### 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 Pr ogram Background............................................... 1-1

1.2 Monitoring and Reporting Requireme nts 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 Federa l GS Initiatives ............................................................ 2-4

2.5 Relationship to Other Geologic Seques tration 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 ....................................................... 3-6Section 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 CO 2 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 F acility 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

ii5.2.3 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 Representati ve 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 Econo mic 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: Regulator y 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 Regul atory Alternative ..................................................... 7-1

iii7.2 Estimated Costs and Impacts of th e Mandatory GHG Reporting Program......... 7-1
7.2.1 Alternative Scenarios Considered............................................................ 7-1

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

ivLIST 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 Geol ogic Sequestration Cost Information

.................................. 4-21

Table 4-4. Unit Cost of Relevant Con tinuous and Periodic Monitoring Technologies ............4-23 Table 4-5. Unit Cost of Relevant Episodic Monitoring Technologies (That ma y be employed
after a subsurface leak is detected) ......................................................................... 4-24 Table 4-6. Assumptions for Applicati on of Technologies by Cost Scenario ...........................4-30 Table 4-7. Summary of Cost Im pacts 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 Repor ting Costs by Facility Type and Subpart (thousand, 2008$) ...4-38 Table 5-1 Geologic Sequestra tion Facilities: Effect of CO 2 Received Threshold on Reported

Amount of CO 2 Received and Number of Facilitie s Required to Report (Subpart RR)

............................................................................................................................... ...5-2 Table 5-2. Facilities Conducting C O 2 Injection: Effect of CO 2 Received Threshold on Reported

Amount of CO 2 Received and Number of Facilitie s Required to Report (Subpart UU)

............................................................................................................................... ...5-2 Table 5-3. National Annualized Mandatory Repor ting Costs Estimates: Subpart RR and Subpart

UU

............................................................................................................................. 5-3

Table 5-4. Annualized Mandato ry Reporting Co sts Estimates (2008$): Subpart RR and Subpart

UU ............................................................................................................................. 5-4 Table 5-5. National Annualized Mandatory Repo rting Costs Estimates (2008): Assum ing All Anthropogenic CO 2 Projects Opt-in ......................................................................... 5-5 Table 5-6. National Annualized Mandatory Repo rting Costs Estimates (2008$): Assum ing All Anthropogenic and 50 Percent of Other CO 2 Projects Opt-in ..................................5-6

vvi Table 5-7. Anticipated Level of U.S GS Activity Developed for the Underground Injection Control Program for Carbon Dioxide Geol ogic Sequestration Wells (UIC Class VI
Rule) ......................................................................................................................... 5-9 Table 5-8. Estimated Annual Revenue for a Repr esentative Commercial ER Field Operation
(2008)

...................................................................................................................... 5-10 Table 5-9. Sales Tests for Represen tative Commercial ER Field Operatio ns ..........................5-11SEC TION 1
INTRODUCTION AND BACKGROUND

1.1 Greenhouse Gas Reporting Program Background
The Greenhouse Gas (GHG) Reporting Program requires reporting of GHG em issions
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 th e regulatory framework for the GHG Reporting Program. The GHG Reporting Program, whic h 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, Oct ober 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 Monito ring and Reporting Requirements fo r Injection and Geologic Sequestration of Carbon Dioxide: Subpart RR and UU
On April 12, 2010, EPA proposed this ru le, 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 (CO 2 ) supplied to the economy. During the public comment period on the Part 98 rule establishing that requi rement, EPA received many comments that CO 2 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, S ubpart 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 requiremen ts covering facilities that conduct geologi c sequestration of CO 2 (40 CFR part 98, subpart RR) and all other facilities that conduct injection of CO 2 (40 CFR part 98, subpart UU). 1 GS is the long-term containment
of a CO 2 stream in subsurface geologic formations. This data will, among other things, inform Agency decisions under the CAA related to th e 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 CO 2 injection only (which both EPA and commenters have referred to as “Tier 1 ” f acilities for simplicity) into a new subpart, 40 CFR part 98, subpart UU, and retained all definitions, requirement s, 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.

1-11-2 Subpart RR information will enable EPA to mo nitor 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) proj ects are reporting under 40 CFR part 98, subpart RR, EPA will be able to eval uate ER as a non-emissive end use. Under 40 CFR part 98, subpart UU, EPA will be able to rec oncile information obtained from this rule with data obtained from 40 CFR part 98, subpart PP on CO 2 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 ende d June 11, 2010. This final rule takes into consideration comments received during the co mment period and finalizes the monitoring and reporting requirements for facilities conducti ng GS and all other facilities conducting CO 2 injection.

This final rule does not address whether da ta 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 addr essed this issue. In that action, EPA proposed which specific data elemen ts 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 cons idering these comments.SECTION 2
REGULA TORY 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 d uplicate 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 U nderground Injection Contro l Class VI rule, and summarize the relationship to the Interagency Ta sk Force on Carbon Capture and Storage and other Federal GS initiatives, as well as the relationship to other ge ologic sequestration
information collection and re porting efforts below.

2.1 EPA’s Overall Rulemaking Approach The GHG Reporting Program provides compre hensive 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 progr am. Because we do not know at this time the specific policies that wi ll be adopted, the data reported to the GHG Reporting Program should be of sufficient qua lity to support a range of approaches.

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

 Obtain data that is of su fficient 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 c onsistent with existing GHG reporting programs by using existing GHG e mission estimation and reporting methodologies to reduce reporti ng burden, where feasible.

This section presents the current regu latory context for Subparts RR and UU and illustrates the anticipated role of the final rule within the framework of the existing mandatory and voluntary programs.

2-12.2 Statutory Au thority
EPA is promulgating this rule under its exis ting CAA authority; speci fically, authorities provided in CAA section 114. As di scussed in detail in Sections I.C and II.Q of the preamble to the Part 98 rule establishing the GHG Repor ting Program (74 FR 56260, October 30, 2009), CAA section 114 provides EPA with broad author ity to require information mandated by this rule, because such data will inform and are releva nt 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 fo r a provision of title II with respect to motor vehicles). EPA may gather information for a va riety of purposes, including for the purpose of assisting in the development of implementati on plans or of emissions standards under CAA section 111, determining compliance with implemen tation 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 coordi nation across EPA offices and regions on GS activities and regulatory development. EPA’s Of fice of Air and Radiation (OAR) and Office of Water (OW) work closely to promote safe a nd effective implementation of GS technologies while ensuring protection of huma n health and the environment. OAR and OW have closely coordinated this rulemaking under CAA author ity and the rulemaking under Safe Drinking Water Act (SDWA) authority establishing Fede ral requirements under the UIC program for
Class VI wells.

EPA’s UIC program was established in the 1970s to preven t endangerment of underground sources of drinking water (USDWs) fr om injection of various fluids, including CO 2 for ER, oil field fluids, water stored for drin king 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 fl uid into USDWs by addressing the potential pathways through which injected fluids can mi grate and potentially endanger USDWs. In 2008, EPA proposed to amend the UIC program to establish a new class of inje ction well — Class VI — to cover the underg round injection of CO 2 for the purpose of GS, or long-term storage of CO 2 (73 FR 43492, July 25, 2008). For a summary of th e UIC program and more details on the final UIC Class VI rule, please see the UIC Geol ogic Sequestration of Ca rbon Dioxide website: http://water.epa.gov/type/groundwat er/uic/wells_sequestration.cfm.

2-2EPA designed the reporting requirements unde r 40 CFR part 98, subpart RR with careful consideration of UIC requirem ents, including Cl ass VI, to minimize overlap between the two programs. There are two areas of potential overl ap. The first overlap is the requirement that owners or operators report the quantity of CO 2 injected. The UIC Class VI rule requires owners or operators to continuousl y monitor the amount of CO 2 injected and submit semi-annual reports on the monthly amount injected. The UIC program requires information on the amount injected to ensure appropriate CO 2 injection operations. Subpart RR re quires facilities to collect data on the amount injected over a quarter and subm it annual reports on the annual amount of CO 2 injected. Data on the amount of CO 2 injected is a component of the 40 CFR part 98, subpart RR mass balance approach used to quantify the amount of CO 2 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 subpa rts of the GHG Reporting Program. Facilities reporting under 40 CFR part 98, subpart RR may use fl ow meters used to comply with the flow monitoring and reporting provisi ons in their permit.

The second overlap is a monitoring plan for de tecting air emissions. While requirements under the UIC program are focused on demonstra ting that USDWs are not endangered as a result
of CO 2 injection into the subsurface, require ments under the GHG Reporting Program through 40 CFR part 98, subpart RR will enable EPA to verify the quantity of CO 2 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 impl ement a monitoring, reporting, and verification (MRV) plan 1 to detect and quantify leakage of injected CO 2 to the surface in the event leakage occurs and to report the amount of CO 2 geologically sequestered using a mass balance approach, regardless of the class of UIC perm it 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 require ments. In particular, the UIC Class VI permit requires a comprehensive site characte rization that includes an assessment of the geologic, hydrogeologic, geochemical, and geomechan ical properties of the proposed GS site to
ensure that GS wells are located in suitable fo rmations. The UIC Class VI permit also requires computational modeling of the Area of Review, a nd a periodic re-evaluation of this Area of
Review based on robust modeli ng and monitoring of the CO 2 stream, injection pressures, integrity of the injection well, groundwater quality and geochemistry, and the position of the CO 2

1 The subpart RR MRV plan includes delineation of mon itoring areas, identification and assessment of potential surface leakage pathways, a strategy for de tecting and quantifying surface leakage of CO 2 if leakage occurs, an approach for establishing th e expected baselines, and a summary of co nsiderations for calculating site-specific variables for the mass balance equation, such as calculating CO 2 in produced fluids.

