Page 1 of 32

**Subpart RR**

**— Geologic Sequestration of Carbon Dioxide**  **§ 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 in clude 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 containm ent 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, yo u 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 i s 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:Page 2 of 32

(i) The planned duration of CO 2 injection for the project. (ii) The plann ed 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 proj ect within 60 day s 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 day s of the Administrator's determination. You may request one extension of up to an additional 180 day s in which to submit the proposed MRV plan. **§ 98. 441**  **Reporting threshold.**Page 3 of 32

(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 t his subpart, the owner or operator must continue for each ye ar thereafter to compl y 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 req uest 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 VIunder the Underground Injection Control program, a copy of the applicable Underground Injec tion Control program Director's authorization of site closure. (ii) For all other wells, and as an alternative for wells permitted as Class VIunder 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 likel y 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.Page 4 of 32

**§ 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 ye ars since the facility became subject to reporting requirements under this subpart. **§ 98. 443**  **Calculating CO 2**  **geologic 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 (Equatio ns 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.Page 5 of 32

(a) You must calculate and report the annual mass of CO 2 received b y 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 q uarterl y. Mass flow and concentration data measurements must be made in accordance with § 98. 444.

where: CO 2T,r = Net annual mass of CO 2 received through flow meter r (metric tons). Q r,p = Quarterl y mass flow through a receiving flow meter r in quarter p (metric

tons). S r,p = Quarterl y mass flow through a receiving flow meter r that is redelivered to

another facility

without being injected into your well in quarter p (metric tons). C CO2,p,r = Quarterl y CO 2 concentration measurement in flow for flow meter r in quarter

p (wt. percent CO 2 , expressed as a decimal fraction). p = Quarter of the ye ar. r = Receiving flow meter. (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 quarterl y . Volumetric flow and concentration data measurements must be made in accordance with § 98. 444.Page 6 of 32

where: CO 2T,r = Net annual mass of CO 2 received through flow meter r (metric tons). Q r,p = Quarterl y volumetric flow through a receiving flow meter r in quarter p at

standard conditions (standard cubic meters). S r,p = Quarterl y volumetric flow through a receiving flow meter r that is redelivered

to another facility

without being injected into your well in quarter p (standard cubic meters). D = Density of C O 2 at standard conditions (metric tons per standard cubic meter): 0.0018682. C CO2,p,r = Quarterl y CO 2 concentration measurement in flow for flow meter r in quarter

p (vol. percent CO 2 , expressed as a decimal fraction). p = Quarter of the ye ar. r = Receivin g flow meter. (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.

where: CO 2 = Total net annual mass of CO 2 received (metric tons ). CO 2T,r = Net annual mass of CO 2 received (metric tons) as calculated in Equation RR

1 or RR

- 2 for flow meter r.
r = Receiving flow meter. (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. where:Page 7 of 32

CO 2T,r = N et annual mass of CO 2 received in containers r (metric tons). C CO2,p,r = Quarterl y CO 2 concentration measurement of contents in containers r in

quarter p (wt. percent CO 2 , expressed as a decimal fraction). Q r,p = Quarterl y mass of contents in containers r in quarter p (metric tons). S r,p = Quarterl y volume of contents in containers r redelivered to another facility

without being injected into your well in quarter p (standard cubic meters). p = Quarter of the ye ar. r = Containers. (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. where: CO 2T,r = Net annual mass of CO 2 received in containers r (metric tons). C CO2,p,r = Quarterl y CO 2 concentration measurement of contents in containers r in

quarter p (vol. percent CO 2 , expressed as a decimal fraction). Q r,p = Quarterl y volume of contents in containers r in quarter p (standard cubic

meters). S r,p = Quarterl y mass of contents in containers r redelivered to another facility

without being injected into your well in quarter p (metric tons). D = Density of the CO 2 received in containers at standard conditions (metric tons per standard cub ic meter):0.0018682. p = Quarter of the ye ar. r = Containers. (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 annuall y the total mass of CO 2 (in metric tons) in the CO 2 stream injected each ye ar in metric tons by

multiplying the mass flow by the CO 2 concentration in the flow, according toPage 8 of 32

Equation RR

- 4 of this section. Mass flow and concentration data measurements must be made in accordance with § 98. 444.

