# 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<sub>2</sub> by pipeline, report the following for each receiving flow meter:
(1) The total net mass of CO<sub>2</sub> received (metric tons) annually.
(2) If a volumetric flow meter is used to receive CO<sub>2</sub> 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<sub>2</sub> concentration in the flow (volume percent CO<sub>2</sub> expressed as a decimal fraction) in each quarter.
(3) If a mass flow meter is used to receive CO<sub>2</sub> 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<sub>2</sub> concentration in the flow (weight percent CO<sub>2</sub> expressed as a decimal fraction) in each quarter.
(4) If the CO<sub>2</sub> received is wholly injected and not mixed with any other supply of CO<sub>2</sub>, 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<sub>2</sub> 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<sub>2</sub> of contents in containers (volume or wt. percent CO<sub>2</sub> 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<sub>2</sub> 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<sub>2</sub> received (metric tons) through all flow meters annually.
(d) The source of the CO<sub>2</sub> received according to the following categories:
(1) CO<sub>2</sub> 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<sub>2</sub> injected (metric tons) annually.
(ii) The CO<sub>2</sub> concentration in flow (volume or weight percent CO<sub>2</sub> 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<sub>2</sub> injected (metric tons) in the reporting year as calculated in Equation RR-6 of this subpart.
(3) For CO<sub>2</sub> emissions from equipment leaks and vented emissions of CO<sub>2</sub>, report the following:
(i) The mass of CO<sub>2</sub> emitted (in metric tons) annually from equipment leaks and vented emissions of CO<sub>2</sub> from equipment located on the surface between the flow meter used to measure injection quantity and the injection wellhead.
(ii) The mass of CO<sub>2</sub> emitted (in metric tons) annually from equipment leaks and vented emissions of CO<sub>2</sub> 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<sub>2</sub> mass produced (metric tons) annually.
(ii) CO<sub>2</sub> concentration in flow (volume or weight percent CO<sub>2</sub> 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<sub>2</sub> in produced oil or other fluid divided by the CO<sub>2</sub> separated through all separators in the reporting year (weight percent CO<sub>2</sub> 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<sub>2</sub> produced in the reporting year as calculated in Equation RR-9 of this subpart.
(7) For each leakage pathway through which CO<sub>2</sub> emissions occurred, report:
(i) A numerical identifier for the leakage pathway.
(ii) The CO<sub>2</sub> (metric tons) emitted through that pathway in the reporting year.
(8) Annual CO<sub>2</sub> mass emitted (metric tons) by surface leakage in the reporting year as calculated by Equation RR-10 of this subpart.
(9) Annual CO<sub>2</sub> (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<sub>2</sub> (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<sub>2</sub>, 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<sub>2</sub> 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.
[75 FR 75078, Dec. 1, 2010, as amended at 76 FR 73906, Nov. 29, 2011; 78 FR 71979, Nov. 29, 2013]