U.S. Environmental Protection Agency 

Documentation of OMB Review Under Executive Order 12866 

Title of Action: 

Docket#: FRL#: RIN:

This action was submitted to the Office of Management and Budget (OMB) for review under Executive Order (E.O.) 

12866, titled Regulatory Planning and Review (58 FR 51735, October 4, 1993). Whenever EPA makes publicly available 

a regulatory action that was reviewed under E.O. 12866, section 6(a)(3)(E) of the E.O. directs the Agency to also: 

(1) Make available to the public a copy of the information that was provided to OMB’s Office of Information and 

Regulatory Affairs (OIRA) for review under the E.O., i.e., the text of the draft regulatory action and, if applicable, 

an assessment of the potential costs and benefits, as well as additional information for those actions that are 

determined to be economically significant under the E.O. (Information requirements are described in sections 

6(a)(3)(B) and (C)). 

(2) Identify for the public any substantive changes between the draft submitted to OIRA and the action that was 

subsequently issued, using a method that is complete, clear, and simple. 

(3) Identify for the public those substantive changes made at the suggestion or recommendation of OIRA.

For this regulatory action, were substantive changes made to information reviewed under E.O. 

12866? [Please check the appropriate answer.]

No. [In the docket, include the information identified in item (1) below.]

Yes. [In the docket, include the information identified in items (1) – (3) below.]

Accordingly, the Agency has included this form and the following information in the public 

docket for this regulatory action: [Please check the appropriate information.]

(1) A copy of the information that was provided to OIRA for review under the E.O. 

(2) Documentation of any substantive changes made to the draft regulatory text that was 

submitted to OIRA when compared with what was subsequently made publicly available. 

The documentation is provided on the pages following this form. Changes made at the 

suggestion or recommendation of OIRA, if any, are clearly identified through attribution to 

OIRA. EPA has used one or more of the following methods to note changes: [Select the 

appropriate option(s).]

(a) Redline-Strikeout – A copy of the draft regulatory action submitted, using redlinestrikeout to show the substantive changes that were made. 

(b) Hand Markup – A copy of the draft regulatory action submitted, using handwritten notes 

to show the substantive changes that were made. 

(c) Note to the file - A document that identifies the substantive changes that were made, 

with page and paragraph references to the draft regulatory action that was submitted. 

If you have any questions about this regulatory action or this documentation, please call the 

contact: 

Name: Email: Phone: 

Revised 05/05/2010 
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6560.50

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 98

[EPA-HQ-OAR-2009-0926; FRL-9131-2]

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

monitoring and reporting from facilities that conduct

geologic sequestration (GS) of carbon dioxide (CO2) and all

other facilities that conduct injection of CO2. This rule

does not require control of greenhouse gases (GHGs), rather

it requires only monitoring and reporting of GHGs.

DATES: The final rule is effective on [INSERT THE

DATE 60 DAYS AFTER PUBLICATION IN THE FEDERAL REGISTER].

ADDRESSES: EPA has established a docket for this

action under Docket ID No. EPA-HQ-OAR-2009-0926. All

documents in the docket are listed on the

www.regulations.gov Web site. Although listed in the

index, some information is not publicly available, e.g.,

confidential business information (CBI) or other
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information whose disclosure is restricted by statute.

Certain other material, such as copyrighted material, is

not placed on the Internet and will be publicly available

only in hard copy form. Publicly available docket

materials are available either electronically through

www.regulations.gov or in hard copy at EPA’s Docket Center,

Public Reading Room, EPA West Building, Room 3334, 1301

Constitution Avenue, NW., Washington, DC 20004. This

Docket Facility is open from 8:30 a.m. to 4:30 p.m., Monday

through Friday, excluding legal holidays. The telephone

number for the Public Reading Room is (202) 566-1744, and

the telephone number for the Air Docket is (202) 566-1742.

FOR FURTHER INFORMATION CONTACT: For technical

information and implementation materials, please go to the

Web site

www.epa.gov/climatechange/emissions/ghgrulemaking.html. To

submit a question, select Rule Help Center, followed by

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:
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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 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

GS 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
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relevant criteria in the sections related to the injection

and GS of CO2. If you have questions regarding the

applicability of this action to a particular facility,

consult the person listed in the preceding “FOR FURTHER

INFORMATION CONTACT” section.

Some facilities that are affected by today’s 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 C

40 CFR part 98, subpart W

40 CFR part 98, subpart PP

Injection of Carbon

Dioxide

40 CFR part 98, subpart C

40 CFR part 98, subpart W

40 CFR part 98, subpart PP

Judicial Review.
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Under section 307(b)(1) of the CAA, judicial review of

this final rule is available only by filing a petition for

review in the U.S. Court of Appeals for the District of

Columbia Circuit by [INSERT THE DATE 60 DAYS AFTER

PUBLICATION IN THE FEDERAL REGISTER]. 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),
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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

AMA active monitoring area

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

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
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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 Rule

A. How were compliance costs estimated?
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B. What are the costs of the rule?

C. What are the economic impacts of the rule?

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

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

IV. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review

B. Paperwork Reduction Act

C. Regulatory Flexibility Act (RFA)

D. Unfunded Mandates Reform Act (UMRA)

E. Executive Order 13132: Federalism

F. Executive Order 13175: Consultation and Coordination

with Indian Tribal Governments

G. Executive Order 13045: Protection of Children from

Environmental Health Risks and Safety Risks

H. Executive Order 13211: Actions that Significantly

Affect Energy Supply, Distribution, or Use

I. National Technology Transfer and Advancement Act

J. Executive Order 12898: Federal Actions to Address

Environmental Justice in Minority Populations and LowIncome Populations

K. Congressional Review Act

I. Background

A. Organization of this Preamble

This preamble is divided into four large sections, as

detailed above in the Table of Contents. The paragraphs

below describe the layout of the preamble and provide 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
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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 Underground

Injection Control (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 Greenhouse Gas (GHG) Reporting Program and

confidentiality determination for data elements in 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

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.
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Finally, the last section of this preamble discusses

the various statutory and executive order requirements

applicable to this proposed rulemaking.

B. Background on the Final Rule

Today’s 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 GHG suppliers in 32

subparts. For more detailed background information on the

GHG Reporting Program, see the preamble to the final rule

establishing that program (74 FR 56260, October 30, 2009).

Subpart PP of the GHG Reporting Program requires the

reporting of CO2 supplied to the economy. During the public

comment period on the final rule establishing that

requirement, EPA received many comments that CO2

geologically sequestered should be considered in the GHG

Reporting Program. (For further information on relevant
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comments received in subpart PP see “Mandatory Greenhouse

Gas Reporting Rule: EPA's Response to Public Comments,

Subpart PP: Suppliers of Carbon Dioxide” in Docket EPA-HQOAR-2008-0508.) In the final rule promulgating subpart PP,

EPA committed to taking action to collect such data in the

near future.

Today’s rule amends 40 CFR part 98 to add reporting

requirements covering facilities that conduct geologic

sequestration of CO2 (subpart RR) and all other facilities

that conduct injection of CO2 (subpart UU). This data will

inform Agency decisions under CAA sections 111 and 112

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. For example, EPA will be able to track

whether incentives or regulations are needed to encourage

faster or further GS project development. Furthermore,

where enhanced oil and gas recovery (ER) projects are

reporting under subpart RR, EPA will be able to evaluate ER

as a non-emissive end use. Under subpart UU, EPA will be

able to reconcile information obtained from this rule with
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data obtained from subpart PP on CO2 supplied to the

economy.

Today’s rule was proposed by EPA on April 12, 2010.

One public hearing was held on April 19, 2010, and the

sixty day public comment period ended June 11, 2010. This

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.

Today's final rule does not address whether data

reported under 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) which addressed this issue. In that action, EPA

proposed which specific data elements would be released to

the public and which would be treated as CBI. EPA received

several comments on that proposal under that action, and is

in the process of considering these comments. A final rule

and determination will be issued before any data is

released. The final determination will address CBI

considerations for all of the data elements under subparts

RR and UU.

C. Legal Authority
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As proposed, 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 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, 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 the

provisions in the CAA (except for a provision of title II

with respect to motor vehicles). EPA may gather

information for a variety of purposes, including for the

purpose of assisting in the development of implementation

plans or of emissions standards under CAA section 111,

determining compliance with implementation plans or such

standards, or more broadly for “carrying out any provision”

of the CAA.

D. Relationship to Underground Injection Control

Regulations under the Safe Water Drinking Act
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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,
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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.

1

EPA designed the reporting requirements under 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). 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 subpart RR mass balance approach2 used to

quantify the amount of CO2 sequestered. EPA determined that

quarterly data collection and annual reporting under

1 http://www.epa.gov/ogwdw000/uic/wells_sequestration.html.

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

that is geologically sequestered includes variables on injected CO2;

fugitive 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.
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subpart RR was necessary in order to harmonize data with

other subparts of the GHG Reporting Program. Facilities

reporting under subpart RR may use flow meters used to

comply with the flow monitoring and reporting provisions in

their permit.

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

Fugitive and vented

emissions from

surface equipment

between flow meters

and the wellhead

Yes N/A

Quantity of CO2

produced with oil or

natural gas (ER) or

other fluids

Yes N/A

Percentage of CO2

estimated to remain

with oil (ER) or

other fluids

Yes N/A

Quantity of CO2

emitted from the

subsurface

Yes N/A

Quantity of CO2

sequestered in the

subsurface

Yes N/A

Cumulative mass of CO2

sequestered in the

subsurface

Yes N/A

Monitoring plan for

detecting air

emissions

Yes Yes
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Monitoring plan for

quantifying air

emissions

Yes N/A

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

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 an MRV plan3 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 subpart RR for

quantification purposes is complementary to and builds on

UIC permit requirements. In particular, the UIC Class VI

3 The subpart RR MRV plan includes delineation of monitoring areas,

identification of potential surface leakage pathways, a strategy for

detecting and quantifying surface leakage of CO2 if leakage occurs, an

approach for establishing the expected environmental and operational

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.
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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 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 surface

detection and quantification of CO2 in the event 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
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appropriate to require surface air or soil gas monitoring

for USDW protection, the UIC Director must approve the use

of monitoring employed under subpart RR so long as the

owner or operator is able to demonstrate USDW protection

pursuant to requirements at §146.90(h)(3).

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 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
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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 [___].

4

For more information, please see the CCS Task Force Web

site.

5

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

4 [Note to draft: This section will be updated with relevant CCS Task

Force recommendations after the CCS Task Force report is finalized.]

5 http://www.whitehouse.gov/administration/eop/ceq/initiatives/ccs.
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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 2009-836 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 monitoring, reporting, and

verification procedures that are being finalized under

subpart RR in this action.

II. Summary of Final Rule

A. Summary of Changes to the General Provisions of the

Greenhouse Gas Reporting Program

Today’s action amends certain requirements in 40 CFR

part 98, subpart A (General Provisions). These amendments

are summarized in this section of the preamble and apply

only to those subparts included in this action. None of

6 Available at: http://www.irs.gov/irb/2009-44_IRB/ar11.html#d0e1860.
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the amendments change the general provisions applicable to

those subparts already incorporated into 40 CFR part 98.

Changes to Applicability. In today’s action, EPA is

amending 40 CFR 98.2(a) so that the GHG Reporting Program

applies to facilities located on or under the Outer

Continental Shelf. These revisions are necessary to ensure

that any facility conducting CO2 injection or GS located on

or under the Outer Continental Shelf of the United States

will be required to report. Other facilities covered by

the GHG Reporting Program at 40 CFR part 98 are also being

affected by this change to applicability (for example,

subpart W petroleum and natural gas systems).

Changes to Definitions. In today’s action, EPA is

also amending 40 CFR 98.6 (definitions). EPA is clarifying

the definition of United States to be clear that the United

States includes the territorial seas. Other facilities

located offshore of the United States covered by the GHG

Reporting Program at 40 CFR part 98 will be affected by

this change in the definition of United States (for

example, subpart W petroleum and natural gas systems). EPA

has also amended 40 CFR part 98 by adding a definition of

“Outer Continental Shelf.” This definition is drawn from

the definition in the U.S. Code. These revisions are

necessary to ensure that any facility conducting CO2
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injection or GS located on or under the Outer Continental

Shelf of the United States will be required to report.

7

B. Summmary of the Reporting Requirements for Geologic

Sequestration of Carbon Dioxide (Subpart RR)

Reporting requirements for facilities conducting GS

are found in 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

subpart UU.

Subpart RR Source Category Definition.

The 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. All

wells permitted as Class VI by the UIC program meet the

definition of this source category. Facilities conducting

ER are not subject to subpart RR unless they choose to optin to the requirements of this subpart or hold a UIC Class

VI permit.

GS R&D projects can apply for an exemption from

reporting requirements under subpart RR. In order to

7 [Note to draft: Whichever rule finalizes first (subpart W or subpart

RR/UU) will have these amendments.]
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obtain an exemption, the owner or operator must demonstrate

to the Administrator’s satisfaction that the project is

neither a demonstration nor a commercial project and that

the project is researching practices and monitoring

techniques that will enable safe and effective long-term

containment of a CO2 stream in subsurface geologic

formations. Projects applying for an exemption must submit

information on the planned duration of CO2 injection for

research, the planned annual CO2 injection volumes during

this time period, the research purposes of the project, the

source and type of funding for the project, whether

research results will be published, 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. EPA will issue a final decision on the

request for an R&D exemption and notify the owner or

operator within 120 days of receipt of the request.

Subpart RR Reporting Threshold.

All facilities that meet the subpart RR source

category definition must report. Once a facility is

subject to the requirements of this subpart, including

facilities that opt-in to subpart RR, the owner or operator

must continue for each year thereafter to comply with all

requirements of this subpart, including the requirement to
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submit annual reports, until the owner or operator has made

a request to discontinue reporting that demonstrates that

the CO2 plume has stabilized and EPA has issued a final

decision on the request to discontinue reporting.

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; the mass of CO2 emitted from surface

leakage; the mass of fugitive and vented CO2 emissions from

sources between the injection flow meter and between the

injection wellhead or the production flow meter and the

production wellhead; and the mass of CO2 sequestered in

subsurface geologic formations.

Subpart RR GHG Calculations and Monitoring.

Facilities covered by this source category must

calculate the annual mass of CO2 received. Starting from

the date outlined 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 and the mass of CO2 emitted

as fugitive or vented emissions from applicable surface

equipment, using the procedures specified in Subpart W of
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the GHG Reporting Program. Facilities that are producing,

oil, gas, or other fluids must additionally subtract the

mass of CO2 produced. Calculation procedures are provided

at §98.443 of the rule.

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.

X A strategy for detecting and quantifying any surface

leakage of CO2 in the event leakage occurs.

X An approach for establishing the expected

environmental and operational baselines.

X A summary of considerations made to calculate sitespecific variables for the mass balance equation.

First, the MRV plan must include a delineation of the

maximum monitoring area (MMA) and the active monitoring
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area (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. The AMA is the area that will be

monitored over a specified time interval chosen by the

reporter that is greater than one year. 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. The boundary of the AMA is

established by superimposing two areas. The first is the

area projected to contain the free phase CO2 plume at the

end of the specified time interval plus an all around

buffer zone of at least one-half mile or greater if known

leakage pathways extend laterally more than one-half mile.8

The second is the area projected to contain the free phase

CO2 plume five years beyond the specified time interval.

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.

8 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.
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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 leakage has occurred,

an explanation of how CO2 leaks will be distinguished from

background or operational variability, 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 leak is detected, the

reporter should have a strategy in place to verify that a

leak has occurred, confirm the location and source of the

leak, and then apply some combination of direct measurement

and estimation to quantify the leak.

Fourth, the MRV plan should include an approach for

establishing the expected environmental and operational

baselines. 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 variability.

Fifth, the MRV plan should include a summary of

considerations made to calculate fugitive and vented

emissions from surface equipment between the flow meters
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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 website, pending the

CBI determination (see section I.B of this preamble). If

the reporter, or any interested person, objects to EPA’s
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final decision, it may be appealed 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, 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; large

changes in injection pressures; failures of the monitoring

system including monitoring system sensitivity,

performance, location, or environmental baseline; changes

to surface land use that affects baseline or operational

conditions; observed plume location that differs from the

predicted plume area used for developing the monitoring

plan; a change in the MMA or AMA; 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 §144.19 of the UIC Class VI rule
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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.

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. Facilities must also report concentration, and mass or

volumetric flow information where flow meters are used or

mass or volume where containers are used. 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,.
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Subpart RR requires reporting of fugitive and vented

CO2 emissions to the extent they are a component of the GS

mass balance. Subpart RR does not require reporting of

fugitive and vented CO2 emissions from all surface equipment

located within the facility; however, facilities may be

required to report fugitive and vented CO2 emissions in the

petroleum and natural gas system subpart, subpart W.

Subpart RR Recordkeeping.

Facilities must retain quarterly records of CO2

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

leakage; CO2 emitted as fugitive 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.

Subpart RR Administrative Appeals.

Under today’s 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 § 78.1 of the types of final decisions that can be
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appealed under part 78 is expanded to cover final decisions

of the Administrator under subpart RR of part 98. This

list includes, but is not limited to, the following

specific types of decisions under subpart RR, e.g., the

approval or disapproval of a request for an R&D exemption

under §98.440(d)(4), the approval or disapproval of a

request for discontinuation of reporting under §

98.441(b)(2), and the approval or disapproval of a MRV plan

under § 98.448(c).

Further, § 78.3 is revised to allow for petitions for

administrative appeal of decisions of the Administrator

under 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, the revised “interested person”

definition is expanded to include, with regard to any

decision by the Administrator, any person who -- in

connection with the Administrator’s process of making that

decision -- submitted comments, testified at a public
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hearing, submitted objections, or submitted his or her name

to be included by the Administrator in an interested

persons list.

In addition, § 78.4 is expanded to state that filings

on behalf of owners and operators of a facility subject to

subpart RR must be signed by the designated representative

of the owners and operators.

E. Summmary of the Reporting Requirements for Injection of

Carbon Dioxide (Subpart UU)

Reporting requirements for all other facilities

conducting CO2 injection are found in subpart UU.

Facilities conducting GS and reporting under subpart RR are

not required to report under subpart UU.

Subpart UU Source Category Definition.

The subpart UU source category consists of any 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 which are exempted from

subpart RR monitoring and reporting requirements. If you

report under subpart RR for a well or group of wells, you

are not required to report under subpart UU for that well

or group of wells.

Subpart UU Reporting Threshold.
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All facilities that inject CO2 underground must report

under this subpart, regardless of the amount of emissions

from the facility or the amount of CO2 injected.

Subpart UU GHGs to Report.

Facilities covered by this source category must report

the annual mass of CO2 received.

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.

Subpart UU Data Reporting.

In addition to reporting the mass of CO2 received,

facilities must report the source of the CO2. Facilities

must also report concentration, and mass or volumetric flow

information where flow meters are used or mass or volume

where containers are used.

Subpart UU Recordkeeping.

Facilities must retain quarterly records of CO2

received.

F. Summary of the Major Changes Since Proposal
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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 below 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, 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 subpart RR.

X EPA has removed the requirement that facilities report

the amount of CO2 injected in subpart UU (Tier 1) but

retained requirements that facilities subject to this

subpart report the amount of CO2 received and the source of

CO2.

X EPA has established procedures for calculating CO2

received in containers.
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X In subpart RR, EPA has established a waiver process

for a GS R&D project to request an exemption from subpart

RR.

X In subpart RR, EPA has retained the requirement that

facilities report the fugitive and vented emissions for

surface equipment that could be included in the GS mass

balance but removed the requirement for reporting fugitive

and vented emissions for all other surface equipment.

X In subpart RR, EPA has added an MRV plan requirement

for the delineation of the areas that will be monitored.

X In subpart RR, EPA has clarified the requirements for

an addendum to the annual report and renamed it monitoring

report.

X EPA has amended 40 CFR part 78 to include

administrative appeals procedures for EPA decisions made

under subpart RR, such as decisions relating to the request

for R&D exemption under §98.440(d)(4), decisions relating

to a request for discontinuation of reporting under

§98.441(b)(2), or MRV plan decisions under §98.448(c).

G. 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
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found in “Mandatory Greenhouse Gas Reporting Rule: EPA's

Response to Public Comments, Subparts RR and UU: Injection

and Geologic Sequestration of Carbon Dioxide.”

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 FY

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 proposing this rule under the

authority provided in CAA section 114. We disagree that we

do not have statutory authority to promulgate this rule.
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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 inform

policy decisions under CAA sections 111 and 112 related to

the use of CCS for mitigating GHG emissions. This data

will prove invaluable to the Agency in several areas,

including reconciling subpart UU data on CO2 received with

CO2 supply data to better understand the amount of CO2

supply that is used for CO2 injection and GS, monitoring the

growth and efficacy of GS over time, and evaluating ER as a

potentially non-emissive end use.

EPA is not citing the FY 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.

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
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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 §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 §98.440(d) that are not included in the

source category.

Response: EPA agrees with commenters that the

structure of proposed §98.440 could be made clearer. It was

never EPA’s intention to override the definition of

facility in §98.6; rather EPA intended to create a defined

term “GS facility” to provide clarity about which
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facilities under the subpart RR source category would be

subject to both “Tier 2” and “Tier 1” requirements. To

harmonize 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

today’s 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 §98.6. EPA has provided several examples in

the General Technical Support Document (TSD) 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 subpart RR and is moving all

procedures and requirements for all other facilities

conducting CO2 injection (Tier 1) into a new subpart UU in

today’s action. EPA has concluded that this organizational

change allows for two source category definitions while

clearly distinguishing the two sets of provisions and
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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 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 today’s final action, EPA removed from the

regulatory text the list of activities that are not

included in the source category. Based on experience with

implementation questions from reporters to the rest of the

GHG Reporting Program, EPA has concluded that this list

does not provide regulatory clarity and instead creates

confusion. Without this list the regulatory text is clear

that the operations covered under 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 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
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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 subpart RR or UU: above

ground CO2 storage, CO2 transportation or distribution, CO2

purification, compression, or processing, CO2 capture, and

CO2 end-uses other than underground injection. EPA notes

that these activities may meet the definition of another

source category in the GHG Reporting Program.

GS R&D

Comment: EPA received a range of comments relating to

exempting GS R&D projects. Some commenters supported the

R&D exemption while others opposed it because they believe

these projects can provide valuable information on the

efficacy of GS as a climate mitigation approach. These

commenters also noted that these projects are currently

gathering data which would provide EPA an early opportunity

to evaluate the appropriateness and application of

monitoring methods. Some commenters suggested that GS R&D

projects be provided an option to opt-in to GS reporting

requirements. One group of commenters recommended that EPA

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

Response: EPA agrees with commenters that collecting

data from all GS projects, including R&D, would provide
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useful information about the efficacy of GS and monitoring

techniques and approaches to quantify leakage. Therefore,

EPA is removing the broad GS R&D exemption. However, the

Agency recognizes that GS is an emerging climate mitigation

approach and there are likely to be some projects which are

focused on testing specific scientific issues or monitoring

techniques rather than verifying GS. Therefore the Agency

is establishing a process to allow for a GS R&D exemption..

In order to obtain an exemption, the owner or operator

must demonstrate to the Administrator’s satisfaction that

the project is neither a demonstration nor a commercial

project and that the project is researching practices and

monitoring techniques that will enable safe and effective

long-term containment of a CO2 stream in subsurface geologic

formations. Projects applying for an exemption must submit

information on the planned duration of injection for

research, planned annual CO2 injection volumes within this

duration, research purpose, source and type of funding,

whether research results will be published, and class and

duration of UIC permit (or relevant legal instrument in the

case of an offshore facility that is not subject to SDWA).

