6560-50-P 

ENVIRONMENTAL PROTECTION AGENCY 

40 CFR Parts 72, 78, and 98 

[EPA-HQ-OAR-2009-0926; FRL-] 

RIN 2060-AP88 

Mandatory Reporting of Greenhouse Gases: Injection and 

Geologic Sequestration of Carbon Dioxide 

AGENCY: Environmental Protection Agency (EPA). 

ACTION: Final rule. 

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 [INSERT THE DATE 30 

DAYS AFTER PUBLICATION OF THIS FINAL RULE IN THE FEDERAL 

REGISTER OR DECEMBER 31, 2010, WHICHEVER IS EARLIER]. 

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 www.regulations.gov website. 

Although listed in the index, some information is not 
Page 2 of 156 

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 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 

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: 
Page 3 of 156 

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 (CO2) 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

Projects 

211 Oil and gas extraction 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 
Page 4 of 156 

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 CO2 (i.e., subparts RR 

and UU). If you have questions regarding the applicability 

of this action to a particular facility, consult the 

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 CO2 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 applicable

subpart) 

Other subparts recommended for

review to determine applicability

Geologic Sequestration

of Carbon Dioxide (40

CFR part 98, subpart

RR) 

40 CFR part 98, subpart C

40 CFR part 98, subpart W

40 CFR part 98, subpart PP 
Page 5 of 156 

Source category

(and main applicable

subpart) 

Other subparts recommended for

review to determine applicability

Injection of Carbon

Dioxide (40 CFR part

98, subpart UU) 

40 CFR part 98, subpart C

40 CFR part 98, subpart W

40 CFR part 98, subpart PP 

What is the effective date? The final rule is 

effective on [INSERT THE DATE 30 DAYS AFTER PUBLICATION OF 

THIS FINAL RULE IN THE FEDERAL REGISTER OR DECEMBER 31, 

2010, WHICHEVER IS EARLIER]. 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, 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 [INSERT THE DATE 30 DAYS AFTER PUBLICATION OF THIS FINAL 

RULE IN THE FEDERAL REGISTER OR DECEMBER 31, 2010, 

WHICHEVER IS EARLIER]. 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 
Page 6 of 156 

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 website 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 CO2 that is received. Facilities 

may use best available monitoring methods for calculating 
 

 

Page 7 of 156 

the mass of CO2 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 CO2 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 

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 [INSERT THE DATE 60 DAYS AFTER THE DATE 

OF PUBLICATION IN THE FEDERAL REGISTER]. Under CAA section 

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. 
Page 8 of 156 

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. 
Page 9 of 156 

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 

CO2 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 
Page 10 of 156 

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? 

IV. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review

B. Paperwork Reduction Act 
Page 11 of 156 

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 LowIncome 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 CO2 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. 
Page 12 of 156 

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 
Page 13 of 156 

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 CO2 supplied to the economy. During the public 

comment period on the Part 98 rule establishing that 

requirement, EPA received comments that CO2 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. 
 

Page 14 of 156 

This final rule amends 40 CFR part 98 to add reporting 

requirements covering facilities that conduct geologic 

sequestration of CO2 (40 CFR part 98, subpart RR) and all 

other facilities that conduct injection of CO2 (40 CFR part 

98, subpart UU).2 GS is the long-term containment of a CO2 

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. 

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 nonemissive 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 

CO2 supplied to the economy. 

2

 EPA has moved all definitions, requirements, and procedures for

facilities conducting CO2 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. 
 

Page 15 of 156 

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 CO2 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 
Page 16 of 156 

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 

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. 
 

 

Page 17 of 156 

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 

CO2 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 CO2 for 

the purpose of GS, or long-term storage of CO2 (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 website.3 

EPA designed the reporting requirements under 40 CFR 

part 98, subpart RR with careful consideration of UIC 

3

 http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 
 

Page 18 of 156 

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 CO2 injected. The UIC Class VI rule requires 

owners or operators to continuously monitor the amount of 

CO2 injected and submit semi-annual reports on the monthly 

amount injected. The UIC program requires information on 

the amount injected to ensure appropriate CO2 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 CO2 injected. Data on the 

amount of CO2 injected is a component of the 40 CFR part 98, 

subpart RR mass balance approach4 used to quantify the 

amount of CO2 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. 

4

 The subpart RR mass balance equation for quantifying the amount of CO2 

that is geologically sequestered includes variables on injected CO2;

equipment leaks and vented CO2 emissions from surface equipment between

the flow meters and the wellhead; CO2 produced and/or remaining with

produced oil, gas or other fluids; and CO2 leakage to the surface. For 

more information, see Section II.B of this preamble. 
 

Page 19 of 156 

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 CO2 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 CO2 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 plan5 to detect and quantify 

leakage of injected CO2 to the surface in the event leakage 

occurs and to report the amount of CO2 geologically 

sequestered using a mass balance approach, regardless of 

the class of UIC permit that a facility holds. 

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 

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 CO2 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 CO2 in produced fluids.

For more information, see Section II.B of this preamble. 
 

Page 20 of 156 

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 CO2 stream, injection 

pressures, integrity of the injection well, groundwater 

quality and geochemistry, and the position of the CO2 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 CO2 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 CO2 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 
 

Page 21 of 156 

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 emissions from 

surface equipment

between flow meters and 

the wellhead 

Yes N/A 

Quantity of CO2 produced

with oil or natural gas

(ER) or other fluids 

Yes N/A 

Percentage of CO2 

estimated to remain 

with oil (ER) or other

fluids 

Yes N/A 

Quantity of CO2 emitted 

from the subsurface 

Yes N/A 

Quantity of CO2 

sequestered in the

subsurface 

Yes N/A 

Cumulative mass of CO2 

sequestered in the

subsurface 

Yes N/A 

Monitoring plan for

detecting air emissions 

Yes Yes1 

Monitoring plan for

quantifying air

emissions 

Yes N/A 

(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 CO2 surface emissions under 40 CFR part 98, subpart RR. 

EPA is committed to working closely within the agency to 
Page 22 of 156 

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 
 

Page 23 of 156 

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 website.6 

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 2009-837 to provide guidance 

regarding eligibility for the Internal Revenue Code section 

45Q credit for CO2 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 

6

 http://www.epa.gov/climatechange/policy/ccs_task_force.html.

7

 Available at: http://www.irs.gov/irb/2009-44_IRB/ar11.html#d0e1860. 
 

Page 24 of 156 

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. 

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 CO2 and injection of CO2 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 CO2 received, develop 

and implement an EPA-approved MRV plan, and report the 

amount of CO2 sequestered using a mass balance approach, by 

subtracting total CO2 emissions from CO2 injected in the 

reporting year. Other facilities injecting CO2 underground 

report under 40 CFR part 98, subpart UU. 

1. Subpart RR Source Category Definition. 
 

Page 25 of 156 

The 40 CFR part 98, subpart RR source category 

consists of any well or group of wells that inject a CO2 

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. 

