November 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
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 Drinking Water 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............................................................. 3-2

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

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

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

3.1.6 Subpart RR Recordkeeping...................................................................... 3-4

3.1.7 Subpart RR Administrative Appeals........................................................ 3-4

3.2 Subpart UU .......................................................................................................... 3-5

3.2.1 Subpart UU Source Category Definition ................................................. 3-5

3.2.2 Subpart UU Reporting Threshold ............................................................ 3-5

3.2.3 Subpart UU GHGs to Report ................................................................... 3-5

3.2.4 Subpart UU GHG Calculations and Monitoring...................................... 3-5

3.2.5 Subpart UU Data Reporting..................................................................... 3-6

3.2.6 Subpart UU Recordkeeping ..................................................................... 3-6

3.3 Summary of Major Changes Since Proposal ....................................................... 3-6
Section 4 Engineering Cost Analysis..................................................................................... 4-8

4.1 Introduction.......................................................................................................... 4-8

4.2 Overview of Cost Analysis .................................................................................. 4-8

4.3 Baseline Reporting............................................................................................... 4-8

4.3.1 Introduction.............................................................................................. 4-8

4.3.2 Data Sources ............................................................................................ 4-9

4.3.3 Published Data on CO2 Sequestration Projects...................................... 4-10

4.3.4 Hydrogeologic Settings.......................................................................... 4-12

4.3.5 Formation Capacity................................................................................ 4-15

4.3.6 Geologic Sequestration Rule Activity Baseline..................................... 4-16

4.4 Reporting Costs.................................................................................................. 4-18

4.4.1 Introduction............................................................................................ 4-18

4.4.2 Cost Assumptions and Methodology..................................................... 4-19

4.4.3 Monitoring, Reporting, and Verification (MRV) Plan 

Requirements and Approval Process ..................................................... 4-22

4.5 Monitoring Technologies................................................................................... 4-25

4.5.1 Cost Scenarios........................................................................................ 4-29

4.6 Projecting and Discounting National Costs ....................................................... 4-32

4.7 MRV Plan Development Costs.......................................................................... 4-35

4.8 Annual Report Costs.......................................................................................... 4-38

4.9 Other Recordkeeping and Reporting Costs........................................................ 4-38

4.10 Subpart UU Facility Costs ................................................................................. 4-38

4.11 Summary of Reporting Costs by Facility Type and Subpart ............................. 4-38

4.12 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

ii 
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 ................................................................................ 5-10

5.3.1 Revenue Estimate for a Representative Commercial ER Operation ..... 5-10

5.3.2 Sales Test Results .................................................................................. 5-11

5.4 Assessing Economic Impacts on Small Entities ................................................ 5-11

5.4.1 Identify Affected Sectors and Entities ................................................... 5-11

5.4.2 Develop Small Entity Economic Impact Measures ............................... 5-12

5.4.3 Results of Screening Analysis ............................................................... 5-12

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

Mandatory Reporting Rule ................................................................................ 5-13

5.5.1 Social Cost of Carbon ............................................................................ 5-13

5.5.2 Qualitative Benefits Review .................................................................. 5-14

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 (RFA)........................................................................ 6-3

6.4 Unfunded Mandates Reform Act (UMRA) ......................................................... 6-4

6.5 Executive Order 13132: Federalism .................................................................... 6-4

6.6 Executive Order 13175: Consultation and Coordination with Indian Tribal 

Governments........................................................................................................ 6-5

6.7 Executive Order 13045: Protection of Children from Environmental 

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

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

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

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

6.10 Executive Order 12898: Federal Actions to Address Environmental Justice 

in Minority Populations and Low-Income Populations....................................... 6-7

6.11 Congressional Review Act................................................................................... 6-7

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

7.1 Summary of Selected Regulatory Alternative ..................................................... 7-1

iii 
7.2 Estimated Costs and Impacts of the Mandatory GHG Reporting Program......... 7-1

7.2.1 Alternative Scenarios Considered............................................................ 7-1

Section 8 References.............................................................................................................. 8-1

iv 
LIST OF TABLES 

Table 4-1. Baseline Assumptions: Subpart RR/UU.................................................................. 4-17 

Table 4-2. Pro-forma Project Characteristics............................................................................ 4-20 

Table 4-3. Major Sources of Geologic Sequestration Cost Information .................................. 4-21 

Table 4-4. Unit Cost of Relevant Continuous and Periodic Monitoring Technologies............4-23 

Table 4-5. Unit Cost of Relevant Episodic Monitoring Technologies (That may be employed 

after a subsurface leak is detected)......................................................................... 4-24 

Table 4-6. Assumptions for Application of Technologies by Cost Scenario ...........................4-30 

Table 4-7. Summary of Cost Impacts Per Project: Subpart RR................................................4-33 

Table 4-8. Cost of Developing MRV Plan under Subpart RR: New Project with existing UIC 

Class VI Permit....................................................................................................... 4-36 

Table 4-9. Cost of Developing MRV Plan under Subpart RR: ER Class II Project................4-37 

Table 4-10. Summary of Reporting Costs by Facility Type and Subpart (thousand, 2008$)...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 

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): Assuming All 

Anthropogenic CO2 Projects Opt-in ......................................................................... 5-5 

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

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

v 
vi 

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) ......................................................................................................................... 5-9 

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

(2008)...................................................................................................................... 5-10 

Table 5-9. Sales Tests for Representative Commercial ER Field Operations..........................5-11 
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 34 subparts. For more detailed 

background information on the GHG Reporting Program, see the preamble to the final Part 98 

rule establishing that program (74 FR 56260, October 30, 2009) and the preamble to the Part 98 

rule expanding that program from 30 to 34 subparts (75 FR 39736, July 12, 2010). 

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 Part 98 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 40 CFR part 98, 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 40 CFR part 

98, subpart PP, EPA committed to taking action to collect such data in the near future. 

This final rule amends 40 CFR part 98 to add reporting requirements covering facilities 

that conduct geologic sequestration of CO2 (40 CFR part 98, subpart RR) and all other facilities 

that conduct injection of CO2 (40 CFR part 98, subpart UU).1 GS is the long-term containment 

of a CO2 stream in subsurface geologic formations. This data will, among other things, inform 

Agency decisions under the CAA related to the use of carbon dioxide capture and geologic 

sequestration (CCS) for mitigating GHG emissions. 

 

1

 EPA has moved all definitions, requirements, and procedures for facilities conducting CO2 injection only (which 

both EPA and commenters have referred to as “Tier 1 ” facilities for simplicity) into a new subpart, 40 CFR part 

98, subpart UU, and retained all definitions, requirements, and procedures related to facilities conducting GS 

(which both EPA and commenters have referred to as “Tier 2” facilities for simplicity) in 40 CFR part 98, 

subpart RR. 

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Subpart RR information will enable EPA to monitor the growth and efficacy of GS (and 

therefore CCS) as a GHG mitigation technology over time and to evaluate relevant policy 

options. Furthermore, where enhanced oil and gas recovery (ER) projects are reporting under 40 

CFR part 98, subpart RR, EPA will be able to evaluate ER as a non-emissive end use. Under 40 

CFR part 98, subpart UU, EPA will be able to reconcile information obtained from this rule with 

data obtained from 40 CFR part 98, subpart PP on 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 60-day public comment period ended June 11, 2010. This final rule takes into 

consideration comments received during the comment period and finalizes the monitoring and 

reporting requirements for facilities conducting GS and all other facilities conducting CO2

injection. 

This final rule does not address whether data reported under 40 CFR part 98, subparts RR 

or UU will be released to the public or will be treated as CBI. EPA published a proposed rule on 

confidentiality determination on July 7, 2010 (75 FR 39094) that addressed this issue. In that 

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

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

is in the process of considering these comments. 
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. 

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. 

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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 Part 98 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, manufacturers of emission control or process equipment, or persons 

whom the Administrator believes may have necessary information to monitor and report 

emissions and provide such other information as the Administrator requests for the purposes of 

carrying out any provision of the CAA (except for a provision of title II with respect to motor 

vehicles). EPA may gather information for a variety of purposes, including for the purpose of 

assisting in the development of implementation plans or of emissions standards under CAA 

section 111, determining compliance with implementation plans or such standards, or more 

broadly for “carrying out any provision” of the CAA. 

