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Note to the Reader:

This redline/strikeout version of the Assessmen t document identifies all changes made to the

document during review by the Office of Management and Budget (OMB). Changes made

specifically in response to OMB review and comme nt are highlighted and flagged by a comment

box, as follows: “Identified changes made in response to OMB review.” Minor changes were

made to this document in add ition to those made specifically in response to OMB review and

comment. These changes are largely editorial and were the result of further review by EPA staff

and management. Any changes not identified by the OMB comment box were initiated in

response to internal EPA review during or immediately after OMB review.

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EO12866_ CO2 RCRA Exclusion 2050

- AG60 N PRM EA _20110303



### ASSESSMENT OF THE POTENTIAL COSTS, BENEFITS, AND OTHER IMPACTS OF THE
CONDITIONAL EXCLUSION FROM THE RCRA 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

March 1

June 2 , 2011

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### ACKNOWLEDGMENTS

The Agency recognizes ICF International for the overall 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. Environmental Protection Agency, Office of Resource Conservation and Recovery (ORCR )

, ) provided guidance and review.

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### TABLE OF CONTENTS

ES. EXECUTIVE SUMMA RY 5

1. INTRODUCTION 12

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 Considered (Regulatory and Non

- Regulatory) 16

2. CHARACTERIZATION OF THE REGULATED COMMUN ITY 16

2.1 CO 2 

### Capture Facilities 17

2.1.1 Current CO 2 

### Capture Facilities 17
2.1.2 Plan ned 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 

### T ransporters 24

2.3 CO 2 

### Sequestration Facilities 26

3. ANALYSIS OF THE INCR EMENTAL COSTS AND BE NEFITS OF THE

PROPOSED RULE 29

3.1 Analytical Approach/Methodology 29

3.2 Baseline Practices 29

3.2.1 H azardous Waste Determination Process for CO 2 

### Capture Facilities 30
3.2.2 Baseline Practices for CO 2 

### Capture Facilities 31

3.2.2.1 Factors that Influence The Baseline Practices of CO 2 

### Carbon Capture

Facilities 32

3.2.2.2 Expected Baseline Practices of CO 2 

### Carbon Capture Facilities 33

3.2.3 Baseline Practices for CO 2 

### Sequestration Facilities 36

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### 3.3 Post Rule Practices 37

3.3.1 Post Rule Practices for CO 2 

### Capture Facilities 37
3.3.2 Post Rule Practices for CO 2 

### Sequestration Facilities 38

3.4 Incremental Costs of the Proposed Rule 38

3.4.1 Compliance Costs 38
3.4.2 Social Costs 42
3 .4.3 Costs to Government Entities 43

3.5 Incremental Cost Savings and Benefits of the Proposed Rule 47

3.5.1 Waste Determination S avings for CO 2 

### Capture Facilities 47
3.5.2 RCRA Training, Planning, and Reporting Requirement Savings for CO 2 

### Capture
Facilities 48
3.5.3 CO 2 

### Treatment Savings for CO 2 

### Capture Facilities 48
3.5.4 Summary of Savings to CO 2 

### Capture Facilities 49
3.5.5 Waste Determination Savings for CO 2 

### Sequ estration Facilities 51
3.5.6 RCRA Training, Planning, and Reporting Requirement Savings for CO 2 

### Sequestration Facilities 52
3.5.7 Summary of Savings to CO 2 

### Sequestration Facilities 53
3.5.8 Unquantified Benefits of the Proposed Rule 55

3.6 Conclusions 55

4. REGULATORY FLEXIBILI TY ANALYSIS 56

5. REFERENCES 57

APPENDIX A: COS T FOR DETERMINING RC RA TOXICITY OF CO 2 

### STREAM 59

APPENDIX B: TREATMEN T COSTS 71

APPENDIX C. SENSITIVITY ANALYSES 77

SENSITIVITY ANALYSIS 1

– FEWER AFFECTED FACIL ITIES 77

APPENDIX D. ASSESSMENT OF ENVIRO NMENTAL JUSTICE IMPA CTS 82

APPENDIX E. UNFUNDED MANDATES RE FORM ACT ANALYSIS 131

APPENDIX F. OTHER REQUIRED ANALY SES 131

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### ES. EXECUTIVE SUMMARY 7

1. INTRODUCTION 17

1.1 Need for Regulation 18

1.2 Summary of Current Rules 19

1.3 Summary of Proposed Changes 20

1.4 Analysis of Alternatives Considered (Regulatory and Non-Regulatory) 21

2. CHARACTERIZATION OF THE REGULATED COMMUNITY 21 7

2.1 CO 2 

### Capture Facilities 21

2.1.1 Current CO 2 

### Capture Facilities 22 8
2.1.2 Planned CO 2 

### Capture Facilities 24 2.1.3 Summary of Current and Planned CO 2 

### Capture Facilities Considered in this Analysis 28

2.2 CO 2 

### Transporters 30

2.3 CO 2 

### Sequestration Facilities 32

3. ANALYSIS OF THE INCREMENTAL COSTS AND BENEFITS OF THE

PROPOSED RULE 35 1

3.1 Analytical Approach/Methodology 36

3.2 Baseline Practices 37

3.2.1 Hazardous Waste Determination Process for CO 2 

### Capture Facilities 37
3.2.2 Baseline Practices for CO 2 

### Capture Facilities 38

3.2.2.1 Factors that Influence The Baseline Practices of CO 2 

### Carbon Capture

Facilities 39 3.2.2.2 Expected Baseline Practices of CO 2 

### Carbon Capture Facilities 41 6

3.2.3 Baseline Practices for CO 2 

### Sequestration Facilities 45

3.3 Post Rule Practices 48

3.3.1 Post Rule Practices for CO 2 

### Capture Facilities 48
3.3.2 Post Rule Practices for CO 2 

### Sequestration Facilities 48

3.4 Incremental Costs of the Proposed Rule 49 3.4.1 Compliance Costs 49

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### 3.4.2 Social Costs 56
3.4.3 Costs to Government Entities 57

3.5 Incremental Cost Savings and Benefits of the Proposed Rule 65 3.5.1 Waste Determination Savings for CO 2 

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

### Capture
Facilities 66
3.5.3 CO 2 

### Treatment Savings for CO 2 

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

### Capture Facilities 68 3.5.5 Waste Determination Savings for CO 2 

### Sequestration Facilities 72 3.5.6 RCRA Training, Planning, and Reporting Requirement Savings for CO 2 

### Sequestration Facilities 72 3.5.7 Summary of Savings to CO 2 

### Sequestration Facilities 73 3.6 Summary of Costs and Savings 71 3.7 Unquantified Benefits of the Proposed Rule 80 4

4. REGULATORY FLEXIBILITY ANALYSIS 81 4

5. REFERENCES 83

APPENDIX A: COST FOR DETERMINING RCRA TOXICITY OF CO 2 

### STREAM 78

APPENDIX B: TREATMENT COSTS 100 2

APPENDIX C. ASSESSMENT OF ENVIRONMENTAL JUSTICE IMPACTS 113

APPENDIX D. UNFUNDED MANDATES REFORM ACT ANALYSIS 164 3

APPENDIX E. OTHER REQUIRED ANALYSES 165 4

ES. Executive Summary

The U.S. Environmental Protection Agency (EPA or the Agency) regulates the generation, transfer, treatment, and disposal of hazar dous waste under the Resource 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 health and the environment. Formatted: Font: Not Bold

Formatted: None

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### 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 characteristics such as ignitability, corrosivity, reactivity, or toxicity . At present, EPA has little information to
conclude that CO 2 

### streams would , or would not qualify as RCRA hazardous wastes ; however

. However , EPA is proposing to revise the regulations 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 believes 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 community that will be directly affected by the proposed rule, estimates the expected incremental costs and benefits of the proposed rule, and certifies that the rule will not have a significant economic impact on a substantial number
of small entities.

ES.1 Characterization of the Regulated Community

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

### capture facilities, transporters, and sequestration 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 atmosp here. Currently EPA estimates that , at a maximum, there could be up to 27 CO 2 

### capture facilities to be 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 electric power generators, oil and gas extraction facilities, na tural gas distribution facilities, ethyl alcohol manufacturers, and nitrogenous fertilizer manufact urers, and appear to represent a mix of large corporations and mid-sized companies.

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 th e 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 Underg round Injection Control program contains extensive technical requirements for ensuring that underground sources of drinking water are protected during geologic sequestration (GS) of CO 2. Comment [LL1]: . Identified changes made in response to OMB review.

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### Our low-end estimate considers only 13 CO 2 

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

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

### capture facilities considered in this analysis

, by North American Industry Classification System (NAICS) code.

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

### Capture Facilities Considered in this Analysis by Industry Sector 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 9 7 7
221112 Fossil Fuel Electric Power Generation 1 5 16 2
221210 Natural Gas Distribution 1 1
325193 Ethyl Alcohol Manufacturing 1 1
325311 Nitrogenous Fertilizer Manufacturing 1 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 products) 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 waste transporters if the CO 2 

### in question was found to be hazardous. Therefore, this analysis assumes that all transportation of CO 2 

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



### .

3 56 Federal Register 26922, June 12, 1991. http://www.greenfacts.org/en/co2-capture- storage/l-3/4-transport-carbon-dioxide.htm Parfomk, Paul W., Folger, Peter, and Adam Vann. C ongressional Research Service, July 31, 2009. Carbon Dioxide (CO 2 ) Pipelines for Carbon Sequestration: Emerging Policy Issues.

4 Department of Transportation, Pipeline and Hazar dous 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 analys is only considers NAICS 48 6990 because it is the industry category most relevant to the activity affected by the proposed rule. Comment [LL2]: Identified changes made in response to OMB review.

Merged Cells

Formatted: Font: Bold

Formatted Table

Merged Cells

Formatted Table Inserted Cells

Comment [LL3]: . Identified changes made in response to OMB review.

Comment [LL4]: Identified changes made in response to OMB review.

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### 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 to could be affected by the proposed rule. This estimate includes 15 planned
commercial CO 2 

### sequestration projects and 14 planned projects funded by DOE. The 15 planned commercial projects are expected to incl ude 12 enhanced oil recovery projects that transition to sequestration in the long term and 3 saline reservoir sequestration projects. 6



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

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

.

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

This analysis estimates the incremental costs and benefits of the proposed rule (i.e., the costs and benefits that arise as a consequence 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 affected entities would be likely to change their behavior under the proposed rule. 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 exclusion 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- hazardous waste. As already stated, CO 2 

### streams are not listed hazardous waste, so would 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 th eir waste, or apply their knowledge – in lieu of testing – of the hazard characteristic of a wast e, in light of the materials or processes used,
to determine whether that waste is a characteristic hazardous waste under RCRA. Public comments submitted to the Agency related to the UIC Class VI injection well rulemaking expressed concern over applying RCRA characteristics to CO 2 

### streams 7 

### , and EPA acknowledges these commenters’ concerns. However, this analysis assumes that, depending

6 Department of Energy, National Energy Technolo gy 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 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. Comment [LL5]: Identified changes made in response to OMB review.

Formatted: Level 1

Comment [LL6]: Identified changes made in response to OMB review.

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Comment [LL7]: Identified changes made in response to OMB review.

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### 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 knowledge and limited testing to determine
whether their CO 2 

### stream is a RCRA hazardous waste.

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

### stream is not RCRA hazardous, the generator (capture) 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 sequestration, (ii) treat the CO 2 

### stream to render it non-hazardous, and send it to a Class VI well for 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
Destine 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 o f for

the geologic sequestration of CO 2
. While f acilities Facilities may capture CO 2 streams for use in Class II wells for Enhanced Oil Recovery (EOR ) , that ). However, EOR assessment is beyond the scope of the this proposed rule.



### Exhibit ES-3 below presents the 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 Comment [LL8]: Identified changes made in response to OMB review.

Formatted Table

Comment [LL9]: Identified changes made in response to OMB review.

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### 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 where were formed as conservative assumptions a range for analytical purposes only 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
classified as hazardous may could be low.

Exhibit ES-3: Conservative Assum ption High-End and Low-End Assumptions 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. The sensitivity analysis in Appendix
C considers the alternative assumption that 90 percent of the CO 2 capture facilities would generate non

hazardous CO 2 streams in the baseline. Comment [LL10]: Identified changes made in response to OMB review.

Comment [LL11]: Identified changes made in response to OMB review.

Formatted Table

Formatted: Not Superscript/ Subscript

Formatted Table Inserted Cells

Formatted: Superscript

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### This analysis assumes that all CO 2 

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

### transportation are possible (e.g., truck, rail), but pipeline transport 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 Clas s I hazardous wells that EPA has assumed also will meet the Class VI requirements. This analysis assumes that, in under the high-end baseline assumption , approximately 57 percent of the sequestration wells would manage nonhazardous 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. As mentioned above, the assumption that 90% CO 2 

### streams would be RCRA hazardous represents a very conservative approach for assessing potential costs in the absence of hazardous waste
characterization dat a

. At this time, EPA has little in formation to conclude that CO 2 

### streams would qualify as RCRA hazardous wastes

. If the Agency receives data in response to the proposed rulemaking (for which this analysis was prepared), this analysis would be revised accordingly.

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 Agen cy receives more definitive data in response to the proposed rulemaking, this analysis will be revised accordingly.

Post-Rule Behavior

This analysis assumes that all CO 2 

### capture facilities will claim 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 ex clusion would exceed the implementation costs. As a result,
all CO 2 

### sequestration facilities are expected to manage CO 2 

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

### would continue to be done by pipeline.

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 e xplained in Section 3.2.3 of this document

10 For the low-end estimate, this analysis 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 assumes 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. Comment [LL12]: Identified changes made in response to OMB review.

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### Costs of the Proposed Rule

In order to claim the exclusion, generators and well owner/operators would have to satisfy the conditions found in the proposed rule. This includes that both CO 2 

### capture facilities and Class VI UIC wells each would be required to sign a certification statement which they must
maintain onsite and make available to EPA or the State

, on within 72 hours of a written
request. 11 

### The facilities would be required to re new 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 re quest. Capture and sequestration facilities each would incur labor costs of $363 to prepare the initial certification 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 costs for each certification statement it
requests that is requested and reviewed. Similarly, the States would incur $61 in labor costs for each certification statement they request and review.

The Agency believes finds 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
does not , therefore, anticipate any negative externa lities as a result of this action. As a result, no social costs are expected to result from the proposed exclusion

.

Savings and Benefits

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

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



### , , 13 

### and exclusion from hazardous waste treatment requirements. The analysis estim ates 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 RC RA hazardous in the baseline would save

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.

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

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### approximately $5,000 annually under the proposed rule 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 pos t-rule and would each save approximately $10.3
million in annual treatment costs.

CO 2 

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

In addition to the quantified savings discussed above, the proposed rule also represents a step toward establishing a supporting 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.

