(4)(ii) or (b)(4)(iii), you must calculate and report combined process and combustion CO
(b) For each smelting furnace that is not subject to the requirements in paragraph (a) of this section, calculate and report the process and combustion CO
(1) Calculate and report under this subpart the combined process and combustion CO
(2) Calculate and report process and combustion CO
(i) For each smelting furnace, determine the annual mass of carbon in each carbon-containing material, other than fuel, that is fed, charged, or otherwise introduced into the smelting furnace and estimate annual process CO
(ii) Determine the combined annual process CO
(iii) Calculate and report under subpart C of this part (General Stationary Fuel Combustion Sources) the combustion CO
If you determine process CO
(a) Determine the annual mass for each material used for the calculations of annual process CO
(b) For each 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. 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 each year. The carbon content of the material must be analyzed at least annually using the 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, and 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
A complete record of all measured parameters used in the GHG emissions calculations in § 98.183 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) For each missing data for the carbon content for the smelting furnaces at your facility that estimate annual process CO
(b) For missing records of the monthly mass of carbon-containing materials, the substitute data value must be based the best available estimate of the mass of the material from all available process data or data used for accounting purposes (such as purchase records).
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.
(a) If a CEMS is used to measure CO
(1) Identification number of each smelting furnace.
(2) Annual lead product production capacity (tons).
(3) Annual production for each lead product (tons).
(4) Total number of smelting furnaces at facility used for lead production.
(b) If a CEMS is not used to measure CO
(1) Identification number of each smelting furnace. (2) Annual process CO
(3) Annual lead product production capacity for the facility and each smelting furnace(tons).
(4) Annual production for each lead product (tons).
(5) Total number of smelting furnaces at facility used for production of lead products reported in paragraph (b)(4) of this section.
(6)-(7) [Reserved]
(8) List the method used for the determination of carbon content for each material used for the calculation of annual process CO
(9) If you use the missing data procedures in § 98.185(b), you must report how the monthly mass of carbon-containing materials with missing data was determined and the number of months the missing data procedures were used.
In addition to the records required by § 98.3(g), you must retain the records of the information specified in paragraphs (a) through (d) of this section, as applicable to the smelting furnaces at your facility.
(a) If a CEMS is used to measure combined process and combustion CO
(1) Monthly smelting furnace production quantity for each lead product (tons).
(2) Number of smelting furnace operating hours each month.
(3) Number of smelting furnace operating hours in calendar year.
(b) If the carbon mass balance procedure is used to determine process CO
(1) Monthly smelting furnace production quantity for each lead product (tons).
(2) Number of smelting furnace operating hours each month.
(3) Number of smelting furnace operating hours in calendar year.
(4) Monthly material quantity consumed, used, or produced for each material included for the calculations of annual process CO
(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
(c) You must keep records that include a detailed explanation of how company records of measurements are used to estimate the carbon input to each smelting furnace, including documentation of any materials excluded from Equation R-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 smelting furnace 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)
(1) Annual mass of lead ore charged to each smelting furnace (tons) (Equation R-1 of § 98.183).
(2) Carbon content of the lead ore per furnace, from the carbon analysis results (percent by weight, expressed as a decimal fraction) (Equation R-1).
(3) Annual mass of lead scrap charged to each smelting furnace (tons) (Equation R-1).
(4) Carbon content of the lead scrap per furnace, from the carbon analysis (percent by weight, expressed as a decimal fraction) (Equation R-1).
(5) Annual mass of flux materials (e.g., limestone, dolomite) charged to each smelting furnace (tons) (Equation R-1).
(6) Carbon content of the flux materials per furnace, from the carbon analysis (percent by weight, expressed as a decimal fraction) (Equation R-1).
(7) Annual mass of carbonaceous materials (e.g., coal, coke) charged to each smelting furnace (tons) (Equation R-1).
(8) Carbon content of the carbonaceous materials per furnace, from the carbon analysis (percent by weight, expressed as a decimal fraction) (Equation R-1).
(9) Annual mass of each other material containing carbon, other than fuel, fed, charged, or otherwise introduced into the smelting furnace (tons) (Equation R-1).
(10) Carbon content of each other material, from the carbon analysis results per furnace (percent by weight, expressed as a decimal fraction) (Equation R-1).
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
(a) Lime manufacturing plants (LMPs) engage in the manufacture of a
(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 lime manufacturing source category consists of marketed and non-marketed 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).
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).
You must report:
(a) CO
(b) CO
(c) N
(d) CO
(e) CO
You must calculate and report the annual process CO
(a) If all lime kilns meet the conditions specified in § 98.33(b)(4)(ii) or (iii), you must calculate and report under this subpart the combined process and combustion CO
(b) If CEMS are not required to be used to determine CO
(1) Calculate and report under this subpart the combined process and combustion CO
(2) Calculate and report process and combustion CO
(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:
(ii) You must calculate a monthly emission factor for each type of calcined byproduct or waste sold (including lime kiln dust) using Equation S-2 of this section:
(iii) You must calculate the annual CO
(iv) You must calculate annual CO
(v) Calculate and report under subpart C of this part (General Stationary Fuel Combustion Sources) the combustion CO
(vi) You must calculate an annual average emission factor for each type of lime product produced using Equation S-5 of this section.
(vii) You must calculate an annual average emission factor for each type of calcined byproduct/waste by lime type that is sold using Equation S-6 of this section.
(viii) You must calculate an annual average result of chemical composition analysis of each type of lime product produced and calcined byproduct/waste sold using Equations S-7 through S-10 of this section.
(a) You must determine the total quantity of each type of lime product that is produced and each calcined byproduct or 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
(b) You must determine the annual quantity of each calcined byproduct or 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 or 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 byproduct or waste sold according to paragraph (c)(1) or (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 or waste sold on a monthly basis. You must determine the chemical composition for each type of calcined byproduct or 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—
(2) The National Lime Association's CO
(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
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 of lime products, 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) 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 or 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).
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.
(a) If a CEMS is used to measure CO
(1) Method used to determine the quantity of lime that is produced and quantity of lime that is sold.
(2) Method used to determine the quantity of calcined lime byproduct or 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 or wastes sold, by type.
(5) Annual amount of calcined lime byproduct or waste sold, by type (tons).
(6) Annual amount of lime product sold, by type (tons).
(7) Annual amount of calcined lime byproduct or 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
(1) Annual CO
(2)-(3) [Reserved]
(4) Standard method used (ASTM or NLA testing method) to determine chemical compositions of each lime type produced and each calcined lime byproduct or waste type.
(5)-(6) [Reserved]
(7) Method used to determine the quantity of lime produced and/or lime sold.
(8) [Reserved]
(9) Method used to determine the quantity of calcined lime byproduct or waste sold.
(10)-(12) [Reserved]
(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 or 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
(i) The annual amount of CO
(ii) The method used to determine the amount of CO
(18) Annual quantity (tons) of lime product sold, by type.
(19) Annual average emission factors for each lime product type produced.
(20) Annual average emission factors for each calcined byproduct/waste by lime type that is sold.
(21) Annual average results of chemical composition analysis of each type of lime product produced and calcined byproduct/waste sold.
In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) through (c) of this section.
(a) Annual operating hours in calendar year.
(b) Records of all analyses (e.g. chemical composition of lime products, by type) and calculations conducted.
(c)
(1) Monthly calcium oxide content for each lime type, determined according to § 98.194(c) (metric tons CaO/metric ton lime) (Equation S-1 of § 98.193).
(2) Monthly magnesium oxide content for each lime type, determined according to § 98.194(c) (metric tons MgO/metric ton lime) (Equation S-1).
(3) Monthly calcium oxide content for each calcined lime byproduct or waste type sold (metric tons CaO/metric ton lime) (Equation S-2 of § 98.193).
(4) Monthly magnesium oxide content for each calcined lime byproduct or waste type sold (metric tons MgO/metric ton lime) (Equation S-2).
(5) Calcium oxide content for each calcined lime byproduct or waste type that is not sold (metric tons CaO/metric ton lime) (Equation S-3 of § 98.193).
(6) Magnesium oxide content for each calcined lime byproduct or waste type that is not sold (metric tons MgO/metric ton lime) (Equation S-3).
(7) Annual weight or mass of calcined byproducts or wastes for lime type that is not sold (tons) (Equation S-3).
(8) Monthly weight or mass of each lime type produced (tons) (Equation S-4 of § 98.193).
(9) Monthly weight or mass of each calcined byproducts or wastes sold (tons) (Equation S-4).
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
75 FR 39761, July 12, 2010, unless otherwise noted.
The magnesium production and processing source category consists of the following processes:
(a) Any process in which magnesium metal is produced through smelting (including electrolytic smelting), refining, or remelting operations.
(b) Any process in which molten magnesium is used in alloying, casting, drawing, extruding, forming, or rolling operations.
You must report GHG emissions under this subpart if your facility contains a magnesium production process and the facility meets the requirements of either § 98.2(a)(1) or (2).
(a) You must report emissions of the following gases in metric tons per year resulting from their use as cover gases or carrier gases in magnesium production or processing:
(1) Sulfur hexafluoride (SF
(2) HFC-134a.
(3) The fluorinated ketone, FK 5-1-12.
(4) Carbon dioxide (CO
(5) Any other GHGs (as defined in § 98.6).
(b) You must report under subpart C of this part (General Stationary Fuel Combustion Sources) the CO
(a) Calculate the mass of each GHG emitted from magnesium production or processing over the calendar year using either Equation T-1 or Equation T-2 of this section, as appropriate. Both of these equations equate emissions of cover gases or carrier gases to consumption of cover gases or carrier gases.
(1) To estimate emissions of cover gases or carrier gases by monitoring changes in container masses and inventories, emissions of each cover gas or carrier gas shall be estimated using Equation T-1 of this section:
(2) To estimate emissions of cover gases or carrier gases by monitoring changes in the masses of individual containers as their contents are used, emissions of each cover gas or carrier gas shall be estimated using Equation T-2 of this section:
(b) For purposes of Equation T-2 of this section, the mass of the cover gas used over the period p for an individual container shall be estimated by using Equation T-3 of this section:
(c) If a facility has mass flow controllers (MFC) and the capacity to track and record MFC measurements to estimate total gas usage, the mass of each cover or carrier gas monitored may be used as the mass of cover or carrier gas consumed (Q
(a) For calendar year 2011 monitoring, the facility may submit a request to the Administrator to use one or more best available monitoring methods as listed in § 98.3(d)(1)(i) through (iv). The request must be submitted no later than October 12, 2010 and must contain the information in § 98.3(d)(2)(ii). To obtain approval, the request must demonstrate to the Administrator's satisfaction that it is not reasonably feasible to acquire, install, and operate a required piece of monitoring equipment by January 1, 2011. The use of best available monitoring methods will not be approved beyond December 31, 2011.
(b) Emissions (consumption) of cover gases and carrier gases may be estimated by monitoring the changes in container weights and inventories using Equation T-1 of this subpart, by monitoring the changes in individual container weights as the contents of each container are used using Equations T-2 and T-3 of this subpart, or by monitoring the mass flow of the pure cover gas or carrier gas into the gas distribution system. Emissions must be estimated at least annually.
(c) When estimating emissions by monitoring the mass flow of the pure cover gas or carrier gas into the gas distribution system, you must use gas flow meters, or mass flow controllers, with an accuracy of 1 percent of full scale or better.
(d) When estimating emissions using Equation T-1 of this subpart, you must ensure that all the quantities required by Equation T-1 of this subpart have been measured using scales or load cells with an accuracy of 1 percent of full scale or better, accounting for the tare weights of the containers. You may accept gas masses or weights provided by the gas supplier
(e) When estimating emissions using Equations T-2 and T-3 of this subpart,
(1) Track the identities and masses of containers leaving and entering storage with check-out and check-in sheets and procedures. The masses of cylinders returning to storage shall be measured immediately before the cylinders are put back into storage.
(2) Ensure that all the quantities required by Equations T-2 and T-3 of this subpart have been measured using scales or load cells with an accuracy of 1 percent of full scale or better, accounting for the tare weights of the containers. You may accept gas masses or weights provided by the gas supplier
(f) All flowmeters, scales, and load cells used to measure quantities that are to be reported under this subpart shall be calibrated using calibration procedures specified by the flowmeter, scale, or load cell manufacturer. Calibration shall be performed prior to the first reporting year. After the initial calibration, recalibration shall be performed at the minimum frequency specified by the manufacturer.
(a) A complete record of all measured parameters used in the GHG emission calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter will be used in the calculations as specified in paragraph (b) of this section.
(b) Replace missing data on the emissions of cover or carrier gases by multiplying magnesium production during the missing data period by the average cover or carrier gas usage rate from the most recent period when operating conditions were similar to those for the period for which the data are missing. Calculate the usage rate for each cover or carrier gas using Equation T-4 of this section:
(c) If the precise before and after weights are not available, it should be assumed that the container was emptied in the process (
In addition to the information required by § 98.3(c), each annual report must include the following information at the facility level:
(a) Emissions of each cover or carrier gas in metric tons.
(b) Types of production processes at the facility (
(c) Amount of magnesium produced or processed in metric tons for each process type. This includes the output of primary and secondary magnesium production processes and the input to magnesium casting processes.
(d) Cover and carrier gas flow rate (
(e) For any missing data, you must report the length of time the data were missing for each cover gas or carrier gas, the method used to estimate emissions in their absence, and the quantity of emissions thereby estimated.
(f) The annual cover gas usage rate for the facility for each cover gas, excluding the carrier gas (kg gas/metric ton Mg).
(g) If applicable, an explanation of any change greater than 30 percent in the facility's cover gas usage rate (
(h) A description of any new melt protection technologies adopted to account for reduced or increased GHG emissions in any given year.
In addition to the records specified in § 98.3(g), you must retain the following information at the facility level:
(a) Check-out and weigh-in sheets and procedures for gas cylinders.
(b) Accuracy certifications and calibration records for scales including the method or manufacturer's specification used for calibration.
(c) Residual gas amounts (heel) in cylinders sent back to suppliers.
(d) Records, including invoices, for gas purchases, sales, and disbursements for all GHGs.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Additionally, some sector-specific definitions are provided below:
(a) This source category includes any equipment that uses carbonates listed in Table U-1 in manufacturing processes that emit carbon dioxide. Table U-1 includes the following carbonates: limestone, dolomite, ankerite, magnesite, siderite, rhodochrosite, or sodium carbonate. Facilities are considered to emit CO
(b) This source category does not include equipment that uses carbonates or carbonate containing minerals that are consumed in the production of cement, glass, ferroalloys, iron and steel, lead, lime, phosphoric acid, pulp and paper, soda ash, sodium bicarbonate, sodium hydroxide, or zinc.
(c) This source category does not include carbonates used in sorbent technology used to control emissions from stationary fuel combustion equipment. Emissions from carbonates used in sorbent technology are reported under 40 CFR 98, subpart C (Stationary Fuel Combustion Sources).
You must report GHG emissions from miscellaneous uses of carbonate if your facility uses carbonates as defined in § 98.210 of this subpart and the facility meets the requirements of either § 98.2(a)(1) or (a)(2).
You must report CO
You must determine CO
(a) Calculate the process emissions of CO
(a) The annual mass of carbonate consumed (for Equation U-1 of this subpart) or carbonate inputs (for Equation U-2 of this subpart) must be determined annually from monthly measurements using the same plant instruments used for accounting purposes including purchase records or direct measurement, such as weigh hoppers or weigh belt feeders.
(b) The annual mass of carbonate outputs (for Equation U-2 of this subpart) must be determined annually from monthly measurements using the same plant instruments used for accounting purposes including purchase records or direct measurement, such as weigh hoppers or belt weigh feeders.
(c) If you follow the procedures of § 98.213(a), as an alternative to assuming a calcination fraction of 1.0, you can determine on an annual basis the calcination fraction for each carbonate consumed based on sampling and chemical analysis using a suitable method such as using an x-ray fluorescence standard method or other enhanced industry consensus standard method published by an industry consensus standard organization (e.g., ASTM, ASME, etc.).
(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, a substitute data value for the missing parameter shall be used in the calculations as specified in paragraph (b) of this section. You must document and keep records of the procedures used for all such estimates.
(b) For each missing value of monthly carbonate consumed, monthly carbonate output, or monthly carbonate input, the substitute data value must be the best available estimate based on
In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) through (g) of this section at the facility level, as applicable.
(a) Annual CO
(b) [Reserved]
(c) Measurement method used to determine the mass of carbonate.
(d) Method used to calculate emissions.
(e) If you followed the calculation method of § 98.213(a), you must report the information in paragraphs (e)(1) through (3) of this section.
(1)-(2) [Reserved]
(3) If you determined the calcination fraction, indicate which standard method was used.
(f) [Reserved]
(g) Number of times in the reporting year that missing data procedures were followed to measure carbonate consumption, carbonate input or carbonate output (months).
In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) through (e) of this section:
(a) Monthly carbonate consumption (by carbonate type in tons).
(b) You must document the procedures used to ensure the accuracy of the monthly measurements of carbonate consumption, carbonate input or carbonate output including, but not limited to, calibration of weighing equipment and other measurement devices.
(c) Records of all analyses conducted to meet the requirements of this rule.
(d) Records of all calculations conducted.
(e)
(1) Fraction calcination achieved for each particular carbonate type. As an alternative to measuring the calcination fraction, a value of 1.0 can be used (decimal fraction) (Equation U-1 of § 98.213).
(2) Annual mass of each carbonate type consumed (tons) (Equation U-1).
(3) Annual mass of each input carbonate type (tons) (Equation U-2 of § 98.213).
(4) Annual mass of each output carbonate type (tons) (Equation U-2).
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
This source category includes a nitric acid production facility using one or more trains to produce weak nitric acid (30 to 70 percent in strength). Starting with reporting year 2018, this source category includes all nitric acid production facilities using one or more trains to produce nitric acid (any strength). A nitric acid train produces nitric acid through the catalytic oxidation of ammonia.
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).
(a) You must report N
(b) You must report under subpart C of this part (General Stationary Fuel Combustion Sources) the emissions of CO
(a) You must determine annual N
(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
(i) If you received Administrator approval for an alternative method of determining N
(ii) You must notify the EPA of your use of a previously approved alternative method in your annual report.
(iii) Otherwise, if you have not received Administrator approval for an alternative method of determining N
(iv) 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
(b) You must conduct an annual performance test for each nitric acid train according to paragraphs (b)(1) through (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). If multiple nitric acid trains exhaust to a common abatement technology and/or emission point, 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 multiple processes are operating and base the site-specific emission factor on the combined production rate of the multiple nitric acid trains.
(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 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:
(d) If nitric acid train “t” exhausts to any N
(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
(e) If nitric acid train “t” exhausts to any N
(f) [Reserved]
(g) You must calculate N
(1) If nitric acid train “t” exhausts to one N
(2) If multiple N
(3) If multiple N
(4) If nitric acid train “t” does not exhaust to any N
(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:
(i) You must determine the total annual amount of nitric acid produced on each nitric acid train “t” (tons acid produced, 100 percent acid basis), according to § 98.224(f).
(a) You must conduct a new performance test according to a test plan as specified in paragraphs (a)(1) through (3) of this section.
(1) Conduct the performance test annually. The test should be conducted at a point during the campaign which is representative of the average emissions rate from the nitric acid campaigns. 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
(b) You must measure the N
(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 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 acid basis) from each nitric acid train during the performance test according to paragraphs (c)(1) or (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.
(1) Analysis of samples, determination of emissions, and raw data.
(2) All information and data used to derive the emissions factor(s).
(3) The production rate during each test and how it was determined.
(e) You must determine the total monthly amount of nitric acid produced. You must also determine the monthly amount of nitric acid produced while N
(f) You must determine the annual amount of nitric acid produced. You must also determine the annual amount of nitric acid produced while N
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 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
In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) through (q) of this section.
(a) Nitric Acid train identification number.
(b) Annual process N
(c) [Reserved]
(d) [Reserved]
(e) Annual nitric acid production from the nitric acid facility (tons, 100 percent acid basis).
(f) Number of nitric acid trains.
(g) Number of different N
(h) Abatement technologies used (if applicable).
(i) [Reserved]
(j) [Reserved]
(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 (7) of this section.
(1) [Reserved]
(2) Test method used for performance test.
(3)-(6) [Reserved]
(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
(1) Name of alternative method.
(2) Description of alternative method.
(3) Request date.
(4) Approval date.
(o) [Reserved]
(p) [Reserved]
(q) Annual percent N
At 81 FR 89260, Dec. 9, 2018, § 98.226 was amended by revising paragraph (h), effective Jan. 1, 2019. For the convenience of the user, the revised text is set forth as follows:
(h) Abatement technologies used (if applicable) and date of installation of abatement technology.
In addition to the information required by § 98.3(g), you must retain the records specified in paragraphs (a) through (h) 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.
(h)
(1) Annual nitric acid produced from each nitric acid train (tons nitric acid produced, 100% acid basis).
(2) Indicate which equation was used to calculate emissions for each nitric acid train.
(3) N
(4) Volumetric flow rate of effluent gas per test run during the performance test (dscf/hr) (Equation V-1).
(5) Production rate per test run during the performance test (tons nitric acid produced per hour, 100 percent acid basis) (Equation V-1).
(6) Annual nitric acid production from each nitric acid train during which each N
(7) Destruction efficiency of N
(8) Destruction efficiency of each N
(9) Destruction efficiency of each N
(10) Fraction control factor of each N
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
75 FR 74488, Nov. 30, 2010, unless otherwise noted.
(a) This source category consists of the following industry segments:
(1)
(2)
(3)
(4)
(5)
(6)
(7)
(8)
(9)
(10)
(b) [Reserved]
(a) You must report GHG emissions under this subpart if your facility contains petroleum and natural gas systems and the facility meets the requirements of § 98.2(a)(2), except for the industry segments in paragraphs (a)(1) through (4) of this section.
(1) Facilities must report emissions from the onshore petroleum and natural gas production industry segment only if emission sources specified in § 98.232(c) emit 25,000 metric tons of CO
(2) Facilities must report emissions from the natural gas distribution industry segment only if emission sources specified in § 98.232(i) emit 25,000 metric tons of CO
(3) Facilities must report emissions from the onshore petroleum and natural gas gathering and boosting industry segment only if emission sources specified in § 98.232(j) emit 25,000 metric tons of CO
(4) Facilities must report emissions from the onshore natural gas transmission pipeline industry segment only if emission sources specified in § 98.232(m) emit 25,000 metric tons of CO
(b) For applying the threshold defined in § 98.2(a)(2), natural gas processing facilities must also include owned or operated residue gas compression equipment.
(a) You must report CO
(b) For offshore petroleum and natural gas production, report CO
(c) For an onshore petroleum and natural gas production facility, report CO
(1) Natural gas pneumatic device venting.
(2) [Reserved]
(3) Natural gas driven pneumatic pump venting.
(4) Well venting for liquids unloading.
(5) Gas well venting during well completions without hydraulic fracturing.
(6) Well venting during well completions with hydraulic fracturing that have a GOR of 300 scf/STB or greater (oil here refers to hydrocarbon liquids produced of all API gravities).
(7) Gas well venting during well workovers without hydraulic fracturing.
(8) Well venting during well workovers with hydraulic fracturing that have a GOR of 300 scf/STB or greater (oil here refers to hydrocarbon liquids produced of all API gravities).
(9) Flare stack emissions.
(10) Storage tanks vented emissions from produced hydrocarbons.
(11) Reciprocating compressor venting.
(12) Well testing venting and flaring.
(13) Associated gas venting and flaring from produced hydrocarbons.
(14) Dehydrator vents.
(15) [Reserved]
(16) EOR injection pump blowdown.
(17) Acid gas removal vents.
(18) EOR hydrocarbon liquids dissolved CO
(19) Centrifugal compressor venting.
(20) [Reserved]
(21) Equipment leaks from valves, connectors, open ended lines, pressure relief valves, pumps, flanges, and other components (such as instruments, loading arms, stuffing boxes, compressor seals, dump lever arms, and breather caps, but does not include components listed in paragraph (c)(11) or (19) of this section, and it does not include thief hatches or other openings on a storage vessel).
(22) You must use the methods in § 98.233(z) and report under this subpart the emissions of CO
(d) For onshore natural gas processing, report CO
(1) Reciprocating compressor venting.
(2) Centrifugal compressor venting.
(3) Blowdown vent stacks.
(4) Dehydrator vents.
(5) Acid gas removal vents.
(6) Flare stack emissions.
(7) Equipment leaks from valves, connectors, open ended lines, pressure relief valves, and meters.
(e) For onshore natural gas transmission compression, report CO
(1) Reciprocating compressor venting.
(2) Centrifugal compressor venting.
(3) Transmission storage tanks.
(4) Blowdown vent stacks.
(5) Natural gas pneumatic device venting.
(6) Flare stack emissions.
(7) Equipment leaks from valves, connectors, open ended lines, pressure relief valves, and meters.
(8) Equipment leaks from all other components that are not listed in paragraph (e)(1), (2), or (7) of this section and are either subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter or you elect to survey using a leak detection method described in § 98.234(a)(6) or (7). The other components subject to this paragraph (e)(8) also do not include thief hatches or other openings on a storage vessel. If these other components are not subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter, you may also elect to report emissions from these other components if you elect to survey them using a leak detection method described in § 98.234(a)(1) through (5).
(f) For underground natural gas storage, report CO
(1) Reciprocating compressor venting.
(2) Centrifugal compressor venting.
(3) Natural gas pneumatic device venting.
(4) Flare stack emissions.
(5) Equipment leaks from valves, connectors, open ended lines, pressure relief valves, and meters associated with storage stations.
(6) Equipment leaks from all other components that are associated with storage stations, are not listed in paragraph (f)(1), (2), or (5) of this section, and are either subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter or you elect to survey using a leak detection method described in § 98.234(a)(6) or (7). If these other components are not subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter, you may also elect to report emissions from these other components if you elect to survey them using a leak detection method described in § 98.234(a)(1) through (5).
(7) Equipment leaks from valves, connectors, open-ended lines, and pressure relief valves associated with storage wellheads.
(8) Equipment leaks from all other components that are associated with storage wellheads, are not listed in paragraph (f)(1), (2), or (7) of this section, and are either subject to the well site or compressor station fugitive emissions standards in § 60.5397a, of this chapter or you elect to survey using a leak detection method described in § 98.234(a)(6) or (7). If these other components are not subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter, you may also elect to report emissions from these other components if you elect to survey them using a leak detection method described in § 98.234(a)(1) through (5).
(g) For LNG storage, report CO
(1) Reciprocating compressor venting.
(2) Centrifugal compressor venting.
(3) Flare stack emissions.
(4) Equipment leaks from valves, pump seals, connectors, and other equipment leak sources in LNG service.
(5) Equipment leaks from vapor recovery compressors, if you do not survey components associated with vapor recovery compressors in accordance with paragraph (g)(6) of this section.
(6) Equipment leaks from all components in gas service that are associated with a vapor recovery compressor, are not listed in paragraph (g)(1) or (2) of this section, and that are either subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter or you elect to survey using a leak detection method described in § 98.234(a).
(7) Equipment leaks from all components in gas service that are not associated with a vapor recovery compressor, are not listed in paragraph (g)(1) or (2) of this section, and are either subject to the well site or compressor station fugitive emissions
(h) LNG import and export equipment, report CO
(1) Reciprocating compressor venting.
(2) Centrifugal compressor venting.
(3) Blowdown vent stacks.
(4) Flare stack emissions.
(5) Equipment leaks from valves, pump seals, connectors, and other equipment leak sources in LNG service.
(6) Equipment leaks from vapor recovery compressors, if you do not survey components associated with vapor recovery compressors in accordance with paragraph (h)(7) of this section.
(7) Equipment leaks from all components in gas service that are associated with a vapor recovery compressor, are not listed in paragraph (h)(1) or (2) of this section, and that are either subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter or you elect to survey using a leak detection method described in § 98.234(a).
(8) Equipment leaks from all components in gas service that are not associated with a vapor recovery compressor, are not listed in paragraph (h)(1) or (2) of this section, and that are either subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter or you elect to survey using a leak detection method described in § 98.234(a)(6) or (7). If these components are not subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter, you may also elect to report emissions from these components if you elect to survey them using a leak detection method described in § 98.234(a)(1) through (5).
(i) For natural gas distribution, report CO
(1) Equipment leaks from connectors, block valves, control valves, pressure relief valves, orifice meters, regulators, and open-ended lines at above grade transmission-distribution transfer stations.
(2) Equipment leaks at below grade transmission-distribution transfer stations.
(3) Equipment leaks at above grade metering-regulating stations that are not above grade transmission-distribution transfer stations.
(4) Equipment leaks at below grade metering-regulating stations.
(5) Distribution main equipment leaks.
(6) Distribution services equipment leaks.
(7) Report under subpart W of this part the emissions of CO
(j) For an onshore petroleum and natural gas gathering and boosting facility, report CO
(1) Natural gas pneumatic device venting.
(2) Natural gas driven pneumatic pump venting.
(3) Acid gas removal vents.
(4) Dehydrator vents.
(5) Blowdown vent stacks.
(6) Storage tank vented emissions.
(7) Flare stack emissions.
(8) Centrifugal compressor venting.
(9) Reciprocating compressor venting.
(10) Equipment leaks from valves, connectors, open ended lines, pressure relief valves, pumps, flanges, and other components (such as instruments, loading arms, stuffing boxes, compressor seals, dump lever arms, and breather caps, but does not include components in paragraph (j)(8) or (9) of this section, and it does not include thief hatches or other openings on a storage vessel).
(11) Gathering pipeline equipment leaks.
(12) You must use the methods in § 98.233(z) and report under this subpart the emissions of CO
(k) Report under subpart C of this part (General Stationary Fuel Combustion Sources) the emissions of CO
(l) You must report under subpart PP of this part (Suppliers of Carbon Dioxide), CO
(m) For onshore natural gas transmission pipeline, report pipeline blowdown CO
You must calculate and report the annual GHG emissions as prescribed in this section. For calculations that specify measurements in actual conditions, reporters may use a flow or volume measurement system that corrects to standard conditions and determine the flow or volume at standard conditions; otherwise, reporters must use average atmospheric conditions or typical operating conditions as applicable to the respective monitoring methods in this section.
(a)
(1) For all industry segments, determine “Count
(2) For the onshore petroleum and natural gas production industry segment, you have the option in the first two consecutive calendar years to determine “Count
(3) For all industry segments, determine the type of pneumatic device using engineering estimates based on best available information.
(4) Calculate both CH
(b) [Reserved]
(c)
(2) Calculate both CH
(d)
(1)
(2)
(3)
(4)
(i) Natural gas feed temperature, pressure, and flow rate.
(ii) Acid gas content of feed natural gas.
(iii) Acid gas content of outlet natural gas.
(iv) Unit operating hours, excluding downtime for maintenance or standby.
(v) Exit temperature of natural gas.
(vi) Solvent pressure, temperature, circulation rate, and weight.
(5) For Calculation Method 3, determine the gas flow rate of the inlet when using Equation W-4A of this section or the gas flow rate of the outlet when using Equation W-4B of this section for the natural gas stream of an AGR unit using a meter according to methods set forth in § 98.234(b). If you do not have a continuous flow meter, either install a continuous flow meter or use an engineering calculation to determine the flow rate.
(6) For Calculation Method 2, if a continuous gas analyzer is not available on the vent stack, either install a continuous gas analyzer or take quarterly gas samples from the vent gas stream for each quarter that the AGR unit is operating to determine Vol
(7) For Calculation Method 3, if a continuous gas analyzer is installed on the inlet gas stream, then the continuous gas analyzer results must be used. If a continuous gas analyzer is not available, either install a continuous gas analyzer or take quarterly gas samples from the inlet gas stream for each quarter that the AGR unit is operating to determine Vol
(8) For Calculation Method 3, determine annual average volumetric fraction of CO
(i) If a continuous gas analyzer is installed on the outlet gas stream, then the continuous gas analyzer results must be used. If a continuous gas analyzer is not available, you may install a continuous gas analyzer.
(ii) If a continuous gas analyzer is not available or installed, quarterly gas samples may be taken from the outlet gas stream for each quarter that the AGR unit is operating to determine Vol
(iii) If a continuous gas analyzer is not available or installed, you may use the outlet pipeline quality specification for CO
(9) Calculate annual volumetric CO
(10) Calculate annual mass CO
(11) Determine if CO
(e)
(1)
(i) Feed natural gas flow rate.
(ii) Feed natural gas water content.
(iii) Outlet natural gas water content.
(iv) Absorbent circulation pump type (
(v) Absorbent circulation rate.
(vi) Absorbent type (
(vii) Use of stripping gas.
(viii) Use of flash tank separator (and disposition of recovered gas).
(ix) Hours operated.
(x) Wet natural gas temperature and pressure.
(xi) Wet natural gas composition. Determine this parameter using one of the methods described in paragraphs (e)(1)(xi)(A) through (D) of this section.
(A) Use the GHG mole fraction as defined in paragraph (u)(2)(i) or (ii) of this section.
(B) If the GHG mole fraction cannot be determined using paragraph (u)(2)(i) or (ii) of this section, select a representative analysis.
(C) You may use an appropriate standard method published by a consensus-based standards organization if such a method exists or you may use an industry standard practice as specified in § 98.234(b) to sample and analyze wet natural gas composition.
(D) If only composition data for dry natural gas is available, assume the wet natural gas is saturated.
(2)
(3)
(4) For glycol dehydrators that use the calculation method in paragraph (e)(2) of this section, calculate both
(5) Determine if the dehydrator unit has vapor recovery. Adjust the emissions estimated in paragraphs (e)(1), (2), and (3) of this section downward by the magnitude of emissions recovered using a vapor recovery system as determined by engineering estimate based on best available data.
(6) Calculate annual emissions from dehydrator vents to flares or regenerator fire-box/fire tubes as follows:
(i) Use the dehydrator vent volume and gas composition as determined in paragraphs (e)(1) through (5) of this section, as applicable.
(ii) Use the calculation method of flare stacks in paragraph (n) of this section to determine dehydrator vent emissions from the flare or regenerator combustion gas vent.
(f)
(1)
(i) Determine the well vent average flow rate (“FR” in Equation W-7A of this section) as specified in paragraphs (f)(1)(i)(A) through (C) of this section for at least one well in a unique well tubing diameter group and pressure group combination in each sub-basin category. Calculate emissions from wells with plunger lifts and wells without plunger lifts separately.
(A) Calculate the average flow rate per hour of venting for each unique tubing diameter group and pressure group combination in each sub-basin category by dividing the recorded total annual flow by the recorded time (in hours) for all measured liquid unloading events with venting to the atmosphere.
(B) Apply the average hourly flow rate calculated under paragraph (f)(1)(i)(A) of this section to all wells in the same pressure group that have the same tubing diameter group, for the number of hours of venting these wells.
(C) Calculate a new average flow rate every other calendar year starting with the first calendar year of data collection. For a new producing sub-basin category, calculate an average flow rate beginning in the first year of production.
(ii) Calculate natural gas volumetric emissions at standard conditions using calculations in paragraph (t) of this section.
(2)
(3)
(4) Calculate CH
(g)
(1) If you elect to use Equation W-10A of this section on gas wells, you must use Calculation Method 1 as specified in paragraph (g)(1)(i) of this section, or Calculation Method 2 as specified in paragraph (g)(1)(ii) of this section, to determine the value of FRM
(i)
(ii)
(iii) For Equation W-10A of this section, calculate FRM
(iv) For Equation W-10A of this section, calculate FRM
(v) For Equation W-10A of this section, the ratio of gas flowback rate during well completions and workovers from hydraulic fracturing to 30-day gas production rate are applied to all well completions and well workovers, respectively, in the sub-basin and well type combination for the total number of hours of flowback and for the first 30 day average gas production rate for each of these wells.
(vi) For Equations W-12A and W-12B of this section, calculate new flowback rates for well completions and well workovers in each sub-basin and well type combination once every two years starting in the first calendar year of data collection.
(vii) For oil wells where the gas production rate is not metered and you elect to use Equation W-10A of this section, calculate the average gas production rate (PR
(A) You may use an appropriate standard method published by a consensus-based standards organization if such a method exists.
(B) You may use an industry standard practice as described in § 98.234(b).
(2) For paragraphs (g) introductory text and (g)(1) of this section, measurements and calculations are completed separately for workovers and completions per sub-basin and well type combination. A well type combination is a unique combination of the parameters listed in paragraphs (g)(2)(i) through (iv) of this section.
(i) Vertical or horizontal (directional drilling).
(ii) With flaring or without flaring.
(iii) Reduced emission completion/workover or not reduced emission completion/workover.
(iv) Oil well or gas well.
(3) Calculate both CH
(4) Calculate annual emissions from well venting during well completions and workovers from hydraulic fracturing where all or a portion of the gas is flared as specified in paragraphs (g)(4)(i) and (ii) of this section.
(i) Use the volumetric total natural gas emissions vented to the atmosphere during well completions and workovers as determined in paragraph (g) of this section to calculate volumetric and mass emissions using paragraphs (u) and (v) of this section.
(ii) Use the calculation method of flare stacks in paragraph (n) of this section to adjust emissions for the portion of gas flared during well completions and workovers using hydraulic fracturing. This adjustment to emissions from completions using flaring, versus completions without flaring, accounts for the conversion of CH
(h)
(1) Calculate both CH
(2) Calculate annual emissions of CH
(i) Use the gas well venting volume and gas composition during well completions and workovers that are flared as determined using the methods specified in paragraphs (h) and (h)(1) of this section.
(ii) Use the calculation method of flare stacks in paragraph (n) of this section to determine emissions from the flare for gas well venting to a flare during completions and workovers without hydraulic fracturing.
(i)
(1)
(2)
(i) Calculate the total annual natural gas emissions from each unique physical volume that is blown down using either Equation W-14A or W-14B of this section.
(ii) Except as allowed in paragraph (i)(2)(iii) of this section, calculate annual CH
(iii) For onshore natural gas transmission compression facilities and LNG import and export equipment, as an alternative to using the procedures in paragraph (i)(2)(ii) of this section, you may elect to sum the annual natural gas emissions as calculated using either Equation W-14A or Equation W-14B of paragraph (i)(2)(i) of this section for all unique physical volumes associated with the equipment type or event type. Calculate the total annual CH
(3)
(4)
(j)
(1)
(i) Separator or non-separator equipment temperature.
(ii) Separator or non-separator equipment pressure.
(iii) Sales oil or stabilized oil API gravity.
(iv) Sales oil or stabilized oil production rate.
(v) Ambient air temperature.
(vi) Ambient air pressure.
(vii) Separator or non-separator equipment oil composition and Reid vapor pressure. If this data is not available, determine these parameters by using one of the methods described in paragraphs (j)(1)(vii)(A) through (C) of this section.
(A) If separator or non-separator equipment oil composition and Reid vapor pressure default data are provided with the software program, select the default values that most closely match your separator or non-separator equipment pressure first, and API gravity secondarily.
(B) If separator or non-separator equipment oil composition and Reid vapor pressure data are available through your previous analysis, select the latest available analysis that is representative of produced crude oil or condensate from the sub-basin category for onshore petroleum and natural gas production or from the county for onshore petroleum and natural gas gathering and boosting.
(C) Analyze a representative sample of separator or non-separator equipment oil in each sub-basin category for onshore petroleum and natural gas production or each county for onshore petroleum and natural gas gathering and boosting for oil composition and Reid vapor pressure using an appropriate standard method published by a consensus-based standards organization.
(2)
(i)
(ii)
(A) If well production oil and gas compositions are available through a previous analysis, select the latest available analysis that is representative of produced oil and gas from the sub-basin category and assume all of the CH
(B) If well production oil and gas compositions are not available, use default oil and gas compositions in software programs, such as API 4697 E&P Tank, that most closely match the well production gas/oil ratio and API gravity and assume all of the CH
(iii)
(A) If other non-separator equipment liquid and gas compositions are available through a previous analysis, select the latest available analysis that is representative of liquid and gas from non-separator equipment in the same county and assume all of the CH
(B) If non-separator equipment liquid and gas compositions are not available, use default liquid and gas compositions in software programs, such as API 4697 E&P Tank, that most closely match the non-separator equipment gas/liquid ratio and API gravity and assume all of the CH
(3)
(4) Determine if the storage tank receiving your separator oil has a vapor recovery system.
(i) Adjust the emissions estimated in paragraphs (j)(1) through (3) of this section downward by the magnitude of emissions recovered using a vapor recovery system as determined by engineering estimate based on best available data.
(ii) [Reserved]
(5) Determine if the storage tank receiving your separator oil is sent to flare(s).
(i) Use your separator flash gas volume and gas composition as determined in this section.
(ii) Use the calculation method of flare stacks in paragraph (n) of this
(6) If you use Calculation Method 1 or Calculation Method 2 in paragraph (j)(1) or (2) of this section, calculate emissions from occurrences of gas-liquid separator liquid dump valves not closing during the calendar year by using Equation W-16 of this section.
(7) Calculate both CH
(k)
(1) Except as specified in paragraph (k)(1)(iv) of this section, you must monitor the tank vapor vent stack annually for emissions using one of the methods specified in paragraphs (k)(1)(i) through (iii) of this section.
(i) Use an optical gas imaging instrument according to methods set forth in § 98.234(a)(1).
(ii) Measure the tank vent directly using a flow meter or high volume sampler according to methods in § 98.234(b) or (d) for a duration of 5 minutes.
(iii) Measure the tank vent using a calibrated bag according to methods in § 98.234(c) for a duration of 5 minutes or until the bag is full, whichever is shorter.
(iv) You may annually monitor leakage through compressor scrubber dump valve(s) into the tank using an acoustic leak detection device according to methods set forth in § 98.234(a)(5).
(2) If the tank vapors from the vent stack are continuous for 5 minutes, or the optical gas imaging instrument or acoustic leak detection device detects a leak, then you must use one of the methods in either paragraph (k)(2)(i) or (ii) of this section.
(i) Use a flow meter, such as a turbine meter, calibrated bag, or high volume sampler to estimate tank vapor volumes from the vent stack according to methods set forth in § 98.234(b) through (d). If you do not have a continuous flow measurement device, you may install a flow measuring device on the tank vapor vent stack. If the vent is directly measured for five minutes under paragraph (k)(1)(ii) or (iii) of this section to detect continuous leakage, this serves as the measurement.
(ii) Use an acoustic leak detection device on each scrubber dump valve connected to the tank according to the method set forth in § 98.234(a)(5).
(3) If a leaking dump valve is identified, the leak must be counted as having occurred since the beginning of the calendar year, or from the previous test that did not detect leaking in the
(4) Use the requirements specified in paragraphs (k)(4)(i) and (ii) of this section to quantify annual emissions.
(i) Use the appropriate gas composition in paragraph (u)(2)(iii) of this section.
(ii) Calculate CH
(5) Calculate annual emissions from storage tanks to flares as specified in paragraphs (k)(5)(i) and (ii) of this section.
(i) Use the storage tank emissions volume and gas composition as determined in paragraphs (k)(1) through (4) of this section.
(ii) Use the calculation method of flare stacks in paragraph (n) of this section to determine storage tank emissions sent to a flare.
(l)
(1) Determine the gas to oil ratio (GOR) of the hydrocarbon production from oil well(s) tested. Determine the production rate from gas well(s) tested.
(2) If GOR cannot be determined from your available data, then you must measure quantities reported in this section according to one of the procedures specified in paragraph (l)(2)(i) or (ii) of this section to determine GOR.
(i) You may use an appropriate standard method published by a consensus-based standards organization if such a method exists.
(ii) You may use an industry standard practice as described in § 98.234(b).
(3) Estimate venting emissions using Equation W-17A (for oil wells) or Equation W-17B (for gas wells) of this section.
(4) Calculate natural gas volumetric emissions at standard conditions using calculations in paragraph (t) of this section.
(5) Calculate both CH
(6) Calculate emissions from well testing if emissions are routed to a flare as specified in paragraphs (l)(6)(i) and (ii) of this section.
