Title 40—Protection of Environment--Volume 1
PART 98—MANDATORY GREENHOUSE GAS REPORTING
§ 98.414   Monitoring and QA/QC requirements.
(a) The mass of fluorinated GHGs, fluorinated HTFs, or nitrous oxide coming out of the production process shall be measured using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of one percent of full scale or better. If the measured mass includes more than one fluorinated GHG or fluorinated HTF, the concentrations of each of the fluorinated GHGs or fluorinated HTFs, other than low-concentration constituents, shall be measured as set forth in paragraph (n) of this section. For each fluorinated GHG or fluorinated HTF, the mean of the concentrations of that fluorinated GHG (mass fraction) measured under paragraph (n) shall be multiplied by the mass measurement to obtain the mass of that fluorinated GHG or fluorinated HTF coming out of the production process.
(b) The mass of any used fluorinated GHGs, fluorinated HTFs, or used nitrous oxide added back into the production process upstream of the output measurement in paragraph (a) of this section shall be measured using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of one percent of full scale or better. If the mass in paragraph (a) is measured by weighing containers that include returned heels as well as newly produced fluorinated GHGs or fluorinated HTFs, the returned heels shall be considered used fluorinated GHGs or fluorinated HTFs for purposes of this paragraph (b) and § 98.413(b).
(c) The mass of fluorinated GHGs, fluorinated HTFs, or nitrous oxide fed into the transformation process shall be measured using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of one percent of full scale or better.
(d) The fraction of the fluorinated GHGs, fluorinated HTFs, or nitrous oxide fed into the transformation process that is actually transformed shall be estimated considering yield calculations or quantities of unreacted fluorinated GHGs, fluorinated HTFs, or nitrous oxide permanently removed from the process and recovered, destroyed, or emitted.
(e) The mass of fluorinated GHGs, fluorinated HTFs, or nitrous oxide sent to another facility for transformation shall be measured using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of one percent of full scale or better.
(f) The mass of fluorinated GHGs or fluorinated HTFs sent to another facility for destruction shall be measured using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of one percent of full scale or better. If the measured mass includes more than trace concentrations of materials other than the fluorinated GHG or fluorinated HTF, the concentration of the fluorinated GHG or fluorinated HTF shall be estimated considering current or previous representative concentration measurements and other relevant process information. This concentration (mass fraction) shall be multiplied by the mass measurement to obtain the mass of the fluorinated GHG or fluorinated HTF sent to another facility for destruction.
(g) You must estimate the share of the mass of fluorinated GHGs or fluorinated HTFs in paragraph (f) of this section that is comprised of fluorinated GHGs or fluorinated HTFs that are not included in the mass produced in § 98.413(a) because they are removed from the production process as by-products or other wastes.
(h) You must measure the mass of each fluorinated GHG or fluorinated HTF that is fed into the destruction device and that was previously produced as defined at § 98.410(b). Such fluorinated GHGs or fluorinated HTFs include but are not limited to quantities that are shipped to the facility by another facility for destruction and quantities that are returned to the facility for reclamation but are found to be irretrievably contaminated and are therefore destroyed. You must use flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of one percent of full scale or better. If the measured mass includes more than trace concentrations of materials other than the fluorinated GHG or fluorinated HTF being destroyed, you must estimate the concentrations of the fluorinated GHG or fluorinated HTF being destroyed considering current or previous representative concentration measurements and other relevant process information. You must multiply this concentration (mass fraction) by the mass measurement to obtain the mass of the fluorinated GHG or fluorinated HTF fed into the destruction device.
(i) Very small quantities of fluorinated GHGs or fluorinated HTFs that are difficult to measure because they are entrained in other media such as destroyed filters and destroyed sample containers are exempt from paragraphs (f) and (h) of this section.
(j) [Reserved]
(k) For purposes of Equation OO-4 of this subpart, the destruction efficiency can be equated to the destruction efficiency determined during a previous performance test of the destruction device or, if no performance test has been done, the destruction efficiency provided by the manufacturer of the destruction device.
(l) In their estimates of the mass of fluorinated GHGs or fluorinated HTFs destroyed, facilities that destroy fluorinated GHGs or fluorinated HTFs shall account for any temporary reductions in the destruction efficiency that result from any startups, shutdowns, or malfunctions of the destruction device, including departures from the operating conditions defined in state or local permitting requirements and/or oxidizer manufacturer specifications.
(m) Calibrate all flow meters, weigh scales, and combinations of volumetric and density measures that are used to measure or calculate quantities that are to be reported under this subpart prior to the first year for which GHG emissions are reported under this part. Calibrations performed prior to the effective date of this rule satisfy this requirement. Recalibrate all flow meters, weigh scales, and combinations of volumetric and density measures at the minimum frequency specified by the manufacturer. Use NIST-traceable standards and suitable methods published by a consensus standards organization (e.g., ASTM, ASME, ISO, or others).
(n) If the mass coming out of the production process includes more than one fluorinated GHG or fluorinated HTF, you shall measure the concentrations of all of the fluorinated GHGs or fluorinated HTFs, other than low-concentration constituents, as follows:
(1) Analytical Methods. Use a quality-assured analytical measurement technology capable of detecting the analyte of interest at the concentration of interest and use a procedure validated with the analyte of interest at the concentration of interest. Where standards for the analyte are not available, a chemically similar surrogate may be used. Acceptable analytical measurement technologies include but are not limited to gas chromatography (GC) with an appropriate detector, infrared (IR), fourier transform infrared (FTIR), and nuclear magnetic resonance (NMR). Acceptable methods include EPA Method 18 in appendix A-1 of 40 CFR part 60; EPA Method 320 in appendix A of 40 CFR part 63; the Protocol for Measuring Destruction or Removal Efficiency (DRE) of Fluorinated Greenhouse Gas Abatement Equipment in Electronics Manufacturing, Version 1, EPA-430-R-10-003, (March 2010) (incorporated by reference, see § 98.7); ASTM D6348-03 Standard Test Method for Determination of Gaseous Compounds by Extractive Direct Interface Fourier Transform Infrared (FTIR) Spectroscopy (incorporated by reference, see § 98.7); or other analytical methods validated using EPA Method 301 in appendix A of 40 CFR part 63 or some other scientifically sound validation protocol. The validation protocol may include analytical technology manufacturer specifications or recommendations.
(2) Documentation in GHG Monitoring Plan. Describe the analytical method(s) used under paragraph (n)(1) of this section in the site GHG Monitoring Plan as required under § 98.3(g)(5). At a minimum, include in the description of the method a description of the analytical measurement equipment and procedures, quantitative estimates of the method's accuracy and precision for the analytes of interest at the concentrations of interest, as well as a description of how these accuracies and precisions were estimated, including the validation protocol used.
(3) Frequency of measurement. Perform the measurements at least once by February 15, 2011 if the fluorinated GHG product is being produced on December 17, 2010. Perform the measurements within 60 days of commencing production of any fluorinated GHG product that was not being produced on December 17, 2010. For fluorinated HTF products that are not also fluorinated GHG products, perform the measurements at least once by February 28, 2018, if the fluorinated HTF product is being produced on January 1, 2018. Perform the measurements within 60 days of commencing production of any fluorinated HTF product that was not being produced on January 1, 2018. Repeat the measurements if an operational or process change occurs that could change the identities or significantly change the concentrations of the fluorinated GHG or fluorinated HTF constituents of the fluorinated GHG or fluorinated HTF product. Complete the repeat measurements within 60 days of the operational or process change.
(4) Measure all product grades. Where a fluorinated GHG or fluorinated HTF is produced at more than one purity level ( e.g., pharmaceutical grade and refrigerant grade), perform the measurements for each purity level.
(5) Number of samples. Analyze a minimum of three samples of the fluorinated GHGs or fluorinated HTF product that have been drawn under conditions that are representative of the process producing the fluorinated GHGs or fluorinated HTF product. If the relative standard deviation of the measured concentrations of any of the fluorinated GHGs or fluorinated HTF constituents (other than low-concentration constituents) is greater than or equal to 15 percent, draw and analyze enough additional samples to achieve a total of at least six samples of the fluorinated GHG or fluorinated HTF product.
(o) All analytical equipment used to determine the concentration of fluorinated GHGs or fluorinated HTFs, including but not limited to gas chromatographs and associated detectors, IR, FTIR and NMR devices, shall be calibrated at a frequency needed to support the type of analysis specified in the site GHG Monitoring Plan as required under paragraph (n) of this section and § 98.3(g)(5). Quality assurance samples at the concentrations of concern shall be used for the calibration. Such quality assurance samples shall consist of or be prepared from certified standards of the analytes of concern where available; if not available, calibration shall be performed by a method specified in the GHG Monitoring Plan.
(p) Isolated intermediates that are produced and transformed at the same facility are exempt from the monitoring requirements of this section.
(q) Low-concentration constituents are exempt from the monitoring and QA/QC requirements of this section.
§ 98.415   Procedures for estimating missing data.
(a) A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable (e.g., if a meter malfunctions), a substitute data value for the missing parameter shall be used in the calculations, according to paragraph (b) of this section.
(b) For each missing value of the mass produced, fed into the production process (for used material being reclaimed), fed into the transformation process, fed into destruction devices, sent to another facility for transformation, or sent to another facility for destruction, the substitute value of that parameter shall be a secondary mass measurement where such a measurement is available. For example, if the mass produced is usually measured with a flowmeter at the inlet to the day tank and that flowmeter fails to meet an accuracy or precision test, malfunctions, or is rendered inoperable, then the mass produced may be estimated by calculating the change in volume in the day tank and multiplying it by the density of the product. Where a secondary mass measurement is not available, the substitute value of the parameter shall be an estimate based on a related parameter. For example, if a flowmeter measuring the mass fed into a destruction device is rendered inoperable, then the mass fed into the destruction device may be estimated using the production rate and the previously observed relationship between the production rate and the mass flow rate into the destruction device.
§ 98.416   Data reporting requirements.
In addition to the information required by § 98.3(c), each annual report must contain the following information:
(a) Each fluorinated GHG, fluorinated HTF, or nitrous oxide production facility shall report the following information:
(1) Mass in metric tons of nitrous oxide and each fluorinated GHG or fluorinated HTF produced at that facility by process, except for amounts that are captured solely to be shipped off site for destruction.
(2) Mass in metric tons of nitrous oxide and each fluorinated GHG or fluorinated HTF transformed at that facility, by process.
(3) Mass in metric tons of each fluorinated GHG or fluorinated HTF that is destroyed at that facility and that was previously produced as defined at § 98.410(b). Quantities to be reported under paragraph (a)(3) of this section include but are not limited to quantities that are shipped to the facility by another facility for destruction and quantities that are returned to the facility for reclamation but are found to be irretrievably contaminated and are therefore destroyed.
(4) [Reserved]
(5) Total mass in metric tons of nitrous oxide and each fluorinated GHG or fluorinated HTF sent to another facility for transformation.
(6) Total mass in metric tons of each fluorinated GHG or fluorinated HTF sent to another facility for destruction, except fluorinated GHGs and fluorinated HTFs that are not included in the mass produced in § 98.413(a) because they are removed from the production process as byproducts or other wastes. Quantities to be reported under paragraph (a)(6) of this section could include, for example, fluorinated GHGs that are returned to the facility for reclamation but are found to be irretrievably contaminated and are therefore sent to another facility for destruction.
(7) Total mass in metric tons of each fluorinated GHG or fluorinated HTF that is sent to another facility for destruction and that is not included in the mass produced in § 98.413(a) because it is removed from the production process as a byproduct or other waste.
(8)-(9) [Reserved]
(10) Mass in metric tons of nitrous oxide and each fluorinated GHG or fluorinated HTF fed into the transformation process, by process.
(11) Mass in metric tons of each fluorinated GHG or fluorinated HTF that is fed into the destruction device and that was previously produced as defined at § 98.410(b). Quantities to be reported under paragraph (a)(11) of this section include but are not limited to quantities that are shipped to the facility by another facility for destruction and quantities that are returned to the facility for reclamation but are found to be irretrievably contaminated and are therefore destroyed.
(12) Mass in metric tons of nitrous oxide and each fluorinated GHG or fluorinated HTF that is measured coming out of the production process, by process.
(13) Mass in metric tons of used nitrous oxide and of each used fluorinated GHG or fluorinated HTF added back into the production process ( e.g., for reclamation), including returned heels in containers that are weighed to measure the mass in § 98.414(a), by process.
(14) Names and addresses of facilities to which any nitrous oxide, fluorinated GHGs, or fluorinated HTFs were sent for transformation, and the quantities (metric tons) of nitrous oxide and of each fluorinated GHG or fluorinated HTF that were sent to each for transformation.
(15) Names and addresses of facilities to which any fluorinated GHGs or fluorinated HTFs were sent for destruction, and the quantities (metric tons) of each fluorinated GHG or fluorinated HTF that were sent to each for destruction.
(16) Where missing data have been estimated pursuant to § 98.415, the reason the data were missing, the length of time the data were missing, the method used to estimate the missing data, and the estimates of those data.
(b) Any facility or importer that destroys fluorinated GHGs or fluorinated HTFs shall submit a one-time report containing the information in paragraphs (b)(1) through (6) of this section for each destruction process by the applicable date set forth in paragraph (b)(7) of this section. Facilities and importers that previously submitted one-time reports under this paragraph for all destruction devices used to destroy fluorinated GHGs or fluorinated HTFs are exempt from this requirement unless they meet the conditions in paragraph (b)(6) of this section.
(1) Destruction efficiency (DE).
(2) Methods used to determine the destruction efficiency.
(3) Methods used to record the mass of fluorinated GHG or fluorinated HTF destroyed.
(4) Chemical identity of the fluorinated GHG(s) used in the performance test conducted to determine DE.
(5) Name of all applicable federal or state regulations that may apply to the destruction process.
(6) If any process changes (including the acquisition of a new destruction device) affect unit destruction efficiency or the methods used to record the mass of fluorinated GHG or fluorinated HTF destroyed, then a revised report must be submitted to reflect the changes. The revised report must be submitted to EPA within 60 days of the change.
(7)(i) Any fluorinated GHG production facility or importer that destroys fluorinated GHGs must submit the one-time destruction report by March 31, 2011 or within 60 days of commencing fluorinated GHG destruction, whichever is later.
(ii) Any fluorinated GHG production facility or importer that destroys fluorinated HTFs that are not also fluorinated GHGs must submit the one-time destruction report by March 31, 2019 or within 60 days of commencing fluorinated HTF destruction, whichever is later.
(iii) Any facility that destroys fluorinated GHGs or fluorinated HTFs but does not produce or import fluorinated GHGs must submit the one-time destruction report by March 31, 2019 or within 60 days of commencing fluorinated GHG or fluorinated HTF destruction, whichever is later.
(c) Each bulk importer of fluorinated GHGs, fluorinated heat transfer fluids (HTFs), or nitrous oxide shall submit an annual report that summarizes its imports at the corporate level, except importers may exclude shipments including less than twenty-five kilograms of fluorinated GHGs, fluorinated HTFs, or nitrous oxide; transshipments if the importer also excludes transshipments from reporting of exports under paragraph (d) of this section; and heels that meet the conditions set forth at § 98.417(e) if the importer also excludes heels from any reporting of exports under paragraph (d) of this section. The report shall contain the following information for each import:
(1) Total mass in metric tons of nitrous oxide and each fluorinated GHG or fluorinated HTF imported in bulk, including each fluorinated GHG or fluorinated HTF constituent of the fluorinated GHG or fluorinated HTF product that makes up between 0.5 percent and 100 percent of the product by mass.
(2) Total mass in metric tons of nitrous oxide and each fluorinated GHG or fluorinated HTF imported in bulk and sold or transferred to persons other than the importer for use in processes resulting in the transformation or destruction of the chemical.
(3) Date on which the fluorinated GHGs, fluorinated HTFs, or nitrous oxide were imported.
(4) Port of entry through which the fluorinated GHGs, fluorinated HTFs, or nitrous oxide passed.
(5) Country from which the imported fluorinated GHGs, fluorinated HTFs, or nitrous oxide were imported.
(6) Harmonized tariff system (HTS) code of the fluorinated GHGs, fluorinated HTFs, or nitrous oxide shipped.
(7) Customs entry number and importer number for each shipment.
(8) Total mass in metric tons of each fluorinated GHG or fluorinated HTF destroyed by the importer.
(9) If applicable, the names and addresses of the persons and facilities to which the nitrous oxide, fluorinated GHGs, or fluorinated HTFs were sold or transferred for transformation, and the quantities (metric tons) of nitrous oxide and of each fluorinated GHG or fluorinated HTF that were sold or transferred to each facility for transformation.
(10) If applicable, the names and addresses of the persons and facilities to which the fluorinated GHGs or fluorinated HTFs were sold or transferred for destruction, and the quantities (metric tons) of each fluorinated GHG or fluorinated HTF that were sold or transferred to each facility for destruction.
(d) Each bulk exporter of fluorinated GHGs, fluorinated HTFs, or nitrous oxide shall submit an annual report that summarizes its exports at the corporate level, except reporters may exclude shipments including less than twenty-five kilograms of fluorinated GHGs, fluorinated HTFs, or nitrous oxide; transshipments if the exporter also excludes transshipments from reporting of imports under paragraph (c) of this section; and heels if the exporter also excludes heels from any reporting of imports under paragraph (c) of this section. The report shall contain the following information for each export:
(1) Total mass in metric tons of nitrous oxide and each fluorinated GHG or fluorinated HTF exported in bulk.
(2) Names and addresses of the exporter and the recipient of the exports.
(3) Exporter's Employee Identification Number.
(4) Harmonized tariff system (HTS) code of the fluorinated GHGs, fluorinated HTFs, or nitrous oxide shipped.
(5) Date on which, and the port from which, the fluorinated GHGs, fluorinated HTFs, or nitrous oxide were exported from the United States or its territories.
(6) Country to which the fluorinated GHGs, fluorinated HTFs, or nitrous oxide were exported.
(e) By March 31, 2011, or within 60 days of commencing fluorinated GHG production, whichever is later, a fluorinated GHG production facility shall submit a one-time report describing the following information:
(1) The method(s) by which the producer in practice measures the mass of fluorinated GHGs produced, including the instrumentation used (Coriolis flowmeter, other flowmeter, weigh scale, etc.) and its accuracy and precision.
(2) The method(s) by which the producer in practice estimates the mass of fluorinated GHGs fed into the transformation process, including the instrumentation used (Coriolis flowmeter, other flowmeter, weigh scale, etc.) and its accuracy and precision.
(3) The method(s) by which the producer in practice estimates the fraction of fluorinated GHGs fed into the transformation process that is actually transformed, and the estimated precision and accuracy of this estimate.
(4) The method(s) by which the producer in practice estimates the masses of fluorinated GHGs fed into the destruction device, including the method(s) used to estimate the concentration of the fluorinated GHGs in the destroyed material, and the estimated precision and accuracy of this estimate.
(5) The estimated percent efficiency of each production process for the fluorinated GHG produced.
(f) By March 31, 2011, all fluorinated GHG production facilities shall submit a one-time report that includes the concentration of each fluorinated GHG constituent in each fluorinated GHG product as measured under § 98.414(n). If the facility commences production of a fluorinated GHG product that was not included in the initial report or performs a repeat measurement under § 98.414(n) that shows that the identities or concentrations of the fluorinated GHG constituents of a fluorinated GHG product have changed, then the new or changed concentrations, as well as the date of the change, must be reflected in a revision to the report. The revised report must be submitted to EPA by the March 31st that immediately follows the measurement under § 98.414(n).
(g) Isolated intermediates that are produced and transformed at the same facility are exempt from the reporting requirements of this section.
(h) Low-concentration constituents are exempt from the reporting requirements of this section.
