U.S. Environmental Protection Agency 

### Documentation of OMB Review Under Executive Order 12866 Title of Action:
Docket#: FRL#: RIN: This action was submitted to the Office of Management and Budget (OMB) for review under Executive Order (E.O.) 12866 , titled Regulatory Planning and Review (58 FR 51735, October 4, 1993). Whenever EPA makes publicly available a regulatory action that was reviewed under E.O. 12866, sect ion 6(a)(3)(E) of the E.O. directs the Agency to also: (1)Make available to the public a copy of the information that was provided to OMB’s Office of Information and Regulatory Affairs (OIRA) for review under the E.O., i.e. , the text of the draft regulatory action and, if applicable, an assessment of the potential costs an d benefits, as well as additional information for those actions that are determined to be economically significant under the E.O. (Information requirements are described in sections 6(a)(3)(B) and (C)). (2)Identify for the public any substa ntive changes between the draft submitted to OIRA and the action that was subsequently issued, using a method that is complete, clear, and simple. (3)Identify for the public those substantive changes made at the suggestion or recommendation of OIRA. For this regulatory action, were substantive changes made to information reviewed under E.O. 12866? [Please check the appropriate answer.] No. [In the docket, include the information identified in item (1) below.] Yes. [In the docket, include the information identified in items (1) – (3) below.] Accordingly, the Agency has included this fo rm and the following information in the public docket for this regulatory action: [Please check the appropriate information.] (1)A copy of the information that was provided to OIRA for review under the E.O. (2)Documentation of any substantive changes made to the draft regul atory text that was submitted to OIRA when compared with what was subsequently made publ icly available. The documentation is provided on the pages fo llowing this form. Changes made at the suggestion or recommendation of OIRA, if any, are clearly identified through attribution to OIRA. EPA has used one or more of the following methods to note changes: [Select the appropriate option(s).] (a) Redline-Strikeout– A copy of the draft regulatory action submitted, using redlinestrikeout to show the substantive changes that were made. (b) Hand Markup– A copy of the draft regulatory action submitted, using handwritten notes to show the substantive changes that were made. (c) Note to the file- A document that identifies the s ubstantive changes that were made, with page and paragraph references to the draft regulatory action that was submitted. If you have any questions about this regulatory action or this documentation, please call the contact: Name: Em ail: Phone: Revised 05/05/2010OMB DRAFT: Please do not cite, quote, or distribute 6560.50 ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 98 [EPA- HQ - OAR- 2009 - 0926 ; FRL - 9131 - 2 ]

RIN 2060 -AP88 Mandatory Reporting of Greenhouse Gases : Injection and

Geologic Sequestration of Carbon Dioxide AGENCY: Environmental Protection Agency (EPA). ACTION: Final Rule. SUMMARY : EPA is promulgating a regulation to require monitoring and reporting from facilities that conduct geologic sequestration (GS) of carbon dioxide (CO 2 ) and all other facilities that conduct injection of CO 2 . This rule does not require control of greenhouse gases (GHGs), rather it requires only monitoring and reporting of GHGs . DATES: The final rule is effective on [ INSERT THE DATE 60 DAYS AFTER PUBLICATION IN THE FEDERAL REGISTER ] . ADDRESSES : EPA has established a docket for thi s action under Docket ID No. EPA - HQ - OAR - 2009
- 0926 . All documents in the docket are listed on the www.regulations.gov Web site. Although listed in the index, some information is not publicly available, e.g.,
con fidential business information (CBI) or otherOMB DRAFT: Please do not cite, quote, or distribute Page 2 of 142 information whose disclosure is restricted by statute . Certain other material, such as copyrighted material, is not placed on the Internet and will be publicly available only in hard copy form. Publicly avai lable docket materials are available either electronically through www.regulations.gov or in hard copy at EPA’s Docket Center, Public Reading Room, EPA West Building, Room 3334, 1301 Constitution Avenue, NW . , Washington, DC 20004. This Docket Facility is open from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding legal holidays. The telephone number for the Public Reading Room is (202) 566
- 1744, and the telephone number for the Air Docket is (202) 566
- 174 2 . FOR FURTHER INFORMATION CONTACT : For technical information and implementation materials, please go to the Web site www.epa.gov/climatechange/emissions/ghgrulemaking.html . To submit a question, select Rule Help Cen ter, followed by Contact Us. You may also c ontact Mark de Figueiredo , Climate Change Division, Office of Atmospheric Programs (MC

– 6207J), Environmental Protection Agency, 1200 Pennsylvania Ave., NW., Washington, DC 20460; telephone number: (202) 343

– 9 928 ; fax number: (202) 343

– 2202 . SUPPLEMENTARY INFORMATION :OMB DRAFT: Please do not cite, quote, or distribute Page 3 of 142 Regulated Entities . The Administrator has determined that this action is subject to the provisions of Clean Air Act (CAA) section 307(d). See CAA section 307(d)(1)(V) (the provisions of CAA section 307(d) apply to “such other actions as the Administrator may determine”). T hese regulations will affect owners or operators of CO 2 injection wells . Regulated categories and entities include those listed in Table 1 of this preamble: Table 1. Examples of Affected Entities by Category Category NAICS Examples of affected facilities CO 2 E nhanced Oil and Gas Recovery Projects 211 Oil and g as e xtraction p rojects using CO 2 e nhanced oil and gas r ecovery Acid Gas Injection Projects 211111 or 211112 Projects tha t inject acid gas

containing CO 2 underground GS Projects N/A CO 2 geologic sequestration projects Table 1 of this preamble is not intended to be exhaustive but rather provides a guide for readers regarding facilities likely to be affected by this action. Table 1 of this preamble lists the types of facilities that EPA is now aware could be potentially affected by the reporting requirements. Other types of facilities not listed in the table could also be subject to reporting requirements. To determine wh ether you are affected by this action, you should carefully examine the applicability criteria found in 40 CFR part 98, subpart A and theOMB DRAFT: Please do not cite, quote, or distribute Page 4 of 142 relevant criteria in the sections related to the injection and GS of CO 2 . If you have questions regarding the applicability of this action to a particular facility, consult the person listed in the preceding “ FOR FURTHER INFORMATION CONTACT ” section. Some facilities that are affected by today’s final rule are required to report under multiple source categories . Table 2 of this preamble has been developed as a guide to help potential CO 2 injection and GS reporters subject to the final rule identify the source categories (by subpart) that they may need to (1) consider in their facility applicability determination, and/or (2) include in their reporting. The table should only be seen as a guide. Additional subparts in 40 CFR part 98 may be relevant for a given reporter. Similarly, not all listed subparts are relevant for all reporters. Table 2. Source Categories and Re levant Subparts Source category (and main applicable subpart) Other s ubparts recommended for review to determine applicability Geologic Sequestration of Carbon Dioxide 40 CFR part 98, subpart C 40 CFR part 98, subpart W 40 CFR part 98, subpart PP Inje ction of Carbon Dioxide 40 CFR part 98, subpart C 40 CFR part 98, subpart W 40 CFR part 98, subpart PP
Judicial Review .OMB DRAFT: Please do not cite, quote, or distribute Page 5 of 142 Under section 307(b)(1) of the CAA, judicial review of this final rule is available only by filing a petition for review in the U.S. Court of Appeals for the District of Columbia Circuit by [ INSERT THE DATE 60 DAYS AFTER PUBLICATION IN THE FEDERAL REGISTER ]. Under CAA section 307(d)(7)(B), only an objection to this final rule that was raised with reasonable specificity during the peri od for public comment can be raised during judicial review. This section also provides a mechanism for EPA to convene a proceeding for reconsideration, “[i]f the person raising an objection can demonstrate to EPA that it was impracticable to raise such ob jection within [the period for public comment] or if the grounds for such objection arose after the period for public comment (but within the time specified for judicial review) and if such objection is of central relevance to the outcome of this rule.” Any person seeking to make such a demonstration to EPA should submit a Petition for Reconsideration to the Office of the Administrator, Environmental Protection Agency, Room 3000, Ariel Rios Building, 1200 Pennsylvania Ave., NW., Washington, DC 20004, with a copy to the person listed in the preceding “ FOR FURTHER INFORMATION CONTACT ” section, and the Associate General Counsel for the Air and Radiation Law Office, Office of General Counsel (Mail Code 2344A),OMB DRAFT: Please do not cite, quote, or distribute Page 6 of 142 Environmental Protection Agency, 1200 Pennsylvania Ave., NW., Washington, DC 20004. Note, under CAA section 307(b)(2), the requirements established by this final rule may not be challenged separately in any civil or criminal proceedings brought by EPA to enforce these requirements. Acronyms and Abbreviati ons . The following acronyms and abbreviations are used in this document. 3
- D three - dimensional AMA active monitoring area CAA Clean Air Act CBI confidential business information CCS carbon dioxide capture and geologic sequestration CFR Code of Federal Regulations CO 2 carbon dioxide DOE Department of Energy EAB Environmental Appeals Board EIA Economic Impact Analysis EPA Environmental Protection Agency E O Executive Orde r ER enhanced oil and gas recovery GHG greenhouse gas GS geologic sequestration ICR Information Collection Request IRS Internal Revenue Service MMA maximum monitoring area MRV monitoring, reporting , and verification NAICS North American Industry Classification System NTTAA National Technology Transfer and Advancement Act OAR Office of Air and Radiation OMB Office of Management and Budget OW Office of Water QA/QC quality assurance/quality controlOMB DRAFT: Please do not cite, quote, or distribute Page 7 of 142
R&D research and development RFA Regulatory Flexibility Act SBREFA Small Business Regulatory Enforcement Fairness

Act SDWA Safe Drinking Water Act TSD technical support document UIC Underground Injection Control US United States UMRA Unfunded Mandates Reform Act of 1995 USDW underground source of drinking water VEF Vulnerability Evaluation Framework Table of Contents I. Background A. Organization of this Preamble B. Background on the Final Rule C . Legal Authority D . Relationship to Underground Injection Control Regulations under the Safe Drinking Water Act E. Relationship to the Interagency Task Force on Carbon Capture and Storage and Other Federal Geologic Sequestration Initiatives F . Relationship to Other Geologic Sequestration Information Collection and Reporting Efforts II. Summary of Final Rule A . Summary of Changes to the General Provisions of the Greenhouse Gas Reporting Program B . Summary of the Reporting Requirements for Geologic Sequestration of Carbon Dioxide ( Subpart RR) C . Summary of the Reporting Requirements for Injection of Carbon Dioxide (Subpart UU) D . Summary of the Major Changes Since Proposal E . Summary of Comments and Responses
I II . Economic Impacts of the Rule A. How were compliance costs estimated?OMB DRAFT: Please do not cite, quote, or distribute Page 8 of 142
B. What are the costs of the rule? C. What are the economic impacts of the rule? D. What are the impacts of the rule on small businesses? E. What are the benefi ts of the rule for society?
IV. Statutory and Executive Order Reviews A. Executive Order 12866: Regulatory Planning and Review B. Paperwork Reduction Act C. Regulatory Flexibility Act (RFA) D. Unfunded Mandates Reform Act (UMRA) E. Executive Order 13132: Federalism F. Executive Order 13175: Consultation and Coordination with Indian Tribal Governments G. Executive Order 13045: Protection of Children from Environmental Health Risks and Safety Risks H. Executive Order 13211: Actions that Significan tly Affect Energy Supply, Distribution, or Use I. National Technology Transfer and Advancement Act J. Executive Order 12898: Federal Actions to Address Environmental Justice in Minority Populations and Low
Income Populations K. Congressional Review Act I. Background A. Organization of this Preamble This preamble is divided into four large sections, as detailed above in the Table of Contents. The paragraphs below describe the layout of the preamble and provide a brief summary of each section. The f irst section of this preamble contains the basic background information about the origin of this rule , including a discussion of how it relates to the finalizedOMB DRAFT: Please do not cite, quote, or distribute Page 9 of 142 requirements for s uppliers of CO 2 (under 40 CFR part 98, subpart PP) . It also contains informa tion on EPA’s legal authority and how this rule relates to the Underground Injection Control ( UIC ) program , the Interagency Task Force on Carbon Capture and Storage and other federal GS initiatives, as well as other GS information collection and reporting efforts . The second section of this preamble provides an overview of the Greenhouse Gas (GHG) Reporting Program and confidentiality determination for data elements in the GHG Reporting Program, and summarizes changes to the general provisions of the GH G Reporting Program . It also provides a summary of this final rule on key design elements such
as: source category definition, reporting threshold, GHGs to report, GHG calculations and monitoring, data reporting, and recordkeeping requirements. In additi on, it describes the major changes made since the proposal and p rovides a brief summary of public comments and EPA’s responses The third section of this preamble provides the summary of the cost impacts, economic impacts, and benefits of this rule and disc usses comments o n the regulatory impacts analysi s .OMB DRAFT: Please do not cite, quote, or distribute Page 10 of 142 Finally, the last section of this preamble discusses the various statutory and executive order requirements applicable to this proposed rulemaking. B. Background on the Final Rule Today’s action finaliz es monitoring and reporting requirements for injection and geologic sequestration of carbon dioxide. On April 12, 2010, EPA proposed this rule amend ing 40 CFR part 98 . 40 CFR part 98 provides the regulato ry framework for the GHG Reporting Program . The G HG Reporting Program requires reporting of GHG emissions and other relevant information from certain source categories in the United States . The GHG Reporting Program , which became effective on December 29, 2009, includes reporting requirements for facili ties and GHG suppliers in 32 subparts . For more detailed background information on the GHG Reporting Program, see the preamble to the final rule establishing th at program (74 FR 56260, October 30, 2009) . S ubpart PP of the GHG Reporting Program requires the reporting of CO 2 supplied to the economy . During the public comment period on the final rule establishing that requirement , EPA received many comments that CO 2 geologically sequestered should be considered in the GHG Reporting Program . (For further i nformation on relevantOMB DRAFT: Please do not cite, quote, or distribute Page 11 of 142 comments received in subpart PP see “Mandatory Greenhouse Gas Reporting Rule: EPA's Response to Public Comments, Subpart PP: Suppliers of Carbon Dioxide” in Docket EPA - HQ OAR - 2008
- 0508 . ) In the final rule promulgating subpart PP , EPA committed to taking action to collect such data in the near future. Today’s rule amends 40 CFR part 98 to add reporting requirements covering facilities that conduct geologic sequestration of CO 2 (subpart RR) and all other facilities that conduct injec tion of CO 2 (subpart UU) . This data will inform Agency decisions under CAA sections 111 and 112 related to the use of carbon dioxide capture and geologic sequestration ( CCS ) for mitigating GHG emissions. S ubpart RR information will enable EPA to monitor the growth and efficacy of GS (and therefore CCS) as a GHG mitigation technology over time and to evaluate relevant policy options. For example, EPA will be able to track whether incentives or regulations are needed to encourage faster or further GS proj ect development. Furthermore, where enhanced oil and gas recovery (ER) projects are reporting under subpart RR , EPA will be able to evaluate ER
as a non - emissive end use . Under s ubpart UU , EPA will be able to reconcile information obtained from this rule withOMB DRAFT: Please do not cite, quote, or distribute Page 12 of 142 data obtained from subpart PP on CO 2 supplied to the economy. Today’s rule was proposed by EPA on April 12, 2010 . One public hearing was held on April 19, 2010, and the sixty day public comment period ended June 11, 2010 . This rule takes into consideration comments received during the comment period and finalizes the monitoring and reporting requirements for facilities conducting GS and all other facilities conducting CO 2 injection . Today's final rule does not address whether data reported under subparts RR or UU will be released to the public or will be treated as CBI. EPA published a proposed rule on confidentiality determination on July 7, 2010 (75 FR 39094) which addressed this issue. In that action, EPA proposed which specific data elements wo uld be released to the public and which would be treated as CBI. EPA received several comments on that proposal under that action, and is in the process of considering these comments. A final rule and determination will be issued before any data is relea sed. The final determination will address CBI considerations for all of the data elements under subparts RR and UU. C . Legal AuthorityOMB DRAFT: Please do not cite, quote, or distribute Page 13 of 142
A s proposed, EPA is promulgating this rule under its existing CAA authority ; specifically , authorities provided in CAA section 114. As discussed in detail in Sections I.C and II.Q of the preamble to the final rule establishing the GHG Reporting Program (74 FR 56260 , October 30, 2009 ) , CAA section 114 provides EPA with the authority to require the information mandated by this rule because such data will inform and are relevant to EPA’s implementation of a wide variety of CAA provisions. Under CAA section 114(a)(1), the Administrator may require emissions sources, persons subject to the CAA, or persons whom the Administ rator believes may have necessary information to monitor and report emissions and provide such other information as the Administrator requests for the purposes of carrying out the provisions in the CAA (except for a provision of title II with respect to mo tor vehicles). EPA may gather information for a variety of purposes , including for the purpose of assisting in the development of implementation plans or of emissions standards under CAA section 111, determining compliance with implementation plans or suc h standards, or more broadly for “carrying out any provision” of the CAA. D . Relationship to Underground Injection Control Regulations under the Safe Water Drinking ActOMB DRAFT: Please do not cite, quote, or distribute Page 14 of 142 The Agency maintains a high
- level of coordination across EPA offices and regions on GS activities and regulatory development. EPA’s O ffice of Air and Radiation (OAR ) and Office of Water ( OW ) work closely to promote safe and effective implementation of GS technologies while ensuring protection of human health and the environment . OAR and OW have closely coordinated t his rulemaking under CAA authority and the rulemaking under Safe Drinking Water Act (SDWA) authority establishing Federal requirements under the UIC program for Class VI wells (hereafter referred to as the UIC Class VI rule). EPA’s UIC program was established in the 1970s to prevent endangerment of underground sources of drinking water ( USDWs ) from injection of various fluids , including CO 2 for ER , oil field fluids, water stored for drinking water supplies, and municipal and i ndustrial waste . The UIC program, which is authorized by Part C of SDWA (42 U.S.C. 300h et seq .) , is designed to prevent the movement of such fluid into USDWs by addressing the potential pathways through which injected fluids can migrate and po tentially e ndanger USDWs . In 2008, EPA proposed to amend the UIC program t o establish a new class of injection well

— Class VI

— to cover the underground injection of CO 2 for the purpose of GS, or long - term storage of CO 2 (73 FR 43492 ,OMB DRAFT: Please do not cite, quote, or distribute Page 15 of 142 July 25, 2008 ) . For a summary of the UIC program a nd more details on the final UIC Class VI rule, please see the UIC Geologic Sequestration of Carbon Dioxide Web site . 1 EPA designed the reporting requirements under subpart RR with careful consideration of UIC requirements, including Class VI , to minimize overlap between the two programs . There are two areas of potential overlap (see Table 3). The first overlap is the requirement that owners or operators report the quantity of CO 2 injected . The UIC Class VI rule requires owners or o perators to continuously monitor the amount of CO 2 injected and submit semi
- annual reports on the monthly amount injected. The UIC program requires information on the amount injected to ensure appropriate CO 2 injection operations . Subpart RR requires fac ilities to collect data on the amount injected over a quarter and submit annual reports on the annual amount of CO 2 injected. Data on the amount of CO 2 injected is a component of the subpart RR mass balance approach 2 used to quantify the amount of CO 2 se questered. EPA determined that quarterly data collection and annual reporting under

1 http://www.epa.gov/ogwdw000/uic/wells_sequestration.html . 2 The subpart RR mass balance equation for quantifying the amount of CO 2 that is geologically sequestered includes variables on injected CO 2 ; fugitive and vented CO 2 emis sions from surface equipment between the flow meters and the wellhead; CO 2 produced and/or remaining with produced oil, gas or other fluids; and CO 2 leakage to the surface. For more information, see Section II.B of this preamble.OMB DRAFT: Please do not cite, quote, or distribute Page 16 of 142 subpart RR was necessary in order to harmonize data with other subparts of the GHG Reporting Program. Facilities reporting under subpart RR may use flow meter s used to
comply with the flow monitoring and reporting provisions in their permit .
Table 3 . Comparison of Reporting Requirements under Subpart RR with UIC Class VI Regulations Reporting Requirement Subpart RR UIC Class VI Quantity of CO 2 received Yes N /A Quan tity of CO 2 injected Yes Yes Fugitive and vented emissions from surface equipment between flow meters and the wellhead Yes N /A

Quantity of CO 2 produced with oil or natural gas (ER) or other fluids Yes N /A

Percent age of CO 2 estimated to remain with oil ( ER) or other fluids Yes N /A
Quantity of CO 2 emitted from the subsurface Yes N /A Quantity of CO 2 sequestered in the subsurface Yes N /A
Cumulative mass of CO 2 sequestered in the subsurface Yes N /A
Monitoring plan for detecting air emissions Yes YesOMB DRAFT: Please do not cite, quote, or distribute Page 17 of 142
Moni toring plan for quantifying air emissions Yes N /A

The second overlap is a monitoring plan for detecting air emissions. While requirements under the UIC program are focused on demonstrating that USDWs are not endangered as a result of CO 2 injection into the subsurface, requirements under the GHG Reporting Program through subpart RR will enable EPA to verify the quantity of CO 2 that is geologically sequestered and to assess the efficacy of GS as a mitigation strategy . Subpart RR achieves this by requiring facilities conducting GS to develop and implement a n MRV plan 3 to detect and quantify leakage of injected CO 2 to the surface in the event leakage occurs and to report the amount of CO 2 geologically sequestered using a mass balance approach, regardless of the class of UIC permit that a facility holds . The monitoring required by subpart RR for quantification purposes is complementary to and builds on UIC permit requirements. In particular, the UIC Class VI

3 The subpart RR MRV plan includes delineation of monitoring areas, identification of potential surface leakage pathways, a strategy for detecting and quantifying surface leakage of CO 2 if leakage occurs, an approach for establishing the expected environmental and operational base lines and a summary of considerations for calculating site
- specific variables for the mass balance equation, such as calculating CO 2 in produced fluids. For more information, see Section II.B of this preamble.OMB DRAFT: Please do not cite, quote, or distribute Page 18 of 142 permit requires a comprehensive site characterizati on that includes an assessment of the geologic, hydrogeologic, geochemical, and geomechanical properties of the proposed GS site to ensure that GS wells are located in suitable formations. The UIC Class VI permit also requires computational modeling of th e Area of Review, and a periodic re
- evaluation of this Area of Review based on robust modeling and monitoring of the CO 2 stream, injection pressures, integrity of the injection well, groundwater quality and geochemistry, and the position of the CO 2 plume
a nd pressure front throughout injection. These requirements can provide the basis for the MRV plan submitted to EPA for subpart RR. Therefore, EPA will accept a UIC Class VI permit to satisfy certain MRV plan requirements ; however, the reporter must inclu de additional information to outline how monitoring will achieve surface detection and quantification of CO 2 in the event leakage
occurs
. The UIC Class VI rule also allows f or surface air and soil gas monitoring at the discretion of the UIC Director
as a means of identifying CO 2 leaks that may pose a risk to USDWs and informing emergency notification of a Class VI owner or operator and UIC Director in the event of a USDW endangerment. If the UIC Director determines that it isOMB DRAFT: Please do not cite, quote, or distribute Page 19 of 142 appropriate to require surf ace air or soil gas monitoring for USDW protection, the UIC Director must approve the use of monitoring employed under subpart RR so long as the owner or operator is able to demonstrate USDW protection pursuant to requirements at § 146.90(h)(3). EPA has de termined that the requirements of these two rules complement one another by concurrently ensuring USDW protection, as required under SDWA , and requiring reporting of CO 2 surface emissions under subpart RR. EPA is committed to work ing closely within the ag ency to coordinate implementation of the UIC and GHG Reporting programs, reduce burden on reporters, provide timely access to verified emissions data, establish mechanisms to efficiently share data, and harmonize data systems to the extent possible. E. Re lationship to the Interagency Task Force on Carbon Capture and Storage and Other Federal Geologic Sequestration Initiatives On February 3, 2010, President Obama established an Interagency Task Force on Carbon Capture and Storage (CCS Task Force) . The CCS Task Force, co - chaired by EPA and the Department of Energy (DOE) , developed a plan to overcome the barriers to the widespread, cost
- effective deployment of CCS within ten years, with a goal of bringing five toOMB DRAFT: Please do not cite, quote, or distribute Page 20 of 142 ten commercial demonstration projects online by 2016. The CCS Task Force’s plan was delivered to President Obama in August 2010. The CCS Task Force explored incentives for commercial CCS adoption and addressed financial, economic, technological, legal, institutional, social, or other barriers to de ployment. For example, the CCS Task Force examined Federal regulatory activities that address the safety, efficacy, and environmental soundness of GS. The CCS Task Force also considered how best to coordinate existing administrative authorities and progr ams, including those involving international collaboration, as well as identified areas where additional administrative authority may be necessary. The CCS Task Force recommended [___] . 4 For more information, please see the CCS Task Force W eb site . 5 F . Relationship to Other Geologic Sequestration Information Collection and Reporting Efforts EPA reviewed and took into account several existing domestic and international reporting and monitoring programs in designing this rule. For additional

4 [Note to draft: This section will be updat ed with relevant CCS Task Force recommendations after the CCS Task Force report is finalized.] 5 http://www.whitehouse.gov/administration/eop/ceq/initiatives/ccs .OMB DRAFT: Please do not cite, quote, or distribute Page 21 of 142 information, please see Section I.F of the notice of proposed rulemaking ( 75 FR 18581, April 12, 2010). A lso as discussed in the notice of proposed rulemaking , EPA notes that the Internal Revenue Service (IRS) published IRS Notice 2009
- 83 6 to provide guidance regardi ng eligibility for the Internal Revenue Code section 45Q credit for CO 2 sequestration , computation of the section 45Q tax credit, reporting requirements for taxpayers claiming the section 45Q tax credit, and rules regarding adequate security measures for s ecure GS . A s clarified in the IRS guidance, taxpayers claiming the section 45Q tax credit must follow the appropriate UIC requirements. The guidance also clarifies that taxpayers claiming section 45Q tax credit must follow the monitoring, reporting, and verification procedures that are being finalized under subpart RR in this action . II. Summary of Final Rule A . Summary of Changes to the General Provisions of the Greenhouse Gas Reporting Program Today’s action amends certain requirements in 40 CFR par t 98, subpart A (General Provisions) . These amendments are summarized in this section of the preamble and apply only to those subparts included in this action. None of

6 Availabl e at: http://www.irs.gov/irb/2009
- 44_IRB/ar11.html#d0e1860.OMB DRAFT: Please do not cite, quote, or distribute Page 22 of 142 the amendments change the general provisions applicable to those subparts already inco rporated into 40 CFR part 98. Changes to Applicability . In today’s action, EPA is amending 40 C FR 98.2(a) so that the GHG Reporting Program applies to facilities located on or under the Outer Continental Shelf. These revisions are necessary to ensure th at any facility conducting CO 2 injection or GS located on or under the Outer Continental Shelf of the United States will be required to report. Other facilities covered by the GHG Reporting Program at 40 CFR part 98 are also being affected by this change to applicability (for example, subpart W petroleum and natural gas systems). Changes to Definitions. In today’s action, EPA is also amending 40 CFR 98.6 (definitions ). EPA is clarifying the definition of United States to be clear that the United States includes the territorial seas. Other facilities located offshore of the United States covered by the GHG Reporting Program at 40 CFR part 98 will be affected by this change in the definition of United States (for example, subpart W petroleum and natural g as systems). EPA has also amended 40 CFR part 98 by adding a definition of “Outer Continental Shelf.” This definition is drawn from the definition in the U.S. Code . These revisions are necessary to ensure that any facility conducting CO 2OMB DRAFT: Please do not cite, quote, or distribute Page 23 of 142 injection or GS located on or under the Outer Continental Shelf of the United States will be required to report . 7 B . Summmary of the Reporting Requirements for Geologic Sequestration of Carbon Dioxide (Subpart RR) Reporting requirements for facilities conducting GS
a re found in subpart RR. T hese facilities are required to report the amount of CO 2 received, develop and implement an EPA - approved MRV plan , and report the amount of CO 2 sequestered using a mass balance approach , by subtracting total CO 2 emissions from CO 2 injected in the reporting year . O ther facilities injecting CO 2 underground report under subpart UU. Subpart RR Source Category Definition. The subpart RR source category consists of any well or group of wells that inject a CO 2 stream for long - term contai nment into a subsurface geologic formation . All wells permitted as Class VI by the UIC program meet the definition of this source category . Facilities conducting ER are not subject to subpart RR unless they choose to opt
in to the requirements of this subpart or hold a UIC Class VI permit. GS R&D projects can apply for an exemption from reporting requirements under subpart RR. In order to
7 [Note to draft: Whichever rule finalizes first (subpart W or subpart RR/UU) will have these amendments.]OMB DRAFT: Please do not cite, quote, or distribute Page 24 of 142 obtain an exemption, the owner or operator must demonstrate to the Administrator’s satisfaction that the project is
n either a demonstration nor a commercial project and that the project is researching practices and monitoring techniques that will enable safe and effective long
- term containment of a CO 2 stream in subsurface geologic formations. Projects applying for an e xemption must submit information on the p lanned duration of CO 2 injection for research, the planned annual CO 2 injection volumes during this time period , the research purpose s of the project , the source and type of funding for the project , whether research results will be published, and the class and duration of UIC permit , or, for an offshore facility not subject to SDWA, a description of the legal instrument authorizing GS . EPA will issue a fina l decision on the request for an R&D exemption and notify th e owner or operator within 120 days of receipt of the request . Subpart RR Reporting Threshold. All facilities that meet the subpart RR source category definition must report . Once a facility is subject to the requirements of this subpart, including faci lities that opt
- in to subpart RR , the owner or operator must continue for each year thereafter to comply with all requirements of this subpart, including the requirement toOMB DRAFT: Please do not cite, quote, or distribute Page 25 of 142 submit annual reports, until the owner or operator has made a request to discontinu e reporting that demonstrates that the CO 2 plume has stabilized and EPA has issued a final decision on the request to discontinue reporting . Subpart RR GHGs to Report. F acilities covered by this source category must report the mass of CO 2 received ; the mas s of CO 2 injected; the mass of CO 2 produced; the mass of CO 2 emitted from surface leakage ; the mass of fugitive and vented CO 2 emissions from sources between the injection flow meter and between the injection wellhead or the production flow meter and the p roduction wellhead ; and the mass of CO 2 sequestered in subsurface geologic formations . Subpart RR GHG Calculation s and Monitoring. F acilities covered by this source category must calculate the annual mass of CO 2 received. Starting from the date outlined in the EPA
- approved MRV plan, f acilities must also use a mass balance approach to calculate the mass of CO 2 geologically sequestered. First, facilities must calculate the annual mass of CO 2 injected . From the annual mass of CO 2 injected , facilities must subtract the mass of CO 2 emitted from surface leakage and the mass of CO 2 emitted as fugitive or vented emissions from applicable surface equipment , using the procedures spe cified in Subpart W ofOMB DRAFT: Please do not cite, quote, or distribute Page 26 of 142 the GHG Reporting Program. Facilities that are producing, oil, gas, or other fluids must additionally subtract the mass of CO 2 produced . Calculation procedures are provided at §98.443 of the rule . Subpart RR Geologic Sequestration Monitoring, Reporting, and Verification (MRV) Plans. F acilities must develop a n MRV plan, submit the MRV plan to EPA, receive an approv ed MRV plan from EPA, implement the EPA - approved plan, and submit annual report s . The MRV plan must include five major components : X Delineation of the maximum monitoring area (MMA) and the active mo nitoring area (AMA). X I dentification and evaluation of the potential surface leakage pathways and an assessment of the likelihood, magnitude, and timing, of surface leakage of CO 2 through these pathways . X A strategy for detecting and quantifying any surf ace leakage of CO 2 in the event leakage occurs. X An approach for establishing the expected environmental and operational baselines. X A s ummary of considerations made to calculate site
specific variables for the mass balance equation . First, the MRV plan must include a delineation of the maximum monitoring area (MMA) and the active monitoringOMB DRAFT: Please do not cite, quote, or distribute Page 27 of 142 area (AMA). The MMA includes the extent of the free phase CO 2 plume over the lifetime of the project plus a buffer zone of one - half mile. The AMA is the area that w ill be monitored over a specifi ed time interval chosen by the reporter that is greater than one year . The first time interval will begin from the date determined in your MRV plan through the date at which the MRV plan calls for the first expansion of the AMA. The boundary of the AMA is established by superimposing two areas. The first is the area projected to contain the free phase CO 2 plume at the end of the specified time interval plus an all around buffer zone of at least one - half mile or greater if kn own leakage pathways extend laterally more than one - half mile. 8 The second is the area projected to contain the free phase CO 2 plume five years beyond the specified time interval . Second, the MRV plan must include i dentification and evaluation of potent ial surface leakage pathways within the MMA and an assessment of the likelihood, magnitude, and timing, of surface leakage of CO 2 through these pathways . Possible conduits for CO 2 leakage include faults, fractures, and abandoned wells.