This information will inform the Administrator’s decision

for granting an exemption. For example, a project could

receive an exemption by showing that the project will take
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place over a limited time period; the annual injection

volumes are limited; the project has a research purpose or

research question; the project receives funding from the

Federal government, State government, academia, or the R&D

budget of a private entity; the research results will be

published; and the project holds a UIC Class V experimental

technology well permit of limited duration. The owner or

operator would be notified of EPA’s final decision within

120 days of receipt of the GS R&D exemption request.

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: The Agency agrees with commenters that there

are non-Federal funding sources which could fund GS R&D

projects and that while Federal funding could be an

indication that a project is conducting GS R&D, it should

not be the basis for an R&D exemption. For example,

sources of funding that may indicate that a project is

conducting GS R&D include Federal, State, and academic

sources. Funding from the R&D budget of a private sector

entity may also indicate that a project is conducting GS
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R&D. Therefore, projects applying for an exemption must

submit information on the source and type of funding.

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 a waiver process through which GS R&D

projects can apply for an exemption from reporting

requirements under subpart RR. This option provides EPA

with maximum flexibility to exempt GS R&D projects that are

researching GS practices and monitoring techniques.

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 receiving a

GS R&D waiver under subpart RR are not required to develop

an MRV plan or report information required of facilities
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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.

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.
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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

but recommended expanding “Tier 1” reporting requirements

as a solution 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 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 today’s final action, EPA is retaining

some of the proposed reporting requirements for CO2

injection facilities. EPA is requiring reporting under

subpart UU (previously referred to as “Tier 1” facilities)

of CO2 received (a term which EPA is defining in this final

action for what commenters described as “new” CO2). EPA is

not requiring reporting on total CO2 injection under subpart
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UU. Reporting on total CO2 injection will be required for

facilities conducting GS under 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 subpart

PP. Furthermore, EPA recognizes that the geology of an oil

and gas reservoir can create a good 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 sequestration

by implementing their EPA-approved MRV plans. Though the

collection of either a partial or full set of data from

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
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projects only and by splitting the proposed rule into two

subparts, EPA is making clear in this action that the

quantity of CO2 geologically sequestered can only be

verified and reported to EPA by developing and implementing

an EPA-approved MRV plan and reporting GS under 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 section 98.6).

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.
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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 at this early

stage in the GS industry. As demonstrated by the range of

suggested thresholds provided by commenters, there is not

enough data to determine a 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 today’s final action, EPA is

requiring reporting from all facilities that meet the

subpart UU (previously referred to as “Tier 1” facilities)

source category definition and from all facilities that
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meet the subpart RR (previously referred to as “Tier 2”

facilities) source category definition. EPA is not

establishing a reporting threshold for these facilities.

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, subpart PP)

that is received for injection underground. This approach

is consistent with the all-in requirements in the GHG

Reporting Program for suppliers of petroleum, natural gas,

and coal-to-liquid products (subparts LL, MM, and NN),

producers of industrial gases (subpart OO), and suppliers

of CO2 (subpart PP).

With respect to 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 subpart RR, the Agency notes that GS R&D

projects can apply for a waiver to be exempt from subpart

RR. 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 today’s final action.

Fugitive and Vented Emissions
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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 subpart

W (petroleum and natural gas systems). A few commenters

recommended that EPA require the reporting fugitive and

vented CO2 emissions from facilities (including ER), be

required solely under subpart W and to limit the reporting

of fugitive and vented emissions reporting under subpart RR

to equipment associated with GS operations for which

emissions were not already being reported under subpart W.

A number of commenters disagreed with EPA’s proposed

reporting requirements for fugitive and vented CO2 emissions

and suggested that EPA scale back or eliminate such

reporting, and one commenter supported such reporting

requirements. Four commenters stated that fugitive and

vented emissions would be trivial in comparison 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
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requirements for the reporting of fugitive and vented CO2

emissions.

Response: EPA proposed to require the reporting of

fugitive and vented CO2 emissions in order to better

understand the volume of fugitive and vented GHG 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 fugitive 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 subpart RR because such data is 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 fugitive 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.

MRV Plan Requirements
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Comment: EPA received many comments supporting the

Agency’s proposal that reporters develop a site-specific

MRV plan, but some commenters stated that more detail was

needed about how MRV plans would be evaluated by EPA.

Response: EPA has set out the basic components for MRV

plans in section II.D 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 §98.448 (a). EPA has

also refined the requirements for what should be included

in the annual report, and in what cases the reporter would

need to resubmit an MRV plan for EPA approval.

EPA’s approach allows for site-specific flexibility

for MRV plans and does not prescribe particular monitoring

technologies. The approach also allows the owner or

operator to leverage the site characterization, risk

assessment, and/or monitoring required by other authorities

as the foundation for demonstrating compliance with the MRV

plan requirements of 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 prepared an
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appendix to the General TSD9 that provides information on

the technical evaluation of MRV plans. The General TSD

provides illustrative examples describing the types of

information that may be included in the MRV plan to fulfill

the regulatory requirements at §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.

EPA has also finalized the Monitoring Plan TSD,

10 which

describes the characteristics of a robust monitoring plan,

and provides descriptions of potential GS geologic settings

and potential leakage pathways. The Monitoring Plan TSD

uses EPA’s Vulnerability Evaluation Framework (VEF)11 to

describe potential vulnerabilities that may influence the

risk for CO2 leakage from a GS project. Because the VEF

provides a holistic discussion of the potential impacts of

9 General Technical Support Document for subpart RR (see docket ID No.

EPA–HQ–OAR–2009–0926).

10 Monitoring Plan Technical Support Document (see docket ID No. EPA–HQ–

OAR–2009–0926).

11 Vulnerability Evaluation Framework for Geologic Sequestration of

Carbon Dioxide (see docket ID No. EPA–HQ–OAR–2009–0926).
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GS, it is not intended to be used as a step by step guide

to develop an MRV plan.

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 subpart RR so that

facilities will not need to disrupt or delay normal

operations. However, EPA clarifies that facilities will

not be allowed to report amounts of CO2 geologically

sequestered under subpart RR until they implement an EPAapproved MRV plan.

EPA agrees with commenters that there should be a

process for public involvement. Therefore, EPA plans to

post approved MRV plans to a public website, pending the

outcome of the confidentiality determination for data

elements in the GHG Reporting Program. “Interested

persons” can then appeal EPA decisions on MRV plans to the

Environmental Appeals Board (EAB) through the appeals

process described in part 78 of the Clean Air Act

regulations. An “interested person” is any person who --
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in connection with the Administrator’s process of making

that decision -- submitted comments, testified at a public

hearing, submitted objections, or submitted his or her name

to be included by the Administrator in an interested

persons list. EPA will provide the public instruction on

joining the interested persons list for subpart RR. More

information on the administrative appeals process can be

found in section III.A. and in “Mandatory Greenhouse Gas

Reporting Rule: EPA’s Response to Public Comments,

Subparts RR and UU: Injection and Geologic Sequestration of

Carbon Dioxide.” 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 consider establishing

a public notice and comment period for such a policy or

progam at that time.

EPA has prepared an appendix in the General TSD that

provides further information 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 subpart RR. Some commenters stated that

any class of UIC permit is enough for purposes of the MRV
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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: The Agency maintains a high-level of

coordination across EPA offices and regions on GS

activities and regulatory development. EPA’s OAR and OW

work closely to promote safe and effective implementation

of GS technologies while ensuring protection of human

health and the environment. EPA agrees with commenters

that the UIC program provides the foundation for the safe

sequestration of CO2 by helping to ensure that injected

fluids remain isolated in the subsurface and away from

underground sources of drinking water, thereby serving to

reduce the risk of CO2 leakage to the atmosphere. A

facility’s UIC permit may be used to demonstrate that

certain monitoring, reporting and verification (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 subpart RR

and UIC Class VI requirements.

III. Economic Impacts of the Final Rule
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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.
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The estimated costs are based on hypothetical or proforma sites for various types of projects such as R&D GS

projects, commercial saline formation projects, and ER GS

projects. The geologic and engineering assumptions for

these pro-forma projects are the same as those used by the

EPA Office of Water in the UIC Class VI rule. The costs

are presented in 2008 dollars.

The capital costs are annualized using an interest

rate of 7% 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.
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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 proposed 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.12

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 $7.0 million (2008$),

as illustrated in Table 7 of this preamble. 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 demonstration or commercial GS and

consequently incur costs associated with monitoring,

reporting and verification. Given uncertainties related to

12 Bureau of Labor Statistics. http://www.bls.gov/bls/wages.htm
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project adoption and the costs of the reporting program,

EPA considered two other private cost scenarios (one higher

and one lower than the reference cost scenario) in order to

assess a range of economic impacts on affected entities, as

illustrated in table 8 of this preamble.

Table 7. National Annualized Mandatory Reporting Costs Estimates

(2008$): subparts RR and UU

Reference

Type Number

of

Projects

Metric

Tons CO2

Received

per Year

First Year

(thousand,

2008$)

Second Year

(thousand,

2008$)

R&D (RR) 9 5,320,000 $73 $73

Facilities

Conducting GS

(Saline) (RR)

1 1,842,885 $318 $240

Facilities

Conducting GS (ER)

(RR)

3 3,300,000 $5,913 $5,680

Additional

Facilities

Conducting GS (ER

opt in) (RR)

0 0 $0 $0

Facilities

Conducting CO2

Injection (no

GS)(UU)1

80 40,115,442 $332 $332

Private Sector,

Total All Projects

93 50,578,327 $6,636 $6,636

Private Sector,

Average ($/ton)

- - $0.13 $0.13

Public Sector,

Total

$344 $344

National Total $6,979 $6,670

(1) Includes UIC Class II ER Facilities

Table 8. Annualized Reporting Costs per Project (2008$): subparts RR

and UU

Alternative Cost Scenarios

Reference Low High

Type First

Year

($1,000)

Second

Year

($1,000)

First

Year

($1,000

)

Second

Year

($1,000)

First

Year

($1,000)

Second

Year

($1,000)
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R&D (RR) $8 $8 $8 $8 $8 $8

Facilities

Conducting

GS (Saline)

(RR)

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

Facilities

Conducting

GS (ER)

(RR)

$1,971 $1,893 $1,739 $1,662 $2,117 $2,040

Facilities

Conducting

GS (ER opt

in) (RR)

$2,029 $1,909 $1,797 $1,678 $2,175 $2,056

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 Economic Impact Analysis (EIA), Section 4 (EPA-HQOAR-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 Economic Impact

Analysis (EIA). In some cases, we revised our cost

estimates, and in some cases we revised monitoring and

reporting requirements in ways which reduced burden.
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Please see source specific comments and responses in

Section III.D 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 believes 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 Economic Impact Analysis (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). In contrast, facilities
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conducting ER CO2 injection (no GS) sales test ratios are

below 0.01 percent, as illustrated in Table 9 of this

preamble.

Table 9. 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) (RR)

3.6% 3.2% 3.9%

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 and that the
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documentation provides adequate explanation of how the

costs were estimated. EPA has estimated the total national

cost of the reporting program based on current regulations.

Accordingly, one would not expect large scale deployment of

CCS in absence of a comprehensive climate policy. 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 of the final Economic Impact

Analysis (EIA).

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 V.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 believes small ER

operations will most likely be UIC Class II ER projects.

As shown in Table 9 of this preamble, the average ratio of
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annualized reporting program costs to revenues of a typical

ER operation likely owned by a representative small

enterprise was less than 0.1%.

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 relevence, transparency issues, market

efficiency. Instead of a quantitative analysis of the

benefits, EPA conducted a systematic literature review of

existing studies, including government, consulting, and

scholarly reports.

The greatest benefit of mandatory reporting of

industry GHG emissions to government will be realized in

developing future GHG policies. For example, in the EU’s
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Emissions Trading System, a lack of accurate monitoring at

the facility level before establishing CO2 allowance permits

resulted in allocation of permits for emissions levels an

average of 15 percent above actual levels in every country

except the United Kingdom.

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
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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 Economic Impact

Analysis (EPA-HQ-2009-0926). A copy of the analysis is

available in the docket for this action and the analysis is

briefly summarized here. In this report, EPA has

identified the regulatory options considered, their costs,

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, and the economic impacts and qualitative

benefits assessment are reported in Section 5. Overall,

EPA has concluded that the costs of the Injection and

Geologic Sequestration of Carbon Dioxide Reporting Rule are

outweighed by the potential benefits of more comprehensive

information about CO2 injection. The total annualized cost
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of the rule will be approximately $7 million (in 2008$)

during the first year of the program and $6.7 million in

subsequent years (344,000 of programmatic costs to the

Agency).

B. Paperwork Reduction Act

The information collection requirements in the 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 Balance the rule’s coverage to maximize the amount of

emissions reported while excluding small emitters.

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-
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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.

This information collection is mandatory and will be

carried out under CAA section 114. Information identified

and marked as Confidential Business Information (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.13

The projected cost and hour burden for non-Federal

respondents is $7.0 million and 9,416 hours per year. The

estimated average burden per response is 56.6 hours; the

frequency of response is annual for all respondents that

must comply with the rule’s reporting requirements, except

for electricity-generating units that are already required

to report quarterly under 40 CFR part 75 (acid rain

13 Although CBI determinations are usually made on a case-by-case basis,

on July 7, 2010, EPA published a proposed rule (75 FR 39094) relating

to CBI determinations for the data collected under the GHG Reporting

Program (40 CFR part 98).
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program); and the estimated average number of likely

respondents per year is 9. 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). These cost

numbers differ from those shown elsewhere in the EIA for

the 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 total

cost estimate of the rule in the EIA includes the cost to

the Agency to administer the program. In addition, the ICR

focuses on respondent burden, while the EIA for the final

rule includes EPA Agency costs. 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
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Register to display the OMB control number for the approved

information collection requirements contained in the final

rule.

C. Regulatory Flexibility Act (RFA)

The RFA generally requires an agency to prepare a

regulatory flexibility analysis of any rule subject to

notice and comment rulemaking requirements under the

Administrative Procedure Act or any other statute unless

the agency certifies that the rule will not have a

significant economic impact on a substantial number of

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 today’s

final rule on small entities, I therefore certify that this

proposed rule will not have a significant economic impact
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on a substantial number of small entities. Currently EPA

believes small ER operations will most likely be facilities

conducting CO2 injection, including UIC Class II ER

projects. 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 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 the final rule.

D. Unfunded Mandates Reform Act (UMRA)
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Title II of the Unfunded Mandates Reform Act of 1995

(UMRA), P.L. 104-4, establishes requirements for federal

agencies to assess the effects of their regulatory actions

on state, local, and tribal governments and the private

sector. Under Section 202 of the UMRA, EPA generally must

prepare a written statement, including a cost-benefit

analysis, for final rules with “federal mandates” that may

result in expenditures to state, local, and tribal

governments, in the aggregate, or to the private sector, of

$100 million or more in any one year.

The 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 $7 million (in 2008$) during the first year

of the program and $6.7 million in subsequent years

($344,000 of programmatic costs to the Agency). Thus, the

final rule is not subject to the requirements of sections

202 or 205 of UMRA.

The final rule is also not subject to the requirements

of section 203 of UMRA because it contains no regulatory

requirements that might significantly or uniquely affect

small governments. Facilities subject to the final rule
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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 executive order 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.”

The 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 Executive Order 13132.

This regulation applies to public- or private-sector

facilities that inject CO2 underground. Few government
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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, Executive Order 13132 does not apply

to the final rule.

In the spirit of Executive Order 13132, and consistent

with EPA policy to promote communications between EPA and

State and local governments, EPA specifically solicits

comment on the final action 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.”

The final rule is not expected to have tribal

implications, as specified in Executive Order 13175. This

regulation applies directly to facilities that inject

and/or sequester CO2 underground. Few facilities expected
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to be affected by the rule are likely to be owned by tribal

governments. Thus, Executive Order 13175 does not apply to

the final rule.

Although Executive Order 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. 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 TCR. In addition, EPA prepared

a short article on the GHG reporting rule that appeared on

the front page of a tribal newsletter—Tribal Air News—that

was distributed to EPA/Office of Air Quality Planning &

Standards’ network of tribal organizations. EPA gave a

presentation on various climate efforts, including the GHG

Reporting Program, at the National Tribal Conference on

Environmental Management on June 24-26, 2008. In addition,

EPA had copies of a short information sheet distributed at

a meeting of the National Tribal Caucus. See the “Summary
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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 Web site and published in the Tribal Air

Newsletter.

G. Executive Order 13045: Protection of Children from

Environmental Health Risks and Safety Risks

EPA interprets Executive Order 13045 (62 FR 19885,

April 23, 1997) as applying only to those regulatory

actions that concern health or safety risks, such that the

analysis required under Section 5-501 of the executive

order has the potential to influence the regulation. This

action is not subject to Executive Order 13045 because it

does not establish an environmental standard intended to

mitigate health or safety risks.

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
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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. 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 No. 104-113 (15

U.S.C. 272 note) directs EPA to use voluntary consensus

standards in its regulatory activities unless to do so

would be inconsistent with applicable law or otherwise

impractical. Voluntary consensus standards are technical

standards (e.g., materials specifications, test methods,

sampling procedures, and business practices) that are

developed or adopted by voluntary consensus standards

bodies. NTTAA directs EPA to provide Congress, through

OMB, with explanations when the Agency decides not to use

available and applicable voluntary consensus standards.

This rulemaking involves technical standards. EPA developed

no new measuring device standard. Rather we allow the use

of an appropriate standard method published by a consensus-
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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 LowIncome Populations

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

establishes federal executive policy on environmental

justice. Its main provision directs federal agencies, to

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.

K. Congressional Review Act
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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 [INSERT THE DATE 60 DAYS AFTER

PUBLICATION IN THE FEDERAL REGISTER].
Page 84 of 142

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List of Subjects in 40 CFR part 98

Environmental protection, Administrative practice and

procedure, Greenhouse gases, Incorporation by reference,

Air pollution control, Reporting and recordkeeping

requirements.

Date:

Lisa P. Jackson,

Administrator.
Page 85 of 142

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For the reasons stated in the preamble, parts 72, 78,

and 98 of title 40, chapter I, of the Code of Federal

Regulations is proposed to be 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.

§ 72.2 [Amended]

2. Section 72.2 is revised 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
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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.

§ 78.1 [Amended]

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.”; and

b. Adding paragraphs (b)(13) through (b)(17) to read as

follows:

§ 78.1 Purpose and scope.

* * * * *

(b) * * *

(13) [Reserved]

(14) [Reserved]

(15) [Reserved]

(16) [Reserved]

(17) Under subpart RR of part 98 of this chapter,
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(i) The approval or disapproval of a request for R&D

exemption under §98.441(b)(1) of this chapter;

(ii) The approval or disapproval of a request for

discontinuation of reporting under §98.441(d)(3) of this

chapter; and

(iii) The approval or disapproval of a geologic

sequestration monitoring, reporting, and verification (MRV)

plan under §98.448(d)of this chapter.

* * * * *

§ 78.3 [Amended]

5. Section 78.3 is amended by:

a. Adding paragraphs (a)(10) and (a)(11);

b. In paragraph (b)(3)(i), removing the words “paragraph

(a)(1) and (2)” and adding, in their place, the words

“paragraph (a)(1), (2), (10), and (11)”; and

c. Adding paragraphs (d)(11) and (d)(12) to read as

follows:

§ 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:
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(i) The owner or operator of a facility covered by the

decision; or

(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.

§ 78.4 [Amended]

6. Section 78.4 is amended by adding paragraphs

(a)(1)(i), (a)(1)(ii), (a)(1)(iii), (a)(1)(iv), and (a)(2)

to read as follows:

§ 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]
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7. The authority citation for part 98 continues to

read as follows:

Authority: 42 U.S.C. 7401, et seq.

Subpart A—[Amended]

8. Section 98.2 is amended by revising paragraph (a)

introductory text to read as follows:

§98.2 Who must report?

(a) The GHG reporting requirements and related

monitoring, recordkeeping, and reporting requirements of

this part apply to the owners and operators of any facility

that is located in the United States or under or attached

to the Outer Continental Shelf (as defined in 43 U.S.C.

§1331) and that meets the requirements of either paragraph

(a)(1), (a)(2), or (a)(3) of this section; and any supplier

that meets the requirements of paragraph (a)(4) of this

section:

* * * * *

9. Table A-3 of subpart A is amended by adding

“Geologic sequestration of carbon dioxide” and “Injection

of carbon dioxide” to read as follows:

Table A-3 of Subpart A—Source Category List for §98.2(a)(1)

Source Categoriesa Applicable in 2010 and Future Years

* * * * * * *

Additional Source Categoriesa Applicable in 2011 and Future

Years

* * * * * * *
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Geologic sequestration of carbon dioxide (subpart RR)

Injection of carbon dioxide (subpart UU)

a Source categories are defined in each applicable subpart.

* * * * *

10. Section 98.6 is amended by adding the following

definitions in alphabetical order to read as follows:

§98.6 Definitions.

* * * * *

Outer Continental Shelf means all submerged lands

lying seaward and outside of the area of lands beneath

navigable waters as defined in 43 U.S.C. §1301, and of

which the subsoil and seabed appertain to the United States

and are subject to its jurisdiction and control.

* * * * *

United States means the 50 states, the District of

Columbia, the Commonwealth of Puerto Rico, American Samoa,

the Virgin Islands, Guam, and any other Commonwealth,

territory or possession of the United States, as well as

the territorial sea as defined by Presidential Proclamation

No. 5928.

* * * * *

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

follows:

Sec.
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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 of any well or group of wells

that injects 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
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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) Request for a research and development exemption.

You may submit a request to the Administrator to receive an

exemption from reporting under this source category for

research and development projects.

(1) Timing of request. You must submit a request to

EPA for an exemption by the time you would be otherwise

required to submit an MRV plan under §98.448.

(2) Content of request. A request for an exemption

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) Whether research results will be published.

(vi) The class 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.
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(vii) The length of time the well or group of wells is

authorized to inject CO2.

(3) Exemption criteria. To obtain an exemption, the

owner or operator of the facility must demonstrate to the

Administrator’s satisfaction that the well or group of

wells is a research and development project.

(4) The Administrator will issue a final decision on

the request for a research and development exemption and

notify the owner or operator within 120 days of receipt of

the request. Any appeal of the Administrator’s final

decision is subject to the provisions of part 78 of this

chapter.

§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, at no threshold.

(b) 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 owner or operator has made
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a request to discontinue reporting that demonstrates that

the CO2 plume has stabilized.

(1) The owner or operator of a well or group of wells

with a Class VI Underground Injection Control permit may

submit to the Administrator a copy of the applicable

Underground Injection Control program Director’s

authorization of site closure to demonstrate that the CO2

plume has stabilized. For other wells, the owner or

operator of the facility must submit a demonstration to the

Administrator’s satisfaction that the CO2 plume has

stabilized.

(2) 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 fugitive and vented CO2 emissions from

surface equipment located between the injection flow meter

and the injection wellhead.
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(f) Mass of fugitive 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 (RR-1 and RR-3). You must calculate CO2

sequestered using injection equations (RR-4 to RR-6),

production/recycling equations (RR-7 to RR-9), surface

leakage equation (RR-10), and sequestration equations (RR11 and RR-12). 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
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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.

CO2T = d p CO p

p

Qr p Q C 2,(

,

)*

4

1

 , 



(Eq. RR-1)

Where:

CO2T = Annual mass of CO2 received (metric tons).

Qr,p = Quarterly mass flow through a receiving flow

meter in quarter p (metric tons per quarter).

Qd,p = Quarterly mass flow through a receiving flow

meter that is redelivered to another facility

without being injected into your well in

quarter p (metric tons per quarter).

CCO2,p = Quarterly CO2 concentration measurement in flow

in quarter p (wt. %CO2/100).

p = quarter.

(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.

CO2T = p CO p

p

Qr p Qd p D C 2,( ) * *

4

1

 , ,



 (Eq. RR-2)
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Where:

CO2T = Annual mass of CO2 received (metric tons).