(i) Each facility that destroys fluorinated GHGs or fluorinated HTFs but does not otherwise report under this section shall report the mass in metric tons of each fluorinated GHG or fluorinated HTF that is destroyed at that facility and that was previously produced as defined at § 98.410(b) or (d), as applicable. Quantities to be reported under this paragraph (i) include but are not limited to quantities that are shipped to the facility by another facility for destruction and quantities that are returned to the facility for reclamation but are found to be irretrievably contaminated and are therefore destroyed.
(j) By March 31, 2019, all facilities that produce fluorinated HTFs that are not also fluorinated GHGs shall submit a one-time report that includes the concentration of each fluorinated HTF or fluorinated GHG constituent in each fluorinated HTF product as measured under § 98.414(n). If the facility commences production of a fluorinated HTF product that was not included in the initial report or performs a repeat measurement under § 98.414(n) that shows that the identities or concentrations of the fluorinated HTF or fluorinated GHG constituents of a fluorinated HTF product have changed, then the new or changed concentrations, as well as the date of the change, must be provided in a revised report. The revised report must be submitted to EPA by the March 31st that immediately follows the new or repeat measurement under § 98.414(n).
(k) For nitrous oxide, saturated perfluorocarbons, sulfur hexafluoride, and fluorinated heat transfer fluids as defined at § 98.6, report the end use(s) for which each GHG or fluorinated HTF is transferred and the aggregated annual quantity of that GHG or fluorinated HTF in metric tons that is transferred to that end use application, if known.
§ 98.417   Records that must be retained.
(a) In addition to the data required by § 98.3(g), the fluorinated GHG or fluorinated HTF production facility shall retain the following records:
(1) Dated records of the data used to estimate the data reported under § 98.416.
(2) Records documenting the initial and periodic calibration of the analytical equipment (including but not limited to GC, IR, FTIR, or NMR), weigh scales, flowmeters, and volumetric and density measures used to measure the quantities reported under this subpart, including the manufacturer directions or industry standards used for calibration pursuant to § 98.414(m) and (o).
(3) Dated records of the total mass in metric tons of each reactant fed into the fluorinated GHG, fluorinated HTF, or nitrous oxide production process, by process.
(4) Dated records of the total mass in metric tons of the reactants, by-products, and other wastes permanently removed from the fluorinated GHG, fluorinated HTF, or nitrous oxide production process, by process.
(b) In addition to the data required by paragraph (a) of this section, any facility that destroys fluorinated GHGs or fluorinated HTFs shall keep records of test reports and other information documenting the facility's one-time destruction efficiency report in § 98.416(b).
(c) In addition to the data required by § 98.3(g), the bulk importer shall retain the following records substantiating each of the imports that they report:
(1) A copy of the bill of lading for the import.
(2) The invoice for the import.
(3) The U.S. Customs entry form.
(d) In addition to the data required by § 98.3(g), the bulk exporter shall retain the following records substantiating each of the exports that they report:
(1) A copy of the bill of lading for the export and
(2) The invoice for the export.
(e) Every person who imports a container with a heel that is not reported under § 98.416(c) shall keep records of the amount brought into the United States that document that the residual amount in each shipment is less than 10 percent of the volume of the container and will:
(1) Remain in the container and be included in a future shipment.
(2) Be recovered and transformed.
(3) Be recovered and destroyed.
(4) Be recovered and included in a future shipment.
(f) Isolated intermediates that are produced and transformed at the same facility are exempt from the recordkeeping requirements of this section.
(g) Low-concentration constituents are exempt from the recordkeeping requirements of this section.
§ 98.418   Definitions.
Except as provided below, all of the terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. If a conflict exists between a definition provided in this subpart and a definition provided in subpart A, the definition in this subpart shall take precedence for the reporting requirements in this subpart.
Isolated intermediate means a product of a process that is stored before subsequent processing. An isolated intermediate is usually a product of chemical synthesis. Storage of an isolated intermediate marks the end of a process. Storage occurs at any time the intermediate is placed in equipment used solely for storage.
Low-concentration constituent means, for purposes of fluorinated GHG or fluorinated HTF production and export, a fluorinated GHG or fluorinated HTF constituent of a fluorinated GHG or fluorinated HTF product that occurs in the product in concentrations below 0.1 percent by mass. For purposes of fluorinated GHG or fluorinated HTF import, low-concentration constituent means a fluorinated GHG or fluorinated HTF constituent of a fluorinated GHG or fluorinated HTF product that occurs in the product in concentrations below 0.5 percent by mass. Low-concentration constituents do not include fluorinated GHGs or fluorinated HTFs that are deliberately combined with the product ( e.g., to affect the performance characteristics of the product).
§ 98.420   Definition of the source category.
(a) The carbon dioxide (CO 2 ) supplier source category consists of the following:
(1) Facilities with production process units that capture a CO 2 stream for purposes of supplying CO 2 for commercial applications or that capture and maintain custody of a CO 2 stream in order to sequester or otherwise inject it underground. Capture refers to the initial separation and removal of CO 2 from a manufacturing process or any other process.
(2) Facilities with CO 2 production wells that extract or produce a CO 2 stream for purposes of supplying CO 2 for commercial applications or that extract and maintain custody of a CO 2 stream in order to sequester or otherwise inject it underground.
(3) Importers or exporters of bulk CO 2 .
(4) Facilities with process units, including but not limited to direct air capture (DAC), that capture a CO 2 stream from ambient air for purposes of supplying CO 2 for commercial applications or that capture and maintain custody of a CO 2 stream in order to sequester or otherwise inject it underground.
(b) This source category is focused on upstream supply. It does not cover:
(1) Storage of CO 2 above ground or in geologic formations.
(2) Use of CO 2 in enhanced oil and gas recovery.
(3) Transportation or distribution of CO 2 .
(4) Purification, compression, or processing of CO 2 .
(5) On-site use of CO 2 captured on site.
(c) This source category does not include CO 2 imported or exported in equipment, such as fire extinguishers.
§ 98.421   Reporting threshold.
Any supplier of CO 2 who meets the requirements of § 98.2(a)(4) of subpart A of this part must report the mass of CO 2 captured, extracted, imported, or exported.
§ 98.422   GHGs to report.
(a) Mass of CO 2 captured from production process units.
(b) Mass of CO 2 extracted from CO 2 production wells.
(c) Mass of CO 2 imported.
(d) Mass of CO 2 exported.
(e) Mass of CO 2 captured from DAC process units.
(1) Mass of CO 2 captured from ambient air.
(2) Mass of CO 2 captured from any on-site heat and/or electricity generation, where applicable.
§ 98.423   Calculating CO2supply.
(a) Except as allowed in paragraph (b) of this section, calculate the annual mass of CO 2 captured, extracted, imported, or exported through each flow meter in accordance with the procedures specified in either paragraph (a)(1) or (a)(2) of this section. If multiple flow meters are used, you shall calculate the annual mass of CO 2 for all flow meters according to the procedures specified in paragraph (a)(3) of this section.
(1) For each mass flow meter, you shall calculate quarterly the mass of CO 2 in a CO 2 stream in metric tons by multiplying the mass flow by the composition data, according to Equation PP-1 of this section. Mass flow and composition data measurements shall be made in accordance with § 98.424 of this subpart.
(2) For each volumetric flow meter, you shall calculate quarterly the mass of CO 2 in a CO 2 stream in metric tons by multiplying the volumetric flow by the concentration and density data, according to Equation PP-2 of this section. Volumetric flow, concentration and density data measurements shall be made in accordance with § 98.424 of this section.
(3) To aggregate data, use either Equation PP-3a or PP-3b in this paragraph, as appropriate.
(i) For facilities with production process units, DAC process units, or production wells that capture or extract a CO 2 stream and either measure it after segregation or do not segregate the flow, calculate the total CO 2 supplied in accordance with equation PP-3a to paragraph (a)(3)(i) of this section.
(ii) For facilities with production process units or DAC process units that capture a CO 2 stream and measure it ahead of segregation, calculate the total CO 2 supplied in accordance with equation PP-3b to paragraph (a)(3)(ii) of this section.
(b) As an alternative to paragraphs (a)(1) through (3) of this section for CO 2 that is supplied in containers, calculate the annual mass of CO 2 supplied in containers delivered by each CO 2 stream in accordance with the procedures specified in either paragraph (b)(1) or (b)(2) of this section. If multiple CO 2 streams are used to deliver CO 2 to containers, you shall calculate the annual mass of CO 2 supplied in containers delivered by all CO 2 streams according to the procedures specified in paragraph (b)(3) of this section.
(1) For each CO 2 stream that delivers CO 2 to containers, for which mass is measured, you shall calculate CO 2 supply in containers using Equation PP-1 of this section.
(2) For each CO 2 stream that delivers to containers, for which volume is measured, you shall calculate CO 2 supply in containers using Equation PP-2 of this section.
(3) To aggregate data, sum the mass of CO 2 supplied in containers delivered by all CO 2 streams in accordance with Equation PP-3a of this section.
(c) Importers or exporters that import or export CO 2 in containers shall calculate the total mass of CO 2 imported or exported in metric tons based on summing the mass in each CO 2 container using weigh bills, scales, or load cells according to Equation PP-4 of this section.
§ 98.424   Monitoring and QA/QC requirements.
(a) Determination of quantity. (1) Reporters following the procedures in § 98.423(a) shall determine quantity using a flow meter or meters located in accordance with this paragraph.
(i) If the CO 2 stream is segregated such that only a portion is captured for commercial application or for injection, you must locate the flow meter according to the following:
(A) For reporters following the procedures in § 98.423(a)(3)(i), you must locate the flow meter(s) after the point of segregation.
(B) For reporters following the procedures in paragraph (a)(3)(ii) of § 98.423, you must locate the main flow meter(s) on the captured CO 2 stream(s) prior to the point of segregation and the subsequent flow meter(s) on the CO 2 stream(s) for on-site use after the point of segregation. You may only follow the procedures in paragraph (a)(3)(ii) of § 98.423 if the CO 2 stream(s) for on-site use is/are the only diversion(s) from the main, captured CO 2 stream(s) after the main flow meter location(s).
(ii) Reporters that have a mass flow meter or volumetric flow meter installed to measure the flow of a CO 2 stream that meets the requirements of paragraph (a)(1)(i) of this section shall base calculations in § 98.423 of this subpart on the installed mass flow or volumetric flow meters.
(iii) Reporters that do not have a mass flow meter or volumetric flow meter installed to measure the flow of the CO 2 stream that meets the requirements of paragraph (a)(1)(i) of this section shall base calculations in § 98.423 of this subpart on the flow of gas transferred off site using a mass flow meter or a volumetric flow meter located at the point of off-site transfer.
(2) Reporters following the procedures in paragraph (b) of § 98.423 shall determine quantity in accordance with this paragraph.
(i) Reporters that supply CO 2 in containers using weigh bills, scales, or load cells shall measure the mass of contents of each CO 2 container to which the CO 2 stream is delivered, sum the mass of contents supplied in all containers to which the CO 2 stream is delivered during each quarter, sample the CO 2 stream delivering CO 2 to containers on a quarterly basis to determine the composition of the CO 2 stream, and apply Equation PP-1.
(ii) Reporters that supply CO 2 in containers using loaded container volumes shall measure the volume of contents of each CO 2 container to which the CO 2 stream is delivered, sum the volume of contents supplied in all containers to which the CO 2 stream is delivered during each quarter, sample the CO 2 stream on a quarterly basis to determine the composition of the CO 2 stream, determine the density quarterly, and apply Equation PP-2.
(3) Importers or exporters that import or export CO 2 in containers shall measure the mass in each CO 2 container using weigh bills, scales, or load cells and sum the mass in all containers imported or exported during the reporting year.
(4) All flow meters, scales, and load cells used to measure quantities that are reported in § 98.423 of this subpart shall be operated and calibrated according to the following procedure:
(i) You shall use an appropriate standard method published by a consensus-based standards organization if such a method exists. Consensus-based standards organizations include, but are not limited to, the following: ASTM International, the American National Standards Institute (ANSI), the American Gas Association (AGA), the American Society of Mechanical Engineers (ASME), the American Petroleum Institute (API), and the North American Energy Standards Board (NAESB).
(ii) Where no appropriate standard method developed by a consensus-based standards organization exists, you shall follow industry standard practices.
(iii) You must ensure that any flow meter calibrations performed are NIST traceable.
(5) Reporters using Equation PP-2 of this subpart and measuring CO 2 concentration as weight % CO 2 shall determine the density of the CO 2 stream on a quarterly basis in order to calculate the mass of the CO 2 stream according to one of the following procedures:
(i) You may use a method published by a consensus-based standards organization. Consensus-based standards organizations include, but are not limited to, the following: ASTM International (100 Barr Harbor Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959, (800) 262-1373, http://www.astm.org ), the American National Standards Institute (ANSI, 1819 L Street, NW., 6th floor, Washington, DC 20036, (202) 293-8020, http://www.ansi.org ), the American Gas Association (AGA, 400 North Capitol Street, NW., 4th Floor, Washington, DC 20001, (202) 824-7000, http://www.aga.org ), the American Society of Mechanical Engineers (ASME, Three Park Avenue, New York, NY 10016-5990, (800) 843-2763, http://www.asme.org ), the American Petroleum Institute (API, 1220 L Street, NW., Washington, DC 20005-4070, (202) 682-8000, http://www.api.org ), and the North American Energy Standards Board (NAESB, 801 Travis Street, Suite 1675, Houston, TX 77002, (713) 356-0060, http://www.api.org ). The method(s) used shall be documented in the Monitoring Plan required under § 98.3(g)(5).
(ii) You may follow an industry standard method.
(b) Determination of concentration. (1) Reporters using Equation PP-1 or PP-2 of this subpart shall sample the CO 2 stream on a quarterly basis to determine the composition of the CO 2 stream.
(2) Methods to measure the composition of the CO 2 stream must conform to applicable chemical analytical standards. Acceptable methods include, but are not limited to, the U.S. Food and Drug Administration food-grade specifications for CO 2 ( see 21 CFR 184.1240) and ASTM standard E1747-95 (Reapproved 2005) Standard Guide for Purity of Carbon Dioxide Used in Supercritical Fluid Applications (ASTM International, 100 Barr Harbor Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959, (800) 262-1373, http://www.astm.org ).
(c) You shall convert the density of the CO 2 stream(s) and all measured volumes of carbon dioxide to the following standard industry temperature and pressure conditions: Standard cubic meters at a temperature of 60 degrees Fahrenheit and at an absolute pressure of 1 atmosphere. If you apply the density value for CO 2 at standard conditions, you must use 0.001868 metric tons per standard cubic meter.
§ 98.425   Procedures for estimating missing data.
(a) Whenever the quality assurance procedures in § 98.424(a)(1) of this subpart cannot be followed to measure quarterly mass flow or volumetric flow of CO 2 , the most appropriate of the following missing data procedures shall be followed:
(1) A quarterly CO 2 mass flow or volumetric flow value that is missing may be substituted with a quarterly value measured during another quarter of the current reporting year.
(2) A quarterly CO 2 mass flow or volumetric flow value that is missing may be substituted with a quarterly value measured during the same quarter from the past reporting year.
(3) If a mass or volumetric flow meter is installed to measure the CO 2 stream, you may substitute data from a mass or volumetric flow meter measuring the CO 2 stream transferred for any period during which the installed meter is inoperable.
(4) The mass or volumetric flow used for purposes of product tracking and billing according to the reporter's established procedures may be substituted for any period during which measurement equipment is inoperable.
(b) Whenever the quality assurance procedures in § 98.424(b) cannot be followed to determine concentration of the CO 2 stream, the most appropriate of the following missing data procedures shall be followed:
(1) A quarterly concentration value that is missing may be substituted with a quarterly value measured during another quarter of the current reporting year.
(2) A quarterly concentration value that is missing may be substituted with a quarterly value measured during the same quarter from the previous reporting year.
(3) The concentration used for purposes of product tracking and billing according to the reporter's established procedures may be substituted for any quarterly value.
(c) Missing data on density of the CO 2 stream shall be substituted with quarterly or annual average values from the previous calendar year.
(d) Whenever the quality assurance procedures in § 98.424(a)(2) of this subpart cannot be followed to measure quarterly quantity of CO 2 in containers, the most appropriate of the following missing data procedures shall be followed:
(1) A quarterly quantity of CO 2 in containers that is missing may be substituted with a quarterly value measured during another representative quarter of the current reporting year.
(2) A quarterly quantity of CO 2 in containers that is missing may be substituted with a quarterly value measured during the same quarter from the past reporting year.
(3) The quarterly quantity of CO 2 in containers recorded for purposes of product tracking and billing according to the reporter's established procedures may be substituted for any period during which measurement equipment is inoperable.
§ 98.426   Data reporting requirements.
In addition to the information required by § 98.3(c) of subpart A of this part, the annual report shall contain the following information, as applicable:
(a) If you use Equation PP-1 of this subpart, report the following information for each mass flow meter or CO 2 stream that delivers CO 2 to containers:
(1) Annual mass in metric tons of CO 2 .
(2) Quarterly mass in metric tons of CO 2 .
(3) Quarterly concentration of the CO 2 stream.
(4) The standard used to measure CO 2 concentration.
(5) The location of the flow meter in your process chain in relation to the points of CO 2 stream capture, dehydration, compression, and other processing.
(b) If you use Equation PP-2 of this subpart, report the following information for each volumetric flow meter or CO 2 stream that delivers CO 2 to containers:
(1) Annual mass in metric tons of CO 2 .
(2) Quarterly volume in standard cubic meters of CO 2 .
(3) Quarterly concentration of the CO 2 stream in volume or weight percent.
(4) Report density as follows:
(i) Quarterly density of the CO 2 stream in metric tons per standard cubic meter if you report the concentration of the CO 2 stream in paragraph (b)(3) of this section in weight percent.
(ii) Quarterly density of CO 2 in metric tons per standard cubic meter if you report the concentration of the CO 2 stream in paragraph (b)(3) of this section in volume percent.
(5) The method used to measure density.
(6) The standard used to measure CO 2 concentration.
(7) The location of the flow meter in your process chain in relation to the points of CO 2 stream capture, dehydration, compression, and other processing.
(c) For the aggregated annual mass of CO 2 emissions calculated using Equation PP-3a or PP-3b, report the following:
(1) If you use Equation PP-3a of this subpart, report the annual CO 2 mass in metric tons from all flow meters and CO 2 streams that deliver CO 2 to containers.
(2) If you use Equation PP-3b of this subpart, report:
(i) The total annual CO 2 mass through main flow meter(s) in metric tons.
(ii) The total annual CO 2 mass through subsequent flow meter(s) in metric tons.
(iii) The total annual CO 2 mass supplied in metric tons.
(iv) The location of each flow meter in relation to the point of segregation.
(d) If you use Equation PP-4 of this subpart, report at the corporate level the annual mass of CO 2 in metric tons in all CO 2 containers that are imported or exported.
(e) Each reporter shall report the following information:
(1) The type of equipment used to measure the total flow of the CO 2 stream or the total mass or volume in CO 2 containers.
(2) The standard used to operate and calibrate the equipment reported in (e)(1) of this section.
(3) The number of days in the reporting year for which substitute data procedures were used for the following purpose:
(i) To measure quantity.
(ii) To measure concentration.
(iii) To measure density.
(f) Report the aggregated annual quantity of CO 2 in metric tons that is transferred to each of the following end use applications, if known:
(1) Food and beverage.
(2) Industrial and municipal water/wastewater treatment.
(3) Metal fabrication, including welding and cutting.
(4) Greenhouse uses for plant growth.
(5) Fumigants (e.g., grain storage) and herbicides.
(6) Pulp and paper.
(7) Cleaning and solvent use.
(8) Fire fighting.
(9) Transportation and storage of explosives.
(10) Injection of carbon dioxide for enhanced oil and natural gas recovery that is covered by subpart UU of this part.
