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 

 June 2, 2011
ACKNOWLEDGMENTS 

The Agency recognizes ICF International for the overall organization and 

development of this report. Eastern Research Group, Inc. also contributed to this report. Lyn 

D. Luben and Phuc Phan of the U.S. Environmental Protection Agency, Office of Resource 

Conservation and Recovery (ORCR) provided guidance and review. 
 Page 3 of 145 

TABLE OF CONTENTS 

ES. EXECUTIVE SUMMARY 5 

1. INTRODUCTION 13 

1.1 Need for Regulation 13

1.2 Summary of Current Rules 14

1.3 Summary of Proposed Changes 16

1.4 Analysis of Alternatives Considered (Regulatory and Non-Regulatory) 16

2. CHARACTERIZATION OF THE REGULATED COMMUNITY 177 

2.1 CO2 Capture Facilities 17

2.1.1 Current CO2 Capture Facilities 188 

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 25

2.3 CO2 Sequestration Facilities 27

3. ANALYSIS OF THE INCREMENTAL COSTS AND BENEFITS OF THE 

PROPOSED RULE 301 

3.1 Analytical Approach/Methodology 31

3.2 Baseline Practices 32

3.2.1 Hazardous Waste Determination Process for CO2 Capture Facilities 32 

3.2.2 Baseline Practices for CO2 Capture Facilities 33 

3.2.2.1 Factors that Influence The Baseline Practices of CO2 Carbon Capture 

Facilities 34 

3.2.2.2 Expected Baseline Practices of CO2 Carbon Capture Facilities 366 

3.2.3 Baseline Practices for CO2 Sequestration Facilities 40 
 Page 4 of 145 

3.3 Post Rule Practices 43

3.3.1 Post Rule Practices for CO2 Capture Facilities 43 

3.3.2 Post Rule Practices for CO2 Sequestration Facilities 43 

3.4 Incremental Costs of the Proposed Rule 43

3.4.1 Compliance Costs 43 

3.4.2 Social Costs 51 

3.4.3 Costs to Government Entities 52 

3.5 Incremental Cost Savings and Benefits of the Proposed Rule 59

3.5.1 Waste Determination Savings for CO2 Capture Facilities 59 

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

Facilities 60 

3.5.3 CO2 Treatment Savings for CO2 Capture Facilities 61 

3.5.4 Summary of Savings to CO2 Capture Facilities 62 

3.5.5 Waste Determination Savings for CO2 Sequestration Facilities 66 

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

Sequestration Facilities 66 

3.5.7 Summary of Savings to CO2 Sequestration Facilities 67 

3.6 Summary of Costs and Savings 71 

3.7 Unquantified Benefits of the Proposed Rule 744 

4. REGULATORY FLEXIBILITY ANALYSIS 744 

5. REFERENCES 75 

APPENDIX A: COST FOR DETERMINING RCRA TOXICITY OF CO2 

STREAM 78 

APPENDIX B: TREATMENT COSTS 912

APPENDIX C. ASSESSMENT OF ENVIRONMENTAL JUSTICE IMPACTS 97 

APPENDIX D. UNFUNDED MANDATES REFORM ACT ANALYSIS 1423 

APPENDIX E. OTHER REQUIRED ANALYSES 1434 
 Page 5 of 145 

ES. Executive Summary 

The U.S. Environmental Protection Agency (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, or would not 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 has determined 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 

than releasing them into the atmosphere. Currently EPA estimates that, at a maximum, there 

 

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.
 Page 6 of 145 

could be up to 27 CO2 capture facilities 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. 

 

Our low-end estimate considers only 13 CO2 capture facilities. This includes ten existing 

capture facilities, two capture projects associated with named DOE pilot projects, and one 

capture facility associated with the FutureGen federal/private partnership. 

Exhibit ES-1 presents the high-end and low-end estimates for the number of 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, High-End and Low-End Estimates, by Industry Sector 

NAICS Industry Sector 

Number of Facilities 

High-End 

Estimate 

Low-End 

Estimate 

211111 Oil and Gas Extraction 7 7 

221112 Fossil Fuel Electric Power Generation 16 2 

221210 Natural Gas Distribution 1 1 

325193 Ethyl Alcohol Manufacturing 1 1 

325311 Nitrogenous Fertilizer Manufacturing 2 2 

Total 27 13 

At present, for economic reasons, captured 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. 

 

3 56 Federal Register 26922, June 12, 1991. 

http://www.greenfacts.org/en/co2-capture-storage/l-3/4-transport-carbon-dioxide.htm

Parfomk, Paul W., Folger, Peter, and Adam Vann. Congressional Research Service, July 31, 2009. Carbon 

Dioxide (CO2) Pipelines for Carbon Sequestration: Emerging Policy Issues. 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. 
 Page 7 of 145 

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 as many as 29 planned sequestration 

facilities could 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 sequestration in the long term and 3 saline reservoir sequestration projects.6 

 

Our low-end estimate considers only six CO2 sequestration facilities that will be Class VI 

UIC wells. This includes five sequestration projects associated with named DOE pilot 

projects and one sequestration facility associated with the FutureGen federal/private 

partnership. Class VI UIC wells fall under the other non-hazardous waste treatment and 

disposal (i.e., management by methods other than landfill, combustion, and incineration) 

industry (NAICS 562219). These Class VI well facilities are not currently operational. 

 

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 streams7

, and EPA 

 

6

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

http://www.netl.doe.gov/technologies/carbon_seq/database/ index.html

7 Comments mainly focused on three key areas: 1) unclear whether or how CO2 streams would be classified as a 

RCRA hazardous waste, 2) analytic procedures used under RCRA (e.g., the toxicity characteristic leaching 
 Page 8 of 145 

acknowledges these commenters’ concerns. However, this 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. 

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 

Destined 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 for the geologic sequestration of CO2. Facilities may capture CO2 streams for use 

in Class II wells for Enhanced Oil Recovery (EOR). However, EOR assessment is beyond the scope of this 

proposed rule. 

 

procedure, TCLP) cannot be used to evaluate supercritical CO2 streams, and, 3) the class VI regulations are 

better suited to ensure the management of CO2 injectate. 
 Page 9 of 145 

Exhibit ES-3 below presents our high-end and low-end assumptions regarding the relative 

prevalence of each baseline practice for CO2 capture facilities. The high-end assumes that 

90% of the CO2 streams are generated as RCRA hazardous waste. The low-end assumes that 

only 10% of the CO2 streams are RCRA hazardous waste. It is important to note that these 

hazardous CO2 percentages were formed as a range for analytical purposes due to the lack of 

definitive data. Based on early literature reviews and current CO2 capture technologies, the 

percentage of CO2 streams that are expected to be classified as hazardous could be low. 

Exhibit ES-3: High-End and Low-End Assumptions 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

 

 High-End Low-End 

Non-hazardous Send the CO2 stream to a Class 

VI well 10% 90% 

Hazardous 

Cease capture 30% 3.3% 

Send the CO2 stream to a Class 

I hazardous well that is 

assumed to meet the Class VI 

requirements 

30% 

3.3% 

Treat the CO2 stream such that 

the stream is non-hazardous 

and send it to a Class VI well 

30% 3.3% 

a

 For purposes of this analysis EPA assumes these high-end and low-end values due to a lack of definitive data

on the relative distribution of CO2 streams’ hazardous waste designation. 

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.

8

 

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, under the high-end baseline assumption, 

approximately 57 percent of the sequestration wells would manage non-hazardous CO2

streams and treated CO2 streams in Class VI wells.9 The remaining wells would manage 

RCRA hazardous CO2 streams in Class I hazardous wells. 

 

8

 Paul W. Parfomak and Peter Folger. “Carbon Dioxide (CO2) Pipelines for Carbon Sequestration: Emerging 

Policy Issues,” Congressional Research Service, Report for Congress, updated January 17, 2008, 

http://assets.opencrs.com/rpts/RL33971_20080117.pdf. 9

 The reasoning behind this assumption is explained in Section 3.2.3 of this document 
 Page 10 of 145 

For the low-end, our analysis assumes that approximately 97 percent of the sequestration 

wells would manage non-hazardous 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.10 

At this time, EPA has little information to conclude that CO2 streams would, or would not 

qualify as RCRA hazardous wastes. If the Agency receives more definitive data in response 

to the proposed rulemaking, this analysis will be revised accordingly. 

Post-Rule Behavior

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 owners/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 within 72 hours of a written 

request.11 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 that is 

requested and reviewed. Similarly, the States would incur $61 in labor costs for each 

certification statement they request and review. 

 

10 For the low-end estimate, this analysis assumes that 90 percent of CO2capture facilities would transport nonhazardous or treated CO2 streams to Class VI sequestration wells for injection (see Exhibit 14). Another 3.3 

percent of CO2 capture facilities would transport hazardous CO2 streams to Class I sequestration wells for 

injection. This analysis assumes that 97 percent of CO2 sequestration wells in the baseline are Class VI wells to 

match the practices of CO2 capture facilities. The remaining 3 percent of CO2 sequestration wells in the 

baseline are Class I wells. 

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

sequestration facility would sign its own certification statement. 
 Page 11 of 145 

The Agency finds that the management of these 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, 

therefore, anticipate any negative externalities as a result of this action. 

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 requirements,12 and exclusion from hazardous waste 

treatment requirements. The analysis estimates that exclusion from hazardous waste 

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

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 

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. 

Annualized Net Savings

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

Due to the high level of uncertainty regarding the percent of CO2 that may be RCRA 

hazardous, and the uncertainty regarding the actual number of facilities potentially affected 

over the projected 50 year period, EPA’s best estimate for the impacts of the proposed rule 

ranges from a low-end annualized net savings of $7.3 million (7% discount rate) to the highend annualized net savings of $44.9 million (3%discount rate). 13

 

12 Note that facilities regulated under the Clean Air Act GHG Reporting Program (see 74 CFR 56260 and 75 FR 

75060) will be required to follow the applicable reporting requirements. 13 Under the high-end estimate, the proposed rule is expected to result in undiscounted annualized net savings of 

approximately $56.6 million. Applying a 3 percent discount rate, the annualized net savings were found to be 

approximately $44.9 million while a 7 percent discount rate resulted in annualized net savings of approximately 

$32.0 million. Under the low-end estimate, the undiscounted annualized net savings are $9.3 million. Applying 
 Page 12 of 145 

Under Executive Order 12866, a rule qualifies as economically 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. 

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 (GS) in 

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

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

the required certification statement. The Agency estimates that this proposed rule could lead 

to net cost savings in the range of $7.3 to $44.9 million annually. 

 

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

and $7.3 million, respectively. 
 Page 13 of 145 

1. Introduction 

The U.S. Environmental Protection Agency 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 finds 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, 

additional regulation pursuant to RCRA’s hazardous waste regulations is unnecessary.14 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 has determined 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 by itself is not a drinking 

water contaminant, a CO2 stream can pose a risk to USDWs as follows: 15

 

14 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). 

15 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 
 Page 14 of 145 

• 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. 

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:16 

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

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

wells are located in suitable formations. 

• Computational modeling of the area of 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 destined for GS may qualify as solid wastes, as defined in 40 CFR 

261.2 (Definition of solid waste). RCRA hazardous waste is a subset of solid waste to which 

EPA applies 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 

 

Under the Underground Injection Control (UIC) Program for Carbon Dioxide (CO2) Geologic Sequestration 

(GS) Wells Final Rule, RIN 2040-AE98. 

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

Dioxide (CO2) Geologic Sequestration (GS) Wells Final Rule, RIN 2040-AE98. 
 Page 15 of 145 

listed hazardous waste but may be considered a hazardous waste if it exhibits one of the four 

hazardous characteristics. 

EPA requires all solid waste generators, under 40 CFR 262.11 (Hazardous waste 

determination), to determine if their waste is 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 

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 a solid waste and determined to be a RCRA hazardous waste 

(and assuming it is to be discarded, such as through geologic sequestration), 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.17 

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.18 

 

17 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. 18 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. 
 Page 16 of 145 

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 

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.19 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 generally equivalent protection to 

human health and the environment as the proposal, while maintaining an unnecessary 

regulatory burden on CO2 capture and sequestration facilities to comply with the 

hazardous waste requirements

 

19 See: §261.4 Exclusions (h) – Carbon Dioxide Stream Injected for Geologic Sequestration
 Page 17 of 145 

• Non-regulatory alternatives – Although non-regulatory approaches such as 

educational outreach programs could 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. 

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. 

The total number of CO2 capture facilities potentially affected by this action, as proposed, is 

uncertain. As a result, we have developed two alternative estimates for the number of 

affected facilities. Our high-end estimate identifies 27 CO2 capture facilities that may be 

affected by the proposed rule. Our low-end estimate considers only 13 capture facilities. 

These estimates are discussed below. 

 

Number of CO2 Capture Facilities – High-End Estimate: 

EPA estimates that a maximum of 27 CO2 capture facilities could 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. Of these seventeen, there are 14 commercial 

projects, two non-commercial DOE pilot projects, and one 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 high-end estimate number of capture facilities by type of project, industry 

sector, and expected first year of CO2 sequestration. 
 Page 18 of 145 

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 2008.20 

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.21 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 2034.22 

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 - 

Grey Ranch 

Plant 

TX Processing of high CO2 

gas prod. 

2030 211111 Oil and Gas 

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 

 

20 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. 21 We recognize that if there is no climate legislation within the projected time frame that the economic driver 

for Class VI storage may not fully occur. It is possible that these projects may store CO2 in domes as a staging 

point for future EOR, EGR, and working fluids for fracturing tight gas sands and shale. Under this model it is 

possible that some or none of these projects would be subject to this rule or the Class VI rule.

22 See footnote b in Exhibit 1. 
 Page 19 of 145 

Facility State Description 

Assumed 

First Year of 

Sequestration

b

 

NAICS NAICS 

Description 

Antrim Gas 

Plant 

MI Processing of high 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

 EPA Office of Water, “Cost Analysis for the Federal Requirements Under the Underground Injection Control 

Program for Carbon Dioxide Geologic Sequestration Wells (Final GS Rule),” EPA identified the Coffeyville 

Fertilizer Plant as a commercial project that would 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.23 The Coffeyville Fertilizer Plant (Coffeyville Resources LLC) employs 250 to 

499 individuals.24 The Great Plains Coal Gasification (Dakota Gasification CO) facility has 

between 500 and 999 employees.25 

2.1.2 Planned 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.26 Although all of these projects are planned, some of them may be cancelled or 

delayed due to approval and funding issues. This high estimate analysis considers only 

fourteen planned commercial projects that EPA has deemed most likely to proceed. 

However, the other planned projects are included in Exhibit 2 for reference only.27 In 

 

23 Koch Industries, 2009, http://www.kochind.com/files/070709KIILeadershipKansas.pdf. 24 Manta, “Coffeyville Resources LLC,” http://www.manta.com/c/mmgvkjp/coffeyville-resources-llc 25 Manta, “Dakota Gasification Co,” http://www.manta.com/c/mmlgj74/dakota-gasification-co 26 These “commercial” CO2 capture projects include some projects that were partially funded as DOE pilot 

projects. 

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

for the Federal Requirements Under the Underground 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. 
 Page 20 of 145 

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). 

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) 

(DOE sponsored Demo 

project) 

WV AEP and 

Alstom 2012 221112 

Fossil Fuel 

Electric Power 

Generation 

AEP Alstom 

Northeastern OK AEP and Alstom 2032 221112 

Fossil Fuel 

Electric Power 

Generation 

Edwardsport IN Duke Energy 2012 221112 

Fossil Fuel 

Electric Power 

Generation 

Great Bend OH AEP 2034 221112 

Fossil Fuel 

Electric Power 

Generation 

Hydrogen Energy HECA CA 

Hydrogen 

Energy (BP 

and Rio 

Tinto) 

2034 221112 

Fossil Fuel 

Electric Power 

Generation 

Kemper County MS 

Mississippi 

Power; ( sub. 

of Southern) 

2034 221112 

Fossil Fuel 

Electric Power 

Generation 

Lima OH 

Global 

Energy; 

Lima Energy 

2031 221112 

Fossil Fuel 

Electric Power 

Generation 

Mesaba MN Excelsior 

Energy 2034 221112 

Fossil Fuel 

Electric Power 

Generation 

Tenasca 

Sweetwater/Trailblaze TX Tenasca Inc., Arch Coal 2035 221112 

Fossil Fuel 

Electric Power 

Generation 
 Page 21 of 145 

Project State Company 

Assumed 

First Year of 

Sequestration 

b

NAICS Industry Sector 

Tenasca Taylorville 

Energy IL Tenasca Inc. 2035 221112 

Fossil Fuel 

Electric Power 

Generation 

Texas Clean Energy 

Project TX Summit Power 2032 221112 

Fossil Fuel 

Electric Power 

Generation 

WA Parish, Sugarland TX 

NRG 

Energy; 

Fluor, 

Ramgen/Dres

ser 

2032 221112 

Fossil Fuel 

Electric Power 

Generation 

Wallula Energy Res. 

Center c WA 

Wallula 

Resource 

Recovery 

2013 221112 

Fossil Fuel 

Electric Power 

Generation 

Worsham-Steed (ZENG) TX 

CO2 Global 

and Falcon 

Gas Storage 

2032 221112 

Fossil Fuel 

Electric Power 

Generation 

Non-commercial DOE Pilot Projects 

Cincinnati Arch Mt. 