2.3 Safe Drinking Water 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

(73 FR 43492, July 25, 2008). For a summary of the UIC program and more details on the final 

UIC Class VI rule, please see the UIC Geologic Sequestration of Carbon Dioxide website: 

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

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EPA designed the reporting requirements under 40 CFR part 98, subpart RR with careful 

consideration of UIC requirements, including Class VI, to minimize overlap between the two 

programs. There are two areas of potential overlap. The first overlap is the requirement that 

owners or operators report the quantity of CO2 injected. The UIC Class VI rule requires owners 

or operators to continuously monitor the amount of CO2 injected and submit semi-annual reports 

on the monthly amount injected. The UIC program requires information on the amount injected 

to ensure appropriate CO2 injection operations. Subpart RR requires facilities to collect data on 

the amount injected over a quarter and submit annual reports on the annual amount of CO2

injected. Data on the amount of CO2 injected is a component of the 40 CFR part 98, subpart RR 

mass balance approach used to quantify the amount of CO2 sequestered. EPA determined that 

quarterly data collection and annual reporting under 40 CFR part 98, subpart RR was necessary 

in order to harmonize data with other subparts of the GHG Reporting Program. Facilities 

reporting under 40 CFR part 98, subpart RR may use flow meters used to comply with the flow 

monitoring and reporting provisions in their permit. 

The second overlap is a monitoring plan for detecting air emissions. While requirements 

under the UIC program are focused on demonstrating that USDWs are not endangered as a result 

of CO2 injection into the subsurface, requirements under the GHG Reporting Program through 

40 CFR part 98, subpart RR will enable EPA to verify the quantity of CO2 that is geologically 

sequestered and to assess the efficacy of GS as a mitigation strategy. Subpart RR achieves this 

by requiring facilities conducting GS to develop and implement a monitoring, reporting, and 

verification (MRV) plan1 to detect and quantify leakage of injected CO2 to the surface in the 

event leakage occurs and to report the amount of CO2 geologically sequestered using a mass 

balance approach, regardless of the class of UIC permit that a facility holds. 

The monitoring required by 40 CFR part 98, subpart RR for quantification purposes is 

complementary to and builds on UIC permit requirements. In particular, the UIC Class VI 

permit requires a comprehensive site characterization that includes an assessment of the 

geologic, hydrogeologic, geochemical, and geomechanical properties of the proposed GS site to 

ensure that GS wells are located in suitable formations. The UIC Class VI permit also requires 

computational modeling of the Area of Review, and a periodic re-evaluation of this Area of 

Review based on robust modeling and monitoring of the CO2 stream, injection pressures, 

integrity of the injection well, groundwater quality and geochemistry, and the position of the CO2 

 

1

 The subpart RR MRV plan includes delineation of monitoring areas, identification and assessment of potential 

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

approach for establishing the expected baselines, and a summary of considerations for calculating site-specific 

variables for the mass balance equation, such as calculating CO2 in produced fluids. 

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plume and pressure front throughout injection. These requirements can provide the basis for the 

MRV plan submitted to EPA for 40 CFR part 98, subpart RR. Therefore, EPA will accept a UIC 

Class VI permit to satisfy certain MRV plan requirements; however, the reporter must include 

additional information to outline how monitoring will achieve detection and quantification of 

CO2 in the event surface leakage occurs. 

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

of the 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 40 CFR part 98, 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 40 CFR part 98, subpart RR. EPA is committed to working 

closely within the agency to coordinate implementation of the UIC and GHG Reporting 

programs, reduce burden on reporters, provide timely access to verified emissions data, establish 

mechanisms to efficiently share data, and harmonize data systems to the extent possible. 

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 

demonstration projects online by 2016. The CCS Task Force’s plan was delivered to President 

Obama in August 2010. 

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2-5 

The CCS Task Force explored incentives for commercial CCS adoption and addressed 

financial, economic, technological, legal, institutional, social, or other barriers to deployment. 

For example, the CCS Task Force examined Federal regulatory activities that address the safety, 

efficacy, and environmental soundness of GS. The CCS Task Force also considered how best to 

coordinate existing administrative authorities and programs, including those involving 

international collaboration, as well as identified areas where additional administrative authority 

may be necessary. The CCS Task Force recommended that EPA finalize this rule. For more 

information, please see the CCS Task Force website: 

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

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 MRV procedures that are 

being finalized under 40 CFR part 98, subpart RR in this final rule.
SECTION 3

SUMMARY OF FINAL RULE: SUBPART RR AND UU 

Facilities that conduct geologic sequestration are subject to 40 CFR part 98, subpart RR. 

All other facilities that inject CO2 underground are subject to 40 CFR part 98, subpart UU. If 

you report under 40 CFR part 98, subpart RR for a well or group of wells, you are not required to 

report under 40 CFR part 98, subpart UU for that well or group of wells. 

3.1 Subpart RR 

3.1.1 Source Category Definition 

The 40 CFR part 98, subpart RR source category consists of any well or group of wells 

that inject a CO2 stream for long-term containment into a subsurface geologic formation.1 All 

wells permitted as Class VI by the UIC program meet the definition of this source category. 

Facilities conducting ER are not subject to 40 CFR part 98, subpart RR unless they choose to 

opt-in to the requirements of this subpart or hold a UIC Class VI permit. 

R&D projects are exempt from reporting requirements under 40 CFR part 98, subpart RR 

provided they meet the eligibility requirements. A project is eligible for the exemption if it 

investigates or will investigate practices, monitoring techniques, or injection verification, or if it 

is engaged in other applied research that focuses on enabling safe and effective long-term 

containment of a CO2 stream in subsurface geologic formations, including research and injection 

tests conducted as a precursor to a larger more permanent long-term storage operation. Small 

and large-scale projects meeting the criteria for an exemption, such as the current Regional 

Carbon Sequestration Partnership projects supported by the Office of Fossil Energy at the 

Department of Energy (DOE), would be considered R&D for the purposes of this exemption 

from reporting for the duration of the R&D activity. Other DOE supported GS R&D projects 

may also satisfy the eligibility requirements for the exemption. In addition, short duration CO2

injection projects conducted to identify local amenability to long term storage will be exempted 

from 40 CFR part 98, subpart RR for the duration of such injection testing. This includes cases 

where an operator is using a short duration CO2 injection test to assess local geologic conditions 

and validate the injectivity potential of a particular site prior to developing that site for 

commercial scale geologic storage of carbon dioxide. Demonstration projects can apply for the 

 

1

 Note that R&D projects that are exempted from subpart RR report under Subpart UU – see discussion below. 

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exemption, but will be measured against the same criteria established in 40 CFR 98.440(d). 

Projects that are not R&D projects, such as commercial GS operations, are not eligible for the 

exemption.

To receive an R&D exemption, the project representative must submit to the 

Administrator information on the planned duration of CO2 injection for research, the planned 

annual CO2 injection volumes during this time period, the purposes of the project, the source and 

type of funding for the project, and the class and duration of UIC permit, or, for an offshore 

facility not subject to SDWA, a description of the legal instrument authorizing GS. 

The Administrator will determine if a project meets the definition of research and 

development project within 60 days of receipt of the submission of a request for exemption. In 

making this determination, the Administrator will take into account any information that the 

reporter submits demonstrating that the planned duration of CO2 injection for the project and the 

planned annual CO2 injection volumes during the duration of the project are consistent with the 

purpose of the research and development project. This rule allows for administrative appeals of 

the Administrator’s R&D determination, as provided for in 40 CFR part 78. 

Facilities that qualify for a GS R&D exemption from 40 CFR part 98, subpart RR are not 

exempted from any other source category of the GHG Reporting Program including 40 CFR part 

98, subpart UU. For other source categories of the GHG Reporting Program, R&D is defined at 

40 CFR 98.6. 

3.1.2 Subpart RR Reporting Threshold 

All facilities that meet the 40 CFR part 98, subpart RR source category definition must report 

(i.e., there is no reporting threshold). However, reporters that receive a subpart RR R&D 

exemption are no longer subject to subpart RR, but rather report CO2 received under subpart UU. 

The cease reporting provisions of §98.2(i) do not apply to subpart RR. Rather, once a facility is 

subject to the requirements of this subpart, including facilities that opt-in to 40 CFR part 98, 

subpart RR, the owner or operator must continue for each year thereafter to comply with all 

requirements of this subpart, including the requirement to submit annual GHG reports, until the 

Administrator has issued a final decision on an owner or operator’s request to discontinue 

reporting. The request to discontinue reporting must include either a copy of the applicable UIC 

program Director’s authorization of site closure, or a demonstration that the injected CO2 stream 

is not expected to migrate in a manner likely to result in surface leakage. Before the reporter can 

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discontinue reporting, but after injection has ceased, EPA expects that in most cases there will be 

minimal burden in monitoring and reporting unless a surface leak is detected. 