(11) Geologic sequestration of carbon dioxide that is covered by subpart RR of this part.
(12) Geologic sequestration of carbon dioxide with enhanced oil recovery that is covered by subpart VV of this part.
(13) Research and development.
(14) Other.
(g) Each production process unit that captures a CO 2 stream for purposes of supplying CO 2 for commercial applications or in order to sequester or otherwise inject it underground when custody of the CO 2 is maintained shall report the percentage of that stream, if any, that is biomass-based during the reporting year.
(h) If you capture a CO 2 stream from a facility that is subject to this part and transfer CO 2 to any facilities that are subject to subpart RR or VV of this part, you must:
(1) Report the facility identification number associated with the annual GHG report for the facility that is the source of the captured CO 2 stream;
(2) Report each facility identification number associated with the annual GHG reports for each subpart RR and subpart VV facility to which CO 2 is transferred; and
(3) Report the annual quantity of CO 2 in metric tons that is transferred to each subpart RR and subpart VV facility.
(i) If you capture a CO 2 stream at a facility with a DAC process unit, report the annual quantity of on-site and off-site electricity and heat generated for each DAC process unit as specified in paragraphs (i)(1) through (3) of this section. The quantities specified in paragraphs (i)(1) through (3) of this section must be provided per energy source if known and must represent the electricity and heat used for the DAC process unit starting with air intake and ending with the compressed CO 2 stream ( i.e., the CO 2 stream ready for supply for commercial applications or, if maintaining custody of the stream, sequestration or injection of the stream underground).
(1) Electricity excluding combined heat and power (CHP). If electricity is provided to a dedicated meter for the DAC process unit, report the annual quantity of electricity consumed, in megawatt hours (MWh), and the information in paragraph (i)(1)(i) or (ii) of this section.
(i) If the electricity is sourced from a grid connection, report the following information:
(A) State where the facility with the DAC process unit is located.
(B) County where the facility with the DAC process unit is located.
(C) Name of the electric utility company that supplied the electricity as shown on the last monthly bill issued by the utility company during the reporting period.
(D) Name of the electric utility company that delivered the electricity. In states with regulated electric utility markets, this will generally be the same utility reported under paragraph (i)(1)(i)(C) of this section, but in states with deregulated electric utility markets, this may be a different utility company.
(E) Annual quantity of electricity consumed in MWh, calculated as the sum of the total energy usage values specified in all billing statements received during the reporting year. Most customers will receive 12 monthly billing statements during the reporting year. Many utilities bill their customers per kilowatt-hour (kWh); usage values on bills that are based on kWh should be divided by 1,000 to report the usage in MWh as required under this paragraph (i)(1)(i)(E).
(ii) If electricity is sourced from on-site or through a contractual mechanism for dedicated off-site generation, for each applicable energy source specified in paragraphs (i)(1)(ii)(A) through (G) of this section, report the annual quantity of electricity consumed, in MWh. If the on-site electricity source is natural gas, oil, or coal, also indicate whether flue gas is also captured by the DAC process unit.
(A) Non-hydropower renewable sources including solar, wind, geothermal and tidal.
(B) Hydropower.
(C) Natural gas.
(D) Oil.
(E) Coal.
(F) Nuclear.
(G) Other.
(2) Heat excluding CHP. For each applicable energy source specified in paragraphs (i)(2)(i) through (vii) of this section, report the annual quantity of heat, steam, or other forms of thermal energy sourced from on-site or through a contractual mechanism for dedicated off-site generation, in megajoules (MJ). If the on-site heat source is natural gas, oil, or coal, also indicate whether flue gas is also captured by the DAC process unit.
(i) Solar.
(ii) Geothermal.
(iii) Natural gas.
(iv) Oil.
(v) Coal.
(vi) Nuclear.
(vii) Other.
(3) CHP—(i) Electricity from CHP. If electricity from CHP is sourced from on-site or through a contractual mechanism for dedicated off-site generation, for each applicable energy source specified in paragraphs (i)(3)(i)(A) through (G) of this section, report the annual quantity consumed, in MWh. If the on-site electricity source for CHP is natural gas, oil, or coal, also indicate whether flue gas is also captured by the DAC process unit.
(A) Non-hydropower renewable sources including solar, wind, geothermal and tidal.
(B) Hydropower.
(C) Natural gas.
(D) Oil.
(E) Coal.
(F) Nuclear.
(G) Other.
(ii) Heat from CHP. For each applicable energy source specified in paragraphs (i)(3)(ii)(A) through (G) of this section, report the quantity of heat, steam, or other forms of thermal energy from CHP sourced from on-site or through a contractual mechanism for dedicated off-site generation, in MJ. If the on-site heat source is natural gas, oil, or coal, also indicate whether flue gas is also captured by the DAC process unit.
(A) Solar.
(B) Geothermal.
(C) Natural gas.
(D) Oil.
(E) Coal.
(F) Nuclear.
(G) Other.
§ 98.427   Records that must be retained.
In addition to the records required by § 98.3(g) of subpart A of this part, you must retain the records specified in paragraphs (a) through (c) of this section, as applicable.
(a) The owner or operator of a facility containing production process units or DAC process units must retain quarterly records of captured or transferred CO 2 streams and composition.
(b) The owner or operator of a CO 2 production well facility must maintain quarterly records of the mass flow or volumetric flow of the extracted or transferred CO 2 stream and concentration and density if volumetric flow meters are used.
(c) Importers or exporters of CO 2 must retain annual records of the mass flow, volumetric flow, and mass of CO 2 imported or exported.
(d) Facilities subject to § 98.426(h) must retain records of CO 2 in metric tons that is transferred to each subpart RR facility.
§ 98.428   Definitions.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
§ 98.430   Definition of the source category.
(a) The source category, importers and exporters of fluorinated GHGs contained in pre-charged equipment or closed-cell foams, consists of any entity that imports or exports pre-charged equipment that contains a fluorinated GHG, and any entity that imports or exports closed-cell foams that contain a fluorinated GHG.
§ 98.431   Reporting threshold.
Any importer or exporter of fluorinated GHGs contained in pre-charged equipment or closed-cell foams who meets the requirements of § 98.2(a)(4) must report each fluorinated GHG contained in the imported or exported pre-charged equipment or closed-cell foams.
§ 98.432   GHGs to report.
You must report the mass of each fluorinated GHG contained in pre-charged equipment or closed-cell foams that you import or export during the calendar year. For imports and exports of closed-cell foams where you do not know the identity and mass of the fluorinated GHG, you must report the mass of fluorinated GHG in CO 2 e.
§ 98.433   Calculating GHG contained in pre-charged equipment or closed-cell foams.
(a) The total mass of each fluorinated GHG imported and exported inside equipment or foams must be estimated using Equation QQ-1 of this section:
(b) When the identity and mass of fluorinated GHGs in a closed-cell foam is unknown to the importer or exporter, the total mass in CO 2 e for the fluorinated GHGs imported and exported inside closed-cell foams must be estimated using Equation QQ-2 of this section:
§ 98.434   Monitoring and QA/QC requirements.
(a) For calendar year 2011 monitoring, you may follow the provisions of § 98.3(d)(1) through (d)(2) for best available monitoring methods rather than follow the monitoring requirements of this section. For purposes of this subpart, any reference in § 98.3(d)(1) through (d)(2) to the year 2010 means 2011, to March 31 means June 30, and to April 1 means July 1. Any reference to the effective date or date of promulgation in § 98.3(d)(1) through (d)(2) means February 28, 2011.
(b) The inputs to the annual submission must be reviewed against the import or export transaction records to ensure that the information submitted to EPA is being accurately transcribed as the correct chemical or blend in the correct pre-charged equipment or closed-cell foam in the correct quantities and units.
§ 98.435   Procedures for estimating missing data.
Procedures for estimating missing data are not provided for importers and exporters of fluorinated GHGs contained in pre-charged equipment or closed-cell foams. A complete record of all measured parameters used in tracking fluorinated GHGs contained in pre-charged equipment or closed-cell foams is required.
§ 98.436   Data reporting requirements.
(a) Each importer of fluorinated GHGs contained in pre-charged equipment or closed-cell foams must submit an annual report that summarizes its imports at the corporate level, except for transshipments, as specified:
(1) Total mass in metric tons of each fluorinated GHG imported in pre-charged equipment or closed-cell foams.
(2) For each type of pre-charged equipment with a unique combination of charge size and charge type, the identity of the fluorinated GHG used as a refrigerant or electrical insulator, charge size (holding charge, if applicable), and number imported.
(3) For closed-cell foams that are imported inside of equipment, the identity of the fluorinated GHG contained in the foam, the mass of the fluorinated GHG contained in the foam in each piece of equipment, and the number of pieces of equipment imported with each unique combination of mass and identity of fluorinated GHG within the closed-cell foams.
(4) For closed cell-foams that are not imported inside of equipment, the identity of the fluorinated GHG in the foam, the density of the fluorinated GHG in the foam (kg fluorinated GHG/cubic foot), and the volume of foam imported (cubic feet) for each type of closed-cell foam with a unique combination of fluorinated GHG density and identity.
(5) Dates on which the pre-charged equipment or closed-cell foams were imported.
(6) If the importer does not know the identity and mass of the fluorinated GHGs within the closed-cell foam, the importer must report the following:
(i) Total mass in metric tons of CO 2 e of the fluorinated GHGs imported in closed-cell foams.
(ii) For closed-cell foams that are imported inside of equipment, the mass of the fluorinated GHGs in CO 2 e contained in the foam in each piece of equipment and the number of pieces of equipment imported for each equipment type.
(iii) For closed-cell foams that are not imported inside of equipment, the density in CO 2 e of the fluorinated GHGs in the foam (kg CO 2 e/cubic foot) and the volume of foam imported (cubic feet) for each type of closed-cell foam.
(iv) Dates on which the closed-cell foams were imported.
(v) Name of the foam manufacturer for each type of closed-cell foam where the identity and mass of the fluorinated GHGs is unknown.
(vi) Certification that the importer was unable to obtain information on the identity and mass of the fluorinated GHGs within the closed-cell foam from the closed-cell foam manufacturer or manufacturers.
(7) The Harmonized tariff system (HTS) code for each type of pre-charged equipment or closed-cell foam imported.
(b) Each exporter of fluorinated GHGs contained in pre-charged equipment or closed-cell foams must submit an annual report that summarizes its exports at the corporate level, except for transshipments, as specified:
(1) Total mass in metric tons of each fluorinated GHG exported in pre-charged equipment or closed-cell foams.
(2) For each type of pre-charged equipment with a unique combination of charge size and charge type, the identity of the fluorinated GHG used as a refrigerant or electrical insulator, charge size (including holding charge, if applicable), and number exported.
(3) For closed-cell foams that are exported inside of equipment, the identity of the fluorinated GHG contained in the foam in each piece of equipment, the mass of the fluorinated GHG contained in the foam in each piece of equipment, and the number of pieces of equipment exported with each unique combination of mass and identity of fluorinated GHG within the closed-cell foams.
(4) For closed-cell foams that are not exported inside of equipment, the identity of the fluorinated GHG in the foam, the density of the fluorinated GHG in the foam (kg fluorinated GHG/cubic foot), and the volume of foam exported (cubic feet) for each type of closed-cell foam with a unique combination of fluorinated GHG density and identity.
(5) Dates on which the pre-charged equipment or closed-cell foams were exported.
(6) If the exporter does not know the identity and mass of the fluorinated GHG within the closed-cell foam, the exporter must report the following:
(i) Total mass in metric tons of CO 2 e of the fluorinated GHGs exported in closed-cell foams.
(ii) For closed-cell foams that are exported inside of equipment, the mass of the fluorinated GHGs in CO 2 e contained in the foam in each piece of equipment and the number of pieces of equipment imported for each equipment type.
(iii) For closed-cell foams that are not exported inside of equipment, the density in CO 2 e of the fluorinated GHGs in the foam (kg CO 2 e/cubic foot) and the volume of foam imported (cubic feet) for each type of closed-cell foam.
(iv) Dates on which the closed-cell foams were exported.
(v) Name of the foam manufacturer for each type of closed-cell foam where the identity and mass of the fluorinated GHGg is unknown.
(vi) Certification that the exporter was unable to obtain information on the identity and mass of the fluorinated GHGs within the closed-cell foam from the closed-cell foam manufacturer or manufacturers.
(7) The Schedule B code for each type of pre-charged equipment or closed-cell foam exported.
§ 98.437   Records that must be retained.
(a) In addition to the data required by § 98.3(g), importers of fluorinated GHGs in pre-charged equipment and closed-cell foams must retain the following records substantiating each of the imports that they report:
(1) A copy of the bill of lading for the import.
(2) The invoice for the import.
(3) The U.S. Customs entry form.
(4) Ports of entry through which the pre-charged equipment or closed-cell foams passed.
(5) Countries from which the pre-charged equipment or closed-cell foams were imported.
(6) For importers that report the mass of fluorinated GHGs within closed-cell foams on a CO 2 e basis, correspondence or other documents that show the importer was unable to obtain information on the identity and mass of fluorinated GHG within closed-cell foams from the foam manufacturer.
(b) In addition to the data required by § 98.3(g), exporters of fluorinated GHGs in pre-charged equipment and closed-cell foams must retain the following records substantiating each of the exports that they report:
(1) A copy of the bill of lading for the export and
(2) The invoice for the export.
(3) Ports of exit through which the pre-charged equipment or closed-cell foams passed.
(4) Countries to which the pre-charged equipment or closed-cell foams were exported.
(5) For exporters that report the mass of fluorinated GHGs within closed-cell foams on a CO 2 e basis, correspondence or other documents that show the exporter was unable to obtain information on the identity and mass of fluorinated GHG within closed-cell foams from the foam manufacturer.
(c) For importers and exports of fluorinated GHGs inside pre-charged equipment and closed-cell foams, the GHG Monitoring Plans, as described in § 98.3(g)(5), must be completed by April 1, 2011.
(d) Persons who transship pre-charged equipment and closed-cell foams containing fluorinated GHGs must maintain records that indicated that the pre-charged equipment or foam originated in a foreign country and was destined for another foreign country and did not enter into commerce in the United States.
§ 98.438   Definitions.
Except as provided in this section, all of the terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. If a conflict exists between a definition provided in this subpart and a definition provided in subpart A, the definition in this subpart must take precedence for the reporting requirements in this subpart.
Appliance means any device which contains and uses a fluorinated greenhouse gas refrigerant and which is used for household or commercial purposes, including any air conditioner, refrigerator, chiller, or freezer.
Closed-cell foam means any foam product, excluding packaging foam, that is constructed with a closed-cell structure and a blowing agent containing a fluorinated GHG. Closed-cell foams include but are not limited to polyurethane (PU) foam contained in equipment, PU continuous and discontinuous panel foam, PU one component foam, PU spray foam, extruded polystyrene (XPS) boardstock foam, and XPS sheet foam. Packaging foam means foam used exclusively during shipment or storage to temporarily enclose items.
Electrical equipment means gas-insulated substations, circuit breakers, other switchgear, gas-insulated lines, or power transformers.
Fluorinated GHG refrigerant means, for purposes of this subpart, any substance consisting in part or whole of a fluorinated greenhouse gas and that is used for heat transfer purposes and provides a cooling effect.
Pre-charged appliance means any appliance charged with fluorinated greenhouse gas refrigerant prior to sale or distribution or offer for sale or distribution in interstate commerce. This includes both appliances that contain the full charge necessary for operation and appliances that contain a partial “holding” charge of the fluorinated greenhouse gas refrigerant (e.g., for shipment purposes).
Pre-charged appliance component means any portion of an appliance, including but not limited to condensers, compressors, line sets, and coils, that is charged with fluorinated greenhouse gas refrigerant prior to sale or distribution or offer for sale or distribution in interstate commerce.
Pre-charged electrical equipment means any electrical equipment, including but not limited to gas-insulated substations, circuit breakers, other switchgear, gas-insulated lines, or power transformers containing a fluorinated GHG prior to sale or distribution, or offer for sale or distribution in interstate commerce. This includes both equipment that contain the full charge necessary for operation and equipment that contain a partial “holding” charge of the fluorinated GHG (e.g., for shipment purposes).
Pre-charged electrical equipment component means any portion of electrical equipment that is charged with a fluorinated greenhouse gas prior to sale or distribution or offer for sale or distribution in interstate commerce.
Pre-charged equipment means any pre-charged appliance, pre-charged appliance component, pre-charged electrical equipment, or pre-charged electrical equipment component.
§ 98.440   Definition of the source category.
(a) The geologic sequestration of carbon dioxide (CO 2 ) source category comprises any well or group of wells that inject a CO 2 stream for long-term containment in subsurface geologic formations.
(b) This source category includes all wells permitted as Class VI under the Underground Injection Control program.
(c) This source category does not include a well or group of wells where a CO 2 stream is being injected in subsurface geologic formations to enhance the recovery of oil or natural gas unless one of the following applies:
(1) The owner or operator injects the CO 2 stream for long-term containment in subsurface geologic formations and has chosen to submit a proposed monitoring, reporting, and verification (MRV) plan to EPA and received an approved plan from EPA.
(2) The well is permitted as Class VI under the Underground Injection Control program.
(d) Exemption for research and development projects. Research and development projects shall receive an exemption from reporting under this subpart for the duration of the research and development activity.
(1) Process for obtaining an exemption. If you are a research and development project, you must submit the information in paragraph (d)(2) of this section to EPA by the time you would be otherwise required to submit an MRV plan under § 98.448. EPA will use this information to verify that the project is a research and development project.
(2) Content of submission. A submission in support of an exemption as a research and development project must contain the following information:
(i) The planned duration of CO 2 injection for the project.
(ii) The planned annual CO 2 injection volumes during this time period.
(iii) The research purposes of the project.
(iv) The source and type of funding for the project.
(v) The class and duration of Underground Injection Control permit or, for an offshore facility not subject to the Safe Drinking Water Act, a description of the legal instrument authorizing geologic sequestration.
(3) Determination by the Administrator.
(i) The Administrator shall determine if a project meets the definition of research and development project within 60 days of receipt of the submission of a request for exemption. In making this determination, the Administrator shall take into account any information you submit demonstrating that the planned duration of CO 2 injection for the project and the planned annual CO 2 injection volumes during the duration of the project are consistent with the purpose of the research and development project.
(ii) Any appeal of the Administrator's determination is subject to the provisions of part 78 of this chapter.
(iii) A project that the Administrator determines is not eligible for an exemption as a research and development project must submit a proposed MRV plan to EPA within 180 days of the Administrator's determination. You may request one extension of up to an additional 180 days in which to submit the proposed MRV plan.
§ 98.441   Reporting threshold.
(a) You must report under this subpart if any well or group of wells within your facility injects any amount of CO 2 for long-term containment in subsurface geologic formations. There is no threshold.
(b) Request for discontinuation of reporting. The requirements of § 98.2(i) do not apply to this subpart. Once a well or group of wells is subject to the requirements of this subpart, the owner or operator must continue for each year thereafter to comply with all requirements of this subpart, including the requirement to submit annual reports, until the Administrator has issued a final decision on an owner or operator's request to discontinue reporting.
(1) Timing of request. The owner or operator of a facility may submit a request to discontinue reporting any time after the well or group of wells is plugged and abandoned in accordance with applicable requirements.
(2) Content of request. A request for discontinuation of reporting must contain either paragraph (b)(2)(i) or (b)(2)(ii) of this section.
(i) For wells permitted as Class VI under the Underground Injection Control program, a copy of the applicable Underground Injection Control program Director's authorization of site closure.
(ii) For all other wells, and as an alternative for wells permitted as Class VI under the Underground Injection Control program, a demonstration that current monitoring and model(s) show that the injected CO 2 stream is not expected to migrate in the future in a manner likely to result in surface leakage.