Simon Saline Reservoir d OH Andersons 

Marathon 2010 325193 Ethyl Alcohol Manufacturing 

San Joaquin Basin, CA 

Saline Formation e CA Clean Energy 

Systems 2012 221112 

Fossil Fuel 

Electric Power 

Generation 

FutureGen - Private/Federal Partnership 

Mt. Simon Saline 

Reservoir IL FutureGen Alliance 2017 221112 

Fossil Fuel 

Electric Power 

Generation 

Planned Commercial Projects Not Included in this Analysis f

ADM Ethanol Plant CO2 

Capture IL ADM 2013 325193 Ethyl Alcohol Manufacturing 

Antelope Valley ND 

Basin 

Electric, 

HTC Pure 

Energy 

N/A 221112 

Fossil Fuel 

Electric Power 

Generation 

Battelle Boise White 

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

C6 Resources CA 

C6 

Resources 

(Shell 

affiliate) 

N/A 324110 Petroleum 

Refineries 
 Page 22 of 145 

Project State Company 

Assumed 

First Year of 

Sequestration 

b

NAICS Industry Sector 

Cash Creek KY Erora Group N/A 221112 

Fossil Fuel 

Electric Power 

Generation 

Cemex Odessa Project TX Cemex N/A 327310 Cement 

Manufacturing 

ConocoPhillips Sweeny 

Power plant TX Conoco Phillips N/A 221112 

Fossil Fuel 

Electric Power 

Generation 

Great Lakes Energy 

Research MI M&M 

Energy N/A 221112 

Fossil Fuel 

Electric Power 

Generation 

Leucadia Energy Lake 

Charles LA Leucadia, Denbury N/A 324199 

All Other 

Petroleum and 

Coal Products 

Manufacturing 

Leucadia Energy Moss 

Point MS MS Leucadia, Denbury N/A 324199 

All Other 

Petroleum and 

Coal Products 

Manufacturing 

Port Arthur Steam 

Methane Reformers TX Air Products, Denbury N/A 325120 Industrial Gas Manufacturing 

Praxair Texas City 

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

SCS Energy PurGen 

One NJ SCS Energy N/A 221112 

Fossil Fuel 

Electric Power 

Generation 

Wolverine Circ. 

Fluidized Bed Plant MI 

Wolverine 

Power 

Supply 

Cooperative 

N/A 221112 

Fossil Fuel 

Electric Power 

Generation 

a

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

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

Technology, Largescale Power Plant CCS Projects Worldwide. Power Plant Carbon Dioxide Capture and 

Storage Projects, http://sequestration.mit.edu/tools/projects/index.html. b

 The assumed first year of sequestration for each facility is based on the research that the EPA Office of Water 

conducted to determine the baseline for the “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. c

 Information received after the completion of this analysis indicates that this project is not going forward. It 

was not awarded a Phase II DOE award. 

d

 Information received after the completion of this analysis indicates that this project has been cancelled and 

moved to Michigan. 

e

 Information received after the completion of this analysis indicates that this project has been cancelled. f Information received after the completion of this analysis indicates that many of these projects have been 

cancelled or did not receive funding from DOE for the next phase of their projects. 
 Page 23 of 145 

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 high-end estimate analysis, by type of project. 

Exhibit 3: Number of Current and Planned CO2 Capture Projects 

Identified and Considered in the High-End Estimate Analysis 

Type of Project Number of Facilities Considered in the Analysis 

Current Capture Plants 10 

Planned Commercial Projects 14 

Planned Non-commercial DOE Pilot Projects 2a

FutureGen Private/Federal Partnership 1 

Total 27 a

 Information received after the completion of this analysis indicates that these projects have been cancelled. 

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

in this high-end estimate analysis, by industry sector. 

Exhibit 4: Number of Current and Planned CO2 Capture Facilities 

Considered in this High-End Estimate Analysis, by Industry Sector 

NAICS NAICS Industry Sector Number of Facilities 

211111 Oil and Gas Extraction 7 

221112 Fossil Fuel Electric Power Generation 16 

221210 Natural Gas Distribution 1 

325193 Ethyl Alcohol Manufacturing 1 

325311 Nitrogenous Fertilizer Manufacturing 2 

Exhibit 5 presents the high-end estimate 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 

Cumulative 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 

2018 0 6 

2019 0 6 

2020 0 6 

2021 0 6 
 Page 24 of 145 

Year Number of CO2 Facilities Beginning 

Sequestration of their CO2 Streams 

Cumulative Number of CO2 Facilities 

Practicing Sequestration of their CO2 

Streams 

2022 0 6 

2023 0 6 

2024 0 6 

2025 0 6 

2026 0 6 

2027 0 6 

2028 0 6 

2029 0 6 

2030 9 15 

2031 1 16 

2032 4 20 

2033 0 20 

2034 5 25 

2035 2 27 

2036 0 27 

Post-2036 0 27 

Total 27 27 

Number of CO2 Capture Facilities – Low-End Estimate: 

Our low-end estimate considers only 13 CO2 capture facilities. This includes ten existing 

capture facilities, two capture projects associated with named DOE pilot projects, and one 

capture facility associated with the FutureGen federal/private partnership. 

 

This low-end estimate for the number of affected CO2 capture facilities assumes the 

following: 

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

• only projects associated with named DOE pilot projects and federal/private 

partnerships will be affected. 

All other assumptions are consistent with the high-end estimate for the number of affected 

CO2 capture facilities. 

Exhibit 6 presents the low-end estimate for the number of CO2 capture facilities expected to 

begin activities in each year under the proposed rule. 

Exhibit 6: Low-End Estimate of the CO2 Capture Facilities Assumed 

to Begin and Practice Sequestration Activities, by Year

Year Annual Number of CO2 Capture Facilities Total Number of CO2 

 Capture Facilities 

2010 - 2012 2 2

2013 0 2

2014 0 2

2015 0 2

2016 0 2
 Page 25 of 145 

Year Annual Number of CO2 Capture Facilities Total Number of CO2 

 Capture Facilities 

2017 1 3

2018 0 3

2019 0 3

2020 0 3

2021 0 3

2022 0 3

2023 0 3

2024 0 3

2025 0 3

2026 0 3

2027 0 3

2028 0 3

2029 0 3

2030 9 12

2031 0 12

2032 0 12

2033 0 12

2034 1 13

2035 0 13

2036 0 13

Post-2036 0 13

Total 13 13

2.2 CO2 Transporters 

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

pipelines, operated by 29 separate entities.28 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 2008.29 This analysis only considers the 29 operators of pipelines reported to be 

operating in 2008. Exhibit 7 lists these active CO2 pipeline operators. The exhibit also 

presents the miles of pipeline operated and barrel-miles30 of CO2 transported in 2008 by each 

operator. 

 

28 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. 29 The CRS Report for Congress indicates there are approximately 3,600 miles of dedicated CO2 pipelines, 

carrying about 50 million metric tons of CO2 per year, primarily for EOR activities in the oil and gas industry. 

(CRS Report for Congress. Regulation of Carbon Dioxide (CO2) Sequestration Pipelines: Jurisdictional Issues. 

Adam Vann and Paul W. Parfomak. April 15, 2008) 

30 A standard barrel contains 42 gallons. 
 Page 26 of 145 

Pipeline transportation of captured 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).31 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.32 

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 7: 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

 

31 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. 32 Manta, “Exxon Mobil Corp,” http://www.manta.com/c/mmcckrf/exxon-mobil-corp 
 Page 27 of 145 

CO2 Pipeline Operator Name 

Miles of CO2 

Pipeline 

Operated

Barrel Miles of 

CO2 transported

Sandridge CO2, LLC 143 5,578,863

Resolute Natural Resources Company 28 14,085,537

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

Transpetco Transport Co. 121 171,933

Trinity 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. 

As with capture facilities, the total number of CO2 sequestration facilities potentially affected 

by this action, as proposed, is uncertain. As a result, we have developed two alternative 

estimates for the number of affected facilities. Our high-end estimate identifies 29 CO2 

sequestration facilities that may be affected by the proposed rule. Our low-end estimate 

considers only six sequestration facilities. These estimates are discussed below. 

Number of CO2 Sequestration Facilities – High-End Estimate:

EPA estimates that, at a maximum, 29 planned sequestration facilities may be affected by the 

proposed rule. This estimate is consistent with EPA’s current assumptions for the UIC Class 

VI program project baseline and cost analysis in developing the Class VI rule.33 The Class 

VI rule cost analysis assumes that there is no Climate Change legislation, and the baseline is 

based upon the most likely scenario under current laws and regulations. This EPA project 

forecast is a mix of actual operating or planned sites and hypothetical sites. 

This high-end estimate includes 15 planned commercial 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.34

 

33 Based on the research that EPA Office of Water conducted to determine the baseline for the “Cost Analysis 

for the Federal Requirements Under the Underground Injection Control Program for Carbon Dioxide Geologic 

Sequestration Wells (Final GS Rule),” 

34 DOE sequestration project database website 

http://www.netl.doe.gov/technologies/carbon_seq/database/index.html
 Page 28 of 145 

Class VI UIC wells fall under the other non-hazardous waste treatment and disposal (i.e., 

management by methods other than landfill, combustion, and incineration) industry (NAICS 

562219). Because these Class VI well facilities are not currently operational, the 

characteristics of these facilities are uncertain. 

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

type. These counts are based on the research that EPA Office of Water conducted to 

determine the baseline for the “Cost 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 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 8: Summary of the High-End Estimate for the Number of Sequestration 

Facilities Considered in this Analysis 

Category Count a

DOE Projects - Named Projects/Specific Locations

Followups at Existing DOE Pilots 5 

FutureGen, Matoon, IL 1 

Subtotal: 6 

DOE Projects - General Unspecified Projects 

Small Saline Pilots 2 

Commercial Scale Saline 5 

Commercial Scale EOR 1 

Subtotal: 8 

Non-DOE (Commercial) Projects 

Commercial Saline 3 

Commercial EOR Converting to GS 12 

Subtotal 15 

Total 29 

a

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

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

Control Program for Carbon Dioxide Geologic Sequestration Wells (Final GS Rule).” 

Exhibit 9 lists the DOE Phase 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. 
 Page 29 of 145 

Exhibit 9: DOE Phase III Sequestration Demonstration Projects a

Regional 

Organization Project Name 

Included 

in This 

Analysis 

MGSC Illinois Basin Mt. Simon Saline Reservoir 

(Decatur, IL) 

yes 

PCOR Williston Basin EOR Sequestration; ND yes 

PCOR Fort Nelson, BC Sandstone Saline Reservoir 

(Brit. Columbia) 

no 

Big Sky Green River Basin Nugget Sand Saline 

Reservoir, Moxa Arch, Western Wyoming 

yes 

SWCARB Saline Reservoirs, Farnham Dome, Price, UT 

and J through PR Sands); Uinta Basin 

no 

SECARB Phase 1: Athropogenic CO2 in Tuscaloosa 

Citronelle Oilfield EOR, Mobile AL 

no 

SECARB Phase 2: Mississippi Tuscaloosa Massive 

Saline Reservoir; SW Mississippi (Cranfield, 

MS) 

no 

MRCSP Cincinnati Arch Mt. Simon Saline 

Reservoir; Greenville, OH 

yes 

WESTCARB San Joaquin Basin, CA Saline Formation; 

Olcese and Vedder Sands 

yes 

FutureGen Project 

 Mt. Simon Saline Reservoir (Matoon, IL) yes a

 This list is based on the research that EPA Office of Water conducted to determine the 

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

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

Rule).”

Exhibit 10 presents the high-end estimate for the number of CO2 sequestration facilities 

expected to begin operation and to continue to operate each year. 

Exhibit 10: High-End Estimate for the CO2 Facilities Expected to 

 Begin Sequestration, by Year 

Year Number of Sequestration Facilities 

Beginning Operation 

Cumulative Number of Sequestration 

Facilities in Operation 

2010 - 2012 2 2 

2013 1 3 

2014 1 4 

2015 0 4 

2016 2 6 

2017 10 16 

2018 1 17 

2019 0 17 

2020 0 17 

2021 0 17 

2022 0 17 
 Page 30 of 145 

Year Number of Sequestration Facilities 

Beginning Operation 

Cumulative Number of Sequestration 

Facilities in Operation 

2023 0 17 

2024 0 17 

2025 0 17 

2026 0 17 

2027 0 17 

2028 0 17 

2029 0 17 

2030 0 17 

2031 1 18 

2032 4 22 

2033 0 22 

2034 5 27 

2035 2 29 

2036 0 29 

Post-2036 0 29 

Total 29 29 

Number of CO2 Sequestration Facilities – Low-End Estimate:

Our low-end estimate considers only six CO2 sequestration facilities. This includes five 

sequestration projects associated with named DOE pilot projects and one sequestration 

facility associated with the FutureGen federal/private partnership. 

 

As with capture facilities, this low-end estimate for the number of affected CO2 capture 

facilities assumes that only existing projects are affected, and only projects associated with 

named DOE pilot projects and federal/private partnerships will be affected. All other 

assumptions are consistent with the high-end estimate for the number of affected CO2

sequestration facilities. 

 

Exhibit 11 below presents the low-end estimate for the number of CO2 sequestration facilities 

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

Exhibit 11: Low-End Estimate of the CO2 Facilities Assumed 

to Begin and Practice Sequestration Activities, by Year

Year Number of Sequestration Facilities 

Beginning Operation 

Total Number of Sequestration 

Facilities in Operation 

2010 - 2012 0 0

2013 0 0

2014 0 0

2015 0 0

2016 0 0

2017 6 6

2018 0 6

2019 0 6

2020 0 6

2021 0 6
 Page 31 of 145 

Year Number of Sequestration Facilities 

Beginning Operation 

Total Number of Sequestration 

Facilities in Operation 

2022 0 6

2023 0 6

2024 0 6

2025 0 6

2026 0 6

2027 0 6

2028 0 6

2029 0 6

2030 0 6

2031 0 6

2032 0 6

2033 0 6

2034 0 6

2035 0 6

2036 0 6

Post-2036 0 6

Total 6 6

3. Analysis of the Incremental Costs 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 
 Page 32 of 145 

analysis then estimates the incremental costs and benefits of the proposed rule relative to the 

baseline over a 50-year period.35 

3.2 Baseline Practices 

Depending on whether or not their captured 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 

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.36 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.37 This third 

 

35 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. 

36 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. 37 We recognize that, besides mercury, other heavy metals such as arsenic and selenium may be present at very 

low levels. 
 Page 33 of 145 

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

approximately $4,500 in one-time costs and $2,700 in annual costs to utilize this method of 

RCRA hazardous waste determination.38 

This analysis assumes that the facilities capturing 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 

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).39

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 12 

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

determine their CO2 stream to be RCRA hazardous waste. 

 

38 See Appendix A for further detail on the calculation of these costs. Labor hours were converted to costs 

using loaded hourly wages of $110.99 for Senior Chemists, and $55.95 for Chemists and Sampling Technicians. 

39 For simplicity, this draft applies a single weighted average waste determination cost. 
 Page 34 of 145 

Exhibit 12: Flow Chart of Baseline Practices of 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 

Destined 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 40

 

 

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 

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.41 

 

40 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. 41 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. 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 
 Page 35 of 145 

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.42 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 public 

image, or to prepare for anticipated regulatory or market changes (i.e., to avoid early 

obsolescence). These same factors may influence generators’ decisions to continue 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. 

 

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. 

42 Although the Class VI requirements are more stringent than the Class I requirements, EPA assumes that UIC 

permit writers would ensure that Class I wells used for 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. 
 Page 36 of 145 

3.2.2.2 Expected Baseline Practices of CO2 Carbon Capture Facilities 

As shown in Exhibit 12 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. There is significant uncertainty in the hazardous constituent content 

of CO2 streams that will be captured, and the complexity of the factors that may influence the 

baseline practices for generators of hazardous streams. As a result, we have assumed a broad 

range for the prevalence of hazardous waste determination and baseline practices for CO2

capture facilities. 

Exhibits 13 and 14 present our conservative (high-end) and low-end assumptions regarding 

the relative prevalence of each baseline practice in the absence of the proposed rule.43 

Exhibit 13 assumes that 90% of the managed CO2 is RCRA hazardous waste, with equal 

distribution among baseline management practices, while Exhibit 14 assumes that 10 percent 

of the managed CO2 is RCRA hazardous waste. It is important to note that, due to the lack of 

definitive data, the hazardous CO2 percentages presented in these Exhibits are designed to 

represent a broad range of potential outcomes for analytical purposes only. Based on early 

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

are potentially classified as hazardous may be low. 

Exhibit 13: High-End Assumption for the Prevalence of Hazardous Waste 

Determination and Baseline Practices for 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 as a high-end estimate due to a lack of data on the 

relative distribution of CO2 streams’ hazardous waste designation. 

 

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

continuous fashion. 
 Page 37 of 145 

Exhibit 14: Low-End Assumption 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 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 % 

a

 For purposes of this analysis EPA assumes these values as a low-end estimate due to a lack of data on the 

relative distribution of CO2 streams’ hazardous waste designation. 

