Title 40—Protection of Environment--Volume 1
PART 98—MANDATORY GREENHOUSE GAS REPORTING
§ 98.308   Definitions.
Except as specified in this section, all terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
Facility, with respect to an electric power system, means the electric power system as set out in this definition. An electric power system is comprised of all electric transmission and distribution equipment insulated with or containing fluorinated GHGs that is linked through electric power transmission or distribution lines and functions as an integrated unit, that is owned, serviced, or maintained by a single electric power transmission or distribution entity (or multiple entities with a common owner), and that is located between:
(1) The point(s) at which electric energy is obtained from an electricity generating unit or a different electric power transmission or distribution entity that does not have a common owner; and
(2) The point(s) at which any customer or another electric power transmission or distribution entity that does not have a common owner receives the electric energy. The facility also includes servicing inventory for such equipment that contains fluorinated GHGs.
Electric power transmission or distribution entity means any entity that transmits, distributes, or supplies electricity to a consumer or other user, including any company, electric cooperative, public electric supply corporation, a similar Federal department (including the Bureau of Reclamation or the Corps of Engineers), a municipally owned electric department offering service to the public, an electric public utility district, or a jointly owned electric supply project.
Energized, for the purposes of this subpart, means connected through busbars or cables to an electrical power system or fully-charged, ready for service, and being prepared for connection to the electrical power system. Energized equipment does not include spare gas insulated equipment (including hermetically-sealed pressure switchgear) in storage that has been acquired by the facility, and is intended for use by the facility, but that is not being used or prepared for connection to the electrical power system.
Insulating gas, for the purposes of this subpart, means any fluorinated GHG or fluorinated GHG mixture, including but not limited to SF 6 and PFCs, that is used as an insulating and/or arc-quenching gas in electrical equipment.
New equipment, for the purposes of this subpart, means either any gas insulated equipment, including hermetically-sealed pressure switchgear, that is not energized at the beginning of the reporting year but is energized at the end of the reporting year, or any gas insulated equipment other than hermetically-sealed pressure switchgear that has been transferred while in use, meaning it has been added to the facility's inventory without being taken out of active service ( e.g., when the equipment is sold to or acquired by the facility while remaining in place and continuing operation).
Operator, for the purposes of this subpart, means any person who operates or supervises a facility, excluding a person whose sole responsibility is to ensure reliability, balance load or otherwise address electricity flow.
Reportable insulating gas, for purposes of this subpart, means an insulating gas whose weighted average GWP, as calculated in equation DD-3 to § 98.302, is greater than one. A fluorinated GHG that makes up either part or all of a reportable insulating gas is considered to be a component of the reportable insulating gas.
Retired equipment, for the purposes of this subpart, means either any gas insulated equipment including hermetically-sealed pressure switchgear, that is energized at the beginning of the reporting year but is not energized at the end of the reporting year, or any gas insulated equipment other than hermetically-sealed pressure switchgear that has been transferred while in use, meaning it has been removed from the facility's inventory without being taken out of active service ( e.g., when the equipment is acquired by a new facility while remaining in place and continuing operation).
§ 98.310   Definition of the source category.
The titanium dioxide production source category consists of facilities that use the chloride process to produce titanium dioxide.
§ 98.311   Reporting threshold.
You must report GHG emissions under this subpart if your facility contains a titanium dioxide production process and the facility meets the requirements of either § 98.2(a)(1) or (a)(2).
§ 98.312   GHGs to report.
(a) You must report CO 2 process emissions from each chloride process line as required in this subpart.
(b) You must report CO 2 , CH 4 , and N 2 O emissions from each stationary combustion unit under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C.
§ 98.313   Calculating GHG emissions.
You must calculate and report the annual process CO 2 emissions for each chloride process line using the procedures in either paragraph (a) or (b) of this section.
(a) Calculate and report under this subpart the process CO 2 emissions by operating and maintaining a CEMS according to the Tier 4 Calculation Methodology specified in § 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources).
(b) Calculate and report under this subpart the annual process CO 2 emissions for each chloride process line by determining the mass of calcined petroleum coke consumed in each line as specified in paragraphs (b)(1) through (b)(3) of this section. Use Equation EE-1 of this section to calulate annual combined process CO 2 emissions from all process lines and use Equation EE-2 of this section to calculate annual process CO 2 emissions for each process line. If your facility generates carbon-containing waste, use Equation EE-3 of this section to estimate the annual quantity of carbon-containing waste generated and its carbon contents according to § 98.314(e) and (f):
(1) You must calculate the annual CO 2 process emissions from all process lines at the facility using Equation EE-1 of this section:
(2) You must calculate the annual CO 2 process emissions from each process lines at the facility using Equation EE-2 of this section:
(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 2 emissions using a CEMS that complies with the Tier 4 Calculation Methodology in subpart C of this part (General Stationary Fuel Combustion Sources), then the calculation methodology in paragraph (b) of this section shall not be used to calculate process CO 2 emissions. The owner or operator shall report under this subpart the combined stack emissions according to the Tier 4 Calculation Methodology in § 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part.
§ 98.314   Monitoring and QA/QC requirements.
(a) You must measure your consumption of calcined petroleum coke using plant instruments used for accounting purposes including direct measurement weighing the petroleum coke fed into your process (by belt scales or a similar device) or through the use of purchase records.
(b) You must document the procedures used to ensure the accuracy of monthly calcined petroleum coke consumption measurements.
(c) You must determine the carbon content of the calcined petroleum coke each month based on reports from the supplier. Alternatively, facilities can measure monthly carbon contents of the petroleum coke using ASTM D3176-89 (Reapproved 2002) Standard Practice for Ultimate Analysis of Coal and Coke (incorporated by reference, see § 98.7) and ASTM D5373-08 Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference, see § 98.7).
(d) For quality assurance and quality control of the supplier data, you must conduct an annual measurement of the carbon content from a representative sample of the petroleum coke consumed using ASTM D3176-89 and ASTM D5373-08.
(e) You must determine the quantity of 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.
§ 98.315   Procedures for estimating missing data.
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).
§ 98.316   Data reporting requirements.
In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) or (b) of this section, as applicable for each titanium dioxide production line.
(a) If a CEMS is used to measure CO 2 emissions, then you must report the relevant information required under § 98.36(e)(2)(vi) for the Tier 4 Calculation Methodology and the following information in this paragraph (a).
(1) Identification number of each process line.
(2) Annual consumption of calcined petroleum coke (tons).
(3) Annual production of titanium dioxide (tons).
(4) Annual production capacity of titanium dioxide (tons).
(5) Annual production of carbon-containing waste (tons), if applicable.
(b) If a CEMS is not used to measure CO 2 emissions, then you must report the information listed in this paragraph (b):
(1) Identification number of each process line.
(2) Annual CO 2 emissions from each chloride process line (metric tons/year).
(3) Annual consumption of calcined petroleum coke for each process line (tons).
(4) Annual production of titanium dioxide for each process line (tons).
(5) Annual production capacity of titanium dioxide for each process line (tons).
(6) [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).
§ 98.317   Records that must be retained.
In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) through (c) of this section for each titanium dioxide production facility.
(a) If a CEMS is used to measure CO 2 emissions, then you must retain under this subpart required for the Tier 4 Calculation Methodology in § 98.37 and the information listed in this paragraph (a):
(1) Records of all calcined petroleum coke purchases.
(2) Annual operating hours for each titanium dioxide process line.
(b) If a CEMS is not used to measure CO 2 emissions, then you must retain records for the information listed in this paraghraph:
(1) Records of all calcined petroleum coke purchases (tons).
(2) Records of all analyses and calculations conducted for all reported data as listed in § 98.316(b).
(3) Sampling analysis results for carbon content of consumed calcined petroleum coke (percent by weight expressed as a decimal fraction).
(4) Sampling analysis results for the carbon content of carbon containing waste (percent by weight expressed as a decimal fraction), if applicable.
(5) Monthly production of carbon-containing waste (tons).
(6) You must document the procedures used to ensure the accuracy of the monthly petroleum coke consumption and quantity of carbon-containing waste measurement including, but not limited to, calibration of weighing equipment 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) Verification software records. You must keep a record of the file generated by the verification software specified in § 98.5(b) for the applicable data specified in paragraphs (c)(1) and (2) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (c)(1) and (2) of this section.
(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).
§ 98.318   Definitions.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
§ 98.320   Definition of the source category.
(a) This source category consists of active underground coal mines, and any underground mines under development that have operational pre-mining degasification systems. An underground coal mine is a mine at which coal is produced by tunneling into the earth to the coalbed, which is then mined with underground mining equipment such as cutting machines and continuous, longwall, and shortwall mining machines, and transported to the surface. Underground coal mines are categorized as active if any one of the following five conditions apply:
(1) Mine development is underway.
(2) Coal has been produced within the last 90 days.
(3) Mine personnel are present in the mine workings.
(4) Mine ventilation fans are operative.
(5) The mine is designated as an ”intermittent” mine by the Mine Safety and Health Administration (MSHA).
(b) This source category includes the following:
(1) Each ventilation 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 ( e.g., storage or transportation of coal).
§ 98.321   Reporting threshold.
You must report GHG emissions under this subpart if your facility contains an active underground coal mine and the facility meets the requirements of § 98.2(a)(1).
§ 98.322   GHGs to report.
(a) You must report CH 4 liberated from ventilation and degasification systems.
(b) You must report CH 4 destruction from systems where gas is sold, used onsite, or otherwise destroyed (including by VAM oxidation and by flaring).
(c) You must report net CH 4 emissions from ventilation and degasification systems.
(d) You must report under this subpart the CO 2 emissions from coal mine gas CH 4 destruction occurring at the facility, where the gas is not a fuel input for energy generation or use ( e.g., flaring and VAM oxidation).
(e) You must report under subpart C of this part (General Stationary Fuel Combustion Sources) the CO 2 , CH 4 , and N 2 O emissions from each stationary fuel combustion unit by following the requirements of subpart C. Report emissions from both the combustion of collected coal mine CH 4 and any other fuels.
(f) An underground coal mine that is subject to this part because emissions from source categories described in Tables A-3, A-4 or A-5 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.
§ 98.323   Calculating GHG emissions.
(a) For each ventilation shaft, vent hole, or centralized point into which CH 4 from multiple shafts and/or vent holes are collected, you must calculate the quarterly CH 4 liberated from the ventilation system using Equation FF-1 of this section. You must measure CH 4 content, flow rate, temperature, pressure, and moisture content of the gas using the procedures outlined in § 98.324.
(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 H2O ), must be based on measurements taken at least once each quarter with no fewer than 6 weeks between measurements. If measurements are taken more frequently than once per quarter, then use the average value for all measurements taken. If continuous measurements are taken, then use the average value over the time period of continuous monitoring.
(3) If a facility has more than one monitoring point, the facility must calculate total CH 4 liberated from ventilation systems (CH 4VTotal ) as the sum of the CH 4 from all ventilation monitoring points in the mine, as follows:
(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 4 from multiple wells and/or vent holes are collected), you must calculate the weekly CH 4 liberated from the mine using CH 4 measured weekly or more frequently (including by CEMS) according to 98.234(c), CH 4 content, flow rate, temperature, pressure, and moisture content, and Equation FF-3 of this section.
(1) Values for V, C, T, P, and, if applicable, (f H2O ), must be based on measurements taken at least once each calendar week with at least 3 days between measurements. If measurements are taken more frequently than once per week, then use the average value for all measurements taken that week. If continuous measurements are taken, then use the average values over the time period of continuous monitoring when the continuous monitoring equipment is properly functioning.
(2) Quarterly total CH 4 liberated from degasification systems for the mine must be determined as the sum of CH 4 liberated determined at each of the monitoring points in the mine, summed over the number of weeks in the quarter, as follows:
(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 4 destroyed for each destruction device and each point of offsite transport to a destruction device, using Equation FF-5 of this section. You must measure CH 4 content and flow rate according to the provisions in § 98.324, and calculate the methane routed to the destruction device (CH 4 ) using either Equation FF-1 or Equation FF-4 of this section, as applicable.
(1) Calculate total CH 4 destroyed as the sum of the methane destroyed at all destruction devices (onsite and offsite), using Equation FF-6 of this section.
(2) [Reserved]
(d) You must calculate the quarterly measured net CH 4 emissions to the atmosphere using Equation FF-7 of this section.
(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 2 emissions using Equation FF-8 of this section.
§ 98.324   Monitoring and QA/QC requirements.