(3) Notification. The Administrator will issue a final decision on the request to discontinue reporting within a reasonable time. Any appeal of the Administrator's final decision is subject to the provisions of part 78 of this chapter.
§ 98.442   GHGs to report.
You must report:
(a) Mass of CO 2 received.
(b) Mass of CO 2 injected into the subsurface.
(c) Mass of CO 2 produced.
(d) Mass of CO 2 emitted by surface leakage.
(e) Mass of CO 2 emissions from equipment leaks and vented emissions of CO 2 from surface equipment located between the injection flow meter and the injection wellhead.
(f) Mass of CO 2 emissions from equipment leaks and vented emissions of CO 2 from surface equipment located between the production flow meter and the production wellhead.
(g) Mass of CO 2 sequestered in subsurface geologic formations.
(h) Cumulative mass of CO 2 reported as sequestered in subsurface geologic formations in all years since the facility became subject to reporting requirements under this subpart.
§ 98.443   Calculating CO2geologic sequestration.
You must calculate the mass of CO 2 received using CO 2 received equations (Equations RR-1 to RR-3 of this section), unless you follow the procedures in § 98.444(a)(4). You must calculate CO 2 sequestered using injection equations (Equations RR-4 to RR-6 of this section), production/recycling equations (Equations RR-7 to RR-9 of this section), surface leakage equations (Equation RR-10 of this section), and sequestration equations (Equations RR-11 and RR-12 of this section). For your first year of reporting, you must calculate CO 2 sequestered starting from the date set forth in your approved MRV plan.
(a) You must calculate and report the annual mass of CO 2 received by pipeline using the procedures in paragraphs (a)(1) or (a)(2) of this section and the procedures in paragraph (a)(3) of this section, if applicable.
(1) For a mass flow meter, you must calculate the total annual mass of CO 2 in a CO 2 stream received in metric tons by multiplying the mass flow by the CO 2 concentration in the flow, according to Equation RR-1 of this section. You must collect these data quarterly. Mass flow and concentration data measurements must be made in accordance with § 98.444.
(2) For a volumetric flow meter, you must calculate the total annual mass of CO 2 in a CO 2 stream received in metric tons by multiplying the volumetric flow at standard conditions by the CO 2 concentration in the flow and the density of CO 2 at standard conditions, according to Equation RR-2 of this section. You must collect these data quarterly. Volumetric flow and concentration data measurements must be made in accordance with § 98.444.
(3) If you receive CO 2 through more than one flow meter, you must sum the mass of all CO 2 received in accordance with the procedure specified in Equation RR-3 of this section.
(b) You must calculate and report the annual mass of CO 2 received in containers using the procedures in paragraphs (b)(1) or (b)(2) of this section.
(1) If you are measuring the mass of contents in a container under the provisions of § 98.444(a)(2)(i), you must calculate the CO 2 received for injection in containers using Equation RR-1 of this section.
(2) If you are measuring the volume of contents in a container under the provisions of § 98.444(a)(2)(ii), you must calculate the CO 2 received for injection in containers using Equation RR-2 of this section.
(c) You must report the annual mass of CO 2 injected in accordance with the procedures specified in paragraphs (c)(1) through (c)(3) of this section.
(1) If you use a mass flow meter to measure the flow of an injected CO 2 stream, you must calculate annually the total mass of CO 2 (in metric tons) in the CO 2 stream injected each year in metric tons by multiplying the mass flow by the CO 2 concentration in the flow, according to Equation RR-4 of this section. Mass flow and concentration data measurements must be made in accordance with § 98.444.
(2) If you use a volumetric flow meter to measure the flow of an injected CO 2 stream, you must calculate annually the total mass of CO 2 (in metric tons) in the CO 2 stream injected each year in metric tons by multiplying the volumetric flow at standard conditions by the CO 2 concentration in the flow and the density of CO 2 at standard conditions, according to Equation RR-5 of this section. Volumetric flow and concentration data measurements must be made in accordance with § 98.444.
(3) To aggregate injection data for all wells covered under this subpart, you must sum the mass of all CO 2 injected through all injection wells in accordance with the procedure specified in Equation RR-6 of this section.
(d) You must calculate the annual mass of CO 2 produced from oil or gas production wells or from other fluid wells for each separator that sends a stream of gas into a recycle or end use system in accordance with the procedures specified in paragraphs (d)(1) through (d)(3) of this section. You must account for any CO 2 that is produced and not processed through a separator. You must account only for wells that produce the CO 2 that was injected into the well or wells covered by this source category.
(1) For each gas-liquid separator for which flow is measured using a mass flow meter, you must calculate annually the total mass of CO 2 produced from an oil or other fluid stream in metric tons that is separated from the fluid by multiplying the mass gas flow by the CO 2 concentration in the gas flow, according to Equation RR-7 of this section. You must collect these data quarterly. Mass flow and concentration data measurements must be made in accordance with § 98.444.
(2) For each gas-liquid separator for which flow is measured using a volumetric flow meter, you must calculate annually the total mass of CO 2 produced from an oil or other fluid stream in metric tons that is separated from the fluid by multiplying the volumetric gas flow at standard conditions by the CO 2 concentration in the gas flow and the density of CO 2 at standard conditions, according to Equation RR-8 of this section. You must collect these data quarterly. Volumetric flow and concentration data measurements must be made in accordance with § 98.444.
(3) To aggregate production data, you must sum the mass of all of the CO 2 separated at each gas-liquid separator in accordance with the procedure specified in Equation RR-9 of this section. You must assume that the total CO 2 measured at the separator(s) represents a percentage of the total CO 2 produced. In order to account for the percentage of CO 2 produced that is estimated to remain with the produced oil or other fluid, you must multiply the quarterly mass of CO 2 measured at the separator(s) by a percentage estimated using a methodology in your approved MRV plan. If fluids containing CO 2 from injection wells covered under this source category are produced and not processed through a gas-liquid separator, the concentration of CO 2 in the produced fluids must be measured at a flow meter located prior to reinjection or reuse using methods in § 98.444(f)(1). The considerations you intend to use to calculate CO 2 from produced fluids for the mass balance equation must be described in your approved MRV plan in accordance with § 98.448(a)(5).
(e) You must report the annual mass of CO 2 that is emitted by surface leakage in accordance with your approved MRV plan. You must calculate the total annual mass of CO 2 emitted from all leakage pathways in accordance with the procedure specified in Equation RR-10 of this section.
(f) You must report the annual mass of CO 2 that is sequestered in subsurface geologic formations in the reporting year in accordance with the procedures specified in paragraphs (f)(1) and (f)(2) of this section.
(1) If you are actively producing oil or natural gas or if you are producing any other fluids, you must calculate the annual mass of CO 2 that is sequestered in the underground subsurface formation in the reporting year in accordance with the procedure specified in Equation RR-11 of this section.
(2) If you are not actively producing oil or natural gas or any other fluids, you must calculate the annual mass of CO 2 that is sequestered in subsurface geologic formations in the reporting year in accordance with the procedures specified in Equation RR-12 of this section.
§ 98.444   Monitoring and QA/QC requirements.
(a) CO 2 received. (1) Except as provided in paragraph (a)(4) of this section, you must determine the quarterly flow rate of CO 2 received by pipeline by following the most appropriate of the following procedures:
(i) You may measure flow rate at the receiving custody transfer meter prior to any subsequent processing operations at the facility and collect the flow rate quarterly.
(ii) If you took ownership of the CO 2 in a commercial transaction, you may use the quarterly flow rate data from the sales contract if it is a one-time transaction or from invoices or manifests if it is an ongoing commercial transaction with discrete shipments.
(iii) If you inject CO 2 received from a production process unit that is part of your facility, you may use the quarterly CO 2 flow rate that was measured at the equivalent of a custody transfer meter following procedures provided in subpart PP of this part. To be the equivalent of a custody transfer meter, a meter must measure the flow of CO 2 being transported to an injection well to the same degree of accuracy as a meter used for commercial transactions.
(2) Except as provided in paragraph (a)(4) of this section, you must determine the quarterly mass or volume of contents in all containers if you receive CO 2 in containers by following the most appropriate of the following procedures:
(i) You may measure the mass of contents of containers summed quarterly using weigh bills, scales, or load cells.
(ii) You may determine the volume of the contents of containers summed quarterly.
(iii) If you took ownership of the CO 2 in a commercial transaction, you may use the quarterly mass or volume of contents from the sales contract if it is a one-time transaction or from invoices or manifests if it is an ongoing commercial transaction with discrete shipments.
(3) Except as provided in paragraph (a)(4) of this section, you must determine a quarterly concentration of the CO 2 received that is representative of all CO 2 received in that quarter by following the most appropriate of the following procedures:
(i) You may sample the CO 2 stream at least once per quarter at the point of receipt and measure its CO 2 concentration.
(ii) If you took ownership of the CO 2 in a commercial transaction for which the sales contract was contingent on CO 2 concentration, and if the supplier of the CO 2 sampled the CO 2 stream in a quarter and measured its concentration per the sales contract terms, you may use the CO 2 concentration data from the sales contract for that quarter.
(iii) If you inject CO 2 from a production process unit that is part of your facility, you may report the quarterly CO 2 concentration of the CO 2 stream supplied that was measured following the procedures provided in subpart PP of this part.
(4) If the CO 2 you receive is wholly injected and is not mixed with any other supply of CO 2 , you may report the annual mass of CO 2 injected that you determined following the requirements under paragraph (b) of this section as the total annual mass of CO 2 received instead of using Equation RR-1 or RR-2 of this subpart to calculate CO 2 received.
(5) You must assume that the CO 2 you receive meets the definition of a CO 2 stream unless you can trace it through written records to a source other than a CO 2 stream.
(b) CO 2 injected. (1) You must select a point or points of measurement at which the CO 2 stream(s) is representative of the CO 2 stream(s) being injected. You may use as the point or points of measurement the location(s) of the flow meter(s) used to comply with the flow monitoring and reporting provisions in your Underground Injection Control permit.
(2) You must measure flow rate of CO 2 injected with a flow meter and collect the flow rate quarterly.
(3) You must sample the injected CO 2 stream at least once per quarter immediately upstream or downstream of the flow meter used to measure flow rate of that CO 2 stream and measure the CO 2 concentration of the sample.
(c) CO 2 produced. (1) The point of measurement for the quantity of CO 2 produced from oil or other fluid production wells is a flow meter directly downstream of each separator that sends a stream of gas into a recycle or end use system.
(2) You must sample the produced gas stream at least once per quarter immediately upstream or downstream of the flow meter used to measure flow rate of that gas stream and measure the CO 2 concentration of the sample.
(3) You must measure flow rate of gas produced with a flow meter and collect the flow rate quarterly.
(d) CO 2 emissions from equipment leaks and vented emissions of CO 2 . If you have equipment located on the surface between the flow meter used to measure injection quantity and the injection wellhead or between the flow meter used to measure production quantity and the production wellhead, you must follow the monitoring and QA/QC requirements specified in subpart W of this part for the equipment.
(e) Measurement devices. (1) All flow meters must be operated continuously except as necessary for maintenance and calibration.
(2) You must calibrate all flow meters used to measure quantities reported in § 98.446 according to the calibration and accuracy requirements in § 98.3(i).
(3) You must operate all measurement devices according to one of the following. You may use an appropriate standard method published by a consensus-based standards organization if such a method exists or an industry standard practice. Consensus-based standards organizations include, but are not limited to, the following: ASTM International, the American National Standards Institute (ANSI), the American Gas Association (AGA), the American Society of Mechanical Engineers (ASME), the American Petroleum Institute (API), and the North American Energy Standards Board (NAESB).
(4) You must ensure that any flow meter calibrations performed are National Institute of Standards and Technology (NIST) traceable.
(f) General. (1) If you measure the concentration of any CO 2 quantity for reporting, you must measure according to one of the following. You may use an appropriate standard method published by a consensus-based standards organization if such a method exists or an industry standard practice.
(2) You must convert all measured volumes of CO 2 to the following standard industry temperature and pressure conditions for use in Equations RR-2, RR-5 and RR-8 of this subpart: Standard cubic meters at a temperature of 60 degrees Fahrenheit and at an absolute pressure of 1 atmosphere.
(3) For 2011, you may follow the provisions of § 98.3(d)(1) through (2) for best available monitoring methods only for parameters required by paragraphs (a) and (b) of § 98.443 rather than follow the monitoring requirements of paragraph (a) of this section. For purposes of this subpart, any reference to the year 2010 in § 98.3(d)(1) through (2) shall mean 2011.
§ 98.445   Procedures for estimating missing data.
A complete record of all measured parameters used in the GHG quantities calculations is required. Whenever the monitoring procedures cannot be followed, you must use the following missing data procedures:
(a) A quarterly flow rate of CO 2 received that is missing must be estimated as follows:
(1) Another calculation methodology listed in § 98.444(a)(1) must be used if possible.
(2) If another method listed in § 98.444(a)(1) cannot be used, a quarterly flow rate value that is missing must be estimated using a representative flow rate value from the nearest previous time period.
(b) A quarterly mass or volume of contents in containers received that is missing must be estimated as follows:
(1) Another calculation methodology listed in § 98.444(a)(2) must be used if possible.
(2) If another method listed in § 98.444(a)(2) cannot be used, a quarterly mass or volume value that is missing must be estimated using a representative mass or volume value from the nearest previous time period.
(c) A quarterly CO 2 concentration of a CO 2 stream received that is missing must be estimated as follows:
(1) Another calculation methodology listed in § 98.444(a)(3) must be used if possible.
(2) If another method listed in § 98.444(a)(3) cannot be used, a quarterly concentration value that is missing must be estimated using a representative concentration value from the nearest previous time period.
(d) A quarterly quantity of CO 2 injected that is missing must be estimated using a representative quantity of CO 2 injected from the nearest previous period of time at a similar injection pressure.
(e) For any values associated with CO 2 emissions from equipment leaks and vented emissions of CO 2 from surface equipment at the facility that are reported in this subpart, missing data estimation procedures should be followed in accordance with those specified in subpart W of this part.
(f) The quarterly quantity of CO 2 produced from subsurface geologic formations that is missing must be estimated using a representative quantity of CO 2 produced from the nearest previous period of time.
(g) You must estimate the mass of CO 2 emitted by surface leakage that is missing as required by your approved MRV plan.
(h) You must estimate other missing data as required by your approved MRV plan.
§ 98.446   Data reporting requirements.
In addition to the information required by § 98.3(c), report the information listed in this section.
(a) If you receive CO 2 by pipeline, report the following for each receiving flow meter:
(1) The total net mass of CO 2 received (metric tons) annually.
(2) If a volumetric flow meter is used to receive CO 2 report the following unless you reported yes to paragraph (a)(4) of this section:
(i) The volumetric flow through a receiving flow meter at standard conditions (in standard cubic meters) in each quarter.
(ii) The volumetric flow through a receiving flow meter that is redelivered to another facility without being injected into your well (in standard cubic meters) in each quarter.
(iii) The CO 2 concentration in the flow (volume percent CO 2 expressed as a decimal fraction) in each quarter.
(3) If a mass flow meter is used to receive CO 2 report the following unless you reported yes to paragraph (a)(4) of this section:
(i) The mass flow through a receiving flow meter (in metric tons) in each quarter.
(ii) The mass flow through a receiving flow meter that is redelivered to another facility without being injected into your well (in metric tons) in each quarter.
(iii) The CO 2 concentration in the flow (weight percent CO 2 expressed as a decimal fraction) in each quarter.
(4) If the CO 2 received is wholly injected and not mixed with any other supply of CO 2 , report whether you followed the procedures in § 98.444(a)(4).
(5) The standard or method used to calculate each value in paragraphs (a)(2) through (a)(3) of this section.
(6) The number of times in the reporting year for which substitute data procedures were used to calculate values reported in paragraphs (a)(2) through (a)(3) of this section.
(7) Whether the flow meter is mass or volumetric.
(8) A numerical identifier for the flow meter.
(b) If you receive CO 2 in containers, report:
(1) The mass (in metric tons) or volume at standard conditions (in standard cubic meters) of contents in containers received in each quarter.
(2) The concentration of CO 2 of contents in containers (volume or wt. percent CO 2 expressed as a decimal fraction) in each quarter.
(3) The mass (in metric tons) or volume (in standard cubic meters) of contents in containers that is redelivered to another facility without being injected into your well in each quarter.
(4) The net mass of CO 2 received (in metric tons) annually.
(5) The standard or method used to calculate each value in paragraphs (b)(1), (b)(2), and (b)(3) of this section.
(6) The number of times in the reporting year for which substitute data procedures were used to calculate values reported in paragraphs (b)(1) and (b)(2) of this section.
(c) If you use more than one receiving flow meter, report the total net mass of CO 2 received (metric tons) through all flow meters annually.
(d) The source of the CO 2 received according to the following categories:
(1) CO 2 production wells.
(2) Electric generating unit.
(3) Ethanol plant.
(4) Pulp and paper mill.
(5) Natural gas processing.
(6) Gasification operations.
(7) Other anthropogenic source.
(8) Discontinued enhanced oil and gas recovery project.
(9) Unknown.
(e) Report the date that you began collecting data for calculating total amount sequestered according to § 98.448(a)(7) of this subpart.
(f) Report the following. If the date specified in paragraph (e) of this section is during the reporting year for this annual report, report the following starting on the date specified in paragraph (e) of this section.
(1) For each injection flow meter (mass or volumetric), report:
(i) The mass of CO 2 injected (metric tons) annually.
(ii) The CO 2 concentration in flow (volume or weight percent CO 2 expressed as a decimal fraction) in each quarter.
(iii) If a volumetric flow meter is used, the volumetric flow rate at standard conditions (in standard cubic meters) in each quarter.
(iv) If a mass flow meter is used, the mass flow rate (in metric tons) in each quarter.
(v) A numerical identifier for the flow meter.
(vi) Whether the flow meter is mass or volumetric.
(vii) The standard used to calculate each value in paragraphs (f)(1)(ii) through (f)(1)(iv) of this section.
(viii) The number of times in the reporting year for which substitute data procedures were used to calculate values reported in paragraphs (f)(1)(ii) through (f)(1)(iv) of this section.
(ix) The location of the flow meter.
(2) The total CO 2 injected (metric tons) in the reporting year as calculated in Equation RR-6 of this subpart.
(3) For CO 2 emissions from equipment leaks and vented emissions of CO 2 , report the following:
(i) The mass of CO 2 emitted (in metric tons) annually from equipment leaks and vented emissions of CO 2 from equipment located on the surface between the flow meter used to measure injection quantity and the injection wellhead.
(ii) The mass of CO 2 emitted (in metric tons) annually from equipment leaks and vented emissions of CO 2 from equipment located on the surface between the production wellhead and the flow meter used to measure production quantity.
(4) For each separator flow meter (mass or volumetric), report:
(i) CO 2 mass produced (metric tons) annually.
(ii) CO 2 concentration in flow (volume or weight percent CO 2 expressed as a decimal fraction) in each quarter.
(iii) If a volumetric flow meter is used, volumetric flow rate at standard conditions (standard cubic meters) in each quarter.
(iv) If a mass flow meter, mass flow rate (metric tons) in each quarter.
(v) A numerical identifier for the flow meter.
(vi) Whether the flow meter is mass or volumetric.
(vii) The standard used to calculate each value in paragraphs (f)(4)(ii) through (f)(4)(iv) of this section.
(viii) The number of times in the reporting year for which substitute data procedures were used to calculate values reported in paragraphs (f)(4)(ii) through (f)(4)(iv) of this section.
(5) The entrained CO 2 in produced oil or other fluid divided by the CO 2 separated through all separators in the reporting year (weight percent CO 2 expressed as a decimal fraction) used as the value for X in Equation RR-9 of this subpart and as determined according to your EPA-approved MRV plan.
