### March 2010 

# Economic Impact Analysis for the

Mandatory Reporting of Greenhouse Gas Emissions Subpart RR: Proposed Carbon Dioxide Injection and Geologic Sequestration Reporting Rule

Draft Report

### C ONTENTS

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

- 1 1.1 Mandatory Reporting Rule Background
................................ .............................. 1

- 1 1.2 Supplemental Proposal of Subpart RR: Geologic Sequestration
......................... 1

- 2 1.3 Subpart RR Context
................................ ................................ ............................. 1

- 5 Section 2 Regulatory Background
................................ ................................ ......................... 2

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

- 1 2.2 Safe Water Drinking Act and UIC Regulations
................................ ................... 2

- 2 2.3 Other Federal, State, and Agency Programs
................................ ........................ 2

- 4 Section 3 Development of Subpart RR
................................ ................................ .................. 3

- 1 3.1 Rule Dimensions for Which Options Were Identified
................................ ......... 3

- 1 3.2 Definition of Affected Entities
................................ ................................ ............. 3

- 2 3.3 Selection of Reporting Threshold
................................ ................................ ........ 3

- 4 3.4 Selection of Data to Be Reported
................................ ................................ ......... 3

- 6 3.5 Selection of proposed monitoring, reporting, and verification (MRV) plan requirements and approval process
................................ ................................ .... 3

- 11 3.5.1 Selection of MRV Plan Option
................................ .............................. 3

- 11 3.5.2 Background on MRV Approaches
................................ ......................... 3

- 13 3.6 Selected Option
................................ ................................ ................................ .. 3

- 14 3.7 Alternative Scenarios Evaluated
................................ ................................ ........ 3

- 15 3.8 Data Quality
................................ ................................ ................................ ....... 3

- 15 Section 4 Engineering Cost Analysis
................................ ................................ ................... 4

- 17 4.1 Introduction
................................ ................................ ................................ ........ 4

- 1 7 4.2 Overview of Cost Analysis
................................ ................................ ................ 4

- 17 4.3 Baseline Reporting
................................ ................................ ............................. 4

- 17 4.3.1 In troduction
................................ ................................ ............................ 4

- 17ii 4.3.2 Data Sources
................................ ................................ .......................... 4

- 19 4.3.3 Published Data on CO 2Sequestration Projects
................................ ...... 4

- 19 4.3.4 Hydrogeologic Settings
................................ ................................ .......... 4

- 21 4.3.5 Formation Capacity
................................ ................................ ................ 4

- 25 4.3.6 Geologic Sequestration Rule Activity B aseline
................................ ..... 4

- 27 4.4 Reporting Costs
................................ ................................ ................................ .. 4

- 33 4.4.1 Introduction
................................ ................................ ............................ 4

- 33 4.4.2 Cost Assumptions and Methodology
................................ ..................... 4

- 33 4.4.3 Monitoring, Reporting, and Verification (MRV) Plan Requirements and Approval Process
................................ ..................... 4

- 35 4. 5 Monitoring Technologies
................................ ................................ ................... 4

- 38 4.5.1 Cost Scenarios
................................ ................................ ........................ 4

- 43 4.6 Projecting and Discounting National Costs
................................ ....................... 4

- 46 4.7 Other Recordkeeping and Reporting Costs
................................ ........................ 4

- 50 4.8 Public Sector Burden
................................ ................................ ......................... 4

- 50 Section 5 Economic impact analysis
................................ ................................ .................... 5

- 51 5.1 Threshold Analysis
................................ ................................ ............................ 5

- 51 5.2 National Cost Estimates
................................ ................................ ..................... 5

- 53 5.2.1 National Cost Estimates Under Alternative GS Facilities (ER opt in) Outcomes
................................ ................................ .......................... 5

- 54 5.2.2 National Cost Estimates Under Alternative GS Facilities (Commercial Saline) Outcomes
................................ ............................. 5

- 55 5.3 Economic Impact Analysis
................................ ................................ ................ 5

- 55 5.3.1 Revenue Estimate for a Representative Commercial ER Operation
..... 5

- 55 5.3.2 Sales Test Results
................................ ................................ .................. 5

- 56 5.4 Assessing Economic Impacts on Small Entities
................................ ................ 5

- 56 5.4.1 Identify A ffected Sectors and Entities
................................ ................... 5

- 56 5.4.2 Develop Small Entity Economic Impact Measures
............................... 5

- 57 5.4.3 Results of Screening Analysis
................................ ............................... 5

- 57 5.5 Characterization of Benefits of Subpart RR of the Mandatory Reporting Rule
................................ ................................ ................................ .................... 5

- 58iii

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

- 60 6.1 Executive Order 12866: Regulatory Planning and Review
............................... 6

- 60 6.2 Paperwork Reduction Act
................................ ................................ .................. 6

- 60 6.3 Regulatory Flexibility Act
................................ ................................ ................. 6

- 62 6.3.1 Identify Affected Sectors and Entities
................................ ................... 6

- 62 6.3.2 Develop Small En tity Economic Impact Measures
............................... 6

- 63 6.3.3 Results of Screening Analysis
................................ ............................... 6

- 63 6.4 Unfunded Mandates Reform Act
................................ ................................ ....... 6

- 64 6.5 Executive Order 13132: Federalism
................................ ................................ .. 6

- 64 6.6 Executive Order 13175: Consultation and Coordination with Indian Tribal Governments
................................ ................................ ................................ ...... 6

- 65 6.7 Executive Order 13045: Protection of Children from Environmental Health and Safety Risks
................................ ................................ ..................... 6

- 65 6.8 Executive Order 13211: Actions that Significantly Affec t Energy Supply, Distribution, or Use
................................ ................................ ........................... 6

- 66 6.9 National Technology Transfer Advancement Act
................................ ............. 6

- 66 6.10 Executive Order 12898: Federal Actions to Address Environmental Justice in Minority Populations and Low

- Income Populations
................................ ..... 6

- 67 Section 7 Conclusions
................................ ................................ ................................ ............ 7

- 1 7.1 Summary of S elected Regulatory Alternative
................................ ..................... 7

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

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

- 2 Section 8 References
................................ ................................ ................................ .............. 8

- 1iv LIST OF TABLES Table4

- 1. Comparison of IC F Assessment of U.S. Sequestration Potential with Published

Estimates
................................ ................................ ................................ ................. 4

- 26 Table 4

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

- 27 Table 4

- 3. Pro

- forma Project Characteristics (ER Scenario: No Additional ER opt In )
.......... 4

- 29 Table 4

- 4. Pro

- forma Project Characteristics (ER Scenario: Anthropogenic ER Only Opt In ) 4

- 30 Table 4

- 5. Pro

- forma Project Characteristics (ER Scenario: Anthropogenic plus One

- half Other

ER Opt In)
................................ ................................ ................................ ............... 4

- 31 Table 4

- 6. Major S ources of Geologic Sequestration Cost Information
................................ ... 4

- 35 Table 4

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

- 36 Table 4

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

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

- 38 Table 4

- 9. Assumptions for Application of Technologi es by Regulatory Alternative
............. 4

- 44 Table 4

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

- 47 Table 4

- 11. Summary of Cost Impacts: Activity Baseline from only Anthropogenic

ER Opt In
................................ ................................ ................................ .............. 4

- 48 Table 4

- 12. Summary of Cost Impacts: Activity Baseline from Anthropogenic CO 2plus One

half of Other ER Opt In
................................ ................................ .......................... 4

- 49 Table 5

- 1 CO 2Injection Facilities: Effect of Injection Threshold on Reported Amount of CO 2

Injected and Number of Facilities Required to Report
................................ ........... 5

- 52 Table 5

- 2. National Annualized Mandatory Reporting Costs Estimates: Subpart RR
............ 5

- 53 Table 5

- 3. Annualized Mandatory Reporting Costs per Project (200 8$): Subpart RR
............ 5

- 53 Table 5

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

Anthropogenic CO 2Projects
................................ ................................ ................... 5

- 54 Table 5

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

Anthropogenic 50 Percent of Other CO 2Projects
................................ .................. 5

- 54 Table 5

- 6. Estimated Annual Revenue for a Representative Co mmercial ER Field Operation

(2008)
................................ ................................ ................................ ...................... 5

- 55 Table 5

- 7. Sales Tests for Representative Commercial ER Field Operations
.......................... 5

- 56v1

- 1 SECTION 1 INTRODUCTION AND BAC KGROUND 1.1 Mandatory ReportingRule Background On December 26, 2007, President Bush signed the fiscal year Consolidated Appropriations Act authoriz ingfunding for EPA to issue a rule requiring the mandatory reporting of greenhouse gas ( GHG ) emissions (Consolidated Appropriations Act, 2008, Pub. L. No.110

- 161, 121 Stat 1844, 2128 (2008)). An accompanying joint explanatory statement directed EPA to "use its existing authority under the Clean Air Act" to develop a mandatory GHG reporting rule. The Proposed Mandatory Reporting of Greenhouse Gases Rule was signed on March 10, 2009 , by Administrator Lisa Jackson; and EPA published a proposed rule requiring mandatory reporting of GHG emissions in April 2009. 74 FR 16448 (April 10 , 2009). After a 60 day comment period, two public hearings, and meeting with over 4,000 additional people in over 150 groups via W ebinars, conferences, individual meetings, and other forms of outreach EPA issued a final rule on October 30, 2009. 74 FR 5 6260. The Mandatory Reporting of Greenhouse Gases Rule requires reporting of GHGs and supply from all sectors of the economy, including fossil fuel suppliers, industrial gas suppliers, and direct emitters of GHGs. The rule does not require the control of greenhouse gases; rather the rule requires specific source categories that are above certain threshold levels to monitor and report those emissions. The final Mandatory Reporting of Greenhouse Gases Rule covers the major GHGs that are directly emitted by anthropogenic activities. These include carbon dioxide (CO 2 ), methane (CH 4 ), nitrous oxide (N 2 O), hydroflourocarbons (HFCs), perfluorocarbons (PFCs), sulfur hexafluoride (SF 6 ), and other specified fluorinated compounds (e.g., hydroflouroethers (HFEs)) usedin boutique applications such as electronics and anesthetics. 1 The final rule contains 3 1 subparts, each requiring reporting from a defined source category. In order to meet the reporting time, quality assurance, and verification requirements of the rule, EPA is establishing a facility

- to
- EPA electronic reporting system to facilitate collecti on of data under this rule. All facilities that are covered under this rule as reporters will use this data system to submit required data.

1 These gases influence the climate system by trapping in the atmosphere heat that would otherwise escape to space. A dditional information about GHGs, climate change, and climate science , andother related issues, can be found at EPA’s climate change w eb site at http://www.epa.gov/climatechange/
.1

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1.2 Supplemental Proposal of Subpart RR: CO 2Injection and Geologic Sequestratio n Today, EPA is proposing to amend the Mandatory Reporting of Greenhouse Gases Program at 40 CFR part 98 to add reporting requirements covering facilities that conduct injection and geologic sequestration(GS) of CO 2 . EPA is proposing a tiered approach for reporting requirements under this subpart. The first tier of proposed regulations would establish a set of reporting requirements that would cover all facilities that inject CO 2underground . All facilities would be required to report the amount of CO 2transferred onsite from offsite sources, the source of the CO 2(if known), and the amount of CO 2injected underground. The second tier of reporting requirements would apply to GS facilities. GS facilities would be required to calculate the amount of CO 2sequestered by subtracting total CO 2emissions from the quantity of CO 2injected in the reporting year. The emitted quantity would include the amount of the injected CO 2that leaked from thesubsurface to the surface (if any), CO 2produced with oil or natural gas where ER operations are conducted at the GS facility, and fugitive or vented CO 2emissions from surface equipment. EPA considered several options for monitoring, reporting and veri fication (MRV) of potential CO 2leakage 2at GS sites: do not require a MRV plan, require a universal MRV plan that applies to all GS sites, or require a site

- specific MRV plan. EPA is proposing to require monitoring according to a site

- specific MRV plan, but is seeking comment on all of the options considered. While the risk of leakage at a well

- selected and well

- managed GS site is expected to be low, the Agency considers it important for all facilities conducting GS to demonstrate that they have met MRV standards. Data on CO 2injection and G S are critical to informing Clean Air Act ( CAA ) GHG policies. This data would provide information and transparency on the amount of CO 2injected and geologically sequestered in the United States and, in combination with other subparts of the MRR, would enable EPA to track the flow of CO 2across a CCS system. In addition, this information would enable EPA to monitor the growth and efficac y of GS (and therefore CCS) as a GHG mitigation technology over time and to evaluate relevant policy options. For example, EPA would be able to track whether incentives or regulations are needed to encourage faster or further GS project development. EPA would also be able to track whether ER sites are transitioning to GS and consider whether incentives or regulations are needed. Where ER

2Leakage in this proposed rule is defined as the movement of CO 2from the injection zone to the surface (for example to the atmosphere, indoor air, ocean s or surface water).1

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facilities are reporting GS, EPA would be able to evaluate ER as a potentially non

- emissive end use. In combination w ith other subpart s of the MRR , EPA would be able to reconcile this data with CO 2supplied (subpart PP) in order to better understand the quantity of CO 2supplied to emissive and non

- emissive end uses. In developing this proposal, EPA considered overlap be tween this program and other programs. In July 2008, EPA proposed to amend its UIC program to establish a new class of injection well for GS projects (73 FR 43492 (July 25, 2008)). Today’s proposal provides a pathway for CO 2injection facilities to report to EPA as GS facilities under the CAA, regardless of their UIC permit classification. Under this proposal, any facility sequestering CO 2 underground can choose to report as a GS facility for purposes of this proposed rule. Since subpart RR is an amendme nt to the MRR, the general provisions of that rule (40 CFR part 98, subpart A) apply to today’s rule unless a provision is superseded by this subpart that applies uniquely to facilities that inject CO 2or that conduct GS. The general provisions address th e following topics: the purpose and scope (40 CFR 98.1); who must report (40 CFR 98.2); the general monitoring, reporting, recordkeeping and verification requirement (40 CFR 98.3); the authorization and responsibilities of the designated authority (40 CFR 98.4); how a report is submitted (40 CFR 98.5); definitions (40 CFR 98.6); the standardized methods incorporated by reference (40 CFR 98.7); the compliance and enforcement provisions (40 CFR 98.8); and the mailing addresses (40 CFR 98.9). In a separate rul emaking package that should shortly follow this proposal, EPA will be issuing minor harmonizing changes to the general provisions for the MRR (40 CFR part 98, subpart A) to accommodate the addition of the proposed CO 2injection and geologic sequestration s ubpart. The changes affect paragraphs on rule applicability, schedule, definitions, and incorporation by reference. In particular, EPA is proposing to revise 40 CFR 98.2(a) to add CO 2injection and geologic sequestration facilities to the list of source c ategories that must report starting with calendar year 2011. EPA also is proposing to restructure 40 CFR 98.2(a) to move the lists of source categories from the text into tables. The table format improves clarity and facilitates the addition of source categories that were not included in calendar year 2010 reporting and begin reporting in future years. Because all CO 2injection and geologic sequestration facilities (as defined in proposed 40 CFR part 98, subpart RR) would be subject to the proposed rule, this source category would be added to the table of “all

- in” source categories referenced from 40 CFR 98.2(a)(1). The introductory text of 40 CFR 98.2(a)(1) and a few other sentences1

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throughout 40 CFR part 98, subpart A that reference “subparts C throughJJ” would be reworded to accommodate proposed new subparts such as RR that are outside of this range of letters. These rewordings either refer to the source category tables or otherwise correct the range of subparts referenced, as appropriate. In additi on, EPA is proposing to amend 40 CFR 98.2 (1) to accommodate a mechanism that would allow CO 2injection and GS facilities to cease reporting. EPA is proposing to amend 40 CFR 98.2(a) so that the MRR applies to facilities located on or under the Outer Continental Shelf. These revisions are necessary to ensure that any CO 2 injection or GS facilities located on or under the Outer Continental Shelf of the United States would be required to report under this rule. In addition, EPA is proposing revisions to th e definition of United States to clarify that the United States includes the territorial seas. Other facilities located offshore of the United States covered by the MRR program at 40 CFR part 98 would also be affected by this change in the definition of U nited States. For example, EPA is intending to revise the MRR requirements to add a new subpart, subpart W, to address petroleum and natural gas systems. Finally, in addition to the change to the definition of United States, EPA is adding a definition of “Outer Continental Shelf.” This definition is drawn from the definition in the U.S. Code. Together, these changes make clear that the MRR applies to facilities on land, in the territorial seas, or on or under the Outer Continental Shelf, of the United S tates, and that otherwise meet the applicability criteria of the rule. EPA is proposing to revise 40 CFR 98.3(b), which establishes the schedule for annual reporting. The text in 40 CFR 98.3(b)(1) and (b)(2) indicate that existing facilities subject to the rule must submit an annual GHG report for calendar year 2010. When proposed subpart RR is added, facilities will become subject to the reporting rule due to CO 2injection or geologic sequestration, and their first annual GHG report would cover calendar year 2011 rather than 2010. Therefore, EPA is proposing to modify the text of 40 CFR 98.3(b) to allow reporting to start in different years, as appropriate. EPA also is proposing to remove and reserve 40 CFR 98.3(b)(1). It would no longer be accurate, and it would not be needed because 40 CFR 98.2(a) would indicate the first reporting year for source categories added to the rule and the requirement for facilities to report in each subsequent year is already contained in 40 CFR 98.2(i). EPA is proposin g to amend 40 CFR 98.6 to add definitions for terms used in the proposed subpart. EPA also is proposing to amend 40 CFR 98.7 (incorporation by reference) to include standard methods used in proposed subpart RR.1

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1.3 Subpart RR Context Subpart PP requires the reporting of CO 2supplied to the economy. Subpart PP applies to all facilities with CO 2 production wells, facilities with production process units that capture and supply CO 2 for commercial application s or that capture and maintain custody of a CO 2 stream to sequester or otherwise inject it underground, and to importers and exporters of bulk CO 2 . During the public comment period on the rule, EPA received many comments on subpart PP that CO 2 injected un derground should be considered when estimating emissions from the CO 2supply industry. Some commenters specified that some of the CO 2supplied for the purposes of enhanced oil and gas recovery (ER) is additionally sequestered rather than emitted and char acterized ER operations as “closed systems” rather than emissive. Other commenters stated that including reporting requirements for geologically sequestered CO 2would fill a critical gap in the reporting system. EPA agrees that ER is a potentially non

- emissive end use and that GS data reporting from ER sites can assist EPA in quantifying the amount of CO 2that is permanently and securely geologically sequestered. In addition, EPA agrees that GS reporting requirements would provide information and transparency on the amount of CO 2injected and geologically sequestered in the United States. Although CCS is occurring now on a relatively small scale, it could play a larger role in mitigating GHG emissions from a wide variety of statio nary sources. According to the Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990

- 2007, stationary sources contributed 67 percent of the total CO 2emissions from fossil fuel combustion in 2007. 3 These sources represent a wide variety of sectors amenable to CO 2 capture: electric power plants (existing and new), natural gas processing facilities, petroleum refineries, iron & steel foundries, ethylene plants, hydrogen production facilities, ammonia refineries, ethanol production facilitie s, ethylene oxide plants, and cement kilns. Furthermore, 95 percent of the 500 largest stationary sources are within 50 miles of a candidate CO 2reservoir4 . Estimated GS capacity in the United States is over 3, 500 Gigatons CO 2(GtCO 2 ) (13,000 Gigatons CO 2at the high end), 5 although the actual capacity may be lower once site

- specific technical and economic considerations are addressed.

3 U.S. EPA Draft Inventory of U.S. Greenhouse Gas Emi ssions and Sinks, 1990

- 2007, Draft Report, EPA 430

- R

- 09

- 004. Available at: http://epa.gov/climatechange/emissions/usinventoryreport.html
. 4 Dooley, JJ, CL Davidson, RT Dahowski, MA Wise, N Gupta, SH Kim, EL Malone . 2006. "Carbon Dioxide C apture and Geologic Storage: A Key Component of a Global Energy Technology Strategy to Address Climate Change." Joint Global Change Research Institute, Battelle Pacific Northwest Division. PNWD

- 3602. 5 DOE . 2008. Carbon Sequestration Atlas of the United States and Canada (Atlas II) . Available at: http://www.netl.doe.gov/technologies/carbon_seq/refshelf/atlasII/
.1

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Even if only a fraction of that geologic capacity is used, CCS is poised to play a sizeable role in mitigating U.S. GHG emissions. Many of the injection and monitoring technologies that may be applicable for GS are commercially available today and will be more widely demonstrated over the next 10 to 15 years. 6The oil and natural gas industry in the U nited S tates has over 35 years of exp erience in transporting and injecting CO 2into the deep subsurface for the purposes of enhancing oil and natural gas production. This experience provides a strong foundation for the injection and monitoring technologies that will be needed for commercial

- scale CCS. U.S. experience with ER combined with the experience of four end

- to
- end commercial CCS projects 7 and ongoing research, demonstration, and deployment programs throughout the world, are building confidence that transportation and seques tration of large volumes of CO 2can be achieved.