8 In some cases, the actual footprint of the free phase CO 2 plume and the area that is projected to contain the free phase CO 2 plume after five years may be the same. The one - half mile or greater area provides a buffer zone in the case that upward migration of a CO 2 leak moves laterally as it approaches the surface.OMB DRAFT: Please do not cite, quote, or distribute Page 28 of 142 Third, the MRV pl an must describe the strategy for detecting and quantifying surface leakage of CO 2 in the event leakage occurs . It should include a description of the approach for determining whether leakage has occurred , an explanation of how CO 2 leaks will be distingui shed from background or operational variability , and the approach for quantifying detected and verified surface leakage . The expected performance of the selected leakage detection monitoring system or technical specifications should also be described in t he MRV plan. If a leak is detected, the reporter should have a strategy in place to verify that a leak has occurred, confirm the location and source of the leak , and then apply some combination of direct measurement and estimation to quantify the leak. Fourth, the MRV plan should include an approach for establishing the expected environmental and operational baselines. The MRV plan should describe how the baselines will be determined, how they will be measured or calculated, how they could be used to de tect monitoring anomalies, and the operating conditions and variability. Fifth, the MRV plan should include a s ummary of considerations made to calculate fugitive and vented emissions from surface equipment between the flow metersOMB DRAFT: Please do not cite, quote, or distribute Page 29 of 142 and either injection or production wellheads, and the quantity of CO 2 that is produced with oil or other fluid s . EPA will send a notice of receipt to the reporter within 15 days to acknowledge that EPA has received the MRV plan submission. EPA will determine if the MRV plan is
c omplete within 45 days of the notice of receipt and will notify the reporter whether the plan is complete or incomplete. If incomplete, the reporter must submit an updated MRV plan within 45 days of EPA notification unless otherwise specified by EPA. On ce EPA determines that the MRV plan is complete, technical review will commence. After 60 days of technical review, EPA will send the reporter a request for additional information including clarifying technical questions, if necessary. The reporter will be encouraged to provide a response to this request within 15 days, however EPA recognizes that there may be circumstances where additional time is needed for the reporter to collect the information requested. Following this iterative process, EPA will i ssue a final MRV plan as submitted, or with revisions. EPA will post the approved MRV plan on a public website, pending the CBI determination (see section I.B of this preamble). If the reporter, or any interested person, objects to EPA’sOMB DRAFT: Please do not cite, quote, or distribute Page 30 of 142 final decision, it may be appealed to EPA’s Environmental Appeals Board. Facilities must re
- submit the MRV plan for EPA approval if a material change was made to monitoring and/or operational parameters, if the facility’s UIC permit class changes, or if an EPA review of t he annual report determines that it is necessary. Examples of material changes include but are not limited to a large change in the volume of CO 2 injected; the construction of new injection wells not referred to in the MRV plan; large changes in injection pressures; failures of the monitoring system including monitoring system sensitivity, performance, location, or environmental baseline; changes to surface land use that affects baseline or operational conditions; observed plume location that differs from the predicted plume area used for developing the monitoring plan; a change in the MMA or AMA ; or a change in monitoring technology that would result in coverage or detection capability different from what is specified in the MRV plan. As an example of a f acility’s UIC permit class changing, the UIC Class VI rule provides that UIC Class II ER projects must seek a UIC Class VI permit when there is an increased risk to USDWs compared to UIC Class II operations. Please see §144.19 of the UIC Class VI ruleOMB DRAFT: Please do not cite, quote, or distribute Page 31 of 142 for a list of risk
- based criteria that the UIC Director shall use to determine if the owner or operator of a UIC Class II ER project must apply for and obtain a UIC Class VI permit. This list of criteria may also be used by Class II ER project owners and ope rators to self - determine if they need to apply for and obtain a UIC Class VI permit. If a facility’s UIC permit were to change from Class II to Class VI, it would be required to submit a revised MRV plan to EPA for approval. Subpart RR Data Reporting. In addition to the information summarized at “Subpart RR GHGs to Report” in this section of the preamble, facilities must report the source of the CO 2 received and the cumulative amount of CO 2 geologically sequestered since the facility first reported under subpart RR. Facilities must also report concentration , and mass or volumetric flow information where flow meters are used or mass or volume where containers are used . They are required to report a description of the monitoring program that was implemente d, including descriptions of monitoring anomalies and surface leakage, if any . Finally, for EPA verification purposes, they are required to report for each injection well the class of UIC permit and well identification number used for the UIC permit , .OMB DRAFT: Please do not cite, quote, or distribute Page 32 of 142
S ubpart RR requires reporting of fugitive and vented CO 2 emissions to the extent they are a component of the GS mass balance . Subpart RR does not require reporting of fugitive and vented CO 2 emissions from all surface equipment located within the facility ; however, facilities may be required to report fugitive and vented CO 2 emissions in the petroleum and natural gas system subpart, subpart W . Subpart RR Recordkeeping . F aciliti es must retain quarterly records of CO 2 received ; injected CO 2 ; produced CO 2 ; C O 2 emitted by surface leakage; CO 2 emitted as fugitive and vented emissions from equipment located on the surface between the flow meter used to measure the injection quantity and the injection wellhead and between the flow meter used to measure the produc tion quantity and the production wellhead; and any other records as outlined for retention in the facility MRV plan. Subpart RR Administrative Appeals . Under today’s final rule, final decisions of the Administrator under part 98, subpart RR are appealable to EPA’s Environmental Appeals Board under the regulations that are set forth in part 78 (40 CFR part 78). Part 78 is revised to accommodate such appeals. Specifically, the list in § 78.1 of the types of final decisions that can beOMB DRAFT: Please do not cite, quote, or distribute Page 33 of 142 appealed under part 78 is expanded to cover final decisions of the Administrator under subpart RR of part 98 . Th is list includes, but is not limited to, the following specific types of decisions under subpart RR, e.g., the approval or disapproval of a request for an R&D exempt ion under §98. 44 0 ( d )( 4 ) , the approval or disapproval of a request for discontinuation of reporting under § 98.441( b )(2) , and the approval or disapproval of a MRV plan under § 98.448( c ). Further, § 78.3 is revised to allow for petitions for administrative appeal of decisions of the Administrator under subpart RR. Under the general approach in the existing part 78, an “interested person” (in addition to the official representative of owners and operators involved in a matter) may petition for an administrati ve appeal of a final decision of the Administrator. The “interested person” definition, which is located in part 72 of the Acid Rain Program regulations, is expanded to take into account final decisions of the Administrator under part 98. In particular, the revised “interested person” definition is expanded to include, with regard to any decision by the Administrator, any person who
-- in connection with the Administrator’s process of making that decision
-- submitted comments, testified at a publicOMB DRAFT: Please do not cite, quote, or distribute Page 34 of 142 heari ng, submitted objections, or submitted his or her name to be included by the Administrator in an interested persons list. In addition, § 78.4 is expanded to state that filings on behalf of owners and operators of a facility subject to subpart RR must be signed by the designated representative of the owners and operators. E . Summmary of the Reporting Requirements for Injection of Carbon Dioxide (Subpart UU) Reporting requirements for all other facilities conducting CO 2 injection are found in subpart UU. Facilities conducting GS and reporting under subpart RR are not required to report under subpart UU. Subpart UU Source Category Definition. The subpart UU source category consists of any well or group of wells that inject a CO 2 stream into the subsurf ace . This includes any wells used to enhance oil and gas recovery and GS R&D projects which are exempted from subpart RR monitoring and reporting requirements. If you report under subpart RR for a well or group of wells, you are not required to report un der subpart UU for that well or group of wells . Subpart UU Reporting Threshold.OMB DRAFT: Please do not cite, quote, or distribute Page 35 of 142 All f acilities that inject CO 2 underground must report under this subpart, regardless of the amount of emissions from the facility or the amount of CO 2 injected. Subpart UU GH Gs to Report. F acilities covered by this source category must report the annual mass of CO 2 received. Subpart UU GHG Calculation s and Monitoring. F acilities covered by this source category must calculate the annual mass of CO 2 received using the calculat ion procedures for either mass or volumetric flow meters. Where CO 2 is received in containers , facilities must use the calculation procedures for determining the mass or volume of contents in containers. Subpart UU Data Reporting. In addition to report ing the mass of CO 2 received , facilities must report the source of the CO 2 . Facilities must also report concentration , and mass or volumetric flow information where flow meters are used or mass or volume where containers are used . Subpart UU Recordkeeping . F acilities must retain quarterly records of CO 2 received . F . Summary of the Major Changes Since ProposalOMB DRAFT: Please do not cite, quote, or distribute Page 36 of 142 The major changes in this rule since the original proposal are identified in the following list. The rationale for these and any other changes to th e rule can be found below or in “ Mandatory Greenhouse Gas Reporting Rule: EPA's Response to Public Comments , Subp art s RR and UU : Injection and Geologic Sequestration of Carbon Dioxide.” X EPA has moved all definitions, requirements, and procedures for fac ilities conducting CO 2 injection only ( which both EPA and commenters have referred to as “Tier 1” facilities for simplicity ) into a new subpart, subpart UU , and retained all definitions, requirements, and procedures related to facilities conducting GS ( wh ich both EPA and commenters have referred to as “Tier 2” facilities for simplicity ) in subpart RR. X EPA has removed the requirement that facilities report the amount of CO 2 injected in subpart UU ( Tier 1 ) but retained requirements that facili ties subject to this subpart rep ort the amount of CO 2 received and the source of CO 2 . X EPA has established procedures for calculating CO 2 received in containers.OMB DRAFT: Please do not cite, quote, or distribute Page 37 of 142
X In subpart RR, EPA has established a waiver process for a GS R&D project to request an exemption from subpart RR . X In subpart RR, EPA has retained the requirement that facilities report the fugitive and vented emissions fo r surface equipment that could be included in the GS mass balance but removed the requirement for reporting fugitive and vented emissions for all other surface equipment. X In subpart RR, EPA has added an MRV plan requirement for the delineation of the areas that will be monitored. X In subpart RR, EPA has clarified the requirements for an addendum to the annual report and renamed it mo nitoring report. X EPA has amended 40 CFR p art 78 to include administrative appeals procedures for EPA decisions made under subpart RR , such as decisions relating to the request for R&D exemption under §98. 44 0 ( d )( 4 ) , decisions relating to a request for dis continuation of reporting under §98.441( b )( 2 ) , or MRV plan decisions under §98.448( c ) . G . Summary of Comments and Responses This section contains a brief summary of major comments and responses. A large number of comments on CO 2 injection and sequestratio n were received covering numerous topics . Responses to significant comments received can beOMB DRAFT: Please do not cite, quote, or distribute Page 38 of 142 found in “Mandatory Greenhouse Gas Reporting Rule: EPA's Response to Public Comments, Subpart s RR and UU : Injection and Geologic Sequestration of Carbon Dioxide.” Legal Authority Comment: EPA received a number of comments regarding its legal authority to require the proposed reporting from facilities conducting CO 2 injection or GS. Some commenters argued that EPA has over - reached its CAA statutory authority, stati ng that the CAA authorizes the regulation of air emissions, not CO 2 injection or GS. One commenter asserted that EPA is overstepping its authority under CAA section 114 by requiring indefinite and broad monitoring and reporting, and that none of EPA’s sta ted purposes in the preamble to the proposal provide adequate justification for the proposed data collection requirements, imposition of new measurement protocols, or installation of new instrumentation. Some commenters also asserted that the FY 2008 Appr opriations Act constrains the scope of EPA’s information gathering to GHG emissions, which does not include CO 2 injection or GS. Some commenters asserted that the proposal was within EPA’s authority under the CAA. Response: EPA is proposing this rule un der the authority provided in CAA section 114. We disagree that we do not have statutory authority to promulgate this rule.OMB DRAFT: Please do not cite, quote, or distribute Page 39 of 142 The Administrator may gather information under CAA section 114, as long as that information is for purposes of carrying out any pr ovision of the CAA. The information submitted to EPA as a result of this rule will inform policy decisions under CAA sections 111 and 112 related to the use of CCS for mitigating GHG emissions. This data will prove invaluable to the Agency in several are as, including reconcil ing subpart UU data on CO 2 received with CO 2 supply data to better understand the amount of CO 2 supply that is used for CO 2 injection and GS, monitor ing the growth and efficacy of GS over time, and evaluat ing ER as a potentially non - e missive end use. EPA is not citing the FY 2008 Consolidated Appropriations Act as the statutory basis for this action. Furthermore, we do not agree that the appropriations language constrains EPA’s ability to collect the information under this action . D efinition of Source Category Comment: EPA received many comments about the definition of source category and GS facility . At least one commenter recommended setting a clearer distinction between CO 2 injection without GS (Tier 1) and CO 2 injection with GS (Tier 2) . This commenter and others recommended a further distinction within the GS group

– GS with ER and GSOMB DRAFT: Please do not cite, quote, or distribute Page 40 of 142 without ER . In addition, several commenters either requested clarification o f or demonstrated a misunderstanding of whether particular provision s of the proposed rule, such as the GS R&D exemption and proposed discontinuation of reporting provisions , would apply to all CO 2 injection, to CO 2 injection with GS only, or to CO 2 injection without GS only. Furthermore, several commenters were confused by the definition of GS facility in the regulatory text and found it to be redundant, complicated, unclear, or vague . At least two commenters urged EPA not to change the definition of facility found in § 98.6 of the GHG Reporting Program General Provisions , while other commenters appeared to support a subpart RR - specific facility definition but raised questions or provided comment about which structures or equipment would be within the GS facility. Some commenters requested edits or additions to the list of activities at § 98.440(d) that are not included in the source category. Response: EPA agrees with commenters that the structure of proposed § 98.44 0 could be made clearer . It was never EPA’s intention to override the definition of facility in § 98.6; rather EPA intended to create a defined term “GS facility” to provide clarity about whichOMB DRAFT: Please do not cite, quote, or distribute Page 41 of 142 facilities under the subpart RR source category would be subject to both “Tier 2” and “Tier 1” requirements . T o harmonize subpart RR with the rest of the GHG Reporting Prog ram as intended and to maximize clarity, the defined term “GS facility” is not included in the final rule . In today’s action, EPA has deleted the term “GS facility” from the regulatory text and has reframed any necessary information as part of the definit ion of “source category” . T he owner or operator of a group of CO 2 injection wells will determine the boundaries of the facility by following the definition in § 98.6 . EPA has provided several examples in the General Technical Support Document ( TSD ) to il lustrate how a facility would be delineated under various operational configurations. In order to effectuate the original intent of the “GS facility” term, and in light of comments expressing confusion between the “Tier 1” and “Tier 2” requirements , EPA is retaining procedures and requirements for facilities conducting GS (Tier 2) in subpart RR and is moving all procedures and requirements for all other facilities conducting CO 2 injection (Tier 1) into a new subpart UU in today’s action . EPA has concluded that this organizational change allows for two source category definitions while clearly distinguishing the two sets of provision s andOMB DRAFT: Please do not cite, quote, or distribute Page 42 of 142 procedures . EPA notes that this new organizational structure is merely formalizing the structure that EPA and commenters have been using to date informally. EPA considered but did not create a third source category as proposed in some comments for GS projects with ER . EPA has concluded that the provisions, procedures, and requirements in subpart RR apply equally to all GS projects

– whether they conduct ER or not . It is most practical to cover both types of projects with one subpart. In today’s final action, EPA removed from the regulatory text the list of activities that are not included in the source category. Based on experience with implementation questions from reporters to the rest of the GHG Reporting Program, EPA has concluded that this list does not provide regulatory clarity and instead creates confusion. Without this list t he regulatory text is clear that the op erations covered under subparts RR and UU are wells that inject CO 2 underground . EPA does not need to explicitly provide a list of operations that do not meet this definition. EPA has found that operators may mistakenly conclude that they are exempt from s ubpart RR or UU reporting requirements if they conduct an activity on the list, even if they also operate wells that inject CO 2 underground. To avoid this confusion, EPA had deleted theOMB DRAFT: Please do not cite, quote, or distribute Page 43 of 142 list from the regulatory text and is clarifying here that operators co nducting any of the following activities need not be concerned with these activities when determining applicability to or reporting under subpart RR or UU: above ground CO 2 storage, CO 2 transportation or distribution, CO 2 purification, compression, or proc essing, CO 2 capture, and CO 2 end - uses other than underground injection. EPA notes that these activities may meet the definition of another source category in the GHG Reporting Program. GS R&D Comment: EPA received a range of comments relating to exempting GS R&D projects. Some commenters supported the R&D exemption while others opposed it because they believe these projects can provide valuable information on the efficacy of GS as a climate miti gation approach. These commente rs also noted that these proje cts are currently gathering data which would provide EPA an early opportunity to evaluate the appropriateness and application of monitoring methods. Some commenters suggested that GS R&D projects be provided an option to opt
- in to GS reporting requirement s. One group of commenters recommended that EPA exempt GS R&D projects on a case
- by - case basis. Response: EPA agrees with commenters that collecting data from all GS projects , including R&D, would provideOMB DRAFT: Please do not cite, quote, or distribute Page 44 of 142 useful information about the efficacy of GS and monitoring techniques and approaches to quantify leakage. Therefore, EPA is removing the broad GS R&D exemption. However, the Agency recognizes that GS is an emerging climate mitigation approach and there are likely to be some projects which are focused on testing specific scientific issues or monitoring techniques rather than verifying GS. Therefore the Agency is establishing a process to allow for a GS R&D exemption. . In order t o obtain an exemption , the owner or operator must demonstrate to the Admi nistrator’s satisfaction that the project is neither a demonstration nor a commercial project and that the project is researching practices and monitoring techniques that will enable safe and effective long - term containment of a CO 2 stream in subsurface ge ologic formations. Projects applying for an exemption must submit information on the p lanned duration of injection for research, planned annual CO 2 injection volumes within this duration, research purpose, source and type of funding, whether research resu lts will be published, and class and duration of UIC permit ( or relevant legal instrument in the case of a n offshore facility that is not subject to SDWA) . This information will inform the Administrator’s decision for granting an exemption. For example, a project could receive an exemption by showing that the project will takeOMB DRAFT: Please do not cite, quote, or distribute Page 45 of 142 place over a limited time period; the annual injection volumes are limited; the project has a research purpose or research question; the project receives funding from the Federal go vernment, State government, academia, or the R&D budget of a private entity; the research results will be published; and the project holds a UIC Class V experimental technology well permit of limited duration . The owner or operator would be notified of EPA’s final decision within 120 days of receipt of the GS R&D exemption request. Comment: Many commenters noted that restricting the proposed exemption to federally funded projects was too stringent, that R&D can also be supported by states, academia, or the private sector, and argued that GS R&D projects should not be defined based on the so urce of funding . Response : The Agency agrees with commenters that there
are non - Federal funding sources which could fund GS R&D projects and that while Federal funding could be an indication that a project is conducting GS R&D, it should not be the basis for an R&D exemption. For example, sources of funding that may indicate that a project is conducting GS R&D include Federal, State, and academic sources. Funding from t he R&D budget of a private sector entity may also indicate that a project is conducting GSOMB DRAFT: Please do not cite, quote, or distribute Page 46 of 142 R&D. Therefore, projects applying for an exemption must submit information on the source and type of funding. Comment: Many commenters suggested that EPA consider a threshold for exempting R&D projects. These commenters noted that a threshold would allow for reduced regulatory burden and that collecting data from projects below the threshold would yield little value for EPA. Response: EPA found that it would be challenging to define a threshold for GS R&D projects because project size could vary depending on the R&D goals and other factors such as availability and source of CO 2 . As stated above, EPA is establishing a waiver process through which GS R&D projects can apply for an exemption from reporting requirements under subpart RR. This option provides EPA with maximum flexibility to exempt GS R&D projects that are researching GS practices and monitoring techniques. Comment: Some commenters recommended that G S R&D projects be required to comply with “Tier 1” requirements, while a few commenters suggested that EPA exempt both Tier 1 and Tier 2 requirements for GS R&D projects. Response: EPA agrees with comments recommending that GS R&D projects report “Tier 1” data . Projects receiving a GS R&D waiver under subpart RR are not required to develop an MRV plan or report information required of facilitiesOMB DRAFT: Please do not cite, quote, or distribute Page 47 of 142 conducting GS. However, these projects are required to report basic information on CO 2 received under subpart UU. EPA determined that GS R&D projects already collect such data and that the burden of reporting such data would be minimal. Reporting Requirements Comment: EPA received many comments about the proposed “Tier 1” reporting requirements . Many commenters from the ER industry in particular urged EPA to remove all “Tier 1” reporting requirements for CO 2 injection projects without GS . These commenters expressed concern that collecting any information from business
- as - usual ER would lead to a misunderstandin g of the CO 2 material balance at such operations . Many stated that data on total CO 2 injected in particular would have no bearing on future policy decisions about GHG emissions and should not be collected . Many commenters conceded that data on the quanti ty of “new” CO 2 received could be collected if EPA insisted on collecting some data from “Tier 1” sources, presumably because it could potentially inform future climate change policy decisions . At least one commenter offered that by collecting data on the quantity of “new” CO 2 received, EPA could reasonably estimate the amount of CO 2 retained underground.OMB DRAFT: Please do not cite, quote, or distribute Page 48 of 142 On the other end of the spectrum, one set of comments echoed that the “Tier 1” reporting requirements as proposed would be insufficient for an accurate C O 2 material balance but recommended expanding “Tier 1” reporting requirements as a solution rather than narrowing or removing them . This set of comments recommended that data on CO 2 recycled from each project be collected so that EPA could get a full unde rstanding of the ER industry. These commenters advocated for collection of quantity data from “Tier 1” reporters , arguing that ER operations dominate CO 2 end - users and the data will be necessary to understand the disposition of CO 2 supply reported under s ubpart PP of the GHG Reporting Program . Meanwhile, at least three commenters offered that the proposed “Tier 1” reporting requirements would be adequate to meet EPA’s stated needs and that no additional data reporting should be required in the final regul ation. Response: In today’s final action, EPA is retaining some of the proposed reporting requirements for CO 2 injection facilities. EPA is requiring reporting under subpart UU (previously referred to as “Tier 1” facilities) of CO 2 received (a term which EPA is defining in this final action for what commenters described as “new” CO 2 ) . EPA is not requiring reporting on total CO 2 injection under subpartOMB DRAFT: Please do not cite, quote, or distribute Page 49 of 142 UU. Reporting on total CO2 injection will be required for facilities conducting GS under subpart RR (pr eviously referred to as “Tier 2” facilities) . EPA has concluded that data on CO 2 received is critical for EPA to better understand the disposition of CO 2 supply reported in subpart PP. Furthermore, EPA recognizes that the geology of an oil and gas reservo ir can create a good barrier to trap CO 2 underground and that many projects in the ER industry could successfully verify and report the geologic sequestration of CO 2 with an EPA
- approved MRV plan . By collecting data on CO 2 received at these facilities, EPA will better understand the scope and size of a potentially non
- emissive end
- use. Due to the comments received on this issue, EPA considered adding recycled CO 2 to the proposed Tier 1 data requirements . Ultimately, EPA concluded that a CO 2 material bala nce is most informative to the Agency from GS projects that verify the quantity of CO 2 geologically sequestration by implementing their EPA
- approved MRV plans . Though the collection of either a partial or full set of data from subpart UU facilities would have given EPA additional data regarding ER operations, it could have also caused confusion amongst reporters and the public about which facilities are estimating and reporting geologic sequestration. By requiring mass balance inputs from GSOMB DRAFT: Please do not cite, quote, or distribute Page 50 of 142 projects only and by splitting the proposed rule into two subparts, EPA is making clear in this action that the quantity of CO 2 geologically sequestered can only be verified and reported to EPA by developing and implementing an EPA - approved MRV plan and reporting GS un der subpart RR . For clarification, EPA reworded the proposed term “CO 2 transferred onsite from offsite” to “CO 2 received” because EPA identified at least one configuration where CO 2 would be supplied to an injection well from an adjacent plant that is part of the same facility (per the definition of facility in section 98.6). Reporting Threshold Comment: EPA proposed “all in” requirements and sought comment on whether and how to establish a threshold . A few of the comments EPA received agreed with EPA’s all - in reporting approach, noting that data from all facilities is significant at this early stage in the GS industry, that at this point there is not enough data to determine a sensible threshold level, that the amount of CO 2 injected in one year is not a good indicator of the amount of CO 2 injected in the follow ing year, and that EPA needs a comprehensive picture of the industry . O ne comment characterized no threshold for “Tier 1” reporting as reasonable because of the associated low burden.OMB DRAFT: Please do not cite, quote, or distribute Page 51 of 142 Other comments opposed the all - in reporting threshold stating that it would burden a higher number of facilities than was necessary . These comments provided a variety of possible approaches and thresholds for EPA to consider including a threshold of 100,000 metric tons per year of “new” CO 2 received , an injection threshold of 25,000 metric tons per year, an injection threshold of 100,000 metric tons of CO 2 per year , an injection threshold of 2
- 3 million metric tons per year, and an emission threshold of 25,000 metri c tons of CO 2 per year . Response: EPA agreed with comment e rs who supported an all - in threshold because it would result in the most comprehensive tracking and reporting . Collecting information on all projects is important at this early stage in the GS in dustry . As demonstrated by the range of suggested thresholds provided by commente rs , there is not enough data to determine a sensible threshold . T he amount of CO 2 injected in one year is not a good indicator of the amount of CO 2 injected in the follow ing year and there are no monitoring standards or data available to determine the amount of CO 2 emitted . In today’s final action, EPA is requiring reporting from all f acilities that meet the subpart UU ( previously referred to as “Tier 1” facilities)
source c ategory definition and from all facilities thatOMB DRAFT: Please do not cite, quote, or distribute Page 52 of 142 meet the subpart RR ( previously referred to as “Tier 2” facilities) source category definition . EPA is not establishing a reporting threshold for these facilities. As noted in the proposal, a n all - in repor ting threshold will allow the Agency to comprehensively track all CO 2 supply (as reported in Suppliers of CO 2 , s ubpart PP) that is received for inject ion underground. This approach is consistent with the all - in requirements in the GHG Reporting Program fo r 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). With respect to subpart UU, EPA has estimated the cost for facilities conducting CO 2 injection to comply with the minimum reporting requirements and has determined that the burden will be small, given the equipment and data collection efforts already in place at ER projects . With respect to subpart RR, the Agency notes that GS R&D pro jects can apply for a waiver to be exempt from subpart RR . EPA has concluded that these two features will ensure that projects receiving and injecting small amounts of CO 2 are not disproportionately burdened by the reporting requirements in today’s final a ction. Fugitive and Vented EmissionsOMB DRAFT: Please do not cite, quote, or distribute Page 53 of 142
Comment: EPA proposed that all facilities subject to “Tier 2” requirements would be required to report fugitive and vented CO 2 emissions from the surface components located within the facility, unless already reported u nder subpart W (petroleum and natural gas systems). A few commenters recommended that EPA require the reporting fugitive and vented CO 2 emissions from facilities (including ER), be required solely under subpart W and to limit the reporting of fugitive and vented emissions reporting under subpart RR to equipment associated with GS operations for which emissions were not already being reported under subpart W. A number of commenters disagreed with EPA’s proposed reporting requirements for fugitive and vente d CO 2 emissions and suggested that EPA scale back or eliminate such reporting, and one commenter supported such reporting requirements . Four commenters stated that fugitive and vented emissions would be trivial in comparison when compared to the amount of CO 2 injected , and three commenters stated that such reporting would unwarrantedly shift CO 2 into a hazardous air pollutant
- like category. One commenter suggested that reporting of fugitive and vented emissions would be germane where applicable to the GS mass balance equation. One commenter supported EPA’s proposedOMB DRAFT: Please do not cite, quote, or distribute Page 54 of 142 requirements for the reporting of fugitive and vented CO 2 emissions. Response: EPA proposed to require the reporting of fugitive and vented CO 2 emissions in order to better understand the volume of fugitive and vented GHG emissions from such facilities as compared to the amount of CO 2 sequestered. However, EPA has concluded that the information that would be generated from such a reporting requirement is not necessary for computing the mass bal ance of the amount of CO 2 sequestered . In the notice of proposed rulemaking, EPA proposed that fugitive and vented CO 2 emissions be included in the GS mass balance calculation if the emissions occur downstream of the CO 2 injection flow meter or upstream of the production flow meter. EPA is retain ing this reporting requirement in subpart RR because such data is important in order to provide a proper accounting of the amount of CO 2 that is geologically sequestered. In this action, EPA is requiring reporti ng of fugitive and vented emissions with respect to equipment located on the surface between the flow meter used to measure injection quantity and the injection wellhead and between the production wellhead and the flow meter used to measure production quan tity. MRV Plan RequirementsOMB DRAFT: Please do not cite, quote, or distribute Page 55 of 142
Comment: EPA received many comments supporting the Agency’s proposal that reporters develop a site
- specific MRV plan , but s ome commenters stated that more detail was needed about how MRV plans would be evaluated by EPA . Resp onse: EPA has set out the basic components for MRV plans in section II. D of this preamble . EPA has clarified the definition of the area where potential leakage pathways should be identified and characterized, and how monitoring could be phased in over time as CO 2 is injected. This is reflected in the regulatory text at § 98.448 (a). EPA has also refined the requirements for what should be included in the annual report, and in what cases the reporter would need to resubmit an MRV plan for EPA approval. EPA’s approach allows for site
- specific flexibility for MRV plans and does not prescribe particular monitoring technologies. The approach also allows the owner or operator to leverage the site characterization, risk assessment , and /or monitoring require d by other authorities
as the foundation for demonstrating compliance with the MRV plan requirements of subpart RR. EPA recognizes the merit in providing greater clarity on the evaluation criteria, but notes that the geology and other conditions among fac ilities conducting GS vary. EPA has prepared anOMB DRAFT: Please do not cite, quote, or distribute Page 56 of 142 appendix to the General TSD 9 that provides information on the technical evaluation of MRV plans. The General TSD provides illustrative examples describing the types of information that may be included in th e MRV plan to fulfill the regulatory requirements at §98.448. This includes delineating the monitoring area, both the maximum area that the CO 2 plume is predicted to cover and how monitoring can be phased in over this area; selecting leakage detection sys tem s that are suitable for the site; determining and verifying that a leak has occurred; identifying baseli ne conditions; and quantifying a CO 2 leak once a leak has been verified . EPA has also finalized the Monitoring P lan TSD , 10 which describes the chara cteristics of a robust monitoring plan, and provides descriptions of potential GS geologic settings and potential leakage pathways . The Monitoring P lan TSD uses EPA’s Vulnerability Evaluation Framework (VEF) 11 to describe potential vulnerabilities that may influence the risk for CO 2 leakage from a GS project . Because t he VEF provides a holistic discussion of the potential impacts of

9 General Technical Support Document for subpart RR (see docket ID No. EPA
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– 0926). 10 Monitoring Plan Technical Support Document (see docket ID No. EPA

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– 0926). 11 Vulnerability Evaluation Framework for Geologic Sequestration of Carbon Dioxide (see docket ID No. EPA

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GS , it is not intended to be used as a step by step guide to develop an MRV plan . Comment: EPA received many comments abou t the procedural aspects of MRV plan approval . Some commenters stated that CO 2 injection should not be allowed until MRV plans are approved. Many c ommenters urged the Agency to allow for public involvement. Response: EPA has set out the general MRV pla n approval process in section II. B of this preamble . EPA has designed MRV plan requirements under subpart RR so that facilities will not need to disrupt or delay normal operations. However, EPA clarifies that facilities will not be allowed to report amou nts of CO 2 geologically sequestered under subpart RR until they implement an EPA
approved MRV plan . EPA agrees with commenters that there should be a process for public involvement . Therefore, EPA plans to post approved MRV plans to a public website, p ending the outcome of the confidentiality determination for data elements in the GHG Reporting Program . “ Interested p erson s ” can then appeal EPA decisions on MRV plan s to the Environmental Appeals Board (EAB) through the appeals process described in p art 78 of the Clean Air Act regulations. An “ i nterested perso n” is any person who --OMB DRAFT: Please do not cite, quote, or distribute Page 58 of 142 in connection with the Administrator’s process of making that decision
-- submitted comments, testified at a public hearing, submitted objections, or submitted his or her name to be included by the Administrator in an interested persons list. EPA wil l provide the public instruction on joining the interested persons list f or subpart RR. More information on the administrative appeals process can be found in section III.A. and in “Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments, Subparts RR and UU: Injection and Geologic Sequestration of Carbon Dioxide . ” If future GS policies or programs are promulgated as a result of the data collected through today ’s rule for which a formal public notice and comment period would be appropriate, EPA will consider establishing a public notice and comment period for such a policy or progam at that time. EPA has prepared an appendix in the General TSD that provides fur ther information about the procedural aspects of MRV plan approval. Comment: EPA received many comments about the role of a UIC permit with respect to MRV plan requirements. Most commenters emphasized the need for coordination between the UIC program a nd subpart RR. Some commenters stated that any class of UIC permit is enough for purposes of the MRVOMB DRAFT: Please do not cite, quote, or distribute Page 59 of 142 plan. Others noted that the MRV plan should build off of the UIC permit and that comprehensive monitoring for the purposes of verifying quantities of CO 2 sequestered cannot occur under S DWA alone. Response: The Agency maintains a high
- level of coordination across EPA offices and regions on GS activities and regulatory development. EPA’s OAR and OW work closely to promote safe and effective implementation of GS technologies while ensuring protection of human health and the environment. EPA agrees with commenters that the UIC program provides the foundation for the safe sequestration of CO 2 by helping to ensure that injected fluids remain isolated in the subsurface and away from underground sources of drinking water , thereby serv ing to reduce the risk of CO 2 leakage to the atmosphere . A facility’s UIC permit may be used to demonstrate that certain monitoring, reporting and verification (MRV) plan requiremen ts have been fulfilled . However, provisions are needed that go beyond what is required of UIC permits in order to quantify leakages, if any . See section I.D of this preamble for a more detailed discussion of subpart RR and UIC Class VI requirements. III . Economic Impacts of the Final RuleOMB DRAFT: Please do not cite, quote, or distribute Page 60 of 142 This section of the preamble examines the costs and economic impacts of the final rule for CO 2 injection and GS , including the estimated costs and benefits of the rule, and the estimated economic impacts of the rule on affected entities, including estimated impacts on small entities. Complete detail of the economic impacts of the rule can be found in the text of the E conomic I mpact Analysis ( E IA) ( EPA - HQ - OAR - 20 09
- 0926 ). This section also contains a brief summary of ma jor comments and responses. A. How were compliance costs estimated? 1. Summary of Method Used to Estimate Compliance Costs EPA estimated costs of complying with the rule and the total incremental annual cost of compliance . A base case is created ass uming relevant monitoring costs required under UIC requirements (including the UIC Class VI rule ) . Then incremental reporting from geologic storage sites were evaluated in terms of required technologies , practices , and costs. The estimated costs include capital and operating and maintenance (O&M) , including labor costs. The cost of drilling and equipping wells represents a large component of sequestration costs. Examples of other costs include seismic data acquisition, periodic sampling and testing of the injected CO 2 .OMB DRAFT: Please do not cite, quote, or distribute Page 61 of 142 The estimated costs are based on hypothetical or pro
forma sites for various types of projects such as R&D GS projects, commercial saline formation projects, and ER GS projects. The geologic and engineering assumption s for these pro - forma projects are the same as those used by the EPA Office of Water in the UIC Class VI rule. The costs are presented in 2008 dollars. The capital costs are annualized using an interest rate of 7 % with projects lasting 4 years , 10 years or 40 years. N ext, annual O&M costs are added to the annualized capital costs to determine total annual direct costs. Finally, a 20 percent overhead and general and administrative cost factor is added to obtain total annual costs . These are then divided by the amount assumed to be injected each year in the pro
- forma project to arrive at total costs per metric ton of CO 2 injected. These per
- ton costs are then used to estimate total annual costs for the level of injection expected in the activity baseline. 2. Summary of Comments and Responses Comment: A majority of the comments received on the compliance costs of the reporting rule focused on facility level costs for monitoring and reporting . One commenter stated that EPA underestimated labor costs in the economic anal ysis of the rule.OMB DRAFT: Please do not cite, quote, or distribute Page 62 of 142 Response: EPA discussed and presented information for the costs and economic impacts of the proposed rule, including the estimated costs and benefits of the proposed rule, and the estimated economic impacts of the proposed rule on affect ed entities, including estimated impacts on small entities . Complete detail of the economic impacts of the proposed rule can be found in Section 4 of the EIA. EPA’s cost estimation methods reflect accepted engineering practices and publicly available cost and price data . For example, EPA used wage rates and overhead factors from the Department of Labor’s Bureau of Labor Statistics. 12 B. What are the costs of the rule? 1. Summary of Costs The total annualized costs incurred under the rule by these entiti es will be approximately $ 7.0 million (2008 $ ) , as illustrated in Table 7 of this preamble . The public sector burden estimate is $ 344,000 for program implementation and verification activities. This may underestimate the total public sector burden dependi ng on the extent to which DOE R&D projects funded with public dollars transition to demonstration or commercial GS and consequently incur costs associated with monitoring, reporting and verification . Given uncertainties related to

12 Bureau of Labor Statistics. http://www.bls.gov/bls/wages.htmOMB DRAFT: Please do not cite, quote, or distribute Page 63 of 142 project adoption and the costs of the reporting program, EPA considered two other private cost scenarios (one higher and one lower than the reference cost scenario) in order to assess a range of economic impacts on affected entities, as illustrated in table 8 of this preamble.

