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EO12866_CO2 RCRA Exclusion 2050-AG60 NPRM EA_20110303

ASSESSMENT OF THE POTENTIAL COSTS, BENEFITS, AND OTHER IMPACTS OF THE 

CONDITIONAL EXCLUSION FROM THE RCRA DEFINITION OF HAZARDOUS WASTE 

FOR CO2 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, 2011
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ACKNOWLEDGMENTS

The Agency recognizes ICF International for the overall organization and 

development of this report. Lyn D. Luben 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 SUMMARY 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 COMMUNITY 16

2.1 CO2 Capture Facilities 17

2.1.1 Current CO2 Capture Facilities 17

2.1.2 Planned CO2 Capture Facilities 19

2.1.3 Summary of Current and Planned CO2 Capture Facilities Considered in this 

Analysis 23

2.2 CO2 Transporters 24

2.3 CO2 Sequestration Facilities 26

3. ANALYSIS OF THE INCREMENTAL COSTS AND BENEFITS OF THE 

PROPOSED RULE 29

3.1 Analytical Approach/Methodology 29

3.2 Baseline Practices 29

3.2.1 Hazardous Waste Determination Process for CO2 Capture Facilities 30

3.2.2 Baseline Practices for CO2 Capture Facilities 31

3.2.2.1 Factors that Influence The Baseline Practices of CO2 Carbon Capture 

Facilities 32

3.2.2.2 Expected Baseline Practices of CO2 Carbon Capture Facilities 33

3.2.3 Baseline Practices for CO2 Sequestration Facilities 36
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3.3 Post Rule Practices 37

3.3.1 Post Rule Practices for CO2 Capture Facilities 37

3.3.2 Post Rule Practices for CO2 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 Savings for CO2 Capture Facilities 47

3.5.2 RCRA Training, Planning, and Reporting Requirement Savings for CO2 Capture 

Facilities 48

3.5.3 CO2 Treatment Savings for CO2 Capture Facilities 48

3.5.4 Summary of Savings to CO2 Capture Facilities 49

3.5.5 Waste Determination Savings for CO2 Sequestration Facilities 51

3.5.6 RCRA Training, Planning, and Reporting Requirement Savings for CO2

Sequestration Facilities 52

3.5.7 Summary of Savings to CO2 Sequestration Facilities 53

3.5.8 Unquantified Benefits of the Proposed Rule 55

3.6 Conclusions 55

4. REGULATORY FLEXIBILITY ANALYSIS 56

5. REFERENCES 57

APPENDIX A: COST FOR DETERMINING RCRA TOXICITY OF CO2 STREAM59

APPENDIX B: TREATMENT COSTS 71

APPENDIX C. SENSITIVITY ANALYSES 77

SENSITIVITY ANALYSIS 1 – FEWER AFFECTED FACILITIES 77

APPENDIX D. ASSESSMENT OF ENVIRONMENTAL JUSTICE IMPACTS 82

APPENDIX E. UNFUNDED MANDATES REFORM ACT ANALYSIS 131

APPENDIX F. OTHER REQUIRED ANALYSES 131
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ES. Executive Summary

The U.S. Environmental Protection Agency (EPA or the Agency) regulates the generation, 

transfer, treatment, and disposal of hazardous 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. 

Currently, carbon dioxide (CO2) streams are not listed as RCRA hazardous wastes, but may 

be classified as a RCRA hazardous waste if they exhibit hazardous characteristics such as 

ignitability, corrosivity, reactivity, or toxicity. At present, EPA has little information to 

conclude that CO2 streams would qualify as RCRA hazardous wastes; however, EPA is 

proposing to revise the regulations for hazardous waste management under RCRA to 

conditionally exclude carbon dioxide (CO2) streams (that are otherwise hazardous) from the 

definition of hazardous waste, provided these CO2 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.12

EPA is taking this action because the Agency believes that the management of these CO2

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 CO2 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 CO2 capture facilities, 

transporters, and sequestration facilities. 

Many electric power plants and other industrial facilities generate CO2 as a byproduct of their 

operations. These facilities typically release that CO2 into the environment. CO2 capture 

facilities are entities that collect their CO2 byproducts and manage them in a manner other 

 

1 EPA has finalized requirements for the sequestration of CO2 in Class VI underground injection wells under 40 

CFR Parts 144 and 146 (Federal Requirements Under the Underground Injection Control (UIC) Program for 

Carbon Dioxide (CO2) Geologic Sequestration (GS) Wells) in a separate rulemaking, (75 FR 77230) December 

10, 2010 (see Docket ID EPA–HQ– OW–2008–0390). 

2

Regulations under the Safe Drinking Water Act Underground Injection Control program contains extensive 

technical requirements for ensuring that underground sources of drinking water are protected during geologic 

sequestration (GS) of CO2.
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than releasing them into the atmosphere. Currently EPA estimates that 27 CO2 capture 

facilities to be affected by the proposed rule. This estimate includes ten facilities that 

currently capture CO2, along with 17 facilities expected to begin CO2 capture in the future. 

These 27 capture facilities include fossil fuel electric power generators, oil and gas extraction 

facilities, natural gas distribution facilities, ethyl alcohol manufacturers, and nitrogenous 

fertilizer manufacturers, and appear to represent a mix of large corporations and mid-sized 

companies. Exhibit ES-1 shows the number of CO2 capture facilities considered in this 

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

Exhibit ES-1: Number of Current and Planned CO2 Capture Facilities Considered in 

this Analysis by Industry Sector

NAICS Industry Sector Number of Facilities

211111 Oil and Gas Extraction 9

221112 Fossil Fuel Electric Power Generation 15

221210 Natural Gas Distribution 1

325193 Ethyl Alcohol Manufacturing 1

325311 Nitrogenous Fertilizer Manufacturing 1

At present, for economic reasons, captured CO2 is transported by pipeline in a supercritical 

state (i.e., dense vapor state).3 As of 2008 there were 30 operating CO2 pipelines, operated 

by 29 separate entities.4 Pipeline transportation of captured CO2 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 CO2 pipelines generally 

appear to be operated by large corporations. EPA has not identified any commercial entities 

that transport CO2 by alternative methods, such as truck or rail that would be subject to the 

standards for hazardous waste transporters if the CO2 in question was found to be hazardous. 

Therefore, this analysis assumes that all transportation of CO2 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 CO2.

CO2 sequestration facilities receive captured CO2 streams and inject them into UIC wells for 

the purposes of sequestration. EPA estimates that 29 planned sequestration facilities to be 

affected by the proposed rule. This estimate includes 15 planned commercial CO2 

sequestration projects and 14 planned projects funded by DOE. The 15 planned commercial 

projects are expected to include 12 enhanced oil recovery projects that transition to

 

3

56 Federal Register 26922, June 12, 1991.

4 Department of Transportation, Pipeline and Hazardous 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 CO2 also may fall into other industrial source 

categories (e.g., oil and gas extraction), but this analysis only considers NAICS 486990 because it is the 

industry category most relevant to the activity affected by the proposed rule.
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sequestration in the long term and 3 saline reservoir sequestration projects.6 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 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 CO2

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

CO2 stream is RCRA hazardous waste or non-hazardous waste. As already stated, CO2

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 their waste, or apply their knowledge – in lieu 

of testing – of the hazard characteristic of a waste, 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 CO2 streams, and EPA 

acknowledges these commenters‟ concerns. However, this analysis assumes that, depending 

on the CO2 generation process used by the CO2 capture facilities, the facilities would either

test the CO2 stream as a gas, or rely on process knowledge and limited testing to determine 

whether their CO2 stream is a RCRA hazardous waste.

Under the baseline scenario, if the owner/operator generator determines that the CO2 stream

is not RCRA hazardous, the generator (capture) facility may transport the CO2 to a Class VI 

well for sequestration. If, however, the CO2 stream is a RCRA hazardous waste, this analysis 

assumes that the capture facility has three options: (i) transport the CO2 stream to a UIC 

Class I hazardous well for sequestration, (ii) treat the CO2 stream to render it non-hazardous, 

and send it to a Class VI well for sequestration, or (iii) cease CO2 capture. The flow chart in 

Exhibit 10 shows the possible baseline practices for CO2 capture facilities depending on the 

results of the hazardous waste determination.

 

6 Department of Energy, National Energy Technology Laboratory, Carbon Capture and Storage Database, 

http://www.netl.doe.gov/technologies/carbon_seq/database/ index.html
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Exhibit ES-2: Flow Chart of Baseline Practices of CO2 Capture Facilities

Waste 

Determination

CO2 Capture Facility's 

Baseline Practice

The CO2 stream is 

not RCRA hazardous

Transport CO2 to 

sequestration facility for 

injection in a Class VI well

Captured CO2 Stream

Destine for Disposal

Cease capturing the CO2

stream

The CO2 stream is 

RCRA hazardous

Transport the CO2 stream to a 

sequestration facility for 

injection in a Class I 

hazardous well 

Treat the CO2 stream and 

transport it to a sequestration 

facility for injection in a 

Class VI well

Note: This assessment is of the geologic sequestration of CO2. While facilities may capture CO2 streams

for use in Class II wells for Enhanced Oil Recovery (EOR), that is beyond the scope of the proposed rule.

Exhibit ES-3 below presents the assumptions regarding the relative prevalence of each 

baseline practice for CO2 capture facilities. It is important to note that these hazardous CO2 

percentages where formed as conservative assumptions for analytical purposes only. Based 

on early literature reviews and current CO2 capture technologies the percentage of CO2 

streams that are expected to be classified as hazardous may be low.
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Exhibit ES-3: Conservative Assumption for the Prevalence of Hazardous Waste 

Determination and Baseline Practices for CO2 Capture Facilities a

Hazardous Waste 

Determination Baseline Practice

Assumed Baseline 

Percentage of Capture 

Facilities a

Non-hazardous Send the CO2 stream to a Class VI well 10 %

Hazardous

Cease capture 30 %

Send the CO2 stream to a Class I 

hazardous well that is assumed to meet 

the Class VI requirements 

30 %

Treat the CO2 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 due to a lack of data on the relative distribution 

of CO2 streams‟ hazardous waste designation. The sensitivity analysis in Appendix C considers the 

alternative assumption that 90 percent of the CO2 capture facilities would generate non-hazardous CO2

streams in the baseline.

This analysis assumes that all CO2 transportation is done via pipelines in the baseline. Other 

forms of CO2 transportation are possible (e.g., truck, rail), but pipeline transport is the most 

efficient and commonly used method of transporting CO2.

7

 

CO2 sequestration facilities, in the baseline, would include a mix of facilities with Class VI 

wells and facilities with Class I hazardous wells that EPA has assumed also will meet the 

Class VI requirements. This analysis assumes that, in the baseline, approximately 57 percent 

of the sequestration wells would manage non-hazardous CO2 streams and treated CO2

streams in Class VI wells.8 The remaining wells would manage RCRA hazardous CO2

streams in Class I hazardous wells. As mentioned above, the assumption that 90% CO2

streams would be RCRA hazardous represents a very conservative approach for assessing 

potential costs in the absence of hazardous waste characterization data. At this time, EPA 

has little information to conclude that CO2 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. 

Post-Rule Behavior

 

7

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.

8 The reasoning behind this assumption is explained in Section 3.2.3 of this document
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This analysis assumes that all CO2 capture facilities will claim the proposed exclusion and 

send their CO2 streams to Class VI wells as a result of the proposed rule, because the savings 

associated with claiming the exclusion would exceed the implementation costs. As a result, 

all CO2 sequestration facilities are expected to manage CO2 in permitted Class VI wells. All 

transportation of CO2 would continue to be done by pipeline.

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 CO2 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 request.9 The facilities would be

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. 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 and reviewed. Similarly, the 

States would incur $61 in labor costs for each certification statement they request and review.

The Agency believes that the management of these CO2 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 anticipate any negative externalities 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 CO2 capture facilities: 

exclusion from hazardous waste determination, exclusion from compliance with RCRA 

training, planning, and reporting requirements10, and exclusion from hazardous waste 

treatment requirements. The analysis estimates that exclusion from hazardous waste 

determination would save each facility $5,500 in one-time costs and $3,000 in annual costs. 

CO2 capture facilities whose waste would be RCRA hazardous in the baseline would save 

approximately $5,000 annually under the proposed rule because they would be exempt from 

the RCRA training, planning, and reporting requirements. CO2 capture facilities that would 

 

9 A single certification statement would be signed by only one facility. Each capture facility and each 

sequestration facility would sign its own certification statement.

10 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. 
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have treated their RCRA hazardous waste CO2 stream in the baseline (i.e., in order to send it 

to a Class VI well) will not need to do so post-rule and would each save approximately $10.3 

million in annual treatment costs. 

CO2 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 summarizes the undiscounted 50-year and annualized costs and benefits 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 annualized net savings of 

approximately $56.6 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 $32.0 million. 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 $164,544 $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 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)
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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

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 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

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 CO2 capture and sequestration 

facilities by exempting CO2 captured for the purpose of geological sequestration in Class VI 

wells from the definition of hazardous waste. For each facility claiming the proposed 

exclusion, these savings are expected to outweigh the cost to prepare and maintain the 

required certification statement. The Agency estimates that this proposed rule will lead to 

net cost savings in the range of $32.0 to $56.6 million annually.11

1. Introduction

The U.S. Environmental Protection Agency regulates the generation, transfer, treatment, and 

disposal of hazardous 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. Currently, carbon 

dioxide (CO2) streams are not listed as RCRA hazardous wastes, but may be classified as a 

RCRA hazardous waste if they exhibit hazardous characteristics such as ignitability, 

corrosivity, reactivity, or toxicity. The Agency believes that the management of these CO2

streams under the proposed conditions, which includes the injection into a Class VI UIC 

well, does not present a substantial risk to human health or the environment. As such, 

 

11 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.
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additional regulation pursuant to RCRA‟s hazardous waste regulations is unnecessary.

12 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 

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 (CO2) stream was determined to be a hazardous waste it would 

be subject to the requirements of RCRA Subtitle C. However, EPA believes that the full set 

of hazardous waste regulations is unnecessary for captured CO2 streams because existing 

regulations governing the transport and injection into a UIC Class VI permitted injection well 

are sufficient to ensure that CO2 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) Program for Carbon Dioxide (CO2) Geologic Sequestration (GS) 

Wells final rule, an improperly managed CO2 GS project has the potential to endanger 

underground sources of drinking water (USDWs). While CO2 itself is not a drinking water 

contaminant, a CO2 stream can pose a risk to USDWs as follows: 13

CO2 streams may contain impurities such as hydrogen sulfide or mercury,

CO2 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. 

 

12 EPA has proposed requirements for the sequestration of CO2 in Class VI underground injection wells under 

40 CFR Parts 144 and 146 (Federal Requirements Under the Underground Injection Control (UIC) Program for 

Carbon Dioxide (CO2) Geologic Sequestration (GS) Wells) in a separate rulemaking (see Docket ID EPA–HQ–

OW–2008–0390). This analysis assumes that Class VI UIC requirements will be finalized as proposed. 

13 Jens Birkholzer, John Apps, Liange Zheng, Yingqi Zhang, Tianfu Xu, and Chin-Fsu Tsang, “Research 

Project on CO2 Geological Storage and Groundwater Resources: Water Quality Effects Caused by CO2

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 (CO2) Geologic Sequestration 

(GS) Wells Final Rule, RIN 2040-AE98.
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The Class VI UIC final rule sets minimum technical criteria for Class VI GS wells to protect 

USDWs from the unique risks associated with CO2 injection, including:14

Site characterization that includes an assessment of the geologic, hydrogeologic, 

geochemical, and geomechanical properties of the proposed GS site to ensure that GS 

wells are located in suitable formations. 

Computational modeling of the area of review (AoR) for GS projects that accounts 

for the physical and chemical properties of the injected CO2 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 CO2 is moving as predicted within the subsurface.

Well construction using materials that can withstand contact with CO2 over the life of 

the GS project. 

Robust monitoring of the CO2 stream, injection pressures, integrity of the injection 

well, ground water quality and geochemistry, and monitoring of the CO2 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 CO2 plume and pressure front have stabilized and the injectate 

does not pose a risk to USDWs. 

Financial responsibility requirements to ensure 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 CO2 streams destine for geological sequestration 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 special 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). CO2

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 hazardous. 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 CO2 is neither a listed waste 

nor excluded as a hazardous waste, generators would be required to determine if their CO2 

stream is a RCRA hazardous waste either by testing its characteristics using methods 

 

14 Preamble to the Federal Requirements Under the Underground Injection Control (UIC) Program for Carbon 

Dioxide (CO2) Geologic Sequestration (GS) Wells Final Rule, RIN 2040-AE98.
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specified in the RCRA regulations, or by applying knowledge of the materials and processes 

that generated the CO2 stream.

If the captured CO2 stream is 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 CO2 streams 

that are transported to an injection facility would be required to be managed in a Class I UIC 

hazardous waste well that is permitted to accept RCRA hazardous waste. A RCRA 

hazardous waste CO2 stream could not be injected into a well that is permitted as a 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 Status Standards for Owners and Operators of Hazardous Waste 

Treatment, Storage, and Disposal Facilities) if they store or treat hazardous waste prior to 

injection; the UIC Class I hazardous well 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.

15

If the CO2 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 required to meet the Class VI UIC requirements, 

which in some regards are similar to the requirements for hazardous waste wells permitted 

under UIC Class I, but are geared specifically toward CO2 sequestration.16, 17

CO2 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 therefore pipeline transportation would be subject 

to the same DOT requirements regardless of a CO2 stream‟s RCRA status. If a RCRA 

hazardous waste CO2 stream was to be transported by other means, such as truck or rail, the 

transporter would be subject to EPA‟s standards 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 

 

15 Permit writers also may require the RCRA hazardous waste CO2 injection well to meet the Class VI UIC 

requirements as well as the Class I hazardous UIC requirements; 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 CO2 injection well. 