50

- Year and Annualized Net Costs and Savings

This study calculates the net costs and savings of the proposed rule over a 50 year period.
Exhibit ES

- 4 summarize s Due to the undiscounted high level of uncertainty regarding the percent of CO 2 

### that may be RCRA hazardous, and the uncertainty regarding the actual number of facilities potentially affected over the projected 50

- year and annualized costs and
benefits period, EPA’s best estimate for the impacts of the proposed rule . Exhibits ES

- 5 and
ES

- 6 summarize the 50

- year and annualized costs and benefits of the proposed rule applying 3 percent and 7 percent discount rates respectively. The proposed rule is expected to result in
undiscounted ranges from a low-end annualized net savings of approximately $5 6

. 6 $7.3
million . Applying a 3 percent (7% discount rate

, ) to the high-end annualized net savings are approximately of $44.9 million . Applying a 7 percent (3% discount rate , the annualized net savings are approximately $3 2

. 0 million. ). 14



### Under Executive Order 12866, a rule qualifies as economically significant if its annual effect on the economy is $100 million or more. This proposed rule is not expected to be economically significant, as defined under Executive Order 12866.

Exhibit ES

- 4 : Undiscounted Net Costs and Savings of the Proposed Rule (2010 $ )

Type of Entity 50

- year Costs 50

- year Savings 50

- year Net Savings Average Net Savings Capture Facilities $164,5 44 $2,829,383,941 $2,829,219,397 $56,584,388

14 Under the high-end estimate, the proposed rule is expect ed to result in undiscounted annualized net savings of approximately $56.6 million. Applying a 3 percent discou nt 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 undiscou nted annualized net savings are $9.3 million. Applying 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. Comment [LL13]: Identified changes made in response to OMB review.

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Type of Entity 50

- year Costs 50

- year Savings 50

- year Net Savings Average Net Savings 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 ES

- 5 : Net Costs and Savings of the Proposed Rule

– 3% Discount Rate (2010 $ )

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 ES

- 6 : 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 Facilitie s $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



### 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 geological sequestration (GS) in
Class VI wells from the definition of hazar dous 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 proposed rule will could lead to net cost savings in the range of $ 3 2.0 7.3 to $ 56.6 44.9 million annually. 15

15 The estimated savings are $ 56.6 million undiscounted, $32.0 million applying a 7 percent discount rate, and $44.9 million applying a 3 percent discount rate. Formatted: Font: Bold

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### 1. Introduction

The U.S. Environmental Protection Agency regulates the generation, transfer, treatment, and disposal of hazardous waste under the Res ource Conservation and Recovery Act (RCRA) Subtitle C. The hazardous waste regulations ar e 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 hazard ous wastes, but may be classified as a RCRA hazardous waste if they exhibit hazar dous characteristics such as ignitability, corrosivity, reactivity, or toxicity. The Agency believes finds that the management of these
CO 2 

### streams under the proposed conditions, which includes the injection into a Class VI UIC well, does not present a substan tial risk to human h ealth or the environment. As such, additional regulation pursuant to RCRA’s hazardous waste regulations is unnecessary. 16 

### This report evaluates the potential impacts of the proposed exclusion.

This introductory chapter explains the need for regulation, summarizes the current and proposed rules, and discusses the regulatory and non-regulatory alternatives that EPA considered. The second chapter characterizes the regulated community that will be directly

16 EPA has proposed 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 Sequest ration (GS) Wells) in a separate rulemaking , (75 FR 77230) December 10, 2010 (see Docket ID EPA–HQ– OW–2008–0390). This a nalysis assumes that Class VI UIC requirements will be finalized as proposed.

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### affected by the proposed rule. The third chapter estimates the expected incremental costs and benefits of the proposed rule. The fourth chapter evaluates the expected impact of the proposed rule on small businesses. The fifth chapter contains references to the data sources used to conduct the economic assessment described 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 believes has determined that the full set of hazardous waste regulations is unnecessary for captured CO 2 

### streams because existing regulations governing the transport and injection into a UIC Class VI permitted injection well are su fficient 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 Federal Requirements Under the Underground Injection Control (UIC) Prog ram 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 drinking 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: 17



### • 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 from geologic formations into ground water (e.g., arsenic, lead, and organic compounds), and

,

• Pressures induced by injection may force native 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 technical criteria for Class VI GS wells to protect USDWs from the unique risks associated with CO 2 

### injection, including: 18



### • 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.

17 Jens Birkholzer, John Apps, Liange Zheng, Yingqi Zhang, Tianfu Xu, and Chin-Fsu Tsang, “Research Project on CO 2 Geological Storage and Groundwater Resour ces: Water Quality Effects Caused by CO 2 Intrusion into Shallow Groundwater,” Lawrence Berkeley National Laboratory, #LBNL-1251E, 2008. http://repositories.cdlib.org/lbnl/LBNL-1251E , as cited by EPA in the 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.

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

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### • Computational modeling of the area of review (AoR) for GS projects that accounts for the physical and chemical properties of the injected CO 2 

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

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

### is moving as predicted within the subsurface.

• Well construction using materials that 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 geochemistry, and monitoring of the CO 2 

### plume and position of the pressure front 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 care (PISC), site closure, and emergency and remedial response.

1.2 Summary of Current Rules

Captured CO 2 

### streams de stine destined for geological sequestration may qualify as solid wastes, as defined in 40 CFR 261.2 (Definition of solid waste). RCRA hazardous waste is a subset of solid waste to which EPA applies sp ecial requirements. A waste is considered RCRA hazardous waste if it is specifically listed as hazardous in 40 CFR 261 Subpart D (Lists of Hazardous Wastes), or if it exhibits hazardous characteristics such as ignitability, corrosivity, reactivity, or toxicity as described in 40 CFR 261 Subpart C (Characteristics of Hazardous Waste). CO 2 

### is not a 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 ha zardous. 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 waste, generators would be required to determine if their CO 2 

### stream is a RCRA hazardous waste either by testing its characteristics using methods specified in the RCRA regulations, 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 through geologic sequestration , and therefore is a
solid waste ), the generator is subject to the various hazardous waste generator standards in 40 CFR 262 (Standards Applicable to Generators of Hazardous 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 pe rmitted to accept RCRA hazardous waste. A
RCRA hazardous waste CO 2 

### stream could not be injected into a well that is permitted as a Comment [LL14]: Identified changes made in response to OMB review.

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### Class VI well under the UIC Class VI regulations. The owners 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 Stat us Standards for Owne rs and Operators of Hazardous Waste Treatment, Storage, and Disposal Facilities) if they store or treat hazardous waste prior to injection; the UIC Class I hazar dous well itself, 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 owners and operators would have to build their sequestration units to meet EPA’s requirements for a Class VI UIC well. 19



### If the CO 2 

### stream is not a RCRA hazardous waste, the 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 requi red to meet the Class VI UIC requirements, which in some regards are similar to the re quirements for hazardous waste wells permitted under UIC Class I, but are geared specifically toward CO 2 

### sequestration. 20

, 21



### CO 2 

### streams captured for the purpose of injection are typically transported by pipeline and are subject to the Department of Transportation (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 are not classified as modes of transportation under RCRA and therefor e pipeline transportation 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 standard s for transporters of hazardous waste in 40 CFR 263 (Standards Applicable to Transporters of Hazardous Waste), as well as the applicable PHMSA Hazardous Materials Regulations 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 streams that are captured and transported for purposes of injection into an underground inject ion well subject to the requirements for Class VI Underground Injection Control wells, including the requirements 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. 22 

### Class VI wells injecting excluded

19 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 requi rements; however, there is no specific UIC regulation that would require permit writers to apply both the Class I hazardous and Class VI standards to a RCRA
hazardous waste CO 2 injection well.

20 Note that certain Certain U.S. Department of Energy CO 2 injection demonstration projects have been permitted under the UIC Class V experimental technolog y well program, while other demonstration projects have been permitted under the UIC Cl ass I non-hazardous waste well program.

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

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### 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 sequestration wells claiming the exclusion would be required to sign and annua lly renew a certification statement stating that
the CO 2 

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

1.4 Analysis of Alternatives Considered (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 RCRA hazardous waste requirements. EPA did not select this option because it would provide similar generally equivalent protection for to human health and the environment as the proposed rule, but would
maintain proposal, while maintaining an unnecessary regulatory burden on CO 2 

### capture and sequestration facilities to comp ly with the hazardous waste requirements

.

•

• 

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

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

### capture and sequestration facilities to comply with the hazardous waste requirements under the current regulatory framework.

2. Characterization of the Regulated Community

The entities that may be directly affected 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.

EPA estimates that The total number of CO 2 

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

### capture Comment [LL15]: Identified changes made in response to OMB review.

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### facilities will that may be affected by the proposed rule. Our low-end estimate considers only 13 capture facilities. These es timates 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 fac ilities that currently capture CO 2 

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

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

### capture facilities are presented below in Sections 2.1.1 and 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.

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 well for enhanced oil recovery (EOR). These ten facilities generated and captured approx imately 11 million metric tons of CO 2 

### in 2008. 23 

### Exhibit 1 lists these existing carbon capture f acilities and their industry 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. 24 

### 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 Fertil izer Plant will begin sequestration in 2034. 25



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

### Streams a

23 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

. 24 We recognize that if there is no climate legislation within 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.

25 See footnote b in Exhibit 1. Comment [LL16]: Identified changes made in response to OMB review.

Comment [LL17]: Identified changes made in response to OMB review.

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### 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
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 In 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),” EPA identified th e Coffeyville Fertilizer Plant as a commercial project that would transition 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 transition to GS 20 years from the present date (i.e., 2030).



### The existing CO 2 

### capture facilities and their parent comp anies vary in size. For example, the Enid Ammonia Fertilizer Plant is operated by Koch Industries, Inc., which has over 70,000 employees. 26 

### The Coffeyville Fertilizer Plant (Coffeyville Resources LLC) employs 250 to

26 Koch Industries, 2009, http://www.kochi nd.com/files/070709KIILeadershipKansas.pdf. Formatted: Font: 11 pt, Bold, Italic

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### 499 individuals. 27 

### The Great Plains Coal Gasification (Dakota Gasification CO) facility has between 500 and 999 employees. 28



### 2.1.2 Planned CO 2 

### Capture Facilities

EPA has identified an additional 31 planned CO 2 

### capture facilities. These facilities are listed
in Exhibit 2. Commercial CO 2 

### capture projects represent 28 of these planned capture projects. 29 

### Although all of these projects are planned, some of them may be cancelled or delayed due to approval and funding issues. This high estimate analysis considers only fourteen planned commercial projects that EPA has deemed most likely to proceed , although

. However, the other planned projects are included in Exhibit 2 for reference only

. 30 

### In addition to these planned commercial project s, there are two other 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 included 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 involving an ethyl alcohol manufacturing plant (NAICS 325193).

27 Manta, “Coffeyville Resources LLC,” http://www.manta.com/c/mmgvkjp/coffeyville-resources-llc

28 Manta, “Dakota Gasification Co,” http://www .manta.com/c/mmlgj74/dakota-gasification-co

29 Note to reviewer: 29 These “commercial” CO 2 capture projects include some projects that were partially funded as DOE pilot projects.

30 As a part of the research that EPA Office of Water c onducted to determine the baseline for the “Cost Analysis for the Federal Requirements Under the Underground In jection Control Program for Carbon Dioxide Geologic Sequestration Wells (Final GS Rule),” EPA reviewed all of the proposed projects and identified 15 commercial projects that were likely to proceed. One of those 15 pr ojects, Coffeyville Fertilizer 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. Comment [LL18]: Identified changes made in response to OMB review.

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### 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

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 Formatted: Font: Bold, Italic

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### Project State Company Assumed First Year of Sequestration

b 

### NAICS Industry Sector

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 Not Included in this Analysis f



### ADM Ethanol Plant CO 2 

### Capture IL ADM 

### N/A 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

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 Formatted: Font: Bold, Italic

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### Project State Company Assumed First Year of Sequestration

b 

### NAICS Industry Sector

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 Worldwide. Power Plant Carbon Dioxide Capture and Storage Projects, http://sequestration.mit.edu/tools/projects/index.html.

b The assumed first year of sequestration for each facility is based on the research that the EPA Office of Water
conducted to determine the baseline for the “Cos t 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 not 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 completion of this analys is indicates that this project has been cancelled and moved to Michigan.

e Information received after the completion of this anal ysis indicates that this project has been cancelled.

f Information received after the completion of this analys is indicates that many of these projects have been cancelled or did not receive funding from DOE for the next phase of their projects. Formatted: Font: Bold, Italic

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### 2.1.3 Summary of Current and Planned CO 2 

### Capture Facilities Considered in this Analysis

Exhibit 3 summarizes the number of current and proposed CO 2 

### capture facilities considered
in the high-end estimate analysis

, 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 2 a 

### FutureGen Private/Federal Partnership 1
Total 27

a Information received after the completion of this analys is indicates that these projects have been cancelled.



### Exhibit 4 summarizes the number of current and proposed CO 2 

### capture facilities considered
in this high-end estimate analysis

, 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 Sector Number of Facilities

211111 Oil and Gas Extraction 9 7
221112 Fossil Fuel Electric Power Generation 1 5 16
221210 Natural Gas Distribution 1
325193 Ethyl Alcohol Manufacturing 1
325311 Nitrogenous Fertilizer Manufacturing 1 2

Exhibit 5 presents the high-end estimate 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 

### Total 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 Comment [LL22]: Identified changes made in response to OMB review.

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Year Number of CO 2 Facilities Beginning Sequestration of their CO 2 Streams 

### Total 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 associ ated with named 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 existi ng capture projects are affected, and;

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

All other assumptions are consistent with the hi gh-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-End Estimate of the CO 2 

### Capture Facilities Assumed to Begin and Practice Sequestration 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 Formatted: Font: 10 pt, Bold, Italic

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Year Annual Number of CO 2 Capture Facilities Total Number of CO 2 Capture Facilities
2016 0 2

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. 31 

### 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, which 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 analysis may exceed the number reported to be operating in 2008. 32 

### This analysis only considers the 29 operators of pipelines reported to be operating in 2008. Exhibit 6 7 lists these active CO 2 

### pipeline operators. The exhibit also presents the miles of pipeline operated and barrel-miles 33 

### of CO 2 

### transported in 2008 by each
operator.

31 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

. 32 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 activit ies 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)

33 A standard barrel contains 42 gallons. Comment [LL23]: Identified changes made in response to OMB review.

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### 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 products) industry (NAICS 486990). 34 

### These CO 2 

### pipelines appear to be generally operated by large companies. For example, ExxonMobil Production Corp brings in between $50 and $100 million in annual revenue, and is a subsidiary of the much larger ExxonMobil Corporation. 35 

### 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 waste transporters. Some U.S. DOE demonstration projects have received shipments of CO 2 

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

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

### is, and will continue to be conducted by pipeline.

Exhibit 6 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

34 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 analys is only considers NAICS 48 6990 because it is the industry category most relevant to the activity affected by the proposed rule.

35 Manta, “Exxon Mobil Corp,” http://www.manta.com/c/mmcckrf/exxon-mobil-corp Formatted: Font: 11 pt, Italic

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### 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 Hazar dous Materials Safety Administration (PHMSA), 2008 Hazardous Liquids Annual Dat a http://www.phmsa.dot.gov/staticfile s/PHMSA/DownloadableFiles/Files/ LIQANN08.zip

. . .



### 2.3 CO 2 

### Sequestration Facilities

CO 2 

### sequestration facility owners and 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 de veloped two alternative
estimates for the number of affected facilit ies. 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 sequestration facilities. These estimates are discussed below.