Qr,p = Quarterly volumetric flow through a receiving

flow meter in quarter p at standard conditions

(standard cubic meters).

Qd,p = Quarterly volumetric flow through a receiving

flow meter that is redelivered to another

facility without being injected into your well

in quarter p (standard cubic meters).

Dp = Density of CO2 at standard conditions (metric

tons per standard cubic meter): 0.0018704.

CCO2,p = Quarterly CO2 concentration measurement in flow

in quarter p (vol. %CO2/100).

p = quarter.

(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.

CO2 = 

V

v 1

CO2T,v (Eq. RR-3)

Where:

CO2 = Total annual mass of CO2 received (metric

tons).

CO2T,v = Annual mass of CO2 received (metric tons) as

calculated in Equation RR-1 or RR-2 for flow

meter v.

v = 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.
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(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:

CO2 = Annual mass of CO2 received in containers

(metric tons).

CCO2,p = Quarterly CO2 concentration measurement of

contents in containers in quarter p (wt. %CO2).

Qp,u = Quarterly mass of contents in containers in

quarter p (metric tons).

p = Quarter of the year.

(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:

CO2 = Annual mass of CO2 received in container

(metric tons).

CCO2,p = Quarterly CO2 concentration measurement of

contents in containers in quarter p (vol.

%CO2).

Qp = Quarterly volume of contents in containers in

quarter p (standard cubic meters).

Dp = Quarterly density of the CO2 received in

containers at standard conditions (metric tons

per standard cubic meter):0.0018704.

p = Quarter of the year.
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(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.

CO2,u = CO p u

p

Qp u C 2, ,*

4

1

 ,



(Eq. RR-4)

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

in quarter p (wt. %CO2/100).

p = quarter.

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
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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.

CO2,u = p u CO p u

p

Qp u D C 2, ,* ,*

4

1

 ,



(Eq. RR-5)

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).

Dp,u = Density of CO2 at standard conditions (metric

tons per standard cubic meter): 0.0018704.

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

meter u in quarter p (vol. %CO2/100).

p = quarter.

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.

CO2I = 

U

u 1

CO2, u (Eq. RR-6)

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.
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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 gas 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.

CO2,w = CO p w

p

Qp w C 2, ,*

4

1

 ,



(Eq. RR-7)

Where:

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

separator w.

Qp,w = Quarterly mass flow rate measurement for

separator w in quarter p (metric tons per

quarter).
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CCO2,p,w = Quarterly CO2 concentration measurement in flow

for separator w in quarter p (wt. % CO2/100).

p = quarter.

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 gas 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.

CO2,w = p w CO p w

p

Qp w D C 2, ,* ,*

4

1

 ,



(Eq. RR-8)

Where:

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

separator w.

Qp,w = Volumetric flow rate measurement for separator

w in quarter p at standard conditions (standard

cubic meters per quarter).

Dp,w = Density of CO2 at standard conditions (metric

tons per standard cubic meter): 0.0018704.

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

separator w in quarter p (vol. % CO2/100).

p = quarter.

w = separator.
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(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.

CO2P = (100+X)% * 

W

w 1

CO2, w (Eq. RR-9)

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 volume in produced oil or other

fluid divided by the separator CO2 volume.

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.
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CO2E = 

X

x 1

CO2, x (Eq. RR-10)

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 conducting enhanced recovery

operations and 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.

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

Where:

CO2 = Total annual CO2 mass sequestered in subsurface

geologic formations (metric tons) at the

facility in the reporting year.

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

the well or group of wells covered by this

source category in the reporting year.

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

the reporting year.
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CO2E = Total annual CO2 mass emitted (metric tons) by

surface leakage in the reporting year.

CO2FI = Total annual CO2 mass emitted (metric tons) as

fugitive 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.

CO2FP = Total annual CO2 mass emitted (metric tons) as

fugitive 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.

(2) If you are not actively producing oil or natural

gas or any other fluids, you must calculate the annual mass

of CO2 that is sequestered in subsurface geologic formations

in the reporting year in accordance with the procedures

specified in Equation RR-12 of this section.

CO2 = CO2I – CO2E – CO2FI (Eq. RR-12)

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

fugitive 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.
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(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. 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
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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) 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 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
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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.

(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 98.444(b) as the total annual mass

of CO2 received instead of using equation RR-1 or RR-2 to

calculate CO2 received.

(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 once per

quarter immediately upstream or downstream of the flow
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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 CO2 stream 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.

(3) You must measure flow rate of CO2 produced with a

flow meter and collect the flow rate quarterly.

(d) Fugitive 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.
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(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: 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 American Energy

Standards Board (NAESB).

(4) You must ensure that any flow meter calibrations

performed are NIST traceable.

(f) General.

(1) If you measure the concentration of any CO2

quantity for reporting, you must use methods that conform

to applicable chemical analytical standards.

(2) You must use the same calculation methodology

throughout a reporting period unless you provide a written

explanation of why a change in methodology was required.
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(3) 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:

standard cubic meters at a temperature of 60 degrees

Fahrenheit and at an absolute pressure of 1 atmosphere.

§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 section

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 section

98.444(a)(2) must be used if possible.
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(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 section

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 fugitive 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
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estimated using a representative quantity of CO2 produced

from the nearest previous period of time.

(g) You must estimate the annual quantity 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) The mass of CO2 received.

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

following for each receiving flow meter:

(i) The total mass of CO2 received (metric tons)

annually.

(ii) The CO2 concentration in the flow (volume or wt.

% CO2/100) in each quarter unless you reported yes to

paragraph (a)(1)(v) of this section.

(iii) If a volumetric flow meter is used to receive

CO2 report the following unless you reported yes to

paragraph (a)(1)(v) of this section:

(A) The volumetric flow through a receiving flow

meter at standard conditions (in standard cubic meters) in

each quarter.
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(B) 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.

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

report the following unless you reported yes to paragraph

(a)(1)(v) of this section:

(A) The mass flow through a receiving flow meter (in

metric tons) in each quarter.

(B) The mass 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.

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

mixed with any other supply of CO2, report whether you

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

(vi) The standard or method used to calculate each

value in paragraphs (a)(1)(ii) through (a)(1)(iv) of this

section.

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

which substitute data procedures were used to calculate

values reported in paragraphs (a)(1)(ii) through (a)(1)(iv)

of this section.

(viii) Whether the flow meter is mass or volumetric.

(ix) A numerical identifier for the flow meter.
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(2) If you receive CO2 in containers, report:

(i) The mass (in metric tons) or volume at standard

conditions (in standard cubic meters) of contents in

containers in each quarter.

(ii) The concentration of CO2 of contents in containers

(volume or wt. % CO2/100) in each quarter.

(iii) The total mass of CO2 received (in metric tons)

annually.

(iv) The standard or method used to calculate each

value in paragraphs (a)(2)(i) and (a)(2)(ii) of this

section.

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

which substitute data procedures were used to calculate

values reported in paragraphs (a)(2)(i) and (a)(2)(ii) of

this section.

(b) If you use more than one receiving flow meter,

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

all flow meters annually.

(c) The source of the the CO2 stream received

according to the following categories:

(1) CO2 production wells.

(2) Electric generating unit.

(3) Ethanol plant.

(4) Pulp and paper mill.
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(5) Natural gas processing.

(6) Gasification operations.

(7) Other anthropogenic source.

(8) CO2 received from a discontinued enhanced oil and

gas recovery project.

(9) Unknown.

(d) Whether, on the date of this annual report

submission, your EPA-approved MRV plan has been fully

implemented. The MRV plan is fully implemented according to

the date in your approved MRV plan.

(e) If you report yes in paragraph (d) of this

section, report the following:

(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 wt.%

CO2/100) 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.
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(vii) The standard used to calculate each value in

paragraphs (d)(1)(ii) through (d)(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 (d)(1)(ii) through (d)(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.

(3) Fugitive and vented CO2 emissions.

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

as fugitive 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 fugitive 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 quantity produced (metric tons cubic meters)

annually.

(ii) CO2 concentration in flow (volume or wt. %

CO2/100) in each quarter.
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(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 (d)(4)(ii) through (d)(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 (d)(4)(ii) through (d)(4)(iv)

of this section.

(5) The value for X (%) used in Equation RR-9 and as

determined according to your EPA-approved MRV plan.

(6) Annual CO2 produced in the reporting year as

calculated in Equation RR-9.

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

leakage in the reporting year as calculated by Equation RR10.

(9) Annual CO2 (metric tons) sequestered in subsurface

geologic formations in the reporting year as calculated by

Equation RR-11 or RR-12.

(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 which 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 paragraph

(e).
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(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 the legal instrument authorizing geologic

sequestration.

§98.447 Records that must be retained.

In addition to the records required by §98.3(g), you

must retain the records specified in paragraphs (a) through

(g) of this section, as applicable.

(a) You must retain quarterly records of CO2 received,

including mass flow rate of contents of containers (mass or
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volumetric) at standard conditions and operating

conditions, operating temperature and pressure, and

concentration of these streams.

(b) 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.

(c) 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.

(d) Annual records of information used to calculate

the CO2 emitted by surface leakage from leakage pathways.

(e) Annual records of information used to calculate

the CO2 emitted as fugitive or vented emissions from

equipment located on the surface between the flow meter

used to measure injection quantity and the injection

wellhead.

(f) Annual records of information used to calculate

the CO2 emitted as fugitive or vented emissions from

equipment located on the surface between the production

wellhead and the flow meter used to measure production

quantity.
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(g) Any other records as specified for retention in

your EPA-approved MRV plan.

§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 one 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

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

to calculate site-specific variables for the mass balance

equation. This includes, but is not limited to,

considerations for calculating fugitive 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 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
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authorizing geologic sequestration as part of your proposed

MRV plan, you must notify EPA when the legal instrument

authorizing geologic sequestration has been approved.

(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

[INSERT THE DATE 180 DAYS AFTER PUBLICATION IN THE FEDERAL

REGISTER] if you were issued a final Underground Injection

Control permit authorizing the injection of CO2 into the

subsurface before [INSERT THE DATE OF PUBLICATION IN THE

FEDERAL REGISTER]. 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 you are 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
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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) 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. 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
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identified in the MRV plan; large changes in injection

pressures; failures of the monitoring system including

monitoring system sensitivity, performance, location, or

environmental baseline; changes to surface land use that

affects baseline or operational conditions; observed plume

location that differs from the predicted plume area used

for developing the monitoring 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 errors in your MRV

plan or monitoring report.

(4) You may submit a revised MRV plan to the

Administrator in any reporting year.

(e) The requirements of paragraph (c) apply to any

submission of a revised MRV Plan.

(f) 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
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plan, your R&D exemption request, your MRV plan submission

extension request, or your initial annual report under this

part, whichever is earlier.

§98.449 Definitions.

Except as provided below, all terms used in this

subpart have the same meaning given in the Clean Air Act

and subpart A of this part.

Active monitoring area is the area that will be

monitored over a specific time interval from the first year

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

boundary of the active monitoring area is established by

superimposing two areas: a) the area projected to contain

the free phase CO2 plume at the end of year t, plus an all

around buffer zone of one-half mile or greater if known

leakage pathways extend laterally more than one-half mile

and b) the area projected to contain the free phase CO2

plume at the end of year t+5.

CO2 received means the CO2 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, CO2 from a production process unit inside

your facility and CO2 that was injected into a well on

another facility, removed from a discontinued enhanced oil
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or natural gas or other production well, and transferred to

your facility.

Expected environmental baseline is the anticipated

value of a monitored parameter which is compared to the

measured monitored parameter at a specific location to

detect anomalies that may indicate subsurface or surface

leakages.

Maximum monitoring area means the area that must be

monitored under this regulation and is defined as equal to

or greater than the area expected to contain the free phase

CO2 plume until the CO2 plume has stabilized plus an allaround buffer zone of at least one-half mile.

Research and development project means a project that

is neither a demonstration nor a commercial project and

that is researching practices or monitoring techniques that

will enable safe and effective long-term containment of a

CO1 stream in subsurface geologic formations.

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.
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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.

* * * * *

12. Part 98 is amended by adding subpart UU to read as

follows:

Sec.

98.470 Definition of the source category.

98.471 Reporting threshold.

98.472 GHGs to report.

98.473 Calculating CO2 received.

98.474 Monitoring and QA/QC requirements.

98.475 Procedures for estimating missing data.

98.476 Data reporting requirements.

98.477 Records that must be retained.

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 injects

a CO2 stream into the subsurface.
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(b) If you report under subpart RR 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 of subpart UU 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
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concentration data measurements must be made in accordance

with §98.474.

CO2T = d p CO p

p

Qr p Q C 2,(

,

) *

4

1

 , 



(Eq. UU-1)

Where:

CO2T = Annual mass of CO2 received (metric tons).

Qr,p = Quarterly mass flow through a receiving flow

meter in quarter p (metric tons).

Qd,p = Quarterly mass flow through a receiving flow

meter that is redelivered to another facility

without being injected into your well in

quarter p (metric tons).

CCO2,p = Quarterly CO2 concentration measurement in flow

in quarter p (wt. %CO2/100).

p = quarter.

(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.

CO2T = d p p CO p

p

Qr p Q D C 2,(

,

) * *

4

1

 , 



(Eq. UU-2)

Where:

CO2T = Annual mass of CO2 received (metric tons).
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Qr,p = Quarterly volumetric flow through a receiving

flow meter in quarter p at standard conditions

(standard cubic meters).

Qd,p = Quarterly volumetric flow through a receiving

flow meter that is redelivered to another

facility without being injected into your well

in quarter p (standard cubic meters).

Dp = Density of CO2 at standard conditions (metric

tons per standard cubic meter): 0.0018704.

CCO2,p = Quarterly CO2 concentration measurement in flow

in quarter p (vol. %CO2/100).

p = quarter.

(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.

CO2 = 

V

v 1

CO2T,v (Eq. UU-3)

Where:

CO2 = Total annual mass of CO2 received (metric

tons).

CO2T,v = Annual mass of CO2 received (metric tons) as

calculated in Equation UU-1 or UU-2 for flow

meter v.

v = 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
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must calculate the CO2 received in containers using Equation

UU-1 of this section.

Where:

CO2 = Annual mass of CO2 received in containers

(metric tons).

CCO2,p = Quarterly CO2 concentration measurement of

contents in containers in quarter p (wt. %CO2).

Qp,u = Quarterly mass of contents in containers in

quarter p (metric tons).

p = Quarter of the year.

(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:

CO2 = Annual mass of CO2 received in containers

(metric tons).

CCO2,p = Quarterly CO2 concentration measurement of

contents in containers in quarter p (vol.

%CO2).

Qp = Quarterly volume of contents in containers in

quarter p (standard cubic meters).

Dp = Quarterly density of the CO2 received in

containers at standard conditions (metric tons

per standard cubic meter):0.0018704.

p = Quarter of the year.

§98.474 Monitoring and QA/QC requirements.

(a) CO2 received.
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(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.

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:
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(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 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
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CO2 concentration of the CO2 stream supplied that was

measured following procedures provided in subpart PP as the

quarterly CO2 concentration of the CO2 stream received.

(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: 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 American Energy

Standards Board (NAESB).

(4) You must ensure that any flow meter calibrations

performed are NIST traceable.

(c) General.
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(1) If you measure the concentration of any CO2

quantity for reporting, you must use methods that conform

to applicable chemical analytical standards.

(2) You must use the same calculation methodology

throughout a reporting period unless you provide a written

explanation of why a change in methodology was required.

(3) You must convert all measured volumes of CO2 to

the following standard industry temperature and pressure

conditions for use in equations UU-2: standard cubic meters

at a temperature of 60 degrees Fahrenheit and at an

absolute pressure of 1 atmosphere.

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

§98.3(d)(1) through (3) 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 (3) 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:
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(1) Another calculation methodology listed in section

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 section

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 section

98.474(a)(3) must be used if posssible.

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

be used, a quarterly concentration value that is missing
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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) The mass of CO2 received.

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

following for each receiving flow meter:

(i) The total mass of CO2 received (metric tons)

annually.

(ii) The CO2 concentration in the flow (volume or wt.

% CO2/100) in each quarter.

(iii) If a volumetric flow meter is used to receive

CO2:

(A) The volumetric flow through a receiving flow

meter at standard conditions (in standard cubic meters) in

each quarter.

(B) The volumetric flow through a receiving flow

meter that is redelivered to another facility without being
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injected into your well (in standard cubic meters) in each

quarter.

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

(A) The mass flow through a receiving flow meter (in

metric tons) in each quarter.

(B) The mass 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.

(v) The standard or method used to calculate each

value in paragraphs (a)(1)(ii) through (a)(1)(iv) of this

section.

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

which substitute data procedures were used to calculate

values reported in paragraphs (a)(1)(ii) through (a)(1)(iv)

of this section.

(vii) Whether the flow meter is mass or volumetric.

(2) If you receive CO2 in containers, report:

(i) The mass (in metric tons) or volume at standard

conditions (in standard cubic meters) of contents in

containers in each quarter.

(ii) The concentration of CO2 of contents in containers

(volume or wt. % CO2/100) in each quarter.

(iii) The total mass of CO2 received (in metric tons)

annually.
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(iv) The standard or method used to calculate each

value in paragraphs (a)(2)(i) and (a)(2)(ii) of this

section.

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

which substitute data procedures were used to calculate

values reported in paragraphs (a)(2)(i) and (a)(2)(ii) of

this section.

(b) If you use more than one receiving flow meter,

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

all flow meters annually.

(c) 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) CO2 received from a discontinued enhanced oil and

gas recovery project.

(9) Unknown.

§98.477 Records that must be retained.
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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.

§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 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, CO2 from a production process unit inside

your facility and CO2 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.
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July 2010

Economic Impact Analysis for the

Mandatory Reporting of

Greenhouse Gas Emissions

Subpart RR and Subpart UU:

Injection and Geologic

Sequestration of Carbon Dioxide

Final Report
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CONTENTS

Section 1 Introduction and Background.................................................................................1-1

1.1 Greenhouse Gas Reporting Program Background ...............................................1-1

1.2 Monitoring and Reporting Requirements for Injection and Geologic

Sequestration of Carbon Dioxide: Subpart RR and UU......................................1-1

Section 2 Regulatory Background..........................................................................................2-1

2.1 EPA’s Overall Rulemaking Approach .................................................................2-1

2.2 Statutory Authority...............................................................................................2-2

2.3 Safe Water Drinking Act and UIC Regulations...................................................2-2

2.4 Relationship to the Interagency Task Force on Carbon Capture and

Storage and Other Federal GS Initiatives.............................................................2-4

2.5 Relationship to Other Geologic Sequestration Information Collection and

Reporting Efforts..................................................................................................2-5

Section 3 Summary of Final Rule: Subpart RR and UU.......................................................3-1

3.1 Subpart RR ...........................................................................................................3-1

3.1.1 Source Category Definition......................................................................3-1

3.1.2 Subpart RR Reporting Threshold .............................................................3-1

3.1.3 Subpart RR GHGs to Report....................................................................3-1

3.1.4 Subpart RR GHG Calculations and Monitoring.......................................3-2

3.1.5 Subpart RR Data Reporting......................................................................3-2

3.1.6 Subpart RR Recordkeeping ......................................................................3-2

3.1.7 Subpart RR Geologic Sequestration Monitoring, Reporting, and

Verification (MRV) Plans ........................................................................3-2

3.1.8 Administrative Appeals............................................................................3-2

3.2 Subpart UU...........................................................................................................3-2

3.2.1 Subpart UU Source Category Definition..................................................3-2

3.2.2 Subpart UU Reporting Threshold.............................................................3-3

3.2.3 Subpart UU GHGs to Report....................................................................3-3

3.2.4 Subpart UU GHG Calculations and Monitoring ......................................3-3

3.2.5 Subpart UU Data Reporting .....................................................................3-3
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ii

3.2.6 Subpart UU Recordkeeping......................................................................3-3

3.3 Summary of Major Changes Since Proposal........................................................3-3

Section 4 Engineering Cost Analysis.....................................................................................4-1

4.1 Introduction ..........................................................................................................4-1

4.2 Overview of Cost Analysis...................................................................................4-1

4.3 Baseline Reporting ...............................................................................................4-1

4.3.1 Introduction ..............................................................................................4-1

4.3.2 Data Sources.............................................................................................4-2

4.3.3 Published Data on CO2 Sequestration Projects........................................4-3

4.3.4 Hydrogeologic Settings............................................................................4-5

4.3.5 Formation Capacity ..................................................................................4-8

4.3.6 Geologic Sequestration Rule Activity Baseline .....................................4-11

4.4 Reporting Costs..................................................................................................4-16

4.4.1 Introduction ............................................................................................4-16

4.4.2 Cost Assumptions and Methodology .....................................................4-17

4.4.3 Monitoring, Reporting, and Verification (MRV) Plan

Requirements and Approval Process......................................................4-19

4.5 Monitoring Technologies ...................................................................................4-22

4.5.1 Cost Scenarios........................................................................................4-26

4.6 Projecting and Discounting National Costs........................................................4-29

4.7 MRV Plan Costs.................................................................................................4-36

4.8 Annual Report Costs ..........................................................................................4-39

4.9 Other Recordkeeping and Reporting Costs........................................................4-39

4.10 Public Sector Burden..........................................................................................4-39

Section 5 Economic impact analysis......................................................................................5-1

5.1 Threshold Analysis...............................................................................................5-1

5.2 National Cost Estimates .......................................................................................5-2

5.2.1 National Cost Estimates Under Alternative Facilities Conducting

GS (ER opt in) Outcomes.........................................................................5-4

5.2.2 National Cost Estimates Under Alternative Facilities Conducting

GS (Commercial Saline) Outcomes .........................................................5-6
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iii

5.2.3 National Cost Estimates: 2011 to 2060 Using Underground

Injection Control Program for Carbon Dioxide Geologic

Sequestration Wells (UIC Class VI Rule) Baseline .................................5-7

5.3 Economic Impact Analysis...................................................................................5-9

5.3.1 Revenue Estimate for a Representative Commercial ER Operation ........5-9

5.3.2 Sales Test Results...................................................................................5-10

5.4 Assessing Economic Impacts on Small Entities.................................................5-10

5.4.1 Identify Affected Sectors and Entities....................................................5-10

5.4.2 Develop Small Entity Economic Impact Measures................................5-11

5.4.3 Results of Screening Analysis................................................................5-11

5.5 Characterization of Benefits of Subpart RR and Subpart UU of the

Mandatory Reporting Rule.................................................................................5-12

Section 6 Statutory and Executive Order Reviews.................................................................6-1

6.1 Executive Order 12866: Regulatory Planning and Review..................................6-1

6.2 Paperwork Reduction Act ....................................................................................6-1

6.3 Regulatory Flexibility Act....................................................................................6-3

6.3.1 Identify Affected Sectors and Entities......................................................6-3

6.3.2 Develop Small Entity Economic Impact Measures..................................6-4

6.3.3 Results of Screening Analysis..................................................................6-4

6.4 Unfunded Mandates Reform Act..........................................................................6-5

6.5 Executive Order 13132: Federalism.....................................................................6-5

6.6 Executive Order 13175: Consultation and Coordination with Indian Tribal

Governments........................................................................................................6-6

6.7 Executive Order 13045: Protection of Children from Environmental

Health and Safety Risks.......................................................................................6-7

6.8 Executive Order 13211: Actions that Significantly Affect Energy Supply,

Distribution, or Use..............................................................................................6-7

6.9 National Technology Transfer Advancement Act................................................6-7

6.10 Executive Order 12898: Federal Actions to Address Environmental Justice

in Minority Populations and Low-Income Populations.......................................6-8

Section 7 Conclusions............................................................................................................7-1

7.1 Summary of Selected Regulatory Alternative......................................................7-1
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7.2 Estimated Costs and Impacts of the Mandatory GHG Reporting Program .........7-2