where: CO 2,u = Annual CO 2 mass injected (metric tons) as measured by flow meter u. Q p,u = Quarterl y mass flow rate measurement for flow meter u in quarter p (metric

tons per quarter). C CO2,p,u = Quarterl y CO 2 concentration measurement in flow for flow meter u in quarter

p (wt. percent CO 2 , expressed as a decimal fraction). p = Quarter of the ye ar. u = Flow meter. (2) If you use a volumetric flow meter to meas ure the flow of an injected CO 2 stream, yo u must calculate annually the total mass of CO 2 (in metric tons) in the CO 2 stream injected each ye ar in metric tons by multiplying the volumetric flow at standard conditions by the CO 2 concentration in the flow an d 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.

where: CO 2,u = Annual CO 2 mass injected (metric tons) as measured by f low meter u. Q p,u = Quarterl y volumetric flow rate measurement for flow meter u in quarter p at

standard conditions (standard cubic meters per quarter). D = Density of CO 2 at standard conditions (metric tons per standard cubic meter): 0.0018682. C CO2,p,u = CO 2 concentration measurement in flow for flow meter u in quarter p (vol.

percent CO 2 , expressed as a decimal fraction).Page 9 of 32

p = Quarter of the ye ar. u = Flow meter. (3) To aggregate injection data for all wells covered under this subpart, yo u 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.

where: CO 2 . = Total annual CO 2 mass injected (metric tons) through all injection wells. CO 2,u = Annual CO 2 mass injected (m etric tons) as measured by flow meter u.
u = Flow meter. (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 sy stem in acc ordance 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 b y this source category

. (1) For each gas

- liquid separator for which flow is measured using a mass flow meter, yo u must calculate annually the total mass of CO 2 produced from an oil or other fluid stream in metric tons that is separat ed from the fluid b y 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 quarterl y. Mass flow and concentration data measurements must be made in accordance with § 98. 444.Page 10 of 32

Where: CO 2,w = Annual CO 2 mass produced (metric tons) through separator w. Q p,w = Quarterl y gas mass flow rate measurement for separator w in quarter p

(metric tons). C CO2,p,w = Quarterl y CO 2 concentration measurement in flow for separator w in quarter

p (wt. percent CO 2 , expressed as a decimal fraction). p = Quarter of the ye ar. w = Separator. (2) For each gas

- liquid separator for which flow is measured using a volumetric flow meter, you must calculate annuall y 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 E quation RR

- 8 of this section. You must collect these data quarterl y. Volumetric flow and concentration data measurements must be made in accordance with § 98. 444.

Where: CO 2,w = Annual CO 2 mass produced (metric tons) through separator w. Q p,w = Volumetric gas flow rate measurement for separator w in quarter p at

standard conditions (standard cubic meters). D = Density of CO 2 at standard conditions (metric tons per standard cubic meter): 0.0018682. C CO2,p,w = CO 2 concentration measurement in flow for sepa rator w in quarter p (vol. percent CO 2 , expressed as a decimal fraction). p = Quarter of the ye ar. w = Separator.Page 11 of 32

(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 quarterl y mass of CO 2 measured at the separator(s) b y 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).

Where: CO 2 . = Total annual CO 2 mass produced (metric tons) through all separators in the

reporting year. CO 2,w = Annual CO 2 mass produced (metric tons) through separator w in the reporting

ye ar. X = Entrained CO 2 in produced oil or other fluid divided by the CO 2 separated through all s eparators in the reporting year (weight percent CO 2 , expressed as a decimal fraction).
w = Separator. (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 annu al mass of CO 2Page 12 of 32

emitted from all leakage pathway s in accordance with the procedure specified in Equation RR

- 10 of this section.

where: CO 2 . = Total annual CO 2 mass emitted by surface leakage (metric tons) in the reporting year. CO 2,x = Annual CO 2 mass em itted (metric tons) at leakage pathway x in the reporting ye ar. x = Leakage pathway

. (f) You must report the annual mass of CO 2 that is sequestered in subsurface geologic formations in the reporting ye ar in accordance with the procedures specified in paragraphs (f)(1) and (f)(2) of this section. (1) If you are activel y 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.