Exhibit 15 presents the number of CO2 capture facilities that EPA expects will be active each 

year under the conservative assumption, and applies the percentages from Exhibit 13 to 

estimate the number of CO2 capture facilities that would engage in each baseline practice 

each year in the absence of the proposed rule.44

Exhibit 15 – Assumed 90% Hazardous Waste: 

Expected Number of CO2 Capture Facilities That Would Engage 

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

Year

Non-hazardousSend to Class VI 

HazardousCease 

Capture 

Hazardous - 

Treat and Send 

to Class VI 

Hazardous - Send to 

Class I that is 

Assumed to Meet 

Class VI 

Requirements Total 

2012 0 1 1 2 4

2013 1 1 1 2 5

2014 1 1 1 2 5

2015 1 1 1 2 5

2016 1 1 1 2 5

2017 1 1 2 2 6

2018 1 1 2 2 6

2019 1 1 2 2 6

2020 1 1 2 2 6

2021 1 1 2 2 6

2022 1 1 2 2 6

2023 1 1 2 2 6

2024 1 1 2 2 6

2025 1 1 2 2 6

2026 1 1 2 2 6

 

44 After applying the weights from Exhibit 13, the number of facilities practicing each baseline practice was 

adjusted slightly to eliminate rounding errors in the total number of capture facilities. 
 Page 38 of 145 

Year

Non-hazardousSend to Class VI 

HazardousCease 

Capture 

Hazardous - 

Treat and Send 

to Class VI 

Hazardous - Send to 

Class I that is 

Assumed to Meet 

Class VI 

Requirements Total 

2027 1 1 2 2 6

2028 1 1 2 2 6

2029 1 1 2 2 6

2030 2 4 4 5 15

2031 2 4 5 5 16

2032 2 6 6 6 20

2033 2 6 6 6 20

2034 3 7 7 8 25

2035 3 8 8 8 27

2036 3 8 8 8 27 

Post 2036 3 8 8 8 27

a

 The numbers in this table are derived by applying the percentages of capture facilities conducting each 

baseline practice presented in Exhibit 13 to the cumulative number of capture facilities expected to 

practice sequestration of their CO2 streams each year, as 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. 

Exhibit 16 below presents the number of CO2 capture facilities that EPA expects will be 

active each year under the low-end assumption, and applies the percentages from Exhibit 14 

to estimate the number of CO2 capture facilities that would engage in each baseline practice 

each year in the absence of the proposed rule.45

Exhibit 16– Assumed 10% Hazardous Waste: 

Expected Number of CO2 Capture Facilities That Would Engage 

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

Year

Non-hazardousSend to Class VI 

HazardousCease 

Capture 

Hazardous - 

Treat and Send 

to Class VI 

Hazardous - Send to 

Class I that is 

Assumed to Meet 

Class VI 

Requirements Total 

2012 4 0 0 0 4 

2013 5 0 0 0 5 

2014 5 0 0 0 5 

2015 5 0 0 0 5 

2016 5 0 0 0 5 

2017 5 0 1 0 6 

2018 5 0 1 0 6 

2019 5 0 1 0 6 

2020 5 0 1 0 6 

2021 5 0 1 0 6 

 

45 After applying the weights from Exhibit 14, the number of facilities practicing each baseline practice was 

adjusted slightly to eliminate rounding errors in the total number of capture facilities. 
 Page 39 of 145 

Year

Non-hazardousSend to Class VI 

HazardousCease 

Capture 

Hazardous - 

Treat and Send 

to Class VI 

Hazardous - Send to 

Class I that is 

Assumed to Meet 

Class VI 

Requirements Total 

2022 5 0 1 0 6 

2023 5 0 1 0 6 

2024 5 0 1 0 6 

2025 5 0 1 0 6 

2026 5 0 1 0 6 

2027 5 0 1 0 6 

2028 5 0 1 0 6 

2029 5 0 1 0 6 

2030 14 0 1 0 15 

2031 14 0 1 1 16 

2032 18 0 1 1 20 

2033 18 0 1 1 20 

2034 23 0 1 1 25 

2035 24 1 1 1 27 

2036 24 1 1 1 27 

Post 2036 24 1 1 1 27 

a

 The numbers in this table are derived by applying the percentages of capture facilities conducting each 

baseline practice presented in Exhibit 14 to the cumulative number of capture facilities expected to 

practice sequestration of their CO2 streams each year, as 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 facilities 

incur under the baseline:46

• 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. 

 

46 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, so 

this analysis assumes the associated costs to be negligible for handling the samples. 
 Page 40 of 145 

• 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). 

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.47 

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

Section 3.5. 

3.2.3 Baseline Practices for 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. 

High-End Assumption: 

This analysis assumes that, in the baseline high-end assumption, 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.48 Exhibit 17 estimates the number of CO2 

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

assumption 

 

47 EPA has assumed that these facilities would meet the requirements of “onsite treatment” under 40 CFR 

260.10 (Definitions) and related RCRA regulations and therefore would not be required to obtain RCRA 

hazardous waste treatment permits. 

48 For the high-end estimate, this analysis assumes that 40 percent of CO2capture facilities would transport nonhazardous or treated CO2 streams to Class VI sequestration wells for injection (see Exhibit 13). 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. 
 Page 41 of 145 

Exhibit 17 – High-End: 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 

2023 10 7 

2024 10 7 

2025 10 7 

2026 10 7 

2027 10 7 

2028 10 7 

2029 10 7 

2030 10 7 

2031 10 8 

2032 13 9 

2033 13 9 

2034 15 12 

2035 17 12 

2036 17 12 

Post 2036 17 12 a The numbers in this table are derived by applying the percentages of sequestration 

facilities conducting each baseline practice discussed above to the number of 

sequestration facilities expected to be in operation each year (cumulative), as presented 

in Exhibit 10. The numbers are rounded to integer values while ensuring the total 

number of capture facilities in each year matches the total from Exhibit 10. 

Low-End Assumption: 

This analysis assumes that, in the baseline low-end assumption, approximately 97 percent of 

the sequestration wells 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.49 Exhibit 18 estimates the number of CO2 

 

49 For the low-end estimate, this analysis assumes that 90 percent of CO2capture facilities would transport nonhazardous or treated CO2 streams to Class VI sequestration wells for injection (see Exhibit 14). Another 3.3 
 Page 42 of 145 

sequestration facilities that would engage in each baseline practice under our low-end 

assumption 

Exhibit 18 – Low End: Expected Number of 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 2 0 

2013 3 0 

2014 4 0 

2015 4 0 

2016 6 0 

2017 15 1 

2018 16 1 

2019 16 1 

2020 16 1 

2021 16 1 

2022 16 1 

2023 16 1 

2024 16 1 

2025 16 1 

2026 16 1 

2027 16 1 

2028 16 1 

2029 16 1 

2030 16 1 

2031 17 1 

2032 21 1 

2033 21 1 

2034 26 1 

2035 28 1 

2036 28 1 

Post 2036 28 1 a The numbers in this table are derived by applying the percentages of sequestration 

facilities conducting each baseline practice discussed above to the number of 

sequestration facilities expected to be in operation each year (cumulative), as presented 

in Exhibit 11. The numbers are rounded to integer values while ensuring the total 

number of capture facilities in each year matches the total from Exhibit 11. 

 

percent of CO2 capture facilities would transport hazardous CO2 streams to Class I sequestration wells for 

injection. This analysis assumes that 97 percent of CO2 sequestration wells in the baseline are Class VI wells to 

match the practices of CO2 capture facilities. The remaining 3 percent of CO2 sequestration wells in the 

baseline are Class I wells. 
 Page 43 of 145 

3.3 Post Rule Practices 

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

to the rule, as proposed. The rule requires no changes for pipeline transportation of CO2, 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.50 Under the 

proposal, CO2 capture facilities claiming the exclusion would avoid the costs of determining 

whether their CO2 stream is RCRA hazardous or non-hazardous. Exempt generators/capture 

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

additional cost of treating the CO2 stream. 

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.51 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 

 

50 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. 

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

experimental wells. 
 Page 44 of 145 

they must maintain onsite and make available to EPA upon request.52 The facilities are 

required to renew the certification statement each year in which they claim the exclusion. 

Facilities claiming the exclusion also must provide the statement to EPA or state 

governments, upon request. Exhibit 19 presents the estimated labor costs per facility 

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

capture facilities and Class VI UIC wells. 

Exhibit 19: 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 

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.

Industry Compliance Costs – High-End Estimate: 

Exhibits 20 and 21 multiply the per facility costs times the maximum number of potentially 

affected capture facilities and Class VI wells, respectively. These facilities are expected to 

incur each cost in each year over the 50-year period beginning in 2012. Facilities are 

assumed to sign the certification in the first year of operation and renew the certification in 

each subsequent year.53 Combined, EPA and state governments are assumed to request 

certification statements from approximately 30 percent of capture facilities and Class VI well 

operators annually.54 The exhibits present the undiscounted certification costs, and also 

present the discounted certification costs applying 3 percent and 7 percent discount rate to 

costs incurred after 2012. 

 

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

sequestration facility would sign its own certification statement. 53 See Exhibits 5 and 10 for the number of 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. 54 This estimate is based on EPA’s best professional judgment. 
 Page 45 of 145 

Exhibit 20: High-End Estimate: 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

2026 0 $0 6 $1,026 2 $6 $1,032 $682 $400

2027 0 $0 6 $1,026 2 $6 $1,032 $662 $374

2028 0 $0 6 $1,026 2 $6 $1,032 $643 $350

2029 0 $0 6 $1,026 2 $6 $1,032 $624 $327

2030 9 $3,267 6 $1,026 5 $15 $4,308 $2,530 $1,275

2031 1 $363 15 $2,565 5 $15 $2,943 $1,678 $814

2032 4 $1,452 16 $2,736 6 $18 $4,206 $2,329 $1,087

2033 0 $0 20 $3,420 6 $18 $3,438 $1,848 $830

2034 5 $1,815 20 $3,420 8 $24 $5,259 $2,745 $1,187

2035 2 $726 25 $4,275 8 $24 $5,025 $2,546 $1,060

2036 0 $0 27 $4,617 8 $24 $4,641 $2,283 $915

2037 0 $0 27 $4,617 8 $24 $4,641 $2,217 $855

2038 0 $0 27 $4,617 8 $24 $4,641 $2,152 $799

2039 0 $0 27 $4,617 8 $24 $4,641 $2,089 $747

2040 0 $0 27 $4,617 8 $24 $4,641 $2,028 $698

2041 0 $0 27 $4,617 8 $24 $4,641 $1,969 $652

2042 0 $0 27 $4,617 8 $24 $4,641 $1,912 $610

2043 0 $0 27 $4,617 8 $24 $4,641 $1,856 $570

2044 0 $0 27 $4,617 8 $24 $4,641 $1,802 $533

2045 0 $0 27 $4,617 8 $24 $4,641 $1,750 $498

2046 0 $0 27 $4,617 8 $24 $4,641 $1,699 $465

2047 0 $0 27 $4,617 8 $24 $4,641 $1,649 $435

2048 0 $0 27 $4,617 8 $24 $4,641 $1,601 $406

2049 0 $0 27 $4,617 8 $24 $4,641 $1,555 $380

2050 0 $0 27 $4,617 8 $24 $4,641 $1,509 $355

2051 0 $0 27 $4,617 8 $24 $4,641 $1,465 $332
 Page 46 of 145 

Year 

Initial Certifications Certifications Renewals 

Certification 

Submissions to State 

or EPA 

Total Cost 

Number 

A 

Cost 

B = A X 

$363 

Number 

C 

Cost 

D = C X $171 

Number 

E 

Cost 

F = C X 

$3 

Undiscounted 

B + D +F 

3% 

Discount 

Rate 

7% 

Discount 

Rate 

2052 0 $0 27 $4,617 8 $24 $4,641 $1,423 $310

2053 0 $0 27 $4,617 8 $24 $4,641 $1,381 $290

2054 0 $0 27 $4,617 8 $24 $4,641 $1,341 $271

2055 0 $0 27 $4,617 8 $24 $4,641 $1,302 $253

2056 0 $0 27 $4,617 8 $24 $4,641 $1,264 $236

2057 0 $0 27 $4,617 8 $24 $4,641 $1,227 $221

2058 0 $0 27 $4,617 8 $24 $4,641 $1,192 $207

2059 0 $0 27 $4,617 8 $24 $4,641 $1,157 $193

2060 0 $0 27 $4,617 8 $24 $4,641 $1,123 $180

2061 0 $0 27 $4,617 8 $24 $4,641 $1,090 $169

50 

Year 

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

Exhibit 21: High-End Estimate: 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
 Page 47 of 145 

Year 

Initial Certifications Certifications Renewals 

Certification 

Submissions to State 

or EPA 

Total Cost 

Number 

A 

Cost 

B = A X 

$363 

Number 

C 

Cost 

D = C X $171 

Number 

E 

Cost 

F = C X 

$3 

Undiscounted 

B + D +F 

3% 

Discount 

Rate 

7% 

Discount 

Rate 

2032 4 $1,452 18 $3,078 7 $21 $4,530 $2,508 $1,171

2033 0 $0 22 $3,762 7 $21 $3,762 $2,022 $909

2034 5 $1,815 22 $3,762 8 $24 $5,577 $2,911 $1,259

2035 2 $726 27 $4,617 9 $27 $5,343 $2,707 $1,127

2036 0 $0 29 $4,959 9 $27 $4,959 $2,439 $978

2037 0 $0 29 $4,959 9 $27 $4,959 $2,368 $914

2038 0 $0 29 $4,959 9 $27 $4,959 $2,299 $854

2039 0 $0 29 $4,959 9 $27 $4,959 $2,232 $798

2040 0 $0 29 $4,959 9 $27 $4,959 $2,167 $746

2041 0 $0 29 $4,959 9 $27 $4,959 $2,104 $697

2042 0 $0 29 $4,959 9 $27 $4,959 $2,043 $651

2043 0 $0 29 $4,959 9 $27 $4,959 $1,984 $609

2044 0 $0 29 $4,959 9 $27 $4,959 $1,926 $569

2045 0 $0 29 $4,959 9 $27 $4,959 $1,870 $532

2046 0 $0 29 $4,959 9 $27 $4,959 $1,815 $497

2047 0 $0 29 $4,959 9 $27 $4,959 $1,762 $464

2048 0 $0 29 $4,959 9 $27 $4,959 $1,711 $434

2049 0 $0 29 $4,959 9 $27 $4,959 $1,661 $406

2050 0 $0 29 $4,959 9 $27 $4,959 $1,613 $379

2051 0 $0 29 $4,959 9 $27 $4,959 $1,566 $354

2052 0 $0 29 $4,959 9 $27 $4,959 $1,520 $331

2053 0 $0 29 $4,959 9 $27 $4,959 $1,476 $309

2054 0 $0 29 $4,959 9 $27 $4,959 $1,433 $289

2055 0 $0 29 $4,959 9 $27 $4,959 $1,391 $270

2056 0 $0 29 $4,959 9 $27 $4,959 $1,351 $253

2057 0 $0 29 $4,959 9 $27 $4,959 $1,311 $236

2058 0 $0 29 $4,959 9 $27 $4,959 $1,273 $221

2059 0 $0 29 $4,959 9 $27 $4,959 $1,236 $206

2060 0 $0 29 $4,959 9 $27 $4,959 $1,200 $193

2061 0 $0 29 $4,959 9 $27 $4,959 $1,165 $180

50 

Year 

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

Industry Compliance Costs – Low-End Estimate: 

Exhibits 22 and 23 multiply the per facility costs times the low-end estimate for the number 

of potentially affected capture facilities and Class VI wells, respectively. As with the highend estimate, these facilities are expected to incur each cost in each year over the 50-year 

period, beginning in 2012. Facilities are assumed to sign the certification in the first year of 
 Page 48 of 145 

operation and renew the certification in each subsequent year.55 Combined, EPA and state 

governments are assumed to request certification statements from approximately 30 percent 

of capture facilities and Class VI well operators annually.56 The exhibits present the 

undiscounted certification costs, and also present the discounted certification costs applying 3 

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

Exhibit 22: Low-End Estimate: Certification Costs for 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

 

55 See Exhibits 6 and 11 for the number of 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. 56 This estimate is based on EPA’s best professional judgment. 
 Page 49 of 145 

Year 

Initial Certifications Certifications Renewals 

Certification 

Submissions to State 

or EPA 

Total Cost 

Number 

A 

Cost 

B = A X 

$363 

Number 

C 

Cost 

D = C X $171 

Number 

E 

Cost 

F = C X 

$3 

Undiscounted 

B + D +F 

3% 

Discount 

Rate 

7% 

Discount 

Rate 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

50 

Year 

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

Exhibit 23: Low-End Estimate: Certification Costs for Class VI 

Underground Injection Control Wells, 2012 to 2061, (2010 dollars) 

Year 

Initial Certifications Certifications Renewals 

Certification 

Submissions to State 

or EPA 

Total Cost 

Number 

A 

Cost 

B = A X 

$363 

Number 

C 

Cost 

D = C X $171 

Number 

E 

Cost 

F = C X 

$3 

Undiscounted 

B + D +F 

3% 

Discount 

Rate 

7% 

Discount 

Rate 

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

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

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

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

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

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

2018 0 $0 6 $1,026 2 $6 $1,026 $859 $684 
 Page 50 of 145 

Year 

Initial Certifications Certifications Renewals 

Certification 

Submissions to State 

or EPA 

Total Cost 

Number 

A 

Cost 

B = A X 

$363 

Number 

C 

Cost 

D = C X $171 

Number 

E 

Cost 

F = C X 

$3 

Undiscounted 

B + D +F 

3% 

Discount 

Rate 

7% 

Discount 

Rate 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

2060 0 $0 6 $1,026 2 $6 $1,026 $248 $40 
 Page 51 of 145 

Year 

Initial Certifications Certifications Renewals 

Certification 

Submissions to State 

or EPA 

Total Cost 

Number 

A 

Cost 

B = A X 

$363 

Number 

C 

Cost 

D = C X $171 

Number 

E 

Cost 

F = C X 

$3 

Undiscounted 

B + D +F 

3% 

Discount 

Rate 

7% 

Discount 

Rate 

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

50 

Year 

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

Under the proposed rule, some 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, for this analysis EPA has assumed 

that there is no difference in cost for construction and permitting of Class I and Class VI 

wells. 