16 Note that certain U.S. Department of Energy CO2 injection demonstration projects have been permitted under 

the UIC Class V experimental technology well program, while other demonstration projects have been 

permitted under the UIC Class I non-hazardous waste well program.
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

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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 injection 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.

18

 Class VI wells injecting excluded 

CO2 would therefore not be subject to EPA‟s RCRA hazardous waste requirements. The 

exclusion would apply to captured CO2 streams only and would not apply to any hazardous 

wastes that are mixed with or co-injected with CO2 streams.

Owners and operators of CO2 capture facilities and sequestration wells claiming the 

exclusion would be required to sign and annually renew a certification statement stating that 

the CO2 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 CO2 streams captured for GS would not be 

excluded from the definition of hazardous waste. CO2 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 protection for human 

health and the environment as the proposed rule, but would maintain an unnecessary 

regulatory burden on CO2 capture and sequestration facilities to comply 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 CO2 sequestration, but would not effectively reduce the unnecessary 

regulatory burden placed on CO2 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 CO2 capture facilities, 

transporters, and sequestration facilities. This section identifies the regulated entities and 

discusses their characteristics. 

 

18 See: §261.4 Exclusions (h) – Carbon Dioxide Stream Injected for Geologic Sequestration
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Page 17 of 133

2.1 CO2 Capture Facilities

Many electric power plants and other industrial facilities generate CO2 as a byproduct of their 

operations. These facilities typically release that CO2 into the environment. CO2 capture 

facilities are entities that collect their CO2 byproducts and manage them in a manner other 

than releasing them into the atmosphere. 

EPA estimates that 27 CO2 capture facilities will be affected by the proposed rule. This 

estimate includes ten facilities that currently capture CO2, along with 17 facilities expected to 

begin CO2 capture in the future, including 14 commercial projects, two non-commercial 

DOE pilot projects, and one other private/federal partnership project. The data sources that 

EPA used to estimate the number of current and planned CO2 capture facilities are presented 

below in Sections 2.1.1 and 2.1.2 respectively. Section 2.1.3 summarizes the number of 

capture facilities by type of project, industry sector, and expected first year of CO2

sequestration.

2.1.1 Current CO2 Capture Facilities

Ten facilities are currently capturing CO2 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 approximately 11 million metric tons of CO2 in 2008.19

Exhibit 1 lists these existing carbon capture facilities and their industry classification under 

the North American Industry Classification System (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 CO2 capture facilities will have to choose a different 

management method for their captured CO2 streams. This analysis assumes that this 

transition will occur in the year 2030 for nine of the ten current CO2 capture facilities. The 

analysis assumes that the Coffeyville Fertilizer Plant will begin sequestration in 2034.20 

Exhibit 1: U.S. Facilities Currently Capturing CO2 Streams a

Facility State Description

Assumed 

First Year of 

Sequestration

b

NAICS NAICS 

Description

Val Verde Gas 

- Pikes Peak 

Plant

TX Processing of high CO2 

gas prod.

2030 211111 Oil and Gas 

Extraction

Val Verde Gas TX Processing of high CO2 2030 211111 Oil and Gas 

 

19 EPA, “Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2008,” April 15, 2010, Table 3-47: 

Potential Emissions from CO2 Capture and Transport, p. 3-53, http://www.epa.gov/climatechange/ 

emissions/downloads10/US-GHG-Inventory-2010_Report.pdf. 

20 See footnote b in Exhibit 1.
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 18 of 133

Facility State Description

Assumed 

First Year of 

Sequestration

b

NAICS NAICS 

Description

- Grey Ranch 

Plant

gas prod. Extraction

Val Verde Gas 

- Puckett Plant

TX Processing of high CO2 

gas prod.

2030 211111 Oil and Gas 

Extraction

Val Verde Gas 

- Terrell Plant

TX Processing of high CO2 

gas prod.

2030 211111 Oil and Gas 

Extraction

Val Verde Gas 

- Mitchell Plant

TX Processing of high CO2 

gas prod.

2030 211111 Oil and Gas 

Extraction

La Barge Gas 

Plant

WY Processing of high CO2 

gas prod.

2030 211111 Oil and Gas 

Extraction

Enid Ammonia 

Fertilizer Plant

OK Fertilizer plant CO2 

production

2030 325311 Nitrogenous 

Fertilizer 

Manufacturing

Coffeyville 

Ammonia 

Fertilizer Plant

KS Fertilizer plant CO2 

production

2034 325311 Nitrogenous 

Fertilizer 

Manufacturing

Antrim Gas 

Plant

MI Processing of high CO2 

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 Worldwide. Power Plant Carbon 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 the 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 CO2 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 CO2 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 CO2 capture facilities and their parent companies vary in size. For example, the 

Enid Ammonia Fertilizer Plant is operated by Koch Industries, Inc., which has over 70,000

employees.21 The Coffeyville Fertilizer Plant (Coffeyville Resources LLC) employs 250 to 

 

21 Koch Industries, 2009, http://www.kochind.com/files/070709KIILeadershipKansas.pdf.
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 19 of 133

499 individuals.22 The Great Plains Coal Gasification (Dakota Gasification CO) facility has 

between 500 and 999 employees.23 

2.1.2 Planned CO2 Capture Facilities

EPA has identified an additional 31 planned CO2 capture facilities. These facilities are listed 

in Exhibit 2. Commercial CO2 capture projects represent 28 of these planned capture 

projects.

24

 Although all of these projects are planned, some of them may be cancelled or 

delayed due to approval and funding issues. This analysis considers only fourteen planned 

commercial projects that EPA has deemed likely to proceed, although the other planned 

projects are included in Exhibit 2 for reference.25 In addition to these planned commercial 

projects, there are two other non-commercial CO2 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 CO2 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). 

 

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

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

24 Note to reviewer: These “commercial” CO2 capture projects include some projects that were partially funded 

as DOE pilot projects.

25 As a part of the research that EPA Office of Water conducted to determine the baseline for the “Cost Analysis 

for the Federal Requirements Under the Underground Injection 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 projects, Coffeyville Fertilizer Plant, is already conducting 

CO2 capture and is accounted for in Exhibit 1, above. Therefore Exhibit 2 lists only 14 planned commercial 

capture projects included in the analysis. 
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 20 of 133

Exhibit 2: Planned CO2 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) 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
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 21 of 133

Project State Company

Assumed 

First Year of 

Sequestration

b

NAICS Industry Sector

WA Parish, Sugarland TX

NRG 

Energy; 

Fluor, 

Ramgen/Dr

esser

2032 221112

Fossil Fuel 

Electric Power 

Generation

Wallula Energy Res. 

Center WA

Wallula 

Resource 

Recovery

2013 221112

Fossil Fuel 

Electric Power 

Generation

Worsham-Steed 

(ZENG) TX

CO2 Global 

and Falcon 

Gas Storage

2032 221112

Fossil Fuel 

Electric Power 

Generation

Non-commercial DOE Pilot Projects

Cincinnati Arch Mt. 

Simon Saline 

Reservoir

OH Andersons 

Marathon 2010 325193 Ethyl Alcohol Manufacturing

San Joaquin Basin, 

CA Saline Formation 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

ADM Ethanol Plant 

CO2 Capture IL ADM N/A 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
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 22 of 133

Project State Company

Assumed 

First Year of 

Sequestration

b

NAICS Industry Sector

Cemex Odessa Project TX Cemex N/A 327310 Cement 

Manufacturing

ConocoPhillips 

Sweeny Power plant TX ConocoPhillips N/A 221112

Fossil Fuel 

Electric Power 

Generation

Great Lakes Energy 

Research MI M&M Energy N/A 221112

Fossil Fuel 

Electric Power 

Generation

Leucadia Energy Lake 

Charles LA Leucadia, Denbury N/A 324199

All Other 

Petroleum and 

Coal Products 

Manufacturing

Leucadia Energy Moss 

Point MS MS Leucadia, Denbury N/A 324199

All Other 

Petroleum and 

Coal Products 

Manufacturing

Port Arthur Steam 

Methane Reformers TX

Air 

Products, 

Denbury

N/A 325120 Industrial Gas 

Manufacturing

Praxair Texas City 

Refinery TX Praxair, BP Products N/A 324110 Petroleum Refineries

SCS Energy PurGen 

One NJ SCS Energy N/A 221112

Fossil Fuel 

Electric Power 

Generation

Wolverine Circ. 

Fluidized Bed Plant MI

Wolverine 

Power 

Supply 

Cooperative

N/A 221112

Fossil Fuel 

Electric Power 

Generation

a Department of Energy, National Energy Technology Laboratory, Carbon Capture and Storage Database, 

http://www.netl.doe.gov/technologies/ carbon_seq/database/index.html, and Massachusetts Institute of 

Technology, Largescale Power Plant CCS Projects 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 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).” 

No sequestration start dates were determined for the projects that are not expected to proceed.
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 23 of 133

2.1.3 Summary of Current and Planned CO2 Capture Facilities Considered in 

this Analysis

Exhibit 3 summarizes the number of current and proposed CO2 capture facilities considered 

in the analysis by type of project. 

Exhibit 3: Number of Current and Planned CO2 Capture Projects Identified and 

Considered in the 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

FutureGen Private/Federal Partnership 1

Total 27

Exhibit 4 summarizes the number of current and proposed CO2 capture facilities considered 

in this analysis by industry sector. 

Exhibit 4: Number of Current and Planned CO2 Capture Facilities Considered in this 

Analysis by Industry Sector

NAICS NAICS Industry Sector Number of Facilities

211111 Oil and Gas Extraction 9

221112 Fossil Fuel Electric Power Generation 15

221210 Natural Gas Distribution 1

325193 Ethyl Alcohol Manufacturing 1

325311 Nitrogenous Fertilizer Manufacturing 1

Exhibit 5 presents the number of current and proposed CO2 capture facilities expected to 

begin and practice sequestration of their CO2 streams each year.

Exhibit 5: Number of Current and Planned CO2 Capture Facilities Considered in this 

Analysis Expected to Begin and Practice Sequestration by Year

Year

Number of CO2 

Facilities Beginning 

Sequestration of their 

CO2 Streams

Total Number of CO2 

Facilities Practicing 

Sequestration of their 

CO2 Streams

2010 - 2012 4 4

2013 1 5

2014 0 5

2015 0 5

2016 0 5

2017 1 6
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 24 of 133

Year

Number of CO2 

Facilities Beginning 

Sequestration of their 

CO2 Streams

Total Number of CO2 

Facilities Practicing 

Sequestration of their 

CO2 Streams

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 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

2.2 CO2 Transporters

Captured CO2 is typically transported by pipeline. As of 2008 there were 30 operating CO2 

pipelines, operated by 29 separate entities.

26 Several other CO2 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 CO2 pipeline is still in place but was idle 

and did not transport any CO2 in 2008. Therefore, the total number of CO2 pipelines and 

pipeline operators considered in this analysis may exceed the number reported to be 

operating in 2008. This analysis only considers the 29 operators of pipelines reported to be 

operating in 2008. Exhibit 6 lists these active CO2 pipeline operators. The exhibit also 

presents the miles of pipeline operated and barrel-miles27 of CO2 transported in 2008 by each 

operator.

Pipeline transportation of captured CO2 falls under the “all other pipeline transportation” (i.e., 

transportation of substances other than crude oil, natural gas and refined petroleum products) 

 

26 Department of Transportation, Pipeline and Hazardous Materials Safety Administration (PHMSA), 2008 

Hazardous Liquids Annual Data http://www.phmsa.dot.gov/staticfiles/PHMSA/DownloadableFiles/Files/ 

LIQANN08.zip.

27 A standard barrel contains 42 gallons.
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 25 of 133

industry (NAICS 486990).28 These CO2 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.29 

EPA has not identified any commercial entities that transport CO2 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 CO2 by truck, however, 

these have generally been short-term demonstration projects involving relatively small 

quantities of CO2, Therefore, this analysis assumes that all transportation of CO2 is, and will 

continue to be conducted by pipeline.

Exhibit 6: CO2 Pipeline Operators in the U.S. as of 2008

CO2 Pipeline Operator Name

Miles of CO2 

Pipeline 

Operated

Barrel Miles 

of CO2 

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 Co2 Pipeline, L.P. 9 7,130,397

Genesis Free State Pipeline, LLC 91 9,079,929

Hess Corporation 32 19,325

Kinder Morgan CO2 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

Sandridge CO2, LLC 143 5,578,863

Resolute Natural Resources Company 28 14,085,537

 

28 Some of the entities conducting pipeline transportation of CO2 also may fall into other industrial source 

categories (e.g., oil and gas extraction), but this analysis only considers NAICS 486990 because it is the 

industry category most relevant to the activity affected by the proposed rule.

29 Manta, “Exxon Mobil Corp,” http://www.manta.com/c/mmcckrf/exxon-mobil-corp
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 26 of 133

CO2 Pipeline Operator Name

Miles of CO2 

Pipeline 

Operated

Barrel Miles 

of CO2 

transported

The George R. Brown Partnership, L.P. 8 2,371,011

Transpetco Transport Co. 121 171,933

Trinity CO2 LLC 137 10,426,899

XTO Energy Inc 17 3,218,730

Total 4,203 34,420,239,914

Source: Department of Transportation, Pipeline and Hazardous Materials Safety Administration (PHMSA), 

2008 Hazardous Liquids Annual Data http://www.phmsa.dot.gov/staticfiles/PHMSA/DownloadableFiles/Files/ 

LIQANN08.zip..

2.3 CO2 Sequestration Facilities

CO2 sequestration facility owners and operators are defined for the purposes of this analysis 

as facilities that will receive captured CO2 streams and inject them into UIC wells for the 

purposes of sequestration. EPA estimates that 29 planned sequestration facilities will be 

affected by the proposed rule. These recommendations are consistent with EPA‟s current 

assumptions for the UIC Class VI program project baseline and cost analysis in developing 

the Class VI rule.30 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 estimate includes 15 planned commercial CO2 sequestration projects and 14 planned 

projects funded by DOE. The 15 planned commercial projects that are expected to be 

constructed are anticipated to include 12 enhanced oil recovery projects that transition to

sequestration in the long term and 3 saline reservoir sequestration projects.31

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 Class VI well facilities are not currently operational, the 

characteristics of these facilities are uncertain.

Exhibit 7 summarizes 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 

Analysis 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 

 

30 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),”

31 DOE sequestration project database website 

http://www.netl.doe.gov/technologies/carbon_seq/database/index.html
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 27 of 133

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 

analysis will each have its own sequestration site and that most of these sites will conduct

Enhanced Oil Recovery (EOR).

Exhibit 7: Summary of Sequestration Facilities Considered in this Analysis a

Category Count

DOE Projects - Named Projects/Specific Locations

Followups at Existing DOE Pilots 5

FutureGen, Matoon, IL 1

Subtotal: 6

DOE Projects - General Unspecified Projects

Small Saline Pilots 2

Commercial Scale Saline 5

Commercial Scale EOR 1

Subtotal: 8

Non-DOE (Commercial) Projects

Commercial Saline 3

Commercial EOR Converting to GS 12

Subtotal 15

Total 29

a These counts are based on the research that EPA Office of Water conducted to determine 

the baseline for the “Cost Analysis for the Federal Requirements Under the Underground 

Injection Control Program for Carbon Dioxide Geologic Sequestration Wells (Final GS 

Rule).”

Exhibit 8 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 CO2 is injected typically over several years.

Exhibit 8: 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
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 28 of 133

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 presents the number of CO2 sequestration facilities expected to begin operation and 

to continue to operate each year.

Exhibit 9: Existing and Planned CO2 Capture Facilities Expected to Begin 

Sequestration by Year

Year

Number of Sequestration 

Facilities Beginning 

Operation 

Total 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
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Year

Number of Sequestration 

Facilities Beginning 

Operation 

Total Number of 

Sequestration Facilities 

in Operation

2034 5 27

2035 2 29

2036 0 29

Post-2036 0 29

Total 29 29

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. 

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.32 

3.2 Baseline Practices

Depending on whether or not their captured CO2 is RCRA hazardous, and other site-specific 

factors, generators of hazardous waste may engage in different baseline practices to manage 

their captured CO2 streams. CO2 sequestration facilities may base their own practices on 

 

32 Consistent with the EPA Office of Water‟s “Cost Analysis for the Federal Requirements Under the 

Underground Injection Control Program for Carbon Dioxide Geologic Sequestration Wells (Final GS Rule),”

EPA 816-R-10-013, July 2010.
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generators‟ behavior. This section discusses the hazardous waste determination process and 

then presents the possible baseline practices for CO2 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 CO2 is by pipeline.

33

 Although 

other forms of CO2 transportation are possible (e.g., truck, rail), this analysis assumes that all 

CO2 transportation is done via pipelines both in the baseline and under the proposed rule.

3.2.1 Hazardous Waste Determination Process for CO2 Capture Facilities

In the absence of the proposed rule, generators of captured CO2 streams must determine 

whether their captured CO2 stream destine for geological sequestration is RCRA hazardous 

waste or non-hazardous waste. A captured CO2 stream may be a RCRA hazardous waste 

depending on its characteristics. Facilities must determine whether the captured CO2 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 CO2 streams for RCRA hazardous characteristics. 