Table 7 . National Annualized Mandatory Reporting Costs Estimates

(2008$): s ubpart s RR and UU Reference Type Number

of Projects Metric

Tons CO 2 Received per Year First Year

(thousand, 2008$) Second Year

(thousand, 2008$) R&D (RR) 9 5,320,000 $73 $73 Facilities Conducting GS (Saline) (RR) 1 1,842,885 $318 $240
Facilities Conducting GS (ER) (RR) 3 3,300,000 $5,913 $5,680
Additional Facilities Conducting GS (ER opt in) (RR) 0 0 $0 $0

Facilities Conducting CO 2 Injection (no GS)(UU) 1 80 40,115,442 $332 $332
Private Sector, Total All Projects 93 50,578,327 $6,636 $6,636 Private Sector, Average ($/ton) - - $0.13 $0.13 Public Sector, Total $344 $344 National Total $6,979 $6,670 ( 1) Includes UIC Class II ER Facilities Table 8 . Annualized Repor ting Costs per Project (2008$): s ubpart s RR

and UU Alternative Cost Scenarios Reference Low High Type First

Year ($1,000) Second

Year ($1,000) First

Year ($1,000 ) Second

Year ($1,000) First

Year ($1,000) Second

Year ($1,000)OMB DRAFT: Please do not cite, quote, or distribute Page 64 of 142 R&D (RR) $8 $8 $8 $8 $8 $8 Facilities Conducting GS (Saline) (RR) $318 $240 $96 $18 $490 $413

Facilities Conducting GS (ER) (RR) $1,971 $1,893 $1,739 $1,662 $2,117 $2,040

Facilities Conducting GS (ER opt in) (RR) $2,029 $1,909 $1,797 $1,678 $2,175 $2,056

Facilities Conducting CO 2 Injection (No GS) (UU) $4 $4 $4 $4 $4 $4

2. Summary of Comments and Responses Comment: EPA received comments on source specific cost data reflected in the engineering cost analysis presented in the Economic Impact Analysis ( E IA), Section 4 (EPA
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- 0926 ) . Some commenters asked EPA to not overly burden entities that may be required to report, and questioned whether the proposed reporting program was duplicative with other EPA regulations on underground injection. Response: EPA considered all relevant comments regarding source specific cost data developed in the engineering cost analysis and used in the Economic Impact Analysis ( E IA) . In some cases, we revised our cost estimates, and in some cases we revised monitoring and reporting requireme nts in ways which reduced burden .OMB DRAFT: Please do not cite, quote, or distribute Page 65 of 142 Please see source specific comments and responses in Section III.D of this preamble and “ Mandatory Greenhouse Gas Reporting Rule: EPA's Response to Public Comments , Subp art s RR and UU: Injection and Geologic Sequestrati on of Carbon Dioxide.” EPA believes the selected option for the mandatory GHG reporting rule strikes a balance between impacts on small entities, consistency with other programs, costs incurred by the reporting entities, and emissions coverage . Section 5 of the f inal Economic Impact Analysis (EIA) ( EPA
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– 0926 ) provides cost comparisons for each alternative evaluated. C. What are the economic impacts of the rule? 1 . Summary of Economic Impacts EPA assessed how the regulatory program may influe nce the profitability of companies by comparing the monitoring program costs to total sales (i.e., a “sales” t est). Given limited data on commercial GS operations, EPA restricted the analysis to ER operations (approximately 90 percent of the fields). To do this, EPA divided the average annualized mandatory reporting costs per field by the estimated revenue for a representative field. Sales test ratios are between 3.1 to 4.0 percent for facilities conducting GS (ER opt in) . In contrast, facilitiesOMB DRAFT: Please do not cite, quote, or distribute Page 66 of 142 conduc ting ER CO 2 injection (no GS) sales test ratios are below 0.01 percent , as illustrated in Table 9 of this preamble . Table 9 . Sales Test for a Representative Commercial ER Field Operation

(2008$) Cost - to - Sales Ratios (CSRs) Alternative Cost Scenario s Reference Low High Facilities Conducting GS (ER) (RR) 3.6% 3.2% 3.9% Facilities Conducting GS (ER opt in) (RR) 3.7% 3.3% 4.0% Facilities Conducting CO 2 Injection (No GS) (UU) <0.1% <0.1% <0.1%
2. Summary of Comments and Responses Comment: EPA re ceived a number of comments on the overall economic impacts of the proposed rule. Some commenters stated that the economic impacts are understated as total national costs could be significantly higher if there is large scale deployment of CCS . Other commenters stated that large increases in operating costs resulting from mandatory reporting of GHGs could prevent projects from moving forward. Response: As described previously, EPA conducted a thorough analysis of available information and reviewed comment s submitted on this issue, and we have determined that this analysis provides a reasonable characterization of costs for facilities in each subpart and that theOMB DRAFT: Please do not cite, quote, or distribute Page 67 of 142 documentation provides adequate explanation of how the costs were estimated . EPA has estimated the total national cost of the reporting program based on current regulations . Accordingly, one would not expect large scale deployment of CCS in absence of a comprehensive climate policy . In response to comments that total national costs would be highe r given large scale deployment of CCS, EPA has augmented the scenario analyzing costs assuming future climate policy in Section 5 of the final Economic Impact Analysis (EIA). D. What are the impacts of the rule on small businesses ? 1. Summary of Impact s on Small Businesses As required by the RFA and the Small Business Regulatory Enforcement and Fairness ACT ( SBREFA ) , EPA assessed the potential impacts of the rule on small entities (small businesses, governments, and non
- profit
or ganizations). (See Sect ion V.C of this preamble for definitions of small entities.) After considering the economic impact of the rule on small entities, EPA has concluded that this action will not have a significant economic impact on a substantial number of small entities. Cu rrently EPA believes small ER operations will most likely be UIC Class II ER p rojects. As shown in Table 9 of this preamble , the average ratio ofOMB DRAFT: Please do not cite, quote, or distribute Page 68 of 142 annualized reporting program costs to revenues of a typical ER operation likely owned by a representative sma ll enterprise was less than 0.1%. Although this rule will not have a significant economic impact on a substantial number of small entities, EPA nonetheless took several steps to reduce the impact of this rule on small entities. For example, EPA ’s monito ring and reporting requirements are buil t off of the UIC program. In addition, EPA is requiring equipment and methods that may already be in use by a facility for compliance with its UIC permit. Also, EPA is requiring annual reporting instead of more fre quent reporting. E. What are the benefits of the rule for society? EPA examined the potential benefits of this rule . EPA’s previous analysis of the GHG Reporting Program discussed the benefits of a reporting system with respect to policy making rel e venc e, transparency issues, market efficiency. Instead of a quantitative analysis of the benefits, EPA conducted a systematic literature review of existing studies , including government, consulting, and scholarly reports. The greatest benefit of mandatory reporting of industry GHG emissions to government will be realized in developing future GHG policies. For example, in the EU ’ sOMB DRAFT: Please do not cite, quote, or distribute Page 69 of 142 Emissions Trading System, a lack of accurate monitoring at the facility level before establishing CO 2 allowance permits resulte d in allocation of permits for emissions levels an average of 15 percent above actual levels in every country except the United Kingdom. Benefits to industry of GHG emissions monitoring include the value of having independent, verifiable data to present t o the public to demonstrate appropriate environmental stewardship, and a better understanding of their emission levels and sources to identify opportunities to reduce emissions. Such monitoring allows for inclusion of standardized GHG data into environmen tal management systems, providing the necessary information to achieve and disseminate their environmental achievements. Standardization will also be a benefit to industry . Once facilities invest in the institutional knowledge and systems to report emiss ions, the cost of monitoring should fall and the accuracy of the accounting should improve. A standardized reporting program will also allow for facilities to benchmark themselves against similar facilities to understand better their relative standing wit hin their industry. IV. Statutory and Executive Order Reviews A . Executive Order 12866: Regulatory Planning and ReviewOMB DRAFT: Please do not cite, quote, or distribute Page 70 of 142 Under Executive Order (EO) 12866 (58 FR 51735, October 4, 1993), this action is a "significant regulatory action” because it may ra ise novel legal or policy issues arising out of legal mandates, the President’s priorities, or the principles set forth in the EO. Accordingly, EPA submitted this action to the Office of Management and Budget (OMB) for review under EO 12866 and any change s made in response to OMB recommendations have been documented in the docket for this action. EPA prepared an analysis of the potential costs and benefits associated with this action in the Economic Impact Analysis (EPA
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- 0926) . A copy of the analys is is available in the docket for this action and the analysis is briefly summarized here . In this report, EPA has identified the regulatory options considered, their costs, the emissions that would likely be reported under each option, and explained the selection of the option chosen for the rule. The costs of the rule are reported in Section 4, and the economic impacts and qualitative benefits assessment are reported in Section 5 . Overall, EPA has concluded that the costs of the Injection and Geologic Sequestration of Carbon Dioxide Reporting Rule are outweighed by the potential benefits of more comprehensive information about CO 2 injection . The total annualized costOMB DRAFT: Please do not cite, quote, or distribute Page 71 of 142 of the rule will be approximately $7 million (in 2008$) during the first year of the p rogram and $6.7 million in subsequent years (344,000 of programmatic costs to the Agency). B. Paperwork Reduction Act The information collection requirements in the final rule have been submitted for approval to the Office of Management and Budget (OMB ) under the Paperwork Reduction Act, 44 U.S.C. 3501 et seq . The Information Collection Request (ICR) document prepared by EPA has been assigned EPA ICR number 2372. 02 . EPA has identified the following goals of the GHG reporting system: X Obtain data that is of sufficient quality that it can be used to analyze and inform the development of a range of future climate change policies and potential regulations. X Balance the rule’s coverage to maximize the amount of emissions reported while excluding small emit ters. X Create reporting requirements that are, to the extent possible and appropriate, consistent with existing GHG reporting programs in order to reduce reporting burden for all parties involved. The information from CO 2 injection and geologic sequestr ation facilities will allow EPA to make well
-OMB DRAFT: Please do not cite, quote, or distribute Page 72 of 142 informed decisions about whether and how to use the CAA to regulate these facilities and encourage voluntary reductions. Because EPA does not yet know the specific policies that will be adopted, the data report ed through the mandatory reporting system should be of sufficient quality to inform policy and program development . Also, consistent with the Appropriations Act, the reporting rule covers a broad range of sectors of the economy. This information collecti on is mandatory and will be carried out under CAA s ection 114 . Information identified and marked as Confidential Business Information (CBI) will not be disclosed except in accordance with procedures set forth in 40 CFR p art 2 . However, emissions informat ion collected under CAA s ection 114 generally cannot be claimed as CBI and will be made public. 13 The projected cost and hour burden for non
- Federal respondents is $7.0 million and 9,416 hours per year. The estimated average burden per response is 56.6 ho urs; the frequency of response is annual for all respondents that must comply with the rule’s reporting requirements, except for electricity
- generating units that are already required to report quarterly under 40 CFR part 75 (acid rain

13 Although CBI determinations are usually mad e on a case - by - case basis, on July 7, 2010, EPA published a proposed rule ( 75 FR 39094) relating to CBI determinations for the data collected under the GHG Reporting Program (40 CFR part 98) .OMB DRAFT: Please do not cite, quote, or distribute Page 73 of 142 program); and the es timated average number of likely respondents per year is 9. The cost burden to respondents resulting from the collection of information includes the total capital and start
- up cost annualized over the equipment’s expected useful life (averaging $717,000 p er year) a total operation and maintenance component (averaging $5.3 million per year), and a labor cost component (averaging $1.0 million per year). Burden is defined at 5 CFR part 1320.3(b) . These cost numbers differ from those shown elsewhere in the EI A for the final rule because ICR costs represent the average cost over the first three years of the rule, but costs are reported elsewhere in the EIA for the first year of the rule and for subsequent years of the rule. Also, the total cost estimate of the rule in the EIA includes the cost to the Agency to administer the program. In addition, the ICR focuses on respondent burden, while the EIA for the final rule includes EPA Agency costs . An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number . The OMB control numbers for EPA’s regulations in 40 CFR are listed in 40 CFR p art 9. When this ICR is approved by OMB, the Agency will publish a technical amendment to 40 CFR part 9 in the FederalOMB DRAFT: Please do not cite, quote, or distribute Page 74 of 142 Register to display the OMB control number for the approved information collection requirements contained in the final rule. C. Regulatory Flexibility Act (RFA) The RFA generally requires an agency to prepare a
r egulatory 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 substant ial number of small entities. Small entities include small businesses, small organizations, and small governmental jurisdictions. For purposes of assessing the impacts of today’s rule on small entities, small entity is defined as: (1) a small business as defined by the Small Business Administration’s regulations at 13 CFR 121.201; (2) a small governmental jurisdiction that is a government of a city, county, town, school district or special district with a population of less than 50,000; and (3) a small org anization that is any not - for - profit enterprise which is independently owned and operated and is not dominant in its field . After considering the economic impacts of today ’ s final rule on small entities, I therefore certify that this proposed rule will n ot have a significant economic impactOMB DRAFT: Please do not cite, quote, or distribute Page 75 of 142 on a substantial number of small entities . Currently EPA believes small ER operations will most likely be facilities conducting CO 2 injection, including UIC Class II ER projects. The average ratio of annualized repor ting program costs to revenues of a typical ER operation likely owned by representative small enterprises is less than 1 percent. Although this rule will not have a significant economic impact on a substantial number of small entities, EPA nonetheless took several steps to reduce the impact of this rule on small entities. For example, monitoring and reporting requirements are built off of the UIC program. In addition, EPA is requiring equipment and methods that may already be in use by a facility for comp liance with its UIC permit. Also, EPA is requiring annual reporting instead of more frequent reporting. During rule implementation, EPA will maintain an “ open door ” policy for stakeholders to ask questions about the rule or provide suggestions to EPA abou t the types of compliance assistance that will be useful to small businesses . EPA intends to develop a range of compliance assistance tools and materials and conduct extensive outreach for the final rule. D. Unfunded Mandates Reform Act (UMRA)OMB DRAFT: Please do not cite, quote, or distribute Page 76 of 142 Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), P.L. 104
- 4, establishes requirements for federal agencies to assess the effects of their regulatory actions on state, local, and tribal governments and the private sector . Under Section 202 of the UMRA, EPA generally must prepare a written statement, including a cost
- benefit analysis, for final rules with “federal mandates” that may result in expenditures to state, local, and tribal governments, in the aggregate, or to the private sector, of $100 million or more in any one year. The final rule does not contain a Federal mandate that may result in expenditures of $100 million or more for State, local, and tribal governments, in the aggregate, or the private sector in any one year . Overall, EPA estimates t hat the total annualized costs of this final rule are approximately $7 million (in 2008$) during the first year of the program and $6.7 million in subsequent years ( $ 344,000 of programmatic costs to the Agency). Thus, the final rule is not subject to the requirements of sections 202 or 205 of UMRA. The final rule is also not subject to the requirements of section 203 of UMRA because it contains no regulatory requirements that might significantly or uniquely affect small governments . Facilities subject to the final ruleOMB DRAFT: Please do not cite, quote, or distribute Page 77 of 142 include facilities that inject CO 2 for enhanced recovery, and those that sequester CO 2 . None of the facilities currently known to undertake these activities are owned by small governments. E. Executive Order 13132: Federalism Executive Order 13132, entitled “Federalism” (64 FR 43255, August 10, 1999), requires EPA to develop an accountable process to ensure “meaningful and timely input by state and local officials in the development of regulatory policies that have federalism implications.” “Policies that have federalism implications” is defined in the executive order to include regulations that have “substantial direct effects on the states, on the relationship between the national government and the states, or on the distribution of power and responsibilities among the various levels of government.” The final rule does not have federalism implications. It will not have substantial direct effects on the states, on the relationship between the national government and the states, or on the dis tribution 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 CO 2 underground . Few governmentOMB DRAFT: Please do not cite, quote, or distribute Page 78 of 142 facilities would be affecte d . This regulation applies directly to facilities that inject CO 2 underground. It does not apply to governmental entities unless the government entity owns a facility that injects and/or sequesters CO 2 underground . This regulation also does not limit th e power of states or localities to collect GHG data and/or regulate GHG emissions . Thus, Executive Order 13132 does not apply to the final rule. In the spirit of Executive Order 13132, and consistent with EPA policy to promote communications between EPA a nd State and local governments, EPA specifically solicits comment on the final action from State and local officials. F. Executive Order 13175: Consultation and Coordination with Indian Tribal Governments Executive Order 13175, entitled “Consultation and Coordination with Indian Tribal Governments” (59 FR 22951, November 6, 2000), requires EPA to develop an accountable process to ensure “meaningful and timely input by tribal officials in the development of regulatory policies that have tribal implications. ” The final rule is not expected to have tribal implications, as specified in Executive Order 13175 . This regulation applies directly to facilities that inject and/or sequester CO 2 underground. Few facilities expectedOMB DRAFT: Please do not cite, quote, or distribute Page 7 9 of 142 to be affected by the rule are lik ely to be owned by tribal governments . Thus, Executive Order 13175 does not apply to the final rule. Although Executive Order 13175 does not apply to this final rule, EPA sought opportunities to provide information to tribal governments and representativ es during development of the GHG reporting rule . In consultation with EPA’s American Indian Environment Office, EPA’s outreach plan included tribes. EPA conducted several conference calls with tribal organizations during the proposal phase . For example, EPA staff provided information to tribes through conference calls with multiple tribal working groups and organizations at EPA that interact with tribes and through individual calls with two tribal board members of TCR. In addition, EPA prepared a short article on the GHG reporting rule that appeared on the front page of a tribal newsletter

—Tribal Air News

—that was distributed to EPA/Office of Air Quality Planning & Standards’ network of tribal organizations. EPA gave a presentation on various climate ef forts, including the GHG Reporting Program, at the National Tribal Conference on Environmental Management on June 24
- 26, 2008. In addition, EPA had copies of a short information sheet distributed at a meeting of the National Tribal Caucus . See the “ Summa ryOMB DRAFT: Please do not cite, quote, or distribute Page 80 of 142 of EPA Outreach Activities for Developing the GHG reporting rule, ” in Docket No. EPA

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– 0508

– 055 for a complete list of tribal contacts . EPA participated in a conference call with tribal air coordinators in April 2009 and prepared a guidance s heet for tribal governments on the proposed GHG reporting rule . It was posted on the GHG Reporting Program Web site and published in the Tribal Air Newsletter. G. Executive Order 13045: Protection of Children from Environmental Health Risks and Safety R isks EPA interprets Executive Order 13045 (62 FR 19885, April 23, 1997) as applying only to those regulatory actions that concern health or safety risks, such that the analysis required under Section 5
- 501 of the executive order has the potential to influe nce the regulation . This action is not subject to Executive Order 13045 because it does not establish an environmental standard intended to mitigate health or safety risks. H. Executive Order 13211: Actions that Significantly Affect Energy Supply, Distri bution, or Use This final rule is not a “significant energy action” as defined in EO 13211 (66 FR 28355, May 22, 2001) because it is not likely to have a significant adverse effect on the supply, distribution, or use of energy. Further, EPAOMB DRAFT: Please do not cite, quote, or distribute Page 81 of 142 has concluded that this rule is not likely to have any adverse energy effects. This final rule relates to monitoring, reporting and recordkeeping at facilities that inject and/or sequester CO 2 underground and does not impact energy supply, distribution or use. Therefo re, we conclude that this rule is not likely to have any adverse effects on energy supply, distribution, or use. I. National Technology Transfer and Advancement Act Section 12(d) of the National Technology Transfer and Advancement Act of 1995 (NTTAA), Pub lic Law No. 104
- 113 (15 U.S.C. 272 note) directs EPA to use voluntary consensus standards in its regulatory activities unless to do so would be inconsistent with applicable law or otherwise impractical . Voluntary consensus standards are technical standard s (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 deci des not to use available and applicable voluntary consensus standards . This rulemaking involves technical standards. EPA developed no new measuring device standard. Rather we allow the use of an appropriate standard method published by a consensus
-OMB DRAFT: Please do not cite, quote, or distribute Page 82 of 142 based standards organization if such a method exists; or an industry standard practice. J. Executive Order 12898: Federal Actions to Address Environmental Justice in Minority Populations and Low
Income Populations Executive Order 12898 (59 FR 7629, February 1 6, 1994) establishes federal executive policy on environmental justice . Its main provision directs federal agencies, to the greatest extent practicable and permitted by law, to make environmental justice part of their mission by identifying and addressing , as appropriate, disproportionately high and adverse human health or environmental effects of their programs, policies, and activities on minority populations and low
- income populations in the United States. EPA has determined that the final rule will no t have disproportionately high and adverse human health or environmental effects on minority or low
- income populations because it does not affect the level of protection provided to human health or the environment. The final rule does not affect the level of protection provided to human health or the environment because it is a rule addressing information collection and reporting procedures. K. Congressional Review ActOMB DRAFT: Please do not cite, quote, or distribute Page 83 of 142 The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the Small Business Regulatory Enforcement Fairness Act of 1996, generally provides that before a rule may take effect, the agency promulgating the rule must submit a rule report, which includes a copy of the rule, to each House of the Congress and to the Comptroller General of the United States. EPA will submit a report containing this rule and other required information to the U.S. Senate, the U.S. House of Representatives, and the Comptroller General of the U.S. prior to publication of the rule in the Federal Register. A maj or rule cannot take effect until 60 days after it is published in the Federal Register. This action is not a “major rule” as defined by 5 U.S.C. 804(2). This rule will be effective [INSERT THE DATE 60 DAYS AFTER PUBLICATION IN THE FEDERAL REGISTER] .Page 84 of 142

OMB DRAFT: Please do not cite, quote, or distribute List of Subjects in 40 CFR part 98 Environmental protection, Administrative practice and procedure, Greenhouse gases, Incorporation by reference, Air pollution control, Reporting and recordkeeping requirements.

Date:

Lisa P. Jackson, Administrator.Page 85 of 142

OMB DRAFT: Please do not cite, quote, or distribute For the reasons stated in the preamble, parts 72, 78, and 98 of title 40, chapter I, of the Code of Federal Regulations is proposed to be amended as follows: PART 72

— [AMENDED] 1. The authority citation for Part 72 is revised to read as f ollows: Authority: 42 U.S.C. 7401, 7403, 7410, 7411, 7426, 7601, et seq. § 72.2 [Amended] 2. Section 72.2 is revised to read as follows: § 72.2 Definitions. * * * * * Interested person means, with regard to a decision of the Administrator, any person who submitted comments or testified at a public hearing pursuant to an opportunity for comment provided by the Administrator as part of the process of making such decision, who submitted objections pursuant to an opportunity for objections provided by the Administrator as part of the process of making such decision, or who submitted (to the Administrator and in a format specified by the Administrator) his or her name to be placed on a list of persons interested in such decision. The Administrator may update the list of interested persons from time to time by requesting additional writtenOMB DRAFT: Please do not cite, quote, or distribute Page 86 of 142 indication of continued interest from the persons listed and may delete from the list the name of any person failing to respond as requested. * * * * * PART 78

— [AMENDED ] 3. The authority citation for Part 78 continues to read as follows: Authority: 42 U.S.C. 7401, 7403, 7410, 7411, 7426, 7601, et seq. § 78.1 [Amended] 4. Section 78.1 is amended by: a. Removing, in paragraph (a)(1), the words “or part 97 of this chapter” and adding, in their place, the words “part 97 of this chapter, or subpart RR of part 98.”; and b. Adding paragraphs (b)(13) through (b)(17) to read as follows: § 78.1 Purpose and scope. * * * * * (b) * * * (13) [Reserved] (14) [Reserved] (15) [Reserved] (16) [Reserved] (17) Under subpart RR of part 98 of this chapter,OMB DRAFT: Please do not cite, quote, or distribute Page 87 of 142 (i) The approval or disapproval of a request for R&D exemption under §98.441(b)(1) of this chapter; (ii) The approval or disapproval of a request for discontinuation of report ing under §98.441( d)(3) of this chapter; and (iii) The approval or disapproval of a geologic sequestration monitoring, reporting, and verification (MRV) plan under §98.448( d )of this chapter. * * * * * § 78.3 [Amended] 5. Section 78.3 is amended by: a. Adding paragraphs (a)(10) and (a)(11); b. In paragraph (b)(3)(i), removing the words “paragraph (a)(1) and (2)” and adding, in their place, the words “paragraph (a)(1), (2), (10), and (11)”; and c. Adding paragraphs (d)(11) and (d)(12) to read as foll ows: § 78.3 Petition for administrative review and request or evidentiary hearing. (a) * * * (10) [Reserved] (11) The following persons may petition for administrative review of a decision of the Administrator that is made under subpart RR of part 98 of this chapter:OMB DRAFT: Please do not cite, quote, or distribute Page 88 of 142 (i) The owner or operator of a facility covered by the decision; or (ii) Any interested person with regard to the decision. * * * * * (d) * * * (11) [Reserved] (12) Any provision or requirement of subpart RR of part 98 of this chapt er. § 78.4 [Amended] 6. Section 78.4 is amended by adding paragraphs (a)(1)(i), (a)(1)(ii), (a)(1)(iii), (a)(1)(iv), and (a)(2) to read as follows: § 78.4 Filings. (a) * * * (1) [Reserved] (i) [Reserved] (ii) [Reserved] (iii) [Reserved] (iv) Any fil ings on behalf of owners and operators of a facility covered by subpart RR of part 98 of this chapter shall be signed by the designated representative. (2) [Reserved]. * * * * * PART 98— [AMENDED]OMB DRAFT: Please do not cite, quote, or distribute Page 89 of 142 7. The authority citation for part 98 continues to
r ead as follows: Authority: 42 U.S.C. 7401, et seq . Subpart A

— [Amended] 8 . Section 98.2 is amended by revising paragraph (a) introductory text to read as follows: §98.2 Who must report? (a) The GHG reporting requirements and related monitoring, recordkee ping, and reporting requirements of this part apply to the owners and operators of any facility that is located in the United States or under or attached to the Outer Continental Shelf (as defined in 43 U.S.C. §1331) and that meets the requirements of eith er paragraph (a)(1), (a)(2), or (a)(3) of this section; and any supplier that meets the requirements of paragraph (a)(4) of this section:
* * * * * 9 . Table A - 3 of subpart A is amended by adding

“ Geologic s equestration of carbon dioxide ” and “Injection of carbon dioxide ” to r ead as follows: Table A- 3 of Subpart A —Source Category List for §98.2(a)( 1 ) Source Categories a Applicable in 2010 and Future Years * * * * * * * Additional Source Categories a Applicable in 2011 and Future Years * * * * * * *OMB DRAFT: Please do not cite, quote, or distribute Page 90 of 142
Geolo gic sequestration of carbon dioxide (subpart RR) Injection of carbon dioxide (subpart UU) a Source categories are defined in each applicable subpart.

* * * * * 10 . Section 98.6 is amended by adding the following definitions in alphabetical order to re ad as follows: §98.6 Definitions.
* * * * * Outer Continental Shelf means all submerged lands lying seaward and outside of the area of lands beneath navigable waters as defined in 43 U.S.C. § 1301 , and of which the subsoil and seabed appertain to the Unite d States and are subject to its jurisdiction and control.
* * * * * United States means the 50 states, the District of Columbia, the Commonwealth of Puerto Rico, American Samoa, the Virgin Islands, Guam, and any other Commonwealth, territory or possession of the United States, as well as the territorial sea as defined by Presidential Proclamation No. 5928.
* * * * * 11 . Part 98 is amended by adding subpart RR to read a s follows: Sec.OMB DRAFT: Please do not cite, quote, or distribute Page 91 of 142 98.440 Definition of the source category. 98.441 Reporting threshold. 98 .442 GHGs to report. 98.443 Calculating CO 2 geologic s equestration. 98.444 Monitoring and QA/QC requirements. 98.445 Procedures for estimating missing data. 98.446 Data reporting requirements. 98.447 Records that must be retained. 98.448 Geologic s e questration monitoring, r eporting, and v erification (MRV) p lan. 98.449 Definitions.
Subpart RR

—Geologic Sequestration of Carbon Dioxide §98.440 Definition of the source category. (a) The geologic sequestration of carbon dioxide ( CO 2 ) source category c omprises of a ny well or group of wells that inject s a CO 2 stream for long - term containment in subsurface geologic formations . (b) This source category includes a ll wells permitted as Class VI under the Underground Injection Control program. ( c ) This so urce category does not include a well or group of wells where a CO 2 stream is being injected in subsurface geologic formations to enhance the recovery of oil or natural gas unless one of the following applies: (1) The owner or operator inject s the CO 2 stre am for long - term containment in subsurface geologic formation s and has chosen to submit a proposed monitoring, reporting, andOMB DRAFT: Please do not cite, quote, or distribute Page 92 of 142 verification (MRV) plan to EPA and received an approved plan from EPA . (2) T he well is permitted as Class VI under the Underground Injection Control program . (d) Request for a r esearch and development exemption . You may submit a request to the Administrator to receive an exemption from reporting under this source category for research and development projects . (1 ) Timing of reque st . You must submit a request to EPA for an exemption by the time you would be otherwise required to submit an MRV plan under §98.448. ( 2 ) Content of request . A r equest for an exemption must contain the following information: (i ) The planned duration of CO 2 injection for the project . (ii ) The planned annual CO 2 injection volumes during this time period. ( iii ) The research purposes of the project. ( iv) The source and type of funding for the project . (v ) Whether research results will be published . ( vi) The class of Underground Injection Control permit or, for an offshore facility not subject to the Safe Drinking Water Act, a description of the legal instrument authorizing geologic sequestration.OMB DRAFT: Please do not cite, quote, or distribute Page 93 of 142 ( vii) The length of time the well or group of wells is authori zed to inject CO 2 . (3 ) Exemption criteria . To obtain an exemption , the owner or operator of the facility must demonstrate to the Administrator’s satisfaction that the well or group of wells is a research and development project . (4) The Administrator will issue a final decision on the request for a research and development exemption and notify the owner or operator within 120 days of receipt of the request . Any appeal of the Administrator’s final decision is subject to the provisions of part 78 of this ch apter . §98.441 Reporting threshold. (a) You must report under this subpart if any well or group of wells within your facility injects any amount of CO 2 for long - term containment in subsurface geologic formations , at no threshold . ( b ) The requirements of § 98.2(i) do not apply to this subpart. Once a well or group of wells is subject to the requirements of this subpart, the owner or operator must continue for each year thereafter to comply with all requirements of this subpart, including the requirement to submit annual reports, un til the owner or operator has madeOMB DRAFT: Please do not cite, quote, or distribute Page 94 of 142 a request to discontinue reporting that demonstrates that the CO 2 plume has stabilized . (1) The owner or operator of a well or group of wells with a Class VI Underground Injection Control permit may submit to the Administrator a copy of the applicable Underground Injection Control program Director’s authorization of site closure to demonstrate that the CO 2 plume has stabilized. For other wells , the owner or operator of the facility must submit a demonstration to the Administrator’s satisfaction that the CO 2 plume has stabilized. ( 2 ) The Administrator will issue a final decision on the request to discontinue reporting within a reasonable time . Any appeal of the Administrator’s final decision is sub ject to the provisions of part 78 of this chapter . §98.442 GHGs to report. You must report: (a) Mass of CO 2 received. (b) Mass of CO 2 injected into the subsurface. (c) Mass of CO 2 produced. ( d ) Mass of CO 2 emitted by surface leakage . ( e ) Mass of fug itive and vented CO 2 emissions from surface equipment located between the injection flow meter and the injection wellhead.OMB DRAFT: Please do not cite, quote, or distribute Page 95 of 142 ( f ) Mass of fugitive and vented CO 2 emissions from surface equipment located between the production flow meter and the production we llhead. ( g ) Mass of CO 2 sequestered in subsurface geologic formation s . (h) Cumulative mass of CO 2 reported as sequestered in subsurface geologic formation s in all years since the facility became subject to reporting requirements under this subpart. §98.4 43 Calculating CO 2 geologic s equestration. You must calculate the mass of CO 2 received using CO 2 r eceived e quations (RR
- 1 and RR - 3 ) . You must calculate CO 2 sequestered using i njection e quations (RR
- 4 to RR - 6 ), p roduction/ r ecycling e quations (RR
- 7 to RR - 9 ), s urface l eakage e quation (RR
- 10 ), and s equestration e quations (RR
1 1 and RR - 1 2 ). For your first year of reporting, you must calculate CO 2 sequestered starting from the date set forth in your approved MRV plan. (a) Y ou must calculate and report the annual mass of CO 2 received by pipeline using the procedures in paragraph s (a)(1) or (a)(2) of this section and the procedures in paragraph (a)(3) of this section, if applicable . (1) For a mass flow meter, you must calculate the total annual mass of CO 2 i n a CO 2 s tream received in metricOMB DRAFT: Please do not cite, quote, or distribute Page 96 of 142 tons by multiplying the mass flow by the CO 2 concentration in the flow, according to Equation RR
- 1 of this section. You must collect these data quarterly. Mass flow and concentration data measurements must b e made in acc ordance with §98.44 4.
CO 2 T = p CO p d p p r C Q Q

, 2 * ) (
, 4 1 ,  

# 

 (Eq. RR - 1) Where: CO 2 T = Annual mass of CO 2 received (metric tons). Q r, p = Quarterly mass flow through a receiving flow

meter in quarter p (metric tons per quarter ). Q d, p = Quarterly mass flow th rough a receiving flow

meter that is redelivered to another facility without being injected into your well in quarter p (metric tons per quarter ). C CO2,p = Quarterly CO 2 concentration measurement in flow

in quarter p (wt. %CO 2 / 100 ). p = quarter . (2) Fo r a volumetric flow meter, you must calculate the total annual mass of CO 2 in a CO 2 s tream received in metric tons by multiplying the volumetric flow at standard conditions by the CO 2 concentration in the flow and the density of CO 2 at standard conditions, according to Equation RR - 2 of this section. You must collect these data quarterly. Volumetric flow and concentration data measurements must b e made in accordance with §98.44 4.

CO 2 T = p CO p p p

d p r C

D Q Q

, 2 * * ) ( 4 1 , , 

# 

  (Eq. RR - 2)OMB DRAFT: Please do not cite, quote, or distribute Page 97 of 142 Where: CO 2 T = Annual mass of CO 2 received (metric tons). Q r, p = Quarterly volumetric flow through a receiving

flow meter in quarter p at standard conditions (standard cubic meters). Q d , p = Quarterly volumetric flow through a receiving

flow meter that is redelivered to another facility without being injected into your well in quarter p (standard cubic meters). D p = Density of CO 2 at standard conditions (metric

tons per standard cubic meter) : 0.0018704 . C CO2,p = Quarterly CO 2 concentration measurement in flow

in quarter p ( vol . %CO 2 / 10 0 ). p = quarter . ( 3) If you receive CO 2 through more than one flow meter, you must sum the mass of all CO 2 received in accordance with the procedure specified in Equation RR
- 3 of this section.
CO 2 = 

## 

 V

v 1 v

2T, CO (Eq. RR - 3) Where: CO 2 = Tota l annual mass of CO 2 received (metric

tons). CO 2T, v = Annual mass of CO 2 received (metric tons) as

calculated in Equation RR
- 1 or RR - 2 for flow meter v. v = flow meter. (b) You must calculate and report the annual mass of CO 2 received in containers usin g the procedures in paragraph s (b)(1) or ( b )(2) of this section .OMB DRAFT: Please do not cite, quote, or distribute Page 98 of 142 ( 1) If you are measuring the mass of contents in a container under the provisions of § 98.44 4( a ) ( 2 )(i) , you must calculate the CO 2 received for injection in containers using Equation RR - 1 of this section.
Where: CO 2 = Annual mass of CO 2 received in container s

(metric tons). C CO2,p = Quarterly CO 2 concentration measurement of

contents in containers in quarter p (wt. %CO 2 ). Q p,u = Quarterly mass of contents in container s in

quarter p (metr ic tons). p = Quarter of the year. ( 2 ) If you are measuring the volume of contents in a container under the provisions of §98.4 4 4 ( a ) ( 2 )(i i ) , you must calculate the CO 2 received for injection in containers using Equation RR - 2 of this section.
Where: CO 2 = Annual mass of CO 2 received in container

(metric tons). C CO2,p = Quarterly CO 2 concentration measurement of

contents in containers in quarter p ( vol . %CO 2 ). Q p = Quarterly volume of contents in containers in

quarter p (standard cubic meters). D p = Qua rterly density of the CO 2 received in

containers at standard conditions (metric tons per standard cubic meter) :0.0018704. p = Quarter of the year.OMB DRAFT: Please do not cite, quote, or distribute Page 99 of 142 ( c ) You must report the annual mass of CO 2 injected in accordance with the procedures specified in paragr aphs (c) ( 1 ) through (c) ( 3 ) of this section. ( 1 ) If you use a mass flow meter to measure the flow of an injected CO 2 stream , you must calculate annually the total mass of CO 2 (in metric tons) in the CO 2 stream injected each year in metric tons by multiplyi ng the mass flow by the CO 2 concentration in the flow , according to Equation RR
- 4 of this section. Mass flow and concentration data measurements must be made in accordance with §98.444.
CO 2 ,u = u p CO p u p C Q

, , 2 * 4 1 , 

# 

 (Eq. RR - 4 ) Where: CO 2,u = Annual CO 2 mass injected (metric tons) as

measured by flow meter u. Q p,u = Quarterly mass flow rate measurement for flow

meter u in quarter p (metric tons per quarter ). C CO2,p,u = Quarterly CO 2 concentration measurement in flow

in quarter p (wt. %CO 2 /100 ). p = quarter . u = flow meter . ( 2 ) If you use a volumetric flow meter to measure the flow of an injected CO 2 stream , you must calculate annually the total mass of CO 2 (in metric tons) in the CO 2 stream injected each year in metric tons by multiplying the volume tric flow at standard conditions by the CO 2OMB DRAFT: Please do not cite, quote, or distribute Page 100 of 142 concentration in the flow and the density of CO 2 at standard conditions , according to Equation RR
- 5 of this section. Volumetric flow and concentration data measurements must be made in accordance with §98.444.
CO 2 ,u = u p CO u p p u p C D Q

, , 2 * *
, 4 1 , 

# 

 (Eq. RR - 5 ) Where: CO 2,u = Annual CO 2 mass injected (metric tons) as

measured by flow meter u. Q p,u = Quarterly v olumetric flow rate measurement for

flow meter u in quarter p at standard conditions (standard cubic meters p er quarter ). D p,u = Density of CO 2 at standard conditions (metric

tons per standard cubic meter) : 0.0018704 . C CO2,p,u = CO 2 concentration measurement in flow for flow

meter u in quarter p ( vol . %CO 2 / 100 ). p = quarter . u = flow meter . ( 3 ) To aggregate in jection data for all wells covered under this subpart , you must sum the mass of all CO 2 injected through all injection wells in accordance with the procedure specified in Equation RR
- 6 of this section.
CO 2I = 

## 

 U

u 1 u

2, CO (Eq. RR - 6 ) Where: C O 2I = Total annual CO 2 mass injected (metric tons)

through all injection wells. CO 2,u = Annual CO 2 mass injected (metric tons) as

measured by flow meter u.OMB DRAFT: Please do not cite, quote, or distribute Page 101 of 142

u = flow meter ( d ) You must calculate the annual mass of CO 2 produced from oil or gas production wells or from other fluid wells for each separator that sends a stream of gas into a recycle or end use system in accordance with the procedures specified in paragraphs (d) ( 1 ) through (d) ( 3 ) of this section. You must account only for wells that produce the CO 2 that was injected into the well or wells covered by this source category. ( 1 ) For each gas - liquid separator for which flow is measured using a mass flow meter, you must calculate annually the total mass of gas produced from an oil or other fluid stre am in metric tons that is separated from the fluid by multiplying the mass gas flow by the CO 2 concentration in the gas flow , according to Equation RR
- 7 of this section. You must collect these data quarterly. Mass flow and concentration data measurements must be made in accordance with §98.444.
CO 2 ,w = w p CO p w p C Q

, , 2 * 4 1 , 

# 

 (Eq. RR - 7 ) Where: CO 2,w = Annual CO 2 mass produced (metric tons) through

separator w. Q p,w = Quarterly mass flow rate measurement for

separator w in quarter p (metric tons per quarter ).OMB DRAFT: Please do not cite, quote, or distribute Page 102 of 142
C CO2,p,w = Quarterly CO 2 concentration measurement in flow

for separator w in quarter p (wt. % CO 2 /100 ). p = quarter . w = separator . ( 2 ) For each gas - liquid separator for which flow is measured using a volumetric flow meter, you must calculate annually the total mass of gas produced from an oil or other fluid stream in metric tons that is separated from the fluid by multiplying the volumetric gas flow at standard conditions by the CO 2 concentration in the gas flow and the density of CO 2 at stand ard conditions , according to Equation RR
- 8 of this section. You must collect these data quarterly. Volumetric flow and concentration data measurements must be made in accordance with §98.444.
CO 2 ,w = w p CO w p p w p C D Q

, , 2 * *
, 4 1 , 

# 

 (Eq. RR - 8 ) Where: CO 2,w = Annual CO 2 mass produced (metric tons) through

separator w. Q p,w = Volumetric flow rate measurement for separator

w in quarter p at standard conditions (standard cubic meters per quarter ). D p,w = Density of CO 2 at standard conditions (metric

tons per stan dard cubic meter) : 0.0018704 . C CO2,p,w = CO 2 concentration measurement in flow for

separator w in quarter p ( vol . % CO 2 /100 ). p = quarter . w = s eparator .OMB DRAFT: Please do not cite, quote, or distribute Page 103 of 142 ( 3 ) To aggregate production data, you must sum the mass of all of the CO 2 separated at each gas - liqu id separator in accordance with the procedure specified in Equation RR
- 9 of this section. You must assume that the total CO 2 measured at the separator(s) represents a percentage of the total CO 2 produced. In order to account for the percentage of CO 2 pro duced that is estimated to remain with the produced oil or other fluid , you must multiply the quarterly mass of CO 2 measured at the separator(s) by a percentage estimated using a methodology in your approved MRV plan.

