[Federal Register Volume 75, Number 230 (Wednesday, December 1, 2010)]
[Rules and Regulations]
[Pages 75060-75089]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2010-29934]



[[Page 75059]]

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Part V





Environmental Protection Agency





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40 CFR Parts 72, 78, and 98



Mandatory Reporting of Greenhouse Gases: Injection and Geologic 
Sequestration of Carbon Dioxide; Final Rule

Federal Register / Vol. 75 , No. 230 / Wednesday, December 1, 2010 / 
Rules and Regulations

[[Page 75060]]


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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 72, 78, and 98

[EPA-HQ-OAR-2009-0926; FRL-9232-6]
RIN 2060-AP88


Mandatory Reporting of Greenhouse Gases: Injection and Geologic 
Sequestration of Carbon Dioxide

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

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SUMMARY: EPA is promulgating a regulation to require greenhouse gas 
monitoring and reporting from facilities that conduct geologic 
sequestration of carbon dioxide and all other facilities that conduct 
injection of carbon dioxide. This rule does not require control of 
greenhouse gases, rather it requires only monitoring and reporting of 
greenhouse gases.

DATES: The final rule is effective on December 31, 2010.

ADDRESSES: EPA has established a docket for this action under Docket ID 
No. EPA-HQ-OAR-2009-0926. All documents in the docket are listed on the 
http://www.regulations.gov Web site. Although listed in the index, some 
information is not publicly available, e.g., confidential business 
information (CBI) or other information whose disclosure is restricted 
by statute. Certain other material, such as copyrighted material, is 
not placed on the Internet and will be publicly available only in hard 
copy form. Publicly available docket materials are available either 
electronically through http://www.regulations.gov or in hard copy at 
EPA's Docket Center, Public Reading Room, EPA West Building, Room 3334, 
1301 Constitution Avenue, NW., Washington, DC 20004. This Docket 
Facility is open from 8:30 a.m. to 4:30 p.m., Monday through Friday, 
excluding legal holidays. The telephone number for the Public Reading 
Room is (202) 566-1744, and the telephone number for the Air Docket is 
(202) 566-1742.

FOR FURTHER INFORMATION CONTACT: For technical information and 
implementation materials, please go to the website http://www.epa.gov/climatechange/emissions/ghgrulemaking.html. To submit a question, 
select Rule Help Center, and then select Contact Us. You may also 
contact Mark de Figueiredo, Climate Change Division, Office of 
Atmospheric Programs (MC-6207J), Environmental Protection Agency, 1200 
Pennsylvania Ave., NW., Washington, DC 20460; telephone number: (202) 
343-9928; fax number: (202) 343-2202.

SUPPLEMENTARY INFORMATION: Regulated Entities. The Administrator has 
determined that this action is subject to the provisions of Clean Air 
Act (CAA) section 307(d). See CAA section 307(d)(1)(V) (the provisions 
of CAA section 307(d) apply to ``such other actions as the 
Administrator may determine''). These regulations will affect owners or 
operators of carbon dioxide (CO<INF>2</INF>) injection wells. Regulated 
categories and entities include those listed in Table 1 of this 
preamble:

                               Table 1--Examples of Affected Entities by Category
----------------------------------------------------------------------------------------------------------------
                Category                                  NAICS                  Examples of affected facilities
----------------------------------------------------------------------------------------------------------------
CO2 Enhanced Oil and Gas Recovery         211..................................  Oil and gas extraction projects
 Projects.                                                                        using CO2 enhanced oil and gas
                                                                                  recovery.
Acid Gas Injection Projects.............  211111 or 211112.....................  Projects that inject acid gas
                                                                                  containing CO2 underground.
Geologic Sequestration Projects.........  N/A..................................  CO2 geologic sequestration
                                                                                  projects.
----------------------------------------------------------------------------------------------------------------

    Table 1 of this preamble is not intended to be exhaustive but 
rather provides a guide for readers regarding facilities likely to be 
affected by this action. Table 1 of this preamble lists the types of 
facilities that EPA is now aware could be potentially affected by the 
reporting requirements. Other types of facilities not listed in the 
table could also be subject to reporting requirements. To determine 
whether you are affected by this action, you should carefully examine 
the applicability criteria found in 40 CFR part 98, subpart A and the 
relevant criteria in the sections related to the injection and geologic 
sequestration (GS) of CO<INF>2</INF> (i.e., subparts RR and UU). If you 
have questions regarding the applicability of this action to a 
particular facility, consult the website person listed in the preceding 
FOR FURTHER INFORMATION CONTACT section.
    Some facilities that are affected by this final rule are required 
to report under multiple source categories. Table 2 of this preamble 
has been developed as a guide to help potential CO<INF>2</INF> 
injection and GS reporters subject to the final rule identify the 
source categories (by subpart) that they may need to (1) consider in 
their facility applicability determination, and/or (2) include in their 
reporting. The table should only be seen as a guide. Additional 
subparts in 40 CFR part 98 may be relevant for a given reporter. 
Similarly, not all listed subparts are relevant for all reporters.

            Table 2--Source Categories and Relevant Subparts
------------------------------------------------------------------------
  Source category (and main    Other subparts recommended for  review to
     applicable subpart)                determine applicability
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Geologic Sequestration of      40 CFR part 98, subpart C.
 Carbon Dioxide (40 CFR part   40 CFR part 98, subpart W.
 98, subpart RR).              40 CFR part 98, subpart PP.
Injection of Carbon Dioxide    40 CFR part 98, subpart C.
 (40 CFR part 98, subpart UU). 40 CFR part 98, subpart W.
                               40 CFR part 98, subpart PP.
------------------------------------------------------------------------

    What is the effective date? The final rule is effective on December 
31, 2010. Section 553(d) of the Administrative Procedure Act (APA), 5 
U.S.C. chapter 5, generally provides that rules may not take effect 
earlier than 30 days after they are published in the Federal Register. 
EPA is issuing this final rule under section 307(d)(1) of the Clean Air 
Act,

[[Page 75061]]

which states: ``The provisions of section 553 through 557 * * * of 
Title 5 shall not, except as expressly provided in this section, apply 
to actions to which this subsection applies.'' Thus, section 553(d) of 
the APA does not apply to this rule. EPA is nevertheless acting 
consistently with the purposes underlying APA section 553(d) in making 
this rule effective on December 31, 2010. Section 5 U.S.C. 553(d)(3) 
allows an effective date less than 30 days after publication ``as 
otherwise provided by the agency for good cause found and published 
with the rule.'' As explained below, EPA finds that there is good cause 
for this rule to become effective on or before December 31, 2010, even 
if this results in an effective date fewer than 30 days from date of 
publication in the Federal Register.
    While this action is being signed prior to December 1, 2010, there 
is likely to be a significant delay in the publication of this rule as 
it contains equations and charts, and is relatively long in length. As 
an example, EPA signed a shorter technical amendments package related 
to the same underlying reporting rule on October 7, 2010, and it was 
not published until October 28, 2010, 75 FR 66434, three weeks later.
    The purpose of the 30-day waiting period prescribed in 5 U.S.C. 
553(d) is to give affected parties a reasonable time to adjust their 
behavior and prepare before the final rule takes effect. Where, as 
here, the final rule will be signed and made available on the EPA Web 
site more than 30 days before the effective date, but where the 
publication is likely to be delayed due to the complexity and length of 
the rule, that purpose is still met. Moreover, EPA determined that 
facilities that are subject to this rule already collect data on 
CO<INF>2</INF> that is received. Facilities may use best available 
monitoring methods for calculating the mass of CO<INF>2</INF> received 
through the first quarter of 2011. Facilities subject to subpart RR 
that were issued a final Underground Injection Control (UIC) permit 
authorizing the injection of CO<INF>2</INF> into the subsurface on or 
before December 31, 2010 are required to submit a proposed monitoring, 
reporting, and verification (MRV) plan to EPA by June 30, 2011 and are 
allowed to request one extension of up to an additional 180 days in 
which to submit their proposed MRV plan. This will provide facilities a 
substantial additional period to adjust their behavior to the 
requirements of the final rule. Accordingly, we find good cause exists 
to make this rule effective on or before December 31, 2010, consistent 
with the purposes of 5 U.S.C. 553(d)(3).\1\
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    \1\ We recognize that this rule could be published at least 30 
days before December 31, 2010, which would negate the need for this 
good cause finding, and we plan to request expedited publication of 
this rule in order to decrease the likelihood of a printing delay. 
However, as we cannot know the date of publication in advance of 
signing this rule, we are proceeding with this good cause finding 
for an effective date on or before December 31, 2010.
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    Judicial Review.
    Under CAA section 307(b)(1), judicial review of this final rule is 
available only by filing a petition for review in the U.S. Court of 
Appeals for the District of Columbia Circuit by January 31, 2011. Under 
CAA section 307(d)(7)(B), only an objection to this final rule that was 
raised with reasonable specificity during the period for public comment 
can be raised during judicial review. This section also provides a 
mechanism for EPA to convene a proceeding for reconsideration, ``[i]f 
the person raising an objection can demonstrate to EPA that it was 
impracticable to raise such objection within [the period for public 
comment] or if the grounds for such objection arose after the period 
for public comment (but within the time specified for judicial review) 
and if such objection is of central relevance to the outcome of this 
rule.'' Any person seeking to make such a demonstration to EPA should 
submit a Petition for Reconsideration to the Office of the 
Administrator, Environmental Protection Agency, Room 3000, Ariel Rios 
Building, 1200 Pennsylvania Ave., NW., Washington, DC 20004, with a 
copy to the person listed in the preceding FOR FURTHER INFORMATION 
CONTACT section, and the Associate General Counsel for the Air and 
Radiation Law Office, Office of General Counsel (Mail Code 2344A), 
Environmental Protection Agency, 1200 Pennsylvania Ave., NW., 
Washington, DC 20004. Note, under CAA section 307(b)(2), the 
requirements established by this final rule may not be challenged 
separately in any civil or criminal proceedings brought by EPA to 
enforce these requirements.
    Acronyms and Abbreviations. The following acronyms and 
abbreviations are used in this document.

3-D three-dimensional
AGA American Gas Association
AMA active monitoring area
ANSI American National Standards Institute
API American Petroleum Institute
ASME American Society of Mechanical Engineers
CAA Clean Air Act
CBI confidential business information
CCS carbon dioxide capture and geologic sequestration
CFR Code of Federal Regulations
CO<INF>2</INF> carbon dioxide
DOE Department of Energy
EAB Environmental Appeals Board
EIA Economic Impact Analysis
EPA Environmental Protection Agency
EO Executive Order
ER enhanced oil and gas recovery
GHG greenhouse gas
GS geologic sequestration
ICR Information Collection Request
IRS Internal Revenue Service
MMA maximum monitoring area
MRV monitoring, reporting, and verification
NAESB North American Energy Standards Board
NAICS North American Industry Classification System
NTTAA National Technology Transfer and Advancement Act
OAR Office of Air and Radiation
OMB Office of Management and Budget
OW Office of Water
QA/QC quality assurance/quality control
R&D research and development
RFA Regulatory Flexibility Act
SBREFA Small Business Regulatory Enforcement Fairness Act
SDWA Safe Drinking Water Act
TSD technical support document
UIC Underground Injection Control
US United States
UMRA Unfunded Mandates Reform Act of 1995
USDW underground source of drinking water
VEF Vulnerability Evaluation Framework

Table of Contents

I. Background
    A. Organization of this Preamble
    B. Background on the Final Rule
    C. Legal Authority
    D. Relationship to Underground Injection Control Regulations 
under the Safe Drinking Water Act
    E. Relationship to the Interagency Task Force on Carbon Capture 
and Storage and Other Federal Geologic Sequestration Initiatives
    F. Relationship to Other Geologic Sequestration Information 
Collection and Reporting Efforts
II. Summary of Final Rule
    A. Summary of Changes to the General Provisions of the 
Greenhouse Gas Reporting Program
    B. Summary of the Reporting Requirements for Geologic 
Sequestration of Carbon Dioxide (Subpart RR)
    C. Summary of the Reporting Requirements for Injection of Carbon 
Dioxide (Subpart UU)
    D. Summary of the Major Changes Since Proposal
    E. Summary of Comments and Responses
III. Economic Impacts of the Final Rule
    A. How were compliance costs estimated?
    B. What are the costs of the rule?
    C. What are the economic impacts of the rule?
    D. What are the impacts of the rule on small businesses?
    E. What are the benefits of the rule for society?

[[Page 75062]]

IV. Statutory and Executive Order Reviews
    A. Executive Order 12866: Regulatory Planning and Review
    B. Paperwork Reduction Act
    C. Regulatory Flexibility Act (RFA)
    D. Unfunded Mandates Reform Act (UMRA)
    E. Executive Order 13132: Federalism
    F. Executive Order 13175: Consultation and Coordination with 
Indian Tribal Governments
    G. Executive Order 13045: Protection of Children from 
Environmental Health Risks and Safety Risks
    H. Executive Order 13211: Actions that Significantly Affect 
Energy Supply, Distribution, or Use
    I. National Technology Transfer and Advancement Act
    J. Executive Order 12898: Federal Actions to Address 
Environmental Justice in Minority Populations and Low-Income 
Populations
    K. Congressional Review Act

I. Background

A. Organization of This Preamble

    This preamble is divided into four sections, as detailed in the 
Table of Contents. This section describes the layout of the preamble 
and provides a brief summary of each section.
    The first section of this preamble contains the basic background 
information about the origin of this rule, including a discussion of 
how it relates to the finalized requirements for suppliers of 
CO<INF>2</INF> under 40 CFR part 98, subpart PP. It also contains 
information on EPA's legal authority and how this rule relates to the 
UIC program, the Interagency Task Force on Carbon Capture and Storage 
and other Federal GS initiatives, as well as other GS information 
collection and reporting efforts.
    The second section of this preamble provides an overview of the GHG 
Reporting Program and summarizes changes to the general provisions of 
the GHG Reporting Program. It also provides a summary of this final 
rule on key design elements such as: Source category definition, 
reporting threshold, GHGs to report, GHG calculations and monitoring, 
data reporting, and recordkeeping requirements. In addition, it 
describes the major changes made since the proposal and provides a 
brief summary of public comments and EPA's responses thereto.
    The third section of this preamble provides the summary of the cost 
impacts, economic impacts, and benefits of this rule and discusses 
comments on the regulatory impacts analysis.
    Finally, the last section of this preamble discusses the various 
statutory and executive order requirements applicable to this final 
rulemaking.

B. Background on the Final Rule

    This action finalizes monitoring and reporting requirements for 
injection and geologic sequestration of carbon dioxide.
    On April 12, 2010, EPA proposed this rule amending 40 CFR part 98. 
40 CFR part 98 provides the regulatory framework for the GHG Reporting 
Program. The GHG Reporting Program requires reporting of GHG emissions 
and other relevant information from certain source categories in the 
United States. The GHG Reporting Program, which became effective on 
December 29, 2009, includes reporting requirements for facilities and 
suppliers in 34 subparts. For more detailed background information on 
the GHG Reporting Program, see the preamble to the final part 98 rule 
establishing that program (74 FR 56260, October 30, 2009) and the 
preamble to the Part 98 rule expanding that program from 30 to 34 
subparts (75 FR 39736, July 12, 2010).
    Subpart PP of the GHG Reporting Program requires the reporting of 
CO<INF>2</INF> supplied to the economy. During the public comment 
period on the part 98 rule establishing that requirement, EPA received 
comments that CO<INF>2</INF> geologically sequestered should be 
considered in the GHG Reporting Program. (For further information on 
relevant comments received in 40 CFR part 98, subpart PP, see 
``Mandatory Greenhouse Gas Reporting Rule: EPA's Response to Public 
Comments, Subpart PP: Suppliers of Carbon Dioxide'' in Docket EPA-HQ-
OAR-2008-0508.) In the final rule promulgating 40 CFR part 98, subpart 
PP, EPA committed to taking action to collect such data in the near 
future.
    This final rule amends 40 CFR part 98 to add reporting requirements 
covering facilities that conduct geologic sequestration of 
CO<INF>2</INF> (40 CFR part 98, subpart RR) and all other facilities 
that conduct injection of CO<INF>2</INF> (40 CFR part 98, subpart 
UU).\2\ GS is the long-term containment of a CO<INF>2</INF> stream in 
subsurface geologic formations. This data will, among other things, 
inform Agency decisions under the CAA related to the use of carbon 
dioxide capture and geologic sequestration (CCS) for mitigating GHG 
emissions.
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    \2\ EPA has moved all definitions, requirements, and procedures 
for facilities conducting CO<INF>2</INF> injection only (which both 
EPA and commenters have referred to as ``Tier 1'' facilities for 
simplicity) into a new subpart, 40 CFR part 98, subpart UU, and 
retained all definitions, requirements, and procedures related to 
facilities conducting GS (which both EPA and commenters have 
referred to as ``Tier 2'' facilities for simplicity) in 40 CFR part 
98, subpart RR.
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    Subpart RR information will enable EPA to monitor the growth and 
efficacy of GS (and therefore CCS) as a GHG mitigation technology over 
time and to evaluate relevant policy options. Furthermore, where 
enhanced oil and gas recovery (ER) projects are reporting under 40 CFR 
part 98, subpart RR, EPA will be able to evaluate ER as a non-emissive 
end use. Under 40 CFR part 98, subpart UU, EPA will be able to 
reconcile information obtained from this rule with data obtained from 
40 CFR part 98, subpart PP on CO<INF>2</INF> supplied to the economy.
    This rule was proposed by EPA on April 12, 2010. One public hearing 
was held on April 19, 2010, and the 60-day public comment period ended 
June 11, 2010. This final rule takes into consideration comments 
received during the comment period and finalizes the monitoring and 
reporting requirements for facilities conducting GS and all other 
facilities conducting CO<INF>2</INF> injection.
    This final rule does not address whether data reported under 40 CFR 
part 98, subparts RR or UU will be released to the public or will be 
treated as CBI. EPA published a proposed rule on confidentiality 
determination on July 7, 2010 (75 FR 39094) that addressed this issue. 
In that action, EPA proposed which specific data elements may be 
released to the public and which would be treated as CBI. EPA received 
several comments on that proposal, and is in the process of considering 
these comments.

C. Legal Authority

    EPA is promulgating this rule under its existing CAA authority; 
specifically, authorities provided in CAA section 114. As discussed in 
detail in Sections I.C and II.Q of the preamble to the final part 98 
rule establishing the GHG Reporting Program (74 FR 56260, October 30, 
2009), CAA section 114 provides EPA with the authority to require the 
information mandated by this rule because such data will inform and are 
relevant to EPA's implementation of a wide variety of CAA provisions. 
Under CAA section 114(a)(1), the Administrator may require emissions 
sources, persons subject to the CAA, manufacturers of emission control 
or process equipment, or persons whom the Administrator believes may 
have necessary information to monitor and report emissions and provide 
such other information as the Administrator requests for the purposes 
of carrying out any provision of the CAA (except for a

[[Page 75063]]

provision of title II with respect to motor vehicles). EPA may gather 
information for a variety of purposes, including for the purpose of 
assisting in the development of implementation plans or of emissions 
standards under CAA section 111, determining compliance with 
implementation plans or such standards, or more broadly for ``carrying 
out any provision'' of the CAA.