(i) Use the well testing emissions volume and gas composition as determined in paragraphs (l)(1) through (4) of this section.
(ii) Use the calculation method of flare stacks in paragraph (n) of this section to determine well testing emissions from the flare.
(m)
(1) Determine the GOR of the hydrocarbon production from each well whose associated natural gas is vented or flared. If GOR from each well is not available, use the GOR from a cluster of wells in the same sub-basin category.
(2) If GOR cannot be determined from your available data, then you must use one of the procedures specified in paragraphs (m)(2)(i) or (ii) of this section to determine GOR.
(i) You may use an appropriate standard method published by a consensus-based standards organization if such a method exists.
(ii) You may use an industry standard practice as described in § 98.234(b).
(3) Estimate venting emissions using Equation W-18 of this section.
(4) Calculate both CH
(5) Calculate emissions from associated natural gas if emissions are routed to a flare as specified in paragraphs (m)(5)(i) and (ii) of this section.
(i) Use the associated natural gas volume and gas composition as determined in paragraph (m)(1) through (4) of this section.
(ii) Use the calculation method of flare stacks in paragraph (n) of this section to determine associated gas emissions from the flare.
(n)
(1) If you have a continuous flow measurement device on the flare, you must use the measured flow volumes to calculate the flare gas emissions. If all of the flare gas is not measured by the existing flow measurement device, then the flow not measured can be estimated using engineering calculations based on best available data or company records. If you do not have a continuous flow measurement device on the flare, you can use engineering calculations based on process knowledge, company records, and best available data.
(2) If you have a continuous gas composition analyzer on gas to the flare, you must use these compositions in calculating emissions. If you do not have a continuous gas composition analyzer on gas to the flare, you must use the appropriate gas compositions for each stream of hydrocarbons going to the flare as specified in paragraphs (n)(2)(i) through (iii) of this section.
(i) For onshore natural gas production and onshore petroleum and natural gas gathering and boosting, determine the GHG mole fraction using paragraph (u)(2)(i) of this section.
(ii) For onshore natural gas processing, when the stream going to flare is natural gas, use the GHG mole fraction in feed natural gas for all streams upstream of the de-methanizer or dew point control, and GHG mole fraction in facility specific residue gas to transmission pipeline systems for all emissions sources downstream of the de-methanizer overhead or dew point control for onshore natural gas processing facilities. For onshore natural gas processing plants that solely fractionate a liquid stream, use the GHG mole fraction in feed natural gas liquid for all streams.
(iii) For any industry segment required to report to flare stack emissions under § 98.232, when the stream going to the flare is a hydrocarbon product stream, such as methane, ethane, propane, butane, pentane-plus and mixed light hydrocarbons, then you may use a representative composition from the source for the stream determined by engineering calculation based on process knowledge and best available data.
(3) Determine flare combustion efficiency from manufacturer. If not available, assume that flare combustion efficiency is 98 percent.
(4) Convert GHG volumetric emissions to standard conditions using calculations in paragraph (t) of this section.
(5) Calculate GHG volumetric emissions from flaring at standard conditions using Equations W-19 and W-20 of this section.
(6) Calculate both CH
(7) Calculate N
(8) If you operate and maintain a CEMS that has both a CO
(9) The flare emissions determined under this paragraph (n) must be corrected for flare emissions calculated and reported under other paragraphs of this section to avoid double counting of these emissions.
(o)
(1)
(i) Centrifugal compressor source as found measurements. Measure venting from each compressor according to either paragraph (o)(1)(i)(A) or (B) of this section at least once annually, based on the compressor mode (as defined in § 98.238) in which the compressor was found at the time of measurement, except as specified in paragraphs (o)(1)(i)(C) and (D) of this section. If additional measurements beyond the required annual testing are performed (including duplicate measurements or measurement of additional operating modes), then all measurements satisfying the applicable monitoring and QA/QC that is required by this paragraph (o) must be used in the calculations specified in this section.
(A) For a compressor measured in operating-mode, you must measure volumetric emissions from blowdown valve leakage through the blowdown vent as specified in either paragraph (o)(2)(i)(A) or (B) of this section and, if the compressor has wet seal oil degassing vents, measure volumetric emissions from wet seal oil degassing vents as specified in paragraph (o)(2)(ii) of this section.
(B) For a compressor measured in not-operating-depressurized-mode, you must measure volumetric emissions from isolation valve leakage as specified in either paragraph (o)(2)(i)(A), (B), or (C) of this section. If a compressor is not operated and has blind flanges in place throughout the reporting period, measurement is not required in this compressor mode.
(C) You must measure the compressor as specified in paragraph (o)(1)(i)(B) of this section at least once in any three consecutive calendar years, provided the measurement can be taken during a scheduled shutdown. If three consecutive calendar years occur without measuring the compressor in not-operating-depressurized-mode, you must measure the compressor as specified in paragraph (o)(1)(i)(B) of this section at the next scheduled depressurized shutdown. The
(D) An annual as found measurement is not required in the first year of operation for any new compressor that begins operation after as found measurements have been conducted for all existing compressors. For only the first year of operation of new compressors, calculate emissions according to paragraph (o)(6)(ii) of this section.
(ii) Centrifugal compressor source continuous monitoring. Instead of measuring the compressor source according to paragraph (o)(1)(i) of this section for a given compressor, you may elect to continuously measure volumetric emissions from a compressor source as specified in paragraph (o)(3) of this section.
(iii) Manifolded centrifugal compressor source as found measurements. For a compressor source that is part of a manifolded group of compressor sources (as defined in § 98.238), instead of measuring the compressor source according to paragraph (o)(1)(i), (ii), or (iv) of this section, you may elect to measure combined volumetric emissions from the manifolded group of compressor sources by conducting measurements at the common vent stack as specified in paragraph (o)(4) of this section. The measurements must be conducted at the frequency specified in paragraphs (o)(1)(iii)(A) and (B) of this section.
(A) A minimum of one measurement must be taken for each manifolded group of compressor sources in a calendar year.
(B) The measurement may be performed while the compressors are in any compressor mode.
(iv) Manifolded centrifugal compressor source continuous monitoring. For a compressor source that is part of a manifolded group of compressor sources, instead of measuring the compressor source according to paragraph (o)(1)(i), (ii), or (iii) of this section, you may elect to continuously measure combined volumetric emissions from the manifolded group of compressor sources as specified in paragraph (o)(5) of this section.
(2)
(i) For blowdown valves on compressors in operating-mode and for isolation valves on compressors in not-operating-depressurized-mode, determine the volumetric emissions using one of the methods specified in paragraphs (o)(2)(i)(A) through (D) of this section.
(A) Determine the volumetric flow at standard conditions from the blowdown vent using calibrated bagging or high volume sampler according to methods set forth in § 98.234(c) and § 98.234(d), respectively.
(B) Determine the volumetric flow at standard conditions from the blowdown vent using a temporary meter such as a vane anemometer according to methods set forth in § 98.234(b).
(C) Use an acoustic leak detection device according to methods set forth in § 98.234(a)(5).
(D) You may choose to use any of the methods set forth in § 98.234(a) to screen for emissions. If emissions are detected using the methods set forth in § 98.234(a), then you must use one of the methods specified in paragraph (o)(2)(i)(A) through (C) of this section. If emissions are not detected using the methods in § 98.234(a), then you may assume that the volumetric emissions are zero. For the purposes of this paragraph, when using any of the methods in § 98.234(a), emissions are detected whenever a leak is detected according to the methods.
(ii) For wet seal oil degassing vents in operating-mode, determine vapor volumes at standard conditions, using
(3)
(i) Continuously measure the volumetric flow for the individual compressor source at standard conditions using a permanent meter according to methods set forth in § 98.234(b).
(ii) If compressor blowdown emissions are included in the metered emissions specified in paragraph (o)(3)(i) of this section, the compressor blowdown emissions may be included with the reported emissions for the compressor source and do not need to be calculated separately using the method specified in paragraph (i) of this section for blowdown vent stacks.
(4)
(i) Measure at a single point in the manifold downstream of all compressor inputs and, if practical, prior to comingling with other non-compressor emission sources.
(ii) Determine the volumetric flow at standard conditions from the common stack using one of the methods specified in paragraphs (o)(4)(ii)(A) through (E) of this section.
(A) A temporary meter such as a vane anemometer according the methods set forth in § 98.234(b).
(B) Calibrated bagging according to methods set forth in § 98.234(c).
(C) A high volume sampler according to methods set forth § 98.234(d).
(D) An acoustic leak detection device according to methods set forth in § 98.234(a)(5).
(E) You may choose to use any of the methods set forth in § 98.234(a) to screen for emissions. If emissions are detected using the methods set forth in § 98.234(a), then you must use one of the methods specified in paragraph (o)(4)(ii)(A) through (o)(4)(ii)(D) of this section. If emissions are not detected using the methods in § 98.234(a), then you may assume that the volumetric emissions are zero. For the purposes of this paragraph, when using any of the methods in § 98.234(a), emissions are detected whenever a leak is detected according to the method.
(5)
(i) Measure at a single point in the manifold downstream of all compressor inputs and, if practical, prior to comingling with other non-compressor emission sources.
(ii) Continuously measure the volumetric flow for the manifolded group of compressor sources at standard conditions using a permanent meter according to methods set forth in § 98.234(b).
(iii) If compressor blowdown emissions are included in the metered emissions specified in paragraph (o)(5)(ii) of this section, the compressor blowdown emissions may be included with the reported emissions for the manifolded group of compressor sources and do not need to be calculated separately using the method specified in paragraph (i) of this section for blowdown vent stacks.
(6)
(i) Using Equation W-21 of this section, calculate the annual volumetric GHG emissions for each centrifugal compressor mode-source combination specified in paragraphs (o)(1)(i)(A) and
(ii) Using Equation W-22 of this section, calculate the annual volumetric GHG emissions from each centrifugal compressor mode-source combination specified in paragraph (o)(1)(i)(A) and (B) of this section that was not measured during the reporting year.
(iii) Using Equation W-23 of this section, develop an emission factor for each compressor mode-source combination specified in paragraph (o)(1)(i)(A) and (B) of this section. These emission factors must be calculated annually and used in Equation W-22 of this section to determine volumetric emissions from a centrifugal compressor in the mode-source combinations that were not measured in the reporting year.
(iv) The reporter emission factor in Equation W-23 of this section may be calculated by using all measurements from a single owner or operator instead of only using measurements from a single facility. If you elect to use this option, the reporter emission factor must be applied to all reporting facilities for the owner or operator.
(7)
(8)
(9)
(10)
(11)
(12)
(i) Paragraphs (o)(1) through (11) of this section are not required for compressor sources that are routed to a flare.
(ii) If any compressor sources are routed to a flare, calculate the emissions for the flare stack as specified in
(iii) Report all applicable activity data for compressors with compressor sources routed to flares as specified in § 98.236(o).
(p)
(1)
(i) Reciprocating compressor source as found measurements. Measure venting from each compressor according to either paragraph (p)(1)(i)(A), (B), or (C) of this section at least once annually, based on the compressor mode (as defined in § 98.238) in which the compressor was found at the time of measurement, except as specified in paragraphs (p)(1)(i)(D) and (E) of this section. If additional measurements beyond the required annual testing are performed (including duplicate measurements or measurement of additional operating modes), then all measurements satisfying the applicable monitoring and QA/QC that is required by this paragraph (o) must be used in the calculations specified in this section.
(A) For a compressor measured in operating-mode, you must measure volumetric emissions from blowdown valve leakage through the blowdown vent as specified in either paragraph (p)(2)(i)(A) or (B) of this section, and measure volumetric emissions from reciprocating rod packing as specified in paragraph (p)(2)(ii) of this section.
(B) For a compressor measured in standby-pressurized-mode, you must measure volumetric emissions from blowdown valve leakage through the blowdown vent as specified in either paragraph (p)(2)(i)(A) or (B) of this section.
(C) For a compressor measured in not-operating-depressurized-mode, you must measure volumetric emissions from isolation valve leakage as specified in either paragraph (p)(2)(i)(A), (B), or (C) of this section. If a compressor is not operated and has blind flanges in place throughout the reporting period, measurement is not required in this compressor mode.
(D) You must measure the compressor as specified in paragraph (p)(1)(i)(C) of this section at least once in any three consecutive calendar years, provided the measurement can be taken during a scheduled shutdown. If there is no scheduled shutdown within three consecutive calendar years, you must measure the compressor as specified in paragraph (p)(1)(i)(C) of
(E) An annual as found measurement is not required in the first year of operation for any new compressor that begins operation after as found measurements have been conducted for all existing compressors. For only the first year of operation of new compressors, calculate emissions according to paragraph (p)(6)(ii) of this section.
(ii) Reciprocating compressor source continuous monitoring. Instead of measuring the compressor source according to paragraph (p)(1)(i) of this section for a given compressor, you may elect to continuously measure volumetric emissions from a compressor source as specified in paragraph (p)(3) of this section.
(iii) Manifolded reciprocating compressor source as found measurements. For a compressor source that is part of a manifolded group of compressor sources (as defined in § 98.238), instead of measuring the compressor source according to paragraph (p)(1)(i), (ii), or (iv) of this section, you may elect to measure combined volumetric emissions from the manifolded group of compressor sources by conducting measurements at the common vent stack as specified in paragraph (p)(4) of this section. The measurements must be conducted at the frequency specified in paragraphs (p)(1)(iii)(A) and (B) of this section.
(A) A minimum of one measurement must be taken for each manifolded group of compressor sources in a calendar year.
(B) The measurement may be performed while the compressors are in any compressor mode.
(iv) Manifolded reciprocating compressor source continuous monitoring. For a compressor source that is part of a manifolded group of compressor sources, instead of measuring the compressor source according to paragraph (p)(1)(i), (ii), or (iii) of this section, you may elect to continuously measure combined volumetric emissions from the manifolded group of compressors sources as specified in paragraph (p)(5) of this section.
(2)
(i) For blowdown valves on compressors in operating-mode or standby-pressurized-mode, and for isolation valves on compressors in not-operating-depressurized-mode, determine the volumetric emissions using one of the methods specified in paragraphs (p)(2)(i)(A) through (D) of this section.
(A) Determine the volumetric flow at standard conditions from the blowdown vent using calibrated bagging or high volume sampler according to methods set forth in § 98.234(c) and (d), respectively.
(B) Determine the volumetric flow at standard conditions from the blowdown vent using a temporary meter such as a vane anemometer, according to methods set forth in § 98.234(b).
(C) Use an acoustic leak detection device according to methods set forth in § 98.234(a)(5).
(D) You may choose to use any of the methods set forth in § 98.234(a) to screen for emissions. If emissions are detected using the methods set forth in § 98.234(a), then you must use one of the methods specified in paragraphs (p)(2)(i)(A) through (C) of this section. If emissions are not detected using the methods in § 98.234(a), then you may assume that the volumetric emissions are zero. For the purposes of this paragraph, when using any of the methods in § 98.234(a), emissions are detected whenever a leak is detected according to the method.
(ii) For reciprocating rod packing equipped with an open-ended vent line on compressors in operating-mode, determine the volumetric emissions using one of the methods specified in
(A) Determine the volumetric flow at standard conditions from the open-ended vent line using calibrated bagging or high volume sampler according to methods set forth in § 98.234(c) and (d), respectively.
(B) Determine the volumetric flow at standard conditions from the open-ended vent line using a temporary meter such as a vane anemometer, according to methods set forth in § 98.234(b).
(C) You may choose to use any of the methods set forth in § 98.234(a) to screen for emissions. If emissions are detected using the methods set forth in § 98.234(a), then you must use one of the methods specified in paragraph (p)(2)(ii)(A) and (p)(4)(ii)(B) of this section. If emissions are not detected using the methods in § 98.234(a), then you may assume that the volumetric emissions are zero. For the purposes of this paragraph, when using any of the methods in § 98.234(a), emissions are detected whenever a leak is detected according to the method.
(iii) For reciprocating rod packing not equipped with an open-ended vent line on compressors in operating-mode, you must determine the volumetric emissions using the method specified in paragraphs (p)(2)(iii)(A) and (B) of this section.
(A) You must use the methods described in § 98.234(a) to conduct annual leak detection of equipment leaks from the packing case into an open distance piece, or for compressors with a closed distance piece, conduct annual detection of gas emissions from the rod packing vent, distance piece vent, compressor crank case breather cap, or other vent emitting gas from the rod packing.
(B) You must measure emissions found in paragraph (p)(2)(iii)(A) of this section using an appropriate meter, calibrated bag, or high volume sampler according to methods set forth in § 98.234(b), (c), and (d), respectively.
(3)
(i) Continuously measure the volumetric flow for the individual compressor sources at standard conditions using a permanent meter according to methods set forth in § 98.234(b).
(ii) If compressor blowdown emissions are included in the metered emissions specified in paragraph (p)(3)(i) of this section, the compressor blowdown emissions may be included with the reported emissions for the compressor source and do not need to be calculated separately using the method specified in paragraph (i) of this section for blowdown vent stacks.
(4)
(i) Measure at a single point in the manifold downstream of all compressor inputs and, if practical, prior to comingling with other non-compressor emission sources.
(ii) Determine the volumetric flow at standard conditions from the common stack using one of the methods specified in paragraph (p)(4)(ii)(A) through (E) of this section.
(A) A temporary meter such as a vane anemometer according the methods set forth in § 98.234(b).
(B) Calibrated bagging according to methods set forth in § 98.234(c).
(C) A high volume sampler according to methods set forth § 98.234(d).
(D) An acoustic leak detection device according to methods set forth in § 98.234(a)(5).
(E) You may choose to use any of the methods set forth in § 98.234(a) to screen for emissions. If emissions are detected using the methods set forth in § 98.234(a), then you must use one of the methods specified in paragraph (p)(4)(ii)(A) through (D) of this section. If emissions are not detected using the methods in § 98.234(a), then you may assume that the volumetric emissions are zero. For the purposes of this paragraph, when using any of the methods
(5)
(i) Measure at a single point in the manifold downstream of all compressor inputs and, if practical, prior to comingling with other non-compressor emission sources.
(ii) Continuously measure the volumetric flow for the manifolded group of compressor sources at standard conditions using a permanent meter according to methods set forth in § 98.234(b).
(iii) If compressor blowdown emissions are included in the metered emissions specified in paragraph (p)(5)(ii) of this section, the compressor blowdown emissions may be included with the reported emissions for the manifolded group of compressor sources and do not need to be calculated separately using the method specified in paragraph (i) of this section for blowdown vent stacks.
(6)
(i) Using Equation W-26 of this section, calculate the annual volumetric GHG emissions for each reciprocating compressor mode-source combination specified in paragraphs (p)(1)(i)(A) through (C) of this section that was measured during the reporting year.
(ii) Using Equation W-27 of this section, calculate the annual volumetric GHG emissions from each reciprocating compressor mode-source combination specified in paragraph (p)(1)(i)(A), (B), and (C) of this section that was not measured during the reporting year.
(iii) Using Equation W-28 of this section, develop an emission factor for each compressor mode-source combination specified in paragraph (p)(1)(i)(A), (B), and (C) of this section. These emission factors must be calculated annually and used in Equation W-27 of this section to determine volumetric emissions from a reciprocating compressor in the mode-source combinations that were not measured in the reporting year.
(iv) The reporter emission factor in Equation W-28 of this section may be calculated by using all measurements from a single owner or operator instead of only using measurements from a single facility. If you elect to use this option, the reporter emission factor must be applied to all reporting facilities for the owner or operator.
(7)
(8)
(9)
(10)
(11)
(12)
(i) Paragraphs (p)(1) through (11) of this section are not required for compressor sources that are routed to a flare.
(ii) If any compressor sources are routed to a flare, calculate the emissions for the flare stack as specified in paragraph (n) of this section and report emissions from the flare as specified in § 98.236(n), without subtracting emissions attributable to compressor sources from the flare.
(iii) Report all applicable activity data for compressors with compressor sources routed to flares as specified in § 98.236(p).
(q)
(1)
(ii) For the components listed in § 98.232(d)(7) and (i)(1), you must conduct surveys using any of the leak detection methods listed in § 98.234(a)(1) through (5) and calculate equipment leak emissions using the procedures specified in paragraph (q)(2) of this section.
(iii) For the components listed in § 98.232(c)(21), (e)(7), (e)(8), (f)(5), (f)(6), (f)(7), (f)(8), (g)(4), (g)(6), (g)(7), (h)(5), (h)(7), (h)(8), and (j)(10) that are subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter, you must conduct surveys using any of the leak detection methods in § 98.234(a)(6) or (7) and calculate equipment leak emissions using the procedures specified in paragraph (q)(2) of this section.
(iv) For the components listed in § 98.232(c)(21), (e)(8), (f)(6), (f)(7), (f)(8), (g)(6), (g)(7), (h)(7), (h)(8), or (j)(10), that are not subject to fugitive emissions standards in § 60.5397a of this chapter, you may elect to conduct surveys according to this paragraph (q), and, if you elect to do so, then you must use one of the leak detection methods in § 98.234(a).
(A) If you elect to use a leak detection method in § 98.234(a)(1) through (5) for the surveyed component types in § 98.232(c)(21), (f)(7), (g)(6), (h)(7), or (j)(10) in lieu of the population count methodology specified in paragraph (r) of this section, then you must calculate emissions for the surveyed component types in § 98.232(c)(21), (f)(7), (g)(6), (h)(7), or (j)(10) using the procedures in paragraph (q)(2) of this section.
(B) If you elect to use a leak detection method in § 98.234(a)(1) through (5) for the surveyed component types in § 98.232(e)(8), (f)(6), (f)(8), (g)(7), and (h)(8), then you must use the procedures in paragraph (q)(2) of this section to calculate those emissions.
(C) If you elect to use a leak detection method in § 98.234(a)(6) or (7) for any elective survey under this subparagraph (q)(1)(iv), then you must survey the component types in § 98.232(c)(21), (e)(8), (f)(6), (f)(7), (f)(8), (g)(6), (g)(7), (h)(7), (h)(8), and (j)(10) that are not subject to fugitive emissions standards in § 60.5397a of this chapter, and you must calculate emissions from the surveyed component types in § 98.232(c)(21), (e)(8), (f)(6), (f)(7), (f)(8), (g)(6), (g)(7), (h)(7), (h)(8), and (j)(10) using the emission calculation requirements in paragraph (q)(2) of this section.
(2)
(i) You must conduct at least one leak detection survey in a calendar year. The leak detection surveys selected must be conducted during the calendar year. If you conduct multiple complete leak detection surveys in a calendar year, you must use the results from each complete leak detection survey when calculating emissions using Equation W-30. For components subject to the well site and compressor station fugitive emissions standards in § 60.5397a of this chapter, each survey conducted in accordance with § 60.5397a of this chapter will be considered a complete leak detection survey for purposes of this section.
(ii) Calculate both CO
(iii) Onshore petroleum and natural gas production facilities must use the appropriate default whole gas leaker emission factors for components in gas service, light crude service, and heavy crude service listed in Table W-1E to this subpart.
(iv) Onshore petroleum and natural gas gathering and boosting facilities must use the appropriate default whole gas leaker factors for components in gas service listed in Table W-1E to this subpart.
(v) Onshore natural gas processing facilities must use the appropriate default total hydrocarbon leaker emission factors for compressor components in gas service and non-compressor components in gas service listed in Table W-2 to this subpart.
(vi) Onshore natural gas transmission compression facilities must use the appropriate default total hydrocarbon leaker emission factors for compressor components in gas service and non-compressor components in gas service listed in Table W-3A to this subpart.
(vii) Underground natural gas storage facilities must use the appropriate default total hydrocarbon leaker emission factors for storage stations or storage wellheads in gas service listed in Table W-4A to this subpart.
(viii) LNG storage facilities must use the appropriate default methane leaker emission factors for LNG storage components in LNG service or gas service listed in Table W-5A to this subpart.
(ix) LNG import and export facilities must use the appropriate default methane leaker emission factors for LNG terminals components in LNG service or gas service listed in Table W-6A to this subpart.
(x) Natural gas distribution facilities must use Equation W-30 of this section and the default methane leaker emission factors for transmission-distribution transfer station components in gas service listed in Table W-7 to this subpart to calculate component emissions from annual equipment leak surveys conducted at above grade transmission-distribution transfer stations. Natural gas distribution facilities are required to perform equipment leak surveys only at above grade stations that qualify as transmission-distribution transfer stations. Below grade transmission-distribution transfer stations and all metering-regulating stations that do not meet the definition of transmission-distribution transfer stations are not required to perform equipment leak surveys under this section.
(A) Natural gas distribution facilities may choose to conduct equipment leak surveys at all above grade transmission-distribution transfer stations over multiple years “n,” not exceeding a five year period to cover all above grade transmission-distribution transfer stations. If the facility chooses to use the multiple year option, then the
(B) Use Equation W-31 of this section to determine the meter/regulator run population emission factors for each GHG
(C) The emission factor “EFs,
(xi) If you chose to conduct equipment leak surveys at all above grade
(r)
(1) Calculate both CH
(2) Onshore petroleum and natural gas production facilities and onshore petroleum and natural gas gathering and boosting facilities must use the appropriate default whole gas population emission factors listed in Table W-1A of this subpart. Major equipment and components associated with gas wells and onshore petroleum and natural gas gathering and boosting systems are considered gas service components in reference to Table W-1A of this subpart and major natural gas equipment in reference to Table W-1B of this subpart. Major equipment and components associated with crude oil wells are considered crude service components in reference to Table W-1A of this subpart and major crude oil equipment in reference to Table W-1C of this subpart. Where facilities conduct EOR operations the emissions factor listed in Table W-1A of this subpart shall be used to estimate all streams of gases, including recycle CO
(i)
(A) Count all major equipment listed in Table W-1B and Table W-1C of this subpart. For meters/piping, use one meters/piping per well-pad for onshore petroleum and natural gas production operations and the number of meters in the facility for onshore petroleum and natural gas gathering and boosting operations.
(B) Multiply major equipment counts by the average component counts listed in Table W-1B of this subpart for onshore natural gas production and onshore petroleum and natural gas gathering and boosting; and Table W-1C of this subpart for onshore oil production. Use the appropriate factor in Table W-1A of this subpart for operations in Eastern and Western U.S. according to the mapping in Table W-1D of this subpart.
(ii)
(3) Underground natural gas storage facilities must use the appropriate default total hydrocarbon population emission factors for storage wellheads in gas service listed in Table W-4B to this subpart.
(4) LNG storage facilities must use the appropriate default methane population emission factor for LNG storage compressors in gas service listed in Table W-5B to this subpart.
(5) LNG import and export facilities must use the appropriate default methane population emission factor for LNG terminal compressors in gas service listed in Table W-6B to this subpart.
(6) Natural gas distribution facilities must use the appropriate methane emission factors as described in paragraphs (r)(6)(i) and (ii) of this section.
(i) Below grade metering-regulating stations, distribution mains, and distribution services must use the appropriate default methane population emission factors listed in Table W-7 of this subpart. Below grade transmission-distribution transfer stations must use the emission factor for below grade metering-regulating stations.
(ii) Above grade metering-regulating stations that are not above grade transmission-distribution transfer stations must use the meter/regulator run population emission factor calculated in Equation W-31. Natural gas distribution facilities that do not have above grade transmission-distribution transfer stations are not required to calculate emissions for above grade metering-regulating stations and are not required to report GHG emissions in § 98.236(r)(2)(v).
(s)
(1) Offshore production facilities under BOEMRE jurisdiction shall report the same annual emissions as calculated and reported by BOEMRE in data collection and emissions estimation study published by BOEMRE referenced in 30 CFR 250.302 through 304 (GOADS).
(i) For any calendar year that does not overlap with the most recent BOEMRE emissions study publication year, report the most recent BOEMRE reported emissions data published by BOEMRE referenced in 30 CFR 250.302 through 304 (GOADS). Adjust emissions based on the operating time for the facility relative to the operating time in the most recent BOEMRE published study.
(ii) [Reserved]
(2) Offshore production facilities that are not under BOEMRE jurisdiction must use the most recent monitoring methods and calculation methods published by BOEMRE referenced in 30 CFR 250.302 through 250.304 to calculate and report annual emissions (GOADS).
(i) For any calendar year that does not overlap with the most recent BOEMRE emissions study publication, you may report the most recently reported emissions data submitted to demonstrate compliance with this subpart of part 98, with emissions adjusted based on the operating time for the facility relative to operating time in the previous reporting period.
(ii) [Reserved]
(3) If BOEMRE discontinues or delays their data collection effort by more than 4 years, then offshore reporters shall once in every 4 years use the most recent BOEMRE data collection and emissions estimation methods to estimate emissions. These emission estimates would be used to report emissions from the facility sources as required in paragraph (s)(1)(i) of this section.
(4) For either first or subsequent year reporting, offshore facilities either within or outside of BOEMRE jurisdiction that were not covered in the previous BOEMRE data collection cycle must use the most recent BOEMRE data collection and emissions estimation methods published by BOEMRE referenced in 30 CFR 250.302 through 250.304 to calculate and report emissions.
(t)
(1) Calculate natural gas volumetric emissions at standard conditions using actual natural gas emission temperature and pressure, and Equation W-33 of this section for conversions of E
(2) Calculate GHG volumetric emissions at standard conditions using actual GHG emissions temperature and pressure, and Equation W-34 of this section.
You may use either a default compressibility factor of 1, or a site-specific compressibility factor based on actual temperature and pressure conditions.
(3) Reporters using 68 °F for standard temperature may use the ratio 519.67/527.67 to convert volumetric emissions from 68 °F to 60 °F.
(u)
(1) Estimate CH
(2) For Equation W-35 of this section, the mole fraction, M
(i)
(ii) GHG mole fraction in feed natural gas for all emissions sources upstream of the de-methanizer or dew point control and GHG mole fraction in facility specific residue gas to transmission pipeline systems for all emissions sources downstream of the de-methanizer overhead or dew point control for onshore natural gas processing facilities. For onshore natural gas processing plants that solely fractionate a liquid stream, use the GHG mole percent in feed natural gas liquid for all streams. If you have a continuous gas composition analyzer on feed natural gas, you must use these values for determining the mole fraction. If you do not have a continuous gas composition analyzer, then annual samples must be taken according to methods set forth in § 98.234(b).
(iii)
(iv)
(v)
(vi)
(vii)
(v)
ρ
(w)
(1) Calculate the total injection pump system volume in cubic feet (including pipelines, manifolds and vessels) between isolation valves.
(2) Retain logs of the number of blowdowns per calendar year.
(3) Calculate the total annual CO
(x)
(1) Determine the amount of CO
(2) Estimate emissions using Equation W-38 of this section.
S
(y) [Reserved]
(z)
(1) If a fuel combusted in the stationary or portable equipment is listed in Table C-1 of subpart C of this part, or is a blend containing one or more fuels listed in Table C-1, calculate emissions according to paragraph (z)(1)(i) of this section. If the fuel combusted is natural gas and is of pipeline quality specification and has a minimum high heat value of 950 Btu per standard cubic foot, use the calculation method described in paragraph (z)(1)(i) of this section and you may use the emission factor provided for natural gas as listed in Table C-1. If the fuel is natural gas, and is not pipeline quality or has a high heat value of less than 950 Btu per standard cubic feet, calculate emissions according to paragraph (z)(2) of this section. If the fuel is field gas, process vent gas, or a blend containing field gas or process vent gas, calculate emissions according to paragraph (z)(2) of this section.
(i) For fuels listed in Table C-1 or a blend containing one or more fuels listed in Table C-1, calculate CO
(ii) Emissions from fuel combusted in stationary or portable equipment at onshore petroleum and natural gas production facilities, at onshore petroleum and natural gas gathering and boosting facilities, and at natural gas distribution facilities will be reported according to the requirements specified in § 98.236(z) and not according to the reporting requirements specified in subpart C of this part.
(2) For fuel combustion units that combust field gas, process vent gas, a blend containing field gas or process vent gas, or natural gas that is not of pipeline quality or that has a high heat value of less than 950 Btu per standard cubic feet, calculate combustion emissions as follows:
(i) You may use company records to determine the volume of fuel combusted in the unit during the reporting year.
(ii) If you have a continuous gas composition analyzer on fuel to the combustion unit, you must use these compositions for determining the concentration of gas hydrocarbon constituent in the flow of gas to the unit. If you do not have a continuous gas composition analyzer on gas to the combustion unit, you must use the appropriate gas compositions for each stream of hydrocarbons going to the combustion unit as specified in the applicable paragraph in (u)(2) of this section.
(iii) Calculate GHG volumetric emissions at actual conditions using Equations W-39A and W-39B of this section:
(iv) Calculate GHG volumetric emissions at standard conditions using calculations in paragraph (t) of this section.
(v) Calculate both combustion-related CH
(vi) Calculate N
(3) External fuel combustion sources with a rated heat capacity equal to or less than 5 mmBtu/hr do not need to report combustion emissions or include these emissions for threshold determination in § 98.231(a). You must report the type and number of each external fuel combustion unit.
(4) Internal fuel combustion sources, not compressor-drivers, with a rated heat capacity equal to or less than 1 mmBtu/hr (or the equivalent of 130 horsepower), do not need to report combustion emissions or include these emissions for threshold determination in § 98.231(a). You must report the type and number of each internal fuel combustion unit.
The GHG emissions data for petroleum and natural gas emissions sources must be quality assured as applicable as specified in this section. Offshore petroleum and natural gas production facilities shall adhere to the monitoring and QA/QC requirements as set forth in 30 CFR 250.
(a) You must use any of the methods described in paragraphs (a)(1) through (5) of this section to conduct leak detection(s) of through-valve leakage from all source types listed in § 98.233(k), (o), and (p) that occur during a calendar year. You must use any of the methods described in paragraphs (a)(1) through (7) of this section to conduct leak detection(s) of equipment leaks from components as specified in § 98.233(q)(1)(i) that occur during a calendar year. You must use any of the methods described in paragraphs (a)(1) through (5) of this section to conduct leak detection(s) of equipment leaks from components as specified in § 98.233(q)(1)(ii) that occur during a calendar year. You must use one of the methods described in paragraph (a)(6) or (7) of this section to conduct leak detection(s) of equipment leaks from components as specified in § 98.233(q)(1)(iii). If electing to comply
(1)
(2)
(3)
(4) [Reserved]
(5)
(6) Optical gas imaging instrument as specified in § 60.5397a of this chapter. Use an optical gas imaging instrument for equipment leak detection in accordance with § 60.5397a(b), (c)(3), (c)(7), and (e) of this chapter and paragraphs (a)(6)(i) through (iii) of this section. Unless using methods in paragraph (a)(7) of this section, an optical gas imaging instrument must be used for all source types that are inaccessible and cannot be monitored without elevating the monitoring personnel more than 2 meters above a support surface.
(i) For the purposes of this subpart, any visible emissions from a component listed in § 98.232 observed by the optical gas imaging instrument is a leak.
(ii) For the purposes of this subpart, the term “fugitive emissions component” in § 60.5397a of this chapter means “component.”
(iii) For the purpose of complying with § 98.233(q)(1)(iv), the phrase “the collection of fugitive emissions components at well sites and compressor stations” in § 60.5397a(b) of this chapter means “the collection of components for which you elect to comply with § 98.233(q)(1)(iv).”
(7) Method 21 as specified in § 60.5397a of this chapter. Use the equipment leak detection methods in appendix A-7 to part 60 of this chapter, Method 21, in accordance with § 60.5397a(b), (c)(8), and (e) of this chapter and paragraphs (a)(7)(i) through (iii) of this section. Inaccessible emissions sources, as defined in part 60 of this chapter, are not exempt from this subpart. If the equipment leak detection methods in this paragraph cannot be used, you must use alternative leak detection devices as described in paragraph (a)(6) of this section to monitor inaccessible equipment leaks.
(i) For the purposes of this subpart, any instrument reading from a component listed in § 98.232 of this chapter of 500 ppm or greater using Method 21 is a leak.
(ii) For the purposes of this subpart, the term “fugitive emissions component” in § 60.5397a of this chapter means “component.”
(iii) For the purpose of complying with § 98.233(q)(1)(iv), the phrase “the collection of fugitive emissions components at well sites and compressor stations” in § 60.5397a(b) of this chapter means “the collection of components for which you elect to comply with § 98.233(q)(1)(iv).”
(b) You must operate and calibrate all flow meters, composition analyzers and pressure gauges used to measure quantities reported in § 98.233 according to the procedures in § 98.3(i) and the procedures in paragraph (b) of this section. You may use an appropriate standard method published by a consensus-based standards organization if such a method exists or you may use an industry standard practice. Consensus-based standards organizations include, but are not limited to, the following: ASTM International, the American National Standards Institute (ANSI), the American Gas Association (AGA), the American Society of Mechanical Engineers (ASME), the American Petroleum Institute (API), and the North American Energy Standards Board (NAESB).
(c) Use calibrated bags (also known as vent bags) only where the emissions are at near-atmospheric pressures and below the maximum temperature specified by the vent bag manufacturer such that the bag is safe to handle. The bag opening must be of sufficient size that the entire emission can be tightly encompassed for measurement till the bag is completely filled.
(1) Hold the bag in place enclosing the emissions source to capture the entire emissions and record the time required for completely filling the bag. If the bag inflates in less than one second, assume one second inflation time.
(2) Perform three measurements of the time required to fill the bag, report the emissions as the average of the three readings.
(3) Estimate natural gas volumetric emissions at standard conditions using calculations in § 98.233(t).
(4) Estimate CH
(d) Use a high volume sampler to measure emissions within the capacity of the instrument.
(1) A technician following manufacturer instructions shall conduct measurements, including equipment manufacturer operating procedures and measurement methods relevant to using a high volume sampler, including positioning the instrument for complete capture of the equipment leak without creating backpressure on the source.
(2) If the high volume sampler, along with all attachments available from the manufacturer, is not able to capture all the emissions from the source then use anti-static wraps or other aids
(3) Estimate natural gas volumetric emissions at standard conditions using calculations in § 98.233(t). Estimate CH
(4) Calibrate the instrument at 2.5 percent methane with 97.5 percent air and 100 percent CH
(e) Peng Robinson Equation of State means the equation of state defined by Equation W-41 of this section:
(f)
(i) Monitoring methods currently used by the facility that do not meet the specifications of this subpart.
(ii) Supplier data.
(iii) Engineering calculations.
(iv) Other company records.
(2)
(i) If Calculation Method 1 for liquids unloading in § 98.233(f)(1) was used in calendar year 2014 and will be used again in calendar year 2015, the vented natural gas flow rate for any well in a unique tubing diameter group and pressure group combination that has not been previously measured.
(ii) If using Equation W-10A of this subpart to determine natural gas emissions from completions and workovers for representative wells, the initial and average flowback rates (when using Calculation Method 1 in § 98.233(g)(1)(i)) or pressures upstream and downstream of the choke (when using Calculation Method 2 in § 98.233(g)(1)(ii)) for any well in a well type combination that has not been previously measured.
(3)
(i) Centrifugal compressor as found measurements of manifolded emissions from groups of centrifugal compressor sources according to § 98.233(o)(4) and (5), in onshore natural gas processing, onshore natural gas transmission compression, underground natural gas storage, LNG storage, and LNG import and export equipment as specified in § 98.232(d)(2), (e)(2), (f)(2), (g)(2), and (h)(2).
(ii) Reciprocating compressor as found measurements of manifolded emissions from groups of reciprocating compressor sources according to § 98.233(p)(4) and (5), in onshore natural gas processing, onshore natural gas transmission compression, underground natural gas storage, LNG storage, and LNG import and export equipment as specified in § 98.232(d)(1), (e)(1), (f)(1), (g)(1), and (h)(1).
(4)
(i)
(ii)
(A) A list of specific source types and parameters for which you are seeking use of best available monitoring methods.
(B) For each specific source type for which you are requesting use of best available monitoring methods, a description of the reasons that the needed equipment could not be obtained and installed before April 1, 2015.
(C) A description of the specific actions you will take to obtain and install the equipment as soon as reasonably feasible and the expected date by which the equipment will be installed and operating.
(iii)
(g)
(2) Best available monitoring methods means any of the following methods:
(i) Monitoring methods currently used by the facility that do not meet the specifications of this subpart.
(ii) Supplier data.
(iii) Engineering calculations.
(iv) Other company records.
(3)
(4)
(5)
(6)
(i) Cumulative hours of venting, days, or times of operation in § 98.233(e), (g), (o), (p), and (r).
(ii) Number of blowdowns, completions, workovers, or other events in § 98.233(g) and (i).
(iii) Cumulative volume produced, volume input or output, or volume of fuel used in paragraphs § 98.233(d), (e), (j), (n), and (z).
(h) For well venting for liquids unloading, if a monitoring period other than the full calendar year is used to determine the cumulative amount of time in hours of venting for each well (the term “T
Except as specified in § 98.233, whenever a value of a parameter is unavailable for a GHG emission calculation required by this subpart (including, but not limited to, if a measuring device malfunctions during unit operation or activity data are not collected), you must follow the procedures specified in paragraphs (a) through (i) of this section, as applicable.
(a) For stationary and portable combustion sources that use the calculation methods of subpart C of this part, you must use the missing data procedures in subpart C of this part.
(b) For each missing value of a parameter that should have been measured quarterly or more frequently using equipment including, but not limited to, a continuous flow meter, composition analyzer, thermocouple, or pressure gauge, you must substitute the arithmetic average of the quality-
(c) For each missing value of a parameter that should have been measured annually, you must repeat the estimation or measurement activity for those sources as soon as possible, including in the subsequent calendar year if missing data are not discovered until after December 31 of the year in which data are collected, until valid data for reporting are obtained. Data developed and/or collected in a subsequent calendar year to substitute for missing data cannot be used for that subsequent year's emissions estimation. Where missing data procedures are used for the previous year, at least 30 days must separate emissions estimation or measurements for the previous year and emissions estimation or measurements for the current year of data collection.
(d) For each missing value of a parameter that should have been measured biannually (every two years), you must conduct the estimation or measurement activity for those sources as soon as possible in the subsequent calendar year if the estimation or measurement was not made in the appropriate year (first year of data collection and every two years thereafter), until valid data for reporting are obtained. Data developed and/or collected in a subsequent calendar year to substitute for missing data cannot be used to alternate or postpone subsequent biannual emissions estimations or measurements.
(e) For the first 6 months of required data collection, facilities that become newly subject to this subpart W may use best engineering estimates for any data that cannot reasonably be measured or obtained according to the requirements of this subpart.
(f) For the first 6 months of required data collection, facilities that are currently subject to this subpart W and that acquire new sources from another facility that were not previously subject to this subpart W may use best engineering estimates for any data related to those newly acquired sources that cannot reasonably be measured or obtained according to the requirements of this subpart.
(g) Unless addressed in another paragraph of this section, for each missing value of any activity data, you must substitute data value(s) using the best available estimate(s) of the parameter(s), based on all applicable and available process or other data (including, but not limited to, processing rates, operating hours).
(h) You must report information for all measured and substitute values of a parameter, and the procedures used to substitute an unavailable value of a parameter per the requirements in § 98.236(bb).
(i) You must follow recordkeeping requirements listed in § 98.237(f).
In addition to the information required by § 98.3(c), each annual report must contain reported emissions and related information as specified in this section. Reporters that use a flow or volume measurement system that corrects to standard conditions as provided in the introductory text in § 98.233 for data elements that are otherwise required to be determined at actual conditions, report gas volumes at standard conditions rather the gas volumes at actual conditions and report the standard temperature and pressure used by the measurement system rather than the actual temperature and pressure.
(a) The annual report must include the information specified in paragraphs (a)(1) through (10) of this section for each applicable industry segment. The annual report must also include annual emissions totals, in metric tons of each GHG, for each applicable industry segment listed in paragraphs (a)(1)
(1)
(i)
(ii)
(iii)
(iv)
(v)
(vi)
(vii)
(viii)
(ix)
(x)
(xi)
(xii)
(xiii)
(xiv) Equipment leak surveys. Report the information specified in paragraph (q) of this section.