CO 2P = (100+X)% * 

## 

 W

w 1 w

2, CO (Eq. RR - 9 ) Where: CO 2P = Total annual CO 2 mass produced (metric tons)

through all separators in the reporting year . CO 2,w = Annual CO 2 mass produced (metric tons) through

separator w in the reporting year. X = Entrained CO 2 volume in produced oil or other

fluid divided by the s eparator CO 2 volume . w = s eparator . ( e ) You must report the annual mass of CO 2 that is emitted by surface leakage in accordance with your approved MRV plan. You must calculate the total annual mass of CO 2 emitted from all leakage pathways in accordance with the procedure specified in Equation RR
- 10 of this section.OMB DRAFT: Please do not cite, quote, or distribute Page 104 of 142

CO 2E = 

## 

 X

x 1 x

2, CO (Eq. RR - 10 ) Where: CO 2E = Total annual CO 2 mass emitted by surface

leakage (metric tons) in the reporting year. CO 2,x = Annual CO 2 mass emitted (metric tons) at

leakage pathway x in the reporting year.
x = leakage pathway ( f ) You must report the annual mass of CO 2 that is sequestered in subsurface geologic formation s in the reporting year in accordance with the procedures spe cified in paragraphs (f) ( 1 ) and (f) ( 2 ) of this section. ( 1 ) If you are conducting enhanced recovery operations and are actively producing oil or natural gas or if you are producing any other fluids , you must calculate the annual mass of CO 2 that is seque stered in the underground subsurface formation in the reporting year in accordance with the procedure specified in Equation RR
- 1 1 of this section.

CO 2 = CO 2I - CO 2P

– CO 2E

– CO 2FI – CO 2FP (Eq. RR - 1 1 ) Where: CO 2 = Total annual CO 2 mass sequestered in subsurface

geologic formation s (metric tons) at the facility in the reporting year. CO 2I = Total annual CO 2 mass injected (metric tons) in

the well or group of wells covered by this source category in the reporting year. CO 2P = Total annual CO 2 mass produce d (metric tons) in

the reporting year.OMB DRAFT: Please do not cite, quote, or distribute Page 105 of 142
CO 2E = Total annual CO 2 mass emitted (metric tons) by

surface leakage in the reporting year. CO 2FI = Total annual CO 2 mass emitted (metric tons) as

fugitive or vented emissions from equipment located on the surface be tween the flow meter used to measure injection quantity and the injection wellhead , for which a calculation procedure is provided in subpart W . CO 2FP = Total annual CO 2 mass emitted (metric tons) as

fugitive or vented emissions from equipment located on th e surface between the production wellhead and the flow meter used to measure production quantity , for which a calculation procedure is provided in subpart W . ( 2 ) If you are not actively producing oil or natural gas or any other fluids , you must calculate the annual mass of CO 2 that is sequestered in subsurface geologic formation s in the reporting year in accordance with the procedures specified in Equation RR
- 1 2 of this section. CO 2 = CO 2I – CO 2E – CO 2FI (Eq. RR - 1 2 ) Where: CO 2 = Total annual CO 2 mass se questered in subsurface

geologic formation s (metric tons) at the facility in the reporting year . CO 2I = Total annual CO 2 mass injected (metric tons) in

the well or group of wells covered by this source category in the reporting year . CO 2E = Total annual C O 2 mass emitted (metric tons) by

surface leakage in the reporting year. CO 2FI = Total annual CO 2 mass emitted (metric tons) as

fugitive or vented emissions from equipment located on the surface between the flow meter used to measure injection quantity and the injection wellhead. §98.444 Monitoring and QA/QC requirements.OMB DRAFT: Please do not cite, quote, or distribute Page 106 of 142 (a) CO 2 received . ( 1 ) Except as provided in paragraph (a)( 4 ) of this section, y ou must determine the quarterly flow rate of CO 2 received by pipeline by following the most appropriate of the following procedures: ( i ) You may measure flow rate at the receiving custody transfer meter prior to any subsequent processing operations at the facility and collect the flow rate quarterly . ( ii ) If you took ownership of the CO 2 in a commercial tran saction, you may use the quarterly flow rate data from the sales contract if it is a one
- time transaction or from invoices or manifests if it is an ongoing commercial transaction with discret e shipments. (iii) If you inject CO 2 received from a production process unit that is part of your facility, you may use the quarterly CO 2 flow rate that was measured at the equivalent of a custody transfer meter following procedures provided in subpart PP. To be the equivalent of a custody transfer meter, a meter must measure the flow of CO 2 being transported to an injection well to the same degree of accuracy as a meter used for commercial transactions. ( 2 ) Except as provided in paragraph (a)( 4 ) of this section, you must determine the quarterly mass or volume ofOMB DRAFT: Please do not cite, quote, or distribute Page 107 of 142
conte nts in all containers if you receive CO 2 in containers by the most appropriate of the following procedures: ( i ) You may measure the mass of contents of containers summed quarterly using weigh bills, scales, or load cells. ( ii ) You may determine the volume of the contents of containers summed quarterly . (iii) If you took ownership of the CO 2 in a commercial transaction, you may use the quarterly mass or volume of contents from the sales contract if it is a one
- time transaction or from invoices or manifests if it is an ongoing commercial transaction with discret e shipments. ( 3 ) Except as provided in paragraph (a)( 4 ) of this section, y ou must determine a quarterly concentration of the CO 2 received that is representative of all CO 2 received in that quarter by following the most appropriate of the following procedures: ( i ) You may sample the CO 2 stream once per quarter at the point of receipt and measure its CO 2 concentration . ( ii ) If you took ownership of the CO 2 in a commercial transaction for which the sal es contract was contingent on CO 2 concentration , and if the supplier of the CO 2 sampled the CO 2 stream in a quarter and measured its concentration per the sales contract terms, you may use the CO 2OMB DRAFT: Please do not cite, quote, or distribute Page 108 of 142 concentration data from the sales contract for that quarter . (iii) If you inject CO 2 from a production process unit that is part of your facility, you may report the quarterly CO 2 concentration of the CO 2 stream supplied that was measured following the procedures provided in subpart PP. ( 4 ) If the CO 2 you rece ive is wholly injected and is not mixed with any other supply of CO 2 , you may report the annual mass of CO 2 injected that you determined following the requirements under 98.444(b) as the total annual mass of CO 2 received instead of using equation RR
- 1 or RR - 2 to calculate CO 2 received. (b) CO 2 injected . ( 1) You must select a point or points of measurement at which t he CO 2 stream (s) is representative of the CO 2 stream (s) being injected . Y ou may use as the point or points of measurement the location (s) of the flow meter (s) used to comply with the flow monitoring and reporting provisions in your Underground Injection Control permit . (2) You must measure flow rate of CO 2 injected with a flow meter and collect the flow rate quarterly. ( 3 ) You must sample th e injected CO 2 stream once per quarter immediately upstream or downstream of the flowOMB DRAFT: Please do not cite, quote, or distribute Page 109 of 142
meter used to measure flow rate of that CO 2 stream and
measure the CO 2 concentration of the sample. (c) CO 2 produced . (1) The point of measurement for the quantity of CO 2 produced from oil or other fluid production wells is a flow meter directly downstream of each separator that sends a stream of gas into a recycle or end use system. ( 2 ) You must sample the produced CO 2 stream once per quarter immediately upstream or downstream of the flow meter used to measure flow rate of that CO 2 stream and
measure the CO 2 concentration of the sample. (3) You must measure flow rate of CO 2 produced with a flow meter and collect the flow rate quarterly. (d) Fugitive and vented CO 2 . If you have equipment located on the surface between the flow meter used to measure injection quantity and the injection wellhead or between the flow meter used to measure production quantity and the production wellhead , you must follow the monitoring and QA /QC requirements specified in s ubpart W of this part for the equipment . (e) Measurement devices . (1) All flow meters must be operated continuously except as necessary for maintenance and calibration.OMB DRAFT: Please do not cite, quote, or distribute Page 110 of 142 (2) You must calibrate all flow meters used to
measure quantities reported in §98.44 6 according to the calibration and accuracy requirements in §98.3(i) . (3) You must operate all measurement devices according to one of the following: an appropriate standard method published by a consensus
- based standards org anization if such a method exists ; or an industry standard practice . Consensus - based standards organizations include, but are not limited to, the following: ASTM International, the American National Standards Institute (ANSI), the American Gas Association (AGA), the American Society of Mechanical Engineers (ASME), the American Petroleum Institute (API), and the North American Energy Standards Board (NAESB). ( 4 ) You must ensure that any flow meter calibrations performed are NIST traceable. ( f ) General . (1) If y ou measure the concentration of any CO 2 quantity for report ing, you must use methods that conform to applicable chemical analytical standards. ( 2 ) You must use the same calculation methodology throughout a reporting period unless you provide a w ritten explanation of why a change in methodology was required.OMB DRAFT: Please do not cite, quote, or distribute Page 111 of 142 (3) Y ou must convert all measured volumes of CO 2 to the following standard industry temperature and pressure conditions for use in equations RR
- 2 , RR - 5 and RR - 8 : standard cubic meter s at a temperature of 60 degrees Fahrenheit and at an absolute pressure of 1 atmosphere . §98.445 Procedures for estimating missing data. A complete record of all measured parameters used in the GHG quantities calculations is required. Whenever the monitoring proce dures cannot be followed, you must use the following missing data procedures: (a) A quarterly flow rate of CO 2 received that is missing must be estimated as follows: (1) Another calculation methodology listed in section 98.444(a)( 1 ) must be used if possibl e. (2) If another method listed in §98.4 44 ( a ) ( 1 ) cannot be used, a quarterly flow rate value that is missing must be estimated using a representative flow rate value from the nearest previous time period. (b) A quarterly mass or volume of contents in
con tainers received that is missing must be estimated as follows: (1) Another calculation methodology listed in section 98.444(a)( 2 ) must be used if possible.OMB DRAFT: Please do not cite, quote, or distribute Page 112 of 142 (2) If another method listed in §98.4 44 ( a ) ( 2 ) cannot be used, a quarterly mass or volume value tha t is missing must be estimated using a representative mass or volume value from the nearest previous time period. ( c ) A quarterly CO 2 concentration of a CO 2 stream received that is missing must be estimated as follows: (1) Another calculation methodology listed in section 98.444(a)( 3 ) must be used if possible. (2) If another method listed in §98.4 44 ( a ) ( 3 ) cannot be used, a quarterly concentration value that is missing must be estimated using a representative concentration value from the nearest previous time period. ( d ) A quarterly quantity of CO 2 injected that is missing must be estimated using a representative quantity of CO 2 injected from the nearest previous period of time at a similar injection pressure. ( e ) For any values associated with fugitive or vented CO 2 emissions from surface equipment at the facility that are reported in this subp art, missing data estimation procedures should be followed in accordance with those specified in s ubpart W of this part . ( f ) The quarterly quantity of CO 2 produc ed from subsurface geologic formations that is missing must beOMB DRAFT: Please do not cite, quote, or distribute Page 113 of 142 estimated using a representative quantity of CO 2 produced from the nearest previous period of time . ( g ) You must estimate t he annual quantity of CO 2 emitted by surface leakage that is missing as required by your approved MRV plan. ( h ) You must estimate other missing data as required by your approved MRV plan. §98.446 Data reporting requirements. In addition to the information required by §98.3(c), report the information listed in this sectio n. (a) The mass of CO 2 received. (1) If you receive CO 2 by pipeline, report the following for each receiving flow meter : (i ) The t otal mass of CO 2 received (metric tons) annually . (ii ) The CO 2 concentration in the flow (volume or wt. % CO 2 /100 ) in each quarter unless you reported yes to paragraph (a)(1)(v) of this section . (iii ) If a volumetric flow meter is used to receive CO 2 report the following unless you reported yes to paragraph (a)(1)(v) of this section: (A) T he volumetric flow through a re ceiving flow meter at standard conditions ( in standard cubic meters ) in each quarter .OMB DRAFT: Please do not cite, quote, or distribute Page 114 of 142 (B) The volumetric flow through a receiving flow meter that is redelivered to another facility without being injected into your well (in standard cubic meters) in each quarter. (iv) If a mass flow meter is used to receive CO 2 report the following unless you reported yes to paragraph (a)(1)(v) of this section: (A) T he mass flow through a receiving flow meter ( in metric tons) in each quarter . (B) The mass flow through a receiving flow meter that is redelivered to another facility without being injected into your well (in standard cubic meters) in each quarter. (v ) If the CO 2 received is wholly injected and not mixed with any other supply of CO 2 , report whether you foll owed the monitoring procedures in 98.444(a)(4). ( v i ) The standard or method used to calculate each value in paragraphs (a)( 1 ) (ii) through (a) ( 1 ) (iv) of this section. (vi i ) The number of times in the reporting year for which substitute data procedures w ere used to calcul ate values reported in paragraphs (a)( 1 ) (ii) through (a) ( 1 ) (iv) of this section. (vi i i) Whether the flow meter is mass or volumetric. (ix) A numerical identifier for the flow meter.OMB DRAFT: Please do not cite, quote, or distribute Page 115 of 142 (2) If you receive CO 2 in containers, report: (i) T he mass ( in metric tons) or volume at standard conditions ( in standard cubic meters) of contents in containers in each quarter. (ii) The concentration of CO 2 of contents in containers (volume or wt. % CO 2 /100 ) in each quarter. (iii) The t otal mass of CO 2 rece ived ( in metric tons) annually . (iv) The standard or method used to calculate each value in paragraphs (a)( 2 ) (i) and (a) ( 2 ) (ii) of this section. (v) The number of times in the reporting year for which substitute data procedures were used to calcul ate
va lues reported in paragraphs (a)( 2 ) (i) and (a) ( 2 ) (ii) of this section. ( b ) If you use more than one receiving flow meter,
r eport the total mass of CO 2 received (metric tons) through all flow meters annually . (c) The source of the the CO 2 stream received
a ccording to the following categories: ( 1 ) CO 2 production wells. ( 2 ) Electric generating unit. ( 3 ) Ethanol plant. ( 4 ) Pulp and paper mill.OMB DRAFT: Please do not cite, quote, or distribute Page 116 of 142 ( 5 ) Natural gas processing . ( 6 ) Gasification operations. ( 7 ) Other anthropogenic source. ( 8 ) CO 2 received from a discontinued enhanced oil and gas recovery project . ( 9 ) Unknown. ( d ) Whether, on the date of this annual report submission, your EPA
- approved MRV plan has been fully implemented. The MRV plan is fully implemented according to the date in your approve d MRV plan. (e ) I f you report yes in paragraph (d ) of this section, report the following: ( 1 ) For each injection flow meter (mass or volumetric), report: (i ) The mass of CO 2 injected (metric tons) annually . (ii ) The CO 2 concentration in flow (volume or wt.% CO 2 /100 ) in each quarter. (iii ) If a volumetric flow meter is used, the volumetric flow rate at standard conditions ( in standard cubic meters ) in each quarter . (iv ) If a mass flow meter is used, the mass flow rate ( in metric tons) in each quart er . (v ) A numerical identifier for the flow meter. (vi ) Whether the flow meter is mass or volumetric.OMB DRAFT: Please do not cite, quote, or distribute Page 117 of 142 ( vii ) The standard used to calculate each value in paragraphs ( d )( 1 ) (ii) through ( d )( 1 ) (iv) of this section. (viii ) The number of times in the rep orting year for which substitute data procedures were used to calcul ate values reported in paragraphs ( d )( 1 ) (ii) through ( d )( 1 ) (iv) of this section. (ix) The location of the flow meter. (2 ) The total CO 2 injected (metric tons) in the reporting year as ca lculated in Equation RR
- 6 . ( 3 ) Fugitive and vented CO 2 emissions . ( i ) The mass of CO 2 emitted ( in metric tons) annually as fugitive or vented emissions from equipment located on the surface between the flow meter used to measure injection quantity and t he injection wellhead. ( ii ) The mass of CO 2 emitted ( in metric tons) annually as fugitive or vented emissions from equipment located on the surface between the production wellhead and the flow meter used to measure production quantity. ( 4 ) For each sepa rator flow meter (mass or volumetric), report: ( i ) CO 2 quantity produced (metric tons cubic meters) annually . ( ii ) CO 2 concentration in flow (volume or wt. % CO 2 /100 ) in each quarter.OMB DRAFT: Please do not cite, quote, or distribute Page 118 of 142 ( iii ) If a volumetric flow meter is used , volumetric flow rate at s tandard conditions ( standard cubic meters ) in each quarter . (iv ) If a mass flow meter, mass flow rate (metric tons) in each quarter . (v ) A numerical identifier for the flow meter. (vi ) Whether the flow meter is mass or volumetric. ( vii ) The sta ndard used to calculate each value in paragraphs ( d )( 4 ) (ii) through ( d )( 4 ) (i v ) of this section . (viii ) The number of times in the reporting year for which substitute data procedures were used to calcul ate values reported in paragraphs ( d )( 4 ) (ii) through ( d )( 4 ) (i v ) of this section. (5 ) The value for X (%) used in Equation RR
- 9 and as determined according to your EPA - approved MRV plan. ( 6 ) Annual CO 2 produced in the reporting year as calculated in Equation RR
- 9 . ( 7 ) For each leakage pathway through which CO 2 emissions occurred , report : (i) A numerical identifier for the leakage pathway. (ii) T he CO 2 (metric tons) emitted through that pathway in the reporting year.OMB DRAFT: Please do not cite, quote, or distribute Page 119 of 142 ( 8 ) Annual CO 2 mass emitted (metric tons) by surface leakage in the reporting year as ca lculated by Equation RR
10 . ( 9 ) Annual CO 2 (metric tons) sequestered in subsurface geologic formations in the reporting year as calculated by Equation RR
- 1 1 or RR - 1 2 . ( 10 ) Cumulative mass of CO 2 (metric tons) reported as sequestered in subsurface geologi c formations in all years since the well or group of wells became subject to reporting requirements under this subpart . ( 11 ) Date that the most recent MRV plan was approved by EPA and the MRV plan approval number that was issued by EPA. (12 ) An annual mo nitoring report which contains the following components : ( i ) A narrative history of the monitoring effort s conducted over the previous calendar year , including a listing of all monitoring equipment that was operated , its period of operation , and any relev ant tests or surveys that were conducted. (ii) A description of any changes to the monitoring program that you concluded were not material changes warrant ing submission of a revised MRV plan under paragraph ( e) .OMB DRAFT: Please do not cite, quote, or distribute Page 120 of 142 (iii) A narrative history of any monitorin g anomalies that were detected in the previous calendar year and how they were investigated and resolved. ( iv ) A description of any surface leakages of CO 2 , including a discussion of all methodologies and technologies involved in detecting and quantif ying the surface leakages and any assumptions and uncertainties involved in calculating the amount of CO 2 emitted. ( 1 3 ) If a well is permitted under the Underground Injection Control program , for each injection well, report: (i ) The well identification number used for the Underground Injection Control permit. ( ii ) The Underground Injection Control permit class. ( 1 4 ) If an offshore well is not subject to the Safe Drinking Water Act, for each injection well, report any well identification number and any ide ntification number used for the the legal instrument authorizing geologic sequestration . §98.447 Records that must be retained. In addition to the records required by §98.3(g), you must retain the records specified in paragraphs (a) through ( g ) of this se ction, as applicable. (a) You must retain quarterly records of CO 2 received , including mass flow rate of contents of containers (mass orOMB DRAFT: Please do not cite, quote, or distribute Page 121 of 142 volume tric) at standard conditions and operating conditions, operating temperature and pressure, and concentration of these streams. (b) Quarterly records of produced CO 2 , including mass flow or volume tric flow at standard conditions and operating conditions , operating temperature and pressure, and concentration of these streams. ( c ) Quarterly records of injected CO 2 i ncluding mass flow or volume tric flow at standard conditions and operating conditions , operating temperature and pressure, and concentration of these streams. (d) Annual records of information used to calculate the CO 2 emitted by surface leakage from leak age pathways. (e) Annual records of information used to calculate the CO 2 emitted as fugitive or vented emissions from equipment located on the surface between the flow meter used to measure injection quantity and the injection wellhead . (f) Annual recor ds of information used to calculate the CO 2 emitted as fugitive or vented emissions from equipment located on the surface between the production wellhead and the flow meter used to measure production quantity .OMB DRAFT: Please do not cite, quote, or distribute Page 122 of 142 ( g ) Any other records as specified for retent ion in your EPA - approved MRV plan. §98.448 Geologic sequestration monitoring, reporting, and verification (MRV) p lan. (a) Contents of MRV p lan . You must develop an d submit to the Administrator a proposed MRV plan for monitoring, reporting, and verifica tion of geologic sequestration at your facility. Your proposed MRV plan must contain the following components : (1) Delineation of the maximum monitoring area and the active monitoring a rea s . The first period for your active monitoring area will beg i n from the date determined in y our MRV plan through the date at which the plan calls for the first expansion of the monitoring area. The length of each monitoring period can be any time interval chosen by you that is greater than one year. (2) Identificatio n of potential surface leakage pathways for CO 2 in the maximum monitoring area and the likelihood , magnitude , and timing, of surface leakage of CO 2 through these pathways . (3) A strategy for detecting and quantifying any surface leakage of CO 2 . (4) A str ategy for establishing the expected environmental baselines.OMB DRAFT: Please do not cite, quote, or distribute Page 123 of 142 (5) A s ummary of the considerations you intend to use to calculate site
- specific variables for the mass balance equation. This includes, but is not limited to, considerations for calculating f ugitive and vented emissions between the injection flow meter and injection well and/or the production flow meter and production well, and considerations for calculating CO 2 in produced fluids. (6) If a well is permitted under the Underground Injection C ontrol program , for each injection well, report the well identification number used for the Underground Injection Control permit and the Underground Injection Control permit class. If the well is not yet permitted, and you have applied for a n Underground Injection Control permit, report t he well identification numbers in the permit application . If an offshore well is not subject to the Safe Drinking Water Act, for each injection well, report any well identification number and any identification number used for the the legal instrument authorizing geologic sequestration . If you are submitting your Underground Injection Control permit application as part of your proposed MRV plan, you must notify EPA when the permit has been approved. If you are an offshore facility not subject to the Safe Drinking Water Act, and are submitting your application for the legal instrumentOMB DRAFT: Please do not cite, quote, or distribute Page 124 of 142 authorizing geologic sequestration as part of your proposed MRV plan, you must notify EPA when the legal instrument authorizing geologic sequ estration has been approved. (b) Timing . You must submit a proposed MRV plan to EPA according to the following schedule: (1) Y ou must submit a proposed MRV plan to EPA by [ INSERT THE DATE 180 DAYS AFTER PUBLICATION IN THE FEDERAL REGISTER ] if you were i ssued a final Underground Injection Control permit authorizing the injection of CO 2 into the subsurface before [ INSERT THE DATE OF PUBLICATION IN THE FEDERAL REGISTER ]. You will be allowed to request one extension of up to an additional 180 days in which to submit your proposed MRV plan . (2) You must submit a proposed MRV plan to EPA within 180 days of receiving a final Underground Injection Control permit authorizing the injection of CO 2 into the subsurface. If you are an offshore facility not subject t o the Safe Drinking Water Act , you must submit a proposed MRV plan to EPA within 180 days of receiving authoriz ation to begin geologic sequestration of CO 2 . You will be allowed to request one extension of the submittal date of up to an additional 180 days . (3) If you are injecting a CO 2 stream in subsurface geologic formations to enhance the recovery of oil orOMB DRAFT: Please do not cite, quote, or distribute Page 125 of 142 natural gas and you are not permitted as Class VI under the Underground Injection Control program , you may opt to submit an MRV plan at any time. (4) If EPA determines that your proposed MRV plan is incomplete, you must submit an updated MRV plan within 45 days of EPA notification, unless otherwise specified by EPA. (c) Final MRV p lan . The Administrator will issue a final MRV Plan within a reason able period of time. The Administrator’s final MRV plan is subject to the provisions of part 78 of this chapter. Once the MRV Plan is final and no longer subject to administrative appeal under part 78 of this chapter , you must implement the plan starting on the day af t er the day on which the plan becomes final and is no longer subject to such appeal . ( d ) MRV plan r evisions . You must revise and submit the MRV plan within 180 days to the Administrator for approval if any of the following in paragraphs ( d )( 1) through ( d )( 4 ) applies . You must include the reason(s) for the revisions in your submittal. (1) A material change was made to monitoring and/or operational parameters. Examples of material changes include but are not limited to : large changes in th e volume of CO 2 injected; the construction of new injection wells notOMB DRAFT: Please do not cite, quote, or distribute Page 126 of 142 identified in the MRV plan; large changes in injection pressures; failures of the monitoring system including monitoring system sensitivity, performance, location, or environmental basel ine; changes to surface land use that affects baseline or operational conditions; observed plume location that differs from the predicted plume area used for developing the monitoring plan; a change in the maximum
monitoring a rea or active monitoring a rea; or a change in monitoring technology that would result in coverage or detection capability different from the MRV plan. (2) A change in the permit class of your Underground Injection Control permit . (3) If you are notified by EPA of errors in your MRV plan or monitoring report . (4) You may submit a revised MRV plan to the Administrator in any reporting year . ( e ) The requirements of paragraph (c) apply to any submission of a revised MRV Plan. ( f ) Each proposed MRV plan or revision and each annual report must be submitted electronically in a format specified by the Administrator. (g) Certificate of representation . You must submit a certificate of representation according to the provisions in § 98.4 at least 60 days before submission of your MRVOMB DRAFT: Please do not cite, quote, or distribute Page 127 of 142 pla n , your R&D exemption request, your MRV plan submission extension request, or your initial annual report under this part, whichever is earlier. §98.449 Definitions. Except as provided below, a ll terms used in this subpart have the same meaning given in th e Clean Air Act and subpart A of this part. Active monitoring a rea i s the area that will be monitored over a specific time interval from the first year of the period (n) to the last year in the period (t). The boundary of the active monitoring area is est ablished by superimposing tw o areas: a) the area projected to contain the free phase CO 2 plume at the end of year t, plus an all around buffer zone of one - half mile or greater if known leakage pathways extend laterally more than one - half mile and b) the ar ea projected to contain the free phase CO 2 plume at the end of year t+ 5 . CO 2 received means the CO 2 that you receive to be injected for the first time into a well on your facility that is covered by this subpart . CO 2 received includes, but is not limited to, CO 2 from a production process unit inside your facility and CO 2 that was injected into a well on another facility, removed from a discontinued enhanced oilOMB DRAFT: Please do not cite, quote, or distribute Page 128 of 142 or natural gas or other production well, and transferred to your facility. Expected e nvironment al b aseline is the anticipated value of a monitored parameter which is compared to the measured monitored parameter at a speci fic location to detect anomalies that may indicate subsurface or surface leakages. Maximum monitoring a rea means the area that must be monitored under this regulation and is defined as equal to or greater than the area expected to contain the free phase CO 2 plume until the CO 2 plume has stabilized plus an all
around buffer zone of at least one - half mile. Research and development project means a project that is neither a demonstration nor a commercial project and that is researching practices or monitoring techniques that will enable safe and effective long
- term containment of a CO 1 stream in subsurface geologic formations . Separat or means a vessel in which streams of multiple phases are gravity separated into individual streams of single phase. Surface Leakage means the movement of the injected CO 2 stream from the injection zone to the surface, and into the atmosphere, indoor air, oceans or surface water.OMB DRAFT: Please do not cite, quote, or distribute Page 129 of 142 Underground Injection Control permit means a permit issued under the authority of Part C of the Safe Drinking Water Act at 42 U.S.C. 300h et seq . Underground Injection Control p rogram means the program responsible for regulating the construction, operation, permitting, and closure of injection wells that place fluids underground for storage or disposal for purposes of protecting underground sources of drinking water from endangerment pursuant to Part C of the Safe Drinking Water A ct at 42 U.S.C . 300h et seq . * * * * * 1 2 . Part 98 is amended by adding subpart UU to read a s follows: Sec. 98. 47 0 Definition of the source category. 98. 47 1 Reporting threshold. 98. 47 2 GHGs to report. 98. 47 3 Calculating CO 2 received . 98. 47 4 Monitorin g and QA/QC requirements. 98. 47 5 Procedures for estimating missing data. 98. 47 6 Data reporting requirements. 98.477 Records that must be retained.
Subpart UU

—Injection of Carbon Dioxide §98. 47 0 Definition of the source category. (a) The injection of carbon dioxide ( CO 2 ) source category comprises a ny well or group of wells that inject s a CO 2 stream into the subsurface .OMB DRAFT: Please do not cite, quote, or distribute Page 130 of 142 (b) If you report under subpart RR for a well or group of wells , you are not required to report under this subpart for that well or g roup of wells . (c) A facility that is subject to this part only because of subpart UU is not required to report emissions under subpart C of this part or any other subpart listed in §98.2(a)(1)or(a)(2). §98. 47 1 Reporting threshold. (a) You must report u nder this subpart if your facility injects any amount of CO 2 into the subsurface . (b) For purposes of this subpart, any reference to CO 2 emissions in §98.2(i ) shall mean CO 2 received . §98.472 GHGs to report . You must report the mass of CO 2 received. §98. 47 3 Calculating CO 2 received . (a) Y ou must calculate and report the annual mass of CO 2 received by pipeline using the procedures in paragraph s (a)(1) or (a)(2) of this section and the procedures in paragraph (a)(3) of this section, if applicable . (1) Fo r a mass flow meter, you must calculate the total annual mass of CO 2 in a CO 2 s tream received in metric tons by multiplying the mass flow by the CO 2 concentration in the flow, according to Equation UU - 1 of this section. You must collect these data quarter ly. Mass flow andOMB DRAFT: Please do not cite, quote, or distribute Page 131 of 142 concentration data measurements must b e made in accordance with §98. 47 4 . CO 2 T = p CO p d p p r C Q Q

, 2 * ) (
, 4 1 ,  

# 

 (Eq. UU - 1) Where: CO 2 T = Annual mass of CO 2 received (metric tons). Q r , p = Quarterly mass flow through a receiving flow

meter i n quarter p (metric tons). Q d,p = Quarterly mass flow through a receiving flow

meter that is redelivered to another facility without being injected into your well in quarter p ( metric tons ) . C CO2,p = Quarterly CO 2 concentration measurement in flow

in qu arter p (wt. %CO 2 / 100 ). p = quarter . (2) For a volumetric flow meter, you must calculate the total annual mass of CO 2 in a CO 2 s tream received in metric tons by multiplying the volumetric flow at standard conditions by the CO 2 concentration in the flow a nd the density of CO 2 at standard conditions, according to Equation UU - 2 of this section. You must collect these data quarterly. Volumetric flow and concentration data measurements must b e made in accordance with §98. 47 4.