D. Relationship to Underground Injection Control Regulations Under the 
Safe Drinking Water Act

    The Agency maintains a high-level of coordination across EPA 
offices and regions on GS activities and regulatory development. EPA's 
Office of Air and Radiation (OAR) and Office of Water (OW) work closely 
to promote safe and effective implementation of GS technologies while 
ensuring protection of human health and the environment. OAR and OW 
have closely coordinated this rulemaking under CAA authority and the 
rulemaking under Safe Drinking Water Act (SDWA) authority establishing 
Federal requirements under the UIC program for Class VI wells 
(hereafter referred to as the UIC Class VI rule).
    EPA's UIC program was established in the 1970s to prevent 
endangerment of underground sources of drinking water (USDWs) from 
injection of various fluids, including CO<INF>2</INF> for ER, oil field 
fluids, water stored for drinking water supplies, and municipal and 
industrial waste. The UIC program, which is authorized by Part C of 
SDWA (42 U.S.C. 300h et seq.), is designed to prevent the movement of 
such fluid into USDWs by addressing the potential pathways through 
which injected fluids can migrate and potentially endanger USDWs. In 
2008, EPA proposed to amend the UIC program to establish a new class of 
injection well--Class VI--to cover the underground injection of 
CO<INF>2</INF> for the purpose of GS, or long-term storage of 
CO<INF>2</INF> (73 FR 43492, July 25, 2008). For a summary of the UIC 
program and more details on the final UIC Class VI rule, please see the 
UIC Geologic Sequestration of Carbon Dioxide Web site.\3\
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    \3\ http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.
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    EPA designed the reporting requirements under 40 CFR part 98, 
subpart RR with careful consideration of UIC requirements, including 
Class VI, to minimize overlap between the two programs. There are two 
areas of potential overlap (see Table 3 of this preamble). The first 
overlap is the requirement that owners or operators report the quantity 
of CO<INF>2</INF> injected. The UIC Class VI rule requires owners or 
operators to continuously monitor the amount of CO<INF>2</INF> injected 
and submit semi-annual reports on the monthly amount injected. The UIC 
program requires information on the amount injected to ensure 
appropriate CO<INF>2</INF> injection operations. Subpart RR requires 
facilities to collect data on the amount injected over a quarter and 
submit annual reports on the annual amount of CO<INF>2</INF> injected. 
Data on the amount of CO<INF>2</INF> injected is a component of the 40 
CFR part 98, subpart RR mass balance approach \4\ used to quantify the 
amount of CO<INF>2</INF> sequestered. EPA determined that quarterly 
data collection and annual reporting under 40 CFR part 98, subpart RR 
was necessary in order to harmonize data with other subparts of the GHG 
Reporting Program. Facilities reporting under 40 CFR part 98, subpart 
RR may use flow meters used to comply with the flow monitoring and 
reporting provisions in their UIC permit.
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    \4\ The subpart RR mass balance equation for quantifying the 
amount of CO<INF>2</INF> that is geologically sequestered includes 
variables on injected CO<INF>2</INF>; equipment leaks and vented 
CO<INF>2</INF> emissions from surface equipment between the flow 
meters and the wellhead; CO<INF>2</INF> produced and/or remaining 
with produced oil, gas or other fluids; and CO<INF>2</INF> leakage 
to the surface. For more information, see Section II.B of this 
preamble.
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    The second overlap is a monitoring plan for detecting air 
emissions. While requirements under the UIC program are focused on 
demonstrating that USDWs are not endangered as a result of 
CO<INF>2</INF> injection into the subsurface, requirements under the 
GHG Reporting Program through 40 CFR part 98, subpart RR will enable 
EPA to verify the quantity of CO<INF>2</INF> that is geologically 
sequestered and to assess the efficacy of GS as a mitigation strategy. 
Subpart RR achieves this by requiring facilities conducting GS to 
develop and implement a MRV plan \5\ to detect and quantify leakage of 
injected CO<INF>2</INF> to the surface in the event leakage occurs and 
to report the amount of CO<INF>2</INF> geologically sequestered using a 
mass balance approach, regardless of the class of UIC permit that a 
facility holds.
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    \5\ The subpart RR MRV plan includes delineation of monitoring 
areas, identification and assessment of potential surface leakage 
pathways, a strategy for detecting and quantifying surface leakage 
of CO<INF>2</INF> if leakage occurs, an approach for establishing 
the expected baselines, and a summary of considerations for 
calculating site-specific variables for the mass balance equation, 
such as calculating CO<INF>2</INF> in produced fluids. For more 
information, see Section II.B of this preamble.
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    The monitoring required by 40 CFR part 98, subpart RR for 
quantification purposes is complementary to and builds on UIC permit 
requirements. In particular, the UIC Class VI permit requires a 
comprehensive site characterization that includes an assessment of the 
geologic, hydrogeologic, geochemical, and geomechanical properties of 
the proposed GS site to ensure that GS wells are located in suitable 
formations. The UIC Class VI permit also requires computational 
modeling of the Area of Review, and a periodic re-evaluation of this 
Area of Review based on robust modeling and monitoring of the 
CO<INF>2</INF> stream, injection pressures, integrity of the injection 
well, groundwater quality and geochemistry, and the position of the 
CO<INF>2</INF> plume and pressure front throughout injection. These 
requirements can provide the basis for the MRV plan submitted to EPA 
for 40 CFR part 98, subpart RR. Therefore, EPA will accept a UIC Class 
VI permit to satisfy certain MRV plan requirements; however, the 
reporter must include additional information to outline how monitoring 
will achieve detection and quantification of CO<INF>2</INF> in the 
event surface leakage occurs.
    The UIC Class VI rule also allows for surface air and soil gas 
monitoring at the discretion of the UIC Director as a means of 
identifying CO<INF>2</INF> leaks that may pose a risk to USDWs and 
informing emergency notification of a Class VI owner or operator and 
UIC Director in the event of a USDW endangerment. If the UIC Director 
determines that it is appropriate to require surface air or soil gas 
monitoring for USDW protection, the UIC Director must approve the use 
of monitoring employed under 40 CFR part 98, subpart RR so long as the 
owner or operator is able to demonstrate USDW protection pursuant to 
requirements at 40 CFR 146.90(h)(3).

 Table 3--Comparison of Reporting Requirements Under Subpart RR With UIC
                          Class VI Regulations
------------------------------------------------------------------------
    Reporting requirement          Subpart RR           UIC Class VI
------------------------------------------------------------------------
Quantity of CO2 received....  Yes.................  N/A.
Quantity of CO2 injected....  Yes.................  Yes.
Equipment leaks and vented    Yes.................  N/A.
 emissions from surface
 equipment between flow
 meters and the wellhead.

[[Page 75064]]

 
Quantity of CO2 produced      Yes.................  N/A.
 with oil or natural gas
 (ER) or other fluids.
Percentage of CO2 estimated   Yes.................  N/A.
 to remain with oil (ER) or
 other fluids.
Quantity of CO2 emitted from  Yes.................  N/A.
 the subsurface.
Quantity of CO2 sequestered   Yes.................  N/A.
 in the subsurface.
Cumulative mass of CO2        Yes.................  N/A.
 sequestered in the
 subsurface.
Monitoring plan for           Yes.................  Yes.\1\
 detecting air emissions.
Monitoring plan for           Yes.................  N/A.
 quantifying air emissions.
------------------------------------------------------------------------
\1\ UIC Class VI rule allows for surface air/soil gas monitoring for
  USDW protection at the discretion of the UIC Director.

    EPA has determined that the requirements of these two rules 
complement one another by concurrently ensuring USDW protection, as 
required under SDWA, and requiring reporting of CO<INF>2</INF> surface 
emissions under 40 CFR part 98, subpart RR. EPA is committed to working 
closely within the agency to coordinate implementation of the UIC and 
GHG Reporting programs, reduce burden on reporters, provide timely 
access to verified emissions data, establish mechanisms to efficiently 
share data, and harmonize data systems to the extent possible.

E. Relationship to the Interagency Task Force on Carbon Capture and 
Storage and Other Federal Geologic Sequestration Initiatives

    On February 3, 2010, President Obama established an Interagency 
Task Force on Carbon Capture and Storage (CCS Task Force). The CCS Task 
Force, co-chaired by EPA and the Department of Energy (DOE), developed 
a plan to overcome the barriers to the widespread, cost-effective 
deployment of CCS within ten years, with a goal of bringing five to ten 
commercial demonstration projects online by 2016. The CCS Task Force's 
plan was delivered to President Obama in August 2010.
    The CCS Task Force explored incentives for commercial CCS adoption 
and addressed financial, economic, technological, legal, institutional, 
social, or other barriers to deployment. For example, the CCS Task 
Force examined Federal regulatory activities that address the safety, 
efficacy, and environmental soundness of GS. The CCS Task Force also 
considered how best to coordinate existing administrative authorities 
and programs, including those involving international collaboration, as 
well as identified areas where additional administrative authority may 
be necessary. The CCS Task Force recommended that EPA finalize this 
rule. For more information, please see EPA's CCS Task Force Web 
site.\6\
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    \6\ http://www.epa.gov/climatechange/policy/ccs_task_force.html.
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F. Relationship to Other Geologic Sequestration Information Collection 
and Reporting Efforts

    EPA reviewed and took into account several existing domestic and 
international reporting and monitoring programs in designing this rule. 
For additional information, please see Section I.F of the notice of 
proposed rulemaking (75 FR 18581, April 12, 2010).
    Also as discussed in the notice of proposed rulemaking, EPA notes 
that the Internal Revenue Service (IRS) published IRS Notice 2009-83 
\7\ to provide guidance regarding eligibility for the Internal Revenue 
Code section 45Q credit for CO<INF>2</INF> sequestration, computation 
of the section 45Q tax credit, reporting requirements for taxpayers 
claiming the section 45Q tax credit, and rules regarding adequate 
security measures for secure GS. As clarified in the IRS guidance, 
taxpayers claiming the section 45Q tax credit must follow the 
appropriate UIC requirements. The guidance also clarifies that 
taxpayers claiming section 45Q tax credit must follow the MRV 
procedures that are being finalized under 40 CFR part 98, subpart RR in 
this final rule.
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    \7\ Available at: http://www.irs.gov/irb/2009-44_IRB/ar11.html#d0e1860.
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II. Summary of Final Rule

A. Summary of Changes to the General Provisions of the Greenhouse Gas 
Reporting Program

    This action amends certain requirements in 40 CFR part 98, subpart 
A (General Provisions).
    Changes to Applicability. In this action, EPA is amending Table A-3 
in 40 CFR 98.2(a)(1) to include the geologic sequestration of 
CO<INF>2</INF> and injection of CO<INF>2</INF> source categories.

B. Summary of the Reporting Requirements for Geologic Sequestration of 
Carbon Dioxide (Subpart RR)

    Reporting requirements for facilities conducting GS are found in 40 
CFR part 98, subpart RR. These facilities are required to report the 
amount of CO<INF>2</INF> received, develop and implement an EPA-
approved MRV plan, and report the amount of CO<INF>2</INF> sequestered 
using a mass balance approach, by subtracting total CO<INF>2</INF> 
emissions from CO<INF>2</INF> injected in the reporting year. Other 
facilities injecting CO<INF>2</INF> underground report under 40 CFR 
part 98, subpart UU.
1. Subpart RR Source Category Definition
    The 40 CFR part 98, subpart RR source category consists of any well 
or group of wells that inject a CO<INF>2</INF> stream for long-term 
containment into a subsurface geologic formation.\8\ All wells 
permitted as Class VI by the UIC program meet the definition of this 
source category. Facilities conducting ER are not subject to 40 CFR 
part 98, subpart RR unless they choose to opt-in to the requirements of 
this subpart or hold a UIC Class VI permit.
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    \8\ Note that R&D projects that are exempted from subpart RR 
report under Subpart UU--see discussion below.
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    Research and development (R&D) projects are exempt from reporting 
requirements under 40 CFR part 98, subpart RR provided they meet the 
eligibility requirements. A project is eligible for the exemption if it 
investigates or will investigate practices, monitoring techniques, or 
injection verification, or if it is engaged in other applied research 
that focuses on enabling safe and effective long-term containment of a 
CO<INF>2</INF> stream in subsurface geologic formations, including 
research and injection tests conducted as a precursor to a larger more 
permanent long-term storage operation. Small and large-scale projects 
meeting the criteria for an exemption, such as the current Regional 
Carbon

[[Page 75065]]

Sequestration Partnership projects supported by the Office of Fossil 
Energy at the DOE, would be considered R&D for the purposes of this 
exemption from reporting for the duration of the R&D activity. Other 
DOE supported GS R&D projects may also satisfy the eligibility 
requirements for the exemption. In addition, short duration 
CO<INF>2</INF> injection projects conducted to identify local 
amenability to long term storage will be exempted from 40 CFR part 98, 
subpart RR for the duration of such injection testing. This includes 
cases where an operator is using a short duration CO<INF>2</INF> 
injection test to assess local geologic conditions and validate the 
injectivity potential of a particular site prior to developing that 
site for commercial scale geologic storage of carbon dioxide. 
Demonstration projects can apply for the exemption, but will be 
measured against the same criteria established in 40 CFR 98.440(d). 
Projects that are not R&D projects, such as commercial GS operations, 
are not eligible for the exemption.
    To receive an R&D exemption, the project representative must submit 
to the Administrator information on the planned duration of 
CO<INF>2</INF> injection for research, the planned annual 
CO<INF>2</INF> injection volumes during this time period, the purposes 
of the project, the source and type of funding for the project, and the 
class and duration of UIC permit, or, for an offshore facility not 
subject to SDWA, a description of the legal instrument authorizing GS.
    The Administrator will 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 will take into account any information that the 
reporter submits demonstrating that the planned duration of 
CO<INF>2</INF> injection for the project and the planned annual 
CO<INF>2</INF> injection volumes during the duration of the project are 
consistent with the purpose of the research and development project. 
This rule allows for administrative appeals of the Administrator's R&D 
determination, as provided for in 40 CFR part 78.
    Facilities that qualify for a GS R&D exemption from 40 CFR part 98, 
subpart RR are not exempted from any other source category of the GHG 
Reporting Program including 40 CFR part 98, subpart UU. For other 
source categories of the GHG Reporting Program, R&D is defined at 40 
CFR 98.6.
2. Subpart RR Reporting Threshold
    All facilities that meet the 40 CFR part 98, subpart RR source 
category definition must report (i.e., there is no reporting 
threshold). However, reporters that receive a subpart RR R&D exemption 
are no longer subject to subpart RR, but rather report CO<INF>2</INF> 
received under subpart UU. The cease reporting provisions of Sec.  
98.2(i) do not apply to subpart RR. Rather, once a facility is subject 
to the requirements of this subpart, including facilities that opt-in 
to 40 CFR part 98, subpart RR, 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. The request to discontinue reporting 
must include either a copy of the applicable UIC program Director's 
authorization of site closure, or a demonstration that the injected 
CO<INF>2</INF> stream is not expected to migrate in a manner likely to 
result in surface leakage. Before the reporter can discontinue 
reporting, but after injection has ceased, EPA expects that in most 
cases there will be minimal burden in monitoring and reporting unless a 
surface leak is detected.
3. Subpart RR GHGs to Report
    Facilities covered by this source category must report the mass of 
CO<INF>2</INF> received; the mass of CO<INF>2</INF> injected; the mass 
of CO<INF>2</INF> produced (i.e., mixed with produced oil, gas, or 
other fluids); the mass of CO<INF>2</INF> emitted from surface leakage; 
the mass of CO<INF>2</INF> equipment leaks and vented CO<INF>2</INF> 
emissions from sources between the injection flow meter and the 
injection wellhead or between the production flow meter and the 
production wellhead; and the mass of CO<INF>2</INF> sequestered in 
subsurface geologic formations (this is calculated from the other 
quantities).
4. Subpart RR GHG Calculations and Monitoring
    Facilities covered by this source category must calculate the 
annual mass of CO<INF>2</INF> received. Starting from the date 
specified in the EPA-approved MRV plan, facilities must also use a mass 
balance approach to calculate the mass of CO<INF>2</INF> geologically 
sequestered. First, facilities must calculate the annual mass of 
CO<INF>2</INF> injected. From the annual mass of CO<INF>2</INF> 
injected, facilities must subtract the mass of CO<INF>2</INF> emitted 
from surface leakage, using the site-specific procedures in their MRV 
plan, and the mass of CO<INF>2</INF> emitted as equipment leaks or 
vented emissions from applicable surface equipment, using the 
procedures specified in 40 CFR part 98, subpart W of the GHG Reporting 
Program. All GS projects with equipment leak or vented emissions from 
surface equipment applicable to the GS mass balance equation should use 
the procedures specified in subpart W, regardless of whether such 
projects are associated with the oil and gas industry. Facilities that 
are producing, oil, gas, or other fluids must additionally subtract the 
mass of CO<INF>2</INF> produced. Calculation procedures are provided at 
40 CFR 98.443.
5. Subpart RR Geologic Sequestration Monitoring, Reporting, and 
Verification (MRV) Plans
    Facilities must develop an MRV plan, submit the MRV plan to EPA, 
receive an approved MRV plan from EPA, implement the EPA-approved plan, 
and submit annual reports.
    The MRV plan must include five major components:
    X Delineation of the maximum monitoring area (MMA) and the active 
monitoring area (AMA).
    X Identification and evaluation of the potential surface leakage 
pathways and an assessment of the likelihood, magnitude, and timing, of 
surface leakage of CO<INF>2</INF> through these pathways in the MMA.
    X A strategy for detecting and quantifying any surface leakage of 
CO<INF>2</INF> in the event leakage occurs.
    X An approach for establishing the expected baselines for 
monitoring CO<INF>2</INF> surface leakage.
    X A summary of considerations made to calculate site-specific 
variables for the mass balance equation.
    First, the MRV plan must include a delineation of the MMA and the 
AMA. The MMA includes the extent of the free phase CO<INF>2</INF> plume 
over the lifetime of the project plus a buffer zone of one-half mile. 
Potential surface leakage pathways must be identified and assessed in 
the MMA. The AMA is the area that will be monitored over a specified 
time interval chosen by the reporter, which must be greater than one 
year. All of the area in the MMA will eventually be covered by one or 
more AMAs. The first time interval will begin from the date determined 
in your MRV plan through the date at which the MRV plan calls for the 
first expansion of the AMA. For each subsequent time interval, a new 
AMA must be determined. This allows operators to phase in monitoring so 
that during any given time interval, only that part of the MMA in which 
leakage might occur needs to be monitored. The boundary of the AMA in 
each time interval is established by superimposing two areas. The first 
is the area projected to contain the free phase CO<INF>2</INF> plume at 
the end of the specified time interval plus an all around buffer zone 
of at least