(a) For calendar year 2011 monitoring, the facility may submit a request to the Administrator to use one or more best available monitoring methods as listed in § 98.3(d)(1)(i) through (iv). The request must be submitted no later than 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 CH 4 liberated from ventilation systems, determine whether CH 4 will be monitored from each ventilation shaft and vent hole, from a centralized monitoring point, or from a combination of the two options. Operators are allowed flexibility for aggregating emissions from more than one ventilation point, as long as emissions from all are addressed, and the methodology for calculating total emissions documented. Monitor by one of the following options:
(1) Collect quarterly or more frequent grab samples (with no fewer than 6 weeks between measurements) for methane concentration and make quarterly measurements of flow rate, temperature, pressure, and, 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 4 liberated at degasification systems, determine whether CH 4 will be monitored from each well and gob gas vent hole, from a centralized monitoring point, or from a combination of the two options. Operators are allowed flexibility for aggregating emissions from more than one well or gob gas vent hole, as long as emissions from all are addressed, and the methodology for calculating total emissions is documented. Monitor both gas volume and methane concentration by one of the following two options:
(1) Monitor emissions through the use of one or more continuous emissions monitoring systems (CEMS). If operators use CEMS as the basis for emissions reporting, they must provide documentation on the process for using data obtained from their CEMS to estimate emissions from their mine ventilation systems.
(2) Collect weekly (once each calendar week, with at least three days between measurements) or more frequent samples, for all degasification wells and gob gas vent holes. Determine weekly or more frequent flow rates, methane concentration, temperature, and pressure from these degasification wells and gob gas vent holes. Methane composition should be determined either by submitting samples to a lab for analysis, or from the use of methanometers at the degasification 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 measurements, the methane concentration (percent), the bottle number of samples collected, and the location of the measurement or collection.
(3) If the CH 4 concentration is determined on a dry basis and flow is determined on a wet basis or CH 4 concentration is determined on a wet basis and flow is determined on a dry basis, and the flow meter does not automatically correct for moisture content, determine the moisture content in the gas in a location near or representative of the location of:
(i) The gas flow meter at least once each calendar week; if measuring with CEMS. If only one measurement is made each calendar week, there must be at least three days between measurements; and
(ii) The grab sample, if using grab samples, at the time of the sample.
(d) Monitoring must adhere to one of the methods specified in paragraphs (d)(1) through (d)(2) of this section.
(1) ASTM D1945-03, Standard Test Method for Analysis of Natural Gas by Gas Chromatography; ASTM D1946-90 (Reapproved 2006), Standard Practice for Analysis of Reformed Gas by Gas Chromatography; ASTM D4891-89 (Reapproved 2006), Standard Test Method for Heating Value of Gases in Natural Gas Range by Stoichiometric Combustion; or ASTM UOP539-97 Refinery Gas Analysis by Gas Chromatography (incorporated by reference, see § 98.7).
(2) As an alternative to the gas chromatography methods provided in paragraph (d)(1) of this section, you may use gaseous organic concentration analyzers and a correction factor to calculate the CH 4 concentration following the requirements in paragraphs (d)(2)(i) through (d)(2)(iii) of this section.
(i) Use Method 25A or 25B at 40 CFR part 60, appendix A-7 to determine gaseous organic concentration as required in § 98.323 and in paragraphs (b) and (c) of this section. You must calibrate the instrument with CH 4 and determine the total gaseous organic concentration as carbon (or as CH 4 ; K = 1 in Equation 25A-1 of Method 25A at 40 CFR part 60, appendix A-7).
(ii) Determine a correction factor that will be used with the 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 4 concentration as specified in Equation FF-9 of this section:
(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 4 in the gas using one of the methods specified in paragraph (d) of this section. The operator shall operate, maintain, and calibrate the flow meter using any of the following test methods or follow the procedures specified by the flow meter manufacturer. Flow meters must meet the accuracy requirements in § 98.3(i).
(1) ASME MFC-3M-2004, Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and Venturi (incorporated by reference, see § 98.7).
(2) ASME MFC-4M-1986 (Reaffirmed 1997), Measurement of Gas Flow by Turbine Meters (incorporated by reference, see § 98.7).
(3) ASME MFC-6M-1998, Measurement of Fluid Flow in Pipes Using Vortex Flowmeters (incorporated by reference, see § 98.7).
(4) ASME MFC-7M-1987 (Reaffirmed 1992), Measurement of Gas Flow by Means of Critical Flow Venturi Nozzles (incorporated by reference, see § 98.7).
(5) ASME MFC-11M-2006 Measurement of Fluid Flow by Means of Coriolis Mass Flowmeters (incorporated by reference, see § 98.7).
(6) ASME MFC-14M-2003 Measurement of Fluid Flow Using Small Bore Precision Orifice Meters (incorporated by reference, see § 98.7).
(7) ASME MFC-18M-2001 Measurement of Fluid Flow using Variable Area Meters (incorporated by reference, see § 98.7).
(f) For CH 4 destruction, CH 4 must be monitored at each onsite destruction device and each point of offsite transport for combustion using continuous monitors of gas routed to the device or point of offsite transport.
(g) All temperature, pressure, and moisture content monitors must be operated and calibrated using the procedures and frequencies specified by the manufacturer.
(h) The owner or operator shall document the procedures used to ensure the accuracy of gas flow rate, gas composition, temperature, pressure, and moisture content measurements. These procedures include, but are not limited to, calibration of flow meters, and other measurement devices. The estimated accuracy of measurements and the technical basis for the estimated accuracy shall be recorded.
§ 98.325   Procedures for estimating missing data.
(a) A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable ( e.g., if a meter malfunctions during unit operation or if a required fuel sample is not taken), a substitute data value for the missing parameter shall be used in the calculations, in accordance with paragraph (b) of this section.
(b) For each missing value of CH 4 concentration, flow rate, temperature, pressure, and moisture content for ventilation and degasification systems, the substitute data value shall be the arithmetic average of the quality-assured values of that parameter immediately preceding and immediately following the missing data incident. If, for a particular parameter, no quality-assured data are available prior to the missing data incident, the substitute data value shall be the first quality-assured value obtained after the missing data period.
§ 98.326   Data reporting requirements.
In addition to the information required by § 98.3(c), each annual report must contain the following information for each mine:
(a) Quarterly CH 4 liberated from each ventilation monitoring point, (metric tons CH 4 ). Where MSHA reports are the monitoring method chosen under § 98.324(b), each annual report must include the MSHA reports used to report quarterly CH 4 concentration and volumetric flow rate as attachments.
(b) Weekly CH 4 liberated from each degasification system monitoring point (metric tons CH 4 ).
(c) Quarterly CH 4 destruction at each ventilation and degasification system destruction device or point of offsite transport (metric tons CH 4 ).
(d) Quarterly CH 4 emissions (net) from all ventilation and degasification systems (metric tons CH 4 ).
(e) Quarterly CO 2 emissions from on-site destruction of coal mine gas CH 4 , where the gas is not a fuel input for energy generation or use ( e.g., flaring) (metric tons CO 2 ).
(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 4 concentration for each ventilation monitoring point, dates and locations of each measurement, and method of measurement (sampling or continuous monitoring). Specify whether the CH 4 concentration measurement at each ventilation monitoring point is on dry basis or wet basis.
(h) Weekly volumetric flow rate used to calculate CH 4 liberated from degasification systems and units of measure (acfm or scfm), and method of measurement (sampling or continuous monitoring), used in Equation FF-3 of this subpart. Specify whether the volumetric flow rate measurement at each degasification 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.
(i) Quarterly CH 4 concentration (%) used to calculate CH 4 liberated from degasification systems, and if the data is based on CEMS or weekly sampling. Specify whether the CH 4 concentration measurement at each degasification monitoring point is on dry basis or wet basis.
(j) Weekly volumetric flow rate used to calculate CH 4 destruction for each destruction device and each point of offsite transport, and units of measure (acfm or scfm).
(k) Weekly CH 4 concentration (%) used to calculate CH 4 flow to each destruction device and each point of offsite transport (C).
(l) Dates in quarterly reporting period where active ventilation of mining operations is taking place.
(m) Dates in quarterly reporting period where degasification of mining operations is taking place.
(n) Dates in quarterly reporting period when continuous monitoring equipment is not properly functioning, if applicable.
(o) 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 4 concentration is measured on a wet basis and volumetric flow is measured on a dry basis, if CH 4 concentration is measured on a dry basis and volumetric flow is measured on a wet basis; and, if a flow meter is used, the flow meter does not automatically correct for moisture content.
(p) For each destruction device, a description of the device, including an indication of whether destruction occurs at the coal mine or off-site. If destruction occurs at the mine, also report an indication of whether a back-up destruction device is present at the mine, the annual operating hours for the primary destruction device, the annual operating hours for the back-up destruction device (if present), and the destruction efficiencies assumed (percent).
(q) A description of the gas collection system (manufacturer, capacity, and number of wells) the surface area of the gas collection system (square meters), and the annual operating hours of the gas collection system.
(r) Identification information and description for each well, 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 number for this coal mine.
§ 98.327   Records that must be retained.
In addition to the information required by § 98.3(g), you must retain the following records:
(a) Calibration records for all monitoring equipment, including the method or manufacturer's specification used for calibration.
(b) Records of gas sales.
(c) Logbooks of parameter measurements.
(d) Laboratory analyses of samples.
§ 98.328   Definitions.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
§ 98.330   Definition of the source category.
The zinc production source category consists of zinc smelters and secondary zinc recycling facilities.
§ 98.331   Reporting threshold.
You must report GHG emissions under this subpart if your facility contains a zinc production process and the facility meets the requirements of either § 98.2(a)(1) or (2).
§ 98.332   GHGs to report.
You must report:
(a) CO 2 process emissions from each Waelz kiln and electrothermic furnace used for zinc production.
(b) CO 2 , CH 4 , and N 2 O combustion emissions from each Waelz kiln. You must calculate and report these emissions under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C.
(c) CO 2 , CH 4 , and N 2 O emissions from each stationary combustion unit other than Waelz kilns. You must report these emissions under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C.
§ 98.333   Calculating GHG emissions.
You must calculate and report the annual process CO 2 emissions using the procedures specified in either paragraph (a) or (b) of this section.
(a) Calculate and report under this subpart the process or combined process and combustion CO 2 emissions by operating and maintaining a CEMS according to the Tier 4 Calculation Methodology in § 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources).
(b) Calculate and report under this subpart the process CO 2 emissions by following paragraphs (b)(1) and (b)(2) of this section.
(1) For each Waelz kiln or electrothermic furnace at your facility used for zinc production, you must determine the mass of carbon in each carbon-containing material, other than fuel, that is fed, charged, or otherwise introduced into each Waelz kiln and electrothermic furnace at your facility for each year and calculate annual CO 2 process emissions from each affected unit at your facility using equation GG-1 to this section. For electrothermic furnaces, carbon containing input materials include carbon electrodes and carbonaceous reducing agents. For Waelz kilns, carbon containing input materials include carbonaceous reducing agents. If you document that a specific material contributes less than 1 percent of the total carbon into the process, you do not have to include the material in your calculation using equation R-1 to § 98.183.
(2) You must determine the CO 2 emissions from all of the Waelz kilns or electrothermic furnaces at your facility using Equation GG-2 of this section.
(c) If GHG emissions from a Waelz kiln or electrothermic furnace are vented through the same stack as any combustion unit or process equipment that reports CO 2 emissions using a CEMS that complies with the Tier 4 Calculation Methodology in subpart C of this part (General Stationary Fuel Combustion Sources), then the calculation methodology in paragraph (b) of this section shall not be used to calculate process emissions. The owner or operator shall report under this subpart the combined stack emissions according to the Tier 4 Calculation Methodology in § 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part.
§ 98.334   Monitoring and QA/QC requirements.
If you determine CO 2 emissions using the carbon input procedure in § 98.333(b)(1) and (b)(2), you must meet the requirements specified in paragraphs (a) and (b) of this section.
(a) Determine the mass of each solid carbon-containing input material consumed using facility instruments, procedures, or records used for accounting purposes including direct measurement weighing or through the use of purchase records same plant instruments or procedures that are used for accounting purposes (such as weigh hoppers, belt weigh feeders, weighed purchased quantities in shipments or containers, combination of bulk density and volume measurements, etc.). Record the total mass for the materials consumed each calendar month and sum the monthly mass to determine the annual mass for each input material.
(b) For each input material identified in paragraph (a) of this section, you must determine the average carbon content of the material consumed or used in the calendar year using the methods specified in either paragraph (b)(1) or (b)(2) of this section.
(1) Information provided by your material supplier.