3.4.2 Social Costs 

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

designed to protect the human health and the environment. However, EPA finds 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 Underground Sources of Drinking Water (USDWs). In 

addition, permit writers for Class VI UIC wells have discretion in whether to allow the 

sequestration of certain wastes depending on factors such as the composition of the waste, 

the structure of the well, and the proximity of the well to USDWs. Therefore, EPA has 

determined that the management of exempted CO2 streams in Class VI UIC wells would not 

pose an unacceptable risk to human health and the environment.57 Based on available 

knowledge, EPA does not anticipate any negative 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 have productivity and output implications. This analysis does not 

model the potential productivity impact of the proposed rule. However, EPA anticipates that 

these impacts would be primarily positive, as affected facilities could use savings associated 

with the proposed rule to increase output or productivity. 

 

57 Today’s proposed conditional exclusion is based upon EPA’s existing knowledge of the composition of CO2 

streams, and its analysis that compliance with the existing standards and regulations designed to prevent any 

exposure of CO2 (and any associated impurities) would render additional regulation under RCRA subtitle C 

unnecessary. Nevertheless, EPA is seeking to collect additional data on the composition of captured CO2 

streams. As CCS pilot projects move forward and continue to generate information, EPA expects the amount of 

available analytical data on captured CO2 to increase.
 Page 52 of 145 

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.58 Exhibits 24 and 25 present the costs per request to EPA and state 

governments, respectively. 

Exhibit 24: 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 25: 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.

Exhibits 26 and 27 below present the high-end estimates for the total costs to EPA and state 

governments to request and review certification statements related to the proposed exclusion 

 

58 These estimates are based on EPA’s best professional judgment. 
 Page 53 of 145 

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 26: High-End Estimate: Costs to EPA to Request and 

Review Certification Statements, 2012 to 2061 (2010 dollars) 

Year 

Number of 

Requests Per Year

A 

Undiscounted Cost

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

2012 0 $0 $0 $0 

2013 0 $0 $0 $0 

2014 0 $0 $0 $0 

2015 0 $0 $0 $0 

2016 0 $0 $0 $0 

2017 1 $47 $41 $34 

2018 1 $47 $39 $31 

2019 1 $47 $38 $29 

2020 1 $47 $37 $27 

2021 1 $47 $36 $26 

2022 1 $47 $35 $24 

2023 1 $47 $34 $22 

2024 1 $47 $33 $21 

2025 1 $47 $32 $20 

2026 1 $47 $31 $18 

2027 1 $47 $30 $17 

2028 1 $47 $29 $16 

2029 1 $47 $28 $15 

2030 1 $47 $28 $14 

2031 1 $47 $27 $13 

2032 1 $47 $26 $12 

2033 1 $47 $25 $11 

2034 2 $94 $49 $21 

2035 2 $94 $48 $20 

2036 2 $94 $46 $19 

2037 2 $94 $45 $17 

2038 2 $94 $44 $16 

2039 2 $94 $42 $15 

2040 2 $94 $41 $14 

2041 2 $94 $40 $13 

2042 2 $94 $39 $12 

2043 2 $94 $38 $12 
 Page 54 of 145 

Year 

Number of 

Requests Per Year

A 

Undiscounted Cost

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

2044 2 $94 $37 $11 

2045 2 $94 $35 $10 

2046 2 $94 $34 $9 

2047 2 $94 $33 $9 

2048 2 $94 $32 $8 

2049 2 $94 $31 $8 

2050 2 $94 $31 $7 

2051 2 $94 $30 $7 

2052 2 $94 $29 $6 

2053 2 $94 $28 $6 

2054 2 $94 $27 $5 

2055 2 $94 $26 $5 

2056 2 $94 $26 $5 

2057 2 $94 $25 $4 

2058 2 $94 $24 $4 

2059 2 $94 $23 $4 

2060 2 $94 $23 $4 

2061 2 $94 $22 $3 

50 Year Total 73 $3,431 $1,498 $626 

Exhibit 27: High-End Estimate: Costs to State Governments to Request and Review 

Certification Statements, 2012 to 2061 (2010 dollars) 

Year 

Number of Requests 

Per Year 

A 

Undiscounted Cost

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

2012 2 $122 $122 $122 

2013 3 $183 $178 $171 

2014 3 $183 $172 $160 

2015 3 $183 $167 $149 

2016 4 $244 $217 $186 

2017 6 $366 $316 $261 

2018 6 $366 $307 $244 

2019 6 $366 $298 $228 

2020 6 $366 $289 $213 

2021 6 $366 $281 $199 

2022 6 $366 $272 $186 

2023 6 $366 $264 $174 
 Page 55 of 145 

Year 

Number of Requests 

Per Year 

A 

Undiscounted Cost

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

2024 6 $366 $257 $163 

2025 6 $366 $249 $152 

2026 6 $366 $242 $142 

2027 6 $366 $235 $133 

2028 6 $366 $228 $124 

2029 6 $366 $221 $116 

2030 9 $549 $322 $162 

2031 9 $549 $313 $152 

2032 12 $732 $405 $189 

2033 12 $732 $393 $177 

2034 14 $854 $446 $193 

2035 15 $915 $464 $193 

2036 15 $915 $450 $180 

2037 15 $915 $437 $169 

2038 15 $915 $424 $158 

2039 15 $915 $412 $147 

2040 15 $915 $400 $138 

2041 15 $915 $388 $129 

2042 15 $915 $377 $120 

2043 15 $915 $366 $112 

2044 15 $915 $355 $105 

2045 15 $915 $345 $98 

2046 15 $915 $335 $92 

2047 15 $915 $325 $86 

2048 15 $915 $316 $80 

2049 15 $915 $307 $75 

2050 15 $915 $298 $70 

2051 15 $915 $289 $65 

2052 15 $915 $280 $61 

2053 15 $915 $272 $57 

2054 15 $915 $264 $53 

2055 15 $915 $257 $50 

2056 15 $915 $249 $47 

2057 15 $915 $242 $44 

2058 15 $915 $235 $41 

2059 15 $915 $228 $38 
 Page 56 of 145 

Year 

Number of Requests 

Per Year 

A 

Undiscounted Cost

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

2060 15 $915 $221 $36 

2061 15 $915 $215 $33 

50 Year Total 554 $33,794 $14,947 $6,471 

Exhibits 28 and 29 below present the low-end estimates for the total costs to EPA and state 

governments to request and review certification statements related to the proposed exclusion 

over the 50-year period beginning 2012. These exhibits present undiscounted costs, and also 

apply 3 percent and 7 percent discount rates to costs incurred after 2012. 

. 

Exhibit 28: Low-End Estimate: Costs to EPA to Request and 

Review Certification Statements, 2012 to 2061 (2010 dollars) 

Year 

Number of 

Requests Per Year

A 

Undiscounted Cost

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

2012 0 $0 $0 $0 

2013 0 $0 $0 $0 

2014 0 $0 $0 $0 

2015 0 $0 $0 $0 

2016 0 $0 $0 $0 

2017 0 $0 $0 $0 

2018 0 $0 $0 $0 

2019 0 $0 $0 $0 

2020 0 $0 $0 $0 

2021 0 $0 $0 $0 

2022 0 $0 $0 $0 

2023 0 $0 $0 $0 

2024 0 $0 $0 $0 

2025 0 $0 $0 $0 

2026 0 $0 $0 $0 

2027 0 $0 $0 $0 

2028 0 $0 $0 $0 

2029 0 $0 $0 $0 

2030 1 $47 $28 $14 

2031 1 $47 $27 $13 

2032 1 $47 $26 $12 

2033 1 $47 $25 $11 

2034 1 $47 $25 $11 

2035 1 $47 $24 $10 
 Page 57 of 145 

Year 

Number of 

Requests Per Year

A 

Undiscounted Cost

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

2036 1 $47 $23 $9 

2037 1 $47 $22 $9 

2038 1 $47 $22 $8 

2039 1 $47 $21 $8 

2040 1 $47 $21 $7 

2041 1 $47 $20 $7 

2042 1 $47 $19 $6 

2043 1 $47 $19 $6 

2044 1 $47 $18 $5 

2045 1 $47 $18 $5 

2046 1 $47 $17 $5 

2047 1 $47 $17 $4 

2048 1 $47 $16 $4 

2049 1 $47 $16 $4 

2050 1 $47 $15 $4 

2051 1 $47 $15 $3 

2052 1 $47 $14 $3 

2053 1 $47 $14 $3 

2054 1 $47 $14 $3 

2055 1 $47 $13 $3 

2056 1 $47 $13 $2 

2057 1 $47 $12 $2 

2058 1 $47 $12 $2 

2059 1 $47 $12 $2 

2060 1 $47 $11 $2 

2061 1 $47 $11 $2 

50 Year Total 32 $1,504 $580 $188 
 Page 58 of 145 

Exhibit 29: Low-End Estimate: Costs to State Governments to Request and Review 

Certification Statements, 2012 to 2061 (2010 dollars) 

Year 

Number of Requests 

Per Year 

A 

Undiscounted Cost

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

2012 1 $61 $61 $61 

2013 1 $61 $59 $57 

2014 1 $61 $57 $53 

2015 1 $61 $56 $50 

2016 1 $61 $54 $47 

2017 3 $183 $158 $130 

2018 3 $183 $153 $122 

2019 3 $183 $149 $114 

2020 3 $183 $144 $107 

2021 3 $183 $140 $100 

2022 3 $183 $136 $93 

2023 3 $183 $132 $87 

2024 3 $183 $128 $81 

2025 3 $183 $125 $76 

2026 3 $183 $121 $71 

2027 3 $183 $117 $66 

2028 3 $183 $114 $62 

2029 3 $183 $111 $58 

2030 5 $305 $179 $90 

2031 5 $305 $174 $84 

2032 5 $305 $169 $79 

2033 5 $305 $164 $74 

2034 5 $305 $159 $69 

2035 5 $305 $155 $64 

2036 5 $305 $150 $60 

2037 5 $305 $146 $56 

2038 5 $305 $141 $53 

2039 5 $305 $137 $49 

2040 5 $305 $133 $46 

2041 5 $305 $129 $43 

2042 5 $305 $126 $40 

2043 5 $305 $122 $37 

2044 5 $305 $118 $35 

2045 5 $305 $115 $33 

2046 5 $305 $112 $31 
 Page 59 of 145 

Year 

Number of Requests 

Per Year 

A 

Undiscounted Cost

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

2047 5 $305 $108 $29 

2048 5 $305 $105 $27 

2049 5 $305 $102 $25 

2050 5 $305 $99 $23 

2051 5 $305 $96 $22 

2052 5 $305 $93 $20 

2053 5 $305 $91 $19 

2054 5 $305 $88 $18 

2055 5 $305 $86 $17 

2056 5 $305 $83 $16 

2057 5 $305 $81 $15 

2058 5 $305 $78 $14 

2059 5 $305 $76 $13 

2060 5 $305 $74 $12 

2061 5 $305 $72 $11 

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

3.5 Incremental Cost Savings and Benefits of the Proposed Rule 

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

requirements under the proposed rule.59 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 destined for GS 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). 

 

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

CO2 in the baseline. 
 Page 60 of 145 

Appendix A of this document discusses the available testing options for waste determination 

(i.e., Option 1, 2, and 3). As stated in Section 3.2, this analysis assumes that the 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 further assumes that the remaining 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 $5,300 in one-time costs and 

$3,000 in annual costs.60 Under the proposed rule, exempt generators would not be required 

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

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 a 

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. Thus, these facilities would be 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 30 estimates the annual savings per facility that would no longer 

be subject to the RCRA training, planning and reporting requirements under the proposed 

rule. 

 

60 See Appendix A for further detail on the calculation of waste determination costs. 
 Page 61 of 145 

Exhibit 30: 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 b 262.12 $0 

Personnel Training c 262.34 $2,762 

Contingency Planning c 262.34 $733 

Emergency Planning c 262.34 $482 

Recordkeeping c 262.40 $711 

Manifest d 262 Subpart B $0 

Manifest Exception Report d 262.42 $0 

Biennial Report c 262.41 $369 

Total $5,057 

a

 These savings apply to facilities that capture hazardous waste 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. 

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 Integrated Gasification Combined Cycle (IGCC) power plant 

would cost $8.94 per metric ton of CO2.

61 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 enhanced oil recovery (EOR), not for sequestration] captured 11 

million metric tons of CO2 waste in 2008, or about 1.1 million metric tons per facility.62 If 

 

61 Appendix B presents the calculation of these CO2 treatment costs. 62 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. . 
 Page 62 of 145 

the planned CO2 capture facilities generate CO2 streams at a similar rate, each facility that 

treats its CO2 stream in the baseline would save approximately $10.27 million per year in 

CO2 stream treatment costs under the proposed rule. 

3.5.4 Summary of Savings to CO2 Capture Facilities 

Exhibit 31 multiplies each of the savings identified above times the appropriate number of 

facilities that would receive each saving in 2012, and calculates a total expected savings of 

approximately $10.31 million to CO2 capture facilities in the first year under the proposed 

rule. 

Exhibit 31: 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 d 1 $10,270,395 $10,270,395 

Total $10,313,678 a

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

first time. Note: One capture facility was in operation in 2010. b

 Annual waste determinations savings apply to all 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. 

Exhibits 32 and 33 below apply the methodology described above to calculate the expected 

savings to CO2 Capture Facilities under the high-end and low-end estimates. Savings as a 

result of the proposal are calculated for each year over a 50-year period beginning in 2012. 

The exhibits present the undiscounted savings, and also apply 3 percent and 7 percent 

discount rates to savings accrued after 2012. 
 Page 63 of 145 

Exhibit 32: High-End Estimate: 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 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

2053 $58,393 $80,912 $82,163,162 $82,302,467 $24,495,519 $5,136,626 
 Page 64 of 145 

2054 $58,393 $80,912 $82,163,162 $82,302,467 $23,782,057 $4,800,585 

2055 $58,393 $80,912 $82,163,162 $82,302,467 $23,089,376 $4,486,528 

2056 $58,393 $80,912 $82,163,162 $82,302,467 $22,416,870 $4,193,017 

2057 $58,393 $80,912 $82,163,162 $82,302,467 $21,763,951 $3,918,708 

2058 $58,393 $80,912 $82,163,162 $82,302,467 $21,130,050 $3,662,344 

2059 $58,393 $80,912 $82,163,162 $82,302,467 $20,514,611 $3,422,751 

2060 $58,393 $80,912 $82,163,162 $82,302,467 $19,917,098 $3,198,833 

2061 $58,393 $80,912 $82,163,162 $82,302,467 $19,336,989 $2,989,563 

50 Year Total $2,208,498 $2,816,749 $2,824,358,694 $2,829,383,941 $1,188,762,217 $472,624,602 

See Exhibits 15 for number of affected facilities, by category. 

Year 2030 Example: [(9 new one-time facilities * $5,273) + (14 annual * $3,073)]. Note that one cease capture facility from 

prior year drops out. 

Exhibit 33: Low-End Estimate: Savings to 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 $0 $0 $28,112 $28,112 $28,112 

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

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

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

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

2017 $23,713 $5,057 $10,270,395 $10,299,165 $8,884,150 $7,343,162 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

2035 $93,525 $10,114 $10,270,395 $10,374,034 $5,256,437 $2,188,370 

2036 $79,906 $10,114 $10,270,395 $10,360,415 $5,096,638 $2,042,521 
 Page 65 of 145 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

See Exhibits 16 for number of affected facilities, by category. 
 Page 66 of 145 

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.63

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 34 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. 

 

63 See Appendix A for further detail on the calculation of waste determination costs. 
 Page 67 of 145 

Exhibit 34: 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 b 144.14(c)(1) $0 

EPA ID b 144.14(c)(2) $0 

Manifest c 144.14(c)(3) $0 

Manifest Discrepancies c 144.14(c)(4) $0 

Operating Record b 144.14(c)(5) $0 

Biennial Report d 144.14(c)(6) $0 

Unmanifested Waste Report c 144.14(c)(7) $0 

Personnel Training e 144.14(c)(8) $2,762 

Certification of closure b 144.14(c)(9) $0 

Total $2,762 

a

 These savings apply to sequestration 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. 