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 CO2 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 largescale projects meeting the criteria for an exemption, such 

as the current Regional Carbon Sequestration Partnership 

projects supported by the Office of Fossil Energy at the 

DOE, would be considered R&D for the purposes of this 

8

 Note that R&D projects that are exempted from subpart RR report under

Subpart UU – see discussion below. 
Page 26 of 156 

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 CO2 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 CO2 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 CO2 injection for research, the 

planned annual CO2 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. 
Page 27 of 156 

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 CO2 

injection for the project and the planned annual CO2 

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 CO2 received under subpart UU. The 

cease reporting provisions of §98.2(i) do not apply to 
Page 28 of 156 

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 CO2 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 CO2 received; the mass of CO2 injected; the mass 

of CO2 produced (i.e., mixed with produced oil, gas, or 

other fluids); the mass of CO2 emitted from surface leakage; 

the mass of CO2 equipment leaks and vented CO2 emissions from 

sources between the injection flow meter and the injection 

wellhead or between the production flow meter and the 
Page 29 of 156 

production wellhead; and the mass of CO2 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 CO2 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 CO2 geologically sequestered. First, facilities must 

calculate the annual mass of CO2 injected. From the annual 

mass of CO2 injected, facilities must subtract the mass of 

CO2 emitted from surface leakage, using the site-specific 

procedures in their MRV plan, and the mass of CO2 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 

CO2 produced. Calculation procedures are provided at 40 CFR 

98.443. 
Page 30 of 156 

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 CO2 through 

these pathways in the MMA. 

X A strategy for detecting and quantifying any surface 

leakage of CO2 in the event leakage occurs. 

X An approach for establishing the expected baselines 

for monitoring CO2 surface leakage. 

X A summary of considerations made to calculate sitespecific 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 CO2 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 
 

 

Page 31 of 156 

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 CO2 

plume at the end of the specified time interval plus an all 

around buffer zone of at least 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 CO2 plume five years beyond the specified time 

interval.9 

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 

9

 In some cases, the actual footprint of the free phase CO2 plume and

the area that is projected to contain the free phase CO2 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 CO2 leak moves 

laterally as it approaches the surface. 
 

 

Page 32 of 156 

timing, of surface leakage of CO2 through these pathways. 

Possible conduits for CO2 leakage include faults, fractures, 

and abandoned wells.10 

Third, the MRV plan must describe the strategy for 

detecting and quantifying surface leakage of CO2 in the 

event leakage occurs. It should include a description of 

the approach for determining whether surface leakage has 

occurred, an explanation of how CO2 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 

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. 
Page 33 of 156 

to leakage of injected CO2 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 CO2 leakages. 

These indicator parameters may be environmental such as 

subsurface pressure, soil CO2 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 

CO2 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 CO2 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 
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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 website, 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 
Page 35 of 156 

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 CO2 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 
Page 36 of 156 

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 CO2 received and 

the cumulative amount of CO2 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 CO2 equipment leaks 

and vented CO2 emissions to the extent they are a component 
Page 37 of 156 

of the GS mass balance. Subpart RR does not require 

reporting of CO2 equipment leaks and vented CO2 emissions 

from all surface equipment located within the facility 

(e.g., operational emissions not related to the CO2 being 

injected); however, GS projects that produce oil or natural 

gas may be required to report CO2 equipment leaks and vented 

CO2 emissions in the petroleum and natural 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 CO2 

received; injected CO2; produced CO2; CO2 emitted by surface 

leakage; CO2 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 
Page 38 of 156 

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 
Page 39 of 156 

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 CO2 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 

CO2 stream into the subsurface. This includes any wells 
Page 40 of 156 

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 CO2 underground must report 

under this subpart (except those in subpart RR), regardless 

of the amount of emissions from the facility or the amount 

of CO2 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 CO2 emissions in 40 CFR 98.2(i) 

means CO2 received. 

3. Subpart UU GHGs to Report. 

Facilities covered by this source category must report 

the annual mass of CO2 received. 

4. Subpart UU GHG Calculations and Monitoring. 

Facilities covered by this source category must 

calculate the annual mass of CO2 received using the 

calculation procedures for either mass or volumetric flow 

meters. Where CO2 is received in containers, facilities 
Page 41 of 156 

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 CO2 received, 

facilities must report the source of the CO2. 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 CO2 

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.” 

EPA has moved all definitions, requirements, and 

procedures for facilities conducting CO2 injection only 

X 
Page 42 of 156 

(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 CO2 injected in 40 CFR part 98, subpart UU 

(Tier 1) but retained requirements that facilities subject 

to this subpart report the amount of CO2 received and the 

source of CO2 if known. 

X EPA has established procedures for calculating CO2 

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 vented emissions for all 

other surface equipment. 
Page 43 of 156 

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 CO2 

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 
Page 44 of 156 

facilities conducting CO2 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 CO2 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 CO2 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 
Page 45 of 156 

will prove valuable to the Agency in several areas, 

including reconciling 40 CFR part 98, subpart UU data on CO2 

received with CO2 supply data to better understand the 

amount of CO2 supply that is used for CO2 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 CO2 injection without GS (Tier 1) and CO2 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 
Page 46 of 156 

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 

CO2 injection, to CO2 injection with GS only, or to CO2 

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” 
 

Page 47 of 156 

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 CO2 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. 

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 CO2 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 

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). 
Page 48 of 156 

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 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 CO2 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 
Page 49 of 156 

on the list, even if they also operate wells that inject CO2 

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 CO2 storage, CO2 transportation or 

distribution, CO2 purification, compression, or processing, 

CO2 capture, and CO2 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 
Page 50 of 156 

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 
Page 51 of 156 

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 CO2. 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 CO2 stream in subsurface geologic formations, including 

research conducted as a precursor to long-term storage. 
 

Page 52 of 156 

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 CO2 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 CO2 injection projects 

without GS. These commenters expressed concern that 

collecting any information from business-as-usual ER would 

lead to a misunderstanding of the CO2 material balance at 

such operations. Many stated that data on total CO2 

injected in particular would have no bearing on future 
Page 53 of 156 

policy decisions about GHG emissions and should not be 

collected. Many commenters conceded that data on the 

quantity of “new” CO2 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” CO2 

received, EPA could reasonably estimate the amount of CO2 

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 CO2 material balance, 

and recommended expanding “Tier 1” reporting requirements 

rather than narrowing or removing them. This set of 

comments recommended that data on CO2 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 CO2 end-users 

and the data will be necessary to understand the 

disposition of CO2 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 
 

Page 54 of 156 

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” reporting requirements for CO2 

injection facilities. EPA is requiring reporting under 40 

CFR part 98, subpart UU (previously referred to as “Tier 1” 

facilities) of CO2 received (a term that EPA is defining in 

this final action for what commenters described as “new” 

CO2). EPA is not requiring reporting on total CO2 injection 

under 40 CFR part 98, subpart UU. Reporting on total CO2 

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 CO2 

received is critical for EPA to better understand the 

disposition of CO2 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 CO2 

underground and that many projects in the ER industry could 

successfully verify and report the geologic sequestration 

of CO2 with an EPA-approved MRV plan. By collecting data on 

CO2 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 CO2 to the proposed Tier 1 data 
Page 55 of 156 

requirements. Ultimately, EPA concluded that a CO2 material 

balance is most informative to the Agency from GS projects 

that verify the quantity of CO2 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 CO2 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 “CO2 

transferred onsite from offsite” to “CO2 received” because 

EPA identified at least one configuration where CO2 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). CO2 received from a natural 

source within the same field or basin in which it is 

injected is also included as CO2 received. 
 

Page 56 of 156 

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 CO2 injected in one year 

is not a good indicator of the amount of CO2 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” CO2 received, an injection threshold of 25,000 metric 

tons per year, an injection threshold of 100,000 metric 

tons of CO2 per year, an injection threshold of 2-3 million 

metric tons per year, and an emission threshold of 25,000 

metric tons of CO2 per year. 
 