3.1.3 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 (i.e., mixed with produced oil, gas, or other fluids); 

the mass of CO2 emitted from surface leakage; the mass of CO2 equipment leaks and vented CO2 

emissions from sources between the injection flow meter and the injection wellhead or between 

the production flow meter and the production wellhead; and the mass of CO2 sequestered in 

subsurface geologic formations (this is calculated from the other quantities). 

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 specified in the EPA-approved MRV plan, facilities must also 

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

facilities must calculate the annual mass of CO2 injected. From the annual mass of CO2 injected, 

facilities must subtract the mass of CO2 emitted from surface leakage, using the site-specific 

procedures in their MRV plan, and the mass of CO2 emitted as equipment leaks or vented 

emissions from applicable surface equipment, using the procedures specified in 40 CFR part 98, 

Subpart W of the GHG Reporting Program. All GS projects with equipment leak or vented 

emissions from surface equipment applicable to the GS mass balance equation should use the 

procedures specified in subpart W, regardless of whether such projects are associated with the oil 

and gas industry. Facilities that are producing, oil, gas, or other fluids must additionally subtract 

the mass of CO2 produced. Calculation procedures are provided at 40 CFR 98.443. 

3.1.5 Subpart RR Data Reporting 

In addition to the information summarized at “Subpart RR GHGs to Report” in this 

section of the preamble, facilities must report the source of the CO2 received and the cumulative 

amount of CO2 geologically sequestered since the facility first reported under subpart RR. All 

facilities must also report concentration, facilities using mass flow meters must report mass flow 

information, facilities using volumetric flow meters must report volumetric flow information, 

and facilities using containers must measure the mass or volume of the containers. They are 

required to report a description of the monitoring program that was implemented, including 

3-3 
descriptions of monitoring anomalies and surface leakage, if any. Finally, for EPA verification 

purposes, they are required to report for each injection well the class of UIC permit and well 

identification number used for the UIC permit. 

Subpart RR requires reporting of CO2 equipment leaks and vented CO2 emissions to the 

extent they are a component of the GS mass balance. Subpart RR does not require reporting of 

CO2 equipment leaks and vented CO2 emissions from all surface equipment located within the 

facility (e.g., operational emissions not related to the CO2 being injected) ; however, GS projects 

that produce oil or natural gas may be required to report CO2 equipment leaks and vented CO2

emissions in the petroleum and natural gas system subpart, 40 CFR part 98, subpart W as part of 

either offshore or onshore petroleum and natural gas production. 

 

3.1.6 Subpart RR Recordkeeping 

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

CO2 emitted by surface leakage; CO2 emitted as equipment leaks and vented emissions from 

equipment located on the surface between the flow meter used to measure the injection quantity 

and the injection wellhead and between the flow meter used to measure the production quantity 

and the production wellhead; and any other records as outlined for retention in the facility MRV 

plan for 3 years per 40 CFR 98.3(g). 

3.1.7 Subpart RR Administrative Appeals 

Under this final rule, final decisions of the Administrator under part 98, subpart RR are 

appealable to EPA’s Environmental Appeals Board under the regulations that are set forth in part 

78 (40 CFR part 78). Part 78 is revised to accommodate such appeals. Specifically, the list in 40 

CFR 78.1 of the types of final decisions that can be appealed under 40 CFR part 78 is expanded 

to cover final decisions of the Administrator under 40 CFR part 98, subpart RR. This list 

includes, but is not limited to, the following specific types of decisions under subpart RR, e.g., 

the determination of eligibility for an R&D exemption under 40 CFR 98.440(d)(4), the approval 

or disapproval of a request for discontinuation of reporting under 40 CFR 98.441(b)(2), and the 

approval or disapproval of a MRV plan under 40 CFR 98.448(c). 

Further, 40 CFR 78.3 is revised to allow for petitions for administrative appeal of 

decisions of the Administrator under 40 CFR part 98, subpart RR. Under the general approach in 

the existing part 78, an “interested person” (in addition to the official representative of owners 

and operators involved in a matter) may petition for an administrative appeal of a final decision 

3-4 
of the Administrator. The “interested person” definition, which is located in part 72 of the Acid 

Rain Program regulations, is expanded to take into account final decisions of the Administrator 

under part 98. In particular, EPA is revising the “interested person” definition by replacing 

specific references to the Acid Rain Program and draft permits with broader references to any 

decision by the Administrator and the Administrator’s process of making that decision. As a 

result of this revision and the revisions of 40 CFR part 78, a person who does not own or operate 

a facility covered by a final decision under 40 CFR part 98, subpart RR will need to submit his or 

her name to be included by the Administrator on an “interested persons list” in order to be able to 

appeal -- by filing a petition for an administrative appeal -- that final decision. 

In addition, 40 CFR 78.4 is expanded to state that filings on behalf of owners and 

operators of a facility subject to 40 CFR part 98, subpart RR must be signed by the designated 

representative of the owners and operators. 

3.2 Subpart UU 

3.2.1 Subpart UU Source Category Definition 

The 40 CFR part 98, 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 that are exempted from 40 CFR part 98, subpart RR monitoring 

and reporting requirements. If you report under 40 CFR part 98, subpart RR for a well or group 

of wells, you are not required to report under 40 CFR part 98, subpart UU for that well or group 

of wells. 

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. Reporters can cease subpart 

UU reporting pursuant to the provisions at 40 CFR 98.2(i) that allow facilities to cease GHG 

reporting to EPA; with respect to subpart UU, any reference to CO2 emissions in 40 CFR 98.2(i) 

means CO2 received. 

3.2.3 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 

using the calculation procedures for either mass or volumetric flow meters. Where CO2 is 

3-5 
received in containers, facilities must use the calculation procedures for determining the mass or 

volume of contents in containers. 

3.2.5 Subpart UU Data Reporting 

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

CO2. All facilities must also report concentration, facilities using mass flow meters must report 

mass flow information, facilities using volumetric flow meters must report volumetric flow 

information, and facilities using containers must measure the mass or volume of the containers. 

3.2.6 Subpart UU Recordkeeping 

Facilities must retain quarterly records of any CO2 received for 3 years per 40 CFR 

98.3(g). 

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, 40 CFR part 98, subpart 

UU, and retained all definitions, requirements, and procedures related to facilities 

conducting GS (which both EPA and commenters have referred to as “Tier 2” 

facilities for simplicity) in 40 CFR part 98, subpart RR. 

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

injected in 40 CFR part 98, 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 if known 

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

 In 40 CFR part 98, subpart RR, EPA has established eligibility requirements for a 

GS R&D project to be exempt from 40 CFR part 98, subpart RR. 

 In 40 CFR part 98, subpart RR, EPA has retained the requirement that facilities 

report the equipment leaks and vented emissions reporting requirement for surface 

equipment that could be included in the GS mass balance but removed the 

requirement for reporting equipment leaks and vented emissions for all other 

surface equipment. 

3-6 
3-7 

 In 40 CFR part 98, subpart RR, EPA has added an MRV plan requirement for the 

delineation of the areas that will be monitored. 

 In 40 CFR part 98, subpart RR, EPA has clarified the requirements for an 

addendum to the annual report and renamed it the monitoring report. 

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

for EPA decisions made under 40 CFR part 98, subpart RR, such as decisions 

relating to eligibility for the R&D exemption under 40 CFR 98.440(d)(4), 

decisions relating to a request for discontinuation of reporting under 40 CFR 

98.441(b)(2), or MRV plan decisions under 40 CFR 98.448(c).
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). 

In section 4.10, we summarize the first year and subsequent year costs by facility and 

subpart (Table 4-10) that are used in the economic analysis presented in section 5. 

4.3 Baseline Reporting 

4.3.1 Introduction 

The Environmental Protection Agency developed cost scenarios 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 

4-8 
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. 

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 cost scenarios 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) 

4-9 
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.” 4 

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 

 

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

RL33801, September, 2007. 

4-10 
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 years, 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. 5

 This publication contains maps and data tables documenting their assessment of 

 

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

Technology Laboratory, Morgantown, WV. 

4-11 
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). 6

 It 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 

 

6

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

4-12 
injection is 2,700 tons per day or about one million tons per year. 7

 It is anticipated that about 20 

million tons will eventually be stored. At Sleipner, the plume has been monitored effectively. 8 

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. 9 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 

 

7 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. 8 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. 

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

Bliss, Interstate Oil and Gas Compact Commission, January, 2005.

4-13 
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. 10 Some 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. 11 

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. 12

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. 