7.2.1 Alternative Scenarios Considered ............................................................7-2

Section 8 References ..............................................................................................................8-1
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LIST OF TABLES

Table 4-1. Comparison of ICF Assessment of U.S. Sequestration Potential with Published

Estimates .................................................................................................................4-10

Table 4-2. Summary of ICF Sequestration Capacity Assessment..............................................4-11

Table 4-3. Pro-forma Project Characteristics (ER Scenario: No Additional ER Opt In)...........4-13

Table 4-4. Pro-forma Project Characteristics (ER Scenario: Anthropogenic ER Only Opt In).4-14

Table 4-5. Pro-forma Project Characteristics (ER Scenario: Anthropogenic plus One-half Other

ER Opt In)...............................................................................................................4-15

Table 4-6. Major Sources of Geologic Sequestration Cost Information....................................4-18

Table 4-7. Unit Cost of Relevant Continuous and Periodic Monitoring Technologies ............4-20

Table 4-8. Unit Cost of Relevant Episodic Monitoring Technologies (That may be employed

after a subsurface leak is detected)..........................................................................4-21

Table 4-9. Assumptions for Application of Technologies by Regulatory Alternative..............4-27

Table 4-10. Summary of Cost Impacts: Activity Baseline with No Additional ER Opt In ......4-30

Table 4-11. Summary of Cost Impacts: Activity Baseline from only Anthropogenic ER Opt In 4-

32

Table 4-12. Summary of Cost Impacts: Activity Baseline from Anthropogenic CO2 plus Onehalf of Other ER Opt In...........................................................................................4-34

Table 4-13. Cost of Developing MRV Plan: New Project with UIC Class VI Permit.............4-37

Table 4-14. Cost of Developing MRV Plan: ER Class II Project (no Class VI Permit).........4-38

Table 5-1 Geologic Sequestration Facilities: Effect of CO2 Received Threshold on Reported

Amount of CO2 Received and Number of Facilities Required to Report (Subpart RR)

...................................................................................................................................5-2

Table 5-2. Facilities Conducting CO2 Injection: Effect of CO2 Received Threshold on Reported

Amount of CO2 Received and Number of Facilities Required to Report (Subpart UU)

...................................................................................................................................5-2

Table 5-3. National Annualized Mandatory Reporting Costs Estimates: Subpart RR and Subpart

UU.............................................................................................................................5-3
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Table 5-4. Annualized Mandatory Reporting Costs Estimates (2008$): Subpart RR and Subpart

UU.............................................................................................................................5-4

Table 5-5. National Annualized Mandatory Reporting Costs Estimates (2008): All

Anthropogenic CO2 Projects.....................................................................................5-5

Table 5-6. National Annualized Mandatory Reporting Costs Estimates (2008$): All

Anthropogenic and 50 Percent of Other CO2 Projects..............................................5-6

Table 5-7. Anticipated Level of U.S GS Activity Developed for the Underground Injection

Control Program for Carbon Dioxide Geologic Sequestration Wells (UIC Class VI

Rule)..........................................................................................................................5-8

Table 5-8. Estimated Annual Revenue for a Representative Commercial ER Field Operation

(2008)........................................................................................................................5-9

Table 5-9. Sales Tests for Representative Commercial ER Field Operations...........................5-10
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SECTION 1

INTRODUCTION AND BACKGROUND

1.1 Greenhouse Gas Reporting Program Background

The Greenhouse Gas (GHG) Reporting Program requires reporting of GHG emissions

and other relevant information from certain source categories in the United States. The GHG

Reporting Program does not require the control of GHGs; rather it requires only monitoring and

reporting of GHGs. 40 CFR part 98 provides the regulatory framework for the GHG Reporting

Program. The GHG Reporting Program, which became effective on December 29, 2009,

includes reporting requirements for facilities and suppliers in 32 subparts. For more detailed

background information on the GHG Reporting Program, see the preamble to the final rule

establishing that program (74 FR 56260, October 30, 2009).

1.2 Monitoring and Reporting Requirements for Injection and Geologic Sequestration

of Carbon Dioxide: Subpart RR and UU

On April 12, 2010, EPA proposed this rule, amending the Greenhouse Gas (GHG)

Reporting Program at 40 CFR part 98. Subpart PP of the GHG Reporting Program requires the

reporting of carbon dioxide (CO2) supplied to the economy. During the public comment period

on the final rule establishing that requirement, EPA received many comments that CO2

geologically sequestered should be considered in the GHG Reporting Program. (For further

information on relevant comments received in subpart PP see “Mandatory Greenhouse Gas

Reporting Rule: EPA's Response to Public Comments, Subpart PP: Suppliers of Carbon

Dioxide” at EPA-HQ-OAR-2008-0508.) In the final rule promulgating subpart PP, EPA

committed to taking action to collect such data in the near future.

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. For example, EPA will be able to track whether incentives or regulations are needed to

encourage faster or further GS project development. Furthermore, where enhanced oil and gas

recovery (ER) projects are reporting under subpart RR, EPA will be able to evaluate ER as a

non-emissive end use. Under subpart UU, EPA will be able to reconcile information obtained

from this rule with data obtained from subpart PP on CO2 supplied to the economy.

The rule was proposed by EPA on April 12, 2010. One public hearing was held on April

19, 2010, and the sixty day public comment period ended June 11, 2010. This rule takes into

consideration comments received during the comment period and finalizes the monitoring and
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reporting requirements for facilities conducting GS and all other facilities conducting CO2

injection.

This final rule does not address whether data reported under 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) which addressed this issue. In that

action, EPA proposed which specific data elements would be released to the public and which

would be treated as CBI. EPA received several comments on that proposal under that action, and

is in the process of considering these comments. A final rule and determination will be issued

before any data is released. The final determination will address CBI considerations for all of

the data elements under subparts RR and UU.
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SECTION 2

REGULATORY BACKGROUND

The intent of the GHG Reporting Program is to collect accurate and timely GHG data

that can be used to inform future policies. Although the GHG Reporting Program is unique, EPA

carefully considered other federal and state programs during development of the rule. The

reporting program will supplement rather than duplicate other U.S. government GHG programs.

We outline EPA’s overall rulemaking approach, statutory authority, relationship to and

coordination with the Safe Drinking Water Act Underground Injection Control Class VI rule, and

summarize the relationship to the Interagency Task Force on Carbon Capture and Storage and

other Federal GS initiatives, as well as the relationship to other geologic sequestration

information collection and reporting efforts below.

2.1 EPA’s Overall Rulemaking Approach

The GHG Reporting Program provides comprehensive and accurate data which will

inform future climate change policies. Potential future climate policies include research and

development initiatives, economic incentives, new or expanded voluntary programs, adaptation

strategies, emission standards, a carbon tax, or a cap-and-trade program. Because we do not

know at this time the specific policies that will be adopted, the data reported to the GHG

Reporting Program should be of sufficient quality to support a range of approaches.

To these ends, we identified the following goals of the GHG Reporting Program:

 Obtain data that is of sufficient quality that it can be used to support a range of

future climate change policies and regulations.

 Balance the rule coverage to maximize the amount of emissions reported while

excluding small emitters.

 Create reporting requirements that are consistent with existing GHG reporting

programs by using existing GHG emission estimation and reporting

methodologies to reduce reporting burden, where feasible.
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This section presents the current regulatory context for Subparts RR and UU and

illustrates the anticipated role of the final rule within the framework of the existing mandatory

and voluntary programs.

2.2 Statutory 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 rule establishing the GHG Reporting Program (74 FR 56260, October 30, 2009), CAA

section 114 provides EPA with broad authority to require information mandated by this rule,

because such data will inform and are relevant to EPA’s carrying out a wide variety of CAA

provisions. Under CAA section 114(a)(1), the Administrator may require emissions sources,

persons subject to the CAA, 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 the provisions in the CAA (except for a

provision of title II with respect to motor vehicles). EPA may gather information for a variety of

purposes, including for the purpose of assisting in the development of implementation plans or of

emissions standards under CAA section 111, determining compliance with implementation plans

or such standards, or more broadly for “carrying out any provision” of the CAA.

2.3 Safe Water Drinking Act and UIC Regulations

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.

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
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(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:

http://www.epa.gov/ogwdw000/uic/wells_sequestration.html.

EPA designed the reporting requirements under 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. 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 subpart RR mass balance approach

used to quantify the amount of CO2 sequestered. EPA determined that quarterly data collection

and annual reporting under subpart RR was necessary in order to harmonize data with other

subparts of the GHG Reporting Program. Facilities reporting under subpart RR may use flow

meters used to comply with the flow monitoring and reporting provisions in their 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

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 an MRV plan1to 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 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

1

The subpart RR MRV plan includes delineation of monitoring areas, identification of potential surface leakage

pathways, a strategy for detecting and quantifying surface leakage of CO2 if leakage occurs, an approach for

establishing the expected environmental and operational 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.
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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 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 surface detection and quantification of CO2 in the event leakage occurs.

The UIC Class VI rule also allows for surface air and soil gas monitoring at the discretion

of the Director as a means of identifying CO2 leaks that may pose a risk to USDWs and

informing emergency notification of a UIC Class VI owner or operator and UIC Director in the

event of a USDW endangerment. If the Director determines that it is appropriate to require

surface air or soil gas monitoring for USDW protection, the Director must approve the use of

monitoring employed under subpart RR so long as the owner or operator is able to demonstrate

USDW protection pursuant to requirements at §146.90(h)(3).

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 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.

In the cost analysis conducted for this rule, EPA has assumed that for saline sequestration

projects these requirements are in the baseline, and consequently estimated incremental costs

associated with surface detection and quantification of CO2. Further detail on the cost analysis is

available in sections 4 and 5 of this document. 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.

2.4 Relationship to the Interagency Task Force on Carbon Capture and Storage and

Other Federal GS 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, costeffective deployment of CCS within ten years, with a goal of bringing five to ten commercial
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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. For more information, please see the CCS Task Force Web site:

http://www.whitehouse.gov/administration/eop/ceq/initiatives/ccs.

2.5 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 (available at: http://www.irs.gov/irb/2009-

44_IRB/ar11.html#d0e1860) 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 monitoring, reporting,

and verification procedures that are being finalized under subpart RR in this action.
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SECTION 3

SUMMARY OF FINAL RULE: SUBPART RR AND UU

Facilities that conduct geologic sequestration are subject to subpart RR. All other

facilities that inject CO2 underground are subject to subpart UU. If you report under subpart RR

for a well or group of wells, you are not required to report under subpart UU for that well or

group of wells.

3.1 Subpart RR

3.1.1 Source Category Definition

The 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. All wells permitted as

Class VI by the UIC program meet the definition of this source category. Facilities conducting

ER are not subject to subpart RR unless they choose to opt-in to the requirements of this subpart

or hold a UIC Class VI permit. Facilities may submit a request to EPA to receive an exemption

from reporting under subpart RR for GS R&D activities.

3.1.2 Subpart RR Reporting Threshold

All facilities that meet the subpart RR source category definition must report. Once a

facility is subject to the requirements of this subpart, including facilities that opt-in to 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 GHG reports, until the owner or

operator has made a request to discontinue reporting that demonstrates that the CO2 plume has

stabilized and EPA has issued a final decision on the request to discontinue reporting.

3.1.3 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; the mass of CO2 emitted from surface leakage; the

mass of fugitive and vented CO2 emissions from sources between the injection flow meter and

between the injection wellhead or the production flow meter and the production wellhead; and

the mass of CO2 sequestered in subsurface geologic formations.
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3.1.4 Subpart RR GHG Calculations and Monitoring

Facilities covered by this source category must calculate the annual mass of CO2

received. Starting from the date outlined in the EPA-approved MRV plan, facilities must also

use a mass balance approach to calculate the mass of CO2 geologically sequestered.

3.1.5 Subpart RR Data Reporting

In addition to the information summarized at “Subpart RR GHGs to Report”, 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. Facilities must also report

concentration, and mass or volumetric flow where flow meters are used or mass or volume where

containers are used. Finally, they are required to report MRV information implemented in the

reporting year and, for EPA verification purposes, the class of UIC permit and well identification

number used for the UIC permit.

3.1.6 Subpart RR Recordkeeping

Facilities must retain quarterly records of CO2 received; injected CO2; produced CO2;

CO2 emitted by surface leakage; and any other records as outlined for retention in the facility

MRV plan.

3.1.7 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.

3.1.8 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.

3.2 Subpart UU

3.2.1 Subpart UU Source Category Definition

The subpart UU source category consists of any 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 which are exempted from subpart RR monitoring and reporting requirements. If

you report under subpart RR for a well or group of wells, you are not required to report under

subpart UU for that well or group of wells.
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3.2.2 Subpart UU Reporting Threshold

All facilities that inject CO2 underground must report under this subpart, regardless of the

amount of emissions from the facility or the amount of CO2 injected.

3.2.3 Subpart UU GHGs to Report

Facilities covered by this source category must report the annual mass of CO2 received.

3.2.4 Subpart UU GHG Calculations and Monitoring

Facilities covered by this source category must calculate the annual mass of CO2

received.

3.2.5 Subpart UU Data Reporting

In addition to reporting the mass of CO2 received, facilities must report the source of the

CO2. Facilities must also report concentration and mass or volumetric flow or mass or volume

where containers are used.

3.2.6 Subpart UU Recordkeeping

Facilities must retain quarterly records of any CO2 received.

3.3 Summary of 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 significant changes to the rule can be found below or

in “Mandatory Greenhouse Gas Reporting Rule: EPA's Response to Public Comments, Subparts

RR and UU: Injection and Geologic Sequestration of Carbon Dioxide.”

 EPA has moved all definitions, requirements, and procedures for facilities

conducting CO2 injection only (which both EPA and commenters have referred to

as “Tier 1” facilities for simplicity) into a new subpart, 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 subpart RR.

 EPA has removed the requirement that facilities report the amount of CO2

injected in subpart UU (Tier 1) reporting requirements but retained requirements

that facilities subject to this subpart report the amount of CO2 received and the

source of CO2.

 EPA has established procedures for calculating CO2 received in containers.

 In subpart RR, EPA has established a waiver process for a GS R&D project to

request an exemption from subpart RR monitoring and reporting requirements.
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 In subpart RR, EPA has retained the requirement that facilities report the fugitive

and vented emissions reporting requirement for surface equipment that could be

included in the GS mass balance but removed the requirement for reporting

fugitive and vented emissions for all other surface equipment.

 In subpart RR, EPA has added an MRV plan requirement for the delineation of

the areas that will be monitored.

 In subpart RR, EPA has clarified the requirements for an addendum to the annual

report and renamed it monitoring report.

 EPA has amended 40 CFR part 78 to include administrative appeals procedures

for EPA decisions made under subpart RR, such as decisions relating to the

request for R&D exemption under §98.440(d)(4), decisions relating to a request

for discontinuation of reporting under §98.441(b)(2), or MRV plan decisions

under §98.448(c).
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SECTION 4

ENGINEERING COST ANALYSIS

4.1 Introduction

Using available industry and EPA data to characterize conditions at affected sources,

EPA estimated the costs of complying with final rule. Incremental monitoring, recordkeeping,

and reporting activities were then identified for each type of facility, and the associated costs

were estimated.

4.2 Overview of Cost Analysis

The costs of complying with the rule will vary from one facility to another, depending on

the nature of the CO2 injection activities (GS or non-GS), the MRV plan selected, existing

monitoring, recordkeeping, and reporting activities at the facility, etc. The costs include labor

costs for performing the monitoring, recordkeeping, and reporting activities necessary to comply

with the rule, as well as capital costs related to the implementation of monitoring activities

outlined in the MRV plan for GS sites. All costs referred to in this section are reported in 2008

dollars.

We first provide a general overview of baseline reporting and GS activities. This is

followed by detail on the cost components associated with this information collection; labor

costs (i.e., the cost of labor by facility staff to meet the information collection requirements of

the rule); and capital and operating and maintenance costs (e.g., the cost of purchasing and

installing monitoring equipment or contractor costs associated with providing the required

information).

4.3 Baseline Reporting

4.3.1 Introduction

The Environmental Protection Agency developed regulatory alternatives for reporting of

CO2 injection and GS. These rules can affect the number and type of monitoring equipment

installed at the sites and the type and frequency of tests and surveys conducted at the sites. In

creating new EPA regulations, a unit cost analysis and the total cost impact of each of the final

regulations is required by federal law. This provides a basis for a full evaluation of the

incremental costs of the final rule. The purpose of this section is to present the “activity

baseline,” which describes the number and types of injection and GS sites that could be subject

to the rule and the volume of CO2 injections that would be expected.
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Through the practice of geological sequestration, CO2 can potentially be sequestered in

underground formations worldwide for thousands of years. Although commercial geologic

sequestration of CO2 has not yet begun in the U.S., several projects such as Sleipner in the North

Sea, In Salah in Algeria, and Weyburn in Alberta have achieved success in recent years. CO2 at

these sites is being sequestered, and technologies to monitor the process have proved effective.

In the U.S., the Department of Energy is supporting approximately 25 sequestration pilot projects

around the country. DOE also has plans to start a number of relatively large scale pilot projects

within coming years.

Geologic sequestration in the U.S. will likely occur in a range of different geologic

settings including: saline reservoirs, oil and gas reservoirs, coal seams, and others. For purposes

of this economic analysis, the costs of specific aspects of geologic sequestration were specified

on the basis of cost per well, per square mile, per sample, or other basis for each project. In

addition, “type cases” were developed for each reservoir type including, in some instances, two

sizes of injection projects for pilot and commercial-size project scales. These include the typical

parameters (e.g. number of monitoring wells and average well depth) for each type of project,

allowing for estimation of total cost per project. In the cost analysis that appears in Chapter 5, a

base case is created assuming relevant monitoring costs are only that which is required under the

UIC rules. Then three regulatory alternatives for reporting from geologic sequestration sites are

evaluated in terms of technologies and practices and their costs.

4.3.2 Data Sources

In order to evaluate the total costs in the U.S. of the final regulations, it is necessary to

establish an activity baseline forecast of the sequestration activity to which the final regulation

applies. The appropriate forecast for this analysis is the level of GS activity that would be

expected even in the absence of future climate change legislation. While climate change

legislation is currently being debated in Congress, no legislation has been enacted. Even in the

absence of national climate legislation, sequestration activity in the U.S. is planned including:

 Research and Development (R&D) projects,

 FutureGen Sequestration Site, and

 Commercial Sequestration Projects Related to State and Regional Incentive

Programs (in part, funded by DOE)
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4.3.3 Published Data on CO2 Sequestration Projects

4.3.3.1 Planned R&D Projects

The Department of Energy has funded an extensive research effort into geologic

sequestration in the U.S. The project is a collaborative effort with seven regional partnerships.

The research effort is managed by the National Energy Technology Laboratory in Morgantown,

West Virginia. The program has two major components: Core R&D and Demonstration and

Deployment.

According to DOE, the goal is to “develop by 2012 systems that will achieve 90%

capture of CO2 at less than a 10 percent increase in the cost of energy services and retain 99

percent sequestration permanence.”

2

The field component of the sequestration research is being carried out by seven regional

partnerships. These partnerships were formed in 2003 and represent consortia of private industry

and government agencies. This effort is tasked with determining the most suitable technologies,

regulations, and infrastructure needs for capture and sequestration.

There are three phases to the work being carried out by the partnerships:

 Characterization (2003-2005)

 Validation (2005-2009)

 Deployment (2009-2017)

The Characterization Phase involved the geologic analysis that resulted in the

development of a National Carbon Sequestration Database and Geographic Information System

(NATCARB). The Validation Phase is currently active and involves such activities as

validation of reservoir simulation methods, data collection for capacity and injectivity, and

demonstration of monitoring technologies. Also being researched are well completion methods,

operations, and abandonment approaches.

The Deployment Stage involves the construction and operation of 8 significant

sequestration projects. These projects are consistent with the Energy Independence and Security

Act of 2007 (EISA), under Title VII, Sec. 702, which requires DOE to conduct at least 7 large

scale sequestration field tests greater than one million tons of CO2 each. These tests are designed

2 Direct Carbon Sequestration: Capturing and Storing Carbon Dioxide, Congressional Research Service, report

RL33801, September, 2007.
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to fully evaluate the potential for commercial scale operations in a range of geological settings.

The tests are planned to have an injection period of up to four, followed by a lengthy monitoring

period. This phase is designed to evaluate the practical aspects of large scale injection over a

prolonged period of time.

A great deal of progress has been made in the areas of site characterization and

monitoring. The next major phase of the DOE research effort is to provide funding support for a

number of commercial scale sequestration operations with injections of up to one million tons

per year.

Sequestration Related to State and Regional Incentive Programs

A number of states or regions have adopted or plan to adopt regulations to address carbon

dioxide and/or greenhouse gas emissions. Most allow for regulated sources of emissions to meet

compliance requirements through the use of offsets. Although geologic sequestration goals or

criteria may not be specified in each case, the potential exists for sequestration activities to

become an accepted and more prevalent way of meeting greenhouse gas reductions.

The programs or state legislation initiatives are generally in the early stages, and there is

considerable uncertainty in terms of which projects will proceed, and on what schedule. ICF has

researched the CSLF (Carbon Sequestration Leadership Forum) online database and the MIT

online database in our analysis of non-DOE projects. It should be noted, that in these databases,

there are several projects for which startup date and/ or planned injection volumes are not

specified.

Laboratory Research

Over the past several years, DOE and the regional partnerships have carried out an effort

to assess and characterize the CO2 sequestration capacity and potential of the U.S. This effort

has resulted in the publication of a large amount of information on potential by geologic setting

and basin or state. A large amount of GIS data has also been compiled on the geology of

sequestration potential.

In 2008, DOE published the most recent version of the NATCARB (National Carbon)

Atlas. 3 This publication contains maps and data tables documenting their assessment of

3 Carbon Sequestration Atlas of the United States and Canada, 2008, U.S. Department of Energy, National Energy

Technology Laboratory, Morgantown, WV.
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sequestration potential in the U.S. Much of the data behind the NATCARB atlas are either

available in GIS form or will eventually be made available.

4.3.4 Hydrogeologic Settings

Geologic sequestration may take place in a number of settings and lithologies. These

include:

 Non-basalt saline reservoirs

 Depleted gas fields

 Depleted and abandoned oil fields

 Enhanced oil recovery (ER)

 Enhanced coalbed methane recovery

For the purposes of analyzing this rule, we will focus on the settings that are most likely

affected by the rule, which includes saline reservoirs and oil and gas fields.

4.3.4.1 Non-Basalt Saline Reservoirs

Most significant sedimentary basins in the U.S. contain regionally significant saline

formations that are potential sequestration reservoirs. These are typically sandstone lithologies

with good porosity, containing formation waters of greater than 10,000 mg/L total dissolved

solids. Salinity may be as high as several times that of seawater. Thus, the water is unsuitable

for drinking or agriculture. Saline reservoirs dominate the assessed potential of the U.S. and

worldwide. In addition, because of their wide geographic distribution in the U.S., saline

reservoirs are often in close proximity to CO2 sources, minimizing pipeline transport distance.

Saline reservoirs represent the vast majority of U.S. sequestration potential (approximately 89

percent of total U.S. capacity). 4It is very likely that saline reservoirs will play a prominent role

in future geologic sequestration.

Sequestration in saline reservoirs has been shown to be effective. The Sleipner field in

the North Sea is the first commercial-scale saline reservoir project. Carbon dioxide is separated

from the gas stream and re-injected into a reservoir at about 800 meters depth. The rate of

4

2007 ICF assessment developed using DOE Atlas volumes and supplementing in several categories.
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4-6

injection is 2,700 tons per day or about one million tons per year. 5It is anticipated that about 20

million tons will eventually be stored. At Sleipner, the plume has been monitored effectively. 6

DOE has extensively studied saline reservoirs for sequestration. Projects include the Frio

Brine pilot in the Texas Gulf Coast and the Mount Simon Sandstone in the Illinois Basin. 7 The

Mount Simon is known to have excellent sequestration potential because of its regional thickness

and reservoir characteristics, and because it has been used extensively for natural gas

sequestration in the Midwest.