(xv)
(xvi)
(xvii)
(xviii)
(2)
(3)
(i)
(ii)
(iii)
(iv)
(v)
(vi)
(vii)
(4)
(i)
(ii)
(iii)
(iv)
(v)
(vi)
(vii)
(5)
(i)
(ii)
(iii)
(iv)
(v)
(vi)
(6)
(i)
(ii)
(iii)
(iv)
(v)
(7)
(i)
(ii)
(iii)
(iv)
(v)
(vi)
(8)
(i)
(ii)
(iii)
(9)
(i)
(ii)
(iii)
(iv)
(v)
(vi)
(vii)
(viii)
(ix)
(x) Equipment leak surveys. Report the information specified in paragraph (q) of this section.
(xi)
(xii)
(10)
(b)
(1) The number of natural gas pneumatic devices as specified in paragraphs (b)(1)(i) and (ii) of this section.
(i) The total number of devices of each type, determined according to § 98.233(a)(1) and (2).
(ii) If the reported value in paragraph (b)(1)(i) of this section is an estimated value determined according to § 98.233(a)(2), then you must report the information specified in paragraphs (b)(1)(ii)(A) through (C) of this section.
(A) The number of devices of each type reported in paragraph (b)(1)(i) of this section that are counted.
(B) The number of devices of each type reported in paragraph (b)(1)(i) of this section that are estimated (not counted).
(C) Whether the calendar year is the first calendar year of reporting or the second calendar year of reporting.
(2) For each type of pneumatic device, the estimated average number of hours in the calendar year that the natural gas pneumatic devices reported in paragraph (b)(1)(i) of this section were operating in the calendar year (“T
(3) Annual CO
(4) Annual CH
(c)
(1) Count of natural gas driven pneumatic pumps.
(2) Average estimated number of hours in the calendar year the pumps were operational (“T” in Equation W-2 of this subpart).
(3) Annual CO
(4) Annual CH
(d)
(1) You must report the information specified in paragraphs (d)(1)(i) through (vi) of this section for each acid gas removal unit.
(i) A unique name or ID number for the acid gas removal unit. For the onshore petroleum and natural gas production and the onshore petroleum and
(ii) Total feed rate entering the acid gas removal unit, using a meter or engineering estimate based on process knowledge or best available data, in million cubic feet per year.
(iii) The calculation method used to calculate CO
(iv) Whether any CO
(v) Annual CO
(vi) Sub-basin ID that best represents the wells supplying gas to the unit (for the onshore petroleum and natural gas production industry segment only) or name of the county that best represents the equipment supplying gas to the unit (for the onshore petroleum and natural gas gathering and boosting industry segment only).
(2) You must report information specified in paragraphs (d)(2)(i) through (iii) of this section, applicable to the calculation method reported in paragraph (d)(1)(iii) of this section, for each acid gas removal unit.
(i) If you used Calculation Method 1 or Calculation Method 2 as specified in § 98.233(d) to calculate CO
(A) Annual average volumetric fraction of CO
(B) Annual volume of gas vented from the acid gas removal unit, in cubic feet.
(ii) If you used Calculation Method 3 as specified in § 98.233(d) to calculate CO
(A) Indicate which equation was used (Equation W-4A or W-4B).
(B) Annual average volumetric fraction of CO
(C) Annual average volumetric fraction of CO
(D) The natural gas flow rate used, as specified in Equation W-4A of this subpart, reported as either total annual volume of natural gas flow into the acid gas removal unit in cubic feet at actual conditions; or total annual volume of natural gas flow out of the acid gas removal unit, as specified in Equation W-4B of this subpart, in cubic feet at actual conditions.
(iii) If you used Calculation Method 4 as specified in § 98.233(d) to calculate CO
(A) The name of the simulation software package used.
(B) Natural gas feed temperature, in degrees Fahrenheit.
(C) Natural gas feed pressure, in pounds per square inch.
(D) Natural gas flow rate, in standard cubic feet per minute.
(E) Acid gas content of the feed natural gas, in mole percent.
(F) Acid gas content of the outlet natural gas, in mole percent.
(G) Unit operating hours, excluding downtime for maintenance or standby, in hours per year.
(H) Exit temperature of the natural gas, in degrees Fahrenheit.
(I) Solvent pressure, in pounds per square inch.
(J) Solvent temperature, in degrees Fahrenheit.
(K) Solvent circulation rate, in gallons per minute.
(L) Solvent weight, in pounds per gallon.
(e)
(1) For each glycol dehydrator that has an annual average daily natural gas throughput greater than or equal to 0.4 million standard cubic feet per day (as specified in § 98.233(e)(1)), you must report the information specified in paragraphs (e)(1)(i) through (xviii) of this section for the dehydrator.
(i) A unique name or ID number for the dehydrator. For the onshore petroleum and natural gas production and the onshore petroleum and natural gas gathering and boosting industry segments, a different name or ID may be used for a single dehydrator for each location it operates at in a given year.
(ii) Dehydrator feed natural gas flow rate, in million standard cubic feet per day, determined by engineering estimate based on best available data.
(iii) Dehydrator feed natural gas water content, in pounds per million standard cubic feet.
(iv) Dehydrator outlet natural gas water content, in pounds per million standard cubic feet.
(v) Dehydrator absorbent circulation pump type (
(vi) Dehydrator absorbent circulation rate, in gallons per minute.
(vii) Type of absorbent (
(viii) Whether stripper gas is used in dehydrator.
(ix) Whether a flash tank separator is used in dehydrator.
(x) Total time the dehydrator is operating, in hours.
(xi) Temperature of the wet natural gas, in degrees Fahrenheit.
(xii) Pressure of the wet natural gas, in pounds per square inch gauge.
(xiii) Mole fraction of CH
(xiv) Mole fraction of CO
(xv) Whether any dehydrator emissions are vented to a vapor recovery device.
(xvi) Whether any dehydrator emissions are vented to a flare or regenerator firebox/fire tubes. If any emissions are vented to a flare or regenerator firebox/fire tubes, report the information specified in paragraphs (e)(1)(xvi)(A) through (C) of this section for these emissions from the dehydrator.
(A) Annual CO
(B) Annual CH
(C) Annual N
(xvii) Whether any dehydrator emissions are vented to the atmosphere without being routed to a flare or regenerator firebox/fire tubes. If any emissions are not routed to a flare or regenerator firebox/fire tubes, then you must report the information specified in paragraphs (e)(1)(xvii)(A) and (B) of this section for those emissions from the dehydrator.
(A) Annual CO
(B) Annual CH
(xviii) Sub-basin ID that best represents the wells supplying gas to the dehydrator (for the onshore petroleum and natural gas production industry segment only) or name of the county that best represents the equipment supplying gas to the dehydrator (for the onshore petroleum and natural gas gathering and boosting industry segment only).
(2) For glycol dehydrators with an annual average daily natural gas
(i) The total number of dehydrators at the facility.
(ii) Whether any dehydrator emissions were vented to a vapor recovery device. If any dehydrator emissions were vented to a vapor recovery device, then you must report the total number of dehydrators at the facility that vented to a vapor recovery device.
(iii) Whether any dehydrator emissions were vented to a control device other than a vapor recovery device or a flare or regenerator firebox/fire tubes. If any dehydrator emissions were vented to a control device(s) other than a vapor recovery device or a flare or regenerator firebox/fire tubes, then you must specify the type of control device(s) and the total number of dehydrators at the facility that were vented to each type of control device.
(iv) Whether any dehydrator emissions were vented to a flare or regenerator firebox/fire tubes. If any dehydrator emissions were vented to a flare or regenerator firebox/fire tubes, then you must report the information specified in paragraphs (e)(2)(iv)(A) through (D) of this section.
(A) The total number of dehydrators venting to a flare or regenerator firebox/fire tubes.
(B) Annual CO
(C) Annual CH
(D) Annual N
(v) For dehydrator emissions that were not vented to a flare or regenerator firebox/fire tubes, report the information specified in paragraphs (e)(2)(v)(A) and (B) of this section.
(A) Annual CO
(B) Annual CH
(3) For dehydrators that use desiccant (as specified in § 98.233(e)(3)), you must report the information specified in paragraphs (e)(3)(i) through (iii) of this section for the entire facility.
(i) The same information specified in paragraphs (e)(2)(i) through (iv) of this section for glycol dehydrators, and report the information under this paragraph for dehydrators that use desiccant.
(ii) Annual CO
(iii) Annual CH
(f)
(1) For each sub-basin and well tubing diameter and pressure group for which you used Calculation Method 1 to calculate natural gas emissions from well venting for liquids unloading, report the information specified in paragraphs (f)(1)(i) through (xii) of this section. Report information separately for wells with plunger lifts and wells without plunger lifts.
(i) Sub-basin ID.
(ii) Well tubing diameter and pressure group ID and a list of the well ID numbers associated with each sub-basin and well tubing diameter and pressure group ID.
(iii) Plunger lift indicator.
(iv) Count of wells vented to the atmosphere for the sub-basin/well tubing diameter and pressure group.
(v) Percentage of wells for which the monitoring period used to determine the cumulative amount of time venting was not the full calendar year.
(vi) Cumulative amount of time wells were vented (sum of “T
(vii) Cumulative number of unloadings vented to the atmosphere for each well, aggregated across all wells in the sub-basin/well tubing diameter and pressure group.
(viii) Annual natural gas emissions, in standard cubic feet, from well venting for liquids unloading, calculated according to § 98.233(f)(1).
(ix) Annual CO
(x) Annual CH
(xi) For each well tubing diameter group and pressure group combination, you must report the information specified in paragraphs (f)(1)(xi)(A) through (E) of this section for each individual well not using a plunger lift that was tested during the year.
(A) Well ID number of tested well.
(B) Casing pressure, in pounds per square inch absolute.
(C) Internal casing diameter, in inches.
(D) Measured depth of the well, in feet.
(E) Average flow rate of the well venting over the duration of the liquids unloading, in standard cubic feet per hour.
(xii) For each well tubing diameter group and pressure group combination, you must report the information specified in paragraphs (f)(1)(xii)(A) through (E) of this section for each individual well using a plunger lift that was tested during the year.
(A) Well ID number.
(B) The tubing pressure, in pounds per square inch absolute.
(C) The internal tubing diameter, in inches.
(D) Measured depth of the well, in feet.
(E) Average flow rate of the well venting over the duration of the liquids unloading, in standard cubic feet per hour.
(2) For each sub-basin for which you used Calculation Method 2 or 3 (as specified in § 93.233(f)) to calculate natural gas emissions from well venting for liquids unloading, you must report the information in (f)(2)(i) through (x) of this section. Report information separately for each calculation method.
(i) Sub-basin ID and a list of the well ID numbers associated with each sub-basin.
(ii) Calculation method.
(iii) Plunger lift indicator.
(iv) Number of wells vented to the atmosphere.
(v) Cumulative number of unloadings vented to the atmosphere for each well, aggregated across all wells.
(vi) Annual natural gas emissions, in standard cubic feet, from well venting for liquids unloading, calculated according to § 98.233(f)(2) or (3), as applicable.
(vii) Annual CO
(viii) Annual CH
(ix) For wells without plunger lifts, the average internal casing diameter, in inches.
(x) For wells with plunger lifts, the average internal tubing diameter, in inches.
(g)
(1) Sub-basin ID and a list of the well ID numbers associated with each sub-basin that had completions or workovers with hydraulic fracturing during the calendar year.
(2) Well type combination (horizontal or vertical, gas well or oil well).
(3) Number of completions or workovers in the sub-basin and well type combination category.
(4) Calculation method used.
(5) If you used Equation W-10A of § 98.233 to calculate annual volumetric total gas emissions, then you must report the information specified in paragraphs (g)(5)(i) through (iii) of this section.
(i) Cumulative gas flowback time, in hours, from when gas is first detected until sufficient quantities are present to enable separation, and the cumulative flowback time, in hours, after sufficient quantities of gas are present to enable separation (sum of “T
(ii) For the measured well(s), the flowback rate, in standard cubic feet per hour (average of “FR
(iii) If you used Equation W-12C of § 98.233 to calculate the average gas production rate for an oil well, then you must report the information specified in paragraphs (g)(5)(iii)(A) and (B) of this section.
(A) Gas to oil ratio for the well in standard cubic feet of gas per barrel of oil (“GOR
(B) Volume of oil produced during the first 30 days of production after completions of each newly drilled well or well workover using hydraulic fracturing, in barrels (“V
(6) If you used Equation W-10B of § 98.233 to calculate annual volumetric total gas emissions, then you must report the information specified in paragraphs (g)(6)(i) through (iii) of this section.
(i) Vented natural gas volume, in standard cubic feet, for each well in the
(ii) Flow rate at the beginning of the period of time when sufficient quantities of gas are present to enable separation, in standard cubic feet per hour, for each well in the sub-basin (“FR
(iii) The well ID number for which vented natural gas volume was measured.
(7) Annual gas emissions, in standard cubic feet (“E
(8) Annual CO
(9) Annual CH
(10) If the well emissions were vented to a flare, then you must report the total N
(h)
(1) For each sub-basin with gas well completions without hydraulic fracturing and without flaring, report the information specified in paragraphs (h)(1)(i) through (vi) of this section.
(i) Sub-basin ID and a list of the well ID numbers associated with each sub-basin for gas well completions without hydraulic fracturing and without flaring.
(ii) Number of well completions that vented gas directly to the atmosphere without flaring.
(iii) Total number of hours that gas vented directly to the atmosphere during venting for all completions in the sub-basin category (the sum of all “T
(iv) Average daily gas production rate for all completions without hydraulic fracturing in the sub-basin without flaring, in standard cubic feet per hour (average of all “V
(v) Annual CO
(vi) Annual CH
(2) For each sub-basin with gas well completions without hydraulic fracturing and with flaring, report the information specified in paragraphs (h)(2)(i) through (vii) of this section.
(i) Sub-basin ID and a list of the well ID numbers associated with each sub-basin for gas well completions without hydraulic fracturing and with flaring.
(ii) Number of well completions that flared gas.
(iii) Total number of hours that gas vented to a flare during venting for all completions in the sub-basin category (the sum of all “T
(iv) Average daily gas production rate for all completions without hydraulic fracturing in the sub-basin with flaring, in standard cubic feet per hour (the average of all “V
(v) Annual CO
(vi) Annual CH
(vii) Annual N
(3) For each sub-basin with gas well workovers without hydraulic fracturing and without flaring, report the information specified in paragraphs (h)(3)(i) through (iv) of this section.
(i) Sub-basin ID and a list of the well ID numbers associated with each sub-basin for gas well workovers without hydraulic fracturing and without flaring.
(ii) Number of workovers that vented gas to the atmosphere without flaring.
(iii) Annual CO
(iv) Annual CH
(4) For each sub-basin with gas well workovers without hydraulic fracturing and with flaring, report the information specified in paragraphs (h)(4)(i) through (v) of this section.
(i) Sub-basin ID and a list of well ID numbers associated with each sub-basin for gas well workovers without hydraulic fracturing and with flaring.
(ii) Number of workovers that flared gas.
(iii) Annual CO
(iv) Annual CH
(v) Annual N
(i)
(1)
(i) Total number of blowdowns in the calendar year for the equipment or event type (the sum of equation variable “N” from Equation W-14A or Equation W-14B of this subpart, for all unique physical volumes for the equipment or event type).
(ii) Annual CO
(iii) Annual CH
(2)
(i) Annual CO
(ii) Annual CH
(3)
(i) Annual CO
(ii) Annual CH
(iii) Annual number of blowdown events.
(j)
(1) If you used Calculation Method 1 or Calculation Method 2 of § 98.233(j) to calculate GHG emissions, then you must report the information specified in paragraphs (j)(1)(i) through (xvi) of this section for each sub-basin (for onshore production) or county (for onshore petroleum and natural gas gathering and boosting) and by calculation method. Onshore petroleum and natural gas gathering and boosting facilities do not report the information specified in paragraphs (j)(1)(ix) and (xi) of this section.
(i) Sub-basin ID (for onshore production) or county name (for onshore petroleum and natural gas gathering and boosting).
(ii) Calculation method used, and name of the software package used if using Calculation Method 1.
(iii) The total annual oil volume from gas-liquid separators and direct from wells or non-separator equipment that is sent to applicable onshore production and onshore petroleum and natural gas gathering and boosting storage tanks, in barrels. You may delay reporting of this data element for onshore production if you indicate in the annual report that wildcat wells and delineation wells are the only wells in the sub-basin with oil production greater than or equal to 10 barrels per day and flowing to gas-liquid separators or direct to storage tanks. If you elect to delay reporting of this data element, you must report by the date
(iv) The average gas-liquid separator or non-separator equipment temperature, in degrees Fahrenheit.
(v) The average gas-liquid separator or non-separator equipment pressure, in pounds per square inch gauge.
(vi) The average sales oil or stabilized oil API gravity, in degrees.
(vii) The minimum and maximum concentration (mole fraction) of CO
(viii) The minimum and maximum concentration (mole fraction) of CH
(ix) The number of wells sending oil to gas-liquid separators or directly to atmospheric tanks.
(x) The number of atmospheric tanks.
(xi) An estimate of the number of atmospheric tanks, not on well-pads, receiving your oil.
(xii) If any emissions from the atmospheric tanks at your facility were controlled with vapor recovery systems, then you must report the information specified in paragraphs (j)(1)(xii)(A) through (E) of this section.
(A) The number of atmospheric tanks that control emissions with vapor recovery systems.
(B) Total CO
(C) Total CH
(D) Annual CO
(E) Annual CH
(xiii) If any atmospheric tanks at your facility vented gas directly to the atmosphere without using a vapor recovery system or without flaring, then you must report the information specified in paragraphs (j)(1)(xiii)(A) through (C) of this section.
(A) The number of atmospheric tanks that vented gas directly to the atmosphere without using a vapor recovery system or without flaring.
(B) Annual CO
(C) Annual CH
(xiv) If you controlled emissions from any atmospheric tanks at your facility with one or more flares, then you must report the information specified in paragraphs (j)(1)(xiv)(A) through (D) of this section.
(A) The number of atmospheric tanks that controlled emissions with flares.
(B) Annual CO
(C) Annual CH
(D) Annual N
(2) If you used Calculation Method 3 to calculate GHG emissions, then you must report the information specified in paragraphs (j)(2)(i) through (iii) of this section.
(i) Report the information specified in paragraphs (j)(2)(i)(A) through (F) of this section, at the basin level, for atmospheric tanks where emissions were calculated using Calculation Method 3 of § 98.233(j). Onshore gathering and boosting facilities do not report the information specified in paragraphs (j)(2)(i)(E) and (F) of this section.
(A) The total annual oil/condensate throughput that is sent to all atmospheric tanks in the basin, in barrels. You may delay reporting of this data element for onshore production if you indicate in the annual report that wildcat wells and delineation wells are the only wells in the sub-basin with oil/condensate production less than 10 barrels per day and that send oil/condensate to atmospheric tanks. If you elect to delay reporting of this data element, you must report by the date specified in § 98.236(cc) the total annual oil/condensate throughput from all wells and
(B) An estimate of the fraction of oil/condensate throughput reported in paragraph (j)(2)(i)(A) of this section sent to atmospheric tanks in the basin that controlled emissions with flares.
(C) An estimate of the fraction of oil/condensate throughput reported in paragraph (j)(2)(i)(A) of this section sent to atmospheric tanks in the basin that controlled emissions with vapor recovery systems.
(D) The number of atmospheric tanks in the basin.
(E) The number of wells with gas-liquid separators (“Count” from Equation W-15 of this subpart) in the basin.
(F) The number of wells without gas-liquid separators (“Count” from Equation W-15 of this subpart) in the basin.
(ii) Report the information specified in paragraphs (j)(2)(ii)(A) through (D) of this section for each sub-basin (for onshore production) or county (for onshore petroleum and natural gas gathering and boosting) with atmospheric tanks whose emissions were calculated using Calculation Method 3 of § 98.233(j) and that did not control emissions with flares.
(A) Sub-basin ID (for onshore production) or county name (for onshore petroleum and natural gas gathering and boosting).
(B) The number of atmospheric tanks in the sub-basin (for onshore production) or county (for onshore petroleum and natural gas gathering and boosting) that did not control emissions with flares.
(C) Annual CO
(D) Annual CH
(iii) Report the information specified in paragraphs (j)(2)(iii)(A) through (E) of this section for each sub-basin (for onshore production) or county (for onshore petroleum and natural gas gathering and boosting) with atmospheric tanks whose emissions were calculated using Calculation Method 3 of § 98.233(j) and that controlled emissions with flares.
(A) Sub-basin ID (for onshore production) or county name (for onshore petroleum and natural gas gathering and boosting).
(B) The number of atmospheric tanks in the sub-basin (for onshore production) or county (for onshore petroleum and natural gas gathering and boosting) that controlled emissions with flares.
(C) Annual CO
(D) Annual CH
(E) Annual N
(3) If you used Calculation Method 1 or Calculation Method 2 of § 98.233(j), and any gas-liquid separator liquid dump values did not close properly during the calendar year, then you must report the information specified in paragraphs (j)(3)(i) through (iv) of this section for each sub-basin (for onshore production) or county (for onshore petroleum and natural gas gathering and boosting).
(i) The total number of gas-liquid separators whose liquid dump valves did not close properly during the calendar year.
(ii) The total time the dump valves on gas-liquid separators did not close properly in the calendar year, in hours (sum of the “T
(iii) Annual CO
(iv) Annual CH
(k)
(1) For each transmission storage tank vent stack, report the information specified in (k)(1)(i) through (iv) of this section.
(i) The unique name or ID number for the transmission storage tank vent stack.
(ii) Method used to determine if dump valve leakage occurred.
(iii) Indicate whether scrubber dump valve leakage occurred for the transmission storage tank vent according to § 98.233(k)(2).
(iv) Indicate if there is a flare attached to the transmission storage tank vent stack.
(2) If scrubber dump valve leakage occurred for a transmission storage tank vent stack, as reported in paragraph (k)(1)(iii) of this section, and the vent stack vented directly to the atmosphere during the calendar year, then you must report the information specified in paragraphs (k)(2)(i) through (v) of this section for each transmission storage vent stack where scrubber dump valve leakage occurred.
(i) Method used to measure the leak rate.
(ii) Measured leak rate (average leak rate from a continuous flow measurement device), in standard cubic feet per hour.
(iii) Duration of time that the leak is counted as having occurred, in hours, as determined in § 98.233(k)(3) (may use best available data if a continuous flow measurement device was used).
(iv) Annual CO
(v) Annual CH
(3) If scrubber dump valve leakage occurred for a transmission storage tank vent stack, as reported in paragraph (k)(1)(iii), and the vent stack vented to a flare during the calendar year, then you must report the information specified in paragraphs (k)(3)(i) through (vi) of this section.
(i) Method used to measure the leak rate.
(ii) Measured leakage rate (average leak rate from a continuous flow measurement device) in standard cubic feet per hour.
(iii) Duration of time that flaring occurred in hours, as defined in § 98.233(k)(3) (may use best available data if a continuous flow measurement device was used).
(iv) Annual CO
(v) Annual CH
(vi) Annual N
(l)
(1) If you used Equation W-17A of § 98.233 to calculate annual volumetric natural gas emissions at actual conditions from oil wells and the emissions are not vented to a flare, then you must report the information specified in paragraphs (l)(1)(i) through (vii) of this section.
(i) Number of wells tested in the calendar year.
(ii) Well ID numbers for the wells tested in the calendar year.
(iii) Average number of well testing days per well for well(s) tested in the calendar year.
(iv) Average gas to oil ratio for well(s) tested, in cubic feet of gas per barrel of oil.
(v) Average flow rate for well(s) tested, in barrels of oil per day. You may delay reporting of this data element if you indicate in the annual report that wildcat wells and/or delineation wells are the only wells that are tested. If you elect to delay reporting of this data element, you must report by the date specified in § 98.236(cc) the measured average flow rate for well(s) tested and the well ID number(s) for the well(s) included in the measurement.
(vi) Annual CO
(vii) Annual CH
(2) If you used Equation W-17A of § 98.233 to calculate annual volumetric natural gas emissions at actual conditions from oil wells and the emissions are vented to a flare, then you must report the information specified in paragraphs (l)(2)(i) through (viii) of this section.
(i) Number of wells tested in the calendar year.
(ii) Well ID numbers for the wells tested in the calendar year.
(iii) Average number of well testing days per well for well(s) tested in the calendar year.
(iv) Average gas to oil ratio for well(s) tested, in cubic feet of gas per barrel of oil.
(v) Average flow rate for well(s) tested, in barrels of oil per day. You may delay reporting of this data element if you indicate in the annual report that wildcat wells and/or delineation wells are the only wells that are tested. If you elect to delay reporting of this data element, you must report by the date specified in § 98.236(cc) the measured average flow rate for well(s) tested and the well ID number(s) for the well(s) included in the measurement.
(vi) Annual CO
(vii) Annual CH
(viii) Annual N
(3) If you used Equation W-17B of § 98.233 to calculate annual volumetric natural gas emissions at actual conditions from gas wells and the emissions were not vented to a flare, then you must report the information specified in paragraphs (l)(3)(i) through (vi) of this section.
(i) Number of wells tested in the calendar year.
(ii) Well ID numbers for the wells tested in the calendar year.
(iii) Average number of well testing days per well for well(s) tested in the calendar year.
(iv) Average annual production rate for well(s) tested, in actual cubic feet per day. You may delay reporting of this data element if you indicate in the annual report that wildcat wells and/or delineation wells are the only wells that are tested. If you elect to delay reporting of this data element, you must report by the date specified in § 98.236(cc) the measured average annual production rate for well(s) tested and the well ID number(s) for the well(s) included in the measurement.
(v) Annual CO
(vi) Annual CH
(4) If you used Equation W-17B of § 98.233 to calculate annual volumetric natural gas emissions at actual conditions from gas wells and the emissions were vented to a flare, then you must report the information specified in paragraphs (l)(4)(i) through (vii) of this section.
(i) Number of wells tested in calendar year.
(ii) Well ID numbers for the wells tested in the calendar year.
(iii) Average number of well testing days per well for well(s) tested in the calendar year.
(iv) Average annual production rate for well(s) tested, in actual cubic feet per day. You may delay reporting of this data element if you indicate in the annual report that wildcat wells and/or delineation wells are the only wells
(v) Annual CO
(vi) Annual CH
(vii) Annual N
(m)
(1) Sub-basin ID and a list of well ID numbers for wells for which associated gas was vented or flared.
(2) Indicate whether any associated gas was vented directly to the atmosphere without flaring.
(3) Indicate whether any associated gas was flared.
(4) Average gas to oil ratio, in standard cubic feet of gas per barrel of oil (average of the “GOR” values used in Equation W-18 of this subpart).
(5) Volume of oil produced, in barrels, in the calendar year during the time periods in which associated gas was vented or flared (the sum of “V
(6) Total volume of associated gas sent to sales, in standard cubic feet, in the calendar year during time periods in which associated gas was vented or flared (the sum of “SG” values used in Equation W-18 of § 98.233(m)). You may delay reporting of this data element if you indicate in the annual report that wildcat wells and/or delineation wells from which associated gas was vented or flared. If you elect to delay reporting of this data element, you must report by the date specified in § 98.236(cc) the measured total volume of associated gas sent to sales for well(s) with associated gas venting and flaring and the well ID number(s) for the well(s) included in the measurement.
(7) If you had associated gas emissions vented directly to the atmosphere without flaring, then you must report the information specified in paragraphs (m)(7)(i) through (iii) of this section for each sub-basin.
(i) Total number of wells for which associated gas was vented directly to the atmosphere without flaring and a list of their well ID numbers.
(ii) Annual CO
(iii) Annual CH
(8) If you had associated gas emissions that were flared, then you must report the information specified in paragraphs (m)(8)(i) through (iv) of this section for each sub-basin.
(i) Total number of wells for which associated gas was flared and a list of their well ID numbers.
(ii) Annual CO
(iii) Annual CH
(iv) Annual N
(n)
(1) Unique name or ID for the flare stack. For the onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting industry segments, a different name or ID may be used for a single
(2) Indicate whether the flare stack has a continuous flow measurement device.
(3) Indicate whether the flare stack has a continuous gas composition analyzer on feed gas to the flare.
(4) Volume of gas sent to the flare, in standard cubic feet (“V
(5) Fraction of the feed gas sent to an un-lit flare (“Z
(6) Flare combustion efficiency, expressed as the fraction of gas combusted by a burning flare.
(7) Mole fraction of CH
(8) Mole fraction of CO
(9) Annual CO
(10) Annual CH
(11) Annual N
(12) Indicate whether a CEMS was used to measure emissions from the flare. If a CEMS was used to measure emissions from the flare, then you are not required to report N
(o)
(1)
(i) Unique name or ID for the centrifugal compressor.
(ii) Hours in operating-mode.
(iii) Hours in not-operating-depressurized-mode.
(iv) Indicate whether the compressor was measured in operating-mode.
(v) Indicate whether the compressor was measured in not-operating-depressurized-mode.
(vi) Indicate which, if any, compressor sources are part of a manifolded group of compressor sources.
(vii) Indicate which, if any, compressor sources are routed to a flare.
(viii) Indicate which, if any, compressor sources have vapor recovery.
(ix) Indicate which, if any, compressor source emissions are captured for fuel use or are routed to a thermal oxidizer.
(x) Indicate whether the compressor has blind flanges installed and associated dates.
(xi) Indicate whether the compressor has wet or dry seals.
(xii) If the compressor has wet seals, the number of wet seals.
(xiii) Power output of the compressor driver (hp).
(xiv) Indicate whether the compressor had a scheduled depressurized shutdown during the reporting year.
(2)
(A) Centrifugal compressor name or ID. Use the same ID as in paragraph (o)(1)(i) of this section.
(B) Centrifugal compressor source (wet seal, isolation valve, or blowdown valve).
(C) Unique name or ID for the leak or vent. If the leak or vent is connected to a manifolded group of compressor
(ii) For each leak or vent, report the information specified in paragraphs (o)(2)(ii)(A) through (E) of this section.
(A) Indicate whether the leak or vent is for a single compressor source or manifolded group of compressor sources and whether the emissions from the leak or vent are released to the atmosphere, routed to a flare, combustion (fuel or thermal oxidizer), or vapor recovery.
(B) Indicate whether an as found measurement(s) as identified in § 98.233(o)(2) or (4) was conducted on the leak or vent.
(C) Indicate whether continuous measurements as identified in § 98.233(o)(3) or (5) were conducted on the leak or vent.
(D) Report emissions as specified in paragraphs (o)(2)(ii)(D)(
(
(
(E) If the leak or vent is routed to flare, combustion, or vapor recovery, report the percentage of time that the respective device was operational when the compressor source emissions were routed to the device.
(3)
(i) For each as found measurement performed on a leak or vent, report the information specified in paragraphs (o)(3)(i)(A) through (F) of this section.
(A) Name or ID of leak or vent. Use same leak or vent ID as in paragraph (o)(2)(i)(C) of this section.
(B) Measurement date.
(C) Measurement method. If emissions were not detected when using a screening method, report the screening method. If emissions were detected using a screening method, report only the method subsequently used to measure the volumetric emissions.
(D) Measured flow rate, in standard cubic feet per hour.
(E) For each compressor attached to the leak or vent, report the compressor mode during which the measurement was taken.
(F) If the measurement is for a manifolded group of compressor sources, indicate whether the measurement location is prior to or after comingling with non-compressor emission sources.
(ii) For each compressor mode-source combination where a reporter emission factor as calculated in Equation W-23 was used to calculate emissions in Equation W-22, report the information specified in paragraphs (o)(3)(ii)(A) through (D) of this section.
(A) The compressor mode-source combination.
(B) The compressor mode-source combination reporter emission factor, in standard cubic feet per hour (EF
(C) The total number of compressors measured in the compressor mode-source combination in the current reporting year and the preceding two reporting years (Count
(D) Indicate whether the compressor mode-source combination reporter emission factor is facility-specific or based on all of the reporter's applicable facilities.
(4)
(i) Name or ID of leak or vent. Use same leak or vent ID as in paragraph (o)(2)(i)(C) of this section.
(ii) Measured volume of flow during the reporting year, in million standard cubic feet.
(iii) Indicate whether the measured volume of flow during the reporting year includes compressor blowdown emissions as allowed for in § 98.233(o)(3)(ii) and (o)(5)(iii).
(iv) If the measurement is for a manifolded group of compressor sources, indicate whether the measurement location is prior to or after comingling with non-compressor emission sources.
(5)
(i) Number of centrifugal compressors that have wet seal oil degassing vents.
(ii) Annual CO
(iii) Annual CH
(p)
(1)
(i) Unique name or ID for the reciprocating compressor.
(ii) Hours in operating-mode.
(iii) Hours in standby-pressurized-mode.
(iv) Hours in not-operating-depressurized-mode.
(v) Indicate whether the compressor was measured in operating-mode.
(vi) Indicate whether the compressor was measured in standby-pressurized-mode.
(vii) Indicate whether the compressor was measured in not-operating-depressurized-mode.
(viii) Indicate which, if any, compressor sources are part of a manifolded group of compressor sources.
(ix) Indicate which, if any, compressor sources are routed to a flare.
(x) Indicate which, if any, compressor sources have vapor recovery.
(xi) Indicate which, if any, compressor source emissions are captured for fuel use or are routed to a thermal oxidizer.
(xii) Indicate whether the compressor has blind flanges installed and associated dates.
(xiii) Power output of the compressor driver (hp).
(xiv) Indicate whether the compressor had a scheduled depressurized shutdown during the reporting year.
(2)
(A) Reciprocating compressor name or ID. Use the same ID as in paragraph (p)(1)(i) of this section.
(B) Reciprocating compressor source (isolation valve, blowdown valve, or rod packing).
(C) Unique name or ID for the leak or vent. If the leak or vent is connected to a manifolded group of compressor sources, use the same leak or vent ID
(ii) For each leak or vent, report the information specified in paragraphs (p)(2)(ii)(A) through (E) of this section.
(A) Indicate whether the leak or vent is for a single compressor source or manifolded group of compressor sources and whether the emissions from the leak or vent are released to the atmosphere, routed to a flare, combustion (fuel or thermal oxidizer), or vapor recovery.
(B) Indicate whether an as found measurement(s) as identified in § 98.233(p)(2) or (4) was conducted on the leak or vent.
(C) Indicate whether continuous measurements as identified in § 98.233(p)(3) or (5) were conducted on the leak or vent.
(D) Report emissions as specified in paragraphs (p)(2)(ii)(D)(
(
(
(E) If the leak or vent is routed to flare, combustion, or vapor recovery, report the percentage of time that the respective device was operational when the compressor source emissions were routed to the device.
(3)
(i) For each as found measurement performed on a leak or vent, report the information specified in paragraphs (p)(3)(i)(A) through (F) of this section.
(A) Name or ID of leak or vent. Use same leak or vent ID as in paragraph (p)(2)(i)(C) of this section.
(B) Measurement date.
(C) Measurement method. If emissions were not detected when using a screening method, report the screening method. If emissions were detected using a screening method, report only the method subsequently used to measure the volumetric emissions.
(D) Measured flow rate, in standard cubic feet per hour.
(E) For each compressor attached to the leak or vent, report the compressor mode during which the measurement was taken.
(F) If the measurement is for a manifolded group of compressor sources, indicate whether the measurement location is prior to or after comingling with non-compressor emission sources.
(ii) For each compressor mode-source combination where a reporter emission factor as calculated in Equation W-28 was used to calculate emissions in Equation W-27, report the information specified in paragraphs (p)(3)(ii)(A) through (D) of this section
(A) The compressor mode-source combination.
(B) The compressor mode-source combination reporter emission factor, in standard cubic feet per hour (EF
(C) The total number of compressors measured in the compressor mode-source combination in the current reporting year and the preceding two reporting years (Count
(D) Indicate whether the compressor mode-source combination reporter emission factor is facility-specific or based on all of the reporter's applicable facilities.
(4)
(i) Name or ID of leak or vent. Use same leak or vent ID as in paragraph (p)(2)(i)(C) of this section.
(ii) Measured volume of flow during the reporting year, in million standard cubic feet.
(iii) Indicate whether the measured volume of flow during the reporting year includes compressor blowdown emissions as allowed for in § 98.233(p)(3)(ii) and (p)(5)(iii).
(iv) If the measurement is for a manifolded group of compressor sources, indicate whether the measurement location is prior to or after comingling with non-compressor emission sources.
(5)
(i) Number of reciprocating compressors.
(ii) Annual CO
(iii) Annual CH
(q) Equipment leak surveys. For any components subject to or complying with the requirements of § 98.233(q), you must report the information specified in paragraphs (q)(1) and (2) of this section. Natural gas distribution facilities with emission sources listed in § 98.232(i)(1) must also report the information specified in paragraph (q)(3) of this section.
(1) You must report the information specified in paragraphs (q)(1)(i) through (v) of this section.
(i) Except as specified in paragraph (q)(1)(ii) of this section, the number of complete equipment leak surveys performed during the calendar year.
(ii) Natural gas distribution facilities performing equipment leak surveys across a multiple year leak survey cycle must report the number of years in the leak survey cycle.
(iii) Except for onshore natural gas processing facilities and natural gas distribution facilities, indicate whether any equipment components at your facility are subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter. Report the indication per facility, not per component type.
(iv) For facilities in onshore petroleum and natural gas production, onshore petroleum and natural gas gathering and boosting, onshore natural gas transmission compression, underground natural gas storage, LNG storage, and LNG import and export equipment, indicate whether you elected to comply with § 98.233(q) according to § 98.233(q)(1)(iv) for any equipment components at your facility.
(v) Report each type of method described in § 98.234(a) that was used to conduct leak surveys.
(2) You must indicate whether your facility contains any of the component types subject to or complying with § 98.233(q) that are listed in § 98.232(c)(21), (d)(7), (e)(7), (e)(8), (f)(5), (f)(6), (f)(7), (f)(8), (g)(4), (g)(6), (g)(7), (h)(5), (h)(7), (h)(8), (i)(1), or (j)(10) for your facility's industry segment. For each component type that is located at your facility, you must report the information specified in paragraphs (q)(2)(i) through (v) of this section. If a component type is located at your facility and no leaks were identified from that component, then you must report the information in paragraphs (q)(2)(i) through (v) of this section but report a zero (“0”) for the information required according to paragraphs (q)(2)(ii) through (v) of this section.
(i) Component type.
(ii) Total number of the surveyed component type that were identified as leaking in the calendar year (“x
(iii) Average time the surveyed components are assumed to be leaking and operational, in hours (average of “T
(iv) Annual CO
(v) Annual CH
(3) Natural gas distribution facilities with emission sources listed in § 98.232(i)(1) must also report the information specified in paragraphs (q)(3)(i) through (viii) and, if applicable, (q)(3)(ix) of this section.
(i) Number of above grade transmission-distribution transfer stations surveyed in the calendar year.
(ii) Number of meter/regulator runs at above grade transmission-distribution transfer stations surveyed in the calendar year (“Count
(iii) Average time that meter/regulator runs surveyed in the calendar year were operational, in hours (average of “T
(iv) Number of above grade transmission-distribution transfer stations surveyed in the current leak survey cycle.
(v) Number of meter/regulator runs at above grade transmission-distribution transfer stations surveyed in current leak survey cycle (sum of “Count
(vi) Average time that meter/regulator runs surveyed in the current leak survey cycle were operational, in hours (average of “T
(vii) Meter/regulator run CO
(viii) Meter/regulator run CH
(ix) If your natural gas distribution facility performs equipment leak surveys across a multiple year leak survey cycle, you must also report:
(A) The total number of meter/regulator runs at above grade transmission-distribution transfer stations at your facility (“Count
(B) Average estimated time that each meter/regulator run at above grade transmission-distribution transfer stations was operational in the calendar year, in hours per meter/regulator run (“T
(C) Annual CO
(D) Annual CH
(r)
(1) You must indicate whether your facility contains any of the emission source types required to use Equation W-32A of § 98.233. You must report the information specified in paragraphs (r)(1)(i) through (v) of this section separately for each emission source type required to use Equation W-32A that is located at your facility. Onshore petroleum and natural gas production facilities and onshore petroleum and natural gas gathering and boosting facilities must report the information specified in paragraphs (r)(1)(i) through (v) separately by component type, service type, and geographic location (
(i) Emission source type. Onshore petroleum and natural gas production facilities and onshore petroleum and natural gas gathering and boosting facilities must report the component type, service type and geographic location.
(ii) Total number of the emission source type at the facility (“Count
(iii) Average estimated time that the emission source type was operational in the calendar year, in hours (“T
(iv) Annual CO
(v) Annual CH
(2) Natural gas distribution facilities must also report the information specified in paragraphs (r)(2)(i) through (v) of this section.
(i) Number of above grade transmission-distribution transfer stations at the facility.
(ii) Number of above grade metering-regulating stations that are not transmission-distribution transfer stations at the facility.
(iii) Total number of meter/regulator runs at above grade metering-regulating stations that are not above grade transmission-distribution transfer stations (“Count
(iv) Average estimated time that each meter/regulator run at above grade metering-regulating stations that are not above grade transmission-distribution transfer stations was operational in the calendar year, in hours per meter/regulator run (“T
(v) If your facility has above grade metering-regulating stations that are not above grade transmission-distribution transfer stations and your facility also has above grade transmission-distribution transfer stations, you must also report:
(A) Annual CO
(B) Annual CH
(3) Onshore petroleum and natural gas production facilities and onshore petroleum and natural gas gathering and boosting facilities must also report the information specified in paragraphs (r)(3)(i) and (ii) of this section.
(i) Calculation method used.
(ii) Onshore petroleum and natural gas production facilities and onshore petroleum and natural gas gathering and boosting facilities must report the information specified in paragraphs (r)(3)(ii)(A) and (B) of this section, for each major equipment type, production type (
(A) An indication of whether the facility contains the major equipment type.
(B) If the facility does contain the equipment type, the count of the major equipment type.
(s)
(1) Annual CO
(2) Annual CH
(3) Annual N
(t) [Reserved]
(u) [Reserved]
(v) [Reserved]
(w)
(1) Sub-basin ID.
(2) EOR injection pump system identifier.
(3) Pump capacity, in barrels per day.
(4) Total volume of EOR injection pump system equipment chambers, in cubic feet (“V
(5) Number of blowdowns for the EOR injection pump system in the calendar year.
(6) Density of critical phase EOR injection gas, in kilograms per cubic foot (“R
(7) Mass fraction of CO
(8) Annual CO
(x)
(1) Sub-basin ID.
(2) Total volume of hydrocarbon liquids produced through EOR operations in the calendar year, in barrels (“V
(3) Average CO
(4) Annual CO
(y) [Reserved]
(z)
(1) Indicate whether the combustion units include: External fuel combustion units with a rated heat capacity less than or equal to 5 million Btu per hour; or, internal fuel combustion units that are not compressor-drivers, with a rated heat capacity less than or equal to 1 mmBtu/hr (or the equivalent of 130 horsepower). If the facility contains external fuel combustion units with a rated heat capacity less than or equal to 5 million Btu per hour or internal fuel combustion units that are not compressor-drivers, with a rated heat capacity less than or equal to 1 million Btu per hour (or the equivalent of 130 horsepower), then you must report the information specified in paragraphs (z)(1)(i) and (ii) of this section for each unit type.
(i) The type of combustion unit.
(ii) The total number of combustion units.
(2) Indicate whether the combustion units include: External fuel combustion units with a rated heat capacity greater than 5 million Btu per hour; internal fuel combustion units that are not compressor-drivers, with a rated heat capacity greater than 1 million Btu per hour (or the equivalent of 130 horsepower); or, internal fuel combustion units of any heat capacity that are compressor-drivers. If your facility contains: External fuel combustion units with a rated heat capacity greater than 5 mmBtu/hr; internal fuel combustion units that are not compressor-drivers, with a rated heat capacity greater than 1 million Btu per hour (or the equivalent of 130 horsepower); or internal fuel combustion units of any heat capacity that are compressor-drivers, then you must report the information specified in paragraphs (z)(2)(i) through (vi) of this section for each combustion unit type and fuel type combination.