Number of CO 2 

### Sequestration Facilities – High-End Estimate:

EPA estimates that , at a maximum, 29 planned sequestration facilities will may be affected by the proposed rule. These recommendations are This estimate is consistent with EPA’s current assumptions for the UIC Class VI program project baseline and cost analysis in developing the Class VI rule. 36 

### 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 current 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 planne d commercial projects that are expected to

36 Based on the research that EPA Office of Water cond ucted to determine the baseline for the “Cost Analysis for the Federal Requirements Under the Underground In jection Control Program for Carbon Dioxide Geologic Sequestration Wells (Final GS Rule),” Formatted: Font: 11 pt, Italic

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### 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 sequestration projects. 37



### 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 facil ities are not currently operational, the
characteristics of these facilities are uncertain.

Exhibit 7 8 summarizes the high-end estimate for the number of sequestration facilities

, by type. These counts are based on the research that EPA Office of Water conducted to determine the baseline for the “Cost Analys is for the Federal Requirements Under the Underground Injection Control 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 location projects that EPA expects to be constructed in the future. EPA expects that 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 analys is will each have its own sequestration
site and that most of these sites will conduct Enhanced Oil Recovery (EOR).

Exhibit 7 8 : Summary of the High-End Estimate for the Number of Sequestration Facilities Considered in this Analysis a 

### 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 Fede ral Requirements Under the Underground Injection Control Program for Carbon Dioxide Geologic Sequestration Wells (Final GS Rule).”

37 DOE sequestration project database website http://www.netl.doe.gov/technologies/carbon_seq/database/index.html Comment [LL25]: Identified changes made in response to OMB review.

Comment [LL26]: Identified changes made in response to OMB review.

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### Exhibit 8 9 lists the DOE Phase III sequestration demonstration projects and highlights the six projects included in the project counts above. The Phase III of the DOE project is the demonstration phase in which a large volume of CO 2 

### is injected

, typically over several years.

Exhibit 8 9 : DOE Phase III Sequestration 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: Mississippi Tuscaloosa Massive
Saline Reservoir; SW Mississippi (Cranfield, MS) no

MRCSP Cincinnati Arch Mt. Simon Saline Reservoir; Greenville, OH yes

WESTCARB San Joaquin Basin, 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 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 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 9 : Existing and Planned 10: High-End Estimate for the CO 2 

### Capture Facilities Expected to Begin Sequestration
, by Year Formatted: Font: 11 pt, Italic

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Year Number of Sequestration Facilities Beginning Operation 

### Total 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
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 na med DOE pilot projects and one sequestration facility associated with the Futu reGen federal/private partnership.

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

### capture facilities assumes that only existing projects ar e affected, and only projects associated with named DOE pilot projects and federal/private partnerships will be affected. All other assumptions are consistent with the high-end 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 practi ce sequestration activities in each year under the proposed rule.

Exhibit 11: Low-End Estimate of the CO 2 

### Facilities Assumed to Begin and Practice Sequestration Activities, by Year Formatted: Font: 10 pt, Bold, Italic

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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
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 and Benefits of the Proposed Rule

This section analyzes the expected costs and benefits of the proposed rule. Section 3.1 describes the analytical approach and methodology. Section 3.2 and Section 3.3 discuss the expected regulatory compliance behavior in the baseline (i.e., in the absence of the proposed rule) and expected regulatory compliance behavior 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 and benefits of the proposed rule (i.e., the costs and benefits that arise as a consequence 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 assumes no regulatory change, it has no associated incremental cost. Therefore, the baseline serves as a reference point from which the incremental costs and benefits of the proposed rule can be measured. Comment [LL28]: Identified changes made in response to OMB review.

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### 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 post-rule behavior have been established, the analysis then estimates the incremental costs and benefits of the proposed rule relative to the baseline over a 50-year period. 38



### 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 engage 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 discusses the hazardous waste determination process and then presents the possible baseline practices for CO 2 

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

### is by pipeline. 39 

### Although
other forms of CO 2 

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

### transportation is done via pipelines both in the baseline and under 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 characteristics. 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 processes 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 compression 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 flui d or liquid under high pressure state. EPA
estimates that a CO 2 

### capture facility would expend approximately $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

38 Consistent with the EPA Office of Water’s “Cost 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.

39 Paul W. Parfomak and Peter 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

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### would not contain pesticides or most metals, and, consequently, samples only for semivolatile organic compounds, volatile organic compounds, and mercury. 40 

### This third option is the least expensive – EPA estimates that a CO 2 

### capture facility would expend approximately $4,500 in one-time costs and $2, 5 00 700 in annual costs to utilize this method
of RCRA hazardous waste determination. 41



### This analysis assumes that the 18 facilities capturing CO 2 

### streams from fossil fuel electric power generation, natural gas distribution, ethyl alcohol manufacturing, and nitrogenous fertilizer manufacturing would rely on process k nowledge 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 9 facilities capturing CO 2 

### streams from oil and gas extraction 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). 42



### 3.2.2 Baseline Practices for CO 2 

### Capture Facilities

Depending on whether its CO 2 

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

### stream. The flow chart in Exhibit 10 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.

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

41 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.

42 For simplicity, this draft applies a single weighted average waste determination cost.

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### Exhibit 10 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
Destine 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 43

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 cost 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

43 Permit writers also may require the well to meet the Class VI UIC requirements. However, there is no specific UIC regulation that would require permit writers to a pply both the Class I and Class VI standards to a RCRA
hazardous waste CO 2 injection well. Comment [LL29]: Identified changes made in response to OMB review.

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### 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. 44



### Transporting the waste to a Class I hazardous waste 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. 45 

### 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 purel y on management costs, generators who
determine that their waste is RCRA hazardous waste 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 elig ible for government subsidies, to improve marketing public image, or to prepare for anticipated regulatory or market changes (i.e., to avoid early obsolescence). These same factors may influence generators’ decisions 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 treat ing the waste for sequestration in a Class VI well, some generators nonetheless, may adopt the latter practice. EPA’s requirements allow

44 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 in curred. 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 permit as part of the planning process as in

. Starting in 2011 EPA intends to apply the Clean Air Act Prevention of Significant Deterioration (PSD) program to new electric power plants emitting greater 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 be included in operating permits for power plan ts 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.

45 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 re gulatory requirement for permit writers to apply the Class VI requirements to Class I wells. For purposes of this analysis, the diffe rence 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 cla ss of injection well or whether the CO 2 stream to be injected is a RCRA hazardous waste or non-hazardous waste. In actuality, the modeling costs for Class I and Class VI wells may differ. Class I UIC well permits require modeling fo r 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.

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### 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. Furthermor e, 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 permit that allows RCRA hazardous waste CO 2 

### stream sequestration.

3.2.2.2 Expected Baseline Practices of CO 2 

### Carbon Capture Facilities

As shown in Exhibit 10 12 above, the analysis assumes that non-hazardous CO 2 

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

### streams have three options: (i) transport their streams to Class 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. Due to There is significant uncertainty in the hazardous constituent
content of CO 2 

### streams that will be captured

, and the complexity of the factors that will may influence the baseline practices for generators of hazardous streams

, Exhibit 11 presents . As a result, we have assumed a broad range for the prevalence of hazardous waste determination and baseline practices for CO 2 

### capture facilities.

Exhibits 13 and 14 present our conservative (high-end) and low-end assumptions regarding the relative prevalence of each baseline practice in the absence of the proposed rule. 46 

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

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

### is RCRA hazardous waste. It is important to note that, due to the lack of definitive data, t hese the hazardous CO 2 

### percentages where formed as conservative assumptions presented in these Exhibits are designed to represent a broad range of potential

outcomes for analytical purposes only. Based on early literature reviews and current CO 2 

### capture technologies

, the percentage of CO 2 

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

46 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. Comment [LL30]: Identified changes made in response to OMB review.

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### Exhibit 11 : Conservative 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. The sensitivity anal ysis in Appendix C considers the alternative assumption that 90 percent of the CO 2 capture facilities would generate non

hazardous CO 2 streams in the baseline.



### Exhibit 12 14: Low-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 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 EP A expects will be active each

year under the conservative assumption , and applies the percentages from Exhibit 11 13 to estimate the number of CO 2 

### capture facilities that would engage in each baseline practice each year in the absence of the proposed rule. 47



### Exhibit 1 2 : 15 – Assumed 90% Hazardous Waste:

47 After applying the weights from Exhibit 11 13 , the number of facilities practicing each baseline practice was adjusted slightly to eliminate rounding erro rs in the total number of capture facilities. Comment [LL31]: Identified changes made in response to OMB review.

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Comment [LL33]: Identified changes made in response to OMB review.

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### Expected Number of CO 2 

### Capture Facilities That Would Engage In Each Baseline Practice in the Absence 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

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 b 3 8 8 8 27

a The numbers in this table are derived by applying the percentages of capture facilities conducting each baseline practice presented in Exhibit 11 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 num ber 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, and applies the percentages from Exhibit 14
to estimate the number of CO 2 

### capture facilities that would en gage in each baseline practice each year in the absence of the proposed rule. 48

48 After applying the weights from Exhibit 14, the numb er of facilities practicing each baseline practice was adjusted slightly to eliminate rounding erro rs in the total number of capture facilities. Formatted: Font: 10 pt, Bold, Italic

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

### Capture Facilities That Would Engage In Each Baseline Practice in the Absence 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
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 applying the percentages of capture facilities conducting each baseline practice presented in Exhibit 14 to the cu mulative 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 num ber of capture facilities in each year matches the
total from Exhibit 5.



### The analysis makes the following assumptions regarding the costs that CO 2 

### capture facilities
incur under the baseline: 49

49 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 testi ng 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 (the

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• 

### 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. Facilities that would
continue CO 2 

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

### streams in subsequent years and therefore 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 capture, would not be considered hazardous waste generators and would face no further costs associated with the hazardous waste regulations.

• 

### CO 2 

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

### streams and do not cease capture would qualify as large quantity generators (LQGs) in the baseline (i.e. they would generate more than 1,000 kilograms 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. 50



### 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 Clas s I hazardous waste wells that EPA has assumed will also meet the Class VI requirements. Th e Class VI wells would manage non-hazardous
CO 2 

### streams and CO 2 

### streams that have been treated prior 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 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. 51 

### Exhibit 13 17 estimates the number of CO 2

facility would likely qualify as a conditionally exempt small quantity gene rator),

, so this analysis assumes the associated costs to be neglig ible for handling the samples.

50 EPA has assumed that these facilities would meet the requirements of “onsite treatment” under 40 CFR 260.10 (Definitions) and related RCRA regulations and therefore would not be required to obtain RCRA hazardous waste treatment permits.

51 The For the high-end estimate, this analysis assumes , in Section 3.2.2.2, that 40 percent of CO 2 capture facilities would transport non-hazardous 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 Comment [LL35]: Identified changes made in response to OMB review.

Comment [LL36]: Identified changes made in response to OMB review.

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### sequestration facilities that would engage in each baseline practice

. under our high-end assumption

Exhibit 13 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

sequestration wells for injection. Of this 70 pe rcent 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 Class VI wells to match the practices of CO 2 capture facilities. The remainin g 3 out of 7 (43 percent) of CO 2 sequestration
wells in the baseline are Class I wells. Comment [LL37]: Identified changes made in response to OMB review.

Comment [LL38]: Identified changes made in response to OMB review.

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Year Manage Non-Hazardous CO 2 (Class VI) Manage Hazardous
CO 2 (Class I) facilities conducting each baseline practice presented discussed above to the number of sequestration facilities expected to be in operation each year (cumulative), as presented
in Exhibit 9 10 . The numbers are rounded to integer values while ensuring the total number of capture facilities in each year matches the total from Exhibit 9 10

.



### Low-End Assumption:

This analysis assumes that, in the baseline low-end assumption, 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. 52 

### Exhibit 18 estimates the number of CO 2 

### 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

52 For the low-end estimate, this analysis 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 assumes 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. Formatted: Font: Bold, Italic

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Year Manage Non-Hazardous CO 2 (Class VI) Manage Hazardous
CO 2 (Class I)

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 operation 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.



### 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 pipeline 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 claim the proposed exclusion and
send their CO 2 

### streams to Class VI wells as a result of the proposed rule. 53 

### Under the proposed rule proposal , CO 2 

### capture facilities claiming the proposed exclusion would avoid the costs of determining whether their CO 2 

### stream is RCRA hazardous or non-hazardous. 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

53 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 expect ed to be similar to the costs of usin g a Class VI well, so this distinction will not affect the results of this analysis. Comment [LL40]: Identified changes made in response to OMB review.

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### Under the proposed rule, all CO 2 

### sequestration facilities are expected to be permitted as Class
VI wells. 54 

### 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 incremental costs of the proposed rule. Section 3.4.1 presents and quantifies the compliance costs of the proposed rule, and Section 3.4.2 qualitatively discusses the potential social costs of the proposed rule. Section 3.4.3 discusses 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 re quired to sign a certifi cation statement which they must maintain onsite and make available to EPA on upon request. 55 

### 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 14 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 14 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 Nationa l 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 th e 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

54 With the possible exception of some sequestration dem onstration projects that may be permitted as Class V experimental wells.

55 A single certification statement would be signed by only one facility. Each capture facility and each sequestration facility would sign its own certification statement. Formatted: Font: 10 pt, Bold, Italic

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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 15 years experience according to The Society of Petrol eum Engineers “Annual Memb ership 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 “Employmen t Cost Index Historical Listing Current-dollar March 2001-September 2010,” http://www.bls.gov/web/eci/echistrynaics.pdf , and multiplied by a lo ading factor of 1.6.

b These hour estimates are based on EPA’s professional judgment.



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

Exhibits 15 20 and 16 21 multiply these the per facility costs times the maximum number of potentially affected capture facilities and Class VI wells, respectively

, . 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 firs t year of operation and renew the certification in each subsequent year. 56 

### Combined, EPA and state governments are assumed to request certification statements from approximately 30 pe rcent of capture facilities and Class VI well operators annually. 57 

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

Exhibit 15 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

56 See Exhibits 10 5 and 11 10 for the number of CO 2 capture and sequestration facilities expected to operate in each year. All of these facilities, regardless of their base line practice, are expected to incur these certification

costs.

57 This estimate is based on EPA’s best professional judgment. Formatted: Font: 10 pt, Bold, Italic

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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

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

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 Formatted: Font: Bold, Italic

Formatted Table

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Formatted: Font: Bold

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### Exhibit 1 6 21: High-End Estimate : Certification 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

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 Comment [LL42]: Identified changes made in response to OMB review.

Formatted: Font: Bold, Italic

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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

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 Cl ass 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 assume d to sign the certification in the first year of operation and renew the certification in each subsequent year. 58 

### Combined, EPA and state governments are assumed to request certification statements from approximately 30 percent of capture facilities and Cl ass VI well operators annually. 59 

### The exhibits present the undiscounted certification costs, and also presen t 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

58 See Exhibits 6 and 11 for the number of CO 2 capture and sequestration facilities expected to operate in each year. All of these facilities, regardless of their baseline practice, are expected to incur these certification costs.

59 This estimate is based on EPA’s best professional judgment. Formatted: Font: Bold, Italic

Formatted Table

Formatted: Font: Italic

Formatted: Font: Bold

Comment [LL43]: Identified changes made in response to OMB review.

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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

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

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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

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: Certification 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

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

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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

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

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 operational and have not yet acquired permits. The cost to obtain the Class VI permit is assumed to be similar 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 construction and permitting of Class I and Class VI
wells.