[[Page 75066]]

one-half mile, or greater if known leakage pathways extend laterally 
more than one-half mile. The second is the area projected to contain 
the free phase CO<INF>2</INF> plume five years beyond the specified 
time interval.\9\
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    \9\ In some cases, the actual footprint of the free phase 
CO<INF>2</INF> plume and the area that is projected to contain the 
free phase CO<INF>2</INF> plume after five years may be the same. 
The one-half mile or greater area provides a buffer zone in the case 
that upward migration of a CO<INF>2</INF> leak moves laterally as it 
approaches the surface.
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    Second, the MRV plan must include identification and evaluation of 
potential surface leakage pathways within the MMA and an assessment of 
the likelihood, magnitude, and timing, of surface leakage of 
CO<INF>2</INF> through these pathways. Possible conduits for 
CO<INF>2</INF> leakage include faults, fractures, and abandoned 
wells.\10\
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    \10\ As discussed in Section I.D. of this preamble, UIC 
requirements can provide the basis for the MRV plan submitted to EPA 
for 40 CFR part 98, subpart RR.
---------------------------------------------------------------------------

    Third, the MRV plan must describe the strategy for detecting and 
quantifying surface leakage of CO<INF>2</INF> in the event leakage 
occurs. It should include a description of the approach for determining 
whether surface leakage has occurred, an explanation of how 
CO<INF>2</INF> surface leaks will be distinguished from the baseline, 
and the approach for quantifying detected and verified surface leakage. 
The expected performance of the selected leakage detection monitoring 
system or technical specifications should also be described in the MRV 
plan. If a surface leak is detected, the reporter should have a 
strategy in place to verify that a surface leak has occurred, confirm 
the location and source of the surface leak, and then apply some 
combination of direct measurement and estimation to quantify the 
surface leak.
    Fourth, the MRV plan should include an approach for establishing 
expected baselines. The primary goal of establishing expected baselines 
is so that the Reporter can discern whether the results of monitoring 
are attributable to leakage of injected CO<INF>2</INF> or from another 
cause (e.g. natural variability). The MRV plan leakage detection and 
quantification strategy may include monitoring a selection of indicator 
parameters to detect potential CO<INF>2</INF> leakages. These indicator 
parameters may be environmental such as subsurface pressure, soil 
CO<INF>2</INF> flux rates, etc., or operational, such as the injection 
pressure and the annular pressure in the well. To judge whether a set 
of measured parameter values obtained during GS operations may indicate 
CO<INF>2</INF> leakage, reporters should know what those parameter 
values would be expected to be in the absence of leaks. The MRV plan 
should describe how the baselines will be determined, how they will be 
measured or calculated, how they could be used to detect monitoring 
anomalies, and the operating conditions and their variability.
    Fifth, the MRV plan should include a description of monitoring and 
calculation methodologies to calculate equipment leaks and vented 
emissions from surface equipment between the flow meters and either 
injection or production wellheads, and the quantity of CO<INF>2</INF> 
that is produced with oil or other fluids.
    EPA will send a notice of receipt to the reporter within 15 days to 
acknowledge that EPA has received the MRV plan submission. EPA will 
determine if the MRV plan is complete within 45 days of the notice of 
receipt and will notify the reporter whether the plan is complete or 
incomplete. If incomplete, the reporter must submit an updated MRV plan 
within 45 days of EPA notification unless otherwise specified by EPA.
    Once EPA determines that the MRV plan is complete, technical review 
will commence. After 60 days of technical review, EPA will send the 
reporter a request for additional information including clarifying 
technical questions, if necessary. The reporter will be encouraged to 
provide a response to this request within 15 days, however EPA 
recognizes that there may be circumstances where additional time is 
needed for the reporter to collect the information requested.
    Following this iterative process, EPA will issue a final MRV plan 
as submitted, or with revisions. EPA will post the approved MRV plan on 
a public Web site, subject to any limitations or requirements in its 
CBI determination (see Section I.B of this preamble). Any reporter, or 
interested person, objecting to EPA's final decision, may appeal it to 
EPA's Environmental Appeals Board.
    Facilities must re-submit the MRV plan for EPA approval if a 
material change was made to monitoring and/or operational parameters 
that was not anticipated in the original plan, if the facility's UIC 
permit class changes, or if an EPA review of the annual report 
determines that it is necessary. Examples of material changes include 
but are not limited to a large change in the volume of CO<INF>2</INF> 
injected; the construction of new injection wells not referred to in 
the MRV plan; failures of the monitoring system to perform as expected 
due to inadequate 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 
monitoring plan; a change in the MMA or AMAs; or a change in monitoring 
technology that would result in coverage or detection capability 
different from what is specified in the MRV plan. As an example of a 
facility's UIC permit class changing, the UIC Class VI rule provides 
that UIC Class II ER projects must seek a UIC Class VI permit when 
there is an increased risk to USDWs compared to UIC Class II 
operations. Please see 40 CFR 144.19 of the UIC Class VI rule for a 
list of risk-based criteria that the UIC Director shall use to 
determine if the owner or operator of a UIC Class II ER project must 
apply for and obtain a UIC Class VI permit. This list of criteria may 
also be used by Class II ER project owners and operators to self-
determine if they need to apply for and obtain a UIC Class VI permit. 
If a facility's UIC permit were to change from Class II to Class VI, it 
would be required to submit a revised MRV plan to EPA for approval.
6. Subpart RR Data Reporting
    In addition to the information summarized at ``Subpart RR GHGs to 
Report'' in this section of the preamble, facilities must report the 
source of the CO<INF>2</INF> received and the cumulative amount of 
CO<INF>2</INF> geologically sequestered since the facility first 
reported under subpart RR. All facilities must also report 
concentration, facilities using mass flow meters must report mass flow 
information, facilities using volumetric flow meters must report 
volumetric flow information, and facilities using containers must 
measure the mass or volume of the containers. They are required to 
report a description of the monitoring program that was implemented, 
including descriptions of monitoring anomalies and surface leakage, if 
any. Finally, for EPA verification purposes, they are required to 
report for each injection well the class of UIC permit and well 
identification number used for the UIC permit.
    Subpart RR requires reporting of CO<INF>2</INF> equipment leaks and 
vented CO<INF>2</INF> emissions to the extent they are a component of 
the GS mass balance. Subpart RR does not require reporting of 
CO<INF>2</INF> equipment leaks and vented CO<INF>2</INF> emissions from 
all surface equipment located within the facility (e.g., operational 
emissions not related to the CO<INF>2</INF> being injected); however, 
GS projects that produce oil or natural gas may be required to report 
CO<INF>2</INF> equipment leaks and vented CO<INF>2</INF> emissions in 
the petroleum and natural

[[Page 75067]]

gas system subpart, 40 CFR part 98, subpart W as part of either 
offshore or onshore petroleum and natural gas production.
7. Subpart RR Recordkeeping
    Facilities must retain quarterly records of CO<INF>2</INF> 
received; injected CO<INF>2</INF>; produced CO<INF>2</INF>; 
CO<INF>2</INF> emitted by surface leakage; CO<INF>2</INF> emitted as 
equipment leaks and vented emissions from equipment located on the 
surface between the flow meter used to measure the injection quantity 
and the injection wellhead and between the flow meter used to measure 
the production quantity and the production wellhead; and any other 
records as outlined for retention in the facility MRV plan for 3 years 
per 40 CFR 98.3(g).
8. Subpart RR Administrative Appeals
    Under this final rule, final decisions of the Administrator under 
part 98, subpart RR are appealable to EPA's Environmental Appeals Board 
under the regulations that are set forth in part 78 (40 CFR part 78). 
Part 78 is revised to accommodate such appeals. Specifically, the list 
in 40 CFR 78.1 of the types of final decisions that can be appealed 
under 40 CFR part 78 is expanded to cover final decisions of the 
Administrator under 40 CFR part 98, subpart RR. This list includes, but 
is not limited to, the following specific types of decisions under 
subpart RR, a determination of eligibility for an R&D exemption under 
40 CFR 98.440(d)(4), the approval or disapproval of a request for 
discontinuation of reporting under 40 CFR 98.441(b)(2), and the 
approval or disapproval of a MRV plan under 40 CFR 98.448(c).
    Further, 40 CFR 78.3 is revised to allow for petitions for 
administrative appeal of decisions of the Administrator under 40 CFR 
part 98, subpart RR. Under the general approach in the existing part 
78, an ``interested person'' (in addition to the official 
representative of owners and operators involved in a matter) may 
petition for an administrative appeal of a final decision of the 
Administrator. The ``interested person'' definition, which is located 
in part 72 of the Acid Rain Program regulations, is expanded to take 
into account final decisions of the Administrator under part 98. In 
particular, EPA is revising the ``interested person'' definition by 
replacing specific references to the Acid Rain Program and draft 
permits with broader references to any decision by the Administrator 
and the Administrator's process of making that decision. As a result of 
this revision and the revisions of 40 CFR part 78, a person who does 
not own or operate a facility covered by a final decision under 40 CFR 
part 98, subpart RR will need to submit his or her name to be included 
by the Administrator on an ``interested persons list'' in order to be 
able to appeal--by filing a petition for an administrative appeal--that 
final decision.
    In addition, 40 CFR 78.4 is expanded to state that filings on 
behalf of owners and operators of a facility subject to 40 CFR part 98, 
subpart RR must be signed by the designated representative of the 
owners and operators.

C. Summary of the Reporting Requirements for Injection of Carbon 
Dioxide (Subpart UU)

    Reporting requirements for all other facilities conducting 
CO<INF>2</INF> injection are found in 40 CFR part 98, subpart UU. 
Facilities conducting GS and reporting under 40 CFR part 98, subpart RR 
are not required to report under 40 CFR part 98, subpart UU.
1. Subpart UU Source Category Definition
    The 40 CFR part 98, subpart UU source category consists of any 
other well or group of wells that inject a CO<INF>2</INF> stream into 
the subsurface. This includes any wells used to enhance oil and gas 
recovery and GS R&D projects that are exempted from 40 CFR part 98, 
subpart RR monitoring and reporting requirements. If you report under 
40 CFR part 98, subpart RR for a well or group of wells, you are not 
required to report under 40 CFR part 98, subpart UU for that well or 
group of wells.
2. Subpart UU Reporting Threshold
    All facilities that inject CO<INF>2</INF> underground must report 
under this subpart (except those in subpart RR), regardless of the 
amount of emissions from the facility or the amount of CO<INF>2</INF> 
injected. Reporters can cease subpart UU reporting pursuant to the 
provisions at 40 CFR 98.2(i) that allow facilities to cease GHG 
reporting to EPA; with respect to subpart UU, any reference to 
CO<INF>2</INF> emissions in 40 CFR 98.2(i) means CO<INF>2</INF> 
received.
3. Subpart UU GHGs to Report
    Facilities covered by this source category must report the annual 
mass of CO<INF>2</INF> received.
4. Subpart UU GHG Calculations and Monitoring
    Facilities covered by this source category must calculate the 
annual mass of CO<INF>2</INF> received using the calculation procedures 
for either mass or volumetric flow meters. Where CO<INF>2</INF> is 
received in containers, facilities must use the calculation procedures 
for determining the mass or volume of contents in containers.
5. Subpart UU Data Reporting
    In addition to reporting the mass of CO<INF>2</INF> received, 
facilities must report the source of the CO<INF>2</INF>. All facilities 
must also report concentration, facilities using mass flow meters must 
report mass flow information, facilities using volumetric flow meters 
must report volumetric flow information, and facilities using 
containers must measure the mass or volume of the containers.
6. Subpart UU Recordkeeping
    Facilities must retain quarterly records of CO<INF>2</INF> received 
for 3 years per 40 CFR 98.3(g).

D. Summary of the Major Changes Since Proposal

    The major changes in this rule since the original proposal are 
identified in the following list. The rationale for these and any other 
changes to the rule can be found in this section or in ``Mandatory 
Greenhouse Gas Reporting Rule: EPA's Response to Public Comments, 
Subparts RR and UU: Injection and Geologic Sequestration of Carbon 
Dioxide.''
    X EPA has moved all definitions, requirements, and procedures for 
facilities conducting CO<INF>2</INF> injection only (which both EPA and 
commenters have referred to as ``Tier 1'' facilities for simplicity) 
into a new subpart, 40 CFR part 98, subpart UU, and retained all 
definitions, requirements, and procedures related to facilities 
conducting GS (which both EPA and commenters have referred to as ``Tier 
2'' facilities for simplicity) in 40 CFR part 98, subpart RR.
    X EPA has removed the requirement that facilities report the amount 
of CO<INF>2</INF> injected in 40 CFR part 98, subpart UU (Tier 1) but 
retained requirements that facilities subject to this subpart report 
the amount of CO<INF>2</INF> received and the source of CO<INF>2</INF> 
if known.
    X EPA has established procedures for calculating CO<INF>2</INF> 
received in containers.
    X In 40 CFR part 98, subpart RR, EPA has established eligibility 
requirements for a GS R&D project to be exempt from 40 CFR part 98, 
subpart RR.
    X In 40 CFR part 98, subpart RR, EPA has retained the requirement 
that facilities report the equipment leaks and vented emissions for 
surface equipment that could be included in the GS mass balance but 
removed the requirement for reporting equipment leaks and

[[Page 75068]]

vented emissions for all other surface equipment.
    X In 40 CFR part 98, subpart RR, EPA has added an MRV plan 
requirement for the delineation of the areas that will be monitored.
    X In 40 CFR part 98, subpart RR, EPA has clarified the requirements 
for an addendum to the annual report and renamed it the monitoring 
report.
    X EPA has amended 40 CFR part 78 to include administrative appeals 
procedures for EPA decisions made under 40 CFR part 98, subpart RR, 
such as decisions relating to eligibility for the R&D exemption under 
40 CFR 98.440(d)(4), decisions relating to a request for 
discontinuation of reporting under 40 CFR 98.441(b)(2), or MRV plan 
decisions under 40 CFR 98.448(c).

E. Summary of Comments and Responses

    This section contains a brief summary of major comments and 
responses. A large number of comments on CO<INF>2</INF> injection and 
sequestration were received covering numerous topics. Responses to 
significant comments received can be found in ``Mandatory Greenhouse 
Gas Reporting Rule: EPA's Response to Public Comments, Subparts RR and 
UU: Injection and Geologic Sequestration of Carbon Dioxide.''
1. Legal Authority
    Comment: EPA received a number of comments regarding its legal 
authority to require the proposed reporting from facilities conducting 
CO<INF>2</INF> injection or GS. Some commenters argued that EPA has 
over-reached its CAA statutory authority, stating that the CAA 
authorizes the regulation of air emissions, not CO<INF>2</INF> 
injection or GS. One commenter asserted that EPA is overstepping its 
authority under CAA section 114 by requiring indefinite and broad 
monitoring and reporting, and that none of EPA's stated purposes in the 
preamble to the proposal provide adequate justification for the 
proposed data collection requirements, imposition of new measurement 
protocols, or installation of new instrumentation. Some commenters also 
asserted that the fiscal year 2008 Appropriations Act constrains the 
scope of EPA's information gathering to GHG emissions, which does not 
include CO<INF>2</INF> injection or GS. Some commenters asserted that 
the proposal was within EPA's authority under the CAA.
    Response: EPA is promulgating this rule under the authority 
provided in CAA section 114. We disagree that we do not have statutory 
authority to promulgate this rule. The Administrator may gather 
information under CAA section 114, as long as that information is for 
purposes of carrying out any provision of the CAA. The information 
submitted to EPA as a result of this rule will, among other things, 
inform policy decisions under the CAA related to the use of CCS for 
mitigating GHG emissions. This data will prove valuable to the Agency 
in several areas, including reconciling 40 CFR part 98, subpart UU data 
on CO<INF>2</INF> received with CO<INF>2</INF> supply data to better 
understand the amount of CO<INF>2</INF> supply that is used for 
CO<INF>2</INF> injection and GS, monitoring the growth and efficacy of 
GS over time, and evaluating ER as a potentially non-emissive end use.
    EPA is not citing the fiscal year 2008 Consolidated Appropriations 
Act as the statutory basis for this action. Furthermore, we do not 
agree that the appropriations language constrains EPA's ability to 
collect the information under this action. Please also refer to 
Mandatory Greenhouse Gas Reporting Rule: EPA's Response to Public 
Comments, Volume No.: 9, Legal Issues (Docket ID No. EPA-HQ-OAR-2008-
0508) for similar comments received in developing the rule establishing 
the GHG Reporting Program.
2. Definition of Source Category
    Comment: EPA received many comments about the definition of source 
category and GS facility. At least one commenter recommended setting a 
clearer distinction between CO<INF>2</INF> injection without GS (Tier 
1) and CO<INF>2</INF> injection with GS (Tier 2). This commenter and 
others recommended a further distinction within the GS group--GS with 
ER and GS without ER. In addition, several commenters either requested 
clarification of or demonstrated a misunderstanding of whether 
particular provisions of the proposed rule, such as the GS R&D 
exemption and proposed discontinuation of reporting provisions, would 
apply to all CO<INF>2</INF> injection, to CO<INF>2</INF> injection with 
GS only, or to CO<INF>2</INF> injection without GS only.
    Furthermore, several commenters were confused by the definition of 
GS facility in the regulatory text and found it to be redundant, 
complicated, unclear, or vague. At least two commenters urged EPA not 
to change the definition of facility found in 40 CFR 98.6 of the GHG 
Reporting Program General Provisions, while other commenters appeared 
to support a subpart RR-specific facility definition but raised 
questions or provided comment about which structures or equipment would 
be within the GS facility. Some commenters requested edits or additions 
to the list of activities at 40 CFR 98.440(d) that are not included in 
the source category.
    Response: EPA agrees with commenters that the structure of proposed 
40 CFR 98.440 could be made clearer. It was never EPA's intention to 
override the definition of facility in 40 CFR 98.6; rather EPA intended 
to create a defined term ``GS facility'' to provide clarity about which 
facilities under the 40 CFR part 98, subpart RR source category would 
be subject to both ``Tier 2'' and ``Tier 1'' requirements. To harmonize 
40 CFR part 98, subpart RR with the rest of the GHG Reporting Program 
as intended and to maximize clarity, the defined term ``GS facility'' 
is not included in the final rule. In this action, EPA has deleted the 
term ``GS facility'' from the regulatory text and has reframed any 
necessary information as part of the definition of ``source category.'' 
The owner or operator of a group of CO<INF>2</INF> injection wells will 
determine the boundaries of the facility by following the definition in 
40 CFR 98.6. EPA has provided several examples in the General Technical 
Support Document (TSD)\11\ to illustrate how a facility would be 
delineated under various operational configurations.
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    \11\ General Technical Support Document for Injection and 
Geologic Sequestration of Carbon Dioxide: Subparts RR and UU (see 
docket ID No. EPA-HQ-OAR-2009-0926).
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    In order to effectuate the original intent of the ``GS facility'' 
term, and in light of comments expressing confusion between the ``Tier 
1'' and ``Tier 2'' requirements, EPA is retaining procedures and 
requirements for facilities conducting GS (Tier 2) in 40 CFR part 98, 
subpart RR and is moving all procedures and requirements for all other 
facilities conducting CO<INF>2</INF> injection (Tier 1) into a new 40 
CFR part 98, subpart UU in this action. EPA has concluded that this 
organizational change allows for two source category definitions while 
clearly distinguishing the two sets of provisions and procedures. EPA 
notes that this new organizational structure is merely formalizing the 
structure that EPA and commenters have been using to date informally.
    EPA considered but did not create a third source category as 
proposed in some comments for GS projects with ER. EPA has concluded 
that the provisions, procedures, and requirements in 40 CFR part 98, 
subpart RR apply equally to all GS projects--whether they conduct ER or 
not. It is most practical to cover both types of projects with one 
subpart.
    In this final action, EPA removed from the regulatory text the list 
of