(i) The type of combustion unit.
(ii) The type of fuel combusted.
(iii) The quantity of fuel combusted in the calendar year, in thousand standard cubic feet, gallons, or tons.
(iv) Annual CO
(v) Annual CH
(vi) Annual N
(aa) Each facility must report the information specified in paragraphs (aa)(1) through (11) of this section, for each applicable industry segment, by using best available data. If a quantity required to be reported is zero, you must report zero as the value.
(1) For onshore petroleum and natural gas production, report the data specified in paragraphs (aa)(1)(i) and (ii) of this section.
(i) Report the information specified in paragraphs (aa)(1)(i)(A) through (C) of this section for the basin as a whole.
(A) The quantity of gas produced in the calendar year from wells, in thousand standard cubic feet. This includes gas that is routed to a pipeline, vented or flared, or used in field operations. This does not include gas injected back into reservoirs or shrinkage resulting from lease condensate production.
(B) The quantity of gas produced in the calendar year for sales, in thousand standard cubic feet.
(C) The quantity of crude oil and condensate produced in the calendar year for sales, in barrels.
(ii) Report the information specified in paragraphs (aa)(1)(ii)(A) through (M) of this section for each unique sub-basin category.
(A) State.
(B) County.
(C) Formation type.
(D) The number of producing wells at the end of the calendar year and a list of the well ID numbers (exclude only those wells permanently taken out of production,
(E) The number of producing wells acquired during the calendar year and a list of the well ID numbers.
(F) The number of producing wells divested during the calendar year and a list of the well ID numbers.
(G) The number of wells completed during the calendar year and a list of the well ID numbers.
(H) The number of wells permanently taken out of production (
(I) Average mole fraction of CH
(J) Average mole fraction of CO
(K) If an oil sub-basin, report the average GOR of all wells, in thousand standard cubic feet per barrel.
(L) If an oil sub-basin, report the average API gravity of all wells.
(M) If an oil sub-basin, report average low pressure separator pressure, in pounds per square inch gauge.
(2) For offshore production, report the quantities specified in paragraphs (aa)(2)(i) and (ii) of this section.
(i) The total quantity of gas handled at the offshore platform in the calendar year, in thousand standard cubic feet, including production volumes and volumes transferred via pipeline from another location.
(ii) The total quantity of oil and condensate handled at the offshore platform in the calendar year, in barrels, including production volumes and volumes transferred via pipeline from another location.
(3) For natural gas processing, report the information specified in paragraphs (aa)(3)(i) through (vii) of this section.
(i) The quantity of natural gas received at the gas processing plant in the calendar year, in thousand standard cubic feet.
(ii) The quantity of processed (residue) gas leaving the gas processing plant in the calendar year, in thousand standard cubic feet.
(iii) The cumulative quantity of all NGLs (bulk and fractionated) received at the gas processing plant in the calendar year, in barrels.
(iv) The cumulative quantity of all NGLs (bulk and fractionated) leaving the gas processing plant in the calendar year, in barrels.
(v) Average mole fraction of CH
(vi) Average mole fraction of CO
(vii) Indicate whether the facility fractionates NGLs.
(4) For natural gas transmission compression, report the quantity specified in paragraphs (aa)(4)(i) through (v) of this section.
(i) The quantity of gas transported through the compressor station in the calendar year, in thousand standard cubic feet.
(ii) Number of compressors.
(iii) Total compressor power rating of all compressors combined, in horsepower.
(iv) Average upstream pipeline pressure, in pounds per square inch gauge.
(v) Average downstream pipeline pressure, in pounds per square inch gauge.
(5) For underground natural gas storage, report the quantities specified in paragraphs (aa)(5)(i) through (iii) of this section.
(i) The quantity of gas injected into storage in the calendar year, in thousand standard cubic feet.
(ii) The quantity of gas withdrawn from storage in the calendar year, in thousand standard cubic feet.
(iii) Total storage capacity, in thousand standard cubic feet.
(6) For LNG import equipment, report the quantity of LNG imported in the calendar year, in thousand standard cubic feet.
(7) For LNG export equipment, report the quantity of LNG exported in the calendar year, in thousand standard cubic feet.
(8) For LNG storage, report the quantities specified in paragraphs (aa)(8)(i) through (iii) of this section.
(i) The quantity of LNG added into storage in the calendar year, in thousand standard cubic feet.
(ii) The quantity of LNG withdrawn from storage in the calendar year, in thousand standard cubic feet.
(iii) Total storage capacity, in thousand standard cubic feet.
(9) For natural gas distribution, report the quantities specified in paragraphs (aa)(9)(i) through (vii) of this section.
(i) The quantity of natural gas received at all custody transfer stations in the calendar year, in thousand standard cubic feet. This value may include meter corrections, but only for the calendar year covered by the annual report.
(ii) The quantity of natural gas withdrawn from in-system storage in the calendar year, in thousand standard cubic feet.
(iii) The quantity of natural gas added to in-system storage in the calendar year, in thousand standard cubic feet.
(iv) The quantity of natural gas delivered to end users, in thousand standard cubic feet. This value does not include stolen gas, or gas that is otherwise unaccounted for.
(v) The quantity of natural gas transferred to third parties such as other LDCs or pipelines, in thousand standard cubic feet. This value does not include stolen gas, or gas that is otherwise unaccounted for.
(vi) The quantity of natural gas consumed by the LDC for operational purposes, in thousand standard cubic feet.
(vii) The estimated quantity of gas stolen in the calendar year, in thousand standard cubic feet.
(10) For onshore petroleum and natural gas gathering and boosting facilities, report the quantities specified in paragraphs (aa)(10)(i) through (iv) of this section.
(i) The quantity of gas received by the gathering and boosting facility in the calendar year, in thousand standard cubic feet.
(ii) The quantity of gas transported to a natural gas processing facility, a natural gas transmission pipeline, a natural gas distribution pipeline, or another gathering and boosting facility in the calendar year, in thousand standard cubic feet.
(iii) The quantity of all hydrocarbon liquids received by the gathering and boosting facility in the calendar year, in barrels.
(iv) The quantity of all hydrocarbon liquids transported to a natural gas processing facility, a natural gas transmission pipeline, a natural gas distribution pipeline, or another gathering and boosting facility in the calendar year, in barrels.
(11) For onshore natural gas transmission pipeline facilities, report the quantities specified in paragraphs (aa)(11)(i) through (vi) of this section.
(i) The quantity of natural gas received at all custody transfer stations in the calendar year, in thousand standard cubic feet. This value may include meter corrections, but only for the calendar year covered by the annual report.
(ii) The quantity of natural gas withdrawn from in-system storage in the calendar year, in thousand standard cubic feet.
(iii) The quantity of natural gas added to in-system storage in the calendar year, in thousand standard cubic feet.
(iv) The quantity of natural gas transferred to third parties such as LDCs or other transmission pipelines, in thousand standard cubic feet.
(v) The quantity of natural gas consumed by the transmission pipeline facility for operational purposes, in thousand standard cubic feet.
(vi) The miles of transmission pipeline for each state in the facility.
(bb) For any missing data procedures used, report the information in § 98.3(c)(8) except as provided in paragraphs (bb)(1) and (2) of this section.
(1) For quarterly measurements, report the total number of quarters that a missing data procedure was used for each data element rather than the total number of hours.
(2) For annual or biannual (once every two years) measurements, you do not need to report the number of hours that a missing data procedure was used for each data element.
(cc) If you elect to delay reporting the information in paragraph (g)(5)(i), (g)(5)(ii), (g)(5)(iii)(A), (g)(5)(iii)(B), (h)(1)(iv), (h)(2)(iv), (j)(1)(iii), (j)(2)(i)(A), (l)(1)(iv), (l)(2)(iv), (l)(3)(iii), (l)(4)(iii), (m)(5), or (m)(6) of this section, you must report the information required in that paragraph no later than the date 2 years following the date specified in § 98.3(b) introductory text.
Monitoring Plans, as described in § 98.3(g)(5), must be completed by April 1, 2011. In addition to the information required by § 98.3(g), you must retain the following records:
(a) Dates on which measurements were conducted.
(b) Results of all emissions detected and measurements.
(c) Calibration reports for detection and measurement instruments used.
(d) Inputs and outputs of calculations or emissions computer model runs used for engineering estimation of emissions.
(e) The records required under § 98.3(g)(2)(i) shall include an explanation of how company records, engineering estimation, or best available information are used to calculate each applicable parameter under this subpart.
(f) For each time a missing data procedure was used, keep a record listing the emission source type, a description of the circumstance that resulted in the need to use missing data procedures, the missing data provisions in § 98.235 that apply, the calculation or analysis used to develop the substitute value, and the substitute value.
Except as provided in this section, all terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
(a) The petrochemical production source category consists of processes as described in paragraphs (a)(1) and (2) of this section.
(1) The petrochemical production source category consists of all processes that produce acrylonitrile, carbon black, ethylene, ethylene dichloride, ethylene oxide, or methanol, as either an intermediate in the on-site production of other chemicals or as an end product for sale or shipment off site, except as specified in paragraphs (b) through (g) of this section.
(2) When ethylene dichloride and vinyl chloride monomer are produced in an integrated process, you may consider the entire integrated process to be the petrochemical process for the purpose of complying with the mass balance option in § 98.243(c). If you elect to consider the integrated process to be the petrochemical process, then the mass balance must be performed over the entire integrated process.
(b) A process that produces a petrochemical as a byproduct is not part of the petrochemical production source category.
(c) A facility that makes methanol, hydrogen, and/or ammonia from synthesis gas is part of the petrochemical source category if the annual mass of methanol produced exceeds the individual annual mass production levels of both hydrogen recovered as product and ammonia. The facility is part of subpart P of this part (Hydrogen Production) if the annual mass of hydrogen recovered as product exceeds the individual annual mass production levels of both methanol and ammonia. The facility is part of subpart G of this part (Ammonia Manufacturing) if the annual mass of ammonia produced exceeds the individual annual mass production levels of both hydrogen recovered as product and methanol.
(d) A direct chlorination process that is operated independently of an oxychlorination process to produce ethylene dichloride is not part of the petrochemical production source category.
(e) A process that produces bone black is not part of the petrochemical source category.
(f) A process that produces a petrochemical from bio-based feedstock is
(g) A process that solely distills or recycles waste solvent that contains a petrochemical is not part of the petrochemical production source category.
You must report GHG emissions under this subpart if your facility contains a petrochemical process as specified in § 98.240, and the facility meets the requirements of either § 98.2(a)(1) or (2).
You must report the information in paragraphs (a) through (c) of this section:
(a) CO
(1) If you comply with § 98.243(b) or (d), report under this subpart the calculated CO
(2) If you comply with § 98.243(c), report under this subpart the calculated CO
(b) CO
(1) If you comply with § 98.243(b) or (d), report these emissions from stationary combustion units that are associated with petrochemical process units and burn only supplemental fuel under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C.
(2) If you comply with § 98.243(c), report CO
(c) CO
(a) If you route all process vent emissions and emissions from combustion of process off-gas to one or more stacks and use CEMS on each stack to measure CO
(b)
(1) Determine CO
(2) For each stack (except flare stacks) that includes emissions from combustion of petrochemical process off-gas, calculate CH
(3) For each flare, calculate CO
(c)
(1) For each gaseous and liquid feedstock and product, measure the volume or mass used or produced each calendar month with a flow meter by following the procedures specified in § 98.244(b)(2). Alternatively, for liquids, you may calculate the volume used or collected in each month based on measurements of the liquid level in a storage tank at least once per month (and just prior to each change in direction of the level of the liquid) following the procedures specified in § 98.244(b)(3). Fuels used for combustion purposes are not considered to be feedstocks.
(2) For each solid feedstock and product, measure the mass used or produced each calendar month by following the procedures specified in § 98.244(b)(1).
(3) Collect a sample of each feedstock and product at least once per month and determine the molecular weight (for gaseous materials when the quantity is measured in scf) and carbon content of each sample according to the procedures of § 98.244(b)(4). If multiple valid molecular weight or carbon content measurements are made during the monthly measurement period, average them arithmetically. However, if a particular liquid or solid feedstock is delivered in lots, and if multiple deliveries of the same feedstock are received from the same supply source in a given calendar month, only one representative sample is required. Alternatively, you may use the results of analyses conducted by a feedstock supplier, or product customer, provided the sampling and analysis is conducted at least once per month using any of the procedures specified in § 98.244(b)(4).
(4) If you determine that the monthly average concentration of a specific compound in a feedstock or product is greater than 99.5 percent by volume or mass, then as an alternative to the sampling and analysis specified in paragraph (c)(3) of this section, you may determine molecular weight and carbon content in accordance with paragraphs (c)(4)(i) through (iii) of this section.
(i) Calculate the molecular weight and carbon content assuming 100 percent of that feedstock or product is the specific compound.
(ii) Maintain records of any determination made in accordance with this paragraph (c)(4) along with all supporting data, calculations, and other information.
(iii) Reevaluate determinations made under this paragraph (c)(4) after any process change that affects the feedstock or product composition. Keep records of the process change and the corresponding composition determinations. If the feedstock or product composition changes so that the average monthly concentration falls below 99.5 percent, you are no longer permitted to use this alternative method.
(5) Calculate the CO
(i)
(ii)
(iii)
(iv)
(d)
(1) Except as specified in paragraphs (d)(2) and (d)(5) of this section, calculate CO
(2) You may use either Equation C-1 or Equation C-2a in subpart C of this part to calculate CO
(i) The annual average flow rate of fuel gas (that contains ethylene process off-gas) in the fuel gas line to the combustion unit, prior to any split to individual burners or ports, does not exceed 345 standard cubic feet per minute at 60 °F and 14.7 pounds per square inch absolute, and a flow meter is not installed at any point in the line supplying fuel gas or an upstream common pipe. Calculate the annual average flow rate using company records assuming total flow is evenly distributed over 525,600 minutes per year.
(ii) The combustion unit has a maximum rated heat input capacity of less than 30 mmBtu/hr, and a flow meter is not installed at any point in the line supplying fuel gas (that contains ethylene process off-gas) or an upstream common pipe.
(3) Except as specified in paragraph (d)(5) of this section, calculate CH
(i) For all gaseous fuels that contain ethylene process off-gas, use the emission factors for “Fuel Gas” in Table C-2 of subpart C of this part (General Stationary Fuel Combustion Sources).
(ii) For Tier 3, use either the default high heat value for fuel gas in Table C-1 of subpart C of this part or a calculated HHV, as allowed in Equation C-8 of subpart C of this part.
(4) You are not required to use the same Tier for each stationary combustion unit that burns ethylene process off-gas.
(5) For each flare, calculate CO
(a) If you use CEMS to determine emissions from process vents, you must comply with the procedures specified in § 98.34(c).
(b) If you use the mass balance methodology in § 98.243(c), use the procedures specified in paragraphs (b)(1) through (b)(4) of this section to determine feedstock and product flows and carbon contents.
(1) Operate, maintain, and calibrate belt scales or other weighing devices as described in Specifications, Tolerances, and Other Technical Requirements for Weighing and Measuring Devices NIST Handbook 44 (2009) (incorporated by reference, see § 98.7), or follow procedures specified by the measurement device manufacturer. You must recalibrate each weighing device according
(2) Operate and maintain all flow meters used for gas and liquid feedstocks and products according to the manufacturer's recommended procedures. You must calibrate each of these flow meters as specified in paragraphs (b)(2)(i) and (b)(2)(ii) of this section:
(i) You may use either the calibration methods specified by the flow meter manufacturer or an industry consensus standard method. Each flow meter must meet the applicable accuracy specification in § 98.3(i), except as otherwise specified in §§ 98.3(i)(4) through (i)(6).
(ii) You must recalibrate each flow meter according to one of the following frequencies. You may recalibrate at the minimum frequency specified by the manufacturer, biennially (every two years), or at the interval specified by the industry consensus standard practice used.
(3) You must perform tank level measurements (if used to determine feedstock or product flows) according to one of the following methods. You may use any standard method published by a consensus-based standards organization or you may use an industry standard practice. Consensus-based standards organizations include, but are not limited to, the following: ASTM International (100 Barr Harbor Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959, (800) 262-1373,
(4) Beginning January 1, 2010, use any applicable methods specified in paragraphs (b)(4)(i) through (xv) of this section to determine the carbon content or composition of feedstocks and products and the average molecular weight of gaseous feedstocks and products. Calibrate instruments in accordance with paragraphs (b)(4)(i) through (xv) of this section, as applicable. For coal used as a feedstock, the samples for carbon content determinations shall be taken at a location that is representative of the coal feedstock used during the corresponding monthly period. For carbon black products, samples shall be taken of each grade or type of product produced during the monthly period. Samples of coal feedstock or carbon black product for carbon content determinations may be either grab samples collected and analyzed monthly or a composite of samples collected more frequently and analyzed monthly. Analyses conducted in accordance with methods specified in paragraphs (b)(4)(i) through (xv) of this section may be performed by the owner or operator, by an independent laboratory, by the supplier of a feedstock, or by a product customer.
(i) ASTM D1945-03, Standard Test Method for Analysis of Natural Gas by Gas Chromatography (incorporated by reference,
(ii) ASTM D6060-96 (Reapproved 2001) Standard Practice for Sampling of Process Vents With a Portable Gas Chromatograph (incorporated by reference,
(iii) ASTM D2505-88(Reapproved 2004)e1 Standard Test Method for Ethylene, Other Hydrocarbons, and Carbon Dioxide in High-Purity Ethylene by Gas Chromatography (incorporated by reference,
(iv) ASTM UOP539-97 Refinery Gas Analysis by Gas Chromatography (incorporated by reference,
(v) ASTM D3176-89 (Reapproved 2002) Standard Practice Method for Ultimate Analysis of Coal and Coke (incorporated by reference,
(vi) ASTM D5291-02 (Reapproved 2007) Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum
(vii) ASTM D5373-08 Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference,
(viii) Method 8015C, Method 8021B, Method 8031, or Method 9060A (all incorporated by reference, see § 98.7).
(ix) Method 18 at 40 CFR part 60, appendix A-6.
(x) Performance Specification 9 in 40 CFR part 60, appendix B for continuous online gas analyzers. The 7-day calibration error test period must be completed prior to the effective date of the rule.
(xi) ASTM D2593-93 (Reapproved 2009) Standard Test Method for Butadiene Purity and Hydrocarbon Impurities by Gas Chromatography (incorporated by reference, see § 98.7).
(xii) ASTM D7633-10 Standard Test Method for Carbon Black—Carbon Content (incorporated by reference, see § 98.7).
(xiii) The results of chromatographic analysis of a feedstock or product, provided that the chromatograph is operated, maintained, and calibrated according to the manufacturer's instructions.
(xiv) The results of mass spectrometer analysis of a feedstock or product, provided that the mass spectrometer is operated, maintained, and calibrated according to the manufacturer's instructions.
(xv) Beginning on January 1, 2010, the methods specified in paragraphs (b)(4)(xv)(A) and (B) of this section may be used as alternatives for the methods specified in paragraphs (b)(4)(i) through (b)(4)(xiv) of this section.
(A) An industry standard practice or a method published by a consensus-based standards organization if such a method exists for carbon black feedstock oils and carbon black products. Consensus-based standards organizations include, but are not limited to, the following: ASTM International (100 Barr Harbor Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959, (800) 262-1373,
(B) Modifications of existing analytical methods or other methods that are applicable to your process provided that the methods listed in paragraphs (b)(4)(i) through (b)(4)(xiv) of this section are not appropriate because the relevant compounds cannot be detected, the quality control requirements are not technically feasible, or use of the method would be unsafe.
(c) If you comply with § 98.243(b) or (d), conduct monitoring and QA/QC for flares in accordance with § 98.254(b) through (e) for each flare gas flow meter, gas composition meter, and/or heating value monitor that you use to comply with § 98.253(b)(1) through (b)(3). You must implement all applicable QA/QC requirements specified in this paragraph (c) beginning no later than January 1, 2015.
For missing feedstock and product flow rates, use the same procedures as for missing fuel usage as specified in § 98.35(b)(2). For missing feedstock and product carbon contents and missing molecular weights for gaseous feedstocks and products, use the same procedures as for missing carbon contents and missing molecular weights for fuels as specified in § 98.35(b)(1).
For missing flare data, follow the procedures in § 98.255(b) and (c).
In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a), (b), or (c) of this section, as appropriate for each process unit.
(a) If you use the mass balance methodology in § 98.243(c), you must report the information specified in paragraphs (a)(1) through (13) of this section for each type of petrochemical produced, reported by process unit.
(1) The petrochemical process unit ID number or other appropriate descriptor.
(2) The type of petrochemical produced, names of products, and names of carbon-containing feedstocks.
(3) Annual CO
(4) The temperature (in °F) at which the gaseous feedstock and product volumes used in Equation X-1 of § 98.243 were determined.
(5) Annual quantity of each type of petrochemical produced from each process unit (metric tons). If you are electing to consider the petrochemical process unit to be the entire integrated ethylene dichloride/vinyl chloride monomer process, report the amount of intermediate EDC produced (metric tons). The reported amount of intermediate EDC produced may be a measured quantity or an estimate that is based on process knowledge and best available data.
(6) For each feedstock and product, provide the information specified in paragraphs (a)(6)(i) through (a)(6)(iii) of this section.
(i) Name of each method used to determine carbon content or molecular weight in accordance with § 98.244(b)(4);
(ii) Description of each type of measurement device (
(iii) Identification of each method (
(7) [Reserved]
(8) Identification of each combustion unit that burned both process off-gas and supplemental fuel, including combustion units that are not part of the petrochemical process unit.
(9) The number of days during which off-specification product was produced if the alternative to sampling and analysis specified in § 98.243(c)(4) is used for a product, and, if applicable, the date of any process change that reduced the monthly average composition to less than 99.5 percent for each product or feedstock for which you comply with the alternative to sampling and analysis specified in § 98.243(c)(4).
(10) You may elect to report the flow and carbon content of wastewater, and you may elect to report the annual mass of carbon released in fugitive emissions and in process vents that are not controlled with a combustion device. These values may be estimated based on engineering analyses. These values are not to be used in the mass balance calculation.
(11) If you determine carbon content or composition of a feedstock or product using a method under § 98.244(b)(4)(xv)(B), report the information listed in paragraphs (a)(11)(i) through (a)(11)(iii) of this section. Include the information in paragraph (a)(11)(i) of this section in each annual report. Include the information in paragraphs (a)(11)(ii) and (a)(11)(iii) of this section only in the first applicable annual report, and provide any changes to this information in subsequent annual reports.
(i) Name or title of the analytical method.
(ii) A copy of the method. If the method is a modification of a method listed in §§ 98.244(b)(4)(i) through (xiv), you may provide a copy of only the sections that differ from the listed method.
(iii) An explanation of why an alternative to the methods listed in §§ 98.244(b)(4)(i) through (xiv) is needed.
(12) Name and annual quantity (in metric tons) of each carbon-containing feedstock included in Equations X-1, X-2, and X-3 of § 98.243.
(13) Name and annual quantity (in metric tons) of each product included in Equations X-1, X-2, and X-3.
(14) Annual average of the measurements or determinations of the carbon content of each feedstock and product,
(i) For feedstocks and products that are gaseous or solid, report this quantity in kg C per kg of feedstock or product.
(ii) For liquid feedstocks and products, report this quantity either in units of kg C per kg of feedstock or product, or kg C per gallon of feedstock or product.
(15) For each gaseous feedstock and product, the annual average of the measurements or determinations of the molecular weight in units of kg per kg mole, conducted according to § 98.243(c)(3) or (4).
(b) If you measure emissions in accordance with § 98.243(b), then you must report the information listed in paragraphs (b)(1) through (10) of this section.
(1) The petrochemical process unit ID or other appropriate descriptor, and the type of petrochemical produced.
(2) For CEMS used on stacks that include emissions from stationary combustion units that burn any amount of off-gas from the petrochemical process, report the relevant information required under § 98.36(c)(2) and (e)(2)(vi) for the Tier 4 calculation methodology. Section 98.36(c)(2)(ii), (ix) and (x) do not apply for the purposes of this subpart.
(3) For CEMS used on stacks that do not include emissions from stationary combustion units, report the information required under § 98.36(b)(6) and (7), (b)(9)(i) and (ii) and (e)(2)(vi).
(4) For each CEMS monitoring location that meets the conditions in paragraph (b)(2) or (3) of this section, provide an estimate based on engineering judgment of the fraction of the total CO
(5) For each CEMS monitoring location that meets the conditions in paragraph (b)(2) of this section, report the CH
(6) [Reserved]
(7) Information listed in § 98.256(e) of subpart Y of this part for each flare that burns process off-gas.
(8) Annual quantity of each type of petrochemical produced from each process unit (metric tons). If you are electing to consider the petrochemical process unit to be the entire integrated ethylene dichloride/vinyl chloride monomer process, report the amount of intermediate EDC produced (metric tons). The reported amount of intermediate EDC produced may be a measured quantity or an estimate that is based on process knowledge and best available data.
(9) Name and annual quantity (in metric tons) of each carbon-containing feedstock.
(10) Name and annual quantity (in metric tons) of each product.
(c) If you comply with the combustion methodology specified in § 98.243(d), you must report under this subpart the information listed in paragraphs (c)(1) through (c)(5) of this section.
(1) The ethylene process unit ID or other appropriate descriptor.
(2) For each stationary combustion unit that burns ethylene process off-gas (or group of stationary sources with a common pipe), except flares, the relevant information listed in § 98.36 for the applicable Tier methodology. For each stationary combustion unit or group of units (as applicable) that burns ethylene process off-gas, provide an estimate based on engineering judgment of the fraction of the total emissions that is attributable to combustion of off-gas from the ethylene process unit.
(3) Information listed in § 98.256(e) of subpart Y of this part for each flare that burns ethylene process off-gas.
(4) Name and annual quantity of each feedstock (metric tons).
(5) Annual quantity of ethylene produced from each process unit (metric tons).
In addition to the recordkeeping requirements in § 98.3(g), you must retain the records specified in paragraphs (a) through (d) of this section, as applicable.
(a) If you comply with the CEMS measurement methodology in § 98.243(b), then you must retain under this subpart the records required for the Tier 4 Calculation Methodology in § 98.37, records of the procedures used to develop estimates of the fraction of total emissions attributable to petrochemical processing and combustion of petrochemical process off-gas as required in § 98.246(b), and records of any annual average HHV calculations.
(b) If you comply with the mass balance methodology in § 98.243(c), then you must retain records of the information listed in paragraphs (b)(1) through (4) of this section.
(1) Results of feedstock or product composition determinations conducted in accordance with § 98.243(c)(4).
(2) Start and end times for time periods when off-specification product is produced, if you comply with the alternative methodology in § 98.243(c)(4) for determining carbon content of product.
(3) As part of the monitoring plan required under § 98.3(g)(5), record the estimated accuracy of measurement devices and the technical basis for these estimates.
(4) The dates and results (
(c) If you comply with the combustion methodology in § 98.243(d), then you must retain under this subpart the records required for the applicable Tier Calculation Methodologies in § 98.37. If you comply with § 98.243(d)(2), you must also keep records of the annual average flow calculations.
(d)
(1) Indicate whether the feedstock is measured as mass or volume (Equation X-1 of § 98.243).
(2) Indicate whether you used the alternative to sampling and analysis specified in § 98.243(c)(4) (Equation X-1).
(3) Volume of gaseous feedstock introduced per month (scf) (Equation X-1).
(4) Mass of gaseous feedstock introduced per month (kg) (Equation X-1).
(5) Average carbon content of the gaseous feedstock per month (kg C per kg of feedstock) (Equation X-1).
(6) Molecular weight of gaseous feedstock per month (kg per kg-mole) (Equation X-1).
(7) Indicate whether the gaseous product is measured as mass or volume (Equation X-1).
(8) Volume of gaseous product produced per month (scf) (Equation X-1).
(9) Mass of gaseous product produced per month (kg) (Equation X-1).
(10) Average carbon content of gaseous product (including streams containing CO
(11) Molecular weight of gaseous product per month (kg per kg-mole) (Equation X-1).
(12) Molar volume conversion factor of product (scf per kg-mole) (Equation X-1).
(13) Indicate whether feedstock is measured as mass or volume (Equation X-2 of § 98.243).
(14) Indicate whether you used the alternative to sampling and analysis specified in § 98.243(c)(4) (Equation X-2).
(15) Volume of liquid feedstock introduced per month (gallons) (Equation X-2).
(16) Mass of liquid feedstock introduced per month (kg) (Equation X-2).
(17) Average carbon content of liquid feedstock per month (kg C per gallon) (Equation X-2).
(18) Average carbon content of liquid feedstock per month (kg C per kg of feedstock) (Equation X-2).
(19) Indicate whether product is measured as mass or volume per month (Equation X-2).
(20) Volume of liquid product produced per month (gallons) (Equation X-2).
(21) Mass of liquid product produced per month (kg) (Equation X-2).
(22) Average carbon content of liquid product per month, including organic liquid wastes (kg C per gallon) (Equation X-2).
(23) Average carbon content of liquid product, including organic liquid wastes (kg C per kg of product) (Equation X-2).
(24) Indicate whether you used the alternative to sampling and analysis specified in § 98.243(c)(4) (Equation X-3 of § 98.243).
(25) Mass of solid feedstock introduced per month (kg) (Equation X-3).
(26) Average carbon content of solid feedstock per month (kg C per kg of feedstock) (Equation X-3).
(27) Mass of solid product produced per month (kg) (Equation X-3).
(28) Average carbon content of solid product per month (kg C per kg of product) (Equation X-3).
(29) Records required in § 98.257(b)(1) through (8) of this section for each flare that burns ethylene process off-gas.
(30) Records required in § 98.37 for each stationary fuel combustion unit (or group of stationary sources with a common pipe) that burns ethylene process off-gas, except flares.
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.
(a) A petroleum refinery is any facility engaged in producing gasoline, gasoline blending stocks, naphtha, kerosene, distillate fuel oils, residual fuel oils, lubricants, or asphalt (bitumen) through distillation of petroleum or through redistillation, cracking, or reforming of unfinished petroleum derivatives, except as provided in paragraph (b) of this section.
(b) For the purposes of this subpart, facilities that distill only pipeline transmix (off-spec material created when different specification products mix during pipeline transportation) are not petroleum refineries, regardless of the products produced.
(c) This source category consists of the following sources at petroleum refineries: Catalytic cracking units; fluid coking units; delayed coking units; catalytic reforming units; coke calcining units; asphalt blowing operations; blowdown systems; storage tanks; process equipment components (compressors, pumps, valves, pressure relief devices, flanges, and connectors) in gas service; marine vessel, barge, tanker truck, and similar loading operations; flares; sulfur recovery plants; and non-merchant hydrogen plants (i.e., hydrogen plants that are owned or under the direct control of the refinery owner and operator).
You must report GHG emissions under this subpart if your facility contains a petroleum refineries process and the facility meets the requirements of either § 98.2(a)(1) or (a)(2).
You must report:
(a) CO
(1) The annual average fuel gas flow rate in the fuel gas line to the combustion unit, prior to any split to individual burners or ports, does not exceed 345 standard cubic feet per minute at 60 °F and 14.7 pounds per square inch absolute and either of the conditions in paragraph (a)(1)(i) or (ii) of this section exist. Calculate the annual average flow rate using company records assuming total flow is evenly distributed over 525,600 minutes per year.
(i) A flow meter is not installed at any point in the line supplying fuel gas or an upstream common pipe.
(ii) The fuel gas line contains only vapors from loading or unloading, waste or wastewater handling, and remediation activities that are combusted in a thermal oxidizer or thermal incinerator.
(2) The combustion unit has a maximum rated heat input capacity of less than 30 mmBtu/hr and either of the following conditions exist:
(i) A flow meter is not installed at any point in the line supplying fuel gas or an upstream common pipe; or
(ii) The fuel gas line contains only vapors from loading or unloading, waste or wastewater handling, and remediation activities that are combusted in a thermal oxidizer or thermal incinerator.
(b) CO
(c) CO
(d) CO
(e) CO
(f) CO
(g) CH
(h) CO
(i) CO
(a) Calculate GHG emissions required to be reported in § 98.252(b) through (i) using the applicable methods in paragraphs (b) through (n) of this section.
(b) For flares, calculate GHG emissions according to the requirements in paragraphs (b)(1) through (b)(3) of this section.
(1) Calculate the CO
(i)
(ii)
(A) If you monitor gas composition, calculate the CO
(B) If you monitor heat content but do not monitor gas composition, calculate the CO
(iii)
(A) For periods of start-up, shutdown, or malfunction, use engineering calculations and process knowledge to estimate the carbon content of the flared gas for each start-up, shutdown, or malfunction event exceeding 500,000 scf/day.
(B) For periods of normal operation, use the average heating value measured for the fuel gas for the heating value of the flare gas. If heating value is not measured, the heating value may be estimated from historic data or engineering calculations.
(C) Calculate the CO
(2) Calculate CH
(3) Calculate N
(c) For catalytic cracking units and traditional fluid coking units, calculate the GHG emissions using the applicable methods described in paragraphs (c)(1) through (c)(5) of this section.
(1) If you operate and maintain a CEMS that measures CO
(i) Calculate CO
(ii) For catalytic cracking units whose process emissions are discharged through a combined stack with other CO
(2) For catalytic cracking units and fluid coking units with rated capacities greater than 10,000 barrels per stream day (bbls/sd) that do not use a continuous CO
(i) Calculate the CO
(ii) Either continuously monitor the volumetric flow rate of exhaust gas from the fluid catalytic cracking unit regenerator or fluid coking unit burner prior to the combustion of other fossil fuels or calculate the volumetric flow rate of this exhaust gas stream using either Equation Y-7a or Equation Y-7b of this section.
(iii) If you have a CO boiler that uses auxiliary fuels or combusts materials other than catalytic cracking unit or fluid coking unit exhaust gas, you must determine the CO
(3) For catalytic cracking units and fluid coking units with rated capacities of 10,000 barrels per stream day (bbls/sd) or less that do not use a continuous CO
(i) If you continuously or no less frequently than daily monitor the O
(ii) If you do not monitor at least daily the O
(iii) If you have a CO boiler that uses auxiliary fuels or combusts materials other than catalytic cracking unit or fluid coking unit exhaust gas, you must determine the CO
(4) Calculate CH
(5) Calculate N
(d) For fluid coking units that use the flexicoking design, the GHG emissions from the resulting use of the low value fuel gas must be accounted for only once. Typically, these emissions will be accounted for using the methods described in subpart C of this part (General Stationary Fuel Combustion Sources). Alternatively, you may use the methods in paragraph (c) of this section provided that you do not otherwise account for the subsequent combustion of this low value fuel gas.
(e) For catalytic reforming units, calculate the CO
(1) If you operate and maintain a CEMS that measures CO
(2) If you continuously or no less frequently than daily monitor the O
(3) Calculate CO
(f) For on-site sulfur recovery plants and for sour gas sent off site for sulfur recovery, calculate and report CO
(1) If you operate and maintain a CEMS that measures CO
(2) Flow measurement. If you have a continuous flow monitor on the sour gas feed to the sulfur recovery plant or the sour gas feed sent for off-site sulfur recovery, you must use the measured flow rates when the monitor is operational to calculate the sour gas flow rate. If you do not have a continuous flow monitor on the sour gas feed to the sulfur recovery plant or the sour gas feed sent for off-site sulfur recovery, you must use engineering calculations, company records, or similar estimates of volumetric sour gas flow.
(3) Carbon content. If you have a continuous gas composition monitor capable of measuring carbon content on the sour gas feed to the sulfur recovery plant or the sour gas feed sent for off-site for sulfur recovery, or if you monitor gas composition for carbon content on a routine basis, you must use the measured carbon content value. Alternatively, you may develop a site-specific carbon content factor using limited measurement data or engineering estimates or use the default factor of 0.20.
(4) Calculate the CO
(5) If tail gas is recycled to the front of the sulfur recovery plant and the recycled flow rate and carbon content is included in the measured data under paragraphs (f)(2) and (f)(3) of this section, respectively, then the annual CO
(g) For coke calcining units, calculate GHG emissions according to the applicable provisions in paragraphs (g)(1) through (g)(3) of this section.
(1) If you operate and maintain a CEMS that measures CO
(2) Calculate the CO
(3) For all coke calcining units, use the CO
(h) For asphalt blowing operations, calculate CO
(1) For uncontrolled asphalt blowing operations or asphalt blowing operations controlled by vapor scrubbing, calculate CO
(2) For asphalt blowing operations controlled by thermal oxidizer or flare, calculate CO
(i) For delayed coking units, calculate the CH
(1) Use the process vent method in paragraph (j) of this section to calculate the CH
(2) Calculate the CH
(j) For each process vent not covered in paragraphs (a) through (i) of this section that can reasonably be expected to contain greater than 2 percent by volume CO
(k) For uncontrolled blowdown systems, you must calculate CH
(l) For equipment leaks, calculate CH
(1) Use process-specific methane composition data (from measurement data or process knowledge) and any of the emission estimation procedures provided in the Protocol for Equipment Leak Emissions Estimates (EPA-453/R-95-017, NTIS PB96-175401).
(2) Use Equation Y-21 of this section.
(m) For storage tanks, except as provided in paragraph (m)(3) of this section, calculate CH
(1) For storage tanks other than those processing unstabilized crude oil, you must either calculate CH
(2) For storage tanks that process unstabilized crude oil, calculate CH
(3) You do not need to calculate CH
(i) Units permanently attached to conveyances such as trucks, trailers, rail cars, barges, or ships;
(ii) Pressure vessels designed to operate in excess of 204.9 kilopascals and without emissions to the atmosphere;
(iii) Bottoms receivers or sumps;
(iv) Vessels storing wastewater; or
(v) Reactor vessels associated with a manufacturing process unit.
(n) For crude oil, intermediate, or product loading operations for which the vapor-phase concentration of methane is 0.5 volume percent or more, calculate CH
At 81 FR 89261, Dec. 9, 2016, § 98.253 was amended by:
a. Revising paragraphs (b) introductory text, (b)(1)(iii)(B), (h)(1) introductory text, and (h)(2) introductory text;
b. Revising parameters “0.98” of Equations Y-16a and Y-16b and “0.02” of Equation Y-17 in paragraph (h)(2); and
c. Revising paragraphs (i) and (j) introductory text, effective Jan. 1, 2019. For the convenience of the user, the revised text is set forth as follows:
(b) For flares, calculate GHG emissions according to the requirements in paragraphs (b)(1) through (3) of this section. All gas discharged through the flare stack must be included in the flare GHG emissions calculations with the exception of gas used for the flare pilots, which may be excluded.
(1) * * *
(iii) * * *
(B) For periods of normal operation, use the average higher heating value measured for the fuel gas used as flare sweep or purge gas for the higher heating value of the flare gas. If higher heating value of the fuel gas is not measured, the higher heating value of the flare gas under normal operations may be estimated from historic data or engineering calculations.
(h) * * *
(1) For uncontrolled asphalt blowing operations or asphalt blowing operations controlled either by vapor scrubbing or by another non-combustion control device, calculate CO
(2) For asphalt blowing operations controlled by either a thermal oxidizer, a flare, or other vapor combustion control device, calculate CO
(i) For each delayed coking unit, calculate the CH
(1) Determine the typical dry mass of coke produced per cycle from company records of the mass of coke produced by the delayed coking unit. Alternatively, you may estimate the typical dry mass of coke produced per cycle based on the delayed coking unit vessel (coke drum) dimensions and typical coke drum outage at the end of the coking cycle using Equation Y-18a of this section.
(2) Determine the typical mass of water in the delayed coking unit vessel at the end of the cooling cycle prior to venting to the atmosphere using Equation Y-18b of this section.
(3) Determine the average temperature of the delayed coking unit vessel when the drum is first vented to the atmosphere using either Equation Y-18c or Y-18d of this section, as appropriate, based on the measurement system available.
(4) Determine the typical mass of steam generated and released per decoking cycle using Equation Y-18e of this section.
(5) Calculate the CH
(j) For each process vent not covered in paragraphs (a) through (i) of this section that can reasonably be expected to contain greater than 2 percent by volume CO
(a) Fuel flow meters, gas composition monitors, and heating value monitors that are associated with sources that use a CEMS to measure CO
(b) All gas flow meters, gas composition monitors, and heating value monitors that are used to provide data for the GHG emissions calculations in this subpart for sources other than those subject to the requirements in paragraph (a) of this section shall be calibrated according to the procedures specified by the manufacturer, or according to the procedures in the applicable methods specified in paragraphs (c) through (g) of this section. In the case of gas flow meters, all gas flow meters must meet the calibration accuracy requirements in § 98.3(i). All gas flow meters, gas composition monitors, and heating value monitors must be recalibrated at the applicable frequency specified in paragraph (b)(1) or (b)(2) of this section.
(1) You must recalibrate each gas flow meter according to one of the following frequencies. You may recalibrate at the minimum frequency specified by the manufacturer, biennially (every two years), or at the interval specified by the industry consensus standard practice used.
(2) You must recalibrate each gas composition monitor and heating value monitor according to one of the following frequencies. You may recalibrate at the minimum frequency specified by the manufacturer, annually, or at the interval specified by the industry standard practice used.
(c) For flare or sour gas flow meters and gas flow meters used to comply with the requirements in § 98.253(j), operate, calibrate, and maintain the flow meter according to one of the following. You may use the procedures specified by the flow meter manufacturer, or a method published by a consensus-based standards organization. Consensus-based standards organizations include, but are not limited to, the following: ASTM International (100 Barr Harbor Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959, (800) 262-1373,
(d) Except as provided in paragraph (g) of this section, determine gas composition and, if required, average molecular weight of the gas using any of the following methods. Alternatively, the results of chromatographic analysis of the fuel may be used, provided that the gas chromatograph is operated, maintained, and calibrated according to the manufacturer's instructions; and the methods used for operation, maintenance, and calibration of the gas chromatograph are documented in the written Monitoring Plan for the unit under § 98.3(g)(5).
(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,
(3) ASTM D1946-90 (Reapproved 2006) Standard Practice for Analysis of Reformed Gas by Gas Chromatography (incorporated by reference,
(4) GPA 2261-00 Analysis for Natural Gas and Similar Gaseous Mixtures by Gas Chromatography (incorporated by reference,
(5) UOP539-97 Refinery Gas Analysis by Gas Chromatography (incorporated by reference,
(6) ASTM D2503-92 (Reapproved 2007) Standard Test Method for Relative Molecular Mass (Molecular Weight) of Hydrocarbons by Thermoelectric Measurement of Vapor Pressure (incorporated by reference, see § 98.7).
(e) Determine flare gas higher heating value using any of the following methods. Alternatively, the results of chromatographic analysis of the fuel may be used, provided that the gas chromatograph is operated, maintained, and calibrated according to the manufacturer's instructions; and the methods used for operation, maintenance, and calibration of the gas chromatograph are documented in the written Monitoring Plan for the unit under § 98.3(g)(5).
(1) ASTM D4809-06 Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method) (incorporated by reference,
(2) ASTM D240-02 (Reapproved 2007) Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter (incorporated by reference,
(3) ASTM D1826-94 (Reapproved 2003) Standard Test Method for Calorific (Heating) Value of Gases in Natural Gas Range by Continuous Recording Calorimeter (incorporated by reference,
(4) ASTM D3588-98 (Reapproved 2003) Standard Practice for Calculating Heat Value, Compressibility Factor, and Relative Density of Gaseous Fuels (incorporated by reference,
(5) ASTM D4891-89 (Reapproved 2006) Standard Test Method for Heating Value of Gases in Natural Gas Range by Stoichiometric Combustion (incorporated by reference,
(f) For gas flow meters used to comply with the requirements in § 98.253(c)(2)(ii), install, operate, calibrate, and maintain each gas flow meter according to the requirements in 40 CFR 63.1572(c) and the following requirements.