2-3plume and pressure front throughout injection. T h ese requirements can provide the basis for the MRV plan submitted to EPA for 40 CFR part 98, s ubpart RR. Therefore, EPA will accept a UIC Class VI permit to satisfy certain MRV plan re quirements; however, the reporter must include additional information to outline how monitoring will achieve detection and quantification of
CO 2 in the event surface leakage occurs

.

The UIC Class VI rule also allows for surf ace air and soil gas monito ring at the discretion of the Director as a means of identifying CO 2 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 prot ection, 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 pursua nt 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 re quired under SDWA, and requiring reporting of
CO 2 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 harm onize 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 consequen tly estimated incremental costs
associated with surface dete ction and quantif ication of CO 2 . 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 implem entation of the UIC and GHG Re porting programs, reduce burden on reporters, provide timely acce ss to verified emissions data , establish mechanisms to efficiently share data, and harmonize da ta 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 establis hed 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, wi th a goal of bringing fi ve to ten commercial demonstration projects online by 2016. The CCS Ta sk Force’s plan was delivered to President Obama in August 2010.

2-42-5 The CCS Task Force explored incentives fo r commercial CCS adoption and addressed financial, economic, technological, legal, institutional, social, or other barriers to deployment. For example, the CCS Task Force examined Federa l regulatory activities th at address the safety, efficacy, and environmental soundness of GS. The CCS Task Force also considered how best to coordinate existing administra tive authorities and program s, including those involving international collaboration, as well as identified areas where additional administrative authority may be necessary. The CCS Task Force recomme nded 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 Sequestra tion Information Colle ction and Reporting Efforts

EPA reviewed and took into account several existing domestic and in ternational reporting and monitoring programs in designing this rule. For additional information, please see Section I.F of the notice of proposed ru lemaking (75 FR 18581, April 12, 2010).

Also as discussed in the no tice of proposed rulemaking, EP A 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 regard ing eligibility for the Internal Revenue Code section 45Q credit for CO 2 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 guida nce, taxpayers claiming the section 45Q tax credit must follow the appr opriate 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: SU BPART RR AND UU

Facilities that conduct geologic sequestration are subject to 40 CFR part 98, subpart RR. All other facilities that inject CO 2 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 Subpar t 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 CO 2 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 subpar t or hold a UIC Class VI permit. R&D projects are exempt from reporting re quirements 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 re search that focuses on enabling safe and effective long-term

containment of a CO 2 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 meeti ng the criteria for an exemption, such as the current Regional Carbon Sequestration Partnership projects suppo rted by the Office of Fossil Energy at the Department of Energy (DOE), would be consid ered R&D for the purposes of this exemption from reporting for the duration of the R&D ac tivity. Other DOE supporte d GS R&D projects may also satisfy the eligibility requirements for the exemption. In addition, short duration CO 2 injection projects conducted to iden tify local amenability to long term storage will be exempted from 40 CFR part 98, subpart RR for the duration of such injection testing. This includes cases where an operator is using a short duration CO 2 injection test to asse ss local geologic conditions and validate the injectivity potential of a partic ular site prior to de veloping that site for commercial scale geologic storage of carbon dioxid e. Demonstration projects can apply for the

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

3-1exemption, but will b e measured against the sa me criteria established in 40 CFR 98.440(d). Projects that are not R&D projects, such as co mmercial GS operations, are not eligible for the exemption. To receive an R&D exemption, the proj ect representative must submit to the Administrator information on the planned duration of CO 2 injection for research, the planned annual CO2 injection volumes during this time peri od, the purposes of the pr oject, 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 proj ect meets the definition of research and development project within 60 days of receipt of the submission of a request for exemption. In making this determination, the Administrator will take into account any information that the reporter submits demonstrating that the planned duration of CO 2 injection for the project and the planned annual CO 2 injection volumes during th e duration of the project are consistent with the purpose of the research and development project. This rule allows for ad ministrative appeals of the Administrator’s R&D determination, as provided for in 40 CFR part 78.
Facilities that qualify for a GS R&D exem ption 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 m eet the 40 CFR part 98, subpart RR s ource category definition must report (i.e., there is no reporting thre shold). However, reporters that receive a subpart RR R&D exemption are no longer subject to subpart RR, but rather report CO 2 received under subpart UU. The cease reporting provisions of §98.2(i) do not appl y to subpart RR. Rather, once a facility is subject to the requirements of th is 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 re quest to discontinue reporting. The request to disconti nue reporting must include either a copy of the applicable UIC program Director’s authorizati on of site closure, or a dem onstration that the injected CO 2 stream is not expected to migrate in a manner likely to re sult in surface leakage. Before the reporter can

3-2discontinue reporting, bu t after inje ction 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 ca tegory must report the mass of CO 2 received; the mass
of CO 2 injected; the mass of CO 2 produced (i.e., mixed with produced oil, gas, or other fluids);
the mass of CO 2 emitted from surface leakage; the mass of CO 2 equipment leaks and vented CO 2 emissions from sources between the injection fl ow meter and the injection wellhead or between the production flow meter and the pr oduction wellhead; and the mass of CO 2 sequestered in subsurface geologic formations (this is ca lculated 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 CO 2 received. Starting from the date specified in the EPA-approved MRV pla n, facilities must also use a mass balance approach to calculate the mass of CO 2 geologically sequestered. First,
facilities must calculate the annual mass of CO 2 injected. From the annual mass of CO 2 injected,
facilities must subtract the mass of CO 2 emitted from surface leakage, using the site-specific procedures in their MRV plan, and the mass of CO 2 emitted as equipment leaks or vented emissions from applicable surface equipment, us ing the procedures specified in 40 CFR part 98, Subpart W of the GHG Reporting Program. All GS projects with equipment leak or vented emissions from surface equipment applicable to the GS mass balance equation should use the procedures specified in subpart W, regardless of whether such projects are associated with the oil and gas industry. Facilities that are producing, oil, gas, or other fluids must additionally subtract
the mass of CO 2 produced. Calculation procedur es 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 CO 2 received and the cumulative
amount of CO 2 geologically sequestered since the facili ty first reported under subpart RR. All facilities must also report concen tration, facilities using mass flow meters must report mass flow information, facilities using volumetric flow me ters must report volumetric flow information, and facilities using containers must measure th e mass or volume of the containers. They are required to report a description of the mon itoring program that was implemented, including

3-3description s of monitoring anomalies and surface leakage, if any. Finally, for EPA verification purposes, they are required to report for each in jection well the class of UIC permit and well identification number used for the UIC permit.

Subpart RR requires reporting of CO 2 equipment leaks and vented CO 2 emissions to the extent they are a component of the GS mass ba lance. Subpart RR does not require reporting of
CO 2 equipment leaks and vented CO 2 emissions from all surface equipment located within the facility (e.g., operational emi ssions not related to the CO 2 being injected) ; however, GS projects that produce oil or natural gas may be required to report CO 2 equipment leaks and vented CO 2 emissions in the petroleum and natural gas system subpart, 40 CFR part 98, subpart W as part of either offshore or onshore petr oleum and natural gas production.

3.1.6 Subpart RR Recordkeeping

Facilities must retain quarterly records of CO 2 received; injected CO 2 ; produced CO 2 ; CO 2 emitted by surface leakage; CO 2 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 accomm odate such appeals. Specifically, the list in 40 CFR 78.1 of the types of final decisions that can be appealed under 40 CF R part 78 is expanded
to cover final decisions of the Administrato r under 40 CFR part 98, subpart RR. This list includes, but is not limited to, the following specific types of decisi ons 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 fo r 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 “intereste d person” (in addition to the offi cial representative of owners and operators involved in a matter) may petition for an administrative appeal of a final decision

3-4of the Admi nistrator. The “inter ested person” definition, which is located in part 72 of the Acid Rain Program regulations, is expanded to take into account final decision s of the Administrator under part 98. In particular, EPA is revising the “interested person” definition by replacing specific references to the Acid Rain Program an d 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 Ad ministrator on an “inter ested 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 stat e 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 Su bpart 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 CO 2 stream into the subsurface. This incl udes 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 CO 2 underground must report under this subpart, regardless of the amount of emissions from the facility or the amount of CO 2 injected. Reporters can cease subpart UU reporting pursuant to the provisions at 40 CFR 98.2(i) that allow facilities to cease GHG reporting to EPA; with respect to subpart UU, any reference to CO 2 emissions in 40 CFR 98.2(i)
means CO 2 received.

3.2.3 Subpart UU GHGs to Report
Facilities covered by this source cate gory must report the annual mass of CO 2 received.

3.2.4 Subpart UU GHG Calculations and Monitoring
Facilities covered by this source category must calculate the annual mass of CO 2 received using the calculation procedures for either mass or volumetric flow meters. Where CO 2 is

3-5received in containers, facilities must use the calculation pr ocedures for determ ining the mass or
volume of contents in containers.

3.2.5 Subpart UU Data Reporting
In addition to reporting the mass of CO 2 received, facilities must report the source of the
CO 2 . All facilities must also re port concentration, facilities using mass flow meters must report mass flow information, facilities using volumet ric 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 qu arterly records of any CO 2 received for 3 years per 40 CFR 98.3(g).