[[Page 75069]]

activities that are not included in the source category. Based on 
experience with implementation questions from reporters to the rest of 
the GHG Reporting Program, EPA has concluded that this list does not 
provide regulatory clarity and instead creates confusion. Without this 
list the regulatory text is clear that the operations covered under 40 
CFR part 98, subparts RR and UU are wells that inject CO<INF>2</INF> 
underground. EPA does not need to explicitly provide a list of 
operations that do not meet this definition. EPA has found that 
operators may mistakenly conclude that they are exempt from 40 CFR part 
98, subpart RR or UU reporting requirements if they conduct an activity 
on the list, even if they also operate wells that inject CO<INF>2</INF> 
underground. To avoid this confusion, EPA had deleted the list from the 
regulatory text and is clarifying here that operators conducting any of 
the following activities need not be concerned with these activities 
when determining applicability to or reporting under 40 CFR part 98, 
subpart RR or UU: above ground CO<INF>2</INF> storage, CO<INF>2</INF> 
transportation or distribution, CO<INF>2</INF> purification, 
compression, or processing, CO<INF>2</INF> capture, and CO<INF>2</INF> 
end-uses other than underground injection. EPA notes that these 
activities may meet the definition of another source category in the 
GHG Reporting Program.
3. Geologic Sequestration Research and Development (GS R&D)
    Comment: EPA received a range of comments relating to exempting GS 
R&D projects. Some commenters supported the R&D exemption while others 
opposed it because they believe these projects can provide valuable 
information on the efficacy of GS as a climate mitigation approach. 
These commenters also noted that these projects are currently gathering 
data which would provide EPA an early opportunity to evaluate the 
appropriateness and application of monitoring methods. Some commenters 
suggested that GS R&D projects be provided an option to opt-in to GS 
reporting requirements. One group of commenters recommended that EPA 
exempt GS R&D projects on a case-by-case basis.
    Response: EPA agrees with commenters that collecting data from all 
GS projects, including R&D, would provide useful information about the 
efficacy of GS and monitoring techniques and approaches to quantify 
leakage. However, the Agency recognizes that GS is an emerging climate 
mitigation approach and there are likely to be some projects that are 
investigating practices, monitoring techniques, injection verification, 
or are engaged in other applied research that will facilitate the 
development and adoption of GS, and that these projects would benefit 
from being exempted from this subpart. Therefore the Agency is 
retaining a GS R&D exemption, with some modifications from the proposed 
rule. See Section II.B of the preamble for a summary of the R&D 
exemption process.
    Comment: Many commenters noted that restricting the proposed 
exemption to federally funded projects was too stringent, that R&D can 
also be supported by states, academia, or the private sector, and 
argued that GS R&D projects should not be defined based on the source 
of funding.
    Response: EPA agrees with commenters that there are non-Federal 
funding sources that could fund GS R&D projects and that Federal 
funding should not be the basis for an R&D exemption. Other sources of 
funding for GS R&D include State and academic sources. Funding might 
also come from the R&D budget of a private sector entity. However, in 
order for EPA to have basic information about projects operating under 
an R&D exemption, projects must provide information on the source and 
type of funding as part of their submission in support of the 
exemption.
    Comment: Many commenters suggested that EPA consider a threshold 
for exempting R&D projects. These commenters noted that a threshold 
would allow for reduced regulatory burden and that collecting data from 
projects below the threshold would yield little value for EPA.
    Response: EPA found that it would be challenging to define a 
threshold for GS R&D projects because project size could vary depending 
on the R&D goals and other factors such as availability and source of 
CO<INF>2.</INF> As stated above, EPA is establishing an exemption for 
R&D projects that are investigating practices, monitoring techniques, 
injection verification, or are engaged in other applied research, that 
will enable safe and effective long-term containment of a 
CO<INF>2</INF> stream in subsurface geologic formations, including 
research conducted as a precursor to long-term storage.
    Comment: Some commenters recommended that GS R&D projects be 
required to comply with ``Tier 1'' requirements, while a few commenters 
suggested that EPA exempt both Tier 1 and Tier 2 requirements for GS 
R&D projects.
    Response: EPA agrees with comments recommending that GS R&D 
projects report ``Tier 1'' data. Projects that qualify for a GS R&D 
exemption under 40 CFR part 98, subpart RR are not required to develop 
an MRV plan or report the GS mass balance information required of 
facilities conducting GS. However, these projects are required to 
report basic information on CO<INF>2</INF> received under subpart UU. 
EPA determined that GS R&D projects already collect such data and that 
the burden of reporting such data would be minimal.
4. Reporting Requirements
    Comment: EPA received many comments about the proposed ``Tier 1'' 
reporting requirements. Many commenters from the ER industry in 
particular urged EPA to remove all ``Tier 1'' reporting requirements 
for CO<INF>2</INF> injection projects without GS. These commenters 
expressed concern that collecting any information from business-as-
usual ER would lead to a misunderstanding of the CO<INF>2</INF> 
material balance at such operations. Many stated that data on total 
CO<INF>2</INF> injected in particular would have no bearing on future 
policy decisions about GHG emissions and should not be collected. Many 
commenters conceded that data on the quantity of ``new'' CO<INF>2</INF> 
received could be collected if EPA insisted on collecting some data 
from ``Tier 1'' sources, presumably because it could potentially inform 
future climate change policy decisions. At least one commenter offered 
that by collecting data on the quantity of ``new'' CO<INF>2</INF> 
received, EPA could reasonably estimate the amount of CO<INF>2</INF> 
retained underground.
    On the other end of the spectrum, one set of comments echoed that 
the ``Tier 1'' reporting requirements as proposed would be insufficient 
for an accurate CO<INF>2</INF> material balance, and recommended 
expanding ``Tier 1'' reporting requirements rather than narrowing or 
removing them. This set of comments recommended that data on 
CO<INF>2</INF> recycled from each project be collected so that EPA 
could get a full understanding of the ER industry. These commenters 
advocated for collection of quantity data from ``Tier 1'' reporters, 
arguing that ER operations dominate CO<INF>2</INF> end-users and the 
data will be necessary to understand the disposition of CO<INF>2</INF> 
supply reported under 40 CFR part 98, subpart PP of the GHG Reporting 
Program. Meanwhile, at least three commenters offered that the proposed 
``Tier 1'' reporting requirements would be adequate to meet EPA's 
stated needs and that no additional data reporting should be required 
in the final regulation.
    Response: In this final rule, EPA is retaining some of the proposed 
``Tier 1''

[[Page 75070]]

reporting requirements for CO<INF>2</INF> injection facilities. EPA is 
requiring reporting under 40 CFR part 98, subpart UU (previously 
referred to as ``Tier 1'' facilities) of CO<INF>2</INF> received (a 
term that EPA is defining in this final action for what commenters 
described as ``new'' CO<INF>2</INF>). EPA is not requiring reporting on 
total CO<INF>2</INF> injection under 40 CFR part 98, subpart UU. 
Reporting on total CO<INF>2</INF> injection will be required for 
facilities conducting GS under 40 CFR part 98, subpart RR (previously 
referred to as ``Tier 2'' facilities). EPA has concluded that data on 
CO<INF>2</INF> received is critical for EPA to better understand the 
disposition of CO<INF>2</INF> supply reported in 40 CFR part 98, 
subpart PP. Furthermore, EPA recognizes that the geology of an oil and 
gas reservoir can create a barrier to trap CO<INF>2</INF> underground 
and that many projects in the ER industry could successfully verify and 
report the geologic sequestration of CO<INF>2</INF> with an EPA-
approved MRV plan. By collecting data on CO<INF>2</INF> received at 
these facilities, EPA will better understand the scope and size of a 
potentially non-emissive end-use.
    Due to the comments received on this issue, EPA considered adding 
recycled CO<INF>2</INF> to the proposed Tier 1 data requirements. 
Ultimately, EPA concluded that a CO<INF>2</INF> material balance is 
most informative to the Agency from GS projects that verify the 
quantity of CO<INF>2</INF> geologically sequestered by implementing 
their EPA-approved MRV plans. Though the collection of either a partial 
or full set of data from 40 CFR part 98, subpart UU facilities would 
have given EPA additional data regarding ER operations, it could have 
also caused confusion amongst reporters and the public about which 
facilities are estimating and reporting geologic sequestration. By 
requiring mass balance inputs from GS projects only and by splitting 
the proposed rule into two subparts, EPA is making clear in this action 
that the quantity of CO<INF>2</INF> geologically sequestered can only 
be verified and reported to EPA by developing and implementing an EPA-
approved MRV plan and reporting GS under 40 CFR part 98, subpart RR.
    For clarification, EPA reworded the proposed term ``CO<INF>2</INF> 
transferred onsite from offsite'' to ``CO<INF>2</INF> received'' 
because EPA identified at least one configuration where CO<INF>2</INF> 
would be supplied to an injection well from an adjacent plant that is 
part of the same facility (per the definition of facility in 40 CFR 
98.6). CO<INF>2</INF> received from a natural source within the same 
field or basin in which it is injected is also included as 
CO<INF>2</INF> received.
5. Reporting Threshold
    Comment: EPA proposed ``all in'' requirements and sought comment on 
whether and how to establish a threshold. A few of the comments EPA 
received agreed with EPA's all-in reporting approach, noting that data 
from all facilities is significant at this early stage in the GS 
industry, that at this point there is not enough data to determine a 
sensible threshold level, that the amount of CO<INF>2</INF> injected in 
one year is not a good indicator of the amount of CO<INF>2</INF> 
injected in the following year, and that EPA needs a comprehensive 
picture of the industry. One comment characterized no threshold for 
``Tier 1'' reporting as reasonable because of the associated low 
burden.
    Other comments opposed the all-in reporting threshold stating that 
it would burden a higher number of facilities than was necessary. These 
comments provided a variety of possible approaches and thresholds for 
EPA to consider including a threshold of 100,000 metric tons per year 
of ``new'' CO<INF>2</INF> received, an injection threshold of 25,000 
metric tons per year, an injection threshold of 100,000 metric tons of 
CO<INF>2</INF> per year, an injection threshold of 2-3 million metric 
tons per year, and an emission threshold of 25,000 metric tons of 
CO<INF>2</INF> per year.
    Response: EPA agreed with commenters who supported an all-in 
threshold because it would result in the most comprehensive tracking 
and reporting. Collecting information on all projects is important, 
especially at this early stage in the GS industry. As demonstrated by 
the range of suggested thresholds provided by commenters, there is no 
one obvious sensible threshold. The amount of CO<INF>2</INF> injected 
in one year is not a good indicator of the amount of CO<INF>2</INF> 
injected in the following year and there are no monitoring standards or 
data available to determine the amount of CO<INF>2</INF> emitted. In 
this final rule, EPA is requiring reporting from all facilities that 
meet the 40 CFR part 98, subpart UU (previously referred to as ``Tier 
1'' facilities) source category definition and from all facilities that 
meet the 40 CFR part 98, subpart RR (previously referred to as ``Tier 
2'' facilities) source category definition. EPA is not establishing a 
reporting threshold for these facilities. Reporters can cease subpart 
UU reporting pursuant to the provisions at 40 CFR 98.2(i) that allow 
facilities to cease GHG reporting to EPA; with respect to subpart UU, 
any reference to CO<INF>2</INF> emissions in 40 CFR 98.2(i) means 
CO<INF>2</INF> received. The cease reporting requirements of Sec.  
98.2(i) do not apply to subpart RR; the owner or operator must continue 
to comply with all requirements until the Administrator has issued a 
final decision on the owner or operator's request to discontinue 
reporting.
    As noted in the proposal, an all-in reporting threshold will allow 
the Agency to comprehensively track all CO<INF>2</INF> supply (as 
reported in Suppliers of CO<INF>2</INF>, 40 CFR part 98, subpart PP) 
that is received for injection underground. This approach is consistent 
with the all-in requirements in the GHG Reporting Program for some 
suppliers of petroleum, natural gas, and coal-to-liquid products (40 
CFR part 98, subparts LL, MM, and NN),\12\ producers of industrial 
gases (40 CFR part 98, subpart OO), and suppliers of CO<INF>2</INF> (40 
CFR part 98, subpart PP).
---------------------------------------------------------------------------

    \12\ In a recently proposed rulemaking (75 FR 48744, August 11, 
2010), EPA proposed to establish a threshold for Local Distribution 
Companies in subpart NN.
---------------------------------------------------------------------------

    With respect to 40 CFR part 98, subpart UU, EPA has estimated the 
cost for facilities conducting CO<INF>2</INF> injection to comply with 
the minimum reporting requirements and has determined that the burden 
will be small, given the equipment and data collection efforts already 
in place at ER projects. With respect to 40 CFR part 98, subpart RR, 
the Agency notes that GS R&D projects are exempt from 40 CFR part 98, 
subpart RR once EPA confirms their eligibility for the exemption. EPA 
has concluded that these two features will ensure that projects 
receiving and injecting small amounts of CO<INF>2</INF> are not 
disproportionately burdened by the reporting requirements in this final 
rule.
6. Equipment Leaks and Vented Emissions
    Comment: EPA proposed that all facilities subject to ``Tier 2'' 
requirements would be required to report fugitive and vented 
CO<INF>2</INF> emissions from the surface components located within the 
facility, unless already reported under 40 CFR part 98, subpart W 
(petroleum and natural gas systems). A few commenters were concerned 
about overlap in reporting requirements and recommended that EPA 
require the reporting of fugitive and vented CO<INF>2</INF> emissions 
from equipment associated with oil and gas production solely under 40 
CFR part 98, subpart W and limit the reporting under 40 CFR part 98, 
subpart RR to fugitive and vented emissions from equipment associated 
with GS operations for which emissions were not already being reported 
under 40 CFR part 98, subpart

[[Page 75071]]

W. A number of commenters disagreed with EPA's proposed reporting 
requirements for fugitive and vented CO<INF>2</INF> emissions and 
suggested that EPA scale back or eliminate such reporting, while one 
commenter supported such reporting requirements. Four commenters stated 
that fugitive and vented emissions would be trivial when compared to 
the amount of CO<INF>2</INF> injected, and three commenters stated that 
such reporting would unwarrantedly shift CO<INF>2</INF> into a 
hazardous air pollutant-like category. One commenter suggested that 
reporting of fugitive and vented emissions would be germane where 
applicable to the GS mass balance equation. One commenter supported 
EPA's proposed requirements for the reporting of fugitive and vented 
CO<INF>2</INF> emissions.
    Response: EPA proposed to require the reporting of fugitive 
CO<INF>2</INF> emissions (referred to in this final action as 
CO<INF>2</INF> equipment leakage) and vented CO<INF>2</INF> emissions 
in order to better understand the volume of CO<INF>2</INF> equipment 
leakage and vented CO<INF>2</INF> emissions from such facilities as 
compared to the amount of CO<INF>2</INF> sequestered. However, EPA has 
concluded that the information that would be generated from such a 
reporting requirement is not necessary for computing the mass balance 
of the amount of CO<INF>2</INF> sequestered.
    In the notice of proposed rulemaking, EPA proposed that 
CO<INF>2</INF> equipment leakage and vented CO<INF>2</INF> emissions be 
included in the GS mass balance calculation if the emissions occur 
downstream of the CO<INF>2</INF> injection flow meter or upstream of 
the production flow meter. EPA is retaining this reporting requirement 
in 40 CFR part 98, subpart RR because such data are important in order 
to provide a proper accounting of the amount of CO<INF>2</INF> that is 
geologically sequestered. In this action, EPA is requiring reporting of 
equipment leakage and vented emissions with respect to equipment 
located on the surface between the flow meter used to measure injection 
quantity and the injection wellhead and between the production wellhead 
and the flow meter used to measure production quantity.
    Emissions not related to the mass balance calculation do not need 
to be reported under subpart RR. Such emissions may need to be reported 
under subpart W if the facility is required to report under this 
subpart.
7. MRV Plan Requirements
    Comment: EPA received many comments supporting the Agency's 
proposal that reporters develop a site-specific MRV plan, but some 
commenters stated that more detail was needed about how MRV plans would 
be evaluated by EPA.
    Response: EPA has set out the basic components for MRV plans in 
Section II.B of this preamble. EPA has clarified the definition of the 
area where potential leakage pathways should be identified and 
characterized, and how monitoring could be phased in over time as 
CO<INF>2</INF> is injected. This is reflected in the regulatory text at 
40 CFR 98.448(a). EPA has also refined the requirements for what should 
be included in the annual report, and in what cases the reporter would 
need to resubmit an MRV plan for EPA approval.
    EPA's approach allows for site-specific flexibility for MRV plans 
and does not prescribe particular monitoring technologies. The approach 
also allows the owner or operator to leverage the site 
characterization, risk assessment, and/or monitoring required by other 
authorities as the foundation for demonstrating compliance with the MRV 
plan requirements of 40 CFR part 98, subpart RR. EPA recognizes the 
merit in providing greater clarity on the evaluation criteria, but 
notes that the geology and other conditions among facilities conducting 
GS vary. EPA has provided information in the General TSD on the 
technical evaluation of MRV plans, including illustrative examples 
describing the types of information that may be included in the MRV 
plan to fulfill the regulatory requirements at 40 CFR 98.448. This 
includes delineating the monitoring area, both the maximum area that 
the CO<INF>2</INF> plume is predicted to cover and how monitoring can 
be phased in over this area; selecting leakage detection systems that 
are suitable for the site; determining and verifying that a leak has 
occurred; identifying baseline conditions; and quantifying a 
CO<INF>2</INF> leak once a leak has been verified.
    Comment: EPA received many comments about the procedural aspects of 
MRV plan approval. Some commenters stated that CO<INF>2</INF> injection 
should not be allowed until MRV plans are approved. Many commenters 
urged the Agency to allow for public involvement.
    Response: EPA has set out the general MRV plan approval process in 
Section II.B of this preamble. EPA has designed MRV plan requirements 
under 40 CFR part 98, subpart RR so that facilities will not need to 
disrupt or delay normal operations. However, EPA clarifies that 
facilities will report the amounts of CO<INF>2</INF> geologically 
sequestered under 40 CFR part 98, subpart RR after they implement an 
EPA-approved MRV plan.
    EPA agrees with commenters that there should be a process for 
public involvement. Therefore, EPA plans to post approved MRV plans to 
a public Web site, to the extent consistent with any confidentiality 
determination. ``Interested persons'' can then appeal EPA decisions on 
MRV plans to the Environmental Appeals Board (EAB) through the appeals 
process described in 40 CFR part 78. An ``interested person'' may be 
any person who--in connection with the Administrator's process of 
making his or her decision--submitted comments, testified at a public 
hearing, submitted objections, or otherwise submitted his or her name 
to be included by the Administrator in an interested persons list. In 
the case of MRV plans, an interested person who wishes to appeal an EPA 
decision should submit his or her name to be included in the interested 
persons list. EPA will provide the public instruction on joining the 
interested persons list for 40 CFR part 98, subpart RR. More 
information on the administrative appeals process can be found in 
Section II.B of this preamble and in ``Mandatory Greenhouse Gas 
Reporting Rule: EPA's Response to Public Comments, Subparts RR and UU: 
Injection and Geologic Sequestration of Carbon Dioxide.'' Though there 
is no formal public comment process prior to approval of individual MRV 
plans in today's rule, EPA believes the administrative appeals process 
provides an opportunity for involvement by any member of the public who 
is concerned about the provisions of an approved plan. Further, if 
future GS policies or programs are promulgated as a result of the data 
collected through today's rule for which a formal public notice and 
comment period would be appropriate, EPA will establish a public notice 
and comment period for such a policy or program at that time.
    EPA has provided further information in the General TSD about the 
procedural aspects of MRV plan approval.
    Comment: EPA received many comments about the role of a UIC permit 
with respect to MRV plan requirements. Most commenters emphasized the 
need for coordination between the UIC program and 40 CFR part 98, 
subpart RR. Some commenters stated that any class of UIC permit is 
enough for purposes of the MRV plan. Others noted that the MRV plan 
should build off of the UIC permit and that comprehensive monitoring 
for the purposes of verifying quantities of CO<INF>2</INF> sequestered 
cannot occur under SDWA alone.
    Response: EPA maintains a high-level of coordination across EPA 
offices and regions on GS activities and regulatory