where: CO 2 = Total annual CO 2 mass sequestered in subsurface geologic formations (metric

tons) at the facility in the reporting year. CO 2 . = Total annual CO 2 mass injected (metric tons) in the well or group of wells

covered b y this source category in the reporting year. CO 2P = Total annual CO 2 mass produced (metric tons) in the reporting ye ar. CO 2 . = Total annual CO 2 mass emitted (metric tons) by surface leakage in the reporting year. CO 2FI = Total annual CO 2 mass emitted (metric tons) from equipment leaks and

vented emissions of CO 2 from equipment located on the surface between thePage 13 of 32 flow meter used to measure injectio n quantity and the injection wellhead, for which a calculation procedure is provided in subpart W of this part. CO 2FP = Total annual CO 2 mass emitted (metric tons) from equipment leaks and

vented emissions of CO 2 from equipment located on the surface betwe en the production wellhead and the flow meter used to measure production quantity, for which a calculation procedure is provided in subpart W of this part. (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.

where: CO 2 = Total annual CO 2 mass sequestered in subsurface geologic formations (metric

tons) at the facility in the reporting year. CO 2 . = Total annual CO 2 mass injected (metric tons) in the well or group of wells

covered b y this source category in the reporting year. CO 2 . = Total annual CO 2 mass emitted (metric tons) by surface leakage in the reporting year. CO 2FI = Total annual CO 2 mass emitted (metric tons) 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, for which a calculation procedure is provided in subpart W of this part. **§ 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 quarterl y flow rate of CO 2 received by pipeline b y 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 quarterl y.Page 14 of 32

(ii) If you took ownership of the CO 2 in a commercial transaction, you may use the quarterl y flow rate data from the sales contract if it is a one

- time transaction or from invoices or manifests if it is an ongoing comm ercial transaction with discrete shipments. (iii) If you inject CO 2 received from a production process unit that is part of your facility , yo u may use the quarterly

CO 2 flow rate that was measured at the equivalent of a custody transfer meter following pro cedures 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) Excep t as provided in paragraph (a)(4) of this section, you must determine the quarterl y mass or volume of contents in all containers if you receive CO 2 in containers b y following the most appropriate of the following procedures: (i) You may

measure the mass of contents of containers summed quarterl y using weigh bills, scales, or load cells. (ii) You may

determine the volume of the contents of containers summed quarterl y. (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 det ermine a quarterl y concentration of the CO 2 received that is representative of all CO 2 received in that quarter b y 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.Page 15 of 32

(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 co ncentration 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 quarterl y 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 yo u receive meets the defi nition 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 injec ted. 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 quarterl y. (3) You must sample the injected CO 2 stream at least once per quarter immediatel y upstream or downstream of the flow meter used to measure flow rate of that CO 2 stream and measure the CO 2 concentration of th e sample.Page 16 of 32

(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 s ys tem. (2) You must sample the produced gas stream at least once per quarter immediatel y 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 quarterl y. (d) CO 2 emissions from equipment leaks and vented emissions of CO 2 . If yo u 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 s tandards organizations include, but are not limited to, the following: ASTM International, the American National Standards Institute (ANSI), the American Gas Association (AGA), the AmericanPage 17 of 32

Society of Mechanical Engineers (ASME), the American Petroleum Ins titute (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 (NI ST) 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 quarterl y 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.Page 18 of 32

(2) If another method listed in § 98. 444(a)(1) cannot be used, a quarterl y flow rate value that is missing must be estimated using a representative flow rate value from the nearest previous time period. (b) A quarterl y 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 quarterl y m ass or volume value that is missing must be estimated using a representative mass or volume value from the nearest previous time period. (c) A quarterl y 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 quarterl y concentration value that is missing must be estimated using a representative concentration value from the nearest previous time period. (d) A quarterl y 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 associate d 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.Page 19 of 32

(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 b y your approved MRV plan. (h) You must estimate other missing data as required b y your approved MRV plan. **§ 98. 446**  **Data reporting requirements.** In addition to the information required b y § 98. 3(c), report the in formation 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) annuall y. (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 ye s to paragraph (a)(4) of this section: (i) The mass flow through a receiving flow meter (in metric tons) in each quarter.Page 20 of 32