3.3 Su mmary of Major Changes Since Proposal
The major changes in this rule since the orig inal proposal are identified in the following list. The rationale for these and any other signifi cant 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.”

 EP A has moved all definitions, requirem ents, and procedures for facilities conducting CO 2 injection only (which both EPA and commenters have referred to as “Tier 1” facilities for simplicity) in to a new subpart, 40 CFR part 98, subpart UU, and retained all definitions, requirements, and procedures re lated to facilities conducting GS (which both EPA and comment ers 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 CO 2 injected in 40 CFR part 98, subpart UU (Tier 1) reporting requirements but retained requirements that facilities subj ect to this subpart re port the amount of CO 2 received and the source of CO 2 if known

 EPA has established pro cedures for calculating CO 2 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 reta ined the requiremen t that facilities report the equipment leaks and vented em issions reporting requirement for surface equipment that could be included in the GS mass balance but removed the requirement for reporting equipment leak s and vented emissions for all other surface equipment.

3-63-7  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 incl ude 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).S ECTION 4
ENGINEER ING COST ANALYSIS

4.1 Introd uction
Using available industry and EPA data to ch aracterize conditions at affected sources, EPA estimated the costs of complying with fi nal rule. Incremental m onitoring, recordkeeping, and reporting activities were then identified for each type of fac ility, 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 CO 2 injection activities (G S 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 relate d to the implementation of monitoring activities outlined in the MRV plan for GS sites. All cost s referred to in this section are reported in 2008
dollars.

We first provide a general overview of base line reporting and GS activities. This is followed by detail on the cost components associat ed with this information collection; labor costs (i.e., the cost of labor by facility staff to meet the information co llection requirements of the rule); and capital and opera ting 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 ar e used in the economic analysis presented in section 5.

4.3 Baseline Reporting

4.3 .1 Introduction
The Environmental Protection Agency deve loped cost scenarios for reporting of CO 2 injection and GS. These rules can affect the num ber and type of monito ring equipment installed at the sites and the type and fr equency of tests and surveys conduc ted 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 purpos e of this section is to present the “activity

4-8baseline,” which describes the num ber and types of injection and GS sites that could be subject
to the rule and the volume of CO 2 injections that would be expected.

Through the practice of ge ological sequestration, CO 2 can potentially be sequestered in underground formations worldwide for thousands of years. Although commercial geologic sequestration of CO 2 has not yet begun in the U.S., several pr ojects such as Sleipner in the North Sea, In Salah in Algeria, and Weyburn in Albe rta have achieved success in recent years. CO 2 at these sites is being sequestered, and technologies to monitor the process have proved effective. In the U.S., the Department of Energy is suppor ting approximately 25 sequestration pilot projects around the country. DOE also has plans to start a number of relatively la rge scale pilot projects within coming years.

Geologic sequestration in the U.S. will likel y occur in a range of different geologic settings including: salin e reservoirs, oil and gas reservoirs, coal seams, and others. For purposes of this economic analysis, the costs of specific aspects of geologic seque stration 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 rese rvoir 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 av erage well depth) for e ach type of project, allowing for estimation of total cost per project. In the cost analys is 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 se questration activity to wh ich the final regulation applies. The appropriate forecast for this analys is is the level of GS activity that would be expected even in the absence of future clim ate change legislation. While climate change legislation is currently being de bated in Congress, no legislation has been enacted. Even in the absence of national climate legi slation, sequestration activity in the U.S. is planned including:

 Rese arch and Development (R&D) projects,

 FutureGen Sequestration Site, and

 Commercial Sequestration Pr ojects Related to State and Regional Incentive Programs (in part, funded by DOE)

4-94 .3.3 Published Data on CO 2 Sequestration Projects

4.3.3 .1 Planned R&D Projects
The Department of Energy has funded an ex tensive research effort into geologic sequestration in the U.S. The project is a collabo rative effort with seve n regional partnerships. The research effort is managed by the Nationa l 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 “devel op by 2012 systems that will achieve 90% capture of CO 2 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 resear ch is being carried out by seven regional partnerships. These partnerships were formed in 2003 and represent consorti a of private industry and government agencies. This effort is tasked with determining the most suitable technologies, regulations, and infrastructure n eeds for capture and sequestration.

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

 Charac terization (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 curr ently 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 constr uction and operation of 8 significant sequestration projects. These projects are cons istent with the Energy In dependence and Security Act of 2007 (EISA), under Title VII, Sec. 702, whic h requires DOE to conduct at least 7 large scale sequestration field tests greater than one million tons of CO 2 each. These tests are designed

4 Direct Carbon Sequestration: Capturing and Storing Carbon Dioxide , Congressional Research Service, report RL33801, September, 2007.

4-10to fu lly evaluate the potential for commercial scale operations in a range of geological settings. The tests are planned to have an injection pe riod of up to four years, followed by a lengthy monitoring period. This phase is designed to ev aluate the practical as pects of large scale injection over a prol onged 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 operati ons with injections of up to one million tons

per year.

Sequestration Related to State and Regional In centive Prog rams

A number of states or regions have adopted or plan to adoptregulations to address carbon dioxide and/or greenhouse gas emi ssions. Most allow for regulated sources of emissions to meet compliance requirements through the use of offset s. Although geologic se questration 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 legislati on initiatives are generally in the early stages, and there is considerable uncertainty in term s of which projects will procee d, and on what schedule. ICF has researched the CSLF (Carbon Se questration 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 da te 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 CO 2 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 da ta has also been compiled on the geology of sequestration potential.

In 2008, DOE published the most recent vers ion 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.

4-11sequestration potential in the U.S. Much of the data behi nd 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 num ber 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 w ill focus on the settings that are most likely affected by the rule, which includes sa line 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 reservoi rs. 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. Sa line reservoirs dominate the asse ssed 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 CO 2 sources, minimizing pipeline transport distance. Saline reservoirs represent the vast majority of U.S. sequestration pot ential (approximately 89 percent of total U.S. capacity). 6 It is very likely that saline re servoirs will play a prominent role in future geologic sequestration.

Sequestration in saline reservoirs has been s hown to be effective. The Sleipner field in
the North Sea is the first commercial-scale saline reservoir project. Carb on dioxide is separated from the gas stream and re-injected into a rese rvoir at about 800 meters depth. The rate of

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

4-12injection is 2,700 tons pe r 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 fo r 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 CO 2 sequestration. These represent known structures that have trapped hydrocarbons over geologic time, thus proving the presence of an effective structure and seal abov e the reservoir. These fields have also been extensively studied, there is a la rge amount of well log and other data available, and the field infrastructure is already in place. This infras tructure could in some cases be utilized in sequestration. A potentially probl ematic aspect of using depleted fields for sequestration is the presence of a large number of existing well bores, 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 th e world’s first project in which CO 2 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 fr om 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, CO 2 can be injected into an oil reservoir in a process called miscible CO 2 enhanced oil recovery. The effect of the CO 2 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.

4-13so that it can move m ore readil y to the production wells. As th e oil is produced, part of the injected CO 2 is produced with the oil. This CO 2 is then separated and re-injected.

In the U.S. most CO 2 ER projects are located in the Pe rmian Basin of West Texas, where projects have been in place for severa l decades. The source of most of the CO 2 is natural CO 2 from several fields in Colorado and New Mexico. 10 Some of the injected CO 2 is from gas processing or other sources. The current volume of CO 2 injected for CO 2 ER is about 2.2 billion cubic feet per day.

In 2005, CO 2 ER operations produced approximately 237,000 barrels of oi l per day in the U.S. About 180,000 barrels per day of that occurre d in West Texas, with most of the rest produced in the Rockies, Mid- Continent, and Gulf Coast. 11

The development of CO 2 ER projects has resulted in a gr eat deal of knowledge about the process and injection well and other technologies have mature d and are well understood. In addition, it is estimated that more than 3,500 miles of high pressure (>1,300 psi) CO 2 pipelines have been built to accommodate these operations. 12

At the Weyburn Field in Saskatchewan, CO 2 from the Dakota Gasification Facility in North Dakota is injected into an oil reservoir for ER and monitoring of CO 2 sequestration. Over the 25 year life of this project, it is expected that about 18 million tons of CO 2 will be sequestered.

4.3.4.4 Enhanced Coalbed Methane Recovery

CO 2 can potentially be sequestered in coal beds through the process of adsorption. CO 2 injected as a gas into a coal bed will adsorb onto the molecular structure and be sequestered.

Methane is naturally adsorbed onto coalbe ds and coalbed methane now represents a significant percentage of U.S. natural gas pr oduction. 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 CO 2 Storage , Gemma Heddle, Howard Herzog, and Mich ael 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.

4-14The concept of enhanced coalbed me thane reco very is based upon the fact that coalbeds have a greater affinity for CO 2 than methane. Thus, when CO 2 is injected into the seam, methane
is liberated and the CO 2 is retained. This additional meth ane represents enhanced gas recovery.

Depending upon depth and other factors, coalbe ds may be mineable or unmineable. Because the process of mining the coal would release any stored CO 2 , only unmineable coals are assessed as representing permanent CO 2 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 CO 2 sequestration. The sequestration process is geochemical trapping, in which the CO 2 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 th e foreseeable future due to the unconventional geology and likely difficulty in monitoring.