(6) Annual CO 2 produced in the reporting year as calculated in Equation RR-9 of this subpart.
(7) For each leakage pathway through which CO 2 emissions occurred, report:
(i) A numerical identifier for the leakage pathway.
(ii) The CO 2 (metric tons) emitted through that pathway in the reporting year.
(8) Annual CO 2 mass emitted (metric tons) by surface leakage in the reporting year as calculated by Equation RR-10 of this subpart.
(9) Annual CO 2 (metric tons) sequestered in subsurface geologic formations in the reporting year as calculated by Equation RR-11 or RR-12 of this subpart.
(10) Cumulative mass of CO 2 (metric tons) reported as sequestered in subsurface geologic formations in all years since the well or group of wells became subject to reporting requirements under this subpart.
(11) Date that the most recent MRV plan was approved by EPA and the MRV plan approval number that was issued by EPA.
(12) An annual monitoring report that contains the following components:
(i) A narrative history of the monitoring efforts conducted over the previous calendar year, including a listing of all monitoring equipment that was operated, its period of operation, and any relevant tests or surveys that were conducted.
(ii) A description of any changes to the monitoring program that you concluded were not material changes warranting submission of a revised MRV plan under § 98.448(d).
(iii) A narrative history of any monitoring anomalies that were detected in the previous calendar year and how they were investigated and resolved.
(iv) A description of any surface leakages of CO 2 , including a discussion of all methodologies and technologies involved in detecting and quantifying the surface leakages and any assumptions and uncertainties involved in calculating the amount of CO 2 emitted.
(13) If a well is permitted under the Underground Injection Control program, for each injection well, report:
(i) The well identification number used for the Underground Injection Control permit.
(ii) The Underground Injection Control permit class.
(14) If an offshore well is not subject to the Safe Drinking Water Act, for each injection well, report any well identification number and any identification number used for the legal instrument authorizing geologic sequestration.
§ 98.447   Records that must be retained.
(a) You must follow the record retention requirements specified by § 98.3(g). In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a)(1) through (7) of this section, as applicable. You must retain all required records for at least 3 years.
(1) Quarterly records of CO 2 received, including mass flow rate of contents of containers (mass or volumetric) at standard conditions and operating conditions, operating temperature and pressure, and concentration of these streams.
(2) Quarterly records of produced CO 2 , including mass flow or volumetric flow at standard conditions and operating conditions, operating temperature and pressure, and concentration of these streams.
(3) Quarterly records of injected CO 2 including mass flow or volumetric flow at standard conditions and operating conditions, operating temperature and pressure, and concentration of these streams.
(4) Annual records of information used to calculate the CO 2 emitted by surface leakage from leakage pathways.
(5) Annual records of information used to calculate the CO 2 emitted from equipment leaks and vented emissions of CO 2 from equipment located on the surface between the flow meter used to measure injection quantity and the injection wellhead.
(6) Annual records of information used to calculate the CO 2 emitted from equipment leaks and vented emissions of CO 2 from equipment located on the surface between the production wellhead and the flow meter used to measure production quantity.
(7) Any other records as specified for retention in your EPA-approved MRV plan.
(b) You must complete your monitoring plans, as described in § 98.3(g)(5), by April 1 of the year you begin collecting data.
§ 98.448   Geologic sequestration monitoring, reporting, and verification (MRV) plan.
(a) Contents of MRV plan. You must develop and submit to the Administrator a proposed MRV plan for monitoring, reporting, and verification of geologic sequestration at your facility. Your proposed MRV plan must contain the following components:
(1) Delineation of the maximum monitoring area and the active monitoring areas. The first period for your active monitoring area will begin from the date determined in your MRV plan through the date at which the plan calls for the first expansion of the monitoring area. The length of each monitoring period can be any time interval chosen by you that is greater than 1 year.
(2) Identification of potential surface leakage pathways for CO 2 in the maximum monitoring area and the likelihood, magnitude, and timing, of surface leakage of CO 2 through these pathways.
(3) A strategy for detecting and quantifying any surface leakage of CO 2 .
(4) A strategy for establishing the expected baselines for monitoring CO 2 surface leakage.
(5) A summary of the considerations you intend to use to calculate site-specific variables for the mass balance equation. This includes, but is not limited to, considerations for calculating CO 2 emissions from equipment leaks and vented emissions of CO 2 between the injection flow meter and injection well and/or the production flow meter and production well, and considerations for calculating CO 2 in produced fluids.
(6) If a well is permitted under the Underground Injection Control program, for each injection well, report the well identification number used for the Underground Injection Control permit and the Underground Injection Control permit class. If the well is not yet permitted, and you have applied for an Underground Injection Control permit, report the well identification numbers in the permit application. If an offshore well is not subject to the Safe Drinking Water Act, for each injection well, report any well identification number and any identification number used for the legal instrument authorizing geologic sequestration. If you are submitting your Underground Injection Control permit application as part of your proposed MRV plan, you must notify EPA when the permit has been approved. If you are an offshore facility not subject to the Safe Drinking Water Act, and are submitting your application for the legal instrument authorizing geologic sequestration as part of your proposed MRV plan, you must notify EPA when the legal instrument authorizing geologic sequestration has been approved.
(7) Proposed date to begin collecting data for calculating total amount sequestered according to equation RR-11 or RR-12 of this subpart. This date must be after expected baselines as required by paragraph (a)(4) of this section are established and the leakage detection and quantification strategy as required by paragraph (a)(3) of this section is implemented in the initial AMA.
(b) Timing. You must submit a proposed MRV plan to EPA according to the following schedule:
(1) You must submit a proposed MRV plan to EPA by June 30, 2011 if you were issued a final Underground Injection Control permit authorizing the injection of CO 2 into the subsurface on or before December 31, 2010. You will be allowed to request one extension of up to an additional 180 days in which to submit your proposed MRV plan.
(2) You must submit a proposed MRV plan to EPA within 180 days of receiving a final Underground Injection Control permit authorizing the injection of CO 2 into the subsurface. If your facility is an offshore facility not subject to the Safe Drinking Water Act, you must submit a proposed MRV plan to EPA within 180 days of receiving authorization to begin geologic sequestration of CO 2 . You will be allowed to request one extension of the submittal date of up to an additional 180 days.
(3) If you are injecting a CO 2 stream in subsurface geologic formations to enhance the recovery of oil or natural gas and you are not permitted as Class VI under the Underground Injection Control program, you may opt to submit an MRV plan at any time.
(4) If EPA determines that your proposed MRV plan is incomplete, you must submit an updated MRV plan within 45 days of EPA notification, unless otherwise specified by EPA.
(c) Final MRV plan. The Administrator will issue a final MRV plan within a reasonable period of time. The Administrator's final MRV plan is subject to the provisions of part 78 of this chapter. Once the MRV plan is final and no longer subject to administrative appeal under part 78 of this chapter, you must implement the plan starting on the day after the day on which the plan becomes final and is no longer subject to such appeal.
(d) MRV plan revisions. You must revise and submit the MRV plan within 180 days to the Administrator for approval if any of the following in paragraphs (d)(1) through (d)(4) of this section applies. You must include the reason(s) for the revisions in your submittal.
(1) A material change was made to monitoring and/or operational parameters that was not anticipated in the original MRV plan. Examples of material changes include but are not limited to: Large changes in the volume of CO 2 injected; the construction of new injection wells not identified in the MRV plan; failures of the monitoring system including monitoring system sensitivity, performance, location, or baseline; changes to surface land use that affects baseline or operational conditions; observed plume location that differs significantly from the predicted plume area used for developing the MRV plan; a change in the maximum monitoring area or active monitoring area; or a change in monitoring technology that would result in coverage or detection capability different from the MRV plan.
(2) A change in the permit class of your Underground Injection Control permit.
(3) If you are notified by EPA of substantive errors in your MRV plan or monitoring report.
(4) You choose to revise your MRV plan for any other reason in any reporting year.
(e) Revised MRV plan. The requirements of paragraph (c) of this section apply to any submission of a revised MRV plan. You must continue reporting under your currently approved plan while awaiting approval of a revised MRV plan.
(f) Format. Each proposed MRV plan or revision and each annual report must be submitted electronically in a format specified by the Administrator.
(g) Certificate of representation. You must submit a certificate of representation according to the provisions in § 98.4 at least 60 days before submission of your MRV plan, your research and development exemption request, your MRV plan submission extension request, or your initial annual report under this part, whichever is earlier.
§ 98.449   Definitions.
Except as provided below, all terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
Active monitoring area is the area that will be monitored over a specific time interval from the first year of the period (n) to the last year in the period (t). The boundary of the active monitoring area is established by superimposing two areas:
(1) The area projected to contain the free phase CO 2 plume at the end of year t, plus an all around buffer zone of one-half mile or greater if known leakage pathways extend laterally more than one-half mile.
(2) The area projected to contain the free phase CO 2 plume at the end of year t + 5.
CO 2 received means the CO 2 stream that you receive to be injected for the first time into a well on your facility that is covered by this subpart. CO 2 received includes, but is not limited to, a CO 2 stream from a production process unit inside your facility and a CO 2 stream that was injected into a well on another facility, removed from a discontinued enhanced oil or natural gas or other production well, and transferred to your facility.
Equipment leak means those emissions that could not reasonably pass through a stack, chimney, vent, or other functionally-equivalent opening.
Expected baseline is the anticipated value of a monitored parameter that is compared to the measured monitored parameter.
Maximum monitoring area means the area that must be monitored under this regulation and is defined as equal to or greater than the area expected to contain the free phase CO 2 plume until the CO 2 plume has stabilized plus an all-around buffer zone of at least one-half mile.
Offshore means seaward of the terrestrial borders of the United States, including waters subject to the ebb and flow of the tide, as well as adjacent bays, lakes or other normally standing waters, and extending to the outer boundaries of the jurisdiction and control of the United States under the Outer Continental Shelf Lands Act.
Research and development project means a project for the purpose of investigating practices, monitoring techniques, or injection verification, or engaging in other applied research, that will enable safe and effective long-term containment of a CO 2 stream in subsurface geologic formations, including research and short duration CO 2 injection tests conducted as a precursor to long-term storage.
Separator means a vessel in which streams of multiple phases are gravity separated into individual streams of single phase.
Surface leakage means the movement of the injected CO 2 stream from the injection zone to the surface, and into the atmosphere, indoor air, oceans, or surface water.
Underground Injection Control permit means a permit issued under the authority of Part C of the Safe Drinking Water Act at 42 U.S.C. 300h et seq.
Underground Injection Control program means the program responsible for regulating the construction, operation, permitting, and closure of injection wells that place fluids underground for storage or disposal for purposes of protecting underground sources of drinking water from endangerment pursuant to Part C of the Safe Drinking Water Act at 42 U.S.C. 300h et seq.
Vented emissions means intentional or designed releases of CH 4 or CO 2 containing natural gas or hydrocarbon gas (not including stationary combustion flue gas), including process designed flow to the atmosphere through seals or vent pipes, equipment blowdown for maintenance, and direct venting of gas used to power equipment (such as pneumatic devices).
§ 98.450   Definition of the source category.
The electrical equipment manufacturing or refurbishment category consists of processes that manufacture or refurbish gas-insulated substations, circuit breakers, other switchgear, gas-insulated lines, or power transformers (including gas-containing components of such equipment) containing fluorinated GHGs, including but not limited to sulfur-hexafluoride (SF 6 ) and perfluorocarbons (PFCs). The processes include equipment testing, installation, manufacturing, decommissioning and disposal, refurbishing, and storage in gas cylinders and other containers.
§ 98.451   Reporting threshold.
You must report GHG emissions under this subpart if your facility contains an electrical equipment manufacturing or refurbishing process and the facility meets the requirements of § 98.2(a)(2). To calculate total annual GHG emissions for comparison to the 25,000 metric ton CO 2 e per year emission threshold in § 98.2(a)(2), follow the requirements of § 98.2(b), with one exception. Instead of following the requirement of § 98.453 to calculate emissions from electrical equipment manufacture or refurbishment, you must calculate emissions of each fluorinated GHG that is a component of a reportable insulating gas and then sum the emissions of each fluorinated GHG resulting from manufacturing and refurbishing electrical equipment using equation SS-1 to this section.
§ 98.452   GHGs to report.
(a) You must report emissions of each fluorinated GHG, including but not limited to SF6 and PFCs, at the facility level, except you are not required to report emissions of fluorinated GHGs that are components of insulating gases whose weighted average GWPs, as calculated in equation SS-2 to this section, are less than or equal to one. You are, however, required to report certain quantities of insulating gases whose weighted average GWPs are less than or equal to one as specified in § 98.456(f), (g), (k) and (q) through (s). Annual emissions from the facility must include fluorinated GHG emissions from equipment that is installed at an off-site electric power transmission or distribution location whenever emissions from installation activities ( e.g., filling) occur before the title to the equipment is transferred to the electric power transmission or distribution entity.
(b) You must report CO 2 , N 2 O and CH 4 emissions from each stationary combustion unit. You must calculate and report these emissions under subpart C of this part by following the requirements of subpart C of this part.
§ 98.453   Calculating GHG emissions.
(a) For each electrical equipment manufacturer or refurbisher, estimate the annual emissions of each fluorinated GHG that is a component of any reportable insulating gas using the mass-balance approach in equation SS-3 to this section:
(b) [Reserved]
(c) Estimate the disbursements of reportable insulating gas j sent to customers in new equipment or cylinders or sent off-site for other purposes including for recycling, for destruction or to be returned to suppliers using equation SS-4 to this section:
(d) Estimate the mass of each insulating gas j disbursed to customers in new equipment or cylinders over the period p by monitoring the mass flow of each insulating gas j into the new equipment or cylinders using a flowmeter, or by weighing containers before and after gas from containers is used to fill equipment or cylinders, or by using the nameplate capacity of the equipment.
(e) If the mass of insulating gas j disbursed to customers in new equipment or cylinders over the period p is estimated by weighing containers before and after gas from containers is used to fill equipment or cylinders, estimate this quantity using equation SS-5 to this section:
(f) If the mass of insulating gas j disbursed to customers in new equipment or cylinders over the period p is determined using a flowmeter, estimate this quantity using equation SS-6 to this section:
(g) Estimate the mass of insulating gas j emitted during the period p downstream of the containers used to fill equipment or cylinders ( e.g., emissions from hoses or other flow lines that connect the container to the equipment or cylinder that is being filled) using equation SS-7 to this section:
(h) If the mass of insulating gas j disbursed to customers in new equipment or cylinders over the period p is determined by using the nameplate capacity, or by using the nameplate capacity of the equipment and calculating the partial shipping charge, use the methods in either paragraph (h)(1) or (2) of this section.
(1) Determine the equipment's actual nameplate capacity, by measuring the nameplate capacities of a representative sample of each make and model and calculating the mean value for each make and model as specified at § 98.454(f).
(2) If equipment is shipped with a partial charge, calculate the partial shipping charge by multiplying the nameplate capacity of the equipment by the ratio of the densities of the partial charge to the full charge.
(i) Estimate the annual emissions of reportable insulating gas j from the equipment that is installed at an off-site electric power transmission or distribution location before the title to the equipment is transferred by using equation SS-8 to this section:
§ 98.454   Monitoring and QA/QC requirements.
(a) [Reserved]
(b) Ensure that all the quantities required by the equations of this subpart have been measured using either flowmeters with an accuracy and precision of ±1 percent of full scale or better or scales with an accuracy and precision of ±1 percent of the filled weight (gas plus tare) of the containers of each reportable insulating gas that are typically weighed on the scale. For scales that are generally used to weigh cylinders containing 115 pounds of gas when full, this equates to ±1 percent of the sum of 115 pounds and approximately 120 pounds tare, or slightly more than ±2 pounds. Account for the tare weights of the containers. You may accept gas masses or weights provided by the gas supplier ( e.g., for the contents of cylinders containing new gas or for the heels remaining in cylinders returned to the gas supplier) if the supplier provides documentation verifying that accuracy standards are met; however, you remain responsible for the accuracy of these masses and weights under this subpart.
(c) All flow meters, weigh scales, and combinations of volumetric and density measures that are used to measure or calculate quantities under this subpart must be calibrated using calibration procedures specified by the flowmeter, scale, volumetric or density measure equipment manufacturer. Calibration must be performed prior to the first reporting year. After the initial calibration, recalibration must be performed at the minimum frequency specified by the manufacturer.
(d) For purposes of equation SS-7 to § 98.453, the emission factor for the valve-hose combination (EFC) must be estimated using measurements and/or engineering assessments or calculations based on chemical engineering principles or physical or chemical laws or properties. Such assessments or calculations may be based on, as applicable, the internal volume of hose or line that is open to the atmosphere during coupling and decoupling activities, the internal pressure of the hose or line, the time the hose or line is open to the atmosphere during coupling and decoupling activities, the frequency with which the hose or line is purged and the flow rate during purges. You must develop a value for EFc (or use an industry-developed value) for each combination of hose and valve fitting, to use in equation SS-7 to § 98.453. The value for EFC must be determined for each combination of hose and valve fitting of a given diameter or size. The calculation must be recalculated annually to account for changes to the specifications of the valves or hoses that may occur throughout the year.
(e) Electrical equipment manufacturers and refurbishers must account for emissions of each reportable insulating gas that occur as a result of unexpected events or accidental losses, such as a malfunctioning hose or leak in the flow line, during the filling of equipment or containers for disbursement by including these losses in the estimated mass of each reportable insulating gas emitted downstream of the container or flowmeter during the period p.
(f) If the mass of each reportable insulating gas j disbursed to customers in new equipment over the period p is determined by assuming that it is equal to the equipment's nameplate capacity or, in cases where equipment is shipped with a partial charge, equal to its partial shipping charge, equipment samples for conducting the nameplate capacity tests must be selected using the following stratified sampling strategy in this paragraph (f). For each make and model, group the measurement conditions to reflect predictable variability in the facility's filling practices and conditions ( e.g., temperatures at which equipment is filled). Then, independently select equipment samples at random from each make and model under each group of conditions. To account for variability, a certain number of these measurements must be performed to develop a robust and representative average nameplate capacity (or shipping charge) for each make, model, and group of conditions. A Student T distribution calculation should be conducted to determine how many samples are needed for each make, model, and group of conditions as a function of the relative standard deviation of the sample measurements. To determine a sufficiently precise estimate of the nameplate capacity, the number of measurements required must be calculated to achieve a precision of one percent of the true mean, using a 95 percent confidence interval. To estimate the nameplate capacity for a given make and model, you must use the lowest mean value among the different groups of conditions, or provide justification for the use of a different mean value for the group of conditions that represents the typical practices and conditions for that make and model. Measurements can be conducted using SF6, another gas, or a liquid. Re-measurement of nameplate capacities should be conducted every five years to reflect cumulative changes in manufacturing methods and conditions over time.
(g) Ensure the following QA/QC methods are employed throughout the year:
(1) Procedures are in place and followed to track and weigh all cylinders or other containers at the beginning and end of the year.
(2) [Reserved]
(h) You must adhere to the following QA/QC methods for reviewing the completeness and accuracy of reporting:
(1) Review inputs to equation SS-3 to § 98.453 to ensure inputs and outputs to the company's system are included.
(2) Do not enter negative inputs and confirm that negative emissions are not calculated. However, the decrease in the inventory for each reportable insulating gas may be calculated as negative.
(3) Ensure that for each reportable insulating gas, the beginning-of-year inventory matches the end-of-year inventory from the previous year.
(4) Ensure that for each reportable insulating gas, in addition to the reportable insulating gas purchased from bulk gas distributors, the reportable insulating gas returned from equipment users with or inside equipment and the reportable insulating gas returned from off-site recycling are also accounted for among the total additions.
§ 98.455   Procedures for estimating missing data.
A complete record of all measured parameters used in the GHG emissions calculations is required. Replace missing data, if needed, based on data from similar manufacturing operations, and from similar equipment testing and decommissioning activities for which data are available.
