### ASSESSMENT OF THE POTENTIAL COSTS, BENEFITS, AND OTHER IMPACTS OF THE CONDITIONAL EXCLUSION FROM THE R CRA DEFINITION OF HAZARDOUS WASTE FOR CO 2 

### STREAMS MANAGED IN UIC CLASS VI WELLS FOR THE PURPOSES OF GEOLOGIC SEQUESTRATION, AS PROPOSED

Economics and Risk Analysis Staff Office of Resource Conservation and Recovery

U. S. Environmental Protection Agency 1200 Pennsylvania Ave., N. W. Washington, DC 20460

June 2, 2011

### ACKNOWLEDGMENTS

The Agency recognizes ICF Internati onal for the overal l organization and development of this report. Eastern Research Group, Inc

. also contributed to this report. Lyn D. Luben and Phuc Phan of the U.S. Envir onmental Protection Agency, Office of Resource Conservation and Recovery (ORCR) provided guidance and review.

### Page 3 of 145 TABLE OF CONTENTS

ES. EXECUTIVE SUMMARY 5

1. INTRODUCTION 13

1.1 Need for Regulation 13

1.2 Summary of Current Rules 14

1.3 Summary of Proposed Changes 16

1.4 Analysis of Alternatives Consider ed (Regulatory a nd Non-Regulatory) 16

2. CHARACTERIZATION OF THE REGULATED COMMUNITY 177

2.1 CO 2 

### Capture Facilities 17 2.1.1 Current CO 2 

### Capture Facilities 188 2.1.2 Planned CO 2 

### Capture Facilities 19 2.1.3 Summary of Current and Planned CO 2 

### Capture Facilities Considered in this Analysis 23

2.2 CO 2 

### Transporters 25

2.3 CO 2 

### Sequestration Facilities 27

3. ANALYSIS OF THE INCREMENTAL COSTS AND BENEFITS OF THE PROPOSED RULE 301

3.1 Analytical Approach/Methodology 31

3.2 Baseline Practices 32 3.2.1 Hazardous Waste Determination Process for CO 2 

### Capture Facilities 32 3.2.2 Baseline Practices for CO 2 

### Capture Facilities 33 3.2.2.1 Factors that Influence Th e Baseline Practices of CO 2 

### Carbon Capture Facilities 34 3.2.2.2 Expected Baseline Practices of CO 2 

### Carbon Capture Facilities 366 3.2.3 Baseline Practices for CO 2 

### Sequestration Facilities 40

### Page 4 of 145 3.3 Post Rule Practices 43 3.3.1 Post Rule Practices for CO 2 

### Capture Facilities 43 3.3.2 Post Rule Practices for CO 2 

### Sequestration Facilities 43

3.4 Incremental Costs of the Proposed Rule 43 3.4.1 Compliance Costs 43 3.4.2 Social Costs 51 3.4.3 Costs to Government Entities 52

3.5 Incremental Cost Savings and Be nefits of the Proposed Rule 59 3.5.1 Waste Determination Savings for CO 2 

### Capture Facilities 59 3.5.2 RCRA Training, Planning, and Repor ting Requirement Savings for CO 2 

### Capture Facilities 60 3.5.3 CO 2 

### Treatment Savings for CO 2 

### Capture Facilities 61 3.5.4 Summary of Savings to CO 2 

### Capture Facilities 62 3.5.5 Waste Determination Savings for CO 2 

### Sequestration Facilities 66 3.5.6 RCRA Training, Planning, and Repor ting Requirement Savings for CO 2 

### Sequestration Facilities 66 3.5.7 Summary of Savings to CO 2 

### Sequestration Facilities 67 3.6 Summary of Costs and Savings 71 3.7 Unquantified Benefits of the Proposed Rule 744

4. REGULATORY FLEXIBILITY ANALYSIS 744

5. REFERENCES 75

APPENDIX A: COST FOR DETER MINING RCRA TOXICITY OF CO 2 

### STREAM 78

APPENDIX B: TR EATMENT COSTS 912

APPENDIX C. ASSESSMENT OF ENVIRONMENTAL JUSTICE IMPACTS 97

APPENDIX D. UNFUNDED MANDATES REFORM ACT ANALYSIS 1423

APPENDIX E. OTHER REQUIRED ANALYSES 1434

### Page 5 of 145 ES. Executive Summary

The U.S. Environmental Protection Agency (E PA or the Agency) re gulates the generation, transfer, treatment, and disposal of hazar dous waste under the Resource Conservation and Recovery Act (RCRA) Subtitle C. The hazardo us waste regulations are designed to ensure that hazardous waste is handled in a manner that protects human health and the environment. Currently, carbon dioxide (CO 2 

### ) streams are not listed as RCRA hazardous wastes, but may be classified as a RCRA hazardous waste if th ey exhibit hazardous char acteristics such as ignitability, corrosivity, reactiv ity, or toxicity. At present, EPA has little information to conclude that CO 2 

### streams would, or would not qua lify as RCRA hazardous wastes. However, EPA is proposing to revise the regul ations for hazardous waste management under RCRA to conditionally exclude carbon dioxide (CO 2 

### ) streams (that are otherwise hazardous) from the definition of hazardous waste, provided these CO 2 

### streams are captured from emission sources, are injected into Class VI Underground Injection Control (UIC) wells for purposes of geologic sequestration (GS) , and meet certain other conditions. 1 2



### EPA is taking this action because the Agency has determined that the management of these CO 2 

### streams under the proposed conditions does not present a substantial risk to human health or the environment, such that additional regulation pursuant to RCRA’s hazardous waste regulations is unnecessary. EPA expects that this amendment will substantially reduce the uncertainty associated with identifying these CO 2 

### streams under RCRA subtitle C, and will also facilitate the deployment of GS by providing regulatory clarity.

This analysis characterizes the regulated comm unity that will be di rectly affected by the proposed rule, estimates the expected incremen tal costs and benefits of the proposed rule, and certifies that the ru le will not have a significant econom ic impact on a substantial number of small entities.

ES.1 Characterization of the Regulated Community

The entities that may be directly a ffected by the proposed rule include CO 2 

### capture facilities, transporters, and sequest ration facilities.

Many electric power plants and othe r industrial facilities generate CO 2 

### as a byproduct of their operations. These facilities typically release that CO 2 

### into the environment. CO 2 

### capture facilities are entities that collect their CO 2 

### byproducts and manage them in a manner other than releasing them into the atmosphere. Curre ntly EPA estimates that, at a maximum, there

1 EPA has finalized requirements for the sequestration of CO 2 in Class VI underground injection wells under 40 CFR Parts 144 and 146 (Federal Requirements Under the Underground Injection Control (UIC) Program for Carbon Dioxide (CO2) Geologic Sequestration (GS) Wells) in a separate rulemaking, (75 FR 77230) December 10, 2010 (see Docket ID EPA–HQ– OW–2008–0390). 2 Regulations under the Safe Drinking Water Act Underground Injection Control program contains extensive technical requirements for ensuring that underground sources of drinking water are protected during geologic sequestration (GS) of CO 2.

### Page 6 of 145 could be up to 27 CO 2 

### capture facilities affected by the proposed rule. This estimate includes ten facilities that currently capture CO 2 

### , along with 17 facilities expected to begin CO 2 

### capture in the future. These 27 capture facilities include fossil fuel elec tric power generators, oil and gas extraction facili ties, natural gas distributi on facilities, ethyl alcohol manufacturers, and nitrogenous fertilizer manufacturers, and a ppear to represent a mix of large corporations and mid-sized companies.

Our low-end estimate considers only 13 CO 2 

### capture facilities. This includes ten existing capture facilities, two capture projects associated with name d DOE pilot projects, and one capture facility associated with the FutureGen federal/private partnership.

Exhibit ES-1 presents the high-end and low-end estimates for the number of CO 2 

### capture facilities considered in this analysis, by No rth American Industry Classification System (NAICS) code.

Exhibit ES-1: Number of Current and Planned CO 2 

### Capture Facilities Considered in this Analysis, High-End and Low-End Estimates, by Industry Sector

NAICS Industry Sector Number of Facilities High-End Estimate Low-End Estimate 

### 211111 Oil and Gas Extraction 7 7 221112 Fossil Fuel Electric Power Generation 16 2 221210 Natural Gas Distribution 1 1 325193 Ethyl Alcohol Manufacturing 1 1 325311 Nitrogenous Fertilizer Manufacturing 2 2 Total 27 13

At present, for economic reasons, captured CO 2 

### is transported by pipeline in a supercritical state (i.e., dense vapor state). 3 

### As of 2008 there were 30 operating CO 2 

### pipelines, operated by 29 separate entities. 4 

### Pipeline transportation of captured CO 2 

### falls under the “all other pipeline transportation” (i.e., transportation of substances other than crude oil, natural gas and refined petroleum produc ts) industry (NAICS 486990). 5 

### These CO 2 

### pipelines generally appear to be operated by large corporations. EPA has not identified any commercial entities that transport CO 2 

### by alternative methods, such as truck or rail that would be subject to the standards for hazardous wast e transporters if the CO 2 

### in question was found to be hazardous.

3 56 Federal Register 26922, June 12, 1991. http://www.greenfacts.org/en/co2-capture-s torage/l-3/4-transport-carbon-dioxide.htm Parfomk, Paul W., Folger, Peter, and Adam Vann. Congressional Research Service, July 31, 2009. Carbon Dioxide (CO 2 ) Pipelines for Carbon Sequestration: Emerging Policy Issues.
4 Department of Transportation, Pipeline and Hazard ous Materials Safety Administration (PHMSA), 2008 Hazardous Liquids Annual Data http://www.phmsa.dot.gov/staticfiles/ PHMSA/DownloadableFiles/Files/ LIQANN08.zip

. 5 Some of the entities conducting pipeline transportation of CO 2 also may fall into other industrial source categories (e.g., oil and gas extraction), but this an alysis only considers NAIC S 486990 because it is the industry category most relevant to the activity affected by the proposed rule.

### Page 7 of 145 Therefore, this analysis assume s that all transportation of CO 2 

### is, and will continue to be, conducted by pipeline, subject to the Department of Trans portation (DOT) Pipeline and Hazardous Material Safety Administration (PHMSA) requirements applicable to CO 2


### .

CO 2 

### sequestration facilities receive captured CO 2 

### streams and inject them into UIC wells for the purposes of sequestration. EPA estimates that as many as 29 planned sequestration facilities could be a ffected by the proposed rule. This estimate includes 15 planned commercial CO 2 

### sequestration projects and 14 planne d projects funded by DOE. The 15 planned commercial projects are expected to incl ude 12 enhanced oil rec overy projects that transition to sequestration in the long term and 3 saline re servoir sequestration projects. 6



### Our low-end estimate considers only six CO 2 

### sequestration facilities that will be Class VI UIC wells. This includes five sequestration projects associated with named DOE pilot projects and one sequestration facility associated with the FutureGen federal/private partnership. Class VI UIC wells fall under the other non-hazardous wa ste treatment and disposal (i.e., management by methods other than landfill, combustion, and incineration) industry (NAICS 562219). These Class VI well facilities ar e not currently operational.

ES.2 Analysis of the Incremental Costs and Benefits of the Proposed Rule

This analysis estimates the incremental costs an d benefits of the proposed rule (i.e., the costs and benefits that arise as a cons equence of the proposed rule). The analysis first lays out the “baseline” behavior that affected entities would be expected to display in the absence of the proposed rule. The next step is to evaluate how the affect ed entities would be likely to change their behavior under the proposed ru le. Once the baseline behavior and post-rule behavior have been characterized, the analysis then estimates the incremental costs and benefits of the proposed rule relative to the baseline and projects them over a 50-year period.

Baseline Behavior

In the absence of the conditional exclusi on being proposed, generators of captured CO 2 

### streams destined for disposal (i.e., geological sequestration) must determine whether their CO 2 

### stream is RCRA hazardous waste or non-ha zardous waste. As already stated, CO 2 

### streams are not listed hazardous waste, so woul d only be defined as RCRA hazardous if they exhibited a characteristic of hazardous waste (40 CFR part 261, subpart C). Under existing RCRA regulations, generators may either test their waste, or apply their knowledge – in lieu of testing – of the hazard characte ristic of a waste, in light of the materials or processes used, to determine whether that waste is a charac teristic hazardous wast e under RCRA. Public comments submitted to the Agency related to the UIC Class VI injection well rulemaking expressed concern over applyi ng RCRA characteristics to CO 2 

### streams 7 

### , and EPA

6 Department of Energy, National Energy Technology Laboratory, Carbon Capture and Storage Database, http://www.netl.doe.gov/technologies/carbon_seq/database/ index.html
7 Comments mainly focused on three key areas: 1) unclear whether or how CO 2 streams would be classified as a RCRA hazardous waste, 2) analytic procedures used under RCRA (e.g., the toxicity characteristic leaching

### Page 8 of 145 acknowledges these commenters’ concerns. However, this an alysis assumes that, depending on the CO 2 

### generation process used by the CO 2 

### capture facilities, the facilities would either test the CO 2 

### stream as a gas, or rely on process k nowledge and limited testing to determine whether their CO 2 

### stream is a RCRA hazardous waste.

Under the baseline scenario, if the owner/ operator generator determines that the CO 2 

### stream is not RCRA hazardous, the generator (cap ture) facility may transport the CO 2 

### to a Class VI well for sequestration. If, however, the CO 2 

### stream is a RCRA hazardous waste, this analysis assumes that the capture facility ha s three options: (i) transport the CO 2 

### stream to a UIC Class I hazardous well for seque stration, (ii) treat the CO 2 

### stream to render it non-hazardous, and send it to a Class VI well fo r sequestration, or (iii) cease CO 2 

### capture. The flow chart in Exhibit 10 shows the possible baseline practices for CO 2 

### capture facilities depending on the results of the hazardous waste determination.

Exhibit ES-2: Flow Chart of Baseline Practices of CO 2 

### Capture Facilities

Waste Determination CO 2 Capture Facility's Baseline Practice

The CO 2 stream is not RCRA hazardous Transport CO 2 to sequestration facility for injection in a Class VI well

Captured CO 2 Stream Destined for Disposal Cease capturing the CO 2 stream

The CO 2 stream is RCRA hazardous Transport the CO 2 stream to a sequestration facility for

injection in a Class I hazardous well

Treat the CO 2 stream and transport it to a sequestration

facility for injection in a Class VI well

Note : This assessment is for the geologic sequestration of CO 2 . Facilities may capture CO 2 streams for use in Class II wells for Enhanced Oil Recovery (EOR). However, EOR assessment is beyond the scope of this
p roposed rule.

procedure, TCLP) cannot be used to evaluate supercritical CO 2 streams, and, 3) the class VI regulations are better suited to ensure the management of CO 2 injectate.

### Page 9 of 145 Exhibit ES-3 below presents our high-end and low-end assumptions regarding the relative prevalence of each baseline practice for CO 2 

### capture facilities. The high-end assumes that 90% of the CO 2 

### streams are generated as RCRA hazardous waste. The low-end assumes that only 10% of the CO 2 

### streams are RCRA hazardous waste. It is important to note that these hazardous CO 2 

### percentages were formed as a range for an alytical purposes due to the lack of definitive data. Based on early literature reviews and current CO 2 

### capture technologies, the percentage of CO 2 

### streams that are expected to be clas sified as hazardou s could be low.

Exhibit ES-3: High-End and Low-End Assu mptions for the Prevalence of Hazardous Waste Determination and Baseline Practices for CO 2 

### Capture Facilities a 

### Hazardous Waste

Determination Baseline Practice Assumed Baseline Percentage of Capture Facilities a 

### High-End Low-End

Non-hazardous Send the CO 2 

### stream to a Class VI well 10% 90%

Hazardous Cease capture 30% 3.3% Send the CO 2 

### stream to a Class I hazardous well that is assumed to meet the Class VI requirements 30% 3.3%

Treat the CO 2 

### stream such that the stream is non-hazardous and send it to a Class VI well 30% 3.3%

a For purposes of this analysis EPA assumes these high-end and low-end values due to a lack of definitive data on the relative distribution of CO 2 streams’ hazardous waste designation.



### This analysis assumes that all CO 2 

### transportation is done via pipeli nes in the baseline. Other forms of CO 2 

### transportation are possible (e.g., truck, rail), but pipeline tran sport is the most efficient and commonly used method of transporting CO 2. 8



### CO 2 

### sequestration facilities, in the baseline, woul d include a mix of facilities with Class VI wells and facilities with Class I hazardous we lls that EPA has assumed also will meet the Class VI requirements. This analysis assu mes that, under the high-end baseline assumption, approximately 57 percent of the sequestr ation wells would manage non-hazardous CO 2 

### streams and treated CO 2 

### streams in Class VI wells. 9 

### The remaining wells would manage RCRA hazardous CO 2 

### streams in Class I hazardous wells.

8 Paul W. Parfomak and Peter Folger. “Carbon Dioxide (CO2) Pipelines for Carbon Sequestration: Emerging Policy Issues,” Congressional Research Service, Report for Congress, updated January 17, 2008, http://assets.opencrs.com/rpts/RL33971_20080117.pdf

. 9 The reasoning behind this assumption is explained in Section 3.2.3 of this document

### Page 10 of 145 For the low-end, our analysis assumes that approximately 97 percent of the sequestration wells would manage non-hazardous CO 2 

### streams and treated CO 2 

### streams in Class VI wells. The remaining sequestration wells would manage RCRA hazardous CO 2 

### streams in Class I hazardous waste wells. 10



### At this time, EPA has little information to conclude that CO 2 

### streams would, or would not qualify as RCRA hazardous wastes. If the Agency receives more definitive data in response to the proposed rulemaking, this anal ysis will be revised accordingly.

Post-Rule Behavior

This analysis assumes that all CO 2 

### capture facilities will clai m the proposed exclusion and send their CO 2 

### streams to Class VI wells as a result of the proposed rule, because the savings associated with claiming the exclusion would ex ceed the implementation costs. As a result, all CO 2 

### sequestration facilities ar e expected to manage CO 2 

### in permitted Class VI wells. All transportation of CO 2 

### would continue to be done by pipeline.

Costs of the Proposed Rule

In order to claim the exclusion, generators a nd well owners/operators would have to satisfy the conditions found in the proposed ru le. This includes that both CO 2 

### capture facilities and Class VI UIC wells each would be required to si gn a certification statement which they must maintain onsite and make available to EP A or the State within 72 hours of a written request. 11 

### The facilities would be re quired to renew the certifica tion statement each year in which they claim the exclusion. Facilities cl aiming the exclusion also must provide the statement to EPA or state governments upon reque st. Capture and sequestration facilities each would incur labor costs of $363 to prepare the initial certifica tion statement, $171 to renew the certification statement annually, and $3 each time they are requested to submit the certification. EPA would incur $47 in labor co sts for each certification statement that is requested and reviewed. Similarly, the States would incur $61 in labor costs for each certification statement they request and review.

10 For the low-end estimate, this anal ysis assumes that 90 percent of CO 2 capture facilities would transport nonhazardous or treated CO 2 streams to Class VI sequestration wells for injection (see Exhibit 14). Another 3.3 percent of CO 2 capture facilities would transport hazardous CO 2 streams to Class I sequestration wells for injection. This analysis as sumes that 97 percent of CO 2 sequestration wells in the baseline are Class VI wells to match the practices of CO 2 capture facilities. The remaining 3 percent of CO 2 sequestration wells in the baseline are Class I wells.
11 A single certification statement would be signed by only one facility. Each capture facility and each sequestration facility would sign its own certification statement.

### Page 11 of 145 The Agency finds that the management of these CO 2 

### streams under the proposed conditions does not present a substantial risk to human health or the envi ronment, such that additional regulation pursuant to RCRA’s hazardous wast e regulations is unnecessary. EPA does not, therefore, anticipate any ne gative externalities as a re sult of this action.

Savings and Benefits

The proposed exclusion would result in three areas of savings for CO 2 

### capture facilities: exclusion from hazardous waste determina tion, exclusion from compliance with RCRA training, planning, and reporting requirements, 12 

### and exclusion from hazardous waste treatment requirements. The analysis estimates that exclusion from hazardous waste determination would save each facility $5,500 in one-time costs and $3,000 in annual costs. CO 2 

### capture facilities whose waste would be RCRA hazardous in the baseline would save approximately $5,000 annually under the proposed ru le because they would be exempt from the RCRA training, planning, and reporting requirements. CO 2 

### capture facilities that would have treated their RCRA hazardous waste CO 2 

### stream in the baseline (i.e., in order to send it to a Class VI well) will not need to do so post-rule and would each save approximately $10.3 million in annual treatment costs.

CO 2 

### sequestration facilities also would receiv e savings due to exclusion from waste determination and RCRA training, planning, and reporting requirements. These facilities would save approximately $4,500 in one-time co sts and $1,500 in annual costs related to hazardous waste determination. They woul d save approximately $3,000 in annual costs related to RCRA training, planni ng, and reporting requirements.

In addition to the quantified savings discussed ab ove, the proposed rule also represents a step toward establishing a supporti ng regulatory framework for the future development and deployment of carbon capture sequestration (CCS) technology. The rule will help provide the regulatory certainty needed to foster industry adoption of CCS.

Annualized Net Savings

This study calculates the net costs and savings of the proposed rule over a 50 year period. Due to the high level of uncertain ty regarding the percent of CO 2 

### that may be RCRA hazardous, and the uncertainty regarding the actu al number of facilities potentially affected over the projected 50 year period, EPA’s best es timate for the impacts of the proposed rule ranges from a low-end annualized net savings of $7.3 million (7% discount rate) to the highend annualized net savings of $44.9 million (3%discount rate). 13

12 Note that facilities regulated under the Clean Air Act GHG Reporting Program (see 74 CFR 56260 and 75 FR 75060) will be required to follow the applicable reporting requirements.

13 Under the high-end estimate, the proposed rule is exp ected to result in undiscounted annualized net savings of approximately $56.6 million. Applying a 3 percent discoun t rate, the annualized net savings were found to be approximately $44.9 million while a 7 percent discount rate resulted in annualized net savings of approximately $32.0 million. Under the low-end estimate, the undiscounted annualized net savings are $9.3 million. Applying

### Page 12 of 145 Under Executive Order 12866, a rule qualifies as economically signif icant if its annual effect on the economy is $100 million or more. This proposed rule is not expected to be economically significant, as defi ned under Executive Order 12866.

ES.3 Regulatory Flexibility Analysis

EPA certifies that the rule will not have a significant adverse economic impact on a substantial number of small entities. The proposed rule relieves the regulatory burden associated with EPA’s hazardous waste regulations on CO 2 

### capture and sequestration facilities by exempting CO 2 

### captured for the purpose of ge ological sequestration (GS) in Class VI wells from the definition of hazardous waste. For each facility claiming the proposed exclusion, these savings are expected to outweigh the cost to prepare and maintain the required certification statement. The Agency estimates that this pr oposed rule could lead to net cost savings in the ra nge of $7.3 to $44.9 million annually.

a 3 percent and 7 percent discount rate, the annualized net savings were found to be approximately $8.5 million and $7.3 million, respectively.

### Page 13 of 145 1. Introduction

The U.S. Environmental Protection Agency regu lates the generation, transfer, treatment, and disposal of hazardous waste under the Resour ce Conservation and Recovery Act (RCRA) Subtitle C. The hazardous waste regulations are designed to ensure that hazardous waste is handled in a manner that protects human hea lth and the environment. Currently, carbon dioxide (CO 2 

### ) streams are not listed as RCRA hazardous wastes, but may be classified as a RCRA hazardous waste if they exhibit hazardous characteristics such as ignitability, corrosivity, reactivity, or toxi city. The Agency finds that the management of these CO 2 

### streams under the proposed conditions, which in cludes the injection in to a Class VI UIC well, does not present a substantial risk to hum an health or the environment. As such, additional regulation pursuant to RCRA’s h azardous waste regulations is unnecessary. 14 

### This report evaluates the potential imp acts of the proposed exclusion.

This introductory chapter expl ains the need for regulati on, summarizes the current and proposed rules, and discusses the regulatory and non-regulat ory alternatives that EPA considered. The second chapter characterizes th e regulated community th at will be directly affected by the proposed rule. The third chapter estimates the expected incremental costs and benefits of the proposed rule. The fourth chapter evaluates the e xpected impact of the proposed rule on small businesses. The fifth chap ter contains references to the data sources used to conduct the economic assessment descri bed in this report. Other required analyses and supporting data analyses are included as appendices.

1.1 Need for Regulation

Currently if a carbon dioxide (CO 2 

### ) stream was determined to be a hazardous waste it would be subject to the requirements of RCRA Subtitle C. However, EPA has determined that the full set of hazardous waste regulati ons is unnecessary for captured CO 2 

### streams because existing regulations governing the transport a nd injection into a UIC Class VI permitted injection well are sufficient to ensure that CO 2 

### streams can be safely managed when captured for the purpose of geologic sequestration (GS).

As discussed in EPA’s preamble to the Fe deral Requirements Under the Underground Injection Control (UIC) Progr am for Carbon Dioxide (CO 2 

### ) Geologic Sequestration (GS) Wells final rule, an improperly managed CO 2 

### GS project has the potential to endanger underground sources of drinki ng water (USDWs). While CO 2 

### by itself is not a drinking water contaminant, a CO 2 

### stream can pose a risk to USDWs as follows: 15

14 EPA has finalized requirements for the sequestration of CO 2 in Class VI underground injection wells under 40 CFR Parts 144 and 146 (Federal Requirements Under the Underground Injection Control (UIC) Program for Carbon Dioxide (CO2) Geologic Sequestration (GS) Wells) in a separate rulemaking, (75 FR 77230) December 10, 2010 (see Docket ID EPA–HQ– OW–2008–0390).
15 Jens Birkholzer, John Apps, Liange Zheng, Yingqi Zhang, Tianfu Xu, and Chin-Fsu Tsang, “Research Project on CO 2 Geological Storage and Groundwater Resources: Water Quality Effects Caused by CO 2 Intrusion into Shallow Groundwater,” Lawrence Berk eley National Laboratory, #LBNL-1251E, 2008. http://repositories.cdlib.org/lbnl/LBNL-1251E , as cited by EPA in the preamble to the Federal Requirements

### Page 14 of 145 • CO 2 

### streams may contain impurities such as hydrogen sulfide or mercury,

• CO 2 

### in the presence of water can cause leaching and mobilization of naturallyoccurring metals or other contaminants fr om geologic formations into ground water (e.g., arsenic, lead, and organic compounds), and,

• Pressures induced by injection may force na tive brines (naturally occurring salty water) into USDWs, causing degradation of water quality and affecting drinking water treatment processes.

The Class VI UIC final rule sets minimum techni cal criteria for Class VI GS wells to protect USDWs from the unique risks associated with CO 2 

### injection, including: 16



### • 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.

• Computational modeling of the area of revi ew (AoR) for GS proj ects that accounts for the physical and chemical properties of the injected CO 2 

### and is based on available site characterization, monito ring, and operational data.

• Periodic reevaluation of the AoR to incor porate monitoring and operational data and verify that the CO 2 

### is moving as predicted within the subsurface.

• Well construction using materials th at can withstand contact with CO 2 

### over the life of the GS project.

• Robust monitoring of the CO 2 

### stream, injection pressures, integrity of the injection well, ground water quality and geoche mistry, and monitoring of the CO 2 

### plume and position of the pressure fr ont throughout injection.

• Comprehensive post-injection monitoring and site care until it can be demonstrated that movement of the CO 2 

### plume and pressure front have stabilized and the injectate does not pose a risk to USDWs.

• Financial responsibility requirements to ensu re that funds will be available for all corrective action, injection well plugging, post-injection site ca re (PISC), site closure, and emergency and remedial response.

1.2 Summary of Current Rules

Captured CO 2 

### streams destined for GS may qualify as solid wastes, as defined in 40 CFR 261.2 (Definition of solid waste). RCRA hazardous wa ste is a subset of solid waste to which EPA applies special requirements. A waste is considered RCRA hazardous waste if it is specifically listed as hazardous in 40 CFR 261 S ubpart D (Lists of Hazar dous Wastes), or if it exhibits hazardous characteristics such as igni tability, corrosivity, reac tivity, or toxicity as described in 40 CFR 261 Subpart C (Cha racteristics of Hazardous Waste). CO 2 

### is not a

Under the Underground Injection Control (UIC) Program for Carbon Dioxide (CO 2 ) Geologic Sequestration (GS) Wells Final Rule, RIN 2040-AE98.
16 Preamble to the Federal Requirements Under the Underground Injection Control (UIC) Program for Carbon Dioxide (CO 2 ) Geologic Sequestration (GS) Wells Final Rule, RIN 2040-AE98.

### Page 15 of 145 listed hazardous waste but may be considered a hazardous waste if it exhibits one of the four hazardous characteristics.

EPA requires all solid waste generators, under 40 CFR 262.11 (Hazardous waste determination), to determine if their waste is h azardous. If a waste is specifically listed as hazardous in 40 CFR 261 Subpart D (Lists of Hazardous Wastes), or specifically excluded under 40 CFR 261.4 (Exclusions), the generator can quickly make this determination by reviewing the listed wastes and the list of exclusions. Because CO 2 

### is neither a listed waste nor excluded as a hazardous wa ste, generators would be requi red to determine if their CO 2 

### stream is a RCRA hazardous waste either by testing its characteristics using methods specified in the RCRA regulati ons, or by applying knowledge of the materials and processes that generated the CO 2 

### stream.

If the captured CO 2 

### stream is a solid waste and determined to be a RCRA hazardous waste (and assuming it is to be discarded, such as th rough geologic sequestration), the generator is subject to the various hazardous waste gene rator standards in 40 CFR 262 (Standards Applicable to Generators of H azardous Waste). Hazardous waste CO 2 

### streams that are transported to an injection facility would be required to be managed in a Class I UIC hazardous waste well that is permitted to accept RCRA hazardous waste. A RCRA hazardous waste CO 2 

### stream could not be injected into a well that is permitted as a Class VI well under the UIC Class VI regulations. The ow ners and operators of Class I hazardous waste wells are subject to the hazardous waste management requirements in 40 CFR 264 (Standards for Owners and Operators of Hazardous Waste Treatment, Storage, and Disposal Facilities) and 265 (Interim Status Standards for Owners and Operators of Hazardous Waste Treatment, Storage, and Disposal Facilities) if they store or treat hazardous waste prior to injection; the UIC Class I hazardous well itse lf, which is permitted under the Safe Drinking Water Act (SDWA) is subject to RCRA permit- by-rule (see 270.60(b)). In addition, these Class I hazardous waste well owne rs and operators would have to build their sequestration units to meet EPA’s requirements for a Class VI UIC well. 17



### If the CO 2 

### stream is not a RCRA hazardous waste, th e generator would not be subject to the hazardous waste generator standards, and could transport the waste to a Class VI well for injection. The Class VI well would be require d to meet the Class VI UIC requirements, which in some regards are similar to the requ irements for hazardous waste wells permitted under UIC Class I, but are ge ared specifically toward CO 2 

### sequestration. 18

17 Permit writers also may require the RCRA hazardous waste CO 2 injection well to meet the Class VI UIC requirements as well as the Class I hazardous UIC requ irements; however, th ere is no specific UIC regulation that would require permit writers to apply both the Class I hazardous and Cla ss VI standards to a RCRA hazardous waste CO 2 injection well.
18 Certain U.S. Department of Energy CO 2 injection demonstration projects have been permitted under the UIC Class V experimental technology well program, while other demonstration projects have been permitted under the UIC Class I non-hazardous waste well program.

### Page 16 of 145 CO 2 

### streams captured for the purpos e of injection are typically transported by pipeline and are subject to the Department of Transporta tion (DOT) Pipeline and Hazardous Materials Safety Administration (PHMSA) regulations in 49 CFR 195 (Transportation of Hazardous Liquids by Pipeline) through 199 (Drug and Alcohol Testing). Pipelines ar e not classified as modes of transportation under RCRA and therefor e pipeline transportatio n would be subject to the same DOT requirements regardless of a CO 2 

### stream’s RCRA status. If a RCRA hazardous waste CO 2 

### stream was to be transported by other means, such as truck or rail, the transporter would be subject to EPA’s standa rds for transporters of hazardous waste in 40 CFR 263 (Standards Applicable to Transporte rs of Hazardous Waste), as well as the applicable PHMSA Hazardous Materials Re gulations in 49 CFR Parts 171 (General Information, Regulations, and Definitions) through 180 (Continuing Qualification and Maintenance of Packagings)

.

1.3 Summary of Proposed Changes

Under the proposed rule, carbon dioxide stream s that are captured and transported for purposes of injection into an underground inject ion well subject to the requirements for Class VI Underground Injection Contro l wells, including the require ments in 40 CFR Parts 144 and 146 of the Underground Injection Control Program of the Safe Drinking Water Act, is not a hazardous waste, provided selected conditions are met. 19 

### Class VI wells injecting excluded CO 2 

### would therefore not be subject to EPA’ s RCRA hazardous waste requirements. The exclusion would apply to captured CO 2 

### streams only and would not apply to any hazardous wastes that are mixed with or co-injected with CO 2 

### streams.

Owners and operators of CO 2 

### capture facilities and seque stration wells claiming the exclusion would be required to sign and annually renew a certif ication statement stating that the CO 2 

### stream for which they are claiming th e exclusion meets the conditions of the exclusion and is being inject ed into a well subject to th e Class VI UIC requirements.

1.4 Analysis of Alternatives Considere d (Regulatory and Non-Regulatory)

In addition to the proposed rule, EPA considered the following alternatives:

• 

### No action – Under this alternative CO 2 

### streams captured for GS would not be excluded from the definition of hazardous waste. CO 2 

### streams determined to be hazardous would be subject to EPA’s RCR A hazardous waste requirements. EPA did not select this option because it would provide generally equivalent protection to human health and the environment as the proposal, while maintaining an unnecessary regulatory burden on CO 2 

### capture and sequestration facilities to comply with the hazardous waste requirements

19 See: §261.4 Exclusions (h) – Carbon Dioxide Stream Injected for Geologic Sequestration

### Page 17 of 145 • 

### Non-regulatory alternatives – Although non-regulatory approaches such as educational outreach programs could in crease awareness of the safety and effectiveness of CO 2 

### sequestration, but would not eff ectively reduce the unnecessary regulatory burden placed on CO 2 

### capture and sequestration faci lities to comply with the hazardous waste requirements under the current regula tory framework.

2. Characterization of the Regulated Community

The entities that may be directly a ffected by the proposed rule include CO 2 

### capture facilities, transporters, and sequestration facilities. This section identifies the regulated entities and discusses their characteristics.

2.1 CO 2 

### Capture Facilities

Many electric power plants and othe r industrial facilities generate CO 2 

### as a byproduct of their operations. These facilities typically release that CO 2 

### into the environment. CO 2 

### capture facilities are entities that collect their CO 2 

### byproducts and manage them in a manner other than releasing them into the atmosphere.

The total number of CO 2 

### capture facilities potentially affect ed by this action, as proposed, is uncertain. As a result, we have developed two alternativ e estimates for the number of affected facilities. Our high-end estimate identifies 27 CO 2 

### capture facilities that may be affected by the proposed rule. Our low-end es timate considers only 13 capture facilities. These estimates are discussed below.

Number of CO 2 

### Capture Facilities – High-End Estimate:

EPA estimates that a maximum of 27 CO 2 

### capture facilities could be affected by the proposed rule. This estimate includes ten f acilities that currently capture CO 2 

### , along with 17 facilities expected to begin CO 2 

### capture in the future. Of these seventeen, there are 14 commercial projects, two non-commercial DOE pilot projec ts, and one private/federal partnership project. The data sources that EPA used to estimate the number of current and planned CO 2 

### capture facilities are presen ted below in Sections 2.1.1 a nd 2.1.2 respectively. Section 2.1.3 summarizes the high-end estimate number of capture facilities by type of project, industry sector, and expected first year of CO 2 

### sequestration.

### Page 18 of 145 2.1.1 Current CO 2 

### Capture Facilities

Ten facilities are currently capturing CO 2 

### from chemical production or combustion processes for the purpose of injection in a Class II UIC we ll for enhanced oil recovery (EOR). These ten facilities generated and captured approximately 11 million metric tons of CO 2 

### in 2008. 20 

### Exhibit 1 lists these existing carbon capture fac ilities and their industr y classification under the North American Industry Classification Syst em (NAICS). As long as these facilities continue their current practices , they would not be affected by the proposed rule. However, at some point in the future, the existing EOR sequestration facilities will likely run out of producible oil, and these existing CO 2 

### capture facilities will have to choose a different management method for their captured CO 2 

### streams. 21 

### This analysis assumes that this transition will occur in the year 2030 for nine of the ten current CO 2 

### capture facilities. The analysis assumes that the Coffeyville Fertili zer Plant will begin sequestration in 2034. 22



### Exhibit 1: U.S. Facilities Currently Capturing CO 2 

### Streams a



### Facility State Description Assumed First Year of Sequestration
b 

### NAICS NAICS Description

Val Verde Gas - Pikes Peak Plant TX Processing of high CO 2 

### gas prod. 2030 211111 Oil and Gas Extraction Val Verde Gas - Grey Ranch Plant TX Processing of high CO 2 

### gas prod. 2030 211111 Oil and Gas Extraction

Val Verde Gas - Puckett Plant TX Processing of high CO 2 

### gas prod. 2030 211111 Oil and Gas Extraction Val Verde Gas - Terrell Plant TX Processing of high CO 2 

### gas prod. 2030 211111 Oil and Gas Extraction Val Verde Gas - Mitchell Plant TX Processing of high CO 2 

### gas prod. 2030 211111 Oil and Gas Extraction La Barge Gas Plant WY Processing of high CO 2 

### gas prod. 2030 211111 Oil and Gas Extraction Enid Ammonia Fertilizer Plant OK Fertilizer plant CO 2 

### production 2030 325311 Nitrogenous Fertilizer Manufacturing Coffeyville Ammonia Fertilizer Plant KS Fertilizer plant CO 2 

### production 2034 325311 Nitrogenous Fertilizer Manufacturing

20 EPA, “Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2008,” April 15, 2010, Table 3-47: Potential Emissions from CO 2 Capture and Transport, p. 3-53, http://www.epa.gov/climatechange/ emissions/downloads10/US-GHG-Inventory-2010_Report.pdf

. 21 We recognize that if there is no climate legislation with in the projected time frame that the economic driver for Class VI storage may not fully occur. It is possible that these projects may store CO 2 in domes as a staging point for future EOR, EGR, and working fluids for fracturing tight gas sands and shale. Under this model it is possible that some or none of these projects would be subject to this rule or the Class VI rule.
22 See footnote b in Exhibit 1.