The potential to sequester CO 2 in organic shale formations is based upon the same concept as that of coal beds. CO 2 will adsorb onto the organic material, displacing methane. Gas shales have recently emerged as a major cu rrent 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 represen t 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. coul d become one of the major areas worldwide for this type of sequestration.

4.3.5 Fo rmation Capacity

4.3.5 .1 Current DOE Assessment of Sequestration Potential
Through the regional sequestration partners hips, 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 CO 2 . 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.

4-15assessment is attribu ted to saline reservoirs). This assessment is much larger than the prior
assessments also shown on the table.

4.3.6 Ge ologic Sequestration Rule Activity Baseline

Based upon the above information on what is anticipated for R&D projects, FutureGen, and state programs, an activity baseline forecas t 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 Ta bles 4-1. The first scenario assumes that no existing CO 2 ER projects choose to report as faci lities conducting GS. The second scenario
assumes that all CO 2 ER projects from anthropogenic sour ces (7 million metric tons per year coming primarily from natural gas processing pl ants) choose to report as facilities conducting GS. The third scenario assumes that all projects from anthropogenic CO 2 sources plus one-half of the remaining CO 2 flood projects choose to report as fa cilities conducting GS. This third scenario adds up to 23.4 million metric tons per year injected of new (i.e., ignoring recycled volumes) CO 2 . These scenarios were chosen to represen t a realistic range of ER projects that might opt-in under subpart RR. The lower bound is wh at one might expect participation to be given the lack of comprehensive climate legisl ation that provides a financial incentive for sequestration. The upper bound recogni zes the fact that not all ER projects are amenable to sequestration due to reservoir de pths and other considerations.

The most comprehensive source of informati on on US ER projects is the annual survey conducted by the Oil and Gas Journal. The 105 pr ojects listed in the Oil and Gas Journal 2007 ER survey were grouped by CO 2 source type – natural or anthropogenic. CO 2 use was allocated to the projects supplied by each source base d on oil production. Anthropogenic sources were well defined for ER projects in Michigan (A ntrim Gas Processing Pl ant), Wyoming/Colorado (LaBarge/Shute Creek Gas Processing Plant), cen tral Oklahoma (Enid Fertilizer Plant) and Kansas (US Energy Partners, Russell Kansas Et hanol Plant) from geographic proximity and information in published literature. Natural CO 2 production from the Jackson Dome in Mississippi was allocated to the 15 projects in Mississippi and Louisi ana based on geographic proximity and information in published literature. Anthropogenic CO 2 from the Val Verde Gas
Plant in Texas is mixed with CO 2 from natural sources and distri buted to several fields in the
Permian Basin so there was not a clear delin eation 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 CO 2 use in the Permian Basin from natu ral sources and Val Verde production

4-164-17 was summed and the percent of Val Verde produc tion was prorated among the 66 projects in the
Permian Basin. Val Verde CO 2 production represents 5.4 % of the total CO 2 used in the Permian Basin, therefore, the equivalent of approximately 4 projects in th e Permian Basin are estimated to use anthropogenic CO 2 from Val Verde. For this analysis 2007 CO 2 production data for natural and anthropogenic sources was taken from th e (1990-2007) Inventory of U.S. Greenhouse Gas Emissions and Sinks, and totaled 2.1 bcf/day wh ich differs from the published DOE estimate of 2.6 bcf/day.

Based on the number of proj ects active in 2007, anthropogenic sources provide approximately 18% of the mass of CO 2 used in ER projects in the US, and represent approximately 27 % of the CO 2 ER projects. These pr ojects result in the additional production of more than 13 million barrels of oil annually. If only ER projects s upplied by anthropogenic sources opted into the reporting program approximately 29 projects would be included. If all the ER projects supplied by anthropogeni c sources, and half of the pr ojects using natural sources opted into the reporting program approximately 67 projects would re port, representing 1.2 bcf/day (23.4 million metric tons per year) or 59% of all CO 2 ER use.

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

Type and Subpart Reference Case Metric Tons CO 2 Received per Year Assuming All Anthropogenic Project Opt-in Metric Tons CO 2 Received per Year Assuming All Anthropog

enic and 50 Percent

of Other

CO 2 Projects Opt-in Metric Tons CO 2 Received per Year R&D (RR) 9 a 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 CO 2 Injection (No GS) (UU) b 92 a 48,735,442 b 76 a 41,763,402 44 a 25,191,701

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

a The 9 R&D facilities facilities are assume d 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 seq uestrati on activity represents our best estimate of what will likely occur in the absence of nationa l climate change legislation. As with any forecast, there are sources of uncertaint y. Categories of uncertainty include:

 Numb er and timing of R&D projects and number of years of injection

 Number and timing of FutureGen project s 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 leas t uncertainty is associated with the R&D projects. These projects have been funded a nd are expected to proc eed at close to the
announced schedule.

The DOE FutureGen project site has been chos en (Illinois) but there is still uncertainty about timing and injection volumes.

Given the number of state and regi onal 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 c limate change legislation. Howeve r, 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 propos al under existing clim ate change policies.

4 .4 Reporting Costs

4

.4.1 Introduction
The purpose of this section is to present th e unit cost estimates for the equipment and services that might be required to co mply with the CO 2 Injection and GS Reporting rule and the
total incremental annual cost of compliance. A base case is cr eated assuming monitoring costs are only that which is required under the UIC rules. Then three cost scenarios for reporting from

4-18geologic sequestration sites are evaluated in terms required tec hnologies 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 co st 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 monitori ng costs were obtained at a recent industry meeting sponsored by the Groundwater Protection Council. 15

The costs reported here include capital and operating and maintena nce (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 pr ojects, saline formation commer cial 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 Ca rbon Dioxide Geologic Se questration Wells, or
the UIC Class VI final rule for CO 2 injection wells 16 , 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 CO 2 for the purposes of GS was proposed July 25, 2008. (73 FR 43492)

4-19Table 4-2. Pro-forma Pr oject 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 equipm ent, materials and labor used in the construction of all types of energy infrastruc ture including power plants, pipe lines and oil and gas wells from 2004 through 2008. With the drop of oil and natu ral gas prices in the Fall of 2008 and the general economic decline around the world the cost s 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

4-20costs, and pi peline costs. Data are available for both the U.S. and Canada. 17 18 19 20 The cost of drilling and equipping wells represen ts a large component of sequestra tion costs. The costs of additional equipment or material specifications for CO 2 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 Associa tion of Petroleum Geologists (AAPG) and the Society of Petroleum Engineers ( SPE). The number of hours requ ired to carry out the various characterization or monitoring ac tivities are estimates that ha ve been reviewed by the EPA workgroup.

Table 4-3. Major Sources of Geolog ic Sequestration Cost Information

Source Cost Categories

A PI 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 Newslette r Onshore rig day rates/ well cost algorithms

FutureGen Sequestration Site Submittals Moni toring 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 Cost s for Geologic Storage of Carbon Dioxide", Sept., 2004 IEA Greenhouse Gas Programme Report PH4/29, "Overview of Moni toring Requirements for Geologic Storage Projects, Nov., 2004. Hoversten, "Investigat ion of Novel Geophysical Techniques for Monitoring CO2 Movement During Sequestration," Oct., 2003. Dahowski, et al, " The Costs of Applying Carbon Dioxide C apture and Geologic Storage Technologies to Two Hypothetical Coal to Liquids Production Configurations: A Preliminary Es timation," Pacific NW National Laboratory, September, 2007.

17 Joint Association Survey of Drilling Costs , American Petroleum Institute, Washington, DC. http://www.api.org/statistic s/accessapi/api-re p orts.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_pub licatio n s/cost_indices_equipment_production/current/costs tudy.html
20 Oil and Gas Journal Pipeline Cost Survey , Oil and Gas Journal Magazine, September 3, 2007.

4-21The assume d 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 f actor of 0.295, 0.142, and 0.075 for projects lasting 4, 10, and 40 years, respec tively. 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 cost s. 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 CO 2 received. These per-ton costs ar e then used to estimate total annual costs for the level of injecti on expected in the activity baseline.

4.4.3 Monitoring, Reporting, and Verificatio n (MRV) Plan Requirements and Approval Process

There are two types of sites th at will report under this rule , facilities that conduct GS (subpart RR) and all othe r facilities conducting CO 2 injection (subpart UU). All sites will incur
costs associated with re porting the annual mass of CO 2 received, however only facilities conducting GS will incur the monitoring plan relate d 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 CO 2 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 CO 2 in the maximum monitoring area and the likelihood, magnitude , and timing, of surface leakage of CO 2 through these pathways.

3. A strategy for detecting and quantifying any surface leakage of CO 2
.
4. A strategy for establishing the expected environmental baselines.

5. A summary of the considerations you intend to use to calculate s ite-specific variables for the mass balance equation.

4-22Table 4-4. Unit Cost of Relevant Continuo us 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

CO 2 Flow Meters on Producing Oil and Gas Wells NA $10,400/ oil well Annual O&M costs are $520 per well per year

CO 2 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.

4-23Table 4-5. Unit Cost of Relevant Episodic Monitoring Technologies (That may be employed a fter 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 squa re mile area in each episode. Project's area is 10 square miles

4-244.5 Moni toring Technologies
Deep Monitoring Wells

Deep monitoring wells are typ ically drilled to monitor the deepest permeable zone above the caprock. Downhole instrumentation can be used to monitor pressure, temperature, and conductivity/salinity. Altern atively, U-tube devices can be used to retrieve pressurized samples for laboratory testing. Other types of monitori ng from wells include micro-seismic, cross-well resistivity, and verti cal seismic profiling.