(1) Locate the flow monitor at a site that provides representative flow rates. Avoid locations where there is swirling flow or abnormal velocity distributions due to upstream and downstream disturbances.
(2) [Reserved]
(3) Use a continuous monitoring system capable of correcting for the temperature, pressure, and moisture content to output flow in dry standard cubic feet (standard conditions as defined in § 98.6).
(g) For exhaust gas CO
(h) Determine the mass of petroleum coke as required by Equation Y-13 of this subpart using mass measurement equipment meeting the requirements for commercial weighing equipment as described in Specifications, Tolerances, and Other Technical Requirements For Weighing and Measuring Devices, NIST Handbook 44 (2009) (incorporated by reference, see § 98.7). Calibrate the measurement device according to the procedures specified by NIST handbook 44 (incorporated by reference, see § 98.7) or the procedures specified by the manufacturer. Recalibrate either biennially or at the minimum frequency specified by the manufacturer.
(i) Determine the carbon content of petroleum coke as required by Equation Y-13 of this subpart using any one of the following methods. Calibrate the measurement device according to procedures specified by the method or procedures specified by the measurement device manufacturer.
(1) ASTM D3176-89 (Reapproved 2002) Standard Practice for Ultimate Analysis of Coal and Coke (incorporated by reference,
(2) ASTM D5291-02 (Reapproved 2007) Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants (incorporated by reference,
(3) ASTM D5373-08 Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference,
(j) Determine the quantity of petroleum process streams using company records. These quantities include the quantity of asphalt blown, quantity of crude oil plus the quantity of intermediate products received from off site, and the quantity of unstabilized crude oil received at the facility.
(k) The owner or operator shall document the procedures used to ensure the accuracy of the estimates of fuel usage, gas composition, and heating value including but not limited to calibration of weighing equipment, fuel flow meters, and other measurement devices. The estimated accuracy of measurements made with these devices shall also be recorded, and the technical basis for these estimates shall be provided.
At 81 FR 89263, Dec. 9, 2016, § 98.254 was amended by revising paragraph (j), redesignating paragraph (k) as paragraph (l), and adding new paragraph (k), effective Jan. 1, 2019. For the convenience of the user, the added and revised text is set forth as follows:
(j) Determine the quantity of petroleum process streams using company records. These quantities include the quantity of coke produced per cycle, asphalt blown, quantity of crude oil plus the quantity of intermediate products received from off site, and the quantity of unstabilized crude oil received at the facility.
(k) Determine temperature or pressure of delayed coking unit vessel using process instrumentation operated, maintained, and calibrated according to the manufacturer's instructions.
A complete record of all measured parameters used in the GHG emissions calculations is required (e.g., concentrations, flow rates, fuel heating values, carbon content values). Therefore, whenever a quality-assured value of a required parameter is unavailable (e.g., if a CEMS malfunctions during unit operation or if a required fuel sample is not taken), a substitute data value for the missing parameter shall be used in the calculations.
(a) For stationary combustion sources, use the missing data procedures in subpart C of this part.
(b) For each missing value of the heat content, carbon content, or molecular weight of the fuel, substitute the arithmetic average of the quality-assured values of that parameter immediately preceding and immediately following the missing data incident. If
(c) For missing CO
(d) For hydrogen plants, use the missing data procedures in subpart P of this part.
In addition to the reporting requirements of § 98.3(c), you must report the information specified in paragraphs (a) through (q) of this section.
(a) For combustion sources, follow the data reporting requirements under subpart C of this part (General Stationary Fuel Combustion Sources).
(b) For hydrogen plants, follow the data reporting requirements under subpart P of this part (Hydrogen Production).
(c)-(d) [Reserved]
(e) For flares, owners and operators shall report:
(1) The flare ID number (if applicable).
(2) A description of the type of flare (steam assisted, air-assisted).
(3) A description of the flare service (general facility flare, unit flare, emergency only or back-up flare).
(4) The calculated CO
(5) A description of the method used to calculate the CO
(6) If you use Equation Y-1a of § 98.253, an indication of whether daily or weekly measurement periods are used, the annual volume of flare gas combusted (in scf/year) and the annual average molecular weight (in kg/kg-mole), and annual average carbon content of the flare gas (in kg carbon per kg flare gas).
(7) If you use Equation Y-1b of § 98.253, an indication of whether daily or weekly measurement periods are used, the annual volume of flare gas combusted (in scf/year), the annual average CO
(i) The annual average concentration of the compound (volume or mole percent).
(ii) [Reserved]
(8) If you use Equation Y-2 of this subpart, an indication of whether daily or weekly measurement periods are used, the annual volume of flare gas combusted (in million (MM) scf/year), the annual average higher heating value of the flare gas (in mmBtu/mmscf), and an indication of whether the annual volume of flare gas combusted and the annual average higher heating value of the flare gas were determined using standard conditions of 68 °F and 14.7 psia or 60 °F and 14.7 psia.
(9) If you use Equation Y-3 of § 98.253, the number of SSM events exceeding 500,000 scf/day.
(10) The basis for the value of the fraction of carbon in the flare gas contributed by methane used in Equation Y-4 of § 98.253.
(f) For catalytic cracking units, traditional fluid coking units, and catalytic reforming units, owners and operators shall report:
(1) The unit ID number (if applicable).
(2) A description of the type of unit (fluid catalytic cracking unit, thermal catalytic cracking unit, traditional fluid coking unit, or catalytic reforming unit).
(3) Maximum rated throughput of the unit, in bbl/stream day.
(4) The calculated CO
(5) A description of the method used to calculate the CO
(6) If you use a CEMS, the relevant information required under § 98.36 for the Tier 4 Calculation Methodology, the CO
(7) If you use Equation Y-6 of § 98.253, the annual average exhaust gas flow rate, %CO
(8) If you use Equation Y-7a of this subpart, the annual average flow rate of inlet air and oxygen-enriched air, %O
(9) If you use Equation Y-7b of this subpart, the annual average flow rate of inlet air and oxygen-enriched air, %N
(10) If you use Equation Y-8 of § 98.253, the basis for the value of the average carbon content of coke.
(11) Indicate whether you use a measured value, a unit-specific emission factor, or a default for CH
(12) Indicate whether you use a measured value, a unit-specific emission factor, or a default emission factor for N
(13) If you use Equation Y-11 of § 98.253, the number of regeneration cycles or measurement periods during the reporting year and the average coke burn-off quantity per cycle or measurement period.
(g) For fluid coking unit of the flexicoking type, the owner or operator shall report:
(1) The unit ID number (if applicable).
(2) A description of the type of unit.
(3) Maximum rated throughput of the unit, in bbl/stream day.
(4) Indicate whether the GHG emissions from the low heat value gas are accounted for in subpart C of this part or § 98.253(c).
(5) If the GHG emissions for the low heat value gas are calculated at the flexicoking unit, also report the calculated annual CO
(h) For on-site sulfur recovery plants and for emissions from sour gas sent off-site for sulfur recovery, the owner and operator shall report:
(1) The plant ID number (if applicable).
(2) For each on-site sulfur recovery plant, the maximum rated throughput (metric tons sulfur produced/stream day), a description of the type of sulfur recovery plant, and an indication of the method used to calculate CO
(3) The calculated CO
(4) [Reserved]
(5) If you recycle tail gas to the front of the sulfur recovery plant, indicate whether the recycled flow rate and carbon content are included in the measured data under § 98.253(f)(2) and (3). Indicate whether a correction for CO
(i) Indicate whether you used the default (95 percent) or a unit specific correction, and if a unit-specific correction was used, report the value of the correction and the approach used.
(ii) If the following data are not used to calculate the recycling correction factor, report the information specified in paragraphs (h)(5)(ii)(A) through (B) of this section.
(A) The annual volume of recycled tail gas (in scf/year) only.
(B) The annual average mole fraction of carbon in the tail gas (in kg-mole C/kg-mole gas).
(6) If you use a CEMS, the relevant information required under § 98.36 for
(7) If you use the process vent method in § 98.253(j) for a non-Claus sulfur recovery plant, the relevant information required under paragraph (l)(5) of this section.
(i) For coke calcining units, the owner and operator shall report:
(1) The unit ID number (if applicable).
(2) Maximum rated throughput of the unit, in metric tons coke calcined/stream day.
(3) The calculated CO
(4) A description of the method used to calculate the CO
(5) If you use Equation Y-13 of § 98.253, an indication of whether coke dust is recycled to the unit (e.g., all dust is recycled, a portion of the dust is recycled, or none of the dust is recycled).
(6) If you use a CEMS, the relevant information required under § 98.36 for the Tier 4 Calculation Methodology, the CO
(7) Indicate whether you use a measured value, a unit-specific emission factor or a default emission factor for CH
(8) Indicate whether you use a measured value, a unit-specific emission factor, or a default emission factor for N
(j) For asphalt blowing operations, the owner or operator shall report:
(1) The unit ID number (if applicable).
(2) [Reserved]
(3) The type of control device used to reduce methane (and other organic) emissions from the unit.
(4) The calculated annual CO
(5) If you use Equation Y-14 of § 98.253, the basis for the CO
(6) If you use Equation Y-15 of § 98.253, the basis for the CH
(7) If you use Equation Y-16a of § 98.253, the basis for the carbon emission factor used.
(8) If you use Equation Y-16b of § 98.253, the basis for the CO
(9) If you use Equation Y-17 of § 98.253, the basis for the CH
(10) If you use Equation Y-19 of this subpart, the relevant information required under paragraph (l)(5) of this section.
(k) For delayed coking units, the owner or operator shall report:
(1) The cumulative annual CH
(2) A description of the method used to calculate the CH
(3) The total number of delayed coking units at the facility; the total number of delayed coking drums at the facility; and, for each coke drum or vessel, the typical drum outage (
(4) For each set of coking drums that are the same dimensions, the number of coking drums in the set, and the mole fraction of methane in coking gas (in kg-mole CH
(5) The basis for the volumetric void fraction of the coke vessel prior to steaming and the basis for the mole fraction of methane in the coking gas.
(6) If you use Equation Y-19 of this subpart, the relevant information required under paragraph (l)(5) of this section for each set of coke drums or vessels of the same size.
(l) For each process vent subject to § 98.253(j), the owner or operator shall report:
(1) The vent ID number (if applicable).
(2) The unit or operation associated with the emissions.
(3) The type of control device used to reduce methane (and other organic) emissions from the unit, if applicable.
(4) The calculated annual CO
(5) The annual volumetric flow discharged to the atmosphere (in scf), and an indication of the measurement or estimation method, annual average mole fraction of each GHG above the concentration threshold or otherwise required to be reported and an indication of the measurement or estimation method, and for intermittent vents, the number of venting events and the cumulative venting time.
(m) For uncontrolled blowdown systems, the owner or operator shall report:
(1) An indication of whether the uncontrolled blowdown emission are reported under § 98.253(k) or § 98.253(j) or a statement that the facility does not have any uncontrolled blowdown systems.
(2) The cumulative annual CH
(3) For uncontrolled blowdown systems reporting under § 98.253(k), the basis for the value of the methane emission factor used for uncontrolled blowdown systems.
(4) For uncontrolled blowdown systems reporting under § 98.253(j), the relevant information required under paragraph (l)(5) of this section.
(n) For equipment leaks, the owner or operator shall report:
(1) The cumulative CH
(2) The method used to calculate the reported equipment leak emissions.
(3) The number of each type of emission source listed in Equation Y-21 of this subpart at the facility.
(o) For storage tanks, the owner or operator shall report:
(1) The cumulative annual CH
(2) For storage tanks other than those processing unstabilized crude oil:
(i) The method used to calculate the reported storage tank emissions for storage tanks other than those processing unstabilized crude (
(ii) [Reserved]
(3) The cumulative CH
(4) For storage tanks that process unstabilized crude oil:
(i) The method used to calculate the reported unstabilized crude oil storage tank emissions.
(ii)-(iv) [Reserved]
(v) The basis for the mole fraction of CH
(vi) If you did not use Equation Y-23, the tank-specific methane composition data and the annual gas generation volume (scf/yr) used to estimate the cumulative CH
(5)-(7) [Reserved]
(p) For loading operations, the owner or operator shall report:
(1) The cumulative annual CH
(2) The types of materials loaded that have an equilibrium vapor-phase concentration of methane of 0.5 volume percent or greater, and the type of vessel (barge, tanker, marine vessel, etc.) in which each type of material is loaded.
(3) The type of control system used to reduce emissions from the loading of material with an equilibrium vapor-phase concentration of methane of 0.5 volume percent or greater, if any (submerged loading, vapor balancing, etc.).
(q) Name of each method listed in § 98.254 or a description of manufacturer's recommended method used to determine a measured parameter.
At 81 FR 89263, Dec. 9, 2016, § 98.256 was amended by revising paragraphs (e)(3) and (6), (h)(5)(ii)(A), and (k), effective Jan. 1, 2019. For the convenience of the user, the revised text is set forth as follows:
(e) * * *
(3) A description of the flare service (general facility flare, unit flare, emergency only or back-up flare) and an indication of whether or not the flare is serviced by a flare gas recovery system.
(6) If you use Equation Y-1a in § 98.253, an indication of whether daily or weekly measurement periods are used, annual average carbon content of the flare gas (in kg carbon per kg flare gas), and, either the annual volume of flare gas combusted (in scf/year) and the annual average molecular weight (in kg/kg-mole), or the annual mass of flare gas combusted (in kg/yr).
(h) * * *
(5) * * *
(ii) * * *
(A) The annual volume of recycled tail gas (in scf/year).
(k) For each delayed coking unit, the owner or operator shall report:
(1) The unit ID number (if applicable).
(2) Maximum rated throughput of the unit, in bbl/stream day.
(3) Annual quantity of coke produced in the unit during the reporting year, in metric tons.
(4) The calculated annual CH
(5) The total number of delayed coking vessels (or coke drums) associated with the delayed coking unit.
(6) The basis for the typical dry mass of coke in the delayed coking unit vessel at the end of the coking cycle (mass measurements from company records or calculated using Equation Y-18a of this subpart).
(7) An indication of the method used to estimate the average temperature of the coke bed, T
(8) An indication of whether a unit-specific methane emissions factor or the default methane emission factor was used for the delayed coking unit.
In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) and (b) of this section.
(a) The records of all parameters monitored under § 98.255. If you comply with the combustion methodology in § 98.252(a), then you must retain under this subpart the records required for the Tier 3 and/or Tier 4 Calculation Methodologies in § 98.37 and you must keep records of the annual average flow calculations.
(b)
(1) Volume of flare gas combusted during measurement period (scf) (Equation Y-1b of § 98.253).
(2) Mole percent CO
(3) Mole percent concentration of compound “x” in the flare gas stream during the measurement period (mole percent) (Equation Y-1b).
(4) Carbon mole number of compound “x” in the flare gas stream during the measurement period (mole carbon atoms per mole compound) (Equation Y-1b).
(5) Molar volume conversion factor (scf per kg-mole) (Equation Y-1b).
(6) Annual volume of flare gas combusted for each flare during normal operations from company records (million (MM) standard cubic feet per year, MMscf/year) (Equation Y-3 of § 98.253).
(7) Higher heating value for fuel gas or flare gas for each flare from company records (British thermal units per scf, Btu/scf = MMBtu/MMscf) (Equation Y-3).
(8) Volume of flare gas combusted during indexed start-up, shutdown, or malfunction event from engineering calculations (scf) (Equation Y-3).
(9) Average molecular weight of the flare gas, from the analysis results or engineering calculations for the event (kg/kg-mole) (Equation Y-3).
(10) Molar volume conversion factor (scf per kg-mole) (Equation Y-3).
(11) Average carbon content of the flare gas, from analysis results or engineering calculations for the event (kg C per kg flare gas) (Equation Y-3).
(12) Weight fraction of carbon in the flare gas prior to combustion in each flare that is contributed by methane from measurement values or engineering calculations (kg C in methane in flare gas/kg C in flare gas) (Equation Y-4 of § 98.253).
(13) Annual throughput of unit from company records for each catalytic cracking unit or fluid coking unit (barrels/year) (Equation Y-8 of § 98.253).
(14) Coke burn-off factor from engineering calculations (default for catalytic cracking units = 7.3; default for fluid coking units = 11) (kg coke per barrel of feed) (Equation Y-8).
(15) Carbon content of coke based on measurement or engineering estimate (kg C per kg coke) (Equation Y-8).
(16) Value of unit-specific CH
(17) Annual activity data (e.g., input or product rate), including the units of measure, in units of measure consistent with the emission factor, for each catalytic cracking unit, traditional fluid coking unit, catalytic reforming unit, and coke calcining unit (calculation method in § 98.253(c)(4)).
(18) Value of unit-specific N
(19) Annual activity data (e.g., input or product rate), including the units of measure, in units of measure consistent with the emission factor, for each catalytic cracking unit, traditional fluid coking unit, catalytic reforming unit, and coke calcining unit (calculation method in § 98.253(c)(5)).
(20) Carbon content of coke based on measurement or engineering estimate (default = 0.94) (kg C per kg coke) (Equation Y-11 of § 98.253).
(21) Volumetric flow rate of sour gas (including sour water stripper gas) feed sent off site for sulfur recovery in the year (scf/year) (Equation Y-12 of § 98.253).
(22) Mole fraction of carbon in the sour gas feed sent off site for sulfur recovery (kg-mole C/kg-mole gas) (Equation Y-12).
(23) Molar volume conversion factor for sour gas sent off site (scf per kg-mole) (Equation Y-12).
(24) Volumetric flow rate of sour gas (including sour water stripper gas) fed to the onsite sulfur recovery plant (scf/year) (Equation Y-12).
(25) Mole fraction of carbon in the sour gas fed to the onsite sulfur recovery plant (kg-mole C/kg-mole gas) (Equation Y-12).
(26) Molar volume conversion factor for onsite sulfur recovery plant (scf per kg-mole) (Equation Y-12).
(27) Annual mass of green coke fed to the coke calcining unit from facility records (metric tons/year) (Equation Y-13 of § 98.253).
(28) Annual mass of marketable petroleum coke produced by the coke calcining unit from facility records (metric tons/year) (Equation Y-13).
(29) Annual mass of petroleum coke dust removed from the process through the dust collection system of the coke calcining unit from facility records. For coke calcining units that recycle the collected dust, the mass of coke dust removed from the process is the mass of coke dust collected less the
(30) Average mass fraction carbon content of green coke from facility measurement data (metric tons C per metric ton green coke) (Equation Y-13).
(31) Average mass fraction carbon content of marketable petroleum coke produced by the coke calcining unit from facility measurement data (metric tons C per metric ton petroleum coke (Equation Y-13).
(32) Quantity of asphalt blown for each asphalt blowing unit (million barrels per year (MMbbl/year)) (Equation Y-14 of § 98.253).
(33) Emission factor for CO
(34) Emission factor for CH
(35) Quantity of asphalt blown (million barrels/year (MMbbl/year)) (Equation Y-16a of § 98.253).
(36) Carbon emission factor from asphalt blowing from facility-specific test data (metric tons C/MMbbl asphalt blown) (Equation Y-16a).
(37) Quantity of asphalt blown for each asphalt blowing unit (million barrels per year (MMbbl/year)) (Equation Y-16b of § 98.253).
(38) Emission factor for CO
(39) Carbon emission factor from asphalt blowing from facility-specific test data for each asphalt blowing unit (metric tons C/MMbbl asphalt blown) (Equation Y-16b).
(40) Emission factor for CH
(41) Cumulative number of vessel openings for all delayed coking unit vessels of the same dimensions during the year (Equation Y-18 of § 98.253).
(42) Height of coking unit vessel for each set of coke drums or vessels of the same size (feet) (Equation Y-18).
(43) Gauge pressure of the coking vessel when opened to the atmosphere prior to coke cutting or, if the alternative method provided in § 98.253(i)(2) is used, gauge pressure of the coking vessel when depressurization gases are first routed to the atmosphere for each set of coke drums or vessels of the same size (pounds per square inch gauge (psig)) (Equation Y-18).
(44) Volumetric void fraction of coking vessel prior to steaming for each set of coke drums or vessels of the same size (cf gas/cf of vessel) (Equation Y-18).
(45) Diameter of coking unit vessel for each set of coke drums or vessels of the same size (feet) (Equation Y-18).
(46) Molar volume conversion factor for each set of coke drums or vessels of the same size (scf per kg-mole) (Equation Y-18).
(47) Average volumetric flow rate of process gas during the event from measurement data, process knowledge, or engineering estimates for each set of coke drums or vessels of the same size (scf per hour) (Equation Y-19 of § 98.253).
(48) Mole fraction of methane in process vent during the event from measurement data, process knowledge, or engineering estimates for each set of coke drums or vessels of the same size (kg-mole CH
(49) Venting time for the event for each set of coke drums or vessels of the same size (hours) (Equation Y-19).
(50) Molar volume conversion factor for each set of coke drums or vessels of the same size (scf per kg-mole) (Equation Y-19).
(51) Quantity of crude oil plus the quantity of intermediate products received from off site that are processed at the facility (MMbbl/year) (Equation Y-20 of § 98.253).
(52) Molar volume conversion factor (scf per kg-mole) (Equation Y-20).
(53) Methane emission factor for uncontrolled blown systems (scf CH
(54) Quantity of crude oil plus the quantity of intermediate products received from off site that are processed
(55) Quantity of unstabilized crude oil received at the facility (MMbbl/year) (Equation Y-23 of § 98.253).
(56) Pressure differential from the previous storage pressure to atmospheric pressure (psi) (Equation Y-23).
(57) Average mole fraction of CH
(58) Molar volume conversion factor (scf per kg-mole) (Equation Y-23).
(59) Specify whether the calculated or default loading factor L specified in § 98.253(n) is entered, for each liquid loaded to each (methods specified in § 98.253(n)).
(60) Saturation factor specified in § 98.253(n), for each liquid loaded to each vessel (methods specified in § 98.253(n)).
(61) True vapor pressure of liquid loaded, for each liquid loaded to each vessel (psia) (methods specified in § 98.253(n)).
(62) Molecular weight of vapors (lb per lb-mole), for each liquid loaded to each vessel (methods specified in § 98.253(n)).
(63) Temperature of bulk liquid loaded, for each liquid loaded to each vessel (°R, degrees Rankine) (methods specified in § 98.253(n)).
(64) Total loading loss (without efficiency correction), for each liquid loaded to each vessel (pounds per 1000 gallons loaded) (methods specified in § 98.253(n)).
(65) Overall emission control system reduction efficiency, including the vapor collection system efficiency and the vapor recovery or destruction efficiency (enter zero if no emission controls), for each liquid loaded to each vessel (percent) (methods specified § 98.253(n)).
(66) Vapor phase concentration of methane in liquid loaded, for each liquid loaded to each vessel (percent by volume) (methods specified in § 98.253(n)).
(67) Quantity of material loaded, for each liquid loaded to each vessel (thousand gallon per year) (methods specified in § 98.253(n)).
At 81 FR 89263, Dec. 9, 2016, § 98.257 was amended by
a. Revising paragraphs (b) introductory text and (b)(41) through (45);
b. Removing paragraph (b)(46);
c. Redesignating paragraphs (b)(47) through (67) as paragraphs (b)(53) through (73);
d. Adding new paragraph (b)(46) and paragraphs (b)(47) through (52); and
e. Revising newly redesignated paragraph (b)(65), effective Jan. 1, 2019. For the convenience of the user, the added and revised text is set forth as follows:
(b)
(41) Typical dry mass of coke in the delayed coking unit vessel at the end of the coking cycle (metric tons/cycle) from company records or calculated using Equation Y-18a of this subpart (Equations Y-18a, Y-18b and Y-18e in § 98.253) for each delayed coking unit.
(42) Internal height of delayed coking unit vessel (feet) (Equation Y-18a in § 98.253) for each delayed coking unit.
(43) Typical distance from the top of the delayed coking unit vessel to the top of the coke bed (
(44) Diameter of delayed coking unit vessel (feet) (Equations Y-18a and Y-18b in § 98.253) for each delayed coking unit.
(45) Mass of water in the delayed coking unit vessel at the end of the cooling cycle prior to atmospheric venting (metric ton/cycle) (Equations Y-18b and Y-18e in § 98.253) for each delayed coking unit.
(46) Typical distance from the bottom of the coking unit vessel to the top of the water level at the end of the cooling cycle just prior to atmospheric venting (feet) from company records or engineering estimates (Equation Y-18b in § 98.253) for each delayed coking unit.
(47) Mass of steam generated and released per decoking cycle (metric tons/cycle) (Equations Y-18e and Y-18f in § 98.253) for each delayed coking unit.
(48) Average temperature of the delayed coking unit vessel when the drum is first vented to the atmosphere ( °F) (Equations Y-18c, Y-18d, and Y-18e in § 98.253) for each delayed coking unit.
(49) Temperature of the delayed coking unit vessel overhead line measured as near the coking unit vessel as practical just prior to venting the atmosphere (Equation Y-18c in § 98.253) for each delayed coking unit.
(50) Pressure of the delayed coking unit vessel just prior to opening the atmospheric vent (psig) (Equation Y-18d in § 98.253) for each delayed coking unit.
(51) Methane emission factor for delayed coking unit (kilograms CH
(52) Cumulative number of decoking cycles (or coke-cutting cycles) for all delayed coking unit vessels associated with the delayed coking unit during the year (Equation Y-18f in § 98.253) for each delayed coking unit.
(65) Specify whether the calculated or default loading factor L specified in § 98.253(n) is entered, for each liquid loaded to each vessel (methods specified in § 98.253(n)).
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
The phosphoric acid production source category consists of facilities with a wet-process phosphoric acid process line used to produce phosphoric acid. A wet-process 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.
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).
(a) You must report CO
(b) You must report under subpart C of this part (General Stationary Fuel Combustion Sources) the emissions of CO
You must calculate and report the annual process CO
(a) Calculate and report under this subpart the process CO
(b) Calculate and report under this subpart the process CO
(1) Calculate the annual CO
(i) If your process measurement provides the inorganic carbon content of phosphate rock as an output, calculate and report the process CO
(ii) If your process measurement provides the CO
(2) You must determine the total emissions from the facility using Equation Z-2 of this section:
(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
(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 using one of the following methods. You may conduct the representative bulk sampling using a method published by a consensus standards organization, or you may use industry consensus standard practice methods, including but not limited to the Phosphate Mining States Methods Used and Adopted by the Association of Fertilizer and Phosphate Chemists (AFPC). If phosphate rock is obtained from more than one origin in a month, you must obtain a
(b) You must determine the carbon dioxide or inorganic carbon content of each monthly grab sample of phosphate rock (consumed in the production of phosphoric acid). You may use a method published by a consensus standards organization, or you may use industry consensus standard practice methods, including but not limited to the Phosphate Mining States Methods Used and Adopted by AFPC.
(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 equipment that is used to measure total mass flow of phosphorous-bearing feed under 40 CFR part 60 or part 63.
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 must be used in the calculations as specified in paragraphs (a) and (b) of this section.
(a) For each missing value of the inorganic carbon content or CO
(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.
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 of the phosphate rock (tons).
(b) Annual phosphoric acid production capacity (tons).
(c) Annual arithmetic average percent inorganic carbon or carbon dioxide 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 (tons).
(e) If you use a CEMS to measure CO
(1) The identification number of each wet-process phosphoric acid process line.
(2) The annual CO
(f) If you do not use a CEMS to measure emissions, then you must report the information in paragraphs (f)(1) through (9) of this section.
(1) Identification number of each wet-process phosphoric acid process line.
(2) Annual CO
(3) Annual phosphoric acid production capacity (tons) for each wet-process phosphoric acid process line.
(4) Method used to estimate any missing values of inorganic carbon content or carbon dioxide content of phosphate rock for each wet-process phosphoric acid process line.
(5) [Reserved]
(6) [Reserved]
(7) Number of wet-process phosphoric acid process lines.
(8) Number of times missing data procedures were used to estimate phosphate rock consumption (months), inorganic carbon contents of the phosphate rock (months), and CO
(9) Annual process CO
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 wet-process phosphoric acid production facility.
(a) Monthly mass of phosphate rock consumed by origin (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.
(d)
(1) Inorganic carbon content of a grab sample batch of phosphate rock by origin obtained during month by wet-process phosphoric acid process line, from the carbon analysis results (percent by weight, expressed as a decimal fraction) (Equation Z-1a of § 98.263).
(2) Mass of phosphate rock by origin consumed in month by wet-process phosphoric acid process line (tons) (Equation Z-1a).
(3) Carbon dioxide content of a grab sample batch of phosphate rock by origin obtained during month by wet-process phosphoric acid process line (percent by weight, expressed as a decimal fraction) (Equation Z-1b of § 98.263).
(4) Mass of phosphate rock by origin consumed in month by wet-process phosphoric acid process line (tons) (Equation Z-1b).
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
(a) The pulp and paper manufacturing source category consists of facilities that produce market pulp (i.e., stand-alone pulp facilities), manufacture pulp and paper (i.e., integrated facilities), produce paper products from purchased pulp, produce secondary fiber from recycled paper, convert paper into paperboard products (e.g., containers), or operate coating and laminating processes.
(b) The emission units for which GHG emissions must be reported are listed in paragraphs (b)(1) through (b)(5) of this section:
(1) Chemical recovery furnaces at kraft and soda mills (including recovery furnaces that burn spent pulping liquor produced by both the kraft and semichemical process).
(2) Chemical recovery combustion units at sulfite facilities.
(3) Chemical recovery combustion units at stand-alone semichemical facilities.
(4) Pulp mill lime kilns at kraft and soda facilities.
(5) Systems for adding makeup chemicals (CaCO
You must report GHG emissions under this subpart if your facility contains a pulp and paper manufacturing process and the facility meets the requirements of either § 98.2(a)(1) or (a)(2).
You must report the emissions listed in paragraphs (a) through (f) of this section:
(a) CO
(b) CO
(c) CO
(d) CO
(e) CO
(f) CO
(a) For each chemical recovery furnace located at a kraft or soda facility, you must determine CO
(1) Calculate fossil fuel-based CO
(2) Calculate fossil fuel-based CH
(3) Calculate biogenic CO
(b) For each chemical recovery combustion unit located at a sulfite or
(1) Calculate fossil CO
(2) Calculate CH
(3) Calculate biogenic CO
(4) Calculate CH
(c) For each pulp mill lime kiln located at a kraft or soda facility, you must determine CO
(1) Calculate CO
(2) Calculate CH
(3) Biogenic CO
(d) For makeup chemical use, you must calculate CO
(a) Each facility subject to this subpart must quality assure the GHG emissions data according to the applicable requirements in § 98.34. All QA/QC data must be available for inspection upon request.
(b) Fuel properties needed to perform the calculations in Equations AA-1 and AA-2 of this subpart must be determined according to paragraphs (b)(1) through (b)(3) of this section.
(1) High heat values of black liquor must be determined no less than annually using T684 om-06 Gross Heating Value of Black Liquor, TAPPI (incorporated by reference,
(2) The annual mass of spent liquor solids must be determined using either of the methods specified in paragraph (b)(2)(i) or (b)(2)(ii) of this section.
(i) Measure the mass of spent liquor solids annually (or more frequently) using T-650 om-05 Solids Content of Black Liquor, TAPPI (incorporated by reference in § 98.7). If measurements are performed more frequently than annually, then the mass of spent liquor solids used in Equation AA-1 of this subpart must be based on the average of the representative measurements made during the year.
(ii) Determine the annual mass of spent liquor solids based on records of measurements made with an online measurement system that determines the mass of spent liquor solids fired in a chemical recovery furnace or chemical recovery combustion unit.
(3) Carbon analyses for spent pulping liquor must be determined no less than annually using ASTM D5373-08 Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference,
(c) Each facility must keep records that include a detailed explanation of how company records of measurements are used to estimate GHG emissions. The owner or operator must also document the procedures used to ensure the accuracy of the measurements of fuel, spent liquor solids, and makeup chemical usage, including, but not limited to calibration of weighing equipment, fuel flow meters, and other measurement devices. The estimated accuracy of measurements made with these devices must be recorded and the technical basis for these estimates must be provided. The procedures used to convert spent pulping liquor flow rates to units of mass (i.e., spent liquor solids firing rates) also must be documented.
(d) Records must be made available upon request for verification of the calculations and measurements.
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.,
(a) There are no missing data procedures for measurements of heat content and carbon content of spent pulping liquor. A re-test must be performed if the data from any annual measurements are determined to be invalid.
(b) For missing measurements of the mass of spent liquor solids or spent pulping liquor flow rates, use the lesser value of either the maximum mass or fuel flow rate for the combustion unit, or the maximum mass or flow rate that the fuel meter can measure. Alternatively, records of the daily spent liquor solids firing rate obtained to comply with § 63.866(c)(1) of this chapter may be used, adjusting for the duration of the missing measurements, as appropriate.
(c) For the use of makeup chemicals (carbonates), the substitute data value shall be the best available estimate of makeup chemical consumption, based on available data (e.g., past accounting records, production rates). The owner or operator shall document and keep records of the procedures used for all such estimates.
In addition to the information required by § 98.3(c) and the applicable information required by § 98.36, each annual report must contain the information in paragraphs (a) through (l) of this section as applicable:
(a) Annual emissions of CO
(b) [Reserved]
(c) Basis for determining the annual mass of the spent liquor solids combusted (whether based on T650 om-05 Solids Content of Black Liquor, TAPPI (incorporated by reference,
(d) [Reserved]
(e) The default emission factor for CO
(f)-(i) [Reserved]
(j) Annual steam purchases (pounds of steam per year).
(k) Total annual production of unbleached virgin chemical pulp produced onsite during the reporting year in air-dried metric tons per year. This total annual production value is the sum of all kraft, semichemical, soda, and sulfite pulp produced onsite, prior to bleaching, through all virgin pulping lines. Do not include mechanical pulp or secondary fiber repulped for paper production in the virgin pulp production total.
(l) For each pulp mill lime kiln, report the information specified in paragraphs (l)(1) and (2) of this section.
(1) The quantity of calcium oxide (CaO) produced (metric tons).
(2) The percent of annual heat input, individually for each fossil fuel type.
In addition to the information required by § 98.3(g), you must retain the records in paragraphs (a) through (g) of this section.
(a) GHG emission estimates (including separate estimates of biogenic CO
(b) Annual analyses of spent pulping liquor HHV for each chemical recovery furnace at kraft and soda facilities.
(c) Annual analyses of spent pulping liquor carbon content for each chemical recovery combustion unit at a sulfite or semichemical pulp facility.
(d) Annual quantity of spent liquor solids combusted in each chemical recovery furnace and chemical recovery combustion unit, and the basis for detemining the annual quantity of the spent liquor solids combusted (whether based on T650 om-05 Solids Content of Black Liquor, TAPPI (incorporated by reference,
(e) Annual steam purchases.
(f) Annual quantities of makeup chemicals used.
(g)
(1) Mass of the solid fuel combusted (tons/year) (Equation C-1 of § 98.33).
(2) Volume of the liquid fuel combusted (gallons/year) (Equation C-1).
(3) Volume of the gaseous fuel combusted (scf/year) (Equation C-1).
(4) Annual natural gas usage (therms/year) (Equation C-1a of § 98.33).
(5) Annual natural gas usage (mmBtu/year) (Equation C-1b of § 98.33).
(6) Mass of the solid fuel combusted (tons/year) (Equation C-2a of § 98.33).
(7) Volume of the liquid fuel combusted (gallons/year) (Equation C-2a).
(8) Volume of the gaseous fuel combusted (scf/year) (Equation C-2a).
(9) Annual mass of the solid fuel combusted (short tons/year) (Equation C-3 of § 98.33).
(10) Annual average carbon content of the solid fuel (percent by weight, expressed as a decimal fraction) (Equation C-3).
(11) Annual volume of the liquid fuel combusted (gallons/year) (Equation C-4 of § 98.33).
(12) Annual average carbon content of the liquid fuel (kg C per gallon of fuel) (Equation C-4).
(13) Annual volume of the gaseous fuel combusted (scf/year) (Equation C-5 of § 98.33).
(14) Annual average carbon content of the gaseous fuel (kg C per kg of fuel) (Equation C-5).
(15) Annual average molecular weight of the gaseous fuel (kg/kg-mole) (Equation C-5).
(16) Molar volume conversion factor at standard conditions, as defined in § 98.6 (scf per kg-mole) (Equation C-5).
(17) Identify if you will use the default high heat value from Table C-1 of subpart C of this part, or actual HHV data (Equation C-8 of § 98.33).
(18) High heat value of the fuel (mmBTU/tons) (Equation C-8).
(19) High heat value of the fuel (mmBTU/gallons) (Equation C-8).
(20) High heat value of the fuel (mmBTU/scf) (Equation C-8).
(21) Mass of spent liquor solids combusted from each chemical recovery furnace located at a kraft or soda facility, in short tons in year, determined according to § 98.274(b) (tons/year) (Equation AA-1 of § 98.273).
(22) Annual high heat value of the spent liquor solids from each chemical recovery furnace located at a kraft or soda facility determined according to § 98.274(b) (mmBtu per kilogram) (Equation AA-1).
(23) Annual high heat value of the spent liquor solids from each chemical recovery combustion unit located at a sulfite or stand-alone semichemical facility, determined according to § 98.274(b) (mmBtu per kilogram) (Equation AA-1).
(24) Mass of the spent liquor solids combusted in short tons per year determined according to § 98.274(b) (tons/year) (Equation AA-2 of § 98.273).
(25) Annual carbon content of the spent liquor solids, determined according to § 98.274(b) (percent by weight, expressed as a decimal fraction (e.g., 95% = 0.95)) (Equation AA-2).
(26) Make-up quantity of CaCO
(27) Make-up quantity of Na
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
Silicon carbide production includes any process that produces silicon carbide for abrasive purposes.
You must report GHG emissions under this subpart if your facility contains a silicon carbide production process and the facility meets the requirements of either § 98.2(a)(1) or (a)(2).
You must report:
(a) CO
(b) CO
You must calculate and report the combined annual process CO
(a) Calculate and report under this subpart the combined annual process CO
(b) Calculate and report under this subpart the combined annual process CO
(1) Use Equation BB-1 of this section to calculate the facility-specific emissions factor for determining CO
(2) Calculate annual CO
(c) If GHG emissions from a silicon carbide production furnace or process unit are vented through the same stack as any combustion unit or process equipment that reports CO
(a) You must measure your consumption of 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 petroleum coke consumption measurements.
(c) For CO
(d) For quality assurance and quality control of the supplier data, you must conduct an annual measurement of the carbon content of the petroleum coke using ASTM D3176-89 and ASTM D5373-08 Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference,
For the petroleum coke input procedure in § 98.283(b), a complete record of all measured parameters used in the GHG emissions calculations is required (e.g., 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) 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 monthly carbon content of petroleum coke, the substitute data value shall be the arithmetic average of the quality-assured values of carbon contents immediately preceding and 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 quality-assured value for carbon contents obtained after the missing data period.
(b) For each missing value of the monthly petroleum coke consumption, the substitute data value shall be the best available estimate of the petroleum coke consumption based on all available process data or information used for accounting purposes (such as purchase records).
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 silicon carbide production facility.
(a) If a CEMS is used to measure process CO
(1) Annual consumption of petroleum coke (tons).
(2) Annual production of silicon carbide (tons).
(3) Annual production capacity of silicon carbide (tons).
(b) If a CEMS is not used to measure process CO
(1) [Reserved]
(2)
(3) Annual production capacity of silicon carbide (tons).
(4) [Reserved]
(5) Whether carbon content of the petroleum coke is based on reports from the supplier or through self measurement using applicable ASTM standard method.
(6) [Reserved]
(7) Sampling analysis results for carbon content of consumed petroleum coke as determined for QA/QC of supplier data under § 98.284(d) (percent by weight expressed as a decimal fraction).
(8) Number of times in the reporting year that missing data procedures were followed to measure the carbon contents of petroleum coke (number of months) and petroleum coke consumption (number of months).
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 silicon carbide production facility.
(a) If a CEMS is used to measure CO
(1) Records of all petroleum coke purchases.
(2) Annual operating hours.
(b) If a CEMS is not used to measure emissions, you must retain records for the information listed in this paragraph (b):
(1) Records of all analyses and calculations conducted for reported data listed in § 98.286(b).
(2) Records of all petroleum coke purchases.
(3) Annual operating hours.
(c)
(1) Carbon content factor for petroleum coke consumed in month from the supplier or as measured by the applicable method (percent by weight expressed as a decimal fraction) (Equation BB-1 of § 98.283).
(2) Petroleum coke consumption in month (tons) (Equation BB-2 of § 98.283).
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
(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)(1) through (3) of this section:
(1) Calcining trona.
(2) Calcining sodium sesquicarbonate.
(3) Using a liquid alkaline feedstock process that directly produces CO
(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.
You must report GHG emissions under this subpart if your facility contains a soda ash manufacturing process and the facility meets the requirements of either § 98.2(a)(1) or (a)(2).
You must report:
(a) CO
(b) CO
(c) CH
(d) CO
You must calculate and report the annual process CO
(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
(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
(1) Calculate and report under this subpart the combined process and combustion CO
(2) Use either Equation CC-1 or Equation CC-2 of this section to calculate annual CO
(3)
(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
(iii) Using the test data, you must calculate a CO
(iv) You must calculate annual CO
(4) Calculate and report under subpart C of this part (General Stationary Fuel Combustion Sources) the combustion CO
Section 98.293 provides three different procedures for emission calculations. The appropriate paragraphs (a) through (c) of this section 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 to each soda ash manufacturing line on a monthly basis using belt scales or methods used for accounting purposes.
(3) Document the procedures used to ensure the accuracy of the monthly measurements of trona consumed.
(b) If you calculate CO
(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
(1) Conduct an annual performance test that is based on representative
(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
(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 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).
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 be the best available estimate(s) of 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
(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.
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
(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
(1) Identification number of each manufacturing line.
(2) Annual process CO
(3) Annual production of soda ash for each manufacturing line (tons).
(4) Annual production capacity of soda ash for each manufacturing line (tons).
(5)-(7) [Reserved]
(8) Whether CO
(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
(iii) CO
(iv) CO
(v) Average process vent flow from mine water stripper/evaporator during performance test (pounds/hour).
(vi) Annual process vent flow rate from mine water stripper/evaporator (thousand pounds/hour).
(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).
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 soda ash manufacturing line.
(a) If a CEMS is used to measure CO
(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 production 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.
(5) If you produce soda ash using the liquid alkaline feedstock process and use the site-specific emission factor
(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.
(c)
(1) Inorganic carbon content in trona input, from the carbon analysis results for month (percent by weight, expressed as a decimal fraction) (Equation CC-1 of § 98.293).
(2) Mass of trona input in month (tons) (Equation CC-1).
(3) Inorganic carbon content in soda ash output, from the carbon analysis results for month (percent by weight, expressed as a decimal fraction) (Equation CC-2 of § 98.293).
(4) Mass of soda ash output in month (tons) (Equation CC-2).
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
75 FR 74855, Dec. 1, 2010, unless otherwise noted.
(a) The electrical transmission and distribution equipment use source category consists of all electric transmission and distribution equipment and servicing inventory insulated with or containing sulfur hexafluoride (SF
(1) Gas-insulated substations.
(2) Circuit breakers.
(3) Switchgear, including closed-pressure and hermetically sealed-pressure switchgear and gas-insulated lines containing SF
(4) Gas containers such as pressurized cylinders.
(5) Gas carts.
(6) Electric power transformers.