§ 98.456   Data reporting requirements.
In addition to the information required by § 98.3(c), each annual report must contain the following information for each chemical at the facility level:
(a) Pounds of each reportable insulating gas stored in containers at the beginning of the year.
(b) Pounds of each reportable insulating gas stored in containers at the end of the year.
(c) Pounds of each reportable insulating gas purchased in bulk.
(d) Pounds of each reportable insulating gas returned by equipment users with or inside equipment.
(e) Pounds of each reportable insulating gas returned to site from off site after recycling.
(f) Pounds of each insulating gas inside new equipment delivered to customers.
(g) Pounds of each insulating gas delivered to equipment users in containers.
(h) Pounds of each reportable insulating gas returned to suppliers.
(i) Pounds of each reportable insulating gas sent off site for destruction.
(j) Pounds of each reportable insulating gas sent off site to be recycled.
(k) The nameplate capacity of the equipment, in pounds, delivered to customers with each insulating gas inside, if different from the quantity in paragraph (f) of this section.
(l) A description of the engineering methods and calculations used to determine emissions from hoses or other flow lines that connect the container to the equipment that is being filled.
(m) The values for EF ci of equation SS-7 to § 98.453 for each hose and valve combination and the associated valve fitting sizes and hose diameters.
(n) The total number of fill operations for each hose and valve combination, or, FC i of equation SS-7 to § 98.453.
(o) If the mass of each reportable insulating gas disbursed to customers in new equipment over the period p is determined according to the methods required in § 98.453(h), report the mean value of nameplate capacity in pounds for each make, model, and group of conditions.
(p) If the mass of each reportable insulating gas disbursed to customers in new equipment over the period p is determined according to the methods required in § 98.453(h), report the number of samples and the upper and lower bounds on the 95-percent confidence interval for each make, model, and group of conditions.
(q) Pounds of each insulating gas used to fill equipment at off-site electric power transmission or distribution locations, or MF, of equation SS-8 to § 98.453.
(r) Pounds of each insulating gas used to charge the equipment prior to leaving the electrical equipment manufacturer or refurbishment facility, or MC, of equation SS-8 to § 98.453.
(s) The nameplate capacity of the equipment, in pounds, installed at off-site electric power transmission or distribution locations used to determine emissions from installation, or N I , of equation SS-8 to § 98.453.
(t) For any missing data, you must report the reason the data were missing, the parameters for which the data were missing, the substitute parameters used to estimate emissions in their absence, and the quantity of emissions thereby estimated.
(u) For each insulating gas reported in paragraphs (a) through (j) and (o) through (r) of this section, an ID number or other appropriate descriptor unique to that insulating gas.
(v) For each ID number or descriptor reported in paragraph (u) of this section for each unique insulating gas, the name (as required in § 98.3(c)(4)(iii)(G)( 1 )) and weight percent of each fluorinated gas in the insulating gas.
§ 98.457   Records that must be retained.
In addition to the information required by § 98.3(g), you must retain the following records:
(a) All information reported and listed in § 98.456.
(b) Accuracy certifications and calibration records for all scales and monitoring equipment, including the method or manufacturer's specification used for calibration.
(c) Certifications of the quantity of gas, in pounds, charged into equipment at the electrical equipment manufacturer or refurbishment facility as well as the actual quantity of gas, in pounds, charged into equipment at installation.
(d) Check-out and weigh-in sheets and procedures for cylinders.
(e) Residual gas amounts, in pounds, in cylinders sent back to suppliers.
(f) Invoices for gas purchases and sales.
(g) GHG Monitoring Plans, as described in § 98.3(g)(5), must be completed by April 1, 2011.
§ 98.458   Definitions.
Except as specified in this section, all terms used in this subpart have the same meaning given in the CAA and subpart A of this part.
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.
Reportable insulating gas , for purposes of this subpart, means an insulating gas whose weighted average GWP, as calculated in equation SS-2 to § 98.452, 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.
§ 98.460   Definition of the source category.
(a) This source category applies to industrial waste landfills that accepted waste on or after January 1, 1980, and that are located at a facility whose total landfill design capacity is greater than or equal to 300,000 metric tons.
(b) An industrial waste landfill is a landfill other than a municipal solid waste landfill, a RCRA Subtitle C hazardous waste landfill, or a TSCA hazardous waste landfill, in which industrial solid waste, such as RCRA Subtitle D wastes (non-hazardous industrial solid waste, defined in 40 CFR 257.2), commercial solid wastes, or conditionally exempt small quantity generator wastes, is placed. An industrial waste landfill includes all disposal areas at the facility.
(c) This source category does not include:
(1) Construction and demolition waste landfills.
(2) Industrial waste landfills that only receive one or more of the following inert waste materials:
(i) Coal combustion or incinerator ash ( e.g., fly ash).
(ii) Cement kiln dust.
(iii) Rocks and/or soil from excavation and construction and similar activities.
(iv) Glass.
(v) Non-chemically bound sand ( e.g., green foundry sand).
(vii) Clay, gypsum, or pottery cull.
(viii) Bricks, mortar, or cement.
(ix) Furnace slag.
(x) Materials used as refractory ( e.g., alumina, silicon, fire clay, fire brick).
(xi) Plastics ( e.g., polyethylene, polypropylene, polyethylene terephthalate, polystyrene, polyvinyl chloride).
(xii) Other waste material that has a volatile solids concentration of 0.5 weight percent (on a dry basis) or less.
(xiii) Other waste material that has a DOC value of 0.3 weight percent (on a wet basis) or less. DOC value must be determined using a 60-day anaerobic biodegradation test procedure identified in § 98.464(b)(4)(i).
(d) This source category consists of the following sources at industrial waste landfills: Landfills, gas collection systems at landfills, and destruction devices for landfill gases (including flares).
§ 98.461   Reporting threshold.
You must report GHG emissions under this subpart if your facility contains an industrial waste landfill meeting the criteria in § 98.460 and the facility meets the requirements of § 98.2(a)(2). For the purposes of § 98.2(a)(2), the emissions from the industrial waste landfill are to be determined using the methane generation corrected for oxidation as determined using Equation TT-6 of this subpart times the global warming potential for methane in Table A-1 of subpart A of this part.
§ 98.462   GHGs to report.
(a) You must report CH 4 generation and CH 4 emissions from industrial waste landfills.
(b) You must report CH 4 destruction resulting from landfill gas collection and destruction devices, if present.
(c) You must report under subpart C of this part (General Stationary Fuel Combustion Sources) the emissions of CO 2 , CH 4 , and N 2 O from each stationary combustion unit associated with the landfill gas destruction device, if present, by following the requirements of subpart C of this part.
§ 98.463   Calculating GHG emissions.
(a) For each industrial waste landfill subject to the reporting requirements of this subpart, calculate annual modeled CH 4 generation according to the applicable requirements in paragraphs (a)(1) through (a)(3) of this section. Apply Equation TT-1 of this section for each waste stream disposed of in the landfill and sum the CH 4 generation rates for all waste streams disposed of in the landfill to calculate the total annual modeled CH 4 generation rate for the landfill.
(1) Calculate annual modeled CH 4 generation using Equation TT-1 of this section.
(2) Waste stream quantities. Determine annual waste quantities as specified in paragraphs (a)(2)(i) through (ii) of this section for each year starting with January 1, 1960 or the year the landfills first accepted waste if after January 1, 1960, up until the most recent reporting year. The choice of method for determining waste quantities will vary according to the availability of historical data. Beginning in the first emissions reporting year (2011 or later) and for each year thereafter, use the procedures in paragraph (a)(2)(i) of this section to determine waste stream quantities. These procedures should also be used for any year prior to the first emissions reporting year for which the data are available. For other historical years, use paragraph (a)(2)(i) of this section, where waste disposal records are available, and use the procedures outlined in paragraph (a)(2)(ii) of this section when waste disposal records are unavailable, to determine waste stream quantities. Historical disposal quantities deposited ( i.e., prior to the first year in which monitoring begins) should only be determined once, as part of the first annual report, and the same values should be used for all subsequent annual reports, supplemented by the next year's data on new waste disposal.
(i) Determine the quantity of waste (in metric tons as received, i.e., wet weight) disposed of in the landfill separately for each waste stream by any one or a combination of the following methods.
(A) Direct mass measurements.
(B) Direct volume measurements multiplied by waste stream density determined from periodic density measurement data or process knowledge.
(C) Mass balance procedures, determining the mass of waste as the difference between the mass of the process inputs and the mass of the process outputs.
(D) The number of loads ( e.g., trucks) multiplied by the mass of waste per load based on the working capacity of the container or vehicle.
(ii) Determine the historical disposal quantities for landfills using the Waste Disposal Factor approach in paragraphs (a)(2)(ii)(A) and (B) of this section when historical production or processing data are available. If production or processing data are available for a given year, you must use Equation TT-3 of this section for that year. Determine historical disposal quantities using the method specified in paragraph (a)(2)(ii)(C) of this section when historical production or processing data are not available, and for waste streams received from an off-site facility when historical disposal quantities cannot be determined using the methods specified in paragraph (a)(2)(i) of this section.
(A) Determining Waste Disposal Factor: For each waste stream disposed of in the landfill, calculate the average waste disposal rate per unit of production or unit throughput using all available waste quantity data and corresponding production or processing rates for the process generating that waste or, if appropriate, the facility, using Equation TT-2 of this section.
(B) Calculate waste: For each waste stream disposed of in the landfill, calculate the waste disposal quantities for historic years in which direct waste disposal measurements are not available using historical production data and Equation TT-3 of this section.
(C) For any year in which historic production or processing data are not available such that historic waste quantities cannot be estimated using Equation TT-3 of this section, calculate an average annual bulk waste disposal quantity using either Equation TT-4a of this section when data are available consecutively for the most recent disposal years or Equation TT-4b of this section when data are available for sporadic (non-consecutive) years.
(3) Degradable organic content (DOC). For any year, X, in Equation TT-1 of this section, use either the applicable default DOC values provided in Table TT-1 of this subpart or determine values for DOC x as specified in paragraphs (a)(3)(i) through (iv) of this section. When developing historical waste quantity data, you may use default DOC values from Table TT-1 of this subpart for certain years and determined values for DOC x for other years. The historical values for DOC or DOC x must be developed only for the first annual report required for the industrial waste landfill; and used for all subsequent annual reports ( e.g., if DOC for year x = 1990 was determined to be 0.15 in the first reporting year, you must use 0.15 for the 1990 DOC value for all subsequent annual reports).
(i) For the first year in which GHG emissions from this industrial waste landfill must be reported, determine the DOC x value of each waste stream disposed of in the landfill no less frequently than once per quarter using the methods specified in § 98.464(b). Calculate annual DOC x for each waste stream as the arithmetic average of all DOC x values for that waste stream that were measured during the year.
(ii) For subsequent years (after the first year in which GHG emissions from this industrial waste landfill must be reported), either use the DOC x of each waste stream calculated for the most recent reporting year for which DOC values were determined according to paragraph (a)(3)(i) of this section, or determine new DOC values for that year following the requirements in paragraph (a)(3)(i) of this section. You must determine new DOC values following the requirements in paragraph (a)(3)(i) of this section if changes in the process operations occurred during the previous reporting year that can reasonably be expected to alter the characteristics of the waste stream, such as the water content or volatile solids concentration. Should changes to the waste stream occur, you must revise the GHG Monitoring Plan as required in § 98.3(g)(5)(iii) and report the new DOC x value according to the requirements of § 98.466.
(iii) If DOC x measurement data for each waste stream are available according to the methods specified in § 98.464(b) for years prior to the first year in which GHG emissions from this industrial waste landfill must be reported, determine DOC x for each waste stream as the arithmetic average of all DOC x values for that waste stream that were measured in Year X. A single measurement value is acceptable for determining DOC x for years prior to the first reporting year.
(iv) For historical years for which DOC x measurement data, determined according to the methods specified in § 98.464(b), are not available, determine the historical values for DOC x using the applicable methods specified in paragraphs (a)(3)(iv)(A) and (B) of this section. Determine these historical values for DOC x only for the first annual report required for this industrial waste landfill; historical values for DOC x calculated for this first annual report should be used for all subsequent annual reports.
(A) For years in which waste stream-specific disposal quantities are determined (as required in paragraphs (a)(2) (ii)(A) and (B) of this section), calculate the average DOC value for a given waste stream as the arithmetic average of all DOC measurements of that waste stream that follow the methods provided in § 98.464(b), including any measurement values for years prior to the first reporting year and the four measurement values required in the first reporting year. Use the resulting waste-specific average DOC value for all applicable years ( i.e., years in which waste stream-specific disposal quantities are determined) for which direct DOC measurement data are not available.
(B) For years for which bulk waste disposal quantities are determined according to paragraphs (a)(2)(ii)(C) of this section, calculate the weighted average bulk DOC value according to the following: Calculate the average DOC value for each waste stream as the arithmetic average of all DOC measurements of that waste stream that follows the methods provided in § 98.464(b) (generally, this will include only the DOC values determined in the first year in which GHG emissions from this industrial waste landfill must be reported); calculate the average annual disposal quantity for each waste stream as the arithmetic average of the annual disposal quantities for each year in which waste stream-specific disposal quantities have been determined; and calculate the bulk waste DOC value using Equation TT-5 of this section. Use the bulk waste DOC value as DOC x for all years for which bulk waste disposal quantities are determined according to paragraphs (a)(2)(ii)(C) of this section.
(b) For each landfill, calculate CH 4 generation (adjusted for oxidation in cover materials) and CH 4 emissions (taking into account any CH 4 recovery, if applicable, and oxidation in cover materials) according to the applicable methods in paragraphs (b)(1) through (b)(3) of this section.
(1) For each landfill, calculate CH 4 generation, adjusted for oxidation, from the modeled CH 4 (G CH 4 from Equation TT-1 of this section) using Equation TT-6 of this section.
(2) For landfills that do not have landfill gas collection systems operating during the reporting year, the CH 4 emissions are equal to the CH 4 generation (MG) calculated in Equation TT-6 of this section.
(3) For landfills with landfill gas collection systems in operation during any portion of the reporting year, perform all of the calculations specified in paragraphs (b)(3)(i) through (iv) of this section.
(i) Calculate the quantity of CH 4 recovered according to the requirements at § 98.343(b).
(ii) Calculate CH 4 emissions using the Equation HH-6 of § 98.343(c)(3)(i), except use G CH 4 determined using Equation TT-1 of this section in Equation HH-6 of § 98.343(c)(3)(i).
(iii) Calculate CH 4 generation (MG) from the quantity of CH 4 recovered using Equation HH-7 of § 98.343(c)(3)(ii).
(iv) Calculate CH 4 emissions from the quantity of CH 4 recovered using Equation HH-8 of § 98.343(c)(3)(ii).
§ 98.464   Monitoring and QA/QC requirements.
(a) For calendar year 2011 monitoring, the facility may submit a request to the Administrator to use one or more best available monitoring methods as listed in § 98.3(d)(1)(i) through (iv). The request must be submitted no later than October 12, 2010 and must contain the information in § 98.3(d)(2)(ii). To obtain approval, the request must demonstrate to the Administrator's satisfaction that it is not reasonably feasible to acquire, install, and operate a required piece of monitoring equipment by January 1, 2011. The use of best available monitoring methods will not be approved beyond December 31, 2011.
(b) For each waste stream placed in the landfill during the reporting year for which you choose to determine volatile solids concentration and/or a waste stream-specific DOC X , you must collect and test a representative sample of that waste stream using the methods specified in paragraphs (b)(1) through (b)(4) of this section, as applicable.
(1) Develop and follow a sampling plan to collect a representative sample (in terms of composition and moisture content) of each waste stream placed in the landfill for which testing is elected.
(2) Determine the percent total solids and the percent volatile solids of each sample following Standard Method 2540G “Total, Fixed, and Volatile Solids in Solid and Semisolid Samples” (incorporated by reference; see § 98.7).
(3) For the purposes of § 98.460(c)(2)(xii), the volatile solids concentration (weight percent on a dry basis) is the percent volatile solids determined using Standard Method 2540G “Total, Fixed, and Volatile Solids in Solid and Semisolid Samples” (incorporated by reference; see § 98.7).
(4) Determine DOC value of a waste stream by either using at least a 60-day anaerobic biodegradation test as specified in paragraph (b)(4)(i) of this section or by estimating the DOC value based on the total and volatile solids measurements as specified in paragraph (b)(4)(ii) of this section.
(i) Perform an anaerobic biodegradation test and determine the DOC value of a waste stream following the procedures and requirements in paragraphs (b)(4)(i)(A) through (E) of this section.
(A) You may use the procedures published by a consensus-based standards organization to conduct a minimum of a 60-day anaerobic biodegradation test. Consensus-based standards organizations include, but are not limited to, the following: ASTM International (100 Barr Harbor Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959, (800) 262-1373, http://www.astm.org ), the American National Standards Institute (ANSI, 1819 L Street, NW., 6th floor, Washington, DC 20036, (202) 293-8020, http://www.ansi.org ), the American Society of Mechanical Engineers (ASME, Three Park Avenue, New York, NY 10016-5990, (800) 843-2763, http://www.asme.org ), and the North American Energy Standards Board (NAESB, 801 Travis Street, Suite 1675, Houston, TX 77002, (713) 356-0060, http://www.api.org ).
(B) Use a minimum of four samples: Two waste stream samples, a control sample using a known substrate (such as ethanol), and a digester sludge blank sample. Each waste stream sample must be appropriately ground to ensure the waste material is fully exposed to the anaerobic digester sludge.
(C) Determine the net mass of carbon degraded in the control sample as the difference in the results of the control sample and the digester sludge blank sample. Determine the net mass of carbon degraded in each waste stream sample as the difference in the results of each waste stream sample and the digester sludge blank sample.
(D) Determine the fraction of carbon degraded in the control sample as the net mass of carbon degraded in the control sample divided by the mass of carbon added via the substrate material in the control sample. If less than 50 percent of the theoretical mass of carbon in the control sample is degraded, the test run is invalid.
(E) Determine the DOC of each waste sample using Equation TT-7 of this section. If the DOC values for the two waste stream samples differ by more than 20 percent, the test run is invalid. The DOC of the waste stream is determined as the average DOC value of the two waste stream samples determined during a valid test.
(ii) Calculate the waste stream-specific DOC X value using Equation TT-8 of this section.
(c) For each waste stream that was historically managed in the landfill for which you choose to determine volatile solids concentration and/or a waste stream-specific DOC X , you must determine volatile solids concentration or DOC X of the waste stream as initially placed in the landfill using the methods specified in paragraph (c)(1) or (2) of this section, as applicable.
(1) If you can identify a similar waste stream to the waste stream that was historically managed in the landfill, you must determine the volatile solids concentration or DOC X of the similar waste stream using the applicable procedures in paragraphs (b)(1) through (4) of this section.
(2) If you cannot identify a similar waste stream to the waste stream that was historically managed in the landfill, you may determine the volatile solids concentration or DOC X of the historically managed waste stream using process knowledge. You must document the basis for the volatile solids concentration or DOC X value as determined through process knowledge.
(d) For landfills with gas collection systems, operate, maintain, and calibrate a gas composition monitor capable of measuring the concentration of CH 4 according to the requirements specified at § 98.344(b).
(e) For landfills with gas collection systems, install, operate, maintain, and calibrate a gas flow meter capable of measuring the volumetric flow rate of the recovered landfill gas according to the requirements specified at § 98.344(c).
(f) For landfills with gas collection systems, all temperature, pressure, and if applicable, moisture content monitors must be calibrated using the procedures and frequencies specified by the manufacturer.
(g) For landfills electing to measure the fraction by volume of CH 4 in landfill gas (F), follow the requirements in paragraphs (g)(1) and (g)(2) of this section.