(2) Collecting and analyzing at least three representative samples of the material using the appropriate testing method. For each carbon-containing input material identified for which the carbon content is not provided by your material supplier, the carbon content of the material must be analyzed at least annually using the appropriate standard methods (and their QA/QC procedures), which are identified in paragraphs (b)(2)(i) through (b)(2)(iii) of this section, as applicable. If you document that a specific process input or output contributes less than one percent of the total mass of carbon into or out of the process, you do not have 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.
§ 98.335   Procedures for estimating missing data.
For the carbon input procedure in § 98.333(b), a complete record of all measured parameters used in the GHG emissions calculations is required (e.g., raw materials carbon content values, etc.). Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter shall be used in the calculations as specified in paragraphs (a) and (b) of this section. You must 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.
§ 98.336   Data reporting requirements.
In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) or (b) of this section, as applicable, for each Waelz kiln or electrothermic furnace.
(a) If a CEMS is used to measure CO 2 emissions, then you must report under this subpart the relevant information required for the Tier 4 Calculation Methodology in § 98.36 and the information listed in this paragraph (a):
(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.
(6) Total amount of electric arc furnace dust annually consumed by all Waelz kilns at the facility (tons).
(b) If a CEMS is not used to measure CO 2 emissions, then you must report the information listed in this paragraph (b):
(1) Identification number and annual process CO 2 emissions from each individual Waelz kiln or electrothermic furnace (metric tons).
(2) Annual zinc product production capacity (tons).
(3) Annual production quantity for each zinc product (tons).
(4) Number of Waelz kilns at each facility used for zinc production.
(5) Number of electrothermic furnaces at each facility used for zinc production.
(6) Total amount of electric arc furnace dust annually consumed by all Waelz kilns at the facility (tons).
(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.
§ 98.337   Records that must be retained.
In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) through (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 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) Verification software records. You must keep a record of the file generated by the verification software specified in § 98.5(b) for the applicable data specified in paragraphs (c)(1) through (9) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (c)(1) through (9) of this section.
(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.
§ 98.338   Definitions.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
§ 98.340   Definition of the source category.
(a) This source category applies to municipal solid waste (MSW) landfills that accepted waste on or after January 1, 1980, 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 4 generation as determined using Equation HH-5 and, if applicable, Equation HH-7 of this subpart of less than 1,190 metric tons of CH 4 in the 2013 reporting year.
(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).
§ 98.341   Reporting threshold.
You must report GHG emissions under this subpart if your facility contains a MSW landfill and the facility meets the requirements of § 98.2(a)(1).
§ 98.342   GHGs to report.
(a) You must report CH 4 generation and CH 4 emissions from landfills.
(b) You must report CH 4 destruction resulting from landfill gas collection and combustion systems.
(c) You must report under subpart C of this part (General Stationary Fuel Combustion Sources) the emissions of CO 2 , CH 4 , and N 2 O from each stationary combustion unit following the requirements of subpart C.
§ 98.343   Calculating GHG emissions.
(a) For all landfills subject to the reporting requirements of this subpart, calculate annual modeled CH 4 generation according to the applicable requirements in paragraphs (a)(1) through (a)(3) of this section.
(1) Calculate annual modeled CH 4 generation using Equation HH-1 of this section.
(2) For years when material-specific waste quantity data are available, apply equation HH-1 to this section for each waste quantity type and sum the CH 4 generation rates for all waste types to calculate the total modeled CH 4 generation rate for the landfill. Use the appropriate parameter values for k, DOC, MCF, DOC F , and F shown in table HH-1 to this subpart. The annual quantity of each type of waste disposed must be calculated as the sum of the daily quantities of waste (of that type) disposed. You may use the uncharacterized MSW parameters for a portion of your waste materials when using the material-specific modeling approach for mixed waste streams that cannot be designated to a specific material type. For years when waste composition data are not available, use the bulk waste parameter values for k and DOC in table HH-1 to this subpart for the total quantity of waste disposed in those years.
(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 disposed. The approach used to determine the annual quantity of waste disposed of must be documented in the monitoring plan.
(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 ( e.g., using volumetric capacity and waste density measurements; direct measurement of a selected number of passenger vehicles and light duty pick-up trucks; or similar methods); record the number of loads received at the landfill by vehicle/container type; calculate the annual mass per vehicle/container type as the mass product of the number of loads of that vehicle/container multiplied by its working capacity; and calculate the annual quantity of waste received as the sum of the annual mass per vehicle/container type across all of the vehicle/container types used to haul waste to the landfill.
(4) For years prior to the first emissions 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 X shall be estimated using one of the applicable methods in paragraphs (a)(4)(i) through (a)(4)(iii) of this section. You must determine which method is most applicable to the conditions and disposal history of your facility. Historical waste disposal quantities should only be determined once, as part of the first annual report, and the same values should be used for all subsequent annual reports, supplemented by the next year's data on new waste disposal.
(i) Assume all prior 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 4 destroyed according to the requirements in paragraphs (b)(1) and (b)(2) of this section.
(1) If you continuously monitor the flow rate, CH 4 concentration, temperature, pressure, and, if necessary, moisture content of the landfill gas that is collected and routed to a destruction device (before any treatment equipment) using a monitoring meter specifically for CH 4 gas, as specified in § 98.344, you must use this monitoring system and calculate the quantity of CH 4 recovered for destruction using Equation HH-4 of this section. A fully integrated system that directly reports CH 4 content requires no other calculation than summing the results of all monitoring periods for a given year.
(2) If you do not continuously monitor according to paragraph (b)(1) of this section, you must determine the flow rate, CH 4 concentration, temperature, pressure, and moisture content of the landfill gas that is collected and routed to a destruction device (before any treatment equipment) according to the requirements in paragraphs (b)(2)(i) through (b)(2)(iii) of this section and calculate the quantity of CH 4 recovered for destruction using Equation HH-4 of this section.
(i) Continuously monitor gas flow rate and determine the cumulative volume of landfill gas each 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 content. If the gas flow meter is not equipped with automatic correction for temperature, pressure, or, if necessary, moisture content, you must determine these parameters as specified in paragraph (b)(2)(iii) of this section.
(ii) Determine the CH 4 concentration in the landfill gas that is collected and routed to a destruction device (before any treatment equipment) in a location near or representative of the location of the gas flow meter at least once each calendar month; if only one measurement is made each calendar month, there must be at least fourteen days between measurements.
(iii) If the gas flow meter is not equipped with automatic correction for temperature, pressure, or, if necessary, moisture content:
(A) Determine the temperature and pressure in the landfill gas that is collected and routed to a destruction device (before any treatment equipment) in a location near or representative of the location of the gas flow meter 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 4 concentration is determined on a dry basis and flow is determined on a wet basis or CH 4 concentration is determined on a wet basis and flow is determined on a dry basis, and the flow meter does not automatically correct for moisture content, determine the moisture content in the landfill gas that is collected and 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.
(c) For all landfills, calculate CH 4 generation (adjusted for oxidation in cover materials) and actual CH 4 emissions (taking into account any CH 4 recovery, and oxidation in cover materials) according to the applicable methods in paragraphs (c)(1) through (c)(3) of this section.
(1) Calculate CH 4 generation, adjusted for oxidation, from the modeled CH 4 (G CH 4 from Equation HH-1 of this section) using Equation HH-5 of this section.
(2) For landfills that do not have landfill gas collection systems, the CH 4 emissions are equal to the CH 4 generation (MG) calculated in Equation HH-5 of this section.
(3) For landfills with landfill gas collection systems, calculate CH 4 emissions using the methodologies specified in paragraphs (c)(3)(i) and (ii) of this section.
(i) Calculate CH 4 emissions from the modeled CH 4 generation and measured CH 4 recovery using equation HH-6 to this section.
(ii) Calculate CH 4 generation and CH 4 emissions using measured CH 4 recovery and estimated gas collection efficiency and equations HH-7 and HH-8 to this section.
§ 98.344   Monitoring and QA/QC requirements.
(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 4 in the recovered landfill gas using one of the methods specified in paragraphs (b)(1) through (b)(6) of this section or as specified by the manufacturer. Gas composition monitors shall be calibrated prior to the first reporting year and recalibrated either annually or at the minimum frequency specified by the manufacturer, whichever is more frequent, or whenever the error in the midrange calibration check exceeds ±10 percent.
(1) Method 18 at 40 CFR part 60, appendix A-6.
(2) ASTM D1945-03, Standard Test Method for Analysis of Natural Gas by Gas Chromatography (incorporated by reference, see § 98.7).
(3) ASTM D1946-90 (Reapproved 2006), Standard Practice for Analysis of Reformed Gas by Gas Chromatography (incorporated by reference, see § 98.7).
(4) GPA Standard 2261-00, Analysis for Natural Gas and Similar Gaseous Mixtures by Gas Chromatography.
(5) UOP539-97 Refinery Gas Analysis by Gas Chromatography (incorporated by reference, see § 98.7).
(6) As an alternative to the gas chromatography methods provided in paragraphs (b)(1) through (b)(5) of this section, you may use total gaseous organic concentration analyzers and calculate the methane concentration following the requirements in paragraphs (b)(6)(i) through (b)(6)(iii) of this section.
(i) Use Method 25A or 25B at 40 CFR part 60, appendix A-7 to determine total gaseous organic concentration. You must calibrate the instrument with methane and determine the total gaseous organic concentration as carbon (or as methane; K = 1 in Equation 25A-1 of Method 25A at 40 CFR part 60, appendix A-7).
(ii) Determine a non-methane organic carbon correction factor at the routine sampling location no less frequently than once a reporting year following the requirements in paragraphs (b)(6)(ii)(A) through (b)(6)(ii)(C) of this section.
(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, see § 98.7).
(2) ASME MFC-4M-1986 (Reaffirmed 1997), Measurement of Gas Flow by Turbine Meters (incorporated by reference, see § 98.7).
(3) ASME MFC-6M-1998, Measurement of Fluid Flow in Pipes Using Vortex Flowmeters (incorporated by reference, see § 98.7).
(4) ASME MFC-7M-1987 (Reaffirmed 1992), Measurement of Gas Flow by Means of Critical Flow Venturi Nozzles (incorporated by reference, see § 98.7).
(5) ASME MFC-11M-2006 Measurement of Fluid Flow by Means of Coriolis Mass Flowmeters (incorporated by reference, see § 98.7). The mass flow must be corrected to volumetric flow based on the measured temperature, pressure, and gas composition.
(6) ASME MFC-14M-2003 Measurement of Fluid Flow Using Small Bore Precision Orifice Meters (incorporated by reference, see § 98.7).
(7) ASME MFC-18M-2001 Measurement of Fluid Flow using Variable Area Meters (incorporated by reference, see § 98.7).
(8) Method 2A or 2D at 40 CFR part 60, appendix A-1.
(d) All temperature, pressure, and if necessary, moisture content monitors must be calibrated using the procedures and frequencies specified by the manufacturer.
(e) For landfills electing to measure the fraction by volume of CH 4 in landfill gas (F), follow the requirements in paragraphs (e)(1) and (2) of this section. (1) Use a gas composition monitor capable of measuring the concentration of CH 4 on a dry basis that is properly operated, calibrated, and maintained according to the requirements specified in paragraph (b) of this section. You must either use a gas composition monitor that is also capable of measuring the O 2 concentration correcting for excess (infiltration) air or you must operate, maintain, and calibrate a second monitor capable of measuring the O 2 concentration on a dry basis according to the manufacturer's specifications.
(2) Use Equation HH-10 of this section to correct the measured CH 4 concentration to 0% oxygen. If multiple CH 4 concentration measurements are made during the reporting year, determine F separately for each measurement made during the reporting year, and use the results to determine the arithmetic average value of F for use in Equation HH-1 of this part.
(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.
§ 98.345   Procedures for estimating missing data.
A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable (e.g., if a meter malfunctions during unit operation or if a required fuel sample is not taken), a substitute data value for the missing parameter shall be used in the calculations, according to the requirements in paragraphs (a) through (c) of this section.
(a) For each missing value of the CH 4 content, the substitute data value shall be the arithmetic average of the quality-assured values of that parameter immediately preceding and immediately following the missing data incident. If the “after” value is not obtained by the end of the reporting year, you may use the “before” value for the missing data substitution. If, for a particular parameter, no quality-assured data are available prior to the missing data incident, the substitute data value shall be the first quality-assured value obtained after the missing data period.
(b) For missing gas flow rates, the substitute 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.
§ 98.346   Data reporting requirements.
In addition to the information required by § 98.3(c), each annual report must contain the following information for each landfill.