(7) Other containers of SF
(a) You must report GHG emissions from an electric power system if the total nameplate capacity of SF
(b) A facility other than an electric power system that is subject to this part because of emissions from any other source category listed in Table A-3 or A-4 in subpart A of this part is not required to report emissions under subpart DD of this part unless the total nameplate capacity of SF
You must report total SF
(a) Calculate the annual SF
(b) Use Equation DD-1 of this section to estimate emissions of PFCs from power transformers, substituting the relevant PFC(s) for SF
(a) For calendar year 2011 monitoring, you may follow the provisions of § 98.3(d)(1) through (d)(2) for best available monitoring methods rather than follow the monitoring requirements of this section. For purposes of this subpart, any reference in § 98.3(d)(1) through (d)(2) to 2010 means 2011, to March 31 means June 30, and to April 1 means July 1. Any reference to the effective date in § 98.3(d)(1) through (d)(2) means February 28, 2011.
(b) You must adhere to the following QA/QC methods for reviewing the completeness and accuracy of reporting:
(1) Review inputs to Equation DD-1 of this section to ensure inputs and outputs to the company's system are included.
(2) Do not enter negative inputs and confirm that negative emissions are not calculated. However, the Decrease in SF
(3) Ensure that beginning-of-year inventory matches end-of-year inventory from the previous year.
(4) Ensure that in addition to SF
(c) Ensure the following QA/QC methods are employed throughout the year:
(1) Ensure that cylinders returned to the gas supplier are consistently weighed on a scale that is certified to be accurate and precise to within 2 pounds of true weight and is periodically recalibrated per the manufacturer's specifications. Either measure residual gas (the amount of gas remaining in returned cylinders) or have the gas supplier measure it. If the gas supplier weighs the residual gas, obtain from the gas supplier a detailed monthly accounting, within ±2 pounds, of residual gas amounts in the cylinders returned to the gas supplier.
(2) Ensure that cylinders weighed for the beginning and end of year inventory measurements are weighed on a scale that is certified to be accurate and precise to within 2 pounds of true weight and is periodically recalibrated per the manufacturer's specifications. All scales used to measure quantities that are to be reported under § 98.306 must be calibrated using calibration procedures specified by the scale manufacturer. Calibration must be performed prior to the first reporting year. After the initial calibration, recalibration must be performed at the minimum frequency specified by the manufacturer.
(3) Ensure all substations have provided information to the manager compiling the emissions report (if it is not already handled through an electronic inventory system).
(d) GHG Monitoring Plans, as described in § 98.3(g)(5), must be completed by April 1, 2011.
A complete record of all measured parameters used in the GHG emissions calculations is required. Replace missing data, if needed, based on data from equipment with a similar nameplate capacity for SF
In addition to the information required by § 98.3(c), each annual report must contain the following information for each electric power system, by chemical:
(a) Nameplate capacity of equipment (pounds) containing SF
(1) Existing at the beginning of the year (excluding hermetically sealed-pressure switchgear).
(2) New hermetically sealed-pressure switchgear during the year.
(3) New equipment other than hermetically sealed-pressure switchgear during the year.
(4) Retired hermetically sealed-pressure switchgear during the year.
(5) Retired equipment other than hermetically sealed-pressure switchgear during the year.
(b) Transmission miles (length of lines carrying voltages above 35 kilovolts).
(c) Distribution miles (length of lines carrying voltages at or below 35 kilovolts).
(d) Pounds of SF
(e) Pounds of SF6 and PFC stored in containers, but not in energized equipment, at the end of the year.
(f) Pounds of SF
(g) Pounds of SF
(h) Pounds of SF
(i) Pounds of SF
(j) Pounds of SF
(k) Pounds of SF
(l) Pounds of SF
(m) State(s) or territory in which the facility lies.
(n) The number of SF
(1) New hermetically sealed-pressure switchgear during the year.
(2) New equipment other than hermetically sealed-pressure switchgear during the year.
(3) Retired hermetically sealed-pressure switchgear during the year.
(4) Retired equipment other than hermetically sealed-pressure switchgear during the year.
In addition to the information required by § 98.3(g), you must retain records of the information reported and listed in § 98.306.
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.
The titanium dioxide production source category consists of facilities that use the chloride process to produce titanium dioxide.
You must report GHG emissions under this subpart if your facility contains a titanium dioxide production process and the facility meets the requirements of either § 98.2(a)(1) or (a)(2).
(a) You must report CO
(b) You must report CO
You must calculate and report the annual process CO
(a) Calculate and report under this subpart the process CO
(b) Calculate and report under this subpart the annual process CO
(1) You must calculate the annual CO
(2) You must calculate the annual CO
(3) If facility generates carbon-containing waste, you must calculate the total annual quantity of carbon-containing waste produced from all process lines using Equation EE-3 of this section and its carbon contents according to § 98.314(e) and (f):
(c) If GHG emissions from a chloride process line are vented through the same stack as any combustion unit or process equipment that reports CO
(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 Ultimate Analysis of Coal and Coke (incorporated by reference,
(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 carbon-containing 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.
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 data value shall be the arithmetic average of the quality-assured 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 quality-assured 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 on 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).
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
(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.
(b) If a CEMS is not used to measure CO
(1) Identification number of each process line.
(2) Annual CO
(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) [Reserved]
(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) [Reserved]
(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.
(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).
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 titanium dioxide production facility.
(a) If a CEMS is used to measure CO
(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
(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 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.
(7) Annual operating hours for each titanium dioxide process line (hours).
(c)
(1) Carbon content factor for petroleum coke consumed in month 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) (Equation EE-2 of § 98.313).
(2) Calcined petroleum coke consumption for process line in month (tons) (Equation EE-2).
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
75 FR 39763, July 12, 2010, unless otherwise noted.
(a) This source category consists of active underground coal mines, and any underground mines under development that have operational pre-mining degasification systems. An underground coal mine is a mine at which coal is produced by tunneling into the earth to the coalbed, which is then mined with underground mining equipment such as cutting machines and continuous, longwall, and shortwall mining machines, and transported to the surface. Underground coal mines are categorized as active if any one of the following five conditions apply:
(1) Mine development is underway.
(2) Coal has been produced within the last 90 days.
(3) Mine personnel are present in the mine workings.
(4) Mine ventilation fans are operative.
(5) The mine is designated as an ”intermittent” mine by the Mine Safety and Health Administration (MSHA).
(b) This source category includes the following:
(1) Each ventilation system shaft or vent hole, including both those points where mine ventilation air is emitted and those where it is sold, used onsite, or otherwise destroyed (including by ventilation air methane (VAM) oxidizers).
(2) Each degasification system well or gob gas vent hole, including degasification systems deployed before, during, or after mining operations are conducted in a mine area. This includes both those wells and vent holes where coal bed gas is emitted, and those where the gas is sold, used onsite, or otherwise destroyed (including by flaring).
(c) This source category does not include abandoned or closed mines, surface coal mines, or post-coal mining activities (
You must report GHG emissions under this subpart if your facility contains an active underground coal mine and the facility meets the requirements of § 98.2(a)(1).
(a) You must report CH
(b) You must report CH
(c) You must report net CH
(d) You must report under this subpart the CO
(e) You must report under subpart C of this part (General Stationary Fuel Combustion Sources) the CO
(f) An underground coal mine that is subject to this part because emissions from source categories described in Tables A-3, A-4 or A-5 of subpart A of this part, or from stationary combustion (subpart C of this part), is not required to report emissions under this subpart unless the coal mine liberates 36,500,000 actual cubic feet (acf) or more of methane per year from its ventilation system.
(a) For each ventilation shaft, vent hole, or centralized point into which CH
(1) The quarterly periods are:
(i) January 1-March 31.
(ii) April 1-June 30.
(iii) July 1-September 30.
(iv) October 1-December 31.
(2) Values of V, C, T, P, and, if applicable, (f
(3) If a facility has more than one monitoring point, the facility must calculate total CH
(b) For each monitoring point in the degasification system (this could be at each degasification well and/or vent hole, or at more centralized points into which CH
(1) Values for V, C, T, P, and, if applicable, (f
(2) Quarterly total CH
(c) If gas from a degasification system or ventilation system is sold, used onsite, or otherwise destroyed (including by flaring or VAM oxidation), you must calculate the quarterly CH
(1) Calculate total CH
(2) [Reserved]
(d) You must calculate the quarterly measured net CH
(e) For the methane collected from degasification and/or ventilation systems that is destroyed on site and is not a fuel input for energy generation or use (those emissions are monitored and reported under Subpart C of this part), you must estimate the CO
(a) For calendar year 2011 monitoring, the facility may submit a request to the Administrator to use one or more best available monitoring methods as listed in § 98.3(d)(1)(i) through (iv). The request must be submitted no later than October 12, 2010 and must contain the information in § 98.3(d)(2)(ii). To obtain approval, the
(b) For CH
(1) Collect quarterly or more frequent grab samples (with no fewer than 6 weeks between measurements) for methane concentration and make quarterly measurements of flow rate, temperature, pressure, and, if applicable, moisture content. The sampling and measurements must be made at the same locations as Mine Safety and Health Administration (MSHA) inspection samples are taken, and should be taken when the mine is operating under normal conditions. You must follow MSHA sampling procedures as set forth in the MSHA Handbook entitled, Coal Mine Safety and Health General Inspection Procedures Handbook, Handbook Number: PH16-V-1 (incorporated by reference, see § 98.7). You must record the date of sampling, flow, temperature, pressure, and moisture measurements, the methane concentration (percent), the bottle number of samples collected, and the location of the measurement or collection.
(2) Obtain results of the quarterly (or more frequent) testing performed by MSHA for the methane flowrate. At the same location and within seven days of the MSHA sampling, make measurements of temperature and pressure using the same procedures specified in paragraph (b)(1) of this section. The annual average barometric pressure from the nearest National Oceanic and Atmospheric Administration (NOAA) weather service station may be used as a default for pressure. If the MSHA data for methane flow is provided in the units of actual cubic feet of methane per day, the methane flow data is inserted into Equation FF-1 of this section in place of the value for V and the variables MCF, C/100%, and 1440 are removed from the equation.
(3) Monitor emissions through the use of one or more continuous emission monitoring systems (CEMS). If operators use CEMS as the basis for emissions reporting, they must provide documentation on the process for using data obtained from their CEMS to estimate emissions from their mine ventilation systems.
(c) For CH
(1) Monitor emissions through the use of one or more continuous emissions monitoring systems (CEMS). If operators use CEMS as the basis for emissions reporting, they must provide documentation on the process for using data obtained from their CEMS to estimate emissions from their mine ventilation systems.
(2) Collect weekly (once each calendar week, with at least three days between measurements) or more frequent samples, for all degasification wells and gob gas vent holes. Determine weekly or more frequent flow rates, methane concentration, temperature, and pressure from these degasification wells and gob gas vent holes. Methane composition should be determined either by submitting samples to a lab for analysis, or from the use of methanometers at the degasification monitoring site. Follow the sampling protocols for sampling of methane emissions from ventilation shafts, as described in § 98.324(b)(1). You must record the date of sampling, flow, temperature, pressure, and moisture
(3) If the CH
(i) The gas flow meter at least once each calendar week; if measuring with CEMS. If only one measurement is made each calendar week, there must be at least three days between measurements; and
(ii) The grab sample, if using grab samples, at the time of the sample.
(d) Monitoring must adhere to one of the methods specified in paragraphs (d)(1) through (d)(2) of this section.
(1) ASTM D1945-03, Standard Test Method for Analysis of Natural Gas by Gas Chromatography; ASTM D1946-90 (Reapproved 2006), Standard Practice for Analysis of Reformed Gas by Gas Chromatography; ASTM D4891-89 (Reapproved 2006), Standard Test Method for Heating Value of Gases in Natural Gas Range by Stoichiometric Combustion; or ASTM UOP539-97 Refinery Gas Analysis by Gas Chromatography (incorporated by reference, see § 98.7).
(2) As an alternative to the gas chromatography methods provided in paragraph (d)(1) of this section, you may use gaseous organic concentration analyzers and a correction factor to calculate the CH
(i) Use Method 25A or 25B at 40 CFR part 60, appendix A-7 to determine gaseous organic concentration as required in § 98.323 and in paragraphs (b) and (c) of this section. You must calibrate the instrument with CH
(ii) Determine a correction factor that will be used with the gaseous organic concentrations measured in paragraph (i) of this section. The correction factor must be determined at the routine sampling location no less frequently than once a reporting year following the requirements in paragraphs (d)(2)(ii)(A) through (d)(2)(ii)(C) of this section.
(A) Take a minimum of three grab samples of the gas with a minimum of 20 minutes between samples and determine the methane composition of the gas using one of the methods specified in paragraph (d)(1) of this section.
(B) As soon as practical after each grab sample is collected and prior to the collection of a subsequent grab sample, determine the gaseous organic concentration of the gas using either Method 25A or 25B at 40 CFR part 60, appendix A-7 as specified in paragraph (d)(2)(i) of this section.
(C) Determine the arithmetic average methane concentration and the arithmetic average gaseous organic concentration of the samples analyzed according to paragraphs (d)(2)(ii)(A) and (d)(2)(ii)(B) of this section, respectively, and calculate the non-methane organic carbon correction factor as the ratio of the average methane concentration to the average total gaseous organic concentration. If the ratio exceeds 1, use 1 for the correction factor.
(iii) Calculate the CH
(e) All flow meters and gas composition monitors that are used to provide data for the GHG emissions calculations shall be calibrated prior to the first reporting year, using the applicable methods specified in paragraphs (d), and (e)(1) through (e)(7) of this section. Alternatively, calibration procedures specified by the flow meter manufacturer may be used. Flow meters and gas composition monitors shall be recalibrated either at the minimum frequency specified by the manufacturer or annually. The operator shall operate, maintain, and calibrate a gas composition monitor capable of measuring the concentration of CH
(1) ASME MFC-3M-2004, Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and Venturi (incorporated by reference,
(2) ASME MFC-4M-1986 (Reaffirmed 1997), Measurement of Gas Flow by Turbine Meters (incorporated by reference,
(3) ASME MFC-6M-1998, Measurement of Fluid Flow in Pipes Using Vortex Flowmeters (incorporated by reference,
(4) ASME MFC-7M-1987 (Reaffirmed 1992), Measurement of Gas Flow by Means of Critical Flow Venturi Nozzles (incorporated by reference,
(5) ASME MFC-11M-2006 Measurement of Fluid Flow by Means of Coriolis Mass Flowmeters (incorporated by reference,
(6) ASME MFC-14M-2003 Measurement of Fluid Flow Using Small Bore Precision Orifice Meters (incorporated by reference,
(7) ASME MFC-18M-2001 Measurement of Fluid Flow using Variable Area Meters (incorporated by reference,
(f) For CH
(g) All temperature, pressure, and moisture content monitors must be operated and calibrated using the procedures and frequencies specified by the manufacturer.
(h) The owner or operator shall document the procedures used to ensure the accuracy of gas flow rate, gas composition, temperature, pressure, and moisture content measurements. These procedures include, but are not limited to, calibration of flow meters, and other measurement devices. The estimated accuracy of measurements and the technical basis for the estimated accuracy shall be recorded.
(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 (
(b) For each missing value of CH
In addition to the information required by § 98.3(c), each annual report must contain the following information for each mine:
(a) Quarterly CH
(b) Weekly CH
(c) Quarterly CH
(d) Quarterly CH
(e) Quarterly CO
(f) Quarterly volumetric flow rate for each ventilation monitoring point and units of measure (scfm or acfm), date and location of each measurement, and method of measurement (quarterly sampling or continuous monitoring), used in Equation FF-1 of this subpart. Specify whether the volumetric flow rate measurement at each ventilation monitoring point is on dry basis or wet basis; and, if a flow meter is used, indicate whether or not the flow meter automatically corrects for moisture content.
(g) Quarterly CH
(h) Weekly volumetric flow rate used to calculate CH
(i) Quarterly CH
(j) Weekly volumetric flow rate used to calculate CH
(k) Weekly CH
(l) Dates in quarterly reporting period where active ventilation of mining operations is taking place.
(m) Dates in quarterly reporting period where degasification of mining operations is taking place.
(n) Dates in quarterly reporting period when continuous monitoring equipment is not properly functioning, if applicable.
(o) Temperature (°R), pressure (atm), moisture content (if applicable), and the moisture correction factor (if applicable) used in Equations FF-1 and FF-3 of this subpart; and the gaseous organic concentration correction factor, if Equation FF-9 of this subpart was required. Moisture content is required to be reported only if CH
(p) For each destruction device, a description of the device, including an indication of whether destruction occurs at the coal mine or off-site. If destruction occurs at the mine, also report an indication of whether a back-up destruction device is present at the mine, the annual operating hours for the primary destruction device, the annual operating hours for the back-up destruction device (if present), and the destruction efficiencies assumed (percent).
(q) A description of the gas collection system (manufacturer, capacity, and number of wells) the surface area of the gas collection system (square meters),
(r) Identification information and description for each well, shaft, and vent hole, including paragraphs (r)(1) through (r)(3) of this section:
(1) Indication of whether the well, shaft, or vent hole is monitored individually, or as part of a centralized monitoring point. Note which method (sampling or continuous monitoring) was used.
(2) Start date and close date of each well, shaft, and vent hole. If the well, shaft, or vent hole is operating through the end of the reporting year, December 31st of the reporting year shall be the close date for purposes of reporting.
(3) Number of days the well, shaft, or vent hole was in operation during the reporting year. To obtain the number of days in the reporting year, divide the total number of hours that the system was in operation by 24 hours per day.
(s) For each centralized monitoring point, identification of the wells and shafts included in the point. Note which method (sampling or continuous monitoring) was used.
(t) Mine Safety and Health Administration (MSHA) identification for this coal mine.
In addition to the information required by § 98.3(g), you must retain the following records:
(a) Calibration records for all monitoring equipment, including the method or manufacturer's specification used for calibration.
(b) Records of gas sales.
(c) Logbooks of parameter measurements.
(d) Laboratory analyses of samples.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
The zinc production source category consists of zinc smelters and secondary zinc recycling facilities.
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).
You must report:
(a) CO
(b) CO
(c) CO
You must calculate and report the annual process CO
(a) Calculate and report under this subpart the process or combined process and combustion CO
(b) Calculate and report under this subpart the process CO
(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, other than fuel, that is fed, charged, or otherwise
(2) You must determine the CO
(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
If you determine CO
(a) Determine the mass of each solid carbon-containing input material consumed using facility instruments, procedures, or records used for accounting purposes including direct measurement
(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 to 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.
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 document 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 carbon-containing 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.
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
(1) Annual zinc product production capacity (tons).
(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
(1) Identification number and annual process CO
(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) [Reserved]
(7) [Reserved]
(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) [Reserved]
(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.
(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 carbon-containing materials with missing data was determined and the number of months the missing data procedures were used.
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 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).
(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. You 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
(c)
(1) Annual mass of zinc bearing material charged to kiln or furnace (tons) (Equation GG-1 of § 98.333).
(2) Carbon content of the zinc bearing material, from the annual carbon analysis for kiln or furnace (percent by weight, expressed as a decimal fraction) (Equation GG-1).
(3) Annual mass of flux materials (e.g., limestone, dolomite) charged to each kiln or furnace (tons) (Equation GG-1).
(4) Carbon content of the flux materials charged to each kiln or furnace, from the annual carbon analysis (percent by weight, expressed as a decimal fraction) (Equation GG-1).
(5) Annual mass of carbon electrode consumed in each furnace (tons) (Equation GG-1).
(6) Carbon content of the carbon electrode consumed in each furnace, from the annual carbon analysis (percent by weight, expressed as a decimal fraction) (Equation GG-1).
(7) Annual mass of carbonaceous materials (e.g., coal, coke) charged to each kiln or furnace (tons) (Equation GG-1).
(8) Carbon content of the carbonaceous materials charged to each kiln or furnace, from the annual carbon analysis (percent by weight, expressed as a decimal fraction) (Equation GG-1).
(9) Identify whether each unit is a Waelz kiln or an electrothermic furnace.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
(a) This source category applies to municipal solid waste (MSW) landfills that accepted waste on or after January 1, 1980, unless all three of the following conditions apply.
(1) The MSW landfill did not receive waste on or after January 1, 2013.
(2) The MSW landfill had CH
(3) The owner or operator of the MSW landfill was not required to submit an annual report under any requirement of this part in any reporting year prior to 2013.
(b) This source category does not include Resource Conservation and Recovery Act (RCRA) Subtitle C or Toxic Substances Control Act (TSCA) hazardous waste landfills, 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).
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).
(a) You must report CH
(b) You must report CH
(c) You must report under subpart C of this part (General Stationary Fuel Combustion Sources) the emissions of CO
(a) For all landfills subject to the reporting requirements of this subpart, calculate annual modeled CH
(1) Calculate annual modeled CH
(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
(3) Beginning in the first emissions reporting year 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 used to haul waste to the landfill, except for passenger cars, light duty pickup trucks, or waste loads that cannot be measured using the scales due to physical limitations (load cannot physically access or fit on the scale) and/or operational limitations of the scale (load exceeding the limits or sensitivity range of the scale). 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 paragraph (a)(3)(i) or paragraph (a)(3)(ii) of this section to determine the annual quantity of waste disposed. For loads that cannot be measured using the scales due to physical and/or operational limitations of the scale, you must use paragraph (a)(3)(ii) of this section or similar engineering calculations to determine the annual quantity of waste
(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 that 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 (
(4) For years prior to the first emissions reporting year, use methods in paragraph (a)(3) of this section when waste disposal quantity data are readily available. When waste disposal quantity data are not readily available, W
(i) Assume all prior years 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 disposal rates found in Table HH-2 to this subpart, and calculate the waste quantity landfilled using Equation HH-2 of this section.
(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 year accepting waste until the last year for which waste disposal data is unavailable, inclusive).
(b) For landfills with gas collection systems, calculate the quantity of CH
(1) If you continuously monitor the flow rate, CH
(2) If you do not continuously monitor according to paragraph (b)(1) of this section, you must determine the flow rate, CH
(i) Continuously monitor gas flow rate and determine the cumulative volume of landfill gas each month 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
(ii) Determine the CH
(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 at least once each calendar month; if only one measurement is made each calendar month, there must be at least fourteen days between measurements.
(B) If the CH
(c) For all landfills, calculate CH
(1) Calculate CH
(2) For landfills that do not have landfill gas collection systems, the CH
(3) For landfills with landfill gas collection systems, calculate CH
(i) Calculate CH
(ii) Calculate CH
(a) Mass measurement equipment used to determine the 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
(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,
(3) ASTM D1946-90 (Reapproved 2006), Standard Practice for Analysis of Reformed Gas by Gas Chromatography (incorporated by reference,
(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.
(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 landfill gas using either Method 25A or 25B at 40 CFR part 60, appendix A-7 as specified in paragraph (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 organic concentration. If the ratio exceeds 1, use 1 for the non-methane organic carbon correction factor.
(iii) Calculate the methane concentration as specified in Equation HH-9 of this section.
(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,
(2) ASME MFC-4M-1986 (Reaffirmed 1997), Measurement of Gas Flow by Turbine Meters (incorporated by reference,
(3) ASME MFC-6M-1998, Measurement of Fluid Flow in Pipes Using Vortex Flowmeters (incorporated by reference,
(4) ASME MFC-7M-1987 (Reaffirmed 1992), Measurement of Gas Flow by Means of Critical Flow Venturi Nozzles (incorporated by reference,
(5) ASME MFC-11M-2006 Measurement of Fluid Flow by Means of Coriolis Mass Flowmeters (incorporated by reference,
(6) ASME MFC-14M-2003 Measurement of Fluid Flow Using Small Bore Precision Orifice Meters (incorporated by reference,
(7) ASME MFC-18M-2001 Measurement of Fluid Flow using Variable Area Meters (incorporated by reference,
(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.
(e) For landfills electing to measure the fraction by volume of CH
(2) Use Equation HH-10 of this section to correct the measured CH
(f) 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, and the technical basis for these estimates shall be recorded.
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
(b) For missing gas flow rates, 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 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.
(c) For missing daily waste disposal quantity data for disposal in the reporting year, 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.
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 quantities, reason for its selection, and the range of years it is applied. For
(c) Waste composition for each year required for Equation HH-1 of this subpart, in percentage by weight, for each waste category listed in Table HH-1 to this subpart that is used in Equation HH-1 of this subpart to calculate the annual modeled CH
(d) For each waste type used to calculate CH
(1) Degradable organic carbon (DOC) and fraction of DOC dissimilated (DOC
(2) Decay rate (k) value used in the calculations.
(e) Fraction of CH
(f) The surface area of the landfill containing waste (in square meters), identification of the type(s) of cover material used (as either organic cover, clay cover, sand cover, or other soil mixtures).
(g) The modeled annual methane generation rate for the reporting year (metric tons CH
(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
(i) For landfills with gas collection systems, you must report:
(1) Total volumetric flow of landfill gas collected for destruction for the reporting year (cubic feet at 520 °R or 60 degrees Fahrenheit and 1 atm).
(2) Annual average CH
(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 calculations 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
(5) An indication of whether destruction occurs at the landfill facility, off-site, or both. If destruction occurs at the landfill facility, also report for each measurement location:
(i) The number of destruction devices associated with the measurement location.
(ii) The annual operating hours of the gas collection system associated with the measurement location.
(iii) For each destruction device associated with the measurement location, report:
(A) The destruction efficiency (decimal).
(B) The annual operating hours where active gas flow was sent to the destruction device.
(6) Annual quantity of recovered CH
(7) A description of the gas collection system (manufacturer, capacity, and number of wells), the surface area (square meters) and estimated waste depth (meters) for each area specified in Table HH-3 to this subpart, the estimated gas collection system efficiency for landfills with this 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
(9) Methane generation (G
(10) Methane generation corrected for oxidation calculated using Equation HH-7 of this subpart, reported in metric tons CH
(11) Methane emissions calculated using Equation HH-6 of this subpart, reported in metric tons CH
(12) Methane emissions calculated using Equation HH-8 of this subpart, reported in metric tons CH
(13) Methane emissions for the landfill (
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/container type if these are used to determine the annual waste quantities.
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.
75 FR 39767, July 12, 2010, unless otherwise noted.
(a) This source category consists of anaerobic processes used to treat industrial wastewater and industrial
(1) Pulp and paper manufacturing.
(2) Food processing.
(3) Ethanol production.
(4) Petroleum refining.
(b) An
(1) An
(2) An
(3) An
(c) This source category does not include municipal wastewater treatment plants or separate treatment of sanitary wastewater at industrial sites.
You must report GHG emissions under this subpart if your facility meets all of the conditions under paragraphs (a) or (b) of this section:
(a)
(2) The facility meets the requirements of either § 98.2(a)(1) or (2).
(3) The facility operates an anaerobic process to treat industrial wastewater and/or industrial wastewater treatment sludge.
(b)
(2) The facility meets the requirements of § 98.2(a)(2).
(3) The facility operates an anaerobic process to treat industrial wastewater and/or industrial wastewater treatment sludge.
(a) You must report CH
(b) You must report CH
(c) You must report CH
(d) You must report under subpart C of this part (General Stationary Fuel Combustion Sources) the emissions of CO
(a) For each anaerobic reactor and anaerobic lagoon, estimate the annual mass of CH
(1) If you measure the concentration of organic material entering the anaerobic reactors or anaerobic lagoon using methods for the determination of chemical oxygen demand (COD), then estimate annual mass of CH
(2) If you measure the concentration of organic material entering an anaerobic reactor or anaerobic lagoon using methods for the determination of 5-day biochemical oxygen demand (BOD
(b) For each anaerobic reactor and anaerobic lagoon from which biogas is not recovered, estimate annual CH
(c) For each anaerobic sludge digester, anaerobic reactor, or anaerobic lagoon from which some biogas is recovered, estimate the annual mass of CH
(1) If you continuously monitor CH
(2) If you do not continuously monitor CH
(i) Determine the CH
(ii) If the gas flow meter is not equipped with automatic correction for temperature, pressure, or, if necessary, moisture content:
(A) Determine the temperature and pressure in the biogas that is collected and routed to a destruction device in a location near or representative of the location of the gas flow meter at least once each calendar week; if only one measurement is made each calendar
(B) If the CH
(d) For each anaerobic sludge digester, anaerobic reactor, or anaerobic lagoon from which some quantity of biogas is recovered, you must estimate both the annual mass of CH
(1) Estimate the annual mass of CH
(2) For each anaerobic sludge digester, anaerobic reactor, or anaerobic lagoon from which some quantity of biogas is recovered, estimate the annual mass of CH
(e) Estimate the total mass of CH
(a) For calendar year 2011 monitoring, the facility may submit a request to the Administrator to use one or more best available monitoring methods as listed in § 98.3(d)(1)(i) through (iv). The request must be submitted no later than October 12, 2010 and must contain the information in § 98.3(d)(2)(ii). To obtain approval, the request must demonstrate to the Administrator's satisfaction that it is not reasonably feasible to acquire, install, and operate a required piece of monitoring equipment by January 1, 2011. The use of best available monitoring methods will not be approved beyond December 31, 2011.
(b) You must determine the concentration of organic material in wastewater treated anaerobically using analytical methods for COD or BOD
(c) You must collect samples representing wastewater influent to the anaerobic wastewater treatment process, following all preliminary and primary treatment steps (
(d) You must measure the flowrate of wastewater entering anaerobic wastewater treatment process at least once each calendar week that the process is operating; if only one measurement is made each calendar week, there must be at least three days between measurements. You must measure the flowrate for the 24-hour period for which you collect samples analyzed for COD or BOD
(1) ASME MFC-3M-2004 Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and Venturi (incorporated by reference,
(2) ASME MFC-5M-1985 (Reaffirmed 1994) Measurement of Liquid Flow in Closed Conduits Using Transit-Time Ultrasonic Flowmeters (incorporated by reference,
(3) ASME MFC-16-2007 Measurement of Liquid Flow in Closed Conduits with Electromagnetic Flowmeters (incorporated by reference,
(4) ASTM D1941-91 (Reapproved 2007) Standard Test Method for Open Channel Flow Measurement of Water with the Parshall Flume, approved June 15, 2007, (incorporated by reference,
(5) ASTM D5614-94 (Reapproved 2008) Standard Test Method for Open Channel Flow Measurement of Water with Broad-Crested Weirs, approved October
(e) All wastewater flow measurement devices must be calibrated prior to the first year of reporting and recalibrated either biennially (every 2 years) or at the minimum frequency specified by the manufacturer. Wastewater flow measurement devices must be calibrated using the procedures specified by the device manufacturer.
(f) For each anaerobic process (such as anaerobic reactor, sludge digester, or lagoon) from which biogas is recovered, you must make the measurements or determinations specified in paragraphs (f)(1) through (f)(3) of this section.
(1) You must continuously measure the biogas flow rate as specified in paragraph (h) of this section and determine the cumulative volume of biogas recovered.
(2) You must determine the CH
(3) As specified in § 98.353(c) and paragraph (h) of this section, you must determine temperature, pressure, and moisture content as necessary to accurately determine the biogas flow rate and CH
(g) For each anaerobic process (such as an anaerobic reactor, sludge digester, or lagoon) from which biogas is recovered, operate, maintain, and calibrate a gas composition monitor capable of measuring the concentration of CH
(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,
(3) ASTM D1946-90 (Reapproved 2006), Standard Practice for Analysis of Reformed Gas by Gas Chromatography (incorporated by reference,
(4) GPA Standard 2261-00, Analysis for Natural Gas and Similar Gaseous Mixtures by Gas Chromatography (incorporated by reference,
(5) ASTM UOP539-97 Refinery Gas Analysis by Gas Chromatography (incorporated by reference,
(6) As an alternative to the gas chromatography methods provided in paragraphs (g)(1) through (g)(5) of this section, you may use total gaseous organic concentration analyzers and calculate the CH
(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 CH
(ii) Determine a non-methane organic carbon correction factor at the routine sampling location no less frequently than once a reporting year following the requirements in paragraphs (g)(6)(ii)(A) through (g)(6)(ii)(C) of this section.
(A) Take a minimum of three grab samples of the biogas with a minimum of 20 minutes between samples and determine the methane composition of the biogas using one of the methods specified in paragraphs (g)(1) through (g)(5) of this section.
(B) As soon as practical after each grab sample is collected and prior to the collection of a subsequent grab
(C) Determine the arithmetic average methane concentration and the arithmetic average total gaseous organic concentration of the samples analyzed according to paragraphs (g)(6)(ii)(A) and (g)(6)(ii)(B) of this section, respectively, and calculate the non-methane organic carbon correction factor as the ratio of the average methane concentration to the average total gaseous organic concentration. If the ratio exceeds 1, use 1 for the non-methane organic carbon correction factor.
(iii) Calculate the CH
(h) For each anaerobic process (such as an anaerobic reactor, sludge digester, or lagoon) from which biogas is recovered, install, operate, maintain, and calibrate a gas flow meter capable of continuously measuring the volumetric flow rate of the recovered biogas using one of the methods specified in paragraphs (h)(1) through (h)(8) of this section or as specified by the manufacturer. Recalibrate each gas flow meter either biennially (every 2 years) or at the minimum frequency specified by the manufacturer. Except as provided in § 98.353(c)(2)(iii), each gas flow meter must be capable of correcting for the temperature and pressure and, if necessary, moisture content.
(1) ASME MFC-3M-2004, Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and Venturi (incorporated by reference,
(2) ASME MFC-4M-1986 (Reaffirmed 1997), Measurement of Gas Flow by Turbine Meters (incorporated by reference,
(3) ASME MFC-6M-1998, Measurement of Fluid Flow in Pipes Using Vortex Flowmeters (incorporated by reference,
(4) ASME MFC-7M-1987 (Reaffirmed 1992), Measurement of Gas Flow by Means of Critical Flow Venturi Nozzles (incorporated by reference,
(5) ASME MFC-11M-2006 Measurement of Fluid Flow by Means of Coriolis Mass Flowmeters (incorporated by reference, see § 98.7). The mass flow must be corrected to volumetric flow based on the measured temperature, pressure, and biogas composition.
(6) ASME MFC-14M-2003 Measurement of Fluid Flow Using Small Bore Precision Orifice Meters (incorporated by reference,
(7) ASME MFC-18M-2001 Measurement of Fluid Flow using Variable Area Meters (incorporated by reference,
(8) Method 2A or 2D at 40 CFR part 60, appendix A-1.
(i) All temperature, pressure, and, moisture content monitors required as specified in paragraph (f) of this section must be calibrated using the procedures and frequencies where specified by the device manufacturer, if not specified use an industry accepted or industry standard practice.
(j) All equipment (temperature, pressure, and moisture content monitors and gas flow meters and gas composition monitors) must be maintained as specified by the manufacturer.
(k) If applicable, the owner or operator must document the procedures used to ensure the accuracy of measurements of COD or BOD
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) For each missing weekly value of COD or BOD
(b) For each missing value of the CH
(c) If, for a particular parameter, no quality-assured data are available prior to the missing data incident, the substitute data value must be the first quality-assured value obtained after the missing data period. If, for a particular parameter, the “after” value is not obtained by the end of the reporting year, you may use the last quality-assured value obtained “before” the missing data period for the missing data substitution. You must document and keep records of the procedures you use for all such estimates.
In addition to the information required by § 98.3(c), each annual report must contain the following information for each wastewater treatment system.
(a) Identify the anaerobic processes used in the industrial wastewater treatment system to treat industrial wastewater and industrial wastewater treatment sludge, provide a unique identifier for each anaerobic process, indicate the average depth in meters of each anaerobic lagoon, and indicate whether biogas generated by each anaerobic process is recovered. Provide a description or diagram of the industrial wastewater treatment system, identifying the processes used, indicating how the processes are related to each other, and providing a unique identifier for each anaerobic process. Each anaerobic process must be identified as one of the following:
(1) Anaerobic reactor.
(2) Anaerobic deep lagoon (depth more than 2 meters).
(3) Anaerobic shallow lagoon (depth less than 2 meters).
(4) Anaerobic sludge digester.
(b) For each anaerobic wastewater treatment process (reactor, deep lagoon, or shallow lagoon) you must report:
(1) Weekly average COD or BOD
(2) Volume of wastewater entering each anaerobic wastewater treatment process for each week the anaerobic process was operated.
(3) Maximum CH
(4) Methane conversion factor (MCF) used as an input to Equation II-1 or II-2 of this subpart, from Table II-1 to this subpart.
(5) Annual mass of CH
(6) If the facility performs an ethanol production processing operation as defined in § 98.358, you must indicate if the facility uses a wet milling process or a dry milling process.
(c) For each anaerobic wastewater treatment process from which biogas is
(d) For each anaerobic wastewater treatment process and anaerobic sludge digester from which some biogas is recovered, you must report:
(1) Annual quantity of CH
(2) Total weekly volumetric biogas flow for each week (up to 52 weeks/year) that biogas is collected for destruction.
(3) Weekly average CH
(4) Weekly average biogas temperature for each week at which flow is measured for biogas collected for destruction, or statement that temperature is incorporated into monitoring equipment internal calculations.
(5) Whether flow was measured on a wet or dry basis, whether CH
(6) Weekly average biogas pressure for each week at which flow is measured for biogas collected for destruction, or statement that pressure is incorporated into monitoring equipment internal calculations.
(7) CH
(8) Whether destruction occurs at the facility or off-site. If destruction occurs at the facility, also report whether a back-up destruction device is present at the facility, the annual operating hours for the primary destruction device, the annual operating hours for the back-up destruction device (if present), the destruction efficiency for the primary destruction device, and the destruction efficiency for the back-up destruction device (if present).
(9) For each anaerobic process from which some biogas is recovered, you must report the annual CH
(e) The total mass of CH
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.
Except as provided below, all terms used in this subpart have the same meaning given in the CAA and subpart A of this part.
(a) This source category consists of livestock facilities with manure management systems that emit 25,000 metric tons CO
(1) Table JJ-1 presents the minimum average annual animal population by animal group that is estimated to emit 25,000 metric tons CO
(2) (i) If a facility has more than one animal group present (e.g., swine and poultry), the facility must determine if they are required to report by calculating the combined animal group factor (CAGF) using equation JJ-1:
(ii) If the calculated CAGF for a facility is less than 1, the facility is not required to report under this rule. If the CAGF is equal to or greater than 1, the facility must use more detailed applicability tables and tools to determine if they are required to report under this rule.
(b) A manure management system (MMS) is a system that stabilizes and/or stores livestock manure, litter, or manure wastewater in one or more of the following system components: Uncovered anaerobic lagoons, liquid/slurry systems with and without crust covers (including but not limited to ponds and tanks), storage pits, digesters, solid manure storage, dry lots (including feedlots), high-rise houses for poultry production (poultry without litter), poultry production with litter, deep bedding systems for cattle and swine, manure composting, and aerobic treatment.
(c) This source category does not include system components at a livestock facility that are unrelated to the stabilization and/or storage of manure such as daily spread or pasture/range/paddock systems or land application activities or any method of manure utilization that is not listed in § 98.360(b).
(d) This source category does not include manure management activities located off site from a livestock facility or off-site manure composting operations.
Livestock facilities must report GHG emissions under this subpart if the facility meets the reporting threshold as defined in 98.360(a) above, contains a manure management system as defined in 98.360(b) above, and meets the requirements of § 98.2(a)(1).
(a) Livestock facilities must report annual aggregate CH
(1) Uncovered anaerobic lagoons.
(2) Liquid/slurry systems (with and without crust covers, and including but not limited to ponds and tanks).
(3) Storage pits.
(4) Digesters, including covered anaerobic lagoons.
(5) Solid manure storage.
(6) Dry lots, including feedlots.
(7) High-rise houses for poultry production (poultry without litter)
(8) Poultry production with litter.
(9) Deep bedding systems for cattle and swine.
(10) Manure composting.
(11) Aerobic treatment.
(b) A livestock facility that is subject to this rule only because of emissions from manure management system components is not required to report emissions from subparts C through PP (other than subpart JJ) of this part.
(c) A livestock facility that is subject to this part because of emissions from source categories described in subparts C through PP of this part is not required to report emissions under subpart JJ of this part unless emissions from manure management systems are 25,000 metric tons CO
(a) For all manure management system components listed in 98.360(b) except digesters, estimate the annual CH
(1) Average annual animal populations for static populations (e.g., dairy cows, breeding swine, layers) must be estimated by performing an animal inventory or review of facility records once each reporting year.
(2) Average annual animal populations for growing populations (meat animals such as beef and veal cattle, market swine, broilers, and turkeys) must be estimated each year using the average number of days each animal is kept at the facility and the number of animals produced annually, and an equation similar or equal to Equation JJ-4 below, adapted from Equation 10.1 in
(b) For each digester, calculate the total amount of CH
(1) For each digester, calculate the annual CH
(2) For each digester, calculate the average annual volumetric flow rate, CH
(3) For each digester, calculate the CH
(4) For each digester, calculate the CH
(c) For each MMS component, estimate the annual N
(d) Estimate the annual total facility emissions using Equation JJ-15 of this section.
(a) Perform an annual animal inventory or review of facility records (for static populations) or population calculation (for growing populations) to determine the average annual animal population for each animal type (see description in § 98.363(a)(1) and (2)).
(b) Perform an analysis on your operation to determine the fraction of total manure by weight for each animal type that is managed in each on-site manure management system component. If your system changes from previous reporting periods, you must reevaluate the fraction of total manure managed in each system component.
(c) The CH
(d) All temperature and pressure monitors must be calibrated using the procedures and frequencies specified by the manufacturer. All equipment (temperature and pressure monitors) shall be maintained as specified by the manufacturer.
(e) For digesters with gas collection systems, install, operate, maintain, and calibrate a gas flow meter capable of measuring the volumetric flow rate to provide data for the GHG emissions calculations, using the applicable methods specified in paragraphs (e)(1) through (e)(6) of this section or as specified by the manufacturer.
(1) ASME MFC-3M-2004 Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and Venturi (incorporated by reference,
(2) ASME MFC-4M-1986 (Reaffirmed 1997) Measurement of Gas Flow by Turbine Meters (incorporated by reference,
(3) ASME MFC-6M-1998 Measurement of Fluid Flow in Pipes Using Vortex Flowmeters (incorporated by reference,
(4) ASME MFC-7M-1987 (Reaffirmed 1992) Measurement of Gas Flow by Means of Critical Flow Venturi Nozzles (incorporated by reference,
(5) ASME MFC-14M-2003 Measurement of Fluid Flow Using Small Bore Precision Orifice Meters (incorporated by reference,
(6) ASME MFC-18M-2001 Measurement of Fluid Flow using Variable Area Meters (incorporated by reference,
(f) If applicable, the owner or operator shall document the procedures used to ensure the accuracy of gas flow rate, gas composition, temperature, and pressure measurements. These procedures include, but are not limited to, calibration of 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.
(g) Each gas flow meter 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. Each gas flow meter must have a rated accuracy of ±5 percent or lower and be capable of correcting for the temperature and pressure and, if the gas composition monitor determines CH
(a) A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable (e.g., if a meter malfunctions during unit operation or if a required fuel sample is not taken), a substitute data value for the missing parameter shall be used in the calculations, according to the requirements in paragraph (b) of this section.
(b) For missing gas flow rates or CH
(a) In addition to the information required by § 98.3(c), each annual report must contain the following information:
(1) List of manure management system components at the facility.
(2) Fraction of manure from each animal type that is handled in each manure management system component.
(3) Average annual animal population (for each animal type) for static populations or the results of Equation JJ-4 for growing populations.
(4) Average number of days that growing animals are kept at the facility (for each animal type).
(5) The number of animals produced annually for growing populations (for each animal type).
(6) Typical animal mass (for each animal type).
(7) Total facility emissions (results of Equation JJ-15).
(8) CH
(9) VS value used (for each animal type).
(10) B
(11) Methane conversion factor used for each MMS component.
(12) Average ambient temperature used to select each methane conversion factor.
(13) N
(14) N value used for each animal type.
(15) N
(b) Facilities with anaerobic digesters must also report:
(1) CH
(2) CH
(3) CH
(4) CH
(5) Total annual volumetric biogas flow for each digester (results of Equation JJ-7).
(6) Average annual CH
(7) Average annual temperature at which gas flow is measured for each digester (results of Equation JJ-9).
(8) Average annual gas flow pressure at which gas flow is measured for each digester (results of Equation JJ-10).