Page 57 of 156 

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 

CO2 injected in one year is not a good indicator of the 

amount of CO2 injected in the following year and there are 

no monitoring standards or data available to determine the 

amount of CO2 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 CO2 emissions in 40 CFR 98.2(i) 

means CO2 received. The cease reporting requirements of 

§98.2(i) do not apply to subpart RR; the owner or operator 

must continue to comply with all requirements until the 
 

Page 58 of 156 

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 CO2 supply (as reported in Suppliers of CO2, 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 NN12), producers of industrial gases 

(40 CFR part 98, subpart OO), and suppliers of CO2 (40 CFR 

part 98, subpart PP). 

With respect to 40 CFR part 98, subpart UU, EPA has 

estimated the cost for facilities conducting CO2 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 

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. 
Page 59 of 156 

small amounts of CO2 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 CO2 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 CO2 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 W. A number of commenters disagreed with EPA’s 

proposed reporting requirements for fugitive and vented CO2 

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 CO2 injected, and three commenters 

stated that such reporting would unwarrantedly shift CO2 
Page 60 of 156 

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 CO2 

emissions. 

Response: EPA proposed to require the reporting of 

fugitive CO2 emissions (referred to in this final action as 

CO2 equipment leakage) and vented CO2 emissions in order to 

better understand the volume of CO2 equipment leakage and 

vented CO2 emissions from such facilities as compared to the 

amount of CO2 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 CO2 sequestered. 

In the notice of proposed rulemaking, EPA proposed 

that CO2 equipment leakage and vented CO2 emissions be 

included in the GS mass balance calculation if the 

emissions occur downstream of the CO2 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 CO2 that is geologically 

sequestered. In this action, EPA is requiring reporting of 
Page 61 of 156 

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 CO2 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. 
Page 62 of 156 

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 CO2 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 CO2 leak once a leak has been verified. 

Comment: EPA received many comments about the 

procedural aspects of MRV plan approval. Some commenters 

stated that CO2 injection should not be allowed until MRV 
Page 63 of 156 

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 CO2 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 website, 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 
Page 64 of 156 

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 
Page 65 of 156 

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 CO2 sequestered cannot occur under SDWA alone. 

Response: EPA maintains a high-level of coordination 

across EPA offices and regions on GS activities and 

regulatory 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 CO2 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 CO2 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 
Page 66 of 156 

This section of the preamble examines the costs and 

economic impacts of the final rule for CO2 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 CO2. 
Page 67 of 156 

The estimated costs are based on hypothetical or proforma 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 CO2 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. 
 

 

Page 68 of 156 

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 

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 CO2 by 2012, and includes costs for 1 saline GS 

facility reporting under subpart RR, and 92 CO2 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 

13 Bureau of Labor Statistics. http://www.bls.gov/bls/wages.htm 
Page 69 of 156 

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 70 of 156 

Table 4. National Annualized Mandatory Reporting Costs

Estimates (2008$): Subparts RR and UU 

Type 

Reference 

Number 

of 

Projects 

Metric 

Tons CO2 

Received 

per Year 

First Year 

(thousand,

2008$) 

Second Year 

(thousand,

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) (RR)a 

0 0 $0 $0 

Facilities 

Conducting CO2 

Injection (no

GS)(UU)b 

92 48,735,442 $410 $410 

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 

Type 

Reference 

Alternative Cost Scenarios 

Low High

First 

Year 

($1,000) 

Second 

Year 

($1,000) 

First 

Year 

($1,000) 

Second 

Year 

($1,000) 

First 

Year 

($1,000) 

Second 

Year 

($1,000)

R&D (RR) $4 $4 $4 $4 $4 $4 

Facilities 

Conducting

GS (Saline)

(RR) 

$318 $240 $96 $18 $490 $413 

Facilities 

Conducting 

$2,124 $2,005 $1,893 $1,773 $2,271 $2,151 
Page 71 of 156 

Type 

Reference 

Alternative Cost Scenarios 

Low High

First 

Year 

($1,000) 

Second 

Year 

($1,000) 

First 

Year 

($1,000) 

Second 

Year 

($1,000) 

First 

Year 

($1,000) 

Second 

Year 

($1,000)

GS (ER opt

in) (RR)

Facilities 

Conducting

CO2 

Injection

(No GS)

(UU) 

$4 $4 $4 $4 $4 $4 

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 
Page 72 of 156 

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 
 

 

 

Page 73 of 156 

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 CO2 injection (no GS) sales test ratios are 

below 0.01 percent, as illustrated in Table 6 of this 

preamble. 

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 in) (RR) 

3.7% 3.3% 4.0% 

Facilities Conducting CO2 

Injection (No GS) (UU) 

<0.1% <0.1% <0.1% 

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. 
Page 74 of 156 

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. 
 

Page 75 of 156 

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 CO2 projects (16) choose to report as 

facilities conducting GS (ER opt in)(Subpart RR). In the 

high scenario, all anthropogenic CO2 projects (16) and fifty 

percent of other CO2 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 
Page 76 of 156 

$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 
Page 77 of 156 

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 
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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. 

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 
Page 79 of 156 

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-HQOAR-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, 
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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 CO2 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 CO2 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: 
Page 81 of 156 

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 CO2 injection and geologic 

sequestration facilities will allow EPA to make wellinformed 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 CO2. 

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 
 

 

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114 generally cannot be claimed as CBI and will be made 

public.14 

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, 

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). 
Page 83 of 156 

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 substantial number of 
Page 84 of 156 

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 CO2 

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 
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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), P.L. 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. 
Page 86 of 156 

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 CO2 for enhanced recovery, and those that 

sequester CO2. 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.” 
Page 87 of 156 

“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 CO2 underground. Few government 

facilities would be affected. This regulation applies 

directly to facilities that inject CO2 underground. It does 

not apply to governmental entities unless the government 

entity owns a facility that injects and/or sequesters CO2 

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 
Page 88 of 156 

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 CO2 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 
Page 89 of 156 

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. 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 
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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 CO2 underground and does not impact 

energy supply, distribution or use. Oil and gas operations 

that use CO2-ER are only required to report under subpart 

UU, unless they opt into subpart RR to establish that CO2 is 

being geologically sequestered. Therefore, we conclude 

that this rule is not likely to have any adverse effects on 

energy supply, distribution, or use. 
Page 91 of 156 

I. National Technology Transfer and Advancement Act 

Section 12(d) of the National Technology Transfer and 

Advancement Act of 1995 (NTTAA), Public Law No. 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 consensusbased 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 LowIncome Populations 

Executive Order 12898 (59 FR 7629, February 16, 1994) 

establishes Federal executive policy on environmental 

justice. Its main provision directs Federal agencies, to 
Page 92 of 156 

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. 
Page 93 of 156 

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 [INSERT THE DATE 30 DAYS AFTER 

PUBLICATION OF THIS FINAL RULE IN THE FEDERAL REGISTER OR 

DECEMBER 31, 2010, WHICHEVER IS EARLIER]. 

Page 95 of 156 

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] 

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. 

2. Section 72.2 is amended by revising the definition 

for “interested person” to read as follows: 

§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 
 

 

Page 96 of 156 

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] 

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. 

4. Section 78.1 is amended by: 

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.” 

b. Adding and reserving paragraphs (b)(13) through (b)(16) 

c. Adding paragraph (b)(17) to read as follows. 

§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 §98.440(d) of this chapter. 
 

Page 97 of 156 

(ii) The approval or disapproval of a request for 

discontinuation of reporting under §98.441(b) of this 

chapter. 

(iii) The approval or disapproval of a geologic 

sequestration monitoring, reporting, and verification (MRV) 

plan under §98.448(c) and §98.448(d) of this chapter. 