### Page 19 of 145 Facility State Description Assumed First Year of Sequestration
b 

### NAICS NAICS Description

Antrim Gas Plant MI Processing of high CO 2 

### gas prod. 2030 211111 Oil and Gas Extraction Great Plains Coal Gasification ND Synthetic Natural Gas Plant 2030 221210 Natural Gas Distribution

a Sources: Department of Energy, National Energy Technology Laboratory, Carbon Capture and Storage Database, http://www.netl.doe.gov/technologies/ carbon_seq/database/index.html , and, Massachusetts Institute of Technology, Largescale Power Plant CCS Projects Wo rldwide. Power Plant Carb on Dioxide Capture and Storage Projects, http://sequestration.mit.edu/tools/projects/index.html.
b EPA Office of Water, “Cost Analysis for the Federal Requirements Under the Underground Injection Control Program for Carbon Dioxide Geologic Sequestration Wells (Final GS Rule),” EPA identified the Coffeyville Fertilizer Plant as a commercial project that would tran sition from EOR to sequestration in 2034. EPA did not identify sequestration start dates for the other current CO 2 capture facilities as a part of that research, but it did assume that EOR projects transitioning to GS would conduct EOR for 20 years before transitioning to GS (see cost analysis for the Final GS Rule). This analysis of the CO 2 exclusion assumes that the existing EOR projects for which more specific information is not available will tr ansition to GS 20 years from the present date (i.e., 2030).



### The existing CO 2 

### capture facilities and th eir parent companies vary in size. For example, the Enid Ammonia Fertilizer Plan t is operated by Koch Industries, Inc., which has over 70,000 employees. 23 

### The Coffeyville Fertilizer Plant (C offeyville Resources LLC) employs 250 to 499 individuals. 24 

### The Great Plains Coal Gasification (Dakota Gasification CO) facility has between 500 and 999 employees. 25



### 2.1.2 Planned CO 2 

### Capture Facilities

EPA has identified an additional 31 planned CO 2 

### capture facilities. Th ese facilities are listed in Exhibit 2. Commercial CO 2 

### capture projects represent 28 of these planned capture projects. 26 

### Although all of these projects are pla nned, some of them may be cancelled or delayed due to approval and funding issues. Th is high estimate analysis considers only fourteen planned commercial projects that EPA has deemed most likely to proceed. However, the other planned projects are included in Exhibit 2 for reference only. 27 

### In

23 Koch Industries, 2009, http://www.kochind. com/files/070709KIILe adershipKansas.pdf.
24 Manta, “Coffeyville Resources LLC,” http://w ww.manta.com/c/mmgvkjp/coffeyville-resources-llc
25 Manta, “Dakota Gasification Co,” http://www .manta.com/c/mmlgj74/dakota-gasification-co
26 These “commercial” CO 2 capture projects include some projects th at were partially funded as DOE pilot projects.
27 As a part of the research that EPA Office of Water conducted to determine the baseline for the “Cost Analysis for the Federal Requirements Under the Underground Inj ection Control Program for Carbon Dioxide Geologic Sequestration Wells (Final GS Rule),” EPA reviewed a ll of the proposed projects and identified 15 commercial projects that were likely to proceed. One of those 15 projects, Coffeyville Fe rtilizer Plant, is already conducting CO 2 capture and is accounted for in Exhibit 1, above. Therefore Exhibit 2 lists only 14 planned commercial capture projects included in the analysis.

### Page 20 of 145 addition to these planned commercial project s, there are two ot her non-commercial CO 2 

### capture pilot projects plus one other private/ federal partnership. EPA expects all three of these additional projects to be constructed, and these projects are in cluded in Exhibit 2.

Most of the planned commercial and DOE pilot CO 2 

### capture facilities are existing or proposed fossil fuel-fired power plants ( NAICS 221112). The one other planned capture facility considered in this analysis is a DOE pilot project involv ing an ethyl alcohol manufacturing plant (NAICS 325193).

Exhibit 2: Planned CO 2 

### Capture and Sequestration Projects a



### Project State Company Assumed First Year of Sequestration b 

### NAICS Industry Sector

Planned Commercial Projects Included in the Analysis

AEP Alstom Mountaineer (Ph.2) (DOE sponsored Demo project) 

### WV AEP and Alstom 2012 221112 Fossil Fuel Electric Power Generation

AEP Alstom Northeastern OK AEP and Alstom 2032 221112 Fossil Fuel Electric Power Generation

Edwardsport IN Duke Energy 2012 221112 Fossil Fuel Electric Power Generation

Great Bend OH AEP 2034 221112 Fossil Fuel Electric Power Generation

Hydrogen Energy HECA CA Hydrogen Energy (BP and Rio Tinto) 2034 221112 Fossil Fuel Electric Power Generation

Kemper County MS Mississippi Power; ( sub. of Southern) 2034 221112 Fossil Fuel Electric Power Generation

Lima OH Global Energy; Lima Energy 2031 221112 Fossil Fuel Electric Power Generation

Mesaba MN Excelsior Energy 2034 221112 Fossil Fuel Electric Power Generation

Tenasca Sweetwater/Trailblaze TX Tenasca Inc., Arch Coal 2035 221112 Fossil Fuel Electric Power Generation

### Page 21 of 145 Project State Company Assumed First Year of Sequestration b 

### NAICS Industry Sector

Tenasca Taylorville Energy IL Tenasca Inc. 2035 221112 Fossil Fuel Electric Power Generation Texas Clean Energy Project TX Summit Power 2032 221112 Fossil Fuel Electric Power Generation

WA Parish, Sugarland TX NRG Energy; Fluor, Ramgen/Dres

ser 2032 221112 Fossil Fuel Electric Power Generation

Wallula Energy Res. Center c 

### WA Wallula Resource Recovery 2013 221112 Fossil Fuel Electric Power Generation

Worsham-Steed (ZENG) TX CO 2 

### Global and Falcon Gas Storage 2032 221112 Fossil Fuel Electric Power Generation 

### Non-commercial DOE Pilot Projects

Cincinnati Arch Mt. Simon Saline Reservoir d 

### OH Andersons Marathon 2010 325193 Ethyl Alcohol Manufacturing San Joaquin Basin, CA Saline Formation e 

### CA Clean Energy Systems 2012 221112 Fossil Fuel Electric Power Generation 

### FutureGen - Private/Federal Partnership

Mt. Simon Saline Reservoir IL FutureGen Alliance 2017 221112 Fossil Fuel Electric Power Generation 

### Planned Commercial Projects No t Included in this Analysis f



### ADM Ethanol Plant CO 2 

### Capture IL ADM 2013 325193 Ethyl Alcohol Manufacturing

Antelope Valley ND Basin Electric, HTC Pure Energy N/A 221112 Fossil Fuel Electric Power Generation

Battelle Boise White Paper Mill WA Battelle and Boise Inc. N/A 322121 Paper Mills

C6 Resources CA C6 Resources (Shell affiliate) N/A 324110 Petroleum Refineries

### Page 22 of 145 Project State Company Assumed First Year of Sequestration b 

### NAICS Industry Sector

Cash Creek KY Erora Group N/A 221112 Fossil Fuel Electric Power Generation Cemex Odessa Project TX Cemex N/A 327310 Cement Manufacturing ConocoPhillips Sweeny Power plant TX Conoco Phillips N/A 221112 Fossil Fuel Electric Power Generation Great Lakes Energy Research MI M&M Energy N/A 221112 Fossil Fuel Electric Power Generation

Leucadia Energy Lake Charles LA Leucadia, Denbury N/A 324199 All Other Petroleum and Coal Products Manufacturing

Leucadia Energy Moss Point MS MS Leucadia, Denbury N/A 324199 All Other Petroleum and Coal Products Manufacturing Port Arthur Steam Methane Reformers TX Air Products, Denbury N/A 325120 Industrial Gas Manufacturing Praxair Texas City Refinery TX Praxair, BP Products N/A 324110 Petroleum Refineries SCS Energy PurGen One NJ SCS Energy N/A 221112 Fossil Fuel Electric Power Generation

Wolverine Circ. Fluidized Bed Plant MI Wolverine Power Supply Cooperative N/A 221112 Fossil Fuel Electric Power Generation

a Department of Energy, National Energy Technology Laboratory, Carbon Capture and Storage Database, http://www.netl.doe.gov/technologies/ carbon_seq/database/index.html , and Massachusetts Institute of Technology, Largescale Power Plant CCS Projects Worl dwide. Power Plant Carbon Dioxide Capture and Storage Projects, http://sequestration.mit.edu/tools/projects/index.html.
b The assumed first year of sequestratio n for each facility is based on the re search that the EPA Office of Water conducted to determine th e baseline for the “Cost Analysis for the Federal Requirements Under the Underground Injection Control Program for Carbon Dioxide Geologic Sequestration Wells (Final GS Rule).” No sequestration start dates were determined for the projects that are no t expected to proceed.

c Information received after the completion of this analysis indicates that this project is not going forward. It was not awarded a Phase II DOE award.
d Information received after the comple tion of this analysis indicates that this project has been cancelled and moved to Michigan.

e Information received after the comple tion of this analysis indicates that this project has been cancelled.

f Information received after the completi on of this analysis indicates that many of these projects have been cancelled or did not receive fu nding from DOE for the next phase of their projects.

### Page 23 of 145 2.1.3 Summary of Current and Planned CO 2 

### Capture Facilities Considered in this Analysis

Exhibit 3 summarizes the numbe r of current and proposed CO 2 

### capture facilities considered in the high-end estimate analys is, by type of project.

Exhibit 3: Number of Current and Planned CO 2 

### Capture Projects Identified and Considered in the High-End Estimate Analysis Type of Project Number of Facilities Considered in the Analysis 

### Current Capture Plants 10 Planned Commercial Projects 14 Planned Non-commercial DOE Pilot Projects 2 a 

### FutureGen Private/Federal Partnership 1 Total 27

a Information received after the completi on of this analysis indicates that these projects have been cancelled.



### Exhibit 4 summarizes the numbe r of current and proposed CO 2 

### capture facilities considered in this high-end estimate anal ysis, by industry sector.

Exhibit 4: Number of Current and Planned CO 2 

### Capture Facilities Considered in this High-End Estimate Analysis, by Industry Sector NAICS NAICS Industry Sect or Number of Facilities 211111 Oil and Gas Extraction 7 221112 Fossil Fuel Electric Power Generation 16 221210 Natural Gas Distribution 1 325193 Ethyl Alcohol Manufacturing 1 325311 Nitrogenous Fertilizer Manufacturing 2

Exhibit 5 presents the high-end estimat e number of current and proposed CO 2 

### capture facilities expected to begin and practice sequestration of their CO 2 

### streams each year.

Exhibit 5: Number of Current and Planned CO 2 

### Capture Facilities Considered in this Analysis Expected to Begin and Practice Sequestration by Year

Year Number of CO 2 Facilities Beginning Sequestration of their CO 2 Streams Cumulative Number of CO 2 Facilities Practicing Sequestration of their CO 2 Streams 2010 - 2012 4 4 2013 1 5 2014 0 5 2015 0 5 2016 0 5 2017 1 6 2018 0 6 2019 0 6 2020 0 6 2021 0 6

### Page 24 of 145 Year Number of CO 2 Facilities Beginning Sequestration of their CO 2 Streams Cumulative Number of CO 2 Facilities Practicing Sequestration of their CO 2 Streams 2022 0 6 2023 0 6 2024 0 6 2025 0 6 2026 0 6 2027 0 6 2028 0 6 2029 0 6 2030 9 15 2031 1 16 2032 4 20 2033 0 20 2034 5 25 2035 2 27 2036 0 27 Post-2036 0 27

Total 27 27



### Number of CO 2 

### Capture Facilities – Low-End Estimate:

Our low-end estimate considers only 13 CO 2 

### capture facilities. This includes ten existing capture facilities, two capture projects associated with name d DOE pilot projects, and one capture facility associated with the FutureGen federal/private partnership.

This low-end estimate for the number of affected CO 2 

### capture facilities assumes the following:

• only facilities associated with existing capture pr ojects are affected, and;

• only projects associated with named DOE pilot projects and federal/private partnerships will be affected.

All other assumptions are consis tent with the high-end estimate for the number of affected CO 2 

### capture facilities.

Exhibit 6 presents the low-end estimate for the number of CO 2 

### capture facilities expected to begin activities in each year under the proposed rule.

Exhibit 6: Low-E nd Estimate of the CO 2 

### Capture Facilities Assumed to Begin and Practice Sequest ration Activities, by Year
Year Annual Number of CO 2 Capture Facilities Total Number of CO 2 Capture Facilities 2010 - 2012 2 2 2013 0 2 2014 0 2 2015 0 2 2016 0 2

### Page 25 of 145 Year Annual Number of CO 2 Capture Facilities Total Number of CO 2 Capture Facilities 2017 1 3 2018 0 3 2019 0 3 2020 0 3 2021 0 3 2022 0 3 2023 0 3 2024 0 3 2025 0 3 2026 0 3 2027 0 3 2028 0 3 2029 0 3 2030 9 12 2031 0 12 2032 0 12 2033 0 12 2034 1 13 2035 0 13 2036 0 13 Post-2036 0 13

Total 13 13



### 2.2 CO 2 

### Transporters

Captured CO 2 

### is typically transported by pipeline. As of 2008 there were 30 operating CO 2 

### pipelines, operated by 29 separate entities. 28 

### Several other CO 2 

### pipeline operators reported zero miles of pipeline in operation in 2008 but did report miles of pipeline in operation for previous calendar years, wh ich may indicate that the CO 2 

### pipeline is still in place but was idle and did not transport any CO 2 

### in 2008. Therefore, the total number of CO 2 

### pipelines and pipeline operators considered in this anal ysis may exceed the number reported to be operating in 2008. 29 

### This analysis only considers the 29 operators of pipelines reported to be operating in 2008. Exhibit 7 lists these active CO 2 

### pipeline operators. The exhibit also presents the miles of pipeline operated and barrel-miles 30 

### of CO 2 

### transported in 2008 by each operator.

28 Department of Transportation, Pipeline and Hazar dous Materials Safety Administration (PHMSA), 2008 Hazardous Liquids Annual Dat a http://www.phmsa.dot.gov/staticfiles/ PHMSA/DownloadableFiles/Files/ LIQANN08.zip

. 29 The CRS Report for Congress indicates there are approximately 3,600 miles of dedicated CO 2 pipelines, carrying about 50 million metric tons of CO 2 per year, primarily for EOR activities in the oil and gas industry. (CRS Report for Congress. Regulation of Carbon Dioxide (CO 2 ) Sequestration Pipelines: Jurisdictional Issues. Adam Vann and Paul W. Parfomak. April 15, 2008)
30 A standard barrel contains 42 gallons.

### Page 26 of 145 Pipeline transportation of captured CO 2 

### falls under the “all other pipe line transportation” (i.e., transportation of substances other than crude oil, natural gas and refined petroleum products) industry (NAICS 486990). 31 

### These CO 2 

### pipelines appear to be generally operated by large companies. For example, ExxonMobil Produc tion Corp brings in between $50 and $100 million in annual revenue, and is a subsidiary of the much larger ExxonMobil Corporation. 32 

### EPA has not identified any comme rcial entities that transport CO 2 

### by alternative methods, such as truck or rail that would be subject to the standards for hazardous waste transporters. Some U.S. DOE demonstration proj ects have received shipments of CO 2 

### by truck, however, these have generally been short-term dem onstration projects involving relatively small quantities of CO 2 

### , Therefore, this analysis assumes that all transportation of CO 2 

### is, and will continue to be c onducted by pipeline.

Exhibit 7: CO 2 

### Pipeline Operators in the U.S. as of 2008

CO 2 

### Pipeline Operator Name Miles of CO 2 

### Pipeline Operated Barrel Miles of CO 2 

### transported 

### Amerada Hess Co., N. Jersey Public Svc Pipeline 23 0 Anadarko Petroleum Corp 155 14,167,044 Apache Corporation 42 288 BMC Holdings, Inc. 5 154,539 BOC Gases 7 370,392 Bravo Pipeline System 880 19,194,374 Buckeye Gulf Coast Pipeline LP 3 27,281 Chaparral Energy, LLC 105 846,088 Chevron Pipe Line Co 129 2,339,079 Dakota Gasification Company 167 16,568,466 Denbury Onshore, LLC 422 11,171 Devon Gas Services, LP 46 1,997,482 Energen Resources Corp. 2 2,884,179 Enmark Energy, Inc 70 13,786 ExxonMobil Refining And Supply Company 23 0 ExxonMobil Production Company 185 54,256,459 Genesis Co 2 

### Pipeline, L.P. 9 7,130,397 Genesis Free State Pipeline, LLC 91 9,079,929 Hess Corporation 32 19,325 Kinder Morgan CO 2 

### Co. LP 1,207 34,250,124,275 Merit Energy Company (2 Pipelines) 138 4,343,448 Occidental Permian Ltd 8 189,000 PCS Nitrogen Fertilizer LP 1 669,939

31 Some of the entities conducting pipeline transportation of CO 2 also may fall into other industrial source categories (e.g., oil and gas extraction), but this an alysis only considers NAIC S 486990 because it is the industry category most relevant to the activity affected by the proposed rule.
32 Manta, “Exxon Mobil Corp,” http://www.manta.com/c/mmcckrf/exxon-mobil-corp

### Page 27 of 145 CO 2 

### Pipeline Operator Name Miles of CO 2 

### Pipeline Operated Barrel Miles of CO 2 

### transported 

### Sandridge CO 2 

### , LLC 143 5,578,863 Resolute Natural Resources Company 28 14,085,537 The George R. Brown Partnership, L.P. 8 2,371,011 Transpetco Transport Co. 121 171,933 Trinity CO 2 

### LLC 137 10,426,899 XTO Energy Inc 17 3,218,730 Total 4,203 34,420,239,914
Source : Department of Transportation, Pipeline and Hazardous Materials Safety Administration (PHMSA), 2008 Hazardous Liquids Annual Dat a http://www.phmsa.dot.gov/staticfiles/ PHMSA/DownloadableFiles/Files/ LIQANN08.zip

. 

### 2.3 CO 2 

### Sequestration Facilities

CO 2 

### sequestration facility owners an d operators are defined for the purposes of this analysis as facilities that will receive captured CO 2 

### streams and inject them into UIC wells for the purposes of sequestration.
As with capture facilities, the total number of CO 2 

### sequestration facilities potentially affected by this action, as proposed, is uncertain. As a result, we have developed two alternative estimates for the number of affected facili ties. Our high-end estimate identifies 29 CO 2 

### sequestration facilities that may be affected by the proposed rule. Our low-end estimate considers only six sequestra tion facilities. These estim ates are discussed below.

Number of CO 2 

### Sequestration Facilities – High-End Estimate:
EPA estimates that, at a maximum, 29 planned sequestration facilities may be affected by the proposed rule. This estimate is consistent w ith EPA’s current assumptions for the UIC Class VI program project baseline and cost an alysis in developing the Class VI rule. 33 

### The Class VI rule cost analysis assumes that there is no Climate Change legislation, and the baseline is based upon the most likely scenario under curr ent laws and regulations. This EPA project forecast is a mix of actual operating or planned sites and hypothetical sites.
This high-end estimate includes 15 planned commercial CO 2 

### sequestration projects and 14 planned projects funded by DOE. The 15 planned commercial projects that are expected to be constructed are anticipated to include 12 enha nced oil recovery projec ts that transition to sequestration in the long term and 3 saline reservoir seque stration projects. 34

33 Based on the research that EPA Office of Water conducted to determine the baseline for the “Cost Analysis for the Federal Requirements Under the Underground Inj ection Control Program for Carbon Dioxide Geologic Sequestration Wells (Final GS Rule),”
34 DOE sequestration project database website http://www.netl.doe.gov/technologies /carbon_seq/database/index.html

### Page 28 of 145 Class VI UIC wells fall under the other non-hazardous waste treatment and disposal (i.e., management by methods other than landfill, co mbustion, and incineration) industry (NAICS 562219). Because these Class VI well facili ties are not currently operational, the characteristics of these facilities are uncertain.

Exhibit 8 summarizes the high-end estimate fo r the number of sequest ration facilities, by type. These counts are based on the resear ch that EPA Office of Water conducted to determine the baseline for the “Cost Analys is for the Federal Requirements Under the Underground Injection Contro l Program for Carbon Dioxide Geologic Sequestration Wells (Final GS Rule).” As indicated, only 6 of the 29 projects are based upon known locations. The remaining 23 projects are unspecified lo cation projects that EPA expects to be constructed in the future. EPA expects th at 8 additional DOE funded projects will be constructed, with most being in saline reservoirs. EPA also expects that the 15 planned commercial capture facilities considered in this anal ysis will each have its own sequestration site and that most of th ese sites will conduct Enhanced Oil Recovery (EOR).
Exhibit 8: Summary of the High-End Estimate for the Number of Sequestration Facilities Considered in this Analysis Category Count a 

### DOE Projects - Named Projects/Specific Locations Followups at Existing DOE Pilots 5 FutureGen, Matoon, IL 1 Subtotal: 6 DOE Projects - General Unspecified Projects Small Saline Pilots 2 Commercial Scale Saline 5 Commercial Scale EOR 1 Subtotal: 8 Non-DOE (Commercial) Projects Commercial Saline 3 Commercial EOR Converting to GS 12 Subtotal 15 Total 29

a These counts are based on the research that EPA Office of Water conducted to determine the baseline for the “Cost Analysis for the Federal Requirements Under the Underground Injection Control Program for Carbon Dioxide Geologic Sequestration Wells (Final GS Rule).”



### Exhibit 9 lists the DOE Phase II I sequestration demonstration pr ojects and highlights the six projects included in the projec t counts above. The Phase II I of the DOE pr oject is the demonstration phase in wh ich a large volume of CO 2 

### is injected, typically over several years.

### Page 29 of 145 Exhibit 9: DOE Phase III Sequest ration Demonstration Projects a



### Regional Organization Project Name Included in This Analysis 

### MGSC Illinois Basin Mt. Simon Saline Reservoir (Decatur, IL) yes
PCOR Williston Basin EOR Sequestration; ND yes PCOR Fort Nelson, BC Sandstone Saline Reservoir (Brit. Columbia) no
Big Sky Green River Basin Nugget Sand Saline Reservoir, Moxa Arch, Western Wyoming yes

SWCARB Saline Reservoirs, Farnham Dome, Price, UT and J through PR Sands); Uinta Basin no
SECARB Phase 1: Athropogenic CO2 in Tuscaloosa Citronelle Oilfield EOR, Mobile AL no

SECARB Phase 2: Mississ ippi Tuscaloosa Massive Saline Reservoir; SW Mississippi (Cranfield, MS) no

MRCSP Cincinnati Arch Mt. Simon Saline Reservoir; Greenville, OH yes
WESTCARB San Joaquin Basi n, CA Saline Formation; Olcese and Vedder Sands yes

FutureGen Project Mt. Simon Saline Reservoir (Matoon, IL) yes

a This list is based on the research that EP A Office of Water conducted to determine the baseline for the “Cost Analysis for the Federal Requirements Under the Underground Injection Control Program for Carbon Dioxide Geologic Sequestration Wells (Final GS Rule).”



### Exhibit 10 presents the high-end estimate for the number of CO 2 

### sequestration facilities expected to begin operation and to continue to operate each year.

Exhibit 10: High-End Estimate for the CO 2 

### Facilities Expected to Begin Sequestration, by Year

Year Number of Sequestration Facilities Beginning Operation Cumulative Number of Sequestration Facilities in Operation 2010 - 2012 2 2 2013 1 3 2014 1 4 2015 0 4 2016 2 6 2017 10 16 2018 1 17 2019 0 17 2020 0 17 2021 0 17 2022 0 17

### Page 30 of 145 Year Number of Sequestration Facilities Beginning Operation Cumulative Number of Sequestration Facilities in Operation 2023 0 17 2024 0 17 2025 0 17 2026 0 17 2027 0 17 2028 0 17 2029 0 17 2030 0 17 2031 1 18 2032 4 22 2033 0 22 2034 5 27 2035 2 29 2036 0 29 Post-2036 0 29

Total 29 29



### Number of CO 2 

### Sequestration Facilities – Low-End Estimate:
Our low-end estimate considers only six CO 2 

### sequestration facilities . This includes five sequestration projects associated with name d DOE pilot projects and one sequestration facility associated with the Futu reGen federal/priva te partnership.

As with capture facilities, this low-end estimate for the number of affected CO 2 

### capture facilities assumes that only existing projects are affected, and only pr ojects associated with named DOE pilot projects and fe deral/private partnerships w ill be affected. All other assumptions are consistent with the high-e nd estimate for the number of affected CO 2 

### sequestration facilities.

Exhibit 11 below presents the low-end estimate for the number of CO 2 

### sequestration facilities expected to begin and practice sequestration activities in each year under the proposed rule.

Exhibit 11: Low-E nd Estimate of the CO 2 

### Facilities Assumed to Begin and Practice Sequest ration Activities, by Year

Year Number of Sequestration Facilities Beginning Operation Total Number of Sequestration Facilities in Operation 2010 - 2012 0 0 2013 0 0 2014 0 0 2015 0 0 2016 0 0 2017 6 6 2018 0 6 2019 0 6 2020 0 6 2021 0 6

### Page 31 of 145 Year Number of Sequestration Facilities Beginning Operation Total Number of Sequestration Facilities in Operation 2022 0 6 2023 0 6 2024 0 6 2025 0 6 2026 0 6 2027 0 6 2028 0 6 2029 0 6 2030 0 6 2031 0 6 2032 0 6 2033 0 6 2034 0 6 2035 0 6 2036 0 6 Post-2036 0 6

Total 6 6



### 3. Analysis of the Incremental Costs a nd Benefits of the Proposed Rule

This section analyzes the exp ected costs and benefits of th e proposed rule. Section 3.1 describes the analytical appr oach and methodology. Section 3.2 and Section 3.3 discuss the expected regulatory compliance be havior in the baseline (i.e., in the absence of the proposed rule) and expected regulatory compliance behavi or under the proposed rules, respectively. Sections 3.4 and 3.5 present the expected costs and benefits of the proposed rule. Finally, Section 3.6 summarizes the conclusions of the analysis.

3.1 Analytical Approach/Methodology

This analysis estimates the incremental costs an d benefits of the proposed rule (i.e., the costs and benefits that arise as a cons equence of the proposed rule). The first step in this approach is to use available information and make assumptions when necessary to lay out the “baseline” behavior that affected entities would be expected to display in the absence of the proposed rule. Because the baseline assume s no regulatory change, it has no associated incremental cost. Therefore, the baseline serves as a re ference point from which the incremental costs and benefits of th e proposed rule can be measured.

The next step is to evaluate how the affected entities would be likely to change their behavior under the proposed rule. Once the baseline and pos t-rule behavior have been established, the

### Page 32 of 145 analysis then estimates the incremental costs an d benefits of the proposed rule relative to the baseline over a 50-year period. 35



### 3.2 Baseline Practices

Depending on whether or not their captured CO 2 

### is RCRA hazardous, and other site-specific factors, generators of hazardous waste may enga ge in different baseline practices to manage their captured CO 2 

### streams. CO 2 

### sequestration facilities may base their own practices on generators’ behavior. This section discusse s the hazardous waste determination process and then presents the possible baseline practices for CO 2 

### capture and sequestra tion facilities. This section does not include a detailed discussion of baseline transportation practices. The most efficient and commonly us ed method of transporting CO 2 

### is by pipeline. 36 

### Although other forms of CO 2 

### transportation are possible (e.g., truck, ra il), this analysis assumes that all CO 2 

### transportation is done via pipelines both in the baseline and unde r the proposed rule.

3.2.1 Hazardous Waste Determination Process for CO 2 

### Capture Facilities

In the absence of the proposed rule, generators of captured CO 2 

### streams must determine whether their captured CO 2 

### stream destine for geological sequestration is RCRA hazardous waste or non-hazardous waste. A captured CO 2 

### stream may be a RCRA hazardous waste depending on its characteristic s. Facilities must determine whether the captured CO 2 

### stream qualifies as hazardous waste either by testing the waste for hazardous characteristics or by applying knowledge of the materials and processe s used to generate the waste, as required by 40 CFR 262.11 (Hazardous waste determination).

EPA has identified three methods to test CO 2 

### streams for RCRA hazardous characteristics. The first method is to test the CO 2 

### stream as a gas prior to co mpression and transport. EPA estimates that a CO 2 

### capture facility would expend appr oximately $7,000 in one-time costs and $4,000 in annual costs to test its CO 2 

### stream as a gas. The second option is to test the CO 2 

### stream in its compressed, supercritical fluid or liquid under high pressure state. EPA estimates that a CO 2 

### capture facility would expend appr oximately $27,000 in one-time costs and $3,500 in annual costs to test its CO 2 

### stream in its supercritical or liquid under high pressure state. The third option is for CO 2 

### streams from a coal or gas fired combustion source that has undergone some particulate and VOC removal, and combines process knowledge with limited testing. This option is based on the assumption that the stream would not contain pesticides or most me tals, and, consequently, samples only for semivolatile organic compounds, volatile organic compounds, and mercury. 37 

### This third

35 Consistent with the EPA Office of Water’s “Cos t Analysis for the Federal Requirements Under the Underground Injection Control Program for Carbon Dioxi de Geologic Sequestration Wells (Final GS Rule),” EPA 816-R-10-013, July 2010.
36 Paul W. Parfomak and Pete r Folger. “Carbon Dioxide (CO 2 ) Pipelines for Carbon Sequestration: Emerging Policy Issues,” Congressional Research Service Report for Congrees, updated January 17, 2008, http://assets.opencrs.com/rpts/RL33971_20080117.pdf

. 37 We recognize that, besides mercury, other heavy metals such as arsenic and selenium may be present at very low levels.

### Page 33 of 145 option is the least expensive – EPA estimates that a CO 2 

### capture facility would expend approximately $4,500 in one-time costs and $2,700 in annual costs to utilize this method of RCRA hazardous waste determination. 38



### This analysis assumes that the facilities capturing CO 2 

### streams from fossil fuel electric power generation, natural gas distribut ion, ethyl alcohol ma nufacturing, and nitr ogenous fertilizer manufacturing would rely on process knowledge and limited testing to determine if their CO 2 

### stream is a RCRA hazardous waste (i.e., Option 3). The analysis assumes that the remaining facilities capturing CO 2 

### streams from oil and gas ex traction would test their CO 2 

### streams as a gas to determine whether their CO 2 

### stream is a RCRA hazar dous waste (i.e., Option 1). 39



### 3.2.2 Baseline Practices for CO 2 

### Capture Facilities

Depending on whether its CO 2 

### stream is RCRA hazardous, a cap ture facility may engage in one of four baseline practices to manage its CO 2 

### stream. The flow chart in Exhibit 12 presents the possible baseline practices for CO 2 

### capture facilities depending on whether they determine their CO 2 

### stream to be RCRA hazardous waste.

38 See Appendix A for further detail on the calculation of these costs. Labor hours were converted to costs using loaded hourly wages of $110.99 for Senior Chemists, and $55.95 for Chemists and Sampling Technicians.
39 For simplicity, this draft applies a single weighted average waste determination cost.

### Page 34 of 145 Exhibit 12: Flow Chart of Baseline Practices of CO 2 

### Capture Facilities

Waste Determination CO 2 Capture Facility's Baseline Practice

The CO 2 stream is not RCRA hazardous Transport CO 2 to sequestration facility for injection in a Class VI well

Captured CO 2 Stream Destined for Disposal Cease capturing the CO 2 stream

The CO 2 stream is RCRA hazardous Transport the CO 2 stream to a sequestration facility for

injection in a Class I

hazardous well 40

Treat the CO 2 stream and transport it to a sequestration

facility for injection in a Class VI well

Note : This assessment is of the geologic sequestration of CO 2 . While facilities may capture CO 2 streams for use in Class II wells for Enhanced Oil Recovery (EOR), that is beyond the scope of the proposed rule



### 3.2.2.1 Factors that Influence The Baseline Practices of CO 2 

### Carbon Capture Facilities

Each generator’s choice in how to manage a RCRA hazardous waste CO 2 

### stream would depend on several factors. The co st of each management option is a significant factor in this decision. Ceasing capture and releasing the CO 2 

### stream would be the lowest cost option, as the process of releasing the CO 2 

### stream would have little to no incremental cost and the generator would avoid costs associated with the RCRA hazardous waste requirements. 41

40 Permit writers also may require the well to meet the Cl ass VI UIC requirements. Howe ver, there is no specific UIC regulation that would require permit writers to appl y both the Class I and Class VI standards to a RCRA hazardous waste CO 2 injection well.
41 EPA has assumed that the generator determines that the CO 2 stream is a RCRA hazardous waste and then decides to forego capturing the CO 2 stream before any capital expenditure is incurred. The analysis assumes that there are no ‘sunk costs’ or other economic harm associated with the decision to forego capture. Starting in 2011, the facility may need to modify their pe rmit as part of the planning process. Starting in 2011 EPA intends to apply the Clean Air Ac t Prevention of Significant Deterioration (PSD) program to new electric power plants emitting great er than 100,000 TPY CO 2 or modified electric power plants emitting greater than 75.000 TPY CO 2 ( 75 Federal Register 31514, June 3, 2010). Therefore, starting in 2011 CO 2 emissions would

### Page 35 of 145 Transporting the waste to a Class I hazardous wa ste well would be the second least expensive option. EPA assumes that the cost of sequestrati on in a Class VI well is generally similar to the cost of sequestration in a Class I hazardous waste well. 42 

### However, a facility that captures CO 2 

### waste and sends it to a Class I hazardous waste well would not be required to treat the waste. In order to send a RCRA hazardous waste CO 2 

### stream to a Class VI well, a generator would first have to treat the CO 2 

### stream to make it non-hazardous, because RCRA hazardous waste could not be injected into a Class VI injection well. The hazardous CO 2 

### treatment process represents a significant cost. Treating the CO 2 

### stream and sending it to a Class VI well would be the most expensive option for RCRA hazardous CO 2 

### capture facilities.

If the generators’ decisions were based pur ely on management costs, generators who determine that their waste is RCRA hazardous wa ste would cease capture. However, factors beyond the cost of managing the CO 2 

### stream may affect their decisions. Capture projects may have been initiated in order to be eligib le for government subsidies, to improve public image, or to prepare for antic ipated regulatory or market changes (i.e., to avoid early obsolescence). These same factors may infl uence generators’ deci sions to continue CO 2 

### capture projects despite the RCRA hazardous waste characteristics of their CO 2 

### streams.

Although sequestration in a Class I hazardous waste well that meets the Class VI requirements would be less expensive than trea ting the waste for sequestration in a Class VI well, some generators nonetheless, may adopt the latter practice. EPA’s requirements allow the sequestration of RCRA hazardous waste CO 2 

### streams in a Class I hazardous waste well. However, EPA has assumed that UIC Permit writers would require that any Class I hazardous waste well injecting a RCRA hazardous waste CO 2 

### stream meet requirements similar to the Class VI requirements. Furtherm ore, UIC permit writers have discretion as to whether to allow the injection and sequestration of certain wastes depending on factors such as the composition of the waste, the specifications of the well, and the proximity of the well to USDWs. Therefore, RCRA hazardous waste CO 2 

### stream generators may not have access to a Class I hazardous waste well perm it that allows RCRA hazardous waste CO 2 

### stream sequestration.

be included in operating permits for power plants as a permit condition. Any change to the CO 2 emissions from a proposed new or modified power plant after issuance of the PSD permit for the power plant would require formal modification of the permit. Costs to modify the permit are not included in this analysis.
42 Although the Class VI requirements are more stringent than the Class I requirements, EPA assumes that UIC permit writers would ensure that Class I wells used for CO 2 sequestration also meet the Class VI requirements. However, EPA acknowledges that there is no explicit regulatory requirement for permit writers to apply the Class VI requirements to Class I wells. For purposes of this analysis, the difference in cost of obtaining a Class I UIC Permit versus a Class VI UIC permit has not been estimated and the cost of obtaining a permit is assumed to be the same regardless of the class of injection well or whether the CO 2 stream to be injected is a RCRA hazardous waste or non-haza rdous waste. In actuality, the modeling costs for Class I and Class VI wells may differ. Class I UIC well permits re quire modeling for the purpose of developing no-migration petitions; the Class VI well permits require computational modeling to delineate the full region surrounding the geological sequestration project that may be impacted by the injection activity, and require periodic reevaluation of the area of review as monitoring and data warrant.

### Page 36 of 145 3.2.2.2 Expected Baseline Practices of CO 2 

### Carbon Capture Facilities

As shown in Exhibit 12 above, the an alysis assumes that non-hazardous CO 2 

### streams will be transported to a Class VI well for seques tration. Those who generate hazardous CO 2 

### streams have three options: (i) tran sport their streams to Cla ss I hazardous waste wells for sequestration, (ii) treat their streams and send them to Class VI wells for sequestration, and (iii) cease CO 2 

### capture. There is significant uncertain ty in the hazardous constituent content of CO 2 

### streams that will be captured, and the complexity of the factors that may influence the baseline practices for generators of hazardous st reams. As a result, we have assumed a broad range for the prevalence of hazardous waste de termination and baseline practices for CO 2 

### capture facilities.

Exhibits 13 and 14 present our conservative (h igh-end) and low-end assumptions regarding the relative prevalence of each baseline prac tice in the absence of the proposed rule. 43 

### Exhibit 13 assumes that 90% of the managed CO 2 

### is RCRA hazardous waste, with equal distribution among baseline management practices , while Exhibit 14 assu mes that 10 percent of the managed CO 2 

### is RCRA hazardous waste. It is importa nt to note that, due to the lack of definitive data, the hazardous CO 2 

### percentages presented in thes e Exhibits are designed to represent a broad range of potential outcomes fo r analytical purposes only. Based on early literature reviews and current CO 2 

### capture technologies, the percentage of CO 2 

### streams that are potentially classified as hazardous may be low.

Exhibit 13: High-End Assumption for the Prevalence of Hazardous Waste Determination and Baseline Practices for CO 2 

### Capture Facilities

Hazardous Waste

Determination Baseline Practice Assumed Baseline Percentage of Capture Facilities a 

### Non-hazardous Send the CO 2 

### stream to a Class VI well 10%

Hazardous Cease capture 30% Send the CO 2 

### stream to a Class I well that is assumed to meet the Class VI requirements 30%

Treat the CO 2 

### stream such that the stream is non-hazardous and send it to a Class VI well 30%

a For purposes of this analysis EPA assumes these values as a high-end estimate due to a lack of data on the relative distribution of CO 2 streams’ hazardous waste designation.

43 This analysis assumes that CO 2 is not stored at the capture site and is sent off-site in a more-or-less continuous fashion.

### Page 37 of 145 Exhibit 14: Low-End Assumption fo r the Prevalence of Hazardous Waste Determination and Baseline Practices for CO 2 

### Capture Facilities

Hazardous Waste

Determination Baseline Practice Assumed Baseline Percentage of Capture Facilities a 

### Non-hazardous Send the CO 2 

### stream to a Class VI well 90 %

Hazardous Cease capture 3.3 % Send the CO 2 

### stream to a Class I well that is assumed to meet the Class VI requirements 3.3 %

Treat the CO 2 

### stream such that the stream is non-hazardous and send it to a Class VI well 3.3 %

a For purposes of this analysis EPA assumes these values as a low-end estimate due to a lack of data on the relative distribution of CO 2 streams’ hazardous waste designation.