[[Page 75072]]

development. EPA's OAR and OW work closely to promote safe and 
effective implementation of GS technologies while ensuring protection 
of human health and the environment. EPA agrees with commenters that 
the UIC program provides the foundation for the safe sequestration of 
CO<INF>2</INF> by helping to ensure that injected fluids remain 
isolated in the subsurface and away from underground sources of 
drinking water, thereby serving to reduce the risk of CO<INF>2</INF> 
leakage to the atmosphere. A facility's UIC permit may be used to 
demonstrate that certain MRV plan requirements have been fulfilled. 
However, provisions are needed that go beyond what is required of UIC 
permits in order to quantify leakages, if any. See Section I.D of this 
preamble for a more detailed discussion of 40 CFR part 98, subpart RR 
and UIC Class VI requirements.

III. Economic Impacts of the Final Rule

    This section of the preamble examines the costs and economic 
impacts of the final rule for CO<INF>2</INF> injection and GS, 
including the estimated costs and benefits of the rule, and the 
estimated economic impacts of the rule on affected entities, including 
estimated impacts on small entities. Complete detail of the economic 
impacts of the rule can be found in the text of the Economic Impact 
Analysis (EIA) (EPA-HQ-OAR-2009-0926). This section also contains a 
brief summary of major comments and responses.

A. How were compliance costs estimated?

1. Summary of Method Used To Estimate Compliance Costs
    EPA estimated costs of complying with the rule and the total 
incremental annual cost of compliance. A base case is created assuming 
relevant monitoring costs required under UIC requirements (including 
the UIC Class VI rule). Then incremental reporting from geologic 
storage sites were evaluated in terms of required technologies, 
practices, and costs.
    The estimated costs include capital and operating and maintenance 
(O&M), including labor costs. The cost of drilling and equipping wells 
represents a large component of sequestration costs. Examples of other 
costs include seismic data acquisition, periodic sampling and testing 
of the injected CO<INF>2</INF>.
    The estimated costs are based on hypothetical or pro-forma sites 
for various types of projects such as R&D GS projects, commercial 
saline formation projects, and ER GS projects. The geologic and 
engineering assumptions for these pro-forma projects are the same as 
those used by the EPA Office of Water in the UIC Class VI rule. The 
costs are presented in 2008 dollars.
    The capital costs are annualized using an interest rate of 7 
percent with projects lasting 4 years, 10 years or 40 years. Next, 
annual O&M costs are added to the annualized capital costs to determine 
total annual direct costs. Finally, a 20 percent overhead and general 
and administrative cost factor is added to obtain total annual costs. 
These are then divided by the amount assumed to be injected each year 
in the pro-forma project to arrive at total costs per metric ton of 
CO<INF>2</INF> injected. These per-ton costs are then used to estimate 
total annual costs for the level of injection expected in the activity 
baseline.
2. Summary of Comments and Responses
    Comment: A majority of the comments received on the compliance 
costs of the reporting rule focused on facility level costs for 
monitoring and reporting. One commenter stated that EPA underestimated 
labor costs in the economic analysis of the rule.
    Response: EPA discussed and presented information for the costs and 
economic impacts of the proposed rule, including the estimated costs 
and benefits of the proposed rule, and the estimated economic impacts 
of the proposed rule on affected entities, including estimated impacts 
on small entities. Complete detail of the economic impacts of the rule 
can be found in Section 4 of the EIA. EPA's cost estimation methods 
reflect accepted engineering practices and publicly available cost and 
price data. For example, EPA used wage rates and overhead factors from 
the Department of Labor's Bureau of Labor Statistics.\13\
---------------------------------------------------------------------------

    \13\ Bureau of Labor Statistics. http://www.bls.gov/bls/wages.htm.
---------------------------------------------------------------------------

B. What are the costs of the rule?

1. Summary of Costs
    The total annualized costs incurred under the rule by these 
entities will be approximately $1.1 million (2008$), as illustrated in 
Table 4 of this preamble. This is based on projects that are currently 
injecting or will be injecting CO<INF>2</INF> by 2012, and includes 
costs for 1 saline GS facility reporting under subpart RR, and 92 
CO<INF>2</INF> injection facilities reporting under subpart UU. There 
are 9 R&D projects that incur costs to apply for a waiver under subpart 
RR, these same facilities are assumed to receive a waiver for the 
reporting requirements under subpart RR and are included in the subpart 
UU baseline of 92 projects. The public sector burden estimate is 
$344,000 for program implementation and verification activities. This 
may underestimate the total public sector burden depending on the 
extent to which DOE R&D projects funded with public dollars transition 
to commercial GS and consequently incur costs associated with 
monitoring, reporting and verification. Given uncertainties related to 
project adoption and the costs of the reporting program, EPA considered 
two other cost scenarios (one higher and one lower than the reference 
cost scenario) in order to assess a range of potential economic impacts 
on affected entities, as illustrated in Table 5 of this preamble. The 
three cost scenarios vary in terms of assumptions about which 
monitoring devices would be used at a facility conducting GS and how 
often sampling and measurement would take place. Because each facility 
conducting GS will have unique characteristics that may result in the 
selection of different monitoring techniques, a range of assumptions 
was used about the percents of sites that would be expected to use each 
device or technique. Complete detail on the cost scenarios is provided 
in Section 4.5.1 of the final Economic Impact Analysis (EIA) (EPA-HQ-
OAR-2009-0926).

[[Page 75073]]



          Table 4--National Annualized Mandatory Reporting Costs Estimates (2008$): Subparts RR and UU
----------------------------------------------------------------------------------------------------------------
                                                                                             Reference
                                                                    Metric tons  -------------------------------
                      Type                           Number of     CO2 received     First year      Second year
                                                     projects        per year       (thousand,      (thousand,
                                                                                      2008$)          2008$)
----------------------------------------------------------------------------------------------------------------
R&D (RR)........................................               9       5,320,000             $36             $36
Facilities Conducting GS (Saline) (RR)..........               1       1,842,885             318             240
Additional Facilities Conducting GS (ER opt in)                0               0               0               0
 (RR) \a\.......................................
Facilities Conducting CO2 Injection (no GS) (UU)              92      48,735,442             410             410
 \b\............................................
Private Sector, Total All Projects..............              93      50,578,327             764             686
Private Sector, Average ($/ton).................  ..............  ..............            0.02            0.01
                                                 ---------------------------------------------------------------
    Public Sector, Total........................  ..............  ..............             344             344
                                                 ---------------------------------------------------------------
        National Total..........................  ..............  ..............           1,107           1,030
----------------------------------------------------------------------------------------------------------------
a. Because reporting for ER facilities is optional, EPA has not included projections of ER reporters in the
  primary analysis. In the alternate costs scenarios EPA has analyzed costs assuming either a medium or high
  level of opt-in.
b. Includes UIC Class II ER Facilities.


                   Table 5--Annualized Reporting Costs per Project (2008$): Subparts RR and UU
----------------------------------------------------------------------------------------------------------------
                                            Reference                     Alternative cost scenarios
                                   -----------------------------------------------------------------------------
                                                                         Low                      High
               Type                  First year  Second year ---------------------------------------------------
                                      ($1,000)     ($1,000)    First year  Second year   First year  Second year
                                                                ($1,000)     ($1,000)     ($1,000)     ($1,000)
----------------------------------------------------------------------------------------------------------------
R&D (RR)..........................           $4           $4           $4           $4           $4           $4
Facilities Conducting GS (Saline)           318          240           96           18          490          413
 (RR).............................
Facilities Conducting GS (ER opt          2,124        2,005        1,893        1,773        2,271        2,151
 in) (RR).........................
Facilities Conducting CO2                     4            4            4            4            4            4
 Injection (No GS) (UU)...........
----------------------------------------------------------------------------------------------------------------

2. Summary of Comments and Responses
    Comment: EPA received comments on source specific cost data 
reflected in the engineering cost analysis presented in the EIA, 
Section 4 (EPA-HQ-OAR-2009-0926). Some commenters asked EPA to not 
overly burden entities that may be required to report, and questioned 
whether the proposed reporting program was duplicative with other EPA 
regulations on underground injection.
    Response: EPA considered all relevant comments regarding source 
specific cost data developed in the engineering cost analysis and used 
in the EIA. In some cases, we revised our cost estimates, and in some 
cases we revised monitoring and reporting requirements in ways that 
reduced burden. Please see source specific comments and responses in 
Section II.E of this preamble and ``Mandatory Greenhouse Gas Reporting 
Rule: EPA's Response to Public Comments, Subparts RR and UU: Injection 
and Geologic Sequestration of Carbon Dioxide.''
    EPA has determined the selected option for the mandatory GHG 
reporting rule strikes a balance between impacts on small entities, 
consistency with other programs, costs incurred by the reporting 
entities, and emissions coverage. Section 5 of the final EIA (EPA-HQ-
OAR-2009-0926) provides cost comparisons for each alternative 
evaluated.

C. What are the economic impacts of the rule?

1. Summary of Economic Impacts
    EPA assessed how the regulatory program may influence the 
profitability of companies by comparing the monitoring program costs to 
total sales (i.e., a ``sales'' test). Given limited data on commercial 
GS operations, EPA restricted the analysis to ER operations 
(approximately 90 percent of the fields). To do this, EPA divided the 
average annualized mandatory reporting costs per field by the estimated 
revenue for a representative field. Sales test ratios are between 3.1 
to 4.0 percent for facilities conducting GS (ER opt in). The number of 
ER operations that would choose to report as facilities conducting GS 
(ER opt in) is unknown and EPA could not identify any information or 
analysis to estimate this quantity. As a result, EPA considered two 
additional scenarios to represent medium and high levels of ER project 
opt ins. Section 5.2.1 of the final Economic Impact Analysis (EIA) 
(EPA-HQ-OAR-2009-0926) details the scenario analysis and projected 
national cost estimates. In contrast, facilities conducting ER 
CO<INF>2</INF> injection (no GS) sales test ratios are below 0.01 
percent, as illustrated in Table 6 of this preamble.

[[Page 75074]]



 Table 6--Sales Test for a Representative Commercial ER Field Operation
                                 [2008$]
------------------------------------------------------------------------
                                        Cost-to-sales ratios (CSRs)
                                  --------------------------------------
                                                    Alternative cost
                                  -------------         scenarios
                                               -------------------------
                                    Reference       Low          High
------------------------------------------------------------------------
Facilities Conducting GS (ER opt          3.7%         3.3%         4.0%
 in) (RR)........................
Facilities Conducting CO2                <0.1%        <0.1%        <0.1%
 Injection (No GS) (UU)..........
------------------------------------------------------------------------

2. Summary of Comments and Responses
    Comment: EPA received a number of comments on the overall economic 
impacts of the proposed rule. Some commenters stated that the economic 
impacts are understated as total national costs could be significantly 
higher if there is large scale deployment of CCS. Other commenters 
stated that large increases in operating costs resulting from mandatory 
reporting of GHGs could prevent projects from moving forward.
    Response: As described previously, EPA conducted a thorough 
analysis of available information and reviewed comments submitted on 
this issue, and we have determined that this analysis provides a 
reasonable characterization of costs for facilities in each subpart, 
under current law, and that the documentation provides adequate 
explanation of how the costs were estimated. EPA has estimated the 
total national cost of the reporting program based on current laws and 
regulations. Accordingly, one would not expect large scale deployment 
of CCS in the absence of a comprehensive climate policy that required 
or otherwise incentivized GS. In response to comments that total 
national costs would be higher given large scale deployment of CCS, EPA 
has augmented the scenario analyzing costs assuming future climate 
policy in Section 5.2.2 of the final EIA. Given the potential for 
future deployment of CCS technologies, EPA considered two additional 
scenarios of the number of large scale saline aquifer GS (commercial 
saline) project deployment by 2050: low (5 projects), medium (9 
projects), and high (54 projects). The low scenario is based on the low 
end of the range of deployment targeted by the CCS Task Force. The 
medium scenario is based on large scale saline project deployment 
projected in the cost analysis prepared for the UIC Class VI final 
rule. The high scenario is based on EPA modeling of the projected 
deployment of CCS under the American Power Act. The national first year 
annual cost estimates increase by $1.3 million under the low outcome; 
$2.5 million under the medium outcome, and $16.8 million under the high 
outcome. In addition to the scenarios above, EPA also considered 
scenarios of the number of ER operations that would choose to report as 
facilities conducting GS (ER opt in) in Section 5.2.1 of the final EIA. 
In the medium scenario, all anthropogenic CO<INF>2</INF> projects (16) 
choose to report as facilities conducting GS (ER opt in) (Subpart RR). 
In the high scenario, all anthropogenic CO<INF>2</INF> projects (16) 
and fifty percent of other CO<INF>2</INF> projects (32) choose to 
report as facilities conducting GS (ER opt in) (Subpart RR). The 
national cost estimate is $35 million under the medium ER opt in 
outcome (first year) and $33 million in subsequent years. The national 
cost estimate is $103 million under the high ER opt in outcome (first 
year) and $97 million in subsequent years.
    To understand these numbers in context, EPA used the estimates of 
cost by facility type shown in Table 5. The large scale saline aquifer 
GS (commercial saline) projects in the American Power Act scenario are 
assumed to be facilities that conduct GS, with an estimated cost of 
$318,000 for the first year and $240,000 for subsequent years. The ER 
opt in scenario used the `Facilities Conducting GS (ER opt in)' project 
cost, with an estimated cost of $2.1 million for the first year and 
$2.0 million for the subsequent year. The basis for these cost 
estimates is explained in detail in Section 4 of the EIA (EPA-HQ-OAR-
2009-0926). The principal driver in the difference in national costs 
for these scenarios is the type of project assumed to be reporting.
    EPA used the same first year, subsequent year methodology for these 
cost scenarios that was used in the core national cost analysis. This 
assumes that the number of projects in a given scenario all opt in or 
begin required reporting in year 1. This assumption overestimates the 
national cost under these scenarios, as it is more likely that projects 
will opt in or begin required reporting over a long period of time.

D. What are the impacts of the rule on small businesses?

1. Summary of Impacts on Small Businesses
    As required by the RFA and the Small Business Regulatory 
Enforcement and Fairness ACT (SBREFA), EPA assessed the potential 
impacts of the rule on small entities (small businesses, governments, 
and non-profit organizations). (See Section IV.C of this preamble for 
definitions of small entities.)
    After considering the economic impact of the rule on small 
entities, EPA has concluded that this action will not have a 
significant economic impact on a substantial number of small entities. 
Currently EPA has determined that small ER operations will most likely 
be UIC Class II ER projects that do not opt in to subpart RR. As shown 
in Table 6 of this preamble, the average ratio of annualized reporting 
program costs to revenues of a typical ER operation likely owned by a 
representative small enterprise and reporting under subpart UU was less 
than 0.1 percent.
    Although this rule will not have a significant economic impact on a 
substantial number of small entities, EPA nonetheless took several 
steps to reduce the impact of this rule on small entities. For example, 
EPA's monitoring and reporting requirements are built off of the UIC 
program. In addition, EPA is requiring equipment and methods that may 
already be in use by a facility for compliance with its UIC permit. 
Also, EPA is requiring annual reporting instead of more frequent 
reporting.

E. What are the benefits of the rule for society?

    EPA examined the potential benefits of this rule. EPA's previous 
analysis of the GHG Reporting Program discussed the benefits of a 
reporting system with respect to policy making relevance, transparency 
issues, and market efficiency. Instead of a quantitative analysis of 
the benefits, EPA conducted a systematic literature review of existing 
studies, including government, consulting, and scholarly reports.