6 Dooley, JJ, CL Davidson, RT Dahowski. 2009. "An Assessment of the Commerci al Availability of Carbon Dioxide Capture and Storage Technologies as of June 2009." Joint Global Change Research Institute. Pacific Northwest National Laboratory. PNNL

- 18520. 7 These projects are : Sleipner (Norwegian North Sea)

- 1 Mt CO 2/yr injected since 1996; Weyburn (Canada)

- 1 Mt CO 2/yr injected since 2000; In Salah ( Algeria)

- 1.2 Mt CO 2/yr injected since 2004; and Snohvite (Norwegian Barents Sea)

- 0.7 Mt CO 2/yr injected since 2008.2

- 1 SECTION 2 REGULATORY BACKGROUN D The intent of the MRRis to collect accurate and timely GHG data that can be used to inform future policies. Although the mandatory GHG rule is unique, EPA carefully considered other federal and state programs during development of the rule. The reporting program will supplement rather than duplicate other U.S. government GHG programs. We outline EPA’s overall rulemaking approach, sources considered, and summarize our review of GHG monitoring protocols for each source category used by federal, state, regional, and international voluntary and mandatory GHG programs, and our review of state mandatory GHG rules below. The remainder of the section provides an overview of related existing programs and discusses their relevance in the development of S ubpart RR. 2.1 EPA’s Overall Rulemaking Approach The mandatory reporting program will provide comprehensive and accurate data which will inform future climate change policies. Potential future climate policies include research and development initiatives, economic incentives, new or expanded voluntary programs, adaptation strategies, emission standards, a carbon tax, or a cap

- and

- trade program. Because we do not know at this time the specific policies that will be adopted, the data reported through the mandatory reporting system should be of sufficient quality to support a range of approaches. Also, consi stent with the Appropriations Amendment, the reporting rule covers a broad range of sectors of the economy. To these ends, we identified the following goals of the mandatory reporting system:

 Obtain data that is of sufficient quality that it can be used t o support a range of future climate change policies and regulations.

 Balance the rule coverage to maximize the amount of emissions reported while excluding small emitters.

 Create reporting requirements that are consistent with existing GHG reporting progr ams by using existing GHG emission estimation and reporting methodologies to reduce reporting burden, where feasible.2

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This section presents the current regulatory context for Subpart RR and illustrates the anticipated role of the current proposal within th e framework of the existing mandatory and voluntary programs. 2.2 Statutory Authority EPA is proposing this rule under the existing authority provided in CAA section 114. As noted in the Mandatory R eporting of GHG Rule, CAA section 114 provides EPA with broad authority to require information mandated by this rule because such data will inform and are relevant to EPA’s carrying out a wide variety of CAA provisions (74 FR at 66264). Under CAA section 114(a)(1), the Administrator may require emissions sources, persons subject to the CAA, or persons whom the Administrator believes may have necessary information to monitor and report emissions and provide such other information as the Administrator reques ts for the purposes of carrying out the provisions in the CAA (except for a provision of title II with respect to motor vehicles). As discussed in greater detail in the response to comments for the final Mandatory Reporting of GHG Rule, the CAA provides EPA with broad authority to require the comprehensive and accurate information mandated in this rule because such data will inform, and are relevant to, EPA’s analyses of various CAA provisions. The information from CO 2injection and GS facilities will all ow EPA to make well

informed decisions about whether and how to use the CAA to regulate these facilities and encourage voluntary reductions. 2.2 Safe Water Drinking Act and UIC Regulations EPA’s UIC programwas established in the 1970s to prevent endangerment of underground sources of drinking water (USDWs) from injection of various fluids, including CO 2 for ER, oil field fluids, water stored for drinking water supplies, and municipal and industrial waste. The UIC program, which is authorized by Part C of the Safe Drinking Water Act (SDWA) (42 U.S.C. 300h et seq .), is designed to prevent the movement of such fluid into USDWs by addressing the potential pathways through which injected fluids can migrate and p otentially endanger USDWs. When EPA initially promulgated its UIC p rogram regulations, the Agency defined five classes of injection wells at 40 CFR 144.6, based on similarities in the fluids injected, construction, injection depth, design, and operating techniques. W ells injectingindustrial non

-2

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hazardous liquids, municipal wastewaters or hazardous wastes beneath the lowermost USDWare categorized as Class I
. Thoseinjectingfluids in connection with conventional oil or natural gas production, enhanced oil and gas production, and the storage of hydrocarbons which are liquid at standard temperature and pressureare categorized as Class II . Class III wells inject fluids associated with the extraction of minerals , and those categorized as Class IV inject hazardous or radioactive wastes into or above USDWs . Class IV injection wells are banned unless authorized under an approved Federal or State ground water remediation project. Class V includes all injection wells that are not included in Classes I

– IV. This well class provides for Class V experimental technology wells including those permitted as GS pilot projects. 8 In 2008, EPA proposed to amend the UIC program to establish a new class of injection well

— Class VI

—

to cover the underground injection of CO 2for the purpose of GS, or long

term storage of CO 2(73 FR 43492 (July 25, 2008)). The proposed requirements would tailor existing comp onents of the UIC program to address the unique nature of GS projects so as to ensure that the injection of large volumes of CO 2in a variety of geologic formations for the purposes of long term storage would not endanger USDWs. The UIC Class VI proposal does not require any facilities to capture and/or sequester CO 2 ; rather the proposed requirements, if finalized, would protect USDWs under the SDWA. The SDWA does not provide authority to develop regulations for all areas related to GS such as capture or transport. As outlined in the UIC Class VI proposal, injection wells used for injecting CO 2for the purposes of ER would continue to be regulated and permitted as Class II as long as any production is occurring
. Facilities regulated under the UIC program are required to collect and report data, with minimum requirements for the collection and reporting of data established at the federal level. Where states are given primacy over the UIC program, the data collected under the UIC program varies. Data currently collected under a state

- issued UIC permit is submitted to states while, under today’s subpart RR proposal, reporters will be submitting data directly to EPA. The Agency believes that state, local, and tribal input is valuable in ensuring that the s ubpart RR reporting requirements appropriately build on the UIC program requirements. Today’s proposal builds on the UIC program requirements for monitoring with the additional goals of verifying the amount of CO 2sequestered and collecting data on CO 2 surface emissions from GS facilities. EPA is proposing that a facility’s UIC permit may be used to demonstrate that certain MRV plan requirements have been fulfilled.

8 S ee EPA UIC Guidance #83 . Available at: http://www.epa.gov/safewater/uic/wells_sequestration.html2

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In the Agency’s August 2009 Notice of Data Availability supplementing the UIC Class VIproposal, EPA noted that it was evaluating the need for a more comprehensive regulatory framework for GS. The Agency acknowledges that regulatory clarity is essential for enabling GS to move forward in a manner that protects human health and the environm ent. EPAis coordinatingGS requirements across relevant statutory or other programs in order to minimize redundanc yand increase clarity for stakeholders. The proposed UIC Class VI rule is a separate rulemaking action; the comment period for that rulem aking closed on December 24, 2008. EPA will not be accepting or responding to comments on the proposed UIC Class VI rule through today's proposal unless related to a specific issue raised by this action. 2.3 Other Federa l, State, and Agency Programs The Department of Energy (DOE) Energy Information Administration implements a voluntary GHG reporting program under section 1605(b) of the En ergy Policy Act of 1992, which directed DOE to issue guidelines establishing a voluntary greenhouse gas reporting program (42 U.S.C. 13385(b)). Under the Energy Information Administration’s “1605(b) program,” reporters can choose to prepare an entity

- wideGHG inventory and identify specific GHG reductions made by the entity. 9 Reporting tools were revised and published in 2009 to assist e ntities in preparing a preliminary estimate of emissions. The 2007 updated 1605(b) guidance outlines a voluntary process to report data on CO 2sequestration. Currently, no CO 2 injection or sequestration entity has reported under the 1605(b) program per the 2007 guidelines. According to the Energy Information Administration website, the first reporting cycle under the revised Voluntary Reporting of Greenhouse Gases Program has not been completed as of January 15, 2010. The Energy Information Administrati on anticipates issuing an annual report and public use database for data reported through 2008 by early 2010. 10The 1605(b) guidance requires the implementation of a site

- specific monitoring plan, but this plan is not evaluated by DOE to determine whether the plan will provide for appropriate monitoring. Four prescriptive monitoring scenarios are offered with grades ranging from “A” to “C”, any of which would be acceptable for compliance with the 1605(b) program. Furthermore, although the 1605(b) guidance cites the importance of reporting CO 2leakage should it occur, the guidance does not include a discussion of, procedures for, or methodologies for using monitoring technologies and

9 Under the 1605(b) program an “entity” is defined as “the whole or part of any business, institution, organization or household that is recognized as an entity under any U.S. Federal, State or local law that applies to it; is located, at least in part, in the U.S.; and whose operations affect U.S. greenhouse gas emissions.” (http://www.pi.energy.gov/enhancingGHGregistry/) 10 http://www.eia.doe.gov/oiaf/1605/data_reports.html2

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techniques to quantify the leakage. As a result of this, and the fact that reporting is voluntary, the 1605(b) program would not meet the data needs of this proposed rule. The Internal Revenue Service (IRS) made public IRS Notice 2009

- 83 Credit for Carbon Dioxide Sequestration under section 45Q on its Web site on October 8, 2009. 11 The notice provides procedures for the allo cation of credits for CO 2sequestration under section 45Q of the Internal Revenue Code. Section 45Q was enacted by section 115 of the Energy Improvement and Extension Act of 2008, (October 3, 2008) and was amended by section 1131 of the American Recovery and Reinvestment Act of 2009 (February 17, 2009). To claim this credit, a taxpayer must follow general monitoring and verification principles, calculate CO 2sequestered in the fiscal year using a mass

- balance equation, and report to IRS the amount of qual ified CO 2 sequestered in the fiscal year. Seventy

- five million metric tons of qualified CO 2can be taken into account for this credit. The IRS included a provision in the notice to supersede its monitoring and verification procedures and requirements with procedures and requirements finalized by EPA in future GS rulemaking such as the UIC Class VI proposal and this proposed rule. EPA has concluded for a number of reasons that the IRS data would not meet the needs outlined in this proposed rule. First, the IRS reporting requirement will expire after 75 million metric tons of CO 2is reported as sequestered to IRS, at which point the data collection will end. Second, the level of reporting and transparency would not meet the verification needs of this prop osed rule. GS facilities only report the quantity of CO 2 sequestered to IRS. The data used to calculate sequestration and the specific monitoring procedures followed will only be reviewed by IRS staff in the case of an audit. Given the variability in ge ology and other conditions at GS facilities, EPA believes that the monitoring approach at each GS facility must be reviewed on a case - by

- case basis to ensure that it is appropriate for the site

- specific geologic and operational conditions. Third, the IRS does not outline procedures or provide a mechanism for quantifying and reporting any CO 2leakage that may occur as is necessary for this proposed rule. EPA notes that the United States submits an inventory of GHG emissions that accounts for CCS to the Secretariat of the United Nations Framework Convention on Climate Change (UNFCCC) each year. The UNFCCC, ratified by the United States in 1992, establishes an overall framework for intergovernmental efforts to tackle the challenge posed by climate change. Th e United States has submitted the Inventory of U.S. Greenhouse Gas Emissions and Sinks (Inventory) to the United Nations every year since 1993. The annual Inventory is consistent with

11 Available at: http://www.irs.gov/irb/2009

- 44_IRB/ar11.html
.2

- 6

national inventory data submitted by other UNFCCC parties, and uses int ernationally accepted methods for its emission estimates. For more information about the Inventory, please refer to the following web site: http://www.epa.gov/climatechange/emissi ons/usinventoryreport.htm The United States currently follows the 1996 12Intergovernmental Panel of Climate Change (IPCC) guidelines in preparing its Inventory, as supplemented by IPCC Good Practice Guidance (GPG) from 2000 13 and 2003 14 . Since these guidelines do not provide information on the accounting of GS, EPA addressed CO 2usage in the 2007 Inventory by accepting some general, top

- down assumptions about the end

- use of supplied CO 2 . First, EPA collected CO 2 production data for natural CO 2domes and estimated for each dome the amount of CO 2used for ER operations and the amo unt of CO 2used for non

- ER operations. EPA assumed that the percentage of naturally produced CO 2used for non

- ER operations (e.g. food processing, chemical production) was all emitted to the atmosphere. The percentage used for ER operations was assumed t o be sequestered. Second, EPA collected data from industry on anthropogenic CO 2emitted from natural gas processing and ammonia plants and accounted it as emitted, regardless of whether the CO 2was captured or not. The IPCC published new inventory gui delines in 2006 15 , which directly address accounting for GS and include methodologies for the estimation of emissions from capture, transport, injection, and GS of CO 2 . The guidelines are based on the principle that the CCS system should be accounted for in a complete and consistent manner across the entire Inventory. The approach accounts for CO 2produced from natural CO 2domes and captured at industrial facilities as well as emissions from capture, transport, and use. For GS specifically, the IPCC guidelines outline a Tier 3 methodo logy 16 for estimating and reporting emissions based on site

specific evaluations of each storage site. EPA believes that the GS m onitoring, reporting, and verification requirements of this proposed rule are consistent with the 2006 IPCC guidelines.

12IPCC, 1996. “ Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories .” National Greenhouse Gas Inventories Programme. Available: http://www.ipcc

- nggip.iges.or.jp/publ ic/gl/invs1.html
. 13 IPCC. 2000. “Good Practice Guidance and Uncertainty Management in National Greenhous e Gas Inventories.” National Greehouse Gas Inventories Programme. Available at: http://www.ipcc

nggip.iges.or.jp/public/gp/english/
. 14 IPCC. 2003. “Good Practice Guidance for Land Use, Land

- Use Change, and Forestry.” National Greenhouse Gas Inven tories Programme. Available at: http://www.ipcc

- nggip.iges.or.jp/public/gpglulucf/gpglulucf.html
. 15 2006 IPCC Guidelines for National Greenhouse Gas Inventories: Volume 2

–Energy
. Chapter 5 Carbon Dioxide Transport, Injection, and Geological Storage. Available at : http://www.ipcc

nggip.iges.or.jp/public/2006gl/index.htm
. 16Tier 3 methods include either detailed emission models or measurements and data at individual plant level where appropriate.2

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In considering how to design this proposal, EPA also took into account the monitoring requirements adopted in other countries, in particular other UNFCCC member countries that have already taken steps towards collecting information for CCS to meet the 2006 IPCC guidelines. The Directive of the European Parliament and of the Council on the geological storage of carbon dioxide (Commissiondecision 2007/589/EC) establishes a legal framework for the environmentally safe geological storage of CO 2 . It requires European Council (EC) member states to ensure that each GS site operator will carry out monitoring of the injection facilities, the st orage complex (including the CO 2plume), and, where appropriate, the surrounding environment for detection of any significant migration or leakage of CO 2or any significant adverse effect on the surrounding environment.3

- 1 SECTION 3 DEVELOPMENT OF SUBPART RR Since EPA is proposing that Subpart RR be added to the existing Mandatory Reporting of Greenhouse G ases Program established under 40 CFR 98, we propose that the provisions of 98.1 through 98.6 apply to today’s rule unless we describe and provide a rationale for an alternative provision in today’s rule. This section describes the development process und erlying the proposal of Subpart RR. 3.1 Rule Dimensions for Which Options Were Identified Possible designs for subpart RR GHG reporting were developed by evaluating options across th e following dimensions: 1. Affected Entities The targeted entities under the Subpart RR source category include : (1) CO 2 injection facilities, defined as a well or a group of wells that inject CO 2into the subsurface or sub

- seabed geologic formations. This definition would encompass both onshore and offshore facilities. (2) GS f acilities , defined as facilities injecting CO 2for the purpose of long

- term containment in subsurface geologic formation s . 2. Thresholds Upon reviewing the results of a detailed threshold analysis, EPA is proposing that all facilities that meet the definition of this source category must report the data outlined below at no threshold. 3. Data to be reported All injection facilities must annually report the following: (a ) Mass of CO 2injected
. (b ) Mass CO 2transferred onsite from offsite (c) Source of CO 2 , if known.3

- 2

In addition, all GS facilities must annually report the following: (1) Mass of CO 2produced, if any. (2) Mass of CO 2sequestered in the subsurface geologic formation. (3) Mass of CO 2emitted from subsurface leaks , if any
. 4. Monitoring, reporting, and verification (MRV) plan requirements

In order to ensure accurate and efficient data reporting, each GS facility must develop a site

- specific MRV plan consistent with EPA guidelines. These dimensions are discussed in more detail below. 3.2 Definition of Affected Entities 1. CO 2Injection Facility EPA is proposing that the CO 2 injection facility be defined broadly to cover a well or a group of wells that inject CO 2into the subsurface or sub

- seabed geologic formations. This definition would encompass both on shore and offshore facilities. EPA is proposing a broad definition of CO 2injection facility to ensure complete reporting of basic information regarding the quantity of CO 2transferred onsite, the source of the CO 2if known, and the amount injected. The b road definition also provides reporters with flexibility either to report this basic information on a well by well basis or to group wells in an area for reporting purposes. Given the proposed threshold and applicability for CO 2 injection facilities, a mo re specific definition addressing the aggregation of groups of wells in an area is not necessary. 2. GS Facility EPA is proposing facilities injecting CO 2for the purpose of long

- term containment in subsurface geologic formations would meet the definitio n of GS in this proposed rule and would report additional information. EPA is proposing that facilities that inject CO 2for ER would not be GS facilities unless they inject CO 2for the purpose of long

- term containment in subsurface geologic formations and choose to submit and gain EPA approval of an MRV plan.3

- 3

To comply with the specific reporting requirements detailed in thepreamble, the reporter would need to identify the sources and surface equipment making up the GS facility. However, EPA recognize s that defining the extent of a GS facility source may be difficult. For example, there may be a number of injection wells in an oilfield under common ownership or common control of which only a subset would be considered GS facilities. In that example, the question of whether and how to aggregate various wells arises. In addition, the area of review associated with a GS facility may extend for a distance beyond the injection point, and widely separated wells may be injecting into the same pore space. B ecause EPA is seeking data on the amount of CO 2 sequestered by these facilities and because EPA is proposing an all

- in threshold for these facilities, EPA is proposing a narrow definition of GS facilityto simplify the reporting requirements associated with emissions from combustion and surface equipment. For purposes of this reporting rule, EPA is proposing to define a GS facility to include all structures associated with the injection of CO 2located between the points of CO 2transfer onsite from offsite and the injection well (or wells). A GS facility that injects CO 2to enhance the recovery of oil or natural gas will also include all structures associated with production located between the production wells and the separators. Although EPA is proposi ng a narrow definition of GS facility, the proposed rule would require GS facilities to monitor over a spatial area that will almost certainly extend beyond the boundaries of the facility, as defined here. Given that a main foc us of this proposal is to ob tain information regarding the efficacy of GS, EPA anticipates that the MRV plans for GS facilities will need to require monitoring over a broad area. This is discussed in the preamble to this rule. EPA is proposing to exempt research and development (R &D) as defined at 40 CFR Part 98.6 from subpart RR, consistent with the approach taken in subparts C through QQ of the MRR. EPA is also proposing that, for the purposes of GS facility requirements under subpart RR, research and development means those pro jects receiving Federal funding to research practices and monitoring techniques that will enable safe and effective long

- term containment of a gaseous, liquid, or supercritical CO 2stream in subsurface geologic formations that are neither demonstration nor commercial projects. R&D projects would not be required to submit an MRV plan under subpart RR. 3. Other CO 2End

- Users In developing this proposed rule, EPA considered requiring reporting from various other end

- users of the CO 2that is produced and supplied to the economy. EPA considered but is not proposing requiring reporting from these other end

- users; EPA has concluded that collecting3

- 4

information pursuant to subpart PP on CO 2supplied to the economy will provide EPA with the necessary data on emissive volumes while minimizing the number of facilities impacted by this rule. 3.3 Selection of Reporting Threshold To determine the appropriate threshold for reporting under subpart RR, EPA considered both a threshold based on the amount of CO 2emitted and a threshold based on the amount of CO 2 injected underground. EPA concluded that an emissions