(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 an d 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 ye ar 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 c ontainers, 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 receive d (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.Page 21 of 32

(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 follo wing 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 pro ject. (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 c oncentration in flow (volume or weight percent CO 2 expressed as a decimal fraction) in each quarter.Page 22 of 32

(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 m eter 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 ye ar 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 C O 2 injected (metric tons) in the reporting ye ar 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 emission s 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) annuall y.Page 23 of 32

(ii) CO 2 co ncentration 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, ma ss 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 ye ar 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 sep arated through all separators in the reporting ye ar (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 repo rting 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 ye ar. (8) Annual CO 2 mass emitted (metric tons) b y surface leakage in the reporting ye ar as calculated b y Equation RR

- 10 of this subpart.Page 24 of 32

(9) Annual CO 2 (metric tons) sequestered in subsurface ge ologic 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 subje ct to reporting requirements under this subpart. (11) Date that the most recent MRV plan was approved b y 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 h istory

of the monitoring efforts conducted over the previous calendar ye ar, including a listing of all monitoring equipment that was operated, its period of operation, and any relevant tests or survey s 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 Injectio n Control permit class.Page 25 of 32

(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. (g ) Whether the CO 2 stream is being injected into subsurface geolo gic formations to enhance the recovery

of oil or natural gas. **§ 98. 447**  **Records that must be retained.** (a) You must follow the record retention requirements specified b y § 98. 3(g). In additio n 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) Quarterl y 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) Quarterl y 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) Quarterl y 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.Page 26 of 32

(6) Annual records of information used to calculate the CO 2 emitted from equipment leaks and vente d 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 moni toring 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 p roposed 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 b y yo u that is greater than 1 ye ar. (2) Identification of potential surface leakage pathway s for CO 2 in the maximum monitoring area and the likelihood, magnitude, and timing, of surface leakage of CO 2 through these pathway s. (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 i ncludes, but is not limited to, considerations for calculating CO 2 emissions from equipment leaks and vented emissions of CO 2 between the injection flowPage 27 of 32

meter and injection well and/or the production flow meter and production well, and considerations for c alculating 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 Co ntrol permit class. I f the well is not yet permitted, and yo u 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, yo u 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 b y paragraph (a)(4) of this section are established and the leakage detection and quantification strategy

as required b y 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 subsurfacePage 28 of 32

on or before December 31, 2010. You will be allowed to request one extension of up to an additional 180 day s in which to submit your proposed MRV plan. (2) You must submit a proposed MRV plan to EPA within 180 day s of receiving a final Underground In

jection Control permit authorizing the injection of CO 2 into the subsurface. If yo ur facility is an offshore facility not subject to the Safe Drinking Water Act, you must submit a proposed MRV plan to EPA within 180 day s 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 day s. (3) If you are injecting a CO 2 stream in subsurface geologic formations to enhance the recovery of oil or natural gas and yo u are not permitted as Class VIunder 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 day s of EPA notif ication, 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 day s 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 w as made to monitoring and/or operational parameters that was not anticipated in the original MRV plan. Examples of material changes include but are not limitedPage 29 of 32

to: L arge changes in the volume of CO 2 injected; the construction of new injection wells not identified in the MRV plan; failures of the monitoring s ys tem including monitoring s ys tem sensitivity, performance, location, or baseline; changes to surface land use that affects baseline or operational conditions; observed plume location that differs signif icantly 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 b y 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 ye ar. (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 yo ur 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 electronicall y in a format specified b y 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 yo ur initial annual report under this part, whichever is earlier. **§ 98. 449**  **Definitions.** Except as provided below, all ter ms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.Page 30 of 32

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 ye ar in the perio d (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 ye ar 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 ye ar 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 covere d 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 reasonabl y 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. Research and development project means a project for the purpose of investigating practices, monitoring techniques, or injection veri fication, or engaging in other applied research, that will enable safe and effective long

- term containment of a CO 2 stream in subsurface geologicPage 31 of 32

formations, including research and short duration CO 2 injection tests conducted as a precursor to long

- term st orage. 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 p ursuant 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 h ydrocarbon gas (not including stationary combustion flue gas), including process des igned 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).Page 32 of 32