[[Page 75075]]

    The greatest benefit of mandatory reporting of industry GHG 
emissions to government will be realized in developing future GHG 
policies.
    Benefits to industry of GHG emissions monitoring include the value 
of having independent, verifiable data to present to the public to 
demonstrate appropriate environmental stewardship, and a better 
understanding of their emission levels and sources to identify 
opportunities to reduce emissions. Such monitoring allows for inclusion 
of standardized GHG data into environmental management systems, 
providing the necessary information to achieve and disseminate their 
environmental achievements.
    Standardization will also be a benefit to industry. Once facilities 
invest in the institutional knowledge and systems to report emissions, 
the cost of monitoring should fall and the accuracy of the accounting 
should improve. A standardized reporting program will also allow for 
facilities to benchmark themselves against similar facilities to 
understand better their relative standing within their industry.

IV. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review

    Under Executive Order (EO) 12866 (58 FR 51735, October 4, 1993), 
this action is a ``significant regulatory action'' because it may raise 
novel legal or policy issues arising out of legal mandates, the 
President's priorities, or the principles set forth in the EO. 
Accordingly, EPA submitted this action to the Office of Management and 
Budget (OMB) for review under EO 12866 and any changes made in response 
to OMB recommendations have been documented in the docket for this 
action.
    EPA prepared an analysis of the potential costs and benefits 
associated with this action in the EIA (EPA-HQ-OAR-2009-0926). A copy 
of the analysis is available in the docket for this action and the 
analysis is briefly summarized here. In the EIA, EPA has identified the 
regulatory options considered, their costs, and the emissions that 
would likely be reported under each option, and explained the selection 
of the option chosen for the rule. The costs of the rule are reported 
in Section 4 of the EIA, and the economic impacts and qualitative 
benefits assessment are reported in Section 5 of the EIA. Overall, EPA 
has concluded that the costs of the Injection and Geologic 
Sequestration of Carbon Dioxide Reporting Rule are justified by the 
potential benefits of more comprehensive information about 
CO<INF>2</INF> injection. In the absence of new climate policy, the 
total annualized cost of the rule will be approximately $1.1 million 
(in 2008$) during the first year of the program and $1.0 million in 
subsequent years (including $344,000 of programmatic costs to the 
Agency). The baseline used to calculate these costs assume 1 facility 
conducting GS reporting under subpart RR and 92 facilities conducting 
CO<INF>2</INF> injection reporting under subpart UU. This national cost 
estimate is described in detail in Section 5.2 of the final EIA.

B. Paperwork Reduction Act

    The information collection requirements in this final rule have 
been submitted for approval to the Office of Management and Budget 
(OMB) under the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. The 
Information Collection Request (ICR) document prepared by EPA has been 
assigned EPA ICR number 2372.02.
    EPA has identified the following goals of the GHG reporting system:
    X Obtain data that is of sufficient quality that it can be used to 
analyze and inform the development of a range of future climate change 
policies and potential regulations.
    X Create reporting requirements that are, to the extent possible 
and appropriate, consistent with existing GHG reporting programs in 
order to reduce reporting burden for all parties involved.
    The information from CO<INF>2</INF> injection and geologic 
sequestration facilities will allow EPA to make well-informed decisions 
about whether and how to use the CAA to regulate these facilities and 
encourage voluntary reductions. Because EPA does not yet know the 
specific policies that will be adopted, the data reported through the 
mandatory reporting system should be of sufficient quality to inform 
policy and program development. Also, consistent with the 
Appropriations Act, the reporting rule covers a broad range of sectors 
of the economy including sites that inject and store CO<INF>2</INF>.
    This information collection is mandatory and will be carried out 
under CAA section 114. Information identified and marked as CBI will 
not be disclosed except in accordance with procedures set forth in 40 
CFR part 2. However, emissions information collected under CAA section 
114 generally cannot be claimed as CBI and will be made public.\14\
---------------------------------------------------------------------------

    \14\ Although CBI determinations are usually made on a case-by-
case basis, on July 7, 2010, EPA published a proposed rule (75 FR 
39094) relating to CBI determinations for the data collected under 
the GHG Reporting Program (40 CFR part 98).
---------------------------------------------------------------------------

    The projected cost and hour burden for non-Federal respondents is 
$7.0 million and 9,416 hours per year. The estimated average burden per 
response is 56.6 hours; the frequency of response is annual for all 
respondents that must comply with the rule's reporting requirements, 
except for electricity-generating units that are already required to 
report quarterly under 40 CFR part 75 (acid rain program); and the 
estimated average number of likely respondents per year is 93. The cost 
burden to respondents resulting from the collection of information 
includes the total capital and start-up cost annualized over the 
equipment's expected useful life (averaging $717,000 per year) a total 
operation and maintenance component (averaging $5.3 million per year), 
and a labor cost component (averaging $1.0 million per year). Burden is 
defined at 5 CFR part 1320.3(b). Although not included in the primary 
economic analysis, the costs and burdens to the ER opt ins were 
estimated using an alternate cost scenario and in this section EPA is 
giving its best estimates of likely costs and burdens, including to 
voluntary reporters, as required by the Paperwork Reduction Act. These 
cost numbers differ from those shown elsewhere in the EIA for this 
final rule because ICR costs represent the average cost over the first 
three years of the rule, but costs are reported elsewhere in the EIA 
for the first year of the rule and for subsequent years of the rule. 
Also, the ICR focuses on respondent burden only, while the EIA for this 
final rule includes EPA Agency costs as well. An agency may not conduct 
or sponsor, and a person is not required to respond to, a collection of 
information unless it displays a currently valid OMB control number. 
The OMB control numbers for EPA's regulations in 40 CFR are listed in 
40 CFR part 9. When this ICR is approved by OMB, the Agency will 
publish a technical amendment to 40 CFR part 9 in the Federal Register 
to display the OMB control number for the approved information 
collection requirements contained in this final rule.

C. Regulatory Flexibility Act (RFA)

    The RFA generally requires an agency to prepare a regulatory 
flexibility analysis of any rule subject to notice and comment 
rulemaking requirements under the Administrative Procedure Act or any 
other statute unless the agency certifies that the rule will not have a 
significant economic impact on a

[[Page 75076]]

substantial number of small entities. Small entities include small 
businesses, small organizations, and small governmental jurisdictions.
    For purposes of assessing the impacts of today's rule on small 
entities, small entity is defined as: (1) A small business as defined 
by the Small Business Administration's regulations at 13 CFR 121.201; 
(2) a small governmental jurisdiction that is a government of a city, 
county, town, school district or special district with a population of 
less than 50,000; and (3) a small organization that is any not-for-
profit enterprise which is independently owned and operated and is not 
dominant in its field.
    After considering the economic impacts of this final rule on small 
entities, I certify that this rule will not have a significant economic 
impact on a substantial number of small entities. Currently EPA has 
determined that small ER operations will most likely be facilities 
conducting CO<INF>2</INF> injection only, including UIC Class II ER 
projects, which are only required to report under subpart UU. The 
average ratio of annualized reporting program costs to revenues of a 
typical ER operation likely owned by representative small enterprises 
is less than 1 percent.
    Although this final rule will not have a significant economic 
impact on a substantial number of small entities, EPA nonetheless took 
several steps to reduce the impact of this rule on small entities. For 
example, monitoring and reporting requirements are built off of the UIC 
program. In addition, EPA is requiring equipment and methods that may 
already be in use by a facility for compliance with its UIC permit. 
Also, EPA is requiring annual reporting instead of more frequent 
reporting.
    During rule implementation, EPA will maintain an ``open door'' 
policy for stakeholders to ask questions about the rule or provide 
suggestions to EPA about the types of compliance assistance that will 
be useful to small businesses. EPA intends to develop a range of 
compliance assistance tools and materials and conduct extensive 
outreach for this final rule.

D. Unfunded Mandates Reform Act (UMRA)

    Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public 
Law 104-4, establishes requirements for Federal agencies to assess the 
effects of their regulatory actions on State, local, and Tribal 
governments and the private sector. Under CAA section 202 of the UMRA, 
EPA generally must prepare a written statement, including a cost-
benefit analysis, for final rules with ``Federal mandates'' that may 
result in expenditures to State, local, and Tribal governments, in the 
aggregate, or to the private sector, of $100 million or more in any one 
year.
    This final rule does not contain a Federal mandate that may result 
in expenditures of $100 million or more for State, local, and Tribal 
governments, in the aggregate, or the private sector in any one year. 
Overall, EPA estimates that the total annualized costs of this final 
rule are approximately $1.1 million (in 2008$) during the first year of 
the program and $1.0 million in subsequent years (including $344,000 of 
programmatic costs to the Agency). Thus, this final rule is not subject 
to the requirements of CAA sections 202 or 205 of the UMRA.
    This final rule is also not subject to the requirements of CAA 
section 203 of the UMRA because it contains no regulatory requirements 
that might significantly or uniquely affect small governments. 
Facilities subject to this final rule include facilities that inject 
CO<INF>2</INF> for enhanced recovery, and those that sequester 
CO<INF>2</INF>. None of the facilities currently known to undertake 
these activities are owned by small governments.

E. Executive Order 13132: Federalism

    Executive Order 13132, entitled ``Federalism'' (64 FR 43255, August 
10, 1999), requires EPA to develop an accountable process to ensure 
``meaningful and timely input by State and local officials in the 
development of regulatory policies that have Federalism implications.'' 
``Policies that have Federalism implications'' is defined in the EO to 
include regulations that have ``substantial direct effects on the 
States, on the relationship between the national government and the 
States, or on the distribution of power and responsibilities among the 
various levels of government.''
    This final rule does not have Federalism implications. It will not 
have substantial direct effects on the States, on the relationship 
between the national government and the States, or on the distribution 
of power and responsibilities among the various levels of government, 
as specified in EO 13132.
    This regulation applies to public- or private-sector facilities 
that inject CO<INF>2</INF> underground. Few government facilities would 
be affected. This regulation applies directly to facilities that inject 
CO<INF>2</INF> underground. It does not apply to governmental entities 
unless the government entity owns a facility that injects and/or 
sequesters CO<INF>2</INF> underground. This regulation also does not 
limit the power of States or localities to collect GHG data and/or 
regulate GHG emissions. Thus, EO 13132 does not apply to this final 
rule. However, as it is EPA's policy to promote communication between 
the Agency and State and local governments, EPA specifically solicited 
comments on the proposed rule from State and local officials.

F. Executive Order 13175: Consultation and Coordination With Indian 
Tribal Governments

    Executive Order 13175, entitled ``Consultation and Coordination 
with Indian Tribal Governments'' (59 FR 22951, November 6, 2000), 
requires EPA to develop an accountable process to ensure ``meaningful 
and timely input by Tribal officials in the development of regulatory 
policies that have Tribal implications.''
    This action does not have Tribal implications, as specified in EO 
13175 (65 FR 67249, November 9, 2000). This regulation applies directly 
to facilities that inject and/or sequester CO<INF>2</INF> underground. 
EPA analyzed the facilities expected to be affected by this rule and 
did not find that any facilities expected to be affected by the rule 
are likely to be owned by tribal governments. In addition, EPA did not 
hear from any Tribal governments contradicting this analysis. Thus, EO 
13175 does not apply to this final rule.
    Although EO 13175 does not apply to this final rule, EPA sought 
opportunities to provide information to Tribal governments and 
representatives during development of the GHG reporting rule. In 
consultation with EPA's American Indian Environment Office, EPA's 
outreach plan included tribes. EPA conducted several conference calls 
with Tribal organizations during the proposal phase of the GHG 
reporting rule. For example, EPA staff provided information to tribes 
through conference calls with multiple Tribal working groups and 
organizations at EPA that interact with tribes and through individual 
calls with two Tribal board members of the Climate Registry (TCR). In 
addition, EPA prepared a short article on the GHG reporting rule that 
appeared on the front page of a Tribal newsletter--Tribal Air News--
that was distributed to EPA/Office of Air Quality Planning & Standards' 
network of Tribal organizations. EPA gave a presentation on various 
climate efforts, including the GHG Reporting Program, at the National 
Tribal Conference on Environmental Management on June 24-26, 2008. In 
addition, EPA had copies of a short information sheet distributed at a 
meeting of the National Tribal Caucus.

[[Page 75077]]

See the ``Summary of EPA Outreach Activities for Developing the GHG 
reporting rule,'' in Docket No. EPA-HQ-OAR-2008-0508-055 for a complete 
list of Tribal contacts. EPA participated in a conference call with 
Tribal air coordinators in April 2009 and prepared a guidance sheet for 
Tribal governments on the proposed GHG reporting rule. It was posted on 
the GHG Reporting Program website and published in the Tribal Air 
Newsletter.

G. Executive Order 13045: Protection of Children From Environmental 
Health Risks and Safety Risks

    This action is not subject to EO 13045 because it does not 
establish an environmental standard intended to mitigate health or 
safety risks, and it is not an economically significant regulatory 
action under EO 12866.

H. Executive Order 13211: Actions That Significantly Affect Energy 
Supply, Distribution, or Use

    This final rule is not a ``significant energy action'' as defined 
in EO 13211 (66 FR 28355, May 22, 2001) because it is not likely to 
have a significant adverse effect on the supply, distribution, or use 
of energy. Further, EPA has concluded that this rule is not likely to 
have any adverse energy effects. This final rule relates to monitoring, 
reporting and recordkeeping at facilities that inject and/or sequester 
CO<INF>2</INF> underground and does not impact energy supply, 
distribution or use. Oil and gas operations that use CO<INF>2</INF>-ER 
are only required to report under subpart UU, unless they opt into 
subpart RR to establish that CO<INF>2</INF> is being geologically 
sequestered. Therefore, we conclude that this rule is not likely to 
have any adverse effects on energy supply, distribution, or use.

I. National Technology Transfer and Advancement Act

    Section 12(d) of the National Technology Transfer and Advancement 
Act of 1995 (NTTAA), Public Law 104-113 (15 U.S.C. 272 note) directs 
EPA to use voluntary consensus standards in its regulatory activities 
unless to do so would be inconsistent with applicable law or otherwise 
impractical. Voluntary consensus standards are technical standards 
(e.g., materials specifications, test methods, sampling procedures, and 
business practices) that are developed or adopted by voluntary 
consensus standards bodies. NTTAA directs EPA to provide Congress, 
through OMB, with explanations when the Agency decides not to use 
available and applicable voluntary consensus standards. This rulemaking 
involves technical standards. EPA developed no new measuring device 
standard. Rather we allow the use of an appropriate standard method 
published by a consensus-based standards organization if such a method 
exists; or an industry standard practice.

J. Executive Order 12898: Federal Actions To Address Environmental 
Justice in Minority Populations and Low-Income Populations

    Executive Order 12898 (59 FR 7629, February 16, 1994) establishes 
Federal executive policy on environmental justice. Its main provision 
directs Federal agencies, to the greatest extent practicable and 
permitted by law, to make environmental justice part of their mission 
by identifying and addressing, as appropriate, disproportionately high 
and adverse human health or environmental effects of their programs, 
policies, and activities on minority populations and low-income 
populations in the United States.
    EPA has determined that the final rule will not have 
disproportionately high and adverse human health or environmental 
effects on minority or low-income populations because it does not 
affect the level of protection provided to human health or the 
environment. The final rule does not affect the level of protection 
provided to human health or the environment because it is a rule 
addressing information collection and reporting procedures only.

K. Congressional Review Act

    The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the 
Small Business Regulatory Enforcement Fairness Act of 1996, generally 
provides that before a rule may take effect, the agency promulgating 
the rule must submit a rule report, which includes a copy of the rule, 
to each House of the Congress and to the Comptroller General of the 
United States. EPA will submit a report containing this rule and other 
required information to the U.S. Senate, the U.S. House of 
Representatives, and the Comptroller General of the U.S. prior to 
publication of the rule in the Federal Register. A major rule cannot 
take effect until 60 days after it is published in the Federal 
Register. This action is not a ``major rule'' as defined by 5 U.S.C. 
804(2). This rule will be effective December 31, 2010.

List of Subjects

40 CFR Part 72

    Acid rain, Administrative practice and procedure, Air pollution 
control, Electric utilities, Intergovernmental relations, Nitrogen 
oxides, Reporting and recordkeeping requirements, Sulfur dioxide.

40 CFR Part 78

    Acid rain, Administrative practice and procedure, Air pollution 
control, Electric utilities, Intergovernmental relations, Nitrogen 
oxides, Reporting and recordkeeping requirements, Sulfur dioxide.

40 CFR Part 98

    Environmental protection, Administrative practice and procedure, 
Greenhouse gases, Air pollution control, Reporting and recordkeeping 
requirements.

    Dated: November 22, 2010.
Lisa P. Jackson,
Administrator.

0
For the reasons stated in the preamble, parts 72, 78, and 98 of title 
40, chapter I, of the Code of Federal Regulations are amended as 
follows:

PART 72--[AMENDED]

0
1. The authority citation for part 72 is revised to read as follows:

    Authority: 42 U.S.C. 7401, 7403, 7410, 7411, 7426, 7601, et seq.


0
2. Section 72.2 is amended by revising the definition for ``interested 
person'' to read as follows:


Sec.  72.2  Definitions.

* * * * *
    Interested person means, with regard to a decision of the 
Administrator, any person who submitted comments or testified at a 
public hearing pursuant to an opportunity for comment provided by the 
Administrator as part of the process of making such decision, who 
submitted objections pursuant to an opportunity for objections provided 
by the Administrator as part of the process of making such decision, or 
who submitted (to the Administrator and in a format specified by the 
Administrator) his or her name to be placed on a list of persons 
interested in such decision. The Administrator may update the list of 
interested persons from time to time by requesting additional written 
indication of continued interest from the persons listed and may delete 
from the list the name of any person failing to respond as requested.
* * * * *

PART 78--[AMENDED]

0
3. The authority citation for part 78 continues to read as follows:

    Authority: 42 U.S.C. 7401, 7403, 7410, 7411, 7426, 7601, et seq.


[[Page 75078]]



0
4. Section 78.1 is amended by:
0
a. Removing, in paragraph (a)(1), the words ``or part 97 of this 
chapter'' and adding, in their place, the words ``part 97 of this 
chapter, or subpart RR of part 98.''
0
b. Adding and reserving paragraphs (b)(13) through (b)(16).
0
c. Adding paragraph (b)(17) to read as follows.


Sec.  78.1  Purpose and scope.

* * * * *
    (b) * * *
    (13)-(16) [Reserved]
    (17) Under subpart RR of part 98 of this chapter,
    (i) A determination of eligibility for research and development 
exemption under Sec.  98.440(d) of this chapter.
    (ii) The approval or disapproval of a request for discontinuation 
of reporting under Sec.  98.441(b) of this chapter.
    (iii) The approval or disapproval of a geologic sequestration 
monitoring, reporting, and verification (MRV) plan under Sec.  
98.448(c) and Sec.  98.448(d) of this chapter.
* * * * *

0
5. Section 78.3 is amended by:
0
a. Adding and reserving paragraph (a)(10).
0
b. Adding paragraph (a)(11).
0
c. In paragraph (b)(3)(i), removing the words ``paragraph (a)(1) and 
(2)'' and adding, in their place, the words ``paragraphs (a)(1), 
(a)(2), (a)(10), and (a)(11)''.
0
d. Adding and reserving paragraph (d)(11).
0
e. Adding paragraph (d)(12).