 

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

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

11 Oil and Gas Journal, April 17, 2006. 

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

Bliss, Interstate Oil and Gas Compact Commission, January, 2005. 

4-14 
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. 13

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. 14 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. As evaluated by ICF, the DOE Lower-48 total is 8,179 

gigatonnes (Gt) of CO2. The range of uncertainty is 3,508 to 12,850 Gt. Most of the 

 

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

Bliss, Interstate Oil and Gas Compact Commission, January, 2005. 

14 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.

4-15 
assessment is attributed to saline reservoirs). This assessment is much larger than the prior 

assessments also shown on the table. 

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 Tables 4-1. 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. These scenarios were chosen to represent a realistic range of ER projects that 

might opt-in under subpart RR. The lower bound is what one might expect participation to be 

given the lack of comprehensive climate legislation that provides a financial incentive for 

sequestration. The upper bound recognizes the fact that not all ER projects are amenable to 

sequestration due to reservoir depths and other considerations. 

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 

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 

4-16 
4-17 

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. 

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 29 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. 

Table 4-1. Baseline Assumptions: Subpart RR/UU 

Type and 

Subpart 

Reference 

Case 

Metric 

Tons CO2

Received 

per Year 

Assuming All 

Anthropogenic 

Project Opt-in 

Metric Tons 

CO2

Received per 

Year 

Assuming 

All 

Anthropog

enic and 

50 Percent 

of Other 

CO2

Projects 

Opt-in 

Metric Tons 

CO2 Received 

per Year 

R&D (RR) 9a 5,320,000 9 a 5,320,000 9 a 5,320,000 

Facilities 

Conducting GS 

(Saline) (RR) 1 1,842,885 1 1,842,885 1 1,842,885 

Facilities 

Conducting GS 

(ER) (RR) 0 0 16 6,972,040 48 23,543,741 

Facilities 

Conducting 

CO2 Injection 

(No GS) (UU)b 92a 48,735,442b 76 a 41,763,402 44 a 25,191,701 

Total Projects 93c 50,578,327c 93c 50,578,327 93 c 50,578,327 

a

The 9 R&D facilities facilities are assumed to apply for a waiver and incur approximately $4,000 in costs under subpart RR. 

The 9 R&D will subsequently be covered under subpart UU (83 + 9 = 92) and incur the additional $4,000 in costs for subpart 

UU. b

Includes UIC Class II ER facilities. 

cTotals are adjusted to avoid double counting of 9 R&D facilities. See footnote a.
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. 

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 monitoring costs 

are only that which is required under the UIC rules. Then three cost scenarios for reporting from 

4-18 
geologic sequestration sites are evaluated in terms required technologies and practices and their 

costs. 

4.4.2 Cost Assumptions and Methodology 

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.15 

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 

those 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 wells16, and are shown below in Table 4-2. 

 

15 Ground Water Protection Council Meeting, New Orleans, LA, January, 16, 2008. 

16 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) 

4-19 
Table 4-2. Pro-forma Project Characteristics 

Per Project Averages for Economic Analysis

Label 

Monitoring 

Wells/ 

Project 

Monitoring 

Well Depth 

Ft 

Footage all 

monitoring 

wells 

Square 

Miles/ 

Project 

Producing 

Oil or Gas 

Wells/ 

Project 

Project Life 

(for 

annualization) 

Known 

DOE EOR 

Pilot 

Projects 7 5,700 39,900 8.8 56 10 

Known 

DOE Saline 

Pilot 

Projects 2 8,000 16,000 1.7 0 4 

Future DOE 

Saline Pilot 

Projects 2 8,000 16,000 1.7 0 4 

Known 

Commercial 

EOR 

Projects 6 5,700 34,200 8.0 48 10 

Known 

Commercial 

Saline 

Projects 9 8,000 72,000 11.6 0 40 

Conversion 

of Existing 

EOR 

Projects to 

GS 6 5,700 34,200 8.0 48 10 

 

The costs represent price levels in mid 2009, and 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 4-3 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 

4-20 
costs, and pipeline costs. Data are available for both the U.S. and Canada. 17 18 19 20The 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. 

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. 

Table 4-3. Major Sources of Geologic Sequestration Cost Information 

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.

 

17 Joint Association Survey of Drilling Costs, American Petroleum Institute, Washington, DC. 

http://www.api.org/statistics/accessapi/api-reports.cfm

18 PSAC Well Cost Study – 2008, Petroleum Services Association of Canada, October 30, 2007. 

19 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

20 Oil and Gas Journal Pipeline Cost Survey, Oil and Gas Journal Magazine, September 3, 2007.

4-21 
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 4-4 and Table 

4-5. 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. 

4-22 
Table 4-4. 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 per well 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 for plan 

$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. 

4-23 
Table 4-5. 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

4-24 
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. 

4-25 
Seismic Surveys 

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. 

4-26 
Eddy Covariance 

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 

4-27 
well-managed sites. The cost estimates presented here for subsurface leak quantification assume 

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. 

4-28 
4-29 

 

Labor Rates 

The cost of labor for many of the cost items and for General and Administrative Costs are 

based on Society of Petroleum Engineers (SPE) 2008 annual salary survey.21 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 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 cost scenarios (low, medium [or reference], and high) presented in Table 

4-6 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 4-6 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. 22 

21 For SPE survey of petroleum engineers see http://www.spe.org/spesite/spe/spe/career/salary_survey/08SalarySurveyHighlights.pdf 22 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. 
4-30 

Table 4-6. Assumptions for Application of Technologies by Cost Scenario 

Saline, Abandoned Oil & Gas Fields: Starting Point is UIC 

Class VI Requirements 

ER plus GS: Starting P

Requirem

Under UIC 

Class VI 

Lowest Level 

RR 

Alternative 

Middle Level 

RR 

Alternative 

Highest Level 

RR 

Alternative 

Under 

UIC 

Class II 

Lowest Level 

RR 

Alternative 

Mid

Al

Fraction Projects Deep Monitoring 100% 100% 100% 100% 0% 100% 

Wells (into or 

right above 

injection zone) Frequency (months) Continuous Continuous Continuous Continuous Continuous Co

Fraction Projects CO 0% 0% 0% 0% 0% 100% 

2 Flow Meters on Producing Oil 

and Gas Wells Frequency 

(months) Continuous Co

Fraction Projects 0% 0% 0% 0% 0% 0% 

CO2 Flow & Gas 

Composition 

Meters on 

Producing Oil and 

Gas Wells 

Frequency 

(months) Continuous Co

Fraction Projects 

Periodic 100% 100% 100% 100% 100% 100% 

Sampling and 

Testing of 

Injected Fluid Frequency (months) 3 3 3 3 3 3 

Fraction Projects 

Estimation of 0% 0% 100% 100% 0% 0% 

Fugitive Emission 

from Surface 

Facilities Frequency (months) 12 12 12 12 12 12 

Fraction Projects 25% 25% 25% 25% 0% 25% 

Periodic Seismic 

Surveys Frequency 

(months) 60 60 60 60 60 60 

Fraction Projects 0% 0% 50% 50% 0% 0% 

Periodic Digital Color Infrared Orthoimagery 

(CIR) or 

Hyperspectral 

Imaging to detect 

changes to vegetation. 

Frequency 

(months) 12 12 12 12 12 12 
Table 4-6. Assumptions for Application of Technologies by Cost Scenario (continued) 

Saline, Abandoned Oil & Gas Fields: Starting Point is UIC 

Class VI Requirements ER plus GS: Starting Point is UI

Under UIC 

Class VI 

Lowest Level 

RR 

Alternative 

Middle Level 

RR 

Alternative 

Highest 

Level RR 

Alternative 

Under UIC 

Class II 

Lowest Level 

RR 

Alternative 

Mi

A

Fraction Projects 0% 0% 50% 50% 0% 0% 

Periodic mobile 

survey to detect 

surface leaks. 

May be good 

option where 

vegetation is 

sparse. 

Frequency 

(months) 12 12 12 12 12 12 

Fraction Projects 25% 25% 25% 100% 0% 25% 

Eddy covariance measurement from permanent 

towers to detect 

surface leaks. 

Frequency 

(months) Continuous Continuous Continuous Continuous Continuous Continuous C

Fraction Projects 0% 0% 100% 100% 0% 0% 

Soil zone 

monitoring 

(sampling gas 

from 

accumulation 

chambers) 

Frequency 

(months) 12 12 12 3 12 12 

Fraction Projects 0% 0% 100% 100% 0% 0% 

Vadose zone 

monitoring wells 

to sample gas 

above water 

table. 