- based threshold would be problematic because of the lack of data on the incidence and scale of surface emissions and leakage from injection and GS of facilities. EPA accordingly analyzed injection fac ilities based on the quantity of CO 2 injected underground and considered whether an injection threshold should apply. EPA evaluated a no threshold option (i.e., all facilities that inject CO 2would be required to report), 1,000 metric tons per year, 10,00 0 metric tons per year, 25,000 metric tons per year, and 100,000 metric tons per year per facility of CO 2injected. To establish a count of CO 2injection facilities, EPA relied on data reported in the Oil and Gas Journal (O&GJ) Enhanced Oil Recovery Surve y published in April 2008 (Volume 106, Issue 15). EPA compiled all the projects listed for miscible and immiscible CO 2floods 1 reported in the O&GJ survey. A total of 105 active ER projects were reported. In some cases multiple projects were conducted by the same co mpany in an oil field. For the purposes of this analysis, EPA grouped these reported projects by field and by owner or operator to align with typical industry practices for reporting project information to state oil and gas commissions. This computation results in eighty facilities for the facility count. The O&GJ survey does not provide the specific volume of CO 2used in each of the active ER projects. To calculate the estimated volume of CO 2injected at each ER project, EPA took the total amount of C O 2used daily for ER, as reported by the U.S. EPA in the Draft 1990

– 2007 Inventory of U.S. Greenhouse Gas Emissions and Sinks, 2apportioned it to each ER project according to an average value for the fractional production of oil attributed to ER using CO 2as presented in the O&GJ survey, and normalized the amount of CO 2injection on an annual basis. The results of the thresh old analysis are pre sentedin the preamble to this rule. For further

1 A miscible CO 2flood injects CO 2as a liquid at high pressure to completely mix with oil and make it flow more easily. An immis cible CO 2flood uses lower pressures of CO 2to swell the oil and provide additional gas pressure to move the oil. 2U.S. EPA Draft Inventory of U.S. Greenhouse Gas Emissions and Sinks, 1990

- 2007, Draft Report, EPA 430

- R

- 09

- 004. Available at : http://epa.gov/climatechange/emissions/usinventoryreport.html3

- 5

information on the assumptions underlying the threshold analysis, please refer to the general technical support document (TSD) for this proposal. 1 The results of this analysis showedthat nearly all injection data can be collected from roughly half of operating facilities at an injection threshold of 100,000 metric tons/yr of CO 2 injected. EPA considered establishing an injection threshold of 100,000 metric tons/yr of CO 2 injected. However, a low CO 2 injection or production quantity in one year is not a reliable prediction of the quantity that may be injected in the following year or in a year of full

- scale operation. For example, six of theeighty facilities reported zero or near zero production and therefore did not exceedthe 1,000 metric tons threshold . However, these six facilities may inject over this threshold in the following year. In addition, more than 40 of the 105 projects in th is analysis were described in the OG&J survey as “just started” or pilot projects, indicating that they may not be at fully operational levels of CO 2 injection. Given the variability of CO 2 injection rates, EPA is proposing that all facilities report irre spective of injection or production quantities in the reporting year. EPA is proposing that all CO 2injection facilities would be required to report the minimum information in subpart RR (quantity of CO 2injected, quantity of CO 2transferred onsite from offsite, and source of the CO 2if known) at no threshold. An all

- in reporting threshold would allow the Agency to comprehensively track all CO 2supply (as reported in Suppliers of CO 2 , subpart PP) that is injected underground. Th is approach is consistent with the all

- in requirements in the MRR 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 reasona ble to require all of the facilities in these source categories to report because it would result in the most comprehensive accounting possible, simplify the rule, and permit facilities to quickly determine whether or not they must report; the same rationale applies for this source category proposed today. Furthermore, it would create a uniform burden for all covered facilities, ensuring a level playing field in, and preventing fragmentation of, the ER sector. EPA has estimated the cost for CO 2injection facilities to comply with the minimum reporting requirements in this proposed rule and has determined that the burden would be small, given the equipment and data collection efforts already in place at ER projects. Under this action, EPA is proposing that the subset of CO 2injection facilities that are conducting GS (i.e. a GS facility) must report to EPA a second tier of data. EPA considered whether a threshold should apply to this second tier of data given that it would place a reporting

1 Subpart RR General TSD ( see docket ID No. EPA

- HQ

- OAR

- 200 9

- 0 926)3

- 6

burden on GS f

acilities. However, EPA could not perform an analysis on GS facilities based on emissions without data on actual or expected GS facility emissions. EPA also could not perform a threshold analysis based on injection due to the uncertainty around predictio ns of injection quantities for potential GS facilities. In addition, it is difficult to predict how many injection facilities would choose to report GS. Therefore, EPA is proposing to exempt GS R&D projects but otherwise require all GS facilities to comp ly with the GS monitoring, reporting, and verification requirements of subpart RR, and that they report fugitive, vented, and combustion emissions from surface equipment (under subpart W, RR, or C, as applicable). An all

- in threshold will allow EPA to wor k with the early

- movers of this nascent industry and to strengthen EPA’s understanding of GS. 3.4 Selection of Data to Be Reported This section describes the data that injection facilities and GS faciliti es must report under subpart RR. The first tier of reporting requirements described is for all facilities that inject CO 2 underground. The second tier of reporting requirements described is for GS facilities only. The first tier has three proposed reporting requirements. First, EPA is proposing that all CO 2injection facilities report the mass of CO 2injected. This would be determined by the mass flow or volumetric flow and CO 2concentration of the CO 2stream injected. Facilities must use mass flow met ers to accurately measure the mass of the CO 2injected or volumetric flow meters to accurately measure the volumetric flow of the CO 2injected. To minimize the purchase and installation of new equipment, facilities subject to the UIC program would be allo wed to measure the mass or volume of CO 2 injected with the flow meters installed for purposes of compliance with their UIC permits. EPA accordingly is proposing two methodologies for making these calculations, depending on whether the facility is using a volumetric or a mass flow meter. EPA is proposing this approach so that facilities can comply with these reporting requirements regardless of the type of flow meter already installed. In the case of a facility using a volumetric flow meter, EPA assumes that the facility can determine operating temperature and pressure, which would allow for the volumetric flow of CO 2to be converted from operating conditions to standard conditions and, using a density value for CO 2at standard conditions and the measured concentration of CO 2in the flow, determine the mass of CO 2 . Facilities would measure the CO 2concentration by sampling and testing the injected stream at the flow meter. With this approach, the flow and the concentration would be measured at the same p oint in the system for maximized data accuracy. Accordingly, if the flow meter were installed at the compressor(s), then the concentration would be measured at the3

- 7

compressor(s). If the flow meter were installed at the well(s), then the concentration wou ld be measured at the well(s). EPA recognizes that a facility with tens or hundreds of injection wells, all of which have flow meters already installed at the wellheads, may face a significant burden in testing concentration at each of those flow meters
. Second, EPA is proposing that all CO 2injection facilities report the mass of the flow transferred onsite from offsite to verify the mass of CO 2reported as injected. This would be determined by the mass flow or volumetric flow and CO 2concentration of the flow transferred onsite from offsite. A subset of CO 2injection facilities

– facilities conducting ER

– inject a combination of new CO 2transferred onsite from offsite and old CO 2recycled from the operation. Therefore, EPA would use reported data on CO 2transferred onsite from offsite to estimate the amount of CO 2recycled from ER operations. EPA is proposing that all CO 2injection facilities monitor the CO 2concentrations and ma ss flow or volumetric flow quarterly. The purpose of these measurements is to account for fluctuations in the CO 2concentration over the reporting year. Third, EPA is proposing that all CO 2injection facilities would report the source contracted to suppl y the CO 2 , if known. EPA would seek information on whether the CO 2was contracted from a natural source (i.e. produced from a natural CO 2dome) or an industrial source. If an industrial source, EPA would seek information on the type of source if known (c aptured at a power plant, pulp and paper mill, ethanol plant, natural gas processing facility, or other type of industrial source). This would allow EPA to track the movement of CO 2through a CCS system and any shift toward anthropogenic CO 2supply source s. Pipelines that carry CO 2to the CO 2 injection facility may contain a mix of CO 2from various sources. EPA recognizes that facilities may not know the source of CO 2that they purchase. Accordingly, EPA would require the data to be reported only if kno wn . EPA recognizes that at this time the source of CO 2injected underground is predominantly CO 2produced from natural CO 2domes. It is possible that GS using naturally sourced CO 2may not qualify as a GHG mitigation action because the purpose of GS is to isolate CO 2that would otherwise have been emitted to the atmosphere. Under this proposed rule, however, GS facilities must report annual CO 2 sequestered regardless of the source. For this proposed rule, EPA also considered, but is not proposing, tha t a CO 2injection facility be required to report only the CO 2 injection data it collects under its current UIC permit (under any class) or relevant permit in the case of a facility that is outside SDWA jurisdiction.3

- 8

Although this would impose the lowest b urden on the reporter since no new data would need to be collected, EPA would not receive complete data on the mass of CO 2injected. While collection of injection volume is a minimum monitoring requirement for all UIC well classes, CO 2concentration data are not. Furthermore, facilities are not required to report CO 2transferred onsite from offsite sources or the source of CO 2under any UIC permit class. EPA is proposing that GS facilities would report a second tier of data in subpart RR. These reporting requirements include the amount of leakage of CO 2to the surface (if any), the amount of CO 2in produced oil or gas (for GS facilities conducting active ER operations), the amount of fugitive and vented CO 2emissions from surface equipment, and the tot al annual amount of CO 2sequestered using a mass balance equation. In this equation, the sum of the CO 2 emissions listed above would be subtracted from the amount of CO 2injected to equal the amount of CO 2sequestered. These four reporting requirements are described in more detail below. GS facilities must report CO 2leakage, if any occurs from the subsurface geologic formation to the surface. EPA is not proposing specific procedures or methodologies fo r detecting or quantifying CO 2leakage. However, each GS facility would be required to develop and implement a site

- specific approach to monitoring, detecting, and quantifying CO 2leakage based on requirements that are outlined in detail in the preamble t o this rule. First , EPA is proposing that GS facilities that are actively producing oil or gas would be required to report the quantity of CO 2produced out of the subsurface with produced oil or natural gas. This would be done by measuring at each separ ator the volumetric flow or mass flow and the concentration of a CO 2stream. These GS facilities would also report CO 2that remains in the oil or gas after separation. Second , unless already reported in the petroleum and natural gas system subpart, subpa rt W, EPA is proposing that all GS facilities would be required to report fugitive and vented CO 2 emissions from surface components located within the facility for which procedures and methodologies are provided in subpart W. This could include pump blow

- downs and fugitive emissions from valves, flanges, and compressors. EPA seeks these data to better understand the volume of fugitive and vented GHG emissions at GS facilities as compared to the volume of CO 2 sequestered. This information is an important indicator of the effectiveness of GS as a GHG mitigation technology. In addition, fugitive and vented CO 2emissions will need to be included in the mass balance calculation of GS if they occur downstream of the CO 2injection flow meter or (if applicable f

or ER projects) upstream of the production flow meter. This proposed rule does not impose a general requirement for all CO 2injection facilities to report fugitive and3

- 9

vented CO 2emissions from surface components since facilities that are not sequesteringCO 2 would not report GS. Lastly, EPA is proposing that GS facilities use a mass balance equation to calculate and report CO 2 sequestered in the subsurface geologic formation in the reporting year. This reported data point would be valuable for EPA as the Agency tracks CO 2across a CCS system and will provide EPA with information on the performance of GS projects over time. Alternatively, EPA could approximate CO 2sequestered in the subsurface without proposing additional reporting requirements for GS f

acilities, by using data already reported on CO 2transferred from offsite and CO 2injected. EPA considered but did not propose this approach because it does not account for potential leakage from the subsurface and does not properly account for CO 2fugiti ve or vented emissions from surface equipment during post

- production, processing, transport, or compression. Given the importance of GS as a GHG mitigation technology, EPA seeks to achieve an accurate reporting of GS
. EPA recommends that CO 2injection and GS facilities review subparts C and PP and proposed subpart W. Subpart C provides GHG calculation procedures and reporting requirements for stationary fuel combustion devices that combust solid, liquid, or gaseous fuel. CO 2injection and GS facilities should pay close attention to compressors and pumps located within the facility boundary. Subpart PP provides procedures for calculating and reporting quantities of CO 2 supplied to the economy. The Subpart W proposal covers petroleum and natural gas sys tems by defining eight types of facilities and providing calculation procedures and reporting requirements for the GHG emissions of specific equipment that may be located in those facilities. CO 2injection and GS facilities should review in particular thedefinitions of onshore and offshore petroleum and natural gas production facilities. EPA is proposing that if an injection facility is not conducting GS, it would determine applicability to other subparts of the rule separately from applicability to sub part RR
. This is similar to the approach taken by reporters of upstream petroleum products supply, natural gas supply, natural gas liquids supply, and carbon dioxide supply (reporters in subparts MM, NN, and PP). For example, an injection facility not ch aracterized as a GS facility would not automatically trigger reporting under subpart C by this proposal, but would make a separate applicability determination under subpart C. A GS facility would automatically trigger applicability under other subparts of the rule. This is similar to the approach taken by reporters of downstream emissions in the rest of the MRR. For example, the GS facility would report under subpart C the emissions from combustion sources located within the facility boundary, such as co mpressors.3

- 10

In selecting data to be reported under today’s proposal, EPA compared reporting requirements under today’s subpart RR proposal with reporting under the U IC Class VI proposal
. EPA found two data elements with potential overlap. The first area o f potential overlap is the reporting of the amount (flow rate) of injected CO 2 . The UIC Class VI and subpart RR proposals differ in the measurement unit and collection/reporting frequency. EPA determined that reporting of the amount (flow rate) of injected CO 2 was necessary in order to harmonize the data with other subparts of the MRR. To ensure that data needs are harmonized between the MRR and the UIC program requirements and to reduce burden, and because this data under a state

issued UIC permit is currently submitted to states while, under today’s subpart RR proposal, reporter s will be submitting data directly to EPA. The second area of potential overlap relates to monitoring plans. Although both the UIC Class VI proposal and today’s subpart RR proposal have monitoring plan requirements, the UIC Class VI proposal is focused on protection of USDWs, while today’s subpart RR proposal is focused on air emissions. Potential differences include baseline data and detection and measurement of CO 2leakage to the surface. Recognizing that air monitoring under the UIC Class VI proposal is at the discretion of the UIC director, EPA notes that a UIC Class VI permit may fulfill requirements under today’s proposal. EPA considered whether a GS facility should also report methane (CH 4 ) leakage emissions from the subsurface. CH 4 emissions f rom the subsurface may occur at oil and natural gas reservoirs or ECBM sites. The cases in which leakage of CH 4 could occur at these sites may be similar to the potential for CO 2leakage. CH 4 leakage could potentially occur through improperly sealed well s, open faults, and other pathways that have also been identified as potential CO 2leakage pathways. However, CH 4 is present as a gas, and thus may be more upwardly mobile than CO 2which is injected as a supercritical fluid. Therefore, the potential for leakage of methane at depleted oil and gas or ECBM sites may be greater than for CO 2. EPA is proposing to focus on CO 2emissions. EPA recognizes the potential for CH 4 leakage from the subsurface at facilities conducting GS in oil and gas reservoirs or coal seams and therefore seeks comment on whether to require reporting on CH 4 leakage. If the potential for CH 4 leakage exists, the GS reporter could include in the MRV plan a monitoring strategy to detect and quantify potential CH 4 leakage. CH 4 fugitive an d vented emissions from surface equipment are covered under the proposed oil and gas subpart, subpart W. Under subparts C through QQ of the MRR, adjacent or contiguous equipment in actual physical contact under common ownership or common control constitutea facility (see Section3

- 11

98.6 of the MRR). In the case of petroleum and natural gas systems and GS, equipment are not necessarily in physical contact with one another in the conventional sense of the term. Subparts W and RR are each proposing interpretations of what would constitute a facility. As a result, a GS facility conducting ER may apply one facility boundary for reporting under subpart W and a different facility boundary for reporting under subpart RR. EPA acknowledges that this may present a ch allenge for submitting annual reports, depending on how the data system is designed. A CO 2injection or GS operation would submit an annual report to EPA according to the proposed definition of facility
. EPA also recognizes that, in the case of an ER operation conducting GS, the combustion emissions from equipment within the GS facility would be included in both annual reports. Though this approach results in duplicative reporting, EPA has concluded that to analyze the efficacy of GS as a GHG mitigation tool, EPA needs to collect information on combustion emissions from GS facility equipment at only the GS facility level rather than aggregated with emissions from additional equipment. 3.5 Selection of proposed monitoring, reporting, and verification (MRV) plan requirements and approval process 3.5.1 Selection of MRV Plan Option EPA considered three alternatives for monitoring, reporting and verification of potential CO 2leakage at GS sites: do not require an MRV plan, require a universal MRV plan that applies to all GS sites, or require a site

- specif ic MRV plan. The three alternatives vary in stringency and specificity as described below. EPA outlines the advantages and disadvantages of each alternative and seeks comment on each alternative, as well as any alternatives not discussed. Under the first

alternative, EPA would allow GS facilities to report the amount of CO 2 sequestered without requiring an MRV plan. Under this alternative, the Agency would rely on published information and existing studies to assume that injected CO 2remains sequestered and would assume these results can be generalized to all GS projects. This alternative would impose the least burden on reporters. EPA notes that international guidelines on information collection and reporting efforts do not support this approach. Furthermore, EPA did not propose this approach because of the limited empirical data and the variability in geology and other conditions among GS facilities. The second alternative that EPA considered was a one

- size

- fits

- all MRV plan approach under which the A gency would prescribe specific monitoring technologies and quantification methods for GS facilities. The advantage of this approach is that all GS facilities would use the3

- 12

same monitoring technologies and methods. The disadvantage of this approach is that the geology and other conditions at potential GS facilities will vary from site to site and a one

- size

fits all approach may not provide the most effective monitoring strategy for all facilities. EPA notes that international guidelines on information co llection and reporting efforts do not support this approach. In addition, since the monitoring and testing plans implemented under the UIC program are necessarily site

- specific in nature, it would be difficult to prescribe a one

- size

- fits

all MRV plan that would complement and build upon the UIC program. This alternative would likely be the least cost effective and most burdensome approach for reporters. The third alternative, and the alternative that EPA is proposing, is that GS facilities be required to develop a site

- specific MRV plan and submit it to EPA for approval. Facilities would report CO 2injection until the final MRV plan has been approved. O nce a final MRV plan has been approved by EPA, GS facilities would implement the plan, including the reporting of the amount of CO 2that has been sequestered. The advantage of this approach is that it provides a flexible and cost

- effective option for repo rters and complements monitoring requirements under the proposed UIC Class VI rule. EPA recognizes that the rigorous proposed UIC Class VI requirements will provide the foundation for the safe sequestration of CO 2and should serve to reduce the risk of CO 2leakage to the atmosphere when finalized. An adequate MRV plan would be tailored to site

- specific conditions and be designed for each stage of the GS project. In addition, the MRV plan would allow for modification or adaptation of the plan based on mon itoring results. Although the risk of leakage at an appropriately selected and managed GS facility may be low, the MRV plan would ensure that if leakage occurs, the GS reporter would have an approved methodology for measuring the emitted CO 2 . If leakage occurs, the MRV plan would also provide a pro cess for revising the MRV plan if necessary
. It is important to recognize that this proposed rule is a data collection and monitoring proposal which does not directly address the potential human health and welf are, ground or surface water, ecosystem or geosphere impacts of GS. Therefore, the proposed rule does not address these potential impacts from CO 2leakage (e.g. requiring remediation or mitigation) as this is outside the scope of this proposal. EPA is pro posing that each submitted MRV plan must include at a minimum the four requirements described below: Step 1

– Assessment of Risk of Leakage: All potential pathways that may result in CO2 leakage have been identified and characterized and the risk of CO2 leakage at each pathway has been evaluated;3

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Step 2

– Strategy for Detecting and Quantifying CO2 Leakage to Surf ace: Potential pathways will be monitored according to the risk of CO2 leakage to ensure that any leakage to the surface will be detected and that leakage to the surface, should it occur, will be quantified according to a specified methodology; Step 3

- S trategy for Establishing Pre

- Injection Environmental Baselines: Environmental baselines against which the monitoring results will be evaluated have been established at potential leakage pathways; and Step 4

- Tailor Mass Balance Equation: Site

- specific va riables have been considered and developed for the mass balance equation provided in the regulatory text to calculate the amount of CO2 sequestered. Details regarding MRV requirements are provided by EPA in the preamble to this rule
. EPA also developed a monitoring plan technical support document that describes characteristics of a robust monitoring plan. 1 3.5.2 Background on MRV Approaches EPA has identified published studies and/or guidelines on monitoring programs that identify and quantify CO 2leakage from GS facilities. 2While the science of quantifying CO 2 leakagefrom GS facilities is evolving, it is generally recognized that, when properly planned and implemented, monitoring methods will be effective at detecting leakages. 3 , 4 Though the methodologies for detecting and quantifying leakage of CO 2 from GS facilities have not been standardized, EPA has concluded that a GS facility would be able to propose a site

- specific plan for leak detection and quantification under this rule based on the current availability of monitoring technologies. A wid e range of techniques for monitoring

1 Monitoring Plan s for Geologic SequestrationTSD ( see docket ID No. EPA

- HQ

- OAR

- 200 9

- 0 926) 2 Arts , R, O Eiken, A Chadwick, P Zweigel, L van der Meer, B Zinszner
. 2004
. “ Monito ring of CO2 injected at Sleipner using time