CO 2 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 ch romatograph to determine percent CO 2 concentration. The
mass of CO 2 passing through the wellhead can then be cal culated from the measured quantities.

CO 2 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
CO 2 passing through the wellhead can then be calc ulated from the measured quantities. This differs from the item directly above in that the chemical compositi on of the gas is being measured automatically by the meter itself rath er through periodically obtaining a sample and sending it to lab for analysis.

Periodic Sampling and Testing of Injected Fluid

All facilities conducti ng GS and all other f acilities conducting CO 2 injection will incur periodic sampling and testing cost s. To estimate the costs, we have applied similar assumptions that were used in Subpart OO for sampling and tes ting of industrial gases. For example, we have
assumed that it takes 12 labor hours to contact an onsite laboratory or o ffsite vendor and develop a plan; to collect and send the sample to an ons ite or offsite laboratory ; and to provide data invoice if sent offsite. Furthermore, we ha ve assumed that it costs approximately $500 per sample to collect and conduct the test of ch emical composition. In a ddition to these costs, facilities conducting GS will ad ditionally incur the costs described in this rule.

4-25Seismic Surveys

Seism ic data acquisition involves the gene ration and detection of sound waves to
evaluation conditions in the subsur face. Periodic acqui sition of seismic data can be used to
detect subsurface CO 2 movement within and outsi de of the reservoir.

Digital Color Infrared Ortho-imagery and Hyper-spectral Imaging

Digital color ortho-imagery and hyper-spectral imaging ar e airborne remote sensing technologies that are used to detect changes in vegetation resulting from CO 2 leaks. Hyperspectral sensors look at objects using electro magnetic spectrum. The object is to detect a specific spectral signature that is known to result from CO 2 uptake. The advantage of these methods is that they can effici ently cover a large surface area.

Airborne or Mobile Remote Sensing Survey

CO 2 detectors are commercially available fo r 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
CO 2 , various types of CO 2 monitors are commercially availa ble and could be used in these applications. Such monitoring techniques are lik ely 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 infrar ed (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 concentr ation, and, when packaged with measurements of wind speed and wind direction, they measure the total gas flow.

LIDAR (Light Detection and Ranging) invol ves the transmission of light from an instrument to a target and the re cording of the reflected light to determine some property of the target. Differential Absorption LIDAR (DIAL) uses two wavelengths of laser to measure CO 2
. The wavelengths used are specific to CO 2 . One wavelength is selected to correspond to a CO 2 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.

4-26Eddy Covariance

Eddy Covariance is a technique whereby high frequency me asurements of atmospheric
CO 2 concentration at a height above the ground are made by an infra-red gas analyzer along with measurements of micro-meteorologi cal variables such as wind ve locity, direction, humidity, and temperature. Integration of these data allows derivation of the net CO 2 flux over the upwind footprint, typically s quare meters to square kilometers in area.

Soil Zone Monitoring with Accumulation Chamber (AC)

Surface CO 2 flux is measured using an accumulation chamber. The chamber is made of stainless steel with an open bottom and is place d at the sampling location. It may be placed either directly on the ground or on a collar installe d 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 in stalled in the zone and samples are taken. The
CO 2 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 meas ure 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 conducti ng 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 suitab le 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 in clude 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 sel ection of sites that are suitable for long-term sequestration and that incidences of leaks to th e surface may be infrequent at well-selected and

4-27well-ma naged sites. The cost estimates presente d here for subsurface leak quantification assume a two percent chance in one year that any gi ven site will have to implement the leak quantification strategy de scribed in the site’s MRV plan. There are no operating statistics for

CO 2 GS from which to draw any citable conclusi ons on how often leaks to the surface may be detected, therefore a very conserva tive 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 cal culations 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 CO 2 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 loca tion of the leak. In other words, different volumes of leaks
would be tested in the reservoi r 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 CO 2 in the gases leaving the chimne y it is possible to measure the
amount of CO 2 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 re presentative sample over the entire area of the leak. It also would be necessary to correct the readings for natural CO 2 fluxes into and out of the
soil.

Many of the leak detection methods for onshor e GS sites can be applied to sub-seabed sites. These include monitoring of the inje ction well and monitoring of the subsurface CO 2 plume: active seismic, passive seismic, sens ors in deep monitoring wells, and reservoir modeling. Though there will be diffe rences in monitoring approaches at sub-seabed GS sites for leak detection and quantifica tion, the cost estimates are a ssumed to be comparable.

4-284-29 Labor Rates

The cost of labor for many of the cost item s and for General and Administrative Costs are based on Society of Petroleum Engin eers (SPE) 2008 annual salary survey. 21 The average salary for a petroleum reservoir engi neer 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 th e cost of goods and services that would be purchased by the entity which owns the facili ty conducting GS. That entity w ould have additional General and Administrative Costs (G&A) on top of those di rect costs for goods and services. These G&A cost are assumed to 20 per cent 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 plac e. Because each faci lity conducting GS will have unique characteristics that may result in the selection of different monitoring techniques, the application of the monitoring devices are in dicated 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 un der 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 a nd 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 Cla ss II requirements were estimat ed for ER proj ects conducting GS and costs incremental to the proposed Class VI re quirements were estimated for all other GS projects.4-30Table 4-6. Assumptions for Application of Technologies by Cost ScenarioSaline, Abandoned Oil & Gas Fields: Starting Point is UICClass VI RequirementsER plus GS: Starting Point is UIC Class IIRequirementsUnder UICClass VILowest LevelRRAlternativeMiddle LevelRRAlternativeHighest LevelRRAlternativeUnderUICClass IILowest LevelRRAlternativeMiddle LevelRRAlternativeHighest LevelRRAlternativeFractionProjects100%100%100%100%0%100%100%100%Deep MonitoringWells (into orright aboveinjection zone)Frequency(months)ContinuousContinuousContinuousContinuousContinuousContinuousContinuousFractionProjects0%0%0%0%0%100%100%100%CO2Flow Meterson Producing Oiland Gas WellsFrequency(months)ContinuousContinuousContinuousFractionProjects0%0%0%0%0%0%0%0%CO2Flow & GasCompositionMeters onProducing Oil andGas WellsFrequency(months)ContinuousContinuousContinuousFractionProjects100%100%100%100%100%100%100%100%PeriodicSampling andTesting ofInjected FluidFrequency(months)33333333FractionProjects0%0%100%100%0%0%0%0%Estimation ofFugitive Emissionfrom SurfaceFacilitiesFrequency(months)1212121212121212FractionProjects25%25%25%25%0%25%25%25%Periodic SeismicSurveysFrequency(months)6060606060606060FractionProjects0%0%50%50%0%0%50%50%Periodic DigitalColor InfraredOrthoimagery(CIR) orHyperspectralImaging to detectchanges tovegetation.Frequency(months)1212121212121212Table 4-6. Assumptions for Application of Technologies by Cost Scenario (continued)Saline, Abandoned Oil & Gas Fields: Starting Point is UICClass VI RequirementsER plus GS: Starting Point is UIC Class II RequirementsUnder UICClass VILowest LevelRRAlternativeMiddle LevelRRAlternativeHighestLevel RRAlternativeUnder UICClass IILowest LevelRRAlternativeMiddle LevelRRAlternativeHighestLevel RRAlternativeFractionProjects0%0%50%50%0%0%50%50%Periodic mobilesurvey to detectsurface leaks.May be goodoption wherevegetation issparse.Frequency(months)1212121212121212FractionProjects25%25%25%100%0%25%25%100%Eddy covariancemeasurementfrom permanenttowers to detectsurface leaks.Frequency(months)ContinuousContinuousContinuousContinuousContinuousContinuousContinuousContinuousFractionProjects0%0%100%100%0%0%100%100%Soil zonemonitoring(sampling gasfromaccumulationchambers)Frequency(months)12121231212123FractionProjects0%0%100%100%0%0%100%100%Vadose zonemonitoring wellsto sample gasabove watertable.Frequency(months)12121231212123FractionProjects0%0%100%100%0%0%100%100%Monitoring wellsfor samples fromwater table.Frequency(months)121212312121234-314.6 Projecting and Discounting Project Costs

The cost per project (Table 4-7, below) is co mp uted by applying the un it cost (Table 4-5) to the “pro-forma” characteristics assumed for each type of project meeting subpart RR requirements (Table 4-2).