4.3.4.2 Depleted Gas Fields and Oil Fields

Depleted gas and oil fields can be excellent candidates for CO2 sequestration. These

represent known structures that have trapped hydrocarbons over geologic time, thus proving the

presence of an effective structure and seal above the reservoir. These fields have also been

extensively studied, there is a large amount of well log and other data available, and the field

infrastructure is already in place. This infrastructure could in some cases be utilized in

sequestration. A potentially problematic aspect of using depleted fields for sequestration is the

presence of a large number of existing wellbores, which can provide leakage pathways.

Typically, oil fields are developed with a closer spacing than gas fields, resulting in a larger

number of existing wells per unit area than in gas fields.

The In Salah Field in Algeria was the world’s first project in which CO2 is injected at

commercial scale into a gas reservoir. However, in this case, the gas is injected downdip in an

actively producing gas reservoir. This differs from an abandoned gas reservoir scenario in which

the gas field is no longer producing.

4.3.4.3 Enhanced Recovery of Oil and Gas

Under certain reservoir and fluid conditions, CO2 can be injected into an oil reservoir in a

process called miscible CO2 enhanced oil recovery. The effect of the CO2 is to mobilize the oil

5

IPCC, 2005: IPCC Special Report on Carbon Dioxide Capture and Storage, by Working Group III of the

Intergovernmental Panel on Climate Change [B. Metz, O. Davidson, H. C. de Coninck, M. Loos, and L. A.

Meyer (eds.)], Cambridge University Press, Cambridge, United Kingdom and New York, NY, USA, 442 pp.

6

IPCC, 2005: IPCC Special Report on Carbon Dioxide Capture and Storage, by Working Group III of the

Intergovernmental Panel on Climate Change [B. Metz, O. Davidson, H. C. de Coninck, M. Loos, and L. A.

Meyer (eds.)], Cambridge University Press, Cambridge, United Kingdom and New York, NY, USA, 442 pp.

7 Carbon Capture and Storage: A Regulatory Framework for States – Summary of Recommendations,, by Kevin

Bliss, Interstate Oil and Gas Compact Commission, January, 2005.
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so that it can move more readily to the production wells. As the oil is produced, part of the

injected CO2 is produced with the oil. This CO2 is then separated and re-injected.

In the U.S. most CO2 ER projects are located in the Permian Basin of West Texas, where

projects have been in place for several decades. The source of most of the CO2 is natural CO2

from several fields in Colorado and New Mexico. 8Some of the injected CO2 is from gas

processing or other sources. The current volume of CO2 injected for CO2 ER is about 2.2 billion

cubic feet per day.

In 2005, CO2 ER operations produced approximately 237,000 barrels of oil per day in the

U.S. About 180,000 barrels per day of that occurred in West Texas, with most of the rest

produced in the Rockies, Mid-Continent, and Gulf Coast. 9

The development of CO2 ER projects has resulted in a great deal of knowledge about the

process and injection well and other technologies have matured and are well understood. In

addition, it is estimated that more than 3,500 miles of high pressure (>1,300 psi) CO2 pipelines

have been built to accommodate these operations. 10

At the Weyburn Field in Saskatchewan, CO2 from the Dakota Gasification Facility in

North Dakota is injected into an oil reservoir for ER and monitoring of CO2 sequestration. Over

the 25 year life of this project, it is expected that about 18 million tons of CO2 will be

sequestered.

4.3.4.4 Enhanced Coalbed Methane Recovery

CO2 can potentially be sequestered in coalbeds through the process of adsorption. CO2

injected as a gas into a coal bed will adsorb onto the molecular structure and be sequestered.

Methane is naturally adsorbed onto coalbeds and coalbed methane now represents a

significant percentage of U.S. natural gas production. Major coalbed methane production areas

include the San Juan Basin of northwestern New Mexico and southwestern Colorado, the Powder

River Basin of eastern Wyoming, and the Warrior Basin in Alabama.

8

The Economics of CO2 Storage, Gemma Heddle, Howard Herzog, and Michael Klett, Laboratory for Energy and

the Environment, Massachusetts Institute of Technology, August, 2003.

9 Oil and Gas Journal, April 17, 2006.

10 Carbon Capture and Storage: A Regulatory Framework for States – Summary of Recommendations,, by Kevin

Bliss, Interstate Oil and Gas Compact Commission, January, 2005.
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The concept of enhanced coalbed methane recovery is based upon the fact that coalbeds

have a greater affinity for CO2 than methane. Thus, when CO2 is injected into the seam, methane

is liberated and the CO2 is retained. This additional methane represents enhanced gas recovery.

Depending upon depth and other factors, coalbeds may be mineable or unmineable.

Because the process of mining the coal would release any stored CO2, only unmineable coals are

assessed as representing permanent CO2 sequestration. 11

4.3.4.5 Other Hydrogeologic Settings

Basalt flows such as those of the Columbia River Basalts in the Pacific West, are

believed to have the potential for permanent CO2 sequestration. The sequestration process is

geochemical trapping, in which the CO2 reacts with silicates in the basalt to form carbonate

minerals. 12 While research is being carried out on basalt, it is considered unlikely that any

commercial scale sequestration will occur in the foreseeable future due to the unconventional

geology and likely difficulty in monitoring.

The potential to sequester CO2 in organic shale formations is based upon the same

concept as that of coal beds. CO2 will adsorb onto the organic material, displacing methane.

Gas shales have recently emerged as a major current and future source of gas production in the

U.S. These include the Barnett Shale in the Fort Worth Basin, the Fayetteville and Woodford

Shales in the Arkoma Basin, and the Appalachian Devonian Shale. These Devonian and

Mississippian age organic shale formations represent tremendously large volumes of rock. To

date little research has been done on enhanced gas recovery with organic shales. However,

should it prove technically feasible, the U.S. could become one of the major areas worldwide for

this type of sequestration.

4.3.5 Formation Capacity

4.3.5.1 Current DOE Assessment of Sequestration Potential

Through the regional sequestration partnerships, DOE has developed a new national

assessment of sequestration potential. The current assessment is summarized in Table 4-3, in the

column titled “2008 NATCARB.” As evaluated by ICF, the DOE Lower-48 total is 8,179

11 Carbon Capture and Storage: A Regulatory Framework for States – Summary of Recommendations,, by Kevin

Bliss, Interstate Oil and Gas Compact Commission, January, 2005.

12 IPCC, 2005: IPCC Special Report on Carbon Dioxide Capture and Storage, by Working Group III of the

Intergovernmental Panel on Climate Change [B. Metz, O. Davidson, H. C. de Coninck, M. Loos, and L. A. Meyer

(eds.)], Cambridge University Press, Cambridge, United Kingdom and New York, NY, USA, 442 pp.
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4-9

gigatonnes (Gt) of CO2. The range of uncertainty is 3,508 to 12,850 Gt. Most of the

assessment is attributed to saline reservoirs). This assessment is much larger than the prior

assessments also shown on the table.

4.3.5.2 ICF Assessment of Sequestration Potential

ICF has also developed a sequestration potential assessment by reservoir type. The

results of this assessment are summarized in Table 4-1. The Lower-48 assessed total is 3,375 Gt.

The assessment includes estimates from DOE, and estimates for resources not covered by DOE.

We have included a rough assessment of the Gulf of Mexico, as well as an estimate of shale gas

sequestration potential. The ICF assessment can be broken out by state or region, and geologic

category.

Table 4-2 presents the ICF Lower-48 assessment by region. Sequestration capacity

associated with depleted oil and gas fields occurs where there has been significant production,

including Appalachia, the Gulf Coast, Mid-Continent, and Rockies. Saline reservoir potential

occurs in many areas of the country. Coalbed methane potential is concentrated in the large

coalbed methane production areas such as New Mexico and Wyoming, while shale gas potential

is associated with some of the new shale gas basins that have emerged over the past decade.
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4-1. Comparison of ICF Assessment of U.S. Sequestration Potential with Published Estimates

Lower 48 Only Aug 2007 ICF 2008 2008 2008 2007 2006 2006 2005

ICF Lower-48 NATCARB NATCARB NATCARB NATCARB NATCARB Batelle IEA

Low High Mid

Category Gt CO2 % Gt CO2 Gt CO2 Gt CO2 Gt CO2 Gt CO2 Gt CO2 Gt CO2

Depleted Oil and Gas Fields

Depleted Oil Reservoirs with EOR Potential 17 0.5% 7 12 0 1

Depleted Conventional Oil Fields 60 1.8% 13 0 1 11

Depleted Gas Fields 50 1.5% 9 35 35

subtotal 126 3.7% 138 138 138 82 29 47 46

Coal and Coalbed Methane

Enhanced CBM 20 0.6% 17 0 1

Deep Unmineable Coal Seams 32 0.9% 11 30 60

subtotal 52 1.5% 73 94 84 86 28 30 60

Shale Formations 107 3.2% 0 0 0 0 45 0 1 0 1

Deep Saline Formations

Onshore 1,187 2,130 7,950 5,040 1,907 6,595 2,730 2,730

Offshore 1,803 4 1,167 4,668 2,918 4 242 3 0 1 900

subtotal 2,990 88.6% 3,297 12,618 7,958 2,149 6,595 3,630 2,730

Onshore Saline-Filled Basalt 100 3.0% 84 100 240 0

Lower-48 Total 3,375 100.0% 3,508 12,850 8,179 2,401 6,797 3,947 2,836

Alaska 84 84

U.S. 8,263 2,485

Notes:

1 No covereage in assessment. 3 Atlantic Offshore Only

2 Represents only a partial assessment of US. 4 GOM, Pacific and Atlantic Offshore
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Table 4-2. Summary of ICF Sequestration Capacity Assessment

Gigatonnes of CO2 Storage

Depleted Depleted

Region (Markal Region Name) EOR Oil Fields Gas Fields Coals Shale Saline Basalt Total

California (California) 1.2 8.0 1.8 0.0 0.0 161.1 0.0 172.2

Eastern Gulf Coast (East South Central) 0.2 1.1 1.3 1.9 28.0 103.2 0.0 135.6

Gulf of Mexico 1.5 5.5 8.4 0.0 0.0 800.0 0.0 815.3

Midwest (East North Central) 0.3 1.3 0.2 3.3 12.7 167.1 0.0 184.9

Northern Midcontinent (West North Central) 0.7 5.9 2.1 0.2 0.0 57.8 0.0 66.7

Northern Rockies (Mountain 1) 0.7 4.6 2.5 17.7 0.0 665.6 33.3 724.4

New England (New England) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Northeast (Middle Atlantic) 0.0 0.3 0.6 0.1 12.0 9.0 0.0 22.0

Pacific NW (Pacific; Lower 48 Onshore Part) 0.0 0.0 0.0 2.3 0.0 53.0 66.6 121.9

Pacific Offshore (Pacific; L48 Offshore) 0.0 1.2 0.0 0.0 0.0 100.0 0.0 101.3

Southern Rockies (Mountain 2) 1.4 3.3 6.0 19.6 0.0 36.5 0.0 66.8

Southeast (South Atlantic) 0.1 0.2 0.7 0.9 19.0 378.0 0.0 398.9

Texas and S. Midcontinent (West S. Central) 10.4 28.0 26.1 5.7 35.0 459.5 0.0 564.6

Total 16.5 59.5 49.7 51.6 106.7 2,990.6 99.9 3,374.6

Offshore (Gulf, Atlantic, Pacific) 1.5 6.7 8.4 0.0 0.0 1,186.6 0.0 1,203.3

Onshore 15.1 52.8 41.2 51.6 106.7 1,804.0 99.9 2,171.3

4.3.6 Geologic Sequestration Rule Activity Baseline

Based upon the above information on what is anticipated for R&D projects, FutureGen,

and state programs, an activity baseline forecast of sequestration activity has been developed.

Because of the uncertainty in which existing ER project might come under subpart RR, three

scenarios have been created and are shown as Table 4-5 to 4-7. The first scenario assumes that

no existing CO2 ER projects choose to report as facilities conducting GS. The second scenario

assumes that all CO2 ER projects from anthropogenic sources (7 million metric tons per year

coming primarily from natural gas processing plants) choose to report as facilities conducting

GS. The third scenario assumes that all projects from anthropogenic CO2 sources plus one-half

of the remaining CO2 flood projects choose to report as facilities conducting GS. This third

scenario adds up to 23.4 million metric tons per year injected of new (i.e., ignoring recycled

volumes) CO2.

The most comprehensive source of information on US ER projects is the annual survey

conducted by the Oil and Gas Journal. The 105 projects listed in the Oil and Gas Journal 2007

ER survey were grouped by CO2 source type – natural or anthropogenic. CO2 use was allocated

to the projects supplied by each source based on oil production. Anthropogenic sources were
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4-12

well defined for ER projects in Michigan (Antrim Gas Processing Plant), Wyoming/Colorado

(LaBarge/Shute Creek Gas Processing Plant), central Oklahoma (Enid Fertilizer Plant) and

Kansas (US Energy Partners, Russell Kansas Ethanol Plant) from geographic proximity and

information in published literature. Natural CO2 production from the Jackson Dome in

Mississippi was allocated to the 15 projects in Mississippi and Louisiana based on geographic

proximity and information in published literature. Anthropogenic CO2 from the Val Verde Gas

Plant in Texas is mixed with CO2 from natural sources and distributed to several fields in the

Permian Basin so there was not a clear delineation of which projects were served by

anthropogenic gas from the Val Verde plant. To estimate the number of facilities served by Val

Verde, the total CO2 use in the Permian Basin from natural sources and Val Verde production

was summed and the percent of Val Verde production was prorated among the 66 projects in the

Permian Basin. Val Verde CO2 production represents 5.4 % of the total CO2 used in the Permian

Basin, therefore, the equivalent of approximately 4 projects in the Permian Basin are estimated to

use anthropogenic CO2 from Val Verde. For this analysis 2007 CO2 production data for natural

and anthropogenic sources was taken from the (1990-2007) Inventory of U.S. Greenhouse Gas

Emissions and Sinks, and totaled 2.1 bcf/day which differs from the published DOE estimate of

2.6 bcf/day used in the threshold analysis.

Based on the number of projects active in 2007, anthropogenic sources provide

approximately 18% of the mass of CO2 used in ER projects in the US, and represent

approximately 27 % of the CO2 ER projects. These projects result in the additional production of

more than 13 million barrels of oil annually. If only ER projects supplied by anthropogenic

sources opted into the reporting program approximately 28 projects would be included. If all the

ER projects supplied by anthropogenic sources, and half of the projects using natural sources

opted into the reporting program approximately 67 projects would report, representing 1.2

bcf/day (23.4 million metric tons per year) or 59% of all CO2 ER use.
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Table 4-3. Pro-forma Project Characteristics (ER Scenario: No Additional ER Opt In)

Baseline Forecast, #

of Projects & Total

Volumes Per Project Averages for Economic Analysis (taken from ICF's UIC Class VI work)

Label

Number

of

Projects

Operating

in 2012

Metric

Tons

CO2

Received

per Year

Project

Count

Monitoring

Wells/

Project

Monitoring

Well Depth

Ft

Footage all

monitoring

wells

Square

Miles/

Project

Producing

Oil or Gas

Wells/

Project

Project Life

(for

annualization)

Metric

Tons

CO2

Received

per Year

/ Project

Known DOE EOR Pilot Projects 2 1,100,000 1 7 5,700 39,900 8.8 56 10 550,000

Known DOE Saline Pilot

Projects 5 2,720,000 1 2 8,000 16,000 1.7 0 4 750,557

Future DOE Saline Pilot

Projects 2 1,500,000 1 2 8,000 16,000 1.7 0 4 750,557

Known Commercial EOR

Projects 3 3,300,000 1 6 5,700 34,200 8.0 48 10 500,000

Known Commercial Saline

Projects 1 0 1 9 8,000 72,000 11.6 0 40 1,842,885

Conversion of Existing EOR

Projects to GS 0 0 1 6 5,700 34,200 8.0 48 10 500,000
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Table 4-4. Pro-forma Project Characteristics (ER Scenario: Anthropogenic ER Only Opt In)

Baseline

Forecast,

# of

Projects &

Total

Volumes Per Project Averages for Economic Analysis (taken from ICF's UIC Class VI work)

Label

Number of

Projects

Operating

in 2012

Metric

Tons

CO2

Receive

d per

Year

Project

Count

Monitorin

g Wells/

Project

Monitori

ng Well

Depth Ft

Footage

all

monitori

ng wells

Square

Miles/

Project

Producin

g Oil or

Gas

Wells/

Project

Project

Life (for

annualiza

tion)

Metric

Tons

CO2

Receive

d per

Year /

Project

Known DOE EOR Pilot Projects 2 1,100,000 1 7 5,700 39,900 8.8 56 10 550,000

Known DOE Saline Pilot Projects 5 2,720,000 1 2 8,000 16,000 1.7 0 4 750,557

Future DOE Saline Pilot Projects 2 1,500,000 1 2 8,000 16,000 1.7 0 4 750,557

Known Commercial EOR Projects 3 3,300,000 1 6 5,700 34,200 8.0 48 10 500,000

Known Commercial Saline Projects 1 0 1 9 8,000 72,000 11.6 0 40 1,842,885

Conversion of Existing EOR Projects

to GS 16 6,972,040 1 6 5,700 34,200 8.0 48 10 500,000
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Table 4-5. Pro-forma Project Characteristics (ER Scenario: Anthropogenic plus One-half Other ER Opt In)

Baseline Forecast, #

of Projects & Total

Volumes Per Project Averages for Economic Analysis (taken from ICF's UIC Class VI work)

Label

Number

of

Projects

Operating

in 2012

Metric

Tons

CO2

Received

per Year

Project

Count

Monitoring

Wells/

Project

Monitoring

Well Depth

Ft

Footage all

monitoring

wells

Square

Miles/

Project

Producing

Oil or Gas

Wells/

Project

Project Life

(for

annualization)

Metric

Tons

CO2

Received

per Year

/ Project

Known DOE EOR Pilot Projects 2 1,100,000 1 7 5,700 39,900 8.8 56 10 550,000

Known DOE Saline Pilot

Projects 5 2,720,000 1 2 8,000 16,000 1.7 0 4 750,557

Future DOE Saline Pilot

Projects 2 1,500,000 1 2 8,000 16,000 1.7 0 4 750,557

Known Commercial EOR

Projects 3 3,300,000 1 6 5,700 34,200 8.0 48 10 500,000

Known Commercial Saline

Projects 1 0 1 9 8,000 72,000 11.6 0 40 1,842,885

Conversion of Existing EOR

Projects to GS 48 23,543,741 1 6 5,700 34,200 8.0 48 10 500,000
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4-16

4.3.6.1 Sources of Uncertainty

The activity baseline forecast of sequestration activity represents our best estimate of

what will likely occur in the absence of national climate change legislation. As with any

forecast, there are sources of uncertainty. Categories of uncertainty include:

 Number and timing of R&D projects and number of years of injection

 Number and timing of FutureGen projects and number of years of injection

 Number and timing of State Incentive projects and number of years of injection

 Average injection rates

 Number of ER projects that will be covered

Of the three categories of project, the least uncertainty is associated with the R&D

projects. These projects have been funded and are expected to proceed at close to the

announced schedule.

The DOE FutureGen project site has been chosen (Illinois) but there is still uncertainty

about timing and injection volumes.

Given the number of state and regional initiatives underway it is very likely that projects

related to state incentives will be initiated. As discussed previously, there are a number of

projects for which either timing or injection volumes were not provided and were estimated by

ICF.

The largest uncertainty over the timeframe of the activity baseline is what may occur at

the national level in terms of climate change legislation. However, any costs associated with

potential future national climate policy cannot be attributed to this subpart currently under

consideration. The activity baseline presented in this document is expressly for the purpose of

evaluating the costs of the subpart RR proposal under existing climate change policies.

4.4 Reporting Costs

4.4.1 Introduction

The purpose of this section is to present the unit cost estimates for the equipment and

services that might be required to comply with the CO2 Injection and GS Reporting rule and the

total incremental annual cost of compliance. A base case is created assuming relevant monitoring

costs are only that which is required under the UIC rules. Then three regulatory alternatives for
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4-17

reporting from geologic sequestration sites are evaluated in terms required technologies and

practices and their costs.

4.4.2 Cost Assumptions and Methodology

The costs reported here include capital and operating and maintenance (O&M) including

labor costs. They are based on hypothetical or pro-forma sites for various types of projects such

as saline formation R&D GS projects, saline formation commercial GS projects, and ER GS

projects. The geologic and engineering assumption for these pro-forma projects are the same as

used by the EPA Office of Water in the final rule, Federal Requirements under the Underground

Injection Control Program for Carbon Dioxide Geologic Sequestration Wells, or the UIC Class

VI final rule for CO2 injection wells13. The costs represent price levels in mid 2009, are presented

in 2008 dollars. There were very steep increases in the costs of equipment, materials and labor

used in the construction of all types of energy infrastructure including power plants, pipelines

and oil and gas wells from 2004 through 2008. With the drop of oil and natural gas prices in the

Fall of 2008 and the general economic decline around the world the costs of equipment,

materials and labor have moderated somewhat.

4.4.2.1 Primary Data Sources for Costs

Table 4-8 summarizes the major data sources for costs used by EPA in the analysis

geologic sequestration costs. A wide range of cost data is available from industry survey

publications for costs typically incurred in oil and gas drilling and production operations. This

includes drilling and completion costs by region and depth interval, equipment and operating

costs, and pipeline costs. Data are available for both the U.S. and Canada. 14 15 16 17The cost of

drilling and equipping wells represents a large component of sequestration costs. The costs of

additional equipment or material specifications for CO2 injection wells are based in part upon

various sources for corrosion resistant materials and specific well components. Cost estimates for

seismic data acquisition are also available from industry publications and presentations.

13 The UIC rulemaking that would create a Class VI well class for injection of CO2 for the purposes of GS was

proposed July 25, 2008. (73 FR 43492)

14 Joint Association Survey of Drilling Costs, American Petroleum Institute, Washington, DC.

http://www.api.org/statistics/accessapi/api-reports.cfm

15 PSAC Well Cost Study – 2008, Petroleum Services Association of Canada, October 30, 2007.

16 Oil and Gas Lease Equipment and Operating Costs, U.S. Energy Information Administration, 2006,

http://www.eia.doe.gov/pub/oil_gas/natural_gas/data_publications/cost_indices_equipment_production/current/costs

tudy.html

17 Oil and Gas Journal Pipeline Cost Survey, Oil and Gas Journal Magazine, September 3, 2007.
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Labor rates are obtained from the U.S. Bureau of Labor Statistics and from surveys of oil

and gas professional performed by the American Association of Petroleum Geologists (AAPG)

and the Society of Petroleum Engineers (SPE). The number of hours required to carry out the

various characterization or monitoring activities are estimates that have been reviewed by the

EPA workgroup.

No comprehensive source has been identified that provides detailed summaries of the full

range of sequestration project cost components. Estimates of the costs of monitoring equipment,

the number of stations required, and the cost of ongoing monitoring are based upon analysis of

available literature and recent presentations by government and academic research groups and

quotations from vendors. Some specific monitoring costs were obtained at a recent industry

meeting sponsored by the Groundwater Protection Council.