- lapse seismic data. ” Energy 29: 1383

- 1392 ; Wilson, M. and M. Monea (Eds.)
. 2004
. “IEA GHG CO2 Weyburn CO2 Monitoring and Storage Project,” Seventh International Conference on Greenhouse Gas Control Technologies, Vol. 3 ; Klusman, RW
. 2003
. “Rate Measurements and Detection of Gas Microseepage to the Atmosphere from an Enhanced Recovery Sequestration Project, Rangely, Colorado, USA,” Applied Geochemistry, 18, 1825

- 1838 ; IPCC. 2006. “2006 IPCC Guidelines for Greenhouse Gas Inventories.” Intergovernmental Panel on Climate Change, Simon Eggleston, ed. http://www.ipcc

- nggip.iges.or.jp/publ ic/2006gl/index.html; DOE/NETL. 2009. “Best Practices for Monitoring, Verification, and Accounting for CO2 Stored in Deep Geologic Formations
. ” U.S. Department of Energy, National Energy Technology Laboratory. 3 Benson, SM. 2006
. “Monitoring Carbon Dioxide Sequestration in Deep Geological Formations for Inventory Verification and Carbon Credits
. ” Society of Petroleum Engineers Paper 102833
. 4FutureGen Alliance. 2006. “Mattoon Site Environmental Information Volume.” December 2006.3

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sequestration of CO 2have been used for a number of years in other applications, including oil and natural gas production, natural gas storage, disposal of liquid and hazardous waste in deep geologic formations, groundw ater monitoring, and ecosystem research. 1 Some monitoring techniques such as seismic monito ring can detect the presence and location of CO 2in the subsurface, including both vertical and lateral spread, although the accuracy of seismic monitoring for quantifying the amount of CO 2 may be more limited than other approaches. Other techniques, suchas soil gas monitors or eddy covariance techniques, can detect, within a certain limit, leakage of CO 2from the confining system. Many of these technologies have excellent sensitivity, and have been shown to be able to detect relatively low concentration s of CO 2above background levels. The minimum leakage rate detectable is a function of parameters such as the volume of CO 2making its way to the surface, the size of the leak area, and the sensitivity of the monitoring device. Descriptions of the vario us monitoring technologies that could be deployed at a GS facility can be found in the general TSD to this proposal 2 . Additional information on GS monitoring technologies can also be found in the IPCC Guidelines for National Greenhouse Gas Inventories (2006), the API/IPECA Inventory Guidelines for CCS (2007), Department of Energy MVA Best Practices Manual (2009), and the International Energy Agency GHG R&D Programme monitoring tool website ( www.co2captureandstorage.info/co2monitoringtool ). 3.6 Selected Option The selected approach is tiered. First, a set of reporting requirements is proposed to cover all facilities that inject CO 2underground regardless of the purpose of injection. A subset of facilities that inject CO 2 and conduct geologic sequestration (GS) have additional requirements and include developing and implementing a Monitoring, Reporting, and Verification (MRV) plan which, once approved by EPA, would be used to verify injected CO 2 as sequestered and to quantify emissions in the event that injected CO 2 leaks, or is suspected of leaking, to the surface. Since the geology and conditions at each GS facility will vary widely, EPA proposes a case - by

- case MRV plan approval process. EPA will evaluate each MRV plan to ensure that the GS facility has an appropriate strategy in place to effectively quantify geologically sequestered

1 Benson, S and L Myer. 2002. “Monitoring to Ensure Safe and Effective Geological Sequestration of Carbon Dioxide.” Lawrence Berkeley Laboratory, Berkeley, California; Benson, SM. 2002. "Geologic Sequ estration of Carbon Dioxide." The Carbon Dioxide Dilemma, Promising Technologies and Policies, Proceedings of a Symposium, National Academy of Engineering, April 23

- 24, 2002, Washington, D.C., pp. 29

- 39. 2 Subpart RR General TSD ( see docket ID No. EPA

- HQ

- OAR

- 200 9

- 0 926)3

- 15

CO 2 . EPA will evaluate the adequacy of the methodologies proposed to detect and quantify leakage, including whether the chosen monitoring technologies are suitable for the type of leakage pathway and for the type of risk evaluated at that pathway. AlthoughMRV plan approval would be an inherently EPA function, the Agency is considering approaches and processes to streamline and facilitate external technical input in the development of specific evaluation criteria or guidelines, particularly at the outset of the program. EPA recognizes that an adaptive approach to the GS portion of this proposal will be necessary to take advantage of the experience gained in developing and implementing MRV plans and in complying with the proposed UIC Class VI requirements. E PA expects to update the guidelines and requirements of an MRV plan over time as technologies, methodologies, and scientific understanding of GS evolve; and the Agency believes that the site

- specific nature of the MRV plan enables the proposed approach to adapt and improve over time. 3.7 Alternative Scenarios Evaluated Given uncertainties related to project adoption and the costs of the reporting program
. EPA currently considered two other costs scenarios (one requires higher levels of monitoring and the other requires lower levels of monitoring relative to the reference cost scenario) in order to assess a range of cost estimates and economic impacts on affected entities. The monitoring options vary by which monitoring d evices would be used at a GS site and how often sampling and measurement would take place. Second, it is currently unknown how many projects conducting ER would choose to meet the definition of a GS facility and submit an MRV plan. As a result, three pote ntial scenarios of the quantity of facilities that would convert have been considered in the economic impact analysis to represent low, medium, and high outcomes. Finally, EPA considered two additional scenarios of the quantity of saline formation GS proj ect outcomes in the economic impact analysis to represent lower and higher outcomes. 3.8 Data Quality For this analysis, EPA gathered existing data from EPA, industry trade associations, states, and publicly available data sources (e.g., labor rates from the Bureau of Labor Statistics [BLS]) to characterize the processes, sources, sectors, facilities, and companies/entities affected. Costs were estimated based on the data collected and engineering analysis and models provided by EPA and its contractors. EPA staff and contractors provided engineering expertise, knowledge of existing facility conditions and a ctivities (e.g., typical labor hours required for developing QA plans and performing CO 2stream sampling), and an estimate of incremental activities required to comply with the rule.3

- 16

The most important elements affecting the data quality for this analysis include the number of affected facilities in the source category, the site by site variability of GS sites, process inputs and outputs (especially for monitoring procedures that involve a carbon mass balance), and the measurements that are already being ma de for reasons not associated with the rule (to allow only the incremental costs to be estimated). The background information was supplemented from numerous sources, including industry surveys from the U.S. Census Bureau, trade associations, and operating permits, for example. Information on measurements that are already made (and thus would not be associated with the rule) was obtained from discussions with industry representatives, knowledge gained from previous site visits, and other sources. The data co llected to characterize the facilities in this source category are judged to be of good quality and the best that is publicly available. Other elements affecting the quality of the data include estimates o f labor hours to perform specific activities, cost of labor, and cost of monitoring equipment. Estimates of labor hours were based on previous analyses of the costs of monitoring, reporting, and recordkeeping for other rules; information from the industry characterization on the number of units or process inputs and outputs to be monitored and engineering judgment. Labor costs were taken from the BLS and adjusted to account for overhead. Monitoring costs were generally based on cost algorithms or approaches that had been previously developed, reviewed, accepted as adequate, and used specifically to estimate the costs associated with various types of measurements and monitoring. The data quality associated with these elements of the cost analysis is analogous to the quality of data used in the development of numerous other Information Collection Requests for the different industrial source categories.4

- 17 SECTION 4 ENGINEERING COST ANA LYSIS 4.1 Introduction Usingavailable industry and EPA data to characterize conditions at affected sources , EPA estimated the costs of complying with this proposed rule . Incremental monitoring, recordkeeping, and reporting activities were then identified for each type of facility, and the associated costs were estimated. 4.2 Overview of Cost Analysis The costs of complying with the rule will vary from one facility to another, depending on the nature of the CO 2injection activities (GS or non

- GS), th e 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 capit al costs related to the implementation of monitoring activities outlined in the MRV plan for GS sites . All costs referred to in this section are reported in 2008 dollars. W e first provide a general overview of baseline reportingand GS activities. This is followed by detail on the cost components associated with this information collection; labor costs (i.e., the cost of labor by facility staff to meet the information collection requirements of the rule); and capital and operatin g and maintenance costs (e.g., the cost of purchasing and installing monitoring equipment or contractor costs associated with providing the required information). 4.3 Baseline Reporting 4.3.1 Introduction The Environmental Protection Agency is developing a set of proposed regulatory alternatives for reporting of CO 2injection and GS
. These rules can affect the number and type of monitoringequipment installed at the sites and the type and frequency of tests and surveys conducted at the sites. In creating new EPA regulations, a unit cost analysis and the t otal cost impact of each of the proposed regulations is required by federal law. This provides a basis for a full evaluation of the incremental costs of the proposed rule. The purpose of this section is to present the “activity baseline,” which describes the number and types of injection and GS sites that could be subject to the rule and the volume of CO 2injections that would be expected.4

- 18

Through the practice of geological sequestration, CO 2 can potentially be sequestered in underground formations world wide for thousands of years. Although commercial geologic sequestration of CO 2 has not yet begun in the U.S., several projects such as Sleipner in the North Sea, In Salah in Algeria, and Weyburn in Alberta have achieved success in recent years. CO 2at these sites is being sequestered, and technologies to monitor the process have proved effective. In the U.S., the Department of Energy is supporting approximately 25 sequestration pilot projects around the country. DOE also has plans to start a number o f relatively large scale pilot projects within coming years. Geologic sequestration in the U.S. will likely occur in a range of different geologic settings including: saline reservoirs, oil and gas reservoirs, coal seams, and others. For purposes of this economic analysis, the costs of specific aspects of geologic sequestration were specified on the basis of cost per well, per square mile, per sample, or other basis for each project. In addition, “type cases” were developed for each reservoir type includin g, in some instances, two sizes of injection projects for pilot and commercial

- size project scales. These include the typical parameters (e.g. number of monitoring wells and average well depth) for each type of project, allowing for estimation of total co st per project. In the cost analysis that appears in Chapter 5, a base case is created assuming relevant monitoring costs are only that which is required under the UIC rules. Then three regulatory alternatives for reporting from geologic sequestration sit es are evaluated in terms of technologies and practices and their costs.4

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4.3.2 Data Sources In order to evaluate the total costs in the U.S. of the proposed regulations, it is necessary to establish an activity baselineforecast of the sequestration activity to which the proposed regulation applies. The appropriate forecast for this analysis is the level of GS activity that would be expected even in the absence of future climate change legislation. While climate changelegislation is currently being debated in Congress, no legislation has been enacted. Even in the absence of national climate legislation, sequestration activity in the U.S. is planned including:

 Research and Development (R&D) projects,

 FutureGen Sequestr ation Site , and

 Commercial Sequestration Projects Related to State and Regional Incentive Programs (in part, funded by DOE) 4.3.3 Published Data on CO 2 S equestration Projects 4.3.3.1 Planned R&D Projects The Department of Energy has funded an extensive research effort into geologic sequestration in the U.S. The project is a collaborative effort with seven regional partnerships. The research effort is managed by the National Energy Technology Laboratory i n Morgantown, West Virginia. The program has two major components: Core R&D and Demonstration and Deployment. According to DOE, the goal is to “develop by 2012 systems that will achieve 90% capture of CO 2at less than a 10 percent increase in the cost of energy services and retain 99 percent sequestrationpermanence. ” 26 The field component of the sequestration research is being carried out by seven regional partnerships. These partnerships were formed in 2003 and represent consortia of private industry and government agencies. This effort is tasked with determining the most suitable technologies, regulations, and infrastru cture needs for capture and sequestration. There are three phases to the work being carried out by the partnerships:

 Characterization (2003

- 2005)

26 Direct Carbon Sequestration: Capturing and Storing Carbon Dioxide , Congressional Research Service, report RL33801, September, 2007.4

- 20

 Validation (2005

- 2009)

 Deployment (2009

- 2017) The Characterization Phase involved the geologic analysis that resulted in the development of a National Carbon Sequestration Database and Geographic Information System (NATCARB). The Validation Phase is currently active and involves such activities as v alidation of reservoir simulation methods, data collection for capacity and injectivity, and demonstration of monitoring technologies. Also being researched are well completion methods, operations, and abandonment approaches. The Deployment Stage involves the construction and operation of 8 significant sequestration projects. These projects are consistent with the Energy Independence and Security Act of 2007 (EISA), under Title VII, Sec. 702, which requires DOE to conduct at least 7 large scale sequestration field tests greater than one million tons of CO 2each. These tests a re designed to fully evaluate the potential for commercial scale operations in a range of geological settings. The tests are planned to have an injection period of up to four, followed by a lengthy monitoring period. This phase is designed to evaluate th e practical aspects of large scale injection over a prolonged period of time. A great deal of progress has been made in the areas of site characterization and monitoring. The next major phase of the DOE research effort is to provide funding support for a number of commercial scale sequestration operations with injections of up to one million tons per year. Sequestration Related to Stateand Regional Incentive Programs A number of states or regions have adopted or plan to adopt regulations to address carbon dioxide and/or greenhouse gas emissions. Most allow for regulated sources of emissions to meet compliance requirements through the use of offsets. Although geologic sequestration goals or criteria may not be specified in each case, the potential exists f or sequestration activities to become an accepted and more prevalent way of meeting greenhouse gas reductions. The programs or state legislation initiatives are generally in the early stages, and there is considerable uncertainty in terms of which projects will proceed, and on what schedule. ICF has researched the CSLF (Carbon Sequestration Leadership Forum) online database and the MIT online database in our analysis of non

- DOE projects. It should be noted, that in these databases,4

- 21

there are several proj ects for which startup date and/ or planned injection volumes are not specified. Laboratory Research Over the past several years, DOE and the regional partnerships have carried out an effort to assess and characterize the CO 2sequestration capacity andpotential of the U.S. This effort has resulted in the publication of a large amount of information on potential by geologic setting and basin or state. A large amount of GIS data has also been compiled on the geology of sequestration potential. In 2008, DOE published the most recent version of the NATCARB (National Carbon) Atlas. 27 This publication contains maps and data tables documenting their assessment of sequestration potential in the U.S. Much of the data behind the NATCARB atlas are either available in GIS form or will eventually be made available. 4.3.4 Hydrogeologic Settings Geologic sequestration may take place in a number of settings and lithologies. These include:

 Non

- basalt saline reservoirs

 Depleted gas fields

 Depleted and abandoned oil fields

 Enhanced oil recovery ( ER )

 Enhanced coalbed methane recovery For the purpose s of analyzing the GS rule, we will focus on the settings that are most likely affected by the rule, which includes saline reservoirs and oil and gas fields. 4.3.4.1 Non

- Basalt Saline Reservoirs Most significant sedimentary basins in the U.S. contain regionally significant saline formations that are potential sequestration reservoirs. These are typically sandstone lithologies with good porosity, containing formation waters of greater than 10,000 mg/L total dissolved

27 Carbon Sequestration Atlas of the United States and Canada , 2008, U.S. Department of Energy, National Energy Technology Laboratory, Morgantown, WV.4

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solids. Salinity may be as high as several times that of seawater. Thus, the water is unsuitable for drinking or agriculture. Saline reservoirs dominate the assessed potential of the U.S. and worldwide. In addition, because of thei r 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 potential (approximately 89 percent of t otal U.S. capacity). 28 It is very likely that saline reservoirs will play a prominent role in future geologic sequestration. Sequestration in saline reservo irs has been shown to be effective. The Sleipner field in the North Sea is the first commercial

- scale saline reservoir project. Carbon dioxide is separated from the gas stream and re

- injected into a reservoir at about 800 meters depth. The rate of injec tion is 2,700 tons per day or about one million tons per year. 29 It is anticipated that about 20 million tons will eventually be stored. At Sleipner, the plume has been monitored effectively. 30 DOE has extensively studied saline reservoirs for sequestration. Projects include the Frio Brine pilot in the Texas Gulf Coast and the Mount Simon Sandstone in the Illinois Basin. 31 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 2sequestration. These represent known structures that have trapped hydrocarbons over geologic time, thus proving the presence of an effective structure and seal above the reservoir. These fie lds have also been extensively studied, there is a large amount of well log and other data available, and the field infrastructure is already in place. This infrastructure could in some cases be utilized in sequestration. A potentially problematic aspect of using depleted fields for sequestration is the

28 2007 ICF assessment developed using DOE Atlas volumes and supplementing in several categories. 29 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. 30 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 Kingdo m and New York, NY, USA, 442 pp. 31 Carbon Capture and Storage: A Regul atory Framework for States

– Summary of Recommendations,, by Kevin Bliss, Interstate Oil and Gas Compact Commission, January, 2005.4

- 23

presence of a large number of existing wellbores, which can provide leakage pathways. Typically, oil fields are developed with a closer spacing than gas fields, resulting in a larger number of existing we lls per unit area than in gas fields. The In Salah Field in Algeria was the 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 from an abandoned gas reservoir scenario in which the gas field is no longer producing. 4.3.4.3 Enhance d Recovery of Oiland Gas Under certain reservoir and fluid conditions, CO 2can be injected into an oil reservoir in a process called miscible CO 2enhanced oil recovery. The effect of the CO 2is to mobilize the oil so that it can move more readily to theproduction wells. As the oil is produced, part of the injected CO 2is produced with the oil. This CO 2is then separated and re

- injected. In the U.S. most CO 2 ER

projects are located in the Permian Basin of West Texas, where projects have been in placefor several decades. The source of most of the CO 2 is natural CO 2 from several fields in Colorado and New Mexico. 32 Some of the injected CO 2is from gas processing or other sources. The current volume of CO 2injected for CO 2 ERis about 2.2 billion cubic feet per day. In 2005, CO 2 ERoperations produced approximately 237,000 barrels of oil per day in the U.S. About 180,000 barrels per day of that occurred in West Texas, with most of the rest produced in the Rockies, Mid

- Continent, and Gulf Coast. 33 The development of CO 2 ERprojects has resulted in a great deal of knowledge about the process and injection well and other technologies have matured and are well understood. In addition, it is estimated that more than 3,500 miles of high pressure (>1 ,300 psi) CO 2pipelines have been built to accommodate these operations. 34 At the Weybu rn Field in Saskatchewan, CO 2from the Dakota Gasification Facility in North Dakota is injected into an oil reservoir for ERand monitoring of CO 2sequestration. Over

32 The Economics of CO 2 Storage , Gemma Heddle, Howard Herzog, and Michael Klett, Laboratory for Energy and the Environment, Massachusetts In stitute of Technology, August, 2003. 33 Oil and Gas Journal, April 17, 200 6. 34 Carbon Capture and Storage: A Regulatory Framework for States

– Summary of Recommendations,, by Kevin Bliss, Interstate Oil and Gas Compact Commission, January, 2005.4

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the 25 year life of this project, it is expected that about 18 million tons of CO 2will be sequestered. 4.3.4.4 Enhanced Coalbed Methane Recovery CO 2can potentially be sequestered in coalbeds 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 coalbeds and coalbed methane now represents a significant percentage of U.S. natural gas production. Major coalbed methane production areas include the San Juan Basin of northwestern New Mexico and southwestern Colorado, the Powder River Basin of eastern Wyoming, and the Warrior Basin in Alabama. The concept of enhanced coalbed methane recovery is based upon the fact that coalbeds have a greater affinity for CO 2than methane. Thus, when CO 2is injected into the seam, meth ane is liberated and the CO 2is retained. This additional methane represents enhanced gas recovery. Depending upon depth and other factors, coalbeds may be mineable or unmineable. Because the process of mining the coal would release any stored CO 2 , onlyunmineable coals are assessed as representing permanent CO 2sequestration. 35 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 2sequestration. The sequestrationprocess is geochemical trapping, in which the CO 2reacts with silicates in the basalt to form carbonate minerals. 36 While research is being carried out on basalt, it is considered unlikely that any commercial scale sequestration will occur in the foreseeab le future due to the unconventional geology and likely difficulty in monitoring. The potential to sequester CO 2in organic shale formations is based upon the same concept as that of coal beds. CO 2will adsorb onto the organic material, displacing methane
. Gas shales have recently emerged as a major current and future source of gas production in the U.S. These include the Barnett Shale in the Fort Worth Basin, the Fayetteville and Woodford

35 Carbon Capture and Storage: A Regulatory Framework for States

– Summary of Recommendations,, by Kevin Bliss, Interstate Oil and Gas Compact Commission, January, 2005. 36 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. Loo s, and L. A. Meyer (eds.)], Cambridge University Press, Cambridge, United Kingdom and New York, NY, USA, 442 pp.4