### Exhibit 15 presents the number of CO 2 

### capture facilities that EPA expects will be active each year under the conservative assumption, and a pplies the percentages from Exhibit 13 to estimate the number of CO 2 

### capture facilities that would e ngage in each baseline practice each year in the absence of the proposed rule. 44



### Exhibit 15 – Assumed 90% Hazardous Waste: Expected Number of CO 2 

### Capture Facilities That Would Engage In Each Baseline Practice in the Abse nce of the Proposed Rule, by Year a



### Year Non-hazardousSend to Class VI HazardousCease Capture Hazardous - Treat and Send

to Class VI Hazardous - Send to Class I that is Assumed to Meet Class VI Requirements Total 2012 0 1 1 2 4 2013 1 1 1 2 5 2014 1 1 1 2 5 2015 1 1 1 2 5 2016 1 1 1 2 5 2017 1 1 2 2 6 2018 1 1 2 2 6 2019 1 1 2 2 6 2020 1 1 2 2 6 2021 1 1 2 2 6 2022 1 1 2 2 6 2023 1 1 2 2 6 2024 1 1 2 2 6 2025 1 1 2 2 6 2026 1 1 2 2 6

44 After applying the weights from Exhibit 13, the numbe r of facilities practicing each baseline practice was adjusted slightly to eliminate rounding errors in the total number of capture facilities.

### Page 38 of 145 Year Non-hazardousSend to Class VI HazardousCease Capture Hazardous - Treat and Send

to Class VI Hazardous - Send to Class I that is Assumed to Meet Class VI Requirements Total 2027 1 1 2 2 6 2028 1 1 2 2 6 2029 1 1 2 2 6 2030 2 4 4 5 15 2031 2 4 5 5 16 2032 2 6 6 6 20 2033 2 6 6 6 20 2034 3 7 7 8 25 2035 3 8 8 8 27 2036 3 8 8 8 27 Post 2036 3 8 8 8 27

a The numbers in this table are derived by applyi ng the percentages of capture facilities conducting each baseline practice presented in Exhibit 13 to the cumulative number of capture facilities expected to practice sequestration of their CO 2 streams each year, as presented in Exhibit 5. The numbers are rounded to integer values while ensuring the total nu mber of capture facilities in each year matches the total from Exhibit 5.



### Exhibit 16 below presents the number of CO 2 

### capture facilities that EPA expects will be active each year under the low-end assumption, a nd applies the percentages from Exhibit 14 to estimate the number of CO 2 

### capture facilities that would enga ge in each baseline practice each year in the absence of the proposed rule. 45



### Exhibit 16– Assumed 10% Hazardous Waste: Expected Number of CO 2 

### Capture Facilities That Would Engage In Each Baseline Practice in the Abse nce of the Proposed Rule, by Year a



### Year Non-hazardousSend to Class VI HazardousCease Capture Hazardous - Treat and Send

to Class VI Hazardous - Send to Class I that is Assumed to Meet Class VI Requirements Total 2012 4 0 0 0 4 2013 5 0 0 0 5 2014 5 0 0 0 5 2015 5 0 0 0 5 2016 5 0 0 0 5 2017 5 0 1 0 6 2018 5 0 1 0 6 2019 5 0 1 0 6 2020 5 0 1 0 6 2021 5 0 1 0 6

45 After applying the weights from Exhibit 14, the numbe r of facilities practicing each baseline practice was adjusted slightly to eliminate rounding errors in the total number of capture facilities.

### Page 39 of 145 Year Non-hazardousSend to Class VI HazardousCease Capture Hazardous - Treat and Send

to Class VI Hazardous - Send to Class I that is Assumed to Meet Class VI Requirements Total 2022 5 0 1 0 6 2023 5 0 1 0 6 2024 5 0 1 0 6 2025 5 0 1 0 6 2026 5 0 1 0 6 2027 5 0 1 0 6 2028 5 0 1 0 6 2029 5 0 1 0 6
2030 14 0 1 0 15
2031 14 0 1 1 16
2032 18 0 1 1 20
2033 18 0 1 1 20
2034 23 0 1 1 25
2035 24 1 1 1 27
2036 24 1 1 1 27
Post 2036 24 1 1 1 27

a The numbers in this table are derived by applyi ng the percentages of capture facilities conducting each baseline practice presented in Exhibit 14 to the cumulative number of capture facilities expected to practice sequestration of their CO 2 streams each year, as presented in Exhibit 5. The numbers are rounded to integer values while ensuring the total nu mber of capture facilities in each year matches the total from Exhibit 5.



### The analysis makes the following assu mptions regarding the costs that CO 2 

### capture facilities incur under the baseline: 46

• 

### Each CO 2 

### capture facility would incur one-time and annual costs to determine if the CO 2 

### stream is RCRA hazardous waste or is non-hazardous. Facil ities that would continue CO 2 

### capture in the baseline would incur the annual costs in each subsequent year. Capture facilities that would cease cap ture in the baseline w ould not retest their CO 2 

### streams in subsequent years and theref ore would incur the annual costs for the first year only

• 

### CO 2 

### capture facilities that generate a CO 2 

### stream that is not RCRA hazardous waste, and CO 2 

### capture facilities that determine that their CO 2 

### stream is RCRA hazardous waste and therefore decide to cease capt ure, would not be considered hazardous waste generators and would face no further co sts associated with the hazardous waste regulations.

46 A facility would be required to treat or di spose of any already captured RCRA hazardous CO 2 in compliance with RCRA standards, including test samples after testing is complete (see 40 CFR 261.4(d)). The tests to determine a CO 2 stream’s hazardous characteristics require th e capture of only a very small quantity of CO 2 , so this analysis assumes the associated costs to be negligible for handling the samples.

### Page 40 of 145 • 

### CO 2 

### capture facilities that generate RCRA hazardous waste CO 2 

### streams and do not cease capture would qualify as large quantity ge nerators (LQGs) in the baseline (i.e. they would generate more than 1,000 k ilograms of hazardous waste per month). Therefore, they would be subject to the full set of hazardous waste generator requirements and would incur the associated costs.

• 

### CO 2 

### capture facilities that treat their RCRA hazardous waste CO 2 

### streams would incur treatment costs. 47



### The avoidance of these costs under the proposed exclusion is quantified as a savings in Section 3.5.

3.2.3 Baseline Practices for CO 2 

### Sequestration Facilities

In the baseline, the universe of CO 2 

### sequestration facilities would include a mix of facilities with Class VI wells and facilities with Cla ss I hazardous waste wells that EPA has assumed will also meet the Class VI requirements. The Class VI wells would manage non-hazardous CO 2 

### streams and CO 2 

### streams that have been treated prio r to sequestration, while the Class I hazardous waste wells would manage the untreated RCRA hazardous waste CO 2 

### streams.

High-End Assumption:

This analysis assumes that, in the baseline high-end assumption, approximately 57 percent of the sequestration wells woul d manage non-hazardous CO 2 

### streams and treated CO 2 

### streams in Class VI wells. The remaining sequest ration wells would manage RCRA hazardous CO 2 

### streams in Class I hazardous waste wells. 48 

### Exhibit 17 estimates the number of CO 2 

### sequestration facilities that would engage in each baseline practice under our high-end assumption

47 EPA has assumed that these facilities would meet the requirements of “onsite treatment” under 40 CFR 260.10 (Definitions) and related RCRA regulations an d therefore would not be required to obtain RCRA hazardous waste treatment permits.
48 For the high-end estimate, this anal ysis assumes that 40 percent of CO 2 capture facilities would transport nonhazardous or treated CO 2 streams to Class VI sequestration wells for injection (see Exhibit 13). Another 30 percent of CO 2 capture facilities would transport hazardous CO 2 streams to Class I sequestration wells for injection. Of this 70 percent of capture facilities transporting their CO 2 to a sequestration well, four out of seven (i.e. 40 out of 70 percent) of them transport their waste to Class VI wells. The analysis assumes that 4 out of 7 (57 percent) of CO 2 sequestration wells in the baseline are Cl ass VI wells to match the practices of CO 2 capture facilities. The remaining 3 out of 7 (43 percent) of CO 2 sequestration wells in the baseline are Class I wells.

### Page 41 of 145 Exhibit 17 – High-End: Expected Number of CO 2 

### Sequestration Facilities That Would Engage In Each Baseline Practice in the Absence of the Proposed Rule, by Year a

Year Manage Non-Hazardous CO 2 (Class VI) Manage Hazardous CO 2 (Class I) 2012 1 1 2013 2 1 2014 2 2 2015 2 2 2016 3 3 2017 9 7 2018 10 7 2019 10 7 2020 10 7 2021 10 7 2022 10 7 2023 10 7 2024 10 7 2025 10 7 2026 10 7 2027 10 7 2028 10 7 2029 10 7 2030 10 7 2031 10 8 2032 13 9 2033 13 9 2034 15 12 2035 17 12 2036 17 12 Post 2036 17 12

a The numbers in this table are derived by applying the percentages of sequestration facilities conducting each baseline practice discussed above to the number of sequestration facilities expected to be in op eration each year (cumulative), as presented in Exhibit 10. The numbers are rounded to integer values while ensuring the total number of capture facilities in each year matches the total from Exhibit 10.



### Low-End Assumption:

This analysis assumes that, in the baseline low-end assumption, approximately 97 percent of the sequestration wells woul d manage non-hazardous CO 2 

### streams and treated CO 2 

### streams in Class VI wells. The remaining sequest ration wells would manage RCRA hazardous CO 2 

### streams in Class I hazardous waste wells. 49 

### Exhibit 18 estimates the number of CO 2

49 For the low-end estimate, this anal ysis assumes that 90 percent of CO 2 capture facilities would transport nonhazardous or treated CO 2 streams to Class VI sequestration wells for injection (see Exhibit 14). Another 3.3

### Page 42 of 145 sequestration facilities that would engage in each baseline practice under our low-end assumption

Exhibit 18 – Low End: Expected Number of CO 2 

### Sequestration Facilities That Would Engage In Each Baseline Practice in the Absence of the Proposed Rule, by Year a

Year Manage Non-Hazardous CO 2 (Class VI) Manage Hazardous CO 2 (Class I)
2012 2 0
2013 3 0
2014 4 0
2015 4 0
2016 6 0
2017 15 1
2018 16 1
2019 16 1
2020 16 1
2021 16 1
2022 16 1
2023 16 1
2024 16 1
2025 16 1
2026 16 1
2027 16 1
2028 16 1
2029 16 1
2030 16 1
2031 17 1
2032 21 1
2033 21 1
2034 26 1
2035 28 1
2036 28 1
Post 2036 28 1

a The numbers in this table are derived by applying the percentages of sequestration facilities conducting each baseline practice discussed above to the number of sequestration facilities expected to be in op eration each year (cumulative), as presented in Exhibit 11. The numbers are rounded to integer values while ensuring the total number of capture facilities in each year matches the total from Exhibit 11.

percent of CO 2 capture facilities would transport hazardous CO 2 streams to Class I sequestration wells for injection. This analysis as sumes that 97 percent of CO 2 sequestration wells in the baseline are Class VI wells to match the practices of CO 2 capture facilities. The remaining 3 percent of CO 2 sequestration wells in the baseline are Class I wells.

### Page 43 of 145 3.3 Post Rule Practices

This section discusses the change in practices of CO 2 

### capture and sequestration facilities due to the rule, as proposed. The rule requires no changes for pipelin e transportation of CO 2 

### , as proposed.

3.3.1 Post Rule Practices for CO 2 

### Capture Facilities

This analysis assumes that all CO 2 

### capture facilities will clai m the proposed exclusion and send their CO 2 

### streams to Class VI wells as a result of the proposed rule. 50 

### Under the proposal, CO 2 

### capture facilities claiming the exclusi on would avoid the costs of determining whether their CO 2 

### stream is RCRA hazardous or non-haza rdous. Exempt generators/capture facilities would not be required to conduct testing of their CO 2 

### streams for hazardous characteristics or be required to evaluate the hazardous constituent content of the CO 2 

### stream based on the materials and processes used to generate the waste. They would only be required to submit an annual certification that the captured CO 2 

### stream is exempt. CO 2 

### capture facilities would also be able to send their CO 2 

### streams to Class VI wells without the additional cost of treating the CO 2 

### stream.

3.3.2 Post Rule Practices for CO 2 

### Sequestration Facilities

Under the proposed rule, all CO 2 

### sequestration facilities are expected to be permitted as Class VI wells. 51 

### Because under the proposed rule CO 2 

### managed by GS would not be classified as RCRA hazardous waste, there would be no need for the owners and operators of injection wells to pursue a Class I hazardous waste well permit.

3.4 Incremental Costs of the Proposed Rule

This section estimates the incr emental costs of the proposed rule. Section 3.4.1 presents and quantifies the compliance costs of the proposed rule, and Sec tion 3.4.2 qualitatively discusses the potential social costs of the proposed rule. Section 3.4.3 discu sses the costs of the rule to federal and state governments.

3.4.1 Compliance Costs

In order to claim the proposed exclusion, authorized representatives at both the CO 2 

### capture facilities and Class VI UIC wells would be required to sign a certification statement which

50 It is possible that some facilities may c ontinue to send their RCRA hazardous waste CO 2 stream to a Class I well that is assumed to meet the Class VI requirements. However, based on this assumption, the costs associated with this practice are expected to be similar to the costs of using a Class VI well, so this distinction will not affect the results of this analysis.
51 With the possible exception of some sequestration demonstration projects that may be permitted as Class V experimental wells.

### Page 44 of 145 they must maintain onsite and ma ke available to EPA upon request. 52 

### The facilities are required to renew the certification statement each year in which they claim the exclusion. Facilities claiming the exclusion also must provide the statement to EPA or state governments, upon request. Exhibit 19 presents the estimated labor costs per facility associated with the certification requirements. These costs are expected to be similar for CO 2 

### capture facilities and Class VI UIC wells.

Exhibit 19: Estimated Costs to Prepare and Renew the CO 2 

### Exclusion Certification Statement Per CO 2 

### Capture Facility or Sequestration Well (2010 dollars)

Labor Category Loaded Hourly Wage a Prepare Initial Certification Statement Renew Certification Statement Make Certification Statement Available to State or EPA 

### Hours b 

### Cost Hours b 

### Cost Hours b 

### Cost Legal $101.13 1.00 $101.13 0.50 $50.57 0.00 $0.00 Management $77.67 1.50 $116.51 0.75 $58.25 0.00 $0.00 Technical $110.99 1.25 $138.74 0.50 $55.50 0.00 $0.00 Clerical $25.06 0.25 $6.27 0.25 $6.27 0.10 $2.51 Total (Rounded) 4.00 $363 2.00 $171 0.10 $3

a Wages for legal, management, and clerical labor are based on unloaded average hourly labor rates from the “Occupational Employment Statistics, May 2009 National Occupational Employment and Waste Estimates, United States” of the Bureau of Labor Statistics (BLS). Wages for technical labor reflect the average of the wage for a petroleum geologist with 15 years experience in the 2008 American Association of Petroleum Geologists (AAPG) Salary Survey according to Larry Nation, “Uncer tainty chills decision making: Salaries Show 5 Percent Increase,” http://www.aapg.org/explorer/salarysurvey.cfm and the wage for a petroleum engineer (reservoirs) with 15 years experience according to The Society of Petr oleum Engineers “Annual Me mbership Salary Survey Highlight Report, 2008 Salary Survey,” http://www.spe.org/career/salary_survey/ . Wages for all labor categories were adjusted to 2010 dollars using the BLS “Employm ent Cost Index Historical Listing Current-dollar March 2001-September 2010,” http://www.bls.gov/web/eci/echistrynaics.pdf , and multiplied by a loading factor of 1.6.
b These hour estimates are based on EPA’s professional judgment.



### Industry Compliance Costs – High-End Estimate:

Exhibits 20 and 21 multiply the per facility co sts times the maximum number of potentially affected capture facilities and Cl ass VI wells, respectively. These facilities are expected to incur each cost in each y ear over the 50-year period begi nning in 2012. Facilities are assumed to sign the certification in the first year of operation and renew the certification in each subsequent year. 53 

### Combined, EPA and state governments are assumed to request certification statements from approximately 30 per cent of capture facilities and Class VI well operators annually. 54 

### The exhibits present the undiscount ed certification costs, and also present the discounted certifica tion costs applying 3 percent a nd 7 percent discount rate to costs incurred after 2012.

52 A single certification statement would be signed by only one facility. Each capture facility and each sequestration facility would sign its own certification statement.
53 See Exhibits 5 and 10 for the number of CO 2 capture and sequestration facilitie s expected to operate in each year. All of these facilities, regardless of their baseline practice, are expected to incur these certification costs.
54 This estimate is based on EPA’s best professional judgment.

### Page 45 of 145 Exhibit 20: High-End Estimate : Certification Costs for CO 2 

### Capture Facilities 2012 to 2061, (2010 dollars)

Year Initial Certifications Certifications Renewals Certification Submissions to State or EPA Total Cost

Number A Cost B = A X

$363 Number C Cost D = C X $171 Number E Cost F = C X $3 Undiscounted B + D +F 3% Discount

Rate 7% Discount

Rate

2012 4 $1,452 0 $0 1 $3 $1,455 $1,455 $1,455
2013 1 $363 4 $684 2 $6 $1,053 $1,022 $984
2014 0 $0 5 $855 2 $6 $861 $812 $752
2015 0 $0 5 $855 2 $6 $861 $788 $703
2016 0 $0 5 $855 2 $6 $861 $765 $657
2017 1 $363 5 $855 2 $6 $1,224 $1,056 $873
2018 0 $0 6 $1,026 2 $6 $1,032 $864 $688
2019 0 $0 6 $1,026 2 $6 $1,032 $839 $643
2020 0 $0 6 $1,026 2 $6 $1,032 $815 $601
2021 0 $0 6 $1,026 2 $6 $1,032 $791 $561
2022 0 $0 6 $1,026 2 $6 $1,032 $768 $525
2023 0 $0 6 $1,026 2 $6 $1,032 $746 $490
2024 0 $0 6 $1,026 2 $6 $1,032 $724 $458
2025 0 $0 6 $1,026 2 $6 $1,032 $703 $428
2026 0 $0 6 $1,026 2 $6 $1,032 $682 $400
2027 0 $0 6 $1,026 2 $6 $1,032 $662 $374
2028 0 $0 6 $1,026 2 $6 $1,032 $643 $350
2029 0 $0 6 $1,026 2 $6 $1,032 $624 $327
2030 9 $3,267 6 $1,026 5 $15 $4,308 $2,530 $1,275
2031 1 $363 15 $2,565 5 $15 $2,943 $1,678 $814
2032 4 $1,452 16 $2,736 6 $18 $4,206 $2,329 $1,087
2033 0 $0 20 $3,420 6 $18 $3,438 $1,848 $830
2034 5 $1,815 20 $3,420 8 $24 $5,259 $2,745 $1,187
2035 2 $726 25 $4,275 8 $24 $5,025 $2,546 $1,060
2036 0 $0 27 $4,617 8 $24 $4,641 $2,283 $915
2037 0 $0 27 $4,617 8 $24 $4,641 $2,217 $855
2038 0 $0 27 $4,617 8 $24 $4,641 $2,152 $799
2039 0 $0 27 $4,617 8 $24 $4,641 $2,089 $747
2040 0 $0 27 $4,617 8 $24 $4,641 $2,028 $698
2041 0 $0 27 $4,617 8 $24 $4,641 $1,969 $652
2042 0 $0 27 $4,617 8 $24 $4,641 $1,912 $610
2043 0 $0 27 $4,617 8 $24 $4,641 $1,856 $570
2044 0 $0 27 $4,617 8 $24 $4,641 $1,802 $533
2045 0 $0 27 $4,617 8 $24 $4,641 $1,750 $498
2046 0 $0 27 $4,617 8 $24 $4,641 $1,699 $465
2047 0 $0 27 $4,617 8 $24 $4,641 $1,649 $435
2048 0 $0 27 $4,617 8 $24 $4,641 $1,601 $406
2049 0 $0 27 $4,617 8 $24 $4,641 $1,555 $380
2050 0 $0 27 $4,617 8 $24 $4,641 $1,509 $355
2051 0 $0 27 $4,617 8 $24 $4,641 $1,465 $332

### Page 46 of 145 Year Initial Certifications Certifications Renewals Certification Submissions to State or EPA Total Cost

Number A Cost B = A X

$363 Number C Cost D = C X $171 Number E Cost F = C X $3 Undiscounted B + D +F 3% Discount

Rate 7% Discount

Rate

2052 0 $0 27 $4,617 8 $24 $4,641 $1,423 $310
2053 0 $0 27 $4,617 8 $24 $4,641 $1,381 $290
2054 0 $0 27 $4,617 8 $24 $4,641 $1,341 $271
2055 0 $0 27 $4,617 8 $24 $4,641 $1,302 $253
2056 0 $0 27 $4,617 8 $24 $4,641 $1,264 $236
2057 0 $0 27 $4,617 8 $24 $4,641 $1,227 $221
2058 0 $0 27 $4,617 8 $24 $4,641 $1,192 $207
2059 0 $0 27 $4,617 8 $24 $4,641 $1,157 $193
2060 0 $0 27 $4,617 8 $24 $4,641 $1,123 $180
2061 0 $0 27 $4,617 8 $24 $4,641 $1,090 $169

50 Year Total 27 $9,801 900 $153,900 281 $843 $164,544 $70,474 $29,098



### Exhibit 21: High-End Estimate: Cert ification Costs for Class VI Underground Injection Control Wells, 2012 to 2061, (2010 dollars)

Year Initial Certifications Certifications Renewals Certification Submissions to State or EPA Total Cost

Number A Cost B = A X

$363 Number C Cost D = C X $171 Number E Cost F = C X $3 Undiscounted B + D +F 3% Discount

Rate 7% Discount

Rate

2012 2 $726 0 $0 1 $3 $726 $726 $726
2013 1 $363 2 $342 1 $3 $705 $684 $659
2014 1 $363 3 $513 1 $3 $876 $826 $765
2015 0 $0 4 $684 1 $3 $684 $626 $558
2016 2 $726 4 $684 2 $6 $1,410 $1,253 $1,076
2017 10 $3,630 6 $1,026 5 $15 $4,656 $4,016 $3,320
2018 1 $363 16 $2,736 5 $15 $3,099 $2,595 $2,065
2019 0 $0 17 $2,907 5 $15 $2,907 $2,364 $1,810
2020 0 $0 17 $2,907 5 $15 $2,907 $2,295 $1,692
2021 0 $0 17 $2,907 5 $15 $2,907 $2,228 $1,581
2022 0 $0 17 $2,907 5 $15 $2,907 $2,163 $1,478
2023 0 $0 17 $2,907 5 $15 $2,907 $2,100 $1,381
2024 0 $0 17 $2,907 5 $15 $2,907 $2,039 $1,291
2025 0 $0 17 $2,907 5 $15 $2,907 $1,980 $1,206
2026 0 $0 17 $2,907 5 $15 $2,907 $1,922 $1,127
2027 0 $0 17 $2,907 5 $15 $2,907 $1,866 $1,054
2028 0 $0 17 $2,907 5 $15 $2,907 $1,812 $985
2029 0 $0 17 $2,907 5 $15 $2,907 $1,759 $920
2030 0 $0 17 $2,907 5 $15 $2,907 $1,708 $860
2031 1 $363 17 $2,907 5 $15 $3,270 $1,865 $904

### Page 47 of 145 Year Initial Certifications Certifications Renewals Certification Submissions to State or EPA Total Cost

Number A Cost B = A X

$363 Number C Cost D = C X $171 Number E Cost F = C X $3 Undiscounted B + D +F 3% Discount

Rate 7% Discount

Rate

2032 4 $1,452 18 $3,078 7 $21 $4,530 $2,508 $1,171
2033 0 $0 22 $3,762 7 $21 $3,762 $2,022 $909
2034 5 $1,815 22 $3,762 8 $24 $5,577 $2,911 $1,259
2035 2 $726 27 $4,617 9 $27 $5,343 $2,707 $1,127
2036 0 $0 29 $4,959 9 $27 $4,959 $2,439 $978
2037 0 $0 29 $4,959 9 $27 $4,959 $2,368 $914
2038 0 $0 29 $4,959 9 $27 $4,959 $2,299 $854
2039 0 $0 29 $4,959 9 $27 $4,959 $2,232 $798
2040 0 $0 29 $4,959 9 $27 $4,959 $2,167 $746
2041 0 $0 29 $4,959 9 $27 $4,959 $2,104 $697
2042 0 $0 29 $4,959 9 $27 $4,959 $2,043 $651
2043 0 $0 29 $4,959 9 $27 $4,959 $1,984 $609
2044 0 $0 29 $4,959 9 $27 $4,959 $1,926 $569
2045 0 $0 29 $4,959 9 $27 $4,959 $1,870 $532
2046 0 $0 29 $4,959 9 $27 $4,959 $1,815 $497
2047 0 $0 29 $4,959 9 $27 $4,959 $1,762 $464
2048 0 $0 29 $4,959 9 $27 $4,959 $1,711 $434
2049 0 $0 29 $4,959 9 $27 $4,959 $1,661 $406
2050 0 $0 29 $4,959 9 $27 $4,959 $1,613 $379
2051 0 $0 29 $4,959 9 $27 $4,959 $1,566 $354
2052 0 $0 29 $4,959 9 $27 $4,959 $1,520 $331
2053 0 $0 29 $4,959 9 $27 $4,959 $1,476 $309
2054 0 $0 29 $4,959 9 $27 $4,959 $1,433 $289
2055 0 $0 29 $4,959 9 $27 $4,959 $1,391 $270
2056 0 $0 29 $4,959 9 $27 $4,959 $1,351 $253
2057 0 $0 29 $4,959 9 $27 $4,959 $1,311 $236
2058 0 $0 29 $4,959 9 $27 $4,959 $1,273 $221
2059 0 $0 29 $4,959 9 $27 $4,959 $1,236 $206
2060 0 $0 29 $4,959 9 $27 $4,959 $1,200 $193
2061 0 $0 29 $4,959 9 $27 $4,959 $1,165 $180

50 Year Total 29 $10,527 1,099 $187,929 346 $1,038 $198,456 $91,892 $42,294



### Industry Compliance Costs – Low-End Estimate:

Exhibits 22 and 23 multiply the per facility co sts times the low-end estimate for the number of potentially affected capture facilities and Class VI wells, respectively. As with the highend estimate, these facilities are expected to incur each cost in each year over the 50-year period, beginning in 2012. Facilities are assumed to sign the certification in the first year of

### Page 48 of 145 operation and renew the certificat ion in each subsequent year. 55 

### Combined, EPA and state governments are assumed to request certificati on statements from approximately 30 percent of capture facilities and Cl ass VI well operators annually. 56 

### The exhibits present the undiscounted certification costs, and also present the discounted certification costs applying 3 percent and 7 percent discount rate to costs incurred after 2012.

Exhibit 22: Low-End Estimate : Certification Costs for

CO 2 

### Capture Facilities 2012 to 2061, (2010 dollars)

Year Initial Certifications Certifications Renewals Certification Submissions to State or EPA Total Cost

Number A Cost B = A X

$363 Number C Cost D = C X $171 Number E Cost F = C X $3 Undiscounted B + D +F 3% Discount

Rate 7% Discount

Rate

2012 2 $726 0 $0 1 $3 $729 $729 $729

2013 0 $0 2 $342 1 $3 $345 $335 $322

2014 0 $0 2 $342 1 $3 $345 $325 $301

2015 0 $0 2 $342 1 $3 $345 $316 $282

2016 0 $0 2 $342 1 $3 $345 $307 $263

2017 1 $363 2 $342 1 $3 $708 $611 $505

2018 0 $0 3 $513 1 $3 $516 $432 $344

2019 0 $0 3 $513 1 $3 $516 $420 $321

2020 0 $0 3 $513 1 $3 $516 $407 $300

2021 0 $0 3 $513 1 $3 $516 $395 $281

2022 0 $0 3 $513 1 $3 $516 $384 $262

2023 0 $0 3 $513 1 $3 $516 $373 $245

2024 0 $0 3 $513 1 $3 $516 $362 $229

2025 0 $0 3 $513 1 $3 $516 $351 $214

2026 0 $0 3 $513 1 $3 $516 $341 $200

2027 0 $0 3 $513 1 $3 $516 $331 $187

2028 0 $0 3 $513 1 $3 $516 $322 $175

2029 0 $0 3 $513 1 $3 $516 $312 $163

2030 9 $3,267 3 $513 4 $12 $3,792 $2,227 $1,122

2031 0 $0 12 $2,052 4 $12 $2,064 $1,177 $571

2032 0 $0 12 $2,052 4 $12 $2,064 $1,143 $533

2033 0 $0 12 $2,052 4 $12 $2,064 $1,110 $498

2034 1 $363 12 $2,052 4 $12 $2,427 $1,267 $548

2035 0 $0 13 $2,223 4 $12 $2,235 $1,132 $471

2036 0 $0 13 $2,223 4 $12 $2,235 $1,099 $441

2037 0 $0 13 $2,223 4 $12 $2,235 $1,067 $412

2038 0 $0 13 $2,223 4 $12 $2,235 $1,036 $385

2039 0 $0 13 $2,223 4 $12 $2,235 $1,006 $360

55 See Exhibits 6 and 11 for the number of CO 2 capture and sequestration facilitie s expected to operate in each year. All of these facilities, regardless of their baseline practice, are expected to incur these certification costs.
56 This estimate is based on EPA’s best professional judgment.

### Page 49 of 145 Year Initial Certifications Certifications Renewals Certification Submissions to State or EPA Total Cost

Number A Cost B = A X

$363 Number C Cost D = C X $171 Number E Cost F = C X $3 Undiscounted B + D +F 3% Discount

Rate 7% Discount

Rate

2040 0 $0 13 $2,223 4 $12 $2,235 $977 $336

2041 0 $0 13 $2,223 4 $12 $2,235 $948 $314

2042 0 $0 13 $2,223 4 $12 $2,235 $921 $294

2043 0 $0 13 $2,223 4 $12 $2,235 $894 $274

2044 0 $0 13 $2,223 4 $12 $2,235 $868 $256

2045 0 $0 13 $2,223 4 $12 $2,235 $843 $240

2046 0 $0 13 $2,223 4 $12 $2,235 $818 $224

2047 0 $0 13 $2,223 4 $12 $2,235 $794 $209

2048 0 $0 13 $2,223 4 $12 $2,235 $771 $196

2049 0 $0 13 $2,223 4 $12 $2,235 $749 $183

2050 0 $0 13 $2,223 4 $12 $2,235 $727 $171

2051 0 $0 13 $2,223 4 $12 $2,235 $706 $160

2052 0 $0 13 $2,223 4 $12 $2,235 $685 $149

2053 0 $0 13 $2,223 4 $12 $2,235 $665 $139

2054 0 $0 13 $2,223 4 $12 $2,235 $646 $130

2055 0 $0 13 $2,223 4 $12 $2,235 $627 $122

2056 0 $0 13 $2,223 4 $12 $2,235 $609 $114

2057 0 $0 13 $2,223 4 $12 $2,235 $591 $106

2058 0 $0 13 $2,223 4 $12 $2,235 $574 $99

2059 0 $0 13 $2,223 4 $12 $2,235 $557 $93

2060 0 $0 13 $2,223 4 $12 $2,235 $541 $87

2061 0 $0 13 $2,223 4 $12 $2,235 $525 $81

50 Year Total 13 $4,719 448 $76,608 146 $438 81,765 $35,353 $14,644



### Exhibit 23: Low-End Estimate: Ce rtification Costs for Class VI Underground Injection Control Wells, 2012 to 2061, (2010 dollars)

Year Initial Certifications Certifications Renewals Certification Submissions to State or EPA Total Cost

Number A Cost B = A X

$363 Number C Cost D = C X $171 Number E Cost F = C X $3 Undiscounted B + D +F 3% Discount

Rate 7% Discount

Rate

2012 0 $0 0 $0 0 $0 $0 $0 $0

2013 0 $0 0 $0 0 $0 $0 $0 $0

2014 0 $0 0 $0 0 $0 $0 $0 $0

2015 0 $0 0 $0 0 $0 $0 $0 $0

2016 0 $0 0 $0 0 $0 $0 $0 $0

2017 6 $2,178 0 $0 2 $6 $2,178 $1,879 $1,553

2018 0 $0 6 $1,026 2 $6 $1,026 $859 $684

### Page 50 of 145 Year Initial Certifications Certifications Renewals Certification Submissions to State or EPA Total Cost

Number A Cost B = A X

$363 Number C Cost D = C X $171 Number E Cost F = C X $3 Undiscounted B + D +F 3% Discount

Rate 7% Discount

Rate

2019 0 $0 6 $1,026 2 $6 $1,026 $834 $639

2020 0 $0 6 $1,026 2 $6 $1,026 $810 $597

2021 0 $0 6 $1,026 2 $6 $1,026 $786 $558

2022 0 $0 6 $1,026 2 $6 $1,026 $763 $522

2023 0 $0 6 $1,026 2 $6 $1,026 $741 $487

2024 0 $0 6 $1,026 2 $6 $1,026 $720 $456

2025 0 $0 6 $1,026 2 $6 $1,026 $699 $426

2026 0 $0 6 $1,026 2 $6 $1,026 $678 $398

2027 0 $0 6 $1,026 2 $6 $1,026 $659 $372

2028 0 $0 6 $1,026 2 $6 $1,026 $639 $348

2029 0 $0 6 $1,026 2 $6 $1,026 $621 $325

2030 0 $0 6 $1,026 2 $6 $1,026 $603 $304

2031 0 $0 6 $1,026 2 $6 $1,026 $585 $284

2032 0 $0 6 $1,026 2 $6 $1,026 $568 $265

2033 0 $0 6 $1,026 2 $6 $1,026 $552 $248

2034 0 $0 6 $1,026 2 $6 $1,026 $535 $232

2035 0 $0 6 $1,026 2 $6 $1,026 $520 $216

2036 0 $0 6 $1,026 2 $6 $1,026 $505 $202

2037 0 $0 6 $1,026 2 $6 $1,026 $490 $189

2038 0 $0 6 $1,026 2 $6 $1,026 $476 $177

2039 0 $0 6 $1,026 2 $6 $1,026 $462 $165

2040 0 $0 6 $1,026 2 $6 $1,026 $448 $154

2041 0 $0 6 $1,026 2 $6 $1,026 $435 $144

2042 0 $0 6 $1,026 2 $6 $1,026 $423 $135

2043 0 $0 6 $1,026 2 $6 $1,026 $410 $126

2044 0 $0 6 $1,026 2 $6 $1,026 $398 $118

2045 0 $0 6 $1,026 2 $6 $1,026 $387 $110

2046 0 $0 6 $1,026 2 $6 $1,026 $376 $103

2047 0 $0 6 $1,026 2 $6 $1,026 $365 $96

2048 0 $0 6 $1,026 2 $6 $1,026 $354 $90

2049 0 $0 6 $1,026 2 $6 $1,026 $344 $84

2050 0 $0 6 $1,026 2 $6 $1,026 $334 $78

2051 0 $0 6 $1,026 2 $6 $1,026 $324 $73

2052 0 $0 6 $1,026 2 $6 $1,026 $315 $69

2053 0 $0 6 $1,026 2 $6 $1,026 $305 $64

2054 0 $0 6 $1,026 2 $6 $1,026 $296 $60

2055 0 $0 6 $1,026 2 $6 $1,026 $288 $56

2056 0 $0 6 $1,026 2 $6 $1,026 $279 $52

2057 0 $0 6 $1,026 2 $6 $1,026 $271 $49

2058 0 $0 6 $1,026 2 $6 $1,026 $263 $46

2059 0 $0 6 $1,026 2 $6 $1,026 $256 $43

2060 0 $0 6 $1,026 2 $6 $1,026 $248 $40

### Page 51 of 145 Year Initial Certifications Certifications Renewals Certification Submissions to State or EPA Total Cost

Number A Cost B = A X

$363 Number C Cost D = C X $171 Number E Cost F = C X $3 Undiscounted B + D +F 3% Discount

Rate 7% Discount

Rate

2061 0 $0 6 $1,026 2 $6 $1,026 $241 $37

50 Year Total 6 $2,178 264 $45,144 90 $270 47,322 $23,345 $11,471



### Under the proposed rule, some CO 2 

### sequestration facilities that would have been permitted as Class I wells in the baseline are expected to be permitted as Class VI wells instead. The analysis assumes that this change in behavior will not result in a cost to these facilities. The planned CO 2 

### sequestration sites are not yet operationa l and have not yet acquired permits. The cost to obtain the Class VI permit is assumed to be simila r to the cost of obtaining a Class I permit, and the Class I hazardous waste wells in the baseline were already assumed in this analysis to be built to Class VI standards. Therefore, for this analysis EPA has assumed that there is no difference in cost for cons truction and permitting of Class I and Class VI wells.

3.4.2 Social Costs

The baseline requirements that appl y to captured RCRA hazardous waste CO 2 

### streams are designed to protect the human health and the environment. However, EPA finds that CO 2 

### streams may be managed in an equally pr otective manner outside of the RCRA hazardous waste program. The Class VI UIC well requ irements are designed to isolate the CO 2 

### stream and prevent it from migrating to Underground Sources of Drinking Water (USDWs). In addition, permit writers for Cla ss VI UIC wells have discreti on in whether to allow the sequestration of certain wastes depending on factors such as the composition of the waste, the structure of the well, and the proximity of the well to USDWs. Therefore, EPA has determined that the management of exempted CO 2 

### streams in Class VI UIC wells would not pose an unacceptable risk to human health and the environment. 57 

### Based on available knowledge, EPA does not anticipate any negative ex ternalities as a result of this action. As a result, no social costs are expected to result from the proposed exclusion.

The proposed rule may have productivity and out put implications. This analysis does not model the potential productivity impact of the proposed rule. However, EPA anticipates that these impacts would be primarily positive, as a ffected facilities could use savings associated with the proposed rule to in crease output or productivity.

57 Today’s proposed conditional exclusion is based upon EPA’s existing knowledge of the composition of CO 2 streams, and its analysis that comp liance with the existing standards and regulations designed to prevent any exposure of CO 2 (and any associated impurities) would rende r additional regulation under RCRA subtitle C unnecessary. Nevertheless, EPA is seeking to collect additional data on the composition of captured CO 2 streams. As CCS pilot projects move forward and continue to generate information, EPA expects the amount of available analytical data on captured CO 2 to increase.

### Page 52 of 145 3.4.3 Costs to Government Entities

Under the proposed rule, CO 2 

### capture facilities and Cla ss VI well operators would be required to sign a certification statement and ma ke it available to EPA or state governments upon request. This analysis assumes that, combined, EPA and state governments will request certification statements from approximate ly 30 percent of capture facilities and Class VI well operators annually, and that state gov ernments will account for about 90 percent of those requests. 58 

### Exhibits 24 and 25 present the co sts per request to EPA and state governments, respectively.

Exhibit 24: Estimated Cost to EPA to Request and Review a CO 2 

### Exclusion Certification (2010 dollars) Labor Category Loaded Hourly Wage a 

### Hours b 

### Cost 

### Management $71.42 0.20 $14.28 Technical $52.37 0.50 $26.19 Clerical $21.02 0.30 $6.31 Total 1.00 $47

a Office of Personnel Management, “Salary Ta ble 2010-GS Incorporating the 1.50% General Schedule Increase Effective January 2010,” http://www.opm.gov/oca/ 10tables/indexGS.asp . The labor rates are based on the following GS levels and steps: legal labor rates were based on GS Level 15, Step 1, managerial labor rates were based on GS Level 14, Step 4, technical labor rates were based on GS Level 12, Step 5, and clerical labor rates were based on GS Level 5, Step 1. EPA then multiplied the unloaded rates by the sta ndard government loading factor of 1.6 to reflect overhead
b These hour estimates are based on EPA’s professional judgment.