(9) Destruction efficiency used for each digester.
(10) Number of days per year that each digester was operating.
(11) Collection efficiency used for each digester.
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.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
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-to-liquids 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.
Any supplier of coal-to-liquid products who meets the requirements of § 98.2(a)(4) must report GHG emissions.
Suppliers of coal-based liquid fuels must report the CO
Suppliers of coal-based liquid fuels must follow the calculation methods of § 98.393 as if they applied to the appropriate coal-to-liquid product supplier (
(a) In calculation methods in § 98.393 for petroleum products or petroleum-based products, suppliers of coal-to-liquid products shall also include coal-to-liquid products.
(b) In calculation methods in § 98.393 for non-crude 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 methods 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.
Suppliers of coal-based liquid fuels must follow the monitoring and QA/QC requirements in § 98.394 as if they applied to the appropriate coal-to-liquid product supplier. Any monitoring and QA/QC requirement for petroleum products in § 98.394 also applies to coal-to-liquid products.
Suppliers of coal-based liquid fuels must follow the procedures for estimating missing data in § 98.395 as if they applied to the appropriate coal-to-liquid product supplier. Any procedure
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) [Reserved]
(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) of this section 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 (excluding any denaturant that may be present in any ethanol product).
(4)-(5) [Reserved]
(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) of this section 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)(6) of this section that is fossil fuel-based (excluding any denaturant that may be present in any ethanol product).
(8) [Reserved]
(9) For every feedstock reported in paragraph (a)(2) of this section for which Calculation Method 2 in § 98.393(f)(2) 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
(10) For every non-solid feedstock reported in paragraph (a)(2) of this section for which Calculation Method 2 in § 98.393(f)(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.
(11) For every product reported in paragraph (a)(6) of this section for which Calculation Method 2 in § 98.393(f)(2) 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
(12) For every non-solid product reported in paragraph (a)(6) of this section for which Calculation Method 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.
(13) [Reserved]
(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 annual quantity in metric tons or barrels.
(15) [Reserved]
(16) The CO
(17) The CO
(18) Annual CO
(19) Annual CO
(20) Annual quantity of bulk NGLs in metric tons or barrels received for processing during the reporting year. Report only quantities of bulk NGLs not reported in paragraph (a)(2) of this section.
(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) [Reserved]
(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.
(3) For each product reported in paragraph (b)(2) of this section that was produced by blending a fossil fuel-based 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 (excluding any denaturant that may be present in any ethanol product).
(4) [Reserved]
(5) For each product reported in paragraph (b)(2) of this section for which Calculation Method 2 in § 98.393(f)(2) 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
(6) For each non-solid product reported in paragraph (b)(2) of this section for which Calculation Method 2 in § 98.393(f)(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.
(7) The CO
(8) The total sum of CO
(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) [Reserved]
(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.
(3) For each product reported in paragraph (c)(2) of this section that was produced by blending a fossil fuel-based 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 (excluding any denaturant that may be present in any ethanol product).
(4) [Reserved]
(5) For each product reported in paragraph (c)(2) of this section for which Calculation Method 2 in § 98.393(f)(2) 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
(6) For each non-solid product reported in paragraph (c)(2) of this section for which Calculation Method 2 in § 98.393(f)(2) 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
(8) Total sum of CO
(d)
(i) Volume or mass of each blending component.
(ii) The CO
(iii) Whether it is a blended feedstock or a blended product.
(2) For a product that enters the facility to be further refined or otherwise used on site that is a blended feedstock, producers must meet the reporting requirements of paragraph (a)(2) of this section by reflecting the individual components of the blended feedstock.
(3) For a product that is produced, imported, or exported that is a blended product, producers, importers, and exporters must meet the reporting requirements of paragraphs (a)(6), (b)(2), and (c)(2) of this section, as applicable, by reflecting the individual components of the blended product.
Suppliers of coal-based liquid fuels must retain records according to the requirements in § 98.397 as if they applied to the appropriate coal-to-liquid product supplier (
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
This source category consists of petroleum refineries and importers and exporters of petroleum products and 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.
Any supplier of petroleum products who meets the requirements of § 98.2(a)(4) must report GHG emissions.
Suppliers of petroleum products must report the CO
(a)
(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
(b)
(2) In the event that a non-crude feedstock enters a refinery as a solid rather than liquid, the refiner shall calculate CO
(c)
(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
(d)
(e)
(f)
(1)
(2)
(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.
(g)
(h)
(1) A reporter using Calculation Method 1 to determine the emission factor of a petroleum product shall calculate the CO
(2) A refinery using Calculation Method 1 of this subpart to determine the emission factor of a non-crude petroleum feedstock shall calculate the CO
(3)
(ii) In the event that a petroleum product contains denatured ethanol, importers and exporters must follow Calculation Method 1 procedures in paragraph (h)(1) of this section; and refineries must sample the petroleum portion of the blended biomass-based fuel prior to blending and calculate CO
(4)
(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)
(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 to subpart MM.
(iii) The blended product or non-crude feedstock is not comprised entirely of natural gas liquids.
(iv) The reporter uses Calculation Method 1.
(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.
(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.
(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” applied in Equation MM-12 of this section and the quantity of non-crude feedstock “k” applied in Equation MM-2 of this section must be determined using the same method or practice.
(a)
(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 of quantity shall be temperature-adjusted and pressure-adjusted 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.
(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.
(3) The annual quantity of crude oil received shall be determined according to one of the following methods. You may use an appropriate standard method published by a consensus-based standards organization or you may use an industry standard practice.
(b)
(2) Measurement equipment shall be recalibrated at the minimum frequency specified by the standard method used or by the equipment manufacturer's directions.
(3) For units and processes that operate continuously with infrequent outages, it may not be possible to complete the calibration of a flow meter or other measurement device without disrupting normal process operation. In such cases, the owner or operator may
(c)
(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 samples 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 reporting 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.
(a)
(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)
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) [Reserved]
(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.
(3) For each feedstock reported in paragraph (a)(2) of this section that was produced by blending a petroleum-based 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)-(5) [Reserved]
(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 natural 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) of this section that was produced by blending a petroleum-based 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) [Reserved]
(9) For every feedstock reported in paragraph (a)(2) of this section for which Calculation Method 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
(10) For every non-solid feedstock reported in paragraph (a)(2) of this section for which Calculation Method 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 Method 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
(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.
(13) [Reserved]
(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) [Reserved]
(16) The CO
(17) The CO
(18) The CO
(19) The sum of CO
(20) For all crude oil that enters the refinery, report the annual quantity in barrels.
(21) The quantity of bulk NGLs in metric tons or barrels received for processing during the reporting year. Report only quantities of bulk NGLs not reported in (a)(2) of this section.
(22) Volume of crude oil in barrels that you injected into a crude oil supply or reservoir.
(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) [Reserved]
(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 (b)(2) of this section that was produced by blending a petroleum-based 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) [Reserved]
(5) For each product reported in paragraph (b)(2) of this section for which Calculation Method 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
(6) For each non-solid product reported in paragraph (b)(2) of this section for which Calculation Method 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
(8) The sum of CO
(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) [Reserved]
(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) of this section that was produced by blending a petroleum-based 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) [Reserved]
(5) For each product reported in paragraph (c)(2) of this section for which Calculation Method 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
(6) For each non-solid product reported in paragraph (c)(2) of this section for which Calculation Method 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
(8) The sum of CO
(d)
(i) Volume or mass of each blending component.
(ii) The CO
(iii) Whether it is a blended non-crude feedstock or a blended product.
(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 paragraph (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)(6), (b)(2), and (c)(2) of this section, as applicable, by reflecting the individual components of the blended product.
(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.
(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 reported quantities of
(c) Reporters shall retain laboratory reports, calculations and worksheets used to estimate the CO
(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
(e) Estimates of missing data shall be documented and records maintained showing the calculations.
(f) Reporters described in this subpart shall also retain all records described in § 98.3(g).
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.
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 constituent liquid products or mixtures of 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 within a single state that are regulated as separate operating companies by State public utility commissions or that operate as independent municipally-owned distribution systems. LDCs do not include pipelines (both interstate and intrastate) delivering natural gas directly to major industrial users and farm taps upstream of the local distribution company inlet.
(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.
Any supplier of natural gas and natural gas liquids that meets the requirements of § 98.2(a)(4) must report GHG emissions associated with the products they supply.
(a) NGL fractionators must report the CO
(b) LDCs must report the CO
(a) LDCs and fractionators shall, for each individual product reported under this part, calculate the estimated CO
(1)
(2)
(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 Equation NN-3 of this section and the default values for the CO
(2)(i) For natural gas delivered to large end-users, use Equation NN-4 of this section and the default values for the CO
(ii) Alternatively, reporter-specific CO
(3) For the net change in natural gas stored on system by the LDC during the reporting year, use Equation NN-5a of this section. For natural gas that is received by means other than through the city gate, and is not otherwise accounted for by Equation NN-1 or NN-2 of this section, use Equation NN-5b of this section.
(i) For natural gas received by the LDC that is injected into on-system storage, and/or liquefied and stored, and for gas removed from storage and used for deliveries, use Equation NN-5a of this section and the default value for the CO
(ii) For natural gas received by the LDC that bypassed the city gate, use Equation NN-5b of this section. This includes natural gas received directly by LDC systems from producers or natural gas processing plants from local production, received as a liquid and vaporized for delivery, or received from any other source that bypassed the city gate. Use the default value for the CO
(4) Calculate the total CO
(c) Each NGL fractionator shall follow the following procedures.
(1)(i) 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
(ii) Alternatively, reporter-specific CO
(2) Calculate the total CO
(a)
(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.
(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 transfer meters or at such meters that are used to determine the NGL product slate delivered from the fractionation facility.
(4) If a NGL fractionator supplies a product that is a mixture or blend of two or more products listed in Tables NN-1 and NN-2 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 received 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 large end-user's meter(s). Where a large end-user is known to have more than one meter located at their facility, based on readily available information in the LDCs possession, the reporter shall measure the natural gas at each meter and sum the annual volume delivered to all meters located at the end-user's facility to determine the total volume delivered to the large end-user. Otherwise, the reporter shall consider the total annual volume delivered through each single meter at a
(8) An LDC using Equation NN-5a and/or NN-5b of this subpart shall measure natural gas as follows:
(i) Fuel
(ii) Fuel
(iii) Fuel
(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 one atmosphere.
(b)
(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 standards 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)
(2) When a reporter used the default EF provided in this section to calculate Equation NN-2, NN-3, NN-4, NN-5a, NN-5b, 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 conduct compositional analysis necessary to determine reporter-specific CO
(d)
(2) Equipment used to measure quantities in Equations NN-1, NN-2, NN-5a, and NN-5b of this subpart shall be recalibrated at the frequency specified by the standard method used or by the manufacturer's directions.
(3) Equipment used to measure quantities in Equations NN-3 and NN-4 of this subpart shall be recalibrated at the frequency commonly used within the industry.
(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)
(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)
(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 assurance 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) [Reserved]
(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.
(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 (including fractionated NGL products received from other NGL fractionators) in the following product categories: Ethane, propane, normal butane, isobutane, and pentanes plus (Fuel
(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 (Fuel
(3) Annual volumes in Mscf of natural gas received for processing.
(4) Annual quantities (in barrels) of y-grade, o-grade, and other bulk NGLs:
(i) Received.
(ii) Supplied to downstream users.
(5) Annual quantity (in barrels) of propane that the NGL fractionator odorizes at the facility and delivers to others.
(6) Annual CO
(7) Annual CO
(8) The specific industry standard used to measure each quantity reported in paragraph (a)(1) of this section.
(9) If the NGL fractionator developed reporter-specific EFs or HHVs, report the following for each product type:
(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 (Fuel
(2) Annual volume in Mscf of natural gas placed into storage or liquefied and stored (Fuel
(3) Annual volume in Mscf of natural gas withdrawn from on-system storage and annual volume in Mscf of vaporized liquefied natural gas (LNG) withdrawn from storage for delivery on the distribution system (Fuel
(4) [Reserved]
(5) Annual volume in Mscf of natural gas that bypassed the city gate(s) and was supplied through the LDC distribution system. This includes natural gas from producers and natural gas processing plants from local production, or natural gas that was vaporized upon receipt and delivered, and any other source that bypassed the city gate (Fuel
(6) Annual volume in Mscf of natural gas delivered to downstream gas transmission pipelines and other local distribution companies (Fuel in Equation NN-3 of this subpart).
(7) Annual volume in Mscf of natural gas delivered by the LDC to each large end-user as defined in § 98.403(b)(2)(i) of this section.
(8) The total annual CO
(9) Annual CO
(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).
(12) For each large end-user reported in paragraph (b)(7) of this section, report:
(i) The customer name, address, and meter number(s).
(ii) Whether the quantity of natural gas reported in paragraph (b)(7) of this section is the total quantity delivered to a large end-user's facility, or the quantity delivered to a specific meter located at the facility.
(iii) If known, report the EIA identification number of each LDC customer.
(13) The annual volume in Mscf of natural gas delivered by the LDC (including natural gas that is not owned by the LDC) 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.
(14) The name of the U.S. state or territory covered in this report submission.
(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).
In addition to the information required by § 98.3(g), the reporter shall retain the following records:
(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
(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.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
(a) The industrial gas supplier source category consists of any facility that produces fluorinated GHGs or nitrous oxide; any bulk importer of fluorinated GHGs or nitrous oxide; and any bulk exporter of fluorinated GHGs or nitrous oxide. Starting with reporting year 2018, this source category also consists of any facility that produces fluorinated HTFs; any bulk importer of fluorinated HTFs; any bulk exporter of fluorinated HTFs; and any facility that destroys fluorinated GHGs or fluorinated HTFs.
(b) To produce a fluorinated GHG means to manufacture a fluorinated GHG from any raw material or feedstock chemical. Producing a fluorinated GHG includes the manufacture of a fluorinated GHG as an isolated intermediate for use in a process that will result in its transformation either at or outside of the production facility. Producing a fluorinated GHG also includes the creation of a fluorinated GHG (with the exception of HFC-23) that is captured and shipped off site for any reason, including destruction. Producing a fluorinated GHG does not include the reuse or recycling of a fluorinated GHG, the creation of HFC-23 during the production of HCFC-22, the creation of intermediates that are created and transformed in a single process with no storage of the intermediates, or the creation of fluorinated GHGs that are released or destroyed at the production facility before the production measurement at § 98.414(a).
(c) To produce nitrous oxide means to produce nitrous oxide by thermally decomposing ammonium nitrate (NH
(d) To produce a fluorinated HTF means to manufacture, from any raw material or feedstock chemical, a fluorinated GHG used for temperature control, device testing, cleaning substrate surfaces and other parts, and soldering in processes including but not limited to certain types of electronics manufacturing production processes. Fluorinated heat transfer fluids do not include fluorinated GHGs used as lubricants or surfactants. For fluorinated heat transfer fluids under this subpart, the lower vapor pressure limit of 1 mm Hg in absolute at 25 °C in the definition of fluorinated greenhouse gas in § 98.6 shall not apply. Fluorinated heat transfer fluids include, but are not limited to, perfluoropolyethers, perfluoroalkanes, perfluoroethers, tertiary perfluoroamines, and perfluorocyclic ethers. Producing a fluorinated HTF does not include the reuse or recycling of a fluorinated HTF, the creation of intermediates, or the creation of fluorinated HTFs that are released or destroyed at the production facility before the production measurement at § 98.414(a).
(e) For purposes of this subpart, to destroy fluorinated GHGs or fluorinated HTFs means to cause the expiration of a previously produced (as defined in paragraphs (b) and (d) of this section) fluorinated GHG or fluorinated HTF to the destruction efficiency actually achieved. Such destruction does not result in a commercially useful end product. For purposes of this subpart, such destruction does not include HFC-23 destruction as defined at § 98.150 or the dissociation of fluorinated GHGs that occurs during electronics manufacturing as defined at § 98.90. For example, such destruction does not include the dissociation of fluorinated GHGs that occurs during etch or chamber cleaning processes or during use of abatement systems that treat the fluorinated GHGs vented from such processes at electronics manufacturing facilities.
Any supplier of industrial greenhouse gases who meets the requirements of § 98.2(a)(4) must report GHG emissions.
You must report the GHG emissions that would result from the release of the nitrous oxide and each fluorinated GHG that you produce, import, export, transform, or destroy during the calendar year. Starting with reporting year 2018, you must also report the emissions that would result from the release of each fluorinated HTF that is not also a fluorinated GHG and that you produce, import, export, transform, or destroy during the calendar year.
(a) Calculate the total mass of the nitrous oxide and each fluorinated GHG or fluorinated HTF produced annually, except for amounts that are captured solely to be shipped off site for destruction, by using Equation OO-1 of this section:
(b) Calculate the total mass of the nitrous oxide and each fluorinated GHG or fluorinated HTF produced over the period “p” by using Equation OO-2 of this section:
(c) Calculate the total mass of the nitrous oxide and each fluorinated GHG or fluorinated HTF transformed by using Equation OO-3 of this section:
(d) Calculate the total mass of each fluorinated GHG or fluorinated HTF destroyed by using Equation OO-4 of this section:
(a) The mass of fluorinated GHGs, fluorinated HTFs, or nitrous oxide coming out of the production process shall be measured using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of one percent of full scale or better. If the measured mass includes more than one fluorinated GHG or fluorinated HTF, the concentrations of each of the fluorinated GHGs or fluorinated HTFs, other than low-concentration constituents, shall be measured as set forth in paragraph (n) of this section. For each fluorinated GHG or fluorinated HTF, the mean of the concentrations of that fluorinated GHG (mass fraction) measured under paragraph (n) shall be multiplied by the mass measurement to obtain the mass of that fluorinated GHG or fluorinated HTF coming out of the production process.
(b) The mass of any used fluorinated GHGs, fluorinated HTFs, or used nitrous oxide added back into the production process upstream of the output measurement in paragraph (a) of this section shall be measured using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of one percent of full scale or better. If the mass in paragraph (a) is measured by weighing containers that include returned heels as well as newly produced fluorinated GHGs or fluorinated HTFs, the returned heels shall be considered used fluorinated GHGs or fluorinated HTFs for purposes of this paragraph (b) and § 98.413(b).
(c) The mass of fluorinated GHGs, fluorinated HTFs, or nitrous oxide fed into the transformation process shall be measured using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of one percent of full scale or better.
(d) The fraction of the fluorinated GHGs, fluorinated HTFs, or nitrous oxide fed into the transformation process that is actually transformed shall be estimated considering yield calculations or quantities of unreacted fluorinated GHGs, fluorinated HTFs, or nitrous oxide permanently removed from the process and recovered, destroyed, or emitted.
(e) The mass of fluorinated GHGs, fluorinated HTFs, or nitrous oxide sent to another facility for transformation shall be measured using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of one percent of full scale or better.
(f) The mass of fluorinated GHGs or fluorinated HTFs sent to another facility for destruction shall be measured using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and
(g) You must estimate the share of the mass of fluorinated GHGs or fluorinated HTFs in paragraph (f) of this section that is comprised of fluorinated GHGs or fluorinated HTFs that are not included in the mass produced in § 98.413(a) because they are removed from the production process as by-products or other wastes.
(h) You must measure the mass of each fluorinated GHG or fluorinated HTF that is fed into the destruction device and that was previously produced as defined at § 98.410(b). Such fluorinated GHGs or fluorinated HTFs include but are not limited to quantities that are shipped to the facility by another facility for destruction and quantities that are returned to the facility for reclamation but are found to be irretrievably contaminated and are therefore destroyed. You must use flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of one percent of full scale or better. If the measured mass includes more than trace concentrations of materials other than the fluorinated GHG or fluorinated HTF being destroyed, you must estimate the concentrations of the fluorinated GHG or fluorinated HTF being destroyed considering current or previous representative concentration measurements and other relevant process information. You must multiply this concentration (mass fraction) by the mass measurement to obtain the mass of the fluorinated GHG or fluorinated HTF fed into the destruction device.
(i) Very small quantities of fluorinated GHGs or fluorinated HTFs that are difficult to measure because they are entrained in other media such as destroyed filters and destroyed sample containers are exempt from paragraphs (f) and (h) of this section.
(j) [Reserved]
(k) For purposes of Equation OO-4 of this subpart, the destruction efficiency can be equated to the destruction efficiency determined during a previous performance test of the destruction device or, if no performance test has been done, the destruction efficiency provided by the manufacturer of the destruction device.
(l) In their estimates of the mass of fluorinated GHGs or fluorinated HTFs destroyed, facilities that destroy fluorinated GHGs or fluorinated HTFs shall account for any temporary reductions in the destruction efficiency that result from any startups, shutdowns, or malfunctions of the destruction device, including departures from the operating conditions defined in state or local permitting requirements and/or oxidizer manufacturer specifications.
(m) Calibrate all flow meters, weigh scales, and combinations of volumetric and density measures that are used to measure or calculate quantities that are to be reported under this subpart prior to the first year for which GHG emissions are reported under this part. Calibrations performed prior to the effective date of this rule satisfy this requirement. Recalibrate all flow meters, weigh scales, and combinations of volumetric and density measures at the minimum frequency specified by the manufacturer. Use NIST-traceable standards and suitable methods published by a consensus standards organization (e.g., ASTM, ASME, ISO, or others).
(n) If the mass coming out of the production process includes more than one fluorinated GHG or fluorinated HTF, you shall measure the concentrations of all of the fluorinated GHGs or fluorinated HTFs, other than low-concentration constituents, as follows:
(1)
(2)
(3)
(4)
(5)
(o) All analytical equipment used to determine the concentration of fluorinated GHGs or fluorinated HTFs, including but not limited to gas chromatographs and associated detectors, IR, FTIR and NMR devices, shall be calibrated at a frequency needed to support the type of analysis specified in the site GHG Monitoring Plan as required under paragraph (n) of this section and § 98.3(g)(5). Quality assurance samples at the concentrations of concern shall be used for the calibration. Such quality assurance samples shall consist of or be prepared from certified standards of the analytes of concern where available; if not available, calibration shall be performed by a method specified in the GHG Monitoring Plan.
(p) Isolated intermediates that are produced and transformed at the same
(q) Low-concentration constituents are exempt from the monitoring and QA/QC requirements of this section.
(a) A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable (e.g., if a meter malfunctions), a substitute data value for the missing parameter shall be used in the calculations, according to paragraph (b) of this section.
(b) For each missing value of the mass produced, fed into the production process (for used material being reclaimed), fed into the transformation process, fed into destruction devices, sent to another facility for transformation, or sent to another facility for destruction, the substitute value of that parameter shall be a secondary mass measurement where such a measurement is available. For example, if the mass produced is usually measured with a flowmeter at the inlet to the day tank and that flowmeter fails to meet an accuracy or precision test, malfunctions, or is rendered inoperable, then the mass produced may be estimated by calculating the change in volume in the day tank and multiplying it by the density of the product. Where a secondary mass measurement is not available, the substitute value of the parameter shall be an estimate based on a related parameter. For example, if a flowmeter measuring the mass fed into a destruction device is rendered inoperable, then the mass fed into the destruction device may be estimated using the production rate and the previously observed relationship between the production rate and the mass flow rate into the destruction device.
In addition to the information required by § 98.3(c), each annual report must contain the following information:
(a) Each fluorinated GHG, fluorinated HTF, or nitrous oxide production facility shall report the following information:
(1) Mass in metric tons of nitrous oxide and each fluorinated GHG or fluorinated HTF produced at that facility by process, except for amounts that are captured solely to be shipped off site for destruction.
(2) Mass in metric tons of nitrous oxide and each fluorinated GHG or fluorinated HTF transformed at that facility, by process.
(3) Mass in metric tons of each fluorinated GHG or fluorinated HTF that is destroyed at that facility and that was previously produced as defined at § 98.410(b). Quantities to be reported under paragraph (a)(3) of this section include but are not limited to quantities that are shipped to the facility by another facility for destruction and quantities that are returned to the facility for reclamation but are found to be irretrievably contaminated and are therefore destroyed.
(4) [Reserved]
(5) Total mass in metric tons of nitrous oxide and each fluorinated GHG or fluorinated HTF sent to another facility for transformation.
(6) Total mass in metric tons of each fluorinated GHG or fluorinated HTF sent to another facility for destruction, except fluorinated GHGs and fluorinated HTFs that are not included in the mass produced in § 98.413(a) because they are removed from the production process as byproducts or other wastes. Quantities to be reported under paragraph (a)(6) of this section could include, for example, fluorinated GHGs that are returned to the facility for reclamation but are found to be irretrievably contaminated and are therefore sent to another facility for destruction.
(7) Total mass in metric tons of each fluorinated GHG or fluorinated HTF that is sent to another facility for destruction and that is not included in the mass produced in § 98.413(a) because it is removed from the production process as a byproduct or other waste.
(8)-(9) [Reserved]
(10) Mass in metric tons of nitrous oxide and each fluorinated GHG or fluorinated HTF fed into the transformation process, by process.
(11) Mass in metric tons of each fluorinated GHG or fluorinated HTF that is fed into the destruction device and that was previously produced as defined at § 98.410(b). Quantities to be reported under paragraph (a)(11) of this section include but are not limited to quantities that are shipped to the facility by another facility for destruction and quantities that are returned to the facility for reclamation but are found to be irretrievably contaminated and are therefore destroyed.
(12) Mass in metric tons of nitrous oxide and each fluorinated GHG or fluorinated HTF that is measured coming out of the production process, by process.
(13) Mass in metric tons of used nitrous oxide and of each used fluorinated GHG or fluorinated HTF added back into the production process (
(14) Names and addresses of facilities to which any nitrous oxide, fluorinated GHGs, or fluorinated HTFs were sent for transformation, and the quantities (metric tons) of nitrous oxide and of each fluorinated GHG or fluorinated HTF that were sent to each for transformation.
(15) Names and addresses of facilities to which any fluorinated GHGs or fluorinated HTFs were sent for destruction, and the quantities (metric tons) of each fluorinated GHG or fluorinated HTF that were sent to each for destruction.
(16) Where missing data have been estimated pursuant to § 98.415, the reason the data were missing, the length of time the data were missing, the method used to estimate the missing data, and the estimates of those data.
(b) Any facility or importer that destroys fluorinated GHGs or fluorinated HTFs shall submit a one-time report containing the information in paragraphs (b)(1) through (6) of this section for each destruction process by the applicable date set forth in paragraph (b)(7) of this section. Facilities and importers that previously submitted one-time reports under this paragraph for all destruction devices used to destroy fluorinated GHGs or fluorinated HTFs are exempt from this requirement unless they meet the conditions in paragraph (b)(6) of this section.
(1) Destruction efficiency (DE).
(2) Methods used to determine the destruction efficiency.
(3) Methods used to record the mass of fluorinated GHG or fluorinated HTF destroyed.
(4) Chemical identity of the fluorinated GHG(s) used in the performance test conducted to determine DE.
(5) Name of all applicable federal or state regulations that may apply to the destruction process.
(6) If any process changes (including the acquisition of a new destruction device) affect unit destruction efficiency or the methods used to record the mass of fluorinated GHG or fluorinated HTF destroyed, then a revised report must be submitted to reflect the changes. The revised report must be submitted to EPA within 60 days of the change.
(7)(i) Any fluorinated GHG production facility or importer that destroys fluorinated GHGs must submit the one-time destruction report by March 31, 2011 or within 60 days of commencing fluorinated GHG destruction, whichever is later.
(ii) Any fluorinated GHG production facility or importer that destroys fluorinated HTFs that are not also fluorinated GHGs must submit the one-time destruction report by March 31, 2019 or within 60 days of commencing fluorinated HTF destruction, whichever is later.
(iii) Any facility that destroys fluorinated GHGs or fluorinated HTFs but does not produce or import fluorinated GHGs must submit the one-time destruction report by March 31, 2019 or within 60 days of commencing fluorinated GHG or fluorinated HTF destruction, whichever is later.
(c) Each bulk importer of fluorinated GHGs, fluorinated HTFs, or nitrous oxide shall submit an annual report that summarizes its imports at the corporate level, except for shipments including less than twenty-five kilograms of fluorinated GHGs, fluorinated
(1) Total mass in metric tons of nitrous oxide and each fluorinated GHG or fluorinated HTF imported in bulk, including each fluorinated GHG or fluorinated HTF constituent of the fluorinated GHG or fluorinated HTF product that makes up between 0.5 percent and 100 percent of the product by mass.
(2) Total mass in metric tons of nitrous oxide and each fluorinated GHG or fluorinated HTF imported in bulk and sold or transferred to persons other than the importer for use in processes resulting in the transformation or destruction of the chemical.
(3) Date on which the fluorinated GHGs, fluorinated HTFs, or nitrous oxide were imported.
(4) Port of entry through which the fluorinated GHGs, fluorinated HTFs, or nitrous oxide passed.
(5) Country from which the imported fluorinated GHGs, fluorinated HTFs, or nitrous oxide were imported.
(6) Commodity code of the fluorinated GHGs, fluorinated HTFs, or nitrous oxide shipped.
(7) Importer number for the shipment.
(8) Total mass in metric tons of each fluorinated GHG or fluorinated HTF destroyed by the importer.
(9) If applicable, the names and addresses of the persons and facilities to which the nitrous oxide, fluorinated GHGs, or fluorinated HTFs were sold or transferred for transformation, and the quantities (metric tons) of nitrous oxide and of each fluorinated GHG or fluorinated HTF that were sold or transferred to each facility for transformation.
(10) If applicable, the names and addresses of the persons and facilities to which the fluorinated GHGs or fluorinated HTFs were sold or transferred for destruction, and the quantities (metric tons) of each fluorinated GHG or fluorinated HTF that were sold or transferred to each facility for destruction.
(d) Each bulk exporter of fluorinated GHGs, fluorinated HTFs, or nitrous oxide shall submit an annual report that summarizes its exports at the corporate level, except for shipments including less than twenty-five kilograms of fluorinated GHGs, fluorinated HTFs, or nitrous oxide, transshipments, and heels. The report shall contain the following information for each export:
(1) Total mass in metric tons of nitrous oxide and each fluorinated GHG or fluorinated HTF exported in bulk.
(2) Names and addresses of the exporter and the recipient of the exports.
(3) Exporter's Employee Identification Number.
(4) Commodity code of the fluorinated GHGs, fluorinated HTFs, or nitrous oxide shipped.
(5) Date on which, and the port from which, the fluorinated GHGs, fluorinated HTFs, or nitrous oxide were exported from the United States or its territories.
(6) Country to which the fluorinated GHGs, fluorinated HTFs, or nitrous oxide were exported.
(e) By March 31, 2011, or within 60 days of commencing fluorinated GHG production, whichever is later, a fluorinated GHG production facility shall submit a one-time report describing the following information:
(1) The method(s) by which the producer in practice measures the mass of fluorinated GHGs produced, including the instrumentation used (Coriolis flowmeter, other flowmeter, weigh scale, etc.) and its accuracy and precision.
(2) The method(s) by which the producer in practice estimates the mass of fluorinated GHGs fed into the transformation process, including the instrumentation used (Coriolis flowmeter, other flowmeter, weigh scale, etc.) and its accuracy and precision.
(3) The method(s) by which the producer in practice estimates the fraction of fluorinated GHGs fed into the transformation process that is actually transformed, and the estimated precision and accuracy of this estimate.
(4) The method(s) by which the producer in practice estimates the masses
(5) The estimated percent efficiency of each production process for the fluorinated GHG produced.
(f) By March 31, 2011, all fluorinated GHG production facilities shall submit a one-time report that includes the concentration of each fluorinated GHG constituent in each fluorinated GHG product as measured under § 98.414(n). If the facility commences production of a fluorinated GHG product that was not included in the initial report or performs a repeat measurement under § 98.414(n) that shows that the identities or concentrations of the fluorinated GHG constituents of a fluorinated GHG product have changed, then the new or changed concentrations, as well as the date of the change, must be reflected in a revision to the report. The revised report must be submitted to EPA by the March 31st that immediately follows the measurement under § 98.414(n).
(g) Isolated intermediates that are produced and transformed at the same facility are exempt from the reporting requirements of this section.
(h) Low-concentration constituents are exempt from the reporting requirements of this section.
(i) Each facility that destroys fluorinated GHGs or fluorinated HTFs but does not otherwise report under this section shall report the mass in metric tons of each fluorinated GHG or fluorinated HTF that is destroyed at that facility and that was previously produced as defined at § 98.410(b) or (d), as applicable. Quantities to be reported under this paragraph (i) include but are not limited to quantities that are shipped to the facility by another facility for destruction and quantities that are returned to the facility for reclamation but are found to be irretrievably contaminated and are therefore destroyed.
(j) By March 31, 2019, all facilities that produce fluorinated HTFs that are not also fluorinated GHGs shall submit a one-time report that includes the concentration of each fluorinated HTF or fluorinated GHG constituent in each fluorinated HTF product as measured under § 98.414(n). If the facility commences production of a fluorinated HTF product that was not included in the initial report or performs a repeat measurement under § 98.414(n) that shows that the identities or concentrations of the fluorinated HTF or fluorinated GHG constituents of a fluorinated HTF product have changed, then the new or changed concentrations, as well as the date of the change, must be provided in a revised report. The revised report must be submitted to EPA by the March 31st that immediately follows the new or repeat measurement under § 98.414(n).
(a) In addition to the data required by § 98.3(g), the fluorinated GHG or fluorinated HTF production facility shall retain the following records:
(1) Dated records of the data used to estimate the data reported under § 98.416.
(2) Records documenting the initial and periodic calibration of the analytical equipment (including but not limited to GC, IR, FTIR, or NMR), weigh scales, flowmeters, and volumetric and density measures used to measure the quantities reported under this subpart, including the manufacturer directions or industry standards used for calibration pursuant to § 98.414(m) and (o).
(3) Dated records of the total mass in metric tons of each reactant fed into the fluorinated GHG, fluorinated HTF, or nitrous oxide production process, by process.
(4) Dated records of the total mass in metric tons of the reactants, by-products, and other wastes permanently removed from the fluorinated GHG, fluorinated HTF, or nitrous oxide production process, by process.
(b) In addition to the data required by paragraph (a) of this section, any facility that destroys fluorinated GHGs or fluorinated HTFs shall keep records of test reports and other information
(c) In addition to the data required by § 98.3(g), the bulk importer shall retain the following records substantiating each of the imports that they report:
(1) A copy of the bill of lading for the import.
(2) The invoice for the import.
(3) The U.S. Customs entry form.
(d) In addition to the data required by § 98.3(g), the bulk exporter shall retain the following records substantiating each of the exports that they report:
(1) A copy of the bill of lading for the export and
(2) The invoice for the export.
(e) Every person who imports a container with a heel that is not reported under § 98.416(c) shall keep records of the amount brought into the United States that document that the residual amount in each shipment is less than 10 percent of the volume of the container and will:
(1) Remain in the container and be included in a future shipment.
(2) Be recovered and transformed.
(3) Be recovered and destroyed.
(4) Be recovered and included in a future shipment.
(f) Isolated intermediates that are produced and transformed at the same facility are exempt from the recordkeeping requirements of this section.
(g) Low-concentration constituents are exempt from the recordkeeping requirements of this section.
Except as provided below, all of the terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. If a conflict exists between a definition provided in this subpart and a definition provided in subpart A, the definition in this subpart shall take precedence for the reporting requirements in this subpart.
(a) The carbon dioxide (CO
(1) Facilities with production process units that capture a CO
(2) Facilities with CO
(3) Importers or exporters of bulk CO
(b) This source category is focused on upstream supply. It does not cover:
(1) Storage of CO
(2) Use of CO
(3) Transportation or distribution of CO
(4) Purification, compression, or processing of CO
(5) On-site use of CO
(c) This source category does not include CO
Any supplier of CO
(a) Mass of CO
(b) Mass of CO
(c) Mass of CO
(d) Mass of CO
(a) Except as allowed in paragraph (b) of this section, calculate the annual mass of CO
(1) For each mass flow meter, you shall calculate quarterly the mass of CO
(2) For each volumetric flow meter, you shall calculate quarterly the mass of CO
(3) To aggregate data, use either Equation PP-3a or PP-3b in this paragraph, as appropriate.
(i) For facilities with production process units or production wells that capture or extract a CO
(ii) For facilities with production process units that capture a CO
(b) As an alternative to paragraphs (a)(1) through (3) of this section for CO
(1) For each CO
(2) For each CO
(3) To aggregate data, sum the mass of CO
(c) Importers or exporters that import or export CO
(a)
(i) If the CO
(A) For reporters following the procedures in § 98.423(a)(3)(i), you must locate the flow meter(s) after the point of segregation.
(B) For reporters following the procedures in paragraph (a)(3)(ii) of § 98.423, you must locate the main flow meter(s) on the captured CO
(ii) Reporters that have a mass flow meter or volumetric flow meter installed to measure the flow of a CO
(iii) Reporters that do not have a mass flow meter or volumetric flow meter installed to measure the flow of the CO
(2) Reporters following the procedures in paragraph (b) of § 98.423 shall determine quantity in accordance with this paragraph.
(i) Reporters that supply CO
(ii) Reporters that supply CO
(3) Importers or exporters that import or export CO
(4) All flow meters, scales, and load cells used to measure quantities that are reported in § 98.423 of this subpart shall be operated and calibrated according to the following procedure:
(i) You shall use an appropriate standard method published by a consensus-based standards organization if such a method exists. Consensus-based standards organizations include, but are not limited to, the following: ASTM International, the American National Standards Institute (ANSI), the American Gas Association (AGA), the American Society of Mechanical Engineers (ASME), the American Petroleum Institute (API), and the North American Energy Standards Board (NAESB).
(ii) Where no appropriate standard method developed by a consensus-based standards organization exists, you shall follow industry standard practices.
(iii) You must ensure that any flow meter calibrations performed are NIST traceable.
(5) Reporters using Equation PP-2 of this subpart and measuring CO
(i) You may use a method published by a consensus-based standards organization. Consensus-based standards organizations include, but are not limited to, the following: ASTM International (100 Barr Harbor Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959, (800) 262-1373,
(ii) You may follow an industry standard method.
(b)
(2) Methods to measure the composition of the CO
(c) You shall convert the density of the CO
(a) Whenever the quality assurance procedures in § 98.424(a)(1) of this subpart cannot be followed to measure quarterly mass flow or volumetric flow of CO
(1) A quarterly CO
(2) A quarterly CO
(3) If a mass or volumetric flow meter is installed to measure the CO
(4) The mass or volumetric flow used for purposes of product tracking and billing according to the reporter's established procedures may be substituted for any period during which measurement equipment is inoperable.
(b) Whenever the quality assurance procedures in § 98.424(b) cannot be followed to determine concentration of the CO
(1) A quarterly concentration value that is missing may be substituted with a quarterly value measured during another quarter of the current reporting year.
(2) A quarterly concentration value that is missing may be substituted with a quarterly value measured during the same quarter from the previous reporting year.
(3) The concentration used for purposes of product tracking and billing according to the reporter's established procedures may be substituted for any quarterly value.
(c) Missing data on density of the CO
(d) Whenever the quality assurance procedures in § 98.424(a)(2) of this subpart cannot be followed to measure quarterly quantity of CO
(1) A quarterly quantity of CO
(2) A quarterly quantity of CO
(3) The quarterly quantity of CO
In addition to the information required by § 98.3(c) of subpart A of this part, the annual report shall contain the following information, as applicable:
(a) If you use Equation PP-1 of this subpart, report the following information for each mass flow meter or CO
(1) Annual mass in metric tons of CO
(2) Quarterly mass in metric tons of CO
(3) Quarterly concentration of the CO
(4) The standard used to measure CO
(5) The location of the flow meter in your process chain in relation to the points of CO
(b) If you use Equation PP-2 of this subpart, report the following information for each volumetric flow meter or CO
(1) Annual mass in metric tons of CO
(2) Quarterly volume in standard cubic meters of CO
(3) Quarterly concentration of the CO
(4) Report density as follows:
(i) Quarterly density of the CO
(ii) Quarterly density of CO
(5) The method used to measure density.
(6) The standard used to measure CO
(7) The location of the flow meter in your process chain in relation to the points of CO
(c) For the aggregated annual mass of CO
(1) If you use Equation PP-3a of this subpart, report the annual CO
(2) If you use Equation PP-3b of this subpart, report:
(i) The total annual CO
(ii) The total annual CO
(iii) The total annual CO
(iv) The location of each flow meter in relation to the point of segregation.
(d) If you use Equation PP-4 of this subpart, report at the corporate level the annual mass of CO
(e) Each reporter shall report the following information:
(1) The type of equipment used to measure the total flow of the CO
(2) The standard used to operate and calibrate the equipment reported in (e)(1) of this section.
(3) The number of days in the reporting year for which substitute data procedures were used for the following purpose:
(i) To measure quantity.
(ii) To measure concentration.
(iii) To measure density.
(f) Report the aggregated annual quantity of CO
(1) Food and beverage.
(2) Industrial and municipal water/wastewater treatment.
(3) Metal fabrication, including welding and cutting.
(4) Greenhouse uses for plant growth.
(5) Fumigants (e.g., grain storage) and herbicides.
(6) Pulp and paper.
(7) Cleaning and solvent use.
(8) Fire fighting.
(9) Transportation and storage of explosives.
(10) Injection of carbon dioxide for enhanced oil and natural gas recovery that is covered by subpart UU of this part.
(11) Geologic sequestration of carbon dioxide that is covered by subpart RR of this part.
(12) Research and development.
(13) Other.
(g) Each production process unit that captures a CO
(h) If you capture a CO
(1) Report the facility identification number associated with the annual GHG report for the subpart D facility;
(2) Report each facility identification number associated with the annual GHG reports for each subpart RR facility to which CO
(3) Report the annual quantity of CO
In addition to the records required by § 98.3(g) of subpart A of this part, you must retain the records specified in paragraphs (a) through (c) of this section, as applicable.
(a) The owner or operator of a facility containing production process units must retain quarterly records of captured or transferred CO
(b) The owner or operator of a CO
(c) Importers or exporters of CO
(d) Facilities subject to § 98.426(h) must retain records of CO
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
75 FR 74856, Dec. 1, 2010, unless otherwise noted.
(a) The source category, importers and exporters of fluorinated GHGs contained in pre-charged equipment or closed-cell foams, consists of any entity that imports or exports pre-charged equipment that contains a fluorinated GHG, and any entity that imports or exports closed-cell foams that contain a fluorinated GHG.
Any importer or exporter of fluorinated GHGs contained in pre-charged equipment or closed-cell foams who meets the requirements of § 98.2(a)(4) must report each fluorinated GHG contained in the imported or exported pre-charged equipment or closed-cell foams.
You must report the mass of each fluorinated GHG contained in pre-charged equipment or closed-cell foams that you import or export during the calendar year. For imports and exports of closed-cell foams where you do not know the identity and mass of the fluorinated GHG, you must report the mass of fluorinated GHG in CO
(a) The total mass of each fluorinated GHG imported and exported inside equipment or foams must be estimated using Equation QQ-1 of this section:
(b) When the identity and mass of fluorinated GHGs in a closed-cell foam is unknown to the importer or exporter, the total mass in CO
(a) For calendar year 2011 monitoring, you may follow the provisions of § 98.3(d)(1) through (d)(2) for best available monitoring methods rather than follow the monitoring requirements of this section. For purposes of this subpart, any reference in § 98.3(d)(1) through (d)(2) to the year 2010 means 2011, to March 31 means June 30, and to April 1 means July 1. Any reference to the effective date or date of promulgation in § 98.3(d)(1) through (d)(2) means February 28, 2011.
(b) The inputs to the annual submission must be reviewed against the import or export transaction records to ensure that the information submitted to EPA is being accurately transcribed as the correct chemical or blend in the correct pre-charged equipment or closed-cell foam in the correct quantities and units.
Procedures for estimating missing data are not provided for importers and exporters of fluorinated GHGs contained in pre-charged equipment or closed-cell foams. A complete record of all measured parameters used in tracking fluorinated GHGs contained in pre-charged equipment or closed-cell foams is required.