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Shales in the Arkoma Basin, and the Appalachian Devonian Shale. These Devonian and Mississippian age organic shale formations represent tremendously large volumes of rock. To date little research has been done on enhanced gas recovery with organic shales. However, should it prove technically feasible, the U.S. coul d become one of the major areas worldwide for this type of sequestration. 4.3.5 Formation Capacity 4.3.5.1 Current DOE Assessment of Sequestration Potential Through the regional sequestration partnerships, DOE has develo ped a new national assessment of sequestration potential. The current assessment is summarized in Table 4

- 3 , in the column titled “2008 NATCARB.” As evaluated by ICF, the DOE Lower

- 48 total is 8,179 gigatonnes (Gt) of CO 2 . The range of uncertainy is 3, 508 to 12,850 Gt. Most of the assessment is attributed to saline reservoirs). This assessment is much larger than the prior assessments also shown on the table. 4.3.5.2 ICF Assessment of Sequestration Potential ICF has also developed a sequestration potential assessment by reservoir type. The results of this assessment are summarized in Table 4

- 1
. The Lower

- 48 assessed total is 3,375 Gt. The assessment includes estimates from DOE, and estimates for resources n ot convered by DOE. We have included a rough assessment of the Gulf of Mexico, as well as an estimate of shale gas sequestration potential. The ICF assessment can be broken out by state or region, and geologic category. Table 4

- 2 presents the ICF Lower

- 4 8 assessment by region. Sequestration capacity associated with depleted oil and gas fields occurs where there has been significant production, including Appalachia, the Gulf Coast, Mid

- Continent, and Rockies. Saline reservoir potential occurs in many are as of the country. Coalbed methane potential is concentrated in the large coalbed methane production areas such as New Mexico and Wyoming, while shale gas potential is associated with some of the new shale gas basins that have emerged over the past decad e.4

- 26

4 - 1 . Comparison of ICF Assessment of U.S. Sequestration Potential with Published Estimates Lower 48 Only Aug 2007 ICF 2008 2008 2008 2007 2006 2006 2005 ICF Lower-48 NATCARB NATCARB NATCARB NATCARB NATCARB Batelle IEA Low High Mid Category Gt CO2 % Gt CO2 Gt CO2 Gt CO2 Gt CO2 Gt CO2 Gt CO2 Gt CO2 Depleted Oil and Gas Fields Depleted Oil Reservoirs with EOR Potential 17 0.5% 7 12 0 1 Depleted Conventional Oil Fields 60 1.8% 13 0 1 11 Depleted Gas Fields 50 1.5% 9 35 35 subtotal 126 3.7% 138 138 138 82 29 47 46 Coal and Coalbed Methane Enhanced CBM 20 0.6% 17 0 1 Deep Unmineable Coal Seams 32 0.9% 11 30 60 subtotal 52 1.5% 73 94 84 86 28 30 60 Shale Formations 107 3.2% 0 0 0 0 45 0 1 0 1 Deep Saline Formations Onshore 1,187 2,130 7,950 5,040 1,907 6,595 2,730 2,730 Offshore 1,803 4 1,167 4,668 2,918 4 242 3 0 1 900 subtotal 2,990 88.6% 3,297 12,618 7,958 2,149 6,595 3,630 2,730 Onshore Saline-Filled Basalt 100 3.0% 84 100 240 0 Lower-48 Total 3,375 100.0% 3,508 12,850 8,179 2,401 6,797 3,947 2,836 Alaska 84 84 U.S. 8,263 2,485 Notes: 1 No covereage in assessment. 3 Atlantic Offshore Only 2 Represents only a partial assessment of US. 4 GOM, Pacific and Atlantic Offshore4

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Table 4 - 2 . Summary of ICF SequestrationCapacity Assessment Gigatonnes of CO2 Storage Depleted Depleted Region (Markal Region Name) EOR Oil Fields Gas Fields Coals Shale Saline Basalt Total California (California) 1.2 8.0 1.8 0.0 0.0 161.1 0.0 172.2 Eastern Gulf Coast (East South Central) 0.2 1.1 1.3 1.9 28.0 103.2 0.0 135.6 Gulf of Mexico 1.5 5.5 8.4 0.0 0.0 800.0 0.0 815.3 Midwest (East North Central) 0.3 1.3 0.2 3.3 12.7 167.1 0.0 184.9 Northern Midcontinent (West North Central) 0.7 5.9 2.1 0.2 0.0 57.8 0.0 66.7 Northern Rockies (Mountain 1) 0.7 4.6 2.5 17.7 0.0 665.6 33.3 724.4 New England (New England) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Northeast (Middle Atlantic) 0.0 0.3 0.6 0.1 12.0 9.0 0.0 22.0 Pacific NW (Pacific; Lower 48 Onshore Part) 0.0 0.0 0.0 2.3 0.0 53.0 66.6 121.9 Pacific Offshore (Pacific; L48 Offshore) 0.0 1.2 0.0 0.0 0.0 100.0 0.0 101.3 Southern Rockies (Mountain 2) 1.4 3.3 6.0 19.6 0.0 36.5 0.0 66.8 Southeast (South Atlantic) 0.1 0.2 0.7 0.9 19.0 378.0 0.0 398.9 Texas and S. Midcontinent (West S. Central) 10.4 28.0 26.1 5.7 35.0 459.5 0.0 564.6 Total 16.5 59.5 49.7 51.6 106.7 2,990.6 99.9 3,374.6 Offshore (Gulf, Atlantic, Pacific) 1.5 6.7 8.4 0.0 0.0 1,186.6 0.0 1,203.3 Onshore 15.1 52.8 41.2 51.6 106.7 1,804.0 99.9 2,171.3

4.3.6 Geologic Sequestration Rule Activity Baseline Based upon the above information on what is anticipated for R&D projects, FutureGen, and state programs, an activity baseline forecast of sequestration activity has been developed. Because of theuncertainty in which existing ER project might come under subpart RR, three scenarios have been created and are shown as Table 4

- 5 to 4

- 7. The first scenario assumes that no existing CO 2ER projects choose to report as GS facilities. The second scenario assumes that all CO 2ER projects from anthropogenic sources (7 million metric tons per year coming primarily from natural gas processing plants) choose to report as GS facilities. 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 GS facilities. This third scenario adds up to 23.4 million metric tons per year injected of new (i.e., ignoring recycled volumes) CO 2 . The most comprehensive source of information on U S ER projects is the annual survey conducted by the Oil and Gas Journal. The 105 projects listed in the Oil and Gas Journal 2007 ERsurvey were grouped by CO 2source type

– natural or anthropogenic. CO 2use was allocated to the projects supplied by each s ource based on oil production. Anthropogenic sources were well defined for ERprojects in Michigan (Antrim Gas Processing Plant), Wyoming/Colorado4

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(LaBarge/Shute Creek Gas Processing Plant), central Oklahoma (Enid Fertilizer Plant) and Kansas (US Energy Pa

rtners, Russell Kansas Ethanol 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 Louisiana based on geographic proximity and information in published literature. Anthropogenic CO 2 from the Val Verde Gas Plant in Texas is mixed with CO 2from natural sources and distributed to several fields in the Permian Basin so there was not a clear delineation of which projects were serv ed by anthropogenic gas from the Val Verde plant. To estimate the number of facilities served by Val Verde, the total CO 2use in the Permian Basin from natural sources and Val Verde production was summed and the percent of Val Verde production was prorated among the 66 projects in the Permian Basin. Val Verde CO 2production represents 5.4 % of the total CO 2used in the Permian Basin, therefore , the equivalent of approximately 4 projects in the Permian Basin are estimated to use anthropogenic CO 2f

rom Val Verde. For this analysis 2007 CO 2production data for natural and anthropogenic sources was taken from the (1990

- 2007) Inventory of U.S. Greenhouse Gas Emissions and Sinks, and totaled 2.1 bcf/day which differs from the published DOE estimate of 2
. 6 bcf/day used in the threshold analysis. Based on the number of projects active in 2007 (latest data available), anthropogenic sources provide approximately 18% of the mass of CO 2used in ERprojects in the US, and represent approximately 27 % of the CO 2 ERprojects. These projects result in the additional production of more than 13 million barrels of oil annually. If only ERprojects supplied by anthropogenic sources opted into the reporting program approximately 28 projects would be included. If all th e ERprojects supplied by anthropogenic sources, and half of the projects using natural sources opted into the reporting program approximately 67 projects would report, representing 1.2 bcf/day (23.4 million metric tons per year) or 59% of all CO 2 ERuse.4

- 29

Table 4 - 3 . Pro - forma Project Characteristics (ER Scenario: No Additional ER Opt In)
Baseline Forecast, # of Projects & Total Volumes Per Project Averages for Economic Analysis (taken from ICF's UIC Class VI work)

Type Number

of Projects Operating in 2012 Metric Tons

CO 2Injected per Year Project

Count Monitoring

Wells/ Project Monitoring

Well Depth Ft Footage all

monitoring wells Squar e

Miles/ Project Producing

Oil or Gas Wells/ Project Project

Life Metric Tons

CO 2 Injected per Year / Project Known R&D ER 1 1,100,000 1 18 5,700 102,600 17.6 144 7 1,100,000 Known R&D Saline 6 2,720,000 1 3 8,000 24,000 1.7 0 7 750,557 Future R&D Saline 2 1,500,000 1 3 8,000 24,000 1.7 0 7 750,557 Known Commercial CO 2Injection Facilities (No GS) 5 3,300,000 1 8 5,700 45,600 8.0 64 20 500,000 Known Commercial Saline 0 0 1 12 8,000 96,000 11.6 0 20 1,842,885 GS Facilities (ER opt in) 0 0 1 8 5,700 45,600 8.0 64 20 500,0004

- 30

Table 4 - 4 . Pro - forma Project Characteristics (ER Scenario: Anthropogenic ER Only Opt In)
Baseline Forecast, # of Projects & Total Volumes Per Project Averages for Economic Analysis (taken from ICF's UIC Class VI wo rk)

Type Number

of Projects Operating in 2012 Metric Tons

CO 2Injected per Year Project

Count Monitoring

Wells/ Project Monitoring

Well Depth Ft Footage all

monitoring wells Square

Miles/ Project Producing

Oil or Gas Wells/ Project Project

Life M etric Tons

CO 2 Injected per Year / Project Known R&D ER 1 1,100,000 1 18 5,700 102,600 17.6 144 7 1,100,000 Known R&D Saline 6 2,720,000 1 3 8,000 24,000 1.7 0 7 750,557 Future R&D Saline 2 1,500,000 1 3 8,000 24,000 1.7 0 7 750,557 Known Commercial CO 2Injection F acilities (No GS) 5 3,300,000 1 8 5,700 45,600 8.0 64 20 500,000 Known Commercial Saline 0 0 1 12 8,000 96,000 11.6 0 20 1,842,885 GS Facilities (ER opt in) 16 6,972,040 1 8 5,700 45,600 8.0 64 20 500,0004

- 31

Table 4 - 5 . Pro - forma Project Characteristics ( ERScenario: Anthropogenic plus One - half Other ER Opt In )
Baseline Forecast, # of Projects & Total Volumes Per Project Averages for Economic Analysis (taken from ICF's UIC Class VI work)

Type Number

of Projects Operating in 2012 Metric Tons

CO 2Injected per Year Project

Count Monitoring

Wells/ Project Monitoring

Well Depth Ft Footage all

monitoring wells Square

Miles/ Project Producing

Oil or Gas Wells/ Project Project

Life Metric Tons

CO 2 Injected per Year / Project Known R&D ER 1 1,100,000 1 18 5,700 102,600 17.6 144 7 1,100,000 Known R&D Saline 6 2,720,000 1 3 8,000 24,000 1.7 0 7 750,557 Future R&D Saline 2 1,500,000 1 3 8,000 24,000 1.7 0 7 750,557 Known Commercial CO 2Injection Facilities (No GS) 5 3,300,000 1 8 5,700 45,600 8.0 64 20 500,000 Known Commercial Saline 0 0 1 12 8,000 96,000 11.6 0 20 1,842,885 GS Facilities (ER opt in) 48 23,543,741 1 8 5,700 45,600 8.0 64 20 500,0004

- 32

4.3.6.1 Sources of Uncertainty The activity baseline forecast of sequestration activity represents our best estimate of what will likely occur in the absence of national climate change legislation. As with any forecast, there are sources of uncertainty. Categories of uncertainty inclu de:

 Number and timing of R&D projects and number of years of injection

 Number and timing of FutureGen projects and number of years of injection

 Number and timing of State Incentive projects and number of years of injection

 Average injection rates

 Number of ER projects that will be covered Of the three categories of project, the least uncertainty is associated with the R&D projects. These projects have been funded and are expected to proceed at close to the announced schedule. The DOE Future Gen project site has been chosen (Illinois) but there is still uncertainty about timing and injection volumes. Given the number of state and regional initiatives underway it is very likely that projects related to state incentives will be initiated. As di scussed previously, there are a number of projects for which either timing or injection volumes were not provided and were estimated by ICF. The largest uncertainty over the timeframe of the activity baseline is what may occur at the national level in term s of climate change legislation. However, any costs associated with potential future national climate policy cannot be attributed to this subpart currently under consideration. The activity baselinepresented in this document is expressly for the purpose o f evaluating the costs of the subpart RR proposalunder existing climate change policies.4

- 33

4.4 Reporting Costs 4.4.1 Introduction The purpose of this section is to present the unit cost estimates for the equipment and services that might be required to comply with the CO 2Injection and GS Reporting rule and the total incremental annual cost of compliance. Abase case i s created assuming relevant monitoring costs are only that which is required under the UIC rules. Then three regulatory alternatives for reporting from geologic sequestrationsites are evaluated in terms required technologies and practices and their costs
. 4.4.2 Cost Assumptions and Methodology The costs reported hereinclude capital and operating and maintenance (O&M) including labor costs. They are based on hypothetical or pro

- forma sites for various types of projects such as sali ne formation R&D GS projects, saline formation commercial GS projects, and ER GS projects. The geologic and engineering assumption for these pro

- forma projects are the same as used by the EPA Office of Water in the proposed Federal Requirements under the Underground Injection Control Program for Carbon Dioxide Geologic Sequestration Wells, or the UIC Class VI proposalfor CO 2injection wells 37 for CO 2injection wells. The Office of Water is currently updating the cost analysis used for the UIC Class VI proposal in preparation for the final rule. Once that data has been updated and made available, thi s cost analysis will be updated accordingly. The costs represent price levels in mid 2009, are presented in 200 8 dollars. There werevery steep increase s in the cost s of equipment, materials and labor used in the construction of all types of energy infras tructure including power plants, pipelines and oil and gas wells from 2004 through 2008
. With the drop of oil and natural gas prices in the Fall of 2008 and the general economic decline around the world the costs of equipment, materials and labor have mod erated somewhat. 4.4.2.1 Primary Data Sources for Costs Table 4

- 8 summarizes the major data sources for costs used by EPA in the analysis geologic sequestration costs . A wide range of cost data is available from industry survey publications for costs typically incurred in oil and gas drilling and production operations. This includes drilling and completion costs by region and depth interval, equipment and operating

37 The UIC rulemaking that would create a Class VI well class for injection of CO 2 for the purposes of GS was propose d July 25, 2008. (73 FR 43492)4

- 34

costs, and pipeline costs. Data are available for both the U.S. and C anada. 38 39 40 41 The cost of drilling and equipping wells represents a large component of sequestration costs. The costs of additional equipment or material specifications for CO 2injection 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 profession al performed by the American Association of Petroleum Geologists (AAPG) and the Society of Petroleum Engineers (SPE) . The number of hours required to carry out the various characterization or monitoring activities are ICF estimates that have been reviewedby the EPA workgroup. No comprehensive source has been identified that provides detailed summaries of the full range of sequestration project cost components. Estimates of the costs of monitoring equipment, the number of stations required, and the cost of ongoing monitoring are based upon analysis of available literature and recent presentations by governmentand academic research groups and quotations from vendors . Some specific monitoring costs were obtained at a recent industry meeting sponsored by theGroundwater Protection Council
. 42

38 Joint Association Survey of Drilling Costs , American Petroleum Institute, Washington, DC. http://www.api.org/statistics/accessapi/api

- reports.cfm 39 PSAC Well Cost Study

– 2008, Petroleum Services Association of Canada, October 30, 2007. 40 Oil and Gas Lease Equipment and Operating Costs , U.S. Energy Information Administration, 2006, http://www.eia.doe.gov/pub/oil_gas/natural_gas/data_publications/cost_indices_equipment_production/current/costs tudy.html 41 Oil and Gas Journal Pipeline Cost Survey , Oil and Gas Journal Magazine, September 3, 2007. 42Ground Water Protection Council Meeting, New Orleans, LA, January, 16, 2008.4

- 35

Table 4 - 6 . Major Sources of Geologic Sequestration Cost Information Source Cost Categories API Joint Association Survey of Drilling Costs Drilling costs in the U.S. for oil, gas, and dry holes by depth interval EIA Oil and Gas Lease Equipment and Operating Cost Survey Surface equipment costs, annual operating costs, pump costs Pipeline Prime Mover and Compressor Costs (FERC) Pumps 2008 Petroleum Services of Canada Well Cost Study (PSAC) Drilling costs, plugging costs, logging costs Oil and Gas Journal Report on Pipeline and Cost Data Reported to FERC Pipeline costs per inch-mile Land Rig Newsletter Onshore rig day rates/ well cost algorithms New Orleans Sequestration Technology Meeting, January, 2008 Monitor station costs in several categories; seismic costs FutureGen Sequestration Site Submittals Monitoring station layout/number of stations Preston Pipe Report Casing and tubing costs Hourly Labor Rates U.S. Bureau of Labor Statistics Selected Presentations and Papers (see below) Sensor costs, monitoring costs, number of stations, seismic costs Significant Papers and Presentations With Cost Data Benson, "Monitoring Protocols and Life Cycle Costs for Geologic Storage of Carbon Dioxide", Sept., 2004 IEA Greenhouse Gas Programme Report PH4/29, "Overview of Monitoring Requirements for Geologic Storage Projects, Nov., 2004. Hoversten, "Investigation of Novel Geophysical Techniques for Monitoring CO2 Movement During Sequestration," Oct., 2003. Dahowski, et al, " The Costs of Applying Carbon Dioxide Capture and Geologic Storage Technologies to Two Hypothetical Coal to Liquids Production Configurations: A Preliminary Estimation," Pacific NW National Laboratory, September, 2007. The assumed capital costs and the annual operating cost of the various monitoring technologies whose application mig ht be affected by the GS Reporting rule are shown in Table 4

- 9 and 4

- 10. The capital costs are annualized using a capital recovery factor of 0.186 for projects lasting 7 years and 0.094 for projects lasting 20 years. The annual O&M costs are added to theannualized capital costs to determine total annual direct costs. To this is added a 20 percent overhead and general and administrative cost factor to obtain total annual costs. These are then divided by the amount assumed to be injected each year in the pro - forma project to arrive at total costs per metric ton of CO 2injected. These per

- ton costs are then used to estimate total annual costs for the level of injection expected in the activity baseline.

4.4.3 Monitoring, Reporting, and Verification (MRV) Plan Requirements and Approval Process There are two types of sites that will report under Subpart RR, injection facilities and a subset of injection facilities conducting GS (i.e. GS facilities) . All sites will incur the periodic sampling and testing costs, however only GS facilities will incur the monitoring plan related4

- 36

costs. EPA proposes that GS facilities must develop an MRV plan, submit it to EPA for approval, and implement it once approve d by EPA to report the amount of CO 2that has been sequestered. EPA is propos ingthat each submitted MRV plan must include at a minimum the four requirements described below
. Step 1

– Assessment of Risk of Leakage: All potential pathways that may result i n CO 2 leakage have been identified and characterized and the risk of CO 2 leakage at each pathway has been evaluated; Step 2

– Strategy for Detecting and Quantifying CO 2Leakage to Surface: Potential pathways will be monitored according to the risk of CO 2l eakage to ensure that any leakage to the surface will be detected and that leakage to the surface, should it occur, will be quantified according to a specified methodology; Step 3

- Strategy for Establishing Pre

- Injection Environmental Baselines: Environm ental baselines against which the monitoring results will be evaluated have been established at potential leakage pathways; and Step 4

- Tailor Mass Balance Equation: Site

- specific variables have been considered and developed for the mass balance equationprovided in the regulatory text to calculate the amount of CO 2sequestered. Table 4 - 7 . Unit Cost of Relevant Continuous and Periodic Monitoring Technologies

Item Capital Cost to

Establish Environmental Baseline Capital Cost for Construction and Equipment Operating Cost Deep Monitoring Wells (into or right above injection zone) $200 lab fee per sam ple

plus $1,000 to collect. 4 samples per well is $4,800 per well. $20,000 + $5,000/well for

design, $10,000 per well for surface disturbance, $165
- $200 per foot to build, $20,000 for equipment Annual O&M costs are $25,000 + $3/ft per well per

year CO 2 Flow Meters on Producing Oil and Gas Wells NA $10,000/ oil well Annual O&M costs are $500 per well per year CO 2 Flow & Gas Composition Meters on Producing Oil and Gas Wells NA $50,000/ oil well Annual O&M costs are $2,500 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 calculations4

- 37 Item Capital Cost to

Establish Environmental Baseline Capital Cost for Construction and Equipment Operating Cost 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. $100,000 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 $10,0 00 per square mile. Airborne survey costs $250 per linear mile. Assuming interline spacing of 200 - 250 feet, a square mile would take about 25 passes and cost $6,250. Plus mobilization costs of $5,000 per site. Period ic airborne survey to detect surface leaks. Works best where vegetation is sparse. NA No construction costs, but planning and quality assurance costs would add $10,000 per square mile. Airborne survey costs $250 per linear mile. Assuming interline spacing of 200 - 250 feet, a square mile would take about 25 passes and cost $6,250. 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 water table. 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

- 38

Table 4 - 8 . Unit Cost of Relevant Episodic Monitoring Techno logies (That may be

employed after a subsurface leak is detected)
Detection Method Method of

Quantification Estimate of Unit Cost

for Leak Quantification Cost per Episode Probability

of Detection Method Deployment Additional

Annual Cost per Project for Leak Quantifica tion 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 $100,00 per square

mile per survey. Leak volume estimation process 160 hours @$110.62/hr. $117,698 1.0% $1,177

Surface leak detected by air, soil or water table monitoring Tenting of area

to estimate leak volume Assume 30 minutes

per tent survey location by two technicians @$100/hr each plus mobilization costs of $5,000. If 640 locations are surveyed (one per acre), cost is $69,000 per square mile. Leak volume estimation process 80 hours @$110.62/hr. $77,849 1.0% $778

Total per Year 2.0% $1, 955 Note: Assumes survey for leak occurs over one square mile area in each episode. Project's area is 10 square miles.