18

Table 4-6. Major Sources of Geologic Sequestration Cost Information

18 Ground Water Protection Council Meeting, New Orleans, LA, January, 16, 2008.

Source Cost Categories

API Joint Association Survey of Drilling Costs Drilling costs in the U.S. for oil, gas, and dry holes by depth interval

EIA Oil and Gas Lease Equipment and Operating Cost Survey Surface equipment costs, annual operating costs, pump costs

Pipeline Prime Mover and Compressor Costs (FERC) Pumps

2008 Petroleum Services of Canada Well Cost Study (PSAC) Drilling costs, plugging costs, logging costs

Oil and Gas Journal Report on Pipeline and Cost Data

Reported to FERC Pipeline costs per inch-mile

Land Rig Newsletter Onshore rig day rates/ well cost algorithms

FutureGen Sequestration Site Submittals Monitoring station layout/number of stations

Preston Pipe Report Casing and tubing costs

Hourly Labor Rates U.S. Bureau of Labor Statistics

Selected Presentations and Papers (see below) Sensor costs, monitoring costs, number of stations, seismic costs

Significant Papers and Presentations With Cost Data

Benson, "Monitoring Protocols and Life Cycle Costs for Geologic Storage of Carbon Dioxide", Sept., 2004

IEA Greenhouse Gas Programme Report PH4/29, "Overview of Monitoring Requirements for Geologic Storage Projects, Nov., 2004.

Hoversten, "Investigation of Novel Geophysical Techniques for Monitoring CO2 Movement During Sequestration," Oct., 2003.

Dahowski, et al, " The Costs of Applying Carbon Dioxide Capture and Geologic Storage Technologies to Two Hypothetical

Coal to Liquids Production Configurations: A Preliminary Estimation," Pacific NW National Laboratory, September, 2007.
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The assumed capital costs and the annual operating cost of the various monitoring

technologies whose application might be affected by the rule are shown in Table 4-7 and 4-8.

The capital costs are annualized using a capital recovery factor of 0.295, 0.142, and 0.075 for

projects lasting 4, 10, and 40 years, respectively. The annual O&M costs are added to the

annualized capital costs to determine total annual direct costs. To this is added a 20 percent

overhead and general and administrative cost factor to obtain total annual costs. These are then

divided by the amount assumed to be received each year in the pro-forma project to arrive at

total costs per metric ton of CO2 received. These per-ton costs are then used to estimate total

annual costs for the level of injection expected in the activity baseline.

4.4.3 Monitoring, Reporting, and Verification (MRV) Plan Requirements and

Approval Process

There are two types of sites that will report under this rule, facilities that conduct GS

(subpart RR) and all other facilities conducting CO2 injection (subpart UU). All sites will incur

costs associated with reporting the annual mass of CO2 received, however only facilities

conducting GS will incur the monitoring plan related costs. Under this rule facilities conducting

GS must develop an MRV plan, submit it to EPA for approval, and implement it once approved

by EPA to report the amount of CO2 that has been sequestered. EPA is proposing that each

submitted MRV plan must contain the following components.

1. Delineation of the maximum monitoring area and the period-specific monitoring areas.

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 environmental baselines.

5. A summary of the considerations you intend to use to calculate site-specific variables

for the mass balance equation.
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Table 4-7. Unit Cost of Relevant Continuous and Periodic Monitoring Technologies

Item

Capital Cost to Establish

Environmental Baseline

Capital Cost for Construction

and Equipment Operating Cost

Deep Monitoring Wells (into

or right above injection zone)

$200 lab fee per sample plus

$1,000 to collect. 4 samples

per well is $4,800 per well.

$20,700 + $5,200/well for design,

$10,400 per well for surface

disturbance, $165-$207 per foot to

build, $20,800 for equipment

Annual O&M costs are $25,900 +

$3.10/ft per well per year

CO2 Flow Meters on

Producing Oil and Gas Wells NA $10,400/ oil well Annual O&M costs are $520 perwell per year

CO2 Flow & Gas

Composition Meters on

Producing Oil and Gas Wells

NA $52,000/ oil well Annual O&M costs are $2,600

per well per year

Periodic Sampling and

Testing of Injected Fluid NA 12 hours @$107.23/hr = $1,286 forplan

$200 lab fee per sample plus

$270 to collect.

Estimation of Fugitive

Emission from Surface

Facilities

NA

40 hours @$107.23/hr = $4,289 for

planning and initial inventory of

facilities

24 hours @$107.23/hr = $2,574

for annual calculations

Periodic Seismic Surveys

Seismic survey baseline

established as part of site

characterization. No extra cost

for monitoring.

No construction costs, but planning

and quality assurance costs would

add $25,000 per project.

$104,000 per square mile

Periodic Digital Color

Infrared Orthoimagery (CIR)

or Hyperspectral Imaging to

detect changes to

vegetation.

Initial survey before injection

commences would establish

baseline.

No construction costs, but planning

and quality assurance costs would

add $10,000 per square mile.

Airborne survey costs $250 per

square mile would be $6,250.

Plus mobilization costs of $5,000

per site.

Periodic mobile survey to

detect surface leaks. May be

good option where

vegetation is sparse.

NA

No construction costs, but planning

and quality assurance costs would

add $10,000 per square mile.

Mobile survey costs $300 per

hour. A square mile would take

about 1 day and cost $2,400.

Plus mobilization costs of $5,000

per site.

Eddy covariance

measurement from

permanent towers to detect

surface leaks.

Establishing baseline is

$35,000 per station.

40 hours @$107.23/hr = $4,289 for

plan plus $70,000/monitoring site. $10,000 per station per year

Soil zone monitoring

(sampling gas from

accumulation chambers)

Initial survey before injection

commences would establish

baseline.

40 hours @$107.23/hr = $4,289 for

plan plus $6,000/monitoring site

$200 lab fee per sample plus

$100 to collect.

Vadose zone monitoring

wells to sample gas above

water table.

Initial survey before injection

commences would establish

baseline.

40 hours @$107.23/hr = $4,289 for

plan plus $8,000/monitoring site

$200 lab fee per sample plus

$100 to collect.

Monitoring wells for samples

from shallow water.

Initial survey before injection

commences would establish

baseline.

40 hours @$107.23/hr = $4,289 for

plan plus $80,000/monitoring site

$200 lab fee per sample plus

$1,000 to collect.
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Table 4-8. Unit Cost of Relevant Episodic Monitoring Technologies (That may be

employed after a subsurface leak is detected)

Detection

Method

Method of

Quantification

Estimate of

Unit Cost for

Leak

Quantification

Cost per

Episode

Probability of

Application in

Any Given

Year per

Project

Additional

Annual Cost

per Project

for Leak

Quantification

Surface leak

detected by air, soil

or water table

monitoring or

subsurface leak

detected by

pressure anomaly

etc.

Material balance

by solving for

leaked quantity

given known

injected amounts

and observed

pressure in

injection zone.

Leak volume

estimation process

160 hours

@$110.62/hr.

$17,698 1.0% $177

Surface leak

detected by MIT

survey or by air, soil

or water table

monitoring.

Analysis of well

logs (e.g., noise

logs, oxygen

activation logs) to

quantify leaks

along wellbore

Additional well log

@4.15/ft +$2,070.

Leak volume

estimation process

160 hours

@$110.62/hr.

$57,118 1.0% $571

Subsurface leak

detected by

pressure anomaly in

containment zone.

Analysis of

pressure readings

in several

monitoring wells

and reservoir

simulation of leak.

Leak volume

estimation process

320 hours

@$110.62/hr.

$35,397 1.0% $354

Surface leak

detected by air, soil

or water table

monitoring.

Detailed seismic

survey plus

reservoir

simulation to

estimate leak

volume at

subsurface to help

calibrate leak

volume into

atmosphere

$104,00 per

square mile per

survey. Leak

volume estimation

process 160 hours

@$110.62/hr.

$121,698 1.0% $1,217

Surface leak

detected by air, soil

or water table

monitoring

Tenting of area to

estimate leak

volume. Alternative

might be to use

eddy covariance

towers set up in

leak area and

compare flux from

around towers set

up in surrounding

(nonleaking) areas.

Approximately

$70,000 per

square mile. Leak

volume estimation

process 80 hours

@$110.62/hr.

$78,849 1.0% $788

Total per

Year

5.0% $3,108

Note: Assumes survey for leak occurs over one square mile area in each episode. Project's area is 10

square miles
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4.5 Monitoring Technologies

Deep Monitoring Wells

Deep monitoring wells are typically drilled to monitor the deepest permeable zone above

the caprock. Downhole instrumentation can be used to monitor pressure, temperature, and

conductivity/salinity. Alternatively, U-tube devices can be used to retrieve pressurized samples

for laboratory testing. Other types of monitoring from wells include micro-seismic, cross-well

resistivity, and vertical seismic profiling.

CO2 Flow Meters on Producing Oil and Gas Wells

Meters, probably located after the wellhead separator, that continuously measure the

pressure, temperature and flow rate of the gas from a well. The composition of the gas is

analyzed periodically using a gas chromatograph to determine percent CO2 concentration. The

mass of CO2 passing through the wellhead can then be calculated from the measured quantities.

CO2 Flow and Gas Composition Meters on Producing Oil and Gas Wells

Meters, probably located after the wellhead separator, that continuously measure the

pressure, temperature, flow rate and chemical composition of the gas from a well. The mass of

CO2 passing through the wellhead can then be calculated from the measured quantities. This

differs from the item directly above in that the chemical composition of the gas is being

measured automatically by the meter itself rather through periodically obtaining a sample and

sending it to lab for analysis.

Periodic Sampling and Testing of Injected Fluid

All facilities conducting GS and all other facilities conducting CO2 injection will incur

periodic sampling and testing costs. To estimate the costs, we have applied similar assumptions

that were used in Subpart OO for sampling and testing of industrial gases. For example, we have

assumed that it takes 12 labor hours to contact an onsite laboratory or offsite vendor and develop

a plan; to collect and send the sample to an onsite or offsite laboratory; and to provide data

invoice if sent offsite. Furthermore, we have assumed that it costs approximately $500 per

sample to collect and conduct the test of chemical composition. In addition to these costs,

facilities conducting GS will additionally incur the costs described in this rule.

Seismic Surveys
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Seismic data acquisition involves the generation and detection of sound waves to

evaluation conditions in the subsurface. Periodic acquisition of seismic data can be used to

detect subsurface CO2 movement within and outside of the reservoir.

Digital Color Infrared Ortho-imagery and Hyper-spectral Imaging

Digital color ortho-imagery and hyper-spectral imaging are airborne remote sensing

technologies that are used to detect changes in vegetation resulting from CO2 leaks.

Hyperspectral sensors look at objects using electromagnetic spectrum. The object is to detect a

specific spectral signature that is known to result from CO2 uptake. The advantage of these

methods is that they can efficiently cover a large surface area.

Airborne or Mobile Remote Sensing Survey

CO2 detectors are commercially available for short closed-path and short open-path

(point) measurements and long open-path (radial line) measurements. Similar detectors have

been integrated into stationary, mobile, and airborne monitoring packages that are commonly

used in combination with high-resolution global positioning system (GPS) to detect and quantify

methane leaks in areas with road access. While these packages have not been widely tested for

CO2, various types of CO2 monitors are commercially available and could be used in these

applications. Such monitoring techniques are likely the leading candidates for monitoring plan

applications because of their low cost and high reliability. The technologies include infrared gas

analyzers (IRGAs, including Fourier transform infrared (FTIR) and non-dispersive infrared

(NDIR) analyzers), tunable diode lasers (TDLs), cavity ring down techniques, and others. The

sample path can range from 10 cm to 1 km, by reflecting a laser beam off retro-reflecting

mirrors. These devices measure the gas concentration, and, when packaged with measurements

of wind speed and wind direction, they measure the total gas flow.

LIDAR (Light Detection and Ranging) involves the transmission of light from an

instrument to a target and the recording of the reflected light to determine some property of the

target. Differential Absorption LIDAR (DIAL) uses two wavelengths of laser to measure CO2.

The wavelengths used are specific to CO2. One wavelength is selected to correspond to a CO2

spectral absorption line, while the other is a non-absorbing wavelength. The difference in

intensity of the two return signals is a measure of concentration.

Eddy Covariance
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Eddy Covariance is a technique whereby high frequency measurements of atmospheric

CO2 concentration at a height above the ground are made by an infra-red gas analyzer along with

measurements of micro-meteorological variables such as wind velocity, direction, humidity, and

temperature. Integration of these data allows derivation of the net CO2 flux over the upwind

footprint, typically square meters to square kilometers in area.

Soil Zone Monitoring with Accumulation Chamber (AC)

Surface CO2 flux is measured using an accumulation chamber. The chamber is made of

stainless steel with an open bottom and is placed at the sampling location. It may be placed

either directly on the ground or on a collar installed in the ground surface. The air is circulated

through the AC and measured with and infra-red gas analyzer.

Vadose Zone Monitoring

The vadose zone is the relatively shallow zone beneath the soil zone that is not saturated

with groundwater. Small diameter probes are installed in the zone and samples are taken. The

CO2 concentration of air samples taken in this zone can be measured by and infrared gas

analyzer.

Monitoring Wells for Sampling of Shallow Water

Shallow monitoring wells may be used to measure the properties of ground water. Such

wells are typically no deeper than several hundred feet.

Estimating Leak Volumes after a Leak is Detected

The monitoring program for facilities conducting GS may detect subsurface leaks and it

will be necessary to estimate the volume of leaks to the surface to comply with the reporting

requirements of this rule. Each site operator will have to devise suitable techniques taking into

account the geology of the sites, the location and nature of the potential leaks and the

performance characteristics of available monitoring and measurement technologies.

It is expected that these estimates may include engineering estimates as well as some

direct measurement and may have a wide margin of uncertainty. It is expected that site

characterization and screening will lead to selection of sites that are suitable for long-term

sequestration and that incidences of leaks to the surface may be infrequent at well-selected and

well-managed sites. The cost estimates presented here for subsurface leak quantification assume
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4-25

a two percent chance in one year that any given site will have to implement the leak

quantification strategy described in the site’s MRV plan. There are no operating statistics for

CO2 GS from which to draw any citable conclusions on how often leaks to the surface may be

detected, therefore a very conservative estimate was used in order to estimate the potential cost.

If the leak is detected in the subsurface (possibly by anomalous pressure readings in a

monitoring well) the leak volume may be estimated to help calibrate a leak volume to the

surface. Quantification is presumed to be done using engineering calculations supplemented,

when technically feasible, by direct observation/measurement using, for example, a 3-D seismic

survey over the area of the suspected leak. The seismic survey might be able to detect the

location, size and density of the CO2 plume formed by the leak in one or more containment zones

located above the injection zone. The volume of the leak also might be estimated using a

reservoir simulation model of the containment zone calibrated to the pressure readings of the

monitoring wells surrounding the location of the leak. In other words, different volumes of leaks

would be tested in the reservoir simulator to find which leak volume most closely matches the

pressure history observed in the surrounding monitoring wells.

Leaks may also be detected at or near the surface by air, soil gas and water table

monitoring devices. It is possible that some of the monitoring devices, such as eddy covariance,

could themselves be used to estimate leak volumes. Another possible way of estimating the

volume of a leak at the surface is to place a tent over the area of the leak. The tent would be

sealed at the ground by weights or spikes and a calibrated volume of gas such as nitrogen would

be introduced into the tent and allowed to escape through a chimney at the top of the tent. By

measuring the concentration of CO2 in the gases leaving the chimney it is possible to measure the

amount of CO2 leaving the ground in the area of the tent. The tent would have to be moved to

many locations and the process repeated to get a representative sample over the entire area of the

leak. It also would be necessary to correct the readings for natural CO2 fluxes into and out of the

soil.

Many of the leak detection methods for onshore GS sites can be applied to sub-seabed

sites. These include monitoring of the injection well and monitoring of the subsurface CO2

plume: active seismic, passive seismic, sensors in deep monitoring wells, and reservoir

modeling. Though there will be differences in monitoring approaches at sub-seabed GS sites for

leak detection and quantification, the cost estimates are assumed to be comparable.

Labor Rates
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The cost of labor for many of the cost items in Table 4-9 and 4-10 and for General and

Administrative Costs are based on Society of Petroleum Engineers (SPE) 2008 annual salary

survey.

19 The average salary for a petroleum reservoir engineer with 15 years of experience is

$143,800. Applying a 1.6 fringe and overhead factor yields an hourly burdened labor cost of

$110.62 per hour.

The unit costs values shown in Table 4-9 and 4-10 reflect the cost of goods and services

that would be purchased by the entity which owns the facility conducting GS. That entity would

have additional General and Administrative Costs (G&A) on top of those direct costs for goods

and services. These G&A cost are assumed to 20 percent of the direct costs.

4.5.1 Cost Scenarios

There are three regulatory alternatives (low, medium [or reference], and high) presented

in Table 4-11 in terms of 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, the application of the monitoring devices are indicated as percents of sites that would

be expected to use each device or technique. Also shown in Table 5-4 are the portions of

facilities that expected to be required to use the device or technique under the UIC Class VI

permits and under UIC Class II permits. The cost impacts of the subpart RR are estimated as the

monitoring and measurement requirements above and beyond the UIC Class II requirements. 20

19 For SPE survey of petroleum engineers see http://www.spe.org/spesite/spe/spe/career/salary_survey/08SalarySurveyHighlights.pdf

20 For the purposes of this rule, costs incremental to Class II requirements were estimated for ER projects conducting

GS and costs incremental to the proposed Class VI requirements were estimated for all other GS projects.
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Table 4-9. Assumptions for Application of Technologies by Regulatory Alternative

Saline, Abandoned Oil & Gas Fields: Starting Point is UIC

Class VI Requirements

ER plus GS: Starting Point is UIC Class II

Requirements

Under UIC

Class VI

Lowest Level

RR

Alternative

Middle Level

RR

Alternative

Highest Level

RR

Alternative

Under

UIC

Class II

Lowest Level

RR

Alternative

Middle Level

RR

Alternative

Highest Level

RR

Alternative

Deep Monitoring

Wells (into or

right above

injection zone)

Fraction

Projects 100% 100% 100% 100% 0% 100% 100% 100%

Frequency

(months) Continuous Continuous Continuous Continuous Continuous Continuous Continuous

CO2 Flow Meters

on Producing Oil

and Gas Wells

Fraction

Projects 0% 0% 0% 0% 0% 100% 100% 100%

Frequency

(months) Continuous Continuous Continuous

CO2 Flow & Gas

Composition

Meters on

Producing Oil and

Gas Wells

Fraction

Projects 0% 0% 0% 0% 0% 0% 0% 0%

Frequency

(months) Continuous Continuous Continuous

Periodic

Sampling and

Testing of

Injected Fluid

Fraction

Projects 100% 100% 100% 100% 100% 100% 100% 100%

Frequency

(months) 3 3 3 3 3 3 3 3

Estimation of

Fugitive Emission

from Surface

Facilities

Fraction

Projects 0% 0% 100% 100% 0% 0% 0% 0%

Frequency

(months) 12 12 12 12 12 12 12 12

Periodic Seismic

Surveys

Fraction

Projects 25% 25% 25% 25% 0% 25% 25% 25%

Frequency

(months) 60 60 60 60 60 60 60 60

Periodic Digital

Color Infrared

Orthoimagery

(CIR) or

Hyperspectral

Imaging to detect

changes to

vegetation.

Fraction

Projects 0% 0% 50% 50% 0% 0% 50% 50%

Frequency

(months) 12 12 12 12 12 12 12 12
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Table 4-9. Assumptions for Application of Technologies by Regulatory Alternative (continued)

Saline, Abandoned Oil & Gas Fields: Starting Point is UIC

Class VI Requirements ER plus GS: Starting Point is UIC Class II Requirements

Under UIC

Class VI

Lowest Level

RR

Alternative

Middle Level

RR

Alternative

Highest

Level RR

Alternative

Under UIC

Class II

Lowest Level

RR

Alternative

Middle Level

RR

Alternative

Highest

Level RR

Alternative

Periodic mobile

survey to detect

surface leaks.

May be good

option where

vegetation is

sparse.

Fraction

Projects 0% 0% 50% 50% 0% 0% 50% 50%

Frequency

(months) 12 12 12 12 12 12 12 12

Eddy covariance

measurement

from permanent

towers to detect

surface leaks.

Fraction

Projects 25% 25% 25% 100% 0% 25% 25% 100%

Frequency

(months) Continuous Continuous Continuous Continuous Continuous Continuous Continuous Continuous

Soil zone

monitoring

(sampling gas

from

accumulation

chambers)

Fraction

Projects 0% 0% 100% 100% 0% 0% 100% 100%

Frequency

(months) 12 12 12 3 12 12 12 3

Vadose zone

monitoring wells

to sample gas

above water

table.

Fraction

Projects 0% 0% 100% 100% 0% 0% 100% 100%

Frequency

(months) 12 12 12 3 12 12 12 3

Monitoring wells

for samples from

water table.