* * * * * 

5. Section 78.3 is amended by: 

a. Adding and reserving paragraph (a)(10). 

b. Adding paragraph (a)(11). 

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)”. 

d. Adding and reserving paragraph (d)(11) 

e. Adding paragraph (d)(12). 

§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. 
Page 98 of 156 

(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. 

6. Section 78.4 is amended by: 

a. Adding and reserving paragraphs (a)(1) 

introductory text, (a)(1)(i), (a)(1)(ii), and (a)(1)(iii). 

b. Adding paragraph (a)(1)(iv). 

c. Adding and reserving paragraph (a)(2). 

§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] 
Page 99 of 156 

7. The authority citation for part 98 continues to 

read as follows: 

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

Subpart A—[Amended] 

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 §98.2(a)(1)

Source Categoriesa Applicable in 2010 and Future Years 

* * * * * * * 

Additional Source Categoriesa Applicable in 2011 and Future

Years 

* * * * * * * 

Geologic sequestration of carbon dioxide (subpart RR)

Injection of carbon dioxide (subpart UU)

a Source categories are defined in each applicable subpart. 

9. Part 98 is amended by adding subpart RR to read as 

follows: 

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. 
 

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98.448 Geologic sequestration monitoring, reporting, and

verification (MRV) plan.

98.449 Definitions. 

Subpart RR—Geologic Sequestration of Carbon Dioxide 

§98.440 Definition of the source category. 

(a) The geologic sequestration of carbon dioxide (CO2) 

source category comprises any well or group of wells that 

inject a CO2 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 CO2 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 CO2 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 
Page 101 of 156 

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 (d)(2) below to EPA by the time you would be 

otherwise required to submit an MRV plan under §98.448. EPA 

will use this information to verify that the project is a 

research and development project. 

(2) Content of submission. A submission in support of 

an exemption as a research and development project must 

contain the following information: 

(i) The planned duration of CO2 injection for the 

project. 

(ii) The planned annual CO2 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 
Page 102 of 156 

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 CO2 

injection for the project and the planned annual CO2 

injection volumes during the duration of the project are 

consistent with the purpose of the research and development 

project. 

(ii) Any appeal of the Administrator’s determination 

is subject to the provisions of part 78 of this chapter. 

(iii) A project that the Administrator determines is 

not eligible for an exemption as a research and development 

project must submit a proposed MRV plan to EPA within 180 

days of the Administrator’s determination. You may request 

one extension of up to an additional 180 days in which to 

submit the proposed MRV plan. 

§98.441 Reporting threshold. 

(a) You must report under this subpart if any well or 

group of wells within your facility injects any amount of 

CO2 for long-term containment in subsurface geologic 

formations. There is no threshold. 

(b) Request for discontinuation of reporting. The 

requirements of §98.2(i) do not apply to this subpart. 

Once a well or group of wells is subject to the 
Page 103 of 156 

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 (2)(i) or 

(2)(ii). 

(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 CO2 stream is not 

expected to migrate in the future in a manner likely to 

result in surface leakage. 
Page 104 of 156 

(3) Notification. The Administrator will issue a 

final decision on the request to discontinue reporting 

within a reasonable time. Any appeal of the 

Administrator’s final decision is subject to the provisions 

of part 78 of this chapter. 

§98.442 GHGs to report. 

You must report: 

(a) Mass of CO2 received. 

(b) Mass of CO2 injected into the subsurface. 

(c) Mass of CO2 produced. 

(d) Mass of CO2 emitted by surface leakage. 

(e) Mass of CO2 equipment leakage and vented CO2 

emissions from surface equipment located between the 

injection flow meter and the injection wellhead. 

(f) Mass of CO2 equipment leakage and vented CO2 

emissions from surface equipment located between the 

production flow meter and the production wellhead. 

(g) Mass of CO2 sequestered in subsurface geologic 

formations. 

(h) Cumulative mass of CO2 reported as sequestered in 

subsurface geologic formations in all years since the 

facility became subject to reporting requirements under 

this subpart. 

§98.443 Calculating CO2 geologic sequestration. 
Page 105 of 156 

You must calculate the mass of CO2 received using CO2 

received equations (Equations RR-1 to RR-3 of this 

section), unless you follow the procedures in 

§98.444(a)(4). You must calculate CO2 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 CO2 sequestered 

starting from the date set forth in your approved MRV plan. 

(a) You must calculate and report the annual mass of 

CO2 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 CO2 in a CO2 stream received in metric 

tons by multiplying the mass flow by the CO2 concentration 

in the flow, according to Equation RR-1 of this section. 

You must collect these data quarterly. Mass flow and 

concentration data measurements must be made in accordance 

with §98.444. 

4 

CO2T,r = (Qr, p  Sr, p ) * CCO (Eq. RR-1) 2, p ,r

p1 
 

 

 

 

Page 106 of 156 

Where: 

CO2T,r = Net annual mass of CO2 received through flow

meter r (metric tons). 

Qr,p = Quarterly mass flow through a receiving flow

meter r in quarter p (metric tons). 

Sr,p = 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). 

CCO2,p,r = Quarterly CO2 concentration measurement in flow 

for flow meter r in quarter p (wt. percent CO2,

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 CO2 in a CO2 stream received in 

metric tons by multiplying the volumetric flow at standard 

conditions by the CO2 concentration in the flow and the 

density of CO2 at standard conditions, according to Equation 

RR-2 of this section. You must collect these data 

quarterly. Volumetric flow and concentration data 

measurements must be made in accordance with §98.444. 

4 

CO2T,r = (Qr, p  Sr, p ) * D *CCO	 (Eq. RR-2) 2, p ,r

p1 

Where: 

CO2T,r = Net annual mass of CO2 received through flow

meter r (metric tons). 

Qr,p = Quarterly volumetric flow through a receiving

flow meter r in quarter p at standard

conditions (standard cubic meters). 
 

 

Page 107 of 156 

Sr,p = 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 CO2 at standard conditions (metric

tons per standard cubic meter): 0.0018682. 

CCO2,p,r = Quarterly CO2 concentration measurement in flow 

for flow meter r in quarter p (vol. percent

CO2, expressed as a decimal fraction). 

p = Quarter of the year. 

r = Receiving flow meter. 

(3) If you receive CO2 through more than one flow 

meter, you must sum the mass of all CO2 received in 

accordance with the procedure specified in Equation RR-3 of 

this section. 

R

CO2 = CO2T,r (Eq. RR-3) r1 

Where: 

CO2 = Total net annual mass of CO2 received (metric

tons). 

CO2T,r = Net annual mass of CO2 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 

CO2 received in containers using the procedures in 

paragraphs (b)(1) or (b)(2) of this section. 

(1) If you are measuring the mass of contents in a 

container under the provisions of §98.444(a)(2)(i), you 
 

 

 

 

 

 

Page 108 of 156 

must calculate the CO2 received for injection in containers 

using Equation RR-1 of this section. 

Where: 

CO2T,r = Net annual mass of CO2 received in containers r 

(metric tons). 

CCO2,p,r = Quarterly CO2 concentration measurement of 

contents in containers r in quarter p (wt.

percent CO2, expressed as a decimal fraction). 

Qr,p = Quarterly mass of contents in containers r in

quarter p (metric tons). 

Sr,p = 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 §98.444(a)(2)(ii), you 

must calculate the CO2 received for injection in containers 

using Equation RR-2 of this section. 

Where: 

CO2T,r = Net annual mass of CO2 received in containers r 

(metric tons). 

CCO2,p,r = Quarterly CO2 concentration measurement of 

contents in containers r in quarter p (vol.

percent CO2, expressed as a decimal fraction). 