Sec.  78.3  Petition for administrative review and request or 
evidentiary hearing.

    (a) * * *
    (10) [Reserved]
    (11) The following persons may petition for administrative review 
of a decision of the Administrator that is made under subpart RR of 
part 98 of this chapter:
    (i) The owner or operator of a facility covered by the decision.
    (ii) Any interested person with regard to the decision.
* * * * *
    (d) * * *
    (11) [Reserved]
    (12) Any provision or requirement of subpart RR of part 98 of this 
chapter.

0
6. Section 78.4 is amended by:
0
a. Adding and reserving paragraphs (a)(1) introductory text, (a)(1)(i), 
(a)(1)(ii), and (a)(1)(iii).
0
b. Adding paragraph (a)(1)(iv).
0
c. Adding and reserving paragraph (a)(2).


Sec.  78.4  Filings.

    (a) * * *
    (1) [Reserved]
    (i) [Reserved]
    (ii) [Reserved]
    (iii) [Reserved]
    (iv) Any filings on behalf of owners and operators of a facility 
covered by subpart RR of part 98 of this chapter shall be signed by the 
designated representative.
    (2) [Reserved]
* * * * *

PART 98--[AMENDED]

0
7. The authority citation for part 98 continues to read as follows:

    Authority: 42 U.S.C. 7401-7671q.

Subpart A--[Amended]

0
8. Table A-3 to subpart A is amended by adding entries to the end of 
the table for ``Geologic sequestration of carbon dioxide'' and 
``Injection of carbon dioxide'' to read as follows:

   Table A-3 of Subpart A--Source Category List for Sec.   98.2(a)(1)
------------------------------------------------------------------------
 
-------------------------------------------------------------------------
Source Categories \a\ Applicable in 2010 and Future Years
 
                                * * * * *
Additional Source Categories \a\ Applicable in 2011 and Future Years
 
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Geologic sequestration of carbon dioxide (subpart RR).
Injection of carbon dioxide (subpart UU).
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\a\ Source categories are defined in each applicable subpart.


0
9. Part 98 is amended by adding subpart RR to read as follows:
Subpart RR--Geologic Sequestration of Carbon Dioxide
Sec.
98.440 Definition of the source category.
98.441 Reporting threshold.
98.442 GHGs to report.
98.443 Calculating CO2 geologic sequestration.
98.444 Monitoring and QA/QC requirements.
98.445 Procedures for estimating missing data.
98.446 Data reporting requirements.
98.447 Records that must be retained.
98.448 Geologic sequestration monitoring, reporting, and 
verification (MRV) plan.
98.449 Definitions.

Subpart RR--Geologic Sequestration of Carbon Dioxide


Sec.  98.440  Definition of the source category.

    (a) The geologic sequestration of carbon dioxide (CO<INF>2</INF>) 
source category comprises any well or group of wells that inject a 
CO<INF>2</INF> 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<INF>2</INF> 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<INF>2</INF> 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 Sec.  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<INF>2</INF> injection for the 
project.
    (ii) The planned annual CO<INF>2</INF> 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<INF>2</INF> injection for the project and the planned annual 
CO<INF>2</INF> injection volumes during the duration of the project are

[[Page 75079]]

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.


Sec.  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<INF>2</INF> for 
long-term containment in subsurface geologic formations. There is no 
threshold.
    (b) Request for discontinuation of reporting. The requirements of 
Sec.  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<INF>2</INF> 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.


Sec.  98.442  GHGs to report.

    You must report:
    (a) Mass of CO<INF>2</INF> received.
    (b) Mass of CO<INF>2</INF> injected into the subsurface.
    (c) Mass of CO<INF>2</INF> produced.
    (d) Mass of CO<INF>2</INF> emitted by surface leakage.
    (e) Mass of CO<INF>2</INF> equipment leakage and vented 
CO<INF>2</INF> emissions from surface equipment located between the 
injection flow meter and the injection wellhead.
    (f) Mass of CO<INF>2</INF> equipment leakage and vented 
CO<INF>2</INF> emissions from surface equipment located between the 
production flow meter and the production wellhead.
    (g) Mass of CO<INF>2</INF> sequestered in subsurface geologic 
formations.
    (h) Cumulative mass of CO<INF>2</INF> reported as sequestered in 
subsurface geologic formations in all years since the facility became 
subject to reporting requirements under this subpart.


Sec.  98.443  Calculating CO2 geologic sequestration.

    You must calculate the mass of CO<INF>2</INF> received using 
CO<INF>2</INF> received equations (Equations RR-1 to RR-3 of this 
section), unless you follow the procedures in Sec.  98.444(a)(4). You 
must calculate CO<INF>2</INF> 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<INF>2</INF> sequestered starting from 
the date set forth in your approved MRV plan.
    (a) You must calculate and report the annual mass of CO<INF>2</INF> 
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<INF>2</INF> in a CO<INF>2</INF> stream received in metric tons by 
multiplying the mass flow by the CO<INF>2</INF> 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 Sec.  98.444.
[GRAPHIC] [TIFF OMITTED] TR01DE10.172

Where:

CO<INF>2T,r</INF> = Net annual mass of CO<INF>2</INF> received 
through flow meter r (metric tons).
Q<INF>r,p</INF> = Quarterly mass flow through a receiving flow meter 
r in quarter p (metric tons).
S<INF>r,p</INF> = Quarterly 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<INF>CO2,p,r</INF> = Quarterly CO<INF>2</INF> concentration 
measurement in flow for flow meter r in quarter p (wt. percent 
CO<INF>2</INF>, expressed as a decimal fraction).
p = Quarter of the year.
r = Receiving flow meter.

    (2) For a volumetric flow meter, you must calculate the total 
annual mass of CO<INF>2</INF> in a CO<INF>2</INF> stream received in 
metric tons by multiplying the volumetric flow at standard conditions 
by the CO<INF>2</INF> concentration in the flow and the density of 
CO<INF>2</INF> 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 
Sec.  98.444.
[GRAPHIC] [TIFF OMITTED] TR01DE10.173

Where:

CO<INF>2T,r</INF> = Net annual mass of CO<INF>2</INF> received 
through flow meter r (metric tons).
Q<INF>r,p</INF> = Quarterly volumetric flow through a receiving flow 
meter r in quarter p at standard conditions (standard cubic meters).

[[Page 75080]]

S<INF>r,p</INF> = Quarterly 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 CO<INF>2</INF> at standard conditions (metric tons 
per standard cubic meter): 0.0018682.
C<INF>CO2,p,r</INF> = Quarterly CO<INF>2</INF> concentration 
measurement in flow for flow meter r in quarter p (vol. percent 
CO<INF>2</INF>, expressed as a decimal fraction).
p = Quarter of the year.
r = Receiving flow meter.

    (3) If you receive CO<INF>2</INF> through more than one flow meter, 
you must sum the mass of all CO<INF>2</INF> received in accordance with 
the procedure specified in Equation RR-3 of this section.
[GRAPHIC] [TIFF OMITTED] TR01DE10.174

Where:

CO<INF>2</INF> = Total net annual mass of CO<INF>2</INF> received 
(metric tons).
CO<INF>2T,r</INF> = Net annual mass of CO<INF>2</INF> 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<INF>2</INF> 
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 Sec.  98.444(a)(2)(i), you must calculate the 
CO<INF>2</INF> received for injection in containers using Equation RR-1 
of this section.

Where:

CO<INF>2T,r</INF> = Net annual mass of CO<INF>2</INF> received in 
containers r (metric tons).
C<INF>CO2,p,r</INF> = Quarterly CO<INF>2</INF> concentration 
measurement of contents in containers r in quarter p (wt. percent 
CO<INF>2</INF>, expressed as a decimal fraction).
Q<INF>r,p</INF> = Quarterly mass of contents in containers r in 
quarter p (metric tons).
S<INF>r,p</INF> = Quarterly mass of contents in containers r 
redelivered to another facility without being injected into your 
well in quarter p (metric tons).
p = Quarter of the year.
r = Containers.

    (2) If you are measuring the volume of contents in a container 
under the provisions of Sec.  98.444(a)(2)(ii), you must calculate the 
CO<INF>2</INF> received for injection in containers using Equation RR-2 
of this section.

Where:

CO<INF>2T,r</INF> = Net annual mass of CO<INF>2</INF> received in 
containers r (metric tons).
C<INF>CO2,p,r</INF> = Quarterly CO<INF>2</INF> concentration 
measurement of contents in containers r in quarter p (vol. percent 
CO<INF>2</INF>, expressed as a decimal fraction).
Q<INF>r,p</INF> = Quarterly volume of contents in containers r in 
quarter p (standard cubic meters).
S<INF>r,p</INF> = Quarterly 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<INF>2</INF> received in containers at standard 
conditions (metric tons per standard cubic meter):0.0018682.
p = Quarter of the year.
r = Containers.

    (c) You must report the annual mass of CO<INF>2</INF> 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<INF>2</INF> stream, you must calculate annually the total mass of 
CO<INF>2</INF> (in metric tons) in the CO<INF>2</INF> stream injected 
each year in metric tons by multiplying the mass flow by the 
CO<INF>2</INF> concentration in the flow, according to Equation RR-4 of 
this section. Mass flow and concentration data measurements must be 
made in accordance with Sec.  98.444.
[GRAPHIC] [TIFF OMITTED] TR01DE10.175

Where:

CO<INF>2,u</INF> = Annual CO<INF>2</INF> mass injected (metric tons) 
as measured by flow meter u.
Q<INF>p,u</INF> = Quarterly mass flow rate measurement for flow 
meter u in quarter p (metric tons per quarter).
C<INF>CO2,p,u</INF> = Quarterly CO<INF>2</INF> concentration 
measurement in flow for flow meter u in quarter p (wt. percent 
CO<INF>2</INF>, expressed as a decimal fraction).
p = Quarter of the year.
u = Flow meter.

    (2) If you use a volumetric flow meter to measure the flow of an 
injected CO<INF>2</INF> stream, you must calculate annually the total 
mass of CO<INF>2</INF> (in metric tons) in the CO<INF>2</INF> stream 
injected each year in metric tons by multiplying the volumetric flow at 
standard conditions by the CO<INF>2</INF> concentration in the flow and 
the density of CO<INF>2</INF> at standard conditions, according to 
Equation RR-5 of this section. Volumetric flow and concentration data 
measurements must be made in accordance with Sec.  98.444.
[GRAPHIC] [TIFF OMITTED] TR01DE10.176

Where:

CO<INF>2,u</INF> = Annual CO<INF>2</INF> mass injected (metric tons) 
as measured by flow meter u.
Q<INF>p,u</INF> = Quarterly volumetric flow rate measurement for 
flow meter u in quarter p at standard conditions (standard cubic 
meters per quarter).
D = Density of CO<INF>2</INF> at standard conditions (metric tons 
per standard cubic meter): 0.0018682.
C<INF>CO2,p,u</INF> = CO<INF>2</INF> concentration measurement in 
flow for flow meter u in quarter p (vol. percent CO<INF>2</INF>, 
expressed as a decimal fraction).
p = Quarter of the year.
u = Flow meter.

    (3) To aggregate injection data for all wells covered under this 
subpart, you must sum the mass of all CO<INF>2</INF> injected through 
all injection wells in accordance with the procedure specified in 
Equation RR-6 of this section.
[GRAPHIC] [TIFF OMITTED] TR01DE10.177

Where:

CO<INF>2I</INF> = Total annual CO<INF>2</INF> mass injected (metric 
tons) through all injection wells.
CO<INF>2,u</INF> = Annual CO<INF>2</INF> mass injected (metric tons) 
as measured by flow meter u.
u = Flow meter.

    (d) You must calculate the annual mass of CO<INF>2</INF> 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 only for wells that 
produce the CO<INF>2</INF> 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<INF>2</INF> 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<INF>2</INF> 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 Sec.  98.444.

[[Page 75081]]

[GRAPHIC] [TIFF OMITTED] TR01DE10.178


Where:

CO<INF>2,w</INF> = Annual CO<INF>2</INF> mass produced (metric tons) 
through separator w.
Q<INF>p,w</INF> = Quarterly gas mass flow rate measurement for 
separator w in quarter p (metric tons).
C<INF>CO2,p,w</INF> = Quarterly CO<INF>2</INF> concentration 
measurement in flow for separator w in quarter p (wt. percent 
CO<INF>2</INF>, expressed as a decimal fraction).
p = Quarter of the year.
w = Separator.

    (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<INF>2</INF> 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<INF>2</INF> concentration in the 
gas flow and the density of CO<INF>2</INF> 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 Sec.  98.444.
[GRAPHIC] [TIFF OMITTED] TR01DE10.179

Where:

CO<INF>2,w</INF> = Annual CO<INF>2</INF> mass produced (metric tons) 
through separator w.
Q<INF>p,w</INF> = Volumetric gas flow rate measurement for separator 
w in quarter p at standard conditions (standard cubic meters).
D = Density of CO<INF>2</INF> at standard conditions (metric tons 
per standard cubic meter): 0.0018682.
C<INF>CO2,p,w</INF> = CO<INF>2</INF> concentration measurement in 
flow for separator w in quarter p (vol. percent CO<INF>2</INF>, 
expressed as a decimal fraction).
p = Quarter of the year.
w = Separator.

    (3) To aggregate production data, you must sum the mass of all of 
the CO<INF>2</INF> 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<INF>2</INF> measured at the separator(s) 
represents a percentage of the total CO<INF>2</INF> produced. In order 
to account for the percentage of CO<INF>2</INF> produced that is 
estimated to remain with the produced oil or other fluid, you must 
multiply the quarterly mass of CO<INF>2</INF> measured at the 
separator(s) by a percentage estimated using a methodology in your 
approved MRV plan.
[GRAPHIC] [TIFF OMITTED] TR01DE10.180

Where:

CO<INF>2P</INF> = Total annual CO<INF>2</INF> mass produced (metric 
tons) through all separators in the reporting year.
CO<INF>2,w</INF> = Annual CO<INF>2</INF> mass produced (metric tons) 
through separator w in the reporting year.
X = Entrained CO<INF>2</INF> in produced oil or other fluid divided 
by the CO<INF>2</INF> separated through all separators in the 
reporting year (weight percent CO<INF>2</INF>, expressed as a 
decimal fraction).
w = Separator.

    (e) You must report the annual mass of CO<INF>2</INF> that is 
emitted by surface leakage in accordance with your approved MRV plan. 
You must calculate the total annual mass of CO<INF>2</INF> emitted from 
all leakage pathways in accordance with the procedure specified in 
Equation RR-10 of this section.
[GRAPHIC] [TIFF OMITTED] TR01DE10.181

Where:

CO<INF>2E</INF> = Total annual CO<INF>2</INF> mass emitted by 
surface leakage (metric tons) in the reporting year.
CO<INF>2,x</INF> = Annual CO<INF>2</INF> mass emitted (metric tons) 
at leakage pathway x in the reporting year.
x = Leakage pathway.

    (f) You must report the annual mass of CO<INF>2</INF> 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<INF>2</INF> 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.
[GRAPHIC] [TIFF OMITTED] TR01DE10.182

Where:

CO<INF>2</INF> = Total annual CO<INF>2</INF> mass sequestered in 
subsurface geologic formations (metric tons) at the facility in the 
reporting year.
CO<INF>2I</INF> = Total annual CO<INF>2</INF> mass injected (metric 
tons) in the well or group of wells covered by this source category 
in the reporting year.
CO<INF>2P =</INF> Total annual CO<INF>2</INF> mass produced (metric 
tons) in the reporting year.
CO<INF>2E</INF> = Total annual CO<INF>2</INF> mass emitted (metric 
tons) by surface leakage in the reporting year.
CO<INF>2FI</INF> = Total annual CO<INF>2</INF> mass emitted (metric 
tons) as equipment leakage or vented emissions 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.
CO<INF>2FP</INF> = Total annual CO<INF>2</INF> mass emitted (metric 
tons) as equipment leakage or vented emissions from equipment 
located on the surface between 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

[[Page 75082]]

CO<INF>2</INF> that is sequestered in subsurface geologic formations in 
the reporting year in accordance with the procedures specified in 
Equation RR-12 of this section.
[GRAPHIC] [TIFF OMITTED] TR01DE10.183

Where:

CO<INF>2</INF> = Total annual CO<INF>2</INF> mass sequestered in 
subsurface geologic formations (metric tons) at the facility in the 
reporting year.
CO<INF>2I</INF> = Total annual CO<INF>2</INF> mass injected (metric 
tons) in the well or group of wells covered by this source category 
in the reporting year.
CO<INF>2E</INF> = Total annual CO<INF>2</INF> mass emitted (metric 
tons) by surface leakage in the reporting year.
CO<INF>2FI</INF> = Total annual CO<INF>2</INF> mass emitted (metric 
tons) as equipment leakage or vented emissions from equipment 
located on the surface between the flow meter used to measure 
injection quantity and the injection wellhead.

Sec.  98.444  Monitoring and QA/QC requirements.