4.5 MonitoringTechnologies Deep Monitoring Wells Deep monitoring wells are typically drilled to monitor the deepest perm eable zone above the caprock. Downhole instrumentation can be used to monitor pressure, temperature, and conductivity/salinity. Alternatively, U

- tube devices can be used to retrieve p ressurized samples for laboratory testing. Other types of monitoring from wells include micro

- seismic, cross

- well resistivity, and vertical seismic profiling.4

- 39

CO 2 Flow Meters on Producing Oil and Gas Wells Meters, probably located after the wellhead separ ator, that continuously measure the pressure, temperature and flow rate of the gas from a well. The composition of the gas is analyzed periodically using a gas chromatograph to determine percent CO 2concentration. The mass of CO 2passing through the wellhe ad can then be calculated 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 c omposition of the gas from a well. The mass of CO 2passing through the wellhead can then be calculated from the measured quantities. This differs from the item directly above in that the chemical composition of the gas is being measured automatically by th e meter itself rather through periodically obtaining a sample and sending it to lab for analysis. Periodic Sampling and Testing of Injected Fluid All injection and GS facilities will incur periodic sampling and testing costs. To estimate the costs, we have applied similar assumptions that were used in Subpart OO for sampling and testing of industrial gases. For example, we have assumed that it take s 12 labor hours to contact an onsite laboratory or offsite vendor and develop a plan; to collect and send the sample to an onsite or offsite laboratory; and to provide data invoice if sent offsite. Furthermore, we have assumed that it costs approximatel y $500 per sample to collect and conduct the test of chemical composition. In addition to these costs, GS facilities will additionally incur the costs described in this rule. Seismic Surveys Seismic data acquisition involves the generation and detection of sound waves to evaluation conditions in the subsurface. Periodic acquisition of seismic data can be used to detect subsurface CO 2movement within and outside of the reservoir. Digital Col or Infrared Ortho

- imagery and Hyper

- spectral Imaging Digital color ortho

- imagery and hyper

- spectral imaging are airborne remote sensing technologies that are used to detect changes in vegetation resulting from CO 2 leaks. Hyperspectral sensors look at obje cts using electromagnetic spectrum. The object is to detect a4

- 40

specific spectral signature that is known to result from CO 2uptake. The advantage of these methods is that they can efficiently cover a large surface area. Airborne Survey (LIDAR) LIDAR (Li ght Detection and Ranging) involves the transmission of light from an instrument to a target and the recording of the reflected light to determine some property of the target. Differential Absorption LIDAR (DIAL) uses two wavelengths of laser to measure C O 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. Airborne Survey (CO 2 Detectors) CO 2detectors are commercially available for short closed

- path and short open

- path (point) measurements and long open

- path (radial line) measurements. Similar detectors have been integrated into stationary , mobile , and airborne monitoring packages that are commonly used in combination with high

- resolution global positioning system (GPS) to detect and quantify methane leaks in areas with road access. While these packages have not been widely tested for CO 2 , various type s of CO 2monitors are commercially available and could be used in these applications. Such monitoring techniques are likely the leading candidates for monitoring plan applications because of their low cost and high reliability. The technologies include i nfrared gas analyzers(IRGAs, including Fourier transform infrared (FTIR) and non

- dispersive infrared (NDIR) analyzers), tunable diode lasers (TDLs), cavity ring down techniques, and others. The sample path can range from 10 cm to 1 km, by reflecting a la ser beam off retro

- reflecting mirrors. These devices measure the gas concentration, and, when packaged with measurements of wind speed and wind direction, they measure the total gas flow. Eddy Covariance Eddy Covariance is a technique whereby high frequency measurements of atmospheric CO 2concentration at a height above the ground are made by an infra

- red gas analyzer along with measurements of micro

- meteorological variables such as wind velocity, direction, humidity, and temperature. Integration of th ese data allows derivation of the net CO 2flux over the upwind footprint, typically square meters to square kilometers in area. Soil Zone Monitoring with Accumulation Chamber (AC)4

- 41

Surface CO 2flux is measured using an accumulation chamber. The chamber is made of stainless steel with an open bottom and is placed at the sampling location. It may be placed either directly on the ground or on a collar installed in the ground surface. The air is circulated through the AC and measured with and infra

- red gas an alyzer. Vadose Zone Monitoring The vadose zone is the relatively shallow zone beneath the soil zone that is not saturated with groundwater. Small diameter probes are installed in the zone and samples are taken. The CO 2concentration of air samples taken in this zone can be measured by and infrared gas analyzer
. Monitoring Wells for Water Table Sampling Shallow monitoring wells may be used to measure the properties of ground water. Such wells are typically no deeper th an several hundred feet. Estimating Leak Volumes after a Leak is Detected The monitoring program for GS facilities may detect subsurface leaks and it will be necessary to estimate the volume of leaks to the surface to comply with the reporting requirements of this rule. Each site operator will have to devise suitable techniques taking into account the geology of the sites, the location and nature of the potential leaks and the performance characteristics of available monitoring and measurement technologies. It is expected that these estimates may include engineering estimates as well as some direct measurement and may have a wide margin of uncertainty. It is expected that site characterization and screening will lead to selection of sites that are suitabl e for long

- term sequestration and that incidences of leaks to the surface may be infrequent at well

- selected and well

- managed sites. The cost estimates presented here for subsurface leak quantification assume a two percent chance in one year that any give n site will have to implement the leak quantification strategy described in the site’s MRV plan. There are no operating statistics for CO 2 GS from which to draw any citable conclusions on how often leaks to the surface maybe detect ed, therefore a very co nservative estimate was used in order to estimate the potential cost.4

- 42

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 surfac e. Quantification is presumed to be done using engineering calculations supplemented, when technically feasible, by direct observation/measurement using, for example, a 3

- D seismic survey over the area of the suspected leak. The seismic survey might be ab le to detect the location, size and density of the CO 2plume formed by the leak in one or more containment zones located above the injection zone. The volume of the leak also might be estimated using a reservoir simulation model of the containment zone calibrated to the pressure readings of the monitoring wells surrounding the location of the leak. In other words, different volumes of leaks would be tested in the reservoir simulator to find which leak volume most closely matches the pressure history observ ed 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 estimateleak 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 intro duced into the tent and allowed to escape through a chimney at the top of the tent. By measuring the concentration of CO 2in the gases leaving the chimney it is possible to measure the amount of CO 2leaving the ground in the area of the tent. The tent wou ld have to be moved to many locations and the process repeated to get a representative sample over the entire area of the leak. It also would benecessary to correct the readings for natural CO 2fluxes into and out of the soil. Many of the leak detection methods for onshore GS sites can be applied to sub

- seabed sites. These include monitoring of the injection well and monitoring of the subsurface CO 2 plume: active seismic, passive seismic, sensors in deep monitoring wells, and reservoir modeling. Thoughthere will be differences in monitoring approaches at sub

- seabed GS sites for leak detection and quantification, the cost estimates are assumed to be comparable. Labor Rates The cost of labor for many of the cost items in Table 4

- 9 and 4

- 10 and for General and Administrative Costs are based on Society of Petroleum Engineers ( SPE ) 2008 annualsalary survey . 43 The average salary for a petroleum reservoir engineer with 15 years of experience is

43 For SPE survey of petroleum engineers see http://www.spe.org/spe

site/spe/spe/career/salary_survey/08SalarySurveyHighlights.pdf4

- 43

$143,800 . Applying a 1.6 fringe and overheadfactor yields an hourly burdened labor cost of $110.62 per hour. The unit costs values shown in Table 4

- 9 and 4

- 10 reflect the cost of goods and services that would be purchased by the entity which owns the GS facility. That entity would have additional General and Administrative Costs (G&A) on top of those direct cost s for goods and services. These G&A cost are assumed to 20 percent of the direct costs. 4.5.1 Cost Scenarios There are three regulatory alternatives (low, medium [or reference], and high) presented in Table 4

- 11 in terms of which moni toring devices would be used at a GS facility and how often sampling and measurement would take place. Because each GS facility will have unique characteristics that may result in the selection of different monitoring techniques, the application of the mon itoring devices are indicated as percents of sites that would be expected to use each device or technique. Also shown in Table 5

- 4 are the portions of facilities that expected to be required to use the device or technique under the UIC Class VI permits an d under UIC Class II permits. The cost impacts of the Rule RR are estimated as the monitoring and measurement requirements above and beyond the UIC Class II requirements. 44

44For the purposes of this proposed rule, costs incremental to Class II requirement s were estimated for ER projects conducting GS and costs incremental to the proposed Class VI requirements were estimated for all other GS projects.4

- 44

Table 4 - 9 . Assumptions for Application of Technologies by Regulatory Alternative Saline, Abandoned Oil & Gas Fields: Starting Point is UIC Class VI Requirements ER plus GS : Starting Point is UIC Class II Requirements
Under UIC Class VI Lowest

Level RR Alternative Middle

Level RR Alternative Highest

Level RR Alternative Under

UIC Class I I Lowest Level RR Alternative Middle

Level RR Alternative Highest

Level RR Alternative Fraction Projects 100% 100% 100% 100% 0% 100% 100% 100% Deep Monitoring Wells (into or right above injection zone) Frequency

(months) Continuous Continuous Continuous Continuous Continuous Continuous Continuous Fraction Projects 0% 0% 0% 0% 0% 100% 100% 100% CO 2 Flow Meters on Producing Oil and Gas Wells Frequency

(months) Continuous Continuous Continuous Fraction Projects 0% 0% 0% 0% 0% 0% 0% 0% CO 2 Flow & Gas Composition Meters on Producing Oil and Gas Wells Frequency

(months) Continuous Continuous Continuous
Fraction Projects 100% 100% 100% 100% 100% 100% 100% 100% Periodic Sampling and Testing of Injected Fluid Frequency

(months) 3 3 3 3 3 3 3 3 Fractio n Projects 0% 0% 100% 100% 0% 0% 0% 0% Estimation of Fugitive Emission from Surface Facilities Frequency

(months) 12 12 12 12 12 12 12 12 Fraction Projects 25% 25% 25% 25% 0% 25% 25% 25% Periodic Seismic Surveys Frequency

(months) 60 60 60 60 60 60 60 60 Fraction Projects 0% 0% 50% 50% 0% 0% 50% 50% Periodic Digital Color Infrared Orthoimagery (CIR) or Hyperspectral Imaging to detect changes to vegetation. Frequency

(months) 12 12 12 12 12 12 12 124

- 45

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

(continued) Saline, Abandoned Oil & Gas Fields: Starting Point is UIC Class VI Requirements ER plus GS : Starting Point is UIC Class II Requirements Under UIC Class VI Lowest

Level RR Alternative Middle

Level RR Alternative Highest

Level RR Alternative Under

UIC Class I I Lowest

Level RR Alternative Middle

Level RR Alternative Highest

Level RR Alternative Fract ion Projects 0% 0% 50% 50% 0% 0% 50% 50% Periodic LIDAR airborne survey to detect surface leaks. Works best where vegetation is sparse. Frequency

(months) 12 12 12 12 12 12 12 12

Fraction Projects 25% 25% 25% 100% 0% 25% 25% 100% Eddy covariance measurement from permanent towers to detect surface leaks. Frequency

(months) Continuous Continuous Continuous Continuous Continuous Continuous Continuous Continuous

Fraction Projects 0% 0% 100% 100% 0% 0% 100% 100% Soil zone monitoring (sampling gas from accumulation chambers) Frequency

(months) 12 12 12 3 12 12 12 3 Fraction Projects 0% 0% 10 0% 100% 0% 0% 100% 100% Vadose zone monitoring wells to sample gas above water table. Frequency

(months) 12 12 12 3 12 12 12 3 Fraction Projects 0% 0% 100% 100% 0% 0% 100% 100% Monitoring wells for samples from water table. Frequency

(months) 12 12 12 3 12 12 12 34

- 46

4.6 Projecting and Discounting National Costs The cost per project is computed by applying the cost algorithms (Table 4

- 5 and 4

- 8) to the “pro

- forma” characteristics assume for each type of project(Tables 4

- 3 to 4

- 5) , “Pro

- form Project Characteristics.” The results for cost per project appear in theleft

- hand side of Table 4

- 10 for the no additional ERopt inactivit y baseline scenario. Table 4

- 11 shows the results for the anthropogenic ER opt in o nlyac tivity scenario. Table 4

- 12 shows the results for the anthropogenic plus one half of other ER op t in activity scenario.4

- 47

Table 4 - 10 . Summary of Cost Impacts: Activity Baseline with No Additional ER Opt In
Environmental Baseline Periodic Monitoring Type Capital Costs Annualized

Capital Costs Capital Cost Annual Operating Cost Annualized Capital

and Contractor Costs Annual

Episodic Monitoring Costs Overhead and

G&A Total Annual

Costs Per Project Known R&D ER $0 $0 $1,286 $1,880 $2,119 $0 $424 $2,542 Known R&D Saline $7,438 $1,380 $4,122,722 $159,505 $924,489 $0 $185,174 $1,111,043 Future R&D Saline $7,438 $1,380 $4,122,722 $159,505 $924,489 $0 $185,174 $1,111,043 Known Commercial CO2 Injection Facilities (No GS) $0 $0 $1,286 $1,880 $2,001 $0 $400 $2,402 Known Commercial Saline $50,750 $4,790 $16,452,855 $662,380 $2,215,413 $0 $444,041 $2,664,244 Under UIC Class VI or II GS Facilities (ER opt in) $0 $0 $1,286 $1,880 $2,001 $0 $400 $2, 402

Known R&D ER $77,000 $14,288 $19,276,372 $941,680 $4,518,473 $3,442 $907,240 $5,443,443 Known R&D Saline $7,438 $1,380 $4,122,722 $159,505 $924,489 $1,955 $185,565 $1,113,390 Future R&D Saline $7,438 $1,380 $4,122,722 $159,505 $924,489 $1,955 $185,565 $1,113,390 Known Commercial CO2 Injection Facilities (No GS) $35,000 $3,304 $8,584,225 $420,680 $1,230,970 $1,955 $247,246 $1,483,475 Known Commercial Saline $50,750 $4,79 0 $16,452,855 $662,380 $2,215,413 $2,268 $444,494 $2,666,966 Low

GS Facilities (ER opt in) $35,000 $3,304 $8,584,225 $420,680 $1,230,970 $1,955 $247,246 $1,483,475

Known R&D ER $166,180 $30,835 $21,333,231 $1,088,360 $5,046,810 $3,442 $1,016,217 $6,097,304 Known R&D Saline $18,310 $3,397 $4,325,685 $180,764 $983,409 $1,955 $197,752 $1,186,514 Future R&D Saline $18,310 $3,397 $4,325,685 $180,764 $983,409 $1,955 $197,752 $1,186,514 Known Commercial CO2 Injection Facilities (No GS) $76,900 $7,259 $9,519,161 $490,080 $1,388,621 $1,955 $279,567 $1,677,403 Known Commercial Saline $110,380 $10,419 $17,812,801 $763,334 $2,444,736 $2,268 $491,485 $2,948,909 Reference

GS Facilities (ER opt in) $76,900 $7, 259 $9,519,161 $490,080 $1,388,621 $1,955 $279,567 $1,677,403

Known R&D ER $397,180 $73,698 $21,823,538 $1,249,400 $5,298,828 $3,442 $1,075,193 $6,451,161 Known R&D Saline $40,623 $7,538 $4,373,045 $196,319 $1,007,751 $1,955 $203,449 $1,220,694 Future R&D Saline $40,623 $7,538 $4,373,045 $196,319 $1,007,751 $1,955 $203,449 $1,220,694 Known Commercial CO2 Injection Facilities (No GS) $181,900 $17,170 $9,742,028 $563,280 $1,482,859 $1,955 $300,397 $1,802,381 Known Commercial Saline $262,630 $24,790 $18,135,958 $869,474 $2,581,380 $2,268 $521,688 $3,130,127 High

GS Facilities (ER opt in) $181,900 $17,170 $9,742,028 $563,280 $1,482,859 $1,955 $300,397 $1,802,3814

- 48

Table 4 - 11 . Summary of Cost Impacts : Activity Baseline from only AnthropogenicER Opt In
Environmental Baseline Periodic Monitoring Type Capital Costs Annualized

Capital Costs Capital Cost Annual Operating Cost Annualized Capital

and Contractor Costs Annual

Episodic Monitoring Costs Overhead and

G&A Total Annual

Costs Per Project Known R&D ER $0 $0 $1,286 $1,880 $2,119 $0 $424 $2,542 Known R&D Saline $7,438 $1,380 $4,122,722 $159,505 $924,489 $0 $185,174 $1,111,043 Future R&D Saline $7,438 $1,380 $4,122,722 $159,505 $924,489 $0 $185,174 $1,111,043 Known Commercial CO2 Injection Facilities (No GS) $0 $0 $1,286 $1,880 $2,001 $0 $400 $2,402 Known Commercial Saline $50,750 $4,790 $16,452,855 $662,380 $2,215,413 $0 $444,041 $2,664,244 Under UIC Class VI or II GS Facilities (ER opt in) $0 $0 $1,286 $1,880 $2,001 $0 $400 $2,402

Known R&D ER $77,000 $14,288 $19,276,372 $941,680 $4,518,473 $3,442 $907,240 $5,443,443 Known R&D Saline $7,438 $1,380 $4,122,722 $159,505 $924,489 $1,955 $185,565 $1,113,390 Future R&D Saline $7,438 $1,380 $4,122,722 $159,505 $924,489 $1,955 $185,565 $1,113,390 Known Commercial CO2 Injection Facilities (No GS) $35,000 $3,304 $8,584,225 $420,680 $1,230,970 $1,955 $247,246 $1,483,475 Known Commercial Saline $50,750 $4,790 $16,452,855 $662,380 $2,215,413 $2,268 $444,494 $2,666,966 Low

GS Facilities (ER opt in) $35,000 $3,304 $8,584,225 $420,680 $1,230,970 $1 ,955 $247,246 $1,483,475

Known R&D ER $166,180 $30,835 $21,333,231 $1,088,360 $5,046,810 $3,442 $1,016,217 $6,097,304 Known R&D Saline $18,310 $3,397 $4,325,685 $180,764 $983,409 $1,955 $197 ,752 $1,186,514 Future R&D Saline $18,310 $3,397 $4,325,685 $180,764 $983,409 $1,955 $197,752 $1,186,514 Known Commercial CO2 Injection Facilities (No GS) $76,900 $7,259 $9,519,161 $490,080 $1,388,621 $1,955 $279,567 $1,677,403 Known Commercial Saline $110,380 $10,419 $17,812,801 $763,334 $2,444,736 $2,268 $491,485 $2,948,909 Reference

GS Facilities (ER opt in) $76,900 $7,259 $9,519,161 $490,080 $1,388,621 $1,955 $279,567 $1,677,403

Known R&D ER $397,180 $73 ,698 $21,823,538 $1,249,400 $5,298,828 $3,442 $1,075,193 $6,451,161 Known R&D Saline $40,623 $7,538 $4,373,045 $196,319 $1,007,751 $1,955 $203,449 $1,220,694 Future R&D Saline $40,623 $7,538 $4,373,045 $196,319 $1,007,751 $1,955 $203,449 $1,220, 694 Known Commercial CO2 Injection Facilities (No GS) $181,900 $17,170 $9,742,028 $563,280 $1,482,859 $1,955 $300,397 $1,802,381 Known Commercial Saline $262,630 $24,790 $18,135,958 $869,474 $2,581,380 $2,268 $521,688 $3,130,127 High