Frequency 

(months) 12 12 12 3 12 12 

Fraction Projects 0% 0% 100% 100% 0% 0% 

Monitoring wells for samples from 

water table. Frequency 

(months) 12 12 12 3 12 12 

4-31 
4.6 Projecting and Discounting Project Costs 

The cost per project (Table 4-7, below) is computed by applying the unit cost (Table 4-5) 

to the “pro-forma” characteristics assumed for each type of project meeting subpart RR 

requirements (Table 4-2). 

4-32 
Table 4-7. Summary of Cost Impacts Per Project: Subpart RR 

Environmental Baseline Periodic Monitoring 

Capital Costs 

Annualized 

Capital Costs 

Capital 

Cost 

Annual 

Operating 

Cost 

Annualized 

Capital 

and 

Contractor 

Costs 

Annual 

Episodic 

Monitoring 

Costs 

Overhead 

and G&A 

Known DOE 

EOR Pilot 

Projects $ - $0 $ 1,286 $ 1,880 $ 2,063 $0 $ 413 

Known DOE 

Saline Pilot 

Projects $ 7,438 $2,196 $ 3,103,485 $ 162,165 $1,078,401 $0 $ 216,119 

Future DOE 

Saline Pilot 

Projects $ 7,438 $2,196 $ 3,103,485 $ 162,165 $1,078,401 $0 $ 216,119 

Known 

Commercial 

EOR Projects 

Class II $ - $0 $ 1,286 $ 1,880 $ 2,063 $0 $ 413 

Known 

Commercial 

Saline Projects $ 50,750 $3,807 $13,906,005 $ 624,642 $1,667,720 $0 $ 334,305 

Under 

UIC 

Class VI 

or II 

Conversion of 

Existing EOR 

Projects to GS 

Class II $ - $0 $ 1,286 $ 1,880 $ 2,063 $0 $ 413 

Known DOE 

EOR Pilot 

Projects $ 38,500 $5,482 $ 8,407,654 $ 475,253 $1,672,314 $3,108 $ 336,181 

Known DOE 

Saline Pilot 

Projects $ 7,438 $2,196 $ 3,103,485 $ 162,165 $1,078,401 $3,108 $ 216,741 

Future DOE 

Saline Pilot 

Projects $ 7,438 $2,196 $ 3,103,485 $ 162,165 $1,078,401 $3,108 $ 216,741 

Known 

Commercial 

EOR Projects $ 35,000 $4,983 $ 7,215,125 $ 419,491 $1,446,763 $3,108 $ 290,971 

Known 

Commercial 

Saline Projects $ 50,750 $3,807 $13,906,005 $ 624,642 $1,667,720 $3,605 $ 335,026 

Low 

Conversion of 

Existing EOR 

Projects to GS $ 35,000 $4,983 $ 7,215,125 $ 419,491 $1,446,763 $3,108 $ 290,971 

4-33 
4-34 

Table 4-7 (Continued). Summary of Cost Impacts Per Project: Subpart RR 

Environmental Baseline Periodic Monitoring 

Capital Costs 

Annualized 

Capital Costs 

Capital 

Cost 

Annual 

Operating 

Cost 

Annualized 

Capital 

and 

Contractor 

Costs 

Annual 

Episodic 

Monitoring 

Costs 

Overhead 

and G&A 

Known DOE 

EOR Pilot 

Projects $ 84,340 $12,008 $ 9,436,084 $ 534,153 $1,877,639 $3,108 $ 378,551 

Known DOE 

Saline Pilot 

Projects $ 18,310 $5,406 $ 3,306,448 $ 180,151 $1,156,308 $3,108 $ 232,964 

Future DOE 

Saline Pilot 

Projects $ 18,310 $5,406 $ 3,306,448 $ 180,151 $1,156,308 $3,108 $ 232,964 

Known 

Commercial 

EOR Projects $ 76,900 $10,949 $ 8,150,061 $ 473,491 $1,633,877 $3,108 $ 329,587 

Known 

Commercial 

Saline Projects $ 110,380 $8,280 $15,265,951 $ 703,266 $1,848,352 $3,605 $ 372,047 

Reference 

Conversion of 

Existing EOR 

Projects to GS $ 76,900 $10,949 $ 8,150,061 $ 473,491 $1,633,877 $3,108 $ 329,587 

Known DOE EOR Pilot Projects $ 199,840 $28,453 $ 9,697,737 $ 614,673 $1,995,412 $3,108 $ 405,395 Known DOE Saline Pilot Projects $ 40,623 $11,993 $ 3,356,995 $ 195,706 $1,186,786 $3,108 $ 240,377 Future DOE Saline Pilot Projects $ 40,623 $11,993 $ 3,356,995 $ 195,706 $1,186,786 $3,108 $ 240,377 Known Commercial EOR Projects $ 181,900 $25,898 $ 8,387,928 $ 546,691 $1,740,944 $3,108 $ 353,990 Known Commercial Saline Projects $ 262,630 $19,700 $15,610,858 $ 809,406 $1,980,363 $3,605 $ 400,734 

High 

Conversion of Existing EOR Projects to GS $ 181,900 $25,898 $ 8,387,928 $ 546,691 $1,740,944 $3,108 $ 353,990 
4.7 MRV Plan Development 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 CFR 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 4-8 and 4-9.

4-35 
Table 4-8. Cost of Developing MRV Plan under Subpart RR: New Project with existing UIC Class VI Per

Scenario Cost Item 

Cost Algorithm in Hours 

First Year Cost per Instance per Project 

Frequency (every X years for 40-year injection + 50 year monitoring life) 

Subsequent Year Cost per Instance per Project Notes 

New Project with UIC Class VI Permit Evaluate Leakage Pathways 16 $ 1,770 once $ 0 

All raw permit. relative 

New Project with UIC Class VI Permit Delineate Areas of Monitoring 32 $ 3,540 5 $ 708 

ModeliVI, but phase pgenerat

New Project with UIC Class VI Permit 

Develop strategy for leak detection, verification and quantification 160 $ 17,698 once $ 0 

Requiranalysipermit 

New Project with UIC Class VI Permit Establish baseline conditions 16 $ 1,770 once $ 0 

Requirexpectecollecttechno

New Project with UIC Class VI Permit Tailor mass balance equation 8 $ 885 once $ 0 New Project with UIC Class VI Permit Write MRV plan 400 $ 44,246 once $ 0 AssumNew Project with UIC Class VI Permit 

Discuss MRV plan with EPA and edits 100 $ 11,062 once $ 0 

Assumothers degree

New Project with UIC Class VI Permit Annual Report 100 $ 11,062 1 $ 11,062 AssumNew Project with UIC Class VI Permit All Items 832 $ 89,200 $ 11,770 

4-36 
4-37 

Table 4-9. Cost of Developing MRV Plan under Subpart RR: ER Class II Project 

Scenario Cost Item 

Cost Algorithm in Hours 

First Year Cost per Instance per Project 

Frequency (every X years for 10-year injection + 50 year monitoring life) 

Subsequent Year Cost per Instance per Project Notes 

ER Class II Project (no Class VI Permit) Evaluate Leakage Pathways 136 $ 15,044 once $ 0 

All raw data ER project eHowever, cointerpret for 

ER Class II Project (no Class VI Permit) Delineate Areas of Monitoring 756 $ 83,625 5 $ 16,725 

Some modeproject evalumost likely nplan. 

ER Class II Project (no Class VI Permit) 

Develop strategy for leak detection, verification and quantification 160 $ 17,698 once $ 0 

Requires conot expected 

ER Class II Project (no Class VI Permit) Establish baseline conditions 16 $ 1,770 once $ 0 

Requires moexpected to collection cotechnology o

ER Class II Project (no Class VI Permit) Tailor mass balance equation 16 $ 1,770 once $ 0 More complER Class II Project (no Class VI Permit) Write MRV plan 600 $ 66,369 once $ 0 Assume 150 ER Class II Project (no Class VI Permit) Discuss MRV plan with EPA and edits 150 $ 16,592 once $ 0 

Assume mowill have to Assume 25% 

ER Class II Project (no Class VI Permit) Annual Report 100 $ 11,062 1 $ 11,062 Assume 25 pER Class II Project (no Class VI Permit) All Items 1,934 $ 147,030 $ 27,787 
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). 

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 Subpart UU Facility Costs 

Facilities reporting under subpart UU will incur the following costs: 

 Monitoring costs (no GS): $2,256 per year 

 Other recordkeeping costs: $1,700 per year 

 Other reporting costs: $500 per year 

4.11 Summary of Reporting Costs by Facility Type and Subpart 

Table 4-10 presents the costs by facility type and subpart.. The first column reports the 

facility type and associated subpart. The second and third columns report total costs for the first 

year and for subsequent years. The last 4 columns show the range of entity costs under different 

scenarios. These facility costs are used to compute the cost-to-sales ratios presented in section 5. 