(a) 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 years when waste quantity data are determined using the methods in § 98.343(a)(3), report separately the quantity of waste determined using the methods in § 98.343(a)(3)(i) and the quantity of waste determined using the methods in § 98.343(a)(3)(ii). For historical waste disposal quantities that were not determined using the methods in § 98.343(a)(3), provide the population served by the landfill for each year the Equation HH-2 of this subpart is applied, if applicable, or, for open landfills using Equation HH-3 of this subpart, provide the value of landfill capacity (LFC) used in the calculation.
(c) Waste composition for each year 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 4 generation.
(d) For each waste type used to calculate CH 4 generation using Equation HH-1 of this subpart, you must report:
(1) Degradable organic carbon (DOC) and fraction of DOC dissimilated (DOC F ) values used in the calculations.
(2) Decay rate (k) value used in the calculations.
(e) Fraction of CH 4 in landfill gas (F), an indication of whether the fraction of CH 4 was determined based on measured values or the default value, and the methane correction factor (MCF) used in the calculations. If an MCF other than the default of 1 is used, provide an indication of whether active aeration of the waste in the landfill was conducted during the reporting year, a description of the aeration system, including aeration blower capacity, the fraction of the landfill containing waste affected by 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.
(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 4 ) calculated using Equation HH-1 of this subpart.
(h) An indication of the applicability of part 60 or part 62 of this chapter requirements to the landfill (part 60, subparts WWW and XXX of this chapter, approved state plan implementing part 60, subparts Cc or Cf of this chapter, Federal plan as implemented at part 62, subparts GGG or OOO of this chapter, or not subject to part 60 or part 62 of this chapter municipal solid waste landfill rules), and if the landfill is subject to a part 60 or part 62 of this chapter municipal solid waste landfill rule, an indication of whether the landfill gas collection system is required under part 60 or part 62 of this chapter.
(i) For landfills without gas collection systems, the annual methane emissions (i.e., the methane generation, adjusted for oxidation, calculated using Equation HH-5 of this subpart), reported in metric tons CH 4 , the oxidation fraction used in the calculation, and an indication of whether passive vents and/or passive flares (vents or flares that are not considered part of the gas collection system as defined in § 98.6) are present at this landfill.
(j) 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 4 concentration of landfill gas collected for destruction (percent by volume).
(3) Monthly average temperature and pressure for each month at which flow is measured for landfill gas collected for destruction, or statement that temperature and/or pressure is incorporated into internal 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 4 concentration was measured on a wet or dry basis, and if required for Equation HH-4 of this subpart, monthly average moisture content for each month at which flow is measured for landfill gas collected for destruction.
(5) The number of gas collection systems at the landfill facility.
(6) For each gas collection system at the facility report:
(i) A unique name or ID number for the gas collection system.
(ii) A description of the gas collection system (manufacturer, capacity, and number of wells).
(iii) The annual hours the gas collection system was operating normally. Do not include periods of shut down or poor operation, such as times when pressure, temperature, or other parameters indicative of operation are outside of normal variances, in the annual operating hours.
(iv) The number of measurement locations associated with the gas collection system.
(v) For each measurement location associated with the gas collection system, report:
(A) A unique name or ID number for the measurement location.
(B) Annual quantity of recovered CH 4 (metric tons CH 4 ) calculated using equation HH-4 to § 98.343.
(C) An indication of whether destruction occurs at the landfill facility, off-site, or both for the measurement location.
(D) If destruction occurs at the landfill facility for the measurement location (in full or in part), also report the number of destruction devices associated with the measurement location that are located at the landfill facility and the information in paragraphs (j)(6)(v)(D)(1) through (6) of this section for each destruction device located at the landfill facility.
( 1 ) A unique name or ID number for the destruction device.
( 2 ) The type of destruction device (flare, a landfill gas to energy project ( i.e., engine or turbine), off-site, or other (specify)).
( 3 ) The destruction efficiency (decimal).
( 4 ) The total annual hours where active gas flow was sent to the destruction device.
( 5 ) The annual operating hours where active gas flow was sent to the destruction device and the destruction device was operating at its intended temperature or other parameter indicative of effective operation. For flares, times when there is no flame present must be excluded from the annual operating hours for the destruction device.
( 6 ) The estimated fraction of the recovered CH4 reported for the measurement location directed to the destruction device based on best available data or engineering judgement (decimal, must total to 1 for each measurement location).
( 7 ) The following information about the landfill.
(i) The surface area (square meters) and estimated waste depth (meters) for each area specified in table HH-3 to this subpart.
(ii) The estimated gas collection system efficiency for the landfill.
(iii) An indication of whether passive vents and/or passive flares (vents or flares that are not considered part of the gas collection system as defined in § 98.6) are present at the landfill.
(8) Methane generation corrected for oxidation calculated using Equation HH-5 of this subpart, reported in metric tons CH 4 , and the oxidation fraction used in the calculation.
(9) Methane generation (G CH4 ) value used as an input to Equation HH-6 of this subpart. Specify whether the value is modeled (G CH4 from HH-1 of this subpart) or measured (R from Equation HH-4 of this subpart).
(10) Methane generation corrected for oxidation calculated using Equation HH-7 of this subpart, reported in metric tons CH 4 , and the oxidation fraction used in the calculation.
(11) Methane emissions calculated using Equation HH-6 of this subpart, reported in metric tons CH 4 , and the oxidation fraction used in the calculation.
(12) Methane emissions calculated using Equation HH-8 of this subpart, reported in metric tons CH 4 , and the oxidation fraction used in the calculation.
(13) Methane emissions for the landfill ( i.e., the subpart HH total methane emissions). Choose the methane emissions from either Equation HH-6 or Equation HH-8 of this subpart that best represents the emissions from the landfill. If the quantity of recovered CH 4 from Equation HH-4 of this subpart is used as the value of G CH4 in Equation HH-6, use the methane emissions calculated using Equation HH-8 as the methane emissions for the landfill.
§ 98.347   Records that must be retained.
In addition to the information required by § 98.3(g), you must retain the calibration records for all monitoring equipment, including the method or manufacturer's specification used for calibration. You must retain records of all measurements made to determine tare weights and working capacities by vehicle/container type if these are used to determine the annual waste quantities.
§ 98.348   Definitions.
Except as specified in this section, all terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
Construction and demolition (C&D) waste landfill means a solid waste disposal facility subject to the requirements of part 257, subparts A or B of this chapter that receives construction and demolition waste and does not receive hazardous waste (defined in § 261.3 of this chapter) or industrial solid waste (defined in § 258.2 of this chapter) or municipal solid waste (as defined in § 98.6) other than residential lead-based paint waste. A C&D waste landfill typically receives any one or more of the following types of solid wastes: Roadwork material, excavated material, demolition waste, construction/renovation waste, and site clearance waste.
Destruction device means a flare, thermal oxidizer, boiler, turbine, internal combustion engine, or any other combustion unit used to destroy or oxidize methane contained in landfill gas.
Final cover means materials used at a landfill to meet final closure regulations of the competent federal, state, or local authority.
Industrial waste landfill means any landfill other than a municipal solid waste landfill, a RCRA Subtitle C hazardous waste landfill, or a TSCA hazardous waste landfill, in which industrial solid waste, such a RCRA Subtitle D wastes (nonhazardous industrial solid waste, defined in § 257.2 of this chapter), commercial solid wastes, or conditionally exempt small quantity generator wastes, is placed. An industrial waste landfill includes all disposal areas at the facility.
Intermediate or interim cover means the placement of material over waste in a landfill for a period of time prior to the disposal of additional waste and/or final closure as defined by state regulation, permit, guidance or written plan, or state accepted best management practice.
Landfill capacity means the maximum amount of solid waste a landfill can accept. For the purposes of this subpart, for landfills that have a permit, the landfill capacity can be determined in terms of volume or mass in the most recent permit issued by the state, local, or Tribal agency responsible for regulating the landfill, plus any in-place waste not accounted for in the most recent permit. If the owner or operator chooses to convert from volume to mass to determine its capacity, the calculation must include a site-specific density.
Leachate recirculation means the practice of taking the leachate collected from the landfill and reapplying it to the landfill by any of one of a variety of methods, including pre-wetting of the waste, direct discharge into the working face, spraying, infiltration ponds, vertical injection wells, horizontal gravity distribution systems, and pressure distribution systems.
Passive vent means a pipe or a system of pipes that allows landfill gas to flow naturally, without the use of a fan or similar mechanical draft equipment, to the surface of the landfill where an opening or pipe (vent) allows for the free flow of landfill gas to the atmosphere or to a passive vent flare without diffusion through the top layer of surface soil.
Solid waste has the meaning established by the Administrator pursuant to the Solid Waste Disposal Act (42 U.S.C.A. 6901 et seq. ).
Working capacity means the maximum volume or mass of waste that is actually placed in the landfill from an individual or representative type of container (such as a tank, truck, or roll-off bin) used to convey wastes to the landfill, taking into account that the container may not be able to be 100 percent filled and/or 100 percent emptied for each load.
§ 98.350   Definition of source category.
(a) This source category consists of anaerobic processes used to treat industrial wastewater and industrial wastewater treatment sludge at facilities that perform the operations listed in this paragraph.
(1) Pulp and paper manufacturing.
(2) Food processing.
(3) Ethanol production.
(4) Petroleum refining.
(b) An anaerobic process is a procedure in which organic matter in wastewater, wastewater treatment sludge, or other material is degraded by micro-organisms in the absence of oxygen, resulting in the generation of CO 2 and CH 4 . This source category consists of the following: anaerobic reactors, anaerobic lagoons, anaerobic sludge digesters, and biogas destruction devices (for example, burners, boilers, turbines, flares, or other devices).
(1) An anaerobic reactor is an enclosed vessel used for anaerobic wastewater treatment ( e.g., upflow anaerobic sludge blanket, fixed film).
(2) An anaerobic sludge digester is an enclosed vessel in which wastewater treatment sludge is degraded anaerobically.
(3) An anaerobic lagoon is a lined or unlined earthen basin used for wastewater treatment, in which oxygen is absent throughout the depth of the basin, except for a shallow surface zone. Anaerobic lagoons are not equipped with surface aerators. Anaerobic lagoons are classified as deep (depth more than 2 meters) or shallow (depth less than 2 meters).
(c) This source category does not include municipal wastewater treatment plants or separate treatment of sanitary wastewater at industrial sites.
§ 98.351   Reporting threshold.
You must report GHG emissions under this subpart if your facility meets all of the conditions under paragraphs (a) or (b) of this section:
(a) Petroleum refineries and pulp and paper manufacturing. (1) The facility is subject to reporting under subpart Y of this part (Petroleum Refineries) or subpart AA of this part (Pulp and Paper Manufacturing).
(2) The facility meets the requirements of either § 98.2(a)(1) or (2).
(3) The facility operates an anaerobic process to treat industrial wastewater and/or industrial wastewater treatment sludge.
(b) Ethanol production and food processing facilities. (1) The facility performs an ethanol production or food processing operation, as defined in § 98.358 of this subpart.
(2) The facility meets the requirements of § 98.2(a)(2).
(3) The facility operates an anaerobic process to treat industrial wastewater and/or industrial wastewater treatment sludge.
§ 98.352   GHGs to report.
(a) You must report CH 4 generation, CH 4 emissions, and CH 4 recovered from treatment of industrial wastewater at each anaerobic lagoon and anaerobic reactor.
(b) You must report CH 4 emissions and CH 4 recovered from each anaerobic sludge digester.
(c) You must report CH 4 emissions and CH 4 destruction resulting from each biogas collection and biogas destruction device.
(d) You must report under subpart C of this part (General Stationary Fuel Combustion Sources) the emissions of CO 2 , CH 4 , and N 2 O from each stationary combustion unit associated with the biogas destruction device, if present, by following the requirements of subpart C of this part.
§ 98.353   Calculating GHG emissions.
(a) For each anaerobic reactor and anaerobic lagoon, estimate the annual mass of CH 4 generated according to the applicable requirements in paragraphs (a)(1) through (a)(2) of this section.
(1) If you measure the concentration of organic material entering the anaerobic reactors or anaerobic lagoon using methods for the determination of chemical oxygen demand (COD), then estimate annual mass of CH 4 generated using Equation II-1 of this section.
(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 5 ), then estimate annual mass of CH 4 generated using Equation II-2 of this section.
(b) For each anaerobic reactor and anaerobic lagoon from which biogas is not recovered, estimate annual CH 4 emissions using Equation II-3 of this section.