The first method is to test the CO2 stream as a gas prior to compression and transport. EPA 

estimates that a CO2 capture facility would expend approximately $7,000 in one-time costs 

and $4,000 in annual costs to test its CO2 stream as a gas. The second option is to test the 

CO2 stream in its compressed, supercritical fluid or liquid under high pressure state. EPA 

estimates that a CO2 capture facility would expend approximately $27,000 in one-time costs 

and $3,500 in annual costs to test its CO2 stream in its supercritical or liquid under high 

pressure state. The third option is for CO2 streams from a coal or gas fired combustion 

source that has undergone some particulate and VOC removal, and combines process 

knowledge with limited testing. This option is based on the assumption that the stream 

would not contain pesticides or most metals, and, consequently, samples only for 

semivolatile organic compounds, volatile organic compounds, and mercury.34 This third 

option is the least expensive – EPA estimates that a CO2 capture facility would expend 

approximately $4,500 in one-time costs and $2,500 in annual costs to utilize this method of 

RCRA hazardous waste determination.35 

This analysis assumes that the 18 facilities capturing CO2 streams from fossil fuel electric 

power generation, natural gas distribution, ethyl alcohol manufacturing, and nitrogenous

fertilizer manufacturing would rely on process knowledge and limited testing to determine if 

their CO2 stream is a RCRA hazardous waste (i.e., Option 3). The analysis assumes that the 

 

33 Paul W. Parfomak and Peter Folger. “Carbon Dioxide (CO2) 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.

34 We recognize that, besides mercury, other heavy metals such as arsenic and selenium may be present at very 

low levels. 

35 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. 
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remaining 9 facilities capturing CO2 streams from oil and gas extraction would test their CO2

streams as a gas to determine whether their CO2 stream is a RCRA hazardous waste (i.e., 

Option 1).

36

3.2.2 Baseline Practices for CO2 Capture Facilities

Depending on whether its CO2 stream is RCRA hazardous, a capture facility may engage in 

one of four baseline practices to manage its CO2 stream. The flow chart in Exhibit 10 

presents the possible baseline practices for CO2 capture facilities depending on whether they 

determine their CO2 stream to be RCRA hazardous waste.

Exhibit 10: Flow Chart of Baseline Practices of CO2 Capture Facilities

Waste 

Determination

CO2 Capture Facility's 

Baseline Practice

The CO2 stream is 

not RCRA hazardous

Transport CO2 to 

sequestration facility for 

injection in a Class VI well

Captured CO2 Stream

Destine for Disposal

Cease capturing the CO2

stream

The CO2 stream is 

RCRA hazardous

Transport the CO2 stream to a 

sequestration facility for 

injection in a Class I 

hazardous well 37

Treat the CO2 stream and 

transport it to a sequestration 

facility for injection in a 

Class VI well

Note: This assessment is of the geologic sequestration of CO2. While facilities may capture CO2 streams

for use in Class II wells for Enhanced Oil Recovery (EOR), that is beyond the scope of the proposed rule

 

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

37 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 apply both the Class I and Class VI standards to a RCRA 

hazardous waste CO2 injection well. 
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3.2.2.1 Factors that Influence The Baseline Practices of CO2 Carbon Capture 

Facilities

Each generator‟s choice in how to manage a RCRA hazardous waste CO2 stream would 

depend on several factors. The cost of each management option is a significant factor in this 

decision. Ceasing capture and releasing the CO2 stream would be the lowest cost option, as 

the process of releasing the CO2 stream would have little to no incremental cost and the 

generator would avoid costs associated with the RCRA hazardous waste requirements.38 

Transporting the waste to a Class I hazardous waste well would be the second least expensive 

option. EPA assumes that the cost of sequestration in a Class VI well is generally similar to 

the cost of sequestration in a Class I hazardous waste well.39 However, a facility that 

captures CO2 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 CO2 stream to a Class VI well, a 

generator would first have to treat the CO2 stream to make it non-hazardous, because RCRA 

hazardous waste could not be injected into a Class VI injection well. The hazardous CO2

treatment process represents a significant cost. Treating the CO2 stream and sending it to a 

Class VI well would be the most expensive option for RCRA hazardous CO2 capture 

facilities.

If the generators‟ decisions were based purely on management costs, generators who 

determine that their waste is RCRA hazardous waste would cease capture. However, factors 

beyond the cost of managing the CO2 stream may affect their decisions. Capture projects 

may have been initiated in order to be eligible 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 

 

38 EPA has assumed that the generator determines that the CO2 stream is a RCRA hazardous waste and then 

decides to forego capturing the CO2 stream before any capital expenditure is incurred. The analysis assumes 

that there are no „sunk costs‟ or other economic harm associated with the decision to forego capture. 

Starting in 2011, the facility may need to modify their 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 CO2 or modified electric power plants emitting greater 

than 75.000 TPY CO2

(

75 Federal Register 31514, June 3, 2010). Therefore, starting in 2011 CO2 emissions 

would be included in operating permits for power plants as a permit condition. Any change to the CO2

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. 

39 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 CO2 sequestration also meet the Class VI requirements. 

However, EPA acknowledges that there is no explicit regulatory requirement for permit writers to apply the 

Class VI requirements to Class I wells. For purposes of this analysis, the difference in cost of obtaining a Class 

I UIC Permit versus a Class VI UIC permit has not been estimated and the cost of obtaining a permit is assumed 

to be the same regardless of the class of injection well or whether the CO2 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 for the purpose of developing no-migration petitions; the 

Class VI well permits require computational modeling to delineate the full region surrounding the geological 

sequestration project that may be impacted by the injection activity and require periodic reevaluation of the area 

of review as monitoring and data warrant.
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continue CO2 capture projects despite the RCRA hazardous waste characteristics of their CO2 

streams. 

Although sequestration in a Class I hazardous waste well that meets the Class VI 

requirements would be less expensive than treating the waste for sequestration in a Class VI 

well, some generators nonetheless, may adopt the latter practice. EPA‟s requirements allow 

the sequestration of RCRA hazardous waste CO2 streamsin 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 CO2 stream meet requirements 

similar to the Class VI requirements. Furthermore, 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 CO2 stream generators may not have access 

to a Class I hazardous waste well permit that allows RCRA hazardous waste CO2 stream 

sequestration.

3.2.2.2 Expected Baseline Practices of CO2 Carbon Capture Facilities

As shown in Exhibit 10 above, the analysis assumes that non-hazardous CO2 streams will be 

transported to a Class VI well for sequestration. Those who generate hazardous CO2 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 CO2 capture. Due to uncertainty in the hazardous constituent content of CO2 

streams that will be captured and the complexity of the factors that will influence the baseline 

practices for generators of hazardous streams, Exhibit 11 presents the assumptions regarding

the relative prevalence of each baseline practice in the absence of the proposed rule.

40

 It is 

important to note that, due to the lack of definitive data, these hazardous CO2 percentages 

where formed as conservative assumptions for analytical purposes only. Based on early 

literature reviews and current CO2 capture technologies the percentage of CO2 streams that 

are expected to be classified as hazardous may be low.

 

40 This analysis assumes that CO2 is not stored at the capture site and is sent off-site in a more-or-less 

continuous fashion. 
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Exhibit 11: Conservative Assumption for the Prevalence of Hazardous Waste 

Determination and Baseline Practices for CO2 Capture Facilities

Hazardous Waste 

Determination Baseline Practice

Assumed Baseline 

Percentage of Capture 

Facilities a

Non-hazardous Send the CO2 stream to a Class VI well 10 %

Hazardous

Cease capture 30 %

Send the CO2 stream to a Class I well 

that is assumed to meet the Class VI 

requirements 

30 %

Treat the CO2 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 due to a lack of data on the relative distribution of 

CO2 streams‟ hazardous waste designation. The sensitivity analysis in Appendix C considers the 

alternative assumption that 90 percent of the CO2 capture facilities would generate non-hazardous CO2

streams in the baseline.

Exhibit 12 presents the number of CO2 capture facilities that EPA expects will be active each 

year, and applies the percentages from Exhibit 11 to estimate the number of CO2 capture 

facilities that would engage in each baseline practice each year in the absence of the 

proposed rule.41

Exhibit 12: Expected Number of CO2 Capture Facilities That Would Engage In Each 

Baseline Practice in the Absence of the Proposed Rule, by Year a

Year

NonhazardousSend to Class 

VI

Hazardous

- Cease

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

 

41 After applying the weights from Exhibit 11, the number of facilities practicing each baseline practice was 

adjusted slightly to eliminate rounding errors in the total number of capture facilities.
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Year

NonhazardousSend to Class 

VI

Hazardous

- Cease

Capture

Hazardous -

Treat and 

Send to 

Class VI

Hazardous - Send 

to Class I that is 

Assumed to Meet 

Class VI 

Requirements Total

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 b3 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 to the number of capture facilities expected to practice 

sequestration of their CO2 streams each year presented in Exhibit 5. The numbers are rounded to integer 

values while ensuring the total number of capture facilities in each year matches the total from Exhibit 5. 

The analysis makes the following assumptions regarding the costs that CO2 capture incur 

under the baseline:

42

Each CO2 capture facility would incur one-time and annual costs to determine if the 

CO2 stream is RCRA hazardous waste or is non-hazardous. Facilities that would 

continue CO2 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 

CO2 streams in subsequent years and therefore would incur the annual costs for the 

first year only 

CO2 capture facilities that generate a CO2 stream that is not RCRA hazardous waste,

and CO2 capture facilities that determine that their CO2 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. 

CO2 capture facilities that generate RCRA hazardous waste CO2 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). 

 

42 A facility would be required to treat or dispose of any already captured RCRA hazardous CO2 in compliance 

with RCRA standards, including test samples after testing is complete (see 40 CFR 261.4(d)). The tests to 

determine a CO2 stream‟s hazardous characteristics require the capture of only a very small quantity of CO2 (the 

facility would likely qualify as a conditionally exempt small quantity generator), so this analysis assumes the 

associated costs to be negligible for handling the samples.
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Therefore, they would be subject to the full set of hazardous waste generator 

requirements and would incur the associated costs. 

CO2 capture facilities that treat their RCRA hazardous waste CO2 streams would 

incur treatment costs.43 

The avoidance of these costs under the proposed exclusion is quantified as a savings in 

Section 3.5.

3.2.3 Baseline Practices for CO2 Sequestration Facilities

In the baseline, the universe of CO2 sequestration facilities would include a mix of facilities 

with Class VI wells and facilities with Class I hazardous waste wells that EPA has assumed 

will also meet the Class VI requirements. The Class VI wells would manage non-hazardous 

CO2 streams and CO2 streams that have been treated prior to sequestration, while the Class I 

hazardous waste wells would manage the untreated RCRA hazardous waste CO2 streams. 

This analysis assumes that, in the baseline, approximately 57 percent of the sequestration 

wells would manage non-hazardous CO2 streams and treated CO2 streams in Class VI wells. 

The remaining sequestration wells would manage RCRA hazardous CO2 streams in Class I

hazardous waste wells. 44 Exhibit 13 estimates the number of CO2 sequestration facilities that 

would engage in each baseline practice.

Exhibit 13: Expected Number of CO2 Sequestration Facilities That Would Engage In 

Each Baseline Practice in the Absence of the Proposed Rule, by Year a

Year

Manage Non-Hazardous CO2

(Class VI)

Manage Hazardous CO2

(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

 

43 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.

44 The analysis assumes, in Section 3.2.2.2, that 40 percent of CO2capture facilities would transport nonhazardous or treated CO2 streams to Class VI sequestration wells for injection. Another 30 percent of CO2

capture facilities would transport hazardous CO2 streams to Class I sequestration wells for injection. Of this 70 

percent of capture facilities transporting their CO2 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 

CO2 sequestration wells in the baseline are Class VI wells to match the practices of CO2 capture facilities. The 

remaining 3 out of 7 (43 percent) of CO2 sequestration wells in the baseline are Class I wells.
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Year

Manage Non-Hazardous CO2

(Class VI)

Manage Hazardous CO2

(Class I)

2023 10 7

2024 10 7

2025 10 7

2026 10 7

2027 10 7

2028 10 7

2029 10 7

2030 10 7

2031 10 8

2032 13 9

2033 13 9

2034 15 12

2035 17 12

2036 17 12

Post 2036 17 12

a The numbers in this table are derived by applying the percentages of 

sequestration facilities conducting each baseline practice presented 

discussed above to the number of sequestration facilities expected to be 

in operation each year presented in Exhibit 9. The numbers are rounded 

to integer values while ensuring the total number of capture facilities in 

each year matches the total from Exhibit 9. 

3.3 Post Rule Practices

This section discusses the change in practices of CO2 capture and sequestration facilities due 

to the rule, as proposed. 

3.3.1 Post Rule Practices for CO2 Capture Facilities

This analysis assumes that all CO2 capture facilities will claim the proposed exclusion and

send their CO2 streams to Class VI wells as a result of the proposed rule.45 Under the 

proposed rule, CO2 capture facilities claiming the proposed exclusion would avoid the costs 

of determining whether their CO2 stream is RCRA hazardous or non-hazardous. Exempt 

generators would not be required to conduct testing of their CO2 streams for hazardous 

characteristics or be required to evaluate the hazardous constituent content of the CO2 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 CO2 stream is exempt. CO2 

capture facilities would be able to send their CO2 streams to Class VI wells without the 

additional cost of treating the CO2 stream. 

 

45 It is possible that some facilities may continue to send their RCRA hazardous waste CO2 stream to a Class I 

well that is assumed to meet the Class VI requirements. However, based on this assumption, the costs 

associated with this practice are expected to be similar to the costs of using a Class VI well, so this distinction 

will not affect the results of this analysis.
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3.3.2 Post Rule Practices for CO2 Sequestration Facilities

Under the proposed rule, all CO2 sequestration facilities are expected to be permitted as Class 

VI wells.46 Because under the proposed rule CO2 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 CO2 capture 

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

they must maintain onsite and make available to EPA on request.47 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 presents the estimated labor costs per facility 

associated with the certification requirements. These costs are expected to be similar for CO2 

capture facilities and Class VI UIC wells.

Exhibit 14: Estimated Costs to Prepare and Renew the CO2 Exclusion Certification 

Statement Per CO2 Capture Facility or Sequestration Well (2010 dollars)

Labor Category

Loaded 

Hourly 

Wage a

Prepare Initial 

Certification 

Statement

Renew 

Certification 

Statement

Make Certification 

Statement Available 

to State or EPA

Hours b Cost Hours b Cost Hours b Cost

Legal $101.13 1.00 $101.13 0.50 $50.57 0.00 $0.00

Management $77.67 1.50 $116.51 0.75 $58.25 0.00 $0.00

Technical $110.99 1.25 $138.74 0.50 $55.50 0.00 $0.00

Clerical $25.06 0.25 $6.27 0.25 $6.27 0.10 $2.51

Total (Rounded) 4.00 $363 2.00 $171 0.10 $3

a Wages for legal, management, and clerical labor are based on unloaded average hourly labor rates from the 

“Occupational Employment Statistics, May 2009 National Occupational Employment and Waste Estimates, 

United States” of the Bureau of Labor Statistics (BLS). Wages for technical labor reflect the average of the wage 

 

46 With the possible exception of some sequestration demonstration projects that may be permitted as Class V 

experimental wells.

47 A single certification statement would be signed by only one facility. Each capture facility and each 

sequestration facility would sign its own certification statement.
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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

for a petroleum geologist with 15 years experience in the 2008 American Association of Petroleum Geologists 

(AAPG) Salary Survey according to Larry Nation, “Uncertainty chills decision making: Salaries Show 5 Percent 

Increase,” http://www.aapg.org/explorer/salarysurvey.cfm and the wage for a petroleum engineer (reservoirs) with 

15 years experience according to The Society of Petroleum Engineers “Annual Membership 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 “Employment Cost Index Historical Listing Current-dollar March 

2001-September 2010,” http://www.bls.gov/web/eci/echistrynaics.pdf, and multiplied by a loading factor of 1.6.

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

Exhibits 15 and 16 multiply these per facility costs times the number of capture facilities and 

Class VI wells, respectively, expected to incur each cost in each year over the 50-year period 

beginning in 2012. Facilities are assumed to sign the certification in the first year of 

operation and renew the certification in each subsequent year.48 Combined, EPA and state 

governments are assumed to request certification statements from approximately 30 percent 

of capture facilities and Class VI well operators annually.49 The exhibit presents the 

undiscounted certification costs, and also presents the discounted certification costs applying

3 percent and 7 percent discount rate to costs incurred after 2012. 

Exhibit 15: Certification Costs for CO2 Capture Facilities 2012 to 2061, (2010 dollars)

Year

Initial Certifications Certifications Renewals

Certification 

Submissions to State 

or EPA Total Cost

Number

A

Cost

B = A X 

$363

Number

C

Cost

D = C X $171

Number

E

Cost

F = C X 

$3

Undiscounted

B + D +F

3% 

Discount 

Rate

7% 

Discount 

Rate

2012 4 $1,452 0 $0 1 $3 $1,455 $1,455 $1,455

2013 1 $363 4 $684 2 $6 $1,053 $1,022 $984

2014 0 $0 5 $855 2 $6 $861 $812 $752

2015 0 $0 5 $855 2 $6 $861 $788 $703

2016 0 $0 5 $855 2 $6 $861 $765 $657

2017 1 $363 5 $855 2 $6 $1,224 $1,056 $873

2018 0 $0 6 $1,026 2 $6 $1,032 $864 $688

2019 0 $0 6 $1,026 2 $6 $1,032 $839 $643

2020 0 $0 6 $1,026 2 $6 $1,032 $815 $601

2021 0 $0 6 $1,026 2 $6 $1,032 $791 $561

2022 0 $0 6 $1,026 2 $6 $1,032 $768 $525

2023 0 $0 6 $1,026 2 $6 $1,032 $746 $490

2024 0 $0 6 $1,026 2 $6 $1,032 $724 $458

2025 0 $0 6 $1,026 2 $6 $1,032 $703 $428

 

48 See Exhibits 10 and 11 for the number of CO2 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.

49 This estimate is based on EPA‟s best professional judgment.
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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

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
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

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Exhibit 16: 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

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
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

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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

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

Under the proposed rule, some CO2 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 CO2 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 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

The baseline requirements that apply to captured RCRA hazardous waste CO2 streams are 

designed to protect the human health and the environment. However, EPA believes that CO2

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 CO2 stream 

and prevent it from migrating to 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 that the management of exempted CO2 streams in Class 

VI UIC wells would not pose a significant risk to human health and the environment. EPA 

does not anticipate any negative externalities as a result of this action. As a result, 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 
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 43 of 133

that these impacts 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, CO2 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 approximately 30 percent of capture facilities and Class 

VI well operators annually, and that state governments will account for about 90 percent of 

those requests.50 Exhibits 17 and 18 present the costs per request to EPA and state 

governments, respectively. 