Fraction

Projects 0% 0% 100% 100% 0% 0% 100% 100%

Frequency

(months) 12 12 12 3 12 12 12 3
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4.6 Projecting and Discounting National Costs

The cost per project is computed by applying the cost algorithms (Table 4-5 and 4-8) to

the “pro-forma” characteristics assume for each type of project (Tables 4-3 to 4-5), “Pro-form

Project Characteristics.” The results for cost per project appear in the left-hand side of Table 4-

10 for the no additional ER opt in activity baseline scenario. Table 4-11 shows the results for the

anthropogenic ER opt in only activity scenario. Table 4-12 shows the results for the

anthropogenic plus one half of other ER opt in activity scenario.
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Table 4-10. Summary of Cost Impacts: Activity Baseline with No Additional ER Opt In

Environmental Baseline Periodic Monitoring

Annual

Episodic

Monitoring

Costs

Overhead

and G&A

Total

Annual

Costs

Capital

Costs

Annualized

Capital

Costs Capital Cost

Annual

Operating

Cost

Annualized

Capital and

Contractor

Costs

Under

UIC

Class VI

or II

Known DOE EOR Pilot

Projects $ - $0 $ 1,286 $ 1,880 $ 2,063 $0 $ 413 $ 2,476

Known DOE Saline Pilot

Projects $ 7,438 $2,196 $ 3,103,485 $ 114,245 $1,030,481 $0 $ 206,535 $1,239,212

Future DOE Saline Pilot

Projects $ 7,438 $2,196 $ 3,103,485 $ 114,245 $1,030,481 $0 $ 206,535 $1,239,212

Known Commercial EOR

Projects

Class II $ - $0 $ 1,286 $ 1,880 $ 2,063 $0 $ 413 $ 2,476

Known Commercial Saline

Projects $ 50,750 $3,807 $13,906,005 $ 533,000 $1,576,077 $0 $ 315,977 $1,895,861

Conversion of Existing EOR

Projects to GS

Class II $ - $0 $ 1,286 $ 1,880 $ 2,063 $0 $ 413 $ 2,476

Low

Known DOE EOR Pilot

Projects $ 38,500 $5,482 $ 8,407,654 $ 392,750 $1,589,811 $3,108 $ 319,680 $1,918,080

Known DOE Saline Pilot

Projects $ 7,438 $2,196 $ 3,103,485 $ 114,245 $1,030,481 $3,108 $ 207,157 $1,242,941

Future DOE Saline Pilot

Projects $ 7,438 $2,196 $ 3,103,485 $ 114,245 $1,030,481 $3,108 $ 207,157 $1,242,941

Known Commercial EOR

Projects $ 35,000 $4,983 $ 7,215,125 $ 339,860 $1,367,131 $3,108 $ 275,044 $1,650,267

Known Commercial Saline

Projects $ 50,750 $3,807 $13,906,005 $ 533,000 $1,576,077 $3,605 $ 316,698 $1,900,187

Conversion of Existing EOR

Projects to GS $ 35,000 $4,983 $ 7,215,125 $ 339,860 $1,367,131 $3,108 $ 275,044 $1,650,267
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Reference

Known DOE EOR Pilot

Projects $ 84,340 $12,008 $ 9,436,084 $ 451,650 $1,795,136 $3,108 $ 362,050 $2,172,302

Known DOE Saline Pilot

Projects $ 18,310 $5,406 $ 3,306,448 $ 132,232 $1,108,388 $3,108 $ 223,380 $1,340,281

Future DOE Saline Pilot

Projects $ 18,310 $5,406 $ 3,306,448 $ 132,232 $1,108,388 $3,108 $ 223,380 $1,340,281

Known Commercial EOR

Projects $ 76,900 $10,949 $ 8,150,061 $ 393,860 $1,554,245 $3,108 $ 313,660 $1,881,962

Known Commercial Saline

Projects $ 110,380 $8,280 $15,265,951 $ 611,624 $1,756,710 $3,605 $ 353,719 $2,122,313

Conversion of Existing EOR

Projects to GS $ 76,900 $10,949 $ 8,150,061 $ 393,860 $1,554,245 $3,108 $ 313,660 $1,881,962

High

Known DOE EOR Pilot

Projects $ 199,840 $28,453 $ 9,697,737 $ 532,170 $1,912,910 $3,108 $ 388,894 $2,333,364

Known DOE Saline Pilot

Projects $ 40,623 $11,993 $ 3,356,995 $ 147,787 $1,138,866 $3,108 $ 230,793 $1,384,759

Future DOE Saline Pilot

Projects $ 40,623 $11,993 $ 3,356,995 $ 147,787 $1,138,866 $3,108 $ 230,793 $1,384,759

Known Commercial EOR

Projects $ 181,900 $25,898 $ 8,387,928 $ 467,060 $1,661,312 $3,108 $ 338,064 $2,028,382

Known Commercial Saline

Projects $ 262,630 $19,700 $15,610,858 $ 717,764 $1,888,721 $3,605 $ 382,405 $2,294,431

Conversion of Existing EOR

Projects to GS $ 181,900 $25,898 $ 8,387,928 $ 467,060 $1,661,312 $3,108 $ 338,064 $2,028,382
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Table 4-11. Summary of Cost Impacts: Activity Baseline from only Anthropogenic ER Opt In

Environmental Baseline Periodic Monitoring

Annual

Episodic

Monitoring

Costs

Overhead

and G&A

Total

Annual

Costs

Capital

Costs

Annualized

Capital

Costs Capital Cost

Annual

Operating

Cost

Annualized

Capital and

Contractor

Costs

Under UIC

Class VI or

II

Known DOE EOR Pilot

Projects $ - $0 $ 1,286 $ 1,880 $ 2,063 $0 $ 413 $ 2,476

Known DOE Saline Pilot

Projects $ 7,438 $2,196 $ 3,103,485 $ 114,245 $1,030,481 $0 $ 206,535 $1,239,212

Future DOE Saline Pilot

Projects $ 7,438 $2,196 $ 3,103,485 $ 114,245 $1,030,481 $0 $ 206,535 $1,239,212

Known Commercial EOR

Projects

Class II $ - $0 $ 1,286 $ 1,880 $ 2,063 $0 $ 413 $ 2,476

Known Commercial Saline

Projects $ 50,750 $3,807 $13,906,005 $ 533,000 $1,576,077 $0 $ 315,977 $1,895,861

Conversion of Existing EOR

Projects to GS

Class II $ - $0 $ 1,286 $ 1,880 $ 2,063 $0 $ 413 $ 2,476

Low

Known DOE EOR Pilot

Projects $ 38,500 $5,482 $ 8,407,654 $ 392,750 $1,589,811 $3,108 $ 319,680 $1,918,080

Known DOE Saline Pilot

Projects $ 7,438 $2,196 $ 3,103,485 $ 114,245 $1,030,481 $3,108 $ 207,157 $1,242,941

Future DOE Saline Pilot

Projects $ 7,438 $2,196 $ 3,103,485 $ 114,245 $1,030,481 $3,108 $ 207,157 $1,242,941

Known Commercial EOR

Projects $ 35,000 $4,983 $ 7,215,125 $ 339,860 $1,367,131 $3,108 $ 275,044 $1,650,267

Known Commercial Saline

Projects $ 50,750 $3,807 $13,906,005 $ 533,000 $1,576,077 $3,605 $ 316,698 $1,900,187

Conversion of Existing EOR

Projects to GS $ 35,000 $4,983 $ 7,215,125 $ 339,860 $1,367,131 $3,108 $ 275,044 $1,650,267
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Reference

Known DOE EOR Pilot

Projects $ 84,340 $12,008 $ 9,436,084 $ 451,650 $1,795,136 $3,108 $ 362,050 $2,172,302

Known DOE Saline Pilot

Projects $ 18,310 $5,406 $ 3,306,448 $ 132,232 $1,108,388 $3,108 $ 223,380 $1,340,281

Future DOE Saline Pilot

Projects $ 18,310 $5,406 $ 3,306,448 $ 132,232 $1,108,388 $3,108 $ 223,380 $1,340,281

Known Commercial EOR

Projects $ 76,900 $10,949 $ 8,150,061 $ 393,860 $1,554,245 $3,108 $ 313,660 $1,881,962

Known Commercial Saline

Projects $ 110,380 $8,280 $15,265,951 $ 611,624 $1,756,710 $3,605 $ 353,719 $2,122,313

Conversion of Existing EOR

Projects to GS $ 76,900 $10,949 $ 8,150,061 $ 393,860 $1,554,245 $3,108 $ 313,660 $1,881,962

High

Known DOE EOR Pilot

Projects $ 199,840 $28,453 $ 9,697,737 $ 532,170 $1,912,910 $3,108 $ 388,894 $2,333,364

Known DOE Saline Pilot

Projects $ 40,623 $11,993 $ 3,356,995 $ 147,787 $1,138,866 $3,108 $ 230,793 $1,384,759

Future DOE Saline Pilot

Projects $ 40,623 $11,993 $ 3,356,995 $ 147,787 $1,138,866 $3,108 $ 230,793 $1,384,759

Known Commercial EOR

Projects $ 181,900 $25,898 $ 8,387,928 $ 467,060 $1,661,312 $3,108 $ 338,064 $2,028,382

Known Commercial Saline

Projects $ 262,630 $19,700 $15,610,858 $ 717,764 $1,888,721 $3,605 $ 382,405 $2,294,431

Conversion of Existing EOR

Projects to GS $ 181,900 $25,898 $ 8,387,928 $ 467,060 $1,661,312 $3,108 $ 338,064 $2,028,382
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Table 4-12. Summary of Cost Impacts: Activity Baseline from Anthropogenic CO2 plus One-half of Other ER Opt In

Environmental Baseline Periodic Monitoring

Annual

Episodic

Monitoring

Costs

Overhead

and G&A

Total

Annual

Costs

Capital

Costs

Annualized

Capital

Costs Capital Cost

Annual

Operating

Cost

Annualized

Capital and

Contractor

Costs

Under UIC

Class VI or

II

Known DOE EOR Pilot

Projects $ - $0 $ 1,286 $ 1,880 $ 2,063 $0 $ 413 $ 2,476

Known DOE Saline Pilot

Projects $ 7,438 $2,196 $ 3,103,485 $ 114,245 $1,030,481 $0 $ 206,535 $1,239,212

Future DOE Saline Pilot

Projects $ 7,438 $2,196 $ 3,103,485 $ 114,245 $1,030,481 $0 $ 206,535 $1,239,212

Known Commercial EOR

Projects

Class II $ - $0 $ 1,286 $ 1,880 $ 2,063 $0 $ 413 $ 2,476

Known Commercial Saline

Projects $ 50,750 $3,807 $13,906,005 $ 533,000 $1,576,077 $0 $ 315,977 $1,895,861

Conversion of Existing EOR

Projects to GS

Class II $ - $0 $ 1,286 $ 1,880 $ 2,063 $0 $ 413 $ 2,476

Low

Known DOE EOR Pilot

Projects $ 38,500 $5,482 $ 8,407,654 $ 392,750 $1,589,811 $3,108 $ 319,680 $1,918,080

Known DOE Saline Pilot

Projects $ 7,438 $2,196 $ 3,103,485 $ 114,245 $1,030,481 $3,108 $ 207,157 $1,242,941

Future DOE Saline Pilot

Projects $ 7,438 $2,196 $ 3,103,485 $ 114,245 $1,030,481 $3,108 $ 207,157 $1,242,941

Known Commercial EOR

Projects $ 35,000 $4,983 $ 7,215,125 $ 339,860 $1,367,131 $3,108 $ 275,044 $1,650,267

Known Commercial Saline

Projects $ 50,750 $3,807 $13,906,005 $ 533,000 $1,576,077 $3,605 $ 316,698 $1,900,187

Conversion of Existing EOR

Projects to GS $ 35,000 $4,983 $ 7,215,125 $ 339,860 $1,367,131 $3,108 $ 275,044 $1,650,267
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4-35

Reference

Known DOE EOR Pilot

Projects $ 84,340 $12,008 $ 9,436,084 $ 451,650 $1,795,136 $3,108 $ 362,050 $2,172,302

Known DOE Saline Pilot

Projects $ 18,310 $5,406 $ 3,306,448 $ 132,232 $1,108,388 $3,108 $ 223,380 $1,340,281

Future DOE Saline Pilot

Projects $ 18,310 $5,406 $ 3,306,448 $ 132,232 $1,108,388 $3,108 $ 223,380 $1,340,281

Known Commercial EOR

Projects $ 76,900 $10,949 $ 8,150,061 $ 393,860 $1,554,245 $3,108 $ 313,660 $1,881,962

Known Commercial Saline

Projects $ 110,380 $8,280 $15,265,951 $ 611,624 $1,756,710 $3,605 $ 353,719 $2,122,313

Conversion of Existing EOR

Projects to GS $ 76,900 $10,949 $ 8,150,061 $ 393,860 $1,554,245 $3,108 $ 313,660 $1,881,962

High

Known DOE EOR Pilot

Projects $ 199,840 $28,453 $ 9,697,737 $ 532,170 $1,912,910 $3,108 $ 388,894 $2,333,364

Known DOE Saline Pilot

Projects $ 40,623 $11,993 $ 3,356,995 $ 147,787 $1,138,866 $3,108 $ 230,793 $1,384,759

Future DOE Saline Pilot

Projects $ 40,623 $11,993 $ 3,356,995 $ 147,787 $1,138,866 $3,108 $ 230,793 $1,384,759

Known Commercial EOR

Projects $ 181,900 $25,898 $ 8,387,928 $ 467,060 $1,661,312 $3,108 $ 338,064 $2,028,382

Known Commercial Saline

Projects $ 262,630 $19,700 $15,610,858 $ 717,764 $1,888,721 $3,605 $ 382,405 $2,294,431

Conversion of Existing EOR

Projects to GS $ 181,900 $25,898 $ 8,387,928 $ 467,060 $1,661,312 $3,108 $ 338,064 $2,028,382
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4.7 MRV Plan Costs

Facilities must develop a monitoring, reporting, and verification (MRV) plan, submit the

MRV plan to EPA, receive an approved MRV plan from EPA, implement the EPA-approved

plan, and submit annual report addenda in accordance with procedures in 98.448(a). The MRV

plan must include a delineation of the monitoring areas; an identification of potential surface

leakage pathways and a risk assessment of leakage of the CO2 through these pathways in the

monitoring area; a strategy for detecting and quantifying any surface leakage of CO2; a strategy

for establishing the expected environmental baselines; and a summary of considerations made to

calculate site-specific variables for the mass balance equation.

Facilities must submit the MRV plan on the schedule described in section 98.448(b).

Facilities must re-submit the MRV plan for EPA approval according to section 98.448(g). An

addendum describing the monitoring program that was implemented, including descriptions of

monitoring anomalies and surface leakage, if any, must be submitted with the next annual report

(March 31 of the subsequent calendar year).

The costs of the developing a MRV plan are reported in Tables 4-13 and 4-14.
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Table 4-13. Cost of Developing MRV Plan: New Project with UIC Class VI Permit

Scenario Cost Item

Cost Algorithm

in Hours

Cost per

Instance per

Project

Frequency

(every X

years for

40-year

injection +

50 year

monitoring

life)

Cost per Project

(over 90-year life,

undiscounted) Notes

New Project with

UIC Class VI

Permit Evaluate Leakage Pathways 16 $ 1,770 once $ 1,770

All raw data should be in UIC Class VI

permit. Time is for re-interpretation

relative to RR regs

New Project with

UIC Class VI

Permit Delineate Areas of Monitoring 32 $ 3,540 5 $ 63,714

Modeling would be done for UIC Class

VI, but needs to be interpreted for free

phase plume. Maps need to be

generated

New Project with

UIC Class VI

Permit

Develop strategy for leak

detection, verification and

quantification 160 $ 17,698 once $ 17,698

Requires considerable statistical

analysis not expected to be in UIC

permit

New Project with

UIC Class VI

Permit Establish baseline conditions 16 $ 1,770 once $ 1,770

Requires more statistical analysis than

expected to be in UIC permit. Data

collection cost are already under each

technology option.

New Project with

UIC Class VI

Permit Tailor mass balance equation 8 $ 885 once $ 885

New Project with

UIC Class VI

Permit Write MRV plan 400 $ 44,246 once $ 44,246 Assume 100 pages at 4 hours per page

New Project with

UIC Class VI

Permit

Discuss MRV plan with EPA

and edits 100 $ 11,062 once $ 11,062

Assume most plans will be OK, but

others will have to be redone to some

degree. Assume 25% of first draft time.

New Project with

UIC Class VI

Permit Annual Report 100 $ 11,062 1 $ 995,538 Assume 25 pages at 4 hours per page

New Project with

UIC Class VI

Permit All Items 832 $ 92,032 $ 1,136,684
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Table 4-14. Cost of Developing MRV Plan: ER Class II Project (no Class VI Permit)

Scenario Cost Item

Cost

Algorithm in

Hours

Cost per

Instance per

Project

Frequency

(every X

years for

10-year

injection +

50 year

monitoring

life)

Cost per

Project (over

60-year life,

undiscounted) Notes

ER Class II Project

(no Class VI Permit) Evaluate Leakage Pathways 136 $ 15,044 once $ 15,044

All raw data should exist through normal

ER project evaluation and monitoring.

However, considerable effort needed to

interpret for RR regs.

ER Class II Project

(no Class VI Permit) Delineate Areas of Monitoring 756 $ 83,625 5 $ 1,003,503

Some modeling would be done for ER

project evaluation and monitoring, but

most likely need to be updated for MRV

plan.

ER Class II Project

(no Class VI Permit)

Develop strategy for leak detection,

verification and quantification 160 $ 17,698 once $ 17,698

Requires considerable statistical analysis

not expected to be in UIC permit

ER Class II Project

(no Class VI Permit) Establish baseline conditions 16 $ 1,770 once $ 1,770

Requires more statistical analysis than

expected to be in UIC permit. Data

collection cost are already under each

technology option.

ER Class II Project

(no Class VI Permit) Tailor mass balance equation 16 $ 1,770 once $ 1,770 More complex for ER

ER Class II Project

(no Class VI Permit) Write MRV plan 600 $ 66,369 once $ 66,369 Assume 150 pages at 4 hours per page

ER Class II Project

(no Class VI Permit) Discuss MRV plan with EPA and edits 150 $ 16,592 once $ 16,592

Assume most plans will be OK, but others

will have to be redone to some degree.

Assume 25% of first draft time.

ER Class II Project

(no Class VI Permit) Annual Report 100 $ 11,062 1 $ 663,692 Assume 25 pages at 4 hours per page

ER Class II Project

(no Class VI

Permit) All Items 1,934 $ 213,930 $ 1,786,438
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4.8 Annual Report Costs

As part of the MRV plan, EPA is requiring annual reporting. Respondents are required to create

an annual report each year. For costing purposes, EPA assumed a 25 page report that require 4

labor hours per page (annual cost is $11,062) (Table 4-13 and Table 4-14)

4.9 Other Recordkeeping and Reporting Costs

Additional recordkeeping ($1,700 per entity) and reporting ($500) costs per facility were

also added to each project type.

4.10 Public Sector Burden

EPA estimates the public sector burden to be $344,000 per year; $55,000 per year is for

verification activities, and remaining costs are for program implementation and developing and

maintaining the data collection system. Program implementation activities include, but are not

limited to, evaluating monitoring plans, developing guidance and training materials to assist the

regulated community, responding to inquires from affected facilities on monitoring and

applicability requirements, and developing tools to assist in determining applicability.
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5-1

SECTION 5

ECONOMIC IMPACT ANALYSIS

EPA prepares an EIA to provide decision makers with a measure of the social costs of

using resources to comply with a program (EPA, 2000). As noted in EPA’s (2000) Guidelines

for Preparing Economic Analyses, several tools are available to estimate social costs and range

from simple direct compliance cost methods to the development of a more complex market

analysis that estimates market changes (e.g., price and consumption) and economic welfare

changes (e.g., changes in consumer and producer surplus). Given data limitations and the size

scope of the final rule, EPA has used the direct compliance cost method as a measure of social

costs21.

5.1 Threshold Analysis

EPA is requiring reporting from all facilities that meet the subpart UU (previously

referred to as “Tier 1” facilities) source category definition and from all facilities that meet the

subpart RR (previously referred to as “Tier 2” facilities) source category definition, at no

threshold. EPA notes that a subpart RR threshold specific to ER projects that are not permitted as

UIC Class VI is unnecessary because such projects can choose to opt-in to the subpart RR source

category by implementing an EPA-approved MRV plan, regardless of quantity of CO2 received.

An all-in reporting threshold will allow the Agency to comprehensively track all CO2

supply (as reported in Suppliers of CO2, subpart PP) that is received. This approach is consistent

with the all-in requirements in the GHG Reporting Program for suppliers of petroleum, natural

gas, and coal-to-liquid products (subparts LL, MM, and NN), producers of industrial gases

(subpart OO), and suppliers of CO2 (subpart PP). It was reasonable to require all of the facilities

in these source categories to report because it would result in the most comprehensive accounting

possible, simplify the rule, and permit facilities to quickly determine whether or not they must

report; the same rationale applies for subparts RR and UU in today’s rule. Furthermore, it will

create a uniform burden for all covered facilities, ensuring a level playing field in, and

preventing fragmentation of, the ER and GS sectors. Finally, EPA concluded that the same

approach in both subparts UU and RR maximizes clarity and simplicity for facilities that choose

to opt in from one to the other. The results of the threshold analysis are presented below in Table

5-1 and Table 5-2. For further information on the assumptions underlying the threshold analysis,

please refer to the general technical support document (TSD) for proposal.22

21 See pages 124 and 125 (EPA, 2000).

22 Subpart RR General TSD (see docket ID No. EPA-HQ-OAR-2009-0926)
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5-2

Table 5-1 Geologic Sequestration Facilities: Effect of CO2 Received Threshold on

Reported Amount of CO2 Received and Number of Facilities Required to

Report (Subpart RR)

Threshold Level

(metric tons/yr of

CO2 received)

Total National

(metric tons/yr

of CO2

received)

Total

Number

of U.S.

Facilities

Amount of CO2

Received

Number of

Facilities

Metric

tons/yr of

CO2

Received

Percent

Covered Number PercentCovered

All In 10,462,885 13 10,462,885 100.00% 13 100.00%

1,000 10,462,885 13 10,462,885 100.00% 13 100.00%

10,000 10,462,885 13 10,462,885 100.00% 13 100.00%

25,000 10,462,885 13 10,462,885 100.00% 13 100.00%

100,000 10,462,885 13 10,462,885 100.00% 13 100.00%

Table 5-2. Facilities Conducting CO2 Injection: Effect of CO2 Received Threshold on

Reported Amount of CO2 Received and Number of Facilities Required to

Report (Subpart UU)

Threshold Level

(metric tons/yr of

CO2 received)

Total National

(metric tons/yr

of CO2

received)

Total

Number

of U.S.

Facilities

Amount of CO2

Received

Number of

Facilities

Metric

tons/yr of

CO2

Received

Percent

Covered Number PercentCovered

All In 40,115,442 80 40,115,442 100.00% 80 100.00%

1,000 40,115,442 80 40,111,115 99.99% 74 92.50%

10,000 40,115,442 80 40,099,065 99.96% 71 88.75%

25,000 40,115,442 80 40,005,238 99.73% 65 81.25%

100,000 40,115,442 80 39,065,039 97.38% 48 60.00%

5.2 National Cost Estimates

The total annualized costs incurred under the rule by these entities would be

approximately $7 million (in 2008$) in the first year and 6.7 million in subsequent years. This

includes a public sector burden estimate of $344,000 for program implementation and

verification activities. The typical annual cost for a facility conducting CO2 injection (no GS) is

$4,000 per year (Table 5-3).
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Table 5-3. National Annualized Mandatory Reporting Costs Estimates: Subpart RR and

Subpart UU

Reference

First Year

Subsequent

Years

Type Number

Metric

Tons CO2

Received

per Year

thousand,

2008$

thousand,

2008$

R&D (RR) 9 5,320,000 $73 $73

Facilities Conducting GS (Saline)

(RR)

1 1,842,885

$318 $240

Facilities Conducting GS (ER)

(RR)

3 3,300,000

$5,913 $5,680

Additional Facilities Conducting

GS (ER opt in) (RR)

0 0

$0 $0

Facilities Conducting CO2

Injection (No GS) (UU) 80

40,115,442

$332 $332

Private Sector, Total All Projects 93 50,578,327 $6,636 $6,326

Private Sector, Average ($/ton) $0.13 $0.13

Public Sector, Total $344 $344

National Total $6,979 $6,670

Given uncertainties related to project adoption and the costs of the reporting program,

EPA also considered two other private costs scenarios (one higher and one lower than the

reference cost scenario) in order to assess a range of economic impacts on affected entities

(Table 5-4).
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5-4

Table 5-4. Annualized Mandatory Reporting Costs Estimates (2008$): Subpart RR and

Subpart UU

Low High

First Year

Subsequent

Years First Year

Subsequent

Years

Type

thousand,

2008$

thousand,

2008$

thousand,

2008$

thousand,

2008$

R&D (RR) $73 $73 $73 $73

Facilities Conducting GS (Saline) (RR) $96 $18 $490 $413

Facilities Conducting GS (ER) (RR) $5,218 $4,985 $6,352 $6,120

Additional Facilities Conducting GS (ER

opt in) (RR) $0 $0 $0 $0

Facilities Conducting CO2 Injection (No

GS) (UU) $332 $332 $332 $332

Private Sector, Total All Projects $5,719 $5,409 $7,247 $6,937

Private Sector, Average ($/ton) $0.11 $0.11 $0.14 $0.14

Public Sector, Total $344 $344 $344 $344

National Total $6,062 $5,752 $7,591 $7,281

5.2.1 National Cost Estimates Under Alternative Facilities Conducting GS (ER opt

in) Outcomes

Currently, 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, two additional scenarios of the have been considered to

represent medium and high outcomes. 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).