(1) Use a gas composition monitor capable of measuring the concentration of CH 4 on a dry basis that is properly operated, calibrated, and maintained according to the requirements specified at § 98.344(b). You must either use a gas composition monitor that is also capable of measuring the 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 TT-9 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 TT-1 of this part.
(h) The facility shall document the procedures used to ensure the accuracy of the estimates of disposal quantities and, if the industrial waste landfill has a gas collection system, gas flow rate, gas composition, temperature, pressure, and moisture content measurements. These procedures include, but are not limited to, calibration of weighing equipment, fuel flow meters, and other measurement devices. The estimated accuracy of measurements made with these devices shall also be recorded, and the technical basis for these estimates shall be provided.
§ 98.465   Procedures for estimating missing data.
(a) A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable ( e.g., if a meter malfunctions during unit operation or if a required fuel sample is not taken), a substitute data value for the missing parameter shall be used in the calculations, in accordance with paragraph (b) of this section.
(b) For industrial waste landfills with gas collection systems, follow the procedures for estimating missing data specified in § 98.345(a) and (b).
§ 98.466   Data reporting requirements.
In addition to the information required by § 98.3(c), each annual report must contain the following information for each landfill.
(a) Report the following general landfill information:
(1) A classification of the landfill as “open” (actively received waste in the reporting year) or “closed” (no longer receiving waste).
(2) The year in which the landfill first started accepting waste for disposal.
(3) The last year the landfill accepted waste (for open landfills, enter the estimated year of landfill closure).
(4) The capacity (in metric tons) of the landfill.
(5) An indication of whether leachate recirculation is used during the reporting year and its typical frequency of use over the past 10 years ( e.g., used several times a year for the past 10 years, used at least once a year for the past 10 years, used occasionally but not every year over the past 10 years, not used).
(b) Report the following waste characterization and modeling information:
(1) The number of waste steams (including “Other Industrial Solid Waste (not otherwise listed)” and “Inerts”) for which Equation TT-1 of this subpart is used to calculate modeled CH 4 generation.
(2) A description of each waste stream (including the types of materials in each waste stream) for which Equation TT-1 of this subpart is used to calculate modeled CH 4 generation.
(3) The fraction of CH 4 in the landfill gas, F, (volume fraction, dry basis, corrected to 0% oxygen) for the reporting year and an indication as to whether this was the default value or a value determined through measurement data.
(4) The methane correction factor (MCF) value used in the calculations. If an MCF value other than the default of 1 is used, provide a description of the aeration system, including aeration blower capacity, the fraction of the landfill containing waste affected by the aeration, the total number of hours during the year the aeration blower was operated, and other factors used as a basis for the selected MCF value.
(5) For each waste stream, the decay rate (k) value used in the calculations.
(c) Report the following historical waste information:
(1) [Reserved]
(2) For each waste stream identified in paragraph (b) of this section, the method(s) for estimating historical waste disposal quantities and the range of years for which each method applies.
(3) For each waste stream identified in paragraph (b) of this section for which Equation TT-2 of this subpart is used, provide:
(i) [Reserved]
(ii) The year of the data used in Equation TT-2 of § 98.463 for the waste disposal quantity and production quantity, for each year used in Equation TT-2 to calculate the average waste disposal factor (WDF).
(iii) [Reserved]
(4) If Equation TT-4a of this subpart is used, provide:
(i) The value of landfill capacity (LFC).
(ii) YrData.
(iii) YrOpen.
(5) If Equation TT-4b of this subpart is used, provide:
(i) WIP (i.e., the quantity of waste in-place at the start of the reporting year from design drawings or engineering estimates (metric tons) or, for closed landfills for which waste in-place quantities are not available, the landfill's design capacity).
(ii) The cumulative quantity of waste placed in the landfill for the years for which disposal quantities are available from company record or from Equation TT-3 of this part.
(iii) YrLast.
(iv) YrOpen.
(v) NYrData.
(d) For each year of landfilling starting with the “Start Year” (S) and each year thereafter up to the current reporting year, report the following information:
(1) The calendar year for which the following data elements apply.
(2) The quantity of waste (W X ) disposed of in the landfill (metric tons, wet weight) for the specified year for each waste stream identified in paragraph (b) of this section.
(3) For each waste stream, the degradable organic carbon (DOC X ) value (mass fraction) for the specified year and an indication as to whether this was the default value from Table TT-1 to this subpart, a measured value using a 60-day anaerobic biodegradation test as specified in § 98.464(b)(4)(i), or a value based on total and volatile solids measurements as specified in § 98.464(b)(4)(ii). If DOC X was determined by a 60-day anaerobic biodegradation test, specify the test method used.
(e) Report the following information describing the landfill cover material:
(1) The type of cover material used (as either organic cover, clay cover, sand cover, or other soil mixtures).
(2) For each type of cover material used, the surface area (in square meters) at the start of the reporting year for the landfill sections that contain waste and that are associated with the selected cover type.
(f) The modeled annual methane generation (G CH4 ) for the reporting year (metric tons CH 4 ) calculated using Equation TT-1 of this subpart.
(g) For landfills without gas collection systems, provide:
(1) The annual methane emissions ( i.e. , the methane generation (MG), adjusted for oxidation, calculated using Equation TT-6 of this subpart), reported in metric tons CH 4 .
(2) An indication of whether passive vents and/or passive flares (vents or flares that are not considered part of the gas collection system as defined in § 98.6) are present at this landfill.
(h) For landfills with gas collection systems, in addition to the reporting requirements in paragraphs (a) through (f) of this section, provide:
(1) The annual methane generation, adjusted for oxidation, calculated using Equation TT-6 of this subpart, reported in metric tons CH 4 .
(2) The oxidation factor used in Equation TT-6 of this subpart.
(3) All information required under 40 CFR 98.346(i)(1) through (7) and 40 CFR 98.346(i)(9) through (12).
§ 98.467   Records that must be retained.
(a) The calibration records for all monitoring equipment, including the method or manufacturer's specification used for calibration, and all measurement data used for the purposes of § 98.460(c)(2)(xii) or (xiii) or used to determine waste stream-specific DOC X values for use in Equation TT-1 of § 98.463.
(b) 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 (b)(1) and (2) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (b)(1) and (2) of this section.
(1) Quantity of each product produced or feedstock entering the process or facility per waste stream per year, from measurement data and/or other company records. You must use the same basis for all years in the calculation (i.e., based on production or based on quantity of feedstock) (metric tons) (Equation TT-2 of § 98.463).
(2) [Reserved]
§ 98.468   Definitions.
Except as provided below, all terms used in this subpart have the same meaning given in the CAA and subpart A of this part.
Construction and demolition (C&D) waste landfill means a solid waste disposal facility subject to the requirements of subparts A or B of part 257 of this chapter that receives construction and demolition waste and does not receive hazardous waste (defined in § 261.3 of this chapter) or industrial solid waste (defined in § 258.2 of this chapter) or municipal solid waste (defined in § 98.6 of this part) other than residential lead-based paint waste. A C&D waste landfill typically receives any one or more of the following types of solid wastes: roadwork material, excavated material, demolition waste, construction/renovation waste, and site clearance waste.
Design capacity means the maximum amount of solid waste a landfill can accept. For the purposes of this subpart, for landfills that have a permit, the design 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 the design capacity from volume to mass to determine its design capacity, the calculation must include a site-specific density. If the design capacity is within 10 percent of the applicability threshold in § 98.460(a) and there is a change in the production process that can reasonably be expected to change the site-specific waste density, the site-specific waste density must be redetermined and the design capacity must be recalculated based on the new waste density.
Industrial sludge means the residual, semi-solid material left from industrial wastewater treatment processes or wet air pollution control devices (e.g., wet scrubbers). Industrial sludge includes underflow material collected in primary or secondary clarifiers, settling basins, or precipitation tanks as well as dredged materials from wastewater tanks or impoundments. Industrial sludge also includes the semi-solid materials remaining after these materials are dewatered via a belt process, centrifuge, or similar dewatering process.
Solid waste has the meaning established by the Administrator pursuant to the Solid Waste Disposal Act (42 U.S.C.A. 6901 et seq. ).
Waste stream means industrial solid waste material that is generated by a specific manufacturing process or client. For wastes generated at the facility that includes the industrial waste landfill, a waste stream is the industrial solid waste material generated by a specific processing unit at that facility. For industrial solid wastes that are received from off-site facilities, a waste stream can be defined as each waste shipment or group of waste shipments received from a single client or group of clients that produce industrial solid wastes with similar waste properties.
§ 98.470   Definition of the source category.
(a) The injection of carbon dioxide (CO 2 ) source category comprises any well or group of wells that inject a CO 2 stream into the subsurface.
(b) If you report under subpart RR of this part for a well or group of wells, you shall not report under this subpart for that well or group of wells.
(c) If you report under subpart VV of this part for a well or group of wells, you shall not report under this subpart for that well or group of wells. If you previously met the source category definition for subpart UU of this part for a project where CO 2 is injected in enhanced recovery operations for oil and other hydrocarbons (CO 2 -EOR) and then began using the standard designated as CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7) such that you met the definition of the source category for subpart VV during a reporting year, you must report under subpart UU for the portion of the year before you began using CSA/ANSI ISO 27916:19 and report under subpart VV for the portion of the year after you began using CSA/ANSI ISO 27916:19.
(d) A facility that is subject to this part only because it is subject to subpart UU of this part is not required to report emissions under subpart C of this part or any other subpart listed in § 98.2(a)(1) or (2).
§ 98.471   Reporting threshold.
(a) You must report under this subpart if your facility injects any amount of CO 2 into the subsurface.
(b) For purposes of this subpart, any reference to CO 2 emissions in § 98.2(i) shall mean CO 2 received.
§ 98.472   GHGs to report.
You must report the mass of CO 2 received.
§ 98.473   Calculating CO2received.
(a) You must calculate and report the annual mass of CO 2 received by pipeline using the procedures in paragraphs (a)(1) or (a)(2) of this section and the procedures in paragraph (a)(3) of this section, if applicable.
(1) For a mass flow meter, you must calculate the total annual mass of CO 2 in a CO 2 stream received in metric tons by multiplying the mass flow by the CO 2 concentration in the flow, according to Equation UU-1 of this section. You must collect these data quarterly. Mass flow and concentration data measurements must be made in accordance with § 98.474.
(2) For a volumetric flow meter, you must calculate the total annual mass of CO 2 in a CO 2 stream received in metric tons by multiplying the volumetric flow at standard conditions by the CO 2 concentration in the flow and the density of CO 2 at standard conditions, according to Equation UU-2 of this section. You must collect these data quarterly. Volumetric flow and concentration data measurements must be made in accordance with § 98.474.
(3) If you receive CO 2 through more than one flow meter, you must sum the mass of all CO 2 received in accordance with the procedure specified in Equation UU-3 of this section.
(b) You must calculate and report the annual mass of CO 2 received in containers using the procedures specified in either paragraph (b)(1) or (b)(2) of this section.
(1) If you are measuring the mass of contents in a container under the provisions of § 98.474(a)(2)(i), you must calculate the CO 2 received in containers using Equation UU-1 of this section.
(2) If you are measuring the volume of contents in a container under the provisions of § 98.474(a)(2)(ii), you must calculate the CO 2 received in containers using Equation UU-2 of this section.
§ 98.474   Monitoring and QA/QC requirements.
(a) CO 2 received. (1) You must determine the quarterly flow rate of CO 2 received by pipeline by following the most appropriate of the following procedures:
(i) You may measure flow rate at the receiving custody transfer meter prior to any subsequent processing operations at the facility and collect the flow rate quarterly.
(ii) If you took ownership of the CO 2 in a commercial transaction, you may use the quarterly flow rate data from the sales contract if it is a one-time transaction or from invoices or manifests if it is an ongoing commercial transaction with discrete shipments.
(iii) If you inject CO 2 from a production process unit that is part of your facility, you may use the quarterly CO 2 flow rate that was measured at the equivalent of a custody transfer meter following procedures provided in subpart PP of this part. To be the equivalent of a custody transfer meter, a meter must measure the flow of CO 2 being transported to an injection well to the same degree of accuracy as a meter used for commercial transactions.
(2) You must determine the quarterly mass or volume of contents in all containers if you receive CO 2 in containers by the most appropriate of the following procedures:
(i) You may measure the mass of contents of containers summed quarterly using weigh bills, scales, or load cells.
(ii) You may determine the volume of the contents of containers summed quarterly.
(iii) If you took ownership of the CO 2 in a commercial transaction, you may use the quarterly mass or volume of contents from the sales contract if it is a one-time transaction or from invoices or manifests if it is an ongoing commercial transaction with discrete shipments.
(3) You must determine a quarterly concentration of the CO 2 received that is representative of all CO 2 received in that quarter by following the most appropriate of the following procedures:
(i) You may sample the CO 2 stream at least once per quarter at the point of receipt and measure its CO 2 concentration.
(ii) If you took ownership of the CO 2 in a commercial transaction for which the sales contract was contingent on CO 2 concentration, and if the supplier of the CO 2 sampled the CO 2 stream in a quarter and measured its concentration per the sales contract terms, you may use the CO 2 concentration data from the sales contract for that quarter.
(iii) If you inject CO 2 from a production process unit that is part of your facility, you may report the quarterly CO 2 concentration of the CO 2 stream supplied that was measured following procedures provided in subpart PP of this part as the quarterly CO 2 concentration of the CO 2 stream received.
(4) You must assume that the CO 2 you receive meets the definition of a CO 2 stream unless you can trace it through written records to a source other than a CO 2 stream.
(b) Measurement devices. (1) All flow meters must be operated continuously except as necessary for maintenance and calibration.
(2) You must calibrate all flow meters used to measure quantities reported in § 98.476 according to the calibration and accuracy requirements in § 98.3(i).
(3) You must operate all measurement devices according to one of the following. You may use an appropriate standard method published by a consensus-based standards organization if such a method exists or an industry standard practice. Consensus-based standards organizations include, but are not limited to, the following: ASTM International, the American National Standards Institute (ANSI), the American Gas Association (AGA), the American Society of Mechanical Engineers (ASME), the American Petroleum Institute (API), and the North American Energy Standards Board (NAESB).
(4) You must ensure that any flow meter calibrations performed are National Institute of Standards and Technology (NIST) traceable.
(c) General. (1) If you measure the concentration of any CO 2 quantity for reporting, you must measure according to one of the following. You may use an appropriate standard method published by a consensus-based standards organization if such a method exists or an industry standard practice.
(2) You must convert all measured volumes of CO 2 to the following standard industry temperature and pressure conditions for use in Equation UU-2 of this subpart: Standard cubic meters at a temperature of 60 degrees Fahrenheit and at an absolute pressure of 1 atmosphere.
(3) For 2011, you may follow the provisions of § 98.3(d)(1) through (2) for best available monitoring methods rather than follow the monitoring requirements of this section. For purposes of this subpart, any reference to the year 2010 in § 98.3(d)(1) through (2) shall mean 2011.
§ 98.475   Procedures for estimating missing data.
A complete record of all measured parameters used in the GHG quantities calculations is required.
(a) Whenever the monitoring procedures for all facilities that used flow meters covered under this subpart cannot be followed to measure flow, the following missing data procedures must be followed:
(1) Another calculation methodology listed in § 98.474(a)(1) must be used if possible.
(2) If another method listed in § 98.474(a)(1) cannot be used, a quarterly flow rate value that is missing must be estimated using a representative flow rate value from the nearest previous time period.
(b) Whenever the monitoring procedures of this subpart cannot be followed to measure quarterly quantity of CO 2 received in containers, the most appropriate of the following missing data procedures must be followed:
(1) Another calculation methodology listed in § 98.474(a)(2) must be used if possible.
(2) If another method listed in § 98.474(a)(2) cannot be used, a quarterly mass or volume that is missing must be estimated using a representative mass or volume from the nearest previous time period.
(c) Whenever the monitoring procedures cannot be followed to measure CO 2 concentration, the following missing data procedures must be followed:
(1) Another calculation methodology listed in § 98.474(a)(3) must be used if possible.
(2) If another method listed in § 98.474(a)(3) cannot be used, a quarterly concentration value that is missing must be estimated using a representative concentration value from the nearest previous time period.
§ 98.476   Data reporting requirements.
If you are subject to this part and report under this subpart, you are not required to report the information in § 98.3(c)(4) for this subpart. In addition to the information required by § 98.3(c)(1) through § 98.3(c)(3) and by § 98.3(c)(5) through § 98.3(c)(9), you must report the information listed in this section.
(a) If you receive CO 2 by pipeline, report the following for each receiving flow meter:
(1) The total net mass of CO 2 received (metric tons) annually.
(2) If a volumetric flow meter is used to receive CO 2 :
(i) The volumetric flow through a receiving flow meter at standard conditions (in standard cubic meters) in each quarter.
(ii) The volumetric flow through a receiving flow meter that is redelivered to another facility without being injected into your well (in standard cubic meters) in each quarter.
(iii) The CO 2 concentration in the flow (volume percent CO 2 expressed as a decimal fraction) in each quarter.
(3) If a mass flow meter is used to receive CO 2 :
(i) The mass flow through a receiving flow meter (in metric tons) in each quarter.
(ii) The mass flow through a receiving flow meter that is redelivered to another facility without being injected into your well (in metric tons) in each quarter.
(iii) The CO 2 concentration in the flow (weight percent CO 2 expressed as a decimal fraction) in each quarter.
(4) The standard or method used to calculate each value in paragraphs (a)(2) through (a)(3) of this section.
(5) The number of times in the reporting year for which substitute data procedures were used to calculate values reported in paragraphs (a)(2) through (a)(3) of this section.
(6) Whether the flow meter is mass or volumetric.
(b) If you receive CO 2 in containers, report:
(1) The mass (in metric tons) or volume at standard conditions (in standard cubic meters) of contents in containers in each quarter.
(2) The concentration of CO 2 of contents in containers (volume or weight percent CO 2 expressed as a decimal fraction) in each quarter.
(3) The mass (in metric tons) or volume (in standard cubic meters) of contents in containers that is redelivered to another facility without being injected into your well in each quarter.
(4) The net total mass of CO 2 received (in metric tons) annually.
(5) The standard or method used to calculate each value in paragraphs (b)(1), (b)(2), and (b)(3) of this section.
(6) The number of times in the reporting year for which substitute data procedures were used to calculate values reported in paragraphs (b)(1) and (b)(2) of this section.
(c) If you use more than one receiving flow meter, report the net total mass of CO 2 received (metric tons) through all flow meters annually.
(d) The source of the CO 2 received according to the following categories:
(1) CO 2 production wells.
(2) Electric generating unit.
(3) Ethanol plant.
(4) Pulp and paper mill.
(5) Natural gas processing.
(6) Gasification operations.
(7) Other anthropogenic source.
(8) Discontinued enhanced oil and gas recovery project.
(9) Unknown.
(e) Report the following:
(1) Whether the facility received a Research and Development project exemption from reporting under 40 CFR part 98, subpart RR, for this reporting year. If you received an exemption, report the start and end dates of the exemption approved by EPA.
(2) Whether the facility includes a well or group of wells where a CO 2 stream was injected into subsurface geologic formations to enhance the recovery of oil during this reporting year.
(3) Whether the facility includes a well or group of wells where a CO 2 stream was injected into subsurface geologic formations to enhance the recovery of natural gas during this reporting year.
(4) Whether the facility includes a well or group of wells where a CO 2 stream was injected into subsurface geologic formations for acid gas disposal during this reporting year.
(5) Whether the facility includes a well or group of wells where a CO 2 stream was injected for a purpose other than those listed in paragraphs (e)(1) through (4) of this section. If you injected CO 2 for another purpose, report the purpose of the injection.
§ 98.477   Records that must be retained.