Table 4-10. Summary of Reporting Costs by Facility Type and Subpart (thousand, 2008$) 

 Reference Low High 

Type (Subpart) 

First 

Year 

Subsequent 

Years 

First 

Year 

Subsequent 

Years 

First 

Year 

Subsequent 

Years 

R&D (RR)a 

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

GS Facilities (Saline) 

(RR) $318 $240 $96 $18 $490 $413 

GS Facilities (ER opt in) 

(RR) $2,124 $2,005 $1,893 $1,773 $2,271 $2,151 

CO2 Injection Facilities 

(No GS) (UU) $4 $4 $4 $4 $4 $4 a

R&D facilities applying for a waiver will incur the reporting costs under UU ($4 thousand). 

4-38 
4-39 

4.12 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. 
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 

costs23. 

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.24

 

23 See pages 124 and 125 (EPA, 2000). 

24 Subpart RR General TSD (see docket ID No. EPA-HQ-OAR-2009-0926) 

5-1 
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) 

Amount of CO2

Received 

Number of 

Facilities Threshold Level 

(metric tons/yr of 

CO2 received) 

Total National 

(metric tons/yr 

of CO2

received) 

Total 

Number 

of U.S. 

Facilities 

Metric 

tons/yr of 

CO2 

Received 

Percent 

Covered Number Percent Covered 

All In 7,162,885 10 7,162,885 100.00% 10 100.00% 

1,000 7,162,885 10 7,162,885 100.00% 10 100.00% 

10,000 7,162,885 10 7,162,885 100.00% 10 100.00% 

25,000 7,162,885 10 7,162,885 100.00% 10 100.00% 

100,000 7,162,885 10 7,162,885 100.00% 10 100.00% 

Note: Includes the 9 R&D facilities assumed to apply for a R&D waiver. 

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) 

Amount of CO2

Received 

Number of 

Facilities Threshold Level 

(metric tons/yr of 

CO2 received) 

Total National 

(metric tons/yr 

of CO2

received) 

Total 

Number 

of U.S. 

Facilities 

Metric 

tons/yr of 

CO2 

Received 

Percent 

Covered Number Percent Covered 

All In 48,735,442 92 48,735,442 100.00% 92 100.00% 

1,000 48,735,442 92 45,431,115 93.22% 86 93.48% 

10,000 48,735,442 92 45,419,065 93.20% 83 90.22% 

25,000 48,735,442 92 45,325,238 93.00% 77 83.70% 

100,000 48,735,442 92 44,385,039 91.07% 60 65.22% 

Note: Includes the 9 R&D facilities assumed to apply for a R&D waiver and will subsequently be covered under subpart UU. 

5.2 National Cost Estimates 

The total annualized costs incurred under the rule by these entities would be 

approximately $1.1 million (in 2008$) in the first year and $1.0 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 

about $4,000 per year (Table 5-3). 

5-2 
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) 9a 5,320,000 $36 $36

Facilities Conducting GS (Saline) 

(RR) 1 1,842,885 $318 $240

Facilities Conducting GS (ER) 

(RR) 0 0 $0 $0

Facilities Conducting CO2

Injection (No GS) (UU)b 92a 48,735,442 $410 $410

5.3 Private Sector, Total All 

Projects 93c 50,578,327 $764 $686

Private Sector, Average ($/ton) $0.02 $0.01

Public Sector, Total $344 $344

National Total $1,107 $1,030 a

The 9 R&D facilities facilities are assumed to apply for a waiver and incur approximately $4,000 in costs under subpart RR. 

The 9 R&D will subsequently be covered under subpart UU (83 + 9 = 92) and incur the additional $4,000 in costs for subpart 

UU. 

b

Includes UIC Class II ER facilities.

cTotals are adjusted to avoid double counting of 9 R&D facilities. See footnote a. 

. 

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). 

5-3 
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) $36 $36 $36 $36

Facilities Conducting GS (Saline) (RR) $96 $18 $490 $413

Additional Facilities Conducting GS (ER 

opt in) (RR) $0 $0 $0 $0

Facilities Conducting CO2 Injection (No 

GS) (UU) $410 $410 $410 $410

Private Sector, Total All Projects $542 $464 $936 $858

Private Sector, Average ($/ton) $0.01 $0.01 $0.02 $0.02

Public Sector, Total $344 $344 $344 $344

National Total $885 $808 $1,279 $1,202

5.3.1 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 $35 million under the medium ER opt 

in outcome (first year) and $33 million in subsequent years. As shown in Tables 5-6, national 

cost estimate is $103 million under the high ER opt in outcome (first year) and $97 million in 

subsequent years. 

5-4 
Table 5-5. National Annualized Mandatory Reporting Costs Estimates (2008): Assuming 

All Anthropogenic CO2 Projects Opt-in 

 

All Anthropogenic CO2

Projects 

 First Year 

Subsequent 

Years 

Type Number 

Metric 

Tons CO2

Received 

per Year 

thousand, 

2008$ 

thousand, 

2008$ 

R&D (RR) 9a 5,320,000 $36 $36

Facilities Conducting GS (Saline) 

(RR) 

1 1,842,885 $318 $240

Additional Facilities Conducting 

GS (ER opt in) (RR) 

16 6,972,040 $33,988 $32,080

Facilities Conducting CO2

Injection (No GS) (UU)b 76a 41,763,402 $339 $339

Private Sector, Total All Projects 93c 50,578,327 $34,681 $32,695

Private Sector, Average ($/ton) $0.69 $0.65

Public Sector, Total $344 $344

National Total $35,024 $33,039 a

The 9 R&D facilities facilities are assumed to apply for a waiver and incur approximately $4,000 in costs under subpart RR. 

The 9 R&D will subsequently be covered under subpart UU (83 + 9 = 92) and incur the additional $4,000 in costs for subpart 

UU. 

b

Includes UIC Class II ER facilities.

cTotals are adjusted to avoid double counting of 9 R&D facilities. See footnote a. 

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

All Anthropogenic and 50 Percent of Other CO2 Projects Opt-in 

 

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) 9a 5,320,000 $36 $36

Facilities Conducting GS (Saline) 

(RR) 

1 1,842,885 $318 $240

Additional Facilities Conducting 

GS (ER opt in) (RR) 

48 23,543,741 $101,965 $96,241

Facilities Conducting CO2

Injection (No GS) (UU)b 44a 25,191,701 $196 $196

Private Sector, Total All Projects 93c 50,578,327 $102,515 $96,714

Private Sector, Average ($/ton) $2.03 $1.91

Public Sector, Total $344 $344

National Total $102,858 $97,057 a

The 9 R&D facilities facilities are assumed to apply for a waiver and incur approximately $4,000 in costs under subpart RR. 

The 9 R&D will subsequently be covered under subpart UU (83 + 9 = 92) and incur the additional $4,000 in costs for subpart 

UU. 

b

Includes UIC Class II ER facilities.

cTotals are adjusted to avoid double counting of 9 R&D facilities. See footnote a. 

5.3.2 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 

5-6 
(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 

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 $1.6 million under the low outcome; $2.9 million 

under the medium outcome, and $17.2 million under the high outcome. 

5.3.3 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 $346 million using a 3 percent discount rate) and $112 million using a 7 percent 

discount rate. The annualized values are $13.4 million using a 3 percent discount rate and 50 

year period and $8.1 million using a 7 percent discount rate and 50 year period. 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 

5-7 
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. 

5-8 
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 Sites 2.0 9.4 0.5 13.7 0.8 26 

5-9 
Source: Underground Injection Control Program for Carbon Dioxide Geologic Sequestration Wells (UIC Class VI Rule) 

economic analysis (EPA-HQ-OW-2008-0390) 

5.4 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) 

5.4.1 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 5-8. 

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. 

5-10 
5.4.2 Sales Test Results 

As shown in Table 5-9 sales test ratios are between 3.3 to 4.2 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 0.1 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 opt in) (RR) 3.9% 3.7% 3.5% 3.3% 4.2% 4.0% 

Facilities Conducting 

CO2 Injection (No GS) 

(UU) <0.1% <0.1% <0.1% <0.1% <0.1% <0.1% 

5.5 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. 

5.5.1 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 Carbon Dioxide Injection and Geologic Sequestration Reporting Rule, small 

entity is defined as a small business as defined by the Small Business Administration’s 

5-11 
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. 