4-32Table 4-7. Summary of Cost Impacts Per Project: Subpart RREnvironmental BaselinePeriodic MonitoringCapital CostsAnnualizedCapital CostsCapitalCostAnnualOperatingCostAnnualizedCapitalandContractorCostsAnnualEpisodicMonitoringCostsOverheadand G&ATotalAnnualCostsKnown DOEEOR PilotProjects$ -$0$ 1,286$ 1,880$ 2,063$0$ 413$ 2,476Known DOESaline PilotProjects$ 7,438$2,196$ 3,103,485$ 162,165$1,078,401$0$ 216,119$1,296,716Future DOESaline PilotProjects$ 7,438$2,196$ 3,103,485$ 162,165$1,078,401$0$ 216,119$1,296,716KnownCommercialEOR ProjectsClass II$ -$0$ 1,286$ 1,880$ 2,063$0$ 413$ 2,476KnownCommercialSaline Projects$ 50,750$3,807$13,906,005$ 624,642$1,667,720$0$ 334,305$2,005,832UnderUICClass VIor IIConversion ofExisting EORProjects to GSClass II$ -$0$ 1,286$ 1,880$ 2,063$0$ 413$ 2,476Known DOEEOR PilotProjects$ 38,500$5,482$ 8,407,654$ 475,253$1,672,314$3,108$ 336,181$2,017,083Known DOESaline PilotProjects$ 7,438$2,196$ 3,103,485$ 162,165$1,078,401$3,108$ 216,741$1,300,445Future DOESaline PilotProjects$ 7,438$2,196$ 3,103,485$ 162,165$1,078,401$3,108$ 216,741$1,300,445KnownCommercialEOR Projects$ 35,000$4,983$ 7,215,125$ 419,491$1,446,763$3,108$ 290,971$1,745,824KnownCommercialSaline Projects$ 50,750$3,807$13,906,005$ 624,642$1,667,720$3,605$ 335,026$2,010,158LowConversion ofExisting EORProjects to GS$ 35,000$4,983$ 7,215,125$ 419,491$1,446,763$3,108$ 290,971$1,745,8244-334-34Table 4-7 (Continued). Summary ofCost Impacts Per Project: Subpart RREnvironmental BaselinePeriodic MonitoringCapital CostsAnnualizedCapital CostsCapitalCostAnnualOperatingCostAnnualizedCapitalandContractorCostsAnnualEpisodicMonitoringCostsOverheadand G&ATotalAnnualCostsKnown DOEEOR PilotProjects$ 84,340$12,008$ 9,436,084$ 534,153$1,877,639$3,108$ 378,551$2,271,305Known DOESaline PilotProjects$ 18,310$5,406$ 3,306,448$ 180,151$1,156,308$3,108$ 232,964$1,397,785Future DOESaline PilotProjects$ 18,310$5,406$ 3,306,448$ 180,151$1,156,308$3,108$ 232,964$1,397,785KnownCommercialEOR Projects$ 76,900$10,949$ 8,150,061$ 473,491$1,633,877$3,108$ 329,587$1,977,520KnownCommercialSaline Projects$ 110,380$8,280$15,265,951$ 703,266$1,848,352$3,605$ 372,047$2,232,284ReferenceConversion ofExisting EORProjects to GS$ 76,900$10,949$ 8,150,061$ 473,491$1,633,877$3,108$ 329,587$1,977,520Known DOEEOR PilotProjects$ 199,840$28,453$ 9,697,737$ 614,673$1,995,412$3,108$ 405,395$2,432,367Known DOESaline PilotProjects$ 40,623$11,993$ 3,356,995$ 195,706$1,186,786$3,108$ 240,377$1,442,263Future DOESaline PilotProjects$ 40,623$11,993$ 3,356,995$ 195,706$1,186,786$3,108$ 240,377$1,442,263KnownCommercialEOR Projects$ 181,900$25,898$ 8,387,928$ 546,691$1,740,944$3,108$ 353,990$2,123,940KnownCommercialSaline Projects$ 262,630$19,700$15,610,858$ 809,406$1,980,363$3,605$ 400,734$2,404,401HighConversion ofExisting EORProjects to GS$ 181,900$25,898$ 8,387,928$ 546,691$1,740,944$3,108$ 353,990$2,123,9404.7 MR V Plan Development Costs
Facilities must develop a monitoring, reporti ng, 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 accord ance with procedures in CFR 98.448(a). The MRV plan must include a delineation of the mo nitoring areas; an iden tification of potential surface leakage pathways and a risk assessment of leakage of the CO 2 through these pathways in the monitoring area; a strate gy for detecting and quantifyi ng any surface leakage of CO 2 ; a strategy for establishing the expect ed environmental baselines; and a summary of considerations made to calculate site-specific va riables 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 EP A approval according to section 98.448(g). An addendum describing the monitoring program that was implemented, including descriptions of monitoring anomalies and surface le akage, 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.

4-35Table 4-8. Cost of Developing MRV Plan under Subpart RR: NewProject withexisting UIC Class VI PermitScenarioCost ItemCost Algorithmin HoursFirst Year Costper Instanceper ProjectFrequency(every Xyears for40-yearinjection +50 yearmonitoringlife)Subsequent YearCost per Instanceper ProjectNotesNew Project withUIC Class VIPermitEvaluate Leakage Pathways16$ 1,770once$ 0All raw data should be in UIC Class VIpermit. Time is for re-interpretationrelative to RR regsNew Project withUIC Class VIPermitDelineate Areas of Monitoring32$ 3,5405$ 708Modeling would be done for UIC ClassVI, but needs to be interpreted for freephase plume. Maps need to begeneratedNew Project withUIC Class VIPermitDevelop strategy for leakdetection, verification andquantification160$ 17,698once$ 0Requires considerable statisticalanalysis not expected to be in UICpermitNew Project withUIC Class VIPermitEstablish baseline conditions16$ 1,770once$ 0Requires more statistical analysis thanexpected to be in UIC permit. Datacollection cost are already under eachtechnology option.New Project withUIC Class VIPermitTailor mass balance equation8$ 885once$ 0New Project withUIC Class VIPermitWrite MRV plan400$ 44,246once$ 0Assume 100 pages at 4 hours per pageNew Project withUIC Class VIPermitDiscuss MRV plan with EPAand edits100$ 11,062once$ 0Assume most plans will be OK, butothers will have to be redone to somedegree. Assume 25% of first draft time.New Project withUIC Class VIPermitAnnual Report100$ 11,0621$11,062Assume 25 pages at 4 hours per pageNew Project withUIC Class VIPermitAll Items832$ 89,200$ 11,7704-364-37Table 4-9. Cost of Developing MRV Planunder Subpart RR: ER Class II ProjectScenarioCost ItemCostAlgorithm inHoursFirst YearCost perInstance perProjectFrequency(every Xyears for10-yearinjection +50 yearmonitoringlife)SubsequentYear Cost perInstance perProjectNotesER Class II Project(no Class VI Permit)Evaluate Leakage Pathways136$ 15,044once$ 0All raw data should exist through normalER project evaluation and monitoring.However, considerableeffort needed tointerpret for RR regs.ER Class II Project(no Class VI Permit)Delineate Areas of Monitoring756$ 83,6255$ 16,725Some modeling would be done for ERproject evaluation and monitoring, butmost likely need to be updated for MRVplan.ER Class II Project(no Class VI Permit)Develop strategy for leak detection,verification and quantification160$ 17,698once$ 0Requires considerable statistical analysisnot expected to be in UIC permitER Class II Project(no Class VI Permit)Establish baseline conditions16$ 1,770once$ 0Requires more statistical analysis thanexpected to be in UIC permit. Datacollection cost are already under eachtechnology option.ER Class II Project(no Class VI Permit)Tailor mass balance equation16$1,770once$ 0More complex for ERER Class II Project(no Class VI Permit)Write MRV plan600$ 66,369once$ 0Assume 150 pages at 4 hours per pageER Class II Project(no Class VI Permit)Discuss MRV plan with EPA and edits150$ 16,592once$ 0Assume most plans will be OK, but otherswill have to be redone to some degree.Assume 25% of first draft time.ER Class II Project(no Class VI Permit)Annual Report100$ 11,0621$11,062Assume 25 pages at 4 hours per pageER Class II Project(no Class VIPermit)All Items1,934$ 147,030$ 27,7874.8 Annual Report Costs
As part of the MRV plan, EPA is requiring a nnual reporting. Respondents ar e required to create an annual report each year. Fo r costing purposes, EPA assumed a 25 page report that require 4 labor hours per page (a nnual 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.

4.1 0 Subpart UU Facility Costs
Facilities reporting under subpart UU will incur the following costs:

 Mon itoring 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 firs t column reports the facility type and associated s ubpart. The second and third columns report total costs for the first year and for subsequent years. The last 4 colu mns show the range of entity costs under different scenarios. These facility costs are used to com pute the cost-to-sales ratio s 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 CO 2 Injection Facilities (No GS) (UU) $4 $4 $4 $4 $4 $4

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

4-384-39 4.12 Public Sector Burden
EPA estimates the public sect or burden to be $344,000 per year; $55,000 per year is for verification activities, and remaining costs ar e 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 tool s to assist in determining applicability.SECTION 5
ECONOMIC IMPACT ANALYSI S

EPA prepares an EIA to provide decision make rs with a measure of the social costs of using resources to comply with a progra m (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

costs 23

.
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 th at 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 CO 2 received.

An all-in reporting threshold will allow th e Agency to comprehensively track all CO 2 supply (as reported in Suppliers of CO 2 , 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 CO 2 (subpart PP). It was reasonable to require all of the facilities in these source categories to re port 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 facili ties, ensuring a level playing field in, and preventing fragmentation of, the ER and GS sect ors. Finally, EPA c oncluded that the same approach in both subparts UU and RR maximizes cl arity 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 th e assumptions underlying the threshold analysis, please refer to the general technica l 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)

5-1Table 5-1 Geologic Sequestrati on Facilitie s: Effect of CO 2 Received Threshold on Reported Amount of CO 2 Received and Number of Facilities Required to Report (Subpart RR)

Amount of CO 2 Received Number of Facilities Threshold Level (metric tons/yr of

CO 2 received) Total National (metric tons/yr of CO 2 received) Total Number of U.S. Facilities Metric tons/yr of CO 2 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 CO 2 Injection: Effect of CO 2 Received Threshold on Reported Amount of CO 2 Received and Number of Facilities Required to Report (Subpart UU)

Amount of CO 2 Received Number of Facilities Threshold Level (metric tons/yr of

CO 2 received) Total National (metric tons/yr of CO 2 received) Total Number of U.S. Facilities Metric tons/yr of CO 2 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 en tities would be approximately $1.1 million (in 2008$) in the first y ear and $1.0 million in subsequent years. This includes a public sector burden estim ate of $344,000 for program implementation and verification activities. The typical an nual cost for a facility conducting CO 2 injection (no GS) is about $4,000 per year (Table 5-3).