3.4.2 Social Costs Formatted: Font: Bold

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### The baseline requirements that apply to captured RCRA hazardous waste CO 2 

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

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

### stream and prevent it from migrating to USDWs. Underground Sources of Drinking Water (USDWs). In addition, permit writers for Class VI UIC wells have discretion 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 believes has determined that the management of exempted CO 2 

### streams in Class VI UIC wells would not pose a significant an unacceptable risk to human health and the
environment. 60 

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

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

3.4.3 Costs to Government Entities

Under the proposed rule, CO 2 

### capture facilities and Class VI well operators would be required to sign a certification statement and make it available to EPA or state governments upon request. This analysis assumes that, combined, EPA and state governments will request certification statements from approximat ely 30 percent of capture facilities and Class VI well operators annually, and that state governments will account for about 90 percent of those requests. 61 

### Exhibits 1 7 24 and 1 8 25 present the costs per request to EPA and state governments, respectively.

Exhibit 1 7 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

60 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 coll ect additional data on the composition of captured CO 2 streams. As CCS pilot projects move forward and contin ue to generate information, EPA expects the amount of available analytical data on captured CO 2 to increase.

61 These estimates are based on EPA’s best professional judgment. Comment [LL44]: Identified changes made in response to OMB review.

Formatted: Font: 11 pt, Bold, Italic

Formatted: Centered

Formatted Table

Formatted: Font: 11 pt, Bold

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a Office of Personnel Management, “Salary Table 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 standa rd government loading factor of 1.6 to reflect
overhead

b These hour estimates are based on EPA’s professional judgment.



### Exhibit 1 8 25 : Estimated Costs to States 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 Statis tics (BLS), “May 2009 National Industry-Specific Occupational Employment and Wage Estimat es, 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 1 9 26 and 20 calculate 27 below present the high-end estimates for the total costs to EPA and state governments to request and review certification statements related to the proposed exclusion over the 50-year peri od beginning 2012. The exhibits present undiscounted costs, and also apply 3 percent and 7 percent discount rates to costs incurred
after 2012.

. Exhibit 19 26: High-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 1 $47 $41 $34

2018 1 $47 $39 $31

2019 1 $47 $38 $29

2020 1 $47 $37 $27

2021 1 $47 $36 $26 Formatted: Font: 11 pt, Bold, Italic

Formatted: Centered

Formatted Table

Formatted: Font: 11 pt, Bold

Formatted Table

Comment [LL45]: Identified changes made in response to OMB review.

Comment [LL46]: Identified changes made in response to OMB review.

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

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

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 Formatted: Font: Bold, Italic

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

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 20 27: High-End Estimate : Costs to State 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

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 Formatted: Font: Bold, Italic

Formatted: Font: Bold

Comment [LL47]: Identified changes made in response to OMB review.

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

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

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 ex hibits present undiscounted costs, and also apply 3 percent and 7 percent discount rates to costs incurred 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 Formatted: Font: Bold, Italic

Formatted: Font: Bold

Comment [LL48]: Identified changes made in response to OMB review.

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

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

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

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

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



### Exhibit 29: Low-End Estimate: Costs to State 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

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

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

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

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

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 excluded from the RCRA hazardous waste requirements under the proposed rule. 62 

### 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, planning, 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 waste well permit in the baseline would also see savings related to hazardous waste determination and 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 

### destine destined for geological sequestration would be required to determine whether the CO 2 

### stream qualifies as RCRA hazardous waste either by testing the content of the waste or by applying knowledge of the materials and processes used to generate the waste, as required by 40 CFR 262.11 (Hazardous waste determination). Appendix A of this document discusses the available testing options for waste determination

. (i.e., Option 1, 2, and 3). As stated in Section 3.2, this analysis assumes that the 18 facilities capturing CO 2 

### streams from fossil fuel electric power generation, natural gas distribution, ethyl alcohol manufacturing, and nitrogenous fertilizer manufacturing would rely on process k nowledge and limited testing to determine if
their CO 2 

### stream is a RCRA hazardous waste (i.e., Option 3). The analysis further assumes that the remaining 9 facilities capturing CO 2 

### streams from oil and gas extraction 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, 5 00 300 in one-time costs and $3,000 in annual costs. 63 

### Under the

62 Section 1.2 of this document summarizes requirement s applicable to generators of RCRA hazardous waste
CO 2 in the baseline.

63 See Appendix A for further detail on the calculation of waste dete rmination costs. This draft applies a single weighted average testing cost. The seventeen facilities that capture CO 2 from fossil fuel power generation, ethyl alcohol manufacturing, and nitrogenous fertilizer manufacturing are expected to combine process knowledge with limited chemical analytical testing. The remaining ten facilities that capture CO 2 from oil and gas extraction and natural gas distribution are expected to test their CO 2 streams as gas prior to compression. Comment [LL49]: Identified changes made in response to OMB review.

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### 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 generators who send RCRA hazardous waste CO 2 

### streams to a Class I hazardous waste well and generators wh o treat their RCRA hazardous waste and then send it to Class VI wells are LQGs in the baseline and are . Thus, these facilities would be subject to the full set of RCRA hazardous waste regulations

, including training, planning, and reporting requirements. The proposed rule w ould relieve these generators of the costs associated with these requirements. Exhibit 21 30 estimates the annual savings per facility that would no longer be subject to the RCRA training, planning and reporting requirements under the proposed rule.

Exhibit 21 30 : Estimated Annual RCRA Traini ng, Planning, and Reporting Requirement Savings Per Hazardous CO 2 

### Capture Facility as a Result of the Proposed
Rule (2010 dollars)

(2010 dollars) Requirement Citation Savings Per Facility a



### EPA ID b 

### 262.12 $0 Personnel Training c 

### 262.34 $2,762

The weighted average costs ass ociated with waste determination are $5, 366 in one time costs and $3,113 in
annual costs

63 See Appendix A for further detail on the cal culation of waste determination costs. Formatted: Font: Bold, Not Superscript/ Subscript

Formatted: Centered, Right: 0" Formatted: Font: Not Bold, Superscript

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### Requirement Citation Savings Per Facility a



### 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 co st 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 re porting requirements. 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 under 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 IGCC Integrated Gasification Combined Cycle (IGCC) power plant would cost $8.94 per metric ton of CO 2



### . 64 

### 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. 65 66 

### If the planned CO 2 

### capture facilities generate CO 2 

### streams at a similar rate, each facility that

64 Appendix B presents the calculation of these CO 2 treatment costs.

65 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

. . 66 We evaluating other options to develop an average annual quantity of captured CO 2 . In addition, the Val Verde Gas Plants in Texas are 5 plants rather than one that is implied in the original table. This facility count was realized after the EA was completed. Hence, the average is closer to 1.1 Million and the treatment costs per plant will decrease in the next draft of the EA. Formatted: Font: 11 pt, Bold

Formatted: Superscript

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### treats its CO 2 

### stream in the baseline will would save approximately $10. 3 27 million per year in CO 2 

### stream treatment costs annually under the proposed rule.

3.5.4 Summary of Savings to CO 2 

### Capture Facilities

Exhibit 22 31 multiplies each of the savings identified above times the appropriate number of
facilities that would receive each saving in 2012, and calculates a total expected savings of approximately $10. 3 31 million to CO 2 

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

Exhibit 22 31 : Savings to CO 2 

### Capture Facilities as a Result 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 savings 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 determination savings in the first year of capture because they would not have conducted waste determinations in subsequent years after ceasing
capture.

c RCRA training, planning, and reporting requirement savings apply 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.



### Exhibit 23 uses this Exhibits 32 and 33 below apply the methodology described 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 proposed rule proposal are calculated for each year over a 50-year period beginning in 2012. The exhibit presents exhibits present the undiscounted savings

, and also applie s apply 3 percent and 7 percent discount rates to savings accrued after
2012. Formatted: Font: Bold

Comment [LL50]: Identified changes made in response to OMB review.

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### Exhibit 23 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 Comment [LL51]: Identified changes made in response to OMB review.

Formatted Table

Formatted: Font: 8 pt

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2053 $58,393 $80,912 $82,163,162 $82,302,467 $24,495,519 $5,136,626

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 annu al * $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 $10,299,165 $8,884,150 $7,343,162

2018 $18,440 $5,057 $10,270,395 $10,293,892 $8,620,973 $6,859,255

2019 $18,440 $5,057 $10,270,395 $10,293,892 $8,369,876 $6,410,519

2020 $18,440 $5,057 $10,270,395 $10,293,892 $8,126,093 $5,991,139

2021 $18,440 $5,057 $10,270,395 $10,293,892 $7,889,411 $5,599,195

2022 $18,440 $5,057 $10,270,395 $10,293,892 $7,659,622 $5,232,893

2023 $18,440 $5,057 $10,270,395 $10,293,892 $7,436,527 $4,890,554

2024 $18,440 $5,057 $10,270,395 $10,293,892 $7,219,929 $4,570,611

2025 $18,440 $5,057 $10,270,395 $10,293,892 $7,009,640 $4,271,599

2026 $18,440 $5,057 $10,270,395 $10,293,892 $6,805,475 $3,992,149

2027 $18,440 $5,057 $10,270,395 $10,293,892 $6,607,258 $3,730,980

2028 $18,440 $5,057 $10,270,395 $10,293,892 $6,414,813 $3,486,897

2029 $18,440 $5,057 $10,270,395 $10,293,892 $6,227,974 $3,258,783

2030 $93,556 $5,057 $10,270,395 $10,369,008 $6,090,699 $3,067,815

2031 $54,446 $10,114 $10,270,395 $10,334,955 $5,893,880 $2,857,701

2032 $82,558 $10,114 $10,270,395 $10,363,067 $5,737,779 $2,678,013

2033 $61,466 $10,114 $10,270,395 $10,341,975 $5,559,321 $2,497,722

2034 $103,197 $10,114 $10,270,395 $10,383,706 $5,419,178 $2,343,739

2035 $93,525 $10,114 $10,270,395 $10,374,034 $5,256,437 $2,188,370 Formatted: Font: Bold, Italic

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2036 $79,906 $10,114 $10,270,395 $10,360,415 $5,096,638 $2,042,521

2037 $79,906 $10,114 $10,270,395 $10,360,415 $4,948,192 $1,908,898

2038 $79,906 $10,114 $10,270,395 $10,360,415 $4,804,070 $1,784,017

2039 $79,906 $10,114 $10,270,395 $10,360,415 $4,664,145 $1,667,305

2040 $79,906 $10,114 $10,270,395 $10,360,415 $4,528,297 $1,558,229

2041 $79,906 $10,114 $10,270,395 $10,360,415 $4,396,404 $1,456,289

2042 $79,906 $10,114 $10,270,395 $10,360,415 $4,268,354 $1,361,018

2043 $79,906 $10,114 $10,270,395 $10,360,415 $4,144,033 $1,271,979

2044 $79,906 $10,114 $10,270,395 $10,360,415 $4,023,333 $1,188,766

2045 $79,906 $10,114 $10,270,395 $10,360,415 $3,906,148 $1,110,996

2046 $79,906 $10,114 $10,270,395 $10,360,415 $3,792,377 $1,038,314

2047 $79,906 $10,114 $10,270,395 $10,360,415 $3,681,919 $970,387

2048 $79,906 $10,114 $10,270,395 $10,360,415 $3,574,679 $906,904

2049 $79,906 $10,114 $10,270,395 $10,360,415 $3,470,562 $847,574

2050 $79,906 $10,114 $10,270,395 $10,360,415 $3,369,478 $792,125

2051 $79,906 $10,114 $10,270,395 $10,360,415 $3,271,338 $740,304

2052 $79,906 $10,114 $10,270,395 $10,360,415 $3,176,056 $691,872

2053 $79,906 $10,114 $10,270,395 $10,360,415 $3,083,550 $646,610

2054 $79,906 $10,114 $10,270,395 $10,360,415 $2,993,737 $604,308

2055 $79,906 $10,114 $10,270,395 $10,360,415 $2,906,541 $564,774

2056 $79,906 $10,114 $10,270,395 $10,360,415 $2,821,885 $527,826

2057 $79,906 $10,114 $10,270,395 $10,360,415 $2,739,694 $493,296

2058 $79,906 $10,114 $10,270,395 $10,360,415 $2,659,897 $461,024

2059 $79,906 $10,114 $10,270,395 $10,360,415 $2,582,424 $430,863

2060 $79,906 $10,114 $10,270,395 $10,360,415 $2,507,208 $402,676

2061 $79,906 $10,114 $10,270,395 $10,360,415 $2,434,183 $376,333

50 Year Total $2,906,136 $384,332 $462,167,786 $465,458,254 $225,164,528 $107,201,394

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

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### 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 required to confirm the characteristics of the waste stream to ensure it has been properly characterized by the 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. 67



### 3.5.6 RCRA Training, Planning, and Reporting Requirement Savings
for CO 2 

### Sequestration Facilitie s

In the baseline, Class I hazardous waste injection 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 requirements in the baseline, per 40 CFR 144.14 (Requirements for wells injecting hazardous waste). 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 no t 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 24 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. The exhibit also presents the expected savings associated with each requirement.

67 See Appendix A for further detail on the calcu lation of waste determination costs. Formatted: Font: Bold

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### Exhibit 24 34 : Estimated Annual RCRA Traini ng, 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 se questration facilities that managed hazardous waste CO 2 streams in the baseline under Class I UIC permits.

b Exclusion from these requirements may result in slight savings, 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 “Regulatory 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 adjusted to 2010 dollars using the Bureau of Labor Statistics (BLS) Inflation
Calculator.



### 3.5.7 Summary of Savings to CO 2 

### Sequestration Facilities

Exhibit 25 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 facilities (high-end estimate) that would receive each saving in 2012, to calculate the total expected high-end savings to CO 2 

### sequestration facilities in the first year under the proposed rule. Comment [LL52]: Identified changes made in response to OMB review.

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### Exhibit 25 35 : Savings to CO 2 

### Sequestration Facilities as a Result 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 26 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 savings accrued after 2012.

Exhibit 26 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 Formatted: Font: Bold

Comment [LL53]: Identified changes made in response to OMB review.

Comment [LL54]: Identified changes made in response to OMB review.

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Year Waste
Determination Hazardous Waste
Generator Requirements Total Savings (Undiscounted) Total Savings (3% Discount Rate) Total Savings (7% Discount Rate)

2032 $51,560 $19,334 $70,894 $39,252 $18,320

2033 $33,801 $19,334 $53,135 $28,563 $12,833

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 calculate 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 percent and 7 percent discount rates to savings
accrued after 2012. Formatted: Font: Bold

Comment [LL55]: Identified changes made in response to OMB review.

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### 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

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Year Waste
Determination Hazardous Waste
Generator Requirements Total Savings (Undiscounted) Total Savings (3% Discount Rate) Total Savings (7% Discount Rate)

2050 $44,556 $2,762 $47,318 $15,389 $3,618

2051 $44,556 $2,762 $47,318 $14,941 $3,381

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 $1,986,125 $944,344 $452,086



### 3.6 Summary of Costs and Savings

The preceding analysis quantified the costs and benefits of the proposed rule under both a high-end and low-end scenario. Detailed costs are presented for capture facilities, sequestration facilities, state governments, and EPA. Detailed cost savings are presented for capture facilities and sequestration facilities. The Exhibits below summarize costs, savings, and net savings over the 50 year period, in aggregate, 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 summarize the 50-year and annualized high-end costs and benefits of the proposed 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 appr oximately $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 net savings of approximately $32.0 million.