### Exhibit 25: Estimated Costs to St ates to Request and Review a CO 2 

### Exclusion Certification (2010 dollars) Labor Category Loaded Hourly Wage a 

### Hours b 

### Cost 

### Management $61.50 0.35 $21.53 Technical $38.53 0.75 $28.90 Clerical $26.74 0.40 $10.70 Total 1.50 $61

a Department of Labor, Bureau of Labor Statistic s (BLS), “May 2009 National Industry-Specific Occupational Employment and Wage Estimates, NAICS 999200 – State Government,” http://www.bls.gov/oes/current/ naics4_999200.htm. EPA updated these rates to June 2010 levels using the BLS “Employment Cost Index Historical Listing Current-dollar March 2001- September 2010,” http://www.bls.gov/web/eci/echistrynaics.pdf . EPA applied a 1.6 loading factor to reflect overhead.
b These hour estimates are based on EPA’s professional judgment.



### Exhibits 26 and 27 below present the high-end es timates for the total costs to EPA and state governments to request and review certification statements related to the proposed exclusion

58 These estimates are based on EPA’s best professional judgment.

### Page 53 of 145 over the 50-year period beginning 2012. The exhi bits present undiscounted costs, and also apply 3 percent and 7 percent discount rates to costs incu rred after 2012.

. Exhibit 26: High-End Estimate: Co sts to EPA to Request and Review Certification Statements, 2012 to 2061 (2010 dollars)

Year Number of Requests Per Year A Undiscounted Cost A X $47 3% Discounted Cost 7% Discounted Cost

2012 0 $0 $0 $0
2013 0 $0 $0 $0
2014 0 $0 $0 $0
2015 0 $0 $0 $0
2016 0 $0 $0 $0
2017 1 $47 $41 $34
2018 1 $47 $39 $31
2019 1 $47 $38 $29
2020 1 $47 $37 $27
2021 1 $47 $36 $26
2022 1 $47 $35 $24
2023 1 $47 $34 $22
2024 1 $47 $33 $21
2025 1 $47 $32 $20
2026 1 $47 $31 $18
2027 1 $47 $30 $17
2028 1 $47 $29 $16
2029 1 $47 $28 $15
2030 1 $47 $28 $14
2031 1 $47 $27 $13
2032 1 $47 $26 $12
2033 1 $47 $25 $11
2034 2 $94 $49 $21
2035 2 $94 $48 $20
2036 2 $94 $46 $19
2037 2 $94 $45 $17
2038 2 $94 $44 $16
2039 2 $94 $42 $15
2040 2 $94 $41 $14
2041 2 $94 $40 $13
2042 2 $94 $39 $12
2043 2 $94 $38 $12

### Page 54 of 145 Year Number of Requests Per Year A Undiscounted Cost A X $47 3% Discounted Cost 7% Discounted Cost

2044 2 $94 $37 $11
2045 2 $94 $35 $10
2046 2 $94 $34 $9
2047 2 $94 $33 $9
2048 2 $94 $32 $8
2049 2 $94 $31 $8
2050 2 $94 $31 $7
2051 2 $94 $30 $7
2052 2 $94 $29 $6
2053 2 $94 $28 $6
2054 2 $94 $27 $5
2055 2 $94 $26 $5
2056 2 $94 $26 $5
2057 2 $94 $25 $4
2058 2 $94 $24 $4
2059 2 $94 $23 $4
2060 2 $94 $23 $4
2061 2 $94 $22 $3 50 Year Total 73 $3,431 $1,498 $626



### Exhibit 27: High-End Estimate: Costs to St ate Governments to Request and Review Certification Statements , 2012 to 2061 (2010 dollars)

Year Number of Requests Per Year A Undiscounted Cost A X $61 3% Discounted Cost 7% Discounted Cost

2012 2 $122 $122 $122
2013 3 $183 $178 $171
2014 3 $183 $172 $160
2015 3 $183 $167 $149
2016 4 $244 $217 $186
2017 6 $366 $316 $261
2018 6 $366 $307 $244
2019 6 $366 $298 $228
2020 6 $366 $289 $213
2021 6 $366 $281 $199
2022 6 $366 $272 $186
2023 6 $366 $264 $174

### Page 55 of 145 Year Number of Requests Per Year A Undiscounted Cost A X $61 3% Discounted Cost 7% Discounted Cost

2024 6 $366 $257 $163
2025 6 $366 $249 $152
2026 6 $366 $242 $142
2027 6 $366 $235 $133
2028 6 $366 $228 $124
2029 6 $366 $221 $116
2030 9 $549 $322 $162
2031 9 $549 $313 $152
2032 12 $732 $405 $189
2033 12 $732 $393 $177
2034 14 $854 $446 $193
2035 15 $915 $464 $193
2036 15 $915 $450 $180
2037 15 $915 $437 $169
2038 15 $915 $424 $158
2039 15 $915 $412 $147
2040 15 $915 $400 $138
2041 15 $915 $388 $129
2042 15 $915 $377 $120
2043 15 $915 $366 $112
2044 15 $915 $355 $105
2045 15 $915 $345 $98
2046 15 $915 $335 $92
2047 15 $915 $325 $86
2048 15 $915 $316 $80
2049 15 $915 $307 $75
2050 15 $915 $298 $70
2051 15 $915 $289 $65
2052 15 $915 $280 $61
2053 15 $915 $272 $57
2054 15 $915 $264 $53
2055 15 $915 $257 $50
2056 15 $915 $249 $47
2057 15 $915 $242 $44
2058 15 $915 $235 $41
2059 15 $915 $228 $38

### Page 56 of 145 Year Number of Requests Per Year A Undiscounted Cost A X $61 3% Discounted Cost 7% Discounted Cost

2060 15 $915 $221 $36
2061 15 $915 $215 $33 50 Year Total 554 $33,794 $14,947 $6,471



### Exhibits 28 and 29 below present the low-end es timates for the total costs to EPA and state governments to request and review certification statements related to the proposed exclusion over the 50-year period beginning 2012. These exhi bits present undiscounted costs, and also apply 3 percent and 7 percent discount rates to costs incu rred after 2012.

. Exhibit 28: Low-End Estimate: Costs to EPA to Request and Review Certification Statements, 2012 to 2061 (2010 dollars)

Year Number of Requests Per Year A Undiscounted Cost A X $47 3% Discounted Cost 7% Discounted Cost

2012 0 $0 $0 $0

2013 0 $0 $0 $0

2014 0 $0 $0 $0

2015 0 $0 $0 $0

2016 0 $0 $0 $0

2017 0 $0 $0 $0

2018 0 $0 $0 $0

2019 0 $0 $0 $0

2020 0 $0 $0 $0

2021 0 $0 $0 $0

2022 0 $0 $0 $0

2023 0 $0 $0 $0

2024 0 $0 $0 $0

2025 0 $0 $0 $0

2026 0 $0 $0 $0

2027 0 $0 $0 $0

2028 0 $0 $0 $0

2029 0 $0 $0 $0

2030 1 $47 $28 $14

2031 1 $47 $27 $13

2032 1 $47 $26 $12

2033 1 $47 $25 $11

2034 1 $47 $25 $11

2035 1 $47 $24 $10

### Page 57 of 145 Year Number of Requests Per Year A Undiscounted Cost A X $47 3% Discounted Cost 7% Discounted Cost

2036 1 $47 $23 $9

2037 1 $47 $22 $9

2038 1 $47 $22 $8

2039 1 $47 $21 $8

2040 1 $47 $21 $7

2041 1 $47 $20 $7

2042 1 $47 $19 $6

2043 1 $47 $19 $6

2044 1 $47 $18 $5

2045 1 $47 $18 $5

2046 1 $47 $17 $5

2047 1 $47 $17 $4

2048 1 $47 $16 $4

2049 1 $47 $16 $4

2050 1 $47 $15 $4

2051 1 $47 $15 $3

2052 1 $47 $14 $3

2053 1 $47 $14 $3

2054 1 $47 $14 $3

2055 1 $47 $13 $3

2056 1 $47 $13 $2

2057 1 $47 $12 $2

2058 1 $47 $12 $2

2059 1 $47 $12 $2

2060 1 $47 $11 $2

2061 1 $47 $11 $2

50 Year Total 32 $1,504 $580 $188

### Page 58 of 145 Exhibit 29: Low-End Estimate: Costs to St ate Governments to Request and Review Certification Statements , 2012 to 2061 (2010 dollars)

Year Number of Requests Per Year A Undiscounted Cost A X $61 3% Discounted Cost 7% Discounted Cost

2012 1 $61 $61 $61

2013 1 $61 $59 $57

2014 1 $61 $57 $53

2015 1 $61 $56 $50

2016 1 $61 $54 $47

2017 3 $183 $158 $130

2018 3 $183 $153 $122

2019 3 $183 $149 $114

2020 3 $183 $144 $107

2021 3 $183 $140 $100

2022 3 $183 $136 $93

2023 3 $183 $132 $87

2024 3 $183 $128 $81

2025 3 $183 $125 $76

2026 3 $183 $121 $71

2027 3 $183 $117 $66

2028 3 $183 $114 $62

2029 3 $183 $111 $58

2030 5 $305 $179 $90

2031 5 $305 $174 $84

2032 5 $305 $169 $79

2033 5 $305 $164 $74

2034 5 $305 $159 $69

2035 5 $305 $155 $64

2036 5 $305 $150 $60

2037 5 $305 $146 $56

2038 5 $305 $141 $53

2039 5 $305 $137 $49

2040 5 $305 $133 $46

2041 5 $305 $129 $43

2042 5 $305 $126 $40

2043 5 $305 $122 $37

2044 5 $305 $118 $35

2045 5 $305 $115 $33

2046 5 $305 $112 $31

### Page 59 of 145 Year Number of Requests Per Year A Undiscounted Cost A X $61 3% Discounted Cost 7% Discounted Cost

2047 5 $305 $108 $29

2048 5 $305 $105 $27

2049 5 $305 $102 $25

2050 5 $305 $99 $23

2051 5 $305 $96 $22

2052 5 $305 $93 $20

2053 5 $305 $91 $19

2054 5 $305 $88 $18

2055 5 $305 $86 $17

2056 5 $305 $83 $16

2057 5 $305 $81 $15

2058 5 $305 $78 $14

2059 5 $305 $76 $13

2060 5 $305 $74 $12

2061 5 $305 $72 $11

50 Year Total 204 $12,444 $5,779 $2,656



### 3.5 Incremental Cost Savings and Benefits of the Proposed Rule

CO 2 

### streams managed by GS would be excl uded from the RCRA hazardous waste requirements under the proposed rule. 59 

### This change would result in three areas of savings for the generators of CO 2 

### streams: exclusion from hazardous waste determination, exclusion from compliance with RCRA training, planni ng, and reporting requirements, and exclusion from hazardous waste treatment requirements. CO 2 

### sequestration facilities managing RCRA hazardous waste CO 2 

### streams under a Class I hazardous wa ste well permit in the baseline would also see savings related to hazardous waste determination a nd compliance with the training, planning, and reporting requirements.

3.5.1 Waste Determination Savings for CO 2 

### Capture Facilities

In the absence of the proposed rule, facilities capturing CO 2 

### destined for GS would be required to determine whether the CO 2 

### stream qualifies as RCRA hazardous waste either by testing the content of the wast e or by applying knowledge of th e materials and processes used to generate the waste, as required by 40 CFR 262.11 (Hazardous waste determination).

59 Section 1.2 of this document summarizes requirements applicab le to generators of RCRA hazardous waste CO 2 in the baseline.

### Page 60 of 145 Appendix A of this document discusses the ava ilable testing options fo r waste determination (i.e., Option 1, 2, and 3). As stat ed in Section 3.2, th is analysis assumes that the facilities capturing CO 2 

### streams from fossil fuel electric powe r generation, natura l gas distribution, ethyl alcohol manufacturing, and nitrogenous fe rtilizer manufacturing would rely on process knowledge and limited testing to determine if their CO 2 

### stream is a RCRA hazardous waste (i.e., Option 3). The analysis further assu mes that the remaining facilities capturing CO 2 

### streams from oil and gas ex traction would test their CO 2 

### streams as a gas to determine whether their CO 2 

### stream is a RCRA hazardous waste (i.e ., Option 1). This analysis applies weighted average waste determination costs of approximately $5,300 in one-time costs and $3,000 in annual costs. 60 

### Under the proposed rule, exempt generators would not be required to determine whether their CO 2 

### stream is or is not RCRA hazardous waste.

3.5.2 RCRA Training, Planning, and Reporting Requirement Savings for CO 2 

### Capture Facilities

This analysis assumes that genera tors who send RCRA hazardous waste CO 2 

### streams to a Class I hazardous waste well and generators w ho treat their RCRA hazardous waste and then send it to Class VI wells are LQGs in the baseline. Thus, these facilities would be subject to the full set of RCRA hazardous waste regula tions, including traini ng, planning, and reporting requirements. The proposed rule would relieve these generators of the costs associated with these requirements. Exhibit 30 estimates the a nnual savings per facility that would no longer be subject to the RCRA training, planning a nd reporting requirements under the proposed rule.

60 See Appendix A for further detail on the calculation of waste determination costs.

### Page 61 of 145 Exhibit 30: Estimated Annua l RCRA Training, Planning, and Reporting Requirement Savings Per Hazardous CO 2 

### Capture Facility as a Result of the Proposed Rule (2010 dollars) Requirement Citation Savings Per Facility a 

### EPA ID b 

### 262.12 $0 Personnel Training c 

### 262.34 $2,762

Contingency Planning c 

### 262.34 $733

Emergency Planning c 

### 262.34 $482 Recordkeeping c 

### 262.40 $711

Manifest d 

### 262 Subpart B $0 Manifest Exception Report d 

### 262.42 $0 Biennial Report c 

### 262.41 $369 Total $5,057

a These savings apply to facilities that capture hazardous waste CO 2 streams that did not cease capture in the baseline.
b Acquiring an EPA ID is not an incremental cost for existing facilities, and is assumed to be a negligible cost for new facilities.

c These savings are consistent with the savings estimated in EPA’s “Regulatory Impact Analysis: 2008 Final Rule Amendments to the Industrial Recycling Exclusions of the RCRA Definition of Solid Waste,” which also excluded certain generators from the RCRA training, planning, and reporting requireme nts. The savings are adjusted to 2010 dollars using the Bureau of Labor Statistics (BLS) Inflation Calculator.
d The analysis assumes that generators transport their CO 2 by pipeline only. The manifest requirements do not apply to pipeline transportation, so no savings are anticipated.



### 3.5.3 CO 2 

### Treatment Savings for CO 2 

### Capture Facilities

Generators that treat their CO 2 

### stream so that they can send it to a Class VI well in the baseline would not need to do so un der the proposed rule. Treating a CO 2 

### stream to render it non-hazardous is an expensive process. EPA estimates that treatment of a CO 2 

### stream generated at an oxy-fuel power plant would cost $9.74 per metric ton of CO 2 

### , and treatment of a CO 2 

### stream generated at an Integrated Gasi fication Combined Cycle (IGCC) power plant would cost $8.94 per metric ton of CO 2


### . 61 

### Taking the average of these two costs, this analysis estimates that treating a CO 2 

### stream to render it non-hazardous costs $9.33 per metric ton of CO 2 

### . The ten current CO 2 

### capture operations combined [which are currently capturing CO 2 

### for use in enhanced oil recovery (EOR), not for sequestration] captured 11 million metric tons of CO 2 

### waste in 2008, or about 1.1 million metric tons per facility. 62 

### If

61 Appendix B presents the calculation of these CO 2 treatment costs. 62 EPA, “Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2008,” April 15, 2010, Table 3-47: Potential Emissions from CO 2 Capture and Transport, p. 3-53, http://www.epa.gov/climatechange/emissions/ downloads10/US-GHG-Inventory-2010_Report.pdf

. .

### Page 62 of 145 the planned CO 2 

### capture facilities generate CO 2 

### streams at a similar rate, each facility that treats its CO 2 

### stream in the baseline would save approximately $10.27 million per year in CO 2 

### stream treatment costs under the proposed rule.

3.5.4 Summary of Savings to CO 2 

### Capture Facilities

Exhibit 31 multiplies each of the savings iden tified above times the appropriate number of facilities that would receive each saving in 2012, and calculates a total expected savings of approximately $10.31 million to CO 2 

### capture facilities in the first year under the proposed rule.

Exhibit 31: Savings to CO 2 

### Capture Facilities as a Resu lt of the Proposed Rule, By Baseline Practice in 2012 (2010 dollars)

Baseline Practice Number of Facilities A Savings Per Facility Under the Proposed Rule B Total Savings Under the Proposed Rule A X B
Waste Determination (One Time) a 3 $5,273 $15,819

Waste Determination

(Annual) b 4 $3,073 $12,293

RCRA Training,

Planning, and

Reporting Requirements c 3 $5,057 $15,171

CO 2 Treatment d 1 $10,270,395 $10,270,395

Total $10,313,678

a One-time waste determination sa vings apply only to those CO 2 capture facilities claiming the exclusion for the first time. Note : One capture facility was in operation in 2010.
b Annual waste determinations savings apply to all CO 2 capture facilities claiming the exclusion in each year beginning with the first year of capture, except for those facilities that would have ceased capture in the absence of the propose rule. Those facilities would only see the “annual” waste determ ination savings in the first year of capture because they would not have conducted wast e determinations in subs equent years after ceasing capture.

c RCRA training, planning, and reporting re quirement savings ap ply only to those CO 2 capture facilities that generate RCRA hazardous waste CO 2 streams and do not cease capture in the baseline (i.e. facilities that treat their CO 2 or send their RCRA hazardous waste CO 2 stream to a Class I well in the baseline).
d CO 2 treatment savings apply only to those CO 2 capture facilities that treat their RCRA hazardous waste CO 2 streams and send them to Class VI wells in the baseline.



### Exhibits 32 and 33 below apply the methodology de scribed above to calculate the expected savings to CO 2 

### Capture Facilities under the high-end and low-end estimates. Savings as a result of the proposal are calculated for each year over a 50-year period beginning in 2012. The exhibits present the undiscounted savings , and also apply 3 pe rcent and 7 percent discount rates to savi ngs accrued after 2012.

### Page 63 of 145 Exhibit 32: High-End Estimate: Savings to CO 2 

### Capture Facilities as a Result of the Proposed Rule, 2012 to 2061 (2010 dollars)

Year Waste Determination Hazardous Waste Requirements CO 2 Treatment Total Savings (Undiscounted) Total Savings (3% Discount Rate) Total Savings (7% Discount Rate)

2012 $28,112 $15,171 $10,270,395 $10, 313,678 $10,313,678 $10,313,678 2013 $17,566 $15,171 $10,270,395 $10, 303,132 $10,003,041 $9,629,096 2014 $12,293 $15,171 $10,270,395 $10, 297,859 $9,706,720 $8,994,549 2015 $12,293 $15,171 $10,270,395 $10, 297,859 $9,424,000 $8,406,121 2016 $12,293 $15,171 $10,270,395 $10, 297,859 $9,149,515 $7,856,188 2017 $20,639 $20,228 $20,540,791 $20, 581,658 $17,753,919 $14,674,438 2018 $15,366 $20,228 $20,540,791 $20, 576,385 $17,232,398 $13,710,914 2019 $15,366 $20,228 $20,540,791 $20, 576,385 $16,730,484 $12,813,938 2020 $15,366 $20,228 $20,540,791 $20, 576,385 $16,243,188 $11,975,643 2021 $15,366 $20,228 $20,540,791 $20, 576,385 $15,770,086 $11,192,190 2022 $15,366 $20,228 $20,540,791 $20, 576,385 $15,310,763 $10,459,991 2023 $15,366 $20,228 $20,540,791 $20, 576,385 $14,864,818 $9,775,692 2024 $15,366 $20,228 $20,540,791 $20, 576,385 $14,431,862 $9,136,161 2025 $15,366 $20,228 $20,540,791 $20, 576,385 $14,011,517 $8,538,468 2026 $15,366 $20,228 $20,540,791 $20, 576,385 $13,603,414 $7,979,877 2027 $15,366 $20,228 $20,540,791 $20, 576,385 $13,207,199 $7,457,829 2028 $15,366 $20,228 $20,540,791 $20, 576,385 $12,822,523 $6,969,933 2029 $15,366 $20,228 $20,540,791 $20, 576,385 $12,449,051 $6,513,957 2030 $90,483 $45,513 $41,081,581 $41, 217,577 $24,210,982 $12,194,794 2031 $42,152 $50,570 $51,351,976 $51, 444,699 $29,338,193 $14,224,888 2032 $70,264 $60,684 $61,622,372 $61, 753,320 $34,191,316 $15,958,231 2033 $43,026 $60,684 $61,622,372 $61, 726,082 $33,180,810 $14,907,657 2034 $84,757 $75,855 $71,892,767 $72, 053,379 $37,604,118 $16,263,396 2035 $72,012 $80,912 $82,163,162 $82, 316,086 $41,708,881 $17,364,322 2036 $58,393 $80,912 $82,163,162 $82, 302,467 $40,487,360 $16,225,653 2037 $58,393 $80,912 $82,163,162 $82, 302,467 $39,308,116 $15,164,162 2038 $58,393 $80,912 $82,163,162 $82, 302,467 $38,163,220 $14,172,114 2039 $58,393 $80,912 $82,163,162 $82, 302,467 $37,051,670 $13,244,966 2040 $58,393 $80,912 $82,163,162 $82, 302,467 $35,972,495 $12,378,473 2041 $58,393 $80,912 $82,163,162 $82, 302,467 $34,924,752 $11,568,666 2042 $58,393 $80,912 $82,163,162 $82, 302,467 $33,907,527 $10,811,838 2043 $58,393 $80,912 $82,163,162 $82, 302,467 $32,919,929 $10,104,521 2044 $58,393 $80,912 $82,163,162 $82, 302,467 $31,961,096 $9,443,478 2045 $58,393 $80,912 $82,163,162 $82, 302,467 $31,030,190 $8,825,680 2046 $58,393 $80,912 $82,163,162 $82, 302,467 $30,126,398 $8,248,299 2047 $58,393 $80,912 $82,163,162 $82, 302,467 $29,248,930 $7,708,691 2048 $58,393 $80,912 $82,163,162 $82, 302,467 $28,397,020 $7,204,384 2049 $58,393 $80,912 $82,163,162 $82, 302,467 $27,569,922 $6,733,069 2050 $58,393 $80,912 $82,163,162 $82, 302,467 $26,766,915 $6,292,588 2051 $58,393 $80,912 $82,163,162 $82, 302,467 $25,987,296 $5,880,923 2052 $58,393 $80,912 $82,163,162 $82, 302,467 $25,230,384 $5,496,190 2053 $58,393 $80,912 $82,163,162 $82, 302,467 $24,495,519 $5,136,626

### Page 64 of 145 2054 $58,393 $80,912 $82,163,162 $82, 302,467 $23,782,057 $4,800,585 2055 $58,393 $80,912 $82,163,162 $82, 302,467 $23,089,376 $4,486,528 2056 $58,393 $80,912 $82,163,162 $82, 302,467 $22,416,870 $4,193,017 2057 $58,393 $80,912 $82,163,162 $82, 302,467 $21,763,951 $3,918,708 2058 $58,393 $80,912 $82,163,162 $82, 302,467 $21,130,050 $3,662,344 2059 $58,393 $80,912 $82,163,162 $82, 302,467 $20,514,611 $3,422,751 2060 $58,393 $80,912 $82,163,162 $82, 302,467 $19,917,098 $3,198,833 2061 $58,393 $80,912 $82,163,162 $82, 302,467 $19,336,989 $2,989,563 50 Year Total $2,208,498 $2,816,749 $2,824,358, 694 $2,829,383,941 $1, 188,762,217 $472,624,602

See Exhibits 15 for number of affected facilities, by category. Year 2030 Example: [(9 new one-time facilities * $5,273) + (14 annual * $3,073)]. Note that one cease capture facility from prior year drops out.



### Exhibit 33: Low-End Estimate: Savings to CO 2 

### Capture Facilities as a Result of the Proposed Rule, 2012 to 2061 (2010 dollars)

Year Waste Determination Hazardous Waste Requirements CO 2 Treatment Total Savings (Undiscounted) Total Savings (3% Discount Rate) Total Savings (7% Discount Rate)

2012 $28,112 $0 $0 $28,112 $28,112 $28,112

2013 $20,639 $0 $0 $20,639 $20,038 $19,289

2014 $15,366 $0 $0 $15,366 $14,484 $13,422

2015 $15,366 $0 $0 $15,366 $14,063 $12,544

2016 $15,366 $0 $0 $15,366 $13,653 $11,723

2017 $23,713 $5,057 $10,270,395 $10,2 99,165 $8,884,150 $7,343,162

2018 $18,440 $5,057 $10,270,395 $10,2 93,892 $8,620,973 $6,859,255

2019 $18,440 $5,057 $10,270,395 $10,2 93,892 $8,369,876 $6,410,519

2020 $18,440 $5,057 $10,270,395 $10,2 93,892 $8,126,093 $5,991,139

2021 $18,440 $5,057 $10,270,395 $10,2 93,892 $7,889,411 $5,599,195

2022 $18,440 $5,057 $10,270,395 $10,2 93,892 $7,659,622 $5,232,893

2023 $18,440 $5,057 $10,270,395 $10,2 93,892 $7,436,527 $4,890,554

2024 $18,440 $5,057 $10,270,395 $10,2 93,892 $7,219,929 $4,570,611

2025 $18,440 $5,057 $10,270,395 $10,2 93,892 $7,009,640 $4,271,599

2026 $18,440 $5,057 $10,270,395 $10,2 93,892 $6,805,475 $3,992,149

2027 $18,440 $5,057 $10,270,395 $10,2 93,892 $6,607,258 $3,730,980

2028 $18,440 $5,057 $10,270,395 $10,2 93,892 $6,414,813 $3,486,897

2029 $18,440 $5,057 $10,270,395 $10,2 93,892 $6,227,974 $3,258,783

2030 $93,556 $5,057 $10,270,395 $10,3 69,008 $6,090,699 $3,067,815

2031 $54,446 $10,114 $10,270,395 $10,3 34,955 $5,893,880 $2,857,701

2032 $82,558 $10,114 $10,270,395 $10,3 63,067 $5,737,779 $2,678,013

2033 $61,466 $10,114 $10,270,395 $10,3 41,975 $5,559,321 $2,497,722

2034 $103,197 $10,114 $10,270,395 $10,3 83,706 $5,419,178 $2,343,739

2035 $93,525 $10,114 $10,270,395 $10,3 74,034 $5,256,437 $2,188,370

2036 $79,906 $10,114 $10,270,395 $10,3 60,415 $5,096,638 $2,042,521

### Page 65 of 145 2037 $79,906 $10,114 $10,270,395 $10,3 60,415 $4,948,192 $1,908,898

2038 $79,906 $10,114 $10,270,395 $10,3 60,415 $4,804,070 $1,784,017

2039 $79,906 $10,114 $10,270,395 $10,3 60,415 $4,664,145 $1,667,305

2040 $79,906 $10,114 $10,270,395 $10,3 60,415 $4,528,297 $1,558,229

2041 $79,906 $10,114 $10,270,395 $10,3 60,415 $4,396,404 $1,456,289

2042 $79,906 $10,114 $10,270,395 $10,3 60,415 $4,268,354 $1,361,018

2043 $79,906 $10,114 $10,270,395 $10,3 60,415 $4,144,033 $1,271,979

2044 $79,906 $10,114 $10,270,395 $10,3 60,415 $4,023,333 $1,188,766

2045 $79,906 $10,114 $10,270,395 $10,3 60,415 $3,906,148 $1,110,996

2046 $79,906 $10,114 $10,270,395 $10,3 60,415 $3,792,377 $1,038,314

2047 $79,906 $10,114 $10,270,395 $10,3 60,415 $3,681,919 $970,387

2048 $79,906 $10,114 $10,270,395 $10,3 60,415 $3,574,679 $906,904

2049 $79,906 $10,114 $10,270,395 $10,3 60,415 $3,470,562 $847,574

2050 $79,906 $10,114 $10,270,395 $10,3 60,415 $3,369,478 $792,125

2051 $79,906 $10,114 $10,270,395 $10,3 60,415 $3,271,338 $740,304

2052 $79,906 $10,114 $10,270,395 $10,3 60,415 $3,176,056 $691,872

2053 $79,906 $10,114 $10,270,395 $10,3 60,415 $3,083,550 $646,610

2054 $79,906 $10,114 $10,270,395 $10,3 60,415 $2,993,737 $604,308

2055 $79,906 $10,114 $10,270,395 $10,3 60,415 $2,906,541 $564,774

2056 $79,906 $10,114 $10,270,395 $10,3 60,415 $2,821,885 $527,826

2057 $79,906 $10,114 $10,270,395 $10,3 60,415 $2,739,694 $493,296

2058 $79,906 $10,114 $10,270,395 $10,3 60,415 $2,659,897 $461,024

2059 $79,906 $10,114 $10,270,395 $10,3 60,415 $2,582,424 $430,863

2060 $79,906 $10,114 $10,270,395 $10,3 60,415 $2,507,208 $402,676

2061 $79,906 $10,114 $10,270,395 $10,3 60,415 $2,434,183 $376,333
50 Year Total $2,906,136 $384,332 $462, 167,786 $465,458,254 $22 5,164,528 $107,201,394

See Exhibits 16 for number of affected facilities, by category.

### Page 66 of 145 3.5.5 Waste Determination Savings for CO 2 

### Sequestration Facilities

In the absence of the proposed rule , sequestration facilities managing CO 2 

### in Class I hazardous waste or Class VI wells would be requ ired to confirm the characteristics of the waste stream to ensure it has been properly characterized by th e generator or transporter. Post-rule, the CO 2 

### stream would be excluded from the definition of RCRA hazardous and this testing would not be needed. EPA estimates that each sequestration well would save approximately $4,500 in one time testing costs and $1,500 in annual testing costs. 63



### 3.5.6 RCRA Training, Planning, and Re porting Requirement Savings for CO 2 

### Sequestration Facilitie s
In the baseline, Class I hazardous waste injecti on wells that are assumed to follow the Class VI standards would be used to manage RCRA hazardous waste CO 2 

### streams, and would be subject to hazardous waste management requ irements in the baseline, per 40 CFR 144.14 (Requirements for wells injecting hazardous wast e). The injection wells used to manage exempt CO 2 

### streams are expected to be permitted as Class VI wells under the proposed rule, not as Class I wells. Because they would not be managing hazardous wastes as Class VI wells, under the proposed rule, they would not be subject to the requirements for hazardous waste managers, resulting in a savings to th ese wells. Some of these savings would be negligible or offset by requirements for Class VI wells. Exhibit 34 lists the requirements for UIC Class I hazardous waste wells from which these CO 2 

### sequestration wells would be exempt if they claim the proposed exclusion. Th e exhibit also presents the expected savings associated with each requirement.

63 See Appendix A for further detail on the calculation of waste determination costs.

### Page 67 of 145 Exhibit 34: Estimated Annua l RCRA Training, Planning, and Reporting Requirement

Savings as a Result of the Proposed Rule Per Hazardous CO 2 

### Sequestration Facility (2010 dollars) Requirement Citation Net Savings Per Facility a 

### Notification b 

### 144.14(c)(1) $0 EPA ID b 

### 144.14(c)(2) $0

Manifest c 

### 144.14(c)(3) $0 Manifest Discrepancies c 

### 144.14(c)(4) $0 Operating Record b 

### 144.14(c)(5) $0 Biennial Report d 

### 144.14(c)(6) $0 Unmanifested Waste Report c 

### 144.14(c)(7) $0 Personnel Training e 

### 144.14(c)(8) $2,762 Certification of closure b 

### 144.14(c)(9) $0 Total $2,762

a These savings apply to sequestration f acilities that managed hazardous waste CO 2 streams in the baseline under Class I UIC permits.
b Exclusion from these requirements may result in slight sa vings, but this analysis assumes those savings to be negligible.

c Acquiring an EPA ID is assumed to be a negligible cost for new facilities.
d The Class VI rule has a semiannual reporting requirement that requires a similar level of detail as the Biennial Report requirement for Class I wells. Data collection is assumed to be the primary cost of each reporting requirement, and is assumed to be comparable for Class I and Class VI wells. The paperwork costs for the Class VI requirements should exceed the costs under the Class I requirements, but the difference is assumed to be negligible.

e This saving is consistent with the savings for LQGs estimated in EPA’s “Regulator y Impact Analysis of the 2008 Final Rule Amendments to the Industrial Recycling Exclusions of the RCRA Definition Of Solid Waste,” which also excluded certain generators from the RCRA training, planning, and reporting requirements. The savings are adjust ed to 2010 dollars using the Bureau of Labor Statistics (BLS) Inflation Calculator.



### 3.5.7 Summary of Savings to CO 2 

### Sequestration Facilities

Exhibit 35 multiplies each of the savings to CO 2 

### sequestration facilities identified in sections 3.5.5 and 3.5.7 times the appropriate number of f acilities (high-end estimate) that would receive each saving in 2012, to calculate th e total expected high-end savings to CO 2 

### sequestration facilities in the fi rst year under th e proposed rule.

### Page 68 of 145 Exhibit 35: Savings to CO 2 

### Sequestration Facilities as a Re sult of the Proposed Rule, By Baseline Practice in 2012 (2010 dollars)

Saving Number of Facilities A Savings Per Facility B Total Savings A X B

Waste Determination (One Time) 2 $4,440 $8,879

Waste Determination (Annual) 2 $1,536 $3,073

Hazardous Waste

Requirements 1 $2,762 $2,762

Total $14,714



### Exhibit 36 uses this methodology to calculate the expected high-end savings as a result of the proposed rule to CO 2 

### Sequestration Facilities for each year over a 50-year period, beginning in 2012. The exhibit presents the undiscounted savings and also applies 3 percent and 7 percent discount rates to sa vings accrued after 2012.

Exhibit 36: High-End Estimate: Savings to CO 2 

### Sequestration Facilities as a Result of the Proposed Rule, 2012 to 2061 (2010 dollars)

Year Waste Determination Hazardous Waste Generator Requirements Total Savings (Undiscounted) Total Savings (3% Discount Rate) Total Savings (7% Discount Rate)

2012 $11,952 $2,762 $14,714 $14,714 $14,714 2013 $9,049 $2,762 $11,811 $11,467 $11,038 2014 $10,585 $2,762 $13,347 $12,581 $11,658 2015 $6,146 $2,762 $8,908 $8,152 $7,271 2016 $18,098 $5,524 $23,622 $20,988 $18,021 2017 $68,979 $13,810 $82,789 $71,414 $59,027 2018 $30,559 $13,810 $44,369 $37,158 $29,565 2019 $26,119 $13,810 $39,929 $32,466 $24,866 2020 $26,119 $13,810 $39,929 $31,520 $23,239 2021 $26,119 $13,810 $39,929 $30,602 $21,719 2022 $26,119 $13,810 $39,929 $29,711 $20,298 2023 $26,119 $13,810 $39,929 $28,846 $18,970 2024 $26,119 $13,810 $39,929 $28,006 $17,729 2025 $26,119 $13,810 $39,929 $27,190 $16,569 2026 $26,119 $13,810 $39,929 $26,398 $15,485 2027 $26,119 $13,810 $39,929 $25,629 $14,472 2028 $26,119 $13,810 $39,929 $24,883 $13,525 2029 $26,119 $13,810 $39,929 $24,158 $12,641 2030 $26,119 $13,810 $39,929 $23,454 $11,814 2031 $32,095 $13,810 $45,905 $26,179 $12,693 2032 $51,560 $19,334 $70,894 $39,252 $18,320 2033 $33,801 $19,334 $53,135 $28,563 $12,833

### Page 69 of 145 Year Waste Determination Hazardous Waste Generator Requirements Total Savings (Undiscounted) Total Savings (3% Discount Rate) Total Savings (7% Discount Rate)

2034 $63,681 $22,096 $85,777 $44,767 $19,361 2035 $53,435 $24,858 $78,293 $39,671 $16,516 2036 $44,556 $24,858 $69,414 $34,147 $13,685 2037 $44,556 $24,858 $69,414 $33,153 $12,790 2038 $44,556 $24,858 $69,414 $32,187 $11,953 2039 $44,556 $24,858 $69,414 $31,250 $11,171 2040 $44,556 $24,858 $69,414 $30,339 $10,440 2041 $44,556 $24,858 $69,414 $29,456 $9,757 2042 $44,556 $24,858 $69,414 $28,598 $9,119 2043 $44,556 $24,858 $69,414 $27,765 $8,522 2044 $44,556 $24,858 $69,414 $26,956 $7,965 2045 $44,556 $24,858 $69,414 $26,171 $7,444 2046 $44,556 $24,858 $69,414 $25,409 $6,957 2047 $44,556 $24,858 $69,414 $24,669 $6,502 2048 $44,556 $24,858 $69,414 $23,950 $6,076 2049 $44,556 $24,858 $69,414 $23,253 $5,679 2050 $44,556 $24,858 $69,414 $22,575 $5,307 2051 $44,556 $24,858 $69,414 $21,918 $4,960 2052 $44,556 $24,858 $69,414 $21,279 $4,636 2053 $44,556 $24,858 $69,414 $20,660 $4,332 2054 $44,556 $24,858 $69,414 $20,058 $4,049 2055 $44,556 $24,858 $69,414 $19,474 $3,784 2056 $44,556 $24,858 $69,414 $18,906 $3,536 2057 $44,556 $24,858 $69,414 $18,356 $3,305 2058 $44,556 $24,858 $69,414 $17,821 $3,089 2059 $44,556 $24,858 $69,414 $17,302 $2,887 2060 $44,556 $24,858 $69,414 $16,798 $2,698 2061 $44,556 $24,858 $69,414 $16,309 $2,521 50 Year Total $1,861,835 $955,652 $2,817,487 $1,316,526 $615,507



### Exhibit 37 uses the same approach to calcu late the expected low-end savings to CO 2 

### Sequestration Facilities over the 50-year period, beginning in 2012. The exhibit presents the undiscounted savings and also applies 3 percen t and 7 percent discount rates to savings accrued after 2012.