CO 2 T = p CO p p d p p r C

D Q Q

, 2 * * ) (
, 4 1 ,  

# 

 (Eq. UU - 2) Where: CO 2 T = Annual mass of CO 2 received (metric tons).OMB DRAFT: Please do not cite, quote, or distribute Page 132 of 142 Q r, p = Quarterly volumetric flow through a receiving

flow meter in quarter p at standard conditions (standard cubic meters). Q d,p = Q uarterly volumetric flow through a receiving

flow meter that is redelivered to another facility without being injected into your well in quarter p ( standard cubic meters ). D p = Density of CO 2 at standard conditions (metric

tons per standard cubic meter) : 0.0018704 . C CO2,p = Quarterly CO 2 concentration measurement in flow

in quarter p ( vol . %CO 2 / 100 ). p = quarter . ( 3) If you receive CO 2 through more than one flow meter, you must sum the mass of all CO 2 received in accordance with the pr ocedure specified in Equation UU
- 3 of this section.
CO 2 = 

## 

 V

v 1 v

2T, CO (Eq. UU - 3) Where: CO 2 = Total annual mass of CO 2 received (metric

tons). CO 2 T ,v = Annual mass of CO 2 received (metric tons) as

calculated in Equation UU
- 1 or UU - 2 for flow meter v. v = flow meter. (b) Y ou must c alculate and report the a nnual mass of CO 2 received in containers using the procedures specified in either parag r aph ( b )(1) or ( b )(2) of this section. ( 1) If you are measuring the mass of contents in a container under the provisions of § 98.47 4(a ) ( 2 )(i) , youOMB DRAFT: Please do not cite, quote, or distribute Page 133 of 142
must calculate the CO 2 received in containers using Equation UU - 1 of this section.
Where: CO 2 = Annual mass of CO 2 received in container s

(metric tons). C CO2,p = Quarterly CO 2 concentration measurement of

contents in container s in quarter p (wt. %CO 2 ). Q p,u = Quarterly ma ss of contents in container s in

quarter p (metric tons). p = Quarter of the year. ( 2 ) If you are measuring the volume of contents in a container under the provisions of §98.474(a ) ( 2 )(ii) , you must calculate the CO 2 received in containers using Equation UU - 2 of this section.
Where: CO 2 = Annual mass of CO 2 received in container s

(metric tons). C CO2,p = Quarterly CO 2 concentration measurement of

contents in containers in quarter p ( vol . %CO 2 ). Q p = Quarterly volume of contents in containers in

quarter p (standard cubic meters). D p = Quarterly density of the CO 2 received in

containers at standard conditions (metric tons per standard cubic meter) :0.0018704. p = Quarter of the year. §98. 47 4 Monitoring and QA/QC requirements. (a) CO 2 received .OMB DRAFT: Please do not cite, quote, or distribute Page 134 of 142 ( 1 ) Y ou must determine the quarterly flow rate of CO 2 received by pipeline by following the most appropriate of the following procedures: ( i ) You may measure flow rate at the receiving custody transfer meter prior to any subsequent processing operations at the fac ility and collect the flow rate quarterly . ( ii ) If you took ownership of the CO 2 in a commercial transaction, you may use the quarterly flow rate data from the sales contract if it is a one
- time transaction or from invoices or manifests if it is an ongoi ng commercial transaction with discret e shipments. (iii) If you inject CO 2 from a production process unit that is part of your facility, you may use the quarterly CO 2 flow rate that was measured at the equivalent of a custody transfer meter following proc edures provided in subpart PP. To be the equivalent of a custody transfer meter, a meter must measure the flow of CO 2 being transported to an injection well to the same degree of accuracy as a meter used for commercial transactions. ( 2 ) You must determine the quarterly mass or volume of contents in all containers if you receive CO 2 in containers by the most appropriate of the following procedures:OMB DRAFT: Please do not cite, quote, or distribute Page 135 of 142 ( i ) You may measure the mass of contents of containers summed quarterly using weigh bills, scales, or load cel ls. ( ii ) You may determine the volume of the contents of containers summed quarterly . (iii) If you took ownership of the CO 2 in a commercial transaction, you may use the quarterly mass or volume of contents from the sales contract if it is a one
- time tra nsaction or from invoices or manifests if it is an ongoing commercial transaction with discret e shipments. ( 3 ) Y ou must determine a quarterly concentration of the CO 2 received that is representative of all CO 2 received in that quarter by following the mos t appropriate of the following procedures: ( i ) You may sample the CO 2 stream once per quarter at the point of receipt and measure its CO 2 concentration . ( ii ) If you took ownership of the CO 2 in a commercial transaction for which the sales contract was co ntingent on CO 2 concentration , and if the supplier of the CO 2 sampled the CO 2 stream in a quarter and measured its concentration per the sales contract terms, you may use the CO 2 concentration data from the sales contract for that quarter . (iii) If you in ject CO 2 from a production process unit that is part of your facility, you may report the quarterlyOMB DRAFT: Please do not cite, quote, or distribute Page 136 of 142
CO 2 concentration of the CO 2 stream supplied that was measured following procedures provided in subpart PP as the quarterly CO 2 concentration of the CO 2 str eam received. (b) Measurement devices . (1) All flow meters must be operated continuously except as necessary for maintenance and calibration. (2) You must calibrate all flow meters used to measure quantities reported in §98.4 7 6 according to the calibrat ion and accuracy requirements in §98.3(i) . (3) You must operate all measurement devices according to one of the following: an appropriate standard method published by a consensus
- based standards organization if such a method exists ; or an industry standa rd practice . Consensus - based standards organizations include, but are not limited to, the following: ASTM International, the American National Standards Institute (ANSI), the American Gas Association (AGA), the American Society of Mechanical Engineers (AS ME), the American Petroleum Institute (API), and the North American Energy Standards Board (NAESB). ( 4 ) You must ensure that any flow meter calibrations performed are NIST traceable. ( c ) General .OMB DRAFT: Please do not cite, quote, or distribute Page 137 of 142 (1) If y ou measure the concentration of any CO 2 quantit y for report ing, you must use methods that conform to applicable chemical analytical standards. ( 2 ) You must use the same calculation methodology throughout a reporting period unless you provide a written explanation of why a change in methodology was re quired. (3) Y ou must convert all measured volumes of CO 2 to the following standard industry temperature and pressure
co nditions for use in equations UU
- 2: standard cubic meter s at a temperature of 60 degrees Fahrenheit and at an absolute pressure of 1 atmo sphere . (4 ) For 2011, you may follow the provisions of §98.3(d)(1) through (3) for best available monitoring methods rather than follow the monitoring requirements of this section. For purposes of this subpart, any reference to the year 2010 in §98.3(d)( 1) through (3) shall mean 2011. §98. 47 5 Procedures for estimating missing data. A complete record of all measured parameters used in the GHG quantities calculations is required. (a) Whenever the monitoring procedures for all facilities that used flow meters covered under this subpart cannot be followed to measure flow , the following missing data procedures must be followed:OMB DRAFT: Please do not cite, quote, or distribute Page 138 of 142 (1) Another calculation methodology listed in section 98. 474(a ) ( 1 ) must be used if possible. (2) If another method listed in §98. 4 74 ( a ) ( 1 ) cannot be used, a quarterly flow rate value that is missing must be estimated using a representative flow rate value from the nearest previous time period. (b) Whenever the monitoring procedures of this subpart cannot be followed to measure quart erly quantity of CO 2 received in containers, the most appropriate of the following missing data procedures must be followed: (1) Another calculation methodology listed in secti on 98.474( a ) ( 2 ) must be used if po ssible. (2) If another method listed in §98 .4 74 ( a ) ( 2 ) cannot be used, a quarterly mass or volume that is missing must be estimated using a representative mass or volume from the nearest previous time period. (c) Whenever the monitoring procedures cannot be followed to measure CO 2 concentration, the following missing data procedures must be followed: (1) Another calculation methodology listed in section 98.474( a ) ( 3 ) must be used if posssible. (2) If another method listed in §98.4 74 ( a ) ( 3 ) cannot be used, a quarterly concentration value that is missi ngOMB DRAFT: Please do not cite, quote, or distribute Page 139 of 142
must be estimated using a representative concentration value from the nearest previous time period. §98. 47 6 Data reporting requirements. If you are subject to this part and report under this subpart , you are not required to report the information in §9 8.3(c) (4) for this subpart . In addition to the information required by §98.3(c) (1) through §98.3(c) (3) and by §98.3(c) (5) through §98.3(c) (9) , you must report the information listed in this section. (a) The mass of CO 2 received . (1) If you receive CO 2 b y pipeline, report the following for each receiving flow meter : (i ) T he t otal mass of CO 2 received (metric tons) annually . (ii ) The CO 2 concentration in the flow (volume or wt. % CO 2 /100 ) in each quarter. (iii ) If a volumetric flow meter is used to rece ive CO 2 : (A) T he volumetric flow through a receiving flow meter at standard conditions ( in standard cubic meters ) in each quarter . (B) The volumetric flow through a receiving flow meter that is redelivered to another facility without beingOMB DRAFT: Please do not cite, quote, or distribute Page 140 of 142 injected into your well ( in standard cubic meters ) in each quarter . (iv) If a mass flow meter is used to receive CO 2 : (A) T he mass flow through a receiving flow meter ( in metric tons) in each quarter . (B) The mass flow through a receiving flow meter that is redeliv ered to another facility without being injected into your well ( in standard cubic meters ) in each quarter . ( v ) The standard or method used to calculate each value in paragraphs (a)( 1 ) (ii) through (a) ( 1 ) (i v) of this section. ( vi ) The number of times in the reporting year for which substitute data procedures were used to calcul ate values reported in paragraphs (a)( 1 ) (i i ) through (a) ( 1 ) (i v) of this section. (vii) Whether the flow meter is mass or volumetric. (2) If you receive CO 2 in containers, report: ( i) T he mass ( in metric tons) or volume at standard conditions ( in standard cubic meters) of contents in containers in each quarter . (ii) The concentration of CO 2 of contents in containers (volume or wt. % CO 2 /100 ) in each quarter. (iii) The t otal mass of CO 2 received ( in metric tons) annually .OMB DRAFT: Please do not cite, quote, or distribute Page 141 of 142 (i v ) The standard or method used to calculate each value in paragraphs (a)( 2 ) (i) and (a) ( 2 ) (ii) of this section. (v) The number of times in the reporting year for which substitute data procedures were used to calcu l ate values reported in paragraphs (a)( 2 ) (i) and (a) ( 2 ) (ii) of this section. ( b ) If you use more than one receiving flow meter, report the total mass of CO 2 received (metric tons) through all flow meters annually. (c) The source of the CO 2 received acc ording to the following categories: ( 1 ) CO 2 production wells. ( 2 ) Electric generating unit. ( 3 ) Ethanol plant. ( 4 ) Pulp and paper mill. ( 5 ) Natural gas processing. ( 6 ) Gasification operations . ( 7 ) Other anthropogenic source. ( 8 ) CO 2 received from a discontinued enhanced oil and gas recovery project . ( 9 ) Unknown. §98. 47 7 Records that must be retained.OMB DRAFT: Please do not cite, quote, or distribute Page 142 of 142 In addition to the records required by §98.3(g), you must retain quarterly records of CO 2 received , including
mass flow rate or contents of container s (mass or volumetric) at standard conditions and operating conditions, operating temperature and pressure, and concentration of these streams. §98.478 Definitions . Except as provided below, a ll terms used in this subpart have the same meaning given in th e Clean Air Act and subpart A of this part. CO 2 received means the CO 2 that you receive to be injected for the first time into a well on your facility that is covered by this subpart . CO 2 received includes, but is not limited to, CO 2 from a production pro cess unit inside your facility and CO 2 that was injected into a well on another facility, removed from a discontinued enhanced oil or natural gas or other production well, and transferred to your facility.OMB DRAFT: Please do not cite, quote, or distribute 

### July 2010 

# Economic Impact Analysis for the

Mandatory Reporting of Greenhouse Gas Emissions Subpart RR and Subpart UU: Injection and Geologic Sequestration of Carbon Dioxide
Final ReportOMB DRAFT: Please do not cite, quote, or distribute


### C ONTENTS Section 1 Introduction and Background
................................ ................................ ................. 1
- 1 1.1 Greenhouse Gas Reporting Program Background
................................ ............... 1
- 1 1.2 Monitoring and Reporting Requirements for Injection and Geologic Sequestration of Carbon Dioxide: Subpart RR and UU
................................ ...... 1
- 1 Section 2 Regulatory Background
................................ ................................ .......................... 2
- 1 2.1 EPA’s Overall Rulemaking Approach
................................ ................................ . 2
- 1 2.2 Statutory Authority
................................ ................................ ............................... 2
-2 2.3 Safe Water Drinking Act and UIC Regulations
................................ ................... 2
-2 2.4 Relationship to the Interagency Task Force on Carbon Capture and Storage and Other Federal GS Initiatives
................................ ............................. 2
-4 2.5 Relationship to Other Geologic Sequestration Information Collection and Reporting Efforts
................................ ................................ ................................ .. 2
- 5 Section 3 Summary of Final Rule: Subpart RR and UU
................................ ....................... 3
- 1 3.1 Subpart RR
................................ ................................ ................................ ........... 3
- 1 3.1.1 Source Category Definition
................................ ................................ ...... 3
- 1 3.1.2 Subpart RR Reporting Threshold
................................ ............................. 3
- 1 3.1.3 Subpart RR GHGs to Report
................................ ................................ .... 3
- 1 3.1.4 Subpart RR GHG Calculations and Monitoring
................................ ....... 3
-2 3.1.5 Subpart RR Data Reporting
................................ ................................ ...... 3
-2 3.1.6 Subpart RR Recordkeeping
................................ ................................ ...... 3
-2 3.1.7 Subpart RR Geologic Sequestration Monitoring, Reporting, and Verification (MRV) Plans
................................ ................................ ........ 3
-2 3.1.8 Administrative Appeals.
................................ ................................ ........... 3
-2 3.2 Subpart UU
................................ ................................ ................................ ........... 3
-2 3.2.1 Subpart UU Source Category Definition
................................ .................. 3
-2 3.2.2 Subpart UU Reporting Threshold
................................ ............................. 3
-3 3.2.3 Subpart UU GHGs to Report
................................ ................................ .... 3
-3 3.2.4 Subpart UU GHG Calculations and Monitoring
................................ ...... 3
-3 3.2.5 Subpart UU Data Reporting
................................ ................................ ..... 3
-3OMB DRAFT: Please do not cite, quote, or distribute

ii 3.2.6 Subpart UU Recordkeeping
................................ ................................ ...... 3
-3 3.3 Summary of Major Changes Since Proposal
................................ ........................ 3
-3 Section 4 Engineering Cost Analysis
................................ ................................ ..................... 4
- 1 4.1 Introduction
................................ ................................ ................................ .......... 4
- 1 4.2 Overview of Cost Analysis
................................ ................................ ................... 4
- 1 4.3 Baseline Reporting
................................ ................................ ............................... 4
- 1 4.3.1 Introduction
................................ ................................ .............................. 4
- 1 4.3.2 Data Sources
................................ ................................ ............................. 4
-2 4.3.3 Published Data on CO2 Sequestration Projects
................................ ........ 4
-3 4.3.4 Hydrogeologic Settings
................................ ................................ ............ 4
- 5 4.3.5 Formation Capacity
................................ ................................ .................. 4
- 8 4.3.6 Geologic Sequestration Rule Activity Baseline
................................ ..... 4
- 11 4.4 Reporting Costs
................................ ................................ ................................ .. 4
- 16 4.4.1 Introduction
................................ ................................ ............................ 4
- 16 4.4.2 Cost Assumptions and Methodology
................................ ..................... 4
- 17 4.4.3 Monitoring, Reporting, and Verification (MRV) Plan Requirements and Approval Process
................................ ...................... 4
- 19 4.5 Monitoring Technologies
................................ ................................ ................... 4
-22 4.5.1 Cost Scenarios
................................ ................................ ........................ 4
-26 4.6 Projecting and Discounting National Costs
................................ ........................ 4
-29 4.7 MRV Plan Costs
................................ ................................ ................................ . 4
-36 4.8 Annual Report Costs
................................ ................................ .......................... 4
-39 4.9 Other Recordkeeping and Reporting Costs
................................ ........................ 4
-39 4.10 Public Sector Burden
................................ ................................ .......................... 4
-39 Section 5 Economic impact analysis
................................ ................................ ...................... 5
- 1 5.1 Threshold Analysis
................................ ................................ ............................... 5
- 1 5.2 National Cost Estimates
................................ ................................ ....................... 5
-2 5.2.1 National Cost Estimates Under Alternative Facilities Conducting GS (ER opt in) Outcomes
................................ ................................ ......... 5
-4 5.2.2 National Cost Estimates Under Alternative Facilities Conducting GS (Commercial Saline) Outcomes
................................ ......................... 5
-6OMB DRAFT: Please do not cite, quote, or distribute

iii 5.2.3 National Cost Estimates: 2011 to 2060 Using Underground Injection Control Program for Carbon Dioxide Geologic Sequestration Wells (UIC Class VI Rule) Baseline
................................ . 5
-7 5.3 Economic Impact Analysis
................................ ................................ ................... 5
-9 5.3.1 Revenue Estimate for a Representative Commercial ER Operation
........ 5
-9 5.3.2 Sales Test Results
................................ ................................ ................... 5
- 10 5.4 Assessing Economic Impacts on Small Entities
................................ ................. 5
- 10 5.4.1 Identify Affected Sectors and Entities
................................ .................... 5
- 10 5.4.2 Develop Small Entity Economic Impact Measures
................................ 5
- 11 5.4.3 Results of Screening Analysis
................................ ................................ 5
- 11 5.5 Characterization of Benefits of Subpart RR and Subpart UU of the Mandatory Reporting Rule
................................ ................................ ................. 5
- 12 Section 6 Statutory and Executive Order Reviews
................................ ................................ . 6
- 1 6.1 Executive Order 12866: Regulatory Planning and Review
................................ .. 6
- 1 6.2 Paperwork Reduction Act
................................ ................................ .................... 6
- 1 6.3 Regulatory Flexibility Act
................................ ................................ .................... 6
-3 6.3.1 Identify Affected Sectors and Entities
................................ ...................... 6
-3 6.3.2 Develop Small Entity Economic Impact Measures
................................ .. 6
-4 6.3.3 Results of Screening Analysis
................................ ................................ .. 6
-4 6.4 Unfunded Mandates Reform Act
................................ ................................ .......... 6
- 5 6.5 Executive Order 13132: Federalism
................................ ................................ ..... 6
- 5 6.6 Executive Order 13175: Consultation and Coordination with Indian Tribal Governments
................................ ................................ ................................ ........ 6
-6 6.7 Executive Order 13045: Protection of Children from Environmental Health and Safety Risks
................................ ................................ ....................... 6
-7 6.8 Executive Order 13211: Actions that Significantly Affect Energy Supply, Distribution, or Use
................................ ................................ .............................. 6
-7 6.9 National Technology Transfer Advancement Act
................................ ................ 6
-7 6.10 Executive Order 12898: Federal Actions to Address Environmental Justice in Minority Populations and Low
-Income Populations
................................ ....... 6
- 8 Section 7 Conclusions
................................ ................................ ................................ ............ 7
- 1 7.1 Summary of Selected Regulatory Alternative
................................ ...................... 7
- 1OMB DRAFT: Please do not cite, quote, or distribute

iv 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
- 1OMB DRAFT: Please do not cite, quote, or distribute

v LIST OF TABLES Table 4
- 1. Comparison of ICF Assessment of U.S. Sequestration Potential with Published

Estimates
................................ ................................ ................................ .................4
- 10 Table 4
-2. Summary of ICF Sequestration Capacity Assessment
................................ .............. 4
- 11 Table 4
-3. Pro
- forma Project Characteristics (ER Scenario: No Additional ER Opt In)
........... 4
- 13 Table 4
-4. Pro
- forma Project Characteristics (ER Scenario: Anthropogenic ER Only Opt In)
. 4
- 14 Table 4
- 5. Pro
- forma Project Characteristics (ER Scenario: Anthropogenic plus One
-half Other

ER Opt In)
................................ ................................ ................................ ............... 4
- 15 Table 4
-6. Major Sources of Geologic Sequestration Cost Information
................................ .... 4
- 18 Table 4
-7. Unit Cost of Relevant Continuous and Periodic Monitoring Technologies
............ 4
-20 Table 4
- 8. Unit Cost of Relevant Episodic Monitoring Technologies (That may be employed

after a subsurface leak is detected)
................................ ................................ .......... 4
-21 Table 4
-9. Assumptions for Application of Technologies by Regulatory Alternative
.............. 4
-27 Table 4
- 10. Summary of Cost Impacts: Activity Baseline with No Additional ER Opt In
...... 4
-30 Table 4
- 11. Summary of Cost Impacts: Activity Baseline from only Anthropogenic ER Opt In 4
-

32 Table 4
- 12. Summary of Cost Impacts: Activity Baseline from Anthropogenic CO 2 plus One
half of Other ER Opt In
................................ ................................ ...........................4
-34 Table 4
- 13. Cost of Developing MRV Plan: New Project with UIC Class VI Permit
............. 4
-37 Table 4
- 14. Cost of Developing MRV Plan: ER Class II Project (no Class VI Permit)
......... 4
-38 Table 5
- 1 Geologic Sequestration Facilities: Effect of CO 2 Received Threshold on Reported

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

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

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

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

UU
................................ ................................ ................................ ............................. 5
-3OMB DRAFT: Please do not cite, quote, or distribute

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

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

Anthropogenic CO2 Projects
................................ ................................ ..................... 5
- 5 Table 5
-6. National Annualized Mandatory Reporting Costs Estimates (2008$): All

Anthropogenic and 50 Percent of Other CO2 Projects
................................ .............. 5
-6 Table 5
-7. Anticipated Level of U.S GS Activity Developed for the Underground Injection

Control Program for Carbon Dioxide Geologic Sequestration Wells (UIC Class VI Rule)
................................ ................................ ................................ .......................... 5
- 8 Table 5
- 8. Estimated Annual Revenue for a Representative Commercial ER Field Operation

(2008)
................................ ................................ ................................ ........................ 5
-9 Table 5
-9. Sales Tests for Representative Commercial ER Field Operations
........................... 5
- 10OMB DRAFT: Please do not cite, quote, or distribute

1
- 1 SECTION 1 INTRODUCTION AND BAC KGROUND 1.1 Greenhouse Gas Reporting Program Background The Greenhouse Gas (GHG) Reporting Program requires reporting of GHG emissions and other relevant information from certain source categories in the United States . The GHG Reporting Program does not require the control of GHGs ; rather it requires only monitoring and reporting of GHGs
. 40 CFR part 98 provides the regulatory framework for the GHG Reporting Program. The GHG Reporting Program, which became effective on December 29, 2009, includes reporting requirements for facilities and suppliers in 32 subparts . For more detailed background information on the GHG Reporting Program, see the preamble to the final rule establishing that program (74 FR 56260, October 30, 2009)
. 1.2 Monitoring and Reporting Requirements for Injection and Geologic Sequestration of Carbon Dioxide: Subpart RR and UU On April 12, 2010, EPA proposed this rule, amending the Greenhouse Gas (GHG) Reporting Program at 40 CFR part 98. Subpart PP of the GHG Reporting Program requires the reporting of carbon dioxide (CO2) supplied to the economy. During the public comment period on the final rule establishing that requirement, EPA received many comments that CO 2 geologically sequestered should be considered in the GHG Reporting Program. (For further information on relevant comments received in subpart PP see “Mandatory Greenhouse Gas Reporting Rule: EPA's Response to Public Comments, Subpart PP: Suppliers of Carbon Dioxide” at EPA
-HQ
-OAR
-2008
-0508.) In the final rule promulgating subpart PP, EPA committed to taking action to collect such data in the near future. Subpart RR information will enable EPA to monitor the growth and efficacy of GS (and therefore CCS) as a GHG mitigation technology over time and to evaluate relevant policy options. For example, EPA will be able to track whether incentives or regulations are needed to encourage faster or further GS project development. Furthermore, where enhanced oil and gas recovery (ER) projects are reporting under subpart RR, EPA will be able to evaluate ER as a non-emissive end use
. Under subpar t UU, EPA will be able to reconcile information obtained from this rule with data obtained from subpart PP on CO2 supplied to the economy. The rule was proposed by EPA on April 12, 2010. One public hearing was held on April 19, 2010, and the sixty day public comment period ended June 11, 2010. This rule takes into consideration comments received during the comment period and finalizes the monitoring andOMB DRAFT: Please do not cite, quote, or distribute

1
-2 reporting requirements for facilities conducting GS and all other facilities conducting CO 2 injection. This final rule does not address whether data reported under subparts RR or UU will be released to the public or will be treated as CBI. EPA published a proposed rule on confidentiality determination on July 7, 2010 (75 FR 39094) which addressed this issue. In that action, EPA proposed which specific data elements would be released to the public and which would be treated as CBI. EPA received several comments on that proposal under that action, and is in the process of considering these comments. A final rule and determination will be issued before any data is released. The final determination will address CBI considerations for all of the data elements under subparts RR and UU.OMB DRAFT: Please do not cite, quote, or distribute

2
- 1 SECTION 2 REGULATORY BACKGROUND The intent of the GHG Reporting Program is to collect accurate and timely GHG data that can be used to inform future policies. Although the GHG Reporting Program is unique, EPA carefully considered other federal and state programs during development of the rule. The reporting program will supplement rather than duplicate other U.S. government GHG programs. We outline EPA’s overall rulemaking approach, statutory authority, relationship to and coordination with the Safe Drinking Water Act Underground Injection Control Class VI rule, and summarize the relationship to the Interagency Task Force on Carbon Capture and Storage and other Federal GS initiatives , as well as the relationship to other geologic s equestration information collection and reporting efforts below. 2.1 EPA’s Overall Rulemaking Approach The GHG Reporting Program provides comprehensive and accurate data which will inform future climate change policies. Potential future climate policies include research and development initiatives, economic incentives, new or expanded voluntary programs, adaptation strategies, emission standards, a carbon tax, or a cap
-and
-trade program. Because we do not know at this time the specific policies that will be adopted, the data reported to the GHG Reporting Program should be of sufficient quality to support a range of approaches. To these ends, we identified the following goals of the GHG Reporting Program :

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

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

 Create reporting requirements that are consistent with existing GHG reporting programs by using existing GHG emission estimation and reporting methodologies to reduce reporting burden, where feasible.OMB DRAFT: Please do not cite, quote, or distribute

2
-2 This section presents the current regulatory context for Subparts RR and UU and illustrates the anticipated role of the final rule within the framework of the existing mandatory and voluntary programs. 2.2 Statutory Authority EPA is promulgating this rule under its existing CAA authority; specifically, authorities provided in CAA section 114. As discussed in detail in Sections I.C and II.Q of the preamble to the final rule establishing the GHG Reporting Program (74 FR 56260 , October 30, 2009) , CAA section 114 provides EPA with broad authority to require information mandated by this rule, because such data will inform and are relevant to EPA’s carrying out a wide variety of CAA provisions. Under CAA section 114(a)(1), the Administrator may require emissions sources, persons subject to the CAA, or persons whom the Administrator believes may have necessary information to monitor and report emissions and provide such other information as the Administrator requests for the purposes of carrying out the provisions in the CAA (except for a provision of title II with respect to motor vehicles). EPA may gather information for a variety of purposes , including for the purpose of assisting in the development of implementation plans or of emissions standards under CAA section 111, determining compliance with implementation plans or such standards, or more broadly for “carrying out any provision” of the CAA. 2.3 Safe Water Drinking Act and UIC Regulations The Agency maintains a high
-level of coordination across EPA offices and regions on GS activities and regulatory development. EPA’s Office of Air and Radiation (OAR) and Office of Water (OW) work closely to promote safe and effective implementation of GS technologies while ensuring protection of human health and the environment. OAR and OW have closely coordinated this rulemaking under CAA authority and the rulemaking under Safe Drinking Water Act (SDWA) authority establishing Federal requirements under the UIC program for Class VI wells
. EPA’s UIC program was established in the 1970s to prevent endangerment of underground sources of drinking water (USDWs) from injection of various fluids, including CO2 for ER, oil field fluids, water stored for drinking water supplies, and municipal and industrial waste. The UIC program, which is authorized by Part C of SDWA (42 U.S.C. 300h et seq.), is designed to prevent the movement of such fluid into USDWs by addressing the potential pathways through which injected fluids can migrate and potentially endanger USDWs. In 2008, EPA proposed to amend the UIC program to establish a new class of injection well

— Class VI

— to cover the underground injection of CO2 for the purpose of GS, or long
-term storage of CO2OMB DRAFT: Please do not cite, quote, or distribute

2
-3 (73 FR 43492, July 25, 2008). For a summary of the UIC program and more details on the final UIC Class VI rule, please see the UIC Geologic Sequestration of Carbon Dioxide Web site: http://www.epa.gov/ogwdw000/uic/wells_sequestration.html
. EPA designed the reporting requirements under subpart RR with careful consideration of UIC requirements, including Class VI, to minimize overlap between the two programs . There are two areas of potential overlap. The first overlap is the requirement that owners or operators report the quantity of CO 2 injected. The UIC Class VI rule requires owners or operators to continuously monitor the amount of CO2 injected and submit semi
-annual reports on the monthly amount injected. The UIC program requires information on the amount injected to ensure appropriate CO2 injection operations . Subpart RR requires facilities to collect data on the amount injected over a quarter and submit annual reports on the annual amount of CO2 injected. Data on the amount of CO2 injected is a component of the subpart RR mass balance approach used to quantify the amount of CO2 sequestered. EPA determined that quarterly data collection and annual reporting under subpart RR was necessary in order to harmonize data with other subparts of the GHG Reporting Program. Facilities reporting under subpart RR may use flow meters used to comply with the flow monitoring and reporting provisions in their permit
. The second overlap is a monitoring plan for detecting air emissions. While requirements under the UIC program are focused on demonstrating that USDWs are not endangered as a result of CO2 injection into the subsurface, requirements under the GHG Reporting Program through subpart RR will enable EPA to verify the quantity of CO 2 that is geologically sequestered and to assess the efficacy of GS as a mitigation strategy. Subpart RR achieves this by requiring facilities conducting GS to develop and implement an MRV plan 1 to detect and quantify leakage of injected CO2 to the surface in the event leakage occurs and to report the amount of CO2 geologically sequestered using a mass balance approach, regardless of the class of UIC permit that a facility holds
. The monitoring required by subpart RR for quantification purposes is complementary to and builds on UIC permit requirements. In particular, the UIC Class VI permit requires a comprehensive site characterization that includes an assessment of the geologic, hydrogeologic, geochemical, and geomechanical properties of the proposed GS site to ensure that GS wells are located in suitable formations. The UIC Class VI permit also requires computational modeling
1 The subpart RR MRV plan includes delineation of monitoring areas, identification of potential surface leakage pathways, a strategy for detecting and quantifying surface leakage of CO 2 if leakage occurs, an approach for establishing the expected environmental and operational baselines and a summary of considerations for calculating site
- specific variables for the mass balance equation, such as calculating CO 2 in produced fluids. For more information, see Section II.B of this preamble.OMB DRAFT: Please do not cite, quote, or distribute

2
-4 of the Area of Review, and a periodic re
-evaluation of this Area of Review based on robust modeling and monitoring of the CO2 stream, injection pressures, integrity of the injection well, groundwater quality and geochemistry, and the position of the CO2 plume and pressure front throughout injection. These requirements can provide the basis for the MRV plan submitted to EPA for subpart RR. Therefore, EPA will accept a UIC Class VI permit to satisfy certain MRV plan requirements ; however, the reporter must include additional information to outline how monitoring will achieve surface detection and quantification of CO 2 in the event leakage occurs

. The UIC Class VI rule also allows f or surface air and soil gas monitoring at the discretion of the Director as a means of identifying CO2 leaks that may pose a risk to USDWs and informing emergency notification of a UIC Class VI owner or operator and UIC Director in the event of a USDW endangerment. If the Director determines that it is appropriate to require surface air or soil gas monitoring for USDW protection, the Director must approve the use of monitoring employed under subpart RR so long as the owner or operator is able to demonstrate USDW protection pursuant to requirements at § 146.90(h)(3). EPA has determined that the requirements of these two rules complement one another by concurrently ensuring USDW protection, as required under SDWA, and requiring reporting of CO2 surface emissions under subpart RR. EPA is committed to working closely within the agency to coordinate implementation of the UIC and GHG Reporting programs, reduce burden on reporters, provide timely access to verified emissions data, establish mechanisms to efficiently share data, and harmonize data systems to the extent possible. In the cost analysis conducted for this rule, EPA has assumed that for saline sequestration projects these requirements are in the baseline, and consequently estimated incremental costs associated with surface detection and quantification of CO 2 . Further detail on the cost analysis is available in sections 4 and 5 of this document. EPA is committed to working closely within the agency to coordinate implementation of the UIC and GHG Reporting programs, reduce burden on reporters, provide timely access to verified emissions data, establish mechanisms to efficiently share data, and harmonize data systems to the extent possible. 2.4 Relationship to the Interagency Task Force on Carbon Capture and Storage and Other Federal GS Initiatives On February 3, 2010, President Obama established an Interagency Task Force on Carbon Capture and Storage (CCS Task Force). The CCS Task Force, co
-chaired by EPA and the Department of Energy (DOE), developed a plan to overcome the barriers to the widespread, cost
effective deployment of CCS within ten years, with a goal of bringing five to ten commercialOMB DRAFT: Please do not cite, quote, or distribute

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- 5 demonstration projects online by 2016. The CCS Task Force’s plan was delivered to President Obama in August 2010. The CCS Task Force explored incentives for commercial CCS adoption and addressed financial, economic, technological, legal, institutional, social, or other barriers to deployment. For example, the CCS Task Force examined Federal regulatory activities that address the safety, efficacy, and environmental soundness of GS. The CCS Task Force also considered how best to coordinate existing administrative authorities and programs, including those involving international collaboration, as well as identified areas where additional administrative authority may be necessary. For more information, please see the CCS Task Force Web site: http://www.whitehouse.gov/administration/eop/ceq/initiatives/ccs. 2.5 Relationship to Other Geologic Sequestration Information Collection and Reporting Efforts EPA reviewed and took into account several existing domestic and international reporting and monitoring programs in designing this rule. For additional information, please see Section I.F of the notice of proposed rulemaking (75 FR 18581, April 12, 2010). Also as discussed in the notice of proposed rulemaking, EPA notes that the Internal Revenue Service (IRS) published IRS Notice 2009
- 83 (available at: http://www.irs.gov/irb/2009
- 44_IRB/ar11.html#d0e1860) to provide guidance regarding eligibility for the Internal Revenue Code section 45Q credit for CO2 sequestration, computation of the section 45Q tax credit, reporting requirements for taxpayers claiming the section 45Q tax credit, and rules regarding adequate security measures for secure GS
. As clarified in the IRS guidance, taxpayers claiming the section 45Q tax credit must follow the appropriate UIC requirements. The guidance also clarifies that taxpayers claiming section 45Q tax credit must follow the monitoring, reporting, and verification procedures that are being finalized under subpart RR in this action.OMB DRAFT: Please do not cite, quote, or distribute

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- 1 SECTION 3 SUMMARY OF FINAL RULE: SUBPART RR AND UU Facilities that conduct geologic sequestration are subject to subpart RR. All other facilities that inject CO 2 underground are subject to subpart UU. If you report under subpart RR for a well or group of wells, you are not required to report under subpart UU for that well or group of wells
. 3.1 Subpart RR 3.1.1 Source Category Definition The subpart RR source category consists of any well or group of wells that inject a CO2 stream for long
-term containment into a subsurface geologic formation. All wells permitted as Class VI by the UIC program meet the definition of this source category. Facilities conducting ER are not subject to subpart RR unless they choose to opt-in to the requirements of this subpart or hold a UIC Class VI permit. Facilities may submit a request to EPA to receive an exemption from reporting under subpart RR for GS R&D activities. 3.1.2 Subpart RR Reporting Threshold All facilities that meet the subpart RR source category definition must report. Once a facility is subject to the requirements of this subpart, including facilities that opt
-in to subpart RR, the owner or operator must continue for each year thereafter to comply with all requirements of this subpart, including the requirement to submit annual GHG reports, until the owner or operator has made a request to discontinue reporting that demonstrates that the CO 2 plume has stabilized and EPA has issued a final decision on the request to discontinue reporting. 3.1.3 Subpart RR GHGs to Report Facilities covered by this source category must report the mass of CO2 received; the mass of CO2 injected; the mass of CO 2 produced; the mass of CO2 emitted from surface leakage ; the mass of fugitive and vented CO2 emissions from sources between the injection flow meter and between the injection wellhead or the production flow meter and the production wellhead; and the mass of CO2 sequestered in subsurface geologic formations
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-2 3.1.4 Subpart RR GHG Calculations and Monitoring Facilities covered by this source category must calculate the annual mass of CO 2 received. Starting from the date outlined in the EPA
-approved MRV plan, f acilities must also use a mass balance approach to calculate the mass of CO2 geologically sequestered. 3.1.5 Subpart RR Data Reporting In addition to the information summarized at “Subpart RR GHGs to Report” , facilities must report the source of the CO2 received and the cumulative amount of CO2 geologically sequestered since the facility first reported under subpart RR. Facilities must also report concentration, and mass or volumetric flow where flow meters are used or mass or volume where containers are used. Finally, they are required to report MRV information implemented in the reporting year and, for EPA verification purposes, the class of UIC permit and well identification number used for the UIC permit
. 3.1.6 Subpart RR Recordkeeping Facilities must retain quarterly records of CO2 received; injected CO 2 ; produced CO2 ; CO2 emitted by surface leakage; and any other records as outlined for retention in the facility MRV plan. 3.1.7 Subpart RR Geologic Sequestration Monitoring, Reporting, and Verification (MRV) Plans Facilities must develop an MRV plan, submit the MRV plan to EPA, receive an approved MRV plan from EPA, implement the EPA
-approved plan, and submit annual reports. 3.1.8 Administrative Appeals. Under this final rule, final decisions of the Administrator under part 98, subpart RR are appealable to EPA’s Environmental Appeals Board under the regulations that are set forth in part 78 (40 CFR part 78). Part 78 is revised to accommodate such appeals. 3.2 Subpart UU 3.2.1 Subpart UU Source Category Definition The subpart UU source category consists of any well or group of wells that inject a CO2 stream into the subsurface . This includes any wells used to enhance oil and gas recovery and GS R&D projects which are exempted from subpart RR monitoring and reporting requirements. If you report under subpart RR for a well or group of wells, you are not required to report under subpart UU for that well or group of wells.OMB DRAFT: Please do not cite, quote, or distribute

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-3 3.2.2 Subpart UU Reporting Threshold All f acilities that inject CO 2 underground must report under this subpart, regardless of the amount of emissions from the facility or the amount of CO 2 injected. 3.2.3 Subpart UU GHGs to Report Facilities covered by this source category must report the annual mass of CO2 received. 3.2.4 Subpart UU GHG Calculations and Monitoring Facilities covered by this source category must calculate the annual mass of CO 2 received
. 3.2.5 Subpart UU Data Reporting In addition to reporting the mass of CO2 received, facilities must report the source of the CO2 . Facilities must also report concentration and mass or volumetric flow or mass or volume where containers are used
. 3.2.6 Subpart UU Recordkeeping Facilities must retain quarterly records of any CO2 received
. 3.3 Summary of Major Changes Since Proposal The major changes in this rule since the original proposal are identified in the following list. The rationale for these and any other significant changes to the rule can be found below or in “Mandatory Greenhouse Gas Reporting Rule: EPA's Response to Public Comments , Subparts RR and UU: Injection and Geologic Sequestration of Carbon Dioxide.”

 EPA has moved all definitions, requirements, and procedures for facilities conducting CO 2 injection only (which both EPA and commenters have referred to as “Tier 1” facilities for simplicity) into a new subpart, subpart UU, and retained all definitions, requirements, and procedures related to facilities conducting GS (which both EPA and commenters have referred to as “Tier 2” facilities for simplicity) in subpart RR.

 EPA has removed the requirement that facilities report the amount of CO2 injected in subpart UU (Tier 1) reporting requirements but retained requirements that facilities subject to this subpart report the amount of CO2 received and the source of CO2 .

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

 In subpart RR, EPA has established a waiver process for a GS R&D project to request an exemption from subpart RR monitoring and reporting requirements.OMB DRAFT: Please do not cite, quote, or distribute

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-4  In subpart RR, EPA has retained the requirement that facilities report the fugitive and vented emissions reporting requirement for surface equipment that could be included in the GS mass balance but removed the requirement for reporting fugitive and vented emissions for all other surface equipment.