5-2Table 5-3. National Annualiz ed Mandatory Re porting Costs Estimates: Subpart RR and Subpart UU

Reference

First Year Subsequent Years

Type Number Metric Tons CO 2 Received per Year thousand, 2008$ thousand, 2008$ R&D (RR) 9 a 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 CO 2 Injection (No GS) (UU) b 92 a 48,735,442 $410 $410

5.3 Private Sector, Total All Projects 93 c 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 assume d 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 adop tion and the costs of the reporting program, EPA also considered two other private costs scenarios (one higher a nd one lower than the reference cost scenario) in order to assess a range of economic impacts on affected entities (Table 5-4).

5-3Table 5-4. Annualiz ed 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 CO 2 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 Alterna tive Facilities Conducting GS (ER opt in) Outcomes
Currently, the number of ER operations th at would choose to report as facilities conducting GS (ER opt in) is unknown and EPA coul d not identify any info rmation or analysis to estimate this quantity. As a result, two additi onal scenarios of the have been considered to represent medium and high outcomes. In the medium scenario, all Anthropogenic CO 2 projects (16) choose to report as facilities conducting GS (ER opt in)(Subpart RR). In the high scenario, all Anthropogenic CO 2 projects (16) and fi fty percent of other CO 2 projects (32) choose to report as facilities conducting GS (ER opt in)(Subpart RR).

As shown in Tables 5-5, national cost es timate is $35 million under the medium ER opt in outcome (first year) and $33 million in subseq uent 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.

5-4Table 5-5. National Annualiz ed Mandatory Re porting Costs Estimates (2008): Assuming All Anthropogenic CO 2 Projects Opt-in

All Anthropogenic CO 2 Projects

First Year Subsequent Years

Type Number Metric Tons CO 2 Received per Year thousand, 2008$ thousand, 2008$ R&D (RR) 9 a 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 CO 2 Injection (No GS) (UU) b 76 a 41,763,402 $339 $339
Private Sector, Total All Projects 93 c 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 assume d 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.

5-5Table 5-6. National Annualiz ed Mandatory Re porting Costs Estimates (2008$): Assuming All Anthropogenic and 50 Percent of Other CO 2 Projects Opt-in

All Anthropogenic and 50 Percent of Other CO 2 Projects

First Year Subsequent Years

Type Number Metric Tons CO 2 Received per Year thousand, 2008$ thousand, 2008$ R&D (RR) 9 a 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 CO 2 Injection (No GS) (UU) b 44 a 25,191,701 $196 $196
Private Sector, Total All Projects 93 c 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 assume d 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 widesprea d, cost-effective deploymen t of CCS within ten years, with a goal of bringing 5 to 10 comme rcial 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

com e from power plants with CCS by 2040, ri sing to approximately 59 percent by 2050 (15 percent and 16 percent respectivel y of total electricity generation) (EPA, 2010) . EPA analysis of APA projects deployment of over 30GW of CC S 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 numbe r 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 ru le (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 develope d 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 CO 2 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 tec hnical criteria for the purposes of protecting underground sources of drinking water (USDWs). Additional details about the development of the Geologic Sequestration Rule ba seline 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 incu rred from 2011 to 2060 is estimate to be $346 million using a 3 percent di scount 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 disc ount 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 wa ivered ER refers to the UIC Class VI Rule’s

5-7provision that owners and operato rs ma y apply for and receive a waiver of the requirement to inject below the lowermost underground source of drinking water.

5-8Table 5-7. Anticipated Level of U.S GS Acti vity 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

5-9Source: 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 sa les (i.e., a “sales” test). Given limited data on commercial geological sequestration operations, EPA restricted the analysis to ER operations. ER activities account for approximate ly 90 percent of the project popu lation (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 CO 2 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 reve nue 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 CO 2 and Producing Domestic Crude Oil with Next Generation

CO 2 -ER Technology, accessed October 28, 2009.

5-105.4.2 Sales Test Results

As shown in Table 5-9 sales test ra tios are between 3.3 to 4.2 percent for facilities conducting GS (Subpart RR) . In contrast, faci lities conducting CO 2 injection (no GS, which includes Class II ER operations) sale s test ratios are below 0.1 percent.

Table 5-9. Sales Tests for Representa tive 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 CO 2 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 dete rmine whether the rule will have a significant impact on a substantial number of small entities (SIS NOSE). 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 th e 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 governme nt 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 owne d and operated and is not dominant in its field.

For the Carbon Dioxide Injection and Geol ogic Sequestration Reporting Rule, small entity is defined as a small business as defined by the Small Business Administration’s

5-11regulations 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 lis t of companies owning active U.S. CO 2 ER projects in 2008 (OGJ, 2008). EPA’s initial review of public ly available sales and employment databases suggest up to 9 of the 23 companies listed in th e 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 meas ure of revenue. Details are provided in section 5.3.

5.5.3 Results of Screening Analysis
The Regulatory Flexibility Act generally re quires 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 agen cy 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 opera tions will most likely be facilities conducting
CO 2 injection (no GS), including Class II ER project s. 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 si gnificant economic impact on a substantial number of small entities, EPA nonetheless took seve ral steps to reduc e 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. Al so, 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 sugge stions to EPA about the types of compliance
assistance that will be useful to small businesse s. EPA intends to develop a range of compliance
assistance tools and materials and conduct extensive outreach for this final rule.

5-125.6 Characterization of Benefits of Subpa rt RR and Subpart UU of the Mandatory Reporting Rule
Sequestering CO 2 in geologic formations has climate be nefits and has been recognized as an important climate mitigation technology. The bene fits and costs of this rule were considered against the backdrop of current regulations, none of which requi re or provide incentives for geologic sequestration. As this final rule does not require owne rs or operators to undertake geologic sequestration, the benefits directly associated with this rule are more appropriately related to the reporting of GHG emissions a nd 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 strict ly qualitative. EPA eval uated the benefits of a reporting system with respect to policy making relevance, transparency issues, and market efficiency. The following discus sion describes one possible mean s of quantifying benefits and provides an overview of the qua litative benefits evaluated.

5.6.1 Social Cost of Carbon

The social cost of carbon (SCC) estimates a llow benefits from reduced emissions in any future year to be estimated by multiplying the cha nge 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 CO 2 emissions and reflect underlying assumptions ab out 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 gove rnment regulations. The inte ragency group was composed of technical experts from a number of Federal agen cies. In developing these estimates, the working group considered public comments, e xplored 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 CO 2 SCC estimates for use in regulatory analyses. For 2010, these estimates are $5, $21, $35, and $65 (i n 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. Th e central value is the average SCC across models at the 3 percent discount rate. For purpos es of capturing the uncertainties involved in regul atory impact analysis, the inte ragency group emphasized the importance and value of considering the full rang e. These SCC estimates also grow over time.

5-13For instance, the central value increases to $24 per ton of CO 2 in 2015 and $26 per ton of CO 2 in
2020.

There are a few important caveats to consider when evaluating benef its using SCC, which
are discussed in detail in the So cial Cost of Carbon TSD as part of the EPA Light-Duty Vehicle Greenhouse Gas Emission Standards and Corporat e 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 extrapolati on 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 geologi c sequestration of CO 2 , the benefits associated with geologic sequestration may be better ascrib ed to regulations that require and/or provide incentives for geologic sequestration. Based on th is 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. C itizens, community groups, and
labor unions have made use of data from Polluta nt Release and Transfer Registers to negotiate directly with polluters to lo wer emissions, circumventing gr eater government regulation. Publicly available emissions data also will allo w 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

5-145-15 The greatest benefit of mandatory reporting of GHGs to government will be realized in developing future GHG policies. Benefits to indu stry of GHG monitoring include the value of having independent, verifiable data to present to the public to demonstrate appropriate environmental stewardship, and a better understa nding of their emission levels and sources to identify opportunities to reduce emissions. Such m onitoring allows for incl usion of standardized GHG data into environmental management syst ems, providing the necessary information to
achieve and disseminate their e nvironmental achievements.

Standardization will also be a benefit to indus try, once facilities invest in the institutional knowledge and systems to report GHG data, the co st of monitoring should fall and the accuracy of the accounting should improve. A standard ized reporting program will also allow for facilities to benchmark themselves against simila r facilities to understa nd better their relative standing within their industry.SEC TION 6
STATUTO RY AND EXECUT IVE 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 regulat ory action” because it may raise novel le gal or policy issues arising out of legal mandates, the President’s priorities, or th e principles set forth in the EO. Accordingly,
EPA submitted this action to the Office of Mana gement 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 anal ysis 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 conc luded that the costs of the Injection and Geologic Sequestration of Carbon Dioxide Re porting Rule are justified by th e potential benef its of more comprehensive information about CO 2 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 year s (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 B udget (OMB) under the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. The Information Coll ection Request (ICR) document prepared by EPA has been assigned EPA ICR number 2372.02.

EPA has identified the following go als of the GHG reporting system:

6-1 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.