Qr,p = Quarterly volume of contents in containers r in

quarter p (standard cubic meters). 

Sr,p = Quarterly mass of contents in containers r

redelivered to another facility without being 
 

 

Page 109 of 156 

injected into your well in quarter p (metric

tons). 

D = Density of the CO2 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 CO2 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 CO2 stream, you must calculate annually the 

total mass of CO2 (in metric tons) in the CO2 stream 

injected each year in metric tons by multiplying the mass 

flow by the CO2 concentration in the flow, according to 

Equation RR-4 of this section. Mass flow and concentration 

data measurements must be made in accordance with §98.444. 

4 

CO2,u = Qp,u *CCO	 (Eq. RR-4) 2, p ,u

p1 

Where: 

CO2,u = Annual CO2 mass injected (metric tons) as

measured by flow meter u. 

Qp,u = Quarterly mass flow rate measurement for flow

meter u in quarter p (metric tons per quarter). 

CCO2,p,u = Quarterly CO2 concentration measurement in flow 

for flow meter u in quarter p (wt. percent CO2,

expressed as a decimal fraction). 

p = Quarter of the year. 
 

 

Page 110 of 156 

u = Flow meter. 

(2) If you use a volumetric flow meter to measure the 

flow of an injected CO2 stream, you must calculate annually 

the total mass of CO2 (in metric tons) in the CO2 stream 

injected each year in metric tons by multiplying the 

volumetric flow at standard conditions by the CO2 

concentration in the flow and the density of CO2 at standard 

conditions, according to Equation RR-5 of this section. 

Volumetric flow and concentration data measurements must be 

made in accordance with §98.444. 

4
 

CO2,u = p1
 

Qp,u * D *CCO (Eq. RR-5) 2, p ,u

Where: 

CO2,u = Annual CO2 mass injected (metric tons) as

measured by flow meter u. 

Qp,u = Quarterly volumetric flow rate measurement for

flow meter u in quarter p at standard

conditions (standard cubic meters per quarter). 

D = Density of CO2 at standard conditions (metric

tons per standard cubic meter): 0.0018682. 

CCO2,p,u = CO2 concentration measurement in flow for flow 

meter u in quarter p (vol. percent CO2,

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 CO2 
Page 111 of 156 

injected through all injection wells in accordance with the 

procedure specified in Equation RR-6 of this section. 

U

CO2I = CO2, u (Eq. RR-6) u1 

Where: 

CO2I = Total annual CO2 mass injected (metric tons)

through all injection wells. 

CO2,u = Annual CO2 mass injected (metric tons) as

measured by flow meter u. 

u = Flow meter. 

(d) You must calculate the annual mass of CO2 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 

CO2 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 CO2 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 CO2 

concentration in the gas flow, according to Equation RR-7 

of this section. You must collect these data quarterly. 
 

 

Page 112 of 156 

Mass flow and concentration data measurements must be made 

in accordance with §98.444. 

4
 

p 1
 

Where: 



CO2,w = Annual CO2 mass produced (metric tons) through

separator w. 

Qp,w = Quarterly gas mass flow rate measurement for

separator w in quarter p (metric tons). 

CCO2,p,w = Quarterly CO2 concentration measurement in flow 

for separator w in quarter p (wt. percent CO2,

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 CO2 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 CO2 concentration in the gas flow and the 

density of CO2 at standard conditions, according to Equation 

RR-8 of this section. You must collect these data 

quarterly. Volumetric flow and concentration data 

measurements must be made in accordance with §98.444. 

4
 

p 1
 

CO2,w = Qp,w *CCO (Eq. RR-7) 2, p ,w

CO2,w = Qp,w * D *CCO (Eq. RR-8) 2, p ,w

Where: 
 

 

Page 113 of 156 

CO2,w = Annual CO2 mass produced (metric tons) through

separator w. 

Qp,w = Volumetric gas flow rate measurement for

separator w in quarter p at standard conditions

(standard cubic meters). 

D = Density of CO2 at standard conditions (metric

tons per standard cubic meter): 0.0018682. 

CCO2,p,w = CO2 concentration measurement in flow for 

separator w in quarter p (vol. percent CO2,

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 CO2 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 CO2 measured at the separator(s) represents a 

percentage of the total CO2 produced. In order to account 

for the percentage of CO2 produced that is estimated to 

remain with the produced oil or other fluid, you must 

multiply the quarterly mass of CO2 measured at the 

separator(s) by a percentage estimated using a methodology 

in your approved MRV plan. 

W

CO2P = (1+X) * CO2, w (Eq. RR-9) w1
 

Where: 

CO2P = Total annual CO2 mass produced (metric tons)

through all separators in the reporting year. 
Page 114 of 156 

CO2,w = Annual CO2 mass produced (metric tons) through

separator w in the reporting year. 

X = Entrained CO2 in produced oil or other fluid

divided by the CO2 separated through all

separators in the reporting year (weight

percent CO2, expressed as a decimal fraction). 

w = Separator. 

(e) You must report the annual mass of CO2 that is 

emitted by surface leakage in accordance with your approved 

MRV plan. You must calculate the total annual mass of CO2 

emitted from all leakage pathways in accordance with the 

procedure specified in Equation RR-10 of this section. 

X

CO2E = CO2, x (Eq. RR-10) x1 

Where: 

CO2E = Total annual CO2 mass emitted by surface

leakage (metric tons) in the reporting year. 

CO2,x = Annual CO2 mass emitted (metric tons) at

leakage pathway x in the reporting year. 

x = Leakage pathway. 

(f) You must report the annual mass of CO2 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 CO2 that is sequestered in the 

underground subsurface formation in the reporting year in 
Page 115 of 156 

accordance with the procedure specified in Equation RR-11 

of this section. 

CO2 = CO2I - CO2P – CO2E – CO2FI – CO2FP (Eq. RR-11) 

Where: 

CO2 = Total annual CO2 mass sequestered in subsurface

geologic formations (metric tons) at the

facility in the reporting year. 

CO2I = Total annual CO2 mass injected (metric tons) in

the well or group of wells covered by this

source category in the reporting year. 

CO2P = Total annual CO2 mass produced (metric tons) in

the reporting year. 

CO2E = Total annual CO2 mass emitted (metric tons) by

surface leakage in the reporting year. 

CO2FI = Total annual CO2 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. 

CO2FP = Total annual CO2 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 CO2 that is sequestered in subsurface geologic formations 

in the reporting year in accordance with the procedures 

specified in Equation RR-12 of this section. 

CO2 = CO2I – CO2E – CO2FI (Eq. RR-12) 
Page 116 of 156 

Where: 

CO2 = Total annual CO2 mass sequestered in subsurface

geologic formations (metric tons) at the

facility in the reporting year. 

CO2I = Total annual CO2 mass injected (metric tons) in

the well or group of wells covered by this

source category in the reporting year. 

CO2E = Total annual CO2 mass emitted (metric tons) by

surface leakage in the reporting year. 

CO2FI = Total annual CO2 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. 

§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 CO2 

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 CO2 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. 
Page 117 of 156 

(iii) If you inject CO2 received from a production 

process unit that is part of your facility, you may use the 

quarterly CO2 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 CO2 

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 CO2 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 CO2 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. 
Page 118 of 156 

(3) Except as provided in paragraph (a)(4) of this 

section, you must determine a quarterly concentration of 

the CO2 received that is representative of all CO2 received 

in that quarter by following the most appropriate of the 

following procedures: 

(i) You may sample the CO2 stream at least once per 

quarter at the point of receipt and measure its CO2 

concentration. 