 In subpart RR, EPA has added an MRV plan requirement for the delineation of the areas that will be monitored
.

 In subpart RR, EPA has clarified the requirements for an addendum to the annual report and renamed it monitoring report
.

 EPA has amended 40 CFR part 78 to include administrative appeals procedures for EPA decisions made under subpart RR, such as decisions relating to the request for R&D exemption under §98.440(d)(4) , decisions relating to a request for discontinuation of reporting under §98.441(b)(2) , or MRV plan decisions under §98.448(c)
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- 1 SECTION 4 ENGINEERING COST ANALYSIS 4.1 Introduction Using available industry and EPA data to characterize conditions at affected sources , EPA estimated the costs of complying with final rule . Incremental monitoring, recordkeeping, and repor ting activities were then identified for each type of facility, and the associated costs were estimated. 4.2 Overview of Cost Analysis The costs of complying with the rule will vary from one facility to another, depending on the nature of the CO2 injection activities (GS or non
-GS), the MRV plan selected, existing monitoring, recordkeeping, and reporting activities at the facility, etc. The costs include labor costs for performing the monitoring, recordkeeping, and reporting activities necessary to comply with the rule, as well as capital costs related to the implementation of monitoring activities outlined in the MRV plan for GS sites . All costs referred to in this section are reported in 2008 dollars. We first provide a general overview of baseline reporting and GS activities. This is followed by detail on the cost components associated with this information collection; labor costs (i.e., the cost of labor by facility staff to meet the information collection requirements of the rule); and capital and operating and maintenance costs (e.g., the cost of purchasing and installing monitoring equipment or contractor costs associated with providing the required information). 4.3 Baseline Reporting 4.3.1 Introduction The Environmental Protection Agency developed regulatory alternatives for reporting of CO2 injection and GS
. These rules can affect the number and type of monitoring equipment installed at the sites and the type and frequency of tests and surveys conducted at the sites. In creating new EPA regulations, a unit cost analysis and the total cost impact of each of the final regulations is required by federal law. This provides a basis for a full evaluation of the incremental costs of the final rule. The purpose of this section is to present the “activity baseline,” which describes the number and types of injection and GS sites that could be subject to the rule and the volume of CO2 injections that would be expected.OMB DRAFT: Please do not cite, quote, or distribute

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-2 Through the practice of geological sequestration, CO 2 can potentially be sequestered in underground formations worldwide for thousands of years. Although commercial geologic sequestration of CO2 has not yet begun in the U.S., several projects such as Sleipner in the North Sea, In Salah in Algeria, and Weyburn in Alberta have achieved success in recent years. CO2 at these sites is being sequestered, and technologies to monitor the process have proved effective. In the U.S., the Department of Energy is supporting approximately 25 sequestration pilot projects around the country. DOE also has plans to start a number of relatively large scale pilot projects within coming years. Geologic sequestration in the U.S. will likely occur in a range of different geologic settings including: saline reservoirs, oil and gas reservoirs, coal seams, and others. For purposes of this economic analysis, the costs of specific aspects of geologic sequestration were specified on the basis of cost per well, per square mile, per sample, or other basis for each project. In addition, “type cases” were developed for each reservoir type including, in some instances, two sizes of injection projects for pilot and commercial
- size project scales. These include the typical parameters (e.g. number of monitoring wells and average well depth) for each type of project, allowing for estimation of total cost per project. In the cost analysis that appears in Chapter 5, a base case is created assuming relevant monitoring costs are only that which is required under the UIC rules. Then three regulatory alternatives for reporting from geologic sequestration sites are evaluated in terms of technologies and practices and their costs. 4.3.2 Data Sources In order to evaluate the total costs in the U.S. of the final regulations, it is necessary to establish an activity baseline forecast of the sequestration activity to which the final regulation applies. The appropriate forecast for this analysis is the level of GS activity that would be expected even in the absence of future climate change legislation. While climate change legislation is currently being debated in Congress, no legislation has been enacted. Even in the absence of national climate legislation, sequestration activity in the U.S. is planned including:

 Research and Development (R&D) projects,

 FutureGen Sequestration Site , and

 Commercial Sequestration Projects Related to State and Regional Incentive Programs (in part, funded by DOE)OMB DRAFT: Please do not cite, quote, or distribute

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-3 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 in Morgantown, West Virginia. The program has two major components: Core R&D and Demonstration and Deployment. According to DOE, the goal is to “develop by 2012 systems that will achieve 90% capture of CO2 at less than a 10 percent increase in the cost of energy services and retain 99 percent sequestration permanence. ” 2 The field component of the sequestration research is being carried out by seven regional partnerships. These partnerships were formed in 2003 and represent consortia of private industry and government agencies. This effort is tasked with determining the most suitable technologies, regulations, and infrastructure needs for capture and sequestration. There are three phases to the work being carried out by the partnerships:

 Characterization (2003
-2005)

 Validation (2005
-2009)

 Deployment (2009
-2017) The Characterization Phase involved the geologic analysis that resulted in the development of a National Carbon Sequestration Database and Geographic Information System (NATCARB). The Validation Phase is currently active and involves such activities as validation of reservoir simulation methods, data collection for capacity and injectivity, and demonstration of monitoring technologies. Also being researched are well completion methods, operations, and abandonment approaches. The Deployment Stage involves the construction and operation of 8 significant sequestration projects. These projects are consistent with the Energy Independence and Security Act of 2007 (EISA), under Title VII, Sec. 702, which requires DOE to conduct at least 7 large scale sequestration field tests greater than one million tons of CO 2 each. These tests are designed
2 Direct Carbon Sequestration: Capturing and Storing Carbon Dioxide, Congressional Research Service, report RL33801, September, 2007.OMB DRAFT: Please do not cite, quote, or distribute

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-4 to fully evaluate the potential for commercial scale operations in a range of geological settings. The tests are planned to have an injection period of up to four, followed by a lengthy monitoring period. This phase is designed to evaluate the practical aspects of large scale injection over a prolonged period of time. A great deal of progress has been made in the areas of site characterization and monitoring. The next major phase of the DOE research effort is to provide funding support for a number of commercial scale sequestration operations with injections of up to one million tons per year. Sequestration Related to State and Regional Incentive Programs A number of states or regions have adopted or plan to adopt regulations to address carbon dioxide and/or greenhouse gas emissions. Most allow for regulated sources of emissions to meet compliance requirements through the use of offsets. Although geologic sequestration goals or criteria may not be specified in each case, the potential exists for sequestration activities to become an accepted and more prevalent way of meeting greenhouse gas reductions. The programs or state legislation initiatives are generally in the early stages, and there is considerable uncertainty in terms of which projects will proceed, and on what schedule. ICF has researched the CSLF (Carbon Sequestration Leadership Forum) online database and the MIT online database in our analysis of non
-DOE projects. It should be noted, that in these databases, there are several projects for which startup date and/ or planned injection volumes are not specified. Laboratory Research Over the past several years, DOE and the regional partnerships have carried out an effort to assess and characterize the CO 2 sequestration capacity and potential of the U.S. This effort has resulted in the publication of a large amount of information on potential by geologic setting and basin or state. A large amount of GIS data has also been compiled on the geology of sequestration potential. In 2008, DOE published the most recent version of the NATCARB (National Carbon) Atlas. 3 This publication contains maps and data tables documenting their assessment of

3 Carbon Sequestration Atlas of the United States and Canada, 2008, U.S. Department of Energy, National Energy Technology Laboratory, Morgantown, WV.OMB DRAFT: Please do not cite, quote, or distribute

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- 5 sequestration potential in the U.S. Much of the data behind the NATCARB atlas are either available in GIS form or will eventually be made available. 4.3.4 Hydrogeologic Settings Geologic sequestration may take place in a number of settings and lithologies. These include:

 Non
-basalt saline reservoirs

 Depleted gas fields

 Depleted and abandoned oil fields

 Enhanced oil recovery (ER)

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

4.3.4.1 Non
-Basalt Saline Reservoirs Most significant sedimentary basins in the U.S. contain regionally significant saline formations that are potential sequestration reservoirs. These are typically sandstone lithologies with good porosity, containing formation waters of greater than 10,000 mg/L total dissolved solids. Salinity may be as high as several times that of seawater. Thus, the water is unsuitable for drinking or agriculture. Saline reservoirs dominate the assessed potential of the U.S. and worldwide. In addition, because of their wide geographic distribution in the U.S., saline reservoirs are often in close proximity to CO 2 sources, minimizing pipeline transport distance. Saline reservoirs represent the vast majority of U.S. sequestration potential (approximately 89 percent of total U.S. capacity). 4 It is very likely that saline reservoirs will play a prominent role in future geologic sequestration. Sequestration in saline reservoirs has been shown to be effective. The Sleipner field in the North Sea is the first commercial
- scale saline reservoir project. Carbon dioxide is separated from the gas stream and re
-injected into a reservoir at about 800 meters depth. The rate of

4 2007 ICF assessment developed using DOE Atlas volumes and supplementing in several categories.OMB DRAFT: Please do not cite, quote, or distribute

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-6 injection is 2,700 tons per day or about one million tons per year. 5 It is anticipated that about 20 million tons will eventually be stored. At Sleipner, the plume has been monitored effectively. 6 DOE has extensively studied saline reservoirs for sequestration. Projects include the Frio Brine pilot in the Texas Gulf Coast and the Mount Simon Sandstone in the Illinois Basin. 7 The Mount Simon is known to have excellent sequestration potential because of its regional thickness and reservoir characteristics, and because it has been used extensively for natural gas sequestration in the Midwest.

4.3.4.2 Depleted Gas Fields and Oil Fields Depleted gas and oil fields can be excellent candidates for CO 2 sequestration. These represent known structures that have trapped hydrocarbons over geologic time, thus proving the presence of an effective structure and seal above the reservoir. These fields have also been extensively studied, there is a large amount of well log and other data available, and the field infrastructure is already in place. This infrastructure could in some cases be utilized in sequestration. A potentially problematic aspect of using depleted fields for sequestration is the presence of a large number of existing wellbores, which can provide leakage pathways. Typically, oil fields are developed with a closer spacing than gas fields, resulting in a larger number of existing wells per unit area than in gas fields. The In Salah Field in Algeria was the world’s first project in which CO2 is injected at commercial scale into a gas reservoir. However, in this case, the gas is injected downdip in an actively producing gas reservoir. This differs from an abandoned gas reservoir scenario in which the gas field is no longer producing.

4.3.4.3 Enhanced Recovery of Oil and Gas Under certain reservoir and fluid conditions, CO2 can be injected into an oil reservoir in a process called miscible CO 2 enhanced oil recovery. The effect of the CO2 is to mobilize the oil

5 IPCC, 2005: IPCC Special Report on Carbon Dioxide Capture and Storage , by Working Group III of the Intergovernmental Panel on Climate Change [B. Metz , O. Davidson, H. C. de Coninck, M. Loos, and L. A. Meyer (eds.)], Cambridge University Press, Cambridge, United Kingdom and New York, NY, USA, 442 pp. 6 IPCC, 2005: IPCC Special Report on Carbon Dioxide Capture and Storage , by Working Group III of the Intergovernmental Panel on Climate Change [B. Metz, O. Davidson, H. C. de Coninck, M. Loos, and L. A. Meyer (eds.)], Cambridge University Press, Cambridge, United Kingdom and New York, NY, USA, 442 pp. 7 Carbon Capture and Storage: A Regulatory Framework for States

– Summary of Recommendations,, by Kevin Bliss, Interstate Oil and Gas Compact Commission, January, 2005.OMB DRAFT: Please do not cite, quote, or distribute

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-7 so that it can move more readily to the production wells. As the oil is produced, part of the injected CO2 is produced with the oil. This CO2 is then separated and re
-injected. In the U.S. most CO2 ER projects are located in the Permian Basin of West Texas, where projects have been in place for several decades. The source of most of the CO2 is natural CO2 from several fields in Colorado and New Mexico. 8 Some of the injected CO2 is from gas processing or other sources. The current volume of CO2 injected for CO2 ER is about 2.2 billion cubic feet per day. In 2005, CO2 ER operations produced approximately 237,000 barrels of oil per day in the U.S. About 180,000 barrels per day of that occurred in West Texas, with most of the rest produced in the Rockies, Mid
-Continent, and Gulf Coast. 9 The development of CO2 ER projects has resulted in a great deal of knowledge about the process and injection well and other technologies have matured and are well understood. In addition, it is estimated that more than 3,500 miles of high pressure (>1,300 psi) CO 2 pipelines have been built to accommodate these operations. 10 At the Weyburn Field in Saskatchewan, CO 2 from the Dakota Gasification Facility in North Dakota is injected into an oil reservoir for ER and monitoring of CO2 sequestration. Over the 25 year life of this project, it is expected that about 18 million tons of CO 2 will be sequestered. 4.3.4.4 Enhanced Coalbed Methane Recovery CO2 can potentially be sequestered in coalbeds through the process of adsorption. CO2 injected as a gas into a coal bed will adsorb onto the molecular structure and be sequestered. Methane is naturally adsorbed onto coalbeds and coalbed methane now represents a significant percentage of U.S. natural gas production. Major coalbed methane production areas include the San Juan Basin of northwestern New Mexico and southwestern Colorado, the Powder River Basin of eastern Wyoming, and the Warrior Basin in Alabama.

8 The Economics of CO2 Storage, Gemma Heddle, Howard Herzog, and Michael Klett, Laboratory for Energy and the Environment, Massachusetts Institute of Technology, August, 2003. 9 Oil and Gas Journal, April 17, 2006. 10 Carbon Capture and Storage: A Regulatory Framework for States

– Summary of Recommendations,, by Kevin Bliss, Interstate Oil and Gas Compact Commission, January, 2005.OMB DRAFT: Please do not cite, quote, or distribute

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- 8 The concept of enhanced coalbed methane recovery is based upon the fact that coalbeds have a greater affinity for CO2 than methane. Thus, when CO2 is injected into the seam, methane is liberated and the CO2 is retained. This additional methane represents enhanced gas recovery. Depending upon depth and other factors, coalbeds may be mineable or unmineable. Because the process of mining the coal would release any stored CO 2 , only unmineable coals are assessed as representing permanent CO2 sequestration. 11

4.3.4.5 Other H

ydrogeologic Settings Basalt flows such as those of the Columbia River Basalts in the Pacific West, are believed to have the potential for permanent CO2 sequestration. The sequestration process is geochemical trapping, in which the CO 2 reacts with silicates in the basalt to form carbonate minerals. 12 While research is being carried out on basalt, it is considered unlikely that any commercial scale sequestration will occur in the foreseeable future due to the unconventional geology and likely difficulty in monitoring. The potential to sequester CO 2 in organic shale formations is based upon the same concept as that of coal beds. CO2 will adsorb onto the organic material, displacing methane. Gas shales have recently emerged as a major current and future source of gas production in the U.S. These include the Barnett Shale in the Fort Worth Basin, the Fayetteville and Woodford Shales in the Arkoma Basin, and the Appalachian Devonian Shale. These Devonian and Mississippian age organic shale formations represent tremendously large volumes of rock. To date little research has been done on enhanced gas recovery with organic shales. However, should it prove technically feasible, the U.S. could become one of the major areas worldwide for this type of sequestration. 4.3.5 Formation Capacity 4.3.5.1 Current DOE Assessment of Sequestration Potential Through the regional sequestration partnerships, DOE has developed a new national assessment of sequestration potential. The current assessment is summarized in Table 4
-3 , in the column titled “2008 NATCARB.” As evaluated by ICF, the DOE Lower
-48 total is 8,179

11 Carbon Capture and Storage: A Regulatory Framework for States

– Summary of Recommendations,, by Kevin Bliss, Interstate Oil and Gas Compact Commission, January, 2005. 12 IPCC, 2005: IPCC Special Report on Carbon Dioxide Capture and Storage , by Working Group III of the Intergovernmental Panel on Climate Change [B. Metz, O. Davidson, H. C. de Coninck, M. Loos, and L. A. Meyer (eds.)], Cambridge University Press , Cambridge, United Kingdom and New York, NY, USA, 442 pp.OMB DRAFT: Please do not cite, quote, or distribute

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-9 gigatonnes (Gt) of CO2 . The range of uncertainty is 3,508 to 12,850 Gt. Most of the assessment is attributed to saline reservoirs). This assessment is much larger than the prior assessments also shown on the table.

4.3.5.2 ICF Assessment of Sequestration Potential ICF has also developed a sequestration potential assessment by reservoir type. The results of this assessment are summarized in Table 4
- 1
. The Lower
-48 assessed total is 3,375 Gt. The assessment includes estimates from DOE, and estimates for resources not covered by DOE. We have included a rough assessment of the Gulf of Mexico, as well as an estimate of shale gas sequestration potential. The ICF assessment can be broken out by state or region, and geologic category. Table 4
-2 presents the ICF Lower
-48 assessment by region. Sequestration capacity associated with depleted oil and gas fields occurs where there has been significant production, including Appalachia, the Gulf Coast, Mid
-Continent, and Rockies. Saline reservoir potential occurs in many areas of the country. Coalbed methane potential is concentrated in the large coalbed methane production areas such as New Mexico and Wyoming, while shale gas potential is associated with some of the new shale gas basins that have emerged over the past decade.OMB DRAFT: Please do not cite, quote, or distribute

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- 10 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 OffshoreOMB DRAFT: Please do not cite, quote, or distribute

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- 11 Table 4-2 . Summary of ICF Sequestration Capacity Assessment Gigatonnes of CO2 Storage Depleted Depleted Region (Markal Region Name) EOR Oil Fields Gas Fields Coals Shale Saline Basalt Total California (California) 1.2 8.0 1.8 0.0 0.0 161.1 0.0 172.2 Eastern Gulf Coast (East South Central) 0.2 1.1 1.3 1.9 28.0 103.2 0.0 135.6 Gulf of Mexico 1.5 5.5 8.4 0.0 0.0 800.0 0.0 815.3 Midwest (East North Central) 0.3 1.3 0.2 3.3 12.7 167.1 0.0 184.9 Northern Midcontinent (West North Central) 0.7 5.9 2.1 0.2 0.0 57.8 0.0 66.7 Northern Rockies (Mountain 1) 0.7 4.6 2.5 17.7 0.0 665.6 33.3 724.4 New England (New England) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Northeast (Middle Atlantic) 0.0 0.3 0.6 0.1 12.0 9.0 0.0 22.0 Pacific NW (Pacific; Lower 48 Onshore Part) 0.0 0.0 0.0 2.3 0.0 53.0 66.6 121.9 Pacific Offshore (Pacific; L48 Offshore) 0.0 1.2 0.0 0.0 0.0 100.0 0.0 101.3 Southern Rockies (Mountain 2) 1.4 3.3 6.0 19.6 0.0 36.5 0.0 66.8 Southeast (South Atlantic) 0.1 0.2 0.7 0.9 19.0 378.0 0.0 398.9 Texas and S. Midcontinent (West S. Central) 10.4 28.0 26.1 5.7 35.0 459.5 0.0 564.6 Total 16.5 59.5 49.7 51.6 106.7 2,990.6 99.9 3,374.6 Offshore (Gulf, Atlantic, Pacific) 1.5 6.7 8.4 0.0 0.0 1,186.6 0.0 1,203.3 Onshore 15.1 52.8 41.2 51.6 106.7 1,804.0 99.9 2,171.3
4.3.6 Geologic Sequestration Rule Activity Baseline Based upon the above information on what is anticipated for R&D projects, FutureGen, and state programs, an activity baseline forecast of sequestration activity has been developed. Because of the uncertainty in which existing ER project might come under subpart RR, three scenarios have been created and are shown as Table 4
- 5 to 4
-7. The first scenario assumes that no existing CO2 ER projects choose to report as facilities conducting GS. The second scenario assumes that all CO 2 ER projects from anthropogenic sources (7 million metric tons per year coming primarily from natural gas processing plants) choose to report as facilities conducting GS. The third scenario assumes that all projects from anthropogenic CO 2 sources plus one
-half of the remaining CO2 flood projects choose to report as facilities conducting GS. This third scenario adds up to 23.4 million metric tons per year injected of new (i.e., ignoring recycled volumes) CO2 . The most comprehensive source of information on US ER projects is the annual survey conducted by the Oil and Gas Journal. The 105 projects listed in the Oil and Gas Journal 2007 ER survey were grouped by CO2 source type

– natural or anthropogenic. CO2 use was allocated to the projects supplied by each source based on oil production. Anthropogenic sources wereOMB DRAFT: Please do not cite, quote, or distribute

4
- 12 well defined for ER projects in Michigan (Antrim Gas Processing Plant), Wyoming/Colorado (LaBarge/Shute Creek Gas Processing Plant), central Oklahoma (Enid Fertilizer Plant) and Kansas (US Energy Partners, Russell Kansas Ethanol Plant) from geographic proximity and information in published literature. Natural 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 CO2 from the Val Verde Gas Plant in Texas is mixed with CO 2 from natural sources and distributed to several fields in the Permian Basin so there was not a clear delineation of which projects were served by anthropogenic gas from the Val Verde plant. To estimate the number of facilities served by Val Verde, the total CO2 use in the Permian Basin from natural sources and Val Verde production was summed and the percent of Val Verde production was prorated among the 66 projects in the Permian Basin. Val Verde CO 2 production represents 5.4 % of the total CO2 used in the Permian Basin, therefore, the equivalent of approximately 4 projects in the Permian Basin are estimated to use anthropogenic CO2 from Val Verde. For this analysis 2007 CO2 production data for natural and anthropogenic sources was taken from the (1990
-2007) Inventory of U.S. Greenhouse Gas Emissions and Sinks, and totaled 2.1 bcf/day which differs from the published DOE estimate of 2 .6 bcf/day used in the threshold analysis. Based on the number of projects active in 2007, anthropogenic sources provide approximately 18% of the mass of CO2 used in ER projects in the US, and represent approximately 27 % of the CO2 ER projects. These projects result in the additional production of more than 13 million barrels of oil annually. If only ER projects supplied by anthropogenic sources opted into the reporting program approximately 28 projects would be included. If all the ER projects supplied by anthropogenic sources, and half of the projects using natural sources opted into the reporting program approximately 67 projects would report, representing 1.2 bcf/day (23.4 million metric tons per year) or 59% of all CO2 ER use.OMB DRAFT: Please do not cite, quote, or distribute

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

Label Number

of Projects Operating in 2012 Metric

Tons CO 2 Received per Year Project

Count Monitoring

Wells/ Project Monitoring

Well Depth Ft Footage all

monitoring wells Square

Miles/ Project Producing

Oil or Gas Wells/ Project Project Life

(for annualization) Metric

Tons CO 2 Received per Year / Project Known DOE EOR Pilot Projects 2 1,100,000 1 7 5,700 39,900 8.8 56 10 550,000 Known DOE Saline Pilot

Projects 5 2,720,000 1 2 8,000 16,000 1.7 0 4 750,557 Future DOE Saline Pilot

Projects 2 1,500,000 1 2 8,000 16,000 1.7 0 4 750,557 Known Commercial EOR

Projects 3 3,300,000 1 6 5,700 34,200 8.0 48 10 500,000 Known Commercial Saline

Projects 1 0 1 9 8,000 72,000 11.6 0 40 1,842,885 Conversion of Existing EOR

Projects to GS 0 0 1 6 5,700 34,200 8.0 48 10 500,000OMB DRAFT: Please do not cite, quote, or distribute

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

Label Number of

Projects Operating in 2012 Metric

Tons CO 2 Receive d per Year Project

Count Monitorin

g Wells/ Project Monitori

ng Well Depth Ft Footage

all monitori ng wells Square

Miles/ Project Producin

g Oil or Gas Wells/ Project Project

Life (for annualiza tion) Metric

Tons CO 2 Receive d per Year / Project Known DOE EOR Pilot Projects 2 1,100,000 1 7 5,700 39,900 8.8 56 10 550,000 Known DOE Saline Pilot Projects 5 2,720,000 1 2 8,000 16,000 1.7 0 4 750,557 Future DOE Saline Pilot Projects 2 1,500,000 1 2 8,000 16,000 1.7 0 4 750,557 Known Commercial EOR Projects 3 3,300,000 1 6 5,700 34,200 8.0 48 10 500,000 Known Commercial Saline Projects 1 0 1 9 8,000 72,000 11.6 0 40 1,842,885 Conversion of Existing EOR Projects to GS 16 6,972,040 1 6 5,700 34,200 8.0 48 10 500,000OMB DRAFT: Please do not cite, quote, or distribute

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

Label Number

of Projects Operating in 2012 Metric

Tons CO 2 Received per Year Project

Count Monitoring

Wells/ Project Monitoring

Well Depth Ft Footage all

monitoring wells Square

Miles/ Project Producing

Oil or Gas Wells/ Project Project Life

(for annualization) Metric

Tons CO 2 Received per Year / Project Known DOE EOR Pilot Projects 2 1,100,000 1 7 5,700 39,900 8.8 56 10 550,000 Known DOE Saline Pilot

Projects 5 2,720,000 1 2 8,000 16,000 1.7 0 4 750,557 Future DOE Saline Pilot

Projects 2 1,500,000 1 2 8,000 16,000 1.7 0 4 750,557 Known Commercial EOR

Projects 3 3,300,000 1 6 5,700 34,200 8.0 48 10 500,000 Known Commercial Saline

Projects 1 0 1 9 8,000 72,000 11.6 0 40 1,842,885 Conversion of Existing EOR

Projects to GS 48 23,543,741 1 6 5,700 34,200 8.0 48 10 500,000OMB DRAFT: Please do not cite, quote, or distribute

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- 16 4.3.6.1 Sources of Uncertainty The activity baseline forecast of sequestration activity represents our best estimate of what will likely occur in the absence of national climate change legislation. As with any forecast, there are sources of uncertainty. Categories of uncertainty include:

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

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

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

 Average injection rates

 Number of ER projects that will be covered Of the three categories of project, the least uncertainty is associated with the R&D projects. These projects have been funded and are expected to proceed at close to the announced schedule. The DOE FutureGen project site has been chosen (Illinois) but there is still uncertainty about timing and injection volumes. Given the number of state and regional initiatives underway it is very likely that projects related to state incentives will be initiated. As discussed previously, there are a number of pro jects for which either timing or injection volumes were not provided and were estimated by ICF. The largest uncertainty over the timeframe of the activity baseline is what may occur at the national level in terms of climate change legislation. However, any costs associated with potential future national climate policy cannot be attributed to this subpart currently under consideration. The activity baseline presented in this document is expressly for the purpose of evaluating the costs of the subpart RR proposal under existing climate change policies. 4.4 Reporting Costs 4.4.1 Introduction The purpose of this section is to present the unit cost estimates for the equipment and services that might be required to comply with the CO 2 Injection and GS Reporting rule and the total incremental annual cost of compliance. A base case is created assuming relevant monitoring costs are only that which is required under the UIC rules. Then three regulatory alternatives forOMB DRAFT: Please do not cite, quote, or distribute

4
- 17 reporting from geologic sequestration sites are evaluated in terms required technologies and practices and their costs. 4.4.2 Cost Assumptions and Methodology The costs reported here include capital and operating and maintenance (O&M) including labor costs. They are based on hypothetical or pro
-forma sites for various types of projects such as saline formation R&D GS projects, saline formation commercial GS projects, and ER GS projects. The geologic and engineering assumption for these pro
-forma projects are the same as used by the EPA Office of Water in the final rule, Federal Requirements under the Underground Injection Control Program for Carbon Dioxide Geologic Sequestration Wells, or the UIC Class VI final rule for CO2 injection wells 13 . The costs represent price levels in mid 2009, are presented in 200 8 dollars. There were very steep increases in the costs of equipment, materials and labor used in the construction of all types of energy infrastructure including power plants, pipelines and oil and gas wells from 2004 through 2008
. With the drop of oil and natural gas prices in the Fall of 2008 and the general economic decline around the world the costs of equipment, materials and labor have moderated somewhat.

4.4.2.1 Primary Data Sources for Costs Table 4
- 8 summarizes the major data sources for costs used by EPA in the analysis geologic sequestration costs . A wide range of cost data is available from industry survey publications for costs typically incurred in oil and gas drilling and production operations. This includes drilling and completion costs by region and depth interval, equipment and operating costs, and pipeline costs. Data are available for both the U.S. and Canada. 14 15 16 17The cost of drilling and equipping wells represents a large component of sequestration costs. The costs of additional equipment or material specifications for CO 2 injection wells are based in part upon various sources for corrosion resistant materials and specific well components. Cost estimates for seismic data acquisition are also available from industry publications and presentations.

13 The UIC rulemaking that would create a Class VI well class for injection of CO 2 for the purposes of GS was proposed July 25, 2008. (73 FR 43492) 14 Joint Association Survey of Drilling Costs , American Petroleum Institute, Washington, DC. http://www.api.org/statistics/accessapi/api
-reports.cfm 15 PSAC Well Cost Study

– 2008, Petroleum Services Association of Canada, October 30, 2007. 16 Oil and Gas Lease Equipment and Operating Costs , U.S. Energy Information Administration, 2006, http://www.eia.doe.gov/pub/oil_gas/natural_gas/data_publications/cost_indices_equipment_production/current/costs tudy.html 17 Oil and Gas Journal Pipeline Cost Survey, Oil and Gas Journal Magazine, September 3, 2007.OMB DRAFT: Please do not cite, quote, or distribute

4
- 18 Labor rates are obtained from the U.S. Bureau of Labor Statistics and from surveys of oil and gas professional performed by the American Association of Petroleum Geologists (AAPG) and the Society of Petroleum Engineers (SPE) . The number of hours required to carry out the various characterization or monitoring activities are estimates that have been reviewed by the EPA workgroup. No comprehensive source has been identified that provides detailed summaries of the full range of sequestration project cost components. Estimates of the costs of monitoring equipment, the number of stations required, and the cost of ongoing monitoring are based upon analysis of available literature and recent presentations by government and academic research groups and quotations from vendors . Some specific monitoring costs were obtained at a recent industry meeting sponsored by the Groundwater Protection Council
. 18

Table 4-6. Major Sources of Geologic Sequestration Cost Inf ormation

18 Ground Water Protection Council Meeting, New Orleans, LA, January, 16, 2008. Source Cost Categories API Joint Association Survey of Drilling Costs Drilling costs in the U.S. for oil, gas, and dry holes by depth interval EIA Oil and Gas Lease Equipment and Operating Cost Survey Surface equipment costs, annual operating costs, pump costs Pipeline Prime Mover and Compressor Costs (FERC) Pumps 2008 Petroleum Services of Canada Well Cost Study (PSAC) Drilling costs, plugging costs, logging costs Oil and Gas Journal Report on Pipeline and Cost Data Reported to FERC Pipeline costs per inch - mile Land Rig Newsletter Onshore rig day rates/ well cost algorithms
FutureGen Sequestration Site Submittals Monitoring station layout/number of stations Preston Pipe Report Casing and tubing costs Hourly Labor Rates U.S. Bureau of Labor Statistics Selected Presentations and Papers (see below) Sensor costs, monitoring costs, number of stations, seismic costs Significant Papers and Presentations With Cost Data Benson, "Monitoring Protocols and Life Cycle Costs for Geologic Storage of Carbon Dioxide", Sept., 2004 IEA Greenhouse Gas Programme Report PH4/29, "Overview of Monitoring Requirements for Geologic Storage Projects, Nov., 2004. Hoversten, "Investigation of Novel Geophysical Techniques for Monitoring CO2 Movement During Sequestration," Oct., 2003. Dahowski, et al, " The Costs of Applying Carbon Dioxide Capture and Geologic Storage Technologies to Two Hypothetical Coal to Liquids Production Configurations: A Preliminary Estimation," Pacific NW National Laboratory, September, 2007.OMB DRAFT: Please do not cite, quote, or distribute

4
- 19 The assumed capital costs and the annual operating cost of the various monitoring technologies whose application might be affected by the rule are shown in Table 4
-7 and 4
- 8. The capital costs are annualized using a capital recovery factor of 0.295, 0.142, and 0.075 for projects lasting 4, 10, and 40 years, respectively. The annual O&M costs are added to the annualized capital costs to determine total annual direct costs. To this is added a 20 percent overhead and general and administrative cost factor to obtain total annual costs. These are then divided by the amount assumed to be received each year in the pro
-forma project to arrive at total costs per metric ton of CO 2 received. These per
-ton costs are then used to estimate total annual costs for the level of injection expected in the activity b aseline. 4.4.3 Monitoring, Reporting, and Verification (MRV) Plan Requirements and Approval Process There are two types of sites that will report under this rule, facilities that conduct GS (subpart RR) and all other facilities conducting CO 2 injection (subpart UU). All sites will incur costs associated with reporting the annual mass of CO 2 received, however only facilities conducting GS will incur the monitoring plan related costs. Under this rule facilities conducting GS must develop an MRV plan, submit it to EPA for approval, and implement it once approved by EPA to report the amount of CO2 that has been sequestered. EPA is proposing that each submitted MRV plan must contain the following components. 1. Delineation of the maximum monitoring area and the period
- specific monitoring areas. 2. Identification of potential surface leakage pathways for CO2 in the maximum monitoring area and the likelihood, magnitude, and timing, of surface leakage of CO2 through these pathways
. 3. A strategy for detecting and quantifying any surface leakage of CO2 . 4. A strategy for establishing the expected environmental baselines
. 5. A summary of the considerations you intend to use to calculate site
- specific variables for the mass balance equation.OMB DRAFT: Please do not cite, quote, or distribute

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

Item Capital Cost to Establish

Environmental Baseline Capital Cost for Construction and Equipment Operating Cost Deep Monitoring Wells (into or right above injection zone) $200 lab fee per sample plus $1,000 to collect. 4 samples per well is $4,800 per well. $20,700 + $5,200/well for design, $10,400 per well for surface disturbance, $165
-$207 per foot to build, $20,800 for equipment Annual O&M costs are $25,900 + $3.10/ft per well per year
CO 2 Flow Meters on Producing Oil and Gas Wells NA $10,400/ oil well Annual O&M costs are $520 per well per year CO 2 Flow & Gas Composition Meters on Producing Oil and Gas Wells NA $52,000/ oil well Annual O&M costs are $2,600 per well per year Periodic Sampling and Testing of Injected Fluid NA 12 hours @$107.23/hr = $1,286 for plan $200 lab fee per sample plus $270 to collect. Estimation of Fugitive Emission from Surface Facilities NA 40 hours @$107.23/hr = $4,289 for planning and initial inventory of

facilities 24 hours @$107.23/hr = $2,574 for annual calculations
Periodic Seismic Surveys Seismic survey baseline established as part of site characterization. No extra cost for monitoring. No construction costs, but planning and quality assurance costs would add $25,000 per project. $104,000 per square mile

Periodic Digital Color Infrared Orthoimagery (CIR) or Hyperspectral Imaging to detect changes to vegetation. Initial survey before injection

commences would establish

baseline. No construction costs, but planning

and quality assurance costs would add $10,000 per square mile. Airborne survey costs $250 per square mile would be $6,250. Plus mobilization costs of $5,000

per site.