(c) For each anaerobic sludge digester, anaerobic reactor, or anaerobic lagoon from which some biogas is recovered, estimate the annual mass of CH 4 recovered according to the requirements in paragraphs (c)(1) and (c)(2) of this section. To estimate the annual mass of CH 4 recovered, you must continuously monitor biogas flow rate and determine the volume of biogas each week and the cumulative volume of biogas each year that is collected and routed to a destruction device as specified in § 98.354(h). If the gas flow meter is not equipped with automatic correction for temperature, pressure, or, if necessary, moisture content, you must determine these parameters as specified in paragraph (c)(2)(ii) of this section.
(1) If you continuously monitor CH 4 concentration (and if necessary, temperature, pressure, and moisture content required as specified in § 98.354(f)) of the biogas that is collected and routed to a destruction device using a monitoring meter specifically for CH 4 gas, as specified in § 98.354(g), you must use this monitoring system and calculate the quantity of CH 4 recovered for destruction using Equation II-4 of this section. A fully integrated system that directly reports CH 4 quantity requires only the summing of results of all monitoring periods for a given year.
(2) If you do not continuously monitor CH 4 concentration according to paragraph (c)(1) of this section, you must determine the CH 4 concentration, temperature, pressure, and, if necessary, moisture content of the biogas that is collected and routed to a destruction device according to the requirements in paragraphs (c)(2)(i) through (c)(2)(ii) of this section and calculate the quantity of CH 4 recovered for destruction using Equation II-4 of this section.
(i) Determine the CH 4 concentration in the biogas that is collected and routed to a destruction device in a location near or representative of the location of the gas flow meter at least once each calendar week; if only one measurement is made each calendar week, there must be least three days between measurements. For a given calendar week, you are not required to determine CH 4 concentration if the cumulative volume of biogas for that calendar week, determined as specified in paragraph (c) of this section, is zero.
(ii) If the gas flow meter is not equipped with automatic correction for temperature, pressure, or, if necessary, moisture content:
(A) Determine the temperature and pressure in the biogas that is collected and routed to a destruction device in a location near or representative of the location of the gas flow meter at least once each calendar week; if only one measurement is made each calendar week, there must be at least three days between measurements.
(B) If the CH 4 concentration is determined on a dry basis and biogas flow is determined on a wet basis, or CH 4 concentration is determined on a wet basis and biogas flow is determined on a dry basis, and the flow meter does not automatically correct for moisture content, determine the moisture content in the biogas that is collected and routed to a destruction device in a location near or representative of the location of the gas flow meter at least once each calendar week that the cumulative biogas flow measured as specified in § 98.354(h) is greater than zero; if only one measurement is made each calendar week, there must be at least three days between measurements.
(d) For each anaerobic sludge digester, anaerobic reactor, or anaerobic lagoon from which some quantity of biogas is recovered, you must estimate both the annual mass of CH 4 that is generated, but not recovered, according to paragraph (d)(1) of this section and the annual mass of CH 4 emitted according to paragraph (d)(2) of this section.
(1) Estimate the annual mass of CH 4 that is generated, but not recovered, using Equation II-5 of this section.
(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 4 emitted using Equation II-6 of this section.
(e) Estimate the total mass of CH 4 emitted from all anaerobic processes from which biogas is not recovered (calculated in Eq. II-3) and all anaerobic processes from which some biogas is recovered (calculated in Equation II-6) using Equation II-7 of this section.
§ 98.354   Monitoring and QA/QC requirements.
(a) For calendar year 2011 monitoring, the facility may submit a request to the Administrator to use one or more best available monitoring methods as listed in § 98.3(d)(1)(i) through (iv). The request must be submitted no later than 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 5 specified in 40 CFR 136.3 Table 1B. For the purpose of determining concentrations of wastewater influent to the anaerobic wastewater treatment process, samples may be diluted to the concentration range of the approved method, but the calculated concentration of the undiluted wastewater must be used for calculations and reporting required by this subpart.
(c) You must collect samples representing wastewater influent to the anaerobic wastewater treatment process, following all preliminary and primary treatment steps ( e.g., after grit removal, primary clarification, oil-water separation, dissolved air flotation, or similar solids and oil separation processes). You must collect and analyze samples for COD or BOD 5 concentration at least once each calendar week that the anaerobic wastewater treatment process is operating; if only one measurement is made each calendar week, there must be at least three days between measurements. You must collect a sample that represents the average COD or BOD 5 concentration of the waste stream over a 24-hour sampling period. You must collect a minimum of four sample aliquots per 24-hour period and composite the aliquots for analysis. Collect a flow-proportional composite sample (either constant time interval between samples with sample volume proportional to stream flow, or constant sample volume with time interval between samples proportional to stream flow). Follow sampling procedures and techniques presented in Chapter 5, Sampling, of the “NPDES Compliance Inspection Manual,” (incorporated by reference, see § 98.7) or Section 7.1.3, Sample Collection Methods, of the “U.S. EPA NPDES Permit Writers' Manual,” (incorporated by reference, see § 98.7).
(d) You must measure the flowrate of wastewater entering anaerobic wastewater treatment process at least once each calendar week that the process is operating; if only one measurement is made each calendar week, there must be at least three days between measurements. You must measure the flowrate for the 24-hour period for which you collect samples analyzed for COD or BOD 5 concentration. The flow measurement location must correspond to the location used to collect samples analyzed for COD or BOD 5 concentration. You must measure the flowrate using one of the methods specified in paragraphs (d)(1) through (d)(5) of this section or as specified by the manufacturer.
(1) ASME MFC-3M-2004 Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and Venturi (incorporated by reference, see § 98.7).
(2) ASME MFC-5M-1985 (Reaffirmed 1994) Measurement of Liquid Flow in Closed Conduits Using Transit-Time Ultrasonic Flowmeters (incorporated by reference, see § 98.7).
(3) ASME MFC-16-2007 Measurement of Liquid Flow in Closed Conduits with Electromagnetic Flowmeters (incorporated by reference, see § 98.7).
(4) ASTM D1941-91 (Reapproved 2007) Standard Test Method for Open Channel Flow Measurement of Water with the Parshall Flume, approved June 15, 2007, (incorporated by reference, see § 98.7).
(5) ASTM D5614-94 (Reapproved 2008) Standard Test Method for Open Channel Flow Measurement of Water with Broad-Crested Weirs, approved October 1, 2008, (incorporated by reference, see § 98.7).
(e) All wastewater flow measurement devices must be calibrated prior to the first year of reporting and recalibrated either biennially (every 2 years) or at the minimum frequency specified by the manufacturer. Wastewater flow measurement devices must be calibrated using the procedures specified by the device manufacturer.
(f) For each anaerobic process (such as anaerobic reactor, sludge digester, or lagoon) from which biogas is recovered, you must make the measurements or determinations specified in 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 4 concentration of the recovered biogas as specified in paragraph (g) of this section at a location near or representative of the location of the gas flow meter. You must determine CH 4 concentration either continuously or intermittently. If you determine the concentration intermittently, you must determine the concentration at least once each calendar week that the cumulative biogas flow measured as specified in paragraph (h) of this section is greater than zero, with at least three days between measurements.
(3) As specified in § 98.353(c) and paragraph (h) of this section, you must determine temperature, pressure, and moisture content as necessary to accurately determine the biogas flow rate and CH 4 concentration. You must determine temperature and pressure if the gas flow meter or gas composition monitor do not automatically correct for temperature or pressure. You must measure moisture content of the recovered biogas if the biogas flow rate is measured on a wet basis and the CH 4 concentration is measured on a dry basis. You must also measure the moisture content of the recovered biogas if the biogas flow rate is measured on a dry basis and the CH 4 concentration is measured on a wet basis.
(g) For each anaerobic process (such as an anaerobic reactor, sludge digester, or lagoon) from which biogas is recovered, operate, maintain, and calibrate a gas composition monitor capable of measuring the concentration of CH 4 in the recovered biogas using one of the methods specified in paragraphs (g)(1) through (g)(6) of this section or as specified by the manufacturer.
(1) Method 18 at 40 CFR part 60, appendix A-6.
(2) ASTM D1945-03, Standard Test Method for Analysis of Natural Gas by Gas Chromatography (incorporated by reference, see § 98.7).
(3) ASTM D1946-90 (Reapproved 2006), Standard Practice for Analysis of Reformed Gas by Gas Chromatography (incorporated by reference, see § 98.7).
(4) GPA Standard 2261-00, Analysis for Natural Gas and Similar Gaseous Mixtures by Gas Chromatography (incorporated by reference, see § 98.7).
(5) ASTM UOP539-97 Refinery Gas Analysis by Gas Chromatography (incorporated by reference, see § 98.7).
(6) As an alternative to the gas chromatography methods provided in paragraphs (g)(1) through (g)(5) of this section, you may use total gaseous organic concentration analyzers and calculate the CH 4 concentration following the requirements in paragraphs (g)(6)(i) through (g)(6)(iii) of this section.
(i) Use Method 25A or 25B at 40 CFR part 60, appendix A-7 to determine total gaseous organic concentration. You must calibrate the instrument with CH 4 and determine the total gaseous organic concentration as carbon (or as CH 4 ; K = 1 in Equation 25A-1 of Method 25A at 40 CFR part 60, appendix A-7).
(ii) Determine a non-methane organic carbon correction factor at the routine sampling location no less frequently than once a reporting year following the requirements in paragraphs (g)(6)(ii)(A) through (g)(6)(ii)(C) of this section.
(A) Take a minimum of three grab samples of the biogas with a minimum of 20 minutes between samples and determine the methane composition of the biogas using one of the methods specified in paragraphs (g)(1) through (g)(5) of this section.
(B) As soon as practical after each grab sample is collected and prior to the collection of a subsequent grab sample, determine the total gaseous organic concentration of the biogas using either Method 25A or 25B at 40 CFR part 60, appendix A-7 as specified in paragraph (g)(6)(i) of this section.
(C) Determine the arithmetic average methane concentration and the arithmetic average total gaseous organic concentration of the samples analyzed according to paragraphs (g)(6)(ii)(A) and (g)(6)(ii)(B) of this section, respectively, and calculate the non-methane organic carbon correction factor as the ratio of the average methane concentration to the average total gaseous organic concentration. If the ratio exceeds 1, use 1 for the non-methane organic carbon correction factor.
(iii) Calculate the CH 4 concentration as specified in Equation II-8 of this section.
(h) For each anaerobic process (such as an anaerobic reactor, sludge digester, or lagoon) from which biogas is recovered, install, operate, maintain, and calibrate a gas flow meter capable of continuously measuring the volumetric flow rate of the recovered biogas using one of the methods specified in paragraphs (h)(1) through (h)(8) of this section or as specified by the manufacturer. Recalibrate each gas flow meter either biennially (every 2 years) or at the minimum frequency specified by the manufacturer. Except as provided in § 98.353(c)(2)(iii), each gas flow meter must be capable of correcting for the temperature and pressure and, if necessary, moisture content.
(1) ASME MFC-3M-2004, Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and Venturi (incorporated by reference, see § 98.7).
(2) ASME MFC-4M-1986 (Reaffirmed 1997), Measurement of Gas Flow by Turbine Meters (incorporated by reference, see § 98.7).
(3) ASME MFC-6M-1998, Measurement of Fluid Flow in Pipes Using Vortex Flowmeters (incorporated by reference, see § 98.7).
(4) ASME MFC-7M-1987 (Reaffirmed 1992), Measurement of Gas Flow by Means of Critical Flow Venturi Nozzles (incorporated by reference, see § 98.7).
(5) ASME MFC-11M-2006 Measurement of Fluid Flow by Means of Coriolis Mass Flowmeters (incorporated by reference, see § 98.7). The mass flow must be corrected to volumetric flow based on the measured temperature, pressure, and biogas composition.
(6) ASME MFC-14M-2003 Measurement of Fluid Flow Using Small Bore Precision Orifice Meters (incorporated by reference, see § 98.7).
(7) ASME MFC-18M-2001 Measurement of Fluid Flow using Variable Area Meters (incorporated by reference, see § 98.7).
(8) Method 2A or 2D at 40 CFR part 60, appendix A-1.
(i) All temperature, pressure, and, moisture content monitors required as specified in paragraph (f) of this section must be calibrated using the procedures and frequencies where specified by the device manufacturer, if not specified use an industry accepted or industry standard practice.
(j) All equipment (temperature, pressure, and moisture content monitors and gas flow meters and gas composition monitors) must be maintained as specified by the manufacturer.
(k) If applicable, the owner or operator must document the procedures used to ensure the accuracy of measurements of COD or BOD 5 concentration, wastewater flow rate, biogas flow rate, biogas composition, temperature, pressure, and moisture content. These procedures include, but are not limited to, calibration of gas flow meters, and other measurement devices. The estimated accuracy of measurements made with these devices must also be recorded, and the technical basis for these estimates must be documented.