(a) You must follow the record retention requirements specified by § 98.3(g). In addition to the records required by § 98.3(g), you must retain quarterly records of CO 2 received, including mass flow rate or contents of containers (mass or volumetric) at standard conditions and operating conditions, operating temperature and pressure, and concentration of these streams. You must retain all required records for at least 3 years.
(b) You must complete your monitoring plans, as described in § 98.3(g)(5), by April 1 of the year you begin collecting data.
§ 98.478   Definitions.
Except as provided below, all terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
CO 2 received means the CO 2 stream that you receive to be injected for the first time into a well on your facility that is covered by this subpart. CO 2 received includes, but is not limited to, a CO 2 stream from a production process unit inside your facility and a CO 2 stream that was injected into a well on another facility, removed from a discontinued enhanced oil or natural gas or other production well, and transferred to your facility.
§ 98.480   Definition of the source category.
(a) This source category pertains to carbon dioxide (CO 2 ) that is injected in enhanced recovery operations for oil and other hydrocarbons (CO 2 -EOR) in which all of the following apply:
(1) You are using the standard designated as CSA/ANSI ISO 27916:19, (incorporated by reference, see § 98.7) as a method of quantifying geologic sequestration of CO 2 in association with EOR operations.
(2) ou are not reporting under subpart RR of this part.
(b) This source category does not include wells permitted as Class VI under the Underground Injection Control program.
(c) If you are subject to only this subpart, you are not required to report emissions under subpart C of this part or any other subpart listed in § 98.2(a)(1) or (2).
§ 98.481   Reporting threshold.
(a) You must report under this subpart if your CO 2 -EOR project uses CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7) as a method of quantifying geologic sequestration of CO 2 in association with CO 2 -EOR operations. There is no threshold for reporting.
(b) The requirements of § 98.2(i) do not apply to this subpart. Once a CO 2 -EOR project becomes subject to the requirements of this subpart, you must continue for each year thereafter to comply with all requirements of this subpart, including the requirement to submit annual reports until the facility has met the requirements of paragraphs (b)(1) and (2) of this section and submitted a notification to discontinue reporting according to paragraph (b)(3) of this section.
(1) Discontinuation of reporting under this subpart must follow the requirements set forth under Clause 10 of CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7).
(2) CO 2 -EOR project termination is completed when all of the following occur:
(i) Cessation of CO 2 injection.
(ii) Cessation of hydrocarbon production from the project reservoir; and
(iii) Wells are plugged and abandoned unless otherwise required by the appropriate regulatory authority.
(3) You must notify the Administrator of your intent to cease reporting and provide a copy of the CO 2 -EOR project termination documentation.
(c) If you previously met the source category definition for subpart UU of this part for your CO 2 -EOR project and then began using CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7) as a method of quantifying geologic sequestration of CO 2 in association with CO 2 -EOR operations during a reporting year, you must report under subpart UU of this part for the portion of the year before you began using CSA/ANSI ISO 27916:19 and report under subpart VV for the portion of the year after you began using CSA/ANSI ISO 27916:19.
§ 98.482   GHGs to report.
You must report the following from Clause 8 of CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7):
(a) The mass of CO 2 received by the CO 2 -EOR project.
(b) The mass of CO 2 loss from the CO 2 -EOR project operations.
(c) The mass of native CO 2 produced and captured.
(d) The mass of CO 2 produced and sent off-site.
(e) The mass of CO 2 loss from the EOR complex.
(f) The mass of CO 2 stored in association with CO 2 -EOR.
§ 98.483   Calculating CO2geologic sequestration.
You must calculate CO 2 sequestered using the following quantification principles from Clause 8.2 of CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7).
(a) You must calculate the mass of CO 2 stored in association with CO 2 -EOR ( m stored ) in the reporting year by subtracting the mass of CO 2 loss from operations and the mass of CO 2 loss from the EOR complex from the total mass of CO 2 input (as specified in equation 1 to this paragraph (a)).
(b) The manner by which associated storage is quantified must assure completeness and preclude double counting. The annual mass of CO 2 that is recycled and reinjected into the EOR complex must not be quantified as associated storage. Loss from the CO 2 recycling facilities must be quantified.
(c) You must quantify the total mass of CO 2 input ( m input ) in the reporting year according to paragraphs (g)(1) through (3) of this section.
(1) You must include the total mass of CO 2 received at the custody transfer meter by the CO 2 -EOR project ( m received ).
(2) The CO 2 stream received (including CO 2 transferred from another CO 2 -EOR project) must be metered.
(i) The native CO 2 recovered and included as m native must be documented.
(ii) CO 2 delivered to multiple CO 2 -EOR projects must be allocated among those CO 2 -EOR projects.
(3) The sum of the quantities of allocated CO 2 must not exceed the total quantities of CO 2 received.
(d) You must calculate the total mass of CO 2 from project operations ( m loss operations ) in the reporting year as specified in equation 2 to this paragraph (d).
§ 98.484   Monitoring and QA/QC requirements.
You must use the applicable monitoring and quality assurance requirements set forth in Clause 6.2 of CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7).
§ 98.485   Procedures for estimating missing data.
Whenever the value of a parameter is unavailable or the quality assurance procedures set forth in § 98.484 cannot be followed, you must follow the procedures set forth in Clause 9.2 of CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7).
§ 98.486   Data reporting requirements.
In addition to the information required by § 98.3(c), the annual report shall contain the following information, as applicable:
(a) The annual quantity of associated storage in metric tons of CO 2 ( m stored ).
(b) The density of CO 2 if volumetric units are converted to mass in order to be reported for annual quantity of CO 2 stored.
(c) The annual quantity of CO 2 input ( m input ) and the information in paragraphs (c)(1) and (2) of this section.
(1) The annual total mass of CO 2 received at the custody transfer meter by the CO 2 -EOR project, including CO 2 transferred from another CO 2 -EOR project ( m received ).
(2) The annual mass of native CO 2 produced and captured in the CO 2 -EOR project ( m native ).
(d) The annual mass of CO 2 that is recycled and reinjected into the EOR complex.
(e) The annual total mass of CO 2 loss from project operations ( m loss operations ), and the information in paragraphs (e)(1) through (4) of this section.
(1) Loss of CO 2 due to leakage from production, handling, and recycling CO 2 -EOR facilities (infrastructure including wellheads) ( m loss leakage facilities ).
(2) Loss of CO 2 from venting/flaring from production operations ( m loss vent/flare ).
(3) Loss of CO 2 due to entrainment within produced gas/oil/water when this CO2 is not separated and reinjected ( m loss entrained ).
(4) Loss of CO 2 due to any transfer of CO 2 outside the CO 2 -EOR project ( m loss transfer ).
(f) The total mass of CO 2 loss from the EOR complex ( m loss EOR complex ).
(g) Annual documentation that contains the following components as described in Clause 4.4 of CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7):
(1) The formulas used to quantify the annual mass of associated storage, including the mass of CO 2 delivered to the CO 2 -EOR project and losses during the period covered by the documentation (see Clause 8 and Annex B of CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7)).
(2) The methods used to estimate missing data and the amounts estimated as described in Clause 9.2 of CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7).
(3) The approach and method for quantification utilized by the operator, including accuracy, precision, and uncertainties (see Clause 8 and Annex B of CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7)).
(4) A statement describing the nature of validation or verification including the date of review, process, findings, and responsible person or entity.
(5) Source of each CO 2 stream quantified as associated storage (see Clause 8.3 of CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7)).
(6) A description of the procedures used to detect and characterize the total CO 2 leakage from the EOR complex.
(7) If only the mass of anthropogenic CO 2 is considered for mstored, a description of the derivation and application of anthropogenic CO 2 allocation ratios for all the terms described in Clauses 8.1 to 8.4.6 of CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7).
(8) Any documentation provided by a qualified independent engineer or geologist, who certifies that the documentation provided, including the mass balance calculations as well as information regarding monitoring and containment assurance, is accurate and complete.
(h) Any changes made within the reporting year to containment assurance and monitoring approaches and procedures in the EOR operations management plan.
§ 98.487   Records that must be retained.
You must follow the record retention requirements specified by § 98.3(g). In addition to the records required by § 98.3(g), you must comply with the record retention requirements in Clause 9.1 of CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7).
§ 98.488   EOR Operations Management Plan.
(a) You must prepare and update, as necessary, a general EOR operations management plan that provides a description of the EOR complex and engineered system (see Clause 4.3(a) of CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7)), establishes that the EOR complex is adequate to provide safe, long-term containment of CO 2 , and includes site-specific and other information including:
(1) Geologic characterization of the EOR complex.
(2) A description of the facilities within the CO 2 -EOR project.
(3) A description of all wells and other engineered features in the CO 2 -EOR project.
(4) The operations history of the project reservoir.
(5) The information set forth in Clauses 5 and 6 of CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7).
(b) You must prepare initial documentation at the beginning of the quantification period, and include the following as described in the EOR operations management plan:
(1) A description of the EOR complex and engineered systems (see Clause 5 of CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7)).
(2) The initial containment assurance (see Clause 6.1.2 of CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7)).
(3) The monitoring program (see Clause 6.2 of CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7)).
(4) The quantification method to be used (see Clause 8 and Annex B of CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7)).
(5) The total mass of previously injected CO 2 (if any) within the EOR complex at the beginning of the CO 2 -EOR project (see Clause 8.5 and Annex B of CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7)).
(c) The EOR operation management plan in paragraph (a) of this section and initial documentation in paragraph (b) of this section must be submitted to the Administrator with the annual report covering the first reporting year that the facility reports under this subpart. In addition, any documentation provided by a qualified independent engineer or geologist, who certifies that the documentation provided is accurate and complete, must also be provided to the Administrator.
(d) If the EOR operations management plan is updated, the updated EOR management plan must be submitted to the Administrator with the annual report covering the first reporting year for which the updated EOR operation management plan is applicable.
§ 98.489   Definitions.
Except as provided in paragraphs (a) and (b) of this section, all terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
Additional terms and definitions are provided in Clause 3 of CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7).
§ 98.490   Definition of the source category.
(a) A coke calciner is a process unit that heats petroleum coke to high temperatures for the purpose of removing impurities or volatile substances in the petroleum coke feedstock.
(b) This source category consists of rotary kilns, rotary hearth furnaces, or similar process units used to calcine petroleum coke and also includes afterburners or other emission control systems used to treat the coke calcining unit's process exhaust gas.
§ 98.491   Reporting threshold.
You must report GHG emissions under this subpart if your facility contains a coke calciner and the facility meets the requirements of either § 98.2(a)(1) or (2).
§ 98.492   GHGs to report.
You must report:
(a) CO 2 , CH 4 , and N 2 O emissions from each coke calcining unit under this subpart.
(b) CO 2 , CH 4 , and N 2 O emissions from auxiliary fuel used in the coke calcining unit and afterburner, if applicable, or other control system used to treat the coke calcining unit's process off-gas under subpart C of this part by following the requirements of subpart C.
§ 98.493   Calculating GHG emissions.
(a) Calculate GHG emissions required to be reported in § 98.492(a) using the applicable methods in paragraph (b) of this section.
(b) For each coke calcining unit, calculate GHG emissions according to the applicable provisions in paragraphs (b)(1) through (4) of this section.
(1) If you operate and maintain a CEMS that measures CO 2 emissions according to subpart C of this part, you must calculate and report CO 2 emissions under this subpart by following the Tier 4 Calculation Methodology specified in § 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part. Auxiliary fuel use CO 2 emissions should be calculated in accordance with subpart C of this part and subtracted from the CO 2 CEMS emissions to determine process CO 2 emissions. Other coke calcining units must either install a CEMS that complies with the Tier 4 Calculation Methodology in subpart C of this part or follow the requirements of paragraph (b)(2) of this section.
(2) Calculate the CO 2 emissions from the coke calcining unit using monthly measurements and equation 1 to this paragraph (b)(2).
(3) Calculate CH4 emissions using equation 2 to this paragraph (b)(3).
(4) Calculate N 2 O emissions using equation 3 to this paragraph (b)(4).
§ 98.494   Monitoring and QA/QC requirements.
(a) Flow meters, gas composition monitors, and heating value monitors that are associated with sources that use a CEMS to measure CO 2 emissions according to subpart C of this part or that are associated with stationary combustion sources must meet the applicable monitoring and QA/QC requirements in § 98.34.
(b) Determine the mass of petroleum coke monthly as required by equation 1 to § 98.493(b)(2) using mass measurement equipment meeting the requirements for commercial weighing equipment as described in NIST HB 44-2023 (incorporated by reference, see § 98.7). Calibrate the measurement device according to the procedures specified by NIST HB 44-2023 (incorporated by reference, see § 98.7) or the procedures specified by the manufacturer. Recalibrate either biennially or at the minimum frequency specified by the manufacturer.
(c) Determine the carbon content of petroleum coke as required by equation 1 § 98.493(b)(2) using any one of the following methods. Calibrate the measurement device according to procedures specified by the method or procedures specified by the measurement device manufacturer.
(1) ASTM D3176-15 (incorporated by reference, see § 98.7).
(2) ASTM D5291-16 (incorporated by reference, see § 98.7).
(3) ASTM D5373-21 (incorporated by reference, see § 98.7).
(d) The owner or operator must document the procedures used to ensure the accuracy of the monitoring systems used including but not limited to calibration of weighing equipment, flow meters, and other measurement devices. The estimated accuracy of measurements made with these devices must also be recorded.
§ 98.495   Procedures for estimating missing data.
A complete record of all measured parameters used in the GHG emissions calculations is required ( e.g., concentrations, flow rates, fuel heating values, carbon content values). Therefore, whenever a quality-assured value of a required parameter is unavailable ( e.g., if a CEMS 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.
(a) For missing auxiliary fuel use data, use the missing data procedures in subpart C of this part.
(b) For each missing value of mass or carbon content of coke, substitute the arithmetic average of the quality-assured values of that parameter immediately preceding and immediately following the missing data incident. If the “after” value 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 must be the first quality-assured value obtained after the missing data period.
(c) For missing CEMS data, you must use the missing data procedures in § 98.35.
§ 98.496   Data reporting requirements.
In addition to the reporting requirements of § 98.3(c), you must report the information specified in paragraphs (a) through (i) of this section for each coke calcining unit.
(a) The unit ID number (if applicable).
(b) Maximum rated throughput of the unit, in metric tons coke calcined/stream day.
(c) The calculated CO 2 , CH 4 , and N 2 O annual process emissions, expressed in metric tons of each pollutant emitted.
(d) A description of the method used to calculate the CO 2 emissions for each unit ( e.g., CEMS or equation 1 to § 98.493(b)(2)).
(e) Annual mass of green coke fed to the coke calcining unit from facility records (metric tons/year).
(f) Annual mass of marketable petroleum coke produced by the coke calcining unit from facility records (metric tons/year).
(g) Annual mass of petroleum coke dust removed from the process through the dust collection system of the coke calcining unit from facility records (metric tons/year) and an indication of whether coke dust is recycled to the unit ( e.g., all dust is recycled, a portion of the dust is recycled, or none of the dust is recycled).
(h) Annual average mass fraction carbon content of green coke fed to the coke calcining unit from facility measurement data (metric tons C per metric ton green coke).
(i) Annual average mass fraction carbon content of marketable petroleum coke produced by the coke calcining unit from facility measurement data (metric tons C per metric ton petroleum coke).
§ 98.497   Records that must be retained.
In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) and (b) of this section.
(a) The records of all parameters monitored under § 98.494.
(b) The applicable verification software records as identified in this paragraph (b). 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 (b)(1) through (5) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (b)(1) through (5) of this section.
(1) Monthly mass of green coke fed to the coke calcining unit from facility records (metric tons/year) (equation 1 to § 98.493(b)(2)).
(2) Monthly mass of marketable petroleum coke produced by the coke calcining unit from facility records (metric tons/year) (equation 1 to § 98.493(b)(2)).
(3) Monthly mass of petroleum coke dust removed from the process through the dust collection system of the coke calcining unit from facility records (metric tons/year) (equation 1 to § 98.493(b)(2)).
(4) Average monthly mass fraction carbon content of green coke fed to the coke calcining unit from facility measurement data (metric tons C per metric ton green coke) (equation 1 to § 98.493(b)(2)).
(5) Average monthly mass fraction carbon content of marketable petroleum coke produced by the coke calcining unit from facility measurement data (metric tons C per metric ton petroleum coke) (equation 1 to § 98.493(b)(2)).
§ 98.498   Definitions.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
§ 98.500   Definition of the source category.
The calcium carbide production source category consists of any facility that produces calcium carbide.
§ 98.501   Reporting threshold.
You must report GHG emissions under this subpart if your facility contains a calcium carbide production process and the facility meets the requirements of either § 98.2(a)(1) or (2).
§ 98.502   GHGs to report.
You must report:
(a) Process CO 2 emissions from each calcium carbide process unit or furnace used for the production of calcium carbide.
(b) CO 2 , CH 4 , and N 2 O emissions from each stationary combustion unit following the requirements of subpart C of this part. You must report these emissions under subpart C of this part by following the requirements of subpart C.
§ 98.503   Calculating GHG emissions.
You must calculate and report the annual process CO 2 emissions from each calcium carbide process unit not subject to paragraph (c) of this section using the procedures in either paragraph (a) or (b) of this section.
(a) Calculate and report under this subpart the combined process and combustion CO 2 emissions by operating and maintaining CEMS according to the Tier 4 Calculation Methodology in § 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part.
(b) Calculate and report under this subpart the annual process CO 2 emissions from the calcium carbide process unit using the carbon mass balance procedure specified in paragraphs (b)(1) and (2) of this section.
(1) For each calcium carbide process unit, determine the annual mass of carbon in each carbon-containing input and output material for the calcium carbide process unit and estimate annual process CO 2 emissions from the calcium carbide process unit using equation 1 to this paragraph (b)(1). Carbon-containing input materials include carbon electrodes and carbonaceous reducing agents. If you document that a specific input or output material contributes less than 1 percent of the total carbon into or out of the process, you do not have to include the material in your calculation using equation 1.
(2) Determine the combined annual process CO 2 emissions from the calcium carbide process units at your facility using equation 2 to this paragraph (b)(2).
(c) If all GHG emissions from a calcium carbide process unit are vented through the same stack as any combustion unit or process equipment that reports CO 2 emissions using a CEMS that complies with the Tier 4 Calculation Methodology in subpart C of this part, then the calculation methodology in paragraph (b) of this section must not be used to calculate process emissions. The owner or operator must 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.
§ 98.504   Monitoring and QA/QC requirements.
If you determine annual process CO 2 emissions using the carbon mass balance procedure in § 98.503(b), you must meet the requirements specified in paragraphs (a) and (b) of this section.
(a) Determine the annual mass for each material used for the calculations of annual process CO 2 emissions using equation 1 to § 98.503(b)(1) by summing the monthly mass for the material determined for each month of the calendar year. The monthly mass may be determined using plant instruments used for accounting purposes, including either direct measurement of the quantity of the material placed in the unit or by calculations using process operating information.
(b) For each material identified in paragraph (a) of this section, you must determine the average carbon content of the material consumed, used, or produced in the calendar year using the methods specified in either paragraph (b)(1) or (2) of this section. If you document that a specific process input or output contributes less than one percent of the total mass of carbon into or out of the process, you do not have to determine the monthly mass or annual carbon content of that input or output.
(1) Information provided by your material supplier.
(2) Collecting and analyzing at least three representative samples of the material inputs and outputs each year. The carbon content of the material must be analyzed at least annually using the standard methods (and their QA/QC procedures) specified in paragraphs (b)(2)(i) and (ii) of this section, as applicable.
(i) ASTM D5373-08 (incorporated by reference, see § 98.7), for analysis of carbonaceous reducing agents and carbon electrodes.
(ii) ASTM C25-06 (incorporated by reference, see § 98.7) for analysis of materials such as limestone or dolomite.