3.5.7 Summary of Savings to CO2 Sequestration Facilities 

Exhibit 35 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 (high-end estimate) that would 

receive each saving in 2012, to calculate the total expected high-end savings to CO2

sequestration facilities in the first year under the proposed rule. 
 Page 68 of 145 

Exhibit 35: 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 36 uses this methodology to calculate the expected high-end 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 36: High-End Estimate: 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 

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

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

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

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

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

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

2033 $33,801 $19,334 $53,135 $28,563 $12,833 
 Page 69 of 145 

Year Waste 

Determination 

Hazardous Waste 

Generator 

Requirements 

Total Savings 

(Undiscounted) 

Total Savings 

(3% Discount 

Rate) 

Total Savings 

(7% Discount 

Rate) 

2034 $63,681 $22,096 $85,777 $44,767 $19,361 

2035 $53,435 $24,858 $78,293 $39,671 $16,516 

2036 $44,556 $24,858 $69,414 $34,147 $13,685 

2037 $44,556 $24,858 $69,414 $33,153 $12,790 

2038 $44,556 $24,858 $69,414 $32,187 $11,953 

2039 $44,556 $24,858 $69,414 $31,250 $11,171 

2040 $44,556 $24,858 $69,414 $30,339 $10,440 

2041 $44,556 $24,858 $69,414 $29,456 $9,757 

2042 $44,556 $24,858 $69,414 $28,598 $9,119 

2043 $44,556 $24,858 $69,414 $27,765 $8,522 

2044 $44,556 $24,858 $69,414 $26,956 $7,965 

2045 $44,556 $24,858 $69,414 $26,171 $7,444 

2046 $44,556 $24,858 $69,414 $25,409 $6,957 

2047 $44,556 $24,858 $69,414 $24,669 $6,502 

2048 $44,556 $24,858 $69,414 $23,950 $6,076 

2049 $44,556 $24,858 $69,414 $23,253 $5,679 

2050 $44,556 $24,858 $69,414 $22,575 $5,307 

2051 $44,556 $24,858 $69,414 $21,918 $4,960 

2052 $44,556 $24,858 $69,414 $21,279 $4,636 

2053 $44,556 $24,858 $69,414 $20,660 $4,332 

2054 $44,556 $24,858 $69,414 $20,058 $4,049 

2055 $44,556 $24,858 $69,414 $19,474 $3,784 

2056 $44,556 $24,858 $69,414 $18,906 $3,536 

2057 $44,556 $24,858 $69,414 $18,356 $3,305 

2058 $44,556 $24,858 $69,414 $17,821 $3,089 

2059 $44,556 $24,858 $69,414 $17,302 $2,887 

2060 $44,556 $24,858 $69,414 $16,798 $2,698 

2061 $44,556 $24,858 $69,414 $16,309 $2,521 

50 Year Total $1,861,835 $955,652 $2,817,487 $1,316,526 $615,507 

Exhibit 37 uses the same approach to calculate the expected low-end savings to CO2

Sequestration Facilities over the 50-year period, beginning in 2012. The exhibit presents the 

undiscounted savings and also applies 3 percent and 7 percent discount rates to savings 

accrued after 2012. 
 Page 70 of 145 

Exhibit 37: Low-End Estimate: 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 $0 $11,952 $11,952 $11,952 

2013 $9,049 $0 $9,049 $8,785 $8,457 

2014 $10,585 $0 $10,585 $9,978 $9,246 

2015 $6,146 $0 $6,146 $5,624 $5,017 

2016 $18,098 $0 $18,098 $16,080 $13,807 

2017 $68,979 $2,762 $71,741 $61,884 $51,150 

2018 $30,559 $2,762 $33,321 $27,906 $22,203 

2019 $26,119 $2,762 $28,881 $23,483 $17,986 

2020 $26,119 $2,762 $28,881 $22,799 $16,809 

2021 $26,119 $2,762 $28,881 $22,135 $15,709 

2022 $26,119 $2,762 $28,881 $21,490 $14,682 

2023 $26,119 $2,762 $28,881 $20,864 $13,721 

2024 $26,119 $2,762 $28,881 $20,257 $12,824 

2025 $26,119 $2,762 $28,881 $19,667 $11,985 

2026 $26,119 $2,762 $28,881 $19,094 $11,201 

2027 $26,119 $2,762 $28,881 $18,538 $10,468 

2028 $26,119 $2,762 $28,881 $17,998 $9,783 

2029 $26,119 $2,762 $28,881 $17,474 $9,143 

2030 $26,119 $2,762 $28,881 $16,965 $8,545 

2031 $32,095 $2,762 $34,857 $19,879 $9,638 

2032 $51,560 $2,762 $54,322 $30,077 $14,038 

2033 $33,801 $2,762 $36,563 $19,655 $8,831 

2034 $63,681 $2,762 $66,443 $34,676 $14,997 

2035 $53,435 $2,762 $56,197 $28,475 $11,855 

2036 $44,556 $2,762 $47,318 $23,277 $9,329 

2037 $44,556 $2,762 $47,318 $22,599 $8,718 

2038 $44,556 $2,762 $47,318 $21,941 $8,148 

2039 $44,556 $2,762 $47,318 $21,302 $7,615 

2040 $44,556 $2,762 $47,318 $20,682 $7,117 

2041 $44,556 $2,762 $47,318 $20,079 $6,651 

2042 $44,556 $2,762 $47,318 $19,495 $6,216 

2043 $44,556 $2,762 $47,318 $18,927 $5,809 

2044 $44,556 $2,762 $47,318 $18,375 $5,429 

2045 $44,556 $2,762 $47,318 $17,840 $5,074 

2046 $44,556 $2,762 $47,318 $17,321 $4,742 

2047 $44,556 $2,762 $47,318 $16,816 $4,432 

2048 $44,556 $2,762 $47,318 $16,326 $4,142 

2049 $44,556 $2,762 $47,318 $15,851 $3,871 

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

2051 $44,556 $2,762 $47,318 $14,941 $3,381 
 Page 71 of 145 

Year Waste 

Determination 

Hazardous Waste 

Generator 

Requirements 

Total Savings 

(Undiscounted) 

Total Savings 

(3% Discount 

Rate) 

Total Savings 

(7% Discount 

Rate) 

2052 $44,556 $2,762 $47,318 $14,506 $3,160 

2053 $44,556 $2,762 $47,318 $14,083 $2,953 

2054 $44,556 $2,762 $47,318 $13,673 $2,760 

2055 $44,556 $2,762 $47,318 $13,275 $2,579 

2056 $44,556 $2,762 $47,318 $12,888 $2,411 

2057 $44,556 $2,762 $47,318 $12,513 $2,253 

2058 $44,556 $2,762 $47,318 $12,148 $2,106 

2059 $44,556 $2,762 $47,318 $11,795 $1,968 

2060 $44,556 $2,762 $47,318 $11,451 $1,839 

2061 $44,556 $2,762 $47,318 $11,117 $1,719 

50 Year Total $1,861,835 $124,290 $1,986,125 $944,344 $452,086 

3.6 Summary of Costs and Savings 

The preceding analysis quantified the costs and benefits of the proposed rule under both a 

high-end and low-end scenario. Detailed costs are presented for capture facilities, 

sequestration facilities, state governments, and EPA. Detailed cost savings are presented for 

capture facilities and sequestration facilities. The Exhibits below summarize costs, savings, 

and net savings over the 50 year period, in aggregate, and on an annualized basis for both the 

high and low scenarios. 

High-End Estimate: 

Exhibit 38 summarizes the undiscounted 50-year and annualized high-end costs and benefits 

of the proposed rule. Exhibits 39 and 40 summarize the 50-year and annualized high-end 

costs and benefits of the proposed rule applying 3 percent and 7 percent discount rates, 

respectively. 

Under the high-end estimate, the proposed rule is expected to result in undiscounted 

annualized net savings of approximately $56.6 million. Applying a 3 percent discount rate, 

the annualized net savings were found to be approximately $44.9 million while a 7 percent 

discount rate resulted in annualized net savings of approximately $32.0 million. 
 Page 72 of 145 

Exhibit 38: High-End Estimate: Net Costs and Savings of the Proposed Rule - 

Undiscounted (2010 dollars) 

Type of Entity 

50-year 

Costs 50-year Savings 

50-year Net 

Savings 

Average 

Annual Net 

Savings 

Capture Facilities $164,544 $2,829,383,941 $2,829,219,397 $56,584,388 

Sequestration Facilities $198,456 $2,817,487 $2,619,031 $52,381 

State Governments $33,794 $0 ($33,794) ($676) 

EPA $3,431 $0 ($3,431) ($69) 

Total $400,225 $2,832,201,428 $2,831,801,203 $56,636,024 

Exhibit 39: High-End Estimate: Net Costs and Savings of the Proposed Rule – 

3% Discount Rate (2010 dollars) 

Type of Entity 

Present Value 

of 50-year 

Costs 

Present Value 

of 50-year 

Savings 

Present Value of 50-

year Net Savings 

Annualized 

Net Savings 

Capture Facilities $70,474 $1,188,762,217 $1,188,691,743 $44,853,488 

Sequestration 

Facilities $91,892 $1,316,526 $1,224,634 $46,210 

State Governments $14,947 $0 ($14,947) ($564) 

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

Total $178,810 $1,190,078,743 $1,189,899,932 $44,899,077 

Exhibit 40: High-End Estimate: Net Costs and Savings of the Proposed Rule – 

7% Discount Rate (2010 dollars) 

Type of Entity 

Present Value 

of 50-year 

Costs 

Present Value 

of 50-year 

Savings 

Present Value of 50-

year Net Savings 

Annualized 

Net Savings 

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

Sequestration 

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

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

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

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

Low-End Estimate: 

Exhibit 41 summarizes the undiscounted 50-year and annualized low-end costs and benefits 

of the proposed rule. Exhibits 42 and 43 summarize the 50-year and annualized low-end 

costs and benefits of the proposed rule applying 3 percent and 7 percent discount rates, 

respectively. 

Under the low-end estimate, the proposed rule is expected to result in undiscounted 

annualized net savings of approximately $9.3 million. Applying a 3 percent discount rate, 

the annualized net savings were found to be approximately $8.5 million. Applying a 7 

percent discount rate, the annualized net savings are approximately $7.3 million. 
 Page 73 of 145 

Exhibit 41: Low-End Estimate: Net Costs and Savings of the Proposed Rule - 

Undiscounted (2010 dollars) 

Type of Entity 

50-year 

Costs 50-year Savings 

50-year Net 

Savings 

Average 

Annual Net 

Savings 

Capture Facilities $164,544 $465,458,254 $465,293,710 $9,305,874 

Sequestration Facilities $199,494 $1,986,125 $1,786,631 $35,733 

State Governments $33,794 $0 ($33,794) ($676) 

EPA $3,431 $0 ($3,431) ($69) 

Total $401,263 $467,444,379 $467,043,116 $9,340,862 

Exhibit 42: Low-End Estimate: Net Costs and Savings of the Proposed Rule – 

3% Discount Rate (2010 dollars) 

Type of Entity 

Present Value 

of 50-year 

Costs 

Present Value 

of 50-year 

Savings 

Present Value of 50-

year Net Savings 

Annualized 

Net Savings 

Capture Facilities $70,474 $225,164,528 $225,094,055 $8,493,584 

Sequestration 

Facilities $92,362 $944,344 $851,982 $32,148 

State Governments $14,947 $0 ($14,947) ($564) 

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

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

Exhibit 43: Low-End Estimate: Net Costs and Savings of the Proposed Rule – 

7% Discount Rate (2010 dollars) 

Type of Entity 

Present Value 

of 50-year 

Costs 

Present Value 

of 50-year 

Savings 

Present Value of 50-

year Net Savings 

Annualized 

Net Savings 

Capture Facilities $29,098 $107,201,394 $107,172,296 $7,257,653 

Sequestration 

Facilities $42,503 $452,086 $409,583 $27,737 

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

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

Total $78,697 $107,653,479 $107,574,782 $7,284,909 
 Page 74 of 145 

Summary: 

Due to the high level of uncertainty regarding the percent of CO2 that may be RCRA 

hazardous, and the uncertainty regarding the actual number of facilities potentially affected 

over the projected 50 year period, EPA estimates that the annualized net savings of the 

proposed rule could range anywhere from the low-end annualized savings of $7.3 million 

(7% discount rate) to the high-end annualized savings of $44.9 million (3%discount rate). 

Under Executive Order 12866, a rule qualifies as economically significant if its annual effect 

on the economy is $100 million or more. This proposed rule is not expected to be 

economically significant, as defined under Executive Order 12866. 

3.7 Unquantified Benefits of the Proposed Rule 

In addition to the quantified savings discussed above, the proposed rule also represents a step 

toward establishing a supporting regulatory framework for the future development and 

deployment of carbon capture sequestration (CCS) technology. The rule will help provide 

the regulatory certainty needed to foster industry adoption of CCS. 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 GS 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 could lead to net cost savings in the range of $7.3 to $56.6 million annually. 

Accordingly, EPA certifies that the rule will not have a significant economic impact on a 

substantial number of small entities. 
 Page 75 of 145 

5. References

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

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 (4606M). EPA 816-R-10-013. 2010. 
 Page 76 of 145 

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

Parfomk, Paul W., Folger, Peter, and Adam Vann. Congressional Research Service, July 31, 

2009. Carbon Dioxide (CO2) Pipelines for Carbon Sequestration: Emerging Policy Issues. 

Available: 

http://nepinstitute.org/get/CRS_Reports/CRS_Climate_and_Environment/Carbon_and_CO2/

CO2_Pipelines_for_Carbon_Sequestration.pdf

PetroSource Energy Company, “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/. 
 Page 77 of 145 

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, we 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. 
 Page 78 of 145 

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

from 40 CFR 261.24 (Toxicity characteristic) 

EPA 

HW 

No.1

 Analyte Group Contaminant CAS No.2

Regulatory 

Level 

(mg/L) 

D004 Metal Arsenic 7440–38–2 5.0 

D005 Metal Barium 7440–39–3 100.0 

D018 Volatile Organic Compound Benzene 71–43–2 0.5 

D006 Metal Cadmium 7440–43–9 1.0 

D019 Volatile Organic Compound Carbon tetrachloride 56–23–5 0.5 

D020 Pesticide Chlordane 57–74–9 0.0 

D021 Volatile Organic Compound Chlorobenzene 108–90–7 100.0 

D022 Volatile Organic Compound Chloroform 67–66–3 6.0 

D007 Metal Chromium 7440–47–3 5.0 

D023 Semivolatile Organic Compound o-Cresol 95–48–7 200.04

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 
 Page 79 of 145 

EPA 

HW 

No.1

 Analyte Group Contaminant CAS No.2

Regulatory 

Level 

(mg/L) 

D041 Semivolatile Organic Compound 2,4,5-

Trichlorophenol 

95–95–4 400.0 

D042 Semivolatile Organic Compound 2,4,6-

Trichlorophenol 

88–06–2 2.0 

D017 Pesticide 2,4,5-TP (Silvex) 93–72–1 1.0 

D043 Volatile Organic Compound Vinyl chloride 75–01–4 0.2 

Notes: 

1

 Hazardous waste number. 

2

 Chemical abstracts service number. 

3

 Quantitation limit is greater than the calculated 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.64 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).65 Transport and injection is commonly as a dense liquid or 

 

64 A supercritical fluid has properties of a gas and properties of a liquid, but is neither. 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

65 Volk, Ronald H., 2009. Proceedings of the Workshop on Future Large CO2 Compression Systems, 

Sponsored by NIST, US DOE and EPRI. March 30-31, 2009. Gaithersburg MD. 
 Page 80 of 145 

supercritical fluid.66 Under the RCRA regulations and test procedures there are no standards 

of comparison for gasses, supercritical fluids, or liquids under high pressure, and there is no 

documented procedure for converting gas concentration or supercritical fluid concentration 

units to liquid concentration. 

Issue 2: Testing Needs to Cover a Variety of Contaminants. The contaminants in Exhibit A-1 

include chemical groupings (metals, pesticides, volatile organic compounds and semi volatile 

organic compounds) that each require different methods of sampling and analysis specified 

by EPA. 

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

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 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 

 

66 Mohitpour, Mo, Andy Jenkins, and Gabe Nahas. 2008. A generalized overview of the requirements for 

design, construction and operation of new pipelines for CO2 sequestration. Journal of Pipeline Engineering, 

Volume 7, No. 4 Fourth quarter 2008 
 Page 81 of 145 

sampling ports for operational testing, but the 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. 

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. 
 Page 82 of 145 

Exhibit A-2: Labor Hours and Costs for Option 1: 

Testing CO2 Stream as a Gas 

Labor Time: 

Labor Category 

Frequency of 

Occurrence 

Hours Costa

Senior Chemist One-time 

40 $4,440 

Chemist Annual 

12 $671 

Sampling Technician Annual 4 $224 

Vendor/Equipment Costs: 

Cost Category 

Frequency of 

Occurrence Cost 

Facility Improvement (installation of 

sampling port) One-time $2,500 

Sampling Equipment Annual $450 

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

Vendor/Equipment Subtotal $5,398 (first Year) 

$2,898 annually 

Total Cost: One Time - $6,940 

Annual - $3,793 

a

 Labor hours were converted to costs using loaded hourly wages of $110.99 for Senior Chemists, and $55.95 

for Chemists and Sampling Technicians 

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 

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 
 Page 83 of 145 

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 Costa

Senior Chemist One-time 200 $22,198 

Chemist Annual 12 $671 

Sampling Technician Annual 4 $224 

Vendor/Equipment Costs: 

Cost Category 

Frequency of 

Occurrence Cost 

Facility Improvement (installation of 

sampling port) One-time 

$5,000 

Sampling Equipment Annual $200 

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

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

$2,648 annually 

Total Cost: One Time - $27,198 

Annual - $3,543 

a

 Labor hours were converted to costs using loaded hourly wages of $110.99 for Senior Chemists, and $55.95 

for Chemists and Sampling Technicians
 Page 84 of 145 

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

Characterization Requirements 

RCRA regulations under 40 CFR 262.11(c)(2) 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.67 

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. 