5.5.2 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. 

5.5.3 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 final rule will not have a significant economic impact on a substantial 

number of small entities, EPA nonetheless took several steps to reduce the impact of this rule on 

small entities. For example, monitoring and reporting requirements are built off of the UIC 

program. In addition, EPA is requiring equipment and methods that may already be in use by a 

facility for compliance with its UIC permit. Also, EPA is requiring annual reporting instead of 

more frequent reporting. 

During rule implementation, EPA will maintain an “open door” policy for stakeholders to 

ask questions about the rule or provide suggestions to EPA about the types of compliance 

assistance that will be useful to small businesses. EPA intends to develop a range of compliance 

assistance tools and materials and conduct extensive outreach for this final rule. 

5-12 
5.6 Characterization of Benefits of Subpart RR and Subpart UU of the Mandatory 

Reporting Rule 

Sequestering CO2 in geologic formations has climate benefits and has been recognized as 

an important climate mitigation technology. The benefits and costs of this rule were considered 

against the backdrop of current regulations, none of which require or provide incentives for 

geologic sequestration. As this final rule does not require owners or operators to undertake 

geologic sequestration, the benefits directly associated with this rule are more appropriately 

related to the reporting of GHG emissions and amounts sequestered. Because quantifying the 

benefits of a policy that monitors but does not reduce GHG emissions would be very difficult, 

the benefits laid out in this chapter are strictly qualitative. EPA evaluated the benefits of a 

reporting system with respect to policy making relevance, transparency issues, and market 

efficiency. The following discussion describes one possible means of quantifying benefits and 

provides an overview of the qualitative benefits evaluated. 

5.6.1 Social Cost of Carbon 

The social cost of carbon (SCC) estimates allow benefits from reduced emissions in any 

future year to be estimated by multiplying the change in emissions in that year by the SCC value 

appropriate for that year. SCC estimates represent the dollar value of a one-ton change in CO2

emissions and reflect underlying assumptions about the growth of emissions and changes in 

socio-economic trajectories. 

In February 2010, an interagency working group published SCC estimates for use in 

regulatory impact analyses of government regulations. The interagency group was composed of 

technical experts from a number of Federal agencies. In developing these estimates, the working 

group considered public comments, explored the technical literature in relevant fields, discussed 

key model inputs and assumptions, and developed estimates of the global benefits of avoiding 

climate change. 

The interagency group selected four CO2 SCC estimates for use in regulatory analyses. 

For 2010, these estimates are $5, $21, $35, and $65 (in 2007 dollars). The first three estimates 

are based on the average SCC across models and socio-economic and emissions scenarios at the 

5, 3, and 2.5 percent discount rates, respectively. The fourth value, which corresponds to the 95th 

percentile SCC estimate at a 3 percent discount rate, represents higher-than-expected impacts 

from temperature change further out in the tails of the SCC distribution. The central value is the 

average SCC across models at the 3 percent discount rate. For purposes of capturing the 

uncertainties involved in regulatory impact analysis, the interagency group emphasized the 

importance and value of considering the full range. These SCC estimates also grow over time. 

5-13 
For instance, the central value increases to $24 per ton of CO2 in 2015 and $26 per ton of CO2 in 

2020. 

There are a few important caveats to consider when evaluating benefits using SCC, which 

are discussed in detail in the Social Cost of Carbon TSD as part of the EPA Light-Duty Vehicle 

Greenhouse Gas Emission Standards and Corporate Average Fuel Economy Standards Final 

Rule.25

1. The integrated assessment models used do not completely capture catastrophic and noncatastrophic impacts. 

2. The integrated assessment models are incomplete in their treatment of adaptation and 

technological change. 

3. There is uncertainty in the extrapolation of damages to high temperatures, and 

assumptions regarding risk aversion. 

Due to the fact that this final rule does not require owners or operators to mitigate climate 

impacts through geologic sequestration of CO2, the benefits associated with geologic 

sequestration may be better ascribed to regulations that require and/or provide incentives for 

geologic sequestration. Based on this analysis and the preceding discussion of caveats, EPA did 

not employ SCC estimates to calculate the benefits of this rule. Instead, as discussed below, EPA 

evaluated the benefits of this rule qualitatively. 

5.6.2 Qualitative Benefits Review 

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. In the case of geologic sequestration, the data 

requirements and transparency of the rule may also serve to broaden public understanding and 

acceptance of the technology as a viable mitigation option. 

 

25 Light-Duty Vehicle Greenhouse Gas Emission Standards and Corporate Average Fuel Economy Standards; Final 

Rule (May 7, 2010) http://epa.gov/otaq/climate/regulations.htm#1-1 

5-14 
5-15 

The greatest benefit of mandatory reporting of GHGs to government will be realized in 

developing future GHG policies. 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 

facilities to benchmark themselves against similar facilities to understand better their relative 

standing within their industry. 
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. 

EPA prepared an analysis of the potential costs and benefits associated with this action in 

the EIA (EPA-HQ-OAR-2009-0926). A copy of the analysis is available in the docket for this 

action and the analysis is briefly summarized here. In the EIA, EPA has identified the regulatory 

options considered, their costs, the emissions that would likely be reported under each option, 

and explained the selection of the option chosen for the rule. The costs of the rule are reported in 

Section 4 of the EIA, and the economic impacts and qualitative benefits assessment are reported 

in Section 5 of the EIA. Overall, EPA has concluded that the costs of the Injection and Geologic 

Sequestration of Carbon Dioxide Reporting Rule are justified by the potential benefits of more 

comprehensive information about CO2 injection. In the absence of new climate policy, the total 

annualized cost of the rule will be approximately $1.1 million (in 2008$) during the first year of 

the program and $1.0 million in subsequent years (including 344,000 of programmatic costs to 

the Agency). 

6.2 Paperwork Reduction Act 

The information collection requirements in this final rule have been submitted for 

approval to the Office of Management and Budget (OMB) under the Paperwork Reduction Act, 

44 U.S.C. 3501 et seq. The Information Collection Request (ICR) document prepared by EPA 

has been assigned EPA ICR number 2372.02. 

EPA has identified the following goals of the GHG reporting system: 

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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. 

 Create reporting requirements that are, to the extent possible and appropriate, 

consistent with existing GHG reporting programs in order to reduce reporting 

burden for all parties involved. 

The information from CO2 injection and geologic sequestration facilities will allow EPA 

to make well-informed decisions about whether and how to use the CAA to regulate these 

facilities and encourage voluntary reductions. Because EPA does not yet know the specific 

policies that will be adopted, the data reported through the mandatory reporting system should be 

of sufficient quality to inform policy and program development. Also, consistent with the 

Appropriations Act, the reporting rule covers a broad range of sectors of the economy including 

sites that inject and store CO2. 

This information collection is mandatory and will be carried out under CAA section 114. 

Information identified and marked as CBI will not be disclosed except in accordance with 

procedures set forth in 40 CFR part 2. However, emissions information collected under CAA 

section 114 generally cannot be claimed as CBI and will be made public.26 

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; 

and the estimated average number of likely respondents per year is 93. The cost burden to 

respondents resulting from the collection of information includes the total capital and start-up 

cost annualized over the equipment’s expected useful life (averaging $717,000 per year) a total 

operation and maintenance component (averaging $5.3 million per year), and a labor cost 

component (averaging $1.0 million per year). 

Burden is defined at 5 CFR part 1320.3(b). Although not included in the primary 

economic analysis, the costs and burdens to the ER opt ins were estimated using an alternate cost 

scenario and in this section EPA is giving its best estimates of likely costs and burdens, including 

to voluntary reporters, as required by the Paperwork Reduction Act. These cost numbers differ 

 

26 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). 

6-2 
from those shown elsewhere in the EIA for this final rule because ICR costs represent the 

average cost over the first three years of the rule, but costs are reported elsewhere in the EIA for 

the first year of the rule and for subsequent years of the rule. Also, the ICR focuses on 

respondent burden only, while the EIA for this final rule includes EPA Agency costs as well. An 

agency may not conduct or sponsor, and a person is not required to respond to, a collection of 

information unless it displays a currently valid OMB control number. The OMB control 

numbers for EPA’s regulations in 40 CFR are listed in 40 CFR part 9. When this ICR is 

approved by OMB, the Agency will publish a technical amendment to 40 CFR part 9 in the 

Federal Register to display the OMB control number for the approved information collection 

requirements contained in this final rule. 

6.3 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. 