§ 98.355   Procedures for estimating missing data.
A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable ( e.g., if a meter malfunctions during unit operation or if a required sample is not taken), a substitute data value for the missing parameter must be used in the calculations, according to the following requirements in paragraphs (a) through (c) of this section:
(a) For each missing weekly value of COD or BOD 5 or wastewater flow entering an anaerobic wastewater treatment process, the substitute data value must be the arithmetic average of the quality-assured values of those parameters for the week immediately preceding and the week immediately following the missing data incident.
(b) For each missing value of the CH 4 content or biogas flow rates, the substitute data value must be the arithmetic average of the quality-assured values of that parameter immediately preceding and immediately following the missing data incident.
(c) If, for a particular parameter, no quality-assured data are available prior to the missing data incident, the substitute data value must be the first quality-assured value obtained after the missing data period. If, for a particular parameter, the “after” value is not obtained by the end of the reporting year, you may use the last quality-assured value obtained “before” the missing data period for the missing data substitution. You must document and keep records of the procedures you use for all such estimates.
§ 98.356   Data reporting requirements.
In addition to the information required by § 98.3(c), each annual report must contain the following information for each wastewater treatment system.
(a) 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 5 concentration of wastewater entering each anaerobic wastewater treatment process, for each week the anaerobic process was operated.
(2) Volume of wastewater entering each anaerobic wastewater treatment process for each week the anaerobic process was operated.
(3) Maximum CH 4 production potential (B 0 ) used as an input to Equation II-1 or II-2 of this subpart, from Table II-1 to this subpart.
(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 4 generated by each anaerobic wastewater treatment process, calculated using Equation II-1 or II-2 of this subpart.
(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 not recovered, you must report the annual CH 4 emissions, calculated using Equation II-3 of this subpart.
(d) For each anaerobic wastewater treatment process and anaerobic sludge digester from which some biogas is recovered, you must report:
(1) Annual quantity of CH 4 recovered from the anaerobic process calculated using Equation II-4 of this subpart.
(2) Total weekly volumetric biogas flow for each week (up to 52 weeks/year) that biogas is collected for destruction.
(3) Weekly average CH 4 concentration for each week that biogas is collected for destruction.
(4) Weekly average biogas temperature for each week at which flow is measured for biogas collected for destruction, or statement that temperature is incorporated into monitoring equipment internal calculations.
(5) Whether flow was measured on a wet or dry basis, whether CH 4 concentration was measured on a wet or dry basis, and if required for Equation II-4 of this subpart, weekly average moisture content for each week at which flow is measured for biogas collected for destruction, or statement that moisture content is incorporated into monitoring equipment internal calculations.
(6) Weekly average biogas pressure for each week at which flow is measured for biogas collected for destruction, or statement that pressure is incorporated into monitoring equipment internal calculations.
(7) CH 4 collection efficiency (CE) used in Equation II-5 of this subpart.
(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 4 emissions, as calculated by Equation II-6 of this subpart.
(e) The total mass of CH 4 emitted from all anaerobic processes from which biogas is not recovered (calculated in Equation II-3 of this subpart) and from all anaerobic processes from which some biogas is recovered (calculated in Equation II-6 of this subpart) using Equation II-7 of this subpart.
§ 98.357   Records that must be retained.
In addition to the information required by § 98.3(g), you must retain the calibration records for all monitoring equipment, including the method or manufacturer's specification used for calibration.
§ 98.358   Definitions.
Except as provided below, all terms used in this subpart have the same meaning given in the CAA and subpart A of this part.
Biogas means the combination of CO 2 , CH 4 , and other gases produced by the biological breakdown of organic matter in the absence of oxygen.
Dry milling means the process in which shelled corn is milled by dry process, without an initial steeping step.
Ethanol production means an operation that produces ethanol from the fermentation of sugar, starch, grain, or cellulosic biomass feedstocks, or the production of ethanol synthetically from petrochemical feedstocks, such as ethylene or other chemicals.
Food processing means an operation used to manufacture or process meat, poultry, fruits, and/or vegetables as defined under NAICS 3116 (Meat Product Manufacturing) or NAICS 3114 (Fruit and Vegetable Preserving and Specialty Food Manufacturing). For information on NAICS codes, see http://www.census.gov/eos/www/naics/.
Industrial wastewater means water containing wastes from an industrial process. Industrial wastewater includes water which comes into direct contact with or results from the storage, production, or use of any raw material, intermediate product, finished product, by-product, or waste product. Examples of industrial wastewater include, but are not limited to, paper mill white water, wastewater from equipment cleaning, wastewater from air pollution control devices, rinse water, contaminated stormwater, and contaminated cooling water.
Industrial wastewater treatment sludge means solid or semi-solid material resulting from the treatment of industrial wastewater, including but not limited to biosolids, screenings, grit, scum, and settled solids.
Wastewater treatment system means the collection of all processes that treat or remove pollutants and contaminants, such as soluble organic matter, suspended solids, pathogenic organisms, and chemicals from wastewater prior to its reuse or discharge from the facility.
Wet milling means the process in which shelled corn is steeped in a dilute solution of sulfurous acid (sulfur dioxide dissolved in water) prior to further processing.
Weekly average means the sum of all values measured in a calendar week divided by the number of measurements.
§ 98.360   Definition of the source category.
(a) This source category consists of livestock facilities with manure management systems that emit 25,000 metric tons CO 2 e or more per year.
(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 e or more per year. Facilities with an average annual animal population, as described in § 98.363(a)(1) and (2), below those listed in Table JJ-1 do not need to report under this rule. A facility with an annual animal population that exceeds those listed in Table JJ-1 should conduct a more thorough analysis to determine applicability.
(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.
§ 98.361   Reporting threshold.
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).
§ 98.362   GHGs to report.
(a) Livestock facilities must report annual aggregate CH 4 and N 2 O emissions for the following MMS components at the facility:
(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 2 e per year or more.
§ 98.363   Calculating GHG emissions.
(a) For all manure management system components listed in 98.360(b) except digesters, estimate the annual CH 4 emissions and sum for all the components to obtain total emissions from the manure management system for all animal types using Equation JJ-1.
(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 2006 IPCC Guidelines for National Greenhouse Gas Inventories, Volume 4, Chapter 10.
(b) For each digester, calculate the total amount of CH 4 emissions, and then sum the emissions from all digesters, as shown in Equation JJ-5 of this section.
(1) For each digester, calculate the annual CH 4 flow to the combustion device (CH 4 C) using Equation JJ-6 of this section. A fully integrated system that directly reports the quantity of CH 4 flow to the digester combustion device requires only summing the results of all monitoring periods for a given year to obtain CH 4 C.
(2) For each digester, calculate the average annual volumetric flow rate, CH 4 concentration of digester gas, temperature, and pressure at which flow are measured using Equations JJ-7 through JJ-10 of this section.
(3) For each digester, calculate the CH 4 destruction at the digester combustion device using Equation JJ-11 of this section.
(4) For each digester, calculate the CH 4 leakage using Equation JJ-12 of this section.
(c) For each MMS component, estimate the annual N 2 O emissions and sum for all MMS components to obtain total emissions from the manure management system for all animal types using Equation JJ-13 of this section.
(d) Estimate the annual total facility emissions using Equation JJ-15 of this section.
§ 98.364   Monitoring and QA/QC requirements.
(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 4 concentration of gas from digesters must be determined using ASTM D1946-90 (Reapproved 2006) Standard Practice for Analysis of Reformed Gas by Gas Chromatography (incorporated by reference see § 98.7). All gas composition monitors shall be calibrated prior to the first reporting year for biogas methane and carbon dioxide content using ASTM D1946-90 (Reapproved 2006) Standard Practice for Analysis of Reformed Gas by Gas Chromatography (incorporated by reference see § 98.7)and recalibrated either annually or at the minimum frequency specified by the manufacturer, whichever is more frequent, or whenever the error in the midrange calibration check exceeds ±10 percent. All monitors shall be maintained as specified by the manufacturer.
(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, see § 98.7).
(2) ASME MFC-4M-1986 (Reaffirmed 1997) Measurement of Gas Flow by Turbine Meters (incorporated by reference, see § 98.7).
(3) ASME MFC-6M-1998 Measurement of Fluid Flow in Pipes Using Vortex Flowmeters (incorporated by reference, see § 98.7).
(4) ASME MFC-7M-1987 (Reaffirmed 1992) Measurement of Gas Flow by Means of Critical Flow Venturi Nozzles (incorporated by reference, see § 98.7).
(5) ASME MFC-14M-2003 Measurement of Fluid Flow Using Small Bore Precision Orifice Meters (incorporated by reference, see § 98.7).
(6) ASME MFC-18M-2001 Measurement of Fluid Flow using Variable Area Meters (incorporated by reference, see § 98.7).
(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 4 concentration on a dry basis, moisture content.
§ 98.365   Procedures for estimating missing data.
(a) A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable (e.g., if a meter malfunctions during unit operation or if a required fuel sample is not taken), a substitute data value for the missing parameter shall be used in the calculations, according to the requirements in paragraph (b) of this section.
(b) For missing gas flow rates or CH 4 content data, the substitute data value shall be the arithmetic average of the quality-assured values of that parameter immediately preceding and immediately following the missing data incident. If, for a particular parameter, no quality-assured data are available prior to the missing data incident, the substitute data value shall be the first quality-assured value obtained after the missing data period.
§ 98.366   Data reporting requirements.
(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 4 emissions from manure management system components listed in § 98.360(b), except digesters (results of Equation JJ-2).
(9) VS value used (for each animal type).
(10) B 0 value used (for each animal type).
(11) Methane conversion factor used for each MMS component.
(12) Average ambient temperature used to select each methane conversion factor.
(13) N 2 O emissions (results of Equation JJ-13).
(14) N value used for each animal type.
(15) N 2 O emission factor selected for each MMS component.
(b) Facilities with anaerobic digesters must also report:
(1) CH 4 emissions from anaerobic digesters (results of Equation JJ-5).
(2) CH 4 flow to the digester combustion device for each digester (results of Equation JJ-6, or value from fully integrated monitoring system as described in 98.363(b)).
(3) CH 4 destruction for each digester (results of Equation JJ-11).
(4) CH 4 leakage for each digester (results of Equation JJ-12).
(5) Total annual volumetric biogas flow for each digester (results of Equation JJ-7).
(6) Average annual CH 4 concentration for each digester (results of Equation JJ-8).
(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.
§ 98.367   Records that must be retained.
In addition to the information required by § 98.3(g), you must retain the calibration records for all monitoring equipment, including the method or manufacturer's specification used for calibration.
§ 98.368   Definitions.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
§ 98.380   Definition of the source category.
This source category consists of producers, importers, and exporters of products listed in Table MM-1 of subpart MM that are coal-based (coal-to-liquid products).
(a) A producer is the owner or operator of a coal-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.
§ 98.381   Reporting threshold.
Any supplier of coal-to-liquid products who meets the requirements of § 98.2(a)(4) must report GHG emissions.
§ 98.382   GHGs to report.
Suppliers of coal-based liquid fuels must report the CO 2 emissions that would result from the complete combustion or oxidation of fossil-fuel products (besides coal or crude oil) produced, used as feedstock, imported, or exported during the calendar year. Additionally, producers must report CO 2 emissions that would result from the complete combustion or oxidation of any biomass co-processed with fossil fuel-based feedstocks.
§ 98.383   Calculating GHG emissions.
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 ( i.e., calculation methods for refiners apply to producers of coal-to-liquid products and calculation methods for importers and exporters of petroleum products apply to importers and exporters of coal-to-liquid products).
(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.
§ 98.384   Monitoring and QA/QC requirements.
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.
§ 98.385   Procedures for estimating missing data.
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 for estimating missing data for petroleum products in § 98.395 also applies to coal-to-liquid products.
§ 98.386   Data reporting requirements.
In addition to the information required by § 98.3(c), the following requirements apply:
(a) Producers shall report the following information for each coal-to-liquid facility:
(1) [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 2 emissions factor in metric tons CO 2 per barrel or per metric ton of product.
(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 2 emissions factor in metric tons CO 2 per barrel or metric ton of product.
(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 2 emissions in metric tons that would result from the complete combustion or oxidation of each feedstock reported in paragraph (a)(2) of this section that were calculated according to § 98.393(b) or (h).
(17) The CO 2 emissions in metric tons that would result from the complete combustion or oxidation of each product (leaving the coal-to-liquid facility) reported in paragraph (a)(6) of this section that were calculated according to § 98.393(a) or (h).