 

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

low levels.
 Page 85 of 145 

Exhibit A-4: Labor Hours and Costs for Option 3: 

Using Process Knowledge to Meet RCRA Characterization Requirements 

Labor Time: 

Labor Category 

Frequency of 

Occurrence 

Hours Costa

Senior Chemist One-time 

40 $4,440 

Chemist Annual 

12 $671 

Sampling Technician Annual 2 $112 

Vendor/Equipment Costs: 

Cost Category 

Frequency of 

Occurrence Cost 

Sampling Equipment Annual $400 

Sample Analysis (includes QC sample) Annual $1,530 

Vendor/Equipment Subtotal $1,930 annually 

Total Cost: One Time - $4,440 

Annual - $2,713 

a

 Labor hours were converted to costs using loaded hourly wages of $110.99 for Senior Chemists, and $55.95 

for Chemists and Sampling Technicians

Option 4 –Testing to Ensure 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).68 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 

 

68 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. 
 Page 86 of 145 

method would take a one-time effort of about 40 hours for a senior chemist or chemical 

engineer. After the method is developed and documented the results of the analysis and waste 

determination would be summarized in an annual report by a staff level chemist who would 

prepare an annual report of findings. 

A breakdown of the costs and labor hours for Option 4 are presented in Exhibit A-5. 

Additional details are provided in Exhibit A-9. 

Exhibit A-5: Labor Hours and Costs for Option 4: 

Testing to Ensure Compliance with RCRA by Injection Facility 

Labor Time: 

Labor Category 

Frequency of 

Occurrence 

Hours Costa

Senior Chemist One-time 

40 $4,440 

Chemist Annual 12 $671 

Vendor/Equipment Costs: 

Cost Category 

Frequency of 

Occurrence Cost 

Sampling Equipment Annual $100 

Sample Analysis (no QC sample) Annual $765 

Vendor/Equipment Subtotal $865 annually 

Total Cost: One Time - $4,440 

Annual - $1,536 

a

 Labor hours were converted to costs using loaded hourly wages of $110.99 for Senior Chemists, and $55.95 

for Chemists and Sampling Technicians

A.4 Additional Details on Cost Estimates 

This section presents additional details on the cost components, assumptions, and data 

sources for developing the cost estimates 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. 
 Page 87 of 145 

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 

 
 Page 88 of 145 

Exhibit A-7: Option 2 Cost and Labor Estimate

Option 2: CO2 stream is tested at point of use as a 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 

 
 Page 89 of 145 

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 

 
 Page 90 of 145 

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 

 
 Page 91 of 145 

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 140oC69), 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.70 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.71 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.72 

• 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.73 

 

69 Note that these temperatures are applicable for the amine solvents. 70 Center for Energy and Economic Development. Carbon Capture. 2007. 71 Center for Energy and Economic Development. Carbon Capture. 2007. 72 NOx and SOx reacts with the amine and will result in a reduction in solvent performance, higher chemical 

consumption, and poor economic performance. 

73 Alstom, Oxyfuel combustion capture. 
 Page 92 of 145 

• Pre-combustion capture is mostly applicable to gasification-based system such as 

Integrated Gasification Combined Cycle (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 (hydrogen sulfide), 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 an 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.74 

• 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. 

 

74 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. 
 Page 93 of 145 

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 

(The capital charge rate is the rate or return required on invested capital.) 

 0.175 

Weighted Cost of Capital 

 9.67% 

Levelization Factor for FOM and VOM 

(FOM = Fixed O&M Costs, VOM = Variable O&M Costs) 

1.1568 

Price of Coal $/MMBtu 

 $ 1.80 

The cost estimates have an 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 

1st quarter 2010 dollars using NIPA tables from the Bureau of Economic Analysis.75 The 

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

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

• Materials, 

• Labor (direct and indirect), 

• Engineering and construction management, and 

• Contingencies (process and project). 

Owner’s costs are excluded from the total plant cost.76 

 

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

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

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

waste large quantity generators under 40 CFR 260.10, and related provisions. 
 Page 94 of 145 

In both cases, bituminous high sulfur Illinois-6 coal with 2.51% sulfur (as-received basis) 

was used for the techno-economic analysis. The energy content of the coal was assumed to 

be 11,666 BTU/lb. 

FGD for Oxyfuel Systems:

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

report. Case 5 is a 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.77 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.78

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. 

 

77 See Table 5 (500 MW capacity, 11,000 BTU) of Technical Support Document of Transport Rule (“Updates to 

EPA Base Case v3.02 EISA Using the Integrated Planning Model” June 17, 2010). 

78 See Table 5-8 of NETL, 2008. 
 Page 95 of 145 

Exhibit B-2: Summary of 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

metric tons/hr 592.58 

metric tons/kWh 0.0010774 

(592.58/550.01)/1,000 

Capital Cost $/kW-net $ 2,493 $ 2,776 $ 283 

Fixed O & M $/kW-year $ 25.59 $ 35.81 $ 10.22 

Variable O & M cents/kWh 0.51 0.68 0.17

 

Levelized Costa Over 20 Years 

Capital Cost cents/kWh 5.86 6.53 0.67

Fixed O & M cents/kWh 0.40 0.56 0.16

Variable O & M cents/kWh 0.59 0.79 0.20

Fuel cents/kWh 2.64 2.64 0.00

Total cents/kWh 9.49 10.51 1.03

Treatment Cost dollars per metric 

ton $9.74b

a

 annualized present value. b rounding across all cells. 

Single Stage Selexol for IGCC:

The economic analysis for the IGCC system was based on Case 2 and Case 1 of the NETL, 

2007 report. These two cases are based on IGCC using a GE gasifer with (Case 2) and 

without (Case 1) 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 2.79 The differential in fixed cost was assumed to be same in the 

 

79 See Exhibit 3-46, account 5A of NETL, 2007 report. 
 Page 96 of 145 

oxyfuel system multiplied by 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.80 The difference between the two options was about 15 MW. 

Exhibit B-3: Assumptions and Summary of Results for IGCC Cases 

 

 

IGCC System 

Unit Co-capture Separated 

capture Difference 

Size of Plant MW 570.77 555.675 -15.09

Net Heat Rate BTU/kWh 10,227 10,505 278

Capacity Factor 0.85 

Captured CO2

tons/hr 505.65 

metric tons/kWh 0.0009099 

(505.65/555.675)/1,000 

Capital Cost $/kW-net $2,236 $2,494 $259 

Fixed O & M $/kW-year $36.31 $45.65 $9.34 

Variable O & M cents/kWh 0.84 0.84 0.01

 

Levelized Costa Over 20 Years 

Capital Cost cents/kWh 5.25 5.86 0.61

Fixed O & M cents/kWh 0.56 0.71 0.15

Variable O & M cents/kWh 0.97 0.98 0.01

Fuel cents/kWh 2.38 2.38 

Total cents/kWh 9.16 9.93 0.76

Treatment Cost dollars per 

metric ton $8.94b

a annualized present value b

 rounding across all cells

 

80 See Exhibit 3-34 of NETL, 2007 report. 
 Page 97 of 145 

Appendix C

Assessment of Environmental Justice Impacts 

C.1 Introduction 

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

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

general calls on each federal agency to make 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 C.2 provides background on the 

proposed rule. Section C.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 C.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 C.5 presents a 

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

be used to transport CO2 under the proposed rule.81 Section C.6 summarizes the conclusions 

of these analyses and identifies possible next steps. 

C.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 is expected to be codified at 40 CFR 261.4(h). 

 

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

reasons for conducting a qualitative analysis. 
 Page 98 of 145 

There are three primary types of facilities that would be 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. For this EJ assessment EPA is applying the high-end 

estimate of 27 facilities that may, at some point over the analytical time frame capture 

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 transported by pipeline. As of 2008, there were 

30 operating CO2 pipelines, operated by 29 separate entities.82 

• Geological Sequestration (GS) Facilities. For this EJ assessment EPA is applying the 

high-end estimate of 29 geological sequestration facilities may claim the exclusion. 

Geological sequestration 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. 

C.3 Comparative Analysis 

This section presents a summary comparison of the federal regulations applicable to 

generators of hazardous waste CO2 and geological sequestration 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 C-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.83 Column 2 presents the proposed rule’s conditions and other federal 

regulations applicable to generators, pipelines and GS facilities operating under the proposed 

 

82 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. 83 Column 1 presents hazardous waste regulations applicable to large quantity generators only. 
 Page 99 of 145 

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 

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. 

• 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 C-1. Comparison of Federal Regulations Applicable to Facilities and Pipelines Operating Under the Baseline and 

Federal Regulations Applicable to Facilities and 

Pipelines Operating under the Baseline 

Federal Regulations Applicable to Facilities and 

Pipelines Operating under the Proposed Rule 

Com

1. GeneratorsaReporting 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 doongoing notification their activities as do tregulations. Howeverenew the certificatioto EPA if requested The baseline and propfacilities to keep specdemonstrate their comrequirements 

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 do

prepare for or responthe hazardous waste r“Other Regulations” other federal regulatiemergency preparedn

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 rerequirements for ememay be comparable to requirements in some doubtful that these reall facilities and potenextent as the hazardoFirst, most of these rethe option of developresponse plan or evacevacuation plan is nohazardous waste requ

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 bOSH 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
 Page 101 of 145 

Federal Regulations Applicable to Facilities and 

Pipelines Operating under the Baseline 

Federal Regulations Applicable to Facilities and 

Pipelines Operating under the Proposed Rule 

Com

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 anonsite releases). In aregulations are triggeCERCLA hazardous specified quantity (e.carbon dioxide stream sulfide, mercury, andare CERCLA hazardoHowever, these substsufficient quantities tregulatory quantity. Fthreshold quantity for CFR Part 68 is 10,00facility’s carbon dioxsubject to these emerdoes not contain a haexceeds its respective Carbon dioxide itself 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 do

of waste CO2 streams 

disposal of untreated migration variance, aregulations 

2. Pipelines RCRA Regulations RCRA does not regulate transportation by pipeline Refer to “Other Regu

information on other 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 

DOT regulation undeproposed rule 

3. Geological Sequestration Facilities RCRA Regulations Class I injection wells disposing of hazardous waste are Class VI UIC wells disposing of exempt CO2 must The baseline regulati
 Page 102 of 145 

Federal Regulations Applicable to Facilities and 

Pipelines Operating under the Baseline 

Federal Regulations Applicable to Facilities and 

Pipelines Operating under the Proposed Rule 

Com

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 

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 

by-rule program for Chazardous waste that requirements. The prClass VI wells to inje

provided that the genowner/operator claim specified conditions. proposed rule both reprogram requirementconditions) to ensure and disposal of the wadditional administraneeded to ensure comrecordkeeping and reRefer to “Other Reguinformation on other 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 hazafrom the UIC Class Vnumber of ways. Sominclude the following

• Class VI regulation

siting standards. FoDirector’s discretiomust characterize aimpede vertical fluipressure dissipationfractures, and proviopportunities for mremediation 

• The Class I hazardo

that the area of revidistance of 2 miles the Class VI regula
 Page 103 of 145 

Federal Regulations Applicable to Facilities and 

Pipelines Operating under the Baseline 

Federal Regulations Applicable to Facilities and 

Pipelines Operating under the Proposed Rule 

Com

to be determined bacomputational modthe physical and chphases of the inject

plume, and pressurappropriate timefraVI regulations requassessment of the A

• Class VI regulation

monitoring during whazardous regulatiomonitoring of grougeochemical changzone. In addition, sand soil monitoring Director’s discretiomust submit and gamonitoring plan be

• Class VI regulation

post-closure period owner/operator muThe Class I regulatyear post-closure p

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 su

applicable threshold quantity spelled out in these federal regulations, it would trigger the emergency requirements, as applicable. For exam

hydrogen sulfide in 40 CFR Part 68 is 10,000 pounds. A facility’s carbon dioxide stream would not be subject to these emergency requirem

hazardous substance that exceeds its respective threshold quantity. Carbon dioxide itself is not a hazardous substance. Note that the requireand 1910.1200 are not triggered by threshold quantities. 

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 

requirements; however, there is no regulatory requirement that permit writers apply the Class VI requirements to Class I wells.
C.4 Screening Analysis of Capture and Geologic Sequestration (GS) Facilities 

This section presents an EJ screening analysis of carbon capture and GS facilities with known 

locations that might claim the exclusion. Similar to the regulatory comparison found in C.3, the 

screening analysis of capture and GS facilities is not an assessment of risk. Instead, the analysis 

uses demographic information to identify communities of concern. The next two sections 

describe the methodology and results. 

C.4.1 Methodology 

EPA took the following steps to complete the analysis: 

1. Ascertained the location of 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, at a maximum, 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, plus four additional major DOE 

sequestration projects are included in this screening analysis. 

Appendix C.A. identifies the 31 GS and capture facilities (33 less two DOE dual 

facilities) that are included in this screening analysis. 

2. Conducted a screening analysis of 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.84 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 

 

84 The one and three mile radii are applied to be consistent with prior ORCR environmental justice demographics 

analyses. 
 Page 105 of 145 

centrally managed database, to ascertain the location of these 

sites.85 This indicator is meant to clarify the proximity and 

incidence of potential 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 C.B. A summary of the data is presented in Section C.4.2. 

C.4.2 Results 

Exhibits C-2 and C-3 summarize the results of the screening analysis. Exhibit C-2 presents the 

results of the analysis of indicators within a 1-mile radius of facilities and Exhibit C-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., 

 

85 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 

Retrieval System (AIRS)/AIRS Facility Subsystem, and Comprehensive Environmental Response, Compensation, 

and Liability Information System (CERCLIS). For additional information, refer to 

http://www.epa.gov/enviro/html/. 
 Page 106 of 145 

populations living below 150% of the poverty level) exceed the state percentage, as these may be 

among the most vulnerable populations.86

Exhibit C-2 shows the following in regard to population 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.87 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. 

 

86 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. 

87 These 3 facilities are a subset of the 21 facilities noted above. 
 Page 107 of 145 

Exhibit C-3 shows the following in regard to population 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.88 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 C.B. for detailed data on the incidence of the indicators within a 1- and 3-mile 

radius of the facilities. 

 

88 These 4 facilities are a subset of the 20 facilities noted above. 
 Page 108 of 145 

Exhibit C-2. Characteristics of 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 

Project 

- X X 2 No 
 Page 109 of 145 

Facility Name Facility Type 

Facilities Whose 1-Mile Populations 

Exceeded the State Percentage 

Number of 

FRS Sites 

within 1-Mile 

Radius 

On Tribal 

% Land? 

Minority 

(All Races)

% Below 

150 Percent 

of Poverty 

Level 

% 0 to 4 

Years or 

65+ Years 

Tenasca 

Sweetwater/Trailblazer 

Commercial 

Capture - X X 9 No 

Tenasca Taylorville 

Energy 

Commercial 

Capture - - X 2 No 

Texas Clean Energy 

Project 

Commercial 

Capture - - X 1 No 

Val Verde Gas Plant, 

Gray Ranch 

Existing Gas and 

Fertilizer Plant X - - 2 No 

Val Verde Gas Plant, 

Mitchell 

Existing Gas and 

Fertilizer Plant X - - 1 No 

Val Verde Gas Plant, 

Pikes Peak 

Existing Gas and 

Fertilizer Plant X - - 1 No 

Val Verde Gas Plant, 

Puckett 

Existing Gas and 

Fertilizer Plant X - - 2 No 

Val Verde Gas Plant, 

Terrell 

Existing Gas and 

Fertilizer Plant - X X 1 No 

WA Parish, Sugarland Commercial 

Capture - - X 2 No 

Wallula Energy Res. 

Center 

Commercial 

Capture - X - 1 No 

Williston Basin EOR 

Sequestration 

Major DOE 

Sequestration 

Project 

- X X 0 No 

Worsham-Steed 

(ZENG) 

Commercial 

Capture - X X 1 No 

* The exhibit uses gray shading to 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. 
 Page 110 of 145 

Exhibit C-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 
 Page 111 of 145 

Facility Name Facility Type 

Facilities Whose 3-Mile Populations 

Exceeded the State Percentage 

Number of 

FRS Sites 

within 3-

Mile 

Radius 

On Tribal 

% 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. 

C.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 C.5.1 of this document provides background information about the existing 

hazardous waste regulations (i.e., the “baseline”) and proposed rule that would exempt CO2

streams from RCRA regulation. Section C.5.2 describes the likelihood of CO2 pipeline failures 

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

surrounding populations from a CO2 pipeline release. Section C.5.4 sets forth some preliminary 

conclusions about CO2 releases from pipelines. 
 Page 112 of 145 

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 

2007.89, 90 The Risk Assessment addresses the potential releases of captured gases at the 

proposed FutureGen power plant, during transportation via pipeline to the 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. 

C.5.1 Background on Baseline and Proposed RCRA Rule 

This section provides a brief description of the baseline regulations and proposed regulations as 

applicable to this analysis. 

Baseline. Under the baseline, 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 

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. 

 

89 This document can be found at the following web site: 

http://www.netl.doe.gov/technologies/coalpower/futuregen/EIS/FG%20Risk%20Assessment%20110807.pdf. 