(ii) If you took ownership of the CO2 in a commercial 

transaction for which the sales contract was contingent on 

CO2 concentration, and if the supplier of the CO2 sampled 

the CO2 stream in a quarter and measured its concentration 

per the sales contract terms, you may use the CO2 

concentration data from the sales contract for that 

quarter. 

(iii) If you inject CO2 from a production process unit 

that is part of your facility, you may report the quarterly 

CO2 concentration of the CO2 stream supplied that was 

measured following the procedures provided in subpart PP of 

this part. 

(4) If the CO2 you receive is wholly injected and is 

not mixed with any other supply of CO2, you may report the 

annual mass of CO2 injected that you determined following 

the requirements under paragraph (b) of this section as the 
Page 119 of 156 

total annual mass of CO2 received instead of using Equation 

RR-1 or RR-2 of this subpart to calculate CO2 received. 

(5) You must assume that the CO2 you receive meets the 

definition of a CO2 stream unless you can trace it through 

written records to a source other than a CO2 stream. 

(b) CO2 injected. 

(1) You must select a point or points of measurement 

at which the CO2 stream(s) is representative of the CO2 

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 CO2 injected with a 

flow meter and collect the flow rate quarterly. 

(3) You must sample the injected CO2 stream at least 

once per quarter immediately upstream or downstream of the 

flow meter used to measure flow rate of that CO2 stream and 

measure the CO2 concentration of the sample. 

(c) CO2 produced. 

(1) The point of measurement for the quantity of CO2 

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. 
Page 120 of 156 

(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 CO2 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 §98.446 according to the 

calibration and accuracy requirements in §98.3(i). 

(3) You must operate all measurement devices 

according to one of the following. You may use an 

appropriate standard method published by a consensus-based 

standards organization if such a method exists or an 

industry standard practice. Consensus-based standards 
Page 121 of 156 

organizations include, but are not limited to, the 

following: ASTM International, the American National 

Standards Institute (ANSI), the American Gas Association 

(AGA), the American Society of Mechanical Engineers (ASME), 

the American Petroleum Institute (API), and the North 

American Energy Standards Board (NAESB). 

(4) You must ensure that any flow meter calibrations 

performed are National Institute of Standards and 

Technology (NIST) traceable. 

(f) General. 

(1) If you measure the concentration of any CO2 

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 CO2 to 

the following standard industry temperature and pressure 

conditions for use in Equations RR-2, RR-5 and RR-8 of this 

subpart: standard cubic meters at a temperature of 60 

degrees Fahrenheit and at an absolute pressure of 1 

atmosphere. 

(3) For 2011, you may follow the provisions of 

§98.3(d)(1) through (2) for best available monitoring 
Page 122 of 156 

methods only for parameters required by paragraphs (a) and 

(b) of §98.443 rather than follow the monitoring 

requirements of paragraph (a) of this section. For 

purposes of this subpart, any reference to the year 2010 in 

§98.3(d)(1) through (2) shall mean 2011. 

§98.445 Procedures for estimating missing data. 

A complete record of all measured parameters used in 

the GHG quantities calculations is required. Whenever the 

monitoring procedures cannot be followed, you must use the 

following missing data procedures: 

(a) A quarterly flow rate of CO2 received that is 

missing must be estimated as follows: 

(1) Another calculation methodology listed in 

§98.444(a)(1) must be used if possible. 

(2) If another method listed in §98.444(a)(1) cannot 

be used, a quarterly flow rate value that is missing must 

be estimated using a representative flow rate value from 

the nearest previous time period. 

(b) A quarterly mass or volume of contents in 

containers received that is missing must be estimated as 

follows: 

(1) Another calculation methodology listed in 

§98.444(a)(2) must be used if possible. 
Page 123 of 156 

(2) If another method listed in §98.444(a)(2) cannot 

be used, a quarterly mass or volume value that is missing 

must be estimated using a representative mass or volume 

value from the nearest previous time period. 

(c) A quarterly CO2 concentration of a CO2 stream 

received that is missing must be estimated as follows: 

(1) Another calculation methodology listed in 

§98.444(a)(3) must be used if possible. 

(2) If another method listed in §98.444(a)(3) cannot 

be used, a quarterly concentration value that is missing 

must be estimated using a representative concentration 

value from the nearest previous time period. 

(d) A quarterly quantity of CO2 injected that is 

missing must be estimated using a representative quantity 

of CO2 injected from the nearest previous period of time at 

a similar injection pressure. 

(e) For any values associated with CO2 equipment 

leakage or vented CO2 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 CO2 produced from 

subsurface geologic formations that is missing must be 
Page 124 of 156 

estimated using a representative quantity of CO2 produced 

from the nearest previous period of time. 

(g) You must estimate the mass of CO2 emitted by 

surface leakage that is missing as required by your 

approved MRV plan. 

(h) You must estimate other missing data as required 

by your approved MRV plan. 

§98.446 Data reporting requirements. 

In addition to the information required by §98.3(c), 

report the information listed in this section. 

(a) If you receive CO2 by pipeline, report the 

following for each receiving flow meter: 

(1) The total net mass of CO2 received (metric tons) 

annually. 

(2) If a volumetric flow meter is used to receive CO2 

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. 
Page 125 of 156 

(iii) The CO2 concentration in the flow (volume 

percent CO2 expressed as a decimal fraction) in each 

quarter. 

(3) If a mass flow meter is used to receive CO2 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 CO2 concentration in the flow (weight 

percent CO2 expressed as a decimal fraction) in each 

quarter. 

(4) If the CO2 received is wholly injected and not 

mixed with any other supply of CO2, report whether you 

followed the procedures in §98.444(a)(4). 

(5) The standard or method used to calculate each 

value in paragraphs (a)(2) through (a)(3) of this section. 

(6) The number of times in the reporting year for 

which substitute data procedures were used to calculate 

values reported in paragraphs (a)(2) through (a)(3) of this 

section. 

(7) Whether the flow meter is mass or volumetric. 
Page 126 of 156 

(8) A numerical identifier for the flow meter. 

(b) If you receive CO2 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 CO2 of contents in containers 

(volume or wt. percent CO2 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 CO2 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 CO2 received (metric tons) 

through all flow meters annually. 
Page 127 of 156 

(d) The source of the CO2 received according to the 

following categories: 

(1) CO2 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 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 CO2 injected (metric tons) annually. 
Page 128 of 156 

(ii) The CO2 concentration in flow (volume or weight 

percent CO2 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 CO2 injected (metric tons) in the 

reporting year as calculated in Equation RR-6 of this 

subpart. 

(3) For CO2 equipment leakage and vented CO2 

emissions, report the following: 

(i) The mass of CO2 emitted (in metric tons) annually 

as equipment leakage or vented emissions from equipment 
Page 129 of 156 

located on the surface between the flow meter used to 

measure injection quantity and the injection wellhead. 

(ii) The mass of CO2 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) CO2 mass produced (metric tons) annually. 

(ii) CO2 concentration in flow (volume or weight 

percent CO2 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 
Page 130 of 156 

values reported in paragraphs (f)(4)(ii) through (f)(4)(iv) 

of this section. 

(5) The entrained CO2 in produced oil or other fluid 

divided by the CO2 separated through all separators in the 

reporting year (weight percent CO2 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 CO2 produced in the reporting year as 

calculated in Equation RR-9 of this subpart. 

(7) For each leakage pathway through which CO2 

emissions occurred, report: 

(i) A numerical identifier for the leakage pathway. 