(18) Annual CO 2 emissions in metric tons that would result from the complete combustion or oxidation of each type of biomass feedstock co-processed with fossil fuel-based feedstocks reported in paragraph (a)(14) of this section, calculated according to § 98.393(c).
(19) Annual CO 2 emissions that would result from the complete combustion or oxidation of all products, calculated according to § 98.393(d).
(20) Annual quantity of bulk NGLs in metric tons or barrels received for processing during the reporting year. 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 2 emissions factor in metric tons per barrel or per metric ton of product.
(6) For each non-solid product reported in paragraph (b)(2) of this section for which Calculation 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 2 emissions in metric tons that would result from the complete combustion or oxidation of each imported product reported in paragraph (b)(2) of this section, calculated according to § 98.393(a).
(8) The total sum of CO 2 emissions that would result from the complete combustion or oxidation of all imported products, calculated according to § 98.393(e).
(c) In addition to the information required by § 98.3(c), each exporter shall report all of the following information at the corporate level:
(1) [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 2 emissions factor in metric tons CO 2 per barrel or per metric ton of product.
(6) For each non-solid product reported in paragraph (c)(2) of this section for which Calculation 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 2 emissions in metric tons that would result from the complete combustion or oxidation of each exported product reported in paragraph (c)(2) of this section, calculated according to § 98.393(a).
(8) Total sum of CO 2 emissions that would result from the complete combustion or oxidation of all exported products, calculated according to § 98.393(e).
(d) Blended feedstock and products. (1) Producers, exporters, and importers must report the following information for each blended product and feedstock where emissions were calculated according to § 98.393(i):
(i) Volume or mass of each blending component.
(ii) The CO 2 emissions in metric tons that would result from the complete combustion or oxidation of each blended feedstock or product, using Equation MM-12 or Equation MM-13 of § 98.393.
(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.
§ 98.387   Records that must be retained.
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 ( e.g., retaining copies of all reports submitted to EPA under § 98.386 and records to support information contained in those reports). Any records for petroleum products that are required to be retained in § 98.397 are also required for coal-to-liquid products.
§ 98.388   Definitions.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
§ 98.390   Definition of the source category.
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.
§ 98.391   Reporting threshold.
Any supplier of petroleum products who meets the requirements of § 98.2(a)(4) must report GHG emissions.
§ 98.392   GHGs To report.
Suppliers of petroleum products must report the CO 2 emissions that would result from the complete combustion or oxidation of each petroleum product and natural gas liquid produced, used as feedstock, imported, or exported during the calendar year. Additionally, refiners must report CO 2 emissions that would result from the complete combustion or oxidation of any biomass co-processed with petroleum feedstocks.
§ 98.393   Calculating GHG emissions.
(a) Calculation for individual products produced, imported, or exported. (1) Except as provided in paragraphs (h) and (i) of this section, any refiner, importer, or exporter shall calculate CO 2 emissions from each individual petroleum product and natural gas liquid using Equation MM-1 of this section.
(2) In the event that an individual petroleum product is produced as a solid rather than liquid any refiner, importer, or exporter shall calculate CO 2 emissions using Equation MM-1 of this section.
(b) Calculation for individual products that enter a refinery as a non-crude feedstock. (1) Except as provided in paragraphs (h) and (i) of this section, any refiner shall calculate CO 2 emissions from each non-crude feedstock using Equation MM-2 of this section.
(2) In the event that a non-crude feedstock enters a refinery as a solid rather than liquid, the refiner shall calculate CO 2 emissions using Equation MM-2 of this section.
(c) Calculation for biomass co-processed with petroleum feedstocks. (1) Refiners shall calculate CO 2 emissions from each type of biomass that enters a refinery and is co-processed with petroleum feedstocks using Equation MM-3 of this section.
(2) In the event that biomass enters a refinery as a solid rather than liquid and is co-processed with petroleum feedstocks, the refiner shall calculate CO 2 emissions from each type of biomass using Equation MM-3 of this section.
(d) Summary calculation for refinery products. Refiners shall calculate annual CO 2 emissions from all products using Equation MM-4 of this section.
(e) Summary calculation for importer and exporter products. Importers and exporters shall calculate annual CO 2 emissions from all petroleum products and natural gas liquids imported or exported, respectively, using Equations MM-1 and MM-5 of this section.
(f) Emission factors for petroleum products and natural gas liquids. The emission factor (EF i,j ) for each petroleum product and natural gas liquid shall be determined using either of the calculation methods described in paragraphs (f)(1) or (f)(2) of this section. The same calculation method must be used for the entire quantity of the product for the reporting year. For refiners, the quantity of a product that enters a refinery (i.e., a non-crude feedstock) is considered separate from the quantity of a product ex refinery gate.
(1) Calculation Method 1. To determine the emission factor (i.e., EF i in Equation MM-1) for solid products, multiply the default carbon share factor (i.e., percent carbon by mass) in column B of Table MM-1 to this subpart for the appropriate product by 44/12. For all other products, use the default CO 2 emission factor listed in column C of Table MM-1 of this subpart for the appropriate product.
(2) Calculation Method 2. (i) For solid products, develop emission factors according to Equation MM-6 of this section using a value of 1 for density and direct measurements of carbon share according to methods set forth in § 98.394(c). For all other products, develop emission factors according to Equation MM-6 of this section using direct measurements of density and carbon share according to methods set forth in § 98.394(c).
(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) Emission factors for biomass co-processed with petroleum feedstocks. Refiners shall use the most appropriate default CO 2 emission factor (EF m ) for biomass in Table MM-2 of this subpart to calculate CO 2 emissions in paragraph (c) of this section.
(h) Special procedures for blended biomass-based fuels. In the event that some portion of a petroleum product is biomass-based and was not derived by co-processing biomass and petroleum feedstocks together (i.e., the petroleum product was produced by blending a petroleum-based product with a biomass-based fuel), the reporting party shall calculate emissions for the petroleum product according to one of the methods in paragraphs (h)(1) through (h)(4) of this section, as appropriate.
(1) A reporter using Calculation Method 1 to determine the emission factor of a petroleum product shall calculate the CO 2 emissions associated with that product using Equation MM-8 of this section in place of Equation MM-1 of this section.
(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 2 emissions associated with that feedstock using Equation MM-9 of this section in place of Equation MM-2 of this section.
(3) Calculation Method 2 procedures for products. (i) A reporter using Calculation Method 2 of this subpart to determine the emission factor of a petroleum product that does not contain denatured ethanol must calculate the CO 2 emissions associated with that product using Equation MM-10 of this section in place of Equation MM-1 of this section.
(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 2 emissions using Equation MM-10a of this section.
(4) Calculation Method 2 procedures for non-crude feedstocks. (i) A refiner using Calculation Method 2 of this subpart to determine the emission factor of a non-crude petroleum feedstock that does not contain denatured ethanol must calculate the CO 2 emissions associated with that feedstock using Equation MM-11 of this section in place of Equation MM-2 of this section.
(ii) In the event that a non-crude feedstock contains denatured ethanol, refiners must follow Calculation Method 1 procedures in paragraph (h)(2) of this section.
(i) Optional procedures for blended products that do not contain biomass. (1) In the event that a reporter produces, imports, or exports a blended product that does not include biomass, the reporter may calculate emissions for the blended product according to the method in paragraph (i)(2) of this section. In the event that a refiner receives a blended non-crude feedstock that does not include biomass, the refiner may calculate emission for the blended non-crude feedstock according to the method in paragraph (i)(3) of this section. The procedures in this section may be used only if all of the following criteria are met:
(i) The reporter knows the relative proportion of each component of the blend (i.e., the mass or volume percentage).
(ii) Each component of blended product “i” or blended non-crude feedstock “j” meets the strict definition of a product listed in Table MM-1 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.
§ 98.394   Monitoring and QA/QC requirements.
(a) Determination of quantity. (1) The quantity of petroleum products, natural gas liquids, and biomass, shall be determined as follows:
(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) Equipment Calibration. (1) All measurement equipment shall be calibrated prior to its first use for reporting under this subpart, using an appropriate standard method published by a consensus based standards organization or according to the equipment manufacturer's directions.
(2) Measurement equipment shall be recalibrated at the minimum frequency specified by the standard method used or by the equipment manufacturer's directions.
(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 postpone the calibration until the next scheduled maintenance outage. The best available information from company records may be used in the interim. Such postponements shall be documented in the monitoring plan that is required under § 98.3(g)(5).
(c) Procedures for Calculation Method 2 of this subpart. (1) Reporting parties shall collect one sample of each petroleum product or natural gas liquid on any day of each calendar month of the reporting year in which the quantity of that product was measured in accordance with the requirements of this subpart. For example, if a given product was measured as entering the refinery continuously throughout the reporting year, twelve samples of that product shall be collected over the reporting year, one on any day of each calendar month of that year. If a given product was only measured from April 15 through June 10 of the reporting year, a refiner would collect three samples during that year, one during each of the calendar months of April, May and June on a day when the product was measured as either entering or exiting the refinery. Each sample shall be collected using an appropriate standard method published by a consensus-based standards organization.
(2) Mixing and handling of samples shall be performed using an appropriate standard method published by a consensus-based standards organization.
(3) Density measurement.
(i) For all products that are not solid, reporters shall test for density using an appropriate standard method published by a consensus-based standards organization.
(ii) The density value for a given petroleum product shall be generated by either making a physical composite of all of the samples collected for the reporting year and testing that single sample or by measuring the individual samples throughout the year and defining the representative density value for the sample set by numerical means, i.e., a mathematical composite. If a physical composite is chosen as the option to obtain the density value, the reporter shall submit each of the individual 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.
§ 98.395   Procedures for estimating missing data.
(a) Determination of quantity. Whenever the quality assurance procedures in § 98.394(a) cannot be followed to measure the quantity of one or more petroleum products, natural gas liquids, types of biomass, feedstocks, or crude oil during any period (e.g., if a meter malfunctions), the following missing data procedures shall be used:
(1) For quantities of a product that are purchased or sold, a period of missing data shall be substituted using a reporter's established procedures for billing purposes in that period as agreed to by the party selling or purchasing the product.
(2) For quantities of a product that are not purchased or sold but of which the custody is transferred, a period of missing data shall be substituted using a reporter's established procedures for tracking purposes in that period as agreed to by the party involved in custody transfer of the product.
(b) Determination of emission factor. Whenever any of the procedures in § 98.394(c) cannot be followed to develop an emission factor for any reason, Calculation Method 1 of this subpart must be used in place of Calculation Method 2 of this subpart for the entire reporting year.
§ 98.396   Data reporting requirements.
In addition to the information required by § 98.3(c), the following requirements apply:
(a) Refiners shall report the following information for each facility:
(1) [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 2 emissions factor in metric tons CO 2 per barrel or per metric ton of product.
(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 2 emissions factor in metric tons CO 2 per barrel or per metric ton of product.
(12) For every non-solid petroleum product and natural gas liquid reported in paragraph (a)(6) for which Calculation Method 2 was used to determine an emissions factor, report:
(i) The density test results in metric tons per barrel.
(ii) The standard method used to test density.
(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 2 emissions in metric tons that would result from the complete combustion or oxidation of each petroleum product and natural gas liquid (ex refinery gate) reported in paragraph (a)(6) of this section that were calculated according to § 98.393(a) or (h).
(17) The CO 2 emissions in metric tons that would result from the complete combustion or oxidation of each feedstock reported in paragraph (a)(2) of this section that were calculated according to § 98.393(b) or (h).
(18) The CO 2 emissions in metric tons that would result from the complete combustion or oxidation of each type of biomass feedstock co-processed with petroleum feedstocks reported in paragraph (a)(14) of this section, calculated according to § 98.393(c).
(19) The sum of CO 2 emissions that would result from the complete combustion or oxidation of all products, calculated according to § 98.393(d).
(20) 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 2 emissions factor in metric tons CO 2 per barrel or per metric ton of product.
(6) For each non-solid product reported in paragraph (b)(2) of this section for which Calculation 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 2 emissions in metric tons that would result from the complete combustion or oxidation of each imported petroleum product and natural gas liquid reported in paragraph (b)(2) of this section, calculated according to § 98.393(a).
(8) The sum of CO 2 emissions that would result from the complete combustion oxidation of all imported products, calculated according to § 98.393(e).
(c) In addition to the information required by § 98.3(c), each exporter shall report all of the following information at the corporate level:
(1) [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 2 emissions factor in metric tons CO 2 per barrel or per metric ton of product.