Periodic mobile survey to detect surface leaks. May be good option where vegetation is sparse
. NA No construction costs, but planning and quality assurance costs would add $10,000 per square mile. Mobile survey costs $300 per hour. A square mile would take about 1 day and cost $2,400. P lus mobilization costs of $5,000

per site. Eddy covariance measurement from permanent towers to detect surface leaks. Establishing baseline is $35,000 per station. 40 hours @$107.23/hr = $4,289 for plan plus $70,000/monitoring site. $10,000 per station per year Soil zone monitoring (sampling gas from accumulation chambers) Initial survey before injection commences would establish

baseline. 40 hours @$107.23/hr = $4,289 for plan plus $6,000/monitoring site $200 lab fee per sample plus $100 to collect. Vadose zone monitoring wells to sample gas above water table. Initial survey before injection

commences would establish

baseline. 40 hours @$107.23/hr = $4,289 for plan plus $8,000/monitoring site $200 lab fee per sample plus $100 to collect. Monitoring wells for samples from shallow water. Initial survey before injection commences would establish

baseline. 40 hours @$107.23/hr = $4,289 for

plan plus $80,000/monitoring site $200 lab fee per sample plus $1,000 to collect.OMB DRAFT: Please do not cite, quote, or distribute

4
-21 Table 4-8. Unit Cost of Relevant Episodic Monitoring Technologies (That may be

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

Quantification Estimate of

Unit Cost for Leak Quantification Cost per

Episode Probability of

Application in Any Given Year per Project Additional

Annual Cost per Project for Leak Quantification Surface leak detected by air, soil or water table monitoring or subsurface leak detected by pressure anomaly etc. Material balance

by solving for leaked quantity given known injected amounts and observed pressure in injection zone. Leak volume

estimation process 160 hours @$110.62/hr. $17,698 1.0% $177

Surface leak detected by MIT survey or by air, soil or water table monitoring. Analysis of well

logs (e.g., noise logs, oxygen activation logs) to quantify leaks along wellbore Additional well log

@4.15/ft +$2,070. Leak volume estimation process 160 hours @$110.62/hr. $57,118 1.0% $571

Subsurface leak detected by pressure anomaly in containment zone. Analysis of pressure readings in several monitoring wells and reservoir simulation of leak. Leak volume

estimation process 320 hours @$110.62/hr. $35,397 1.0% $354

Surface leak detected by air, soil or water table monitoring. Detailed seismic survey plus reservoir simulation to estimate leak volume at subsurface to help calibrate leak volume into atmosphere $104,00 per

square mile per survey. Leak volume estimation process 160 hours @$110.62/hr. $121,698 1.0% $1,21 7

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

estimate leak volume. Alternative might be to use eddy covariance towers set up in leak area and compare flux from around towers set up in surrounding (nonleaking) areas. Approximately $70,000 per square mile. Leak volume estimation process 80 hours @$110.62/hr. $78,849 1.0% $788

Total per Year 5.0% $3,108 Note: Assumes survey for leak occurs over one square mile area in each episode. Project's area is 10 square milesOMB DRAFT: Please do not cite, quote, or distribute

4
-22 4.5 Monitoring Technologies Deep Monitoring Wells Deep monitoring wells are typically drilled to monitor the deepest permeable zone above the caprock. Downhole instrumentation can be used to monitor pressure, temperature, and conductivity/salinity. Alternatively, U
-tube devices can be used to retrieve pressurized samples for laboratory testing. Other types of monitoring from wells include micro
- seismic, cross
-well resistivity, and vertical seismic profiling. CO2 Flow Meters on Producing Oil and Gas Wells Meters, probably located after the wellhead separator, that continuously measure the pressure, temperature and flow rate of the gas from a well. The composition of the gas is analyzed periodically using a gas chromatograph to determine percent CO2 concentration. The mass of CO2 passing through the wellhead can then be calculated from the measured quantities. CO2 Flow and Gas Composition Meters on Producing Oil and Gas Wells Meters, probably located after the wellhead separator, that continuously measure the pressure, temperature, flow rate and chemical composition of the gas from a well. The mass of CO2 passing through the wellhead can then be calculated from the measured quantities. This differs from the item directly above in that the chemical compo sition of the gas is being measured automatically by the meter itself rather through periodically obtaining a sample and sending it to lab for analysis. Periodic Sampling and Testing of Injected Fluid All facilities conducting GS and all other facilities conducting CO 2 injection will incur periodic sampling and testing costs. To estimate the costs, we have applied similar assumptions that were used in Subpart OO for sampling and testing of industrial gases. For example, we have assumed that it takes 12 labor hours to contact an onsite laboratory or offsite vendor and develop a plan; to collect and send the sample to an onsite or offsite laboratory; and to provide data invoice if sent offsite. Furthermore, we have assumed that it costs approximately $500 per sample to collect and conduct the test of chemical composition. In addition to these costs, facilities conducting GS will additionally incur the costs described in this rule. Seismic SurveysOMB DRAFT: Please do not cite, quote, or distribute

4
-23 Seismic data acquisition involves the generation and detection of sound waves to evaluation conditions in the subsurface. Periodic acquisition of seismic data can be used to detect subsurface CO2 movement within and outside of the reservoir. Digital Color Infrared Ortho

-imagery and Hyper

-spectral Imaging Digital color ortho
-imagery and hyper
- spectral imaging are airborne remote sensing technologies that are used to detect changes in vegetation resulting from CO 2 leaks. Hyperspectral sensors look at objects using electromagnetic spectrum. The object is to detect a specific spectral signature that is known to result from CO 2 uptake. The advantage of these methods is that they can efficiently cover a large surface area. Airborne or Mobile Remote Sensing Survey CO2 detectors are commercially available for short closed
-path and short open
-path (point) measurements and long open
-path (radial line) measurements. Similar detectors have been integrated into stationary, mobile , and airborne monitoring packages that are commonly used in combination with high
-resolution global positioning system (GPS) to detect and quantify methane leaks in areas with road access. While these packages have not been widely tested for CO2 , various types of CO2 monitors are commercially available and could be used in these applications. Such monitoring techniques are likely the leading candidates for monitoring plan applications because of their low cost and high reliability. The technologies include infrared gas analyzers (IRGAs, including Fourier transform infrared (FTIR) and non
-dispersive infrared (NDIR) analyzers), tunable diode lasers (TDLs), cavity ring down techniques, and others. The sample path can range from 10 cm to 1 km, by reflecting a laser beam off retro
-reflecting mirrors. These devices measure the gas concentration, and, when packaged with measurements of wind speed and wind direction, they measure the total gas flow. LIDAR (Light Detection and Ranging) involves the transmission of light from an instrument to a target and the recording of the reflected light to determine some property of the target. Differential Absorption LIDAR (DIAL) uses two wavelengths of laser to measure CO 2 . The wavelengths used are specific to CO2 . One wavelength is selected to correspond to a CO2 spectral absorption line, while the other is a non
- absorbing wavelength. The difference in intensity of the two return signals is a measure of concentration. Eddy CovarianceOMB DRAFT: Please do not cite, quote, or distribute

4
-24 Eddy Covariance is a technique whereby high frequency measurements of atmospheric CO2 concentration at a height above the ground are made by an infra
-red gas analyzer along with measurements of micro
-meteorological variables such as wind velocity, direction, humidity, and temperature. Integration of these data allows derivation of the net CO2 flux over the upwind footprint, typically square meters to square kilometers in area. Soil Zone Monitoring with Accumulation Chamber (AC) Surface CO2 flux is measured using an accumulation chamber. The chamber is made of stainless steel with an open bottom and is placed at the sampling location. It may be placed either directly on the ground or on a collar installed in the ground surface. The air is circulated through the AC and measured with and infra
-red gas analyzer. Vad ose Zone Monitoring The vadose zone is the relatively shallow zone beneath the soil zone that is not saturated with groundwater. Small diameter probes are installed in the zone and samples are taken. The CO2 concentration of air samples taken in this zone can be measured by and infrared gas analyzer
. Monitoring Wells for Sampling of Shallow Water Shallow monitoring wells may be used to measure the properties of ground water. Such wells are typically no deeper than several hundred feet. Estimating Leak Volumes after a Leak is Detected The monitoring program for facilities conducting GS may detect subsurface leaks and it will be necessary to estimate the volume of leaks to the surface to comply with the reporting requirements of this rule. Each site operator will have to devise suitable techniques taking into account the geology of the sites, the location and nature of the potential leaks and the performance characteristics of available monitoring and measurement technologies. It is expected that these e stimates may include engineering estimates as well as some direct measurement and may have a wide margin of uncertainty. It is expected that site characterization and screening will lead to selection of sites that are suitable for long
-term sequestration and that incidences of leaks to the surface may be infrequent at well
- selected and well
-managed sites. The cost estimates presented here for subsurface leak quantification assumeOMB DRAFT: Please do not cite, quote, or distribute

4
-25 a two percent chance in one year that any given site will have to implement the leak quantification strategy described in the site’s MRV plan. There are no operating statistics for CO2 GS from which to draw any citable conclusions on how often leaks to the surface may be detected, therefore a very conservative estimate was used in order to estimate the potential cost. If the leak is detected in the subsurface (possibly by anomalous pressure readings in a monitoring well) the leak volume may be estimated to help calibrate a leak volume to the surface. Quantification is presumed to be done using engineering calculations supplemented, when technically feasible, by direct observation/measurement using, for example, a 3
-D seismic survey over the area of the suspected leak. The seismic survey might be able to detect the location, size and density of the CO2 plume formed by the leak in one or more containment zones located above the injection zone. The volume of the leak also might be estimated using a reservoir simulation model of the containment zone calibrated to the pressure readings of the monitoring wells surrounding the location of the leak. In other words, different volumes of leaks would be tested in the reservoir simulator to find which leak volume most closely matches the pressure history observed in the surrounding monitoring wells. Leaks may also be detected at or near the surface by air, soil gas and water table monitoring devices. It is possible that some of the monitoring devices, such as eddy covariance, could themselves be used to estimate leak volumes. Another possible way of estimating the volume of a leak at the surface is to place a tent over the area of the leak. The tent would be sealed at the ground by weights or spikes and a calibrated volume of gas such as nitrogen would be introduced into the tent and allowed to escape through a chimney at the top of the tent. By measuring the concentration of CO2 in the gases leaving the chimney it is possible to measure the amount of CO2 leaving the ground in the area of the tent. The tent would have to be moved to many locations and the process repeated to get a representative sample over the entire area of the leak. It also would be necessary to correct the readings for natural CO 2 fluxes into and out of the soil. Many of the leak detection methods for onshore GS sites can be applied to sub
- seabed sites. These include monitoring of the injection well and monitoring of the subsurface CO 2 plume: active seismic, passive seismic, sensors in deep monitoring wells, and reservoir modeling. Though there will be differences in monitoring approaches at sub
- seabed GS sites for leak detection and quantification, the cost estimates are assumed to be comparable. Labor RatesOMB DRAFT: Please do not cite, quote, or distribute

4
-26 The cost of labor for many of the cost items in Table 4
-9 and 4
- 10 and for General and Administrative Costs are based on Society of Petroleum Engineers ( SPE) 2008 annual salary survey. 19 The average salary for a petroleum reservoir engineer with 15 years of experience is $143,800 . Applying a 1.6 fringe and overhead factor yields an hourly burdened labor cost of $110.62 per hour. The unit costs values shown in Table 4
-9 and 4
- 10 reflect the cost of goods and services that would be purchased by the entity which owns the facility conducting GS. That entity would have additional General and Administrative Costs (G&A) on top of those direct costs for goods and services. These G&A cost are assumed to 20 percent of the direct costs. 4.5.1 Cost Scenarios There are three regulatory alternatives (low, medium [or reference], and high) presented in Table 4
- 11 in terms of which monitoring devices would be used at a facility conducting GS and how often sampling and measurement would take place. Because each facility conducting GS will have unique characteristics that may result in the selection of different monitoring techniques, the application of the monitoring devices are indicated as percents of sites that would be expected to use each device or technique. Also shown in Table 5
-4 are the portions of facilities that expected to be required to use the device or technique under the UIC Class VI permits and under UIC Class II permits. The cost impacts of the subpart RR are estimated as the monitoring and measurement requirements above and beyond the UIC Class II requirements. 20

19 For SPE survey of petroleum engineers see http://www.spe.org/spe
site/spe/spe/career/salary_survey/08SalarySurveyHighlights.pdf 20 For the purposes of this rule, costs incremental to Class II requirements were estimated for ER projects conducting GS and costs incremental to the proposed Class VI requirements were estimated for all other GS projects.OMB DRAFT: Please do not cite, quote, or distribute

4
-27 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 Deep Monitoring Wells (into or right above injection zone) Fraction

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

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

Projects 0% 0% 0% 0% 0% 0% 0% 0% Frequency (months) Continuous Continuous Continuous Periodic Sampling and Testing of Injected Fluid Fraction

Projects 100% 100% 100% 100% 100% 100% 100% 100% Frequency (months) 3 3 3 3 3 3 3 3 Estimation of Fugitive Emission from Surface Facilities Fraction

Projects 0% 0% 100% 100% 0% 0% 0% 0% Frequency (months) 12 12 12 12 12 12 12 12
Periodic Seismic Surveys Fraction

Projects 25% 25% 25% 25% 0% 25% 25% 25% Frequency (months) 60 60 60 60 60 60 60 60 Periodic Digital Color Infrared Orthoimagery (CIR) or Hyperspectral Imaging to detect changes to vegetation. Fraction

Projects 0% 0% 50% 50% 0% 0% 50% 50% Frequency (months) 12 12 12 12 12 12 12 12OMB DRAFT: Please do not cite, quote, or distribute

4
-28 Table 4-9. Assumptions for Application of Technologies by Regulatory Alternative (continued) Saline, Abandoned Oil & Gas Fields: Starting Point is UIC

Class VI Requirements ER plus GS : Starting Point is UIC Class II Requirements
Under UIC Class VI Lowest Level

RR Alternative Middle Level

RR Alternative Highest

Level RR Alternative Under UIC

Class II Lowest Level

RR Alternative Middle Level

RR Alternative Highest

Level RR Alternative Periodic mobile survey to detect surface leaks
. May be good option where vegetation is sparse . Fraction

Projects 0% 0% 50% 50% 0% 0% 50% 50% Frequency (months) 12 12 12 12 12 12 12 12 Eddy covariance measurement from permanent towers to detect surface leaks. Fraction

Projects 25% 25% 25% 100% 0% 25% 25% 100% Frequency (months) Continuous Continuous Continuous Continuous Continuous Continuous Continuous Continuous Soil zone monitoring (sampling gas from accumulation chambers) Fraction

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

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

Projects 0% 0% 100% 100% 0% 0% 100% 100% Frequency (months) 12 12 12 3 12 12 12 3OMB DRAFT: Please do not cite, quote, or distribute

4
-29 4.6 Projecting and Discounting National Costs The cost per project is computed by applying the cost algorithms (Table 4
- 5 and 4
- 8) to the “pro
-forma” characteristics assume for each type of project (Tables 4
-3 to 4
- 5) , “Pro
-form Project Characteristics.” The results for cost per project appear in the left
-hand side of Table 4
- 10 for the no additional ER opt in activity baseline scenario. Table 4
- 11 shows the results for the anthropogenic ER opt in only activity scenario. Table 4
- 12 shows the results for the anthropogenic plus one half of other ER opt in activity scenario.OMB DRAFT: Please do not cite, quote, or distribute

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

Environmental Baseline Periodic Monitoring Annual Episodic Monitoring Costs Overhead

and G&A Total

Annual Costs Capital Costs Annualized

Capital Costs Capital Cost Annual Operating Cost Annualized

Capital and Contractor Costs

Under UIC Class VI or II Known DOE EOR Pilot Projects $
- $0 $ 1,286 $ 1,880 $ 2,063 $0 $ 413 $ 2,476 Known DOE Saline Pilot

Projects $ 7,438 $2,196 $ 3,103,485 $ 114,245 $1,030,481 $0 $ 206,535 $1,239,212 Future DOE Saline Pilot

Projects $ 7,438 $2,196 $ 3,103,485 $ 114,245 $1,030,481 $0 $ 206,535 $1,239,212 Known Commercial EOR

Projects Class II $
- $0 $ 1,286 $ 1,880 $ 2,063 $0 $ 413 $ 2,476 Known Commercial Saline

Projects $ 50,750 $3,807 $13,906,005 $ 533,000 $1,576,077 $0 $ 315,977 $1,895,861 Conversion of Existing EOR

Projects to GS Class II $
- $0 $ 1,286 $ 1,880 $ 2,063 $0 $ 413 $ 2,476

Low Known DOE EOR Pilot Projects $ 38,500 $5,482 $ 8,407,654 $ 392,750 $1,589,811 $3,108 $ 319,680 $1,918,080 Known DOE Saline Pilot

Projects $ 7,438 $2,196 $ 3,103,485 $ 114,245 $1,030,481 $3,108 $ 207,157 $1,242,941 Future DOE Saline Pilot

Projects $ 7,438 $2,196 $ 3,103,485 $ 114,245 $1,030,481 $3,108 $ 207,157 $1,242,941 Known Commercial EOR

Projects $ 35,000 $4,983 $ 7,215,125 $ 339,860 $1,367,131 $3,108 $ 275,044 $1,650,267 Known Commercial Saline

Projects $ 50,750 $3,807 $13,906,005 $ 533,000 $1,576,077 $3,605 $ 316,698 $1,900,187 Conversion of Existing EOR

Projects to GS $ 35,000 $4,983 $ 7,215,125 $ 339,860 $1,367,131 $3,108 $ 275,044 $1,650,267OMB DRAFT: Please do not cite, quote, or distribute

4
-31 Reference Known DOE EOR Pilot Projects $ 84,340 $12,008 $ 9,436,084 $ 451,650 $1,795,136 $3,108 $ 362,050 $2,172,302 Known DOE Saline Pilot

Projects $ 18,310 $5,406 $ 3,306,448 $ 132,232 $1,108,388 $3,108 $ 223,380 $1,340,281 Future DOE Saline Pilot

Projects $ 18,310 $5,406 $ 3,306,448 $ 132,232 $1,108,388 $3,108 $ 223,380 $1,340,281 Known Commercial EOR

Projects $ 76,900 $10,949 $ 8,150,061 $ 393,860 $1,554,245 $3,108 $ 313,660 $1,881,962 Known Commercial Saline

Projects $ 110,380 $8,280 $15,265,951 $ 611,624 $1,756,710 $3,605 $ 353,719 $2,122,313 Conversion of Existing EOR

Projects to GS $ 76,900 $10,949 $ 8,150,061 $ 393,860 $1,554,245 $3,108 $ 313,660 $1,881,962

High Known DOE EOR Pilot

Projects $ 199,840 $28,453 $ 9,697,737 $ 532,170 $1,912,910 $3,108 $ 388,894 $2,333,364 Known DOE Saline Pilot Projects $ 40,623 $11,993 $ 3,356,995 $ 147,787 $1,138,866 $3,108 $ 230,793 $1,384,759 Future DOE Saline Pilot Projects $ 40,623 $11,993 $ 3,356,995 $ 147,787 $1,138,866 $3,108 $ 230,793 $1,384,759 Known Commercial EOR Projects $ 181,900 $25,898 $ 8,387,928 $ 467,060 $1,661,312 $3,108 $ 338,064 $2,028,382 Known Commercial Saline Projects $ 262,630 $19,700 $15,610,858 $ 717,764 $1,888,721 $3,605 $ 382,405 $2,294,431 Conversion of Existing EOR Projects to GS $ 181,900 $25,898 $ 8,387,928 $ 467,060 $1,661,312 $3,108 $ 338,064 $2,028,382OMB DRAFT: Please do not cite, quote, or distribute

4
-32 Table 4- 11 . Summary of Cost Impacts : Activity Baseline from only Anthropogenic ER Opt In
Environmental Baseline Periodic Monitoring Annual Episodic Monitoring Costs Overhead

and G&A Total

Annual Costs Capital Costs Annualized

Capital Costs Capital Cost Annual Operating Cost Annualized

Capital and Contractor Costs

Under UIC Class VI or II Known DOE EOR Pilot Projects $
- $0 $ 1,286 $ 1,880 $ 2,063 $0 $ 413 $ 2,476 Known DOE Saline Pilot

Projects $ 7,438 $2,196 $ 3,103,485 $ 114,245 $1,030,481 $0 $ 206,535 $1,239,212 Future DOE Saline Pilot

Projects $ 7,438 $2,196 $ 3,103,485 $ 114,245 $1,030,481 $0 $ 206,535 $1,239,212 Known Commercial EOR

Projects Class II $
- $0 $ 1,286 $ 1,880 $ 2,063 $0 $ 413 $ 2,476 Known Commercial Saline

Projects $ 50,750 $3,807 $13,906,005 $ 533,000 $1,576,077 $0 $ 315,977 $1,895,861 Conversion of Existing EOR

Projects to GS Class II $
- $0 $ 1,286 $ 1,880 $ 2,063 $0 $ 413 $ 2,476

Low Known DOE EOR Pilot Projects $ 38,500 $5,482 $ 8,407,654 $ 392,750 $1,589,811 $3,108 $ 319,680 $1,918,080 Known DOE Saline Pilot

Projects $ 7,438 $2,196 $ 3,103,485 $ 114,245 $1,030,481 $3,108 $ 207,157 $1,242,941 Future DOE Saline Pilot

Projects $ 7,438 $2,196 $ 3,103,485 $ 114,245 $1,030,481 $3,108 $ 207,157 $1,242,941 Known Commercial EOR

Projects $ 35,000 $4,983 $ 7,215,125 $ 339,860 $1,367,131 $3,108 $ 275,044 $1,650,267 Known Commercial Saline

Projects $ 50,750 $3,807 $13,906,005 $ 533,000 $1,576,077 $3,605 $ 316,698 $1,900,187 Conversion of Existing EOR

Projects to GS $ 35,000 $4,983 $ 7,215,125 $ 339,860 $1,367,131 $3,108 $ 275,044 $1,650,267OMB DRAFT: Please do not cite, quote, or distribute

4
-33 Reference Known DOE EOR Pilot Projects $ 84,340 $12,008 $ 9,436,084 $ 451,650 $1,795,136 $3,108 $ 362,050 $2,172,302 Known DOE Saline Pilot

Projects $ 18,310 $5,406 $ 3,306,448 $ 132,232 $1,108,388 $3,108 $ 223,380 $1,340,281 Future DOE Saline Pilot

Projects $ 18,310 $5,406 $ 3,306,448 $ 132,232 $1,108,388 $3,108 $ 223,380 $1,340,281 Known Commercial EOR

Projects $ 76,900 $10,949 $ 8,150,061 $ 393,860 $1,554,245 $3,108 $ 313,660 $1,881,962 Known Commercial Saline

Projects $ 110,380 $8,280 $15,265,951 $ 611,624 $1,756,710 $3,605 $ 353,719 $2,122,313 Conversion of Existing EOR

Projects to GS $ 76,900 $10,949 $ 8,150,061 $ 393,860 $1,554,245 $3,108 $ 313,660 $1,881,962

High Known DOE EOR Pilot Projects $ 199,840 $28,453 $ 9,697,737 $ 532,170 $1,912,910 $3,108 $ 388,894 $2,333,364 Known DOE Saline Pilot

Projects $ 40,623 $11,993 $ 3,356,995 $ 147,787 $1,138,866 $3,108 $ 230,793 $1,384,759 Future DOE Saline Pilot

Projects $ 40,623 $11,993 $ 3,356,995 $ 147,787 $1,138,866 $3,108 $ 230,793 $1,384,759 Known Commercial EOR

Projects $ 181,900 $25,898 $ 8,387,928 $ 467,060 $1,661,312 $3,108 $ 338,064 $2,028,382 Known Commercial Saline

Projects $ 262,630 $19,700 $15,610,858 $ 717,764 $1,888,721 $3,605 $ 382,405 $2,294,431 Conversion of Existing EOR

Projects to GS $ 181,900 $25,898 $ 8,387,928 $ 467,060 $1,661,312 $3,108 $ 338,064 $2,028,382OMB DRAFT: Please do not cite, quote, or distribute

4
-34 Table 4- 12 . Summary of Cost Impacts : Activity Baseline from Anthropogenic CO 2 plus One-half of Other ER Opt In
Environmental Baseline Periodic Monitoring Annual Episodic Monitoring Costs Overhead

and G&A Total

Annual Costs Capital Costs Annualized

Capital Costs Capital Cost Annual Operating Cost Annualized

Capital and Contractor Costs

Under UIC Class VI or II Known DOE EOR Pilot Projects $
- $0 $ 1,286 $ 1,880 $ 2,063 $0 $ 413 $ 2,476 Known DOE Saline Pilot

Projects $ 7,438 $2,196 $ 3,103,485 $ 114,245 $1,030,481 $0 $ 206,535 $1,239,212 Future DOE Saline Pilot

Projects $ 7,438 $2,196 $ 3,103,485 $ 114,245 $1,030,481 $0 $ 206,535 $1,239,212 Known Commercial EOR

Projects Class II $
- $0 $ 1,286 $ 1,880 $ 2,063 $0 $ 413 $ 2,476 Known Commercial Saline

Projects $ 50,750 $3,807 $13,906,005 $ 533,000 $1,576,077 $0 $ 315,977 $1,895,861 Conversion of Existing EOR

Projects to GS Class II $
- $0 $ 1,286 $ 1,880 $ 2,063 $0 $ 413 $ 2,476

Low Known DOE EOR Pilot Projects $ 38,500 $5,482 $ 8,407,654 $ 392,750 $1,589,811 $3,108 $ 319,680 $1,918,080 Known DOE Saline Pilot

Projects $ 7,438 $2,196 $ 3,103,485 $ 114,245 $1,030,481 $3,108 $ 207,157 $1,242,941 Future DOE Saline Pilot

Projects $ 7,438 $2,196 $ 3,103,485 $ 114,245 $1,030,481 $3,108 $ 207,157 $1,242,941 Known Commercial EOR

Projects $ 35,000 $4,983 $ 7,215,125 $ 339,860 $1,367,131 $3,108 $ 275,044 $1,650,267 Known Commercial Saline

Projects $ 50,750 $3,807 $13,906,005 $ 533,000 $1,576,077 $3,605 $ 316,698 $1,900,187 Conversion of Existing EOR

Projects to GS $ 35,000 $4,983 $ 7,215,125 $ 339,860 $1,367,131 $3,108 $ 275,044 $1,650,267OMB DRAFT: Please do not cite, quote, or distribute

4
-35 Reference Known DOE EOR Pilot Projects $ 84,340 $12,008 $ 9,436,084 $ 451,650 $1,795,136 $3,108 $ 362,050 $2,172,302 Known DOE Saline Pilot

Projects $ 18,310 $5,406 $ 3,306,448 $ 132,232 $1,108,388 $3,108 $ 223,380 $1,340,281 Future DOE Saline Pilot

Projects $ 18,310 $5,406 $ 3,306,448 $ 132,232 $1,108,388 $3,108 $ 223,380 $1,340,281 Known Commercial EOR

Projects $ 76,900 $10,949 $ 8,150,061 $ 393,860 $1,554,245 $3,108 $ 313,660 $1,881,962 Known Commercial Saline

Projects $ 110,380 $8,280 $15,265,951 $ 611,624 $1,756,710 $3,605 $ 353,719 $2,122,313 Conversion of Existing EOR

Projects to GS $ 76,900 $10,949 $ 8,150,061 $ 393,860 $1,554,245 $3,108 $ 313,660 $1,881,962

High Known DOE EOR Pilot Projects $ 199,840 $28,453 $ 9,697,737 $ 532,170 $1,912,910 $3,108 $ 388,894 $2,333,364 Known DOE Saline Pilot

Projects $ 40,623 $11,993 $ 3,356,995 $ 147,787 $1,138,866 $3,108 $ 230,793 $1,384,759 Future DOE Saline Pilot

Projects $ 40,623 $11,993 $ 3,356,995 $ 147,787 $1,138,866 $3,108 $ 230,793 $1,384,759 Known Commercial EOR

Projects $ 181,900 $25,898 $ 8,387,928 $ 467,060 $1,661,312 $3,108 $ 338,064 $2,028,382 Known Commercial Saline

Projects $ 262,630 $19,700 $15,610,858 $ 717,764 $1,888,721 $3,605 $ 382,405 $2,294,431 Conversion of Existing EOR

Projects to GS $ 181,900 $25,898 $ 8,387,928 $ 467,060 $1,661,312 $3,108 $ 338,064 $2,028,382OMB DRAFT: Please do not cite, quote, or distribute

4
-36 4.7 MRV Plan Costs Facilities must develop a monitoring, reporting, and verification (MRV) plan, submit the MRV plan to EPA, receive an approved MRV plan from EPA, implement the EPA
-approved plan, and submit annual report addenda in accordance with procedures in 98.448(a). The MRV plan must include a delineation of the monitoring areas; an identification of potential surface leakage pathways and a risk assessment of leakage of the CO2 through these pathways in the monitoring area; a strategy for detecting and quantifying any surface leakage of CO 2 ; a strategy for establishing the expected environmental baselines; and a summary of considerations made to calculate site
- specific variables for the mass balance equation. Facilities must submit the MRV plan on the schedule described in section 98.448(b). Facilities must re
- submit the MRV plan for EPA approval according to section 98.448(g). An addendum describing the monitoring program that was implemented, including descriptions of monitoring anomalies and surface leakage, if any, must be submitted with the next annual report (March 31 of the subsequent calendar year). The costs of the developing a MRV plan are reported in Tables 4
- 13 and 4
- 14.OMB DRAFT: Please do not cite, quote, or distribute

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

Scenario Cost Item Cost Algorithm in Hours Cost per

Instance per Project Frequency

(every X years for 40-year injection + 50 year monitoring life) Cost per Project

(over 90-year life, undiscounted) Notes New Project with UIC Class VI Permit Evaluate Leakage Pathways 16 $ 1,770 once $ 1,770 All raw data should be in UIC Class VI permit. Time is for re
-interpretation relative to RR regs New Project with UIC Class VI Permit Delineate Areas of Monitoring 32 $ 3,540 5 $ 63,714 Modeling would be done for UIC Class VI, but needs to be interpreted for free phase plume. Maps need to be generated New Project with UIC Class VI Permit Develop strategy for leak

detection, verification and quantification 160 $ 17,698 once $ 17,698 Requires considerable statistical analysis not expected to be in UIC permit New Project with UIC Class VI Permit Establish baseline conditions 16 $ 1,770 once $ 1,770 Requires more statistical analysis than expected to be in UIC permit. Data collection cost are already under each technology option. New Project with UIC Class VI Permit Tailor mass balance equation 8 $ 885 once $ 885 New Project with UIC Class VI Permit Write MRV plan 400 $ 44,246 once $ 44,246 Assume 100 pages at 4 hours per page New Project with UIC Class VI Permit Discuss MRV plan with EPA

and edits 100 $ 11,062 once $ 11,062 Assume most plans will be OK, but others will have to be redone to some degree. Assume 25% of first draft time. New Project with UIC Class VI Permit Annual Report 100 $ 11,062 1 $ 995,538 Assume 25 pages at 4 hours per page New Project with UIC Class VI Permit All Items 832 $ 92,032 $ 1,136,684OMB DRAFT: Please do not cite, quote, or distribute

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

Scenario Cost Item Cost Algorithm in Hours Cost per

Instance per Project Frequency

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

Project (over 60-year life, undiscounted) Notes
ER Class II Project (no Class VI Permit) Evaluate Leakage Pathways 136 $ 15,044 once $ 15,044 All raw data should exist through normal ER project evaluation and monitoring. However, considerable effort needed to interpret for RR regs.
ER Class II Project (no Class VI Permit) Delineate Areas of Monitoring 756 $ 83,625 5 $ 1,003,503 Some modeling would be done for ER project evaluation and monitoring, but most likely need to be updated for MRV plan.
ER Class II Project (no Class VI Permit) Develop strategy for leak detection,

verification and quantification 160 $ 17,698 once $ 17,698 Requires considerable statistical analysis not expected to be in UIC permit

ER Class II Project (no Class VI Permit) Establish baseline conditions 16 $ 1,770 once $ 1,770 Requires more statistical analysis than expected to be in UIC permit. Data collection cost are already under each technology option. ER Class II Project (no Class VI Permit) Tailor mass balance equation 16 $ 1,770 once $ 1,770 More complex for ER ER Class II Project (no Class VI Permit) Write MRV plan 600 $ 66,369 once $ 66,369 Assume 150 pages at 4 hours per page

ER Class II Project (no Class VI Permit) Discuss MRV plan with EPA and edits 150 $ 16,592 once $ 16,592 Assume most plans will be OK, but others will have to be redone to some degree. Assume 25% of first draft time. ER Class II Project (no Class VI Permit) Annual Report 100 $ 11,062 1 $ 663,692 Assume 25 pages at 4 hours per page ER Class II Project (no Class VI Permit) All Items 1,934 $ 213,930 $ 1,786,438OMB DRAFT: Please do not cite, quote, or distribute

4
-39 4.8 Annual Report Costs As part of the MRV plan, EPA is requiring annual reporting. Respondents are required to create an annual report each year. For costing purposes, EPA assumed a 25 page report that require 4 labor hours per page (annual cost is $11,062) (Table 4
- 13 and Table 4
- 14) 4.9 Other Recordkeeping and Reporting Costs Additional recordkeeping ($1,700 per entity) and reporting ($500) costs per facility were also added to each project type. 4.10 Public Sector Burden EPA estimates the public sector burden to be $344,000 per year; $55,000 per year is for verification activities, and remaining costs are for program implementation and developing and maintaining the data collection system. Program implementation activities include, but are not limited to, evaluating monitoring plans, developing guidance and training materials to assist the regulated community, responding to inquires from affected facilities on monitoring and applicability requirements, and developing tools to assist in determining applicability.OMB DRAFT: Please do not cite, quote, or distribute

5
- 1 SECTION 5 ECONOMIC IMPACT ANALYSIS EPA prepares an EIA to provide decision makers with a measure of the social costs of using resources to comply with a program (EPA, 2000). As noted in EPA’s (2000) Guidelines for Preparing Economic Analyses , several tools are available to estimate social costs and range from simple direct compliance cost methods to the development of a more complex market analysis that estimates market changes (e.g., price and consumption) and economic welfare changes (e.g., changes in consumer and producer surplus). Given data limitations and the size scope of the final rule, EPA has used the direct compliance cost method as a measure of social costs 21
. 5.1 Threshold Analysis EPA is requiring reporting from all facilities that meet the subpart UU (previously referred to as “Tier 1” facilities) source category definition and from all facilities that meet the subpart RR (previously referred to as “Tier 2” facilities) source category definition, at no threshold. EPA notes that a subpart RR threshold specific to ER projects that are not permitted as UIC Class VI is unnecessary because such projects can choose to opt
-in to the subpart RR source category by implementing an EPA
-approved MRV plan, regardless of quantity of CO2 received. An all
-in reporting threshold will allow the Agency to comprehensively track all CO 2 supply (as reported in Suppliers of CO2 , subpart PP) that is received. This approach is consistent with the all
-in requirements in the GHG Reporting Program for suppliers of petroleum, natural gas, and coal
-to-liquid products (subparts LL, MM, and NN), producers of industrial gases (subpart OO), and suppliers of CO2 (subpart PP). It was reasonable to require all of the facilities in these source categorie s to report because it would result in the most comprehensive accounting possible, simplify the rule, and permit facilities to quickly determine whether or not they must report; the same rationale applies for subparts RR and UU in today’s rule. Furthermore, it will create a uniform burden for all covered facilities, ensuring a level playing field in, and preventing fragmentation of, the ER and GS sectors. Finally, EPA concluded that the same approach in both subparts UU and RR maximizes clarity and simplicity for facilities that choose to opt in from one to the other. The results of the threshold analysis are presented below in Table 5
- 1 and Table 5
-2
. For further information on the assumptions underlying the threshold analysis, please refer to the general technical support document (TSD) for proposal. 22

21 See pages 124 and 125 (EPA, 2000). 22 Subpart RR General TSD (see docket ID No. EPA
-HQ
-OAR
-200 9
-0 926)OMB DRAFT: Please do not cite, quote, or distribute

5
-2 Table 5- 1 Geologic Sequestration Facilities: Effect of CO2 Received Threshold on

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

Threshold Level (metric tons/yr of CO 2 received) Total National

(metric tons/yr of CO 2 received) Total

Number of U.S. Facilities Amount of CO 2

Received Number of Facilities Metric tons/yr of CO 2 Received Percent

Covered Number Percent

Covered All In 10,462,885 13 10,462,885 100.00% 13 100.00% 1,000 10,462,885 13 10,462,885 100.00% 13 100.00% 10,000 10,462,885 13 10,462,885 100.00% 13 100.00% 25,000 10,462,885 13 10,462,885 100.00% 13 100.00% 100,000 10,462,885 13 10,462,885 100.00% 13 100.00% Table 5-2 . Facilities Conducting CO2 Injection: Effect of CO2 Received Threshold on

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

Threshold Level (metric tons/yr of CO 2 received) Total National

(metric tons/yr of CO 2 received) Total

Number of U.S. Facilities Amount of CO 2

Received Number of Facilities Metric tons/yr of CO 2 Received Percent

Covered Number Percent

Covered All In 40,115,442 80 40,115,442 100.00% 80 100.00% 1,000 40,115,442 80 40,111,115 99.99% 74 92.50% 10,000 40,115,442 80 40,099,065 99.96% 71 88.75% 25,000 40,115,442 80 40,005,238 99.73% 65 81.25% 100,000 40,115,442 80 39,065,039 97.38% 48 60.00%
5.2 National Cost Estimates The total annualized costs incurred under the rule by these entities would be approximately $7 million (in 200 8$) in the first year and 6.7 million in subsequent years. This includes a public sector burden estimate of $344,000 for program implementation and verification activities. The typical annual cost for a facility conducting CO 2 injection (no GS) is $4,000 per year (Table 5
- 3).OMB DRAFT: Please do not cite, quote, or distribute

5
-3 Table 5-3 . National Annualized Mandatory Reporting Costs Estimates: Subpart RR and Subpart UU Reference
First Year Subsequent