As shown in Tables 5-5, national cost estimate is $39 million under the medium ER opt

in outcome (first year) and $37 million in subsequent years. As shown in Tables 5-6, national

cost estimate is $104 million under the high ER opt in outcome (first year) and $98 million in

subsequent years.
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Table 5-5. National Annualized Mandatory Reporting Costs Estimates (2008): All

Anthropogenic CO2 Projects

All Anthropogenic CO2

Projects

First Year

Subsequent

Years

Type Number

Metric

Tons CO2

Received

per Year

thousand,

2008$

thousand,

2008$

R&D (RR) 9 5,320,000 $73 $73

Facilities Conducting GS (Saline)

(RR)

1 1,842,885

$318 $240

Facilities Conducting GS (ER)

(RR)

3 3,300,000

$5,913 $5,680

Additional Facilities Conducting

GS (ER opt in) (RR)

16 6,972,040

$32,459 $30,552

Facilities Conducting CO2

Injection (No GS) (UU) 64

33,143,402

$266 $266

Private Sector, Total All Projects 93 50,578,327 $39,029 $36,811

Private Sector, Average ($/ton) $0.77 $0.73

Public Sector, Total $344 $344

National Total $39,372 $37,155
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5-6

Table 5-6. National Annualized Mandatory Reporting Costs Estimates (2008$): All

Anthropogenic and 50 Percent of Other CO2 Projects

All Anthropogenic and 50

Percent of Other CO2

Projects

First Year

Subsequent

Years

Type Number

Metric

Tons CO2

Received

per Year

thousand,

2008$

thousand,

2008$

R&D (RR) 9 5,320,000 $73 $73

Facilities Conducting GS (Saline)

(RR)

1 1,842,885

$318 $240

Facilities Conducting GS (ER)

(RR)

3 3,300,000

$5,913 $5,680

Additional Facilities Conducting

GS (ER opt in) (RR)

48 23,543,741

$97,378 $91,655

Facilities Conducting CO2

Injection (No GS) (UU) 32

16,571,701

$133 $133

Private Sector, Total All Projects 93 50,578,327 $103,815 $97,782

Private Sector, Average ($/ton) $2.05 $1.93

Public Sector, Total $344 $344

National Total $104,159 $98,125

5.2.2 National Cost Estimates Under Alternative Facilities Conducting GS

(Commercial Saline) Outcomes

As discussed in Section 2, on February 3, 2010, President Obama established the CCS

Task Force. The CCS Task Force, co-chaired by DOE and EPA, was charged with proposing a

plan to overcome the barriers to the widespread, cost-effective deployment of CCS within ten

years, with a goal of bringing 5 to 10 commercial demonstration projects online by 2016.

Additionally, the American Clean Energy Security Act (ACES) and the American Power Act

(APA) are estimated to induce about 30 percent of fossil-fuel-based electricity generation to

come from power plants with CCS by 2040, rising to approximately 59 percent by 2050 (15

percent and 16 percent respectively of total electricity generation) (EPA, 2010). EPA analysis of
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5-7

APA projects deployment of over 30GW of CCS in 2030, which corresponds to over 54 550MW

power plants. These modeling exercises show that CCS may play an important role in helping

the United States meet carbon reduction targets.

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 (73 FR 43492). 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.

5.2.3 National Cost Estimates: 2011 to 2060 Using Underground Injection Control

Program for Carbon Dioxide Geologic Sequestration Wells (UIC Class VI

Rule) Baseline

EPA also conducted a cost analysis projected between 2011 and 2060. To do this, we

used estimates of the anticipated level of U.S GS activity developed for the Underground

Injection Control Program for Carbon Dioxide Geologic Sequestration Wells (UIC Class VI

Rule) economic analysis (EPA-HQ-OW-2008-0390). The UIC Class VI Rule establishes

minimum Federal requirements under the Safe Drinking Water Act (SDWA) for injection of CO2

for the purposes of long-term storage (also known as GS). The final rule creates a new class of

injection well, Class VI, and sets minimum technical criteria for the purposes of protecting

underground sources of drinking water (USDWs). Additional details about the development of

the Geologic Sequestration Rule baseline can be found in section 3.4 of the UIC Class VI Rule’s

economic impact analysis (EPA-HQ-OW-2008-0390) Table 5-7 reports the baseline population

numbers. As shown in Table 5-7, present value of the total costs incurred from 2011 to 2060 is

estimate to be $332 million using a 3 percent discount rate) and $108 million using a 7 percent

discount rate. These numbers are conservative estimates based on the assumption that the

projects report for the entire time period. In some cases, the plume and pressure front may

stabilize before 2060 resulting in fewer years of reporting costs. Waivered saline and waivered

ER refers to the UIC Class VI Rule’s provision that owners and operators may apply for and

receive a waiver of the requirement to inject below the lowermost underground source of

drinking water.
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Table 5-7. Anticipated Level of U.S GS Activity Developed for the Underground Injection

Control Program for Carbon Dioxide Geologic Sequestration Wells (UIC

Class VI Rule)

Type of Formation

Saline Formations Enhanced Recovery

Year

Pilot

Project

Large

Project

Waivered

Saline ER

Waivered

ER Total

2011 0 0 0 0 0 0

2012 0 0.86 0.05 0 0 1

2013 0 0.86 0.05 0 0 1

2014 0 1.71 0.1 0 0 2

2015 0 0 0 0 0 0

2016 0 1.71 0.1 0 0 2

2017 2 4.28 0.24 0 0 7

2018 0 0 0 0 0 0

2019 0 0 0 0 0 0

2020 0 0 0 0 0 0

2021 0 0 0 0 0 0

2022 0 0 0 0 0 0

2023 0 0 0 0 0 0

2024 0 0 0 0 0 0

2025 0 0 0 0 0 0

2026 0 0 0 0 0 0

2027 0 0 0 0 0 0

2028 0 0 0 0 0 0

2029 0 0 0 0.86 0.05 1

2030 0 0 0 0 0 0

2031 0 0 0 0.86 0.05 1

2032 0 0 0 3.42 0.19 4

2033 0 0 0 2.57 0.14 3

2034 0 0 0 0.86 0.05 1

2035 0 0 0 1.71 0.1 2

2036 0 0 0 2.57 0.14 3

2037 0 0 0 0.86 0.05 1

2038 0 0 0 0 0 0

2039 0 0 0 0 0 0

2040 0 0 0 0 0 0

2041 0 0 0 0 0 0

2042 0 0 0 0 0 0

2043 0 0 0 0 0 0

2044 0 0 0 0 0 0

2045 0 0 0 0 0 0

2046 0 0 0 0 0 0

2047 0 0 0 0 0 0

2048 0 0 0 0 0 0

2049 0 0 0 0 0 0

2050 0 0 0 0 0 0

2051 0 0 0 0 0 0

2052 0 0 0 0 0 0

2053 0 0 0 0 0 0

2054 0 0 0 0 0 0

2055 0 0 0 0 0 0

2056 0 0 0 0 0 0

2057 0 0 0 0 0 0

2058 0 0 0 0 0 0

2059 0 0 0 0 0 0

2060 0 0 0 0 0 0

Total 2.0 9.4 0.5 13.7 0.8 26
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Source: Underground Injection Control Program for Carbon Dioxide Geologic Sequestration Wells (UIC Class VI Rule)

economic analysis (EPA-HQ-OW-2008-0390)

5.3 Economic Impact Analysis

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 geological sequestration operations, EPA restricted the analysis to ER operations.

ER activities account for approximately 90 percent of the project population (83 of 93 facilities).

To do this, we divided the average annualized mandatory reporting costs per field by the

estimated revenue for a representative field.

Sales Test Ratio= Average Cost (Table 5-3)/Estimated revenue (Table 5-6)

5.3.1 Revenue Estimate for a Representative Commercial ER Operation

EPA obtained national production statistics from the latest Department of Energy report

about CO2 ER technologies (DOE, 2009). Data suggest a typical operation produces

approximately 776,000 barrels of oil per year. Using the DOE choice of an average long-term

price of oil ($70), EPA estimated total revenue of $54.3 million per year. To enhance the

transparency of the calculation, we provide data, sources, and methods in Table 5-7.

Table 5-8. Estimated Annual Revenue for a Representative Commercial ER Field

Operation (2008)

Label Variable Value Source and Calculation Method

A Barrels Per Day 250,000 DOE, 2009 p: 19

B Barrels per year 77,562,500 A × 0.85 × 365

C Population 100 DOE, 2009 p: 19

D Average Barrels per year 775,625 B / C

E Price per barrel $70 DOE, 2009 p: 2

F

Total Revenue

($ million) $54 D× E

Source: EPA calculations using data from DOE (2009). Storing CO2 and Producing Domestic Crude Oil with Next Generation

CO2-ER Technology, accessed October 28, 2009.
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5.3.2 Sales Test Results

As shown in Table 5-8 sales test ratios are between 3.1 to 4.0 percent for facilities

conducting GS (Subpart RR). In contrast, facilities conducting CO2 injection (no GS, which

includes Class II ER operations) sales test ratios are below 0.01 percent.

Table 5-9. Sales Tests for Representative Commercial ER Field Operations

Alternative Cost Scenarios

Reference Low High

Type First Year

Subsequent

Years

First

Year

Subsequent

Years

First

Year

Subsequent

Years

Facilities Conducting GS

(ER) (RR) 3.6% 3.5% 3.2% 3.1% 3.9% 3.8%

Facilities Conducting GS

(ER opt in) (RR) 3.7% 3.5% 3.3% 3.1% 4.0% 3.8%

Facilities Conducting

CO2 Injection (No GS)

(UU) <0.1% <0.1% <0.1% <0.1% <0.1% <0.1%

5.4 Assessing Economic Impacts on Small Entities

The first step in this assessment was to determine whether the rule will have a significant

impact on a substantial number of small entities (SISNOSE). To make this determination, EPA

used a screening analysis that allows us to indicate whether EPA can certify the rule as not

having a SISNOSE. The elements of this analysis included

 identifying affected sectors and entities,

 selecting and describing the measures and economic impact thresholds used in the

analysis, and

 determining SISNOSE certification category.

5.4.1 Identify Affected Sectors and Entities

For the purposes of assessing the impacts of the rule on small entities, we defined a small

entity as (1) a small business, as defined by SBA’s regulations at 13 CFR Part 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; or (3) a small organization that is any notfor-profit enterprise that is independently owned and operated and is not dominant in its field.
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For the Carbon Dioxide Injection and Geologic Sequestration Reporting Rule, small

entity is defined as a small business as defined by the Small Business Administration’s

regulations at 13 CFR 121.201; according to these size standards, ultimate parent companies

owning oil and gas extraction operations (NAICS 211) are categorized as small if the total

number of employees at the firm is fewer than 500.

The Oil & Gas Journal publishes a list of companies owning active U.S. CO2 ER projects

in 2008 (OGJ, 2008). EPA’s initial review of publicly available sales and employment databases

suggest up to 9 of the 23 companies listed in the OGJ survey have fewer than 500 employees.

5.4.2 Develop Small Entity Economic Impact Measures

The sales test examined the average total annualized mandatory reporting costs per ER

field to a representative measure of revenue. Details are provided in section 5.3.

5.4.3 Results of Screening Analysis

The Regulatory Flexibility Act generally requires an agency to prepare a regulatory

flexibility analysis of any rule subject to notice and comment rulemaking requirements under the

Administrative Procedure Act or any other statute, unless the agency certifies that the rule will

not have a significant economic impact on a substantial number of 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 believes small ER operations will most likely be facilities conducting

CO2 injection (no GS), including Class II ER projects. 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%.

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 is proposing monitoring and reporting requirements that build off of

the UIC program. In addition, EPA is proposing 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.

One public hearing on the proposal was held on April 19, 2010. In addition, EPA has an

open door policy, similar to the outreach conducted during the development of the proposed and
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final Mandatory GHG Reporting Rule. Details of these meetings are available in the docket

(EPA-HQ-OAR-2009-0926).

5.5 Characterization of Benefits of Subpart RR and Subpart UU of the Mandatory

Reporting Rule

EPA examined the potential benefits of the Injection and Geologic Sequestration of

Carbon Dioxide Reporting Rule. EPA’s previous analysis of the GHG reporting rule 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.

A mandatory reporting system will benefit the public by increased transparency of

facility GHG data. Transparent, public data on GHGs allows for accountability of polluters to

the public stakeholders who bear the cost of the pollution. Citizens, community groups, and

labor unions have made use of data from Pollutant Release and Transfer Registers to negotiate

directly with polluters to lower emissions, circumventing greater government regulation.

Publicly available emissions data also will allow individuals to alter their consumption habits

based on the GHG emissions of producers.

The greatest benefit of mandatory reporting of GHGs to government will be realized in

developing future GHG policies. For example, in the EU’s Emissions Trading System, a lack of

accurate monitoring at the facility level before establishing CO2 allowance permits resulted in

allocation of permits for emissions levels an average of 15 percent above actual levels in every

country except the United Kingdom.

Benefits to industry of GHG 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 GHG data, the cost of monitoring should fall and the accuracy

of the accounting should improve. A standardized reporting program will also allow for
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facilities to benchmark themselves against similar facilities to understand better their relative

standing within their industry.
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SECTION 6

STATUTORY AND EXECUTIVE ORDER REVIEWS

This section describes EPA’s compliance with several applicable executive orders and

statutes during the development of the final Injection and Geologic Sequestration of Carbon

Dioxide Reporting Rule.

6.1 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.

In addition, EPA prepared an analysis of the potential costs and benefits associated with

this action. This analysis is contained in. in the Economic Impact Analysis (EPA-HQ-2009-

0926). A copy of the analysis is available in the docket for this action and the analysis is briefly

summarized here. In this report, EPA has identified the regulatory options considered, their

costs, 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, and the

economic impacts and qualitative benefits assessment are reported in Section 5. Overall, EPA

has concluded that the costs of the Injection and Geologic Sequestration of Carbon Dioxide

Reporting Rule are outweighed by the potential benefits of more comprehensive information

about CO2 injection. The total annualized cost of the rule will be approximately $7 million (in

2008$) during the first year of the program and $6.7 million in subsequent years (344,000 of

programmatic costs to the Agency).

6.2 Paperwork Reduction Act

The information collection requirements in the 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 mandatory GHG reporting system:
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 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.

 Balance the rule’s coverage to maximize the amount of emissions reported while

excluding small emitters.

 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.

This information collection is mandatory and will be carried out under CAA Sections

114. Information identified and marked as Confidential Business Information (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.23

The projected cost and hour burden for non-Federal respondents is $7.0 million and 9,416

hours per year. The estimated average burden per response is 56.6 hours; the frequency of

response is annual for all respondents that must comply with the rule’s reporting requirements,

except for electricity-generating units that are already required to report quarterly under 40 CFR

part 75 (acid rain program); and the estimated average number of likely respondents per year is

9. 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). These cost numbers differ from those shown

elsewhere in the EIA for the 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

23 Although CBI determinations are usually made on a case-by-case basis, on July 7, 2010, EPA published a

proposed rule (75 FR 39094) relating to CBI determinations for the data collected under the GHG Reporting

Program (40 CFR part 98).
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and for subsequent years of the rule. Also, the total cost estimate of the rule in the EIA includes

the cost to the Agency to administer the program. In addition, the ICR focuses on respondent

burden, while the EIA for the final rule includes EPA Agency costs. 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 the

final rule.

6.3 Regulatory Flexibility Act

The Regulatory Flexibility Act generally requires an agency to prepare a regulatory

flexibility analysis of any rule subject to notice and comment rulemaking requirements under the

Administrative Procedure Act or any other statute, unless the agency certifies that the rule will

not have a significant economic impact on a substantial number of small entities. Small entities

include small businesses, small governmental jurisdictions, and small not-for-profit enterprises.

The first step in this assessment was to determine whether the rule will have a significant

impact on a substantial number of small entities (SISNOSE). To make this determination, EPA

used a screening analysis that allows us to indicate whether EPA can certify the rule as not

having a SISNOSE. The elements of this analysis included

 identifying affected sectors and entities,

 selecting and describing the measures and economic impact thresholds used in the

analysis, and

 determining SISNOSE certification category.

6.3.1 Identify Affected Sectors and Entities

For the purposes of assessing the impacts of the rule on small entities, we defined a small

entity as (1) a small business, as defined by SBA’s regulations at 13 CFR part 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; or (3) a small organization that is any notfor-profit enterprise that is independently owned and operated and is not dominant in its field.

For the Injection and Geologic Sequestration of Carbon Dioxide Reporting Rule, small

entity is defined as a small business as defined by the Small Business Administration’s

regulations at 13 CFR 121.201; according to these size standards, ultimate parent companies
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owning oil and gas extraction operations (NAICS 211) are categorized as small if the total

number of employees at the firm is fewer than 500.

The Oil & Gas Journal publishes a list of companies owning active U.S. CO2 ER projects

in 2008 (OGJ, 2008). EPA’s initial review of publicly available sales and employment databases

suggest up to 9 of the 23 companies listed in the OGJ survey have fewer than 500 employees.

EPA continues to collect other information about corporate structures of these 9 companies to

assess whether these companies are owned by larger parent companies.

6.3.2 Develop Small Entity Economic Impact Measures

These sales test examined the average total annualized mandatory reporting costs per ER

field to a representative measure of revenue. Details are provided in section 5.3.

6.3.3 Results of Screening Analysis

The Regulatory Flexibility Act generally requires an agency to prepare a regulatory

flexibility analysis of any rule subject to notice and comment rulemaking requirements under the

Administrative Procedure Act or any other statute, unless the agency certifies that the rule will

not have a significant economic impact on a substantial number of 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 believes small ER operations will most likely be facilities conducting

CO2 injection (no GS), including Class II ER projects. As shown in Table 5-7, the average ratio

of annualized reporting program costs to revenues of a typical ER operation likely owned by

model small enterprises was less than 1%.

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 is proposing monitoring and reporting requirements that build off of

the UIC program. In addition, EPA is proposing 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, similar to the

outreach conducted during the development of the proposed and final Mandatory GHG

Reporting Rule. Details of these meetings are available in the docket (EPA-HQ-OAR-2008-

0508).
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6.4 Unfunded Mandates Reform Act

Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), P.L. 104-4, establishes

requirements for federal agencies to assess the effects of their regulatory actions on state, local,

and tribal governments and the private sector. Under Section 202 of the UMRA, EPA generally

must prepare a written statement, including a cost-benefit analysis, for final rules with “federal

mandates” that may result in expenditures to state, local, and tribal governments, in the

aggregate, or to the private sector, of $100 million or more in any one year.

The 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 $7 million (in 2008$) during the first year of the program and $6.7 million in

subsequent years ($344,000 of programmatic costs to the Agency). Thus, the final rule is not

subject to the requirements of sections 202 or 205 of UMRA.

The final rule is also not subject to the requirements of section 203 of UMRA because it

contains no regulatory requirements that might significantly or uniquely affect small

governments. Facilities subject to the 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.

6.5 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 executive order 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.”

The 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 Executive Order 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
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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,

Executive Order 13132 does not apply to the final rule.

In the spirit of Executive Order 13132, and consistent with EPA policy to promote

communications between EPA and State and local governments, EPA specifically solicits

comment on the final action from State and local officials.

6.6 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.”

The final rule is not expected to have tribal implications, as specified in Executive Order

13175. This regulation applies directly to facilities that inject and/or sequester CO2 underground.

Few facilities expected to be affected by the rule are likely to be owned by tribal governments.

Thus, Executive Order 13175 does not apply to the final rule.

Although Executive Order 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. 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 TCR. In addition, EPA prepared a short article on the GHG reporting rule that

appeared on the front page of a tribal newsletter—Tribal Air News—that was distributed to

EPA/Office of Air Quality Planning & Standards’ network of tribal organizations. EPA gave a

presentation on various climate efforts, including the GHG Reporting Program, at the National

Tribal Conference on Environmental Management on June 24-26, 2008. In addition, EPA had

copies of a short information sheet distributed at a meeting of the National Tribal Caucus. See

the “Summary of EPA Outreach Activities for Developing the GHG reporting rule,” in Docket

No. EPA–HQ–OAR–2008–0508–055 for a complete list of tribal contacts. EPA participated in a

conference call with tribal air coordinators in April 2009 and prepared a guidance sheet for tribal
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governments on the proposed GHG reporting rule. It was posted on the GHG Reporting

Program Web site and published in the Tribal Air Newsletter.

6.7 Executive Order 13045: Protection of Children from Environmental Health and

Safety Risks

EPA interprets Executive Order 13045 (62 F.R. 19885, April 23, 1997) as applying only

to those regulatory actions that concern health or safety risks, such that the analysis required

under Section 5-501 of the executive order has the potential to influence the regulation. This

action is not subject to Executive Order 13045 because it does not establish an environmental

standard intended to mitigate health or safety risks.

6.8 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. Therefore, we conclude that this rule is not likely to have any adverse effects

on energy supply, distribution, or use.

6.9 National Technology Transfer Advancement Act

Section 12(d) of the National Technology Transfer and Advancement Act of 1995

(NTTAA), Public Law No. 104-113 (15 U.S.C. 272 note) directs EPA to use voluntary

consensus standards in its regulatory activities unless to do so would be inconsistent with

applicable law or otherwise impractical. Voluntary consensus standards are technical standards

(e.g., materials specifications, test methods, sampling procedures, and business practices) that are

developed or adopted by voluntary consensus standards bodies. NTTAA directs EPA to provide

Congress, through OMB, with explanations when the Agency decides not to use available and

applicable voluntary consensus standards. This rulemaking involves technical standards. EPA

developed no new measuring device standard. Rather we allow the use of an appropriate

standard method published by a consensus-based standards organization if such a method exists;

or an industry standard practice.
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6.10 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 lowincome 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.
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SECTION 7

CONCLUSIONS

EPA is promulgating a regulation to require monitoring and reporting from facilities that

conduct carbon dioxide (CO2) injection and geologic sequestration (GS). This rule does not

require control of greenhouse gases (GHGs), rather it requires only monitoring and reporting of

GHGs.

7.1 Summary of Selected Regulatory Alternative

This rule amends 40 CFR part 98 to add reporting requirements covering facilities that

conduct geologic sequestration (GS) of CO2 (subpart RR) and all other facilities that conduct

injection of CO2 (subpart UU). This data will inform Agency decisions under CAA sections 111

and 112 related to the use of carbon dioxide capture and geologic sequestration (CCS) for

mitigating GHG emissions. In combination with data from subpart PP of the GHG Reporting

Program (suppliers of CO2), data from subpart UU and subpart RR will enable EPA to track the

flow of CO2 across the CCS system. EPA will be able to reconcile subpart UU data on CO2

received with CO2 supply data in order to better understand the quantity of CO2 supply that is

used for underground injection versus the quantity supplied to other end-uses. EPA will be able

to reconcile subpart RR data on CO2 received with CO2 supply data in order to understand the

quantity of CO2 supply that is geologically sequestered.

Subpart RR information will enable EPA to collect data on the amount of CO2 emissions

from facilities conducting GS, if any, and will provide a nationally consistent approach for

quantifying CO2 sequestered. Subpart RR information will also 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. For example, EPA will be able to track whether incentives or

regulations are needed to encourage faster or further GS project development. Furthermore,

where enhanced oil and gas recovery (ER) projects are reporting under subpart RR, EPA will be

able to evaluate ER as a non-emissive end use. Subpart UU information will enable EPA to

track ER operations and GS research and development (R&D) projects over time and to consider

whether incentives or regulations would be effective or are needed for them to transition to

subpart RR.

The rule was proposed by EPA on April 12, 2010. One public hearing was held on April

19, 2010, and the sixty day public comment period ended June 11, 2010. This rule takes into

consideration comments received during the comment period and finalizes the monitoring and
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7-2

reporting requirements for facilities conducting GS and all other facilities conducting CO2

injection.

7.2 Estimated Costs and Impacts of the Mandatory GHG Reporting Program

Under the rule, EPA estimates that 93 facilities would be covered by the rule. The total

annualized costs incurred under the rule by these entities would be approximately $7 million (in

2008$) in the first year and $6.7 million in subsequent years. This includes a public sector

burden estimate of $344,000 for program implementation and verification activities. These costs

are distributed to several economic sectors and represent approximately 0.0001% of 2008 gross

domestic product; overall, EPA does not believe the rule will have a significant macroeconomic

impact on the national economy or on small entities within those sectors.

7.2.1 Alternative Scenarios Considered

7.2.1.1 Facilities Conducting GS (ER opt in) Outcomes

Currently, 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, two additional scenarios of the have been considered to

represent medium and high outcomes. 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).As shown in Tables 5-5, national cost

estimate is $39 million under the medium ER opt in outcome (first year) and $37 million in

subsequent years. As shown in Tables 5-6, national cost estimate is $104 million under the high

ER opt in outcome (first year) and $98 million in subsequent years.

7.2.1.2 Facilities Conducting GS (Commercial Saline) Outcomes

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 (73 FR 43492). 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.
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SECTION 8

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