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### Exhibit 38: High-End Estimate: Net Costs and Savings of the Proposed Rule - Undiscounted (2010 dollars)

T yp e of Entit y 50-year
Costs 50- y ear Savin g s 50-year Net
Savin g s Average
Annual Net

Savin g s 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 Cost s 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 Cost s 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 summarize the 50-year and annualized low-end costs and benefits of the proposed rule applying 3 percent and 7 percent discount rates, respectively.

Under the low-end estimate, the proposed rule is expected to result in undiscounted annualized net savings of approximately $9.3 million. Applying a 3 percent discount rate, Formatted: Font: Bold

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### 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.

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 Formatted: Font: Bold

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### Summary:

Due to the high level of uncertainty regarding the percent of CO 2 

### that may be RCRA hazardous, and the uncertainty regarding the act ual 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 mi llion (3%discount rate).

Under Executive Order 12866, a rule qualifies as economically significant if its annual effect on the economy is $100 million or more. This proposed rule is not expected to be economically significant, as defined under Executive Order 12866.

3.5.8 3.7 Unquantified Benefits of the Proposed Rule

In addition to the quantified savings discussed above, the proposed rule also represents a step toward establishing a supporting 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.

3.6 Conclusions

The preceding analysis quantified the costs and benefits of the proposed rule. Exhibit 27
summarizes the undiscounted 50

- year and annualized costs and benefits of the proposed rule.
Exhibits 28 and 29 summarize the 50

- year and annualized costs and benefits of the proposed rule applying 3 percent and 7 percent discount rates respectively. The proposed ru le is expected to result in undiscounted annualized net savings of approximately $ 5 6

. 6 million. Applying a 3 percent discount rate, the annualized net savings are approximately $ 44. 9 million. Applying a 7 percent discount rate, the annualized net savings are approximately $ 3 2

. 0 million. 68 

### Under Executive Order 12866, a rule qualifies as economically significant if its annual effect on the economy is $100 million or more. This proposed rule is not expected to be economically significant, as defined under E xecutive Order 12866.

Exhibit 27 : Undiscounted Net Costs and Savings of the Proposed Rule (2010 dollars)

Type of Entity 50

- year Costs 50

- year Savings 50

- year Net Savings Average Net Savings Capture Facilities $164,544 $2,829,383,941 $2,829,219,397 $56,584,388

68 Appendix C presents two sensitivity analyses that consider the costs and savings of the proposed rule under assumptions that differ from the main analys is. The first sensitivity analysis conside rs a fewer number of
affected facilities than the main an alysis. The second sensitivity an alysis makes different assumptions regarding the hazardous characteristics of captured CO 2 streams in the baseline. Comment [LL56]: Identified changes made in response to OMB review.

Comment [LL57]: Identified changes made in response to OMB review.

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Type of Entity 50

- year Costs 50

- year Savings 50

- year Net Savings Average Net Savings 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 28 : Net Costs and Sa vings 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 29 : Net Costs a nd 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



### In addition to the quantified savings, the proposed rule will help establish a supporting regulatory framework for the future development and deployment of carbon capture sequestration (CCS) technology and will help provide the regulatory certainty needed to foster 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 regulations 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 rule 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, an d small governmental jurisdictions. Formatted: Centered, Right: 0"

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### This proposed rule does not have a significant impact on a substantial number of small entities because it relieves the regulatory burd en associated with EPA’s hazardous waste regulations on CO 2 

### capture and sequ estration facilities by exempting CO 2 

### captured for the purpose of geological sequestration in Class VI we ll from the definition of hazardous waste. For each facility claiming the proposed exclusi on, these savings are expected to outweigh the cost to prepare and maintain the required certi fication statement. The Agency estimates that this proposed rule will could lead to net cost savings in the range of $ 3 2.0 7.3 to $56.6 million annually. Accordingly, EPA certifies that the rule will not have a significant economic impact on a substantial number of small entities.

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### 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.cdlib.org/lbnl/LBNL-1251E . As cited by EPA in the preamble to the Federal Requirements Under the Underground Injection Control Program for Carbon Dioxide Geologic Sequestration Wells Final Rule, RIN 2040-
AE98.

Department of Energy, National Energy Technology Lab. Carbon Capture and Storage
Database. Available: http://www.netl.doe.gov/technologie s/carbon_seq/database/index.html

Department of Labor, Bureau of Labor Statistics. “CPI Inflation Calculator.” Available: http://www.bls.gov/data/inflation_calculator.htm

.

Department of Labor, Bureau of Labor Statistics. “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 Statistics. “May 2009 National Industry-Specific Occupational Employment and Wage Estimates, NAICS 999200 – State Government.” Avialable: http://www.bls.gov/oes/current/naics4_999200.htm.

Department of Labor, Bureau of Labor Statistics. “Occupational Employment Statistics, May 2009 National Occupational and Wage Estimates, United States.” Last modified May 14. 2010, Available: http://www.bls.gov/oes/current/oes_nat.htm

.

Department of Transportation, Pipeline a nd Hazardous Materials Safety 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. “Regulatory Impact Analysis: 2008 Final Rule Amendments to the Industrial Recycling Exclusions of the RCRA Definition of Solid Waste.” Environmental Protection Agency, Office of Solid Waste. September 2008.

EPA. “Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2008.” Table 3-47: Potential Emissions from CO2 Capture and Transport. p. 3-53. April 15, 2010. Available: http://www.epa.gov/climatechange/emissi ons/downloads10/US-GHG-Inventory2010_Report.pdf

EPA. “Cost Analysis for the Federal Requirements Under the Underground Injection Control Program for Carbon Dioxide Geologic Sequestration Wells (Final GS Rule).” Office of Water ( 460 M). 4606M). EPA 816-R-10-013. 2010.

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### EPA. Final Rule for Federal Requirements Unde r the Underground Injection Control (UIC) Program for Carbon Dioxide (CO2) Geologic Sequestration (GS) Wells. Signed by the Administrator on November 22, 2010.

Koch Industries. “Koch Industries Welcomes 2 009 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 (M IT). Largescale Power Plant CCS Projects Worldwide. Power Plant Carbon Dioxide Capture and Storage Projects website. http://sequestration.mit.edu/tools/projects/index.html

Nation, Larry. “Uncertainty chills decision making: Salaries Show 5 Percent Increase.”
American Association of Petroleum Geologists (AAPG). Available: http://www.aapg.org/explorer/salarysurvey.cfm

Office of Personnel Management. “Salary Table 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 Research 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 Sequestration: Emerging Policy Issues.
Available: http://nepinstitute.org/ge t/CRS_Reports/CRS_Climate_a nd_Environment/Carbon_and_CO2/ CO2_Pipelines_for_Carbon_Sequestration.pdf

PetroSource Energy Company, “Petrosource 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/career/salary_survey/

.

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### Appendix A

Cost for Determining RCRA Toxicity of CO 2 

### Stream

Under the Business As Usual (BAU) scenario a ge nerator would be required to determine if
the CO 2 

### stream is classified as a Hazardous Waste under the Resource Conservation and Recovery Act (RCRA). This appendix summar izes the options and associated costs for determining if the waste meets 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 the costs associated with the corrosivity characteristic.

A.1 Summary of the RCRA Toxicity Characteristic

Determining if a solid waste is classified as hazardous under RCRA requires the generator to
first determine if the material is a “Listed” wast e, (i.e., contained in a list of wastes defined as hazardous by the regulation). If it is not listed then the waste material must either be tested and characterized to determine if it is hazardous 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 determine whether the waste is RCRA hazardous. For the purposes of this analysis, ICF we developed separate cost es timates for generators of CO 2 

### streams that will conduct physical testing of the waste and generators of CO 2 

### streams that will apply process knowledge with limited chemical analytical testing. EPA also evaluated testing for operators of sequestration facilities. RCRA regulations under 40 CFR 261.24 (Toxicity characteristic) provide criteria for these definitions and references to methods to be used for testing to determine the RCRA toxicity charact eristic of the waste. This appendix addresses only the characteristic of toxicity resulting from the chemical constituen ts of the waste.

Under 40 CFR 261.24 of RCRA the waste is considered 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 concentration criteria are presented in
Exhibit A-1.

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### Exhibit A-1: Maximum Concentration of Contaminants for the Toxicity 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

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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 regulat ory level. The quantitation limit therefore becomes the regulatory level.

4 If o-, m-, and p-Cresol concentrations cannot be differentiated, 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 evalua ting the testing of CO 2 

### streams.

Issue 1: Lack of RCRA test pro cedures for gasses, supercritical fluids or liquids under high

pressure. The concentration limits for hazardous waste constituen ts in the RCRA regulation 40 CFR 261.24 (Toxicity characteristic) is in liquid units (milligrams per liter). In particular, the RCRA toxicity test procedures specified in EPA publication SW-846 require flushing the solid waste sample with a slightly acidic aque ous solution to leach out potentially hazardous
contaminants. The concentration of constituen ts in the leachate is compared to the RCRA concentration limits (see Exhibit A-1). If the concentration in the leachate exceeds the RCRA
concentration limits then the waste is classified as a RCRA hazardous waste. In the case of a liquid waste, the RCRA regulation under 40 CFR 261.24(a) allows the waste itself to be considered to be the leachate for the purpose of comparison with the concentration standards. However, there is no RCRA regulation or guidance that specifies test procedures for wastes that are gas, supercritical fl uid, or dense liquid under high pressure. 69 

### CO 2 

### streams captured for the purposes of injection will typi cally 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). 70 

### Transport and injection is commonly as a dense liquid or

69 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 a nd 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

70 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.

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### supercritical fluid. 71 

### 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 concentration 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 (metals, pesticides , volatile organic 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 and transported generally contain some impurities when in supercritical or liquid under high pressure state that can complicate
the measurement the composition of the CO 2 

### stream due to differences in the density and the compressibility of the components. The concentration of components in CO 2 

### in a supercritical or liquid under high pressure stat e may not be representative of the composition at a lower pressure.

A.3 Options and Associated Costs for Testing CO 2 

### Stream

This section presents four options 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 Limi ted Analytical Testing to Meet RCRA Characterization Requirements; and

• 

### Option 4 – Injection Facility Testing to Ensure Compliance with RCRA.

Option 1 – Testing CO 2 

### Stream as a Gas

Under this option, facilities 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 Option 1 scenario includes
full characterization of all listed RCRA contamin ants to account for all potential processes that may generate CO 2 

### streams for subsequent sequestration.

This analysis uses costs for sampling and analysis 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 construct a special sampling port on the process line to

71 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

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### collect a representative sample of the CO 2 

### stream for analysis. Facilities may already have sampling ports for operational testing, but the stream would not normally be sampled for the full range of RCRA contaminants listed in Exhibit 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 me tal 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 characterization annually, an d the sampling program would also include collection of quality control samp les for verification. 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 currently no guidance for determining if a gas
contains a concentration of hazardous contamin ants above the RCRA toxicity characteristic limits in Exhibit A-1. Therefore, a facility wo uld need to construct a methodology to relate the sampled gas concentrations to the liqui d 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 measurements to liquid concentration measurements considering all the physical and chemical properties of the CO 2 

### stream and listed constituents. We have not developed the detail s of this conversion method, but based on input from our analytical chemists we assume 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 results 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 measur ements (in milligrams per kilogram) to liquid
concentrations based on the dilutions used in the toxicity leaching test specified in EPA
Publication SW-846.

A breakdown of the costs and labor hours for this option are presented in Exhibit A-2. Additional details are provided in Exhibit A-6.

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### 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 Improvement (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 h ourly 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, facilities 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 pressu re. A special sampling port designed for high pressure and corrosive fluids would be required on the high pressure CO 2 

### stream line. CO 2 

### generator facilities would likely not have su ch a port already inst alled under normal operations, therefore the cost of installation woul d be incurred. Sampling of high pressure fluids and gasses is performed with a specialized 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 hi gh pressure sample is collected it must be analyzed using a standard method that is acceptable to EPA. There are currently no standard methods or guidelines for analysis of samples collected as supercritical fluids or liquids under high pressure. Since standard methods are available for analysis of gas samples, this Formatted Table

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### option assumes that the facility would devel op and document a procedure to gasify the supercritical fluid or liquid under high pressure and then analyze it as a gas. The analytical method development would require creating data quality and performance indicators by a senior chemist, and would require demonstrating that the integrity of the sample composition is maintained during phase shift from supercritical fluid or liquid under high pressure to gas. Analytical method development is allowed and 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 detection level of mercury in wastewater with less sample preparation. Method development is a one-time cost.

After the method is developed and samples are analyzed the generator would need to determine if the gas contains a concentration 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 cons truct 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 for 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 Improvement (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 Formatted Table

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a Labor hours were converted to costs using loaded h ourly wages of $110.99 for Senior Chemists, and $55.95 for Chemists and Sampling Technicians



### Option 3 – Using Process Knowledge and Limited Analytical Testing to Meet RCRA Characterization Requirements

RCRA regulations under 40 CFR 262.11(c)(2) allows generators to use knowledge of the process to determine the characteristics of th e waste stream for classification. Under Option 3, a generator would use existing data on the raw materials, operations 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 su pport air quality, processing, and pipeline requirements, therefore the generator would test for a few key components such as mercury, volatile and semi volatile organic compounds. For this cost estimate 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 un likely that the waste stream would contain pesticides, or most metals listed in Exhibit A-1. Under Option 3, the generator would only sample for semivolatile organic compounds, volatile organic compounds, and mercury. 72



### The generator would be required to document the CO 2 

### stream generation process and the
rationale for how the RCRA hazardous waste dete rmination was made. We estimate that the documentation would be performed by a senior level plant engineer or chemist and require approximately 40 hours. Once the determination was made, a staff level chemist would prepare an annual report of findings. A breakdown of the costs and labor hours for Option 3 are presented in Exhibit A-4. Additional details are provided in Exhibit A-8.

72 We recognize that, besides mercury, other heavy metals su ch as arsenic and selenium may be present at very

low levels.

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### Exhibit A-4: Labor Hours and Costs for Option 3: Using Process Knowledge to Meet RCRA 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 h ourly wages of $110.99 for Senior Chemists, and $55.95 for Chemists and Sampling Technicians



### Option 4 –Testing to Ensure Compliance with RCRA by Injection Facility

Facilities that inject the CO 2 

### would have responsibility to confirm the characteristics of the waste stream to ensure it has been properly characterized by the generator. CO 2 

### received forinjection by pipeline may be commingled from 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 the point where ownership of the CO 2 

### is transferred to the facility, or at a location immediately prior to injection. The RCRA testing would be done at
the same time as the CO 2 

### stream composition testing requi red under the UIC Class VI and would use the same sampling port, but wo uld analyze for diff erent constituents.