### Page 70 of 145 Exhibit 37: Low-End Estimate: Savings to CO 2 

### Sequestration Facilities as a Result of the Proposed Rule, 2012 to 2061 (2010 dollars)

Year Waste Determination Hazardous Waste Generator Requirements Total Savings (Undiscounted) Total Savings (3% Discount Rate) Total Savings (7% Discount Rate)

2012 $11,952 $0 $11,952 $11,952 $11,952

2013 $9,049 $0 $9,049 $8,785 $8,457

2014 $10,585 $0 $10,585 $9,978 $9,246

2015 $6,146 $0 $6,146 $5,624 $5,017

2016 $18,098 $0 $18,098 $16,080 $13,807

2017 $68,979 $2,762 $71,741 $61,884 $51,150

2018 $30,559 $2,762 $33,321 $27,906 $22,203

2019 $26,119 $2,762 $28,881 $23,483 $17,986

2020 $26,119 $2,762 $28,881 $22,799 $16,809

2021 $26,119 $2,762 $28,881 $22,135 $15,709

2022 $26,119 $2,762 $28,881 $21,490 $14,682

2023 $26,119 $2,762 $28,881 $20,864 $13,721

2024 $26,119 $2,762 $28,881 $20,257 $12,824

2025 $26,119 $2,762 $28,881 $19,667 $11,985

2026 $26,119 $2,762 $28,881 $19,094 $11,201

2027 $26,119 $2,762 $28,881 $18,538 $10,468

2028 $26,119 $2,762 $28,881 $17,998 $9,783

2029 $26,119 $2,762 $28,881 $17,474 $9,143

2030 $26,119 $2,762 $28,881 $16,965 $8,545

2031 $32,095 $2,762 $34,857 $19,879 $9,638

2032 $51,560 $2,762 $54,322 $30,077 $14,038

2033 $33,801 $2,762 $36,563 $19,655 $8,831

2034 $63,681 $2,762 $66,443 $34,676 $14,997

2035 $53,435 $2,762 $56,197 $28,475 $11,855

2036 $44,556 $2,762 $47,318 $23,277 $9,329

2037 $44,556 $2,762 $47,318 $22,599 $8,718

2038 $44,556 $2,762 $47,318 $21,941 $8,148

2039 $44,556 $2,762 $47,318 $21,302 $7,615

2040 $44,556 $2,762 $47,318 $20,682 $7,117

2041 $44,556 $2,762 $47,318 $20,079 $6,651

2042 $44,556 $2,762 $47,318 $19,495 $6,216

2043 $44,556 $2,762 $47,318 $18,927 $5,809

2044 $44,556 $2,762 $47,318 $18,375 $5,429

2045 $44,556 $2,762 $47,318 $17,840 $5,074

2046 $44,556 $2,762 $47,318 $17,321 $4,742

2047 $44,556 $2,762 $47,318 $16,816 $4,432

2048 $44,556 $2,762 $47,318 $16,326 $4,142

2049 $44,556 $2,762 $47,318 $15,851 $3,871

2050 $44,556 $2,762 $47,318 $15,389 $3,618

2051 $44,556 $2,762 $47,318 $14,941 $3,381

### Page 71 of 145 Year Waste Determination Hazardous Waste Generator Requirements Total Savings (Undiscounted) Total Savings (3% Discount Rate) Total Savings (7% Discount Rate)

2052 $44,556 $2,762 $47,318 $14,506 $3,160

2053 $44,556 $2,762 $47,318 $14,083 $2,953

2054 $44,556 $2,762 $47,318 $13,673 $2,760

2055 $44,556 $2,762 $47,318 $13,275 $2,579

2056 $44,556 $2,762 $47,318 $12,888 $2,411

2057 $44,556 $2,762 $47,318 $12,513 $2,253

2058 $44,556 $2,762 $47,318 $12,148 $2,106

2059 $44,556 $2,762 $47,318 $11,795 $1,968

2060 $44,556 $2,762 $47,318 $11,451 $1,839

2061 $44,556 $2,762 $47,318 $11,117 $1,719

50 Year Total $1,861,835 $124,290 $1,98 6,125 $944,344 $452,086



### 3.6 Summary of Costs and Savings

The preceding analysis quantifie d the costs and benefits of the proposed rule under both a high-end and low-end scenari o. Detailed costs are presente d for capture facilities, sequestration facilities, state gov ernments, and EPA. Detailed cost savings are presented for capture facilities and sequestra tion facilities. The Exhibits below summarize costs, savings, and net savings over the 50 year period, in aggreg ate, and on an annualized basis for both the high and low scenarios.

High-End Estimate:

Exhibit 38 summarizes the undiscounted 50-year and annualized high-end costs and benefits of the proposed rule. Exhibits 39 and 40 su mmarize the 50-year and annualized high-end costs and benefits of the pr oposed rule applying 3 percent and 7 percent discount rates, respectively.

Under the high-end estimate, the proposed rule is expected to result in undiscounted annualized net savings of approximately $56.6 million. Applying a 3 percent discount rate, the annualized net savings were found to be approximately $44.9 million while a 7 percent discount rate resulted in annualized ne t savings of approximately $32.0 million.

### Page 72 of 145 Exhibit 38: High-End Estimate: Net Costs and Savings of the Proposed Rule - Undiscounted (2010 dollars)

Type of Entity 50-year Costs 50-year Savings 50-year Net Savings Average Annual Net

Savings Capture Facilities $164,544 $2,829,383 ,941 $2,829,219,397 $56,584,388 Sequestration Facilities $198,456 $2 ,817,487 $2,619,031 $52,381 State Governments $33,794 $0 ($33,794) ($676) EPA $3,431 $0 ($3,431) ($69) Total $400,225 $2,832,201,428 $2,831,801,203 $56,636,024



### Exhibit 39: High-End Estimate: Net Costs and Savings of the Proposed Rule – 3% Discount Rate (2010 dollars)

Type of Entity Present Value of 50-year Costs Present Value of 50-year

Savings Present Value of 50- year Net Savings Annualized Net Savings Capture Facilities $70,474 $1,188,762 ,217 $1,188,691,743 $44,853,488 Sequestration Facilities $91,892 $1,316,526 $1,224,634 $46,210 State Governments $14,947 $0 ($14,947) ($564) EPA $1,498 $0 ($1,498) ($57) Total $178,810 $1,190,078,743 $1,189,899,932 $44,899,077



### Exhibit 40: High-End Estimate: Net Costs and Savings of the Proposed Rule – 7% Discount Rate (2010 dollars)

Type of Entity Present Value of 50-year Costs Present Value of 50-year

Savings Present Value of 50- year Net Savings Annualized Net Savings Capture Facilities $29,098 $472,624,602 $472,595,504 $32,003,924 Sequestration Facilities $42,294 $615,507 $573,213 $38,818 State Governments $6,471 $0 ($6,471) ($438) EPA $626 $0 ($626) ($42) Total $78,488 $473,240,109 $473,161,620 $32,042,262



### Low-End Estimate:

Exhibit 41 summarizes the undiscounted 50-year and annualized low-end costs and benefits of the proposed rule. Exhibits 42 and 43 su mmarize the 50-year and annualized low-end costs and benefits of the pr oposed rule applying 3 percent and 7 percent discount rates, respectively.

Under the low-end estimate, th e proposed rule is expected to result in undiscounted annualized net savings of approximately $9.3 million. Applying a 3 percent discount rate, the annualized net savings were found to be approximately $8.5 million. Applying a 7 percent discount rate, the annualized net savings are approximately $7.3 million.

### Page 73 of 145 Exhibit 41: Low-End Estimate: Net Costs and Savings of the Proposed Rule - Undiscounted (2010 dollars)

Type of Entity 50-year Costs 50-year Savings 50-year Net Savings Average Annual Net

Savings Capture Facilities $164,544 $465,458,254 $465,293,710 $9,305,874 Sequestration Facilities $199,494 $1,986,125 $1,786,631 $35,733
State Governments $33,794 $0 ($33,794) ($676)

EPA $3,431 $0 ($3,431) ($69)
Total $401,263 $467,444,379 $467,043,116 $9,340,862



### Exhibit 42: Low-End Estimate: Net Costs and Savings of the Proposed Rule – 3% Discount Rate (2010 dollars)

Type of Entity Present Value of 50-year Costs Present Value of 50-year

Savings Present Value of 50- year Net Savings Annualized Net Savings Capture Facilities $70,474 $225,164,528 $225,094,055 $8,493,584 Sequestration Facilities $92,362 $944,344 $851,982 $32,148
State Governments $14,947 $0 ($14,947) ($564)

EPA $1,498 $0 ($1,498) ($57)
Total $179,280 $226,108,872 $225,929,592 $8,525,112



### Exhibit 43: Low-End Estimate: Net Costs and Savings of the Proposed Rule – 7% Discount Rate (2010 dollars)

Type of Entity Present Value of 50-year Costs Present Value of 50-year

Savings Present Value of 50- year Net Savings Annualized Net Savings Capture Facilities $29,098 $107,201,394 $107,172,296 $7,257,653 Sequestration Facilities $42,503 $452,086 $409,583 $27,737
State Governments $6,471 $0 ($6,471) ($438)

EPA $626 $0 ($626) ($42)
Total $78,697 $107,653,479 $107,574,782 $7,284,909

### Page 74 of 145 Summary:

Due to the high level of uncertain ty regarding the percent of CO 2 

### that may be RCRA hazardous, and the uncertainty regarding the actu al number of facilities potentially affected over the projected 50 year period, EPA estimates that the annualized net savings of the proposed rule could range anywhere from th e low-end annualized savings of $7.3 million (7% discount rate) to the high-end annualized savings of $44.9 million (3%discount rate).

Under Executive Order 12866, a rule qualifies as economically signif icant if its annual effect on the economy is $100 million or more. This proposed rule is not expected to be economically significant, as defi ned under Executive Order 12866.

3.7 Unquantified Benefits of the Proposed Rule

In addition to the quantified savings discussed ab ove, the proposed rule also represents a step toward establishing a supporti ng regulatory framework for the future development and deployment of carbon capture sequestration (CCS) technology. The rule will help provide the regulatory certainty needed to fost er industry adoption of CCS. There are no environmental costs expected as a result of the proposed rule, because both the Class I hazardous waste and Class VI UIC regulati ons are sufficient to ensure that CO 2 

### streams are managed so as to protect public health and the environment.

4. Regulatory Flexibility Analysis

The Regulatory Flexibility Act (RFA), as amended by the Small Business Regulatory Enforcement and Fairness Act, 5 U.S.C. §§ 601- 612, generally requires an agency to conduct a regulatory flexibility analysis for any ru le subject to notice and comment rulemaking requirements unless the agency certifies that the rule will not have a significant economic impact on a substantial number of small entitie s. Small entities include small businesses, small not-for-profit enterprises, and small governmental jurisdictions.

This proposed rule does not have a significan t impact on a substant ial number of small entities because it relieves th e regulatory burden associated with EPA’s hazardous waste regulations on CO 2 

### capture and sequestrati on facilities by exempting CO 2 

### captured for the purpose of GS in Class VI well from the defi nition of hazardous waste. For each facility claiming the proposed exclusion, these savings ar e expected to outweigh the cost to prepare and maintain the required certification statement. The Agency estimates that this proposed rule could lead to net cost savings in the range of $7.3 to $56.6 million annually. Accordingly, EPA certifies that the rule will not have a significan t economic impact on a substantial number of small entities.

### Page 75 of 145 5. References

Birkholzer, J., J. Apps, L. Zheng, Y. Zhang, T. Xu, and C.F. Tsang. “Research Project on CO 2 

### Geological Storage and Groundwater Resources : Water Quality Effects Caused by CO2 Intrusion into Shallow Groundwater. ” Lawrence Berkeley National Laboratory. #LBNL1251E. October, 2008. Available: http://repositories.cd lib.org/lbnl/LBNL-1251E . As cited by EPA in the preamble to the Federal Re quirements Under the Underground Injection Control Program for Carbon Dioxide Geologi c Sequestration Wells Final Rule, RIN 2040- AE98.

Department of Energy, National Energy T echnology Lab. Carbon Capture and Storage Database. Available: http://www.netl.doe.gov/technologies /carbon_seq/database/index.html

Department of Labor, Bureau of Labor Statistics . “CPI Inflation Calc ulator.” Available: http://www.bls.gov/data/in flation_calculator.htm

. Department of Labor, Bureau of Labor Statisti cs. “Employment Cost Index Historical Listing Current-dollar March 2001-September 2010.” Available: http://www.bls.gov/web/eci/ echistrynaics.pdf

Department of Labor. Bureau of Labor Statis tics. “May 2009 Nati onal Industry-Specific Occupational Employment and Wage Estimat es, NAICS 999200 – State Government.” Avialable: http://www.bls .gov/oes/current/naics4_999200.htm.

Department of Labor, Bureau of Labor Statis tics. “Occupational Employment Statistics, May 2009 National Occupational and Wage Estimates , United States.” Last modified May 14. 2010, Available: http://www.bls.gov/oe s/current/oes_nat.htm

. Department of Transportation, Pipeline and Hazardous Materials Sa fety Administration (PHMSA). 2008 Hazardous Liquids Annual Data. Available: http://www.phmsa.dot.gov/staticfiles/PHMS A/DownloadableFiles/Files/LIQANN08.zip

. Eads, Mark and DPRA Incorporated. “Re gulatory Impact Analysis: 2008 Final Rule Amendments to the Industrial Recycling Ex clusions of the RCRA Definition of Solid Waste.” Environmental Protection Agenc y, Office of Solid Waste. September 2008.

EPA. “Inventory of U.S. Greenhouse Gas Em issions and Sinks: 1990- 2008.” Table 3-47: Potential Emissions from CO2 Capture and Tr ansport. p. 3-53. April 15, 2010. Available: http://www.epa.gov/climatechange/emi ssions/downloads10/US-GHG-Inventory2010_Report.pdf

EPA. “Cost Analysis for the Federal Requireme nts Under the Undergr ound Injection Control Program for Carbon Dioxide Geol ogic Sequestration Wells (Fin al GS Rule).” Office of Water (4606M). EPA 816-R-10-013. 2010.

### Page 76 of 145 EPA. Final Rule for Federal Requirements Unde r the Underground Inje ction Control (UIC) Program for Carbon Dioxide (CO2) Geologi c Sequestration (GS) Wells. Signed by the Administrator on November 22, 2010.

Koch Industries. “Koch Industries Welcomes 2009 Leadership Kansas Class.” July 27, 2009. Available: http://www.kochind.com/files/ 070709KIILeadershipKansas.pdf

. Manta. “Coffeyville Resources LLC.” Available: http://www.manta.com/c/mmgvkjp/coffeyville-resources-llc

Manta. “Dakota Gasification Co.” Available: http://www.manta.com/c/mmlgj74/dakotagasification-co

Manta. “Exxon Mobil Corp.” Available: http://www.manta.com/c/mmcckrf/exxon-mobilcorp
Massachusetts Institute of Technology (MIT). Largescale Power Plant CCS Projects Worldwide. Power Plant Carbon Dioxide Ca pture and Storage Projects website. http://sequestration.mit.edu /tools/projects/index.html

Nation, Larry. “Uncertainty ch ills decision making: Salaries Show 5 Percent Increase.” American Association of Petroleu m Geologists (AAPG) . Available: http://www.aapg.org/explorer/salarysurvey.cfm

Office of Personnel Management. “Salary Ta ble 2010-GS Incorporating the 1.50% General Schedule Increase Effective January 2010.” Available: http://www.opm.gov/oca/ 10tables/indexGS.asp

. Parfomak, P.W., and P.Folger. “Carbon Dioxide (CO 2 

### ) Pipelines for Carbon Sequestration: Emerging Policy Issues.” Congressional Resear ch Service, Report for Congress. Updated January 17, 2008. Available: http://assets.opencrs.com/rpts/RL33971_20080117.pdf

Parfomk, Paul W., Folger, Peter, and Adam Vann. Congressional Research Service, July 31, 2009. Carbon Dioxide (CO 2 

### ) Pipelines for Carbon Sequestra tion: Emerging Policy Issues. Available: http://nepinstitute.org/get/CRS_Reports /CRS_Climate_and_Environment/Carbon_and_CO2/ CO2_Pipelines_for_Carbon_Sequestration.pdf

PetroSource Energy Company, “P etrosource Energy Pipeline,” http://www.petrosourceenergy.com/ images_large/pipelineco_map.html

. The Society of Petroleum Engineers. “Annual Membership Salary Survey Highlight Report, 2008 Salary Survey.” Available: http://www.spe.org/ca reer/salary_survey/

.

### Page 77 of 145 Appendix A

Cost for Determining RCRA Toxicity of CO 2 

### Stream

Under the Business As Usual (BAU) scenario a ge nerator would be requir ed to determine if the CO 2 

### stream is classified as a Hazardous Waste under the Resource Conservation and Recovery Act (RCRA). This appendix summarizes the options and associated costs for determining if the waste meet s the toxicity characteristic under RCRA. The corrosivity characteristic is also potentially applicable to the classification of CO 2 

### streams as hazardous waste under RCRA, however, this analysis does not address th e costs associated with the corrosivity characteristic.

A.1 Summary of the RCRA T oxicity Characteristic

Determining if a solid waste is classified as hazardous under RCRA requires the generator to first determine if the material is a “Listed” waste, (i.e., contained in a list of wastes defined as hazardous by the regulation). If it is not listed th en the waste material must either be tested and characterized to determine if it is hazar dous by virtue of its ignitability, reactivity, corrosivity or toxicity (under 40 CFR 262.11(c)(1 )), or the generator can apply “knowledge of the hazard characteristic of the waste in light of the materials or the processes used” (under 40 CFR 262.11(c)(2)) to determin e whether the waste is RCRA hazardous. For the purposes of this analysis, we developed separate cost estimates for generators of CO 2 

### streams that will conduct physical testi ng of the waste and generators of CO 2 

### streams that will apply process knowledge with limited chemical analytical test ing. EPA also evaluated testing for operators of sequestration facilities. RCRA regulations under 40 CFR 261.24 (Toxicity ch aracteristic) provide criteria for these definitions and refere nces to methods to be used for testing to determine the RCRA toxicity char acteristic of the waste. This appendix addresses only the characteristic of toxicity re sulting from the chemical constituents of the waste.

Under 40 CFR 261.24 of RCRA the waste is co nsidered a RCRA hazardous waste if the waste contains hazardous constituents and if the concentration of certain components resulting from the RCRA test method exceeds the numerical concentration limits in the regulation. The list of hazardous contaminants and concentrati on criteria are presented in Exhibit A-1.

### Page 78 of 145 Exhibit A-1: Maximum Concentration of Cont aminants for the Toxi city Characteristic from 40 CFR 261.24 (Toxicity characteristic)
EPA HW No. 1 Analyte Group Contaminant CAS No. 2 Regulatory Level (mg/L) D004 Metal Arsenic 7440–38–2 5.0 D005 Metal Barium 7440–39–3 100.0 D018 Volatile Organic Compound Benzene 71–43–2 0.5
D006 Metal Cadmium 7440–43–9 1.0 D019 Volatile Organic Compound Carbon tetrachloride 56–23–5 0.5
D020 Pesticide Chlordane 57–74–9 0.0 D021 Volatile Organic Compound Chlorobenzene 108–90–7 100.0
D022 Volatile Organic Compound Chloroform 67–66–3 6.0

D007 Metal Chromium 7440–47–3 5.0 D023 Semivolatile Organic Compound o-Cresol 95–48–7 200.0 4 D024 Semivolatile Organic Compound m-Cresol 108–39–4 200.0 4
D025 Semivolatile Organic Compound p-Cresol 106–44–5 200.0 4
D026 Semivolatile Organic Compound Cresol 200.0 4

D016 Pesticide 2,4-D 94–75–7 10.0 D027 Volatile Organic Compound 1,4-Dichlorobenzene 106–46–7 7.5 D028 Volatile Organic Compound 1,2-Dichloroethane 107–06–2 0.5
D029 Volatile Organic Compound 1,1-Dichloroethylene 75–35–4 0.7
D030 Semivolatile Organic Compound 2,4-Dinitrotoluene 121–14–2 0.13 3
D012 Pesticide Endrin 72–20–8 0.0 D031 Pesticide Heptachlor (and its epoxide) 76–44–8 0.0

D032 Semivolatile Organic Compound Hexachlorobenzene 118–74–1 0.13 3 D033 Semivolatile Organic Compound Hexachlorobutadiene 87–68–3 0.5
D034 Semivolatile Organic Compound Hexachloroethane 67–72–1 3.0 D008 Metal Lead 7439–92–1 5.0 D013 Pesticide Lindane 58–89–9 0.4 D009 Metal Mercury 7439–97–6 0.2 D014 Pesticide Methoxychlor 72–43–5 10.0 D035 Volatile Organic Compound Methyl ethyl ketone 78–93–3 200.0 D036 Volatile Organic Compound Nitrobenzene 98–95–3 2.0
D037 Semivolatile Organic Compound Pentrachlorophenol 87–86–5 100.0
D038 Pesticide Pyridine 110–86–1 5.0 3
D010 Metal Selenium 7782–49–2 1.0 D011 Metal Silver 7440–22–4 5.0 D039 Volatile Organic Compound Tetrachloroethylene 127–18–4 0.7 D015 Pesticide Toxaphene 8001–35–2 0.5 D040 Volatile Organic Compound Trichloroethylene 79–01–6 0.5

### Page 79 of 145 EPA HW No. 1 Analyte Group Contaminant CAS No. 2 Regulatory Level (mg/L) D041 Semivolatile Organic Compound 2,4,5- Trichlorophenol 95–95–4 400.0

D042 Semivolatile Organic Compound 2,4,6- Trichlorophenol 88–06–2 2.0

D017 Pesticide 2,4,5-TP (Silvex) 93–72–1 1.0 D043 Volatile Organic Compound Vinyl chloride 75–01–4 0.2

Notes:
1 Hazardous waste number.
2 Chemical abstracts service number.
3 Quantitation limit is greater than the calculated regula tory level. The quantitation limit therefore becomes the regulatory level.
4 If o-, m-, and p-Cresol concentrations cannot be differe ntiated, the total cresol (D026) concentration is used. The regulatory level of total cresol is 200 mg/l.



### A.2 Summary of Key Issues

This section summarizes four key issues for consideration in evaluating the testing of CO 2 

### streams.

Issue 1: Lack of RCRA test procedures for gas ses, supercritical fluid s or liquids under high
pressure. The concentration limits for hazardous waste constituents in the RCRA regulation 40 CFR 261.24 (Toxicity characteristic) is in liqui d units (milligrams per liter). In particular, the RCRA toxicity test proce dures specified in EPA publica tion SW-846 require flushing the solid waste sample with a slightly acidic aque ous solution to leach out potentially hazardous contaminants. The concentration of constituents in the leachate is compared to the RCRA concentration limits (see Exhibit A-1). If th e concentration in the leachate exceeds the RCRA concentration limits then the wast e is classified as a RCRA hazardous waste. In the case of a liquid waste, the RCRA regulation under 40 CF R 261.24(a) allows the waste itself to be considered to be the leachate for the pur pose of comparison with the concentration standards. However, there is no RCRA regulation or guidance that specifi es test procedures for wastes that are gas, supercritical fluid, or dense liquid under high pressure. 64 

### CO 2 

### streams captured for the purposes of injection will typica lly be either gas, supercritical fluids, or liquids under high pressure. At the point of capture CO 2 

### streams will typically be in the gas phase (14.5 to 500 psi). 65 

### Transport and injection is commonly as a dense liquid or

64 A supercritical fluid has properties of a gas and properties of a liquid, but is neither. CO 2 must be compressed to approximately 1100 psi to become supercritical and is normally injected as a supercritical fluid. CO 2 will most likely be transported by pipeline for technical an d economical reasons.. (See: CRS Report to Congress. Carbon Dioxide (CO2) Pipelines for Carbon Sequestration: Emerging Policy Issues. Paul W. Parfomak and Peter Folger. January 17, 2008
65 Volk, Ronald H., 2009. Proceedings of the Workshop on Future Large CO2 Compression Systems, Sponsored by NIST, US DOE and EPRI. March 30-31, 2009. Gaithersburg MD.

### Page 80 of 145 supercritical fluid. 66 

### Under the RCRA regulations and test procedures there are no standards of comparison for gasses, supercritical fluids, or liquids under high pressure, and there is no documented procedure for converting gas concentr ation or supercritical fluid concentration units to liquid concentration.

Issue 2: Testing Needs to Cover a Variety of Contaminants. The contaminants in Exhibit A-1 include chemical groupings (metal s, pesticides, volatile organi c compounds and semi volatile organic compounds) that each require different methods of sampling and analysis specified by EPA.

Issue 3: Measurement of Concentrations in Supercritical and Liquid Under High Pressure CO 2 

### Streams is Complex. CO 2 

### streams currently injected an d transported generally contain some impurities when in supercritical or liquid under high pressure state that can complicate the measurement of the CO 2 

### stream due to differences in th e density and the compressibility of the components. The concen tration of components in CO 2 

### in a supercritical or liquid under high pressure state may not be representativ e of the composition at a lower pressure.

A.3 Options and Associated Costs for Testing CO 2 

### Stream

This section presents four op tions and costs for testing a CO 2 

### Stream:

• 

### Option 1 – Testing CO 2 

### Stream as a Gas;

• 

### Option 2 – Testing CO 2 

### Stream as a Supercritical Fluid or Liquid Under High Pressure;

• 

### Option 3 – Using Process Knowledge and Li mited Analytical Te sting to Meet RCRA Characterization Requirements; and

• 

### Option 4 – Injection Facility Testi ng to Ensure Compliance with RCRA.

Option 1 – Testing CO 2 

### Stream as a Gas

Under this option, facilit ies that generate CO 2 

### as a gas will sample the gas at a low pressure prior to compression and transport of the CO 2 

### stream, thus avoiding the issues associated with sampling and analyzing a supercritical fluid or liquid under high pressure. The gas would likely only contain the metals listed in Ex hibit A-1, but this Opti on 1 scenario includes full characterization of all lis ted RCRA contaminants to account for all potential processes that may generate CO 2 

### streams for subsequent sequestration.

This analysis uses costs for sampling and anal ysis that use standard procedures and are consistent with existing EPA methods for process testing or emissions stack testing of gases. In some cases a facility would need to constr uct a special sampling por t on the process line to collect a representative sample of the CO 2 

### stream for analysis. Faci lities may already have

66 Mohitpour, Mo, Andy Jenkins, and Gabe Nahas. 2008. A generalized overview of the requirements for design, construction and operation of new pipelines for CO2 sequestration. Journal of Pipeline Engineering, Volume 7, No. 4 Fourth quarter 2008

### Page 81 of 145 sampling ports for operational testing, but the st ream would not normally be sampled for the full range of RCRA contaminants listed in Exhi bit A-1, and the existing ports may not be at appropriate sampling locations for CO 2 

### stream characterization. Construction of a sampling port would require stainless steel or similar metal to ensure sample quality and minimize the effects of the corrosive CO 2 

### stream. Samples of the CO 2 

### stream would be collected for verification of characteriza tion annually, and the sampling program would also include collection of quality control samples for verifica tion. Note that this analysis does not estimate the cost of testing the CO 2 

### stream for corrosivity; however, the generator would be required to determine if the CO 2 

### stream meets the corrosivity characteristic which would incur similar cost for developing the approach and performing the tests.

As mentioned in Issue 1 above, there is cu rrently no guidance for determining if a gas contains a concentration of hazardous contamin ants above the RCRA to xicity characteristic limits in Exhibit A-1. Therefore, a facility w ould need to construct a methodology to relate the sampled gas concentrations to the liquid concentration units (milligrams per liter) specified in the RCRA regulations for direct comparison. This desktop analysis would require a senior level chemist or chemical engineer to develop and document a calculation method to convert the gas concentration measur ements to liquid concentration measurements considering all the physical and chemical properties of the CO 2 

### stream and listed constituents. We have not developed the deta ils of this conversion method, but based on input from our analytical chemists we assu me that it will require approximately 40 hours. Once the procedure has been developed a staff level chemist could perform the calculations and prepare the letter style report with the re sults in approximately 12 hours. As a point of reference, some states have developed inform al RCRA solid waste screening procedures for soils that convert the soil concentration meas urements (in milligrams per kilogram) to liquid concentrations based on the dilu tions used in the toxicity leaching test specified in EPA Publication SW-846.

A breakdown of the costs and labor hours for th is option are presented in Exhibit A-2. Additional details are provided in Exhibit A-6.

### Page 82 of 145 Exhibit A-2: Labor Hours and Costs for Option 1: Testing CO 2 

### Stream as a Gas Labor Time:

Labor Category Frequency of Occurrence Hours Cost a



### Senior Chemist One-time 40 $4,440

Chemist Annual 12 $671

Sampling Technician Annual 4 $224

Vendor/Equipment Costs:

Cost Category Frequency of Occurrence Cost Facility Improveme nt (installation of sampling port) One-time $2,500 Sampling Equipment Annual $450 Sample Analysis (includes QC sample) Annual $2,448
Vendor/Equipment Subtotal $5,398 (first Year) $2,898 annually Total Cost : One Time - $6,940 Annual - $3,793

a Labor hours were converted to costs using loaded hourly wages of $110.99 for Senior Chemists, and $55.95 for Chemists and Sampling Technicians



### Option 2 – Testing CO 2 

### Stream as a Supercritical Fluid or Liquid Under High Pressure

Under this option, facilit ies that generate CO 2 

### as a gas would compress the CO 2 

### stream to supercritical fluid or liquid under high pressure conditions for transport and then sample it as supercritical fluid or liquid under high pressure. A special sampling port designed for high pressure and corrosive fluids woul d be required on the high pressure CO 2 

### stream line. CO 2 

### generator facilities would lik ely not have such a port al ready installed under normal operations, therefore the cost of installation would be incurred . Sampling of high pressure fluids and gasses is performed with a speci alized sampling vessel (bomb sampler) that ensures a representative sample is collected and that can withstand high pressure. These samplers can be purchased or rented from the laboratory performing the analysis. The analytical requirements are assumed to be the same as Option 1.

Once the supercritical fluid or liquid under high pressure sample is collected it must be analyzed using a standard method that is accepta ble to EPA. There are currently no standard methods or guidelines for analysis of samples collected as supercriti cal fluids or liquids under high pressure. Since standard methods are av ailable for analysis of gas samples, this option assumes that the facili ty would develop and document a procedure to gasify the

### Page 83 of 145 supercritical fluid or liquid unde r high pressure and then analyze it as a gas. The analytical method development would require creating da ta quality and performance indicators by a senior chemist, and would requ ire demonstrating that the inte grity of the sample composition is maintained during phase shift from supercriti cal fluid or liquid under high pressure to gas. Analytical method development is allowed a nd commonly used in other EPA programs when existing methods are not fully applicable and th erefore must be modified. An example of a successful method development to support the Clean Water Act is the approval of EPA Method 245.7 in 2007 which provides a lower detec tion level of mercury in wastewater with less sample preparation. Method de velopment is a one-time cost.

After the method is developed and samples ar e analyzed the generator would need to determine if the gas contains a concentra tion of hazardous contaminants above the RCRA toxicity characteristic limits, which are in liqui d concentration units (milligrams per liter). As in Option 1, a facility would need to c onstruct a methodology to relate the sampled gas concentrations to a liquid concentration for dir ect comparison. The results of the analysis and waste determination would be summarized in an annual report. This option assumes the same level of effort as Option 1 for these tasks.

A breakdown of the costs and labor hours fo r Option 2 are presented in Exhibit A-3. Additional details are provided in Exhibit A-7.

Exhibit A-3: Labor Hours and Costs for Option 2: Testing CO 2 

### Stream as a Supercritical Fluid or Liquid Under High Pressure Labor Time:

Labor Category Frequency of Occurrence Hours Cost a



### Senior Chemist One-time 200 $22,198

Chemist Annual 12 $671
Sampling Technician Annual 4 $224 Vendor/Equipment Costs:

Cost Category Frequency of Occurrence Cost Facility Improveme nt (installation of sampling port) One-time $5,000

Sampling Equipment Annual $200 Sample Analysis (includes QC sample) Annual $2,448
Vendor/Equipment Subtotal $7,648 (first year) $2,648 annually Total Cost : One Time - $27,198 Annual - $3,543

a Labor hours were converted to costs using loaded hourly wages of $110.99 for Senior Chemists, and $55.95 for Chemists and Sampling Technicians

### Page 84 of 145 Option 3 – Using Process Knowledge and Limited Analytical Testing to Meet RCRA Characterization Requirements

RCRA regulations under 40 CFR 262.11(c)(2) allo ws generators to use knowledge of the process to determine the characteristics of th e waste stream for clas sification. Under Option 3, a generator would use existing data on the raw materials, operati ons and intermediate testing, supplemented by some limited testing, to determine if the waste stream is hazardous. Under this scenario, the CO 2 

### stream is assumed to be subjected to some treatment of impurities and solids prior to transport to s upport air quality, pro cessing, and pipeline requirements, therefore the generator would te st for a few key components such as mercury, volatile and semi volatile orga nic compounds. For this cost es timate we have assumed that the CO 2 

### stream is from a coal or gas fired combustion source that has undergone some particulate and VOC removal, and it is unl ikely that the waste stream would contain pesticides, or most metals listed in Exhib it A-1. Under Option 3, th e generator would only sample for semivolatile organic compounds , volatile organic compounds, and mercury. 67



### The generator would be required to document the CO 2 

### stream generation process and the rationale for how the RCRA hazardous waste de termination was made. We estimate that the documentation would be performed by a senior le vel plant engineer or chemist and require approximately 40 hours. Once the determina tion was made, a staff level chemist would prepare an annual report of findings. A brea kdown of the costs and labor hours for Option 3 are presented in Exhibit A-4. Additiona l details are provided in Exhibit A-8.

67 We recognize that, besides mercury, other heavy metals such as arsenic and selenium may be present at very low levels.

### Page 85 of 145 Exhibit A-4: Labor Hours and Costs for Option 3: Using Process Knowledge to Meet RCR A Characterization Requirements Labor Time:

Labor Category Frequency of Occurrence Hours Cost a



### Senior Chemist One-time 40 $4,440

Chemist Annual 12 $671

Sampling Technician Annual 2 $112 Vendor/Equipment Costs:

Cost Category Frequency of Occurrence Cost Sampling Equipment Annual $400 Sample Analysis (includes QC sample) Annual $1,530 Vendor/Equipment Subtotal $1,930 annually Total Cost : One Time - $4,440 Annual - $2,713

a Labor hours were converted to costs using loaded hourly wages of $110.99 for Senior Chemists, and $55.95 for Chemists and Sampling Technicians



### Option 4 –Testing to Ensure Complia nce with RCRA by Injection Facility

Facilities that inject the CO 2 

### would have responsibility to co nfirm the characteristics of the waste stream to ensure it has been pr operly characterized by the generator. CO 2 

### received for injection by pipeline may be commingled fr om multiple sources and have a range of nonCO 2 

### constituents. Under Option 4, an injection facility would test a sample of the CO 2 

### stream annually for RCRA constituents at th e point where ownership of the CO 2 

### is transferred to the facility, or at a location immedi ately prior to injection. The R CRA testing would be done at the same time as the CO 2 

### stream composition testing requ ired under the UIC Class VI and would use the same sampling port, but woul d analyze for different constituents.

The injection facility would need to determin e if the results of the gas analysis contain concentrations of hazardous c onstituents above the RCRA toxi city characteristic limits, which are in liquid concentration units (milligrams per liter). 68 

### As in Option 1, an injection facility would need to constr uct a methodology to relate the sa mpled gas concentrations to a liquid concentration for direct comparison. The development and documentation of this

68 Alternatively, an injection facility could consider asse ssing the result of a spill of the material into the soil, water, and air media and determine if the resulting me dia exceeds the RCRA toxicity characteristic. While this does not meet the RCRA characterization standard for waste streams it may provide a cost effective method for the facility to estimate the concentration of supercritical or gaseous CO 2 for comparison to RCRA toxicity characteristic standards.

### Page 86 of 145 method would take a one-time effort of about 40 hours for a senior chemist or chemical engineer. After the method is de veloped and documented the result s of the analysis and waste determination would be summarized in an a nnual report by a staff level chemist who would prepare an annual report of findings.

A breakdown of the costs and labor hours fo r Option 4 are presented in Exhibit A-5. Additional details are provided in Exhibit A-9.

Exhibit A-5: Labor Hours and Costs for Option 4: Testing to Ensure Compliance wi th RCRA by Injection Facility Labor Time:

Labor Category Frequency of Occurrence Hours Cost a



### Senior Chemist One-time 40 $4,440

Chemist Annual 12 $671 Vendor/Equipment Costs:

Cost Category Frequency of Occurrence Cost Sampling Equipment Annual $100 Sample Analysis (no QC sample) Annual $765 Vendor/Equipment Subtotal $865 annually Total Cost : One Time - $4,440 Annual - $1,536

a Labor hours were converted to costs using loaded hourly wages of $110.99 for Senior Chemists, and $55.95 for Chemists and Sampling Technicians



### A.4 Additional Details on Cost Estimates

This section presents additional details on the cost components, assumptions, and data sources for developing the cost estimates fo r each testing option. The information is summarized in four exhibits:

• 

### Exhibit A-6: Option 1 Cost and Labor Estimate;

• 

### Exhibit A-7: Option 2 Cost and Labor Estimate;

• 

### Exhibit A-8: Option 3 Cost and Labor Estimate; and

• 

### Exhibit A-9: Option 4 Cost and Labor Estimate.

### Page 87 of 145 Exhibit A-6: Option 1 Cost and Labor Estimate
Option 1: CO2 stream is tested at point of ge neration as a gas, after some treatment

Cost Category Range of Costs Frequency of Cost Occurrence Notes Data Source Sampling Costs Sampling port installation $2,500 1 Probably already exists for operational or other compliance related sampling Assumed cost is similar to installing pressure relief valve. Ref: 2009 Means Heavy constr/Envl cost Book, not high pressure. Sampling equipment $450 rental of Multi Train Sampling eqpt (max cost) 1 test per year SUMMA sampling containers or sampling train for sorbent tube for VOST/metals Commercial Lab Price list(CAS), published equipment vendors prices

Technician 4 hrs 1 per year ICF Estimate

Analytical Laboratory Costs Metals $249 2 (1 sample and 1 QC) Multi-metal train RS Means Env'l Remediation Unit Costs VOC $294 2 (1 sample and 1 QC) TO-15 or RCRA 0030 RS Means Env'l Remediation Unit Costs SVOC $440 2 (1 sample and 1 QC) TO-13 RS Means Env'l Remediation Unit Costs Pesticides $241 2 (1 sample and 1 QC) TO-4 RS Means Env'l Remediation Unit Costs

$1,224 Interpretation and Documentation Costs Senior Level Chemist Chem Eng. 40 hrs 1 initial Develop correlation for gas samples to RCRA Tox Char limits ICF Estimate

Mid Level Chemist 12 annual QC data, Compare results, prepare report ICF Estimate

### Page 88 of 145 Exhibit A-7: Option 2 Cost and Labor Estimate

Option 2: CO2 stream is tested at point of use as a su percritical fluid or liquid under high pressure

Cost Category Range of Costs Frequency of Cost Occurrence Notes Data Source Sampling Costs Sampling port installation $5,000 1 Probably does not exist for operational or other compliance related sampling Assumed cost is similar to installing pressure relief valve. Ref: 2009 Means Heavy constr/Envl cost Book- doubled cost of iron bronze valve to account forhigh pressure and noncorrosive materials. Sampling equipment $200 for bomb sampler rental 2 samples - 1 QC 1 sample Pressurized pipeline or downhole sampling bomb Technician 4 1 per year Analytical Laboratory Costs Metals $249 2 (1 sample and 1 QC) Multi-metal train RS Means Env'l Remediation Unit Costs VOC $294 2 (1 sample and 1 QC) TO-15 or RCRA 0030 RS Means Env'l Remediation Unit Costs SVOC $440 2 (1 sample and 1 QC) TO-13 RS Means Env'l Remediation Unit Costs Pesticides $241 2 (1 sample and 1 QC) TO-4 RS Means Env'l Remediation Unit Costs

Interpretation and Documentation Costs Senior Level Chemist Chem Eng. 160 hrs 1 initial Method Development and verification for analyzing supercritical fluids or liquids under high pressure ICF Estimate from Analytical Chemist with expertise in method development and supercritical and liquid under high pressure waste processes Senior Level Chemist Chem Eng. 40 hr s 1 initial Develop correlation for gas samples to RCRA Tox Char limits ICF Estimate from Analytical Chemist

Mid Level Chemist 12 annua l QC data, Compare results, prepare report

### Page 89 of 145 Exhibit A-8: Option 3 Cost and Labor Estimate

Option 3: CO 2 is tested at point of generation as gas, but only for sel ected compounds. Use process kn owledge to characterize waste

Cost Category Range of Costs Frequency of Cost Occurrence Notes Data Source Sampling Costs Sampling port installation $0 0 Process system already has sampling ports for existing QC testing within system that can be used for process waste characterization

Sampling equipment $95 per canister+ $20 for flow controller (or $105 for Sorbent tube) 1 Rental of Manual Sampling Train for Metals

Technician 2 1 per year Sampling metals only

Analytical Laboratory Costs Mercury only $30.50 2 (1 sample and 1 QC) Mercury EPA Method 245.2 RS Means Env'l Remediation Unit Costs

VOC $294 2 (1 sample and 1 QC) TO-15 or RCRA 0030 RS Means Env'l Remediation Unit Costs SVOC $440 2 (1 sample and 1 QC) TO-13 RS Means Env'l Remediation Unit Costs

Interpretation and Documentation Costs Senior Level Chemist Chem Eng. 40 1 initial Documentation of Process to demonstrate knowledge of system and wastes. ICF Estimate from Analytical Chemist

Mid Level Chemist 12 annual QC data, Compare results, prepare report ICF Estimate

### Page 90 of 145 Exhibit A-9: Option 4 Cost and Labor Estimate

Option 4: CO2 stream is tested at point of injection as superc ritical fluid or liquid under high pressure for verification of c omposition

Cost Category Range of Costs Frequency of Cost Occurrence Notes Data Source Sampling Costs Sampling port installation $0 0 Assume sampling port is already in place to comply with Subpart RR CO 2 concentration sampling Sampling equipment $100 for bomb sampler rental 1 Pressurized sampling bomb Estimate from lab

Technician 0 0 Technician is already collecting samples for Subpart RR or UIC compliance

Analytical Laboratory Costs Metals (Mercury only) $31 1 Mercury by EPA Method 245.2 RS Means Env'l Remediation Unit Costs. No QC sample required because sample is for verification of generator analysis VOC $294 1 TO-15 or RCRA 0030 RS Means Env'l Remediation Unit Costs. No QC sample required because sample is for verification of generator analysis SVOC $440 1 TO-13 RS Means Env'l Remediation Unit Costs. No QC sample required because sample is for verification of generator analysis Interpretation and Documentation Costs
Senior Level ChemistChem Eng. 40 hrs 1 initial Develop correlation for gas samples to RCRA Tox Char limits ICF Estimate from Analytical Chemist

Mid Level Chemist 12 annual QC data, Compare results, prepare report ICF Estimate

### Page 91 of 145 Appendix B

Treatment Costs
This appendix presents the costs for treating the CO 2 

### streams such that it is non-RCRA hazaroudous. Section B.1 summaries the th ree major capture technology systems and associated treatment options. Sectio n B.2 presents the treatment costs.