Exhibit 17: Estimated Cost to EPA to Request and Review a CO2 Exclusion

Certification (2010 dollars)

Labor Category Loaded Hourly Wage a Hours b Cost

Management $71.42 0.20 $14.28

Technical $52.37 0.50 $26.19

Clerical $21.02 0.30 $6.31

Total 1.00 $47

a Office of Personnel Management, “Salary 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 standard government loading factor of 1.6 to reflect overhead

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

Exhibit 18: Estimated Costs to States to Request and Review a CO2 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 Statistics (BLS), “May 2009 

National Industry-Specific Occupational Employment and Wage Estimates, 

NAICS 999200 – State Government,” http://www.bls.gov/oes/current/

naics4_999200.htm. EPA updated these rates to June 2010 levels using the 

BLS “Employment Cost Index Historical Listing Current-dollar March 

2001-September 2010,” http://www.bls.gov/web/eci/echistrynaics.pdf. EPA 

applied a 1.6 loading factor to reflect overhead.

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

 

50 These estimates are based on EPA‟s best professional judgment.
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

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Exhibits 19 and 20 calculate 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. The exhibits present undiscounted costs, and also apply 3 percent and 7 

percent discount rates to costs incurred after 2012. 

. 

Exhibit 19: 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

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
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

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Year

Number of 

Requests Per Year

A

Undiscounted Cost

A X $47 3% Discounted Cost 7% Discounted Cost

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

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: 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
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

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Year

Number of Requests 

Per Year

A

Undiscounted Cost

A X $61 3% Discounted Cost 7% Discounted Cost

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

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
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 47 of 133

Year

Number of Requests 

Per Year

A

Undiscounted Cost

A X $61 3% Discounted Cost 7% Discounted Cost

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

3.5 Incremental Cost Savings and Benefits of the Proposed Rule

CO2 streams managed by GS would be excluded from the RCRA hazardous waste 

requirements under the proposed rule.51 This change would result in three areas of savings 

for the generators of CO2 streams: exclusion from hazardous waste determination, exclusion

from compliance with RCRA training, planning, and reporting requirements, and exclusion

from hazardous waste treatment requirements. CO2 sequestration facilities managing RCRA 

hazardous waste CO2 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 CO2 Capture Facilities

In the absence of the proposed rule, facilities capturing CO2 destine for geological 

sequestration would be required to determine whether the CO2 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. As stated in Section 3.2, this analysis assumes that 

the 18 facilities capturing CO2 streams from fossil fuel electric power generation, natural gas 

distribution, ethyl alcohol manufacturing, and nitrogenous fertilizer manufacturing would 

rely on process knowledge and limited testing to determine if their CO2 stream is a RCRA 

hazardous waste (i.e., Option 3). The analysis assumes that the remaining 9 facilities 

capturing CO2 streams from oil and gas extraction would test their CO2 streams as a gas to 

determine whether their CO2 stream is a RCRA hazardous waste (i.e., Option 1). This 

analysis applies weighted average waste determination costs of approximately $5,500 in onetime costs and $3,000 in annual costs.52

 Under the proposed rule, exempt generators would 

not be required to determine whether their CO2 stream is or is not RCRA hazardous waste. 

 

51 Section 1.2 of this document summarizes requirements applicable to generators of RCRA hazardous waste 

CO2 in the baseline.

52 See Appendix A for further detail on the calculation of waste determination costs. This draft applies a single 

weighted average testing cost. The seventeen facilities that capture CO2 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 CO2 from oil and 
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Page 48 of 133

3.5.2 RCRA Training, Planning, and Reporting Requirement Savings 

for CO2 Capture Facilities

This analysis assumes that generators who send RCRA hazardous waste CO2 streamsto Class 

I hazardous waste well and generators who treat their RCRA hazardous waste and then send 

it to Class VI wells are LQGs in the baseline and are subject to the full set of RCRA 

hazardous waste regulations including training, planning, and reporting requirements. The 

proposed rule would relieve these generators of the costs associated with these requirements. 

Exhibit 21 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: Estimated Annual RCRA Training, Planning, and Reporting Requirement

Savings Per Hazardous CO2 Capture Facility as a Result of the Proposed Rule (2010 

dollars)

Requirement Citation Savings Per Facility a

EPA ID b262.12 $0

Personnel Training c262.34 $2,762

Contingency Planning c262.34 $733

Emergency Planning c262.34 $482

Recordkeeping c262.40 $711

Manifest d262 Subpart B $0

Manifest Exception Report d262.42 $0

Biennial Report c262.41 $369

Total $5,057

a These savings apply to facilities that capture hazardous waste CO2 streams that did not 

cease capture in the baseline.

b Acquiring an EPA ID is not an incremental cost for existing facilities, and is assumed to 

be a negligible cost for new facilities.

c These savings are consistent with the savings estimated in EPA‟s “Regulatory Impact 

Analysis: 2008 Final Rule Amendments to the Industrial Recycling Exclusions of the 

RCRA Definition of Solid Waste,” which also excluded certain generators from the 

RCRA training, planning, and reporting 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 CO2 by pipeline only. The manifest 

requirements do not apply to pipeline transportation, so no savings are anticipated. 

 

gas extraction and natural gas distribution are expected to test their CO2 streams as gas prior to compression. 

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

annual costs 
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 49 of 133

3.5.3 CO2 Treatment Savings for CO2 Capture Facilities

Generators that treat their CO2 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 CO2 stream to render it 

non-hazardous is an expensive process. EPA estimates that treatment of a CO2 stream 

generated at an oxy-fuel power plant would cost $9.74 per metric ton of CO2, and treatment

of a CO2 stream generated at an IGCC power plant would cost $8.94 per metric ton of CO2.

53

 

Taking the average of these two costs, this analysis estimates that treating a CO2 stream to 

render it non-hazardous costs $9.33 per metric ton of CO2. The ten current CO2 capture 

operations combined (which are currently capturing CO2 for use in EOR, not for 

sequestration) captured 11 million metric tons of CO2 waste in 2008, or about 1.1 million

metric tons per facility.54 55 If the planned CO2 capture facilities generate CO2 streams at a 

similar rate, each facility that treats its CO2 stream in the baseline will save approximately 

$10.3 million in CO2 stream treatment costs annually under the proposed rule.

3.5.4 Summary of Savings to CO2 Capture Facilities

Exhibit 22 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 million to CO2 capture facilities in the first year under the proposed 

rule.

Exhibit 22: Savings to CO2 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

CO2 Treatment d1 $10,270,395 $10,270,395

 

53 Appendix B presents the calculation of these CO2 treatment costs.

54 EPA, “Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2008,” April 15, 2010, Table 3-47: 

Potential Emissions from CO2 Capture and Transport, p. 3-53, http://www.epa.gov/climatechange/emissions/ 

downloads10/US-GHG-Inventory-2010_Report.pdf. .

55 We evaluating other options to develop an average annual quantity of captured CO2. 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. 
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 50 of 133

Baseline Practice

Number of 

Facilities

A

Savings Per Facility 

Under the Proposed Rule

B

Total Savings Under the 

Proposed Rule

A X B

Total $10,313,678

a One-time waste determination savings apply only to those CO2 capture facilities claiming the exclusion for the 

first time.

b Annual waste determinations savings apply to all CO2 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 CO2 capture facilities that 

generate RCRA hazardous waste CO2 streams and do not cease capture in the baseline (i.e. facilities that treat 

their CO2 or send their RCRA hazardous waste CO2 stream to a Class I well in the baseline).

d CO2

treatment savings apply only to those CO2 capture facilities that treat their RCRA hazardous waste CO2

streams and send them to Class VI wells in the baseline.

Exhibit 23 uses this methodology to calculate the expected savings to CO2 Capture Facilities

as a result of the proposed rule 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 23: Savings to CO2 Capture Facilities as a Result of the Proposed Rule, 2012 to 

2061 (2010 dollars) 

Year Waste 

Determination

Hazardous 

Waste 

Requirements

CO2 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
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2032 $70,264 $60,684 $61,622,372 $61,753,320 $34,191,316 $15,958,231

2033 $43,026 $60,684 $61,622,372 $61,726,082 $33,180,810 $14,907,657

2034 $84,757 $75,855 $71,892,767 $72,053,379 $37,604,118 $16,263,396

2035 $72,012 $80,912 $82,163,162 $82,316,086 $41,708,881 $17,364,322

2036 $58,393 $80,912 $82,163,162 $82,302,467 $40,487,360 $16,225,653

2037 $58,393 $80,912 $82,163,162 $82,302,467 $39,308,116 $15,164,162

2038 $58,393 $80,912 $82,163,162 $82,302,467 $38,163,220 $14,172,114

2039 $58,393 $80,912 $82,163,162 $82,302,467 $37,051,670 $13,244,966

2040 $58,393 $80,912 $82,163,162 $82,302,467 $35,972,495 $12,378,473

2041 $58,393 $80,912 $82,163,162 $82,302,467 $34,924,752 $11,568,666

2042 $58,393 $80,912 $82,163,162 $82,302,467 $33,907,527 $10,811,838

2043 $58,393 $80,912 $82,163,162 $82,302,467 $32,919,929 $10,104,521

2044 $58,393 $80,912 $82,163,162 $82,302,467 $31,961,096 $9,443,478

2045 $58,393 $80,912 $82,163,162 $82,302,467 $31,030,190 $8,825,680

2046 $58,393 $80,912 $82,163,162 $82,302,467 $30,126,398 $8,248,299

2047 $58,393 $80,912 $82,163,162 $82,302,467 $29,248,930 $7,708,691

2048 $58,393 $80,912 $82,163,162 $82,302,467 $28,397,020 $7,204,384

2049 $58,393 $80,912 $82,163,162 $82,302,467 $27,569,922 $6,733,069

2050 $58,393 $80,912 $82,163,162 $82,302,467 $26,766,915 $6,292,588

2051 $58,393 $80,912 $82,163,162 $82,302,467 $25,987,296 $5,880,923

2052 $58,393 $80,912 $82,163,162 $82,302,467 $25,230,384 $5,496,190

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

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

3.5.5 Waste Determination Savings for CO2 Sequestration Facilities

In the absence of the proposed rule, sequestration facilities managing CO2 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 CO2 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.56

 

56 See Appendix A for further detail on the calculation of waste determination costs. 
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

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3.5.6 RCRA Training, Planning, and Reporting Requirement Savings 

for CO2 Sequestration Facilities

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 CO2 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 CO2 streams are expected to be permitted as Class VI wells under the proposed rule, 

not as Class I wells. Because they would not be managing hazardous wastes as Class VI 

wells, under the proposed rule, they would not be subject to the requirements for hazardous 

waste managers, resulting in a savings to these wells. Some of these savings would be 

negligible or offset by requirements for Class VI wells. Exhibit 24 lists the requirements for 

UIC Class I hazardous waste wells from which these CO2 sequestration wells would be 

exempt if they claim the proposed exclusion. The exhibit also presents the expected savings

associated with each requirement.

Exhibit 24: Estimated Annual RCRA Training, Planning, and Reporting Requirement

Savings as a Result of the Proposed Rule Per Hazardous CO2 Sequestration Facility

(2010 dollars)

Requirement Citation Net Savings Per Facility a

Notification b144.14(c)(1) $0

EPA ID b144.14(c)(2) $0

Manifest c144.14(c)(3) $0

Manifest Discrepancies c144.14(c)(4) $0

Operating Record b144.14(c)(5) $0

Biennial Report d144.14(c)(6) $0

Unmanifested Waste Report c144.14(c)(7) $0

Personnel Training e144.14(c)(8) $2,762

Certification of closure b144.14(c)(9) $0

Total $2,762

a

These savings apply to sequestration facilities that managed hazardous waste CO2 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. 
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3.5.7 Summary of Savings to CO2 Sequestration Facilities

Exhibit 25 multiplies each of the savings to CO2 sequestration facilities identified in sections 

3.5.5 and 3.5.7 times the appropriate number of facilities that would receive each saving in 

2012, to calculate the total expected savings to CO2 sequestration facilities in the first year 

under the proposed rule.

Exhibit 25: Savings to CO2 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 uses this methodology to calculate the expected savings as a result of the proposed 

rule to CO2 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: Savings to CO2 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
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Year Waste 

Determination

Hazardous Waste 

Generator 

Requirements

Total Savings 

(Undiscounted)

Total Savings 

(3% Discount 

Rate)

Total Savings 

(7% Discount 

Rate)

2027 $26,119 $13,810 $39,929 $25,629 $14,472

2028 $26,119 $13,810 $39,929 $24,883 $13,525

2029 $26,119 $13,810 $39,929 $24,158 $12,641

2030 $26,119 $13,810 $39,929 $23,454 $11,814

2031 $32,095 $13,810 $45,905 $26,179 $12,693

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

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

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
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 55 of 133

3.5.8 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 rule is 

expected to result in undiscounted annualized net savings of approximately $56.6 million. 

Applying a 3 percent discount rate, the annualized net savings are approximately $44.9

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

$32.0 million.57 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 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 

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 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 

 

57 Appendix C presents two sensitivity analyses that consider the costs and savings of the proposed rule under 

assumptions that differ from the main analysis. The first sensitivity analysis considers a fewer number of 

affected facilities than the main analysis. The second sensitivity analysis makes different assumptions 

regarding the hazardous characteristics of captured CO2 streams in the baseline.
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 56 of 133

Exhibit 29: Net Costs and Savings of the Proposed Rule – 7% Discount Rate (2010 dollars)

Type of Entity

Present Value 

of 50-year

Costs

Present Value 

of 50-year

Savings

Present Value of 50-

year Net Savings

Annualized 

Net Savings

Capture Facilities $29,098 $472,624,602 $472,595,504 $32,003,924 

Sequestration 

Facilities $42,294 $615,507 $573,213 $38,818 

State Governments $6,471 $0 ($6,471) ($438)

EPA $626 $0 ($626) ($42)

Total $78,488 $473,240,109 $473,161,620 $32,042,262 

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 CO2 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 entities. Small entities include small businesses, 

small not-for-profit enterprises, and small governmental jurisdictions. This proposed rule 

does not have a significant impact on a substantial number of small entities because it 

relieves the regulatory burden associated with EPA‟s hazardous waste regulations on CO2

capture and sequestration facilities by exempting CO2 captured for the purpose of geological

sequestration in Class VI well from the definition of hazardous waste. For each facility 

claiming the proposed exclusion, these savings are expected to outweigh the cost to prepare 

and maintain the required certification statement. The Agency estimates that this proposed 

rule will lead to net cost savings in the range of $32.0 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.
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 57 of 133

5. References

Birkholzer, J., J. Apps, L. Zheng, Y. Zhang, T. Xu, and C.F. Tsang. “Research Project on 

CO2 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/technologies/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 and Hazardous Materials Safety Administration 

(PHMSA). 2008 Hazardous Liquids Annual Data. Available: 

http://www.phmsa.dot.gov/staticfiles/PHMSA/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/emissions/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). EPA 816-R-10-013. 2010.
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 58 of 133

EPA. Final Rule for Federal Requirements Under 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 2009 Leadership Kansas Class.” July 27, 2009.

Available: http://www.kochind.com/files/070709KIILeadershipKansas.pdf.

Manta. “Coffeyville Resources LLC.” Available: 

http://www.manta.com/c/mmgvkjp/coffeyville-resources-llc

Manta. “Dakota Gasification Co.” Available: http://www.manta.com/c/mmlgj74/dakotagasification-co

Manta. “Exxon Mobil Corp.” Available: http://www.manta.com/c/mmcckrf/exxon-mobilcorp

Massachusetts Institute of Technology (MIT). Largescale Power Plant CCS Projects 

Worldwide. Power Plant Carbon Dioxide 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 (CO2) 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

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/.
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 59 of 133

Appendix A

Cost for Determining RCRA Toxicity of CO2 Stream

Under the Business As Usual (BAU) scenario a generator would be required to determine if 

the CO2 stream is classified as a Hazardous Waste under the Resource Conservation and 

Recovery Act (RCRA). This appendix summarizes the options and associated costs for 

determining if the waste meets the toxicity characteristic under RCRA. The corrosivity 

characteristic is also potentially applicable to the classification of CO2 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” waste, (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 developed separate cost estimates for generators of CO2 streams that 

will conduct physical testing of the waste and generators of CO2 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 characteristic of the waste. This appendix addresses 

only the characteristic of toxicity resulting from the chemical constituents 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. 

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
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EPA 

HW 

No.1 Analyte Group Contaminant CAS No.2

Regulatory 

Level 

(mg/L)

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 95–48–7 200.04

D024 Semivolatile Organic Compound m-Cresol 108–39–4 200.04

D025 Semivolatile Organic Compound p-Cresol 106–44–5 200.04

D026 Semivolatile Organic Compound Cresol 200.04

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 0.133

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 0.133

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 5.03

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

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.
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2 Chemical abstracts service number.

3

 Quantitation limit is greater than the calculated regulatory 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 evaluating the testing of CO2

streams.

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

pressure. The concentration limits for hazardous waste constituents 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 aqueous solution to leach out potentially hazardous 

contaminants. The concentration of constituents in the leachate is compared to the RCRA 

concentration limits (see Exhibit A-1). If 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 fluid, or dense liquid under high pressure.

58 CO2 streams 

captured for the purposes of injection will typically be either gas, supercritical fluids, or

liquids under high pressure. At the point of capture CO2 streams will typically be in the gas 

phase (14.5 to 500 psi).

59 Transport and injection is commonly as a dense liquid or 

supercritical fluid.60 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. 

 

58 A supercritical fluid has properties of a gas and properties of a liquid, but is neither. CO2 must be compressed 

to approximately 1100 psi to become supercritical and is normally injected as a supercritical fluid. CO2 will 

most likely be transported by pipeline for technical and 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

59 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.

60 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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Issue 3: Measurement of Concentrations in Supercritical and Liquid Under High Pressure

CO2 Streams is Complex. CO2 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 CO2 stream due to differences in the density and the 

compressibility of the components. The concentration of components in CO2 in a 

supercritical or liquid under high pressure state may not be representative of the composition 

at a lower pressure.

A.3 Options and Associated Costs for Testing CO2 Stream

This section presents four options and costs for testing a CO2 Stream:

Option 1 – Testing CO2 Stream as a Gas;

Option 2 – Testing CO2 Stream as a Supercritical Fluid or Liquid Under High 

Pressure;

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

Characterization Requirements; and

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

Option 1 – Testing CO2 Stream as a Gas

Under this option, facilities that generate CO2 as a gas will sample the gas at a low pressure 

prior to compression and transport of the CO2 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 Exhibit A-1, but this Option 1 scenario includes 

full characterization of all listed RCRA contaminants to account for all potential processes 

that may generate CO2 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 

collect a representative sample of the CO2 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 CO2 stream characterization. Construction of a sampling 

port would require stainless steel or similar metal to ensure sample quality and minimize the 

effects of the corrosive CO2 stream. Samples of the CO2 stream would be collected for 

verification of characterization annually, and the sampling program would also include 

collection of quality control samples for verification. Note that this analysis does not estimate 

the cost of testing the CO2 stream for corrosivity; however, the generator would be required 

to determine if the CO2 stream meets the corrosivity characteristic which would incur similar 

cost for developing the approach and performing the tests. 
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As mentioned in Issue 1 above, there is currently no guidance for determining if a gas 

contains a concentration of hazardous contaminants above the RCRA toxicity characteristic 

limits in Exhibit A-1. Therefore, a facility would need to construct a methodology to relate 

the sampled gas concentrations to the liquid concentration units (milligrams per liter) 

specified in the RCRA regulations for direct comparison. This desktop analysis would 

require a senior level chemist or chemical engineer to develop and document a calculation 

method to convert the gas concentration measurements to liquid concentration measurements 

considering all the physical and chemical properties of the CO2 stream and listed 

constituents. We have not developed the details 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 informal RCRA solid waste screening procedures for 

soils that convert the soil concentration measurements (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. 

Exhibit A-2: Labor Hours and Costs for Option 1: Testing CO2 Stream as a Gas

Labor Time:

Labor Category

Frequency of 

Occurrence Hours

Senior Chemist One-time 40

Chemist Annual 12

Sampling Technician Annual 4

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

Option 2 – Testing CO2 Stream as a Supercritical Fluid or Liquid Under High Pressure

Under this option, facilities that generate CO2 as a gas would compress the CO2 stream to 

supercritical fluid or liquid under high pressure conditions for transport and then sample it as 

supercritical fluid or liquid under high pressure. A special sampling port designed for high 

pressure and corrosive fluids would be required on the high pressure CO2 stream line. CO2

generator facilities would likely not have such a port already installed under normal 
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operations, therefore the cost of installation would 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 high 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 

option assumes that the facility would develop 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 therefore 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 liquid concentration units (milligrams per liter). 

As in Option 1, a facility would need to construct a methodology to relate the sampled gas 

concentrations to a liquid concentration for direct 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 CO2 Stream as a 

Supercritical Fluid or Liquid Under High Pressure

Labor Time:

Labor Category

Frequency of

Occurrence Hours

Senior Chemist One-time 200

Chemist Annual 12

Sampling Technician Annual 4

Vendor/Equipment Costs:

Cost Category

Frequency of 

Occurrence Cost

Facility Improvement (installation of One-time $5,000
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sampling port)

Sampling Equipment Annual $200

Sample Analysis (includes QC sample) Annual $2,448

Vendor/Equipment Subtotal $7,648 (first year)

$2,648 annually

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 the 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 CO2 stream is assumed to be subjected to some treatment of 

impurities and solids prior to transport to support 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 CO2 stream is from a coal or gas fired combustion source that has undergone some 

particulate and VOC removal, and it is unlikely 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.61

The generator would be required to document the CO2 stream generation process and the 

rationale for how the RCRA hazardous waste determination 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.

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

Senior Chemist One-time 40

Chemist Annual 12

Sampling Technician Annual 2

 

61 We recognize that, besides mercury, other heavy metals such as arsenic and selenium may be present at very 

low levels.
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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

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

Facilities that inject the CO2 would have responsibility to confirm the characteristics of the 

waste stream to ensure it has been properly characterized by the generator. CO2 received for 

injection by pipeline may be commingled from multiple sources and have a range of nonCO2 constituents. Under Option 4, an injection facility would test a sample of the CO2 stream 

annually for RCRA constituents at the point where ownership of the CO2 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 CO2 stream composition testing required under the UIC Class VI and 

would use the same sampling port, but would analyze for different 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).62 As in Option 1, an injection 

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 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

Senior Chemist One-time 40

Chemist Annual 12

 

62 Alternatively an injection facility could consider assessing the 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 

the facility to estimate the concentration of supercritical or gaseous CO2 for comparison to RCRA toxicity

characteristic standards. 
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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

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.

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 Category Range of Costs

Frequency of 

Cost Occurrence Notes Data Source

Sampling Costs

Sampling port 

installation

$2,500 1 Probably already exists for 

operational or other 

compliance related sampling

Assumed cost is similar to 

installing pressure relief 

valve. Ref: 2009 Means 

Heavy constr/Envl cost Book, 

not high pressure.

Sampling equipment $450 rental of Multi Train 

Sampling eqpt (max cost)

1 test per year SUMMA sampling 

containers or sampling train 

for sorbent tube for 

VOST/metals

Commercial Lab Price 

list(CAS), published 

equipment vendors prices

Technician 4 hrs 1 per year ICF Estimate

Analytical Laboratory Costs

 Metals $249 2 (1 sample and 1 

QC)

Multi-metal train RS Means Env'l Remediation 

Unit Costs

 VOC $294 2 (1 sample and 1 

QC)

TO-15 or RCRA 0030 RS Means Env'l Remediation 

Unit Costs

 SVOC $440 2 (1 sample and 1 

QC)

TO-13 RS Means Env'l Remediation 

Unit Costs

 Pesticides $241 2 (1 sample and 1 

QC)

TO-4 RS Means Env'l Remediation 

Unit Costs

$1,224 

Interpretation and Documentation Costs

Senior Level Chemist 

Chem Eng.

40 hrs 1 initial Develop correlation for gas 

samples to RCRA Tox Char 

limits

ICF Estimate

Mid Level Chemist 12 annual QC data, Compare results, 

prepare report

ICF Estimate
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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 Category Range of Costs

Frequency of 

Cost Occurrence Notes Data Source

Sampling Costs

Sampling port installation $5,000 1 Probably does not exist for 

operational or other 

compliance related 

sampling

Assumed cost is similar to 

installing pressure relief 

valve. Ref: 2009 Means 

Heavy constr/Envl cost 

Book- doubled cost of iron 

bronze valve to account for 

high pressure and noncorrosive materials.

Sampling equipment $200 for bomb 

sampler rental

2 samples - 1 QC 

1 sample

Pressurized pipeline or 

downhole sampling bomb

Technician 4 1 per year

Analytical Laboratory Costs

 Metals $249 2 (1 sample and 1 

QC)

Multi-metal train RS Means Env'l Remediation 

Unit Costs

 VOC $294 2 (1 sample and 1 

QC)

TO-15 or RCRA 0030 RS Means Env'l Remediation 

Unit Costs

 SVOC $440 2 (1 sample and 1 

QC)

TO-13 RS Means Env'l Remediation 

Unit Costs

 Pesticides $241 2 (1 sample and 1 

QC)

TO-4 RS Means Env'l Remediation 

Unit Costs

Interpretation and Documentation Costs

Senior Level Chemist Chem Eng. 160 hrs 1 initial Method Development and 

verification for analyzing 

supercritical fluids or 

liquids under high pressure

ICF Estimate from Analytical 

Chemist with expertise in 

method development and 

supercritical and liquid under 

high pressure waste processes

Senior Level Chemist Chem Eng. 40 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: CO2 is tested at point of generation as gas, but only for selected compounds. Use process knowledge to characterize waste

Cost Category Range of Costs

Frequency of 

Cost Occurrence Notes Data Source

Sampling Costs

Sampling port installation $0 0 Process system already has 

sampling ports for existing 

QC testing within system 

that can be used for process 

waste characterization 

Sampling equipment $95 per canister+ $20 for flow 

controller (or $105 for 

Sorbent tube)

1 Rental of Manual Sampling 

Train for Metals

Technician 2 1 per year Sampling metals only

Analytical Laboratory Costs

 Mercury only $30.50 2 (1 sample and 1 

QC)

Mercury EPA Method 245.2 RS Means Env'l Remediation 

Unit Costs

 VOC $294 2 (1 sample and 1 

QC)

TO-15 or RCRA 0030 RS Means Env'l Remediation 

Unit Costs

 SVOC $440 2 (1 sample and 1 

QC)

TO-13 RS Means Env'l Remediation 

Unit Costs

Interpretation and Documentation Costs

Senior Level Chemist Chem 

Eng.

40 1 initial Documentation of Process to 

demonstrate knowledge of 

system and wastes. 

ICF Estimate from Analytical 

Chemist

Mid Level Chemist 12 annual QC data, Compare results, 

prepare report

ICF Estimate
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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 composition

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 CO2

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 CO2 streams such that it is non-RCRA 

hazaroudous. Section B.1 summaries the three major capture technology systems and 

associated treatment options. Section B.2 presents the treatment costs.

B.1 CO2 Capture Technologies and Treatment Options for CO2 Streams

Currently, there are three major CO2 capture technology systems, with two based on 

pulverized coal system, and one based on gasification: 

Post-combustion capture involves the capture of CO2 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 CO2

binds with the solvent and the flue gas, separated from most of its CO2, is sent to the 

stack. The CO2-rich solvent is pumped to a regeneration vessel (or stripper) through 

a heat exchanger. Under a higher atmospheric pressure and temperatures (ranging 

from 100 to 140oC

63), the solvent is regenerated and CO2 is stripped. The heat 

supplied to the regeneration vessel to strip CO2 from the solvent carries a significant 

energy cost.64 The CO2 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.65 Amine 

scrubbing system is currently a proven technology and it is capable of removing 

between 80% and 95% CO2 from a flue gas stream. However, acid gases such as NOx

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

tower.66

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 CO2 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 CO2, which 

is then dehydrated and purified. The nearly pure CO2 stream is then compressed for 

transportation and storage.67 

 

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

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

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

66 NOx and SOx reacts with the amine and will result in a reduction in solvent performance, higher chemical 

consumption, and poor economic performance.

67 Alstom, Oxyfuel combustion capture.
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Pre-combustion capture is mostly applicable to gasification-based system such as 

Integrated Gasification Combined Cycle (IGCC) 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, H2, H2O. 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 H2S, is not removed during 

gas treatment stage, but rather removed in the CO2 removal stage using a two-stage 

Selexol process, for example. The separated H2S 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 SOx and NOx, as discussed earlier, and therefore the CO2

streams from power plants with post-combustion capture are not expected to have these 

hazardous components. However, the CO2 streams could contain other hazardous elements 

that are present in coal, such as mercury, arsenic, cadmium, etc.

In oxyfuel and gasification based systems, however, there are process options that could be 

added or taken out such that the hazardous components in the CO2 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 SOx from a flue gas can be taken out. With a FGD 

within the recirculating stream removing about 98% of the SOx, the SOx

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 SOx in the CO2

stream would be more than 100 times lower (i.e., 0.01%), compared to a CO2 stream 

without FGD (1%). However, one needs to consider the economic impact of adding 

an FGD. Furthermore, the production of NOx in an oxyfuel system is significantly 

lower because of the use of oxygen instead of air as an oxidant for combustion, and 

NOx concentration could be about 40 ppm.68

In an IGCC system, there is an option of removing both H2S and CO2 using a single 

stage Selexol gas separation process, instead of two stages (one stage for H2S and 

another for CO2), as mentioned earlier. The single stage process eliminates the need 

for the sulfur processing and handling facilities (which is typically used to convert 

H2S 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.

 

68 See Case C2 of Table 3.8 in IEA 2004 – “Impact of Impurities in CO2 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 H2S and CO2 vs. separated capture of CO2 and H2S 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 0.175

Weight Cost of Capital 9.67%

Levelization Factor for FOM and 

VOM 1.1568

price of 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.69 The 

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

• Equipment (complete with initial chemical and catalyst loadings),

• Materials,

• Labor (direct and indirect),

• Engineering and construction management, and

• Contingencies (process and project).

Owner‟s costs are excluded from the total plant cost.70 

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.

 

69 Table 1.1.9 in NIPA Section 1, published by Bureau of Economic Analysis, published July 30, 2010.

70 Costs do not account for environmental permitting costs. It is assumed that treatment can be conducted under 

existing facility permits, including under the provisions for onsite hazardous waste treatment by hazardous 

waste large quantity generators under 40 CFR 260.10 and related provisions. 
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FGD for Oxyfuel systems

The economic analysis for the oxyfuel system was based on Case 5 of the NETL, 2008 

report. Case 5 is a 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 CO2 stream is scrubbed of SO2. The CO2 stream after 

the flue gas recycle is only dehydrated to 0.015% by volume, such that the CO2 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.71 The cost of the FGD was given in 2006 dollars and was converted to 1st quarter 2010 

dollars using the NIPA tables from BEA as shown in Exhibit B-2 in the “FGD” column. 

Therefore, the cost of the FGD was subtracted from the Case 5 numbers to derive the cost of 

the plant without an FGD.

It was assumed that the same amount of fuel and oxidant would be used in this case, and the 

only change was the removal of the FGD. Reduction 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.72

Exhibit B-2 below shows the key assumptions and results for the two oxyfuel cases, with and 

without FGD, and differences between the two (“FGD” column) highlights the impact of 

adding an FGD to treat the CO2 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.

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 CO2 tons/hr 592.58

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

 

71 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). 

72 See Table 5-8 of NETL, 2008.
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Oxyfuel System

Unit

Without 

FGD

With FGD 

(case 5)

FGD

Levelized Cost 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

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) CO2 capture. In Case 1, a one stage selexol unit is used for separating H2S 

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 H2S, and subsequently separating the CO2 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 H2S and CO2 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 2.73 The differential in fixed cost was assumed to be same in the 

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 1st

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 the 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.74 The difference between the two options was about 15 MW.

 

73 See Exhibit 3-46, account 5A of NETL, 2007 report.

74 See Exhibit 3-34 of NETL, 2007 report.
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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 CO2 tons/hr 505.65

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 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
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Appendix C.

Sensitivity Analyses

This appendix considers the costs and savings under two sets of assumptions that differ 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 CO2 streams in the 

baseline.

Sensitivity Analysis 1 – Fewer Affected Facilities

The main analysis in this document considers the impacts of the proposed rule on both 

existing CO2 capture and sequestration projects and several planned projects 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 proposed rule. All other assumptions are 

consistent with the main analysis. 

This sensitivity analysis considers only 13 capture facilities:

10 existing capture facilities,

2 capture projects associated with named DOE pilot projects, and

1 capture facility associated 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 federal/private partnerships.

Exhibit C-1 presents the number of CO2 capture and sequestration facilities expected to begin 

sequestration activities in each year under the proposed rule.

Exhibit C-1: CO2 Capture and Sequestration Facilities Assumed to Begin and Practice 

Sequestration Activities by Year Under Sensitivity Analysis 1

Year

Number of CO2 

Facilities Beginning 

Sequestration of their 

CO2 Streams

Total Number of CO2 

Facilities Practicing 

Sequestration of their 

CO2 Streams

Number of Sequestration 

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
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Year

Number of CO2 

Facilities Beginning 

Sequestration of their 

CO2 Streams

Total Number of CO2 

Facilities Practicing 

Sequestration of their 

CO2 Streams

Number of Sequestration 

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 summarizes 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 rates 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, the proposed rule is expected to result in undiscounted average net 

savings of approximately $30.0 million. Applying a 3 percent discount rate, the annualized 

net savings are approximately $24.7 million. Applying a 7 percent discount rate, the 

annualized net savings are approximately $18.7 million. 

Exhibit 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 Savings 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 Facilities $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 

Sensitivity Analysis 2 – 90 Percent of CO2 Capture Facilities Generate Streams are Nonhazardous in the Baseline

The main analysis in this document conservatively assumes that, in the baseline, 90 percent 

of CO2 capture facilities generate streams that are hazardous in the baseline. This sensitivity 

analysis makes the opposite assumption – that 90 percent of CO2 capture facilities generate 

streams that are non-hazardous in the baseline. Consequently, this sensitivity analysis 

assumes a different prevalence of baseline practices by CO2 capture and sequestration 

facilities. All other assumptions are consistent with the main analysis. Exhibits C-5 presents

the assumptions of this sensitivity analysis regarding the relative prevalence of each baseline 

practice in the absence of the proposed rule for CO2 capture facilities.
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Exhibit C-5: Assumed Prevalence of Hazardous Waste Determination and Baseline 

Practices for CO2 Capture Facilities

Hazardous Waste 

Determination Baseline Practice

Assumed Baseline 

Percentage of Capture 

Facilities 

Non-hazardous Send the CO2 stream to a Class VI well 90 %

Hazardous

Cease capture 3.3 %

Send the CO2 stream to a Class I well 

that is assumed to meet the Class VI 

requirements 

3.3 %

Treat the CO2 stream such that the 

stream is non-hazardous and send it to a 

Class VI well

3.3 %

Corresponding to the baseline practices of capture facilities, this sensitivity analysis assumes 

that, in the baseline, approximately 97 percent of the sequestration facilities would manage 

untreated and treated non-hazardous CO2 in Class VI wells. The remaining sequestration 

wells would manage RCRA hazardous CO2 streams as Class I hazardous waste wells. 75 

Exhibit C-6 summarizes the undiscounted 50-year and annualized costs and benefits of the 

proposed rule under the assumptions of this sensitivity analysis. Exhibits 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 are approximately $8.5 million. Applying a 7 

percent discount rate, the annualized net savings are approximately $7.3 million. 

 

75 This sensitivity analysis assumes that 93 percent of CO2capture facilities would transport non-hazardous or 

treated CO2streams to Class VI sequestration wells for injection. Another 3.3 percent of CO2 capture facilities 

would transport hazardous CO2 streams to Class I sequestration wells for injection. Under this assumption, 93 

out of 97 (97 percent) of CO2 capture facilities injecting into a sequestration well transport their waste to Class 

VI wells. The analysis assumes that 97 percent of CO2 sequestration wells are Class VI wells to match the 

practices of CO2 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-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 C-8: Net Costs and Savings of the Proposed Rule Under Sensitivity Analysis 2 –

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 
Appendix D.

Assessment of Environmental Justice Impacts

D.1 Introduction

Executive Order 12898 (59 FR 7629, February 16, 1994) establishes Federal executive policy 

on environmental justice. It applies to agency “programs, policies, and activities” and in 

general calls on each federal agency to make achieving 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 potential EJ impacts associated with the proposed 

RCRA conditional exclusion at 40 CFR 261.4(h). Section D.2 provides background on the 

proposed rule. Section D.3 presents a comparison of the federal regulations applicable to 

generators of hazardous waste CO2, pipelines, and geological sequestration (GS) facilities 

operating under the baseline requirements and proposed RCRA exclusion. The comparison 

identifies key regulatory differences. Section D.4 presents a screening analysis of EJ impacts 

associated with generators and GS facilities that might claim the exclusion. The screening 

analysis examines indicators (e.g., income, race, age) of populations living within a 1- and 3-

mile radius of the facilities, to identify vulnerable populations. Section D.5 presents a 

qualitative screening assessment of potential EJ impacts associated with pipelines that might 

be used to transport CO2 under the proposed rule.76 Section D.6 summarizes the conclusions 

of these analyses and identifies possible next steps.

D.2 Background on Proposed Rule

EPA is proposing a conditional exclusion from the definition of hazardous waste for carbon 

dioxide (CO2) streams that are captured, transported, and injected into a well subject to the 

requirements for Class VI Underground 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 CO2 stream is exempt under section 

261.4(h) to have an authorized representative sign a certification statement worded as 

specified. The exclusion would only apply to the CO2 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, CO2 streams. The exclusion would be codified at 40 CFR 261.4(h).

 

76 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 affected by EPA‟s proposed action:

Generators (i.e., capture facilities). Electric power plants and other industrial facilities 

generate CO2 as a byproduct of their operations. CO2 capture facilities are entities 

that collect their CO2 byproducts and manage them in a manner other than releasing 

them into the environment. EPA estimates that 27 facilities might capture CO2 and 

claim the exclusion as a generator under the proposal. These facilities include 

planned or existing fossil-fuel burning utilities, gas and fertilizer plants, and DOE 

projects. This waste CO2 would qualify as a RCRA hazardous waste if it exhibits any 

of the RCRA hazardous characteristics. 

Pipelines. Captured CO2 is typically is transported by pipeline. As of 2008, there 

were 30 operating CO2 pipelines, operated by 29 separate entities.77 

GS Facilities. EPA estimates that 29 geological sequestration facilities might claim 

the exclusion. Geological sequestration (GS) refers to the process of injecting CO2

captured from an emission source (e.g., a power plant) into deep subsurface rock 

formations in order to permanently isolate the CO2.

D.3 Comparative Analysis

This section presents a summary comparison of the federal regulations applicable to 

generators of hazardous waste CO2 and geological sequestration (GS) facilities operating 

under the baseline requirements and proposed RCRA exclusion. The design and function of 

the regulatory comparison in this chapter is meant to help facilitate an initial appraisal of 

regulatory requirements for the environmental justice analysis. This comparison is not 

intended to represent conclusions about risk but instead broadly indentify areas where 

regulatory requirements appear to be reduced or increased for those CO2 streams that would 

be RCRA hazardous. Additionally, the comparison is not intended to compare regulatory 

requirements for CO2 streams found to be non-hazardous under RCRA. 

EPA developed Exhibit D-1 for purposes of comparing these federal regulations. Column 1 

of the exhibit presents the RCRA hazardous waste regulations and other federal regulations 

applicable to generators, pipelines and GS facilities operating under the hazardous waste 

regulatory program.78 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 regulations 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 

 

77 Department of Transportation, Pipeline and Hazardous Materials Safety Administration (PHMSA), 2008 

Hazardous Liquids Annual Data 

http://www.phmsa.dot.gov/staticfiles/PHMSA/DownloadableFiles/Files/LIQANN08.zip.

78 Column 1 presents hazardous waste regulations applicable to large quantity generators only.
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generators, pipelines, and GS facilities operating under the federal hazardous waste 

regulations (Column 1).

Below is a brief summary of the regulatory comparison for CO2 streams found to be RCRA 

hazardous waste under the current regulations to CO2 streams that would be governed under 

the proposed rule. 

Generators of hazardous CO2 operating under the proposed conditional exclusion

would be subject to less stringent federal 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 reporting 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 CO2 streams managed under the proposed conditional exclusion

would be subject to the same federal regulations as pipelines carrying CO2 streams 

managed under the baseline. Pipeline transport of CO2 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 CO2 operating under the proposed conditional exclusion

(i.e., facilities subject to Class VI UIC requirements) 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 for siting, determining the area of review, 

monitoring of groundwater quality and potentially other environmental media. Note, 

however, that for this analysis EPA assumes that a Class I hazardous well used for 

injection of hazardous waste CO2 streams under the baseline would also be required 

by the permit writers to meet the Class VI UIC well requirements. There is no 

regulatory requirement, however, that permit writers apply the Class VI requirements 

to Class I hazardous waste wells.
Exhibit D-1. Comparison of Federal Regulations Applicable to Facilities and Pipelines Operating Under the Baseline and Proposed Rule

Federal Regulations Applicable to Facilities and 

Pipelines Operating under the Baseline

Federal Regulations Applicable to Facilities and 

Pipelines Operating under the Proposed Rule

Comments

1. Generatorsa

Reporting and Recordkeeping

RCRA Regulations

Notification under RCRA 3010 to obtain EPA 

identification number (40 CFR 262.12)

Biennial reporting of hazardous waste quantities and 

types (40 CFR 262.41)

Recordkeeping of biennial report, waste analyses, 

and other documents as specified (40 CFR 262.40)

Recordkeeping and annual renewal of signed 

certification statement. Certification must be 

provided to EPA if requested (40 CFR 261.4(h))

Reporting requirements under CAA subpart PP (40 

CFR 98.420) for suppliers (generators) of CO2, and 

subpart RR (40 CFR 98.440) for geological 

sequestration facilities. 

The proposed rule does not include initial or 

ongoing notification or reporting to EPA on 

their activities as do the hazardous waste 

regulations. However, it requires facilities to 

renew the certification annually and provide it 

to EPA if requested

The baseline and proposed rule require 

facilities to keep specified records to 

demonstrate their compliance with applicable 

requirements

Emergency Preparedness and Response

RCRA Regulations

Personnel training on emergencies (40 CFR 262.34 

and 265.16)

Contingency planning, emergency procedures, and 

emergency equipment (40 CFR Part 265, Subpart C 

and D)

No relevant requirement The proposed rule does not require facilities to 

prepare for or respond to emergencies, as do 

the hazardous waste regulations. Refer to 

“Other Regulations” below for information on 

other federal regulations that might require 

emergency preparedness and response

Other Federal Regulations

CAA (Chemical Accident Prevention): A facility that is a stationary source that has more than a threshold quantity 

of a “regulated substance” in a process must develop and implement a risk management program under 40 CFR 

Part 68. Facilities with a process subject to Program 2 or 3 (e.g., a process that has had an accidental release 

within the past five years with offsite consequences as specified) must prepare an emergency response program or 

make alternative arrangements with offsite authorities b

These other federal regulations establish 

requirements for emergency preparedness that 

may be comparable to the hazardous waste 

requirements in some cases. However, it is 

doubtful that these requirements will address 

all facilities and potential releases to the same 

extent as the hazardous waste regulations. 

First, most of these regulations give facilities 

the option of developing either an emergency 

response plan or evacuation plan. An 

evacuation plan is not comparable to the 

hazardous waste requirements (e.g., for 

CERCLA/EPCRA (Emergency Notification): A generator must immediately notify the National Response Center 

of a release of hazardous substance equal to or exceeding its reportable quantity in any 24-hour period, as required 

at 40 CFR Part 302 b

OSH Act (Process Safety Management): A facility that has a process (e.g., use, storage, handling) which involves 

a “highly hazardous chemical” at or above specified quantity must have an evacuation plan, as required at 29 CFR 

1910.38 and 1910.119 b
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Federal Regulations Applicable to Facilities and 

Pipelines Operating under the Baseline

Federal Regulations Applicable to Facilities and 

Pipelines Operating under the Proposed Rule

Comments

OSH Act (Hazardous Waste Operations and Emergency Response (HAZWOPER)): A facility is required to 

establish an emergency response program if it has employees who are responsible for emergency response 

operations for releases of, or substantial threats of releases of, hazardous substances without regard to the location 

of the hazard (e.g., anywhere at the facility), such as designated response employees, as required by 29 CFR 

1910.120(q). If the facility will evacuate employees and will not allow employees to assist in response, it need 

not prepare an emergency response plan. It must prepare an evacuation plan b

personnel training and equipment to address 

onsite releases). In addition, most of these 

regulations are triggered only when a 

CERCLA hazardous substance exceeds a 

specified quantity (e.g., threshold quantity). A 

carbon dioxide stream may contain hydrogen 

sulfide, mercury, and/or other chemicals that 

are CERCLA hazardous substances. 

However, these substances must be present in 

sufficient quantities to trigger the specified 

regulatory quantity. For example, the 

threshold quantity for hydrogen sulfide in 40 

CFR Part 68 is 10,000 pounds. Hence, a 

facility‟s carbon dioxide stream would not be 

subject to these emergency requirements if it 

does not contain a hazardous substance that 

exceeds its respective threshold quantity. 

Carbon dioxide itself is not a hazardous 

substance 

NA OSH Act (Hazard Communication): Facilities must 

provide information to their employees about any 

chemical (except hazardous waste) which is a physical 

or health hazard to which they are exposed, by means 

of a hazard communication program, labels and other 

forms of warning, material safety data sheets, and 

information and training (e.g., hazards detection, 

emergency procedures), as required at 29 CFR 

1910.1200. Hazardous wastes are exempt from these 

provisions 

Waste Treatment

RCRA Regulations

Hazardous waste must be treated to applicable 

treatment standards or be disposed of in a nomigration unit (40 CFR Part 268)

No relevant requirement The proposed rule does not require treatment 

of waste CO2 streams or, alternatively, 

disposal of untreated waste in a unit with a nomigration variance, as do the hazardous waste 

regulations

2. Pipelines

RCRA Regulations

RCRA does not regulate transportation by pipeline Refer to “Other Regulations” below for 

information on other federal regulations that 

apply to pipelines

Other Federal Regulations

Pipeline transportation of CO2 is subject to DOT regulation. For example, 49 CFR Part 195 applies to pipeline 

facilities and the transportation of hazardous liquids or carbon dioxide associated with those facilities in or 

affecting interstate or foreign commerce, except as otherwise specified 

Pipeline transport of CO2 would be subject to 

DOT regulation under both the baseline and 

proposed rule

3. Geological Sequestration Facilities
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Federal Regulations Applicable to Facilities and 

Pipelines Operating under the Baseline

Federal Regulations Applicable to Facilities and 

Pipelines Operating under the Proposed Rule

Comments

RCRA Regulations

Class I injection wells disposing of hazardous waste are 

permitted by rule under RCRA if they meet the 

requirements of 40 CFR 270.60:

Have a UIC permit

Comply with UIC permit conditions and applicable 

UIC requirements at 40 CFR 144.14

Comply with 40 CFR 246.101 (i.e., corrective action)

Submit permit application information on solid waste 

management units at the facility, if applicable

Class VI UIC wells disposing of exempt CO2 must 

meet the requirements of 40 CFR 261.4(h)(1):

Be subject to Class VI UIC program, including UIC 

requirements at 40 CFR Parts 144 and 146

Dispose of CO2 streams, but not CO2 streams that are 

mixed with or otherwise co-injected with hazardous 

waste

Keep onsite records of signed certification statement, 

renew it annually, and provide it to EPA if requested

The baseline regulations establish a permitby-rule program for Class I wells injecting 

hazardous waste that meet specified 

requirements. The proposed rule would allow 

Class VI wells to inject exempt CO2 streams, 

provided that the generator and well 

owner/operator claim the exclusion and meet 

specified conditions. The baseline and 

proposed rule both rely heavily on the UIC 

program requirements (e.g., permit 

conditions) to ensure protective management 

and disposal of the waste. Both also establish 

additional administrative requirements as 

needed to ensure compliance (e.g., 

recordkeeping and reporting)

Refer to “Other Regulations” below for 

information on other federal regulations that 

apply to pipelines

Other Federal Regulations

The 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 care

In addition, Class I hazardous injection wells also may be subject to the no-migration requirements of 40 CFR 

Part 148 if they will dispose of RCRA hazardous wastes that do not meet applicable treatment standards

The UIC Class I hazardous regulations differ 

from the UIC Class VI regulations in a 

number of ways. Some key differences 

include the following:c

Class VI regulations impose additional 

siting standards. For example, at the 

Director‟s discretion, the owner/operator 

must characterize additional zones that will 

impede vertical fluid movement, allow for 

pressure dissipation, are free of faults and 

fractures, and provide additional 

opportunities for monitoring, mitigation and 

remediation
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Federal Regulations Applicable to Facilities and 

Pipelines Operating under the Baseline

Federal Regulations Applicable to Facilities and 

Pipelines Operating under the Proposed Rule

Comments

The Class I hazardous regulations require 

that the area of review (AoR) be a fixed 

distance of 2 miles around the well, whereas 

the Class VI regulations require AoR radius 

to be determined based on site-specific 

computational modeling that accounts for 

the physical and chemical properties of all 

phases of the injected CO2 stream, CO2

plume, and pressure front over an 

appropriate timeframe. In addition, Class 

VI regulations require continual reassessment of the AoR radius

Class VI regulations require same 

monitoring during well operation as Class I 

hazardous regulations, in addition to 

monitoring of groundwater quality and 

geochemical changes above the confining 

zone. In addition, surface air monitoring 

and soil monitoring may be required at the 

Director‟s discretion. The owner/operator 

must submit and gain approval of the 

monitoring plan before injection

Class VI regulations establish a 50-year 

post-closure period during which the 

owner/operator must conduct monitoring. 

The Class I regulations do not require a 50-

year post-closure period

a Column 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 the 

applicable threshold quantity spelled out in these federal regulations, it would trigger the emergency requirements, as applicable. For example, the threshold quantity for 

hydrogen 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 a 

hazardous substance that exceeds its respective threshold quantity. Carbon dioxide itself is not a hazardous substance. Note that the requirements of 29 CFR 1910.120(q) 

and 1910.1200 are not triggered by threshold quantities. 
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c EPA anticipates that a Class I well used for injection of hazardous waste CO2 streams would also be required by the permit writers to meet the Class VI UIC well 

requirements; however, there is no regulatory requirement that permit writers apply the Class VI requirements to Class I wells.
D.4 Screening Analysis of Capture and GS Facilities

This section presents an EJ screening analysis of carbon capture and GS facilities with known 

locations that might claim the exclusion. Similar to the regulatory comparison found in D.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.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 capture facilities, and DOE and FutureGen 

GS projects that may claim the exclusion. Please note the following:

EPA estimates that 27 capture facilities may claim the exclusion, 

including 14 planned major commercial facilities, one FutureGen facility, 

10 existing fertilizer and gas facilities, and two DOE sequestration 

projects. These facilities are included in this screening analysis. 

Appendix D.A. identifies the 31 facilities (33 less two DOE dual facilities) 

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 analysis 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. 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 Registry System (FRS), which is a 

centrally managed database, to ascertain the location of these 

sites.79 This indicator is meant to clarify the proximity and 

 

79 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 Information System (RCRAInfo), Aerometric Information 
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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 falling 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.B. A summary of the data is presented in Section D.4.2.

D.4.2 Results

Exhibits D-2 and D-3 summarize the results of the screening analysis. Exhibit D-2 presents the 

results of the analysis of indicators within a 1-mile radius of facilities and Exhibit D-3 presents 

the results for the analysis of indicators within a 3-mile radius of facilities. Each exhibit lists the 

facilities alphabetically, indicates its type (e.g., commercial capture), and uses an “X” to indicate 

if an indicator within its radius exceeds the state percentage. In addition, each exhibit uses gray 

shading to identify facilities whose minority populations and/or low-income populations (i.e., 

 

Retrieval System (AIRS)/AIRS Facility Subsystem, and Comprehensive Environmental Response, Compensation, 

and Liability Information System (CERCLIS). For additional information, refer to 

http://www.epa.gov/enviro/html/.
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Page 92 of 133

populations living below 150% of the poverty level) exceed the state percentage, as these may be 

among the most vulnerable populations80.

Exhibit D-2 shows the following in regard to population characteristics within a 1-mile radius of 

the facilities:

21 of the 31 GS and capture facilities examined (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.81 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. 

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 located 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.

 

80 This analysis focuses on selected demographics surrounding the identified capture and sequestration facilities. 

We have not conducted an exposure or risk assessment of CO2 sequestration in Class I or Class VI facilities. Our 

experience with deep well injection indicates that the risk of exposure resulting from CO2 movement outside of the 

permitted injection zone is low. However, we recognize that there is a potential for CO2 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. 

81 These 3 facilities are a subset of the 21 facilities noted above.
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Exhibit D-3 shows the following in regard to population characteristics within a 3-mile radius of 

the facilities:

20 of the 31 GS and capture facilities examined (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.82 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 facilities have 2 sites located within their 3-

mile radius, 5 facilities have 3 sites located 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.B. for detailed data on the incidence of the indicators within a 1- and 3-

mile radius of the facilities.

 

82 These 4 facilities are a subset of the 20 facilities noted above.
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Exhibit D-2. Characteristics of Populations within 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

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 - X 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

Project

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) exceed the state percentage, as these may be among the most 

vulnerable populations.

**The1-mile radius around these facilities falls in two states. The population within the 1-mile radius was allocated 

proportionally to the two states (i.e., creating two mutually exclusive population groups, one for each state), as described 

in the methodology. The indicator in this exhibit has an asterisk to indicate that one of the population groups for this 

facility exceeded its respective state average, while the other population group did not.
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Exhibit D-3. Characteristics of Populations within 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 

% Minority Land?

(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
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

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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 

% Minority Land?

(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) exceed the state percentage, as these may be among the most 

vulnerable populations.

**The 3-mile radius around these facilities falls in two states. The population within the 3-mile radius was allocated 

proportionally to the two states (i.e., creating two mutually exclusive population groups, one for each state), as described 

in the methodology. The indicator in this exhibit has an asterisk to indicate that one of the population groups for this 

facility exceeded its respective state‟s average, while the other population group did not.

D.5 Qualitative Screening Analysis of Pipelines

This section presents a qualitative screening analysis of EJ issues associated with pipelines 

carrying carbon dioxide (CO2) under the proposed RCRA conditional exclusion. The analysis 

provides a preliminary characterization of potential health impacts to human populations near the 

pipelines. Section D.5.1 of this document provides background information about the existing 

hazardous waste regulations (i.e., the “baseline”) and proposed rule that would exempt CO2

streams from RCRA regulation. Section D.5.2 describes the likelihood of CO2 pipeline failures 

that could lead to a release. Section D.5.3 describes some of the possible health impacts to 
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surrounding populations from a CO2 pipeline release. Section D.5.4 sets forth some preliminary 

conclusions about CO2 releases from pipelines. 

The primary data source used in this qualitative analysis is the document, “Final Risk 

Assessment Report for the FutureGen Project Environmental Impact Statement,” dated October 

2007.83, 84 The Risk Assessment addresses the potential releases of captured gases at the 

proposed FutureGen power plant, during transportation via pipeline to the geological 

sequestration (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 from other comments received on the Final Risk Assessment. It 

contains peer-reviewed chemical concentration effect levels related to health impacts to human 

and biological receptors.

Note that a quantitative, 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 CO2 pipelines and 

uncertainty exists about the particular pipelines that would be used to transport CO2 streams 

under the baseline and proposed rule by capture facilities that now are being planned. In 

addition, new pipelines may be built to transport CO2 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 qualitative 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.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, CO2 streams that exhibit a RCRA hazardous characteristic under 

40 CFR Part 261 must be classified hazardous waste and managed and disposed of in accordance 

with the RCRA hazardous waste regulations. This includes, for example, treatment of the CO2

stream to meet applicable RCRA treatment standards before land disposal, if applicable, and 

disposal in a UIC well that meets applicable UIC and RCRA requirements. 

A CO2 stream generator under the baseline may have several options for addressing its hazardous 

waste CO2. It may treat the hazardous waste CO2 to render it non-hazardous (i.e., by removing 

the characteristics that make the CO2 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 CO2 stream 

 

83 This document can be found at the following web site: 

http://www.netl.doe.gov/technologies/coalpower/futuregen/EIS/FG%20Risk%20Assessment%20110807.pdf.

84 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 CO2 into geological sequestration (GS) facilities. 
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generator may opt for other methods, such as disposing of untreated RCRA hazardous waste CO2

stream in a UIC Class I hazardous well that that meets applicable no-migration requirements 

under 40 CFR Part 148. 

Pipeline transport of CO2 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 associated with those facilities in or affecting interstate or foreign 

commerce, except as otherwise specified. This regulation includes requirements for the design, 

construction, testing, operation and maintenance, reporting, and corrosion control of pipelines. 

Proposed Rule. Under the proposal, CO2 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. Consequently, generators claiming the exclusion could 

transport and dispose of their CO2 streams as non-hazardous waste in Class VI UIC wells. 

Captured CO2 streams would not be classified as hazardous waste under the proposed rule and 

would therefore not need to be treated before injection in a Class VI UIC well. 

Pipeline transport of CO2 streams under the proposed rule would continue to be subject to U.S. 

DOT regulation. U.S. DOT regulatory requirements for transport of CO2 streams would not be 

affected by the exclusion.

D.5.2 Risks of Pipeline Failure

The FutureGen Risk Assessment presents data concerning the probability of a release from an 

aboveground CO2 pipeline, based on data from the US Department of Transportation Office of 

Pipeline Safety and based on the length of the pipeline.85 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.86

The Risk Assessment based its incident probability calculations on a number of data and 

assumptions, such as the following:

The CO2 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 indicated that 31accidents involving CO2 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).

 

85

 See page 6-14 of the FutureGen Risk Assessment.

86 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 this is an error in converting between mile-year and 

kilometer-year. EPA used the risk values expressed in kilometer-year in preparing Figures 1 and 2.
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Based on the Risk Assessment data and formulas, Figure 1 shows the probability of at least one 

pipeline rupture over a 50 year period, given three different pipeline lengths. Exhibit D-4 shows 

the probability of at least one pipeline puncture over a 50 year period, given three different 

pipeline lengths. For example, Figure 1 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-5 shows that, 

over a 50 year period, there is an estimated 60% probability of a pipeline puncture in a 150 

kilometer pipeline.87 

Exhibit D-4. Probability of CO2 Pipeline Rupture over 50 Year Period: 

50-, 100- and 150-Mile Pipelinesa

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-5. Probability of CO2 Pipeline Puncture over 50 Year Period: 

50-, 100- and 150-Mile Pipelinesa

 

87

 The Risk Assessment identifies some data gaps and limitations 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.
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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.5.3 Potential Health Impacts of CO2 Pipeline Releases

The Risk Assessment describes release simulations from pipeline transmission lines that were 

performed. The simulations examined emissions of CO2 and H2S. The SLAB air dispersion 

model was used to simulate the emission of CO2 for various release scenarios involving the 

pipeline when the gas is in a supercritical gas state.88 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 conditions that affect plume transport;

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

Step 3. Estimate population affected for each atmospheric state;

Step 4. Determine the expected number of individuals potentially affected 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 CO2 releases due to pipeline ruptures or punctures at any 

of the four candidate sites. This is shown in Exhibit D-4. In all cases, the expected number of 

individuals affected is less than one. 

Exhibit D-6 shows that the largest number of people potentially affected by H2S releases is 

associated with pipeline ruptures. The model simulations 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 H2S exposure are predicted 

for pipeline ruptures at the Tuscola Site for 7.4 individuals. Fewer numbers 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 H2S 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 for the Jewett pipeline is one. No adverse or lifethreatening effects are predicted for H2S releases from pipeline ruptures or punctures at the 

Odessa and Mattoon sites.

 

88 The SLAB model was developed by the Lawrence Livermore National Laboratory, and is designed to

simulate denser-than-air gas releases for both horizontal jet and vertically elevated jet scenarios. SLAB is

approved by U.S. EPA as a hazardous air dispersion model.
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Exhibit D-6: Summary of Expected Numbers of Individuals from

the Public Affected by Pipeline Releasesa

Mattoon, 

IL

Tuscola, 

IL

Jewett, 

TX

Odessa, TX

(A) Ruptures

CO2 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

H2S 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

CO2 Health Effects

Adverse 0.01 <0.1 0.2 <0.1

Life Threatening <0.01 <0.1 <0.2 <0.1

H2S Health Effects

Adverse <0.2 1 6 <0.1

Irreversible 

Adverse

0.002 0.02 0.1 0.005

Life Threatening <0.002 <0.02 <0.1 <0.001

a

This exhibit is taken from the “Final Risk Assessment Report for the 

FutureGen Project Environmental Impact Statement,” dated October 2007 

(see page 6-8).

The Risk Assessment concludes that “these results indicate that the potential human-health 

effects due to pipeline ruptures or punctures at all sites are minimal. The primary predicted effect 

identified in the „pipeline-walk‟ analysis in the event of a release is mild transient health effects. 

It is anticipated that the predicted exposures can be avoided since the adverse-effects-level H2S 

concentration (0.51 ppmv) is associated with the perception of an objectionable odor. Likewise, 
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Page 103 of 133

the life threatening effects of H2S exposures are associated with long exposure levels that can be 

detected and avoided.”89 

D.5.4 Preliminary Conclusions on Potential Releases

Under the baseline, generators of hazardous waste CO2 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 would be prohibited. Treatment of the CO2 would 

reduce the presence of metals and other harmful constituents (e.g., hydrogen sulfide) as 

appropriate to render it non-hazardous. Note that some generators may decide to address their 

hazardous waste CO2 streams in other ways (e.g., disposing of untreated hazardous waste CO2

streams in a Class I UIC well that meets no migration requirements).

Under the proposed rule, generators could dispose of their exempt CO2 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 required under the RCRA regulations. As a result, it 

is possible that a greater quantity of untreated CO2 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 CO2 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 CO2 at all under the baseline (e.g., because of treatment 

costs) may be induced to capture it under the proposed 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 CO2 pipelines is related to several factors, including 

the composition of the CO2 stream among other things. A greater quantity of untreated CO2

streams being transported by pipeline under the proposed rule could potentially be associated 

with a higher potential for exposures of hazardous constituents to surrounding populations, 

although the health effects appear to be mild.

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

D.6.1 Comparative Analysis

Results

The comparative analysis identified the following potential regulatory differences: 

 

89 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 generators operating under the baseline in regard 

to RCRA reporting and recordkeeping, emergency preparedness and response, and waste 

treatment. 

Pipelines carrying CO2 streams managed under the proposed conditional exclusion would 

be subject to the same federal regulations as pipelines carrying CO2 streams managed 

under the baseline. In particular, pipeline transport of CO2 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 conditional 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 stringent than, federal regulation of GS facilities 

operating under the baseline (i.e., facilities subject to Class I UIC requirements). For 

example, GS facilities operating under the 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 well used for injection of hazardous waste CO2

streams under the baseline would also be required by the permit writers to meet the Class 

VI UIC well requirements. There is no regulatory requirement, however, that permit 

writers apply the 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.6.2 Screening Analysis of Capture and GS Facilities

Results

EPA‟s screening analysis found that: 

21 of the 31 GS and capture facilities examined (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 examined (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 these 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 information could help EPA better 

understand the potential vulnerabilities and concerns of these populations.

In addition, it is important to note that the screening analysis was not performed on a number of 

planned GS facilities for which EPA does not have 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 CO2 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 would be prohibited. Treatment of the CO2 would 

reduce the presence of metals and other harmful constituents (e.g., hydrogen sulfide) as 

appropriate to render it non-hazardous. Note that some generators may decide to address their 

hazardous waste CO2 streams in other ways.

Under the proposed rule, generators could dispose of their exempt CO2 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 required under the RCRA regulations. As a result, it 

is possible that a greater quantity of untreated CO2 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 pipeline 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 potential for human exposure to hazardous constituents from accidental 

releases from CO2 pipelines is related to several factors, including the composition of the CO2

stream among other things. A greater quantity of untreated CO2 streams being transported by 

pipeline under the proposed rule could potentially be associated with a higher potential for 

exposures of hazardous constituents to surrounding populations, although the health effects 

appear to be mild.

Possible Next Steps

The conclusions of this analysis are based on a single source, i.e., the FutureGen Risk 

Assessment. Additional research and analysis may be appropriate to learn more about the 

potential risks and health impacts to populations near CO2 pipelines. 

Appendix D.A. – Facilities Included in the Environmental Screening Analysis 

The facilities in Exhibits D.A-1 through D.A-3 are included in the EJ screening analysis 

presented in Chapter 4 of this document. 

Exhibit D.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 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.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 36/22/44

97/45/38

Coffeyville Ammonia 

Fertilizer Plant KS 37/05/19

95/43/39

Antrim Gas Plant MI 45/1/27 84/36/7

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

Exhibit D.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 OH

38/54/1

3 84/50/56

San Joaquin Basin, CA 

Saline Formation 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.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.B-1. Percentage of Population that is Minority (by Race and in Total) Within 

1-Mile Radius of Facility

Exhibit D.B-2. Percentage of Population that is Below150% of Poverty Level Within 1-

Mile Radius of Facility

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

Radius of Facility

Exhibit D.B-4. Number of FRS Sites Within 1-Mile Radius of Facility

Exhibit D.B-5. Percentage of Population that is Minority (by Race and in Total) Within 

3-Mile Radius of Facility

Exhibit D.B-6. Percentage of Population that is Below150% of Poverty Level Within 3-

Mile Radius of Facility

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

Radius of Facility

Exhibit D.B-8. Number of FRS Sites Within 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 location and indicators. If the facility is located in 

two states, information is provided on both states and respective indicators in each state. In 

addition, the exhibits use a gray highlight to identify indicators whose percentage within the 1- or 

3-mile radius of the facility exceeds the state‟s percentage.
Exhibit D.B-1. Percentage of Population that is Minority (by Race and in Total) Within 1-Mile Radius of Facility

Facility Name Facility Type

Percent of 

Population 

that is Black 

Alone: 1-Mile 

Radius

Percent of 

Population 

that is Black 

Alone: State

Percent of 

Population 

that is Native 

American 

Alone: 1-Mile 

Radius

Percent of 

Population 

that is Native 

American 

Alone: State

Percent of 

Population 

that is Asian 

Alone: 1-

Mile Radius

Percent of 

Population 

that is Asian 

Alone: State

Percent of 

Population 

that is Pacific 

Alone: 1-Mile 

Radius

Percent of 

Population 

that is Pacific 

Alone: State

Percent of 

Population 

that is 

Hispanic: 1-

Mile Radius

Percent of 

Population 

that is 

Hispanic: 

State

Percent of 

Population 

that is 

Minority (All 

Races): 1-

Mile Radius

Percent of 

Population 

that is 

Minority (All 

Races): State

AEP Alstom 

Mountaineer (Ph.2) Commercial Capture

Ohio 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 Alstom 

Northeastern Commercial Capture

Oklahoma 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 Plant

Exisiting Gas and 

Fertilizer Plant

Michigan 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 Saline

Major DOE 

Sequestration Project

Indiana 1.1% 9.2% 0.4% 0.2% 0.0% 1.4% 0.0% 0.0% 1.7% 5.5% 4.1% 17.6%

Kentucky 0.0% 7.8% 0.5% 0.2% 0.2% 1.0% 0.0% 0.0% 1.4% 2.5% 2.6% 12.5%

Coffeyville Fertilizer 

Plant Commercial Capture

Kansas 25.0% 6.1% 5.1% 0.9% 0.3% 2.3% 0.0% 0.0% 5.0% 9.5% 42.2% 20.8%

Edwardsport Commercial Capture

Indiana 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 Plant

Exisiting Gas and 

Fertilizer Plant

Oklahoma 0.1% 8.0% 0.1% 7.9% 0.0% 1.8% 0.6% 0.1% 2.4% 8.0% 4.6% 29.8%

Futuregen FutureGen

Illinois 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 Bend Commercial Capture

Ohio 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 Coal 

Gasification

Exisiting Gas and 

Fertilizer Plant

North 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 Basin 

Nugget Sand Saline 

Reservoir

Major DOE 

Sequestration Project

Wyoming 0.2% 1.4% 0.4% 2.5% 0.1% 0.7% 0.0% 0.1% 4.7% 8.1% 6.3% 13.7%
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Exhibit D.B-1. Percentage of Population that is Minority (by Race and in Total) Within 1-Mile Radius of Facility (Cont’d)

Facility Name Facility Type

Percent of 

Population 

that is Black 

Alone: 1-Mile 

Radius

Percent of 

Population 

that is Black 

Alone: State

Percent of 

Population 

that is Native 

American 

Alone: 1-Mile 

Radius

Percent of 

Population 

that is Native 

American 

Alone: State

Percent of 

Population 

that is Asian 

Alone: 1-

Mile Radius

Percent of 

Population 

that is Asian 

Alone: State

Percent of 

Population 

that is Pacific 

Alone: 1-Mile 

Radius

Percent of 

Population 

that is Pacific 

Alone: State

Percent of 

Population 

that is 

Hispanic: 1-

Mile Radius

Percent of 

Population 

that is 

Hispanic: 

State

Percent of 

Population 

that is 

Minority (All 

Races): 1-

Mile Radius

Percent of 

Population 

that is 

Minority (All 

Races): State

Hydrogen Energy 

HECA Commercial Capture

California 13.1% 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 Saline 

Reservoir

Major DOE 

Sequestration Project

Illinois 21.4% 14.9% 0.1% 0.3% 0.5% 4.6% 0.0% 0.0% 3.2% 16.0% 29.5% 37.0%

Kemper County Commercial Capture

Mississippi 70.4% 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 Plant

Exisiting Gas and 

Fertilizer Plant

Wyoming 0.1% 1.4% 0.1% 2.5% 0.0% 0.7% 0.0% 0.1% 5.1% 8.1% 7.9% 13.7%

Lima Commercial Capture

Ohio 24.6% 12.2% 0.3% 0.1% 0.5% 1.6% 0.0% 0.0% 3.1% 2.7% 31.7% 18.0%

Mesaba Commercial Capture

Minnesota 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 Saline 

Reservoir

Major DOE 

Sequestration Project

Illinois 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 Saline 

Formation

Major DOE 

Sequestration Project

California 4.6% 6.6% 5.0% 1.1% 4.1% 12.8% 3.0% 0.3% 45.7% 37.7% 55.6% 61.1%

Tenasca 

Sweetwater/Trailbla

zer Commercial Capture

Texas 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 Taylorville 

Energy Commercial Capture

Illinois 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 Clean 

Energy Project Commercial Capture

Texas 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 Gas 

Plant, Gray Ranch

Exisiting Gas and 

Fertilizer Plant

Texas 13.6% 12.0% 0.1% 0.7% 0.2% 3.6% 0.0% 0.1% 59.6% 37.3% 75.0% 55.1%
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Exhibit D.B-1. Percentage of Population that is Minority (by Race and in Total) Within 1-Mile Radius of Facility (Cont’d)

Facility Name Facility Type

Percent of 

Population 

that is Black 

Alone: 1-Mile 

Radius

Percent of 

Population 

that is Black 

Alone: State

Percent of 

Population 

that is Native 

American 

Alone: 1-Mile 

Radius

Percent of 

Population 

that is Native 

American 

Alone: State

Percent of 

Population 

that is Asian 

Alone: 1-

Mile Radius

Percent of 

Population 

that is Asian 

Alone: State

Percent of 

Population 

that is Pacific 

Alone: 1-Mile 

Radius

Percent of 

Population 

that is Pacific 

Alone: State

Percent of 

Population 

that is 

Hispanic: 1-

Mile Radius

Percent of 

Population 

that is 

Hispanic: 

State

Percent of 

Population 

that is 

Minority (All 

Races): 1-

Mile Radius

Percent of 

Population 

that is 

Minority (All 

Races): State

Val Verde Gas 

Plant, Mitchell

Exisiting Gas and 

Fertilizer Plant

Texas 13.6% 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, Pikes Peak

Exisiting Gas and 

Fertilizer Plant

Texas 13.6% 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, Puckett

Exisiting Gas and 

Fertilizer Plant

Texas 13.6% 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, Terrell

Exisiting Gas and 

Fertilizer Plant

Texas 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, 

Sugarland Commercial Capture

Texas 13.6% 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. 

Center Commercial Capture

Washington 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 EOR 

Sequestration*

Major DOE 

Sequestration Project

North 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 Capture

Texas 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.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%
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 114 of 133

Exhibit D.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%
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 115 of 133

Exhibit D.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%
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 116 of 133

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

Radius of Facility (Cont’d)
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 117 of 133

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.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.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 1
Exhibit D.B-5. Percentage of Population that is Minority (by Race and in Total) Within 3-Mile Radius of Facility 

Facility Name Facility Type

Percent of 

Population 

that is Black 

Alone: 3-

Mile Radius

Percent of 

Population 

that is Black 

Alone: State

Percent of 

Population 

that is Native 

American 

Alone: 3-Mile 

Radius

Percent of 

Population 

that is 

Native 

American 

Alone: State

Percent of 

Population 

that is Asian 

Alone: 3-

Mile Radius

Percent of 

Population 

that is Asian 

Alone: State

Percent of 

Population 

that is 

Pacific 

Alone: 3-

Mile Radius

Percent of 

Population 

that is 

Pacific 

Alone: State

Percent of 

Population 

that is 

Hispanic: 3-

Mile Radius

Percent of 

Population 

that is 

Hispanic: 

State

Percent of 

Population 

that is 

Minority (All 

Races): 3-

Mile Radius

Percent of 

Population 

that is 

Minority (All 

Races): 

State

AEP Alstom Mountaineer 

(Ph.2) Commercial Capture

Ohio 0.3% 12.2% 0.0% 0.1% 0.3% 1.6% 0.0% 0.0% 0.0% 2.7% 1.9% 18.0%

West Virginia 0.1% 3.7% 0.0% 0.1% 0.0% 0.6% 0.0% 0.0% 0.4% 1.2% 1.4% 6.5%

AEP Alstom Northeastern Commercial Capture

Oklahoma 0.2% 8.0% 11.1% 7.9% 0.4% 1.8% 0.0% 0.1% 1.4% 8.0% 24.2% 29.8%

Antrim Gas Plant

Exisiting Gas and 

Fertilizer Plant

Michigan 0.3% 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. Simon 

Saline

Major DOE 

Sequestration 

Project

Indiana 1.3% 9.2% 0.3% 0.2% 0.1% 1.4% 0.0% 0.0% 1.1% 5.5% 3.9% 17.6%

Kentucky 0.0% 7.8% 0.4% 0.2% 0.2% 1.0% 0.0% 0.0% 1.1% 2.5% 2.2% 12.5%

Coffeyville Fertilizer Plant Commercial Capture

Kansas 12.6% 6.1% 4.9% 0.9% 0.5% 2.3% 0.0% 0.0% 4.5% 9.5% 27.7% 20.8%

Edwardsport Commercial Capture

Indiana 0.2% 9.2% 0.1% 0.2% 0.0% 1.4% 0.0% 0.0% 1.8% 5.5% 3.6% 17.6%

Enid Gas Plant

Exisiting Gas and 

Fertilizer Plant

Oklahoma 0.1% 8.0% 0.5% 7.9% 0.0% 1.8% 0.4% 0.1% 2.3% 8.0% 5.1% 29.8%

Futuregen FutureGen

Illinois 0.9% 14.9% 0.0% 0.3% 0.3% 4.6% 0.0% 0.0% 1.3% 16.0% 5.3% 37.0%

Great Bend Commercial Capture

Ohio 0.4% 12.2% 0.3% 0.1% 0.6% 1.6% 0.0% 0.0% 0.5% 2.7% 4.2% 18.0%

West Virginia 1.2% 3.7% 0.0% 0.1% 2.6% 0.6% 0.0% 0.0% 0.8% 1.2% 5.5% 6.5%
Exhibit D.B-5. Percentage of Population that is Minority (by Race and in Total) Within 3-Mile Radius of Facility (Cont’d)

Facility Name Facility Type

Percent of 

Population 

that is Black 

Alone: 3-

Mile Radius

Percent of 

Population 

that is Black 

Alone: State

Percent of 

Population 

that is Native 

American 

Alone: 3-Mile 

Radius

Percent of 

Population 

that is 

Native 

American 

Alone: State

Percent of 

Population 

that is Asian 

Alone: 3-

Mile Radius

Percent of 

Population 

that is Asian 

Alone: State

Percent of 

Population 

that is 

Pacific 

Alone: 3-

Mile Radius

Percent of 

Population 

that is 

Pacific 

Alone: State

Percent of 

Population 

that is 

Hispanic: 3-

Mile Radius

Percent of 

Population 

that is 

Hispanic: 

State

Percent of 

Population 

that is 

Minority (All 

Races): 3-

Mile Radius

Percent of 

Population 

that is 

Minority (All 

Races): 

State

Great Plains Coal 

Gasification

Exisiting Gas and 

Fertilizer Plant

North 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 Basin Nugget 

Sand Saline Reservoir

Major DOE 

Sequestration 

Project

Wyoming 0.2% 1.4% 0.4% 2.5% 0.1% 0.7% 0.0% 0.1% 4.7% 8.1% 6.3% 13.7%

Hydrogen Energy HECA Commercial Capture

California 13.1% 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 

Saline Reservoir

Major DOE 

Sequestration 

Project

Illinois 16.7% 14.9% 0.2% 0.3% 1.2% 4.6% 0.1% 0.0% 2.3% 16.0% 23.4% 37.0%

Kemper County Commercial Capture

Mississippi 69.6% 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 Plant

Exisiting Gas and 

Fertilizer Plant

Wyoming 0.2% 1.4% 0.3% 2.5% 0.1% 0.7% 0.1% 0.1% 5.3% 8.1% 8.4% 13.7%

Lima Commercial Capture

Ohio 22.5% 12.2% 0.2% 0.1% 0.7% 1.6% 0.0% 0.0% 2.4% 2.7% 28.6% 18.0%

Mesaba Commercial Capture

Minnesota 0.0% 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 Reservoir

Major DOE 

Sequestration 

Project

Illinois 0.9% 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, CA 

Saline Formation

Major DOE 

Sequestration 

Project

California 2.9% 6.6% 4.6% 1.1% 6.3% 12.8% 0.8% 0.3% 69.2% 37.7% 77.4% 61.1%

Tenasca Sweetwater/ 

Trailblazer Commercial Capture

Texas 7.1% 12.0% 0.5% 0.7% 0.7% 3.6% 0.1% 0.1% 36.4% 37.3% 46.5% 55.1%
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 122 of 133

Exhibit D.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***

Page 123 of 133

Facility Name Facility Type

Percent of 

Population 

that is Black 

Alone: 3-

Mile Radius

Percent of 

Population 

that is Black 

Alone: State

Percent of 

Population 

that is Native 

American 

Alone: 3-Mile 

Radius

Percent of 

Population 

that is 

Native 

American 

Alone: State

Percent of 

Population 

that is Asian 

Alone: 3-

Mile Radius

Percent of 

Population 

that is Asian 

Alone: State

Percent of 

Population 

that is 

Pacific 

Alone: 3-

Mile Radius

Percent of 

Population 

that is 

Pacific 

Alone: State

Percent of 

Population 

that is 

Hispanic: 3-

Mile Radius

Percent of 

Population 

that is 

Hispanic: 

State

Percent of 

Population 

that is 

Minority (All 

Races): 3-

Mile Radius

Percent of 

Population 

that is 

Minority (All 

Races): 

State

Tenasca Taylorville Energy Commercial Capture

Illinois 0.2% 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 Project Commercial Capture

Texas 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 Gas Plant, Gray 

Ranch

Exisiting Gas and 

Fertilizer Plant

Texas 13.6% 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, Mitchell

Exisiting Gas and 

Fertilizer Plant

Texas 13.6% 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, Pikes 

Peak

Exisiting Gas and 

Fertilizer Plant

Texas 13.6% 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, Puckett

Exisiting Gas and 

Fertilizer Plant

Texas 13.6% 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, Terrell

Exisiting Gas and 

Fertilizer Plant

Texas 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, Sugarland Commercial Capture

Texas 15.2% 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. Center Commercial Capture

Washington 1.0% 3.7% 1.1% 1.6% 0.8% 7.0% 0.2% 0.4% 13.9% 10.1% 17.1% 26.0%

Williston Basin EOR 

Sequestration*

Major DOE 

Sequestration 

Project

North Dakota 0.3% 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 Capture

Texas 1.5% 12.0% 1.0% 0.7% 0.5% 3.6% 0.0% 0.1% 9.3% 37.3% 15.8% 55.1%
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 124 of 133
Exhibit D.B-6. Percentage of Population that is Below150% of Poverty Level Within 3-Mile Radius of 

Facility

Facility Name Facility Type

Percent of Population 

below 150% of Poverty 

Level: 3-Mile Radius

Percent of Population 

below 150% of Poverty 

Level: State

AEP Alstom Mountaineer (Ph.2) Commercial Capture

Ohio 33.8% 23.9%

West Virginia 27.5% 28.7%

AEP Alstom Northeastern Commercial Capture

Oklahoma 20.1% 27.9%

Antrim Gas Plant

Exisiting Gas and 

Fertilizer Plant

Michigan 27.2% 25.6%

Cincinnati Arch Mt. Simon Saline

Major DOE 

Sequestration Project

Indiana 23.3% 24.1%

Kentucky 13.3% 29.1%

Coffeyville Fertilizer Plant Commercial Capture

Kansas 32.3% 21.8%

Edwardsport Commercial Capture

Indiana 25.5% 24.1%

Enid Gas Plant

Exisiting Gas and 

Fertilizer Plant

Oklahoma 21.1% 27.9%

Futuregen FutureGen

Illinois 22.2% 20.9%

Great Bend Commercial Capture

Ohio 35.0% 23.9%

West Virginia 24.1% 28.7%

Great Plains Coal Gasification

Exisiting Gas and 

Fertilizer Plant

North Dakota 25.7% 20.0%

Green River Basin Nugget Sand Saline 

Reservoir

Major DOE 

Sequestration Project

Wyoming 9.1% 16.8%

Hydrogen Energy HECA Commercial Capture

California 4.1% 21.2%

Illinois Basin Mt. Simon Saline 

Reservoir

Major DOE 

Sequestration Project

Illinois 36.2% 20.9%

Kemper County Commercial Capture

Mississippi 61.4% 33.4%

La Barge Gas Plant

Exisiting Gas and 

Fertilizer Plant

Wyoming 12.3% 16.8%
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 126 of 133

Exhibit D.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%
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 127 of 133

Exhibit D.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%
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

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

(Cont’d)

Facility Name Facility Type

Percent of 

Population that is 

0-4 Years: 3-Mile 

Radius

Percent of 

Population that is 

0-4 Years: State

Percent of 

Population that is 

65+ Years: 3-Mile 

Radius

Percent of 

Population that is 

65+ Years: State

Lima Commercial Capture

Ohio 6.3% 5.6% 14.1% 14.4%

Mesaba Commercial Capture

Minnesota 3.5% 5.9% 25.4% 13.5%

Mt. Simon Saline Reservoir

Major DOE Sequestration 

Project

Illinois 3.8% 6.0% 16.9% 13.0%

San Joaquin Basin, CA Saline 

Formation

Major DOE Sequestration 

Project

California 8.3% 6.3% 10.7% 11.9%

Tenasca Sweetwater/Trailblazer Commercial Capture

Texas 7.0% 7.0% 13.7% 10.8%

Tenasca Taylorville Energy Commercial Capture

Illinois 4.8% 6.0% 15.6% 13.0%

Texas Clean Energy Project Commercial Capture

Texas 7.4% 7.0% 12.9% 10.8%

Val Verde Gas Plant, Gray Ranch

Exisiting Gas and 

Fertilizer Plant

Texas 4.6% 7.0% 9.2% 10.8%

Val Verde Gas Plant, Mitchell

Exisiting Gas and 

Fertilizer Plant

Texas 4.6% 7.0% 9.2% 10.8%

Val Verde Gas Plant, Pikes Peak

Exisiting Gas and 

Fertilizer Plant

Texas 4.6% 7.0% 9.2% 10.8%

Val Verde Gas Plant, Puckett

Exisiting Gas and 

Fertilizer Plant

Texas 4.6% 7.0% 9.2% 10.8%

Val Verde Gas Plant, Terrell

Exisiting Gas and 

Fertilizer Plant

Texas 3.3% 7.0% 19.8% 10.8%

WA Parish, Sugarland Commercial Capture

Texas 6.0% 7.0% 11.8% 10.8%

Wallula Energy Res. Center Commercial Capture

Washington 5.2% 5.6% 12.0% 13.2%

Williston Basin EOR 

Sequestration*

Major DOE Sequestration 

Project

North Dakota 4.4% 5.7% 20.2% 14.9%

Worsham-Steed (ZENG) Commercial Capture

Texas 5.8% 7.0% 15.2% 10.8%
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

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Exhibit D.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.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
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 131 of 133

Appendix E.

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 State, 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.

Other Required Analyses

F-1 Executive Order 12866: Regulatory Planning and Review

EPA has determined that the proposed rule is a "significant regulatory action" as defined by 

Executive Order 12866 because it raises novel legal or policy issues arising out of legal 

mandates, the President's priorities, or the principles set forth in the Executive Order. 

Accordingly, EPA submitted this action to the Office of Management and Budget (OMB) for 

review under EO 12866, and any changes made in response to OMB recommendations have been 

documented in the docket for this action.

The expected annual costs and benefits of the proposed rule do not exceed $100 million. The 

rule does not create inconsistencies or 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 implications. EPA does not anticipate that the 

proposed rule will have substantial direct impacts on the states, the relationship between the 

government and the states, or on the distribution 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 CO2 capture or sequestration 

facilities.
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

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F-4 Executive Order 13045: Protection of Children from Environmental Health and 

Safety Risks

EPA does not believe that the rule will have environmental 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

Although the affected universe of the proposed rule includes energy suppliers such as coal 

power plants, the rule is not expected to result in changes of behavior that would affect 

energy supply, distribution or usage. 

F-6 National Technology Transfer Advancement Act

This proposed rulemaking does not involve technical 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 that the 

actions allowed by the proposed exclusions are safe and do not present significant adverse 

health or environmental impacts (See Appendix D).

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 
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 133 of 133

the regulatory requirements for hazardous waste, when managed in Class VI UIC wells for 

purposes of geologic sequestration.

F-11 Joint Impacts of Rules

The proposed rule will exempt CO2 streams captured for the purpose of geological 

sequestration in a Class VI UIC well from the definition of hazardous waste. Such waste will 

not be subject to EPA‟s hazardous waste regulations. These CO2 streams would still qualify 

as solid wastes per the definition in 40 CFR 261.2 (Definition of solid waste). The 

management of these CO2 streams would be subject to the Underground Injection Control 

Program (UICP) requirements in 40 CFR Parts 144 (Requirements for wells injecting 

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).90 CO2

capture and sequestration facilities claiming the proposed exclusion would remain subject to 

the mandatory reporting requirements for greenhouse gas emissions in 40 CFR Part 98

(Mandatory Greenhouse Gas Reporting). The transportation of captured CO2 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 CO2 by air, water, or highway would remain subject to the 

PHMSA requirements in 49 CFR Parts 171-180.

 

90 Non-hazardous solid wastes that are subject the UICP requirement are not subject to the requirements for 

non-hazardous solid waste in 40 CFR Parts 257 and 258.