90 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. 
 Page 113 of 145 

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. 

C.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.91 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.92

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). 

Based on the Risk Assessment data and formulas, Exhibit C-4 shows the probability of at least 

one pipeline rupture over a 50 year period, given three different pipeline lengths. Exhibit C-5 

shows the probability of at least one pipeline puncture over a 50 year period, given three 

different pipeline lengths. For example, Exhibit C-4 shows that, over a 50 year period, there is 

an estimated 35% probability of a pipeline rupture in a 150 kilometer pipeline and Exhibit C-5 

 

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

92 The Risk Assessment mentioned these estimates on pages 4-4 and 6-14; however, it mentions different risk values 

for ruptures and punctures in mile-year. EPA has determined that this is an error in converting between mile-year 

and kilometer-year. EPA used the risk values expressed in kilometer-year in preparing Figures 1 and 2. 
 Page 114 of 145 

shows that, over a 50 year period, there is an estimated 60% probability of a pipeline puncture in 

a 150 kilometer pipeline.93 

Exhibit C-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 C-5. Probability of CO2 Pipeline Puncture 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). 

 

93 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. 
 Page 115 of 145 

C.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.94 Pipeline release simulations were 

evaluated for a “hole-puncture” and a complete severing of the pipeline. An automated 

“pipeline-walk” approach was developed to evaluate the effects of thermodynamically 

determined gas-phase releases along the entire 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 C-6. In all cases, the expected number of 

individuals affected is less than one. 

Exhibit C-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. 

 

94 The SLAB model was developed by the Lawrence Livermore National Laboratory, and is designed to 

simulate denser-than-air gas releases for both horizontal jet and vertically elevated jet scenarios. SLAB is 

approved by U.S. EPA as a hazardous air dispersion model. 
 Page 116 of 145 

Exhibit C-6: Summary of Expected Numbers of Individuals from 

the Public Affected by Pipeline Releasesa

Mattoon, 

IL 

Tuscola, 

IL 

Jewett, 

TX 

Odessa, 

TX 

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 

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, 

the life threatening effects of H2S exposures are associated with long exposure levels that can be 

detected and avoided.”95 

 

95 See page 6-7 of the FutureGen Risk Assessment. 
 Page 117 of 145 

C.5.4 Preliminary Conclusions on Potential Releases 

Under the baseline, generators of hazardous waste 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 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. 

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

 C.6.1 Comparative Analysis 

 Results

The comparative analysis identified the following potential regulatory differences: 

• 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 
 Page 118 of 145 

regulation under both the baseline and proposed rule. Pipeline transport is not subject to 

RCRA regulation. 

• GS facilities operating under the proposed 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. 

 C.6.2 Screening Analysis of Capture and Geologic Sequestration (GS) Facilities 

Results

 EPA’s screening analysis found that: 

• 21 of the 31 GS and capture facilities 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). 

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 
 Page 119 of 145 

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 

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 
 Page 120 of 145 

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 C.A. – Facilities Included in the Environmental Screening Analysis 

The facilities in Exhibits C.A-1 through C.A-3 are included in the EJ screening analysis. 

Exhibit C.A-1. Planned Major Commercial (Non-DOE) 

and FutureGen Capture Facilities 

Facility Name State Lat 

D/M/S 

Long 

D/M/S 

Commercial 

AEP Alstom Mountaineer 

(Ph.2) WV 38/58/44 81/56/20 

AEP Alstom Northeastern OK 36/25/51 95/42/03 

Edwardsport IN 38/48/24 87/14/49 

Great Bend OH 38/59/56 81/45/47 

Hydrogen Energy HECA CA 35/17/03 119/26/44 

Kemper County MS 32/48/53 88/43/24 

Lima OH 40/44/33 84/06/49 

Mesaba MN 47/33/55 92/08/47 

Tenasca Taylorville Energy IL 39/35/21 89/11/20 

Tenasca 

Sweetwater/Trailblazer TX 32/28/04 100/24/27 

Texas Clean Energy Project TX 31/44/46 102/36/30 

WA Parish, Sugarland TX 29/28/40 95/38/06 

Wallula Energy Res. Centera WA 46/07/14 118/54/15 

Worsham-Steed (ZENG) TX 32/27/41 97/53/27 

FutureGen 

Futuregen IL 39/29/49 88/26/26 
 Page 121 of 145 

Exhibit C.A-2. Existing Gas and Fertilizer Plants 

Facility State Lat 

D/M/S 

Long 

D/M/S 

Val Verde Gas - Pikes Peak 

Plant 

TX 30/38/1

7 102/56/34 

Val Verde Gas - Grey Ranch 

Plant 

TX 30/33/1

6 102/26/33 

Val Verde Gas - Puckett Plant TX 30/44/4

0 102/29/30 

Val Verde Gas - Terrell Plant TX 30/22/1

9 101/50/39 

Val Verde Gas - Mitchell Plant TX 30/40/1

6 102/29/37 

La Barge Gas Plant WY 42/15/4

3 110/11/41 

Enid Ammonia Fertilizer Gas 

Plant OK 36/22/44 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

8 101/49/54 

Exhibit C.A-3. Major DOE Sequestration Projects 

Facility State Lat 

D/M/S 

Long 

D/M/S 

Illinois Basin Mt. Simon 

Saline Reservoir IL 

39/52/4

5 88/53/41 

Williston Basin EOR 

Sequestration ND 

48/31/2

8 102/58/11 

Green River Basin Nugget 

Sand Saline Reservoir WY 

43/15/3

0 110/12/60 

Cincinnati Arch Mt. Simon 

Salinea OH 

38/54/1

3 84/50/56 

San Joaquin Basin, CA 

Saline Formationa CA 

36/33/4

9 119/12/19 

Mt. Simon Saline Reservoir IL 

39/29/4

9 88/26/26 

 a Information received after the completion of this analysis indicates that these facilities are not expected to move 

forward.
 Page 122 of 145 

Appendix C.B. Characteristics of Populations Within 1- and 3-Mile Radius of Facilities: 

Detailed Exhibits Supporting the Environmental Justice Screening Analyses 

This appendix presents detailed results of the environmental justice screening analysis. Data are 

presented on the incidence of each indicator that EPA examined within a 1- and 3-mile radius of 

capture and GS facilities. These data are presented in the following exhibits: 

• Exhibit C.B-1. Percentage of Population that is Minority (by Race and in Total) Within 1-

Mile Radius of Facility 

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

Mile Radius of Facility 

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

Radius of Facility 

• Exhibit C.B-4. Number of FRS Sites Within 1-Mile Radius of Facility 

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

Mile Radius of Facility 

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

Mile Radius of Facility 

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

Radius of Facility 

• Exhibit C.B-8. Number of FRS Sites 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 C.B-1. Percentage of Population that is Minority (by Race and in Total) Within 1-Mile Radiu

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

Perce

Popula

that 

Hispa

Sta

AEP Alstom Mountaineer (Ph.2) Commercial CaptureOhio 0.2% 12.2% 0.0% 0.1% 0.0% 1.6% 0.0% 0.0% 0.0% 2.7West Virginia 0.0% 3.7% 0.0% 0.1

% 0.1

% 0.6% 0.0% 0.0% 0.0% 1.2

AEP Alstom Northeastern Commercial CaptureOklahoma 0.1

% 8.0% 12.2% 7.9% 0.0% 1.8% 0.0% 0.1

% 1.3% 8.0

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

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% 5.5Kentucky 0.0% 7.8% 0.5% 0.2% 0.2% 1.0% 0.0% 0.0% 1.4% 2.5Coffeyville Fertilizer Plant Commercial CaptureKansas 25.0% 6.1

% 5.1

% 0.9% 0.3% 2.3% 0.0% 0.0% 5.0% 9.5

Edwardsport Commercial CaptureIndiana 0.1

% 9.2% 0.0% 0.2% 0.0% 1.4% 0.0% 0.0% 2.3% 5.5

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

Futuregen FutureGenIllinois 1.9% 14.9% 0.0% 0.3% 0.6% 4.6% 0.0% 0.0% 1.1

% 16.0

Great Bend Commercial CaptureOhio 0.4% 12.2% 0.3% 0.1% 0.7% 1.6% 0.0% 0.0% 0.0% 2.7West Virginia 0.6% 3.7% 0.0% 0.1

% 2.9% 0.6% 0.0% 0.0% 0.8% 1.2

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% 2.2Green 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
 Page 124 of 145 

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

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 

Populatio

that is 

Hispanic

State

Hydrogen Energy HECA Commercial CaptureCalifornia 13.1% 6.6% 1.3% 1.1% 2.9% 12.8% 0.0% 0.3% 21.0% 37.7% 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% 

Kemper County Commercial CaptureMississippi 70.4% 37.5% 0.0% 0.4% 0.4% 0.8% 0.0% 0.0% 0.3% 2.4% 

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% Lima Commercial CaptureOhio 24.6% 12.2% 0.3% 0.1% 0.5% 1.6% 0.0% 0.0% 3.1% 2.7% Mesaba Commercial CaptureMinnesota 0.0% 4.8% 0.0% 1.2% 0.0% 3.7% 0.0% 0.0% 0.2% 4.4% 

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% 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% Tenasca Sweetwater/Trailblazer Commercial CaptureTexas 8.7% 12.0% 0.8% 0.7% 0.3% 3.6% 0.0% 0.1% 43.2% 37.3% 

Tenasca Taylorville Energy Commercial CaptureIllinois 0.2% 14.9% 0.0% 0.3% 0.6% 4.6% 0.0% 0.0% 0.1% 16.0% Texas Clean Energy Project Commercial CaptureTexas 0.2% 12.0% 0.0% 0.7% 0.0% 3.6% 0.0% 0.1% 47.3% 37.3% 

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% 
 Page 125 of 145 

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

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

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% 

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% 

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% 

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% 

WA Parish, 

Sugarland Commercial CaptureTexas 13.6% 12.0% 0.6% 0.7% 5.4% 3.6% 0.0% 0.1% 28.0% 

Wallula Energy Res.

Center Commercial CaptureWashington 1.1% 3.7% 0.9% 1.6% 0.9% 7.0% 0.0% 0.4% 12.8% 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% Worsham-Steed (ZENG) Commercial CaptureTexas 0.9% 12.0% 1.0% 0.7% 0.5% 3.6% 0.0% 0.1% 7.5% 
Exhibit C.B-2. Percentage of Population that is Below150% of Poverty Level 

Within 1-Mile Radius of Facility 

Facility Name Facility Type

Percent of Population 

below 150% of Poverty

Level : 1-Mile Radius

Percent of Population 

below 150% of Poverty

Level: State

AEP Alstom Mountaineer (Ph.2) Commercial Capture

Ohio 35.3% 23.9%

West Virginia 17.6% 28.7%

AEP Alstom Northeastern Commercial Capture

Oklahoma 21.8% 27.9%

Antrim Gas Plant Exisiting Gas and Fertilizer Plant

Michigan 15.7% 25.6%

Cincinnati Arch Mt. Simon Saline Major DOE Sequestration Project

Indiana 37.4% 24.1%

Kentucky 12.4% 29.1%

Coffeyville Fertilizer Plant Commercial Capture

Kansas 39.4% 21.8%

Edwardsport Commercial Capture

Indiana 25.3% 24.1%

Enid Gas Plant Exisiting Gas and Fertilizer Plant

Oklahoma 19.8% 27.9%

Futuregen FutureGen

Illinois 26.0% 20.9%

Great Bend Commercial Capture

Ohio 35.5% 23.9%

West Virginia 22.6% 28.7%

Great Plains Coal Gasification Exisiting Gas and Fertilizer Plant

North Dakota 27.9% 20.0%

Green River Basin Nugget Sand 

Saline Reservoir Major DOE Sequestration Project

Wyoming 9.1% 16.8%

Hydrogen Energy HECA Commercial Capture

California 4.1% 21.2%

Illinois Basin Mt. Simon Saline 

Reservoir Major DOE Sequestration Project

Illinois 28.4% 20.9%

Kemper County Commercial Capture

Mississippi 64.5% 33.4%

La Barge Gas Plant Exisiting Gas and Fertilizer Plant

Wyoming 13.9% 16.8%
 Page 127 of 145 

Exhibit C.B-2. Percentage of Population that is Below150% of Poverty Level 

Within 1-Mile Radius of Facility (Cont’d) 

Facility Name Facility Type

Percent of Population 

below 150% of Poverty

Level : 1-Mile Radius

Percent of Population 

below 150% of Poverty

Level: State

Lima Commercial Capture

Ohio 48.2% 23.9%

Mesaba Commercial Capture

Minnesota 12.8% 18.1%

Mt. Simon Saline Reservoir Major DOE Sequestration Project

Illinois 26.0% 20.9%

San Joaquin Basin, CA Saline 

Formation Major DOE Sequestration Project

California 35.8% 21.2%

Tenasca Sweetwater/Trailblazer Commercial Capture

Texas 40.5% 27.7%

Tenasca Taylorville Energy Commercial Capture

Illinois 11.6% 20.9%

Texas Clean Energy Project Commercial Capture

Texas 18.8% 27.7%

Val Verde Gas Plant, Gray Ranch Exisiting Gas and Fertilizer Plant

Texas 17.7% 27.7%

Val Verde Gas Plant, Mitchell Exisiting Gas and Fertilizer Plant

Texas 17.7% 27.7%

Val Verde Gas Plant, Pikes Peak Exisiting Gas and Fertilizer Plant

Texas 17.7% 27.7%

Val Verde Gas Plant, Puckett Exisiting Gas and Fertilizer Plant

Texas 17.7% 27.7%

Val Verde Gas Plant, Terrell Exisiting Gas and Fertilizer Plant

Texas 28.9% 27.7%

WA Parish, Sugarland Commercial Capture

Texas 10.8% 27.7%

Wallula Energy Res. Center Commercial Capture

Washington 32.3% 20.1%

Williston Basin EOR Sequestration* Major DOE Sequestration Project

North Dakota 21.6% 20.0%

Worsham-Steed (ZENG) Commercial Capture

Texas 33.1% 27.7%
 Page 128 of 145 

Exhibit C.B-3. Percentage of Population 0 to 4 Years and 65+ Years 

Within 1-Mile Radius of Facility 

Facility Name Facility Type

Percent of 

Population that is 

0-4 Years: 1-Mile 

Radius

Percent of 

Population that 

is 0-4 Years: 

State

Percent of 

Population that 

is 65+ Years: 1-

Mile Radius

Percent of 

Population that 

is 65+ Years: 

State

AEP Alstom Mountaineer 

(Ph.2) Commercial Capture

Ohio 5.0% 5.6% 19.7% 14.4%

West Virginia 5.0% 5.0% 17.2% 16.5%

AEP Alstom Northeastern Commercial Capture

Oklahoma 5.3% 6.2% 13.2% 13.5%

Antrim Gas Plant

Exisiting Gas and 

Fertilizer Plant

Michigan 4.6% 5.3% 16.1% 14.0%

Cincinnati Arch Mt. Simon 

Saline

Major DOE 

Sequestration Project

Indiana 5.2% 6.0% 12.6% 13.4%

Kentucky 4.8% 5.7% 15.0% 13.7%

Coffeyville Fertilizer Plant Commercial Capture

Kansas 7.0% 6.2% 15.1% 13.4%

Edwardsport Commercial Capture

Indiana 5.8% 6.0% 15.2% 13.4%

Enid Gas Plant

Exisiting Gas and 

Fertilizer Plant

Oklahoma 5.5% 6.2% 18.1% 13.5%

Futuregen FutureGen

Illinois 4.3% 6.0% 10.6% 13.0%

Great Bend Commercial Capture

Ohio 4.8% 5.6% 15.1% 14.4%

West Virginia 4.8% 5.0% 20.5% 16.5%

Great Plains Coal 

Gasification

Exisiting Gas and 

Fertilizer Plant

North Dakota 2.8% 5.7% 22.2% 14.9%

Green River Basin Nugget 

Sand Saline Reservoir

Major DOE 

Sequestration Project

Wyoming 5.6% 6.1% 20.4% 13.4%

Hydrogen Energy HECA Commercial Capture

California 3.3% 6.3% 7.9% 11.9%

Illinois Basin Mt. Simon 

Saline Reservoir

Major DOE 

Sequestration Project

Illinois 5.8% 6.0% 13.2% 13.0%

Kemper County Commercial Capture

Mississippi 5.2% 6.4% 19.9% 12.9%
 Page 129 of 145 

Exhibit C.B-3. Percentage of Population 0 to 4 Years and 65+ Years 

Within 1-Mile Radius of Facility (Cont’d) 

Facility Name Facility Type

Percent of 

Population that is 

0-4 Years: 1-Mile 

Radius

Percent of 

Population that 

is 0-4 Years: 

State

Percent of 

Population that 

is 65+ Years: 1-

Mile Radius

Percent of 

Population that 

is 65+ Years: 