This rule will not have a significant economic impact on a substantial number of small 

entities. Currently EPA has determined that small ER operations will most likely be facilities 

conducting CO2 injection only, including UIC Class II ER projects, which are only required to 

report under subpart UU. The average ratio of annualized reporting program costs to revenues of 

a typical ER operation likely owned by representative small enterprises is less than 1 percent. 

Although this final rule will not have a significant economic impact on a substantial 

number of small entities, EPA nonetheless took several steps to reduce the impact of this rule on 

small entities. For example, monitoring and reporting requirements are built off of the UIC 

program. In addition, EPA is requiring equipment and methods that may already be in use by a 

facility for compliance with its UIC permit. Also, EPA is requiring annual reporting instead of 

more frequent reporting. 

6-3 
During rule implementation, EPA will maintain an “open door” policy for stakeholders to 

ask questions about the rule or provide suggestions to EPA about the types of compliance 

assistance that will be useful to small businesses. EPA intends to develop a range of compliance 

assistance tools and materials and conduct extensive outreach for this final rule. 

6.4 Unfunded Mandates Reform Act (UMRA) 

Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), P.L. 104-4, establishes 

requirements for Federal agencies to assess the effects of their regulatory actions on State, local, 

and Tribal governments and the private sector. Under CAA section 202 of the UMRA, EPA 

generally must prepare a written statement, including a cost-benefit analysis, for final rules with 

“Federal mandates” that may result in expenditures to State, local, and Tribal governments, in 

the aggregate, or to the private sector, of $100 million or more in any one year. 

This final rule does not contain a Federal mandate that may result in expenditures of $100 

million or more for State, local, and Tribal governments, in the aggregate, or the private sector in 

any one year. Overall, EPA estimates that the total annualized costs of this final rule are 

approximately $1.1 million (in 2008$) during the first year of the program and $1.0 million in 

subsequent years (including $344,000 of programmatic costs to the Agency). Thus, this final 

rule is not subject to the requirements of CAA sections 202 or 205 of the UMRA. 

This final rule is also not subject to the requirements of CAA section 203 of the UMRA 

because it contains no regulatory requirements that might significantly or uniquely affect small 

governments. Facilities subject to this final rule include facilities that inject CO2 for enhanced 

recovery, and those that sequester CO2. None of the facilities currently known to undertake 

these activities are owned by small governments. 

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 EO to include regulations that have 

“substantial direct effects on the States, on the relationship between the national government and 

the States, or on the distribution of power and responsibilities among the various levels of 

government.” 

This final rule does not have Federalism implications. It will not have substantial direct 

effects on the States, on the relationship between the national government and the States, or on 

6-4 
the distribution of power and responsibilities among the various levels of government, as 

specified in EO 13132. 

This regulation applies to public- or private-sector facilities that inject CO2 underground. 

Few government facilities would be affected. This regulation applies directly to facilities that 

inject CO2 underground. It does not apply to governmental entities unless the government entity 

owns a facility that injects and/or sequesters CO2 underground. This regulation also does not 

limit the power of States or localities to collect GHG data and/or regulate GHG emissions. Thus, 

EO 13132 does not apply to this final rule. However, as it is EPA's policy to promote 

communication between the Agency and State and local governments, EPA specifically solicited 

comments on the proposed rule from State and local officials. 

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.” 

This action does not have Tribal implications, as specified in EO 13175 (65 FR 67249, 

November 9, 2000). This regulation applies directly to facilities that inject and/or sequester CO2

underground. EPA analyzed the facilities expected to be affected by this rule and did not find 

that any facilities expected to be affected by the rule are likely to be owned by tribal 

governments. In addition, EPA did not hear from any Tribal governments contradicting this 

analysis. Thus, EO 13175 does not apply to this final rule. 

Although EO 13175 does not apply to this final rule, EPA sought opportunities to provide 

information to Tribal governments and representatives during development of the GHG reporting 

rule. In consultation with EPA’s American Indian Environment Office, EPA’s outreach plan 

included tribes. EPA conducted several conference calls with Tribal organizations during the 

proposal phase of the GHG reporting rule. For example, EPA staff provided information to 

tribes through conference calls with multiple Tribal working groups and organizations at EPA 

that interact with tribes and through individual calls with two Tribal board members of 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 

6-5 
Environmental Management on June 24-26, 2008. In addition, EPA had copies of a short 

information sheet distributed at a meeting of the National Tribal Caucus. See the “Summary of 

EPA Outreach Activities for Developing the GHG reporting rule,” in Docket No. EPA–HQ–

OAR–2008–0508–055 for a complete list of Tribal contacts. EPA participated in a conference 

call with Tribal air coordinators in April 2009 and prepared a guidance sheet for Tribal 

governments on the proposed GHG reporting rule. It was posted on the GHG Reporting 

Program website and published in the Tribal Air Newsletter. 

6.7 Executive Order 13045: Protection of Children from Environmental Health Risks 

and Safety Risks 

This action is not subject to EO 13045 because it does not establish an environmental 

standard intended to mitigate health or safety risks, and it is not an economically significant 

regulatory action under EO 12866. 

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. Oil and gas operations that use CO2-ER are only required to report under 

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

sequestered. Therefore, we conclude that this rule is not likely to have any adverse effects on 

energy supply, distribution, or use. 

6.9 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 

6-6 
6-7 

standard method published by a consensus-based standards organization if such a method exists; 

or an industry standard practice. 

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 only. 

6.11 Congressional Review Act 

The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the Small Business 

Regulatory Enforcement Fairness Act of 1996, generally provides that before a rule may take 

effect, the agency promulgating the rule must submit a rule report, which includes a copy of the 

rule, to each House of the Congress and to the Comptroller General of the United States. EPA 

will submit a report containing this rule and other required information to the U.S. Senate, the 

U.S. House of Representatives, and the Comptroller General of the U.S. prior to publication of 

the rule in the Federal Register. A major rule cannot take effect until 60 days after it is published 

in the Federal Register. This action is not a “major rule” as defined by 5 U.S.C. 804(2). This 

rule will be effective [INSERT THE DATE 30 DAYS AFTER PUBLICATION OF THIS 

FINAL RULE IN THE FEDERAL REGISTER OR DECEMBER 31, 2010, WHICHEVER IS 

EARLIER]. 
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 final rule amends 40 CFR part 98 to add reporting requirements covering facilities 

that conduct geologic sequestration of CO2 (40 CFR part 98, subpart RR) and all other facilities 

that conduct injection of CO2 (40 CFR part 98, subpart UU).1 GS is the long-term containment 

of a CO2 stream in subsurface geologic formations. This data will, among other things, inform 

Agency decisions under the CAA related to the use of carbon dioxide capture and geologic 

sequestration (CCS) for mitigating GHG emissions. 

Subpart RR information will enable EPA to monitor the growth and efficacy of GS (and 

therefore CCS) as a GHG mitigation technology over time and to evaluate relevant policy 

options. Furthermore, where enhanced oil and gas recovery (ER) projects are reporting under 40 

CFR part 98, subpart RR, EPA will be able to evaluate ER as a non-emissive end use. Under 40 

CFR part 98, subpart UU, EPA will be able to reconcile information obtained from this rule with 

data obtained from 40 CFR part 98, subpart PP on 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 

reporting requirements for facilities conducting GS and all other facilities conducting CO2

injection. 

This final rule does not address whether data reported under 40 CFR part 98, subparts RR 

or UU will be released to the public or will be treated as CBI. EPA published a proposed rule on 

confidentiality determination on July 7, 2010 (75 FR 39094) that addressed this issue. In that 

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

 

1

 EPA has moved all definitions, requirements, and procedures for facilities conducting CO2 injection only (which 

both EPA and commenters have referred to as “Tier 1 ” facilities for simplicity) into a new subpart, 40 CFR part 

98, subpart UU, and retained all definitions, requirements, and procedures related to facilities conducting GS 

(which both EPA and commenters have referred to as “Tier 2” facilities for simplicity) in 40 CFR part 98, 

subpart RR. 

7-1 
7-2 

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 are released. 
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 $1.1 million 

(in 2008$) in the first year and $1.0 million in subsequent years. This includes a public sector 

burden estimate of $344,000 for program implementation and verification activities. These costs 

represent less than 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 $35 million under the medium ER opt in outcome (first year) and $33 million in 

subsequent years. As shown in Tables 5-6, national cost estimate is $103 million under the high 

ER opt in outcome (first year) and $97 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 $1.6 million under the low outcome; $2.9 million 

under the medium outcome, and $17.2 million under the high outcome.

7-1 
SECTION 8

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for Inventory Verification and Carbon Credits,” Society of Petroleum Engineers Paper 

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