(a) Each importer of fluorinated GHGs contained in pre-charged equipment or closed-cell foams must submit an annual report that summarizes its imports at the corporate level, except for transshipments, as specified:
(1) Total mass in metric tons of each fluorinated GHG imported in pre-charged equipment or closed-cell foams.
(2) For each type of pre-charged equipment with a unique combination of charge size and charge type, the identity of the fluorinated GHG used as a refrigerant or electrical insulator, charge size (holding charge, if applicable), and number imported.
(3) For closed-cell foams that are imported inside of equipment, the identity of the fluorinated GHG contained in the foam, the mass of the fluorinated GHG contained in the foam
(4) For closed cell-foams that are not imported inside of equipment, the identity of the fluorinated GHG in the foam, the density of the fluorinated GHG in the foam (kg fluorinated GHG/cubic foot), and the volume of foam imported (cubic feet) for each type of closed-cell foam with a unique combination of fluorinated GHG density and identity.
(5) Dates on which the pre-charged equipment or closed-cell foams were imported.
(6) If the importer does not know the identity and mass of the fluorinated GHGs within the closed-cell foam, the importer must report the following:
(i) Total mass in metric tons of CO
(ii) For closed-cell foams that are imported inside of equipment, the mass of the fluorinated GHGs in CO
(iii) For closed-cell foams that are not imported inside of equipment, the density in CO
(iv) Dates on which the closed-cell foams were imported.
(v) Name of the foam manufacturer for each type of closed-cell foam where the identity and mass of the fluorinated GHGs is unknown.
(vi) Certification that the importer was unable to obtain information on the identity and mass of the fluorinated GHGs within the closed-cell foam from the closed-cell foam manufacturer or manufacturers.
(b) Each exporter of fluorinated GHGs contained in pre-charged equipment or closed-cell foams must submit an annual report that summarizes its exports at the corporate level, except for transshipments, as specified:
(1) Total mass in metric tons of each fluorinated GHG exported in pre-charged equipment or closed-cell foams.
(2) For each type of pre-charged equipment with a unique combination of charge size and charge type, the identity of the fluorinated GHG used as a refrigerant or electrical insulator, charge size (including holding charge, if applicable), and number exported.
(3) For closed-cell foams that are exported inside of equipment, the identity of the fluorinated GHG contained in the foam in each piece of equipment, the mass of the fluorinated GHG contained in the foam in each piece of equipment, and the number of pieces of equipment exported with each unique combination of mass and identity of fluorinated GHG within the closed-cell foams.
(4) For closed-cell foams that are not exported inside of equipment, the identity of the fluorinated GHG in the foam, the density of the fluorinated GHG in the foam (kg fluorinated GHG/cubic foot), and the volume of foam exported (cubic feet) for each type of closed-cell foam with a unique combination of fluorinated GHG density and identity.
(5) Dates on which the pre-charged equipment or closed-cell foams were exported.
(6) If the exporter does not know the identity and mass of the fluorinated GHG within the closed-cell foam, the exporter must report the following:
(i) Total mass in metric tons of CO
(ii) For closed-cell foams that are exported inside of equipment, the mass of the fluorinated GHGs in CO
(iii) For closed-cell foams that are not exported inside of equipment, the density in CO
(iv) Dates on which the closed-cell foams were exported.
(v) Name of the foam manufacturer for each type of closed-cell foam where
(vi) Certification that the exporter was unable to obtain information on the identity and mass of the fluorinated GHGs within the closed-cell foam from the closed-cell foam manufacturer or manufacturers.
(a) In addition to the data required by § 98.3(g), importers of fluorinated GHGs in pre-charged equipment and closed-cell foams must retain the following records substantiating each of the imports that they report:
(1) A copy of the bill of lading for the import.
(2) The invoice for the import.
(3) The U.S. Customs entry form.
(4) Ports of entry through which the pre-charged equipment or closed-cell foams passed.
(5) Countries from which the pre-charged equipment or closed-cell foams were imported.
(6) For importers that report the mass of fluorinated GHGs within closed-cell foams on a CO
(b) In addition to the data required by § 98.3(g), exporters of fluorinated GHGs in pre-charged equipment and closed-cell foams must retain the following records substantiating each of the exports that they report:
(1) A copy of the bill of lading for the export and
(2) The invoice for the export.
(3) Ports of exit through which the pre-charged equipment or closed-cell foams passed.
(4) Countries to which the pre-charged equipment or closed-cell foams were exported.
(5) For exporters that report the mass of fluorinated GHGs within closed-cell foams on a CO
(c) For importers and exports of fluorinated GHGs inside pre-charged equipment and closed-cell foams, the GHG Monitoring Plans, as described in § 98.3(g)(5), must be completed by April 1, 2011.
(d) Persons who transship pre-charged equipment and closed-cell foams containing fluorinated GHGs must maintain records that indicated that the pre-charged equipment or foam originated in a foreign country and was destined for another foreign country and did not enter into commerce in the United States.
Except as provided in this section, all of the terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. If a conflict exists between a definition provided in this subpart and a definition provided in subpart A, the definition in this subpart must take precedence for the reporting requirements in this subpart.
75 FR 75078, Dec. 1, 2010, unless otherwise noted.
(a) The geologic sequestration of carbon dioxide (CO
(b) This source category includes all wells permitted as Class VI under the Underground Injection Control program.
(c) This source category does not include a well or group of wells where a CO
(1) The owner or operator injects the CO
(2) The well is permitted as Class VI under the Underground Injection Control program.
(d)
(1)
(2)
(i) The planned duration of CO
(ii) The planned annual CO
(iii) The research purposes of the project.
(iv) The source and type of funding for the project.
(v) The class and duration of Underground Injection Control permit or, for an offshore facility not subject to the Safe Drinking Water Act, a description
(3)
(i) The Administrator shall determine if a project meets the definition of research and development project within 60 days of receipt of the submission of a request for exemption. In making this determination, the Administrator shall take into account any information you submit demonstrating that the planned duration of CO
(ii) Any appeal of the Administrator's determination is subject to the provisions of part 78 of this chapter.
(iii) A project that the Administrator determines is not eligible for an exemption as a research and development project must submit a proposed MRV plan to EPA within 180 days of the Administrator's determination. You may request one extension of up to an additional 180 days in which to submit the proposed MRV plan.
(a) You must report under this subpart if any well or group of wells within your facility injects any amount of CO
(b)
(1)
(2)
(i) For wells permitted as Class VI under the Underground Injection Control program, a copy of the applicable Underground Injection Control program Director's authorization of site closure.
(ii) For all other wells, and as an alternative for wells permitted as Class VI under the Underground Injection Control program, a demonstration that current monitoring and model(s) show that the injected CO
(3)
You must report:
(a) Mass of CO
(b) Mass of CO
(c) Mass of CO
(d) Mass of CO
(e) Mass of CO
(f) Mass of CO
(g) Mass of CO
(h) Cumulative mass of CO
You must calculate the mass of CO
(a) You must calculate and report the annual mass of CO
(1) For a mass flow meter, you must calculate the total annual mass of CO
(2) For a volumetric flow meter, you must calculate the total annual mass of CO
(3) If you receive CO
(b) You must calculate and report the annual mass of CO
(1) If you are measuring the mass of contents in a container under the provisions of § 98.444(a)(2)(i), you must calculate the CO
(2) If you are measuring the volume of contents in a container under the provisions of § 98.444(a)(2)(ii), you must calculate the CO
(c) You must report the annual mass of CO
(1) If you use a mass flow meter to measure the flow of an injected CO
(2) If you use a volumetric flow meter to measure the flow of an injected CO
(3) To aggregate injection data for all wells covered under this subpart, you must sum the mass of all CO
(d) You must calculate the annual mass of CO
(1) For each gas-liquid separator for which flow is measured using a mass flow meter, you must calculate annually the total mass of CO
(2) For each gas-liquid separator for which flow is measured using a volumetric flow meter, you must calculate annually the total mass of CO
(3) To aggregate production data, you must sum the mass of all of the CO
(e) You must report the annual mass of CO
(f) You must report the annual mass of CO
(1) If you are actively producing oil or natural gas or if you are producing any other fluids, you must calculate the annual mass of CO
(2) If you are not actively producing oil or natural gas or any other fluids, you must calculate the annual mass of CO
(a)
(i) You may measure flow rate at the receiving custody transfer meter prior to any subsequent processing operations at the facility and collect the flow rate quarterly.
(ii) If you took ownership of the CO
(iii) If you inject CO
(2) Except as provided in paragraph (a)(4) of this section, you must determine the quarterly mass or volume of contents in all containers if you receive CO
(i) You may measure the mass of contents of containers summed quarterly using weigh bills, scales, or load cells.
(ii) You may determine the volume of the contents of containers summed quarterly.
(iii) If you took ownership of the CO
(3) Except as provided in paragraph (a)(4) of this section, you must determine a quarterly concentration of the CO
(i) You may sample the CO
(ii) If you took ownership of the CO
(iii) If you inject CO
(4) If the CO
(5) You must assume that the CO
(b)
(2) You must measure flow rate of CO
(3) You must sample the injected CO
(c)
(2) You must sample the produced gas stream at least once per quarter immediately upstream or downstream of the flow meter used to measure flow rate of that gas stream and measure the CO
(3) You must measure flow rate of gas produced with a flow meter and collect the flow rate quarterly.
(d)
(e)
(2) You must calibrate all flow meters used to measure quantities reported in § 98.446 according to the calibration and accuracy requirements in § 98.3(i).
(3) You must operate all measurement devices according to one of the following. You may use an appropriate standard method published by a consensus-based standards organization if such a method exists or an industry standard practice. Consensus-based standards organizations include, but are not limited to, the following: ASTM International, the American National Standards Institute (ANSI), the American Gas Association (AGA), the American Society of Mechanical Engineers (ASME), the American Petroleum Institute (API), and the North American Energy Standards Board (NAESB).
(4) You must ensure that any flow meter calibrations performed are National Institute of Standards and Technology (NIST) traceable.
(f)
(2) You must convert all measured volumes of CO
(3) For 2011, you may follow the provisions of § 98.3(d)(1) through (2) for best available monitoring methods only for parameters required by paragraphs (a) and (b) of § 98.443 rather than follow the monitoring requirements of paragraph (a) of this section. For purposes of this subpart, any reference to the year 2010 in § 98.3(d)(1) through (2) shall mean 2011.
A complete record of all measured parameters used in the GHG quantities calculations is required. Whenever the monitoring procedures cannot be followed, you must use the following missing data procedures:
(a) A quarterly flow rate of CO
(1) Another calculation methodology listed in § 98.444(a)(1) must be used if possible.
(2) If another method listed in § 98.444(a)(1) cannot be used, a quarterly flow rate value that is missing must be estimated using a representative flow rate value from the nearest previous time period.
(b) A quarterly mass or volume of contents in containers received that is missing must be estimated as follows:
(1) Another calculation methodology listed in § 98.444(a)(2) must be used if possible.
(2) If another method listed in § 98.444(a)(2) cannot be used, a quarterly mass or volume value that is missing must be estimated using a representative mass or volume value from the nearest previous time period.
(c) A quarterly CO
(1) Another calculation methodology listed in § 98.444(a)(3) must be used if possible.
(2) If another method listed in § 98.444(a)(3) cannot be used, a quarterly concentration value that is missing must be estimated using a representative concentration value from the nearest previous time period.
(d) A quarterly quantity of CO
(e) For any values associated with CO
(f) The quarterly quantity of CO
(g) You must estimate the mass of CO
(h) You must estimate other missing data as required by your approved MRV plan.
In addition to the information required by § 98.3(c), report the information listed in this section.
(a) If you receive CO
(1) The total net mass of CO
(2) If a volumetric flow meter is used to receive CO
(i) The volumetric flow through a receiving flow meter at standard conditions (in standard cubic meters) in each quarter.
(ii) The volumetric flow through a receiving flow meter that is redelivered to another facility without being injected into your well (in standard cubic meters) in each quarter.
(iii) The CO
(3) If a mass flow meter is used to receive CO
(i) The mass flow through a receiving flow meter (in metric tons) in each quarter.
(ii) The mass flow through a receiving flow meter that is redelivered to another facility without being injected into your well (in metric tons) in each quarter.
(iii) The CO
(4) If the CO
(5) The standard or method used to calculate each value in paragraphs (a)(2) through (a)(3) of this section.
(6) The number of times in the reporting year for which substitute data procedures were used to calculate values reported in paragraphs (a)(2) through (a)(3) of this section.
(7) Whether the flow meter is mass or volumetric.
(8) A numerical identifier for the flow meter.
(b) If you receive CO
(1) The mass (in metric tons) or volume at standard conditions (in standard cubic meters) of contents in containers received in each quarter.
(2) The concentration of CO
(3) The mass (in metric tons) or volume (in standard cubic meters) of contents in containers that is redelivered to another facility without being injected into your well in each quarter.
(4) The net mass of CO
(5) The standard or method used to calculate each value in paragraphs (b)(1), (b)(2), and (b)(3) of this section.
(6) The number of times in the reporting year for which substitute data procedures were used to calculate values reported in paragraphs (b)(1) and (b)(2) of this section.
(c) If you use more than one receiving flow meter, report the total net mass of CO
(d) The source of the CO
(1) CO
(2) Electric generating unit.
(3) Ethanol plant.
(4) Pulp and paper mill.
(5) Natural gas processing.
(6) Gasification operations.
(7) Other anthropogenic source.
(8) Discontinued enhanced oil and gas recovery project.
(9) Unknown.
(e) Report the date that you began collecting data for calculating total amount sequestered according to § 98.448(a)(7) of this subpart.
(f) Report the following. If the date specified in paragraph (e) of this section is during the reporting year for this annual report, report the following starting on the date specified in paragraph (e) of this section.
(1) For each injection flow meter (mass or volumetric), report:
(i) The mass of CO
(ii) The CO
(iii) If a volumetric flow meter is used, the volumetric flow rate at standard conditions (in standard cubic meters) in each quarter.
(iv) If a mass flow meter is used, the mass flow rate (in metric tons) in each quarter.
(v) A numerical identifier for the flow meter.
(vi) Whether the flow meter is mass or volumetric.
(vii) The standard used to calculate each value in paragraphs (f)(1)(ii) through (f)(1)(iv) of this section.
(viii) The number of times in the reporting year for which substitute data procedures were used to calculate values reported in paragraphs (f)(1)(ii) through (f)(1)(iv) of this section.
(ix) The location of the flow meter.
(2) The total CO
(3) For CO
(i) The mass of CO
(ii) The mass of CO
(4) For each separator flow meter (mass or volumetric), report:
(i) CO
(ii) CO
(iii) If a volumetric flow meter is used, volumetric flow rate at standard conditions (standard cubic meters) in each quarter.
(iv) If a mass flow meter, mass flow rate (metric tons) in each quarter.
(v) A numerical identifier for the flow meter.
(vi) Whether the flow meter is mass or volumetric.
(vii) The standard used to calculate each value in paragraphs (f)(4)(ii) through (f)(4)(iv) of this section.
(viii) The number of times in the reporting year for which substitute data procedures were used to calculate values reported in paragraphs (f)(4)(ii) through (f)(4)(iv) of this section.
(5) The entrained CO
(6) Annual CO
(7) For each leakage pathway through which CO
(i) A numerical identifier for the leakage pathway.
(ii) The CO
(8) Annual CO
(9) Annual CO
(10) Cumulative mass of CO
(11) Date that the most recent MRV plan was approved by EPA and the MRV plan approval number that was issued by EPA.
(12) An annual monitoring report that contains the following components:
(i) A narrative history of the monitoring efforts conducted over the previous calendar year, including a listing of all monitoring equipment that was operated, its period of operation, and any relevant tests or surveys that were conducted.
(ii) A description of any changes to the monitoring program that you concluded were not material changes warranting submission of a revised MRV plan under § 98.448(d).
(iii) A narrative history of any monitoring anomalies that were detected in the previous calendar year and how they were investigated and resolved.
(iv) A description of any surface leakages of CO
(13) If a well is permitted under the Underground Injection Control program, for each injection well, report:
(i) The well identification number used for the Underground Injection Control permit.
(ii) The Underground Injection Control permit class.
(14) If an offshore well is not subject to the Safe Drinking Water Act, for each injection well, report any well identification number and any identification number used for the legal instrument authorizing geologic sequestration.
(a) You must follow the record retention requirements specified by § 98.3(g). In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a)(1) through (7) of this section, as applicable. You must retain all required records for at least 3 years.
(1) Quarterly records of CO
(2) Quarterly records of produced CO
(3) Quarterly records of injected CO
(4) Annual records of information used to calculate the CO
(5) Annual records of information used to calculate the CO
(6) Annual records of information used to calculate the CO
(7) Any other records as specified for retention in your EPA-approved MRV plan.
(b) You must complete your monitoring plans, as described in § 98.3(g)(5), by April 1 of the year you begin collecting data.
(a)
(1) Delineation of the maximum monitoring area and the active monitoring areas. The first period for your active monitoring area will begin from the date determined in your MRV plan through the date at which the plan calls for the first expansion of the monitoring area. The length of each monitoring period can be any time interval chosen by you that is greater than 1 year.
(2) Identification of potential surface leakage pathways for CO
(3) A strategy for detecting and quantifying any surface leakage of CO
(4) A strategy for establishing the expected baselines for monitoring CO
(5) A summary of the considerations you intend to use to calculate site-specific variables for the mass balance equation. This includes, but is not limited to, considerations for calculating CO
(6) If a well is permitted under the Underground Injection Control program, for each injection well, report the well identification number used for the Underground Injection Control permit and the Underground Injection Control permit class. If the well is not yet permitted, and you have applied for an Underground Injection Control permit, report the well identification numbers in the permit application. If an offshore well is not subject to the Safe Drinking Water Act, for each injection well, report any well identification number and any identification number used for the legal instrument authorizing geologic sequestration. If you are submitting your Underground Injection Control permit application as part of your proposed MRV plan, you must notify EPA when the permit has been approved. If you are an offshore facility not subject to the Safe Drinking Water Act, and are submitting your application for the legal instrument authorizing geologic sequestration as part of your proposed MRV plan, you must notify EPA when the legal instrument authorizing geologic sequestration has been approved.
(7) Proposed date to begin collecting data for calculating total amount sequestered according to equation RR-11 or RR-12 of this subpart. This date must be after expected baselines as required by paragraph (a)(4) of this section are established and the leakage detection and quantification strategy as required by paragraph (a)(3) of this section is implemented in the initial AMA.
(b)
(1) You must submit a proposed MRV plan to EPA by June 30, 2011 if you were issued a final Underground Injection Control permit authorizing the injection of CO
(2) You must submit a proposed MRV plan to EPA within 180 days of receiving a final Underground Injection Control permit authorizing the injection of CO
(3) If you are injecting a CO
(4) If EPA determines that your proposed MRV plan is incomplete, you must submit an updated MRV plan within 45 days of EPA notification, unless otherwise specified by EPA.
(c)
(d)
(1) A material change was made to monitoring and/or operational parameters that was not anticipated in the original MRV plan. Examples of material changes include but are not limited to: Large changes in the volume of CO
(2) A change in the permit class of your Underground Injection Control permit.
(3) If you are notified by EPA of substantive errors in your MRV plan or monitoring report.
(4) You choose to revise your MRV plan for any other reason in any reporting year.
(e)
(f)
(g)
Except as provided below, all terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
(1) The area projected to contain the free phase CO
(2) The area projected to contain the free phase CO
75 FR 74859, Dec. 1, 2010, unless otherwise noted.
The electrical equipment manufacturing or refurbishment category consists of processes that manufacture or refurbish gas-insulated substations, circuit breakers, other switchgear, gas-insulated lines, or power transformers (including gas-containing components of such equipment) containing sulfur-hexafluoride (SF
You must report GHG emissions under this subpart if your facility contains an electrical equipment manufacturing or refurbishing process and the facility meets the requirements of § 98.2(a)(1). Electrical equipment manufacturing and refurbishing facilities covered by this rule are those that have total annual purchases of SF
(a) You must report SF
(b) You must report CO
(a) For each electrical equipment manufacturer or refurbisher, estimate the annual SF
(b) Use the mass-balance method in paragraph (a) of this section to estimate emissions of PFCs associated with the manufacture or refurbishment of power transformers, substituting the relevant PFC(s) for SF
(c) Estimate the disbursements of SF
(d) Estimate the mass of SF
(e) If the mass of SF
(f) If the mass of SF
(g) Estimate the mass of SF
(h) If the mass of SF
(1) Determine the equipment's actual nameplate capacity, by measuring the nameplate capacities of a representative sample of each make and model and calculating the mean value for each make and model as specified at § 98.454(f).
(2) If equipment is shipped with a partial charge, calculate the partial shipping charge by multiplying the nameplate capacity of the equipment by the ratio of the densities of the partial charge to the full charge.
(i) Estimate the annual SF
(a) For calendar year 2011 monitoring, you may follow the provisions of § 98.3(d)(1) through (d)(2) for best available monitoring methods rather than follow the monitoring requirements of this section. For purposes of this subpart, any reference in § 98.3(d)(1) through (d)(2) to 2010 means 2011, March 31 means June 30, and April 1 means July 1. Any reference to the effective date in § 98.3(d)(1) through (d)(2) means February 28, 2011.
(b) Ensure that all the quantities required by the equations of this subpart have been measured using either flowmeters with an accuracy and precision of ±1 percent of full scale or better or scales with an accuracy and precision of ±1 percent of the filled weight (gas plus tare) of the containers of SF
(c) All flow meters, weigh scales, and combinations of volumetric and density measures that are used to measure or calculate quantities under this subpart must be calibrated using calibration procedures specified by the flowmeter, scale, volumetric or density measure equipment manufacturer. Calibration must be performed prior to the first reporting year. After the initial calibration, recalibration must be performed at the minimum frequency specified by the manufacturer.
(d) For purposes of Equations SS-5 of this subpart, the emission factor for the valve-hose combination (EF
(e) Electrical equipment manufacturers and refurbishers must account for SF
(f) If the mass of SF
(g) Ensure the following QA/QC methods are employed throughout the year:
(1) Procedures are in place and followed to track and weigh all cylinders or other containers at the beginning and end of the year.
(h) You must adhere to the following QA/QC methods for reviewing the completeness and accuracy of reporting:
(1) Review inputs to Equation SS-1 of this subpart to ensure inputs and outputs to the company's system are included.
(2) Do not enter negative inputs and confirm that negative emissions are not calculated. However, the decrease in SF
(3) Ensure that beginning-of-year inventory matches end-of-year inventory from the previous year.
(4) Ensure that in addition to SF
A complete record of all measured parameters used in the GHG emissions calculations is required. Replace missing data, if needed, based on data from similar manufacturing operations, and from similar equipment testing and decommissioning activities for which data are available.
In addition to the information required by § 98.3(c), each annual report must contain the following information for each chemical at the facility level:
(a) Pounds of SF
(b) Pounds of SF
(c) Pounds of SF
(d) Pounds of SF
(e) Pounds of SF
(f) Pounds of SF
(g) Pounds of SF
(h) Pounds of SF
(i) Pounds of SF
(j) Pounds of SF
(k) The nameplate capacity of the equipment, in pounds, delivered to customers with SF
(l) A description of the engineering methods and calculations used to determine emissions from hoses or other flow lines that connect the container to the equipment that is being filled.
(m) The values for EF
(n) The total number of fill operations for each hose and valve combination, or, F
(o) If the mass of SF
(p) If the mass of SF
(q) Pounds of SF
(r) Pounds of SF
(s) The nameplate capacity of the equipment, in pounds, installed at off-site electric power transmission or distribution locations used to determine emissions from installation, or N
(t) For any missing data, you must report the reason the data were missing, the parameters for which the data were missing, the substitute parameters used to estimate emissions in their absence, and the quantity of emissions thereby estimated.
In addition to the information required by § 98.3(g), you must retain the following records:
(a) All information reported and listed in § 98.456.
(b) Accuracy certifications and calibration records for all scales and monitoring equipment, including the method or manufacturer's specification used for calibration.
(c) Certifications of the quantity of gas, in pounds, charged into equipment at the electrical equipment manufacturer or refurbishment facility as well as the actual quantity of gas, in pounds, charged into equipment at installation.
(d) Check-out and weigh-in sheets and procedures for cylinders.
(e) Residual gas amounts, in pounds, in cylinders sent back to suppliers.
(f) Invoices for gas purchases and sales.
(g) GHG Monitoring Plans, as described in § 98.3(g)(5), must be completed by April 1, 2011.
All terms used in this subpart have the same meaning given in the CAA and subpart A of this part.
75 FR 39773, July 12, 2010, unless otherwise noted.
(a) This source category applies to industrial waste landfills that accepted waste on or after January 1, 1980, and that are located at a facility whose total landfill design capacity is greater than or equal to 300,000 metric tons.
(b)
(c) This source category does not include:
(1) Construction and demolition waste landfills.
(2) Industrial waste landfills that only receive one or more of the following inert waste materials:
(i) Coal combustion or incinerator ash (
(ii) Cement kiln dust.
(iii) Rocks and/or soil from excavation and construction and similar activities.
(iv) Glass.
(v) Non-chemically bound sand (
(vii) Clay, gypsum, or pottery cull.
(viii) Bricks, mortar, or cement.
(ix) Furnace slag.
(x) Materials used as refractory (
(xi) Plastics (
(xii) Other waste material that has a volatile solids concentration of 0.5 weight percent (on a dry basis) or less.
(xiii) Other waste material that has a DOC value of 0.3 weight percent (on a wet basis) or less. DOC value must be determined using a 60-day anaerobic biodegradation test procedure identified in § 98.464(b)(4)(i).
(d) This source category consists of the following sources at industrial waste landfills: Landfills, gas collection systems at landfills, and destruction devices for landfill gases (including flares).
You must report GHG emissions under this subpart if your facility contains an industrial waste landfill meeting the criteria in § 98.460 and the facility meets the requirements of § 98.2(a)(2). For the purposes of § 98.2(a)(2), the emissions from the industrial waste landfill are to be determined using the methane generation corrected for oxidation as determined using Equation TT-6 of this subpart times the global warming potential for methane in Table A-1 of subpart A of this part.
(a) You must report CH
(b) You must report CH
(c) You must report under subpart C of this part (General Stationary Fuel Combustion Sources) the emissions of CO
(a) For each industrial waste landfill subject to the reporting requirements of this subpart, calculate annual modeled CH
(1) Calculate annual modeled CH
(2)
(i) Determine the quantity of waste (in metric tons as received,
(A) Direct mass measurements.
(B) Direct volume measurements multiplied by waste stream density determined from periodic density measurement data or process knowledge.
(C) Mass balance procedures, determining the mass of waste as the difference between the mass of the process inputs and the mass of the process outputs.
(D) The number of loads (
(ii) Determine the historical disposal quantities for landfills using the Waste Disposal Factor approach in paragraphs (a)(2)(ii)(A) and (B) of this section when historical production or processing data are available. If production or processing data are available for a given year, you must use Equation TT-3 of this section for that year. Determine historical disposal quantities using the method specified in paragraph (a)(2)(ii)(C) of this section when historical production or processing data are not available, and for waste streams received from an off-site facility when historical disposal quantities cannot be determined using the methods specified in paragraph (a)(2)(i) of this section.
(A)
(B)
(C) For any year in which historic production or processing data are not available such that historic waste quantities cannot be estimated using Equation TT-3 of this section, calculate an average annual bulk waste disposal quantity using either Equation TT-4a of this section when data are available consecutively for the most recent disposal years or Equation TT-4b of this section when data are available for sporadic (non-consecutive) years.
(3)
(i) For the first year in which GHG emissions from this industrial waste landfill must be reported, determine the DOC
(ii) For subsequent years (after the first year in which GHG emissions from this industrial waste landfill must be reported), either use the DOC
(iii) If DOC
(iv) For historical years for which DOC
(A) For years in which waste stream-specific disposal quantities are determined (as required in paragraphs (a)(2) (ii)(A) and (B) of this section), calculate the average DOC value for a given waste stream as the arithmetic average of all DOC measurements of that waste stream that follow the methods provided in § 98.464(b), including any measurement values for years prior to the first reporting year and the four measurement values required in the first reporting year. Use the resulting waste-specific average DOC value for all applicable years (
(B) For years for which bulk waste disposal quantities are determined according to paragraphs (a)(2)(ii)(C) of this section, calculate the weighted average bulk DOC value according to the following: Calculate the average DOC value for each waste stream as the arithmetic average of all DOC measurements of that waste stream that follows the methods provided in § 98.464(b) (generally, this will include only the DOC values determined in the first year in which GHG emissions from this industrial waste landfill must be reported); calculate the average annual disposal quantity for each waste stream as the arithmetic average of the annual disposal quantities for each year in which waste stream-specific disposal quantities have been determined; and calculate the bulk waste DOC value using Equation TT-5 of this section. Use the bulk waste DOC value as DOC
(b) For each landfill, calculate CH
(1) For each landfill, calculate CH
(2) For landfills that do not have landfill gas collection systems operating during the reporting year, the CH
(3) For landfills with landfill gas collection systems in operation during any portion of the reporting year, perform all of the calculations specified in paragraphs (b)(3)(i) through (iv) of this section.
(i) Calculate the quantity of CH
(ii) Calculate CH
(iii) Calculate CH
(iv) Calculate CH
(a) For calendar year 2011 monitoring, the facility may submit a request to the Administrator to use one or more best available monitoring methods as listed in § 98.3(d)(1)(i) through (iv). The request must be submitted no later than October 12, 2010 and must contain the information in § 98.3(d)(2)(ii). To obtain approval, the request must demonstrate to the Administrator's satisfaction that it is not reasonably feasible to acquire, install, and operate a required piece of monitoring equipment by January 1, 2011. The use of best available monitoring methods will not be approved beyond December 31, 2011.
(b) For each waste stream placed in the landfill during the reporting year for which you choose to determine volatile solids concentration and/or a waste stream-specific DOC
(1) Develop and follow a sampling plan to collect a representative sample (in terms of composition and moisture content) of each waste stream placed in the landfill for which testing is elected.
(2) Determine the percent total solids and the percent volatile solids of each sample following Standard Method 2540G “Total, Fixed, and Volatile Solids in Solid and Semisolid Samples” (incorporated by reference;
(3) For the purposes of § 98.460(c)(2)(xii), the volatile solids concentration (weight percent on a dry basis) is the percent volatile solids determined using Standard Method 2540G “Total, Fixed, and Volatile Solids in Solid and Semisolid Samples” (incorporated by reference; see § 98.7).
(4) Determine DOC value of a waste stream by either using at least a 60-day anaerobic biodegradation test as specified in paragraph (b)(4)(i) of this section or by estimating the DOC value based on the total and volatile solids measurements as specified in paragraph (b)(4)(ii) of this section.
(i) Perform an anaerobic biodegradation test and determine the DOC value of a waste stream following the procedures and requirements in paragraphs (b)(4)(i)(A) through (E) of this section.
(A) You may use the procedures published by a consensus-based standards organization to conduct a minimum of a 60-day anaerobic biodegradation test. Consensus-based standards organizations include, but are not limited to, the following: ASTM International (100 Barr Harbor Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959, (800) 262-1373,
(B) Use a minimum of four samples: Two waste stream samples, a control sample using a known substrate (such as ethanol), and a digester sludge blank sample. Each waste stream sample must be appropriately ground to ensure the waste material is fully exposed to the anaerobic digester sludge.
(C) Determine the net mass of carbon degraded in the control sample as the difference in the results of the control sample and the digester sludge blank sample. Determine the net mass of carbon degraded in each waste stream sample as the difference in the results of each waste stream sample and the digester sludge blank sample.
(D) Determine the fraction of carbon degraded in the control sample as the net mass of carbon degraded in the control sample divided by the mass of carbon added via the substrate material in the control sample. If less than 50 percent of the theoretical mass of carbon in the control sample is degraded, the test run is invalid.
(E) Determine the DOC of each waste sample using Equation TT-7 of this section. If the DOC values for the two waste stream samples differ by more than 20 percent, the test run is invalid. The DOC of the waste stream is determined as the average DOC value of the two waste stream samples determined during a valid test.
(ii) Calculate the waste stream-specific DOC
(c) For each waste stream that was historically managed in the landfill for which you choose to determine volatile solids concentration and/or a waste stream-specific DOC
(1) If you can identify a similar waste stream to the waste stream that was historically managed in the landfill, you must determine the volatile solids
(2) If you cannot identify a similar waste stream to the waste stream that was historically managed in the landfill, you may determine the volatile solids concentration or DOC
(d) For landfills with gas collection systems, operate, maintain, and calibrate a gas composition monitor capable of measuring the concentration of CH
(e) For landfills with gas collection systems, install, operate, maintain, and calibrate a gas flow meter capable of measuring the volumetric flow rate of the recovered landfill gas according to the requirements specified at § 98.344(c).
(f) For landfills with gas collection systems, all temperature, pressure, and if applicable, moisture content monitors must be calibrated using the procedures and frequencies specified by the manufacturer.
(g) For landfills electing to measure the fraction by volume of CH
(1) Use a gas composition monitor capable of measuring the concentration of CH
(2) Use Equation TT-9 of this section to correct the measured CH
(h) The facility shall document the procedures used to ensure the accuracy of the estimates of disposal quantities and, if the industrial waste landfill has a gas collection system, gas flow rate, gas composition, temperature, pressure, and moisture content measurements. These procedures include, but are not limited to, calibration of weighing equipment, fuel flow meters, and other measurement devices. The estimated accuracy of measurements made with these devices shall also be recorded, and the technical basis for these estimates shall be provided.
(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 (
(b) For industrial waste landfills with gas collection systems, follow the procedures for estimating missing data specified in § 98.345(a) and (b).
In addition to the information required by § 98.3(c), each annual report must contain the following information for each landfill.
(a) Report the following general landfill information:
(1) A classification of the landfill as “open” (actively received waste in the reporting year) or “closed” (no longer receiving waste).
(2) The year in which the landfill first started accepting waste for disposal.
(3) The last year the landfill accepted waste (for open landfills, enter the estimated year of landfill closure).
(4) The capacity (in metric tons) of the landfill.
(5) An indication of whether leachate recirculation is used during the reporting year and its typical frequency of use over the past 10 years (
(b) Report the following waste characterization and modeling information:
(1) The number of waste steams (including “Other Industrial Solid Waste (not otherwise listed)” and “Inerts”) for which Equation TT-1 of this subpart is used to calculate modeled CH
(2) A description of each waste stream (including the types of materials in each waste stream) for which Equation TT-1 of this subpart is used to calculate modeled CH
(3) The fraction of CH
(4) The methane correction factor (MCF) value used in the calculations. If an MCF value other than the default of 1 is used, provide a description of the aeration system, including aeration blower capacity, the fraction of the landfill containing waste affected by the aeration, the total number of hours during the year the aeration blower was operated, and other factors used as a basis for the selected MCF value.
(5) For each waste stream, the decay rate (k) value used in the calculations.
(c) Report the following historical waste information:
(1) [Reserved]
(2) For each waste stream identified in paragraph (b) of this section, the method(s) for estimating historical waste disposal quantities and the range of years for which each method applies.
(3) For each waste stream identified in paragraph (b) of this section for which Equation TT-2 of this subpart is used, provide:
(i) [Reserved]
(ii) The year of the data used in Equation TT-2 of § 98.463 for the waste disposal quantity and production quantity, for each year used in Equation TT-2 to calculate the average waste disposal factor (WDF).
(iii) [Reserved]
(4) If Equation TT-4a of this subpart is used, provide:
(i) The value of landfill capacity (LFC).
(ii) YrData.
(iii) YrOpen.
(5) If Equation TT-4b of this subpart is used, provide:
(i) WIP (i.e., the quantity of waste in-place at the start of the reporting year from design drawings or engineering estimates (metric tons) or, for closed landfills for which waste in-place quantities are not available, the landfill's design capacity).
(ii) The cumulative quantity of waste placed in the landfill for the years for which disposal quantities are available from company record or from Equation TT-3 of this part.
(iii) YrLast.
(iv) YrOpen.
(v) NYrData.
(d) For each year of landfilling starting with the “Start Year” (S) and each year thereafter up to the current reporting year, report the following information:
(1) The calendar year for which the following data elements apply.
(2) The quantity of waste (W
(3) For each waste stream, the degradable organic carbon (DOC
(e) Report the following information describing the landfill cover material:
(1) The type of cover material used (as either organic cover, clay cover, sand cover, or other soil mixtures).
(2) For each type of cover material used, the surface area (in square meters) at the start of the reporting year for the landfill sections that contain waste and that are associated with the selected cover type.
(f) The modeled annual methane generation (G
(g) For landfills without gas collection systems, provide:
(1) The annual methane emissions (
(2) An indication of whether passive vents and/or passive flares (vents or flares that are not considered part of the gas collection system as defined in § 98.6) are present at this landfill.
(h) For landfills with gas collection systems, in addition to the reporting requirements in paragraphs (a) through (f) of this section, provide:
(1) The annual methane generation, adjusted for oxidation, calculated using Equation TT-6 of this subpart, reported in metric tons CH
(2) The oxidation factor used in Equation TT-6 of this subpart.
(3) All information required under 40 CFR 98.346(i)(1) through (7) and 40 CFR 98.346(i)(9) through (12).
(a) The calibration records for all monitoring equipment, including the method or manufacturer's specification used for calibration, and all measurement data used for the purposes of § 98.460(c)(2)(xii) or (xiii) or used to determine waste stream-specific DOC
(b)
(1) Quantity of each product produced or feedstock entering the process or facility per waste stream per year, from measurement data and/or other company records. You must use the same basis for all years in the calculation (i.e., based on production or based on quantity of feedstock) (metric tons) (Equation TT-2 of § 98.463).
(2) [Reserved]
Except as provided below, all terms used in this subpart have the same meaning given in the CAA and subpart A of this part.
75 FR 75086, Dec. 1, 2010, unless otherwise noted.
(a) The injection of carbon dioxide (CO
(b) If you report under subpart RR of this part for a well or group of wells, you are not required to report under this subpart for that well or group of wells.
(c) A facility that is subject to this part only because it is subject to subpart UU of this part is not required to report emissions under subpart C of this part or any other subpart listed in § 98.2(a)(1) or (a)(2).
(a) You must report under this subpart if your facility injects any amount of CO
(b) For purposes of this subpart, any reference to CO
You must report the mass of CO
(a) You must calculate and report the annual mass of CO
(1) For a mass flow meter, you must calculate the total annual mass of CO
(2) For a volumetric flow meter, you must calculate the total annual mass of CO
(3) If you receive CO
(b) You must calculate and report the annual mass of CO
(1) If you are measuring the mass of contents in a container under the provisions of § 98.474(a)(2)(i), you must calculate the CO
(2) If you are measuring the volume of contents in a container under the provisions of § 98.474(a)(2)(ii), you must calculate the CO
(a)
(i) You may measure flow rate at the receiving custody transfer meter prior to any subsequent processing operations at the facility and collect the flow rate quarterly.
(ii) If you took ownership of the CO
(iii) If you inject CO
(2) You must determine the quarterly mass or volume of contents in all containers if you receive CO
(i) You may measure the mass of contents of containers summed quarterly using weigh bills, scales, or load cells.
(ii) You may determine the volume of the contents of containers summed quarterly.
(iii) If you took ownership of the CO
(3) You must determine a quarterly concentration of the CO
(i) You may sample the CO
(ii) If you took ownership of the CO
(iii) If you inject CO
(4) You must assume that the CO
(b)
(2) You must calibrate all flow meters used to measure quantities reported in § 98.476 according to the calibration and accuracy requirements in § 98.3(i).
(3) You must operate all measurement devices according to one of the following. You may use an appropriate
(4) You must ensure that any flow meter calibrations performed are National Institute of Standards and Technology (NIST) traceable.
(c)
(2) You must convert all measured volumes of CO
(3) For 2011, you may follow the provisions of § 98.3(d)(1) through (2) for best available monitoring methods rather than follow the monitoring requirements of this section. For purposes of this subpart, any reference to the year 2010 in § 98.3(d)(1) through (2) shall mean 2011.
A complete record of all measured parameters used in the GHG quantities calculations is required.
(a) Whenever the monitoring procedures for all facilities that used flow meters covered under this subpart cannot be followed to measure flow, the following missing data procedures must be followed:
(1) Another calculation methodology listed in § 98.474(a)(1) must be used if possible.
(2) If another method listed in § 98.474(a)(1) cannot be used, a quarterly flow rate value that is missing must be estimated using a representative flow rate value from the nearest previous time period.
(b) Whenever the monitoring procedures of this subpart cannot be followed to measure quarterly quantity of CO
(1) Another calculation methodology listed in § 98.474(a)(2) must be used if possible.
(2) If another method listed in § 98.474(a)(2) cannot be used, a quarterly mass or volume that is missing must be estimated using a representative mass or volume from the nearest previous time period.
(c) Whenever the monitoring procedures cannot be followed to measure CO
(1) Another calculation methodology listed in § 98.474(a)(3) must be used if possible.
(2) If another method listed in § 98.474(a)(3) cannot be used, a quarterly concentration value that is missing must be estimated using a representative concentration value from the nearest previous time period.
If you are subject to this part and report under this subpart, you are not required to report the information in § 98.3(c)(4) for this subpart. In addition to the information required by § 98.3(c)(1) through § 98.3(c)(3) and by § 98.3(c)(5) through § 98.3(c)(9), you must report the information listed in this section.
(a) If you receive CO
(1) The total net mass of CO
(2) If a volumetric flow meter is used to receive CO
(i) The volumetric flow through a receiving flow meter at standard conditions (in standard cubic meters) in each quarter.
(ii) The volumetric flow through a receiving flow meter that is redelivered
(iii) The CO
(3) If a mass flow meter is used to receive CO
(i) The mass flow through a receiving flow meter (in metric tons) in each quarter.
(ii) The mass flow through a receiving flow meter that is redelivered to another facility without being injected into your well (in metric tons) in each quarter.
(iii) The CO
(4) The standard or method used to calculate each value in paragraphs (a)(2) through (a)(3) of this section.
(5) The number of times in the reporting year for which substitute data procedures were used to calculate values reported in paragraphs (a)(2) through (a)(3) of this section.
(6) Whether the flow meter is mass or volumetric.
(b) If you receive CO
(1) The mass (in metric tons) or volume at standard conditions (in standard cubic meters) of contents in containers in each quarter.
(2) The concentration of CO
(3) The mass (in metric tons) or volume (in standard cubic meters) of contents in containers that is redelivered to another facility without being injected into your well in each quarter.
(4) The net total mass of CO
(5) The standard or method used to calculate each value in paragraphs (b)(1), (b)(2), and (b)(3) of this section.
(6) The number of times in the reporting year for which substitute data procedures were used to calculate values reported in paragraphs (b)(1) and (b)(2) of this section.
(c) If you use more than one receiving flow meter, report the net total mass of CO
(d) The source of the CO
(1) CO
(2) Electric generating unit.
(3) Ethanol plant.
(4) Pulp and paper mill.
(5) Natural gas processing.
(6) Gasification operations.
(7) Other anthropogenic source.
(8) Discontinued enhanced oil and gas recovery project.
(9) Unknown.
(e) Report the following:
(1) Whether the facility received a Research and Development project exemption from reporting under 40 CFR part 98, subpart RR, for this reporting year. If you received an exemption, report the start and end dates of the exemption approved by EPA.
(2) Whether the facility includes a well or group of wells where a CO
(3) Whether the facility includes a well or group of wells where a CO
(4) Whether the facility includes a well or group of wells where a CO
(5) Whether the facility includes a well or group of wells where a CO
(a) You must follow the record retention requirements specified by § 98.3(g). In addition to the records required by § 98.3(g), you must retain quarterly records of CO
(b) You must complete your monitoring plans, as described in § 98.3(g)(5), by April 1 of the year you begin collecting data.
Except as provided below, all terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.