The injection facility would need to determine if the results of the gas analysis contain
concentrations of hazardous constituents above the RCRA toxicity characteristic limits, which are in liquid concentration units (milligrams per liter). 73 

### As in Option 1, an injection

73 Alternatively

, an injection facility could consider assessing th e result of a spill of the material into the soil,

water

, and air media and determine if the resulting media 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 Formatted Table

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### facility would need to construct a methodology to relate the sampled gas concentrations to a liquid concentration for direct comparison. The development and documentation of this
method would take a one-time effort of about 40 hours for a senior chemist or chemical engineer. After the method is developed and documented the results of the analysis and waste determination would be summarized in an annual report by a staff level chemist who would prepare an annual report of findings.

A breakdown of the costs and labor hours for 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 with 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 h ourly 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 for 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.

the facility to estimate the concentr ation of supercritical or gaseous CO 2 for comparison to RCRA toxicity
characteristic standards. Formatted Table

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### Exhibit A-6: Option 1 Cost and Labor Estimate

Option 1: CO2 stream is tested at point of generation as a gas, after some treatment

Cost Cate g or y Ran g e 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

Inter p retation 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

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### Exhibit A-7: Option 2 Cost and Labor Estimate

Option 2: CO2 stream is tested at point of use as a supercritical fluid or liquid under high pressure

Cost Cate g or y Ran g e 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

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Senior Level Chemist Chem 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

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### Exhibit A-8: Option 3 Cost and Labor Estimate

Option 3: CO 2 is tested at point of generation as gas, but only for selected compounds. Use process knowledge to characterize waste

Cost Cate g or y Ran g e 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

Inter p retation 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

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### Exhibit A-9: Option 4 Cost and Labor Estimate

Option 4: CO2 stream is tested at point of injection as supercritical 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

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### 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 three major capture technology systems and associated treatment options. Secti on 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 absorbent 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 regeneration vessel (or stripper) through a heat exchanger. Under a higher atmosp heric pressure and temperatures (ranging
from 100 to 140 o 

### C 74 

### ), 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. 75 

### The CO 2 

### is then cooled, dried, and compressed to a supercritical fluid or liquid under high pressure state

, at which point it can be stored geologically or used commercially. The regenerated ‘lean’ solvent is cooled and pumped back to the absorption tower through a heat exchanger to be reused in the process. 76 

### Amine scrubbing system is currently a proven technology and it is capable of removing
between 80% and 95% CO 2 

### from a flue gas stream. However, acid gases such as NO
x 

### and SO
x 

### must be removed from the flue gas prior to passing through the absorber

tower. 77



### • Oxy-fuel combustion is a process in which high purity oxygen is substituted for air during combustion in a pulverized coal plant, to produce an extremely concentrated
stream of CO 2 

### that is easily compressed and delivered by pipeline for storage. The process involves the recirculation of flue gas to maintain similar mass-flow and lower temperatures in the boiler. The raw flue gas consists of water vapour and CO 2 

### , which is then dehydrated and purified. The nearly pure CO 2 

### stream is then compressed for transportation and storage. 78

74 Note that these temperatures are applicable for the amine solvents.

75 Center for Energy and Economic Development. Carbon Capture . 2007.

76 Center for Energy and Economic Development. Carbon Capture . 2007.

77 NO

x and SO

x reacts with the amine and will result in a reduction in solvent performance, higher chemical consumption, and poor economic performance.

78 Alstom, Oxyfuel combustion capture

.

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### • 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 feedstock) 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 order to remove the carbon, 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. Typically, sulfur, in the form of H 2 

### S

, (hydrogen sulfide), is not removed during gas treatment stage, but rather removed in the CO 2 

### removal stage using a two-stage Selexol 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-combustion 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-combustion 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 either installing or not installing a flue gas desulfurizer (FGD) in which the SO
x 

### from a flue gas can be taken out. With a 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 without 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 NO x 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. 79



### • 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 facilit ies (which is typically used to convert

H 2 

### S into elemental sulfur). The cost of a single stage selexol unit is lower than a two stage unit, in addition the cost of the sulfur processing unit is eliminated.

79 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.

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### B.2 Treatment Costs

Cost estimates for the addition of an FGD for 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 NETL, 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 Weight 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 Price of coal Coal $/MMBtu $ 1.80

The cost estimates have an accuracy of +/-30%, consistent with a screening study, and the year of construction of the plant 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. 80 

### The total plant cost includes the cost of following (NETL, 2007):

• Equipment (complete with initial ch emical 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. 81

80 Table 1.1.9 in NIPA Section 1, published by Bur eau of Economic Analysis, published July 30, 2010.

81 Costs do not account for environmental permitting costs. It is assumed that treatment can be conducted under existing facility permits, including under the provision s for onsite hazardous waste treatment by hazardous waste large quantity generators under 40 CFR 260.10

, and related provisions. Formatted Table

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### 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 Systems:

The economic analysis for the oxyfuel system was based on Case 5 of the NETL, 2008 report. Case 5 is a supercritical pulverized oxyfuel plant, 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 Technical Support Document for EPA’s Transport
Rule. 82 

### 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 fr om the Case 5 numbers to derive the cost of the plant without an FGD.

It was assumed that the same amount of fuel and oxidant would be used in this case, and the only change was the removal of the FGD. Re duction 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 reagent preparation, FGD pumps and agitators, and 2 MW of power associated with induced fans for the FGD. 83



### Exhibit B-2 below shows the key assumptions and 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 was calculated using the numbers in Exhibit B-1 and the formulation given in section 2.9.2 of NETL, 2008.

82 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).

83 See Table 5-8 of NETL, 2008. Formatted: Font: Arial

Formatted: Normal, Don't keep with next

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### Exhibit B-2: Summary of Assumptions 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 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. 02 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 calculated 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. 84 

### The differential in fixed cost was assumed to be same in the

84 See Exhibit 3-46, account 5A of NETL, 2007 report. Formatted Table Formatted: Font: 11 pt, Bold

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Merged Cells

Formatted: Centered

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Formatted: Subscript

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### oxyfuel system multiplied by the 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 and 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. 85 

### The difference between the two options was about 15 MW.

Exhibit B-3: Assumptions and Summary 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 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

85 See Exhibit 3-34 of NETL, 2007 report. Formatted Table Formatted: Font: 11 pt, Bold

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### Appendix C.

Sensitivity Analyses

This appendix considers the costs and savings under two sets of assumptions that diffe r from the assumptions made in the main analysis. The first sensitivity analysis considers a smaller
number of affected facilities than the main analysis . The second sensitivity analysis makes different assumptions regarding the hazardous characteristics of captured CO 2 

### streams in the
baseline.

Sensitivity Analysis 1

– Fewer Affected Facilities

The main analysis in this document consider s the impacts of the proposed rule on both existing CO 2 

### capture and sequestration projects and several planned project s that do not yet
exist . This sensitivity analysis assumes that only facilities associated with existing capture and sequestration projects and projects associated with named DOE pilot projects and federal/private partnerships will be affected by the propo sed rule. All other assumptions are consistent with the main analysis.

This sensitivity analysis considers only 1 3 capture facilities:

• 10 existing capture facilities,

• 2 capture projects associated with named DOE pilot projects, and

• 1 capture facility a ssociated with the FutureGen federal/private partnerships.

This sensitivity analysis considers only 6 sequestration facilities:

• 5 sequestration projects associated with named DOE pilot projects, and

• 1 sequestration facility associated with the FutureGen f ederal/ private partnerships.

Exhibit C

- 1 presents the number of CO 2 

### capture and sequestration faci lities expected to begin sequestration activities in each year under the proposed rule.

Exhibit C

- 1: CO 2 

### Capture and Sequestration Facilities Assumed to Begin and Practice Sequestration Activities by Year Under Sensitivity Analysis 1

Year Number of CO 2 Facilities Beginning Sequestration of their
CO 2 Streams Total Number of CO 2 Facilities Practicing Sequestration of their
CO 2 Streams Number of Sequestrati on Facilities Beginning Operation Total Number of Sequestration
Facilities in Operation
2010

- 2012 2 2 0 0

2013 0 2 0 0

2014 0 2 0 0
2015 0 2 0 0

2016 0 2 0 0

2017 1 3 6 6

2018 0 3 0 6
2019 0 3 0 6

2020 0 3 0 6 Comment [LL59]: Identified changes made in response to OMB review.(Appendix C omitted and restructured within the document)

Comment [LL60]:

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Year Number of CO 2 Facilities Beginning Sequestration of their
CO 2 Streams Total Number of CO 2 Facilities Practicing Sequestration of their
CO 2 Streams Number of Sequestrati on Facilities Beginning Operation Total Number of Sequestration
Facilities in Operation
2021 0 3 0 6

2022 0 3 0 6

2023 0 3 0 6

2024 0 3 0 6
2025 0 3 0 6

2026 0 3 0 6

2027 0 3 0 6

2028 0 3 0 6
2029 0 3 0 6

2030 9 12 0 6

2031 0 12 0 6

2032 0 12 0 6

2033 0 12 0 6

2034 1 13 0 6
2035 0 13 0 6

2036 0 13 0 6

Post

- 2036 0 13 0 6

Total 13 13 6 6



### Exhibit C

- 2 summarize s the undiscounted 50

- year and annualized costs and benefits of the proposed rule under the assumptions of this sensitivity analysis. Exhibits C

- 3 and C

- 4
summarize the 50

- year and annualized costs and benefits applying 3 percent and 7 percent
discount ra tes respectively. Because this sensitivity analysis considers fewer affected facilities than the main analysis, the expected net savings are lower. Under the assumptions of this sensitivity analysis, t he proposed rule is expected to result in undiscounte d average net savings of approximately $ 3 0 .0 million. Applying a 3 percent discount rate, the annualized net savings are approximately $ 2 4

. 7 million. Applying a 7 percent discount rate, the annualized net savings are approximately $ 18 .7 million.

Exhibi t C

- 2: Undiscounted Net Costs and Savings of the Proposed Rule Under Sensitivity Analysis 1 (2010 dollars)

Type of Entity 50

- year Costs 50

- year Savings 50

- year Net Savings Average Net Savings Capture Facilities $81,765 $1,502,025,667 $1,501,943,902 $30 ,038,878 Sequestration Facilities $47,322 $690,052 $642,730 $12,855

State Governments $12,444 $0 ($12,444) ($249)

EPA $1,504 $0 ($1,504) ($30)

Total $143,035 $1,502,715,719 $1,502,572,684 $30,051,454

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### Exhibit C

- 3: Net Costs and Savi ngs of the Proposed Rule Under Sensitivity Analysis 1

– 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 $35,353 $ 653,373,965 $653,338,612 $24,652,746 Sequestration
Facilities $23,345 $344,138 $320,793 $12,105

State Governments $5,779 $0 ($5,779) ($218)

EPA $580 $0 ($580) ($22)

Total $65,057 $653,718,103 $653,653,046 $24,664,611



### Exhibit C

- 4: Net Costs and Savings of the Proposed Rule Under Sensitivity Analysis 1

– 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 Facili ties $14,644 $275,492,457 $275,477,813 $18,655,216 Sequestration
Facilities $11,471 $172,014 $160,543 $10,872

State Governments $2,656 $0 ($2,656) ($180)

EPA $188 $0 ($188) ($13)

Total $28,958 $275,664,470 $275,635,512 $18,665,895



### Sen sitivity Analysis 2

– 90 Percent of CO 2 

### Capture Facilities Generate Streams are Non

hazardous in the Baseline

The main analysis in this document conservatively assume s that, in the baseline, 90 percent
of CO 2 

### capture facilities generate streams that are h azardous in the baseline. This sensitivity analysis makes the opposite assumption

– that 90 percent of CO 2 

### capture facilities generate
streams that are non

- hazardous in the baseline. Consequently, this sensitivity analysis assumes a different prevalence of baseline practices by CO 2 

### capture and sequestration facilities. All other assumptions are consistent with the main analysis. Exhibit s C

- 5 present s the assumptions of this sensitivity analysis re garding the relative prev alence of each baseline practice in the absence of the proposed rule for CO 2 

### capture facilities.

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### Exhibit C

- 5: Assumed Prevalence of Hazardous Waste Determination and Baseline
Practices for CO 2 

### Capture Facilities

Hazardous Waste

Determination Baseline Practice Assumed Baselin e Percentage of Capture
Facilities

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 %

Corresponding to the baseline practic es of capture facilities, this sensitivity analysis assumes that, in the baseline, approximately 97 percent of the sequestration facilities would mana ge untreated and treated non

- hazardous CO 2 

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

### streams as Class I hazardous waste wells. 86



### Exhibit C

- 6 summarizes the undiscounted 50

- year and annualized costs and benefit s of the proposed rule under the assumptions of this sensitivity analysis. Exhibit s C

- 7 and C

- 8
summarize the 50

- year and annualized costs and benefits applying 3 percent and 7 percent discount rates respectively. The savings associated with the proposed rule are lower for facilities that generate non

- hazardous waste in the baseline than for facilities that generate hazardous waste in the baseline. Therefore, the expected savings under the assumptions of this sensitivity analysis are significantly lower than under the main analysis. Under the assumptions of this sensitivity analysis, the proposed rule is expected to result in
undiscounted average net savings of approximately $ 9.3 million. Applying a 3 percent discount rate, the annualized net savings ar e approximately $ 8.5 million. Applying a 7 percent discount rate, the annualized net savings are approximately $ 7.3 million.

86 This sensitivity analysis a ssumes that 93 percent of CO 2 capture facilities would transport non

- hazardous or
treated CO 2 streams to Class VI sequestration wells for injection. Another 3.3 percent of CO 2 capture facilities would transport hazardous CO 2 streams to Class I sequestration wells for injection. Under this assumption, 93 out of 97 (97 percent) of CO 2 capture facilities i njecting into a sequestration well transport their waste to Class VI wells. The analysis assumes that 97 percent of CO 2 sequestration wells are Class VI wells to match the practices of CO 2 capture facilities.

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### Exhibit C

- 6: Undiscounted Net Costs and Savings of the Proposed Rule Under Sensitivity Analysis 2 (2010 dollars)

Type of Entity 50

- year Costs 50

- year Savings 50

- year Net Savings Average 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 C

- 7: Net Costs and Savings of the Proposed Rule Under Sensitivity Analysis 2

– 3%
Discount Rate (2010 dollars)

Type of Entity Present Value
of 50

- ye ar

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 $1 4,947 $0 ($14,947) ($564)

EPA $1,498 $0 ($1,498) ($57)

Total $179,280 $226,108,872 $225,929,592 $8,525,112



### Exhibit C

- 8: Net Costs and Savings of the Proposed Rule Under Sensitivity Analysis 2

– 7% Discount Rate (2010 dollars)

T yp e of Entit y Pr esent Value
of 50

- year

Costs Present Value
of 50

- year

Savin g s Present Value of 50

- y ear Net Savin g s Annualized
Net Savin g s 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 Formatted: Font: Bold

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### Appendix D.