GS Facilities (ER opt in) $181,900 $17,170 $9,742,028 $563,280 $1,482,859 $1,955 $300,397 $1,802,3814

- 49

Table 4 - 12 . Summary of Cost Impacts : Activity Baseline from Anthropogenic CO 2 plus One - half of OtherER Opt In
Environmental Baseline Periodic Monitoring Type Capital Costs Annualized

Capital Costs Capital Cost Annual Operating Cost Annualized Capital

and Contractor Costs Annual

Episodic Monitoring Costs Overhead and

G&A Total Annual

Costs Per Project Known R&D ER $0 $0 $1,286 $1,880 $2,119 $0 $424 $2,542 Known R&D Saline $7,438 $1,380 $4,122,722 $159,505 $924,489 $0 $185,174 $1,111,043 Future R&D Saline $7,438 $1,380 $4,122,722 $159,505 $924,489 $0 $185,174 $1,111,043 Known Commercial CO2 Injection Facilities (No GS) $0 $0 $1,286 $1,880 $2,001 $0 $400 $2,402 Known Commercial Saline $50,750 $4,790 $16,452,855 $662,380 $2,215,413 $0 $444,041 $2,664,244 Under UIC Class VI or II GS Facilities (ER opt in) $0 $0 $1,286 $1,880 $2,001 $0 $400 $2,402

Known R&D ER $77,000 $14,288 $19,276,372 $941,680 $4,518,473 $3,442 $907,240 $5,443,443 Known R&D Saline $7,438 $1,380 $4,122,722 $159,505 $924,489 $1,955 $185,565 $1,113,390 Future R&D Saline $7,438 $1,380 $4,122,722 $159,505 $924,489 $1,955 $185,565 $1,113,390 Known Commercial CO2 Injection Facilities (No GS) $35,000 $3,304 $8,584,225 $420,680 $1,230,970 $1,955 $247,246 $1,483,475 Known Commercial Saline $50,750 $4,79 0 $16,452,855 $662,380 $2,215,413 $2,268 $444,494 $2,666,966 Low

GS Facilities (ER opt in) $35,000 $3,304 $8,584,225 $420,680 $1,230,970 $1,955 $247,246 $1,483,475

Known R&D ER $166,180 $30,835 $21,333,231 $1,088,360 $5,046,810 $3,442 $1,016,217 $6,097,304 Known R&D Saline $18,310 $3,397 $4,325,685 $180,764 $983,409 $1,955 $197,752 $1,186,514 Future R&D Saline $18,310 $3,397 $4,325,685 $180,764 $983,409 $1,955 $197,752 $1,186,514 Known Commercial CO2 Injection Facilities (No GS) $76,900 $7,259 $9,519,161 $490,080 $1,388,621 $1,955 $279,567 $1,677,403 Known Commercial Saline $110,380 $10,419 $17,812,801 $763,334 $2,444,736 $2,268 $491,485 $2,948,909 Reference

GS Facilities (ER opt in) $76,900 $7, 259 $9,519,161 $490,080 $1,388,621 $1,955 $279,567 $1,677,403

Known R&D ER $397,180 $73,698 $21,823,538 $1,249,400 $5,298,828 $3,442 $1,075,193 $6,451,161 Known R&D Saline $40,623 $7,538 $4,373,045 $196,319 $1,007,751 $1,955 $203,449 $1,220,694 Future R&D Saline $40,623 $7,538 $4,373,045 $196,319 $1,007,751 $1,955 $203,449 $1,220,694 Known Commercial CO2 Injection Facilities (No GS) $181,900 $17,170 $9,742,028 $563,280 $1,482,859 $1,955 $300,397 $1,802,381 Known Commercial Saline $262,630 $24,790 $18,135,958 $869,474 $2,581,380 $2,268 $521,688 $3,130,127 High

GS Facilities (ER opt in) $181,900 $17,170 $9,742,028 $563,280 $1,482,859 $1,955 $300,397 $1,802,3814

- 50

4.7 Other Recordkeeping and Reporting Costs Additional recordkeeping ($1,700 per entity) and reporting ($500) costs per field were also added to each project type. 4.8 Public Sector Burden EPA estimates the public sector burden to be $344,000 per year; $55,000 per year is for verification activities, and remaining costs are for program implementation and developing and maintaining the data collection system. Program implementation activities include, but are not limited to, evaluating monitoring plans, developing guidance and training materials to assist the regulated community, responding to inquires from affected facilities on monitoring and applicability requirements, and developing tools to assist in determining applicability.5

- 51 SECTION 5 ECON OMIC IMPACT ANALYSIS EPA prepares an EIA to provide decision makers with a measure of the social costs of using resources to comply with a program (EPA, 2000 ). As noted in EPA’s (2000) Guidelines for Preparing Economic Analyses , several tools are availabl e 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 pro ducer surplus). Given data limitations and the size scope of the proposed rule, EPA has used the direct compliance cost method as a measure of social costs 45
. 5.1 Threshold Analysis EPA considered both a threshold based on the amount of CO 2emitted and a threshold based on the amount

of CO 2 injected underground. EPA concluded that an emissions

- based threshold would be problematic because of the lack of data on the incidence and scale of surface emissions and leakage from injection and GS of facilities
. EPA accordingly analyzed injection facilities based on the quantity of CO 2 inject ed undergroundand considered whether an injection threshold should apply
. EPA evaluated a no threshold option (i.e., all facilities that inject CO 2 would be required to report), 1,000 metric tons per year, 10,000 metric tons per year, 25,000 metric tons per year, and 100,000 metric tons per year per facility of CO 2injected. The results of the threshold analysis are presentedbelow in Table 5

- 1
. For further information on the assumptions underlying the threshold analysis, please refer to the general tec hnical support document (TSD) for this proposal. 46

45 See pages 124 and 125 (EPA, 2000). 46Subpart RR General TSD ( see docket ID No. EPA

- HQ

- OAR

- 200 9

- 0 926)5

- 52

Table 5 - 1 CO 2I njection Facilities: Effect of Injection Threshold on Reported Amount of

CO 2Injected and Number of Facilities Required to Report Amount of CO 2 Injected Number of Facilities Threshold Level (metric tons/yr of CO 2injected) Total National

(metric tons/yr of CO 2 injected) Total

Number of U.S. Facilities Metric

tons/yr of CO 2 Injected Percent

Covered Number Percent

Covered All In 40,111,639 80 40,111,639 100.0% 80 100.0% 1,000 40,111,639 80 40,111,115 100.0% 74 92.5% 10,000 40,111,639 80 40,099,065 100.0% 71 88.8% 25,000 40,111,639 80 40,005,238 100.0% 65 81.3% 100,000 40,111,639 80 39,065,039 97.4% 48 60.0%
EPA is proposingthat all CO 2 injection facilities would be required to report the minimum information in s ubpart RR (quantity of CO 2injected, quantity of CO 2transferred onsite from offsite, and source of the CO 2if known) at no threshold. An all

- in reporting threshold would allow the Agency to comprehensively track all CO 2supply (as reported in Suppliers o f CO 2 , s ubpart PP) that is injected underground. This approach is consistent with the all

- in requirements in the MRR for suppliers of petroleum, natural gas, and coal

- to
- liquid products ( s ubparts LL, MM, and NN), producers of industrial gases ( s ubpart OO), and suppliers of CO 2( s ubpart PP). It was reasonable to require all of the facilities in these source categories to report because it would result in the most comprehensive accounting possible, simplify the rule, and permit facilities to quickly determine whether or not they must report; the same rationale applies for this source category proposed today. Furthermore, it would create a uniform burden for all covered facilities, ensuring a level playing field in , and preventing fragmentation of, the ER sector. EPA has estimated the cost for CO 2injection facilities to comply with the minimum reporting requirements in this proposed rule and has determined that the burden would be small, given the equipment and data collection efforts already in p lace at ER projects. Under this action, EPA is proposing that the subset of CO 2injection facilities that are conducting GS (i.e. a GS facility) must report to EPA a second tier of data . EPA considered whether a threshold should apply to this second tier of data given that it would place a reporting burden on GS facilities. However, EPA could not perform an analysis on GS facilities based on emissions without data on actual or expected GS facility emissions. EPA also could not perform a threshold analys is based on injection due to the uncertainty around predictions of injection quantities for potential GS facilities. In addition, it is difficult to predict how many injection5

- 53

facilities would choose to report GS. Therefore, EPA is proposing to exempt GS R&D projects but otherwise require all GS facilities to comply with the GS monitoring, reporting, and verification requirements of subpart RR, and that they report fugitive, vented, and combustion emissions from surface equipment (under subpart W, RR, or C, as applicable). An all

- in threshold will allow EPA to work with the early

- movers of this nascent industry and to strengthen EPA’s understanding of GS. 5.2 National Cost Estimates The total annualized costs incurred under the rule by these entities would be approximately $713,000 (in 200 8$ ). This includes a public sector burden estimate of $344,000 for program implementation and verification activities. The typical annual cost for a CO 2 injection facility with no GS is $4,000 per year. Table 5 - 2 . National Annualized Mandatory Reporting Costs Estimates: Subpart RR

Type Number Metric Tons CO 2Injected per Year Total Annual Cost

(thousand, 2008$) R&D 9 5,320,000 $ 37 CO 2Injection Facilities (No GS) a 80 36,815,442 $332 Private Sector, Total All Projects 89 45,435,442 $3 69 Private Sector, Average ($/ton) $0.01 Public Sector, Total $344 National Total $71 3
aIncludes Class II ER projects Given uncertainties related to project adoption and the costs of the reporting program, EPA also considered two other private costs scenarios (one higher and one lower than the reference cost scenario) in order to assess a range of economic impacts on affe cted entities (Table 5

- 3). Table 5 - 3 . Annualized Mandatory Reporting Costs per Project (2008$): Subpart RR Average Alternative Cost Scenarios Type Reference ($1,000) Low

($1,000) High

($1,000) GS Facilities (commercial saline) $28 9 $ 7 $4 70 GS Facilities (ER opt in) $1,67 9 $1,48 5 $1,80 4 CO 2Injection Facilities (No GS) a $4 $4 $4
aIncludes Class II ER projects5

- 54

5.2.1 National Cost Estimates Under Alternative GS Facilities (ER opt in) Outcomes Currently, the number of ER operations that would choose to report as GS Facilities (ER opt in) is unknown and EPA could not identify any information or analysis to estimate this quantity . As a result, two additional scenarios of the have been considered to represent medium and high outcomes. As shown in Tables 5

- 4, national cost estimate is $24 million under the medium ER opt in outcome. As shown in T ables 5

- 5, national cost estimate is $79 million under the high ER opt in outcome. Table 5 - 4 . National Annualized Mandatory Repo rting Costs Estimates (2008): All

A nthropogenic CO 2P rojects
Type Number Metric Tons CO 2Injected per Year Total Annual Cost

(thousand, 2008$) R&D 9 5,320,000 $ 37 GS Facilities (ER opt in) 16 6,972,040 $23, 423 CO 2Injection Facilities (No GS) a 64 33,143,402 $266 Private Sector, Total All Projects 89 45,435,442 $23, 726 Private Sector, Average ($/ton) $0.52 Public Sector, Total $344 National Total $24,0 69
aIncludes Class II ERprojects Table 5 - 5 . National Annualized Mandatory Reporting Costs Estimates (2008$): All A nthropogenic 50 Percent of O ther CO 2P rojects

Type Number Metric Tons CO 2Injected per Year Total Annual Cost

(thousand, 2008$) R&D 9 5,320,000 $ 37 GS Facilities (ER opt in) 48 23,543,741 $79 , 071 CO 2Injection Facilities (No GS) a 32 16,571,701 $133 Private Sector, Total All Projects 89 45,435,442 $79, 241 Private Sector, Average ($/ton) $1.74 Public Sector, Total $344 National Total $79, 585
aIncludes Class II ER projects5

- 55

5.2.2 National Cost Estimates Under Alternative GS Facilities (Commercial Saline) Outcomes EPA considered two additional scenarios of the number of large scale saline aquifer GS ( commercial saline ) project deployment over the next 25 years : low (3 projects), medium (6 projects), and high (9 projects). The medium scenario is based on large scale saline project deployment projected in the cost analysis prepared for the UIC Class VI rule proposed on July 25, 2008 (73 FR 43492 )
. The national cost estimates estimate increase $867,000 under the low outcome; $1.7 million under the medium outcome, and $2.6 million under the high outcome. 5.3 Economic Impact Analysis EPA assessed how the regulatory program may influence the profitability of companies by comparing the monitoring program costs to total sales (i.e., a “sales” t est). Given limited data on commercial geological sequestration operations, EPA restricted the analysis to ER operations. As shown in Table 5

- 2, ER activities account for approximately 90 percent of the project popu lation. To do this, we divided the average annualized mandatory reporting costs per field by the estimated revenue for a representative field.

Sales Test Ratio= Average Cost (Table 5

- 3)/Estimated revenue (Table 5

- 6) 5.3.1 Revenue Estim ate for a Representative Commercial ER Operation EPA obtained national production statistics from the latest Department of Energy report about CO 2ER Technologies (DOE, 2009). Data suggest a typical operation produces approximate ly 776,000 barrels of oil per year. Using the DOE choice of an average long

- term price of oil ($70), EPA estimated total revenue of $54.3 million per year. To enhance the transparency of the calculation, we provide data, sources, and methods in Table 5

- 6
. Table 5 - 6 . Estimated Annual Revenue for a Representative Commercial ER Field Operation (2008) Label Variable Value Sourceand 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 $ 7 0 DOE, 2009 p: 2 F Total Revenue ($ milliion) $54 D × E Source: EPA calculations using data from DOE ( 2009 ) . Storing CO 2and Producing Domestic Crude Oil with Next Generation CO 2 - ERTechnology, accessed October 28, 2009.5

- 56

5.3.2 Sales Test Results As shown in Table 5

- 7 sales test ratios are between 3.1 to 3.3 percent for GS f acilities (ER opt in) . In contrast, CO 2injection facilities (no GS, which includes Class II ER operations) sales test ratios are below 0.01 percent. Table 5 - 7 . Sales Test s for Representative Commercial ER Field Operation s Cost - to - Sales Ratios (CSRs)

Alternative Cost Scenarios Type Reference Low High GS Facilities (ER opt in) 3.1% 2.7% 3.3% CO 2Injection Facilities (No GS) a <0.01% <0.01% <0.01%
aIncludes Class II ER operations 5.4 Assessing Economic Impacts on Small Entities The first step in this assessment was to determine whether the rule will have a significant impact on a substantial number of small entities (SISNOSE). To make this determination, EPA used a screening analysis that allows us to indicate whether EPA can certify the rule as not having a SISNOSE. The elements of this analysis included

 identifying affected sectors and entities,

 selecting and describing the measures and economic impact thresholds used in the analysis, and

 determining SISNOSE certification category. 5.4.1 Identify Affected Sectors and Entities For the purposes of assessing the impacts of the rule on small entities, we defined a small entity as (1) a small business, as defined by SBA’s regulations at 13 CFR Part 121.201; (2) a small governmental jurisdiction that is a government of a city, county, town, school district, or special district with a population of less than 50,000; or (3) a small organization that is any not

for

- profit enterprise that is independently owned and operated and is not dominant in its field. For the Carbon Dioxide Injection and Geologic Sequestration Reporting Rule, small entityis defined as a small business as defined by the Small Business Administration’s regulations at 13 CFR 121.201; according to these size standards, ultimate parent companies5

- 57

ow ning oil and gas extraction operations (NAICS 211) are categorized as small if the total number of employe es at the firm is fewer than 500. The Oil & Gas Journal publishes a list of companies owning active U.S. CO 2 ERprojects in 2008 (OGJ, 2008). EPA’s initial review of publicly available sales and employment databases suggest up to 9 of the 23 companies listed in the OGJ survey have fewer than 500 employees. EPA continues to collect other information about corporate structures of these 9 companies to assess whether these companies are owned by larger parent companies. 5.4.2 Develop Small Entity Economic Impact Measures The sales test

examine dthe average total annualized mandatory reporting costs per ER field to a representative measure of revenue. Details are provided in section 5.3. 5.4.3 Results of Screening Analysis The Regulatory Flexibility Act generally requires an agency to prepare a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements under the Administrative Procedure Act or any other statute, unless the agency certifies that the rule will not have a significant economic impact on a substantial number of small entities. After considering the economic impact of the rule on small entities, EPA has concluded that this action will not have a significant economic impact on a substantial number of small entities. Currently EPA believes small ER operations will most likely be CO 2injection facilities (no GS), including Class II ER projects. The average ratio of annualized reporting program costs to revenues of a typical ER operation likely owned by representative small enterprises is less than 1%. Although this rule will not have a significant eco nomic impact on a substantial number of small entities, EPA nonetheless took several steps to reduce the impact of this rule on small entities. For example, EPA is proposing monitoring and reporting requirements that build off of the UIC program. In addi tion, EPA is proposing equipment and methods that may already be in use by a facility for compliance with its UIC permit. Also, EPA is requiring annual reporting instead of more frequent reporting. In addition to the public hearing that EPA plans to hold, EPA has an open door policy, similar to the outreach conducted during the development of the proposed and final Mandatory GHG Reporting Rule. Details of these meetings are available in the docket (EPA

- HQ

- OAR

2009

- 0926).5

- 58

5.5 Characterization of Benefits of Subpart RR of the Mandatory Reporting Rule EPA examined the potential benefits of the Carbon Dioxide Injection and Geologic Sequestration Reporting Rule. EPA’s p revious analysis of the GHG reporting rule discussed the benefits of a reporting system with respect to policy making relevance, transparency issues, and market efficiency. Instead of a quantitative analysis of the benefits, EPA conducted a systematic lit erature review of existing studies including government, consulting, and scholarly reports. A mandatory reporting system will benefit the public by increased transparency of facility GHG data. Transparent, public data on GHGs allows for accountability o f polluters to the public stakeholders who bear the cost of the pollution. Citizens, community groups, and labor unions have made use of data from Pollutant Release and Transfer Registers to negotiate directly with polluters to lower emissions, circumventing greater government regulation. Publicly available emissions data also will allow individuals to alter their consumption habits based on the GHG emissions of producers. The greatest benefit of mandatory reporting of GHGs to government will be realizedin developing future GHG policies. For example, in the EU’s Emissions Trading System, a lack of accurate monitoring at the facility level before establishing CO 2allowance permits resulted in allocation of permits for emissions levels an average of 15 percent above actual levels in every country except the United Kingdom. Benefits to industry of GHG monitoring include the value of having independent, verifiable data to present to the public to demonstrate appropriate environmental stewardship, and a bett er understanding of their emission levels and sources to identify opportunities to reduce emissions. Such monitoring allows for inclusion of standardized GHG data into environmental management systems, providing the necessary information to achieve and di sseminate their environmental achievements. Standardization will also be a benefit to industry, once facilities invest in the institutional knowledge and systems to report GHG data, the cost of monitoring should fall and the accuracy of the accounting sh ould improve. A standardized reporting program will also allow for facilities to benchmark themselves against similar facilities to understand better their relative standing within their industry. Data on CO 2injection and GS are critical to informing CA A GHG policies. This data would provide information and transparency on the amount of CO 2injected and geologically sequestered in the United States and, in combination with other subparts of the MRR, would5

- 59

enable EPA to track the flow of CO 2across a CCS system. In addition, this information would enable EPA to monitor the growth and efficacy of GS (and therefore CCS) as a GHG mitigation technology over time and to evaluate relevant policy options. For example, EPA would be able to track whether incenti ves or regulations are needed to encourage faster or further GS project development. EPA would also be able to track whether ER sites are reporting GS and consider whether incentives or regulations are needed. Where ER facilities are reporting GS, EPA wo uld be able to evaluate ER as a potentially non

- emissive end use. In combination with subpart PP, EPA would be able to reconcile this data with CO 2supplied in order to better understand the quantity of CO 2supplied to emissive and non

- emissive end uses.6

- 60 SECTION 6 STATUTORY AND EXECUT IVE ORDER REVIEWS This section describes EPA’s compliance with several applicable executive orders and statutes during the development of the proposed Carbon Dioxide Injection and Geologic Sequestration Reporting Rule, subpart RR under Track II of the GHG reporting rule. 6.1 Executive Order 12866: Regulatory Planning and Review Under Section 3(f)(1) of Executive Order 12866 (58 FR 51735, October 4, 1993), this proposed action is not by itself an “economically sig nificant regulatory action” because it is unlikely to have an annual economic effect of less than $100 million. EPA’s cost analysis, presented in Section 4 of the Economic Impact Analysis (EIA), estimates that for the minimum reporting under the recommende d regulatory option, the total annualized cost of the rule w ill be approximately 713,000 (in 2008$) during the first year of the program and $ 713,000 in subseque nt years ( 344,000 of programmatic costs to the Agency). This proposed action adds Subpart RR to the mandatory GHG reporting rule, which was a significant regulatory action. Thus, EPA has chosen to analyze the impacts of Subpart RR as if it were significant. EPA submitted this proposed action to the Office of Management and Budget (OMB) for review un der Executive Order 12866, and any changes made in response to OMB recommendations have been documented in the docket for this proposed action. In addition, EPA prepared this EIA , including an analysis of the potential costs associated with this action. Inthis report, EPA has identified the regulatory options considered, their costs, the emissions that would likely be reported under each option, and explained the selection of the option chosen for the rule. The costs of the rul e are reported in Section 4, and the economic impacts and qualitative benefits assessment are reported in Section 5. Overall, EPA has concluded that the costs of the Carbon Dioxide Injection and Geologic Sequestration Reporting Ruleare outweighed by the potential benefits of more comprehensive i nformation about CO 2 injection. 6.2 Paperwork Reduction Act The information collection requirements in this proposed rulehave been submitted for approval to the Office of Management and Budget (OMB) under the Paperwork Reduction Act , 44 U.S.C. 3501 et seq . The Information Collection Request (ICR) document prepared by EPA has been assigned EPA ICR number 2372.01 EPA has i dentified the following goals of the mandatory GHG reporting system:6

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 Obtain data that is of sufficient quality that it can be used to analyze and inform the development of a range of future climate change policies and potential regulations.