(ii) The CO2 (metric tons) emitted through that 

pathway in the reporting year. 

(8) Annual CO2 mass emitted (metric tons) by surface 

leakage in the reporting year as calculated by Equation RR10 of this subpart. 

(9) Annual CO2 (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 CO2 (metric tons) reported as 

sequestered in subsurface geologic formations in all years 
Page 131 of 156 

since the well or group of wells became subject to 

reporting requirements under this subpart. 

(11) Date that the most recent MRV plan was approved 

by EPA and the MRV plan approval number that was issued by 

EPA. 

(12) An annual monitoring report that contains the 

following components: 

(i) A narrative history of the monitoring efforts 

conducted over the previous calendar year, including a 

listing of all monitoring equipment that was operated, its 

period of operation, and any relevant tests or surveys that 

were conducted. 

(ii) A description of any changes to the monitoring 

program that you concluded were not material changes 

warranting submission of a revised MRV plan under 

§98.448(d). 

(iii) A narrative history of any monitoring anomalies 

that were detected in the previous calendar year and how 

they were investigated and resolved. 

(iv) A description of any surface leakages of CO2, 

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 CO2 emitted. 
Page 132 of 156 

(13) If a well is permitted under the Underground 

Injection Control program, for each injection well, report: 

(i) The well identification number used for the 

Underground Injection Control permit. 

(ii) The Underground Injection Control permit class. 

(14) If an offshore well is not subject to the Safe 

Drinking Water Act, for each injection well, report any 

well identification number and any identification number 

used for the legal instrument authorizing geologic 

sequestration. 

§98.447 Records that must be retained. 

(a) You must follow the record retention requirements 

specified by §98.3(g). In addition to the records required 

by §98.3(g), you must retain the records specified in 

paragraphs (1) through (7) of this section, as applicable. 

You must retain all required records for at least 3 years. 

(1) Quarterly records of CO2 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 CO2, including mass 

flow or volumetric flow at standard conditions and 
Page 133 of 156 

operating conditions, operating temperature and pressure, 

and concentration of these streams. 

(3) Quarterly records of injected CO2 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 CO2 emitted by surface leakage from leakage pathways. 

(5) Annual records of information used to calculate 

the CO2 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 CO2 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 §98.3(g)(5), by April 1 of the year you begin 

collecting data. 
Page 134 of 156 

§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 CO2 in the maximum monitoring area and the 

likelihood, magnitude, and timing, of surface leakage of CO2 

through these pathways. 

(3) A strategy for detecting and quantifying any 

surface leakage of CO2. 

(4) A strategy for establishing the expected 

baselines for monitoring CO2 surface leakage. 

(5) A summary of the considerations you intend to use 

to calculate site-specific variables for the mass balance 
Page 135 of 156 

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 CO2 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 
Page 136 of 156 

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 (a)(4) are established 

and the leakage detection and quantification strategy as 

required by (a)(3) 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 CO2 

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 CO2 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 CO2. You will be allowed to 
Page 137 of 156 

request one extension of the submittal date of up to an 

additional 180 days. 

(3) If you are injecting a CO2 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. 
Page 138 of 156 

(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 CO2 

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 
Page 139 of 156 

approved plan while awaiting approval of a revised MRV 

plan. 

(f) Format. Each proposed MRV plan or revision and 

each annual report must be submitted electronically in a 

format specified by the Administrator. 

(g) Certificate of representation. You must submit a 

certificate of representation according to the provisions 

in §98.4 at least 60 days before submission of your MRV 

plan, your research and development exemption request, your 

MRV plan submission extension request, or your initial 

annual report under this part, whichever is earlier. 

§98.449 Definitions. 

Except as provided below, all terms used in this 

subpart have the same meaning given in the Clean Air Act 

and subpart A of this part. 

Active monitoring area is the area that will be 

monitored over a specific time interval from the first year 

of the period (n) to the last year in the period (t). The 

boundary of the active monitoring area is established by 

superimposing two areas: 

(1) The area projected to contain the free phase CO2 

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. 
Page 140 of 156 

(2) The area projected to contain the free phase CO2 

plume at the end of year t+5. 

CO2 received the CO2 stream that you receive to be 

injected for the first time into a well on your facility 

that is covered by this subpart. CO2 received includes, but 

is not limited to, a CO2 stream from a production process 

unit inside your facility and a CO2 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 

CO2 plume until the CO2 plume has stabilized plus an allaround 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 
Page 141 of 156 

applied research, that will enable safe and effective longterm containment of a CO2 stream in subsurface geologic 

formations, including research and short duration CO2 

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 CO2 

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 CH4 or CO2 containing natural gas or hydrocarbon 

gas (not including stationary combustion flue gas), 
Page 142 of 156 

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). 

10. Part 98 is amended by adding subpart UU to read 

as follows: 

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 

§98.470 Definition of the source category. 

(a) The injection of carbon dioxide (CO2) source 

category comprises any well or group of wells that inject a 

CO2 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 
Page 143 of 156 

required to report emissions under subpart C of this part 

or any other subpart listed in §98.2(a)(1) or (a)(2). 

§98.471 Reporting threshold. 

(a) You must report under this subpart if your 

facility injects any amount of CO2 into the subsurface. 

(b) For purposes of this subpart, any reference to CO2 

emissions in §98.2(i) shall mean CO2 received. 

§98.472 GHGs to report. 

You must report the mass of CO2 received. 

§98.473 Calculating CO2 received. 

(a) You must calculate and report the annual mass of 

CO2 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 CO2 in a CO2 stream received in metric 

tons by multiplying the mass flow by the CO2 concentration 

in the flow, according to Equation UU-1 of this section. 

You must collect these data quarterly. Mass flow and 

concentration data measurements must be made in accordance 

with §98.474. 

4 

CO2T,r = (Qr, p r  S , p ) *CCO (Eq. UU-1) 2, p ,r

p1 

Where: 
 

 

 

 

 

Page 144 of 156 

CO2T,r = Net annual mass of CO2 received through flow

meter r (metric tons). 

Qr,p = Quarterly mass flow through a receiving flow

meter r in quarter p (metric tons). 

Sr,p = 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). 

CCO2,p,r = Quarterly CO2 concentration measurement in flow 

for flow meter r in quarter p (wt. percent CO2,

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 CO2 in a CO2 stream received in 

metric tons by multiplying the volumetric flow at standard 

conditions by the CO2 concentration in the flow and the 

density of CO2 at standard conditions, according to Equation 

UU-2 of this section. You must collect these data 

quarterly. Volumetric flow and concentration data 

measurements must be made in accordance with §98.474. 

4 

= (Qr, p r  S , p ) * D *C	 CO (Eq. UU-2) p1 

CO2T,r 	 2, p ,r

Where: 

CO2T,r = Net annual mass of CO2 received through flow

meter r (metric tons). 

Qr,p = Quarterly volumetric flow through a receiving

flow meter r in quarter p at standard

conditions (standard cubic meters). 

Sr,p = Quarterly volumetric flow through a receiving

flow meter r that is redelivered to another 
 

Page 145 of 156 

facility without being injected into your well

in quarter p (standard cubic meters). 

D = Density of CO2 at standard conditions (metric

tons per standard cubic meter): 0.0018704. 

CCO2,p,r = Quarterly CO2 concentration measurement in flow 

for flow meter r in quarter p (vol. percent

CO2, expressed as a decimal fraction). 

p = Quarter of the year. 

r = Receiving flow meter. 

(3) If you receive CO2 through more than one flow 

meter, you must sum the mass of all CO2 received in 

accordance with the procedure specified in Equation UU-3 of 

this section. 

R

CO2 = CO2T,r (Eq. UU-3) r1 

Where: 

CO2 = Total net annual mass of CO2 received (metric

tons). 

CO2T,r = Net annual mass of CO2 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 

CO2 received in containers using the procedures specified in 

either paragraph (b)(1) or (b)(2) of this section. 

(1) If you are measuring the mass of contents in a 

container under the provisions of §98.474(a)(2)(i), you 

must calculate the CO2 received in containers using Equation 

UU-1 of this section. 
 

 

 

 

 

 

Where: 

CO2T,r = Annual mass of CO2 received in containers r 

(metric tons). 

CCO2,p,r = Quarterly CO2 concentration measurement of 

contents in containers r in quarter p (wt.

percent CO2, expressed as a decimal fraction). 

Qr,p = Quarterly mass of contents in containers r in

quarter p (metric tons). 

Sr,p = 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. 

Page 146 of 156 

(2) If you are measuring the volume of contents in a 

container under the provisions of §98.474(a)(2)(ii), you 

must calculate the CO2 received in containers using Equation 

UU-2 of this section. 

Where: 

CO2T,r = Annual mass of CO2 received in containers r 

(metric tons). 

CCO2,p,r = Quarterly CO2 concentration measurement of 

contents in containers r in quarter p (vol.

percent CO2, expressed as a decimal fraction). 

Sr,p = 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). 

Qr,p = Quarterly volume of contents in containers r in

quarter p (standard cubic meters). 

D = Density of the CO2 received in containers at 

standard conditions (metric tons per standard

cubic meter):0.0018682. 
Page 147 of 156 

p = Quarter of the year. 

r = Containers. 

§98.474 Monitoring and QA/QC requirements.
 

(a) CO2 received. 

(1) You must determine the quarterly flow rate of CO2 

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 CO2 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 CO2 from a production process unit 

that is part of your facility, you may use the quarterly CO2 

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 CO2 being 

transported to an injection well to the same degree of 

accuracy as a meter used for commercial transactions. 
Page 148 of 156 

(2) You must determine the quarterly mass or volume 

of contents in all containers if you receive CO2 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 CO2 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 CO2 received that is representative of all CO2 received 

in that quarter by following the most appropriate of the 

following procedures: 

(i) You may sample the CO2 stream at least once per 

quarter at the point of receipt and measure its CO2 

concentration. 

(ii) If you took ownership of the CO2 in a commercial 

transaction for which the sales contract was contingent on 

CO2 concentration, and if the supplier of the CO2 sampled 
Page 149 of 156 

the CO2 stream in a quarter and measured its concentration 

per the sales contract terms, you may use the CO2 

concentration data from the sales contract for that 

quarter. 

(iii) If you inject CO2 from a production process unit 

that is part of your facility, you may report the quarterly 

CO2 concentration of the CO2 stream supplied that was 

measured following procedures provided in subpart PP of 

this part as the quarterly CO2 concentration of the CO2 

stream received. 

(4) You must assume that the CO2 you receive meets the 

definition of a CO2 stream unless you can trace it through 

written records to a source other than a CO2 stream. 

(b) Measurement devices. 

(1) All flow meters must be operated continuously 

except as necessary for maintenance and calibration. 

(2) You must calibrate all flow meters used to 

measure quantities reported in §98.476 according to the 

calibration and accuracy requirements in §98.3(i). 

(3) You must operate all measurement devices 

according to one of the following. You may use an 

appropriate standard method published by a consensus-based 

standards organization if such a method exists or an 

industry standard practice. Consensus-based standards 
Page 150 of 156 

organizations include, but are not limited to, the 

following: ASTM International, the American National 

Standards Institute (ANSI), the American Gas Association 

(AGA), the American Society of Mechanical Engineers (ASME), 

the American Petroleum Institute (API), and the North 

American Energy Standards Board (NAESB). 

(4) You must ensure that any flow meter calibrations 

performed are National Institute of Standards and 

Technology (NIST) traceable. 

(c) General. 

(1) If you measure the concentration of any CO2 

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 CO2 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 

§98.3(d)(1) through (2) for best available monitoring 

methods rather than follow the monitoring requirements of 
Page 151 of 156 

this section. For purposes of this subpart, any reference 

to the year 2010 in §98.3(d)(1) through (2) shall mean 

2011. 

§98.475 Procedures for estimating missing data.
 

A complete record of all measured parameters used in 

the GHG quantities calculations is required. 

(a) Whenever the monitoring procedures for all 

facilities that used flow meters covered under this subpart 

cannot be followed to measure flow, the following missing 

data procedures must be followed: 

(1) Another calculation methodology listed in 

§98.474(a)(1) must be used if possible. 

(2) If another method listed in §98.474(a)(1) cannot 

be used, a quarterly flow rate value that is missing must 

be estimated using a representative flow rate value from 

the nearest previous time period. 

(b) Whenever the monitoring procedures of this 

subpart cannot be followed to measure quarterly quantity of 

CO2 received in containers, the most appropriate of the 

following missing data procedures must be followed: 

(1) Another calculation methodology listed in 

§98.474(a)(2) must be used if possible. 

(2) If another method listed in §98.474(a)(2) cannot 

be used, a quarterly mass or volume that is missing must be 
Page 152 of 156 

estimated using a representative mass or volume from the 

nearest previous time period. 

(c) Whenever the monitoring procedures cannot be 

followed to measure CO2 concentration, the following missing 

data procedures must be followed: 

(1) Another calculation methodology listed in 

§98.474(a)(3) must be used if possible. 

(2) If another method listed in §98.474(a)(3) cannot 

be used, a quarterly concentration value that is missing 

must be estimated using a representative concentration 

value from the nearest previous time period. 

§98.476 Data reporting requirements. 

If you are subject to this part and report under this 

subpart, you are not required to report the information in 

§98.3(c)(4) for this subpart. In addition to the 

information required by §98.3(c)(1) through §98.3(c)(3) and 

by §98.3(c)(5) through §98.3(c)(9), you must report the 

information listed in this section. 

(a) If you receive CO2 by pipeline, report the 

following for each receiving flow meter: 

(1) The total net mass of CO2 received (metric tons) 

annually. 

(2) If a volumetric flow meter is used to receive CO2: 
Page 153 of 156 

(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 CO2 concentration in the flow (volume 

percent CO2 expressed as a decimal fraction) in each 

quarter. 

(3) If a mass flow meter is used to receive CO2: 

(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 CO2 concentration in the flow (weight 

percent CO2 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 
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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 CO2 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 CO2 of contents in containers 

(volume or weight percent CO2 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 CO2 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. 

(5) 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. 
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(c) If you use more than one receiving flow meter, 

report the net total mass of CO2 received (metric tons) 

through all flow meters annually. 

(d) The source of the CO2 received according to the 

following categories: 

(1) CO2 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. 

§98.477 Records that must be retained. 

(a) You must follow the record retention requirements 

specified by §98.3(g). In addition to the records required 

by §98.3(g), you must retain quarterly records of CO2 

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. 
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(b) You must complete your monitoring plans, as 

described in §98.3(g)(5), by April 1 of the year you begin 

collecting data. 

§98.478 Definitions. 

Except as provided below, all terms used in this 

subpart have the same meaning given in the Clean Air Act 

and subpart A of this part. 

CO2 received means the CO2 stream that you receive to 

be injected for the first time into a well on your facility 

that is covered by this subpart. CO2 received includes, but 

is not limited to, a CO2 stream from a production process 

unit inside your facility and a CO2 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.