State

La Barge Gas Plant

Exisiting Gas and 

Fertilizer Plant

Wyoming 6.9% 6.1% 12.0% 13.4%

Lima Commercial Capture

Ohio 7.0% 5.6% 11.2% 14.4%

Mesaba Commercial Capture

Minnesota 3.5% 5.9% 26.0% 13.5%

Mt. Simon Saline Reservoir

Major DOE 

Sequestration Project

Illinois 4.3% 6.0% 10.6% 13.0%

San Joaquin Basin, CA 

Saline Formation

Major DOE 

Sequestration Project

California 6.7% 6.3% 14.1% 11.9%

Tenasca 

Sweetwater/Trailblazer Commercial Capture

Texas 7.3% 7.0% 12.4% 10.8%

Tenasca Taylorville Commercial Capture

Illinois 4.8% 6.0% 15.6% 13.0%

Texas Clean Energy Commercial Capture

Texas 7.4% 7.0% 12.9% 10.8%

Val Verde Gas Plant, Gray 

Ranch

Exisiting Gas and 

Fertilizer Plant

Texas 4.6% 7.0% 9.2% 10.8%

Val Verde Gas Plant, 

Mitchell

Exisiting Gas and 

Fertilizer Plant

Texas 4.6% 7.0% 9.2% 10.8%

Val Verde Gas Plant, Pikes 

Peak

Exisiting Gas and 

Fertilizer Plant

Texas 4.6% 7.0% 9.2% 10.8%

Val Verde Gas Plant, 

Puckett

Exisiting Gas and 

Fertilizer Plant

Texas 4.6% 7.0% 9.2% 10.8%

Val Verde Gas Plant, 

Terrell

Exisiting Gas and 

Fertilizer Plant

Texas 3.3% 7.0% 19.8% 10.8%

WA Parish, Sugarland Commercial Capture

Texas 5.9% 7.0% 12.0% 10.8%

Wallula Energy Res. Commercial Capture

Washington 5.2% 5.6% 12.3% 13.2%

Williston Basin EOR 

Sequestration*

Major DOE 

Sequestration Project

North Dakota 4.0% 5.7% 26.9% 14.9%

Worsham-Steed (ZENG) Commercial Capture

Texas 5.8% 7.0% 15.7% 10.8%
Exhibit C.B-4. Number of FRS Sites 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 C.B-4. Number of FRS Sites Within 1-Mile Radius of Facility (Cont’d) 

Facility Name Facility Type Number of EPA FRS Sites within 1-

Mile Radius

Lima Commercial Capture

Ohio 31

Mesaba Commercial Capture

Minnesota 1

Mt. Simon Saline Reservoir

Major DOE Sequestration 

Project

Illinois 1

San Joaquin Basin, CA Saline 

Formation

Major DOE Sequestration 

Project

California 2

Tenasca Sweetwater/Trailblazer Commercial Capture

Texas 9

Tenasca Taylorville Energy Commercial Capture

Illinois 2

Texas Clean Energy Project Commercial Capture

Texas 1

Val Verde Gas Plant, Gray 

Ranch

Exisiting Gas and Fertilizer 

Plant

Texas 2

Val Verde Gas Plant, Mitchell

Exisiting Gas and Fertilizer 

Plant

Texas 1

Val Verde Gas Plant, Pikes 

Peak

Exisiting Gas and Fertilizer 

Plant

Texas 1

Val Verde Gas Plant, Puckett

Exisiting Gas and Fertilizer 

Plant

Texas 2

Val Verde Gas Plant, Terrell

Exisiting Gas and Fertilizer 

Plant

Texas 1

WA Parish, Sugarland Commercial Capture

Texas 2

Wallula Energy Res. Center Commercial Capture

Washington 1

Williston Basin EOR 

Sequestration*

Major DOE Sequestration 

Project

North Dakota 0

Worsham-Steed (ZENG) Commercial Capture

Texas 1
Exhibit C.B-5. Percentage of Population that is Minority (by Race and in Total) Within 3-Mile Radiu

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

AEP Alstom Mountaineer (Ph.2) Commercial CaptureOhio 0.3% 12.2% 0.0% 0.1% 0.3% 1.6% 0.0% 0.0% 0.0% West Virginia 0.1% 3.7% 0.0% 0.1% 0.0% 0.6% 0.0% 0.0% 0.4% AEP Alstom Northeastern Commercial CaptureOklahoma 0.2% 8.0% 11.1% 7.9% 0.4% 1.8% 0.0% 0.1% 1.4% 

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% 

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% 

Kentucky 0.0% 7.8% 0.4% 0.2% 0.2% 1.0% 0.0% 0.0% 1.1% 

Coffeyville Fertilizer Plant Commercial CaptureKansas 12.6% 6.1% 4.9% 0.9% 0.5% 2.3% 0.0% 0.0% 4.5% 

Edwardsport Commercial CaptureIndiana 0.2% 9.2% 0.1% 0.2% 0.0% 1.4% 0.0% 0.0% 1.8% 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% 

Futuregen FutureGenIllinois 0.9% 14.9% 0.0% 0.3% 0.3% 4.6% 0.0% 0.0% 1.3% Great Bend Commercial CaptureOhio 0.4% 12.2% 0.3% 0.1% 0.6% 1.6% 0.0% 0.0% 0.5% 

West Virginia 1.2% 3.7% 0.0% 0.1% 2.6% 0.6% 0.0% 0.0% 0.8% 
Exhibit C.B-5. Percentage of Population that is Minority (by Race and in Total) Within 3-Mile Radius of 

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

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% 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% Hydrogen Energy HECA Commercial CaptureCalifornia 13.1% 6.6% 1.3% 1.1% 2.9% 12.8% 0.0% 0.3% 21.0% 37.7% 

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% 

Kemper County Commercial CaptureMississippi 69.6% 37.5% 0.0% 0.4% 0.3% 0.8% 0.0% 0.0% 0.4% 2.4% 

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% 

Lima Commercial CaptureOhio 22.5% 12.2% 0.2% 0.1% 0.7% 1.6% 0.0% 0.0% 2.4% 2.7% 

Mesaba Commercial CaptureMinnesota 0.0% 4.8% 0.0% 1.2% 0.0% 3.7% 0.0% 0.0% 0.2% 4.4% 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% 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% 

Tenasca Sweetwater/ Trailblazer Commercial CaptureTexas 7.1% 12.0% 0.5% 0.7% 0.7% 3.6% 0.1% 0.1% 36.4% 37.3% 
 Page 134 of 145 

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

(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 o

Populatio

that is 

Hispanic: 

Mile Radiu

Tenasca Taylorville Energy Commercial CaptureIllinois 0.2% 14.9% 0.0% 0.3% 0.5% 4.6% 0.0% 0.0% 0.1% Texas Clean Energy Project Commercial CaptureTexas 0.2% 12.0% 0.0% 0.7% 0.0% 3.6% 0.0% 0.1% 47.3% 

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% 

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% 

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% 

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% 

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% 

WA Parish, Sugarland Commercial CaptureTexas 15.2% 12.0% 0.5% 0.7% 4.9% 3.6% 0.0% 0.1% 27.1% Wallula Energy Res. Center Commercial CaptureWashington 1.0% 3.7% 1.1% 1.6% 0.8% 7.0% 0.2% 0.4% 13.9% 

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% Worsham-Steed (ZENG) Commercial CaptureTexas 1.5% 12.0% 1.0% 0.7% 0.5% 3.6% 0.0% 0.1% 9.3% 
 Page 135 of 145 
Exhibit C.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%
 Page 137 of 145 

Exhibit C.B-6. Percentage of Population that is Below150% of Poverty Level 

Within 3-Mile Radius of Facility (Cont’d) 

Facility Name Facility Type

Percent of Population 

below 150% of Poverty 

Level: 3-Mile Radius

Percent of Population 

below 150% of Poverty 

Level: State

Lima Commercial Capture

Ohio 37.6% 23.9%

Mesaba Commercial Capture

Minnesota 13.0% 18.1%

Mt. Simon Saline Reservoir

Major DOE 

Sequestration Project

Illinois 22.2% 20.9%

San Joaquin Basin, CA Saline 

Formation

Major DOE 

Sequestration Project

California 45.3% 21.2%

Tenasca Sweetwater/Trailblazer Commercial Capture

Texas 35.0% 27.7%

Tenasca Taylorville Energy Commercial Capture

Illinois 11.6% 20.9%

Texas Clean Energy Project Commercial Capture

Texas 18.8% 27.7%

Val Verde Gas Plant, Gray Ranch

Exisiting Gas and 

Fertilizer Plant

Texas 17.7% 27.7%

Val Verde Gas Plant, Mitchell

Exisiting Gas and 

Fertilizer Plant

Texas 17.7% 27.7%

Val Verde Gas Plant, Pikes Peak

Exisiting Gas and 

Fertilizer Plant

Texas 17.7% 27.7%

Val Verde Gas Plant, Puckett

Exisiting Gas and 

Fertilizer Plant

Texas 17.7% 27.7%

Val Verde Gas Plant, Terrell

Exisiting Gas and 

Fertilizer Plant

Texas 28.9% 27.7%

WA Parish, Sugarland Commercial Capture

Texas 13.3% 27.7%

Wallula Energy Res. Center Commercial Capture

Washington 26.2% 20.1%

Williston Basin EOR Sequestration*

Major DOE 

Sequestration Project

North Dakota 17.3% 20.0%

Worsham-Steed (ZENG) Commercial Capture

Texas 35.9% 27.7%
 Page 138 of 145 

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

Facility Name Facility Type

Percent of 

Population that is

0-4 Years: 3-Mile 

Radius

Percent of 

Population that is

0-4 Years: State

Percent of 

Population that is

65+ Years: 3-Mile 

Radius

Percent of 

Population that is

65+ Years: State

AEP Alstom Mountaineer (Ph.2) Commercial Capture

Ohio 5.0% 5.6% 18.4% 14.4%

West Virginia 5.0% 5.0% 17.7% 16.5%

AEP Alstom Northeastern Commercial Capture

Oklahoma 5.2% 6.2% 13.7% 13.5%

Antrim Gas Plant

Exisiting Gas and 

Fertilizer Plant

Michigan 5.0% 5.3% 13.1% 14.0%

Cincinnati Arch Mt. Simon Saline

Major DOE Sequestration 

Project

Indiana 4.7% 6.0% 16.7% 13.4%

Kentucky 5.1% 5.7% 14.0% 13.7%

Coffeyville Fertilizer Plant Commercial Capture

Kansas 6.5% 6.2% 17.0% 13.4%

Edwardsport Commercial Capture

Indiana 5.7% 6.0% 15.9% 13.4%

Enid Gas Plant

Exisiting Gas and 

Fertilizer Plant

Oklahoma 5.6% 6.2% 18.0% 13.5%

Futuregen FutureGen

Illinois 3.8% 6.0% 16.9% 13.0%

Great Bend Commercial Capture

Ohio 4.9% 5.6% 14.9% 14.4%

West Virginia 4.7% 5.0% 22.5% 16.5%

Great Plains Coal Gasification

Exisiting Gas and 

Fertilizer Plant

North Dakota 2.9% 5.7% 21.7% 14.9%

Green River Basin Nugget Sand 

Saline Reservoir

Major DOE Sequestration 

Project

Wyoming 5.6% 6.1% 20.4% 13.4%

Hydrogen Energy HECA Commercial Capture

California 3.3% 6.3% 7.9% 11.9%

Illinois Basin Mt. Simon Saline 

Reservoir

Major DOE Sequestration 

Project

Illinois 5.7% 6.0% 15.5% 13.0%

Kemper County Commercial Capture

Mississippi 5.4% 6.4% 19.2% 12.9%

La Barge Gas Plant

Exisiting Gas and 

Fertilizer Plant

Wyoming 6.6% 6.1% 13.3% 13.4%
 Page 139 of 145 

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

(Cont’d)

Facility Name Facility Type

Percent of 

Population that is

0-4 Years: 3-Mile 

Radius

Percent of 

Population that is

0-4 Years: State

Percent of 

Population that is

65+ Years: 3-Mile 

Radius

Percent of 

Population that is

65+ Years: State

Lima Commercial Capture

Ohio 6.3% 5.6% 14.1% 14.4%

Mesaba Commercial Capture

Minnesota 3.5% 5.9% 25.4% 13.5%

Mt. Simon Saline Reservoir

Major DOE Sequestration 

Project

Illinois 3.8% 6.0% 16.9% 13.0%

San Joaquin Basin, CA Saline 

Formation

Major DOE Sequestration 

Project

California 8.3% 6.3% 10.7% 11.9%

Tenasca Sweetwater/Trailblazer Commercial Capture

Texas 7.0% 7.0% 13.7% 10.8%

Tenasca Taylorville Energy Commercial Capture

Illinois 4.8% 6.0% 15.6% 13.0%

Texas Clean Energy Project Commercial Capture

Texas 7.4% 7.0% 12.9% 10.8%

Val Verde Gas Plant, Gray Ranch

Exisiting Gas and 

Fertilizer Plant

Texas 4.6% 7.0% 9.2% 10.8%

Val Verde Gas Plant, Mitchell

Exisiting Gas and 

Fertilizer Plant

Texas 4.6% 7.0% 9.2% 10.8%

Val Verde Gas Plant, Pikes Peak

Exisiting Gas and 

Fertilizer Plant

Texas 4.6% 7.0% 9.2% 10.8%

Val Verde Gas Plant, Puckett

Exisiting Gas and 

Fertilizer Plant

Texas 4.6% 7.0% 9.2% 10.8%

Val Verde Gas Plant, Terrell

Exisiting Gas and 

Fertilizer Plant

Texas 3.3% 7.0% 19.8% 10.8%

WA Parish, Sugarland Commercial Capture

Texas 6.0% 7.0% 11.8% 10.8%

Wallula Energy Res. Center Commercial Capture

Washington 5.2% 5.6% 12.0% 13.2%

Williston Basin EOR 

Sequestration*

Major DOE Sequestration 

Project

North Dakota 4.4% 5.7% 20.2% 14.9%

Worsham-Steed (ZENG) Commercial Capture

Texas 5.8% 7.0% 15.2% 10.8%
 Page 140 of 145 

Exhibit C.B-8. Number of FRS Sites 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 C.B-8. Number of FRS Sites Within 3-Mile Radius of Facility (Cont’d) 

Facility Name Facility Type

Number of EPA 

FRS Sites within 

Buffer: 3-Mile

Lima Commercial Capture

Ohio 88

Mesaba Commercial Capture

Minnesota 3

Mt. Simon Saline Reservoir Major DOE Sequestration Project

Illinois 13

San Joaquin Basin, CA Saline Formation Major DOE Sequestration Project

California 3

Tenasca Sweetwater/Trailblazer Commercial Capture

Texas 17

Tenasca Taylorville Energy Commercial Capture

Illinois 3

Texas Clean Energy Project Commercial Capture

Texas 1

Val Verde Gas Plant, Gray Ranch Exisiting Gas and Fertilizer Plant

Texas 2

Val Verde Gas Plant, Mitchell Exisiting Gas and Fertilizer Plant

Texas 2

Val Verde Gas Plant, Pikes Peak Exisiting Gas and Fertilizer Plant

Texas 1

Val Verde Gas Plant, Puckett Exisiting Gas and Fertilizer Plant

Texas 3

Val Verde Gas Plant, Terrell Exisiting Gas and Fertilizer Plant

Texas 1

WA Parish, Sugarland Commercial Capture

Texas 4

Wallula Energy Res. Center Commercial Capture

Washington 5

Williston Basin EOR Sequestration* Major DOE Sequestration Project

North Dakota 0

Worsham-Steed (ZENG) Commercial Capture

Texas 4
 Page 142 of 145 

Appendix D

Unfunded Mandates Reform Act Analysis 

No analysis is required under the Unfunded Mandates Reform Act (UMRA) because the 

proposed rule does not include any mandate that is expected to result in expenditure by the 

private sector or aggregate expenditure by 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. 
 Page 143 of 145 

Appendix E

Other Required Analyses 

F-1 Executive Order 12866: Regulatory Planning and Review 

EPA has determined that the proposed rule is a "significant regulatory action" as defined by 

Executive Order 12866 because it raises novel legal or policy issues arising out of legal 

mandates, the President's priorities, or the principles set forth in the Executive Order. 

Accordingly, EPA submitted this action to the Office of Management and Budget (OMB) for 

review under EO 12866, and any changes made in response to OMB recommendations have been 

documented in the docket for this action. 

The expected annual costs and benefits of the proposed rule do not exceed $100 million. The 

rule does not create inconsistencies or 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. 

F-4 Executive Order 13045: Protection of Children from Environmental Health and 

Safety Risks 

EPA does not find 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 
 Page 144 of 145 

Although the affected universe of the proposed rule includes energy suppliers such as coal 

power plants, the rule is not expected to result in behavioral changes that would affect energy 

supply, distribution or usage. 

F-6 National Technology Transfer Advancement Act 

This proposed rulemaking does not involve technical 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 finds that the actions 

allowed by the proposed exclusions are safe and do not present significant adverse health or 

environmental impacts (See Appendix C). 

F-8 Executive Order 12630: Regulatory Takings Analysis 

The proposed rule does not constitute a regulatory taking because it is not expected to result 

in the physical invasion of property and should not negatively impact the economic viability 

of property. 

F-9 Executive Order 12988: Civil Justice Reform 

The proposed rule specifies in clear language the effect of the regulation; specifies its 

relationship to the provisions of other laws; incorporates clear legal standards; has no 

retroactive effect; and defines key terms. Therefore, no additional analysis or actions are 

required under EO 12988. 

F-10 Executive Order 13352: Facilitation of Cooperative Conservation 

The proposed rule is designed to promote cooperative conservation between EPA, state, and 

local governments by identifying clear criteria for excluding carbon dioxide injectate from 

the regulatory requirements for hazardous 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 
 Page 145 of 145 

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).96 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.

 

96 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.