 Balance the rule’s coverage to maximize the amount of emissions reported while excluding small emitters.

 Create reporting requirements that are, to the extent possible and appropriate, consistent with existing GHG reporting programs in order to reduce rep orting burden for all parties involved. The information from CO 2injection and geologic sequestration facilities will allow EPA to make well

- informed decisions about whether and how to use the CAA to regulate these facilities and encourage voluntary reduc tions. Because EPA does not yet know the specific policies that will be adopted, the data reported through the mandatory reporting system should be of sufficient quality to inform policy and program development. Also, consistent with the Appropriations Ac t, the reporting rule covers a broad range of sectors of the economy. This information collection is mandatory and will be carried out under CAA Sections 114. Information identified and marked as Confidential Business Information (CBI) will not be disclos ed except in accordance with procedures set forth in 40 CFR Part 2. However, emissions information collected under CAA Sections 114 generally cannot be claimed as CBI and will be made public. 47 The projected average ICR cost and respondent burden is $0.8 million and 4,510 hours per year. The estimated average annual burden perresponse is 6.8 hours; the frequency of response is annual for all respondents that must comply with the rule’s reporting requirements, except for electricity

- generating units that are already required to report quarterly under 40 CFR Part 75 (ARP); and the estimated average number of likely respondents per year is 89. The cost burden to respondents resulting from the collection of information includes the total capital and start
- up cost annualized over the equipment’s expected useful life (averaging $0.1 million per year) a total operation and maintenance component (averaging $0.3 million per year), and a labor cost component (averaging $0.3 million per year). Burden is defined at 5 CFR Part 1320.3(b). These cost numbers differ from those shown elsewherein the EIAbecause ICR costs represent the average cost over the first three years of the rule, but costs are reported elsewhere

47 Although CBI determinations are usually made on a case

- by

- casebasis, EPA has issued guidance in an earlier Federal Register notice on what constitutes emissions data that cannot be considered CBI (956 FR 7042

– 7043, February 21, 1991). As discussed in Section II.Rof the preamble to the rule, EPA will be initiating a separate notice and comment process to make CBI determinations for the data collected under this proposed rulemaking.6

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in the EIAfor the first year of the rule. Also, the total cost estimate of the rule in the EIA includes the cost to the Agenc y to administer the program. The ICR differentiates between respondent burden and cost to the Agency. 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 con trol number. The OMB control numbers for EPA’s regulations in 40 CFR are listed in 40 CFR Part 9. When this ICR is approved by OMB, the Agency will publish a technical amendment to 40 CFR part 9 in the Federal Register to display the OMB control number for the approved information collection requirements contained in the final rule. 6.3 Regulatory Flexibility Act The Regulatory Flex ibility Act generally requires an agency to prepare a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements under the Administrative Procedure Act or any other statute, unless the agency certifies that the rule w ill not have a significant economic impact on a substantial number of small entities. Small entities include small businesses, small governmental jurisdictions, and small not

- for

- profit enterprises. The first step in this assessment was to determine whether the rule will have a significant impact on a substantial number of small entities (SISNOSE). To make this determination, EPA used a screening analysis that allows us to indicate whether EPA can certify the rule as not having a SISNOSE. The elements of th is analysis included

 identifying affected sectors and entities,

 selecting and describing the measures and economic impact thresholds used in the analysis, and

 determining SISNOSE certification category. 6.3.1 Identify Affected Sectors and Entities For the purposes of assessing the impacts of the rule on small entities, we defined a small entity as (1) a small business, as defined by SBA’s regulations at 13 CFR Part 121.201; (2) a small governmental jurisdiction that is a government of a city, county, town, school district, or special district with a population of less than 50,000; or (3) a small organization that is any not

for

- profit enterprise that is independently owned and operated and is not dominant in its field. For the Carbon Dioxide Injection and Geologic Sequestration Reporting Rule, small entityis defined as a small business as defined by the Small Business Administration’s regulations at 13 CFR 121.201; according to these si ze standards, ultimate parent companies6

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owning oil and gas extraction operations (NAICS 211) are categorized as small if the total number of employe es at the firm is fewer than 500. The Oil & Gas Journal publishes a list of companies owning active U.S. C O 2 ERprojects in 2008 (OGJ, 2008). EPA’s initial review of publicly available sales and employment databases suggest up to 9 of the 23 companies listed in the OGJ survey have fewer than 500 employees. EPA continues to collect other information about cor porate structures of these 9 companies to assess whether these companies are owned by larger parent companies. 6.3.2 Develop Small Entity Economic Impact Measures These sales test

examine dthe average total annualized mandatory reporting costs per ER field to a representative measure of revenue. Details are provided in section 5.3. 6.3.3 Results of Screening Analysis The Regulatory Flexibil ity Act generally requires an agency to prepare a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements under the Administrative Procedure Act or any other statute, unless the agency certifies that the rule will not have a significant economic impact on a substantial number of small entities. After considering the economic impact of the rule on small entities, EPA has concluded that this action will not have a significant economic impact on a substantial numb er o f small entities. Currently EPA believes small ER operations will most likely be CO 2injection facilities (no GS), including Class II ERprojects. As shown in Table5

- 7, the average ratio of annualized reporting program costs to revenues of a typical ER operation likely owned by model small enterprises was less than 1%. Although this rule will not have a significant economic impact on a substantial number of small entities, EPA nonetheless took several steps to reduce the impact of this rule on small entities. For example, EPA is proposing monitoring and reporting requirements that build off of the UIC program. In addition, EPA is proposing equipment and methods that may already be in use by a facility for compliance with its UIC permit. Also, EPA is requiring annual reporting instead of more frequent reporting. In addition to the public hearing that EPA plans to h old, EPA has an open door policy, similar to the outreach conducted during the development of the proposed and final Mandatory GHG Reporting Rule. Details of these meetings are available in the docket (EPA

- HQ

- OAR

2008

- 0508).6

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

- 4, establishes requirements for federal agencies to assess the effects of their regulatory actions on state, local, and tribal governments and the private sector. Under Section 202 of th e UMRA, EPA generally must prepare a written statement, including a cost

- benefit analysis, for final rules with “federal mandates” that may result in expenditures to state, local, and tribal governments, in the aggregate, or to the private sector, of $100 million or more in any one year. This proposed ruledoes not contain a Federal mandate that may result in expenditures of $100 million or more for State, local, and tribal governments, in the aggregate, or the private sector in any one year . Overall, EPA estimates that the total annualized costs of this proposed rule are approximately $713,000 per year. Thus, this proposed ruleis not subject to the requirements of sections 202 or 205 of UMRA. This propos ed ruleis also not subject to the requirements of section 203 of UMRA because it contains no regulatory requirements that might significantly or uniquely affect small governments . Facilities subject to the proposed rule include facilities that inject CO 2 for enhanced recovery of crude oil, 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 ensure “meaningful and timely input by state and local officials in the development of regulatory policies that have federalism implications.” “Policies that have federalism implications” is defined in the executive order to include regulations that have “substantial direct effects on the states, on the relationship between the national government and the stat es, or on the distribution of power and responsibilities among the various levels of government.” This proposed ruledoes not have federalism implications. It will not have substantial direct effects on the states, on the relationship between the national government and the states, or on the distribution of power and responsibilities among the various levels of government, as specified in Executive Order 13132. This regulation applies to public

- or private

- sector facilities that inject GHG underground
. Few government facilities would be affected. This regulation also does not limit6

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the power of states or localities to collect GHG data and/or regulate GHG emissions. Thus, Executive Order 13132 does not apply to this proposed rule
. In the spirit of Executive Order 13132, and consistent with EPA policy to promote communications between EPA and State and local governments, EPA specifically solicits comment on this proposed actionfrom State and local officials. 6.6 Executive Order 13175: Consultation and Coordination with Indian Tribal Governments Executive Order 13175, entitled “Consultation and Coordination with Indian Tribal Governments” (59 FR 22951, November 6, 2000), requires EPA to develop an accountable process to ensure “meaningful and timely input by tribal officials in the development of regulatory policies that have tribal implications.” This proposed ruleis not expected to have tribal implications, as specified in Executive Order 13175. This regulation applies to facilities that facilities that injec t GHG underground
. Few facilities ex pected to be affected by the rule are likely to be owned by tribal governments. Thus, Executive Order 13175 does not apply to this proposed rule
. Although Executive Order 13175 does not apply to this proposed rule , EPA sought opportunities to provide info rmation to tribal governments and representatives during development of the MRR rule. In consultation with EPA’s American Indian Environment Office, EPA’s outreach plan for the MRR included tribes. For a complete list of tribal contacts, see the “Summary o f EPA Outreach Activities for Developing the Greenhouse Gas Reporting Rule,” in the Docket for this proposed rule making (EPA

- HQ

- OAR

- 2008

- 0508

- 055). In addition to the consultation activities supporting the MRR, EPA continues to provide information to tribal governments and representatives during development of the Track II rules such as this proposed rulemaking. EPA specifically solicits additional comment on this proposed action from tribal officials. 6.7 Executive Order 13045: Protection of Children from Environmental Health and Safety Risks EPA interprets Executive Order 13045 (62 F.R. 19885, April 23, 1997) as applying only to tho se regulatory actions that concern health or safety risks, such that the analysis required under Section 5

- 501 of the executive order has the potential to influence the regulation. This action is not subject to Executive Order 13045 because it does not est ablish an environmental standard intended to mitigate health or safety risks.6

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6.8 Executive Order 13211: Actions that Significantly Affect Energy Supply, Distribution, or Use This proposed ruleis not a “significant energy action” as defined in Executive Order 13211 (66 FR 28355, May 22, 2001) because it is not likely to have a significant adverse effect on the supply, distribution, or use of energy. Further, we have concluded that this proposed rule is not likely to have any adverse energy effects. This proposal relates to monitoring, reporting, and recordkeeping at facilities that directly inject CO 2for enhanced recovery of oil or geologic sequestration ; it does not adversely affect energy supply, distribution or use. Therefore, we conclude that this proposed ruleis not likely to have any adverse effects on energy supply, distribution, or use. 6.9 National Technology Trans fer Advancement Act Section 12(d) of the National Technology Transfer and Advancement Act of 1995 (NTTAA), Public Law No. 104

- 113 (15 U.S.C. 272 note) directs EPA to use voluntary consensus s tandards in its regulatory activities unless to do so would be inconsistent with applicable law or otherwise impractical. Voluntary consensus standards are technical standards (e.g., materials specifications, test methods, sampling procedures, and business practices) that are developed or adopted by voluntary consensus standards bodies. NTTAA directs EPA to provide Congress, through OMB, with explanations when the Agency decides not to use available and applicable voluntary consensus standards. This propos ed rule making involves technical standards. EPA proposes to use voluntary consensus standards from six different voluntary consensus standards bodies: American Society for Testing and Material (ASTM), American Society of Mechanical Engineers (ASME), Intern ational Organization for Standardization (ISO), Gas Processors Association (GPA), American Gas Association (AGA), and American Petroleum Institute (API). These voluntary consensus standards will help facilities monitor, report, and keep records of GHG emis sions associated with their CO 2injection and geologic sequestration activities . No new test methods were developed for this proposed rule . Instead, from existing rules for source categories and voluntary GHG programs, EPA identified existing means of moni toring, reporting, and keeping records. The existing methods (voluntary consensus standards) include a broad range of measurement techniques, methods to measure gas or liquid flow, and methods to gauge and measure petroleum and petroleum products. The test methods are incorporated by reference into the rule and are available as specified in Section 98.6 of subpart A.6

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By incorporating voluntary consensus standards into this proposed rule , EPA is both meeting the requirements of the NTTAA and presenting multi ple options and flexibility for complying with the proposed rule. EPA welcomes comments on this aspect of the proposed rulemaking and, specifically, invites the public to identify potentially

- applicable voluntary consensus standards and to explain why suchstandards should be used in this proposed regulation. 6.10 Executive Order 12898: Federal Actions to Address Environmental Justice in Minority Populations and Low - Income Populations Executive Order 12898 (59 FR 7629, February 16, 1994) establishes federal executive policy on environmental justice. Its main provision directs federal agencies, to the greatest extent practicable and permitted by law, to make environmental justice part of their mission by identifying and addressing, as appropriate, disproportionately high and adverse human health or environmental effects of their programs, policies, and activities on minority populations and low

income populations in the United States. EP A has determined that this proposedrule will not have disproportionately high and adverse human health or environmental effects on minority or low

- income populations because it does not affect the level of protection provided to human health or the enviro nment. This proposedrule does not affect the level of protection provided to human health or the environment because it is a rule addressing information collection and reporting procedures.7

- 1 SECTION 7 CONCLUSIONS EPA is proposing to add Subpart RR to the existing Mandatory Reporting of Greenhouse Gases Program established under 40 CFR 98 to track the fate of CO 2injected underground and confirm CO 2sequestration volumes
. The proposed approach is tiered. First, a set of reporting requirements is proposed to cover facilities that inject CO 2underground regardless of the purpose of injection. Se cond, a subset of facilities that inject CO 2and conduct geologic sequestration (GS) are subject to an additional set of requirements. 7.1 Summary of Selected Regulatory Alternative EPA is proposingthat all CO 2 injec tion facilities would be required to report the minimum information in s ubpart RR (quantity of CO 2injected, quantity of CO 2transferred onsite from offsite, and source of the CO 2if known) at no threshold. An all

- in reporting threshold would allow the Ag ency to comprehensively track all CO 2supply (as reported in Suppliers of CO 2 , s ubpart PP) that is injected underground. This approach is consistent with the all

- in requirements in the MRR for suppliers of petroleum, natural gas, and coal

- to
- liquid produc ts ( s ubparts LL, MM, and NN), producers of industrial gases ( s ubpart OO), and suppliers of CO 2( s ubpart PP). It was reasonable to require all of the facilities in these source categories to report because it would result in the most comprehensive accounti ng possible, simplify the rule, and permit facilities to quickly determine whether or not they must report; the same rationale applies for this source category proposed today. Furthermore, it would create a uniform burden for all covered facilities, ensuring a level playing field in , and preventing fragmentation of, the ER sector. EPA has estimated the cost for CO 2injection facilities to comply with the minimum reporting requirements in this proposed rule and has determined that the burden would be small , given the equipment and data collection efforts already in place at ER projects. Under this action, EPA is proposing that the subset of CO 2injection facilities that are conducting GS (i.e. a GS facility) must report to EPA a second tier of data . EPA c onsidered whether a threshold should apply to this second tier of data given that it would place a reporting burden on GS facilities. However, EPA could not perform an analysis on GS facilities based on emissions without data on actual or expected GS faci lity emissions. EPA also could not perform a threshold analysis based on injection due to the uncertainty around predictions of injection quantities for potential GS facilities. In addition, it is difficult to predict how many injection facilities would choose to report GS. Therefore, EPA is proposing to exempt GS R&D projects but otherwise require all GS facilities to comply with the GS monitoring, reporting, and7

- 2

verification requirements of subpart RR, and that they report fugitive, vented, and combustion emissions from surface equipment (under subpart W, RR, or C, as applicable). An all

- in threshold will allow EPA to work with the early

- movers of this nascent industry and to strengthen EPA’s understanding of GS. 7.2 Estimated Costs and Impacts of the Mandatory GHG Reporting Program Under the rule, EPA estimates that 89 fields would be covere d by the rule, injecting approximately 40 MtCO 2per year. The total annualized costs incurred under the rule by these entities would be approximately $713,000 (in 200 8$ ). This includes a public sector burden estimate of $344,000 for program implementation and verification activities. These costs are distributed to severaleconomic sectors and represent approximately 0.00 0 1% of 2008 gross domestic product; overall, EPA does not believe the rule will have a significant macroeconomic impact on the national economy or on small entities within those sector s. 7.2.1 Alternative Scenarios Considered 7.2.1.1 GS Facilities (ER opt in) Outcomes Currently, the number of GS Facilities (ER opt in) is unknown and EPA could not identify any information or analysis to estimate this quantity . As a result, two additional scenarios of the have been considered to represent medium and high outcomes. As shown in Tables 5

- 4, national cost estimate is $24 million under the medium ER opt in outcome. As shown in Tables 5

- 5, national cost estimate is $79 million under the high ER opt in outcome. 7.2.1.2 GS Facilities (Commercial Saline) Outcomes EPA considered two additional scenarios of the quantity of commercial saline project outcome s : low (3 projects), medium (6 projects), and high (9 projects). The national cost estimates estimate increase $867,000 under the low outcome; $1.7 million under the medium outcome, and $2.6 million under the high outcome.8

- 1 SECTION 8 REFERENCES Benson, S.M., 2006, “Monitoring Carbon Dioxide Sequestration in Deep Geological Formations for Inventory Verification and Carbon Credits,” Society of Petroleum Engineers Paper 102833, 14pp. Carbon Capture and Storage: A Regulatory Framework for States

– Summary of Recommendations, by Kevin Bliss, Interstate Oil and Gas Compact Commission, January, 2005
. Carbon Sequestration Atlas of the United States and Canada, 2008, U.S. Department of Energy, National Energy Technology Laboratory, Morgantown, WV. Direct Carbon Sequestration: Capturing and Storing Carbon Dioxide , Congressional Research Service, report RL33801, September, 2007. Discussion Paper: Identifying Gapsin CO 2 Monitoring and Verification of Storage , by B. Reynen, M. Wilson, N. Riley, T. Manai, O. M. Mathiassen, and S. Holloway, A Task Force under the Technical Group of the Carbon Sequestration Leadership Foru, (CSLF), Paper No. CSLF

- T

- 2005

- 3, Presented at the Technical Group Meeting, April 30, 2005 The Economics of CO 2 Storage , Gemma Heddle, Howard Herzog, and Michael Klett, Laboratory for Energy and the Environment, Massachusetts Institute of Technology, August, 2003. The Future of Coal, Options for a Carbon

- constrained World, An Interdisciplinary MIT Study, Massachusetts Institute of Technology, 2007. FutureGen Alliance, 2006, “Mattoon Site Environmental Information Volume,” December, 2006. Ground Water Protection Coun cil Meeting, New Orleans, LA, January, 16, 2008
. 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. Joint Association Survey of Drilling Costs, American Petroleum Institute, Washington, DC. http: //www.api.org/statistics/accessapi/api

- reports.cfm Oil and Gas Journal, April 17, 2006
. Oil and Gas Journal Pipeline Cost Survey, Oil and Gas Journal Magazine, September 3, 2007. PSAC Well Cost Study

–

2008, Petroleum Services Association of Canada, October 30, 2007. Regional Carbon Sequestration Partnerships Annual Project Review Meeting , DOE/NETL, December 12, 2007.8

- 2

U.S. Department of Energy, National Energy Technology Laboratory website, www.netl.doe.gov Oil and Gas Lease Equipment and Operating Cost s , U.S. Energy Information Administration, 2006, http://www.eia.doe.gov/pub/oil_gas/natural_gas/data_publications/cost_indi ces_equipme nt_production/current/coststudy.html U.S. Department of Energy (DOE). 2009. Storing CO 2and Producing Domestic Crude Oil with Next Generation CO 2 - ERTechnology, accessed October 28, 2009. U.S. Env ironmental Protection Agency (EPA). September 2000. Guidelines for Preparing Economic Analyses . EPA 240

- R

- 00

- 003. Washington, DC: EPA. Available at <http://yosemite.epa.gov/ee/epa/eed.nsf/webpages/Guidelines.html>.