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### Appendix C

Assessment of Environmental Justice Impacts

D C .1 Introduction

Executive Order 12898 (59 FR 7629, February 16, 1994) establishes Federal executive policy on environmental justice. It applies to agen cy “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 such as EPA to identify and address 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 poten tial EJ impacts associated with the proposed RCRA conditional exclusion at 40 CFR 261.4(h). Section D C .2 provides background on the proposed rule. Section D C .3 presents a comparison of the federal regulations applicable to generators of hazardous waste CO 2 

### , pipelines, and geological sequestration (GS) facilities operating under the baseline requirements and proposed RCRA exclusion. The comparison identifies key regulatory differences. Section D C .4 presents a screening analysis of EJ impacts associated with generators and GS f acilities that might claim the exclusion. The screening analysis examines indicators (e.g., inco me, race, age) of populations living within a 1- and 3-mile radius of the facilities, to identify vulnerable populations. Section D C .5 presents a qualitative screening assessment of po tential EJ impacts associated with pipelines that might be used to transport CO 2 

### under the proposed rule. 87 

### Section D C .6 summarizes the conclusions of these analyses and identifies possible next steps.

D C .2 Background on Proposed Rule

EPA is proposing a conditional exclusion fro m the definition of hazardous waste for carbon dioxide (CO 2 

### ) streams that are captured, transported, and injected into a well subject to the requirements for Class VI U nderground Injection 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 wastes that are mixed with, or are otherwise co-injected with, CO 2 

### streams. The exclusion would is expected to be codified at 40 CFR 261.4(h).

87 EPA did not conduct a quantitative, pipeline-specific screening analysis. Refer to Section 4.5 for EPA’s reasons for conducting a qualitative analysis.

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### There are three primary types of facilities that would be a ffected by EPA’s proposed action:

• Generators (i.e., capture facilities). 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. EPA estimates that 27 facilities might 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 generator under the proposal. These facilitie s include planned or existing fossil-fuel burning utilities, gas and fertilizer pl ants, and DOE projects. This waste CO 2 

### would qualify as a RCRA hazardous waste if it exhibits any of the RCRA hazardous
characteristics.

• Pipelines. Captured CO 2 

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

### pipelines, operated by 29 separate entities. 88



### • Geological Sequestration ( GS ) Facilities. For this EJ assessment EPA estimates that is applying the high-end estimate of 29 geological sequestration facilities might may claim the exclusion. Geological sequestration (GS) 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



### .

D 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 (GS) facilities operating under the baseline requirements and proposed RCR A exclusion. The design and function of the regulatory comparison in this chapter is mean t to help facilitate an initial appraisal of regulatory requirements for th e environmental justice analysis. This comparison is not intended to represent conclusions about risk but instead broadly indentify areas where regulatory requirements appear 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-hazardous under RCRA.

EPA developed Exhibit D C -1 for purposes of comparing thes e 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

88 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

.

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### regulatory program. 89 

### Column 2 presents the proposed rule’s conditions and other federal regulations applicable to generators, pipelines and GS facilities operating under the proposed rule. Column 3 briefly compares these regula tions 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 th e 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 reporting and recordkeeping, emergency preparedness and response, and waste treatment. Generators under the proposed conditional exclusion, for example, would not be required to report to EPA under RCRA (there may be other applicable repo rting requirements under other regulatory programs not discussed here), except if requested. Generators under the baseline are required to notify initially and 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 federal 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 baseline and proposed rule. Pipeline transport covered by
DOT is generally not subject to RCRA regulation.

• 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 federal regulation of GS facilities operating under the baseline (i.e., facilities subject 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 quality and potentially other environmental media. Note, however, that for this analysis EPA assu mes 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 Cla ss VI UIC well requirements. There is no regulatory requirement, however, that permit writers apply the Class VI requirements
to Class I hazardous waste wells.

89 Column 1 presents hazardous waste regulations applicable to large quantity generators only.

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Page 116 of 167 Formatted: Tab stops: 5", LeftExhibitDC-1. Comparison of Federal Regulations Applicable to Facilities and Pipelines Operating Under the Baseline and Proposed RuleFederal 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 doesnot 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 sourcethat 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 hazardous substance equal to or exceeding its reportablequantity in any 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 1910.119b***E.O. 12866 Review–Draft–Do Not Cite, Quote, or Release During Review***Page118of167Formatted:Tab stops: 5", LeftFederal Regulations Applicable to Facilities andPipelines Operating under the BaselineFederal Regulations Applicable to Facilities andPipelines Operating under the Proposed RuleCommentsOSH Act (Hazardous Waste Operations and 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 the facility), such asdesignated response employees, as required by 29 CFR1910.120(q). If thefacility 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/or other chemicals thatare CERCLA hazardous substances.However, these substances must be present insufficient quantities to trigger the specifiedregulatory quantity. For example, thethreshold quantity forhydrogen 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 which they 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 wastes are exempt from theseprovisionsWaste TreatmentRCRA Regulations•Hazardous waste must be treated 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, as do 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 orcarbon dioxide associated 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 Facilities***E.O. 12866 Review–Draft–Do Not Cite, Quote, or Release During Review***Page119of167Formatted:Tab stops: 5", LeftFederal Regulations Applicable to Facilities andPipelines Operating under the BaselineFederal Regulations Applicable to Facilities andPipelines Operating under the Proposed RuleCommentsRCRA RegulationsClass I injection wells disposing of hazardous waste arepermitted 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 applicableClass VI UIC wells disposing of exempt CO2mustmeet 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 requestedThe baseline regulations establish a permitby-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 wastes that 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***E.O. 12866 Review–Draft–Do Not Cite, Quote, or Release During Review***Page120of167Formatted:Tab stops: 5", LeftFederal Regulations Applicable to Facilities andPipelines Operating under the BaselineFederal Regulations Applicable to Facilities andPipelines Operating under the Proposed RuleComments•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 radiusto 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 regulations applicable to large quantity generators only.bA carbon dioxide stream may contain hydrogen sulfide, mercury, and/or other chemicals that 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.***E.O. 12866 Review–Draft–Do Not Cite, Quote, or Release During Review***Page121of167Formatted:Tab stops: 5", LeftcEPA 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 VIrequirements to Class I wells.

### D C .4 Screening Analysis of Capture and Geologic Sequestration ( GS ) Facilities

This section presents an EJ screening analysis of carbon capture and GS facilities with known locations that might claim the exclusion. Si milar to the regulatory comparison found in D C .3, the screening analysis of capture and GS facilities is not an assessment of risk. Instead, the analysis uses demographic information to identify communities of concern.

. The next two sections describe the methodology and results.

D C .4.1 Methodology

EPA took the following steps to complete the analysis:

1. Ascertained the location of planned, major commercial (non-DOE) and FutureGen capture facilities, existing cap ture facilities, and DOE and FutureGen GS projects that may claim the exclusion. Please note the following:

• EPA estimates that , at a maximum, 27 capture facilities may claim the exclusion, including 14 planned ma jor commercial facilities, one FutureGen facility, 10 existing fert ilizer and gas facilities, and two DOE sequestration projects. These facilities , plus four additional major DOE sequestration projects are included in this screening analysis.

Appendix D 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 these facilities and surrounding residential populations to identify vulnerable populations based on demographic and other indicator data. EPA performed the analysis using Geographic Information System (GIS) mapping tools. This anal ysis involved the following activities:

• Identified indicators to include in the analysis: percent minority (e.g., indigenous populations), percent below 150% of poverty level, and percent 0-4 years and 65+ years within a 1- and 3-mile radius. 90 

### In addition, two other indicators were evaluated:

- Whether the 1- and 3-mile radius of each facility bisects Tribal land; and

- The number of environmentally regulated 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 Regist ry System (FRS), which is a

90 The one and three mile radii are applied to be consiste nt with prior ORCR environmental justice demographics analyses. Comment [LL61]: Identified changes made in response to OMB review.

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### centrally managed database, to ascertain the lo cation of these
sites. 91 

### This indicator is meant to clarify the proximity and incidence of potential existing pollution sources to which populations may be exposed.

• Located each facility using latitude and longitude and quantified the incidence of each indicator within 1- and 3-mile radii. EPA performed the analysis using 2010 Census Estimate data obtained from GeoLytics Inc. GeoLytics is a company that publishes detailed census, demographic and geographic data as well as estimates 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 data at the local level.

• Compared the percentage of each indicator 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 used to determine the incidence of each indicator within that portion of the Block Group encompassed by the radius. In addition, EPA found that some 1- and 3- mile radii fell within two states (i.e., for facilities near state borders). In this case, proportional overlay tools were used to determine the incidence of each indicator within that portion of the radius fa lling in each respective state, calculate its percentage within the state’s portion of the radius (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 D C .B. A summary of the data is presented in Section D C .4.2.

D C .4.2 Results

Exhibits D C -2 and D C -3 summarize the results of the screening analysis. Exhibit D C -2 presents the results of the analysis of indicators with in a 1-mile radius of facilities and Exhibit D C -3 presents the results for the analysis of indicators within a 3-mile radi us of facilities. Each exhibit lists the facilities alphabetically, indicates its type (e.g., commercial capture), and uses an “X” to

91 The FRS has over 1.5 million unique facility records related to such systems as the Toxic Release Inventory (TRI), Resource Conservation and Recovery Act Inform ation System (RCRAInfo), Aerometric Information Retrieval System (AIRS)/AIRS Facility Subsystem, a nd Comprehensive Environmental Response, Compensation, and Liability Information System (CERCLIS). For additional information, refer to http://www.epa.gov/enviro/html/.

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### 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., populations living below 150% of the poverty level) exceed the state percentage, as these may be among the most vulnerable populations 92



### . . 93



### Exhibit D C -2 shows the following in re gard to population characteris tics within a 1-mile radius
of the facilities:

• 21 of the 31 GS and capture facilities exam ined (68%) have populations within a 1-mile radius that exceed their respective state’s percentage of minority populations and/or populations below 150% of the 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 state’s percentage of minority populations and populations below 150% of the poverty level. 94 

### These facilities include:

- Coffeyville Fertilizer Plant;

- Kemper County Plant; and

- Lima Plant.

Each of these 3 facilities has populations within a 1-mile radius with children 0 to 4 years and/or adults 65 years and older in percentages that exceed their respective state’s percentages.

Each of these 3 facilities has at least one existing FRS site 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.

92 This analysis focuses on selected demographics surroundi ng 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 facilit ies. Our experience with deep well injection 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 Wastew ater in South Florida,” April 2003.

93 This analysis focuses on selected demographics surrou nding 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 injection 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.

94 These 3 facilities are a subset of the 21 facilities noted above. Comment [LL62]: Identified changes made in response to OMB review.

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### • 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 facilities 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 located within their 1-mile radius.

• No facility’s 1-mile radius bisects Tribal land.

Exhibit D C -3 shows the following in re gard to population characteris tics within a 3-mile radius
of the facilities:

• 20 of the 31 GS and capture facilities exam ined (65%) have populations within a 3-mile radius that exceed their respective state’s percentage of minority populations and/or populations below 150% of the 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 state’s percentage of minority populations and populations below 150% of the poverty level. 95 

### These facilities include:

- Coffeyville Fertilizer Plant;

- Kemper County Plant;

- Lima Plant; and

- San Joaquin Basin Project, CA Saline Formation.

Each of these 4 facilities has populations within a 3-mile radius with children 0 to 4 years and/or adults 65 years and older 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 Basin 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-

95 These 4 facilities are a subset of the 20 facilities noted above.

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### mile radius, 5 facilities have 3 sites locat ed within their 3-mile radius, and 16
facilities have 4 or more sites located within their 3-mile radius.

• No facility’s 3-mile radius bisects Tribal land.

Refer to Appendix D C .B. for detailed data on the incidence of the indicators within a 1- and 3-
mile radius of the facilities.

Exhibit D C -2. Characteristics of Populations wi thin 1-Mile Radius 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

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### 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

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

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 identify 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 stat es. The population within the 1-mile radius was allocated proportionally to the two states (i.e., creating two mutually exclusive population groups, one for each state), as described in the methodology. The indicator in this exhibit has an as terisk to indicate that one of the population groups for this facility exceeded its respective state average, while the other population group did not.

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### Exhibit D C -3. Characteristics of Populations wi thin 3-Mile Radius 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

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### 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 identify 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 stat es. The population within the 3-mile radius was allocated proportionally to the two states (i.e., creating two mutually exclus ive population groups, one for each state), as described in the methodology. The indicator in this exhibit has an as terisk to indicate that one of the population groups for this facility exceeded its respective state’s averag e, while the other population group did not.



### D C .5 Qualitative Screening Analysis of Pipelines

This section presents a qualitative screening anal ysis of EJ issues associated with pipelines carrying carbon dioxide (CO 2 

### ) under the proposed RCRA conditional exclusion. The analysis provides a preliminary characterization of potential health impacts to human populations near the pipelines. Section D C .5.1 of this document provides background information about the existing hazardous waste regulations (i.e., the “baseline”) and proposed rule that would exempt CO 2 

### streams from RCRA regulation. Section D C .5.2 describes the likelihood of CO 2 

### pipeline failures
that could lead to a release. Section D C .5.3 describes some of the possible health impacts to

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### surrounding populations from a CO 2 

### pipeline release. Section D C .5.4 sets forth some preliminary conclusions about CO 2 

### releases from pipelines.

The primary data source used in this qualita tive analysis is the document, “Final Risk Assessment Report for the FutureGen Project En vironmental Impact Statement,” dated October
2007. 96, 97 

### The Risk Assessment addresses the pote ntial releases of captured gases at the proposed FutureGen power plant, during transportation via pipeline to the geological
sequestrat ion (GS) GS facility, and during subsurface storage. The Risk Assessment was prepared under contract to the U.S. Department of Energy (DOE) and revised in response to comments received during DOE’s review, from the public hearings on FutureGen’s Draft Environmental Impact Statement (EIS), and fr om 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, pipeline-specific analysis of EJ issues 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 would be used to transport CO 2 

### streams under the baseline and proposed rule by capture facilities that now are being planned. In addition, new pipelines may be built to transport CO 2 

### streams from capture facilities to distribution pipelines and wells and the location of these new pipelines 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.

D 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 applicable UIC and RCRA requirements.

A CO 2 

### stream generator under the baseline may have several options for addressing 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 would be prohibited. Alternatively, a CO 2 

### stream

96 This document can be found at the following web site: http://www.netl.doe.gov/technologies/coalpower/futur egen/EIS/FG%20Risk%20Assessment%20110807.pdf.

97 FutureGen is a public-private partnership to build a first- of-its-kind coal-fueled power plant. It will generate electricity while capturing and injecting CO 2 into geological sequestration (GS) facilities.

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### 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 th at meets applicable no-migration requirements
under 40 CFR Part 148.

Pipeline transport of CO 2 

### streams is subject to Department of Transportation (DOT) regulation. For example, 49 CFR Part 195 applies to pipeline facilities and the transportation of hazardous liquids or carbon dioxide associat ed 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 control 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. Conseq uently, generators claiming the exclusion could transport and dispose of their CO 2 

### streams as non-hazardous waste in Class VI UIC wells. Captured CO 2 

### streams would not be classified as h azardous waste under the 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 regulatory requirements for transport of CO 2 

### streams would not be affected by the exclusion.

D C .5.2 Risks of Pipeline Failure

The FutureGen Risk Assessment presents data concerning 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. 98 

### According to the Risk Assessment, rupture and puncture failure frequencies were calculated to be 5.92 x 10 -5 

### /(kilometer-year) and
1.18 x 10 -4 

### /(kilometer-year), respectively. 99



### The Risk Assessment based its incident probability 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 indi cated 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).

98 See page 6-14 of the FutureGen Risk Assessment.

99 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 believes has determined that this is an error in converting between mile-year and kilometer-year. EPA used the risk values expr essed in kilometer-year in preparing Figures 1 and 2.