(6) For each non-solid product reported in paragraph (c)(2) of this section for which Calculation 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 2 emissions in metric tons that would result from the complete combustion or oxidation of for each exported petroleum product and natural gas liquid reported in paragraph (c)(2) of this section, calculated according to § 98.393(a).
(8) The sum of CO 2 emissions that would result from the complete combustion or oxidation of all exported products, calculated according to § 98.393(e).
(d) Blended non-crude feedstock and products. (1) Refineries, exporters, and importers must report the following information for each blended product and non-crude feedstock where emissions were calculated according to § 98.393(i):
(i) Volume or mass of each blending component.
(ii) The CO 2 emissions in metric tons that would result from the complete combustion or oxidation of each blended non-crude feedstock or product, using Equation MM-12 or Equation MM-13 of this section.
(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.
§ 98.397   Records that must be retained.
(a) All reporters shall retain copies of all reports submitted to EPA under § 98.396. In addition, all reporters shall maintain sufficient records to support information contained in those reports, including but not limited to information on the characteristics of their feedstocks and products.
(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 petroleum products, natural gas liquids, and biomass, reporters shall maintain metering, gauging, and other records normally maintained in the course of business to document product and feedstock flows including the date of initial calibration and the frequency of recalibration for the measurement equipment used.
(c) Reporters shall retain laboratory reports, calculations and worksheets used to estimate the CO 2 emissions of the quantities of petroleum products, natural gas liquids, biomass, and feedstocks reported under this subpart.
(d) Reporters shall maintain laboratory reports, calculations and worksheets used in the measurement of density and carbon share for any petroleum product or natural gas liquid for which CO 2 emissions were calculated using Calculation Method 2.
(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).
§ 98.398   Definitions.
Except as specified in this section, all terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
Bulk NGLs for purposes of reporting under this subpart means mixtures of NGLs that are sold or delivered as undifferentiated product.
Natural Gas Liquids (NGLs) for the purposes of reporting under this subpart means hydrocarbons that are separated from natural gas as liquids through the process of absorption, condensation, adsorption, or other methods, and are sold or delivered as differentiated product. Generally, such liquids consist of ethane, propane, butanes, or pentanes plus.
§ 98.400   Definition of the source category.
This supplier category consists of natural gas liquids fractionators and local natural gas distribution companies.
(a) Natural gas liquids fractionators are installations that fractionate natural gas liquids (NGLs) into their 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.
§ 98.401   Reporting threshold.
Any supplier of natural gas and natural gas liquids that meets the requirements of § 98.2(a)(4) must report GHG emissions associated with the products they supply.
§ 98.402   GHGs to report.
(a) NGL fractionators must report the CO 2 emissions that would result from the complete combustion or oxidation of the annual quantity of ethane, propane, normal butane, isobutane, and pentanes plus that is produced and sold or delivered to others.
(b) LDCs must report the CO 2 emissions that would result from the complete combustion or oxidation of the annual volumes of natural gas provided to end-users on their distribution systems.
§ 98.403   Calculating GHG emissions.
(a) LDCs and fractionators shall, for each individual product reported under this part, calculate the estimated CO 2 emissions that would result from the complete combustion or oxidation of the products supplied using either of Calculation Methodology 1 or 2 of this subpart:
(1) Calculation Methodology 1. NGL fractionators shall estimate CO 2 emissions that would result from the complete combustion or oxidation of the product(s) supplied using Equation NN-1 of this section. The annual volume of each NGL product supplied (Fuel h ) shall include any amount of that NGL supplied in a mixture or blend of two or more products listed in Tables NN-1 and NN-2 of this subpart. The annual volume of each NGL product supplied shall exclude any amount of that NGL contained in bulk NGLs exiting the facility ( e.g., y-grade, o-grade, and other bulk NGLs). LDCs shall estimate CO 2 emissions that would result from the complete combustion or oxidation of the natural gas received at the city gate (including natural gas that is transported by, but not owned by, the reporter) using Equation NN-1 of this section. For each product, use the default value for higher heating value and CO 2 emission factor in Table NN-1 of this subpart. Alternatively, for each product, a reporter-specific higher heating value and CO 2 emission factor may be used, in place of one or both defaults provided they are developed using methods outlined in § 98.404. For each product, you must use the same volume unit throughout the equation.
(2) Calculation Methodology 2. NGL fractionators shall estimate CO 2 emissions that would result from the complete combustion or oxidation of the product(s) supplied using Equation NN-2 of this section. The annual volume of each NGL product supplied (Fuel h ) shall include any amount of that NGL supplied in a mixture or blend of two or more products listed in Tables NN-1 and NN-2 of this subpart. The annual volume of each NGL product supplied shall exclude any amount of that NGL contained in bulk NGLs exiting the facility ( e.g., y-grade, o-grade, and other bulk NGLs). LDCs shall estimate CO 2 emissions that would result from the complete combustion or oxidation of the natural gas received at the city gate (including natural gas that is transported by, but not owned by, the reporter) using Equation NN-2 of this section. For each product, use the default CO 2 emission factor found in Table NN-2 of this subpart. Alternatively, for each product, a reporter-specific CO 2 emission factor may be used in place of the default factor, provided it is developed using methods outlined in § 98.404. For each product, you must use the same volume unit throughout the equation.
(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 emission factors found in Table NN-2 of this subpart. Alternatively, reporter-specific CO 2 emission factors may be used, provided they are developed using methods outlined in § 98.404.
(2)(i) For natural gas delivered to large end-users, use Equation NN-4 of this section and the default values for the CO 2 emission factors found in Table NN-2 of this subpart. A large end-user means any end-user facility receiving greater than or equal to 460,000 Mscf of natural gas per year. If the LDC does not know the total quantity of gas delivered to the end-user facility based on readily available information in the LDCs possession, then large end-user means any single meter at an end-user facility to which the LDC delivers equal to or greater than 460,000 Mscf per year.
(ii) Alternatively, reporter-specific CO 2 emission factors may be used, provided they are developed using methods outlined in § 98.404.
(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 2 emission factors found in Table NN-2 of this subpart. Alternatively, a reporter-specific CO 2 emission factor may be used, provided it is developed using methods outlined in § 98.404.
(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 2 emission factors found in Table NN-2 of this subpart. Alternatively, a reporter-specific CO 2 emission factor may be used, provided it is developed using methods outlined in § 98.404.
(4) Calculate the total CO 2 emissions that would result from the complete combustion or oxidation of the annual supply of natural gas to end-users that receive a supply less than 460,000 Mscf per year using Equation NN-6 of this section.
(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 2 emission factors found in Table NN-2 of this subpart.
(ii) Alternatively, reporter-specific CO 2 emission factors may be used, provided they are developed using methods outlined in § 98.404.
(2) Calculate the total CO 2 equivalent emissions that would result from the combustion or oxidation of fractionated NGLs supplied less the quantity received from other fractionators using Equation NN-8 of this section.
§ 98.404   Monitoring and QA/QC requirements.
(a) Determination of quantity. (1) NGL fractionators and LDCs shall determine the quantity of NGLs and natural gas using methods in common use in the industry for billing purposes as audited under existing Sarbanes Oxley regulation.
(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 single particular location to be the volume delivered to an individual large end-user.
(8) An LDC using Equation NN-5a and/or NN-5b of this subpart shall measure natural gas as follows:
(i) Fuel 1 shall be measured at the on-system storage injection meters and/or at the meters measuring natural gas to be liquefied.
(ii) Fuel 2 shall be measured at the meters used for measuring on-system storage withdrawals and/or LNG vaporization injection.
(iii) Fuel z shall be measured using established business practices.
(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) Determination of higher heating values (HHV). (1) When a reporter uses the default HHV provided in this section to calculate Equation NN-1 of this subpart, the appropriate value shall be taken from Table NN-1 of this subpart.
(2) When a reporter uses a reporter-specific HHV to calculate Equation NN-1 of this subpart, an appropriate standard test published by a consensus-based 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) Determination of emission factor (EF). (1) When a reporter used the default EF provided in this section to calculate Equation NN-1 of this subpart, the appropriate value shall be taken from Table NN-1 of this subpart.
(2) When a reporter used the default EF provided in this section to calculate Equation NN-2, NN-3, NN-4, NN-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 2 emission factors. Consensus-based standards organizations include, but are not limited to, the following: AGA and GPA.
(d) Equipment Calibration. (1) Equipment used to measure quantities in Equations NN-1, NN-2, NN-5a and NN-5b of this subpart shall be calibrated prior to its first use for reporting under this subpart, using a suitable standard method published by a consensus based standards organization or according to the equipment manufacturer's directions.
(2) Equipment used to measure quantities in Equations NN-1, NN-2, 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.
§ 98.405   Procedures for estimating missing data.
(a) Whenever a quality-assured value of the quantity of natural gas liquids or natural gas supplied during any period is unavailable (e.g., if a flow meter malfunctions), a substitute data value for the missing quantity measurement must be used in the calculations according to paragraphs (b) and (c) of this section.
(b) Determination of quantity. (1) NGL fractionators shall substitute meter records provided by pipeline(s) for all pipeline receipts of NGLs; by manifests for deliveries made to trucks or rail cars; or metered quantities accepted by the entities purchasing the output from the fractionator whether by pipeline or by truck or rail car. In cases where the metered data from the receiving pipeline(s) or purchasing entities are not available, fractionators may substitute estimates based on contract quantities required to be delivered under purchase or delivery contracts with other parties.
(2) LDCs shall either substitute their delivering pipeline metered deliveries at the city gate or substitute nominations and scheduled delivery quantities for the period when metered values of actual deliveries are not available.
(c) Determination of HHV and EF. (1) Whenever an LDC that makes its own HHV measurements according to established business practices cannot follow the quality assurance procedures for developing a reporter-specific HHV, as specified in § 98.404, during any period for any reason, the reporter shall use either its delivering pipeline measurements or the default HHV provided in Table NN-1 of this part for that period.
(2) Whenever an LDC that does not make its own HHV measurements according to established business practices or an NGL fractionator cannot follow the quality 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.
§ 98.406   Data reporting requirements.
(a) In addition to the information required by § 98.3(c), the annual report for each NGL fractionator covered by this rule shall contain the following information.
(1) Annual quantity (in barrels) of each NGL product supplied (including fractionated NGL products received from other NGL fractionators) in the following product categories: Ethane, propane, normal butane, isobutane, and pentanes plus (Fuel h in Equations NN-1 and NN-2 of this subpart).
(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 g in Equation NN-7 of this subpart).
(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 2 emissions (metric tons) that would result from the complete combustion or oxidation of the quantities in paragraphs (a)(1) and (a)(2) of this section, calculated in accordance with § 98.403(a) and (c)(1).
(7) Annual CO 2 mass emissions (metric tons) that would result from the combustion or oxidation of fractionated NGLs supplied less the quantity received from other fractionators, calculated in accordance with § 98.403(c)(2). If the calculated value is negative, the reporter shall report the value as zero.
(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 h in Equations NN-1 and NN-2 of this subpart).
(2) Annual volume in Mscf of natural gas placed into storage or liquefied and stored (Fuel 1 in Equation NN-5a).
(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 2 in Equation NN-5a).
(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 z in Equation NN-5b).
(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 2 mass emissions (metric tons) associated with the volumes in paragraphs (b)(1) through (b)(7) of this section, calculated in accordance with § 98.403(a) and (b)(1) through (b)(3).
(9) Annual CO 2 emissions (metric tons) that would result from the complete combustion or oxidation of the annual supply of natural gas to end-users registering less than 460,000 Mscf, calculated in accordance with § 98.403(b)(4). If the calculated value is negative, the reporter shall report the value as zero.
(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).
§ 98.407   Records that must be retained.
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 2 emissions for the volumes reported under this part.
(d) Records related to the large end-users identified in § 98.406(b)(7).
(e) Records relating to measured Btu content or carbon content showing specific industry standards used to develop reporter-specific higher heating values and emission factors.
(f) Records of such audits as required by Sarbanes Oxley regulations on the accuracy of measurements of volumes of natural gas and NGLs delivered to customers or on behalf of customers.
§ 98.408   Definitions.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
§ 98.410   Definition of the source category.
(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 4 NO 3 ). Producing nitrous oxide does not include the reuse or recycling of nitrous oxide or the creation of by-products that are released or destroyed at the production facility.
(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.
§ 98.411   Reporting threshold.
Any supplier of industrial greenhouse gases who meets the requirements of § 98.2(a)(4) must report GHG emissions.
§ 98.412   GHGs to report.
You must report the GHG emissions that would result from the release of the nitrous oxide and each fluorinated GHG that you produce, import, export, transform, or destroy during the calendar year. 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.
§ 98.413   Calculating GHG emissions.
(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: