Wednesday, 

December 1, 2010 

Part V 

Environmental 

Protection Agency 

40 CFR Parts 72, 78, and 98 

Mandatory Reporting of Greenhouse 

Gases: Injection and Geologic 

Sequestration of Carbon Dioxide; Final 

Rule 


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75060 Federal Register / Vol. 75, No. 230 / Wednesday, December 1, 2010 / Rules and Regulations 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Parts 72, 78, and 98 

[EPA–HQ–OAR–2009–0926; FRL–9232–6] 

RIN 2060–AP88 

Mandatory Reporting of Greenhouse 

Gases: Injection and Geologic 

Sequestration of Carbon Dioxide 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Final rule. 

SUMMARY: EPA is promulgating a 

regulation to require greenhouse gas 

monitoring and reporting from facilities 

that conduct geologic sequestration of 

carbon dioxide and all other facilities 

that conduct injection of carbon 

dioxide. This rule does not require 

control of greenhouse gases, rather it 

requires only monitoring and reporting 

of greenhouse gases. 

DATES: The final rule is effective on 

December 31, 2010. 

ADDRESSES: EPA has established a 

docket for this action under Docket ID 

No. EPA–HQ–OAR–2009–0926. All 

documents in the docket are listed on 

the http://www.regulations.gov Web 

site. Although listed in the index, some 

information is not publicly available, 

e.g., confidential business information 

(CBI) or other information whose 

disclosure is restricted by statute. 

Certain other material, such as 

copyrighted material, is not placed on 

the Internet and will be publicly 

available only in hard copy form. 

Publicly available docket materials are 

available either electronically through 

http://www.regulations.gov or in hard 

copy at EPA’s Docket Center, Public 

Reading Room, EPA West Building, 

Room 3334, 1301 Constitution Avenue, 

NW., Washington, DC 20004. This 

Docket Facility is open from 8:30 a.m. 

to 4:30 p.m., Monday through Friday, 

excluding legal holidays. The telephone 

number for the Public Reading Room is 

(202) 566–1744, and the telephone 

number for the Air Docket is (202) 566– 

1742. 

FOR FURTHER INFORMATION CONTACT: For 

technical information and 

implementation materials, please go to 

the website http://www.epa.gov/ 

climatechange/emissions/ 

ghgrulemaking.html. To submit a 

question, select Rule Help Center, and 

then select Contact Us. You may also 

contact Mark de Figueiredo, Climate 

Change Division, Office of Atmospheric 

Programs (MC–6207J), Environmental 

Protection Agency, 1200 Pennsylvania 

Ave., NW., Washington, DC 20460; 

telephone number: (202) 343–9928; fax 

number: (202) 343–2202. 

SUPPLEMENTARY INFORMATION: Regulated 

Entities. The Administrator has 

determined that this action is subject to 

the provisions of Clean Air Act (CAA) 

section 307(d). See CAA section 

307(d)(1)(V) (the provisions of CAA 

section 307(d) apply to ‘‘such other 

actions as the Administrator may 

determine’’). These regulations will 

affect owners or operators of carbon 

dioxide (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 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 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. 

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 December 31, 2010. 

Section 553(d) of the Administrative 

Procedure Act (APA), 5 U.S.C. chapter 

5, generally provides that rules may not 

take effect earlier than 30 days after they 

are published in the Federal Register. 

EPA is issuing this final rule under 

section 307(d)(1) of the Clean Air Act, 


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1We 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. 

which states: ‘‘The provisions of section 

553 through 557 * * * of Title 5 shall 

not, except as expressly provided in this 

section, apply to actions to which this 

subsection applies.’’ Thus, section 

553(d) of the APA does not apply to this 

rule. EPA is nevertheless acting 

consistently with the purposes 

underlying APA section 553(d) in 

making this rule effective on December 

31, 2010. Section 5 U.S.C. 553(d)(3) 

allows an effective date less than 30 

days after publication ‘‘as otherwise 

provided by the agency for good cause 

found and published with the rule.’’ As 

explained below, EPA finds that there is 

good cause for this rule to become 

effective on or before December 31, 

2010, even if this results in an effective 

date fewer than 30 days from date of 

publication in the Federal Register. 

While this action is being signed prior 

to December 1, 2010, there is likely to 

be a significant delay in the publication 

of this rule as it contains equations and 

charts, and is relatively long in length. 

As an example, EPA signed a shorter 

technical amendments package related 

to the same underlying reporting rule on 

October 7, 2010, and it was not 

published until October 28, 2010, 75 FR 

66434, three weeks later. 

The purpose of the 30-day waiting 

period prescribed in 5 U.S.C. 553(d) is 

to give affected parties a reasonable time 

to adjust their behavior and prepare 

before the final rule takes effect. Where, 

as here, the final rule will be signed and 

made available on the EPA Web site 

more than 30 days before the effective 

date, but where the publication is likely 

to be delayed due to the complexity and 

length of the rule, that purpose is still 

met. Moreover, EPA determined that 

facilities that are subject to this rule 

already collect data on CO2 that is 

received. Facilities may use best 

available monitoring methods for 

calculating 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 January 31, 2011. 

Under CAA section 307(d)(7)(B), only 

an objection to this final rule that was 

raised with reasonable specificity 

during the period for public comment 

can be raised during judicial review. 

This section also provides a mechanism 

for EPA to convene a proceeding for 

reconsideration, ‘‘[i]f the person raising 

an objection can demonstrate to EPA 

that it was impracticable to raise such 

objection within [the period for public 

comment] or if the grounds for such 

objection arose after the period for 

public comment (but within the time 

specified for judicial review) and if such 

objection is of central relevance to the 

outcome of this rule.’’ Any person 

seeking to make such a demonstration to 

EPA should submit a Petition for 

Reconsideration to the Office of the 

Administrator, Environmental 

Protection Agency, Room 3000, Ariel 

Rios Building, 1200 Pennsylvania Ave., 

NW., Washington, DC 20004, with a 

copy to the person listed in the 

preceding FOR FURTHER INFORMATION

CONTACT section, and the Associate 

General Counsel for the Air and 

Radiation Law Office, Office of General 

Counsel (Mail Code 2344A), 

Environmental Protection Agency, 1200 

Pennsylvania Ave., NW., Washington, 

DC 20004. Note, under CAA section 

307(b)(2), the requirements established 

by this final rule may not be challenged 

separately in any civil or criminal 

proceedings brought by EPA to enforce 

these requirements. 

Acronyms and Abbreviations. The 

following acronyms and abbreviations 

are used in this document. 

3–D three-dimensional 

AGA American Gas Association 

AMA active monitoring area 

ANSI American National Standards 

Institute 

API American Petroleum Institute 

ASME American Society of Mechanical 

Engineers 

CAA Clean Air Act 

CBI confidential business information 

CCS carbon dioxide capture and geologic 

sequestration 

CFR Code of Federal Regulations 

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 

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? 


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75062 Federal Register / Vol. 75, No. 230 / Wednesday, December 1, 2010 / Rules and Regulations 

2EPA 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. 

IV. Statutory and Executive Order Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review 

B. Paperwork Reduction Act 

C. Regulatory Flexibility Act (RFA) 

D. Unfunded Mandates Reform Act 

(UMRA) 

E. Executive Order 13132: Federalism 

F. Executive Order 13175: Consultation 

and Coordination with Indian Tribal 

Governments 

G. Executive Order 13045: Protection of 

Children from Environmental Health 

Risks and Safety Risks 

H. Executive Order 13211: Actions that 

Significantly Affect Energy Supply, 

Distribution, or Use 

I. National Technology Transfer and 

Advancement Act 

J. Executive Order 12898: Federal Actions 

to Address Environmental Justice in 

Minority Populations and Low-Income 

Populations 

K. Congressional Review Act 

I. Background 

A. Organization of This Preamble 

This preamble is divided into four 

sections, as detailed in the Table of 

Contents. This section describes the 

layout of the preamble and provides a 

brief summary of each section. 

The first section of this preamble 

contains the basic background 

information about the origin of this rule, 

including a discussion of how it relates 

to the finalized requirements for 

suppliers of 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. 

The second section of this preamble 

provides an overview of the GHG 

Reporting Program and summarizes 

changes to the general provisions of the 

GHG Reporting Program. It also 

provides a summary of this final rule on 

key design elements such as: Source 

category definition, reporting threshold, 

GHGs to report, GHG calculations and 

monitoring, data reporting, and 

recordkeeping requirements. In 

addition, it describes the major changes 

made since the proposal and provides a 

brief summary of public comments and 

EPA’s responses thereto. 

The third section of this preamble 

provides the summary of the cost 

impacts, economic impacts, and benefits 

of this rule and discusses comments on 

the regulatory impacts analysis. 

Finally, the last section of this 

preamble discusses the various statutory 

and executive order requirements 

applicable to this final rulemaking. 

B. Background on the Final Rule 

This action finalizes monitoring and 

reporting requirements for injection and 

geologic sequestration of carbon 

dioxide. 

On April 12, 2010, EPA proposed this 

rule amending 40 CFR part 98. 40 CFR 

part 98 provides the regulatory 

framework for the GHG Reporting 

Program. The GHG Reporting Program 

requires reporting of GHG emissions 

and other relevant information from 

certain source categories in the United 

States. The GHG Reporting Program, 

which became effective on December 

29, 2009, includes reporting 

requirements for facilities and suppliers 

in 34 subparts. For more detailed 

background information on the GHG 

Reporting Program, see the preamble to 

the final part 98 rule establishing that 

program (74 FR 56260, October 30, 

2009) and the preamble to the Part 98 

rule expanding that program from 30 to 

34 subparts (75 FR 39736, July 12, 

2010). 

Subpart PP of the GHG Reporting 

Program requires the reporting of 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. 

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. 

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 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 


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3http://water.epa.gov/type/groundwater/uic/ 

wells_sequestration.cfm. 

4The 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. 

5The 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. 

provision of title II with respect to 

motor vehicles). EPA may gather 

information for a variety of purposes, 

including for the purpose of assisting in 

the development of implementation 

plans or of emissions standards under 

CAA section 111, determining 

compliance with implementation plans 

or such standards, or more broadly for 

‘‘carrying out any provision’’ of the CAA. 

D. Relationship to Underground 

Injection Control Regulations Under the 

Safe Drinking Water Act 

The Agency maintains a high-level of 

coordination across EPA offices and 

regions on GS activities and regulatory 

development. EPA’s Office of Air and 

Radiation (OAR) and Office of Water 

(OW) work closely to promote safe and 

effective implementation of GS 

technologies while ensuring protection 

of human health and the environment. 

OAR and OW have closely coordinated 

this rulemaking under CAA authority 

and the rulemaking under Safe Drinking 

Water Act (SDWA) authority 

establishing Federal requirements under 

the UIC program for Class VI wells 

(hereafter referred to as the UIC Class VI 

rule). 

EPA’s UIC program was established in 

the 1970s to prevent endangerment of 

underground sources of drinking water 

(USDWs) from injection of various 

fluids, including 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 Web site.3

EPA designed the reporting 

requirements under 40 CFR part 98, 

subpart RR with careful consideration of 

UIC requirements, including Class VI, to 

minimize overlap between the two 

programs. There are two areas of 

potential overlap (see Table 3 of this 

preamble). The first overlap is the 

requirement that owners or operators 

report the quantity of 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 approach 4 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. 

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 plan 5 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 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 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.


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75064 Federal Register / Vol. 75, No. 230 / Wednesday, December 1, 2010 / Rules and Regulations 

6http://www.epa.gov/climatechange/policy/ 

ccs_task_force.html. 

7Available at: http://www.irs.gov/irb/2009– 

44_IRB/ar11.html#d0e1860. 

8Note that R&D projects that are exempted from 

subpart RR report under Subpart UU—see 

discussion below. 

TABLE 3—COMPARISON OF REPORTING REQUIREMENTS UNDER SUBPART RR WITH UIC CLASS VI REGULATIONS— 

Continued 

Reporting requirement Subpart RR UIC Class VI 

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 ................... Yes.1

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 coordinate 

implementation of the UIC and GHG 

Reporting programs, reduce burden on 

reporters, provide timely access to 

verified emissions data, establish 

mechanisms to efficiently share data, 

and harmonize data systems to the 

extent possible. 

E. Relationship to the Interagency Task 

Force on Carbon Capture and Storage 

and Other Federal Geologic 

Sequestration Initiatives 

On February 3, 2010, President 

Obama established an Interagency Task 

Force on Carbon Capture and Storage 

(CCS Task Force). The CCS Task Force, 

co-chaired by EPA and the Department 

of Energy (DOE), developed a plan to 

overcome the barriers to the 

widespread, cost-effective deployment 

of CCS within ten years, with a goal of 

bringing five to ten commercial 

demonstration projects online by 2016. 

The CCS Task Force’s plan was 

delivered to President Obama in August 

2010. 

The CCS Task Force explored 

incentives for commercial CCS adoption 

and addressed financial, economic, 

technological, legal, institutional, social, 

or other barriers to deployment. For 

example, the CCS Task Force examined 

Federal regulatory activities that address 

the safety, efficacy, and environmental 

soundness of GS. The CCS Task Force 

also considered how best to coordinate 

existing administrative authorities and 

programs, including those involving 

international collaboration, as well as 

identified areas where additional 

administrative authority may be 

necessary. The CCS Task Force 

recommended that EPA finalize this 

rule. For more information, please see 

EPA’s CCS Task Force Web site.6

F. Relationship to Other Geologic 

Sequestration Information Collection 

and Reporting Efforts 

EPA reviewed and took into account 

several existing domestic and 

international reporting and monitoring 

programs in designing this rule. For 

additional information, please see 

Section I.F of the notice of proposed 

rulemaking (75 FR 18581, April 12, 

2010). 

Also as discussed in the notice of 

proposed rulemaking, EPA notes that 

the Internal Revenue Service (IRS) 

published IRS Notice 2009–83 7 to 

provide guidance regarding eligibility 

for the Internal Revenue Code section 

45Q credit for 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 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 

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 large-scale projects 

meeting the criteria for an exemption, 

such as the current Regional Carbon 


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Sequestration Partnership projects 

supported by the Office of Fossil Energy 

at the DOE, would be considered R&D 

for the purposes of this exemption from 

reporting for the duration of the R&D 

activity. Other DOE supported GS R&D 

projects may also satisfy the eligibility 

requirements for the exemption. In 

addition, short duration 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. 

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 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 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. 

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 site-specific variables 

for the mass balance equation. 

First, the MRV plan must include a 

delineation of the MMA and the AMA. 

The MMA includes the extent of the free 

phase 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 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 


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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. 

10As 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. 

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 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 

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 complete 

within 45 days of the notice of receipt 

and will notify the reporter whether the 

plan is complete or incomplete. If 

incomplete, the reporter must submit an 

updated MRV plan within 45 days of 

EPA notification unless otherwise 

specified by EPA. 

Once EPA determines that the MRV 

plan is complete, technical review will 

commence. After 60 days of technical 

review, EPA will send the reporter a 

request for additional information 

including clarifying technical questions, 

if necessary. The reporter will be 

encouraged to provide a response to this 

request within 15 days, however EPA 

recognizes that there may be 

circumstances where additional time is 

needed for the reporter to collect the 

information requested. 

Following this iterative process, EPA 

will issue a final MRV plan as 

submitted, or with revisions. EPA will 

post the approved MRV plan on a public 

Web site, subject to any limitations or 

requirements in its CBI determination 

(see Section I.B of this preamble). Any 

reporter, or interested person, objecting 

to EPA’s final decision, may appeal it to 

EPA’s Environmental Appeals Board. 

Facilities must re-submit the MRV 

plan for EPA approval if a material 

change was made to monitoring and/or 

operational parameters that was not 

anticipated in the original plan, if the 

facility’s UIC permit class changes, or if 

an EPA review of the annual report 

determines that it is necessary. 

Examples of material changes include 

but are not limited to a large change in 

the volume of 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 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 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 


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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 revised to 

accommodate such appeals. 

Specifically, the list in 40 CFR 78.1 of 

the types of final decisions that can be 

appealed under 40 CFR part 78 is 

expanded to cover final decisions of the 

Administrator under 40 CFR part 98, 

subpart RR. This list includes, but is not 

limited to, the following specific types 

of decisions under subpart RR, a 

determination of eligibility for an R&D 

exemption under 40 CFR 98.440(d)(4), 

the approval or disapproval of a request 

for discontinuation of reporting under 

40 CFR 98.441(b)(2), and the approval or 

disapproval of a MRV plan under 40 

CFR 98.448(c). 

Further, 40 CFR 78.3 is revised to 

allow for petitions for administrative 

appeal of decisions of the Administrator 

under 40 CFR part 98, subpart RR. 

Under the general approach in the 

existing part 78, an ‘‘interested person’’ 

(in addition to the official representative 

of owners and operators involved in a 

matter) may petition for an 

administrative appeal of a final decision 

of the Administrator. The ‘‘interested 

person’’ definition, which is located in 

part 72 of the Acid Rain Program 

regulations, is expanded to take into 

account final decisions of the 

Administrator under part 98. In 

particular, EPA is revising the 

‘‘interested person’’ definition by 

replacing specific references to the Acid 

Rain Program and draft permits with 

broader references to any decision by 

the Administrator and the 

Administrator’s process of making that 

decision. As a result of this revision and 

the revisions of 40 CFR part 78, a person 

who does not own or operate a facility 

covered by a final decision under 40 

CFR part 98, subpart RR will need to 

submit his or her name to be included 

by the Administrator on an ‘‘interested 

persons list’’ in order to be able to 

appeal—by filing a petition for an 

administrative appeal—that final 

decision. 

In addition, 40 CFR 78.4 is expanded 

to state that filings on behalf of owners 

and operators of a facility subject to 40 

CFR part 98, subpart RR must be signed 

by the designated representative of the 

owners and operators. 

C. Summary of the Reporting 

Requirements for Injection of Carbon 

Dioxide (Subpart UU) 

Reporting requirements for all other 

facilities conducting 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 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 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.’’ 

X 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. 

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 


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11 General Technical Support Document for 

Injection and Geologic Sequestration of Carbon 

Dioxide: Subparts RR and UU (see docket ID No. 

EPA–HQ–OAR–2009–0926). 

vented emissions for all other surface 

equipment. 

X In 40 CFR part 98, subpart RR, 

EPA has added an MRV plan 

requirement for the delineation of the 

areas that will be monitored. 

X In 40 CFR part 98, subpart RR, 

EPA has clarified the requirements for 

an addendum to the annual report and 

renamed it the monitoring report. 

X EPA has amended 40 CFR part 78 

to include administrative appeals 

procedures for EPA decisions made 

under 40 CFR part 98, subpart RR, such 

as decisions relating to eligibility for the 

R&D exemption under 40 CFR 

98.440(d)(4), decisions relating to a 

request for discontinuation of reporting 

under 40 CFR 98.441(b)(2), or MRV plan 

decisions under 40 CFR 98.448(c). 

E. Summary of Comments and 

Responses 

This section contains a brief summary 

of major comments and responses. A 

large number of comments on 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 

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 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 nonemissive 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 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’’ 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 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 


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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 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 enduses other than underground injection. 

EPA notes that these activities may meet 

the definition of another source category 

in the GHG Reporting Program. 

3. Geologic Sequestration Research and 

Development (GS R&D) 

Comment: EPA received a range of 

comments relating to exempting GS 

R&D projects. Some commenters 

supported the R&D exemption while 

others opposed it because they believe 

these projects can provide valuable 

information on the efficacy of GS as a 

climate mitigation approach. These 

commenters also noted that these 

projects are currently gathering data 

which would provide EPA an early 

opportunity to evaluate the 

appropriateness and application of 

monitoring methods. Some commenters 

suggested that GS R&D projects be 

provided an option to opt-in to GS 

reporting requirements. One group of 

commenters recommended that EPA 

exempt GS R&D projects on a case-bycase basis. 

Response: EPA agrees with 

commenters that collecting data from all 

GS projects, including R&D, would 

provide useful information about the 

efficacy of GS and monitoring 

techniques and approaches to quantify 

leakage. However, the Agency 

recognizes that GS is an emerging 

climate mitigation approach and there 

are likely to be some projects that are 

investigating practices, monitoring 

techniques, injection verification, or are 

engaged in other applied research that 

will facilitate the development and 

adoption of GS, and that these projects 

would benefit from being exempted 

from this subpart. Therefore the Agency 

is retaining a GS R&D exemption, with 

some modifications from the proposed 

rule. See Section II.B of the preamble for 

a summary of the R&D exemption 

process. 

Comment: Many commenters noted 

that restricting the proposed exemption 

to federally funded projects was too 

stringent, that R&D can also be 

supported by states, academia, or the 

private sector, and argued that GS R&D 

projects should not be defined based on 

the source of funding. 

Response: EPA agrees with 

commenters that there are non-Federal 

funding sources that could fund GS R&D 

projects and that Federal funding 

should not be the basis for an R&D 

exemption. Other sources of funding for 

GS R&D include State and academic 

sources. Funding might also come from 

the R&D budget of a private sector 

entity. However, in order for EPA to 

have basic information about projects 

operating under an R&D exemption, 

projects must provide information on 

the source and type of funding as part 

of their submission in support of the 

exemption. 

Comment: Many commenters 

suggested that EPA consider a threshold 

for exempting R&D projects. These 

commenters noted that a threshold 

would allow for reduced regulatory 

burden and that collecting data from 

projects below the threshold would 

yield little value for EPA. 

Response: EPA found that it would be 

challenging to define a threshold for GS 

R&D projects because project size could 

vary depending on the R&D goals and 

other factors such as availability and 

source of 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. 

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 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 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’’ 


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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. 

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 

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 EPAapproved 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. 

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. 

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 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-toliquid products (40 CFR part 98, 

subparts LL, MM, and NN),12 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 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 


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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 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 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 sitespecific 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. 

EPA’s approach allows for sitespecific 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 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 

Web site, to the extent consistent with 

any confidentiality determination. 

‘‘Interested persons’’ can then appeal 

EPA decisions on MRV plans to the 

Environmental Appeals Board (EAB) 

through the appeals process described 

in 40 CFR part 78. An ‘‘interested 

person’’ may be any person who—in 

connection with the Administrator’s 

process of making his or her decision— 

submitted comments, testified at a 

public hearing, submitted objections, or 

otherwise submitted his or her name to 

be included by the Administrator in an 

interested persons list. In the case of 

MRV plans, an interested person who 

wishes to appeal an EPA decision 

should submit his or her name to be 

included in the interested persons list. 

EPA will provide the public instruction 

on joining the interested persons list for 

40 CFR part 98, subpart RR. More 

information on the administrative 

appeals process can be found in Section 

II.B of this preamble and in ‘‘Mandatory 

Greenhouse Gas Reporting Rule: EPA’s 

Response to Public Comments, Subparts 

RR and UU: Injection and Geologic 

Sequestration of Carbon Dioxide.’’ 

Though there is no formal public 

comment process prior to approval of 

individual MRV plans in today’s rule, 

EPA believes the administrative appeals 

process provides an opportunity for 

involvement by any member of the 

public who is concerned about the 

provisions of an approved plan. Further, 

if future GS policies or programs are 

promulgated as a result of the data 

collected through today’s rule for which 

a formal public notice and comment 

period would be appropriate, EPA will 

establish a public notice and comment 

period for such a policy or program at 

that time. 

EPA has provided further information 

in the General TSD about the procedural 

aspects of MRV plan approval. 

Comment: EPA received many 

comments about the role of a UIC permit 

with respect to MRV plan requirements. 

Most commenters emphasized the need 

for coordination between the UIC 

program and 40 CFR part 98, subpart 

RR. Some commenters stated that any 

class of UIC permit is enough for 

purposes of the MRV plan. Others noted 

that the MRV plan should build off of 

the UIC permit and that comprehensive 

monitoring for the purposes of verifying 

quantities of 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 


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13Bureau of Labor Statistics. http://www.bls.gov/ 

bls/wages.htm. 

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 

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. 

The estimated costs are based on 

hypothetical or pro-forma sites for 

various types of projects such as R&D 

GS projects, commercial saline 

formation projects, and ER GS projects. 

The geologic and engineering 

assumptions for these pro-forma 

projects are the same as those used by 

the EPA Office of Water in the UIC Class 

VI rule. The costs are presented in 2008 

dollars. 

The capital costs are annualized using 

an interest rate of 7 percent with 

projects lasting 4 years, 10 years or 40 

years. Next, annual O&M costs are 

added to the annualized capital costs to 

determine total annual direct costs. 

Finally, a 20 percent overhead and 

general and administrative cost factor is 

added to obtain total annual costs. 

These are then divided by the amount 

assumed to be injected each year in the 

pro-forma project to arrive at total costs 

per metric ton of 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. 

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 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). 


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TABLE 4—NATIONAL ANNUALIZED MANDATORY REPORTING COSTS ESTIMATES (2008$): SUBPARTS RR AND UU 

Type Number of 

projects 

Metric tons 

CO2 received 

per year 

Reference 

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 

First year 

($1,000) 

Second 

year 

($1,000) 

Low High 

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 GS (ER opt in) (RR) ...................... 2,124 2,005 1,893 1,773 2,271 2,151 

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 

Comments, Subparts RR and UU: 

Injection and Geologic Sequestration of 

Carbon Dioxide.’’ 

EPA has determined the selected 

option for the mandatory GHG reporting 

rule strikes a balance between impacts 

on small entities, consistency with other 

programs, costs incurred by the 

reporting entities, and emissions 

coverage. Section 5 of the final EIA 

(EPA–HQ–OAR–2009–0926) provides 

cost comparisons for each alternative 

evaluated. 

C. What are the economic impacts of the 

rule? 

1. Summary of Economic Impacts 

EPA assessed how the regulatory 

program may influence the profitability 

of companies by comparing the 

monitoring program costs to total sales 

(i.e., a ‘‘sales’’ test). Given limited data 

on commercial GS operations, EPA 

restricted the analysis to ER operations 

(approximately 90 percent of the fields). 

To do this, EPA divided the average 

annualized mandatory reporting costs 

per field by the estimated revenue for a 

representative field. Sales test ratios are 

between 3.1 to 4.0 percent for facilities 

conducting GS (ER opt in). The number 

of ER operations that would choose to 

report as facilities conducting GS (ER 

opt in) is unknown and EPA could not 

identify any information or analysis to 

estimate this quantity. As a result, EPA 

considered two additional scenarios to 

represent medium and high levels of ER 

project opt ins. Section 5.2.1 of the final 

Economic Impact Analysis (EIA) (EPA– 

HQ–OAR–2009–0926) details the 

scenario analysis and projected national 

cost estimates. In contrast, facilities 

conducting ER CO2 injection (no GS) 

sales test ratios are below 0.01 percent, 

as illustrated in Table 6 of this 

preamble. 


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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. 

Response: As described previously, 

EPA conducted a thorough analysis of 

available information and reviewed 

comments submitted on this issue, and 

we have determined that this analysis 

provides a reasonable characterization 

of costs for facilities in each subpart, 

under current law, and that the 

documentation provides adequate 

explanation of how the costs were 

estimated. EPA has estimated the total 

national cost of the reporting program 

based on current laws and regulations. 

Accordingly, one would not expect large 

scale deployment of CCS in the absence 

of a comprehensive climate policy that 

required or otherwise incentivized GS. 

In response to comments that total 

national costs would be higher given 

large scale deployment of CCS, EPA has 

augmented the scenario analyzing costs 

assuming future climate policy in 

Section 5.2.2 of the final EIA. Given the 

potential for future deployment of CCS 

technologies, EPA considered two 

additional scenarios of the number of 

large scale saline aquifer GS 

(commercial saline) project deployment 

by 2050: low (5 projects), medium (9 

projects), and high (54 projects). The 

low scenario is based on the low end of 

the range of deployment targeted by the 

CCS Task Force. The medium scenario 

is based on large scale saline project 

deployment projected in the cost 

analysis prepared for the UIC Class VI 

final rule. The high scenario is based on 

EPA modeling of the projected 

deployment of CCS under the American 

Power Act. The national first year 

annual cost estimates increase by $1.3 

million under the low outcome; $2.5 

million under the medium outcome, 

and $16.8 million under the high 

outcome. In addition to the scenarios 

above, EPA also considered scenarios of 

the number of ER operations that would 

choose to report as facilities conducting 

GS (ER opt in) in Section 5.2.1 of the 

final EIA. In the medium scenario, all 

anthropogenic 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 $318,000 for 

the first year and $240,000 for 

subsequent years. The ER opt in 

scenario used the ‘Facilities Conducting 

GS (ER opt in)’ project cost, with an 

estimated cost of $2.1 million for the 

first year and $2.0 million for the 

subsequent year. The basis for these cost 

estimates is explained in detail in 

Section 4 of the EIA (EPA–HQ–OAR– 

2009–0926). The principal driver in the 

difference in national costs for these 

scenarios is the type of project assumed 

to be reporting. 

EPA used the same first year, 

subsequent year methodology for these 

cost scenarios that was used in the core 

national cost analysis. This assumes that 

the number of projects in a given 

scenario all opt in or begin required 

reporting in year 1. This assumption 

overestimates the national cost under 

these scenarios, as it is more likely that 

projects will opt in or begin required 

reporting over a long period of time. 

D. What are the impacts of the rule on 

small businesses? 

1. Summary of Impacts on Small 

Businesses 

As required by the RFA and the Small 

Business Regulatory Enforcement and 

Fairness ACT (SBREFA), EPA assessed 

the potential impacts of the rule on 

small entities (small businesses, 

governments, and non-profit 

organizations). (See Section IV.C of this 

preamble for definitions of small 

entities.) 

After considering the economic 

impact of the rule on small entities, EPA 

has concluded that this action will not 

have a significant economic impact on 

a substantial number of small entities. 

Currently EPA has determined that 

small ER operations will most likely be 

UIC Class II ER projects that do not opt 

in to subpart RR. As shown in Table 6 

of this preamble, the average ratio of 

annualized reporting program costs to 

revenues of a typical ER operation likely 

owned by a representative small 

enterprise and reporting under subpart 

UU was less than 0.1 percent. 

Although this rule will not have a 

significant economic impact on a 

substantial number of small entities, 

EPA nonetheless took several steps to 

reduce the impact of this rule on small 

entities. For example, EPA’s monitoring 

and reporting requirements are built off 

of the UIC program. In addition, EPA is 

requiring equipment and methods that 

may already be in use by a facility for 

compliance with its UIC permit. Also, 

EPA is requiring annual reporting 

instead of more frequent reporting. 

E. What are the benefits of the rule for 

society? 

EPA examined the potential benefits 

of this rule. EPA’s previous analysis of 

the GHG Reporting Program discussed 

the benefits of a reporting system with 

respect to policy making relevance, 

transparency issues, and market 

efficiency. Instead of a quantitative 

analysis of the benefits, EPA conducted 

a systematic literature review of existing 

studies, including government, 

consulting, and scholarly reports. 


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14Although CBI determinations are usually made 

on a case-by-case basis, on July 7, 2010, EPA 

published a proposed rule (75 FR 39094) relating 

to CBI determinations for the data collected under 

the GHG Reporting Program (40 CFR part 98). 

The greatest benefit of mandatory 

reporting of industry GHG emissions to 

government will be realized in 

developing future GHG policies. 

Benefits to industry of GHG emissions 

monitoring include the value of having 

independent, verifiable data to present 

to the public to demonstrate appropriate 

environmental stewardship, and a better 

understanding of their emission levels 

and sources to identify opportunities to 

reduce emissions. Such monitoring 

allows for inclusion of standardized 

GHG data into environmental 

management systems, providing the 

necessary information to achieve and 

disseminate their environmental 

achievements. 

Standardization will also be a benefit 

to industry. Once facilities invest in the 

institutional knowledge and systems to 

report emissions, the cost of monitoring 

should fall and the accuracy of the 

accounting should improve. A 

standardized reporting program will 

also allow for facilities to benchmark 

themselves against similar facilities to 

understand better their relative standing 

within their industry. 

IV. Statutory and Executive Order 

Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review 

Under Executive Order (EO) 12866 

(58 FR 51735, October 4, 1993), this 

action is a ‘‘significant regulatory action’’ 

because it may raise novel legal or 

policy issues arising out of legal 

mandates, the President’s priorities, or 

the principles set forth in the EO. 

Accordingly, EPA submitted this action 

to the Office of Management and Budget 

(OMB) for review under EO 12866 and 

any changes made in response to OMB 

recommendations have been 

documented in the docket for this 

action. 

EPA prepared an analysis of the 

potential costs and benefits associated 

with this action in the EIA (EPA–HQ– 

OAR–2009–0926). A copy of the 

analysis is available in the docket for 

this action and the analysis is briefly 

summarized here. In the EIA, EPA has 

identified the regulatory options 

considered, their costs, and the 

emissions that would likely be reported 

under each option, and explained the 

selection of the option chosen for the 

rule. The costs of the rule are reported 

in Section 4 of the EIA, and the 

economic impacts and qualitative 

benefits assessment are reported in 

Section 5 of the EIA. Overall, EPA has 

concluded that the costs of the Injection 

and Geologic Sequestration of Carbon 

Dioxide Reporting Rule are justified by 

the potential benefits of more 

comprehensive information about 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: 

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 well-informed 

decisions about whether and how to use 

the CAA to regulate these facilities and 

encourage voluntary reductions. 

Because EPA does not yet know the 

specific policies that will be adopted, 

the data reported through the mandatory 

reporting system should be of sufficient 

quality to inform policy and program 

development. Also, consistent with the 

Appropriations Act, the reporting rule 

covers a broad range of sectors of the 

economy including sites that inject and 

store 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 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 electricitygenerating units that are already 

required to report quarterly under 40 

CFR part 75 (acid rain program); and the 

estimated average number of likely 

respondents per year is 93. The cost 

burden to respondents resulting from 

the collection of information includes 

the total capital and start-up cost 

annualized over the equipment’s 

expected useful life (averaging $717,000 

per year) a total operation and 

maintenance component (averaging $5.3 

million per year), and a labor cost 

component (averaging $1.0 million per 

year). Burden is defined at 5 CFR part 

1320.3(b). Although not included in the 

primary economic analysis, the costs 

and burdens to the ER opt ins were 

estimated using an alternate cost 

scenario and in this section EPA is 

giving its best estimates of likely costs 

and burdens, including to voluntary 

reporters, as required by the Paperwork 

Reduction Act. These cost numbers 

differ from those shown elsewhere in 

the EIA for this final rule because ICR 

costs represent the average cost over the 

first three years of the rule, but costs are 

reported elsewhere in the EIA for the 

first year of the rule and for subsequent 

years of the rule. Also, the ICR focuses 

on respondent burden only, while the 

EIA for this final rule includes EPA 

Agency costs as well. An agency may 

not conduct or sponsor, and a person is 

not required to respond to, a collection 

of information unless it displays a 

currently valid OMB control number. 

The OMB control numbers for EPA’s 

regulations in 40 CFR are listed in 40 

CFR part 9. When this ICR is approved 

by OMB, the Agency will publish a 

technical amendment to 40 CFR part 9 

in the Federal Register to display the 

OMB control number for the approved 

information collection requirements 

contained in this final rule. 

C. Regulatory Flexibility Act (RFA) 

The RFA generally requires an agency 

to prepare a regulatory flexibility 

analysis of any rule subject to notice 

and comment rulemaking requirements 

under the Administrative Procedure Act 

or any other statute unless the agency 

certifies that the rule will not have a 

significant economic impact on a 


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substantial number of small entities. 

Small entities include small businesses, 

small organizations, and small 

governmental jurisdictions. 

For purposes of assessing the impacts 

of today’s rule on small entities, small 

entity is defined as: (1) A small business 

as defined by the Small Business 

Administration’s regulations at 13 CFR 

121.201; (2) a small governmental 

jurisdiction that is a government of a 

city, county, town, school district or 

special district with a population of less 

than 50,000; and (3) a small 

organization that is any not-for-profit 

enterprise which is independently 

owned and operated and is not 

dominant in its field. 

After considering the economic 

impacts of this final rule on small 

entities, I certify that this rule will not 

have a significant economic impact on 

a substantial number of small entities. 

Currently EPA has determined that 

small ER operations will most likely be 

facilities conducting 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 this rule on small 

entities. For example, monitoring and 

reporting requirements are built off of 

the UIC program. In addition, EPA is 

requiring equipment and methods that 

may already be in use by a facility for 

compliance with its UIC permit. Also, 

EPA is requiring annual reporting 

instead of more frequent reporting. 

During rule implementation, EPA will 

maintain an ‘‘open door’’ policy for 

stakeholders to ask questions about the 

rule or provide suggestions to EPA 

about the types of compliance assistance 

that will be useful to small businesses. 

EPA intends to develop a range of 

compliance assistance tools and 

materials and conduct extensive 

outreach for this final rule. 

D. Unfunded Mandates Reform Act 

(UMRA) 

Title II of the Unfunded Mandates 

Reform Act of 1995 (UMRA), Public 

Law 104–4, establishes requirements for 

Federal agencies to assess the effects of 

their regulatory actions on State, local, 

and Tribal governments and the private 

sector. Under CAA section 202 of the 

UMRA, EPA generally must prepare a 

written statement, including a costbenefit analysis, for final rules with 

‘‘Federal mandates’’ that may result in 

expenditures to State, local, and Tribal 

governments, in the aggregate, or to the 

private sector, of $100 million or more 

in any one year. 

This final rule does not contain a 

Federal mandate that may result in 

expenditures of $100 million or more 

for State, local, and Tribal governments, 

in the aggregate, or the private sector in 

any one year. Overall, EPA estimates 

that the total annualized costs of this 

final rule are approximately $1.1 

million (in 2008$) during the first year 

of the program and $1.0 million in 

subsequent years (including $344,000 of 

programmatic costs to the Agency). 

Thus, this final rule is not subject to the 

requirements of CAA sections 202 or 

205 of the UMRA. 

This final rule is also not subject to 

the requirements of CAA section 203 of 

the UMRA because it contains no 

regulatory requirements that might 

significantly or uniquely affect small 

governments. Facilities subject to this 

final rule include facilities that inject 

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.’’ ‘‘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 

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 

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. 


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See the ‘‘Summary of EPA Outreach 

Activities for Developing the GHG 

reporting rule,’’ in Docket No. EPA–HQ– 

OAR–2008–0508–055 for a complete list 

of Tribal contacts. EPA participated in 

a conference call with Tribal air 

coordinators in April 2009 and prepared 

a guidance sheet for Tribal governments 

on the proposed GHG reporting rule. It 

was posted on the GHG Reporting 

Program website and published in the 

Tribal Air Newsletter. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

This action is not subject to EO 13045 

because it does not establish an 

environmental standard intended to 

mitigate health or safety risks, and it is 

not an economically significant 

regulatory action under EO 12866. 

H. Executive Order 13211: Actions That 

Significantly Affect Energy Supply, 

Distribution, or Use 

This final rule is not a ‘‘significant 

energy action’’ as defined in EO 13211 

(66 FR 28355, May 22, 2001) because it 

is not likely to have a significant 

adverse effect on the supply, 

distribution, or use of energy. Further, 

EPA has concluded that this rule is not 

likely to have any adverse energy 

effects. This final rule relates to 

monitoring, reporting and 

recordkeeping at facilities that inject 

and/or sequester 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. 

I. National Technology Transfer and 

Advancement Act 

Section 12(d) of the National 

Technology Transfer and Advancement 

Act of 1995 (NTTAA), Public Law 104– 

113 (15 U.S.C. 272 note) directs EPA to 

use voluntary consensus standards in its 

regulatory activities unless to do so 

would be inconsistent with applicable 

law or otherwise impractical. Voluntary 

consensus standards are technical 

standards (e.g., materials specifications, 

test methods, sampling procedures, and 

business practices) that are developed or 

adopted by voluntary consensus 

standards bodies. NTTAA directs EPA 

to provide Congress, through OMB, with 

explanations when the Agency decides 

not to use available and applicable 

voluntary consensus standards. This 

rulemaking involves technical 

standards. EPA developed no new 

measuring device standard. Rather we 

allow the use of an appropriate standard 

method published by a consensus-based 

standards organization if such a method 

exists; or an industry standard practice. 

J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

Executive Order 12898 (59 FR 7629, 

February 16, 1994) establishes Federal 

executive policy on environmental 

justice. Its main provision directs 

Federal agencies, to the greatest extent 

practicable and permitted by law, to 

make environmental justice part of their 

mission by identifying and addressing, 

as appropriate, disproportionately high 

and adverse human health or 

environmental effects of their programs, 

policies, and activities on minority 

populations and low-income 

populations in the United States. 

EPA has determined that the final rule 

will not have disproportionately high 

and adverse human health or 

environmental effects on minority or 

low-income populations because it does 

not affect the level of protection 

provided to human health or the 

environment. The final rule does not 

affect the level of protection provided to 

human health or the environment 

because it is a rule addressing 

information collection and reporting 

procedures only. 

K. Congressional Review Act 

The Congressional Review Act, 5 

U.S.C. 801 et seq., as added by the Small 

Business Regulatory Enforcement 

Fairness Act of 1996, generally provides 

that before a rule may take effect, the 

agency promulgating the rule must 

submit a rule report, which includes a 

copy of the rule, to each House of the 

Congress and to the Comptroller General 

of the United States. EPA will submit a 

report containing this rule and other 

required information to the U.S. Senate, 

the U.S. House of Representatives, and 

the Comptroller General of the U.S. 

prior to publication of the rule in the 

Federal Register. A major rule cannot 

take effect until 60 days after it is 

published in the Federal Register. This 

action is not a ‘‘major rule’’ as defined 

by 5 U.S.C. 804(2). This rule will be 

effective December 31, 2010. 

List of Subjects 

40 CFR Part 72 

Acid rain, Administrative practice 

and procedure, Air pollution control, 

Electric utilities, Intergovernmental 

relations, Nitrogen oxides, Reporting 

and recordkeeping requirements, Sulfur 

dioxide. 

40 CFR Part 78 

Acid rain, Administrative practice 

and procedure, Air pollution control, 

Electric utilities, Intergovernmental 

relations, Nitrogen oxides, Reporting 

and recordkeeping requirements, Sulfur 

dioxide. 

40 CFR Part 98 

Environmental protection, 

Administrative practice and procedure, 

Greenhouse gases, Air pollution control, 

Reporting and recordkeeping 

requirements. 

Dated: November 22, 2010. 

Lisa P. Jackson, 

Administrator. 

■ 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 

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. 


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■ 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. 

(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. 

(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] 

■ 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 Categories a Applicable in 2010 

and Future Years 

* * * * * 

Additional Source Categories a Applicable 

in 2011 and Future Years 

* * * * * 

Geologic sequestration of carbon dioxide 

(subpart RR). 

Injection of carbon dioxide (subpart UU). 

aSource categories are defined in each applicable subpart. 

■ 9. Part 98 is amended by adding 

subpart RR to read as follows: 

Subpart RR—Geologic Sequestration of 

Carbon Dioxide 

Sec. 

98.440 Definition of the source category. 

98.441 Reporting threshold. 

98.442 GHGs to report. 

98.443 Calculating CO2 geologic 

sequestration. 

98.444 Monitoring and QA/QC 

requirements. 

98.445 Procedures for estimating missing 

data. 

98.446 Data reporting requirements. 

98.447 Records that must be retained. 

98.448 Geologic sequestration monitoring, 

reporting, and verification (MRV) plan. 

98.449 Definitions. 

Subpart RR—Geologic Sequestration 

of Carbon Dioxide 

§ 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 

exemption from reporting under this 

subpart for the duration of the research 

and development activity. 