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### Based on the Risk Assessment data and formulas, Figure 1 Exhibit C-4 shows the probability of at least one pipeline rupture over a 50 year period, given three different pipeline lengths. Exhibit

D

- 4 C-5 shows the probability of at least one pipeline puncture over a 50 year period, given three different pipeline lengths. For example, Figure 1 Exhibit C-4 shows that, over a 50 year period, there is an estimated 35% probability of a pipeline rupture in a 150 kilometer pipeline and
Exhibit D C -5 shows that, over a 50 year period, there is an estimated 60% probability of a pipeline puncture in a 150 kilometer pipeline. 100



### Exhibit D 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 D C -5. Probability of CO 2 

### Pipeline Puncture over 50 Year Period: 50-, 100- and 150-Mile Pipelines a

100 The Risk Assessment identifies some data gaps and li mitations 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. Formatted: Font: Italic

Formatted: Font: Italic

Formatted: Underline

Formatted: Underline

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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).



### D 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. 101 

### 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 length of the pipeline at each site being examined. The five main steps in this approach involved the following:

• Step 1. Summarize meteorological cond itions that affect plume transport;

• Step 2. Simulate the area potentially affected by a pipeline release;

• Step 3. Estimate population affect ed for each atmospheric state;

• Step 4. Determine the expected number of indi viduals potentially aff ected at the specified release points; and

• Step 5. Characterize the potential exposure along the entire pipeline.

As explained by the Risk Assessment, the results of the “pipeline-walk” analyses indicated no predicted potential health effects from CO 2 

### releases due to pipeline ruptures or punctures at any
of the four candidate sites. This is shown in Exhibit D

- 4 C-6 . In all cases, the expected number
of individuals affected is less than one.

Exhibit D C -6 shows that the largest number of people potentially affected by H 2 

### S releases is associated with pipeline ruptures. The model simu lations 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 potential for adverse effects from H 2 

### S exposure are predicted for pipeline ruptures at the Tuscola Site for 7. 4 individuals. Fewer num bers of individuals at both sites are predicted to be affected by a pipeline puncture. The maximum number of expected individuals experiencing adverse 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 expected to experience irreversible-adverse or life threatening effects fo r the Jewett pipeline is one. No adverse or lifethreatening effects are predicted for H 2 

### S releases from pipeline ruptures or punctures at the
Odessa and Mattoon sites.

101 The SLAB model was developed by the Lawrence Li vermore 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 hazardous air dispersion model.

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### Exhibit D C -6: Summary of Expected Numbers of Individuals from the Public Affected by Pipeline Releases a 

### Mattoon,
IL Tuscola,
IL Jewett,
TX Odessa,
TX (A) 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 (B) 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 “F inal Risk Assessment Report for the FutureGen Project Environmental Impact Statement,” dated October 2007 (see page 6-8).

The Risk Assessment concludes that “these resu lts indicate that the po tential human-health effects due to pipeline ruptures or punctures at al l sites are minimal. 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 predicted exposures can be avoided since the adverse-effects-level H 2 

### S concentration (0.51 ppmv) is associated with the perception of an objectionable odor. Likewise, Formatted: Centered

Formatted: Centered

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### the life threatening effects of H 2 

### S exposures are associated with long exposure levels that can be
detected and avoided.” 102



### D C .5.4 Preliminary Conclusion s 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, pursuant to EPA’s UIC amendments, injection of RCRA
hazardous waste into a Class VI UIC well wo uld be prohibited. Treatment of the CO 2 

### would reduce the presence of metals and other harmfu l constituents (e.g., hydrogen sulfide) as appropriate to render it non-hazardous. 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 generator and UIC well owner/operator claim the exclusion and comply with its conditions. No treatment would be requir ed 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 proposed 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 generators 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 propos ed rule for transport via pipeline to Class VI
UIC wells.

The Risk Assessment concludes that its results indicate that the potential human-health effects due to pipeline ruptures or punctures at all sites under examination are minimal. The primary predicted effect identified in the ‘pipeline-walk’ analysis in the event of a release is mild transient health effects. It also indicates that the potential for human exposure to hazardous
constituents from accidental releases from CO 2 

### pipelines is related to several factors, 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 associated with a higher potential for exposures of hazar dous constituents to surrounding populations, although the health effects appear to be mild.

D C .6 Summary Chapter: Results of Analyses and Possible Next Steps

D C .6.1 Comparative Analysis

Results

The comparative analysis identified the following potential regulatory differences:

102 See page 6-7 of the FutureGen Risk Assessment.

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### • Generators operating under the proposed conditional exclusion would generally be subject to less stringent regulation than gene rators operating under the baseline in regard to RCRA reporting and recordkeeping, emergency preparedness and response, and waste

treatment.

• Pipelines carrying CO 2 

### streams managed under the proposed conditional exclusion would be subject to the same federal regulations as pipelines carrying CO 2 

### streams managed under the baseline. In particular, pipeline transport of CO 2 

### would be subject to DOT regulation under both the baseline and proposed rule. Pipeline transport is not subject to RCRA regulation.

• GS facilities operating under the proposed conditiona l exclusion (i.e., facilities subject to Class VI UIC requirements) would be subject to federal regulation that would be comparable to, and in certain cases more stri ngent than, federal regulation of GS facilities operating under the baseline (i.e., facilities s ubject to Class I UIC requirements). For example, GS facilities operating under the proposed rule would be subject to additional and more stringent requirements related to siting, determining the area of review, monitoring of groundwater quality and other environmental media. Note, however, that EPA anticipates that a Class I hazardous we ll used for injection of hazardous waste CO 2 

### streams under the baseline would also be require d by the permit writers to meet the Class VI UIC well requirements. There is no regulatory requirement, however, that permit writers apply the Class VI requirements 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 compared. 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 relevant federal regulations.

D 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 exam ined (68%) have populations within a 1-mile radius that exceed their respective 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 that exceed their respective state’s percentage of minority populations and populations below 150% of the poverty level. These facilities include:

- Coffeyville Fertilizer Plant (capture facility);

- Kemper County Plant (capture facility); and

- Lima Plant (capture facility).

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### Each of these 3 facilities has populations within a 1-mile radius with children 0 to 4 years and/or adults 65 years and older in percentages that exceed their respective state’s percentages. In addition, each has at least one existing FRS site 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.

• 20 of the 31 GS and capture facilities exam ined (65%) have populations within a 3-mile radius that exceed their respective state’s percentage of minority populations and/or populations below 150% of the poverty level. They are shaded in gray in the exhibit. Of thes e 20 facilities, 4 have populations within a 3-mile radius that exceed their respective state’s percentage of minority populations and populations below 150% of the poverty level. These facilities
include:

- Coffeyville Fertilizer Plant (capture facility);

- Kemper County Plant (capture facility);

- Lima Plant (capture facility); and

- San Joaquin Basin Project, CA Saline Formation (GS Facility).

Each of these 4 facilities has populations within a 3-mile radius with children 0 to 4 years and/or adults 65 years and older in percentages that exceed their respective state’s percentages. In addition, each 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 Basin Project has 3
sites within a 3-mile radius.

Possible Next Steps

Additional research could be performed to learn more about the particular characteristics of the populations identified in this screening analysis. This in formation could help EPA better understand the potential vulnerabilitie s and concerns of these populations.

In addition, it is important to note that the sc reening analysis was 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

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### 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, pursuant to EPA’s UIC amendments, injection of RCRA
hazardous waste into a Class VI UIC well wo uld be prohibited. Treatment of the CO 2 

### would reduce the presence of metals and other harmfu l constituents (e.g., hydrogen sulfide) as appropriate to render it non-hazardous. 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 generator and UIC well owner/operator claim the exclusion and comply with its conditions. No treatment would be requir ed 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 proposed 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 punctures at all four sites under examination are minimal. The primary predicted effect in the event of a release is mild
transient health effects.

It also indicates that the poten tial for human exposure 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 gr eater quantity of untreated CO 2 

### streams being transported by pipeline under the proposed rule could potentially be associated with a higher potential for exposures of hazardous constituents to surroun ding populations, althoug h 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 D C .A. – Facilities Included in the Environmental Screening Analysis

The facilities in Exhibits D C .A-1 through D C .A-3 are included in the EJ screening analysis presented in Chapter 4 of this document

.

Exhibit D 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 WV 38/58/44 81/56/20

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### (Ph.2)
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 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

Exhibit D 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

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### Great Plains Coal Gasification ND 47/21/4
8 101/49/54

Exhibit D 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 Saline a 

### OH 38/54/1
3 84/50/56 San Joaquin Basin, CA
Saline Formation Formation a 

### CA 36/33/4
9 119/12/19

Mt. Simon Saline Reservoir IL 39/29/4
9 88/26/26

.

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### Appendix D

a Information received after the completion of this analysis indicates that these facilities are not expected to move
forward. Comment [LL63]: Identified changes made in response to OMB review.

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### Appendix C .B. Characteristics of Populations Within 1- and 3-Mile Radius of Facilities: Detailed Exhibits Supporting the Environmental Justice Screening Analyses

This appendix presents detailed results of the environmental justice screening analysis presented in Chapter 4 of this document.

. 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 D C .B-1. Percentage of Population that is Minority (by Race and in Total) Within 1-Mile Radius of Facility

• Exhibit D C .B-2. Percentage of Population that is Below150% of Poverty Level Within 1- Mile Radius of Facility

• Exhibit D C .B-3. Percentage of Population 0 to 4 Years and 65+ Years Within 1-Mile Radius of Facility

• Exhibit D C .B-4. Number of FRS Sites With in 1-Mile Radius of Facility

• Exhibit D C .B-5. Percentage of Population that is Minority (by Race and in Total) Within 3-Mile Radius of Facility

• Exhibit D C .B-6. Percentage of Population that is Below150% of Poverty Level Within 3- Mile Radius of Facility

• Exhibit D C .B-7. Percentage of Population 0 to 4 Years and 65+ Years Within 3-Mile Radius of Facility

• Exhibit D C .B-8. Number of FRS Sites With in 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 facility’s state locatio n and indicators. If the facility is located in two states, information is provided on both stat es and respective indicator s in each state. In addition, the exhibits use a gray highlight to iden tify indicators whose percentage within the 1- or 3-mile radius of the facility exceeds the state’s percentage.ExhibitDC.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%***E.O. 12866 Review–Draft–Do Not Cite, Quote, or Release During Review***Page144of167Formatted:Tab stops: 5", LeftExhibitDC.B-1. Percentage of Population that is Minority (by Raceand 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%***E.O. 12866 Review–Draft–Do Not Cite, Quote, or Release During Review***Page145of167Formatted:Tab stops: 5", LeftExhibitDC.B-1. Percentage of Population that is Minority (by Raceand 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 D C .B-2. Percentage of Population that 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 Project

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%

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### Exhibit D C .B-2. Percentage of Population that 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 Project

North Dakota 21.6% 20.0% Worsham-Steed (ZENG) Commercial Capture
Texas 33.1% 27.7%

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### Exhibit D C .B-3. Percentage of Population 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%

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### Exhibit D C .B-3. Percentage of Population 0 to 4 Years and 65+ Years
Within 1-Mile Radius of Facility (Cont’d)

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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 D C .B-4. Number of FRS Sites Within 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 D 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 Taylorville 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 Washington 1

Williston Basin EOR Sequestration* Major DOE Sequestration Project
North Dakota 0 Worsham-Steed (ZENG) Commercial Capture

Texas 1ExhibitDC.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%ExhibitDC.B-5. Percentage of Population that is Minority (by Raceand 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%Formatted:Font: Bold***E.O. 12866 Review–Draft–Do Not Cite, Quote, or Release During Review***Page155of167Formatted:Tab stops: 5", LeftExhibitDC.B-5. Percentage of Population that is Minority (by Race and in Total) Within 3-Mile Radius of Facility(Cont’d)***E.O. 12866 Review–Draft–Do Not Cite, Quote, or Release During Review***Page156of167Formatted:Tab stops: 5", LeftFacility 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%

### Exhibit D C .B-6. Percentage of Population th at is Below150% of Poverty Level Within 3

- Mile Radius of Facility Within 3-Mile Radius of Facility

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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 Fert ilizer 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%

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### Exhibit D C .B-6. Percentage of Population that 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 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 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%

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### Exhibit D 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%

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### Exhibit D C .B-7. Percentage of Population 0 to 4 Years and 65+ Years With in 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%

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### Exhibit D C .B-8. Number of FRS Sites Within 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 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 37 Kemper County Commercial Capture Mississippi 3 La Barge Gas Plant Exisiting Gas and Fertilizer Plant Wyoming 2

### Exhibit D 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

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### Appendix E.

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 St ate, 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 insignificant costs to state governments.

Appendix F. Formatted: Font: Not Bold

Formatted: Left, None, Space After: 10 pt, No bullets or numbering, Don't adjust space between Latin and Asian text, Don't adjust space between Asian text and numbers

Formatted: None, Space After: 10 pt, Don't adjust space between Latin and Asian text, Don't adjust space between Asian text and
numbers

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### 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 th e proposed rule do not exceed $100 million. The rule does not create inconsistencies or interfere with an action taken or planned by another agency; does not materially alter the budgetary impact or the 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 impl ications. EPA does not anticipate that the proposed rule will have substantial direct im pacts on the states, the relationship between the government and the states, or on the distribu tion of power and responsibilities among the various levels of government.

F-3 Executive Order 13175: Consultation and Coordination with Indian Tribal
Governments

The proposed rule is not expected to have substantial tribal 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 believe find that the rule will have environmen tal health or safety impacts that disproportionately affect children. Therefore, no additional analysis is required under this
Executive Order.

F-5 Executive Order 13211: Actions that Significantly Affect Energy Supply, Distribution, or Usage

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### Although the affected universe of the proposed ru le includes energy suppliers such as coal power plants, the rule is not expected to result in behavioral changes of behavior that would affect energy supply, distribution or usage.

F-6 National Technology Transfer Advancement Act

This proposed rulemaking does not involve t echnical standards. Therefore, the use of voluntary consensus standards is not applicable.

F-7 Executive Order 12898: Federal Actions to Address Environmental Justice in Minority Populations and Low-Income Populations

The proposed rule is not expected to have disproportionately high and adverse human health or environmental effects on minority or low-income populations. EPA believes finds that the actions allowed by the proposed exclusions are safe and do not present significant adverse health or environmental impacts (See Appendix D C ).

F-8 Executive Order 12630: Regulatory Takings Analysis

The proposed rule does not constitute 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 regulation; specifies its relationship to the provisions of other laws; incorporates clear legal standards; has no retroactive effect; and defines key terms. Therefore, no additional analysis or actions are required under EO 12988.

F-10 Executive Order 13352: Facilitation of Cooperative Conservation

The proposed rule is designed to promote cooperative conservation between EPA, state, and local governments by identifying clear criteria for excluding carbon dioxide 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 de finition 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 the Underground Injection Control Program (UICP) requirements in 40 CFR Parts 144 (Requirements for wells injecting

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### hazardous waste) and the proposed technical criteria and standards for Class VI UIC wells in 40 CFR Part 146 (Underground Injection Control Program: Criteria and Standards). 103 

### CO 2 

### capture and sequestration facilities claiming th e proposed exclusion woul d remain subject to the mandatory reporting requirements for greenhouse 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 Department of Transportation (DOT) Pipeline and Hazardous Materials Safety Administration (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.

103 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.