Years
Type Number Metric Tons CO 2 Received per Year thousand,

2008$ thousand,

2008$ R&D (RR) 9 5,320,000 $73 $73 Facilities Conducting GS (Saline) (RR) 1 1,842,885 $318 $240 Facilities Conducting GS (ER) (RR) 3 3,300,000 $5,913 $5,680 Additional Facilities Conducting GS (ER opt in) (RR) 0 0 $0 $0 Facilities Conducting CO2 Injection (No GS) (UU) 80 40,115,442 $332 $332 Private Sector, Total All Projects 93 50,578,327 $6,636 $6,326 Private Sector, Average ($/ton) $0.13 $0.13 Public Sector, Total $344 $344 National Total $6,979 $6,670 Given uncertainties related to project adoption and the costs of the reporting program, EPA also considered two other private costs scenarios (one higher and one lower than the reference cost scenario) in order to assess a range of economic impacts on affected entities (Table 5
-4).OMB DRAFT: Please do not cite, quote, or distribute

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

Subpart UU Low High

First Year Subsequent

Years First Year Subsequent Years Type thousand, 2008$ thousand,

2008$ thousand,

2008$ thousand,

2008$ R&D (RR) $73 $73 $73 $73 Facilities Conducting GS (Saline) (RR) $96 $18 $490 $413 Facilities Conducting GS (ER) (RR) $5,218 $4,985 $6,352 $6,120 Additional Facilities Conducting GS (ER opt in) (RR) $0 $0 $0 $0 Facilities Conducting CO 2 Injection (No GS) (UU) $332 $332 $332 $332 Private Sector, Total All Projects $5,719 $5,409 $7,247 $6,937 Private Sector, Average ($/ton) $0.11 $0.11 $0.14 $0.14 Public Sector, Total $344 $344 $344 $344 National Total $6,062 $5,752 $7,591 $7,281 5.2.1 National Cost Estimates Under Alternative Facilities Conducting GS (ER opt in) Outcomes Currently, the number of ER operations that would choose to report as facilities conducting GS (ER opt in) is unknown and EPA could not identify any information or analysis to estimate this quantity. As a result, two additional scenarios of the have been considered to represent medium and high outcomes. In the medium scenario , all Anthropogenic CO2 projects (16) choose to report as facilities conducting GS (ER opt in)(Subpart RR). In the high scenario , all Anthropogenic CO2 projects (16) and fifty percent of other CO2 projects (32) choose to report as facilities conducting GS (ER opt in)(Subpart RR). As shown in Tables 5
- 5, national cost estimate is $39 million under the medium ER opt in outcome (first year) and $37 million in subsequent years. As shown in Tables 5
-6, national cost estimate is $104 million under the high ER opt in outcome (first year) and $98 million in subsequent years.OMB DRAFT: Please do not cite, quote, or distribute

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

Anthropogenic CO 2 Projects All Anthropogenic CO 2 Projects
First Year Subsequent

Years
Type Number Metric Tons CO 2 Received per Year thousand,

2008$ thousand,

2008$ R&D (RR) 9 5,320,000 $73 $73 Facilities Conducting GS (Saline) (RR) 1 1,842,885 $318 $240 Facilities Conducting GS (ER) (RR) 3 3,300,000 $5,913 $5,680 Additional Facilities Conducting GS (ER opt in) (RR) 16 6,972,040 $32,459 $30,552 Facilities Conducting CO 2 Injection (No GS) (UU) 64 33,143,402 $266 $266 Private Sector, Total All Projects 93 50,578,327 $39,029 $36,811 Private Sector, Average ($/ton) $0.77 $0.73 Public Sector, Total $344 $344 National Total $39,372 $37,155OMB DRAFT: Please do not cite, quote, or distribute

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-6 Table 5-6. National Annualized Mandatory Reporting Costs Estimates (2008$): All Anthropogenic and 50 Percent of Other CO2 Projects

All Anthropogenic and 50 Percent of Other CO2 Projects

First Year Subsequent

Years
Type Number Metric Tons CO 2 Received per Year thousand,

2008$ thousand,

2008$ R&D (RR) 9 5,320,000 $73 $73 Facilities Conducting GS (Saline) (RR) 1 1,842,885 $318 $240 Facilities Conducting GS (ER) (RR) 3 3,300,000 $5,913 $5,680 Additional Facilities Conducting GS (ER opt in) (RR) 48 23,543,741 $97,378 $91,655 Facilities Conducting CO2 Injection (No GS) (UU) 32 16,571,701 $133 $133 Private Sector, Total All Projects 93 50,578,327 $103,815 $97,782 Private Sector, Average ($/ton) $2.05 $1.93 Public Sector, Total $344 $344 National Total $104,159 $98,125
5.2.2 National Cost Estimates Under Alternative Facilities Conducting GS (Commercial Saline) Outcomes As discussed in Section 2, on February 3, 2010, President Obama established the CCS Task Force . The CCS Task Force, co
- chaired by DOE and EPA, was charged with proposing a plan to overcome the barriers to the widespread, cost
-effective deployment of CCS within ten years, with a goal of bringing 5 to 10 commercial demonstration projects online by 2016. Additionally, the American Clean Energy Security Act (ACES) and the American Power Act (APA) are estimated to induce about 30 percent of fossil
-fuel
-based electricity generation to come from power plants with CCS by 2040, rising to approximately 59 percent by 2050 (15 percent and 16 percent respectively of total electricity generation) (EPA, 2010). EPA analysis ofOMB DRAFT: Please do not cite, quote, or distribute

5
-7 APA projects deployment of over 30GW of CCS in 2030, which corresponds to over 54 550MW power plants. These modeling exercises show that CCS may play an important role in helping the United States meet carbon reduction targets. Given the potential for future deployment of CCS technologies, EPA considered two additional scenarios of the number of large scale saline aquifer GS (commercial saline) proj ect deployment by 2050 : low (5 projects), medium (9 projects), and high (54 projects). The low scenario is based on the low end of the range of deployment targeted by the CCS Task Force. The medium scenario is based on large scale saline project deployment projected in the cost analysis prepared for the UIC Class VI final rule (73 FR 43492) . The high scenario is based on EPA modeling of the projected deployment of CCS under the American Power Act. The national first year annual cost estimates increase by $ 1 .3 million under the low outcome; $2.5 million under the medium outcome, and $ 16.8 million under the high outcome. 5.2.3 National Cost Estimates: 2011 to 2060 Using Underground Injection Control Program for Carbon Dioxide Geologic Sequestration Wells (UIC Class VI Rule) Baseline EPA also conducted a cost analysis projected between 2011 and 2060. To do this, we used estimates of the anticipated level of U.S GS activity developed for the Underground Injection Control Program for Carbon Dioxide Geologic Sequestration Wells (UIC Class VI Rule) economic analysis (EPA
-HQ
- OW
-2008
-0390). The UIC Class VI Rule establishes minimum Federal requirements under the Safe Drinking Water Act (SDWA) for injection of CO 2 for the purposes of long
-term storage (also known as GS). The final rule creates a new class of injection well, Class VI, and sets minimum technical criteria for the purposes of protecting underground sources of drinking water (USDWs). Additional details about the development of the Geologic Sequestration Rule baseline can be found in section 3.4 of the UIC Class VI Rule’s economic impact analysis (EPA
-HQ
-OW
-2008
-0390) Table 5
-7 reports the baseline population numbers. As shown in Table 5
-7, present value of the total costs incurred from 2011 to 2060 is estimate to be $332 million using a 3 percent discount rate) and $108 million using a 7 percent discount rate. These numbers are conservative estimates based on the assumption that the projects report for the entire time period. In some cases, the plume and pressure front may stabilize before 2060 resulting in fewer years of reporting costs. Waivered saline and waivered ER refers to the UIC Class VI Rule’s provision that owners and operators may apply for and receive a waiver of the requirement to inject below the lowermost underground source of drinking water.OMB DRAFT: Please do not cite, quote, or distribute

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

Control Program for Carbon Dioxide Geologic Sequestration Wells (UIC Class VI Rule) Type of Formation Saline Formations Enhanced Recovery Year Pilot

Project Large

Project Waivered

Saline ER Waivered ER Total 2011 0 0 0 0 0 0 2012 0 0.86 0.05 0 0 1 2013 0 0.86 0.05 0 0 1 2014 0 1.71 0.1 0 0 2 2015 0 0 0 0 0 0 2016 0 1.71 0.1 0 0 2 2017 2 4.28 0.24 0 0 7 2018 0 0 0 0 0 0 2019 0 0 0 0 0 0 2020 0 0 0 0 0 0 2021 0 0 0 0 0 0 2022 0 0 0 0 0 0 2023 0 0 0 0 0 0 2024 0 0 0 0 0 0 2025 0 0 0 0 0 0 2026 0 0 0 0 0 0 2027 0 0 0 0 0 0 2028 0 0 0 0 0 0 2029 0 0 0 0.86 0.05 1 2030 0 0 0 0 0 0 2031 0 0 0 0.86 0.05 1 2032 0 0 0 3.42 0.19 4 2033 0 0 0 2.57 0.14 3 2034 0 0 0 0.86 0.05 1 2035 0 0 0 1.71 0.1 2 2036 0 0 0 2.57 0.14 3 2037 0 0 0 0.86 0.05 1 2038 0 0 0 0 0 0 2039 0 0 0 0 0 0 2040 0 0 0 0 0 0 2041 0 0 0 0 0 0 2042 0 0 0 0 0 0 2043 0 0 0 0 0 0 2044 0 0 0 0 0 0 2045 0 0 0 0 0 0 2046 0 0 0 0 0 0 2047 0 0 0 0 0 0 2048 0 0 0 0 0 0 2049 0 0 0 0 0 0 2050 0 0 0 0 0 0 2051 0 0 0 0 0 0 2052 0 0 0 0 0 0 2053 0 0 0 0 0 0 2054 0 0 0 0 0 0 2055 0 0 0 0 0 0 2056 0 0 0 0 0 0 2057 0 0 0 0 0 0 2058 0 0 0 0 0 0 2059 0 0 0 0 0 0 2060 0 0 0 0 0 0 Total 2.0 9.4 0.5 13.7 0.8 26OMB DRAFT: Please do not cite, quote, or distribute

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-9 Source: Underground Injection Control Program for Carbon Dioxide Geologic Sequestration Wells (UIC Class VI Rule) economic analysis (EPA
-HQ
-OW
-2008
-0390) 5.3 Economic Impact Analysis EPA assessed how the regulatory program may influence the profitability of companies by comparing the monitoring program costs to total sales (i.e., a “sales” test). Given limited data on commercial geological sequestration operations, EPA restricted the analysis to ER operations. ER activities account for approximately 90 percent of the project population (83 of 93 facilities). To do this, we divided the average annualized mandatory reporting costs per field by the estimated revenue for a representative field.

Sales Test Ratio= Average Cost (Table 5
-3)/Estimated revenue (Table 5
- 6) 5.3.1 Revenue Estimate for a Representative Commercial ER Operation EPA obtained national production statistics from the latest Department of Energy report about CO2 ER technologies (DOE, 2009). Data suggest a typical operation produces approximately 776,000 barrels of oil per year. Using the DOE choice of an average long
-term price of oil ($70), EPA estimated total revenue of $54.3 million per year. To enhance the transparency of the calculation, we provide data, sources, and methods in Table 5
-7. Table 5-8. Estimated Annual Revenue for a Representative Commercial ER Field Operation (2008) Label Variable Value Source and Calculation Method A Barrels Per Day 250,000 DOE, 2009 p: 19 B Barrels per year 77,562,500 A × 0.85 × 365 C Population 100 DOE, 2009 p: 19 D Average Barrels per year 775,625 B / C E Price per barrel $ 7 0 DOE, 2009 p: 2 F Total Revenue ($ million) $54 D × E Source: EPA calculations using data from DOE (2009) . Storing CO 2 and Producing Domestic Crude Oil with Next Generation CO2-ER Technology, accessed October 28, 2009.OMB DRAFT: Please do not cite, quote, or distribute

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- 10 5.3.2 Sales Test Results As shown in Table 5
- 8 sales test ratios are between 3.1 to 4.0 percent for facilities conducting GS ( Subpart RR) . In contrast, facilities conducting CO2 injection (no GS, which includes Class II ER operations) sales test ratios are below 0.01 percent. Table 5-9. Sales Tests for Representative Commercial ER Field Operation s Alternative Cost Scenarios Reference Low High Type First Year Subsequent Years First

Year Subsequent Years First

Year Subsequent Years Facilities Conducting GS (ER) (RR) 3.6% 3.5% 3.2% 3.1% 3.9% 3.8% Facilities Conducting GS (ER opt in) (RR) 3.7% 3.5% 3.3% 3.1% 4.0% 3.8% Facilities Conducting CO2 Injection (No GS) (UU) <0.1% <0.1% <0.1% <0.1% <0.1% <0.1% 5.4 Assessing Economic Impacts on Small Entities The first step in this assessment was to determine whether the rule will have a significant impact on a substantial number of small entities (SISNOSE). To make this determination, EPA used a screening analysis that allows us to indicate whether EPA can certify the rule as not having a SISNOSE. The elements of this analysis included

 identifying affected sectors and entities,

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

 determining SISNOSE certification category. 5.4.1 Identify Affected Sectors and Entities For the purposes of assessing the impacts of the rule on small entities, we defined a small entity as (1) a small business, as defined by SBA’s regulations at 13 CFR Part 121.201; (2) a small governmental jurisdiction that is a government of a city, county, town, school district, or special district with a population of less than 50 ,000; or (3) a small organization that is any not
for
-profit enterprise that is independently owned and operated and is not dominant in its field.OMB DRAFT: Please do not cite, quote, or distribute

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- 11 For the Carbon Dioxide Injection and Geologic Sequestration Reporting Rule, small entity is defined as a small business as defined by the Small Business Administration’s regulations at 13 CFR 121.201; according to these size standards, ultimate parent companies owning oil and gas extraction operations (NAICS 211) are categorized as small if the total number of em

ployees at the firm is fewer than 500. The Oil & Gas Journal publishes a list of companies owning active U.S. CO2 ER projects in 2008 (OGJ, 2008). EPA’s initial review of publicly available sales and employment databases suggest up to 9 of the 23 companies listed in the OGJ survey have fewer than 500 employees. 5.4.2 Develop Small Entity Economic Impact Measures The sales test examined the average total annualized mandatory reporting costs per ER field to a representative measure of revenue. Details are provided in section 5.3. 5.4.3 Results of Screening Analysis The Regulatory Flexibility Act generally requires an agency to prepare a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements under the Administrative Procedure Act or any other statute, unless the agency certifies that the rule will not have a significant economic impact on a substantial number of small entities. After considering the economic impact of the rule on small entities, EPA has concluded that this action will not have a significant economic impact on a substantial number of small entities. Currently EPA believes small ER operations will most likely be facilities conducting CO2 injection (no GS), including Class II ER projects. The average ratio of annualized reporting program costs to revenues of a typical ER operation likely owned by representative small enterprises is less than 1%. Although this rule will not have a significant economic impact on a substantial number of small entities, EPA nonetheless took several steps to reduce the impact of this rule on small entities. For example, EPA is proposing monitoring and reporting requirements that build off of the UIC program. In addition, EPA is proposing equipment and methods that may already be in use by a facility for compliance with its UIC permit. Also, EPA is requiring annual reporting instead of more frequent reporting. One public hearing on the proposal was held on April 19, 2010. In addition, EPA has an open door policy, similar to the outreach conducted during the development of the proposed andOMB DRAFT: Please do not cite, quote, or distribute

5
- 12 final Mandatory GHG Reporting Rule. Details of these meetings are available in the docket (EPA
-HQ
- OAR
-2009
-0926). 5.5 Characterization of Benefits of Subpart RR and Subpart UU of the Mandatory Reporting Rule EPA examined the potential benefits of the Injection and Geologic Sequestration of Carbon Dioxide Reporting Rule. EPA’s previous analysis of the GHG reporting rule discussed the benefits of a reporting system with respect to policy making relevance, transparency issues, and market efficiency. Instead of a quantitative analysis of the benefits, EPA conducted a systematic literature review of existing studies including government, consulting, and scholarly reports.A mandatory reporting system will benefit the public by increased transparency of facility GHG data. Transparent, public data on GHGs allows for accountability of polluters to the public stakeholders who bear the cost of the pollution. Citizens, community groups, and labor unions have made use of data from Pollutant Release and Transfer Registers to negotiate directly with polluters to lower emissions, circumventing greater government regulation. Publicly available emissions data also will allow individuals to alter their consumption habits based on the GHG emissions of producers. The greatest benefit of mandatory reporting of GHGs to government will be realized in developing future GHG policies. For example, in the EU’s Emissions Trading System, a lack of accurate monitoring at the facility level before establishing CO 2 allowance permits resulted in allocation of permits for emissions levels an average of 15 percent above actual levels in every country except the United Kingdom. Benefits to industry of GHG monitoring include the value of having independent, verifiable data to present to the public to demonstrate appropriate environmental stewardship, and a better understanding of their emission levels and sources to identify opportunities to reduce emissions. Such monitoring allows for inclusion of standardized GHG data into environmental management systems, providing the necessary information to achieve and disseminate their environmental achievements. Standardization will also be a benefit to industry, once facilities invest in the institutional knowledge and systems to report GHG data, the cost of monitoring should fall and the accuracy of the accounting should improve. A standardized reporting program will also allow forOMB DRAFT: Please do not cite, quote, or distribute

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- 13 facilities to benchmark themselves against similar facilities to understand better their relative standing within their industry.OMB DRAFT: Please do not cite, quote, or distribute

6
- 1 SECTION 6 STATUTORY AND EXECUTIVE ORDER REVIEWS This section describes EPA’s compliance with several applicable executive orders and statutes during the development of the final Injection and Geologic Sequestration of Carbon Dioxide Reporting Rule. 6.1 Executive Order 12866: Regulatory Planning and Review Under Executive Order (EO) 128 66 (58 FR 51735, October 4, 1993), this action is a "significant regulatory action” because it may raise novel legal or policy issues arising out of legal mandates, the President’s priorities, or the principles set forth in the EO. Accordingly, EPA submitted this action to the Office of Management and Budget (OMB) for review under EO 12866 and any changes made in response to OMB recommendations have been documented in the docket for this action. In addition, EPA prepared an analysis of the potential costs and benefits associated with this action. This analysis is contained in
. in the Economic Impact Analysis (EPA
-HQ
-2009
- 0926). A copy of the analysis is available in the docket for this action and the analysis is briefly summarized here. In this report, EPA has identified the regulatory options considered, their costs, the emissions that would likely be reported under each option, and explained the selection of the option chosen for the rule. The costs of the rule are reported in Section 4, and the economic impacts and qualitative benefits assessment are reported in Section 5. Overall, EPA has concluded that the costs of the Injection and Geologic Sequestration of Carbon Dioxide Reporting Rule are outweighed by the potential benefits of more comprehensive information about CO2 injection. The total annualized cost of the rule will be approximately $7 million (in 2008$) during the first yea r of the program and $6.7 million in subsequent years (344,000 of programmatic costs to the Agency). 6.2 Paperwork Reduction Act The information collection requirements in the final rule have been submitted for approval to the Office of Management and Budget (OMB) under the Paperwork Reduction Act, 44 U.S.C. 3501 et seq . The Information Collection Request (ICR) document prepared by EPA has been assigned EPA ICR number 2372.02. EPA has identified the following goals of the mandatory GHG reporting system:OMB DRAFT: Please do not cite, quote, or distribute

6
-2  Obtain data that is of sufficient quality that it can be used to analyze and inform the development of a range of future climate change policies and potential regulations.

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

 Create reporting requirements that are, to the extent possible and appropriate, consistent with existing GHG reporting programs in order to reduce reporting burden for all parties involved. The information from CO2 injection and geologic sequestration facilities will allow EPA to make well
-informed decisions about whether and how to use the CAA to regulate these facilities and encourage voluntary reductions. Because EPA does not yet know the specific policies that will be adopted, the data reported through the mandatory reporting system should be of sufficient quality to inform policy and program development. Also, consistent with the Appropriations Act, the reporting rule covers a broad range of sectors of the economy. This information collection is mandatory and will be carried out under CAA Sections 114. Information identified and marked as Confidential Business Information (CBI) will not be disclosed except in accordance with procedures set forth in 40 CFR part 2. However, emissions information collected under CAA section 114 generally cannot be claimed as CBI and will be made public. 23 The projected cost and hour burden for non
-Federal respondents is $7.0 million and 9,416 hours per year. The estimated average burden per response is 56.6 hours; the frequency of response is annual for all respondents that must comply with the rule’s reporting requirements, except for electricity
-generating units that are already required to report quarterly under 40 CFR part 75 (acid rain program); and the estimated average number of likely respondents per year is 9. The cost burden to respondents resulting from the collection of information includes the total capital and start
-up cost annualized over the equipment’s expected useful life (averaging $717,000 per year) a total operation and maintenance component (averaging $5.3 million per year), and a labor cost component (averaging $1.0 million per year). Burden is defined at 5 CFR part 1320.3(b). These cost numbers differ from those shown elsewhere in the EIA for the final rule because ICR costs represent the average cost over the first three years of the rule, but costs are reported elsewhere in the EIA for the first year of the rule
23 Although CBI determinations are usually made on a case
-by
-case basis, on July 7, 2010, EPA published a proposed rule (75 FR 39094) relating to CBI determinations for the data collected under the GHG Reporting Program (40 CFR part 98 ).OMB DRAFT: Please do not cite, quote, or distribute

6
-3 and for subsequent years of the rule. Also, the total cost estimate of the rule in the EIA includes the cost to the Agency to administer the program. In addition, the ICR focuses on respondent burden, while the EIA for the final rule includes EPA Agency costs. An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. The OMB control numbers for EPA’s regulations in 40 CFR are listed in 40 CFR part 9. When this ICR is approved by OMB, the Agency will publish a technical amendment to 40 CFR part 9 in the Federal Register to display the OMB control number for the approved information collection requirements contained in the final rule. 6.3 Regulatory Flexibility Act The Regulatory Flexibility Act generally requires an agency to prepare a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements under the Administrative Procedure Act or any other statute, unless the agency certifies that the rule will not have a significant economic impact on a substantial number of small entities. Small entities include small businesses, small governmental jurisdictions, and small not
-for
-profit enterprises. The first step in this assessment was to determine whether the rule will have a significant impact on a substantial number of small entities (SISNOSE). To make this determination, EPA used a screening analysis that allows us to indicate whether EPA can certify the rule as not having a SISNOSE. The elements of this analysis included

 identifying affected sectors and entities,

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

 determining SISNOSE certification category. 6.3.1 Identify Affected Sectors and Entities For the purposes of assessing the impacts of the rule on small entities, we defined a small entity as (1) a small business, as defined by SBA’s regulations at 13 CFR part 121.201; (2) a small governmental jurisdiction that is a government of a city, county, town, school district, or special district with a population of less than 50,000; or (3) a small organization that is any not
for
-profit enterprise that is independently owned and operated and is not dominant in its field. For the Injection and Geologic Sequestration of Carbon Dioxide Reporting Rule, small entity is defined as a small business as defined by the Small Business Administration’s regulations at 13 CFR 121.201 ; according to these size standards, ultimate parent companiesOMB DRAFT: Please do not cite, quote, or distribute

6
-4 owning oil and gas extraction operations (NAICS 211) are categorized as small if the total number of employees at the firm is fewer than 500. The Oil & Gas Journal publishes a list of companies owning active U.S. CO2 ER projects in 2008 (OGJ, 2008). EPA’s initial review of publicly available sales and employment databases suggest up to 9 of the 23 companies listed in the OGJ survey have fewer than 500 employees. EPA continues to collect other information about corporate structures of these 9 companies to assess whether these companies are owned by larger parent companies. 6.3.2 Develop Small Entity Economic Impact Measures These sales test examined the average total annualized mandatory reporting costs per ER field to a representative measure of revenue. Details are provided in section 5.3. 6.3.3 Results of Screening Analysis The Regulatory Flexibility Act generally requires an agency to prepare a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements under the Administrative Procedure Act or any other statute, unless the agency certifies that the rule will not have a significant economic impact on a substantial number of small entities. After considering the economic impact of the rule on small entities, EPA has concluded that this action will not have a significant economic impact on a substantial numb er of small entities. Currently EPA believes small ER operations will most likely be facilities conducting CO2 injection (no GS), including Class II ER projects. As shown in Table 5
- 7, the average ratio of annualized reporting program costs to revenues of a typical ER operation likely owned by model small enterprises was less than 1%. Although this rule will not have a significant economic impact on a substantial number of small entities, EPA nonetheless took several steps to reduce the impact of this rule on small entities. For example, EPA is proposing monitoring and reporting requirements that build off of the UIC program. In addition, EPA is proposing equipment and methods that may already be in use by a facility for compliance with its UIC permit. Also, EPA is requiring annual reporting instead of more frequent reporting. During rule implementation, EPA will maintain an open door policy, similar to the outreach conducted during the development of the proposed and final Mandatory GHG Reporting Rule. Details of these meetings are available in the docket (EPA
-HQ
-OAR
-2008
- 0508).OMB DRAFT: Please do not cite, quote, or distribute

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- 5 6.4 Unfunded Mandates Reform Act Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), P.L. 104
-4, establishes requirements for federal agencies to assess the effects of their regulatory actions on state, local, and tribal governments and the private sector. Under Section 202 of the UMRA, EPA generally must prepare a written statement, including a cost
-benefit analysis, for final rules with “federal mandates” that may result in expenditures to state, local, and tribal governments, in the aggregate, or to the private sector, of $100 million or more in any one year. The final rule does not contain a Federal mandate that may result in expenditures of $100 million or more for State, local, and tribal governments, in the aggregate, or the private sector in any one year. Overall, EPA estimates that the total annualized costs of this final rule are approximately $7 million (in 2008$) during the first year of the program and $6.7 million in subsequent years ($ 344,000 of programmatic costs to the Agency)
. Thus, the final rule is not subj ect to the requirements of sections 202 or 205 of UMRA. The final rule is also not subject to the requirements of section 203 of UMRA because it contains no regulatory requirements that might significantly or uniquely affect small governments . Facilities subject to the final rule include facilities that inject CO 2 for enhanced recovery, and those that sequester CO2 . None of the facilities currently known to undertake these activities are owned by small governments. 6.5 Executive Order 13132: Federalism Executive Order 13132, entitled “Federalism” (64 FR 43255, August 10, 1999), requires EPA to develop an accountable process to ensure “meaningful and timely input by state and local officials in the development of regulatory policies that have federalism implications.” “Policies that have federalism implications” is defined in the executive order to include regulations that have “substantial direct effects on the states, on the relationship between the national government and the states, or on the distribution of power and responsibilities among the various levels of government.” The final rule does not have federalism implications. It will not have substantial direct effects on the states, on the relationship between the national government and the states, or on the distribution of power and responsibilities among the various levels of government, as specified in Executive Order 13132. This regulation applies to public
- or private
- sector facilities that inject CO 2 underground
. Few government facilities would be affected
. This regulation applies directly to facilities thatOMB DRAFT: Please do not cite, quote, or distribute

6
-6 inject CO2 underground. It does not apply to governmental entities unless the government entity owns a facility that injects and/or sequesters CO 2 underground. This regulation also does not limit the power of states or localities to collect GHG data and/or regulate GHG emissions. Thus, Executive Order 13132 does not apply to the final rule
. In the spirit of Executive Order 13132, and consistent with EPA policy to promote communications between EPA and State and local governments, EPA specifically solicits comment on the final action from State and local officials. 6.6 Executive Order 13175: Consultation and Coordination with Indian Tribal Governments Executive Order 13175, entitled “Consultation and Coordination with Indian Tribal Governments” (59 FR 22951, November 6, 2000), requires EPA to develop an accountable process to ensure “meaningful and timely input by tribal officials in the development of regulatory policies that have tribal implications.” The final rule is not expected to have tribal implications, as specified in Executive Order 13175. This regulation applies directly to facilities that inject and/or sequester CO2 underground. Few facilities expected to be affected by the rule are likely to be owned by tribal governments. Thus, Executive Order 13175 does not apply to the final rule
. Although Executive Order 13175 does not apply to this final rule, EPA sought opportunities to provide information to tribal governments and representatives during development of the GHG reporting rule. In consultation with EPA’s American Indian Environment Office, EPA’s outreach plan included tribes. EPA conducted several conference calls with tribal organizations during the proposal phase. For example, EPA staff provided information to tribes through conference calls with multiple tribal working groups and organizations at EPA that interact with tribes and through individual calls with two tribal board members of TCR. In addition, EPA prepared a short article on the GHG reporting rule that appeared on the front page of a tribal newsletter

—Tribal Air News

—

that was distributed to EPA/Office of Air Quality Planning & Standards’ network of tribal organizations. EPA gave a presentation on various climate efforts, including the GHG Reporting Program, at the National Tribal Conference on Environmental Management on June 24
-26, 2008. In addition, EPA had copies of a short information sheet distributed at a meeting of the National Tribal Caucus. See the “ Summary of EPA Outreach Activities for Developing the GHG reporting rule, ” in Docket No. EPA

–HQ

–OAR

–2008

–0508

–055 for a complete list of tribal contacts. EPA participated in a conference call with tribal air coordinators in April 2009 and prepared a guidance sheet for tribalOMB DRAFT: Please do not cite, quote, or distribute

6
-7 governments on the proposed GHG reporting rule. It was posted on the GHG Reporting Program Web site and published in the Tribal Air Newsletter. 6.7 Executive Order 13045: Protection of Children from Environmental Health and Safety Risks EPA interprets Executive Order 13045 (62 F.R. 19885, April 23, 1997) as applying only to those regulatory actions that concern health or safety risks, such that the analysis required under Section 5
- 501 of the executive order has the potential to influence the regulation. This action is not subject to Executive Order 13045 because it does not establish an environmental standard intended to mitigate health or safety risks. 6.8 Executive Order 13211: Actions that Significantly Affect Energy Supply, Distribution, or Use This final rule is not a “significant energy action” as defined in EO 13211 (66 FR 28355, May 22, 2001) because it is not likely to have a significant adverse effect on the supply, distribution, or use of energy. Further, EPA has concluded that this r ule is not likely to have any adverse energy effects. This final rule relates to monitoring, reporting and recordkeeping at facilities that inject and/or sequester CO2 underground and does not impact energy supply, distribution or use. Therefore, we conclude that this rule is not likely to have any adverse effects on energy supply, distribution, or use. 6.9 National Technology Transfer Advancement Act Section 12(d) of the National Technology Transfer and Advancement Act of 1995 (NTTAA), Public Law No. 104
- 113 (15 U.S.C. 272 note) directs EPA to use voluntary consensus standards in its regulatory activities unless to do so would be inconsistent with applicable law or otherwise impractical. Voluntary consensus standards are technical standards (e.g., materials specifications, test methods, sampling procedures, and business practices) that are developed or adopted by voluntary consensus standards bodies. NTTAA directs EPA to provide Congress, through OMB, with explanations when the Agency decides not to use availa ble and applicable voluntary consensus standards. This rulemaking involves technical standards. EPA developed no new measuring device standard. Rather we allow the use of an appropriate standard method published by a consensus
-based standards organization if such a method exists; or an industry standard practice.OMB DRAFT: Please do not cite, quote, or distribute

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- 8 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. EPA has determined that the final rule will not have disproportionately high and adverse human health or environmental effects on minority or low
-income populations because it does not affect the level of protection provided to human health or the environment. The final rule does not aff

ect the level of protection provided to human health or the environment because it is a rule addressing information collection and reporting procedures.OMB DRAFT: Please do not cite, quote, or distribute

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- 1 SECTION 7 CONCLUSIONS EPA is promulgating a regulation to require monitoring and reporting from facilities that conduct carbon dioxide (CO2) injection and geologic sequestration (GS). This rule does not require control of greenhouse gases (GHGs), rather it requires only monitoring and reporting of GHGs. 7.1 Summary of Selected Regulatory Alternative This rule amends 40 CFR part 98 to add reporting requirements covering facilities that conduct geologic sequestration (GS) of CO2 (subpart RR) and all other facilities that conduct injection of CO2 (subpart UU)
. This data will inform Agency decisions under CAA sections 111 and 112 related to the use of carbon dioxide capture and geologic sequestration (CCS ) for mitigating GHG emissions. In combination with data from subpart PP of the GHG Reporting Program (suppliers of CO2) , data from subpart UU and subpart RR will enable EPA to track the flow of CO2 across the CCS system. EPA will be able to reconcile subpart UU data on CO 2 received with CO2 supply data in order to better understand the quantity of CO2 supply that is used for underground injection versus the quantity supplied to other end
-uses. EPA will be able to reconcile subpart RR data on CO2 received with CO2 supply data in order to understand the quantity of CO2 supply that is geologically sequestered. Subpart RR information will enable EPA to collect data on the amount of CO2 emissions from facilities conducting GS , if any, and will provide a nationally consistent approach for quantifying CO2 sequestered. Subpart RR information will also enable EPA to monitor the growth and efficacy of GS (and therefore CCS) as a GHG mitigation technology over time and to evaluate relevant policy options. For example, EPA will be able to track whether incentives or regulations are needed to encourage faster or further GS project development. Furthermore, where enhanced oil and gas recovery (ER) projects are reporting under subpart RR, EPA will be able to evaluate ER as a non
-emissive end use. Subpart UU information will enable EPA to track ER operations and GS research and development (R&D) projects over time and to consider whether incentives or regulations would be effective or are needed for them to transition to subpart RR. The rule was proposed by EPA on April 12, 2010. One public hearing was held on April 19, 20 10, and the sixty day public comment period ended June 11, 2010. This rule takes into consideration comments received during the comment period and finalizes the monitoring andOMB DRAFT: Please do not cite, quote, or distribute

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-2 reporting requirements for facilities conducting GS and all other facilities conducting CO2 injection. 7.2 Estimated Costs and Impacts of the Mandatory GHG Reporting Program Under the rule, EPA estimates that 93 facilities would be covered by the rule . The total annualized costs incurred under the rule by these entities would be approximately $7 million (in 200 8$) in the first year and $6.7 million in subsequent years
. This includes a public sector burden estimate of $344,000 for program implementation and verification activities. These costs are distributed to several economic sectors and represent approximately 0.000 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 sectors. 7.2.1 Alternative Scenarios Considered 7.2.1.1 F acilities Conducting GS (ER opt in) Outcomes Currently, the number of ER operations that would choose to report as facilities conducting GS (ER opt in) is unknown and EPA could not identify any information or analysis to estimate this quantity. As a result, two additional scenarios of the have been considered to represent medium and high outcomes. In the medium scenario , all Anthropogenic CO2 projects (16) choose to report as facilities conducting GS (ER opt in)(Subpart RR). In the high scenario , all Anthropogenic CO2 projects (16) and fifty percent of other CO2 projects (32) choose to report as facilities conducting GS (ER opt in)(Subpart RR).As shown in Tables 5
- 5, national cost estimate is $39 million under the medium ER opt in outcome (first year) and $37 million in subsequent years. As shown in Tables 5
-6, national cost estimate is $104 million under the high ER opt in outcome (first year) and $98 million in subsequent years.

7.2.1.2 Facilities Conducting GS (Commercial Saline) Outcomes Given the potential for future deployment of CCS technologies, EPA considered two additional scenarios of the number of large scale saline aquifer GS (commercial saline) project deployment by 2050 : low (5 projects), medium (9 projects), and high (54 projects). The low scenario is based on the low end of the range of deployment targeted by the CCS Task Force. The medium scenario is based on large scale saline project deployment projected in the cost analysis prepared for the UIC Class VI final rule (73 FR 43492) . The high scenario is based on EPA modeling of the projected deployment of CCS under the American Power Act. The national first year annual cost estimates increase by $ 1.3 million under the low outcome; $2.5 million under the medium outcome, and $ 16.8 million under the high outcome.OMB DRAFT: Please do not cite, quote, or distribute

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- 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 Gaps in CO2 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 Forum, (CSLF), Paper No. CSLF
-T
-2005
-3, Presented at the Technical Group Meeting, April 30, 2005 The Economics of CO2 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 Council 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.OMB DRAFT: Please do not cite, quote, or distribute

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-2 Regional Carbon Sequestration Partnerships Annual Project Review Meeting, DOE/NETL, December 12, 2007. U.S. Department of Energy, National Energy Technology Laboratory website, www.netl.doe.gov 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_equipme nt_production/current/coststudy.html U.S. Department of Energy (DOE). 2009. Storing CO2 and Producing Domestic Crude Oil with Next Generation CO2-ER Technology, accessed October 28, 2009. U.S. Environmental Protection Agency (EPA). September 2000. Guidelines for Preparing Economic Analyses . EPA 240
-R
-00
-003. Washington, DC: EPA. Available at : http://yosemite.ep a.gov/ee/epa/eed.nsf/webpages/Guidelines.html. U.S. Environmental Protection Agency. 20 10 . EPA Analysis of the American Power Act of 2010 in the 111 th Congress
. http://epa.gov/climatechange/economics/economicanalyses.html#apa2010