 Cr eate reporting requirements that are, to the extent possible and appropriate, consistent with existing GHG reporting pr ograms in order to reduce reporting burden for all parties involved.

The information from CO 2 injection and geologic sequest ration facilities will allow EPA
to make well-informed decisions about whethe r and how to use the C AA 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 progr am development. Also, consistent with the Appropriations Act, the reporting rule covers a broad range of sectors of the economy including sites that inject and store CO 2
.
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. Howe ver, 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 co mply with the rule’s reporting requirements; and the estimated average number of likely resp ondents per year is 93. The cost burden to respondents resulting from the collection of info rmation 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 (averagi ng $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 bur dens to the ER opt ins were es timated using an alternate cost scenario and in this section EPA is giving its be st estimates of likely co sts and burdens, including to voluntary reporters, as require d 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).

6-2from those shown elsewhere in the E IA 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 fina l 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 te chnical 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 prep are a regulatory flexibil ity analysis of any rule subject to notice and comment rulemaking requirements under the Administrative Procedure Act or any other statute unless the agency certifie s that the rule will not have a significant economic impact on a substantial number of sm all entities. Small en tities include small businesses, small organizations, a nd small governmental jurisdictions.

For purposes of assessing the impacts of toda y’s rule on small entiti es, 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 jurisdic tion 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 sm all ER operations will most likely be facilities conducting CO 2 injection only, including UIC Class II ER projects, which ar e only required to report under subpart UU. The average ratio of annualized reporting progra m costs to revenues of a typical ER operation likely owned by representativ e small enterprises is less than 1 percent.

Although this final rule will not have a si gnificant economic impact on a substantial number of small entities, EPA nonetheless took seve ral steps to reduc e 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. Al so, EPA is requiring annual reporting instead of more frequent reporting.

6-3During rule imple mentation, EPA will maintain an “open door” policy for stakeholders to ask questions about the rule or provide sugge stions to EPA about the types of compliance
assistance that will be useful to small businesse s. EPA intends to deve lop 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 eff ects of their regulatory actions on State, local, and Tribal governments and the private sect or. Under CAA secti on 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 expenditure s 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 ma ndate that may result in expenditures of $100 million or more for State, local, and Tribal governmen ts, 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 fi rst 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 th e requirements of CAA s ection 203 of the UMRA because it contains no regulatory requirements that might significantly or uniquely affect small governments. Facilities subject to this fi nal rule include faci lities that inject CO 2 for enhanced recovery, and those that sequester CO 2 . 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 ensu re “meaningful and timely input by State and local officials in the development of regulator y policies that have Fe deralism implications.” “Policies that have Federalism implications” is defi ned in the EO to include regulations that have
“substantial direct effects on th e States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among th e various levels of government.”

This final rule does not have Federalism impli cations. It will not ha ve substantial direct effects on the States, on the relationship between the national government and the States, or on

6-4the distribution of power and responsibilities among the various levels of governm ent, as specified in EO 13132.

This regulation applies to public- or private-sector facilities that inject CO 2 underground. Few government facilities would be affected. This regulation applies directly to facilities that inject CO 2 underground. It does not apply to governmental entities unless the government entity owns a facility that injects and/or sequesters CO 2 underground. This regulation also does not limit the power of States or loca lities to collect GHG data and/or regulate GHG emissions. Thus, EO 13132 does not apply to this final rule. Ho wever, as it is EPA's policy to promote communication between the Agency and State an d 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 a nd 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 implica tions, as specified in EO 13175 (65 FR 67249, November 9, 2000). This regulation applies directly to facilities that inj ect and/or sequester CO 2 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 fr om 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 repres entatives during development of the GHG reporting
rule. In consultation with EPA’s American I ndian Environment Office, EPA’s outreach plan
included tribes. EPA conducted several conferen ce 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 a nd organizations at EPA
that interact with tribes and th rough individual calls with two Tribal board me mbers of TCR. In addition, EPA prepared a short article on the GHG re porting rule that appear ed 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 th e GHG Reporting Program, at the National Tribal Conference on

6-5Environmental Managem ent on June 24-26, 2008. In addition, EPA had copies of a short information sheet distributed at a meeting of th e 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 contac ts. EPA participated in a conference call with Tribal air coordinators in April 2009 and prepared a guida nce 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 Ch ildren from Environmental Health Risks and Safety Risks
This action is not subject to EO 13045 becau se 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 “s ignificant energy action” as defined in EO 13211 (66 FR 28355, May 22, 2001) because it is not likely to ha ve a significant adverse effect on the supply, distribution, or use of energy. Furt her, EPA has concluded that this rule is not likely to have any adverse energy effects. This final rule relates to monitori ng, reporting and recordkeeping at facilities that inject and/or sequester CO 2 underground and does not impact energy supply,
distribution or use. Oil a nd gas operations that use CO 2 -ER are only required to report under subpart UU, unless they opt into subpart RR to establish that CO 2 is being geologically sequestered. Therefore, we concl ude that this rule is not likel y to have any adverse effects on energy supply, distribution, or use.

6.9 N ational Technology Transfer and Advancement Act
Section 12(d) of the Nati onal 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 regul atory activities unless to do so would be inconsistent with applicable law or otherwise impractical. Volunt ary consensus standards are technical standards ( e.g. , materials specifications, test methods, sampli ng procedures, and busine ss practices) that are developed or adopted by voluntary consensus st andards bodies. NTTAA directs EPA to provide Congress, through OMB, with explanations when the Agency decides not to use available and applicable voluntary consensus standards. Th is rulemaking involves t echnical standards. EPA developed no new measuring devi ce standard. Rather we allow the use of an appropriate

6-66-7 standard method published by a consensus-based st andards organization if such a method exists; or an industry standard practice.

6.10 Executive Order 12898: Federal Actions to Address Environm ental 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 provi sion 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, disp roportionately high and adverse human health or environmental effects of their programs, policie s, 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 minor ity or low-income populations because it does not affect the level of protection provided to hu man health or the environment. The final rule does not affect the level of prot ection provided to human health or the environment because it is a rule addressing information collect ion and reporting procedures only.

6.11 Congr essional 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, genera lly provides that before a rule may take effect, the agency promulgating the rule must su bmit 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 othe r required information to the U.S. Senate, the U.S. House of Representatives, and the Comptrolle r General of the U.S. prior to publication of
the rule in the Federal Register . A major rule cannot take eff ect 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 DA TE 30 DAYS AFTER PUBLICATION OF THIS
FINAL RULE IN THE FEDERAL REGISTER OR DECEMBER 31, 2 010, WHICHEVER IS EARLIER].SEC TION 7
CONCLUS IONS

EPA is promulgating a regulation to require monitoring and reporting from facilities that conduct carbon dioxide (CO 2 ) injection and geologic sequestra tion (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 requiremen ts covering facilities that conduct geologi c sequestration of CO 2 (40 CFR part 98, subpart RR) and all other facilities that conduct injection of CO 2 (40 CFR part 98, subpart UU). 1 GS is the long-term containment
of a CO 2 stream in subsurface geologic formations. This data will, among other things, inform Agency decisions under the CAA related to th e use of carbon dioxide capture and geologic sequestration (CCS) for mitigating GHG emissions.

Subpart RR information will enable EPA to mo nitor 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) proj ects are reporting under 40 CFR part 98, subpart RR, EPA will be able to eval uate ER as a non-emissive end use. Under 40 CFR part 98, subpart UU, EPA will be able to rec oncile information obtained from this rule with data obtained from 40 CFR part 98, subpart PP on CO 2 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 co mment period and finalizes the monitoring and reporting requirements for facilities conducti ng GS and all other f acilities conducting CO 2 injection.

This final rule does not address whether da ta 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 addr essed this issue. In that action, EPA proposed which specific data elemen ts may be released to the public and which

1 EPA has moved all definitions, requirements, and procedures for facilities conducting CO 2 injection only (which both EPA and commenters have referred to as “Tier 1 ” f acilities for simplicity) into a new subpart, 40 CFR part 98, subpart UU, and retained all definitions, requirement s, 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.

7-17-2 would be treated as CBI. EPA received several comments on that proposal under that action, and is in the process of consideri ng these comments. A final rule and determination will be issued before any data are released.7.2 Esti mated Costs and Impacts of th e Mandatory GHG Reporting Program

Under the rule, EPA estim ates that 93 facili ties would be covered by the rule. The total annualized costs incurred under the rule by thes e entities would be approximately $1.1 million (in 2008$) in the first year and $1.0 million in subse quent years. This includes a public sector burden estimate of $344,000 for program implementa tion and verification ac tivities. These costs represent less than 0.0001% of 2008 gross domes tic product; overall, EPA does not believe the rule will have a significant macroeconomic impa ct on the national economy or on small entities
within those sectors.

7.2.1 Al ternative Scenarios Considered

7.2.1.1 Fa cilities Conducting GS (ER opt in) Outcomes
Currently, the number of ER operations that would choos e to report as facilities conducting GS (ER opt in) is unknown and EPA coul d not identify any info rmation or analysis to estimate this quantity. As a result, two additi onal scenarios of the have been considered to represent medium and high outcomes. In the medium scenario, all Anthropogenic CO 2 projects (16) choose to report as facilities conducting GS (ER opt in) (Subpart RR). In the high scenario, all Anthropogenic CO 2 projects (16) and fi fty percent of other CO 2 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, na tional 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 numbe r 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 ru le (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.

7-1SECTION 8
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