    (a) CO2 received.
    (1) Except as provided in paragraph (a)(4) of this section, you 
must determine the quarterly flow rate of CO<INF>2</INF> 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<INF>2</INF> 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<INF>2</INF> received from a production 
process unit that is part of your facility, you may use the quarterly 
CO<INF>2</INF> 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<INF>2</INF> 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<INF>2</INF> 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<INF>2</INF> 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<INF>2</INF> received 
that is representative of all CO<INF>2</INF> received in that quarter 
by following the most appropriate of the following procedures:
    (i) You may sample the CO<INF>2</INF> stream at least once per 
quarter at the point of receipt and measure its CO<INF>2</INF> 
concentration.
    (ii) If you took ownership of the CO<INF>2</INF> in a commercial 
transaction for which the sales contract was contingent on 
CO<INF>2</INF> concentration, and if the supplier of the CO<INF>2</INF> 
sampled the CO<INF>2</INF> stream in a quarter and measured its 
concentration per the sales contract terms, you may use the 
CO<INF>2</INF> concentration data from the sales contract for that 
quarter.
    (iii) If you inject CO<INF>2</INF> from a production process unit 
that is part of your facility, you may report the quarterly 
CO<INF>2</INF> concentration of the CO<INF>2</INF> stream supplied that 
was measured following the procedures provided in subpart PP of this 
part.
    (4) If the CO<INF>2</INF> you receive is wholly injected and is not 
mixed with any other supply of CO<INF>2</INF>, you may report the 
annual mass of CO<INF>2</INF> injected that you determined following 
the requirements under paragraph (b) of this section as the total 
annual mass of CO<INF>2</INF> received instead of using Equation RR-1 
or RR-2 of this subpart to calculate CO<INF>2</INF> received.
    (5) You must assume that the CO<INF>2</INF> you receive meets the 
definition of a CO<INF>2</INF> stream unless you can trace it through 
written records to a source other than a CO<INF>2</INF> stream.
    (b) CO2 injected.
    (1) You must select a point or points of measurement at which the 
CO<INF>2</INF> stream(s) is representative of the CO<INF>2</INF> 
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<INF>2</INF> injected with a 
flow meter and collect the flow rate quarterly.
    (3) You must sample the injected CO<INF>2</INF> stream at least 
once per quarter immediately upstream or downstream of the flow meter 
used to measure flow rate of that CO<INF>2</INF> stream and measure the 
CO<INF>2</INF> concentration of the sample.
    (c) CO2 produced.
    (1) The point of measurement for the quantity of CO<INF>2</INF> 
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<INF>2</INF> 
concentration of the sample.
    (3) You must measure flow rate of gas produced with a flow meter 
and collect the flow rate quarterly.
    (d) CO2 equipment leakage and vented CO2. 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 Sec.  98.446 according to the calibration and accuracy 
requirements in Sec.  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

[[Page 75083]]

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<INF>2</INF> 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<INF>2</INF> 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 Sec.  98.3(d)(1) 
through (2) for best available monitoring methods only for parameters 
required by paragraphs (a) and (b) of Sec.  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 Sec.  
98.3(d)(1) through (2) shall mean 2011.


Sec.  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<INF>2</INF> received that is 
missing must be estimated as follows:
    (1) Another calculation methodology listed in Sec.  98.444(a)(1) 
must be used if possible.
    (2) If another method listed in Sec.  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 Sec.  98.444(a)(2) 
must be used if possible.
    (2) If another method listed in Sec.  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<INF>2</INF> concentration of a CO<INF>2</INF> 
stream received that is missing must be estimated as follows:
    (1) Another calculation methodology listed in Sec.  98.444(a)(3) 
must be used if possible.
    (2) If another method listed in Sec.  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<INF>2</INF> injected that is missing 
must be estimated using a representative quantity of CO<INF>2</INF> 
injected from the nearest previous period of time at a similar 
injection pressure.
    (e) For any values associated with CO<INF>2</INF> equipment leakage 
or vented CO<INF>2</INF> emissions 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<INF>2</INF> produced from 
subsurface geologic formations that is missing must be estimated using 
a representative quantity of CO<INF>2</INF> produced from the nearest 
previous period of time.
    (g) You must estimate the mass of CO<INF>2</INF> 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.


Sec.  98.446  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), report 
the information listed in this section.
    (a) If you receive CO<INF>2</INF> by pipeline, report the following 
for each receiving flow meter:
    (1) The total net mass of CO<INF>2</INF> received (metric tons) 
annually.
    (2) If a volumetric flow meter is used to receive CO<INF>2</INF> 
report the following unless you reported yes to paragraph (a)(5) 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<INF>2</INF> concentration in the flow (volume percent 
CO<INF>2</INF> expressed as a decimal fraction) in each quarter.
    (3) If a mass flow meter is used to receive CO<INF>2</INF> report 
the following unless you reported yes to paragraph (a)(5) 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<INF>2</INF> concentration in the flow (weight percent 
CO<INF>2</INF> expressed as a decimal fraction) in each quarter.
    (4) If the CO<INF>2</INF> received is wholly injected and not mixed 
with any other supply of CO<INF>2</INF>, report whether you followed 
the procedures in Sec.  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<INF>2</INF> 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<INF>2</INF> of contents in containers 
(volume or wt. percent CO<INF>2</INF> 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<INF>2</INF> received (in metric tons) 
annually.
    (5) The standard or method used to calculate each value in 
paragraphs (b)(1) and (b)(2) 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<INF>2</INF> received (metric tons) through all flow 
meters annually.
    (d) The source of the CO<INF>2</INF> received according to the 
following categories:
    (1) CO<INF>2</INF> 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) Whether you began data collection according to your approved 
MRV plan in a reporting year prior to this annual report submission.
    (f) If you report yes in paragraph (e) of this section, report the 
following. If

[[Page 75084]]

this is your first year of reporting, report the following starting on 
the date you began data collection according to your approved MRV plan.
    (1) For each injection flow meter (mass or volumetric), report:
    (i) The mass of CO<INF>2</INF> injected (metric tons) annually.
    (ii) The CO<INF>2</INF> concentration in flow (volume or weight 
percent CO<INF>2</INF> 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)(i) 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<INF>2</INF> injected (metric tons) in the 
reporting year as calculated in Equation RR-6 of this subpart.
    (3) For CO<INF>2</INF> equipment leakage and vented CO<INF>2</INF> 
emissions, report the following:
    (i) The mass of CO<INF>2</INF> emitted (in metric tons) annually as 
equipment leakage or vented emissions from equipment located on the 
surface between the flow meter used to measure injection quantity and 
the injection wellhead.
    (ii) The mass of CO<INF>2</INF> emitted (in metric tons) annually 
as equipment leakage or vented emissions 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<INF>2</INF> mass produced (metric tons) annually.
    (ii) CO<INF>2</INF> concentration in flow (volume or weight percent 
CO<INF>2</INF> 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<INF>2</INF> in produced oil or other fluid 
divided by the CO<INF>2</INF> separated through all separators in the 
reporting year (weight percent CO<INF>2</INF> 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<INF>2</INF> produced in the reporting year as 
calculated in Equation RR-9 of this subpart.
    (7) For each leakage pathway through which CO<INF>2</INF> emissions 
occurred, report:
    (i) A numerical identifier for the leakage pathway.
    (ii) The CO<INF>2</INF> (metric tons) emitted through that pathway 
in the reporting year.
    (8) Annual CO<INF>2</INF> mass emitted (metric tons) by surface 
leakage in the reporting year as calculated by Equation RR-10 of this 
subpart.
    (9) Annual CO<INF>2</INF> (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<INF>2</INF> (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 Sec.  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<INF>2</INF>, 
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<INF>2</INF> 
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.


Sec.  98.447  Records that must be retained.

    (a) You must follow the record retention requirements specified by 
Sec.  98.3(g). In addition to the records required by Sec.  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<INF>2</INF> 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<INF>2</INF>, 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<INF>2</INF> 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<INF>2</INF> emitted by surface leakage from leakage pathways.
    (5) Annual records of information used to calculate the 
CO<INF>2</INF> emitted as equipment leakage or vented emissions 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<INF>2</INF> emitted as equipment leakage or vented emissions 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

[[Page 75085]]

Sec.  98.3(g)(5), by April 1 of the year you begin collecting data.


Sec.  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<INF>2</INF> in the maximum monitoring area and the likelihood, 
magnitude, and timing, of surface leakage of CO<INF>2</INF> through 
these pathways.
    (3) A strategy for detecting and quantifying any surface leakage of 
CO<INF>2</INF>.
    (4) A strategy for establishing the expected baselines for 
monitoring CO<INF>2</INF> 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 equipment leakage 
and vented emissions between the injection flow meter and injection 
well and/or the production flow meter and production well, and 
considerations for calculating CO<INF>2</INF> 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<INF>2</INF> 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<INF>2</INF> 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<INF>2</INF>. 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<INF>2</INF> 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<INF>2</INF> 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) Final 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 Sec.  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.


Sec.  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

[[Page 75086]]

boundary of the active monitoring area is established by superimposing 
two areas:
    (1) The area projected to contain the free phase CO<INF>2</INF> 
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<INF>2</INF> 
plume at the end of year t+5.
    CO2 received the CO<INF>2</INF> stream that you receive to be 
injected for the first time into a well on your facility that is 
covered by this subpart. CO<INF>2</INF> received includes, but is not 
limited to, a CO<INF>2</INF> stream from a production process unit 
inside your facility and a CO<INF>2</INF> 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<INF>2</INF> plume until the 
CO<INF>2</INF> 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 
verification, or engaging in other applied research, that will enable 
safe and effective long-term containment of a CO<INF>2</INF> stream in 
subsurface geologic formations, including research and short duration 
CO<INF>2</INF> 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<INF>2</INF> 
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<INF>4</INF> or CO<INF>2</INF> 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).

0
10. Part 98 is amended by adding subpart UU to read as follows:
Subpart UU--Injection of Carbon Dioxide
Sec.
98.470 Definition of the source category.
98.471 Reporting threshold.
98.472 GHGs to report.
98.473 Calculating CO2 received.
98.474 Monitoring and QA/QC requirements.
98.475 Procedures for estimating missing data.
98.476 Data reporting requirements.
98.477 Records that must be retained.
98.478 Definitions.

Subpart UU--Injection of Carbon Dioxide


Sec.  98.470  Definition of the source category.

    (a) The injection of carbon dioxide (CO<INF>2</INF>) source 
category comprises any well or group of wells that inject a 
CO<INF>2</INF> stream into the subsurface.
    (b) If you report under subpart RR of this part for a well or group 
of wells, you are not required to report under this subpart for that 
well or group of wells.
    (c) A facility that is subject to this part only because it is 
subject to subpart UU of this part is not required to report emissions 
under subpart C of this part or any other subpart listed in Sec.  
98.2(a)(1) or (a)(2).


Sec.  98.471  Reporting threshold.

    (a) You must report under this subpart if your facility injects any 
amount of CO<INF>2</INF> into the subsurface.
    (b) For purposes of this subpart, any reference to CO<INF>2</INF> 
emissions in Sec.  98.2(i) shall mean CO<INF>2</INF> received.


Sec.  98.472  GHGs to report.

    You must report the mass of CO<INF>2</INF> received.


Sec.  98.473  Calculating CO<INF>2</INF> received.

    (a) You must calculate and report the annual mass of CO<INF>2</INF> 
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<INF>2</INF> in a CO<INF>2</INF> stream received in metric tons by 
multiplying the mass flow by the CO<INF>2</INF> 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 Sec.  98.474.
[GRAPHIC] [TIFF OMITTED] TR01DE10.184

Where:

CO<INF>2T,r</INF> = Net annual mass of CO<INF>2</INF> received 
through flow meter r (metric tons).
Q<INF>r,p</INF> = Quarterly mass flow through a receiving flow meter 
r in quarter p (metric tons).
S<INF>r,p</INF> = Quarterly 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<INF>CO2,p,r</INF> = Quarterly CO<INF>2</INF> concentration 
measurement in flow for flow meter r in quarter p (wt. percent 
CO<INF>2</INF>, expressed as a decimal fraction).
p = Quarter of the year.
r = Receiving flow meter.

    (2) For a volumetric flow meter, you must calculate the total 
annual mass of CO<INF>2</INF> in a CO<INF>2</INF> stream received in 
metric tons by multiplying the volumetric flow at standard conditions 
by the CO<INF>2</INF> concentration in the flow and the density of 
CO<INF>2</INF> 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 
Sec.  98.474.

[[Page 75087]]

[GRAPHIC] [TIFF OMITTED] TR01DE10.185

Where:

CO<INF>2T,r</INF> = Net annual mass of CO<INF>2</INF> received 
through flow meter r (metric tons).
Q<INF>r,p</INF> = Quarterly volumetric flow through a receiving flow 
meter r in quarter p at standard conditions (standard cubic meters).
S<INF>r,p</INF> = Quarterly 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 CO<INF>2</INF> at standard conditions (metric tons 
per standard cubic meter): 0.0018704.
C<INF>CO2,p,r</INF> = Quarterly CO<INF>2</INF> concentration 
measurement in flow for flow meter r in quarter p (vol. percent 
CO<INF>2</INF>, expressed as a decimal fraction).
p = Quarter of the year.
r = Receiving flow meter.

    (3) If you receive CO<INF>2</INF> through more than one flow meter, 
you must sum the mass of all CO<INF>2</INF> received in accordance with 
the procedure specified in Equation UU-3 of this section.
[GRAPHIC] [TIFF OMITTED] TR01DE10.186

Where:

CO<INF>2</INF> = Total net annual mass of CO<INF>2</INF> received 
(metric tons).
CO<INF>2T,r</INF> = Net annual mass of CO<INF>2</INF> received 
(metric tons) as calculated in Equation UU-1 or UU-2 for flow meter 
r.
r = Receiving flow meter.

    (b) You must calculate and report the annual mass of CO<INF>2</INF> 
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 Sec.  98.474(a)(2)(i), you must calculate the 
CO<INF>2</INF> received in containers using Equation UU-1 of this 
section.

Where:

CO<INF>2T,r</INF> = Annual mass of CO<INF>2</INF> received in 
containers r (metric tons).
C<INF>CO2,p,r</INF> = Quarterly CO<INF>2</INF> concentration 
measurement of contents in containers r in quarter p (wt. percent 
CO<INF>2</INF>, expressed as a decimal fraction).
Q<INF>r,p</INF> = Quarterly mass of contents in containers r in 
quarter p (metric tons).
S<INF>r,p</INF> = Quarterly mass of contents in containers r that is 
redelivered to another facility without being injected into your 
well in quarter p (standard cubic meters).
p = Quarter of the year.
r = Containers.

    (2) If you are measuring the volume of contents in a container 
under the provisions of Sec.  98.474(a)(2)(ii), you must calculate the 
CO<INF>2</INF> received in containers using Equation UU-2 of this 
section.

Where:

CO<INF>2T,r</INF> = Annual mass of CO<INF>2</INF> received in 
containers r (metric tons).
C<INF>CO2,p,r</INF> = Quarterly CO<INF>2</INF> concentration 
measurement of contents in containers r in quarter p (vol. percent 
CO<INF>2</INF>, expressed as a decimal fraction).
S<INF>r,p</INF> = Quarterly mass of contents in containers r that is 
redelivered to another facility without being injected into your 
well in quarter p (standard cubic meters).
Q<INF>r,p</INF> = Quarterly volume of contents in containers r in 
quarter p (standard cubic meters).
D = Density of the CO<INF>2</INF> received in containers at standard 
conditions (metric tons per standard cubic meter): 0.0018682.
p = Quarter of the year.
r = Containers.

Sec.  98.474  Monitoring and QA/QC requirements.

    (a) CO<INF>2</INF> received.
    (1) You must determine the quarterly flow rate of CO<INF>2</INF> 
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<INF>2</INF> 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<INF>2</INF> from a production process unit 
that is part of your facility, you may use the quarterly CO<INF>2</INF> 
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<INF>2</INF> 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<INF>2</INF> 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<INF>2</INF> 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<INF>2</INF> received that is representative of all CO<INF>2</INF> 
received in that quarter by following the most appropriate of the 
following procedures:
    (i) You may sample the CO<INF>2</INF> stream at least once per 
quarter at the point of receipt and measure its CO<INF>2</INF> 
concentration.
    (ii) If you took ownership of the CO<INF>2</INF> in a commercial 
transaction for which the sales contract was contingent on 
CO<INF>2</INF> concentration, and if the supplier of the CO<INF>2</INF> 
sampled the CO<INF>2</INF> stream in a quarter and measured its 
concentration per the sales contract terms, you may use the 
CO<INF>2</INF> concentration data from the sales contract for that 
quarter.
    (iii) If you inject CO<INF>2</INF> from a production process unit 
that is part of your facility, you may report the quarterly 
CO<INF>2</INF> concentration of the CO<INF>2</INF> stream supplied that 
was measured following procedures provided in subpart PP of this part 
as the quarterly CO<INF>2</INF> concentration of the CO<INF>2</INF> 
stream received.
    (4) You must assume that the CO<INF>2</INF> you receive meets the 
definition of a CO<INF>2</INF> stream unless you can trace it through 
written records to a source other than a CO<INF>2</INF> 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 Sec.  98.476 according to the calibration and accuracy 
requirements in Sec.  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

[[Page 75088]]

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<INF>2</INF> 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<INF>2</INF> to the 
following standard industry temperature and pressure conditions for use 
in Equations 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 Sec.  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 Sec.  98.3(d)(1) through (2) 
shall mean 2011.


Sec.  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 Sec.  98.474(a)(1) 
must be used if possible.
    (2) If another method listed in Sec.  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<INF>2</INF> received in 
containers, the most appropriate of the following missing data 
procedures must be followed:
    (1) Another calculation methodology listed in Sec.  98.474(a)(2) 
must be used if possible.
    (2) If another method listed in Sec.  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<INF>2</INF> concentration, the following missing data 
procedures must be followed:
    (1) Another calculation methodology listed in Sec.  98.474(a)(3) 
must be used if possible.
    (2) If another method listed in Sec.  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.


Sec.  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 Sec.  98.3(c)(4) for this 
subpart. In addition to the information required by Sec.  98.3(c)(1) 
through Sec.  98.3(c)(3) and by Sec.  98.3(c)(5) through Sec.  
98.3(c)(9), you must report the information listed in this section.
    (a) If you receive CO<INF>2</INF> by pipeline, report the following 
for each receiving flow meter:
    (1) The total net mass of CO<INF>2</INF> received (metric tons) 
annually.
    (2) If a volumetric flow meter is used to receive CO<INF>2</INF>:
    (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<INF>2</INF> concentration in the flow (volume percent 
CO<INF>2</INF> expressed as a decimal fraction) in each quarter.
    (3) If a mass flow meter is used to receive CO<INF>2</INF>:
    (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<INF>2</INF> concentration in the flow (weight percent 
CO<INF>2</INF> 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<INF>2</INF> 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<INF>2</INF> of contents in containers 
(volume or weight percent CO<INF>2</INF> 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<INF>2</INF> received (in metric tons) 
annually.
    (5) The standard or method used to calculate each value in 
paragraphs (b)(1) and (b)(2) 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<INF>2</INF> received (metric tons) through all flow 
meters annually.
    (d) The source of the CO<INF>2</INF> received according to the 
following categories:
    (1) CO<INF>2</INF> 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.


Sec.  98.477  Records that must be retained.

    (a) You must follow the record retention requirements specified by 
Sec.  98.3(g). In addition to the records required by Sec.  98.3(g), 
you must retain quarterly records of CO<INF>2</INF> 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 Sec.  
98.3(g)(5), by April 1 of the year you begin collecting data.


Sec.  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<INF>2</INF> received means the CO<INF>2</INF> stream that you 
receive to be injected for the first time into a well on your facility 
that is covered by this subpart. CO<INF>2</INF> received includes, but 
is not limited to, a CO<INF>2</INF> stream from a production process 
unit inside your facility and a CO<INF>2</INF> stream that was injected 
into a well on another facility, removed from a

[[Page 75089]]

discontinued enhanced oil or natural gas or other production well, and 
transferred to your facility.

[FR Doc. 2010-29934 Filed 11-30-10; 8:45 am]
BILLING CODE 6560-50-P