B.1 CO 2 

### Capture Technologies and Treatment Options for CO 2 

### Streams
Currently, there are three major CO 2 

### capture technology systems, with two based on pulverized coal system, and one based on gasification:

• Post-combustion capture involves the capture of CO 2 

### from a typical pulverized coal plant. In this process, a clean flue gas stream is sent to an absorption tower where the flue gas is brought in contact with an ab sorbent solvent (such as amines). The CO 2 

### binds with the solvent and the flue gas, separated from most of its CO 2 

### , is sent to the stack. The CO 2 

### -rich solvent is pumped to a regene ration vessel (or st ripper) through a heat exchanger. Under a higher atmospheric pressure and temperatures (ranging from 100 to 140 o 

### C 69 

### ), the solvent is regenerated and CO 2 

### is stripped. The heat supplied to the regeneration vessel to strip CO 2 

### from the solvent carries a significant energy cost. 70 

### The CO 2 

### is then cooled, dried, and comp ressed to a supercritical fluid or liquid under high pressure state, at whic h point it can be stored geologically or used commercially. The rege nerated ‘lean’ solvent is cool ed and pumped back to the absorption tower through a heat excha nger to be reused in the process. 71 

### Amine scrubbing system is currently a proven t echnology and it is capable of removing between 80% and 95% CO 2 

### from a flue gas stream. Ho wever, acid gases such as NO x 

### and SO x 

### must be removed from the flue ga s prior to passing th rough the absorber
tower. 72



### • Oxy-fuel combustion is a process in which high purity oxygen is substituted for air during combustion in a pulverized coal plan t, to produce an extremely concentrated stream of CO 2 

### that is easily compressed and delivered by pipeline for storage. The process involves the recircula tion of flue gas to maintain similar mass-flow and lower temperatures in the boiler. The raw fl ue gas consists of water vapour and CO 2 

### , which is then dehydrated and puri fied. The nearly pure CO 2 

### stream is then compressed for transportation and storage. 73

69 Note that these temperatures are applicable for the amine solvents.
70 Center for Energy and Economic Development. Carbon Capture . 2007.
71 Center for Energy and Economic Development. Carbon Capture . 2007.
72 NO x and SO x reacts with the amine and will result in a reduction in solven t performance, higher chemical consumption, and poor economic performance.
73 Alstom, Oxyfuel combustion capture

.

### Page 92 of 145 • Pre-combustion capture is mostly applicable to gasification-based system such as Integrated Gasification Combined Cycle (I GCC) power plants, and natural gas based combined cycle plants. A gasifier converts coal (or other feedst ock) using steam and oxygen to a synthetic gas (syngas) consisting mostly of CO, H 2 

### , H 2 

### O. The syngas is subsequently cooled and cleaned. In orde r to remove the carb on, the carbon monoxide in the syngas is reacted with steam to produce carbon dioxide and hydrogen in a water gas shift reaction. The carbon dioxide is subsequently removed from the syngas using a Selexol or Rectisol process, and the hydrogen is used for power generation in a combined cycle plant. Typical ly, sulfur, in the form of H 2 

### S (hydrogen sulfide), is not removed during gas treatment stag e, but rather removed in the CO 2 

### removal stage using a two-stage Sele xol process, for example. The separated H 2 

### S is then converted into elemental sulfur in a sulfur recovery unit.
As part of the standard process, post-co mbustion capture process using amine-based scrubbing will be relatively free of SO x 

### and NO x 

### , as discussed earlier, and therefore the CO 2 

### streams from power plants with post-combusti on capture are not expected to have these hazardous components. However, the CO 2 

### streams could contain other hazardous elements that are present in coal, such as mercury, arsenic, cadmium, etc.
In oxyfuel and gasification based systems, howev er, there are process options that could be added or taken out such that the hazardous components in the CO 2 

### stream can be lowered or increased.

• In an oxyfuel system, there is an option of e ither installing or not installing a flue gas desulfurizer (FGD) in which the SO x 

### from a flue gas can be taken out. With an FGD within the recirculating stream removing about 98% of the SO x 

### , the SO x 

### concentration in the flue gas would be about 0.3%, whereas w ithout the FGD, the concentration would be about 1%. With an FGD, the concentration of SO x 

### in the CO 2 

### stream would be more than 100 times lower (i.e., 0.01%), compared to a CO 2 

### stream without FGD (1%). However, one needs to consider the economic impact of adding an FGD. Furthermore, the production of NOx in an oxyfuel system is significantly lower because of the use of oxygen instead of air as an oxidant for combustion, and NOx concentration could be about 40 ppm. 74



### • In an IGCC system, there is an option of removing both H 2 

### S and CO 2 

### using a single stage Selexol gas separation process, instead of two stages (one stage for H 2 

### S and another for CO 2 

### ), as mentioned earlier. The single stage process eliminates the need for the sulfur processing and handling facilities (which is typically used to convert H 2 

### S into elemental sulfur). The cost of a si ngle stage selexol unit is lower than a two stage unit, in addition the cost of th e sulfur processing unit is eliminated.

74 See Case C2 of Table 3.8 in IEA 2004 – “Impact of Impurities in CO 2 capture, transport, and storage” Report PH4/32, International Energy Agency, August 2004.

### Page 93 of 145 B.2 Treatment Costs

Cost estimates for the addition of an FGD fo r the oxyfuel system was calculated from a 2008 NETL report (NETL, 2008. DOE/NETL-2007/1291, “Pulverized Coal Oxycombustion Power Plants,” Revision 2, August 2008), and estimates for the difference between cocapture of H 2 

### S and CO 2 

### vs. separated capture of CO 2 

### and H 2 

### S was calculated using a 2007 NETL report (NETL, 2007. DOE/NETL-2007/1281, “Cost and Performance Baseline for Fossil Energy Plants,” Revision 1, August 2007).
Economic Assumptions:
The economic assumptions were based on N ETL, 2008, and the relevant parameters are shown in Exhibit B-1.

Exhibit B-1: Economic Assumptions for Cost Estimates

Capital Charge Rate (The capital charge rate is the rate or return required on invested capital.) 

### 0.175 Weighted Cost of Capital 9.67% Levelization Factor for FOM and VOM (FOM = Fixed O&M Costs, VOM = Variable O&M Costs) 

### 1.1568 Price of Coal $/MMBtu $ 1.80

The cost estimates have an accu racy of +/-30%, consistent with a screening study, and the year of construction of the pl ant is assumed to be 2007. However, the “overnight” total plant cost numbers from the NETL studies, which were in January 2007 dollars, were converted to 1 st 

### quarter 2010 dollars using NIPA tables from the Bureau of Economic Analysis. 75 

### The total plant cost includes the following (NETL, 2007):

• Equipment (complete with initial chemical and catalyst loadings),

• Materials,

• Labor (direct and indirect),

• Engineering and construction management, and

• Contingencies (process and project).
Owner’s costs are excluded from the total plant cost. 76

75 Table 1.1.9 in NIPA Section 1, published by Bureau of Economic Analysis, published July 30, 2010.
76 Costs do not account for environmental permitting costs. It is assumed that treatment can be conducted under existing facility permits, including und er the provisions for onsite hazard ous waste treatment by hazardous waste large quantity generators under 40 CFR 260.10, and related provisions.

### Page 94 of 145 In both cases, bituminous high sulfur Illinois-6 coal with 2.51% sulfur (as-received basis) was used for the techno-economic analysis. The energy content of the coal was assumed to be 11,666 BTU/lb.

FGD for Oxyfuel Systems:
The economic analysis for the oxyfuel system was based on Case 5 of the NETL, 2008 report. Case 5 is a superc ritical pulverized oxyfuel plan t, based on a 95% pure oxygen produced air separation unit. Case 5 includes an FGD in the flue gas recycle process, and therefore represents the case where the CO 2 

### stream is scrubbed of SO 2 

### . The CO 2 

### stream after the flue gas recycle is only dehydrated to 0.015% by volume, such that the CO 2 

### concentration in the stream is about 83%. See NETL, 2008 report for more details on the plant configuration and assumptions.
In order to assess the impact of not having an FGD, cost of the FGD (capital cost, fixed and variable O&M) was taken from the recent Tech nical Support Document for EPA’s Transport Rule. 77 

### The cost of the FGD was given in 2006 dollars and was converted to 1 st 

### quarter 2010 dollars using the NIPA tables from BEA as shown in Exhibit B-2 in the “FGD” column. Therefore, the cost of the FGD was subtracted from the Case 5 numbers to derive the cost of the plant without an FGD.

It was assumed that the same amount of fuel a nd oxidant would be used in this case, and the only change was the removal of the FGD. Reduc tion in the auxiliary consumption from the FGD removal was about 7.26 MW, which included the removal of power consumption associated with limestone handling and reagen t preparation, FGD pumps and agitators, and 2 MW of power associated with induced fans for the FGD. 78



### Exhibit B-2 below shows the key assumptions an d results for the two oxyfuel cases, with and without FGD, and differences between the tw o (“FGD” column) highlights the impact of adding an FGD to treat the CO 2 

### stream. The levelized cost wa s calculated using the numbers in Exhibit B-1 and the formulati on given in section 2.9.2 of NETL, 2008.

77 See Table 5 (500 MW capacity, 11,000 BTU) of Technical Support Document of Transport Rule (“Updates to EPA Base Case v3.02 EISA Using the Integrated Planning Model” June 17, 2010).
78 See Table 5-8 of NETL, 2008.

### Page 95 of 145 Exhibit B-2: Summary of Assump tions and Results for Oxyfuel Oxyfuel System

Unit Without FGD With FGD (case 5) FGD



### Size of Plant MW 557.27 550.01 -7.26 Net Heat Rate BTU/kWh 11,503 11,655 152 Capacity Factor 0.85

Captured CO 2 

### metric tons/hr 592.58 metric tons/kWh 0.0010774 (592.58/550.01)/1,000 

### Capital Cost $/kW-net $ 2,493 $ 2,776 $ 283 Fixed O & M $/kW-year $ 25.59 $ 35.81 $ 10.22
Variable O & M 

### cents/kWh 0.51 0.68 0.17

Levelized Cost a 

### Over 20 Years Capital Cost cents/kWh 5.86 6.53 0.67 Fixed O & M cents/kWh 0.40 0.56 0.16 Variable O & M cents/kWh 0.59 0.79 0.20 Fuel cents/kWh 2.64 2.64 0.00 Total cents/kWh 9.49 10.51 1.03 Treatment Cost dollars per metric ton $9.74 b

a annualized present value. b rounding across all cells.



### Single Stage Selexol for IGCC:
The economic analysis for the IGCC system was based on Case 2 and Case 1 of the NETL, 2007 report. These two cases are based on IGCC using a GE gasifer with (Case 2) and without (Case 1) CO 2 

### capture. In Case 1, a one stage selexol unit is used for separating H 2 

### S from syngas stream and the rest of the stream is then vented. In Case 2, a two stage selexol unit is used for first separating the H 2 

### S, and subsequently separating the CO 2 

### from the syngas. See NETL, 2007 report for more details on the plant configuration and assumptions.
The cost impact of only having a single stage Selexol unit was calculate d using the total plant cost details of Case 1 and Case 2 given in NETL, 2007 report. The difference between the co-capture of H 2 

### S and CO 2 

### and separated capture was given by the cost difference in $/kW between Case 2 and Case 1 for the selexol units, and the cost of the sulfur plant and mercury removal. It was assumed that the co-capture plant would not include the mercury capture units that are in Case 2. 79 

### The differential in fixed cost was assumed to be same in the

79 See Exhibit 3-46, account 5A of NETL, 2007 report.

### Page 96 of 145 oxyfuel system multiplied by th e capital cost differential between the oxyfuel and IGCC cases. The differential variable cost between the two cases is negligible, as the only difference is the amount of Selexol used. All of the cost numbers were converted to 1 st 

### quarter 2010 dollars using the NIPA tables from BEA and shown in Exhibit B-3 below.

It was assumed that the same amount of fuel a nd oxidant would be used in this case, and the only change was selexol unit. Reduction in th e auxiliary consumption for the co-capture plant, relative to the separated capture plant, derives from the power consumption for Selexol unit auxiliaries between Case 2 and Case 1, and the power for Claus plant compressor and auxiliaries. 80 

### The difference between the two options was about 15 MW.

Exhibit B-3: Assumptions and Su mmary of Results for IGCC Cases IGCC System
Unit Co-capture Separated capture Difference



### Size of Plant MW 570.77 555.675 -15.09 Net Heat Rate BTU/kWh 10,227 10,505 278 Capacity Factor 0.85

Captured CO 2 

### tons/hr 505.65 metric tons/kWh 0.0009099 (505.65/555.675)/1,000 

### Capital Cost $/kW-net $2,236 $2,494 $259

Fixed O & M $/kW-year $36.31 $45.65 $9.34 Variable O & M cents/kWh 0.84 0.84 0.01

Levelized Cost a 

### Over 20 Years Capital Cost cents/kWh 5.25 5.86 0.61 Fixed O & M cents/kWh 0.56 0.71 0.15 Variable O & M cents/kWh 0.97 0.98 0.01 Fuel cents/kWh 2.38 2.38

Total cents/kWh 9.16 9.93 0.76 Treatment Cost dollars per metric ton $8.94 b

a annualized present value b rounding across all cells

80 See Exhibit 3-34 of NETL, 2007 report.

### Page 97 of 145 Appendix C

Assessment of Environmental Justice Impacts

C.1 Introduction

Executive Order 12898 (59 FR 7629, February 16, 1994) establishes Federal executive policy on environmental justice. It applies to agency “programs, policies, and activities” and in general calls on each federal agency to make ach ieving environmental justice (EJ) part of its mission. It directs agencies su ch as EPA to identify and addr ess disproportionately high and adverse human health or environmental effects of agency programs, policies, and actions on minority populations and low-income populations.

The purpose of this Appendix is to assess potenti al EJ impacts associated with the proposed RCRA conditional exclusion at 40 CFR 261.4(h). Section C.2 provides background on the proposed rule. Section C.3 presents a comparis on of the federal regula tions applicable to generators of hazardous waste CO 2 

### , pipelines, and geological se questration (GS) facilities operating under the baseline requirements a nd proposed RCRA exclusion. The comparison identifies key regulatory differen ces. Section C.4 presents a scre ening analysis of EJ impacts associated with generators a nd GS facilities that might clai m the exclusion. The screening analysis examines indicators (e.g., income, race, age) of populations living within a 1- and 3- mile radius of the facilities, to identify vulnerable populations. Section C.5 presents a qualitative screening assessment of potential EJ impacts associated with pipelines that might be used to transport CO 2 

### under the proposed rule. 81 

### Section C.6 summarizes the conclusions of these analyses and iden tifies possible next steps.

C.2 Background on Proposed Rule

EPA is proposing a conditional exclusion from the definition of hazar dous waste for carbon dioxide (CO 2 

### ) streams that are captured, transported, and injected into a well subject to the requirements for Class VI Underground Inje ction Control (UIC) wells, including the requirements in 40 CFR Parts 144 and 146 of the Underground Injection Control Program of the Safe Drinking Water Act. The conditional exclusion would require generators and owner/operators of a Class VI UIC well who claim that a CO 2 

### stream is exempt under section 261.4(h) to have an authorized representativ e sign a certification statement worded as specified. The exclusion would only apply to the CO 2 

### stream itself (as defined in 40 CFR 146.81(d)), and would not apply to hazardous wast es that are mixed with, or are otherwise co-injected with, CO 2 

### streams. The exclusion is expect ed to be codified at 40 CFR 261.4(h).

81 EPA did not conduct a quantitative, pipeline-specific sc reening analysis. Refer to Section 4.5 for EPA’s reasons for conducting a qualitative analysis.

### Page 98 of 145 There are three primary types of facilities that would be aff ected by EPA’s proposed action:

• Generators (i.e., capture fac ilities). Electric power plants and other industrial facilities generate CO 2 

### as a byproduct of their operations. CO 2 

### capture facilities are entities that collect their CO 2 

### byproducts and manage them in a manner other than releasing them into the environment. For this EJ assessment EPA is applying the high-end estimate of 27 facilities that may, at some point over the analytical time frame capture CO 2 

### and claim the exclusion as a genera tor under the proposal. These facilities include planned or existing fossil-fuel burning utilities, gas and fertilizer plants, and DOE projects. This waste CO 2 

### would qualify as a RCRA hazardous waste if it exhibits any of the RCRA h azardous characteristics.

• Pipelines. Captured CO 2 

### is typically transported by pi peline. As of 2008, there were 30 operating CO 2 

### pipelines, operated by 29 separate entities. 82



### • Geological Sequestration (GS) Facilities. For this EJ a ssessment EPA is applying the high-end estimate of 29 geol ogical sequestration facilities may claim the exclusion. Geological sequestration refers to the process of injecting CO 2 

### captured from an emission source (e.g., a power plant) into deep subsurface rock formations in order to permanently isolate the CO 2


### . C.3 Comparative Analysis

This section presents a summary comparison of the federal regulations applicable to generators of hazardous waste CO 2 

### and geological sequestration fa cilities operating under the baseline requirements and proposed RCRA ex clusion. The design and function of the regulatory comparison in this chapter is meant to help facilitate an initial appraisal of regulatory requirements for the environmental justice analysis. This comparison is not intended to represent conclusions about risk but instead broadly indentify areas where regulatory requirements a ppear to be reduced or increased for those CO 2 

### streams that would be RCRA hazardous. Additionally, the comparison is not intended to compare regulatory requirements for CO 2 

### streams found to be non-ha zardous under RCRA.

EPA developed Exhibit C-1 for purposes of comp aring these federal regulations. Column 1 of the exhibit presents the RCRA hazardous waste regulations and other federal regulations applicable to generators, pipelines and GS facilities operating under the hazardous waste regulatory program. 83 

### Column 2 presents the proposed rule’s conditions and other federal regulations applicable to generators, pipeline s and GS facilities operating under the proposed

82 Department of Transportation, Pipeline and Hazar dous Materials Safety Administration (PHMSA), 2008 Hazardous Liquids Annual Dat a http://www.phmsa.dot.gov/staticfiles/PHMS A/DownloadableFiles/Files/LIQANN08.zip

. 83 Column 1 presents hazardous wa ste regulations applicable to large quantity generators only.

### Page 99 of 145 rule. Column 3 briefly compares these regulat ions to determine if the federal regulations applicable to generators, pipelines and GS facilities operating under the proposed rule (Column 2) are comparable to the federal regulations applicable to hazardous waste generators, pipelines, and GS facilities operating under the federal hazardous waste regulations (Column 1).

Below is a brief summary of the regulatory comparison for CO 2 

### streams found to be RCRA hazardous waste under the current regulations to CO 2 

### streams that would be governed under the proposed rule.

• Generators of hazardous CO 2 

### operating under the proposed conditional exclusion would be subject to less stringent federa l regulation than generators operating under the baseline in regard to RCRA re porting and recordkeeping, emergency preparedness and response, and waste tr eatment. Generators under the proposed conditional exclusion, for example, would not be required to report to EPA under RCRA (there may be other applicable re porting requirements under other regulatory programs not discussed here), except if reque sted. Generators under the baseline are required to notify initially a nd report biennially on their activities, waste types and volumes.

• Pipelines carrying CO 2 

### streams managed under the proposed conditional exclusion would be subject to the same federa l regulations as pipelines carrying CO 2 

### streams managed under the baseline. Pipeline transport of CO 2 

### would be subject to DOT regulation under both the base line and proposed rule.

• GS facilities of hazardous CO 2 

### operating under the proposed conditional exclusion (i.e., facilities subject to Class VI UIC re quirements) would be subject to federal regulation that would be comparable to fe deral regulation of GS facilities operating under the baseline (i.e., facilities subj ect to Class I hazardous waste UIC requirements). For example, GS facilities operating under the proposed rule would be subject to more stringent requirements fo r siting, determining the area of review, monitoring of groundwater quali ty and potentially other environmental media. Note, however, that for this analysis EPA assume s that a Class I hazardous well used for injection of hazardous waste CO 2 

### streams under the baseline would also be required by the permit writers to meet the Class VI UIC well requirements. There is no regulatory requirement, however, that permit writers apply the Cl ass VI requirements to Class I hazardous waste wells.Exhibit C-1. Comparison of Federal Regulations Applicable toFacilities and Pipelines OperatingUnder the Baseline and ProposedRuleFederal Regulations Applicable to Facilities andPipelines Operating under the BaselineFederal Regulations Applicable to Facilities andPipelines Operating under the Proposed RuleComments1. GeneratorsaReporting and RecordkeepingRCRA Regulations•Notification under RCRA 3010 to obtain EPAidentification number (40 CFR 262.12)•Biennial reporting of hazardous waste quantities andtypes (40 CFR 262.41)•Recordkeeping of biennial report, waste analyses,and other documents as specified (40 CFR 262.40)•Recordkeeping and annual renewal of signedcertification statement. Certification must beprovided to EPA if requested (40 CFR 261.4(h))•Reporting requirements under CAA subpart PP (40CFR 98.420) for suppliers (generators) of CO2, andsubpart RR (40 CFR 98.440) for geologicalsequestration facilities.The proposed rule does not include initial orongoing notification or reporting to EPA ontheir activities as do the hazardous wasteregulations. However, it requires facilities torenew the certification annually and provide itto EPA if requestedThe baseline and proposed rule requirefacilities to keep specified records todemonstrate their compliance with applicablerequirementsEmergency Preparedness and ResponseRCRA Regulations•Personnel training on emergencies (40 CFR 262.34and 265.16)•Contingency planning, emergency procedures, andemergency equipment (40 CFR Part 265, Subpart Cand D)•No relevant requirementThe proposed rule does not require facilities toprepare for or respond to emergencies, as dothe hazardous waste regulations. Refer to“Other Regulations” below for information onother federal regulations that might requireemergency preparedness and responseOther Federal RegulationsCAA (Chemical Accident Prevention): A facility that is a stationary source that has more than a threshold quantityof a “regulated substance” in a process must develop and implement a risk management program under 40 CFRPart 68. Facilities with a process subject to Program 2 or3 (e.g., a process that has had an accidental releasewithin the past five years with offsite consequences as specified) must prepare an emergency response program ormake alternative arrangements with offsite authoritiesbThese other federal regulations establishrequirements for emergency preparedness thatmay be comparable to the hazardous wasterequirements in some cases. However, it isdoubtful that these requirements will addressall facilities and potential releases to the sameextent as the hazardous waste regulations.First, most of these regulations give facilitiesthe option of developing either an emergencyresponse plan or evacuation plan. Anevacuation plan is not comparable to thehazardous waste requirements (e.g., forCERCLA/EPCRA (Emergency Notification): A generator must immediately notify the National Response Centerof a release of hazardoussubstance equal to or exceeding its reportable quantity inany 24-hour period, as requiredat 40 CFR Part 302bOSH Act (Process Safety Management): A facility that has a process (e.g., use, storage, handling) which involvesa “highly hazardous chemical” at or above specified quantity must have an evacuation plan, as required at 29 CFR1910.38 and 1910.119bPage 101 of 145Federal Regulations Applicable to Facilities andPipelines Operating under the BaselineFederal Regulations Applicable to Facilities andPipelines Operating under the Proposed RuleCommentsOSH Act (Hazardous Waste Operationsand Emergency Response (HAZWOPER)): A facility is required toestablish an emergency response program if it has employees who are responsible for emergency responseoperations for releases of, or substantial threats of releases of, hazardous substances without regard to the locationof the hazard (e.g., anywhere at thefacility), such as designated response employees, as required by 29 CFR1910.120(q). If the facility will evacuate employees and will not allow employees to assist in response, it neednot prepare an emergency response plan.It must prepare an evacuation planbpersonnel training and equipment to addressonsite releases). In addition, most of theseregulations are triggered only when aCERCLA hazardous substance exceeds aspecified quantity (e.g., threshold quantity). Acarbon dioxide stream may contain hydrogensulfide, mercury, and/orother chemicals thatare CERCLA hazardous substances.However, these substances must be present insufficient quantities to trigger the specifiedregulatory quantity. For example, thethreshold quantity for hydrogen sulfide in 40CFR Part 68 is 10,000 pounds. Hence, afacility’s carbon dioxide stream would not besubject to these emergency requirements if itdoes not contain a hazardous substance thatexceeds its respective threshold quantity.Carbon dioxide itself is not a hazardoussubstanceNAOSH Act (Hazard Communication):Facilities mustprovide information to their employees about anychemical (except hazardous waste) which is a physicalor health hazard to whichthey are exposed, by meansof a hazard communication program, labels and otherforms of warning, material safety data sheets, andinformation and training (e.g., hazards detection,emergency procedures), as required at 29 CFR1910.1200. Hazardous wastesare exempt from theseprovisionsWaste TreatmentRCRA Regulations•Hazardous waste must betreated to applicabletreatment standards or be disposed of in a nomigration unit (40 CFR Part 268)•No relevant requirementThe proposed rule does not require treatmentof waste CO2streams or, alternatively,disposal of untreated waste in a unit with a nomigration variance, asdo the hazardous wasteregulations2. PipelinesRCRA RegulationsRCRA does not regulate transportation by pipeline Refer to “Other Regulations” below forinformation on other federal regulations thatapply to pipelinesOther Federal RegulationsPipeline transportation of CO2is subject to DOT regulation. For example, 49 CFR Part 195 applies to pipelinefacilities and the transportation of hazardous liquids or carbon dioxideassociated with those facilities in oraffecting interstate or foreign commerce, except as otherwise specifiedPipeline transport of CO2would be subject toDOT regulation under both the baseline andproposed rule3. Geological Sequestration FacilitiesRCRA RegulationsClass I injection wells disposing of hazardous waste are Class VI UIC wells disposing of exempt CO2must The baseline regulations establish a permit-Page 102 of 145Federal Regulations Applicable to Facilities andPipelines Operating under the BaselineFederal Regulations Applicable to Facilities andPipelines Operating under the Proposed RuleCommentspermitted by rule under RCRA if they meet therequirements of 40 CFR 270.60:•Have a UIC permit•Comply with UIC permit conditions and applicableUIC requirements at 40 CFR 144.14•Comply with 40 CFR 246.101 (i.e., corrective action)•Submit permit application information on solid wastemanagement units at the facility, if applicablemeet the requirements of 40 CFR 261.4(h)(1):•Be subject to Class VI UIC program, including UICrequirements at 40 CFR Parts 144 and 146•Dispose of CO2streams, but not CO2streams that aremixed with or otherwise co-injected with hazardouswaste•Keep onsite records of signed certification statement,renew it annually, and provide it to EPA if requestedby-rule program for Class I wells injectinghazardous waste that meet specifiedrequirements. The proposed rule would allowClass VI wells to inject exempt CO2streams,provided that the generator and wellowner/operator claim the exclusion and meetspecified conditions. The baseline andproposed rule both rely heavily on the UICprogram requirements (e.g., permitconditions) to ensure protective managementand disposal of the waste. Both also establishadditional administrative requirements asneeded to ensure compliance (e.g.,recordkeeping and reporting)Refer to “Other Regulations” below forinformation on other federal regulations thatapply to pipelinesOther Federal RegulationsThe UIC Class I hazardous regulations and UIC Class VI regulations address the same broad areas:•Siting•Area of review and corrective action•Financial responsibility•Construction•Logging, sampling, and testing prior to operation•Operation•Mechanical integrity tests•Monitoring•Closure/post-closure careIn addition, Class I hazardous injection wells also maybe subject to the no-migration requirements of 40 CFRPart 148 if they will dispose of RCRA hazardous wastesthat do not meet applicable treatment standardsThe UIC Class I hazardous regulations differfrom the UIC Class VI regulations in anumber of ways. Some key differencesinclude the following:c•Class VI regulations impose additionalsiting standards. For example, at theDirector’s discretion, the owner/operatormust characterize additional zones that willimpede vertical fluid movement, allow forpressure dissipation, are free of faults andfractures, and provide additionalopportunities for monitoring, mitigation andremediation•The Class I hazardous regulations requirethat the area of review (AoR) be a fixeddistance of 2 miles around the well, whereasthe Class VI regulations require AoR radiusPage 103 of 145Federal Regulations Applicable to Facilities andPipelines Operating under the BaselineFederal Regulations Applicable to Facilities andPipelines Operating under the Proposed RuleCommentsto be determined based on site-specificcomputational modeling that accounts forthe physical and chemical properties of allphases of the injected CO2stream, CO2plume, and pressure front over anappropriate timeframe. In addition, ClassVI regulations require continual reassessment of the AoR radius•Class VI regulations require samemonitoring during well operation as Class Ihazardous regulations, in addition tomonitoring of groundwater quality andgeochemical changes above the confiningzone. In addition,surface air monitoringand soil monitoring may be required at theDirector’s discretion. The owner/operatormust submit and gain approval of themonitoring plan before injection•Class VI regulations establish a 50-yearpost-closure period during which theowner/operator must conduct monitoring.The Class I regulations do not require a 50-year post-closure periodaColumn 1 presents hazardous waste regulationsapplicable to large quantity generators only.bA carbon dioxide stream may contain hydrogensulfide, mercury, and/or other chemicalsthat are “hazardous substances”. If a hazardous substance meets or exceeds theapplicable threshold quantity spelled out in these federal regulations, it would trigger the emergency requirements, as applicable. For example, the threshold quantity forhydrogen sulfide in 40 CFR Part 68 is 10,000 pounds. A facility’s carbon dioxide stream would not be subject to these emergency requirements if it does not contain ahazardous substance that exceeds its respective threshold quantity. Carbon dioxide itself is not a hazardous substance. Notethat the requirements of 29 CFR 1910.120(q)and 1910.1200 are not triggered by threshold quantities.cEPA anticipates that a Class I well used for injection of hazardous waste CO2streams would also be required by the permit writers to meet the Class VI UIC wellrequirements; however, there is no regulatory requirement that permit writers apply the Class VI requirements to Class I wells.

### C.4 Screening Analysis of Capture and Ge ologic Sequestration (GS) Facilities

This section presents an EJ sc reening analysis of carbon capture and GS facilities with known locations that might claim the exclusion. Simila r to the regulatory comparison found in C.3, the screening analysis of capture and GS facilities is not an assessment of risk. Instead, the analysis uses demographic information to identify comm unities of concern. The next two sections describe the methodology and results.

C.4.1 Methodology

EPA took the following steps to complete the analysis:

1. Ascertained the location of pla nned, major commercial (non-DOE) and FutureGen capture facilities, existing cap ture facilities, and DOE and FutureGen GS projects that may claim the ex clusion. Please note the following:

• EPA estimates that, at a maximum, 27 capture facilities may claim the exclusion, including 14 planned majo r commercial facilities, one FutureGen facility, 10 existing fertili zer and gas facili ties, and two DOE sequestration projects. These facili ties, plus four additional major DOE sequestration projects are included in this screening analysis.

Appendix C.A. identifies the 31 GS and capture facilities (33 less two DOE dual facilities) that are included in this screening analysis.

2. Conducted a screening analysis of thes e facilities and su rrounding residential populations to identify vulne rable populations based on demographic and other indicator data. EPA performed the an alysis using Geographic Information System (GIS) mapping tools. This anal ysis involved the following activities:

• Identified indicators to include in the analysis: perc ent minority (e.g., indigenous populations), percent be low 150% of poverty level, and percent 0-4 years and 65+ years wi thin a 1- and 3-mile radius. 84 

### In addition, two other indica tors were evaluated:

- Whether the 1- and 3-mile radius of each facility bisects Tribal land; and

- The number of environmentally regu lated sites located within the 1- and 3-mile radius of each facility (e.g., hazardous waste treatment, storage and disposal facilities and Superfund sites). EPA referred to its Facility Registry System (FRS), which is a

84 The one and three mile radii are applied to be consistent with prior ORCR environmental justice demographics analyses.

### Page 105 of 145 centrally managed database, to ascertain the location of these sites. 85 

### This indicator is meant to clarify the proximity and incidence of potential existi ng pollution sources to which populations may be exposed.

• Located each facility using latit ude and longitude and quantified the incidence of each indicator within 1- and 3-mile radii. EPA performed the analysis using 2010 Census Estimate da ta obtained from GeoLytics Inc. GeoLytics is a company that publishe s detailed census, demographic and geographic data as well as estimate s and projections based on modeling systems designed to forecast the current and future composition of the U.S. population based on multiple inputs. GeoLytics’ data were used because, as of the date of this analysis, the U.S. Census Bureau has not yet released Decennial 2010 census da ta at the local level.

• Compared the percentage of each indicat or in the radial populations to the state percentage. Radial populations were examined at the Census Block Group level. Note that, if a radius encompassed only a portion of a Block Group, proportional overlay tools were us ed to determine the incidence of each indicator within that portion of the Block Group encompassed by the radius. In addition, EPA found that so me 1- and 3- mile radii fell within two states (i.e., for facilities near st ate borders). In this case, proportional overlay tools were used to determin e the incidence of each indicator within that portion of the radius falling in each respective state, calculate its percentage within the state’s portion of the radi us (e.g., as a percentage of the Block Group in that state), and then compare the percentage to the state’s percentage.

• Identified those populations whose 1- and 3-mile indicator percentages exceeded the respective state’s percentages; and

• Produced tabular summaries of the data . Detailed data are presented in Appendix C.B. A summary of the da ta is presented in Section C.4.2.

C.4.2 Results

Exhibits C-2 and C-3 summarize the results of the screening analysis. Ex hibit C-2 presents the results of the analysis of indica tors within a 1-mile radius of facilities and Exhi bit C-3 presents the results for the analysis of indicators within a 3- mile radius of facilities. Each exhibit lists the facilities alphabetically, indicate s its type (e.g., commerci al capture), and uses an “X” to indicate if an indicator within its radius exceeds the state percentage. In addition, each exhibit uses gray shading to identify facilities whose minority populations and/or low-income populations (i.e.,

85 The FRS has over 1.5 million unique facility records rela ted to such systems as the Toxic Release Inventory (TRI), Resource Conservation and Recovery Act Info rmation System (RCRAInfo), Aerometric Information Retrieval System (AIRS)/AIRS Facility Subsystem, and Comprehensive Environmental Response, Compensation, and Liability Information System (CERCLIS). For additional information, refer to http://www.epa.gov/enviro/html/.

### Page 106 of 145 populations living below 150% of the poverty level) exceed the state percentage, as these may be among the most vulnerable populations. 86



### Exhibit C-2 shows the following in regard to population characteristic s within a 1-mile radius of the facilities:

• 21 of the 31 GS and capture facilities ex amined (68%) have populations within a 1-mile radius that exceed their resp ective state’s percentage of minority populations and/or populations below 150% of th e poverty level. They are shaded in gray in the exhibit.

• 3 of the 31 GS and capture facilities (10%) have populations within a 1-mile radius that exceed their respective stat e’s percentage of minority populations and populations below 150% of the poverty level. 87 

### These facilities include:

- Coffeyville Fertilizer Plant;

- Kemper County Plant; and

- Lima Plant.

Each of these 3 facili ties has populations within a 1-mile radius with children 0 to 4 years and/or adults 65 years and ol der in percentages that exceed their respective state’s percentages.

Each of these 3 facilities ha s at least one existing FRS s ite located within a 1-mile radius. The Coffeyville Fertilizer Plant has 9 sites within a 1-mile radius, the Kemper County Plant has 1 site within a 1-mile radius, and the Lima Plant has 31 sites within a 1-mile radius.

• 22 of the 31 GS and capture facilities (71%) have populations within a 1-mile radius with children 0 to 4 years and/or adults 65+ years in percentages that exceed their respective state’s percentages.

• 29 of the 31 GS and capture facilities ( 94%) have at least one existing FRS site located within a 1-mile radius. Six facili ties have 2 sites located within their 1- mile radius, 4 facilities have 3 sites lo cated within their 1-mile radius, and 6 facilities have 4 or more sites lo cated within their 1-mile radius.

• No facility’s 1-mile radius bisects Tribal land.

86 This analysis focuses on selected demographics surr ounding the identified capture and sequestration facilities. We have not conducted an exposure or risk assessment of CO 2 sequestration in Class I or Class VI facilities. Our experience with deep well inj ection indicates that the risk of exposure resulting from CO 2 movement outside of the permitted injection zone is low. However, we recognize that there is a potential for CO 2 movement outside the injection zone that may impact USDWs. (See: U.S. EPA, Office of Water. 2003. “Relative Risk Assessment of Management Options for Treated Wastewater in South Florida,” April 2003.

87 These 3 facilities are a subset of the 21 facilities noted above.

### Page 107 of 145 Exhibit C-3 shows the following in regard to population characteristic s within a 3-mile radius of the facilities:

• 20 of the 31 GS and capture facilities ex amined (65%) have populations within a 3-mile radius that exceed their resp ective state’s percentage of minority populations and/or populations below 150% of th e poverty level. They are shaded in gray in the exhibit.

• 4 of the 31 GS and capture facilities (13%) have populations within a 3-mile radius that exceed their respective stat e’s percentage of minority populations and populations below 150% of the poverty level. 88 

### These facilities include:

- Coffeyville Fertilizer Plant;

- Kemper County Plant;

- Lima Plant; and

- San Joaquin Basin Project , CA Saline Formation.

Each of these 4 facili ties has populations within a 3-mile radius with children 0 to 4 years and/or adults 65 years and ol der in percentages that exceed their respective state’s percentages.

Each of these 4 facilities has existing FRS sites located within a 3-mile radius. The Coffeyville Fertilizer Plant has 31 sites within a 3-mile radius, the Kemper County Plant has 3 sites within a 3-mile radius, the Lima Plant has 88 sites within a 3-mile radius, and the San Joaquin Basi n Project has 3 sites within a 3-mile radius.

• 24 of the 31 GS and capture facilities (77%) have populations within a 3-mile radius with children 0 to 4 years and/or adults 65+ years in percentages that exceed their respective state’s percentages.

• 29 of the 31 GS and capture facilities ( 94%) have at least one existing FRS site located within a 3-mile radius. Three fac ilities have 2 sites located within their 3- mile radius, 5 facilities have 3 sites lo cated within their 3-mile radius, and 16 facilities have 4 or more sites lo cated within their 3-mile radius.

• No facility’s 3-mile radius bisects Tribal land.

Refer to Appendix C.B. for detailed data on the in cidence of the indicators within a 1- and 3-mile radius of the facilities.

88 These 4 facilities are a subset of the 20 facilities noted above.

### Page 108 of 145 Exhibit C-2. Characteristics of Population s within 1-Mile Radi us of Facilities*

Facility Name Facility Type Facilities Whose 1-Mile Populations Exceeded the State Percentage Number of FRS Sites within 1-Mile Radius On Tribal Land? % Minority (All Races) % Below 150 Percent of Poverty Level % 0 to 4 Years or 65+ Years

AEP Alstom Mountaineer (Ph.2) Commercial Capture - X** X** 7 No

AEP Alstom Northeastern Commercial Capture - - - 3 No

Antrim Gas Plant Existing Gas and Fertilizer Plant - - X 0 No

Cincinnati Arch Mt. Simon Saline Major DOE Sequestration Project - X** X** 3 No

Coffeyville Fertilizer Plant Commercial Capture X X X 9 No

Edwardsport Commercial Capture - X X 4 No

Enid Gas Plant Existing Gas and Fertilizer Plant - - X 1 No
Futuregen Futuregen - X - 1 No

Great Bend Commercial Capture - X** X 3 No

Great Plains Coal Gasification Existing Gas and Fertilizer Plant - X X 3 No

Green River Basin Nugget Sand Saline Reservoir Major DOE Sequestration Project - - X 1 No

Hydrogen Energy HECA Commercial Capture - - - 1 No

Illinois Basin Mt. Simon Saline Reservoir Major DOE Sequestration Project - X X 5 No

Kemper County Commercial Capture X X X 1 No

La Barge Gas Plant Existing Gas and Fertilizer Plant - - X 2 No

Lima Commercial Capture X X X 31 No

Mesaba Commercial Capture - - X 1 No

Mt. Simon Saline Reservoir Major DOE Sequestration Project - X - 1 No

San Joaquin Basin, CA Saline Formation Major DOE Sequestration Project - X X 2 No

### Page 109 of 145 Facility Name Facility Type Facilities Whose 1-Mile Populations Exceeded the State Percentage Number of FRS Sites within 1-Mile Radius On Tribal Land? % Minority (All Races) % Below 150 Percent of Poverty Level % 0 to 4 Years or 65+ Years

Tenasca Sweetwater/Trailblazer Commercial Capture - X X 9 No
Tenasca Taylorville Energy Commercial Capture - - X 2 No
Texas Clean Energy Project Commercial Capture - - X 1 No

Val Verde Gas Plant, Gray Ranch Existing Gas and Fertilizer Plant X - - 2 No
Val Verde Gas Plant, Mitchell Existing Gas and Fertilizer Plant X - - 1 No
Val Verde Gas Plant, Pikes Peak Existing Gas and Fertilizer Plant X - - 1 No
Val Verde Gas Plant, Puckett Existing Gas and Fertilizer Plant X - - 2 No
Val Verde Gas Plant, Terrell Existing Gas and Fertilizer Plant - X X 1 No

WA Parish, Sugarland Commercial Capture - - X 2 No
Wallula Energy Res. Center Commercial Capture - X - 1 No

Williston Basin EOR Sequestration Major DOE Sequestration Project - X X 0 No

Worsham-Steed (ZENG) Commercial Capture - X X 1 No
* The exhibit uses gray shading to id entify facilities whose minority populations and/or low-income populations (i.e., populations living below 150% of the poverty level) excee d the state percentage, as these may be among the most vulnerable populations.

** The1-mile radius around these facilities falls in two states. The population within the 1-mile radius was allocated proportionally to the two states (i.e., creating two mutually exclus ive population groups, one fo r each state), as described in the methodology. The indicator in this exhibit has an asterisk to indicate that one of the population groups for this facility exceeded its respective state average, while the othe r population group did not.

### Page 110 of 145 Exhibit C-3. Characteristics of Population s within 3-Mile Radi us of Facilities*

Facility Name Facility Type Facilities Whose 3-Mile Populations Exceeded the State Percentage Number of FRS Sites within 3- Mile Radius On Tribal Land? % Minority (All Races) % Below 150 Percent of Poverty Level % 0 to 4 Years or 65+ Years
AEP Alstom Mountaineer (Ph.2) Commercial Capture - X** X 11 No

AEP Alstom Northeastern Commercial Capture - - X 4 No

Antrim Gas Plant Existing Gas and Fertilizer Plant - X - 0 No

Cincinnati Arch Mt. Simon Saline Major DOE Sequestration Project - - X 9 No

Coffeyville Fertilizer Plant Commercial Capture X X X 31 No

Edwardsport Commercial Capture - X X 9 No

Enid Gas Plant Existing Gas and Fertilizer Plant - - X 5 No
Futuregen Futuregen - X X 13 No

Great Bend Commercial Capture - X** X 8 No

Great Plains Coal Gasification Existing Gas and Fertilizer Plant - X X 4 No

Green River Basin Nugget Sand Saline Reservoir Major DOE Sequestration Project - - X 1 No

Hydrogen Energy HECA Commercial Capture - - - 1 No

Illinois Basin Mt. Simon Saline Reservoir Major DOE Sequestration Project - X X 37 No

Kemper County Commercial Capture X X X 3 No

La Barge Gas Plant Existing Gas and Fertilizer Plant - - X 2 No

Lima Commercial Capture X X X 88 No

Mesaba Commercial Capture - - X 3 No

Mt. Simon Saline Reservoir Major DOE Sequestration Project - X X 13 No

San Joaquin Basin, CA Saline Formation Major DOE Sequestration Project X X X 3 No

### Page 111 of 145 Facility Name Facility Type Facilities Whose 3-Mile Populations Exceeded the State Percentage Number of FRS Sites within 3- Mile Radius On Tribal Land? % Minority (All Races) % Below 150 Percent of Poverty Level % 0 to 4 Years or 65+ Years Tenasca Sweetwater/Trailbla

zer Commercial Capture - X X 17 No

Tenasca Taylorville Energy Commercial Capture - - X 3 No
Texas Clean Energy Project Commercial Capture - - X 1 No

Val Verde Gas Plant, Gray Ranch Existing Gas and Fertilizer Plant X - - 2 No

Val Verde Gas Plant, Mitchell Existing Gas and Fertilizer Plant X - - 2 No

Val Verde Gas Plant, Pikes Peak Existing Gas and Fertilizer Plant X - - 1 No

Val Verde Gas Plant, Puckett Existing Gas and Fertilizer Plant X - - 3 No

Val Verde Gas Plant, Terrell Existing Gas and Fertilizer Plant - X X 1 No
WA Parish, Sugarland Commercial Capture - - X 4 No
Wallula Energy Res. Center Commercial Capture - X - 5 No

Williston Basin EOR Sequestration Major DOE Sequestration Project - - X 0 No

Worsham-Steed (ZENG) Commercial Capture - X X 4 No
* The exhibit uses gray shading to id entify facilities whose minority populations and/or low-income populations (i.e., populations living below 150% of the poverty level) excee d the state percentage, as these may be among the most vulnerable populations.

** The 3-mile radius around these facilities falls in two states . The population within the 3-mile radius was allocated proportionally to the two states (i.e., creating two mutually exclus ive population groups, one fo r each state), as described in the methodology. The indicator in this exhibit has an asterisk to indicate that one of the population groups for this facility exceeded its respective state’s average, while the other popu lation group did not.



### C.5 Qualitative Screening Analysis of Pipelines

This section presents a qualitat ive screening analysis of EJ is sues associated with pipelines carrying carbon dioxide (CO 2 

### ) under the proposed RCRA conditional exclusion. The analysis provides a preliminary characteriza tion of potential health impact s to human populat ions near the pipelines. Section C.5.1 of this document pr ovides background information about the existing hazardous waste regulations (i.e., the “baselin e”) and proposed rule that would exempt CO 2 

### streams from RCRA regulation. Sec tion C.5.2 describes the likelihood of CO 2 

### pipeline failures that could lead to a release. Section C.5.3 de scribes some of the possible health impacts to surrounding populations from a CO 2 

### pipeline release. Section C .5.4 sets forth some preliminary conclusions about CO 2 

### releases from pipelines.

### Page 112 of 145 The primary data source used in this qualitati ve analysis is the document, “Final Risk Assessment Report for the FutureGen Project Envi ronmental Impact Statement,” dated October 2007. 89, 90 

### The Risk Assessment addresses the pote ntial releases of ca ptured gases at the proposed FutureGen power plant, during transporta tion via pipeline to the GS facility, and during subsurface storage. The Risk Assessment was prep ared under contract to th e U.S. Department of Energy (DOE) and revised in response to comm ents received during DOE’s review, from the public hearings on FutureGen’s Draft Environmen tal Impact Statement (EIS), and from other comments received on the Final Risk Assessment. It contains peer-reviewed chemical concentration effect levels related to health impacts to human and biological receptors.

Note that a quantitative, pipeli ne-specific analysis of EJ i ssues under the RCRA proposed rule was not performed for several reasons. There are over 3,000 miles of existing CO 2 

### pipelines and uncertainty exists about the particular pipelines that w ould be used to transport CO 2 

### streams under the baseline and proposed rule by capture f acilities that now ar e being planned. In addition, new pipelines may be built to transport CO 2 

### streams from capture facilities to distribution pipelines and wells a nd the location of these new pipe lines is not known. Because of these uncertainties, EPA determined that a qu alitative screening analysis based on existing information would be an appropriate first step to characterize some of the potential health impacts to human populations under the proposal and then to assess the need for additional research and analysis.

C.5.1 Background on Baseline and Proposed RCRA Rule

This section provides a brief description of the baseline regulations and proposed regulations as applicable to this analysis.

Baseline . Under the baseline, CO 2 

### streams that exhibit a RCRA hazardous characteristic under 40 CFR Part 261 must be classified hazardous wa ste and managed and disposed of in accordance with the RCRA hazardous waste regulations. This includes, for example, treatment of the CO 2 

### stream to meet applicable RCRA treatment stan dards before land disposal, if applicable, and disposal in a UIC well that meets app licable UIC and RCRA requirements.

A CO 2 

### stream generator under the baseline may have several options for a ddressing its hazardous waste CO 2 

### . It may treat the hazardous waste CO 2 

### to render it non-hazardous (i.e., by removing the characteristics that make the CO 2 

### stream hazardous) and dispose of it as non-hazardous waste in a Class VI UIC well. Note that, under EPA’ s Class VI UIC amendments , injection of a RCRA hazardous waste in a Class VI UIC well w ould be prohibited. Alternatively, a CO 2 

### stream generator may opt for other methods, such as disposing of untreated RCRA hazardous waste CO 2 

### stream in a UIC Class I hazardous well that that meets applicable no-migration requirements under 40 CFR Part 148.

89 This document can be found at the following web site: http://www.netl.doe.gov/technologies /coalpower/futuregen/EIS/FG%20 Risk%20Assessment%20110807.pdf.
90 FutureGen is a public-private partnership to build a firs t-of-its-kind coal-fueled power plant. It will generate electricity while capturing and injecting CO 2 into geological sequestr ation (GS) facilities.

### Page 113 of 145 Pipeline transport of CO 2 

### streams is subject to Department of Transportation (DOT) regulation. For example, 49 CFR Part 195 applies to pipelin e facilities and the transportation of hazardous liquids or carbon dioxide associated with those facilities in or affecting interstate or foreign commerce, except as otherwise specified. This regulation includes requirements for the design, construction, testing, operation and maintenance, reporting, and corrosion c ontrol of pipelines.

Proposed Rule . Under the proposal, CO 2 

### streams would be exempt from the definition of hazardous waste, provided the generator and Class VI UIC well owner/operator claim the exclusion and meet specified conditions. Cons equently, generators claiming the exclusion could transport and dispose of their CO 2 

### streams as non-hazardous wast e in Class VI UIC wells. Captured CO 2 

### streams would not be classified as h azardous waste under th e proposed rule and would therefore not need to be treated be fore injection in a Class VI UIC well.

Pipeline transport of CO 2 

### streams under the proposed rule would continue to be subject to U.S. DOT regulation. U.S. DOT regulator y requirements for transport of CO 2 

### streams would not be affected by the exclusion.

C.5.2 Risks of Pipeline Failure

The FutureGen Risk Assessment presents data c oncerning the probability of a release from an aboveground CO 2 

### pipeline, based on data from the US Department of Transportation Office of Pipeline Safety and based on the length of the pipeline. 91 

### According to the Risk Assessment, rupture and puncture failure frequenc ies were calculated to be 5.92 x 10 -5 

### /(kilometer-year) and 1.18 x 10 -4 

### /(kilometer-year), respectively. 92



### The Risk Assessment based its incident proba bility calculations on a number of data and assumptions, such as the following:

• The CO 2 

### pipeline failure frequency was calculated based on data contained in the on-line library of the Office of Pipeline Safety ( http://ops.dot.gov/ stats/IA98.htm ).

• Accident data from 1994-2006 indica ted that 31accidents involving CO 2 

### pipelines occurred during this time period.

• DOE assumes the total length of pipelines in operation in the U.S. during this time period was approximately 1,616 miles (2,600 kilometers).

Based on the Risk Assessment data and formulas, Exhibit C-4 shows the probability of at least one pipeline rupture over a 50 year period, given three diffe rent pipeline lengths. Exhibit C-5 shows the probability of at least one pipeline puncture over a 50 year pe riod, given three different pipeline lengths. For example, Exhibi t C-4 shows that, over a 50 year period, there is an estimated 35% probability of a pipeline rupt ure in a 150 kilometer pipeline and Exhibit C-5

91 See page 6-14 of the FutureGen Risk Assessment.
92 The Risk Assessment mentioned these estimates on pages 4-4 and 6-14; however, it mentions different risk values for ruptures and punctures in mile-year. EPA has determined that this is an error in converting between mile-year and kilometer-year. EPA used the risk values expresse d in kilometer-year in preparing Figures 1 and 2.

### Page 114 of 145 shows that, over a 50 year period, there is an es timated 60% probability of a pipeline puncture in a 150 kilometer pipeline. 93



### Exhibit C-4. Probability of CO 2 

### Pipeline Rupture over 50 Year Period: 50-, 100- and 150-Mile Pipelines a

a Based on data and formulas in “Final Risk Assessment Report for the FutureGen Project Environmental Impact Statement,” dated October 2007 (see page 6-14).



### Exhibit C-5. Probability of CO 2 

### Pipeline Puncture over 50 Year Period: 50-, 100- and 150-Mile Pipelines a

a Based on data and formulas in “Final Risk Assessment Report for the FutureGen Project Environmental Impact Statement,” dated October 2007 (see page 6-14).

93 The Risk Assessment identifies some data gaps and limitati ons in its risk estimates (see page 6-20). For example, there are many established techniques for minimizing the chances and consequences of a pipeline rupture or puncture.

### Page 115 of 145 C.5.3 Potential Health Impacts of CO 2 

### Pipeline Releases

The Risk Assessment describes release simulations from pipeline transmission lines that were performed. The simulations examined emissions of CO 2 

### and H 2 

### S. The SLAB air dispersion model was used to simulate the emission of CO 2 

### for various release scenarios involving the pipeline when the gas is in a supercritical gas state. 94 

### Pipeline release simulations were evaluated for a “hole-puncture” and a complete severing of the pipeline. An automated “pipeline-walk” approach was developed to evaluate the effects of thermodynamically determined gas-phase releases along the entire lengt h of the pipeline at each site being examined. The five main steps in this approach involved the following:

• Step 1. Summarize meteorological conditi ons that affect plume transport;

• Step 2. Simulate the area potentially affected by a pipeline release;

• Step 3. Estimate population affected for each atmospheric state;

• Step 4. Determine the expected number of indivi duals potentially affect ed at the specified release points; and

• Step 5. Characterize the potential ex posure along the entire pipeline.

As explained by the Risk Assessment, the results of the “pipeline-walk” analyses indicated no predicted potential he alth effects from CO 2 

### releases due to pipeline r uptures or punctures at any of the four candidate sites. This is shown in Exhibit C-6. In all cases, the expected number of individuals affected is less than one.

Exhibit C-6 shows that the largest numb er of people potentially affected by H 2 

### S releases is associated with pipeline ruptures. The model si mulations predict that up to 52 individuals from the general public would be expected to experience adverse effects from a pipeline rupture at the Jewett Site (H2S, 0.51 ppmv). The poten tial for adverse effects from H 2 

### S exposure are predicted for pipeline ruptures at the Tusc ola Site for 7.4 individuals. Fe wer numbers of individuals at both sites are predicted to be affected by a pipe line puncture. The maximum number of expected individuals experiencing a dverse effects from the H 2 

### S release from a puncture is six at the Jewett Site and one at the Tuscola Site. The maximum number of individuals e xpected to experience irreversible-adverse or life threatening effects for the Jewett pipeline is one. No adverse or lifethreatening effects are predicted for H 2 

### S releases from pipeline r uptures or punctures at the Odessa and Mattoon sites.

94 The SLAB model was developed by the Lawrence Livermore National Laboratory, and is designed to simulate denser-than-air gas releases for both horizontal jet and vertically elevated jet scenarios. SLAB is approved by U.S. EPA as a h azardous air dispersion model.

### Page 116 of 145 Exhibit C-6: Summary of Expected Numbers of Individuals from the Public Affected by Pipeline Releases a 

### Mattoon, IL Tuscola, IL Jewett, TX Odessa, TX Ruptures: CO 2 

### Health Effects Adverse 0 <0.1 <0.5 0 Irreversible Adverse 0 <0.1 <0.5 0

Life Threatening 0 <0.1 <0.5 0 H 2 

### S Health Effects Adverse 0.12 7.4 52 0.19 Irreversible Adverse 0.001 <0.2 1 0.004

Life Threatening <0.001 <0.2 1 <0.004 Punctures: CO 2 

### Health Effects Adverse 0.01 <0.1 0.2 <0.1 Life Threatening <0.01 <0.1 <0.2 <0.1 H 2 

### S Health Effects Adverse <0.2 1 6 <0.1 Irreversible Adverse 0.002 0.02 0.1 0.005

Life Threatening <0.002 <0.02 <0.1 <0.001

a 

### This exhibit is taken from the “Final Risk Assessment Report for the FutureGen Project Environmental Imp act Statement,” dated October 2007 (see page 6-8).

The Risk Assessment concludes that “these resu lts indicate that the potential human-health effects due to pipeline ruptures or punctures at all sites are mini mal. The primary predicted effect identified in the ‘pipeline-walk’ analysis in the even t of a release is mild transient health effects. It is anticipated that the pred icted exposures can be avoided si nce the adverse-effects-level H 2 

### S concentration (0.51 ppmv) is asso ciated with the perception of an objectionable odor. Likewise, the life threatening effects of H 2 

### S exposures are associated with long exposure levels that can be detected and avoided.” 95

95 See page 6-7 of the FutureGen Risk Assessment.

### Page 117 of 145 C.5.4 Preliminary Conclusions on Potential Releases

Under the baseline, generators of hazardous waste CO 2 

### streams must conduct treatment to remove its RCRA characteristic(s) and thereby render it non-hazardous before sending it to a Class VI UIC well. This is because, pursuan t to EPA’s UIC amendmen ts, injection of RCRA hazardous waste into a Class VI UIC well w ould be prohibited. Treatment of the CO 2 

### would reduce the presence of metals and other ha rmful constituents (e.g., hydrogen sulfide) as appropriate to render it non-hazar dous. Note that some generators may decide to address their hazardous waste CO 2 

### streams in other ways (e.g., disposing of untreated hazardous waste CO 2 

### streams in a Class I UIC well that meets no migration requirements).

Under the proposed rule, generators could dispose of their exempt CO 2 

### stream in Class VI UIC wells, provided that the genera tor and UIC well owner/operator cl aim the exclusion and comply with its conditions. No treatment would be requ ired under the RCRA regulations. As a result, it is possible that a greater quantity of untreated CO 2 

### streams will be transported by pipeline for injection in UIC wells under the pr oposed rule than the baseline. For example, generators that would have treated their hazardous waste CO 2 

### under the baseline for injection in a Class VI UIC well could forgo treatment under the proposed rule. In addition, some gene rators that would not have captured their hazardous waste CO 2 

### at all under the baseline (e.g., because of treatment costs) may be induced to capture it under the pro posed rule for transport via pipeline to Class VI UIC wells.

The Risk Assessment concludes that the potential human-health effects due to pipeline ruptures or punctures at all sites under examination are mi nimal. The primary predicted effect identified in the ‘pipeline-walk’ analysis in the event of a release is mild tran sient health effects. It also indicates that the potential for human expos ure to hazardous constituents from accidental releases from CO 2 

### pipelines is related to several fact ors, including the composition of the CO 2 

### stream among other things. A greater quantity of untreated CO 2 

### streams being transported by pipeline under the proposed rule could potentially be associat ed with a higher potential for exposures of hazardous constituents to surr ounding populations, although the health effects appear to be mild.

C.6 Summary Chapter: Results of Analyses and Possible Next Steps

C.6.1 Comparative Analysis

Results

The comparative analysis identified the fo llowing potential regul atory differences:

• Generators operating under the proposed conditional exclusion would generally be subject to less stringent regul ation than generators operati ng under the baseline in regard to RCRA reporting and recordkeeping, emerge ncy preparedness and response, and waste
treatment.

• Pipelines carrying CO 2 

### streams managed under the proposed conditional exclusion would be subject to the same federal re gulations as pipelines carrying CO 2 

### streams managed under the baseline. In partic ular, pipeline transport of CO 2 

### would be subject to DOT

### Page 118 of 145 regulation under both the baseline and proposed rule. Pipeline transport is not subject to RCRA regulation.

• GS facilities operating under the proposed cond itional exclusion (i.e., facilities subject to Class VI UIC requirements) would be subj ect to federal regulation that would be comparable to, and in certain cases more stringent than, federal regulation of GS facilities operating under the baseline (i.e., facilities subject to Class I UIC requirements). For example, GS facilities operating under the pr oposed rule would be subject to additional and more stringent requirements related to siting, determining the area of review, monitoring of groundwater quality and other environmenta l media. Note, however, that EPA anticipates that a Class I hazardous well used for injection of hazardous waste CO 2 

### streams under the baseline would also be requi red by the permit writers to meet the Class VI UIC well requirements. There is no re gulatory requirement, however, that permit writers apply the Class VI require ments to Class I hazardous wells.

Possible Next Steps

The scope of comparative analysis is limited in that only a small number of federal regulations (e.g., RCRA regulations) were examined and compare d. An effort was made to identify the most relevant federal regulations for purposes of this analysis. However, additional analysis could be done on other potentially rele vant federal regulations.

C.6.2 Screening Analysis of Capture and Geologic Sequestration (GS) Facilities

Results

EPA’s screening analysis found that:

• 21 of the 31 GS and capture facilities ex amined (68%) have populations within a 1-mile radius that exceed their resp ective state’s percentage of minority populations and/or populations below 150% of the poverty level. Of these 21 facilities, 3 have populations within a 1-mile radius th at exceed th eir respective state’s percentage of minority populations and populations below 150% of the poverty level. These facilities include:

- Coffeyville Fertilizer Pl ant (capture facility);

- Kemper County Plant (cap ture facility); and

- Lima Plant (capture facility).

Each of these 3 facili ties has populations within a 1-mile radius with children 0 to 4 years and/or adults 65 years and ol der in percentages that exceed their respective state’s percentages. In additi on, each has at least on e existing FRS site located within a 1-mile radius. The Coffe yville Fertilizer Plant has 9 sites within a 1-mile radius, the Kemper County Plant has 1 site within a 1-mile radius, and the Lima Plant has 31 sites within a 1-mile radius.

• 20 of the 31 GS and capture facilities ex amined (65%) have populations within a 3-mile radius that exceed their resp ective state’s percentage of minority populations and/or populations below 150% of th e poverty level. They are

### Page 119 of 145 shaded in gray in the exhibit. Of thes e 20 facilities, 4 have populations within a 3-mile radius that exceed their resp ective state’s percentage of minority populations and populations below 150% of the poverty level. These facilities include:

- Coffeyville Fertilizer Pl ant (capture facility);

- Kemper County Plant (c apture facility);

- Lima Plant (capture facility); and

- San Joaquin Basin Project, CA Saline Formation (GS Facility).

Each of these 4 facili ties has populations within a 3-mile radius with children 0 to 4 years and/or adults 65 years and ol der in percentages that exceed their respective state’s percentages. In ad dition, each has existing FRS sites located within a 3-mile radius. The Coffeyville Fe rtilizer Plant has 31 sites within a 3- mile radius, the Kemper County Plant has 3 sites within a 3-mile radius, the Lima Plant has 88 sites within a 3-mile radius , and the San Joaquin Basin Project has 3 sites within a 3-mile radius.

Possible Next Steps

Additional research could be perf ormed to learn more about the pa rticular characteristics of the populations identified in this screening analysis. This information could help EPA better understand the potential vulnerabilities and concerns of these populations.

In addition, it is important to not e that the screening analysis wa s not performed on a number of planned GS facilities for which EPA does not ha ve location information. When their location becomes known, a screening analysis of them could be performed.

D.6.3 Qualitative Screening Analysis of Pipelines

Results

Under the baseline, generators of hazardous waste CO 2 

### streams must conduct treatment to remove its RCRA characteristic(s) and thereby render it non-hazardous before sending it to a Class VI UIC well. This is because, pursuan t to EPA’s UIC amendmen ts, injection of RCRA hazardous waste into a Class VI UIC well w ould be prohibited. Treatment of the CO 2 

### would reduce the presence of metals and other ha rmful constituents (e.g., hydrogen sulfide) as appropriate to render it non-hazar dous. Note that some generators may decide to address their hazardous waste CO 2 

### streams in other ways.

Under the proposed rule, generators could dispose of their exempt CO 2 

### stream in Class VI UIC wells, provided that the genera tor and UIC well owner/operator cl aim the exclusion and comply with its conditions. No treatment would be requ ired under the RCRA regulations. As a result, it is possible that a greater quantity of untreated CO 2 

### streams will be transported by pipeline for injection in UIC wells under the pro posed rule than the baseline.

The FutureGen Risk Assessment concludes that the results of its “pipe-walk” analysis indicate that the potential human-health effects due to pi peline ruptures or punctu res at all four sites

### Page 120 of 145 under examination are minimal. The primary predicte d effect in the event of a release is mild transient health effects.

It also indicates that the poten tial for human exposure to hazar dous constituents from accidental releases from CO 2 

### pipelines is related to several fact ors, including the composition of the CO 2 

### stream among other things. A greater quantity of untreated CO 2 

### streams being transported by pipeline under the proposed rule could potentially be associat ed with a higher potential for exposures of hazardous constituents to surr ounding populations, although the health effects appear to be mild.

Possible Next Steps

The conclusions of this analysis are based on a single source, i.e., the FutureGen Risk Assessment. Additional research and analysis may be appropriate to learn more about the potential risks and health impacts to populations near CO 2 

### pipelines.

Appendix C.A. – Facilities Included in the Environmental Screening Analysis

The facilities in Exhibits C.A-1 through C.A-3 ar e included in the EJ screening analysis.

Exhibit C.A-1. Planned Major Commercial (Non-DOE) and FutureGen Capture Facilities Facility Name State Lat D/M/S Long D/M/S Commercial AEP Alstom Mountaineer (Ph.2) WV 38/58/44 81/56/20

AEP Alstom Northeastern OK 36/25/51 95/42/03 Edwardsport IN 38/48/24 87/14/49 Great Bend OH 38/59/56 81/45/47 Hydrogen Energy HECA CA 35/17/03 119/26/44 Kemper County MS 32/48/53 88/43/24 Lima OH 40/44/33 84/06/49 Mesaba MN 47/33/55 92/08/47 Tenasca Taylorville Energy IL 39/35/21 89/11/20 Tenasca Sweetwater/Trailblazer TX 32/28/04 100/24/27 Texas Clean Energy Project TX 31/44/46 102/36/30 WA Parish, Sugarland TX 29/28/40 95/38/06 Wallula Energy Res. Center a 

### WA 46/07/14 118/54/15 Worsham-Steed (ZENG) TX 32/27/41 97/53/27 FutureGen Futuregen IL 39/29/49 88/26/26

### Page 121 of 145 Exhibit C.A-2. Existing Gas and Fertilizer Plants Facility State Lat D/M/S Long D/M/S Val Verde Gas - Pikes Peak Plant TX 30/38/1 7 102/56/34 Val Verde Gas - Grey Ranch Plant TX 30/33/1 6 102/26/33

Val Verde Gas - Puckett Plant TX 30/44/4 0 102/29/30

Val Verde Gas - Terrell Plant TX 30/22/1 9 101/50/39

Val Verde Gas - Mitchell Plant TX 30/40/1 6 102/29/37

La Barge Gas Plant WY 42/15/4 3 110/11/41

Enid Ammonia Fertilizer Gas Plant OK 36/22/4 4 97/45/38 Coffeyville Ammonia Fertilizer Plant KS 37/05/1 9 95/43/39

Antrim Gas Plant MI 45/1/27 84/36/7

Great Plains Coal Gasification ND 47/21/4 8 101/49/54

Exhibit C.A-3. Major DOE Sequestration Projects Facility State Lat D/M/S Long D/M/S Illinois Basin Mt. Simon Saline Reservoir IL 39/52/4 5 88/53/41 Williston Basin EOR Sequestration ND 48/31/2 8 102/58/11 Green River Basin Nugget Sand Saline Reservoir WY 43/15/3 0 110/12/60 Cincinnati Arch Mt. Simon Saline a 

### OH 38/54/1 3 84/50/56 San Joaquin Basin, CA Saline Formation a 

### CA 36/33/4 9 119/12/19

Mt. Simon Saline Reservoir IL 39/29/4 9 88/26/26

a Information received after the completion of this analysis indicates that thes e facilities are not expected to move forward.

### Page 122 of 145 Appendix C.B. Characteristics of Populations Within 1- and 3-Mile Radius of Facilities: Detailed Exhibits Supporting the Enviro nmental Justice Screening Analyses

This appendix presents detailed results of the en vironmental justice screening analysis. Data are presented on the incidence of each indicator that EPA examined within a 1- and 3-mile radius of capture and GS facilities. These data are presented in the following exhibits:

• Exhibit C.B-1. Percentage of Population that is Minority (by Race and in Total) Within 1- Mile Radius of Facility

• Exhibit C.B-2. Percentage of Population that is Below150% of Poverty Level Within 1- Mile Radius of Facility

• Exhibit C.B-3. Percentage of Population 0 to 4 Years and 65+ Years Within 1-Mile Radius of Facility

• Exhibit C.B-4. Number of FRS Sites W ithin 1-Mile Radius of Facility

• Exhibit C.B-5. Percentage of Population that is Minority (by Race and in Total) Within 3- Mile Radius of Facility

• Exhibit C.B-6. Percentage of Population that is Below150% of Poverty Level Within 3- Mile Radius of Facility

• Exhibit C.B-7. Percentage of Population 0 to 4 Years and 65+ Years Within 3-Mile Radius of Facility

• Exhibit C.B-8. Number of FRS Sites W ithin 3-Mile Radius of Facility

Each exhibit lists the facility’s name and type (e .g., commercial capture). In the row below each facility is information on the facil ity’s state location and indicators. If the facility is located in two states, information is provided on both states and respective indicators in each state. In addition, the exhibits use a gray hi ghlight to identify indi cators whose percentage within the 1- or 3-mile radius of the facility exceeds the state’s percentage.Exhibit C.B-1. Percentage of Population that is Minority (by Race and in Total) Within 1-Mile Radius of FacilityFacility Name Facility TypePercent ofPopulationthat is BlackAlone: 1-MileRadiusPercent ofPopulationthat is BlackAlone: StatePercent ofPopulationthat is NativeAmericanAlone: 1-MileRadiusPercent ofPopulationthat is NativeAmericanAlone: StatePercent ofPopulationthat is AsianAlone: 1-Mile RadiusPercent ofPopulationthat is AsianAlone: StatePercent ofPopulationthat is PacificAlone: 1-MileRadiusPercent ofPopulationthat is PacificAlone: StatePercent ofPopulationthat isHispanic: 1-Mile RadiusPercent ofPopulationthat isHispanic:StatePercent ofPopulationthat isMinority (AllRaces): 1-Mile RadiusPercent ofPopulationthat isMinority (AllRaces): StateAEP AlstomMountaineer (Ph.2)Commercial CaptureOhio 0.2% 12.2% 0.0% 0.1% 0.0% 1.6% 0.0% 0.0% 0.0% 2.7% 1.0% 18.0%West Virginia 0.0%3.7%0.0%0.1%0.1%0.6%0.0%0.0%0.0%1.2%0.1%6.5%AEP AlstomNortheasternCommercial CaptureOklahoma 0.1%8.0%12.2%7.9%0.0%1.8%0.0%0.1%1.3%8.0%27.2%29.8%Antrim Gas PlantExisiting Gas andFertilizer PlantMichigan 0.1%14.4%0.1%0.5%0.1%2.4%0.0%0.0%0.2%4.3%2.7%23.0%Cincinnati Arch Mt.Simon SalineMajor DOESequestration ProjectIndiana 1.1% 9.2%0.4%0.2% 0.0% 1.4% 0.0% 0.0% 1.7% 5.5% 4.1% 17.6%Kentucky0.0%7.8%0.5%0.2%0.2%1.0%0.0%0.0%1.4%2.5%2.6%12.5%Coffeyville FertilizerPlantCommercial CaptureKansas25.0%6.1%5.1%0.9%0.3%2.3%0.0%0.0%5.0%9.5%42.2%20.8%EdwardsportCommercial CaptureIndiana 0.1%9.2%0.0%0.2%0.0%1.4%0.0%0.0%2.3%5.5%4.2%17.6%Enid Gas PlantExisiting Gas andFertilizer PlantOklahoma 0.1%8.0%0.1%7.9%0.0%1.8%0.6%0.1%2.4%8.0%4.6%29.8%FuturegenFutureGenIllinois 1.9%14.9%0.0%0.3%0.6%4.6%0.0%0.0%1.1%16.0%5.4%37.0%Great BendCommercial CaptureOhio 0.4% 12.2%0.3%0.1% 0.7% 1.6% 0.0% 0.0% 0.0% 2.7% 4.0% 18.0%West Virginia 0.6%3.7%0.0%0.1%2.9%0.6%0.0%0.0%0.8%1.2%5.3%6.5%Great Plains CoalGasificationExisiting Gas andFertilizer PlantNorth Dakota 0.0%1.2%0.5%5.6%0.0%0.7%0.0%0.0%0.0%2.2%1.5%10.8%Green River BasinNugget Sand SalineReservoirMajor DOESequestration ProjectWyoming 0.2%1.4%0.4%2.5%0.1%0.7%0.0%0.1%4.7%8.1%6.3%13.7%Page 124 of 145Exhibit C.B-1. Percentage of Population thatis Minority (by Race and in Total) Within 1-Mile Radius of Facility (Cont’d)Facility Name Facility TypePercent ofPopulationthat is BlackAlone: 1-MileRadiusPercent ofPopulationthat is BlackAlone: StatePercent ofPopulationthat is NativeAmericanAlone: 1-MileRadiusPercent ofPopulationthat is NativeAmericanAlone: StatePercent ofPopulationthat is AsianAlone: 1-Mile RadiusPercent ofPopulationthat is AsianAlone: StatePercent ofPopulationthat is PacificAlone: 1-MileRadiusPercent ofPopulationthat is PacificAlone: StatePercent ofPopulationthat isHispanic: 1-Mile RadiusPercent ofPopulationthat isHispanic:StatePercent ofPopulationthat isMinority (AllRaces): 1-Mile RadiusPercent ofPopulationthat isMinority (AllRaces): StateHydrogen EnergyHECACommercial CaptureCalifornia13.1%6.6%1.3%1.1% 2.9% 12.8% 0.0% 0.3% 21.0% 37.7% 40.8% 61.1%Illinois Basin Mt.Simon SalineReservoirMajor DOESequestration ProjectIllinois21.4%14.9% 0.1% 0.3% 0.5% 4.6% 0.0% 0.0% 3.2% 16.0% 29.5% 37.0%Kemper CountyCommercial CaptureMississippi70.4%37.5% 0.0% 0.4% 0.4% 0.8% 0.0% 0.0% 0.3% 2.4%71.4%41.9%La Barge Gas PlantExisiting Gas andFertilizer PlantWyoming 0.1% 1.4% 0.1% 2.5% 0.0% 0.7% 0.0% 0.1% 5.1% 8.1% 7.9% 13.7%LimaCommercial CaptureOhio24.6%12.2%0.3%0.1% 0.5% 1.6% 0.0% 0.0%3.1%2.7%31.7%18.0%MesabaCommercial CaptureMinnesota 0.0% 4.8% 0.0% 1.2% 0.0% 3.7% 0.0% 0.0% 0.2% 4.4% 1.1% 15.7%Mt. Simon SalineReservoirMajor DOESequestration ProjectIllinois 1.9% 14.9% 0.0% 0.3% 0.6% 4.6% 0.0% 0.0% 1.1% 16.0% 5.4% 37.0%San Joaquin Basin,CA SalineFormationMajor DOESequestration ProjectCalifornia 4.6% 6.6%5.0%1.1% 4.1% 12.8%3.0%0.3%45.7%37.7% 55.6% 61.1%TenascaSweetwater/TrailblazerCommercial CaptureTexas 8.7% 12.0%0.8%0.7% 0.3% 3.6% 0.0% 0.1%43.2%37.3% 54.8% 55.1%Tenasca TaylorvilleEnergyCommercial CaptureIllinois 0.2% 14.9% 0.0% 0.3% 0.6% 4.6% 0.0% 0.0% 0.1% 16.0% 2.7% 37.0%Texas CleanEnergy ProjectCommercial CaptureTexas 0.2% 12.0% 0.0% 0.7% 0.0% 3.6% 0.0% 0.1%47.3%37.3% 50.6% 55.1%Val Verde GasPlant, Gray RanchExisiting Gas andFertilizer PlantTexas13.6%12.0% 0.1% 0.7% 0.2% 3.6% 0.0% 0.1%59.6%37.3%75.0%55.1%Page 125 of 145Exhibit C.B-1. Percentage of Population thatis Minority (by Race and in Total) Within 1-Mile Radius of Facility (Cont’d)Facility Name Facility TypePercent ofPopulationthat is BlackAlone: 1-MileRadiusPercent ofPopulationthat is BlackAlone: StatePercent ofPopulationthat is NativeAmericanAlone: 1-MileRadiusPercent ofPopulationthat is NativeAmericanAlone: StatePercent ofPopulationthat is AsianAlone: 1-Mile RadiusPercent ofPopulationthat is AsianAlone: StatePercent ofPopulationthat is PacificAlone: 1-MileRadiusPercent ofPopulationthat is PacificAlone: StatePercent ofPopulationthat isHispanic: 1-Mile RadiusPercent ofPopulationthat isHispanic:StatePercent ofPopulationthat isMinority (AllRaces): 1-Mile RadiusPercent ofPopulationthat isMinority (AllRaces): StateVal Verde GasPlant, MitchellExisiting Gas andFertilizer PlantTexas13.6%12.0% 0.1% 0.7% 0.2% 3.6% 0.0% 0.1%59.6%37.3%75.0%55.1%Val Verde GasPlant, Pikes PeakExisiting Gas andFertilizer PlantTexas13.6%12.0% 0.1% 0.7% 0.2% 3.6% 0.0% 0.1%59.6%37.3%75.0%55.1%Val Verde GasPlant, PuckettExisiting Gas andFertilizer PlantTexas13.6%12.0% 0.1% 0.7% 0.2% 3.6% 0.0% 0.1%59.6%37.3%75.0%55.1%Val Verde GasPlant, TerrellExisiting Gas andFertilizer PlantTexas 0.0% 12.0%4.1%0.7% 0.4% 3.6% 0.0% 0.1% 35.1% 37.3% 42.1% 55.1%WA Parish,SugarlandCommercial CaptureTexas13.6%12.0% 0.6% 0.7%5.4%3.6% 0.0% 0.1% 28.0% 37.3% 50.7% 55.1%Wallula Energy Res.CenterCommercial CaptureWashington 1.1% 3.7% 0.9% 1.6% 0.9% 7.0% 0.0% 0.4%12.8%10.1% 15.6% 26.0%Williston Basin EORSequestration*Major DOESequestration ProjectNorth Dakota 0.0% 1.2% 0.0% 5.6% 0.0% 0.7% 0.0% 0.0% 0.0% 2.2% 1.6% 10.8%Worsham-Steed(ZENG)Commercial CaptureTexas 0.9% 12.0%1.0%0.7% 0.5% 3.6% 0.0% 0.1% 7.5% 37.3% 13.6% 55.1%

### Exhibit C.B-2. Percentage of Population th at is Below150% of Poverty Level Within 1-Mile Radius of Facility

Facility Name Facility Type Percent of Population below 150% of Poverty Level : 1-Mile Radius Percent of Population below 150% of Poverty Level: State
AEP Alstom Mountaineer (Ph.2) Commercial Capture Ohio 35.3% 23.9% West Virginia 17.6% 28.7% AEP Alstom Northeastern Commercial Capture Oklahoma 21.8% 27.9% Antrim Gas Plant Exisiting Gas and Fertilizer Plant Michigan 15.7% 25.6% Cincinnati Arch Mt. Simon Saline Major DOE Sequestration Projec t Indiana 37.4% 24.1% Kentucky 12.4% 29.1% Coffeyville Fertilizer Plant Commercial Capture Kansas 39.4% 21.8% Edwardsport Commercial Capture Indiana 25.3% 24.1% Enid Gas Plant Exisiting Gas and Fertilizer Plant Oklahoma 19.8% 27.9% Futuregen FutureGen Illinois 26.0% 20.9% Great Bend Commercial Capture Ohio 35.5% 23.9% West Virginia 22.6% 28.7% Great Plains Coal Gasification Exisiting Gas and Fertilizer Plant North Dakota 27.9% 20.0% Green River Basin Nugget Sand Saline Reservoir Major DOE Sequestration Project Wyoming 9.1% 16.8% Hydrogen Energy HECA Commercial Capture California 4.1% 21.2% Illinois Basin Mt. Simon Saline Reservoir Major DOE Sequestration Project Illinois 28.4% 20.9% Kemper County Commercial Capture Mississippi 64.5% 33.4% La Barge Gas Plant Exisiting Gas and Fertilizer Plant Wyoming 13.9% 16.8%

### Page 127 of 145 Exhibit C.B-2. Percentage of Population th at is Below150% of Poverty Level Within 1-Mile Radius of Facility (Cont’d)

Facility Name Facility Type Percent of Population below 150% of Poverty Level : 1-Mile Radius Percent of Population below 150% of Poverty Level: State

Lima Commercial Capture Ohio 48.2% 23.9% Mesaba Commercial Capture Minnesota 12.8% 18.1% Mt. Simon Saline Reservoir Major DOE Sequestration Project Illinois 26.0% 20.9% San Joaquin Basin, CA Saline Formation Major DOE Sequestration Project California 35.8% 21.2% Tenasca Sweetwater/Trailblazer Commercial Capture Texas 40.5% 27.7% Tenasca Taylorville Energy Commercial Capture Illinois 11.6% 20.9% Texas Clean Energy Project Commercial Capture Texas 18.8% 27.7% Val Verde Gas Plant, Gray Ranch Exisiting Gas and Fertilizer Plant Texas 17.7% 27.7% Val Verde Gas Plant, Mitchell Exisiting Gas and Fertilizer Plant Texas 17.7% 27.7% Val Verde Gas Plant, Pikes Peak Exisiting Gas and Fertilizer Plant Texas 17.7% 27.7% Val Verde Gas Plant, Puckett Exisiting Gas and Fertilizer Plant Texas 17.7% 27.7% Val Verde Gas Plant, Terrell Exisiting Gas and Fertilizer Plant Texas 28.9% 27.7% WA Parish, Sugarland Commercial Capture Texas 10.8% 27.7% Wallula Energy Res. Center Commercial Capture Washington 32.3% 20.1% Williston Basin EOR Sequestration* Major DOE Sequestration Projec t North Dakota 21.6% 20.0% Worsham-Steed (ZENG) Commercial Capture Texas 33.1% 27.7%

### Page 128 of 145 Exhibit C.B-3. Percentage of Populat ion 0 to 4 Years and 65+ Years Within 1-Mile Radius of Facility

Facility Name Facility Type Percent of Population that is 0-4 Years: 1-Mile Radius Percent of Population that

is 0-4 Years: State Percent of Population that is 65+ Years: 1-

Mile Radius Percent of Population that

is 65+ Years: State AEP Alstom Mountaineer (Ph.2) Commercial Capture Ohio 5.0% 5.6% 19.7% 14.4% West Virginia 5.0% 5.0% 17.2% 16.5%
AEP Alstom Northeastern Commercial Capture Oklahoma 5.3% 6.2% 13.2% 13.5%

Antrim Gas Plant Exisiting Gas and Fertilizer Plant Michigan 4.6% 5.3% 16.1% 14.0% Cincinnati Arch Mt. Simon Saline Major DOE Sequestration Project
Indiana 5.2% 6.0% 12.6% 13.4% Kentucky 4.8% 5.7% 15.0% 13.7% Coffeyville Fertilizer Plant Commercial Capture Kansas 7.0% 6.2% 15.1% 13.4% Edwardsport Commercial Capture Indiana 5.8% 6.0% 15.2% 13.4%

Enid Gas Plant Exisiting Gas and Fertilizer Plant Oklahoma 5.5% 6.2% 18.1% 13.5% Futuregen FutureGen Illinois 4.3% 6.0% 10.6% 13.0% Great Bend Commercial Capture
Ohio 4.8% 5.6% 15.1% 14.4% West Virginia 4.8% 5.0% 20.5% 16.5%
Great Plains Coal Gasification Exisiting Gas and Fertilizer Plant North Dakota 2.8% 5.7% 22.2% 14.9% Green River Basin Nugget Sand Saline Reservoir Major DOE Sequestration Project Wyoming 5.6% 6.1% 20.4% 13.4% Hydrogen Energy HECA Commercial Capture California 3.3% 6.3% 7.9% 11.9%
Illinois Basin Mt. Simon Saline Reservoir Major DOE Sequestration Project Illinois 5.8% 6.0% 13.2% 13.0% Kemper County Commercial Capture Mississippi 5.2% 6.4% 19.9% 12.9%

### Page 129 of 145 Exhibit C.B-3. Percentage of Populat ion 0 to 4 Years and 65+ Years Within 1-Mile Radius of Facility (Cont’d)

Facility Name Facility Type Percent of Population that is 0-4 Years: 1-Mile Radius Percent of Population that

is 0-4 Years: State Percent of Population that is 65+ Years: 1-

Mile Radius Percent of Population that

is 65+ Years: State

La Barge Gas Plant Exisiting Gas and Fertilizer Plant Wyoming 6.9% 6.1% 12.0% 13.4%
Lima Commercial Capture Ohio 7.0% 5.6% 11.2% 14.4%
Mesaba Commercial Capture Minnesota 3.5% 5.9% 26.0% 13.5%

Mt. Simon Saline Reservoir Major DOE Sequestration Project Illinois 4.3% 6.0% 10.6% 13.0% San Joaquin Basin, CA Saline Formation Major DOE Sequestration Project California 6.7% 6.3% 14.1% 11.9%
Tenasca Sweetwater/Trailblazer Commercial Capture Texas 7.3% 7.0% 12.4% 10.8% Tenasca Taylorville Commercial Capture Illinois 4.8% 6.0% 15.6% 13.0% Texas Clean Energy Commercial Capture Texas 7.4% 7.0% 12.9% 10.8% Val Verde Gas Plant, Gray Ranch Exisiting Gas and Fertilizer Plant Texas 4.6% 7.0% 9.2% 10.8% Val Verde Gas Plant, Mitchell Exisiting Gas and Fertilizer Plant Texas 4.6% 7.0% 9.2% 10.8% Val Verde Gas Plant, Pikes Peak Exisiting Gas and Fertilizer Plant Texas 4.6% 7.0% 9.2% 10.8% Val Verde Gas Plant, Puckett Exisiting Gas and Fertilizer Plant Texas 4.6% 7.0% 9.2% 10.8% Val Verde Gas Plant, Terrell Exisiting Gas and Fertilizer Plant Texas 3.3% 7.0% 19.8% 10.8% WA Parish, Sugarland Commercial Capture Texas 5.9% 7.0% 12.0% 10.8% Wallula Energy Res. Commercial Capture Washington 5.2% 5.6% 12.3% 13.2% Williston Basin EOR Sequestration* Major DOE Sequestration Project North Dakota 4.0% 5.7% 26.9% 14.9% Worsham-Steed (ZENG) Commercial Capture Texas 5.8% 7.0% 15.7% 10.8%

### Exhibit C.B-4. Number of FRS Sites Wi thin 1-Mile Radius of Facility
Facility Name Facility Type Number of EPA FRS Sites within 1- Mile Radius

AEP Alstom Mountaineer (Ph.2) Commercial Capture Ohio 4 West Virginia 3 AEP Alstom Northeastern Commercial Capture Oklahoma 3

Antrim Gas Plant Exisiting Gas and Fertilizer Plant Michigan 0 Cincinnati Arch Mt. Simon Saline Major DOE Sequestration Project Indiana 2 Kentucky 1 Coffeyville Fertilizer Plant Commercial Capture Kansas 9 Edwardsport Commercial Capture Indiana 4

Enid Gas Plant Exisiting Gas and Fertilizer Plant Oklahoma 1 Futuregen FutureGen Illinois 1 Great Bend Commercial Capture Ohio 1 West Virginia 2

Great Plains Coal Gasification Exisiting Gas and Fertilizer Plant North Dakota 3 Green River Basin Nugget Sand Saline Reservoir Major DOE Sequestration Project Wyoming 1 Hydrogen Energy HECA Commercial Capture California 1 Illinois Basin Mt. Simon Saline Reservoir Major DOE Sequestration Project Illinois 5 Kemper County Commercial Capture Mississippi 1

La Barge Gas Plant Exisiting Gas and Fertilizer Plant Wyoming 2

### Exhibit C.B-4. Number of FRS Sites Within 1-Mile Radius of Facility (Cont’d)
Facility Name Facility Type Number of EPA FRS Sites within 1- Mile Radius Lima Commercial Capture Ohio 31 Mesaba Commercial Capture Minnesota 1

Mt. Simon Saline Reservoir Major DOE Sequestration Project Illinois 1 San Joaquin Basin, CA Saline Formation Major DOE Sequestration Project California 2 Tenasca Sweetwater/Trailblazer Commercial Capture Texas 9 Tenasca Taylorv ille Energy Commercial Capture Illinois 2 Texas Clean Energy Project Commercial Capture Texas 1 Val Verde Gas Plant, Gray Ranch Exisiting Gas and Fertilizer Plant Texas 2

Val Verde Gas Plant, Mitchell Exisiting Gas and Fertilizer Plant Texas 1 Val Verde Gas Plant, Pikes Peak Exisiting Gas and Fertilizer Plant Texas 1

Val Verde Gas Plant, Puckett Exisiting Gas and Fertilizer Plant Texas 2

Val Verde Gas Plant, Terrell Exisiting Gas and Fertilizer Plant Texas 1 WA Parish, Sugarland Commercial Capture Texas 2 Wallula Energy Res. Center Commercial Capture Washin g ton 1 Williston Basin EOR Sequestration* Major DOE Sequestration Project North Dakota 0 Worsham-Steed (ZENG) Commercial Capture Texas 1Exhibit C.B-5. Percentage of Population that is Minority (by Race and in Total) Within 3-Mile Radius of FacilityFacility Name Facility TypePercent ofPopulationthat is BlackAlone: 3-Mile RadiusPercent ofPopulationthat is BlackAlone: StatePercent ofPopulationthat is NativeAmericanAlone: 3-MileRadiusPercent ofPopulationthat isNativeAmericanAlone: StatePercent ofPopulationthat is AsianAlone: 3-Mile RadiusPercent ofPopulationthat is AsianAlone: StatePercent ofPopulationthat isPacificAlone: 3-Mile RadiusPercent ofPopulationthat isPacificAlone: StatePercent ofPopulationthat isHispanic: 3-Mile RadiusPercent ofPopulationthat isHispanic:StatePercent ofPopulationthat isMinority (AllRaces): 3-Mile RadiusPercent ofPopulationthat isMinority (AllRaces):StateAEP Alstom Mountaineer(Ph.2)Commercial CaptureOhio0.3% 12.2% 0.0% 0.1% 0.3% 1.6% 0.0% 0.0% 0.0% 2.7% 1.9% 18.0%West Virginia0.1% 3.7% 0.0% 0.1% 0.0% 0.6% 0.0% 0.0% 0.4% 1.2% 1.4% 6.5%AEP Alstom NortheasternCommercial CaptureOklahoma0.2% 8.0%11.1%7.9% 0.4% 1.8% 0.0% 0.1% 1.4% 8.0% 24.2% 29.8%Antrim Gas PlantExisiting Gas andFertilizer PlantMichigan0.3% 14.4%0.8%0.5% 0.5% 2.4% 0.0% 0.0% 1.6% 4.3% 5.2% 23.0%Cincinnati Arch Mt. SimonSalineMajor DOESequestrationProjectIndiana1.3% 9.2%0.3%0.2% 0.1% 1.4% 0.0% 0.0% 1.1% 5.5% 3.9% 17.6%Kentucky0.0% 7.8%0.4%0.2% 0.2% 1.0% 0.0% 0.0% 1.1% 2.5% 2.2% 12.5%Coffeyville Fertilizer PlantCommercial CaptureKansas12.6%6.1%4.9%0.9% 0.5% 2.3% 0.0% 0.0% 4.5% 9.5%27.7%20.8%EdwardsportCommercial CaptureIndiana0.2% 9.2% 0.1% 0.2% 0.0% 1.4% 0.0% 0.0% 1.8% 5.5% 3.6% 17.6%Enid Gas PlantExisiting Gas andFertilizer PlantOklahoma0.1% 8.0% 0.5% 7.9% 0.0% 1.8%0.4%0.1% 2.3% 8.0% 5.1% 29.8%FuturegenFutureGenIllinois0.9% 14.9% 0.0% 0.3% 0.3% 4.6% 0.0% 0.0% 1.3% 16.0% 5.3% 37.0%Great BendCommercial CaptureOhio0.4% 12.2%0.3%0.1% 0.6% 1.6% 0.0% 0.0% 0.5% 2.7% 4.2% 18.0%West Virginia1.2% 3.7% 0.0% 0.1%2.6%0.6% 0.0% 0.0% 0.8% 1.2% 5.5% 6.5%Exhibit C.B-5. Percentage of Population thatis Minority (by Race and in Total) Within 3-Mile Radius of Facility (Cont’d)Facility Name Facility TypePercent ofPopulationthat is BlackAlone: 3-Mile RadiusPercent ofPopulationthat is BlackAlone: StatePercent ofPopulationthat is NativeAmericanAlone: 3-MileRadiusPercent ofPopulationthat isNativeAmericanAlone: StatePercent ofPopulationthat is AsianAlone: 3-Mile RadiusPercent ofPopulationthat is AsianAlone: StatePercent ofPopulationthat isPacificAlone: 3-Mile RadiusPercent ofPopulationthat isPacificAlone: StatePercent ofPopulationthat isHispanic: 3-Mile RadiusPercent ofPopulationthat isHispanic:StatePercent ofPopulationthat isMinority (AllRaces): 3-Mile RadiusPercent ofPopulationthat isMinority (AllRaces):StateGreat Plains CoalGasificationExisiting Gas andFertilizer PlantNorth Dakota0.0% 1.2% 0.5% 5.6% 0.0% 0.7% 0.0% 0.0% 0.0% 2.2% 1.5% 10.8%Green River Basin NuggetSand Saline ReservoirMajor DOESequestrationProjectWyoming0.2% 1.4% 0.4% 2.5% 0.1% 0.7% 0.0% 0.1% 4.7% 8.1% 6.3% 13.7%Hydrogen Energy HECACommercial CaptureCalifornia13.1%6.6%1.3%1.1% 2.9% 12.8% 0.0% 0.3% 21.0% 37.7% 40.8% 61.1%Illinois Basin Mt. SimonSaline ReservoirMajor DOESequestrationProjectIllinois16.7%14.9% 0.2% 0.3% 1.2% 4.6%0.1%0.0% 2.3% 16.0% 23.4% 37.0%Kemper CountyCommercial CaptureMississippi69.6%37.5% 0.0% 0.4% 0.3% 0.8% 0.0% 0.0% 0.4% 2.4%70.7%41.9%La Barge Gas PlantExisiting Gas andFertilizer PlantWyoming0.2% 1.4% 0.3% 2.5% 0.1% 0.7%0.1%0.1% 5.3% 8.1% 8.4% 13.7%LimaCommercial CaptureOhio22.5%12.2%0.2%0.1% 0.7% 1.6% 0.0% 0.0% 2.4% 2.7%28.6%18.0%MesabaCommercial CaptureMinnesota0.0% 4.8% 0.0% 1.2% 0.0% 3.7% 0.0% 0.0% 0.2% 4.4% 1.3% 15.7%Mt. Simon Saline ReservoirMajor DOESequestrationProjectIllinois0.9% 14.9% 0.0% 0.3% 0.3% 4.6% 0.0% 0.0% 1.3% 16.0% 5.3% 37.0%San Joaquin Basin, CASaline FormationMajor DOESequestrationProjectCalifornia2.9% 6.6%4.6%1.1% 6.3% 12.8%0.8%0.3%69.2%37.7%77.4%61.1%Tenasca Sweetwater/TrailblazerCommercial CaptureTexas7.1% 12.0% 0.5% 0.7% 0.7% 3.6% 0.1% 0.1% 36.4% 37.3% 46.5% 55.1%Page 134 of 145Exhibit C.B-5. Percentage of Population that is Minority (by Race and in Total) Within 3-Mile Radius of Facility(Cont’d)Facility Name Facility TypePercent ofPopulationthat is BlackAlone: 3-Mile RadiusPercent ofPopulationthat is BlackAlone: StatePercent ofPopulationthat is NativeAmericanAlone: 3-MileRadiusPercent ofPopulationthat isNativeAmericanAlone: StatePercent ofPopulationthat is AsianAlone: 3-Mile RadiusPercent ofPopulationthat is AsianAlone: StatePercent ofPopulationthat isPacificAlone: 3-Mile RadiusPercent ofPopulationthat isPacificAlone: StatePercent ofPopulationthat isHispanic: 3-Mile RadiusPercent ofPopulationthat isHispanic:StatePercent ofPopulationthat isMinority (AllRaces): 3-Mile RadiusPercent ofPopulationthat isMinority (AllRaces):StateTenasca Taylorville EnergyCommercial CaptureIllinois0.2% 14.9% 0.0% 0.3% 0.5% 4.6% 0.0% 0.0% 0.1% 16.0% 2.6% 37.0%Texas Clean Energy ProjectCommercial CaptureTexas0.2% 12.0% 0.0% 0.7% 0.0% 3.6% 0.0% 0.1%47.3%37.3% 50.6% 55.1%Val Verde Gas Plant, GrayRanchExisiting Gas andFertilizer PlantTexas13.6%12.0% 0.1% 0.7% 0.2% 3.6% 0.0% 0.1%59.6%37.3%75.0%55.1%Val Verde Gas Plant, MitchellExisiting Gas andFertilizer PlantTexas13.6%12.0% 0.1% 0.7% 0.2% 3.6% 0.0% 0.1%59.6%37.3%75.0%55.1%Val Verde Gas Plant, PikesPeakExisiting Gas andFertilizer PlantTexas13.6%12.0% 0.1% 0.7% 0.2% 3.6% 0.0% 0.1%59.6%37.3%75.0%55.1%Val Verde Gas Plant, PuckettExisiting Gas andFertilizer PlantTexas13.6%12.0% 0.1% 0.7% 0.2% 3.6% 0.0% 0.1%59.6%37.3%75.0%55.1%Val Verde Gas Plant, TerrellExisiting Gas andFertilizer PlantTexas0.0% 12.0%4.1%0.7% 0.4% 3.6% 0.0% 0.1% 35.1% 37.3% 42.1% 55.1%WA Parish, SugarlandCommercial CaptureTexas15.2%12.0% 0.5% 0.7%4.9%3.6% 0.0% 0.1% 27.1% 37.3% 50.7% 55.1%Wallula Energy Res. CenterCommercial CaptureWashington1.0% 3.7% 1.1% 1.6% 0.8% 7.0% 0.2% 0.4%13.9%10.1% 17.1% 26.0%Williston Basin EORSequestration*Major DOESequestrationProjectNorth Dakota0.3% 1.2% 0.5% 5.6% 0.6% 0.7% 0.0% 0.0% 0.0% 2.2% 2.0% 10.8%Worsham-Steed (ZENG)Commercial CaptureTexas1.5% 12.0%1.0%0.7% 0.5% 3.6% 0.0% 0.1% 9.3% 37.3% 15.8% 55.1%Page 135 of 145

### Exhibit C.B-6. Percentage of Population th at is Below150% of Poverty Level Within 3-Mile Radius of Facility

Facility Name Facility Type Percent of Population below 150% of Poverty

Level: 3-Mile Radius Percent of Population below 150% of Poverty Level: State AEP Alstom Mountaineer (Ph.2) Commercial Capture Ohio 33.8% 23.9% West Virginia 27.5% 28.7% AEP Alstom Northeastern Commercial Capture Oklahoma 20.1% 27.9%

Antrim Gas Plant Exisiting Gas and Fertilizer Plant Michigan 27.2% 25.6%

Cincinnati Arch Mt. Simon Saline Major DOE Sequestration Project Indiana 23.3% 24.1% Kentucky 13.3% 29.1% Coffeyville Fertilizer Plant Commercial Capture Kansas 32.3% 21.8% Edwardsport Commercial Capture Indiana 25.5% 24.1%

Enid Gas Plant Exisiting Gas and Fertilizer Plant Oklahoma 21.1% 27.9% Futuregen FutureGen Illinois 22.2% 20.9% Great Bend Commercial Capture Ohio 35.0% 23.9% West Virginia 24.1% 28.7%

Great Plains Coal Gasification Exisiting Gas and Fertilizer Plant North Dakota 25.7% 20.0% Green River Basin Nugget Sand Saline Reservoir Major DOE Sequestration Project Wyoming 9.1% 16.8% Hydrogen Energy HECA Commercial Capture California 4.1% 21.2% Illinois Basin Mt. Simon Saline Reservoir Major DOE Sequestration Project Illinois 36.2% 20.9% Kemper County Commercial Capture Mississippi 61.4% 33.4%

La Barge Gas Plant Exisiting Gas and Fertilizer Plant Wyoming 12.3% 16.8%

### Page 137 of 145 Exhibit C.B-6. Percentage of Population th at is Below150% of Poverty Level Within 3-Mile Radius of Facility (Cont’d)

Facility Name Facility Type Percent of Population below 150% of Poverty

Level: 3-Mile Radius Percent of Population below 150% of Poverty Level: State Lima Commercial Capture Ohio 37.6% 23.9% Mesaba Commercial Capture Minnesota 13.0% 18.1%

Mt. Simon Saline Reservoir Major DOE Sequestration Project Illinois 22.2% 20.9% San Joaquin Basin, CA Saline Formation Major DOE Sequestration Project California 45.3% 21.2% Tenasca Sweetwater/Trailblazer Commercial Capture Texas 35.0% 27.7% Tenasca Taylorv ille Energy Commercial Capture Illinois 11.6% 20.9% Texas Clean Energy Project Commercial Capture Texas 18.8% 27.7%

Val Verde Gas Plant, Gray Ranch Exisiting Gas and Fertilizer Plant Texas 17.7% 27.7%

Val Verde Gas Plant, Mitchell Exisiting Gas and Fertilizer Plant Texas 17.7% 27.7%

Val Verde Gas Plant, Pikes Peak Exisiting Gas and Fertilizer Plant Texas 17.7% 27.7%

Val Verde Gas Plant, Puckett Exisiting Gas and Fertilizer Plant Texas 17.7% 27.7%

Val Verde Gas Plant, Terrell Exisiting Gas and Fertilizer Plant Texas 28.9% 27.7% WA Parish, Sugarland Commercial Capture Texas 13.3% 27.7% Wallula Energy Res. Center Commercial Capture Washington 26.2% 20.1%

Williston Basin EOR Sequestration* Major DOE Sequestration Project North Dakota 17.3% 20.0% Worsham-Steed (ZENG) Commercial Capture Texas 35.9% 27.7%

### Page 138 of 145 Exhibit C.B-7. Percentage of Population 0 to 4 Years and 65+ Years Within 3-Mile Radius of Facility

Facility Name Facility Type Percent of Population that is 0-4 Years: 3-Mile Radius Percent of Population that is

0-4 Years: State Percent of Population that is 65+ Years: 3-Mile Radius Percent of Population that is 65+ Years: State AEP Alstom Mountaineer (Ph.2) Commercial Capture Ohio 5.0% 5.6% 18.4% 14.4% West Virginia 5.0% 5.0% 17.7% 16.5% AEP Alstom Northeastern Commercial Capture Oklahoma 5.2% 6.2% 13.7% 13.5%

Antrim Gas Plant Exisiting Gas and Fertilizer Plant Michigan 5.0% 5.3% 13.1% 14.0%

Cincinnati Arch Mt. Simon Saline Major DOE Sequestration Project Indiana 4.7% 6.0% 16.7% 13.4% Kentucky 5.1% 5.7% 14.0% 13.7% Coffeyville Fertilizer Plant Commercial Capture Kansas 6.5% 6.2% 17.0% 13.4% Edwardsport Commercial Capture Indiana 5.7% 6.0% 15.9% 13.4%

Enid Gas Plant Exisiting Gas and Fertilizer Plant Oklahoma 5.6% 6.2% 18.0% 13.5% Futuregen FutureGen Illinois 3.8% 6.0% 16.9% 13.0% Great Bend Commercial Capture Ohio 4.9% 5.6% 14.9% 14.4% West Virginia 4.7% 5.0% 22.5% 16.5%

Great Plains Coal Gasification Exisiting Gas and Fertilizer Plant North Dakota 2.9% 5.7% 21.7% 14.9% Green River Basin Nugget Sand Saline Reservoir Major DOE Sequestration Project Wyoming 5.6% 6.1% 20.4% 13.4% Hydrogen Energy HECA Commercial Capture California 3.3% 6.3% 7.9% 11.9% Illinois Basin Mt. Simon Saline Reservoir Major DOE Sequestration Project Illinois 5.7% 6.0% 15.5% 13.0% Kemper County Commercial Capture Mississippi 5.4% 6.4% 19.2% 12.9%

La Barge Gas Plant Exisiting Gas and Fertilizer Plant Wyoming 6.6% 6.1% 13.3% 13.4%

### Page 139 of 145 Exhibit C.B-7. Percentage of Population 0 to 4 Years and 65+ Years Within 3-Mile Radius of Facility (Cont’d)

Facility Name Facility Type Percent of Population that is 0-4 Years: 3-Mile Radius Percent of Population that is

0-4 Years: State Percent of Population that is 65+ Years: 3-Mile Radius Percent of Population that is 65+ Years: State Lima Commercial Capture Ohio 6.3% 5.6% 14.1% 14.4% Mesaba Commercial Capture Minnesota 3.5% 5.9% 25.4% 13.5%

Mt. Simon Saline Reservoir Major DOE Sequestration Project Illinois 3.8% 6.0% 16.9% 13.0% San Joaquin Basin, CA Saline Formation Major DOE Sequestration Project California 8.3% 6.3% 10.7% 11.9% Tenasca Sweetwater/Trailblazer Commercial Capture Texas 7.0% 7.0% 13.7% 10.8% Tenasca Taylorville Energy Commercial Capture Illinois 4.8% 6.0% 15.6% 13.0% Texas Clean Energy Project Commercial Capture Texas 7.4% 7.0% 12.9% 10.8%

Val Verde Gas Plant, Gray Ranch Exisiting Gas and Fertilizer Plant Texas 4.6% 7.0% 9.2% 10.8%

Val Verde Gas Plant, Mitchell Exisiting Gas and Fertilizer Plant Texas 4.6% 7.0% 9.2% 10.8%

Val Verde Gas Plant, Pikes Peak Exisiting Gas and Fertilizer Plant Texas 4.6% 7.0% 9.2% 10.8%

Val Verde Gas Plant, Puckett Exisiting Gas and Fertilizer Plant Texas 4.6% 7.0% 9.2% 10.8%

Val Verde Gas Plant, Terrell Exisiting Gas and Fertilizer Plant Texas 3.3% 7.0% 19.8% 10.8% WA Parish, Sugarland Commercial Capture Texas 6.0% 7.0% 11.8% 10.8% Wallula Energy Res. Center Commercial Capture Washington 5.2% 5.6% 12.0% 13.2% Williston Basin EOR Sequestration* Major DOE Sequestration Project North Dakota 4.4% 5.7% 20.2% 14.9% Worsham-Steed (ZENG) Commercial Capture Texas 5.8% 7.0% 15.2% 10.8%

### Page 140 of 145 Exhibit C.B-8. Number of FRS Sites Wi thin 3-Mile Radius of Facility

Facility Name Facility Type Number of EPA FRS Sites within

Buffer: 3-Mile AEP Alstom Mountaineer (Ph.2) Commercial Capture Ohio 5 West Virginia 6 AEP Alstom Northeastern Commercial Capture Oklahoma 4 Antrim Gas Plant Exisiting Gas and Fertilizer Plant Michigan 0 Cincinnati Arch Mt. Simon Saline Major DOE Sequestration Project Indiana 5 Kentucky 4 Coffeyville Fertilizer Plant Commercial Capture Kansas 31 Edwardsport Commercial Capture Indiana 9 Enid Gas Plant Exisiting Gas and Fertilizer Plant Oklahoma 5 Futuregen FutureGen Illinois 13 Great Bend Commercial Capture Ohio 2 West Virginia 6 Great Plains Coal Gasification Exisiting Gas and Fertilizer Plant North Dakota 4 Green River Basin Nugget Sand Saline R eservoir Major DOE Sequestration Project Wyoming 1 Hydrogen Energy HECA Commercial Capture California 1 Illinois Basin Mt. Simon Saline Reservoir Major DOE Sequestration Project Illinois 37 Kemper County Commercial Capture Mississippi 3 La Barge Gas Plant Exisiting Gas and Fertilizer Plant Wyoming 2

### Exhibit C.B-8. Number of FRS Sites Within 3-Mile Radius of Facility (Cont’d)

Facility Name Facility Type Number of EPA FRS Sites within

Buffer: 3-Mile Lima Commercial Capture Ohio 88 Mesaba Commercial Capture Minnesota 3 Mt. Simon Saline Reservoir Major DOE Sequestration Project Illinois 13 San Joaquin Basin, CA Saline Formation Major DOE Sequestration Project California 3 Tenasca Sweetwater/Trailblazer Commercial Capture Texas 17 Tenasca Taylorville Energy Commercial Capture Illinois 3 Texas Clean Energy Project Commercial Capture Texas 1 Val Verde Gas Plant, Gray Ranch Exisiting Gas and Fertilizer Plant Texas 2 Val Verde Gas Plant, Mitchell Exisiting Gas and Fertilizer Plant Texas 2 Val Verde Gas Plant, Pikes Peak Exisiting Gas and Fertilizer Plant Texas 1 Val Verde Gas Plant, Puckett Exisiting Gas and Fertilizer Plant Texas 3 Val Verde Gas Plant, Terrell Exisiting Gas and Fertilizer Plant Texas 1 WA Parish, Sugarland Commercial Capture Texas 4 Wallula Energy Res. Center Commercial Capture Washington 5 Williston Basin EOR Sequestration* Major DOE Sequestration Project North Dakota 0 Worsham-Steed (ZENG) Commercial Capture Texas 4

### Page 142 of 145 Appendix D

Unfunded Mandates Reform Act Analysis

No analysis is required under the Unfunded Mandates Reform Act (UMRA) because the proposed rule does not include any mandate that is expected to result in expenditure by the private sector or aggregate expenditure by Stat e, local, and tribal governments in excess of $100 million in any one year. The proposed rule is expected to result in net savings to the private sector and insignifican t costs to state governments.

### Page 143 of 145 Appendix E

Other Required Analyses

F-1 Executive Order 12866: Regulatory Planning and Review

EPA has determined that the proposed rule is a "significant regulatory action" as defined by Executive Order 12866 because it raises novel legal or policy issues arising out of legal mandates, the President's priorities, or the principles set forth in the Executive Order. 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.



### The expected annual costs and benefits of the proposed rule do not exceed $100 million. The rule does not create inconsistencies or interf ere with an action taken or planned by another agency; does not materially a lter the budgetary impact or th e rights and obligations of recipients of entitlements, grants , user fees, or loan programs.

F-2 Executive Order 13132: Federalism

The proposed rule does not have Federalism imp lications. EPA does not anticipate that the proposed rule will have substantial direct imp acts on the states, the relationship between the government and the states, or on the distribut ion of power and res ponsibilities among the various levels of government.

F-3 Executive Order 13175: Consultation and Coordination with Indian Tribal Governments

The proposed rule is not expect ed to have substantial trib al implications. No Tribal governments are known to own or operate current or planned CO 2 

### capture or sequestration facilities.

F-4 Executive Order 13045: Protection of Children from Environmental Health and Safety Risks

EPA does not find that the rule will have envi ronmental health or safety impacts that disproportionately affect childre n. Therefore, no additional an alysis is required under this Executive Order.

F-5 Executive Order 13211: Actions that Significantly Affect Energy Supply, Distribution, or Usage

### Page 144 of 145 Although the affected universe of the proposed ru le includes energy suppliers such as coal power plants, the rule is not e xpected to result in behavioral changes that would affect energy supply, distribution or usage.

F-6 National Technology Transfer Advancement Act

This proposed rulemaking does not involve technical standard s. Therefore, the use of voluntary consensus standa rds is not applicable.

F-7 Executive Order 12898: Federal Action s to Address Enviro nmental Justice in Minority Populations and Low-Income Populations

The proposed rule is not expect ed to have disproportionately high and adverse human health or environmental effects on minor ity or low-income populations. EPA finds that the actions allowed by the proposed exclusions are safe and do not present significan t adverse health or environmental impacts (See Appendix C).

F-8 Executive Order 12630: Re gulatory Takings Analysis

The proposed rule does not constitu te a regulatory taking because it is not expected to result in the physical invasion of property and should not negatively impact the economic viability of property.

F-9 Executive Order 12988: Civil Justice Reform

The proposed rule specifies in clear language the effect of the regul ation; specifies its relationship to the provisions of other laws; incorporates clear legal standards; has no retroactive effect; and defines key terms. Therefore, no addi tional analysis or actions are required under EO 12988.

F-10 Executive Order 13352: Facilitat ion of Cooperative Conservation

The proposed rule is designed to promote coope rative conservation between EPA, state, and local governments by identifying clear criteria for excluding carbon di oxide injectate from the regulatory requirements for hazardous wast e, when managed in Class VI UIC wells for purposes of geologic sequestration.

F-11 Joint Impacts of Rules

The proposed rule will exempt CO 2 

### streams captured for the purpose of geological sequestration in a Class VI UIC well from the definition of hazardous waste. Such waste will not be subject to EPA’s hazardous waste regulations. These CO 2 

### streams would still qualify as solid wastes per the definition in 40 CFR 261.2 (Definition of solid waste). The management of these CO 2 

### streams would be subject to th e Underground Injection Control Program (UICP) requirements in 40 CFR Pa rts 144 (Requirements for wells injecting

### Page 145 of 145 hazardous waste) and the proposed technical crite ria and standards for Class VI UIC wells in 40 CFR Part 146 (Underground Injection Cont rol Program: Criteria and Standards). 96 

### CO 2 

### capture and sequestration facilities claiming th e proposed exclusion would remain subject to the mandatory reporting requirements for green house gas emissions in 40 CFR Part 98 (Mandatory Greenhouse Gas Reporting). The transportation of captured CO 2 

### streams by pipeline would remain subject to the Depart ment of Transportation (DOT) Pipeline and Hazardous Materials Safety Administra tion (PHMSA) under 49 CFR Parts 195-199. The transportation of captured CO 2 

### by air, water, or highway would remain subject to the PHMSA requirements in 49 CFR Parts 171-180.

96 Non-hazardous solid wastes that ar e subject the UICP requirement are not subject to the requirements for non-hazardous solid waste in 40 CFR Parts 257 and 258.