(1) Process for obtaining an 

exemption. If you are a research and 

development project, you must submit 

the information in paragraph (d)(2) of 

this section to EPA by the time you 

would be otherwise required to submit 

an MRV plan under § 98.448. EPA will 

use this information to verify that the 

project is a research and development 

project. 

(2) Content of submission. A 

submission in support of an exemption 

as a research and development project 

must contain the following information: 

(i) The planned duration of 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 

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 


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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 

requirements of this subpart, the owner 

or operator must continue for each year 

thereafter to comply with all 

requirements of this subpart, including 

the requirement to submit annual 

reports, until the Administrator has 

issued a final decision on an owner or 

operator’s request to discontinue 

reporting. 

(1) Timing of request. The owner or 

operator of a facility may submit a 

request to discontinue reporting any 

time after the well or group of wells is 

plugged and abandoned in accordance 

with applicable requirements. 

(2) Content of request. A request for 

discontinuation of reporting must 

contain either paragraph (b)(2)(i) or 

(b)(2)(ii) of this section. 

(i) For wells permitted as Class VI 

under the Underground Injection 

Control program, a copy of the 

applicable Underground Injection 

Control program Director’s 

authorization of site closure. 

(ii) For all other wells, and as an 

alternative for wells permitted as Class 

VI under the Underground Injection 

Control program, a demonstration that 

current monitoring and model(s) show 

that the injected CO2 stream is not 

expected to migrate in the future in a 

manner likely to result in surface 

leakage. 

(3) Notification. The Administrator 

will issue a final decision on the request 

to discontinue reporting within a 

reasonable time. Any appeal of the 

Administrator’s final decision is subject 

to the provisions of part 78 of this 

chapter. 

§ 98.442 GHGs to report. 

You must report: 

(a) Mass of 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. 

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. 

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. 

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). 


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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. 

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 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 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. 

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. 

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. 

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 injected 

through all injection wells in 

accordance with the procedure specified 

in Equation RR–6 of this section. 

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. Mass flow and concentration 

data measurements must be made in 

accordance with § 98.444. 


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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. 

Where: 

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. 

Where: 

CO2P = Total annual CO2 mass produced 

(metric tons) through all separators in 

the reporting year. 

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. 

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 

accordance with the procedure specified 

in Equation RR–11 of this section. 

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 


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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. 

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. 

(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. 

(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 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. 

(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 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 


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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 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. 

(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 

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. 

(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. 

(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. 

(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 


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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. 

(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 

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 

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 RR–10 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 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. 

(13) If a well is permitted under the 

Underground Injection Control program, 

for each injection well, report: 

(i) The well identification number 

used for the Underground Injection 

Control permit. 

(ii) The Underground Injection 

Control permit class. 

(14) If an offshore well is not subject 

to the Safe Drinking Water Act, for each 

injection well, report any well 

identification number and any 

identification number used for the legal 

instrument authorizing geologic 

sequestration. 

§ 98.447 Records that must be retained. 

(a) You must follow the record 

retention requirements specified by 

§ 98.3(g). In addition to the records 

required by § 98.3(g), you must retain 

the records specified in paragraphs 

(a)(1) through (7) of this section, as 

applicable. You must retain all required 

records for at least 3 years. 

(1) Quarterly records of 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 

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 


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

begin collecting data. 

§ 98.448 Geologic sequestration 

monitoring, reporting, and verification 

(MRV) plan. 

(a) Contents of MRV plan. You must 

develop and submit to the 

Administrator a proposed MRV plan for 

monitoring, reporting, and verification 

of geologic sequestration at your facility. 

Your proposed MRV plan must contain 

the following components: 

(1) Delineation of the maximum 

monitoring area and the active 

monitoring areas. The first period for 

your active monitoring area will begin 

from the date determined in your MRV 

plan through the date at which the plan 

calls for the first expansion of the 

monitoring area. The length of each 

monitoring period can be any time 

interval chosen by you that is greater 

than 1 year. 

(2) Identification of potential surface 

leakage pathways for 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 sitespecific variables for the mass balance 

equation. This includes, but is not 

limited to, considerations for calculating 

equipment leakage and vented 

emissions between the injection flow 

meter and injection well and/or the 

production flow meter and production 

well, and considerations for calculating 

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 MRV plan, you must notify 

EPA when the legal instrument 

authorizing geologic sequestration has 

been approved. 

(7) Proposed date to begin collecting 

data for calculating total amount 

sequestered according to equation RR– 

11 or RR–12 of this subpart. This date 

must be after expected baselines as 

required by paragraph (a)(4) of this 

section are established and the leakage 

detection and quantification strategy as 

required by paragraph (a)(3) of this 

section is implemented in the initial 

AMA. 

(b) Timing. You must submit a 

proposed MRV plan to EPA according to 

the following schedule: 

(1) You must submit a proposed MRV 

plan to EPA by June 30, 2011 if you 

were issued a final Underground 

Injection Control permit authorizing the 

injection of 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 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. 

(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 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 


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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 onehalf mile or greater if known leakage 

pathways extend laterally more than 

one-half mile. 

(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 all-around 

buffer zone of at least one-half mile. 

Research and development project 

means a project for the purpose of 

investigating practices, monitoring 

techniques, or injection verification, or 

engaging in other applied research, that 

will enable safe and effective long-term 

containment of a 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), 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: 

Subpart UU—Injection of Carbon Dioxide 

Sec. 

98.470 Definition of the source category. 

98.471 Reporting threshold. 

98.472 GHGs to report. 

98.473 Calculating CO2 received. 

98.474 Monitoring and QA/QC 

requirements. 

98.475 Procedures for estimating missing 

data. 

98.476 Data reporting requirements. 

98.477 Records that must be retained. 

98.478 Definitions. 

Subpart UU—Injection of Carbon 

Dioxide 

§ 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 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. 

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 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. 


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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 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. 

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. 

(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. 

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. 

(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 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 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 


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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 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 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: 

(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 

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. 

(6) The number of times in the 

reporting year for which substitute data 

procedures were used to calculate 

values reported in paragraphs (b)(1) and 

(b)(2) of this section. 

(c) If you use more than one receiving 

flow meter, report the net total mass of 

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. 

(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 


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discontinued enhanced oil or natural 

gas or other production well, and 

transferred to your facility. 

[FR Doc. 2010–29934 Filed 11–30–10; 8:45 am] 

BILLING CODE 6560–50–P 


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